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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
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FORM 10-K
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/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER: 1-9743
ENRON OIL & GAS COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 47-0684736
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
1400 SMITH STREET, HOUSTON, TEXAS 77002-7369
(Address of principal executive offices) (zip code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 713-853-6161
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SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Title of each class Name of each exchange on which registered
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Common Stock, $.01 par value New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes /X/ No / /.
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. /X/
Aggregate market value of the voting stock held by non-affiliates of the
registrant, based on the closing sale price in the daily composite list for
transactions on the New York Stock Exchange on March 2, 1995 was $636,486,102.
As of March 2, 1995, there were 159,940,827 shares of the registrant's Common
Stock, $.01 par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE. Certain portions of the registrant's
definitive Proxy Statement for the May 2, 1995 Annual Meeting of Shareholders
("Proxy Statement") are incorporated in Part III by reference.
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<PAGE>
TABLE OF CONTENTS
PART I
PAGE
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Item 1. Business............................. 1
General.......................... 1
Business Segments................ 1
Exploration and Production....... 1
Marketing........................ 4
Wellhead Volumes and Prices, and
Lease and Well Expenses........ 6
Other Natural Gas Marketing
Volumes and Prices............. 7
Competition...................... 7
Regulation....................... 7
Relationship Between the Company
and Enron Corp................. 11
Other Matters.................... 13
Current Executive Officers of the
Registrant..................... 14
Item 2. Properties........................... 15
Oil and Gas Exploration and
Production Properties and
Reserves....................... 15
Item 3. Legal Proceedings.................... 18
Item 4. Submission of Matters to a Vote of
Security Holders..................... 18
PART II
Item 5. Market for the Registrant's Common
Equity and Related Shareholder
Matters............................ 19
Item 6. Selected Financial Data.............. 20
Item 7. Management's Discussion and Analysis
of Financial Condition and Results
of Operations...................... 21
Item 8. Financial Statements and
Supplementary Data................... 28
Item 9. Disagreements on Accounting and
Financial Disclosure................. 28
PART III
Item 10. Directors and Executive Officers of
the Registrant....................... 28
Item 11. Executive Compensation............... 28
Item 12. Security Ownership of Certain
Beneficial Owners and Management... 28
Item 13. Certain Relationships and Related
Transactions......................... 28
PART IV
Item 14. Exhibits, Financial Statement
Schedule, and Reports on Form
8-K................................ 29
i
<PAGE>
PART I
ITEM 1. BUSINESS
GENERAL
Enron Oil & Gas Company (the "Company"), a Delaware corporation, is engaged,
either directly or through a marketing subsidiary with regard to domestic
operations or through various subsidiaries with regard to international
operations, in the exploration for, and the development, production and
marketing of, natural gas and crude oil primarily in major producing basins in
the United States, as well as in Canada, Trinidad and India and to a lesser
extent, selected other international areas. The Company's principal producing
areas are further described under "Exploration and Production" below. At
December 31, 1994, the Company's estimated net proved natural gas reserves were
1,910 billion cubic feet ("Bcf") and estimated net proved crude oil, condensate
and natural gas liquids reserves were 37 million barrels ("MMBbl"). (See
"Supplemental Information to Consolidated Financial Statements"). At such date,
approximately 70% of the Company's reserves (on a natural gas equivalent basis)
was located in the United States, 16% in Canada, 11% in Trinidad and 3% in
India. As of December 31, 1994, the Company employed approximately 740 persons.
The Company pursues its oil and gas exploration and development operations
primarily by the acquisition, through various means including but not limited to
leasing, purchasing and farming-in of acreage that is either undeveloped or
lightly developed, and drilling of internally generated prospects. The Company
also maintains a strategy of selling selected oil and gas properties that for
various reasons may no longer fit into future operational plans or are not
assessed to have sufficient future growth potential, and when the economic value
to be obtained by selling the properties and reserves in the ground is evaluated
to be greater than what would be obtained by holding the properties and
producing the reserves over time. As a result, the Company typically receives
each year a varying but rather substantial level of proceeds related to such
sales which proceeds are available for general corporate use.
Enron Corp. currently owns 80% of the outstanding common stock of the
Company. (See "Relationship Between the Company and Enron Corp.").
Unless the context otherwise requires, all references herein to the Company
include Enron Oil & Gas Company, its predecessors and subsidiaries, and any
reference to the ownership of interest or pursuit of operations in any
international areas by the Company recognizes that all such interests are owned
and operations are pursued by subsidiaries of Enron Oil & Gas Company. Unless
the context otherwise requires, all references herein to Enron Corp. include
Enron Corp., its predecessors and affiliates, other than the Company and its
subsidiaries.
With respect to information on the Company's working interest in wells or
acreage, "net" oil and gas wells or acreage are determined by multiplying
"gross" oil and gas wells or acreage by the Company's working interest in the
wells or acreage. Unless otherwise defined, all references to wells are gross.
BUSINESS SEGMENTS
The Company's operations are all natural gas and crude oil exploration and
production related. Accordingly, such operations are classified as one business
segment.
EXPLORATION AND PRODUCTION
NORTH AMERICAN OPERATIONS. The Company's six principal domestic producing areas
are the Big Piney area, South Texas area, Matagorda Trend area, Canyon Trend
area, Pitchfork Ranch area and Vernal area. Properties in these areas comprised
approximately 76% of the Company's domestic reserves (on a natural gas
equivalent basis) and 76% of the Company's maximum domestic net natural gas
deliverability as of December 31, 1994 and are substantially all operated by the
Company.
1
The Company's other domestic natural gas and crude oil producing properties are
located primarily in other areas of Texas, Utah, New Mexico and Oklahoma.
At December 31, 1994, 93% of the Company's proved domestic reserves (on a
natural gas equivalent basis) was natural gas and 7% was crude oil, condensate
and natural gas liquids. A substantial portion of the Company's domestic natural
gas reserves is in long-lived fields with well-established production histories.
The opportunity exists to increase production in many of these fields through
continued infill and other development drilling.
The Company also has natural gas and crude oil producing properties located
in Western Canada, primarily in the provinces of Alberta, Saskatchewan and
Manitoba.
BIG PINEY AREA. The Company's largest reserve accumulation is located in the
Big Piney area in Sublette and Lincoln counties in southwestern Wyoming. The
Company is the holder of the largest productive acreage base in this area, with
approximately 219,000 net acres under lease directly within field limits. The
Company operates approximately 650 natural gas wells in this area in which it
owns a 91% average working interest. Deliveries from the area net to the Company
averaged 124 million cubic feet ("MMcf") per day of natural gas and 1.5 thousand
barrels ("MBbl") per day of crude oil, condensate, and natural gas liquids in
1994. At December 31, 1994, maximum natural gas deliverability net to the
Company was approximately 142 MMcf per day.
The current principal producing intervals are the Frontier and Mesaverde
formations. The Frontier formation, which occurs at 6,500-10,000 feet, contains
approximately 66% of the Company's current Big Piney reserves. The Company
drilled 67 wells in the Big Piney area in 1994 and anticipates an active
drilling program will continue for several years. (See "Other Matters - Tight
Gas Sand Tax Credits (Section 29) and Severance Tax Exemption").
SOUTH TEXAS AREA. The Company's activities in South Texas are focused in the
Wilcox, Expanded Wilcox, Frio and Lobo producing horizons. The primary area of
activity is in the Lobo Trend which occurs primarily in Webb and Zapata
counties.
The Company operates approximately 470 wells in the South Texas area.
Production is primarily from the Lobo sand of the Wilcox formation at depths
ranging from 7,000 to 11,000 feet. The Company has approximately 250,000 net
acres under lease in this area. Natural gas deliveries net to the Company
averaged 181 MMcf per day in 1994. At December 31, 1994, maximum natural gas
deliverability net to the Company was approximately 201 MMcf per day. The
Company drilled 56 wells in the South Texas area in 1994 and anticipates an
active drilling program will continue for several years. (See "Other Matters -
Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption").
MATAGORDA TREND AREA. The Company has an interest in several fields in the
Matagorda Trend area, located 20 miles south of Port O'Connor, Texas in federal
waters. The Company has a 78% working interest in Block 638 and a 92% working
interest in Block 620. In Matagorda Blocks 555, 556, 700 and 713, the Company
has an approximate 70%, 50%, 62% and 64% working interest, respectively. In
addition, the Company has an approximate 82% and 50% working interest in Mustang
Island Blocks 758 and 784, respectively. In addition, the Company has extended
its Matagorda Trend holdings into the Mustang Island area as a result of the
purchase in 1994 of 15 OCS Blocks in the Matagorda and Mustang Island areas. The
Company had a new field discovery at Mustang Island 759 in which it owns a 75%
working interest and which is expected to commence deliveries in mid 1995 at a
net rate of approximately 50 MMcf per day. The Company operates all of the
offshore tracts mentioned above. Natural gas deliveries from these areas net to
the Company averaged 65 MMcf per day in 1994. At December 31, 1994, maximum
natural gas deliverability net to the Company from these blocks was
approximately 85 MMcf per day.
CANYON TREND AREA. The Company's activities in this area have been
concentrated in Crockett, Sutton, Terrell and Val Verde Counties, Texas where
the Company drilled 331 natural gas wells during the period 1992 through 1994.
During 1994, the Company increased its acreage position by
2
approximately 7,800 net acres to approximately 91,800 net acres and now operates
approximately 500 natural gas wells in this area in which it owns a 97% average
working interest. Production is from the Canyon sands and Strawn limestone at
depths from 5,500 to 11,500 feet. In 1994, natural gas deliveries net to the
Company averaged 65 MMcf per day and at December 31, 1994, maximum natural gas
deliverability net to the Company was approximately 66 MMcf per day. The Company
expects to maintain an active drilling program in the Canyon Trend area during
1995. (See "Other Matters - Tight Gas Sand Tax Credits (Section 29) and
Severance Tax Exemption").
PITCHFORK RANCH FIELD. The Pitchfork Ranch field located in Lea County, New
Mexico, produces primarily from the Bone Spring, Atoka and Morrow formations. In
1994, deliveries net to the Company averaged 36 MMcf per day of natural gas and
approximately 2 MBbl per day of crude oil, condensate and natural gas liquids.
At December 31, 1994, maximum deliverability net to the Company was
approximately 39 MMcf per day of natural gas and 3 MBbl per day of crude oil,
condensate and natural gas liquids. During 1994, the Company increased crude
oil, condensate and natural gas liquids reserves and deliverability through
drilling. Additionally, the Company has increased its acreage position by
approximately 12,300 net acres to approximately 27,900 net acres and expects to
maintain an active drilling program in this field during 1995. (See "Other
Matters - Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption").
VERNAL AREA. In the Vernal area, located primarily in Uintah County, Utah,
the Company operates approximately 195 producing wells and presently controls
approximately 79,000 net acres. In 1994, natural gas deliveries net to the
Company from the Vernal area averaged 24 MMcf per day which is the maximum
deliverability. Production is from the Green River and Wasatch formations
located at depths between 4,500-8,000 feet. The Company has an average working
interest of approximately 60%. The Company drilled 20 wells in the Vernal area
in 1994 and expects to maintain a comparable drilling program during 1995. (See
"Other Matters - Tight Gas Sand Tax Credits (Section 29) and Severance Tax
Exemption").
CANADA. The Company is engaged in the exploration for and the development
and production of natural gas and crude oil and the operation of natural gas
processing plants in western Canada, principally in the provinces of Alberta,
Saskatchewan, and Manitoba. The Company conducts operations from offices in
Calgary. The Company produces natural gas from seven major areas and crude oil
from three major areas. The Sandhills area in Southern Saskatchewan is the
largest single producing area where an additional 160 wells were drilled in 1994
resulting in deliverability net to the Company from the field of approximately
38 MMcf per day at December 31, 1994. Maximum Canadian natural gas
deliverability net to the Company at December 31, 1994 was approximately 85 MMcf
per day, and the Company held approximately 354,000 net undeveloped acres in
Canada. The Company expects to maintain an active drilling program in Canada
during 1995.
OUTSIDE NORTH AMERICA OPERATIONS. The Company has operations offshore Trinidad
and India and is conducting exploration in selected other international areas.
Properties offshore Trinidad and India comprised 100% of the Company's reserves
and production outside of North America.
TRINIDAD. In November 1992, the Company was awarded a 95% working interest
concession in the South East Coast Consortium Block offshore Trinidad,
encompassing three undeveloped fields, previously held by three government-owned
energy companies. The Kiskadee field is currently being developed while the
remaining two undeveloped fields are anticipated to be developed over the next
three to five years. Existing surplus processing and transportation capacity at
the Pelican Field facilities owned and operated by Trinidadian companies is
being used to process and transport the production. Natural gas is being sold
into the local market under a take-or-pay agreement with the National Gas
Company of Trinidad and Tobago. At December 31, 1994, maximum natural gas
deliverability net to the Company was approximately 150 MMcf per day and the
Company held approximately 71,000 net undeveloped acres in Trinidad. Natural gas
market takes were increased to approximately 121 MMcf per day and condensate
deliveries were increased to approximately 5 MBbl per day, both net to the
Company, as of January 1, 1995.
3
INDIA. In December 1994, the Company signed agreements covering profit
sharing, joint operations and product sales and representing a 30% working
interest in and was designated operator of the Tapti, Panna and Mukta Blocks
located offshore Bombay, India. The blocks were previously operated by the
Indian national oil company, Oil & Natural Gas Corporation Limited, which
retains a 40% working interest. The 363,000 acre Tapti Block contains two major
proved gas accumulations delineated by 22 expendable exploration wells that have
been plugged. The Company plans to commence development of the Tapti Block
accumulations immediately. The 106,000 acre Panna Block and the 192,000 acre
Mukta Block are partially developed with five producing platforms located in the
Panna and Mukta fields. The fields were producing approximately 3 MBbl per day
of crude oil net to the Company as of December 31, 1994; all associated gas was
being flared. The Company intends to continue development of the accumulations
and to expand processing capacity to allow crude oil production at full
deliverability as well as to permit natural gas sales.
OTHER INTERNATIONAL. The Company continues to pursue other selected
conventional natural gas and crude oil opportunities outside North America.
During 1995, the Company will pursue other exploitation opportunities in
countries where indigenous natural gas reserves have been identified,
particularly where synergies in natural gas transportation, processing and power
cogeneration can be optimized with other Enron Corp. affiliated companies. In
early 1995, the Company and the Qatar General Petroleum Corporation signed a
nonbinding letter of intent concerning the possible development of a liquefied
natural gas project for natural gas to be produced from the North Dome Field.
The Company and Enron Corp. may jointly hold up to a 40 percent working interest
in the joint venture and would drill and develop the agreed upon reserves. In
addition, the Company signed letters of intent in early 1995 with the National
Oil Corporation of Uzbekistan, and Gazprom, the Russian Natural Gas Company, to
pursue the feasibility of joint venture development and marketing of previously
discovered hydrocarbon reserves in Uzbekistan.
The Company continues evaluation and assessment of its international
opportunity portfolio in the coalbed methane recovery arena, including projects
in South Wales in the U.K., the Lorraine Basin in France, Galilee Basin in
Queensland, Australia and in two basins in China. A similar project in Russia
continues under evaluation.
MARKETING
WELLHEAD MARKETING. The Company's North America wellhead natural gas
production is currently being sold on the spot market and under long-term
natural gas contracts at market responsive prices. In many instances, the
long-term contract prices closely approximate the prices received for natural
gas being sold on the spot market. Wellhead natural gas volumes from Trinidad
are sold at prices that are based on a fixed price schedule with periodic
escalations. Natural gas volumes in India will be sold to the Gas Authority of
India, Ltd. under a take-or-pay contract at a price linked to a basket of world
market fuel oil quotations with floor and ceiling limits. Approximately 45% of
the Company's wellhead natural gas production is currently being sold to
pipeline and marketing subsidiaries of Enron Corp.
Substantially all of the Company's wellhead crude oil and condensate is sold
under short-term contracts at market responsive prices.
OTHER MARKETING. Enron Oil & Gas Marketing, Inc. ("EOGM"), a wholly-owned
subsidiary of the Company, is a marketing company engaging in various marketing
activities. Both the Company and EOGM contract to provide, under short and
long-term agreements, natural gas to various purchasers and then aggregate the
necessary supplies for the sales with purchases from various sources including
third-party producers, marketing companies, pipelines or from the Company's own
production. In addition, EOGM has purchased and constructed several small
gathering systems in order to facilitate its entry into the gathering business
on a limited basis. Both EOGM and the Company utilize other short and long-term
hedging and trading mechanisms including sales and purchases utilizing
NYMEX-related commodity market transactions. These marketing activities have
4
provided an effective balance in managing the Company's exposure to commodity
price risks in the energy market.
In September 1992, the Company sold a volumetric production payment for
$326.8 million to a limited partnership of which an Enron Corp. affiliated
company is general partner with a 1% interest. Under the terms of the production
payment agreements, the Company conveyed a real property interest in
approximately 124 billion cubic feet equivalent ("Bcfe") (136 trillion British
thermal units) of its natural gas and other hydrocarbon reserves. Effective
October 1, 1993, the agreements were amended providing for the extension of the
original term of the volumetric production payment through March 31, 1999 and
including a revised schedule of daily quantities of hydrocarbons to be delivered
which is approximately one-half of the original schedule. The revised schedule
will total approximately 89.1 Bcfe (97.8 trillion British thermal units) versus
approximately 87.9 Bcfe (96.4 trillion British thermal units) remaining to be
delivered under the original agreement. Daily quantities of hydrocarbons no
longer required to be delivered under the revised schedule during the period
from October 1, 1993 through June 30, 1996 are available for sale by the
Company. The Company retains responsibility for its working interest share of
the cost of operations. The Company also entered into a separate agreement with
the same limited partnership whereby it has agreed to exchange volumes owned by
the Company in various other areas for equivalent volumes produced by the
Company and owned by the limited partnership under the terms of the volumetric
production payment. The costs incurred, if any, to effect redeliveries pursuant
to such exchange are borne by the Company.
The Company also has contracted to supply natural gas to a Texas City, Texas
cogeneration facility which is owned by Cogenron Inc. Cogenron Inc. is 50% owned
by Enron Corp. The primary contract provides for the sale of natural gas under a
fixed schedule of prices substantially above current spot market prices. Current
deliveries of approximately 45 MMcf of natural gas per day are being supplied
primarily by purchases at market responsive prices under a long-term agreement
with an Enron Corp. subsidiary. The Company has also entered into a price swap
agreement with a third party that has the effect of converting the prices under
this contract to a fixed schedule of prices. The resulting prices under this
combination of purchase and price swap agreements are substantially below the
fixed schedule of prices in the primary sales contract. The arrangements are
designed, as to the volumes involved, to provide the Company a fixed margin of
profit under its agreement with Cogenron Inc. However, the Company's commitment
to deliver volumes of natural gas in excess of the current delivery levels at
the schedule of predetermined prices discussed above could be disadvantageous to
the Company during any time spot market prices exceed the applicable contract
prices for natural gas.
5
WELLHEAD VOLUMES AND PRICES, AND LEASE AND WELL EXPENSES
The following table sets forth certain information regarding the Company's
wellhead volumes of and average prices for natural gas per thousand cubic feet
("Mcf"), crude oil and condensate, and natural gas liquids per barrel ("Bbl"),
and average lease and well expenses per thousand cubic feet equivalent ("Mcfe" -
natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas
to 1.0 barrel of crude oil and condensate or natural gas liquids) delivered
during each of the three years in the period ended December 31, 1994:
YEAR ENDED DECEMBER 31,
-------------------------------
1994 1993 1992
--------- --------- ---------
VOLUMES (PER DAY)
Natural Gas (MMcf)
United States(1)............. 614 649 534
Canada....................... 72 58 30
Trinidad..................... 63 2 -
--------- --------- ---------
Total(1)................... 749 709 564
========= ========= =========
Crude Oil and Condensate (MBbl)
United States................ 8.0 6.6 6.3
Canada....................... 2.0 2.2 2.2
Trinidad..................... 2.5 .1 -
India........................ .1 - -
--------- --------- ---------
Total...................... 12.6 8.9 8.5
========= ========= =========
Natural Gas Liquids (MBbl)
United States................ .3 .2 .3
Canada....................... .4 .4 .4
--------- --------- ---------
Total...................... .7 .6 .7
========= ========= =========
AVERAGE PRICES
Natural Gas ($/Mcf)
United States(2)............. $ 1.71 $ 1.97 $ 1.61
Canada....................... 1.42 1.34 1.18
Trinidad..................... .93 .89 -
Composite(2)............... 1.62 1.92 1.58
Crude Oil and Condensate ($/Bbl)
United States................ $ 16.06 $ 16.96 $ 18.29
Canada....................... 14.05 14.63 16.80
Trinidad..................... 15.50 14.36 -
India........................ 15.70 - -
Composite.................. 15.62 16.37 17.90
Natural Gas Liquids ($/Bbl)
United States................ $ 12.45 $ 13.85 $ 11.56
Canada....................... 8.45 9.46 10.05
Composite.................. 9.90 11.12 10.69
LEASE AND WELL EXPENSES ($/MCFE)
United States................ $ .19 $ .18 $ .20
Canada....................... .34 .48 .50
Trinidad..................... .17 1.46 -
India........................ .13 - -
Composite.................. .20 .21 .22
- ---------
(1) Includes 48 MMcf per day in 1994, 81 MMcf per day in 1993 and 28 MMcf per
day in 1992 delivered under the terms of a volumetric production payment
agreement effective October 1, 1992, as amended.
(2) Includes an average equivalent wellhead value of $1.27 per Mcf in 1994,
$1.57 per Mcf in 1993 and $1.70 Mcf in 1992 for the volumes described in
note (1), net of transportation costs.
6
OTHER NATURAL GAS MARKETING VOLUMES AND PRICES
The following table sets forth certain information regarding the Company's
volumes of natural gas delivered under other marketing and volumetric production
payment arrangements, and resulting average per unit gross revenue and per unit
amortization of deferred revenues along with associated costs during each of the
three years in the period ended December 31, 1994. (See "Marketing" for a
discussion of other natural gas marketing arrangements and agreements).
YEAR ENDED DECEMBER 31,
-------------------------------
1994 1993 1992
--------- --------- ---------
Volumes (MMcf per day)(1)............ 324 293 255
Average Gross Revenue ($/Mcf)(2)..... $ 2.38 $ 2.57 $ 2.62
Associated Costs ($/Mcf)(3)(4)....... 2.06 2.32 1.99
--------- --------- ---------
Margin ($/Mcf)....................... $ 0.32 $ 0.25 $ 0.63
========= ========= =========
- ---------
(1) Includes 48 MMcf per day in 1994, 81 MMcf per day in 1993 and 28 MMcf per
day in 1992 delivered under the terms of volumetric production payment and
exchange agreements effective October 1, 1992, as amended.
(2) Includes per unit deferred revenue amortization for the volumes detailed
in note (1) at an equivalent of $2.46 per Mcf ($2.36 per million British
thermal units) in 1994, $2.50 per Mcf ($2.40 per million British thermal
units) in 1993 and $2.51 per Mcf ($2.40 per million British thermal units)
in 1992.
(3) Includes an average value of $1.92 per Mcf in 1994, $2.20 per Mcf in 1993
and $2.37 per Mcf in 1992, including average equivalent wellhead value,
any applicable transportation costs and exchange differentials, for the
volumes detailed in note (1).
(4) Including transportation and exchange differentials.
COMPETITION
The Company actively competes for reserve acquisitions and exploration
leases, licenses and concessions, frequently against companies with
substantially larger financial and other resources. To the extent the Company's
exploration budget is lower than that of certain of its competitors, the Company
may be disadvantaged in effectively competing for certain reserves, leases,
licenses and concessions. Competitive factors include price, contract terms, and
quality of service, including pipeline connection times and distribution
efficiencies. In addition, the Company faces competition from other producers
and suppliers, including competition from other world wide energy supplies
including Canadian natural gas.
REGULATION
DOMESTIC REGULATION OF NATURAL GAS AND CRUDE OIL PRODUCTION. Natural gas and
crude oil production operations are subject to various types of regulation,
including regulation in the United States by state and federal agencies.
Domestic legislation affecting the oil and gas industry is under constant
review for amendment or expansion. Also, numerous departments and agencies, both
federal and state, are authorized by statute to issue and have issued rules and
regulations which, among other things, require permits for the drilling of
wells, regulate the spacing of wells, prevent the waste of natural gas and
liquid hydrocarbon resources through proration and restrictions on flaring,
require drilling bonds and regulate environmental and safety matters. The
regulatory burden on the oil and gas industry increases its cost of doing
business and, consequently, affects its profitability.
A substantial portion of the Company's oil and gas leases in the Big Piney
area and in the Gulf of Mexico, as well as some in other areas, are granted by
the federal government and administered by the Bureau of Land Management (the
"BLM") and the Minerals Management Service (the "MMS") federal agencies.
Operations conducted by the Company on federal oil and gas leases must comply
7
with numerous statutory and regulatory restrictions concerning the above and
other matters. Certain operations must be conducted pursuant to appropriate
permits issued by the BLM and the MMS.
Sales of crude oil, condensate and natural gas liquids by the Company are
made at unregulated market prices.
The transportation and sale for resale of natural gas in interstate commerce
are regulated pursuant to the Natural Gas Act of 1938 (the "NGA") and the
Natural Gas Policy Act of 1978 (the "NGPA"). These statutes are administered by
the Federal Energy Regulatory Commission (the "FERC"). Effective January 1,
1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas
prices for all "first sales" of natural gas, which includes all sales by the
Company of its own production. Consequently, sales of the Company's natural gas
currently may be made at market prices, subject to applicable contract
provisions.
Regulation of natural gas importation is administered primarily by the
Department of Energy's Office of Fossil Energy (the "DOE/FE"), pursuant to the
NGA. The NGA provides that any party seeking to import natural gas must first
seek DOE/FE authorization, which authorization may be granted, modified or
denied in accordance with the public interest. The Energy Policy Act of 1992
amended the NGA's public interest standard with respect to imports from and
exports to certain countries, such as Canada, to deem imports from and exports
to such countries to be in the public interest, and require such import/export
applications to be granted without delay. In addition, the Energy Policy Act
amended the NGPA to treat natural gas imported from Canada as "first sales" of
natural gas under Section 3 of the NGPA, thus allowing such imported natural gas
to be sold for resale without certificate authorization from the FERC.
Additionally, the National Energy Board of Canada has dramatically revised its
natural gas export policies to permit large volumes of Canadian natural gas to
compete with natural gas produced in the U.S. for the U.S. spot market.
Additional natural gas pipeline capacity from Canada to the U.S. has been built
and other such construction proposals are pending approval. While the impact on
the Company of this change is uncertain, it is possible that it will increase
competition in the markets in which the Company sells natural gas. For example,
Canadian natural gas competes directly with natural gas produced from the
Company's Big Piney area for customers located in the Pacific Northwest region
of the United States.
Since 1985, the FERC has endeavored to make natural gas transportation more
accessible to gas buyers and sellers on an open and non-discriminatory basis.
These efforts have significantly altered the marketing and pricing of natural
gas. Commencing in April 1992, the FERC issued Order Nos. 636, 636-A and 636-B
("Order No. 636"), which mandate a fundamental restructuring of interstate
pipeline sales and transportation services. Order No. 636 requires interstate
natural gas pipelines to "unbundle" or segregate the sales, transportation,
storage, and other components of their existing city-gate sales service, and to
separately state the rates for each unbundled service. Under Order No. 636,
unbundled pipeline sales can be made only in the production areas. Order No. 636
also requires interstate pipelines to assign capacity rights they have on
upstream pipelines to such pipelines' former sales customers and provides for
the recovery by interstate pipelines of costs associated with the transition
from providing bundled sales services to providing unbundled transportation and
storage services. The purpose of Order No. 636 is to further enhance competition
in the natural gas industry by assuring the comparability of pipeline sales
service and services offered by a pipelines' competitors. As of early 1995, the
FERC had issued final orders accepting most pipelines' Order No. 636 compliance
filings and had commenced a series of one-year reviews of individual pipeline
implementations of Order No. 636. Numerous parties have filed petitions for
court review of Order No. 636 as well as orders in individual pipeline
restructuring proceedings. Upon such judicial review, these orders may be
amended or reversed in whole or in part. Order No. 636 does not directly
regulate the Company's activities, but has had and will have an indirect effect
because of its broad scope. With Order No. 636 and pending ongoing FERC reviews
of individual pipeline restructurings, subject to court review, it is difficult
to predict with precision its effects. In many instances, however, Order No. 636
has substantially reduced or brought to an end interstate pipelines' traditional
roles as
8
wholesalers of natural gas in favor of providing only storage and transportation
services. Order No. 636 has also substantially increased competition in natural
gas markets, even though there remains significant uncertainty with respect to
the marketing and transportation of natural gas. In spite of this uncertainty,
Order No. 636 may enhance the Company's ability to market and transport its
natural gas production, although it may also subject the Company to more
restrictive pipeline imbalance tolerances and greater penalties for violation of
such tolerances.
In December 1992, the FERC issued Order No. 547, governing the issuance of
blanket marketer sales certificates to all natural gas sellers other than
interstate pipelines. The order eliminates the need for natural gas producers
and marketers to seek specific authorization under Section 7 of the NGA from the
FERC to make sales of natural gas, such as imported natural gas and natural gas
purchased from interstate pipelines. Instead, effective January 7, 1993, these
natural gas sellers, by operation of the order, will be issued blanket
certificates of public convenience and necessity allowing them to make
jurisdictional natural gas sales for resale at negotiated rates without seeking
specific FERC authorization. The FERC intends Order No. 547, in tandem with
Order No. 636, to foster a competitive market for natural gas by giving natural
gas purchasers access to multiple supply sources at market-driven prices. In
July 1994, the FERC eliminated a regulation that had rendered virtually all
sales of natural gas by pipeline affiliates, such as the Company, to be
deregulated first sales. As a result, only sales by the Company of its own
production now qualify for this status. All other sales of gas by the Company,
such as those of gas purchased from third parties, are now jurisdictional sales
subject to the Order No. 547 certificate. The Company does not anticipate this
change will have any significant current adverse effects in light of the
flexible terms and conditions of the existing blanket certificate. Such sales
are subject to the future possibility of greater federal oversight, however,
including the possibility the FERC might prospectively impose more restrictive
conditions on such sales.
In December 1993, the FERC issued Order No. 497-E, which modified in some
respects the standards of conduct, record keeping and reporting requirements and
other measures that govern relationships between interstate pipelines and their
marketing affiliates. Order No. 497-E narrowed the contemporaneous disclosure
standard of conduct and the reporting requirements, while at the same time
possibly expanding the class of pipeline and marketing affiliate employees to
whom the standards of conduct apply. In 1994, the Commission issued Order Nos.
566, 566-A and 566-B, in which it extended indefinitely its regulations (Order
No. 497 regulations) governing relationships between interstate pipelines and
their marketing affiliates, subject to revisions to delete an out-of-date
standard and revise certain reporting and record keeping requirements. Among
other matters, these new rules require pipelines to post on their electronic
bulletin boards, within 24 hours of gas flow, information concerning discounted
transportation provided to marketing affiliates to enable competing marketers to
request comparable discounts. The rules retain existing standards, as revised by
Order No. 497-E, requiring the contemporaneous disclosure to all shippers of
transportation-related information provided a marketing affiliate, and
prohibiting disclosure of certain information to marketing affiliates. Order No.
497 does not directly regulate the Company's activities, although a substantial
portion of the Company's natural gas production is sold to or transported by
interstate pipeline affiliates which are subject to the Order. The Company's
activities may therefore be indirectly affected by these regulations.
The Company owns, directly or indirectly, certain natural gas pipelines that
it believes meet the traditional tests the FERC has used to establish a
pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA.
State regulation of gathering facilities generally includes various safety,
environmental, and in some circumstances, non-discriminatory take requirements,
but does not generally entail rate regulation. Natural gas gathering may receive
greater regulatory scrutiny at both the state and federal levels as the pipeline
restructuring under Order No. 636 is implemented. For example, the State of
Oklahoma in 1993 enacted a prohibition against discriminatory gathering rates
and recently announced plans to conduct an inquiry on alleged discriminatory
practices by gatherers and transporters. In certain recent cases, the FERC has
asserted ancillary NGA jurisdiction over gathering activities of interstate
pipelines and their affiliates. In late 1993, the FERC convened a
9
conference to consider issues relating to gathering services performed by
interstate pipelines or their affiliates. Commencing in May 1994, the FERC
issued a series of orders in individual cases that delineate its gathering
policy as a result of the comments received. Among other matters, the FERC
slightly narrowed its statutory tests for establishing gathering status and
reaffirmed that, except in situations in which the gatherer acts in concert with
an interstate pipeline affiliate to frustrate the FERC's transportation
policies, it does not have jurisdiction over natural gas gathering facilities
and services and that such facilities and services are properly regulated by
state authorities. This FERC action may further encourage regulatory scrutiny of
natural gas gathering by state agencies. In addition, the FERC has approved
several transfers by interstate pipelines, including certain of the Company's
pipeline affiliates, of gathering facilities to unregulated independent or
affiliated gathering companies. This could increase competition among gatherers
in the affected areas. Certain of the FERC's orders delineating its new
gathering policy are subject to pending court appeals. The Company's gathering
operations could be adversely affected should they be subject in the future to
the application of state or federal regulation of rates and services.
The FERC has recently announced its intention to reexamine certain of its
transportation-related policies, including the appropriate manner for setting
rates for new interstate pipeline construction, the manner in which interstate
pipelines release transportation capacity under Order No. 636, and the use of
market-based rates for interstate gas transmission. While any resulting FERC
action would affect the Company only indirectly, these inquiries are intended to
further enhance competition in natural gas markets.
The Company's natural gas gathering operations may be or become subject to
safety and operational regulations relating to the design, installation,
testing, construction, operation, replacement, and management of facilities.
Pipeline safety issues have recently become the subject of increasing focus in
various political and administrative arenas at both the state and federal
levels. For example, federal legislation addressing pipeline safety issues was
considered last year, which, if enacted, would have included a federal
"one-call" notification system and certain new facilities specifications
applicable to certain new construction. Similar "one call" legislation has been
reintroduced in the U.S. Congress. The Company cannot predict what effect, if
any, the adoption of this or other additional pipeline safety legislation might
have on its operations, but does not believe that any adverse effect would be
material.
The Company cannot predict the effect that any of the aforementioned orders
or the challenges to such orders will ultimately have on the Company's
operations. Additional proposals and proceedings that might affect the natural
gas industry are pending before Congress, the FERC and the courts. The Company
cannot predict when or whether any such proposals or proceedings may become
effective. It should also be noted that the natural gas industry historically
has been very heavily regulated; therefore, there is no assurance that the less
regulated approach currently being pursued by the FERC will continue
indefinitely. Thus, the Company cannot predict the ultimate outcome or
durability of the unbundled regulatory regime mandated by Order No. 636.
ENVIRONMENTAL REGULATION. Various federal, state and local laws and
regulations covering the discharge of materials into the environment, or
otherwise relating to the protection of the environment, may affect the
Company's operations and costs as a result of their effect on natural gas and
crude oil exploration, development and production operations. It is not
anticipated that the Company will be required in the near future to expend
amounts that are material in relation to its total exploration and development
expenditure program by reason of environmental laws and regulations, but
inasmuch as such laws and regulations are frequently changed, the Company is
unable to predict the ultimate cost of compliance.
CANADIAN REGULATION. In Canada, the petroleum industry operates under
Federal, provincial and municipal legislation and regulations governing land
tenure, royalties, production rates, pricing, environmental protection, exports
and other matters. The price of natural gas and crude oil in Canada has been
deregulated and is now determined by market conditions and negotiations between
buyers and sellers.
10
Various matters relating to the transportation and export of natural gas
continue to be subject to regulation by both provincial and Federal agencies;
however, the North American Free Trade Agreement has reduced the risk of
altering cross-border commercial transactions.
Canadian governmental regulations may have a material effect on the economic
parameters for engaging in oil and gas activities in Canada and may have a
material effect on the advisability of investments in Canadian oil and gas
drilling activities. The Company is monitoring political, regulatory and
economic developments in Canada.
INTERNATIONAL REGULATION. The Company's exploration and production
operations outside North America are subject to various types of regulations
imposed by the respective governments of the countries in which the Company's
operations are conducted, and may affect the Company's operations and costs
within that country. The Company currently has operations offshore Trinidad and
India and exploration activities in other selected international areas.
RELATIONSHIP BETWEEN THE COMPANY AND ENRON CORP.
OWNERSHIP OF COMMON STOCK. Enron Corp. owns 80% of the outstanding shares
of common stock of the Company and, through its ability to elect all directors
of the Company, has the ability to control all matters relating to the
management of the Company, including any determination with respect to
acquisition or disposition of Company assets, future issuance of common stock
or other securities of the Company and any dividends payable on the common
stock. Enron Corp. also has the ability to control the Company's exploration,
development, acquisition and operating expenditure plans. If Enron Corp.
should sell a substantial amount of the common stock of the Company that it
owns, such action could adversely affect the prevailing market price for the
common stock and could impair the Company's ability to raise capital through
the sale of its equity securities. In addition, a sale by Enron Corp. of any
common stock owned by Enron Corp. would cause Enron Corp.'s ownership interest
in the Company to fall below 80% with the result that (i) the Company would
cease to be included in the consolidated federal income tax return filed by
Enron Corp. and (ii) the tax allocation agreement between the Company and
Enron Corp. described below would terminate. The Company has granted certain
registration rights to Enron Corp. with respect to the common stock owned by
Enron Corp. (See "Contractual Arrangements" below). There is no agreement
between Enron Corp. and the Company that would prevent Enron Corp. from
acquiring additional shares of common stock of the Company.
CONTRACTUAL ARRANGEMENTS. The Company entered into a Services Agreement (the
"Services Agreement") with Enron Corp. effective January 1994, pursuant to which
Enron Corp. provides various services, such as maintenance of certain employee
benefit plans, provision of telecommunications and computer services, lease of
office space and the provision of purchasing and operating services and certain
other corporate staff and support services. Such services historically have been
supplied to the Company by Enron Corp., and the Services Agreement provides for
the further delivery of such services substantially identical in nature and
quality to those services previously provided. The Company has agreed to a fixed
rate for the rental of office space and to reimburse Enron Corp. for all other
direct costs incurred in rendering services to the Company under the contract
and to pay Enron Corp. for allocated indirect costs incurred in rendering such
services up to a maximum of $6.7 million for 1994, such cap to be increased in
subsequent years for inflation and certain changes in the Company's allocation
bases with any increase not to exceed 7.5% per year. The Services Agreement is
for an initial term of five years through December 1998 and will continue
thereafter until terminated by either party.
The Company is included in the consolidated federal income tax return filed
by Enron Corp. as the common parent for itself and its subsidiaries and
affiliated companies, excluding any foreign subsidiaries. Consistent therewith
and pursuant to a Tax Allocation Agreement (the "Tax Agreement") between the
Company, the Company's subsidiaries and Enron Corp., either Enron Corp. will pay
to the Company and each subsidiary an amount equal to the tax benefit realized
in the Enron Corp. consolidated federal income tax return resulting from the
utilization of the Company's or the
11
subsidiary's net operating losses and/or tax credits, or the Company and each
subsidiary will pay to Enron Corp. an amount equal to the federal income tax
computed on its separate taxable income less the tax benefits associated with
any net operating losses and/or tax credits generated by the Company or the
subsidiary which are utilized in the Enron Corp. consolidated return. Enron
Corp. will pay the Company and each subsidiary for the tax benefits associated
with their net operating losses and tax credits utilized in the Enron Corp.
consolidated return, provided that a tax benefit was realized except as
discussed in the following paragraph, even if such benefits could not have been
used by the Company or the subsidiary on a separately filed tax return.
The Company has entered into an agreement with Enron Corp. providing for the
Company to be paid for all realizable benefits associated with tight gas sand
federal income tax credits concurrent with tax reporting and settlement for the
periods in which they are generated. (See "Other Matters Tight Gas Sand Tax
Credits (Section 29) and Severance Tax Exemption").
The Tax Agreement applies to the Company and each of its subsidiaries for
all years in which the Company or any of its subsidiaries are or were included
in the Enron Corp. consolidated return.
To the extent a state or other taxing jurisdiction requires or permits a
consolidated, combined, or unitary tax return to be filed and such return
includes the Company or any of its subsidiaries, the principles expressed with
respect to consolidated federal income tax allocation shall apply.
Pursuant to the terms of a Stock Restriction and Registration Agreement with
Enron Corp., the Company has agreed that upon the request of Enron Corp. (or
certain assignees), the Company will register under the Securities Act of 1933
and applicable state securities laws the sale of the Company common stock owned
by Enron Corp. which Enron Corp. has requested to be registered. The Company's
obligation is subject to certain limitations relating to a minimum amount of
common stock required for registration, the timing of registration and other
similar matters. The Company is obligated to pay all expenses incidental to such
registration, excluding underwriters' discounts and commissions and certain
legal fees and expenses.
CONFLICTS OF INTEREST. The nature of the respective businesses of the
Company and Enron Corp. and its affiliates is such as to potentially give rise
to conflicts of interest between the two companies. Conflicts could arise, for
example, with respect to transactions involving purchases, sales and
transportation of natural gas and other business dealings between the Company
and Enron Corp. and its affiliates, potential acquisitions of businesses or oil
and gas properties, the issuance of additional shares of voting securities, the
election of directors or the payment of dividends by the Company.
Circumstances may also arise that would cause Enron Corp. to engage in the
exploration for and/or development and production of natural gas and crude oil
in competition with the Company. For example, opportunities might arise which
would require financial resources greater than those available to the Company,
which are located in areas or countries in which the Company does not intend to
operate or which involve properties that the Company would be unwilling to
acquire. Also, Enron Corp. might acquire a competing oil and gas business as
part of a larger acquisition. In addition, as part of Enron Corp.'s strategy of
securing supplies of natural gas or capital, Enron Corp. may from time to time
acquire producing properties or interests in entities owning producing
properties, and thereafter engage in exploration, development and production
activities with respect to such properties or indirectly engage in such
activities through such companies. Enron Corp. may also acquire interests in oil
and gas properties or companies in connection with its financing activities. For
example, in its financing activities Enron Corp. or an entity in which it has an
interest may make loans secured by oil and gas properties or securities of oil
and gas companies, may acquire production payments or may receive interests in
oil and gas properties as equity components of lending tranactions. As a result
of its lending activities, Enron Corp. may also acquire oil and gas properties
or companies upon foreclosure of secured loans or as part of a borrower's
rearrangement of its obligations. Such acquisition, exploration, development and
production activities may directly or indirectly compete with the Company's
business. Thus, there can be no assurances that Enron Corp. will not engage
directly or indirectly through entities other than the Company, in the natural
gas and crude oil exploration, development and production business in
competition with the Company.
12
The Company and Enron Corp. and its affiliates have in the past entered into
significant intercompany transactions and agreements incident to their
respective businesses, and the Company and Enron Corp. and its affiliates may be
expected to enter into material transactions and agreements from time to time in
the future. Such transactions and agreements have related to, among other
things, the purchase and sale of natural gas, the financing of exploration and
development efforts by the Company, and the provision of certain corporate
services. (See "Marketing" and the Consolidated Financial Statements and notes
thereto). The Company believes that its existing transactions and agreements
with Enron Corp. and its affiliates have been at least as favorable to the
Company as could be obtained from third parties, and the Company intends that
the terms of any future transactions and agreements between the Company and
Enron Corp. and its affiliates will be at least as favorable to the Company as
could be obtained from third parties.
OTHER MATTERS
ENERGY PRICES. Since the Company is primarily a natural gas company, it is
more significantly impacted by changes in natural gas prices than in the prices
for crude oil, condensate and natural gas liquids. During recent periods,
domestic natural gas has been priced significantly below parity with crude oil,
condensate and natural gas liquids based on the energy equivalency of, and
differences in transportation and processing costs associated with, the
respective products. This imbalance in parity has been primarily driven by,
among other things, a supply of domestic natural gas volumes in excess of demand
requirements. The Company is unable to predict when this supply imbalance may
resolve due to the significant impacts of factors such as general economic
conditions, technology developments, weather and other international energy
supplies over which the Company has no control.
Average North America wellhead natural gas prices have fluctuated, at times
rather dramatically, during the last three years. While these fluctuations
resulted in increases in average wellhead natural gas prices realized by the
Company of 15% from 1991 to 1992 and 22% from 1992 to 1993, the average North
America natural gas price received by the Company decreased 13% from 1993 to
1994. Wellhead natural gas volumes from Trinidad are sold at prices that are
based on a fixed schedule of periodic escalations. While natural gas deliveries
in India are not expected to commence until 1996, the price of such deliveries,
when initiated, will be indexed to a basket of world market fuel oil quotations
structured to include floor and ceiling limits. Due to the many uncertainties
associated with the world political environment, the availabilities of other
world wide energy supplies and the relative competitive relationships of the
various energy sources in the view of the consumers, the Company is unable to
predict what changes may occur in natural gas prices in the future.
Substantially all of the Company's wellhead crude oil and condensate is sold
under short-term contracts at market responsive prices. Crude oil and condensate
prices also have fluctuated, at times rather dramatically, during the last three
years. These fluctuations have resulted in an overall decline in average
wellhead crude and condensate prices realized by the Company of 5% from 1991 to
1992, 9% from 1992 to 1993 and 5% from 1993 to 1994. Due to the many
uncertainties associated with the world political environment, the
availabilities of other world wide energy supplies and the relative competitive
relationships of the various energy sources in the view of the consumers, the
Company is unable to predict what changes may occur in crude oil and condensate
prices in the future.
To mitigate the risk of market price fluctuations, the Company engages in
certain price risk management activities to hedge commodity prices associated
with the sales and purchases of natural gas and crude oil.
TIGHT GAS SAND TAX CREDITS (SECTION 29) AND SEVERANCE TAX EXEMPTION. Federal
United States tax law provides a tax credit for production of certain fuels
produced from nonconventional sources (including natural gas produced from tight
formations), subject to a number of limitations. Fuels qualifying for the credit
must be produced from a well drilled or a facility placed in service before
January 1, 1993, and must be sold before January 1, 2003.
The credit, which is currently approximately $.52 per MMBtu of natural gas,
is computed by reference to the price of crude oil, and is phased out as the
price of crude oil exceeds $23.50 in 1980 dollars (adjusted for inflation) with
complete phaseout if such price exceeds $29.50 in 1980 dollars
13
(similarly adjusted). Under this formula, the commencement of phaseout would be
triggered if the average price for crude oil rose above approximately $44 per
barrel in current dollars. Significant benefits from the tax credit are accruing
to the Company since a portion (and in some cases a substantial portion) of the
Company's natural gas production from new wells drilled after November 5, 1990,
and before January 1, 1993, on the Company's leases in several of the Company's
significant producing areas qualify for this tax credit.
Certain natural gas production from wells spudded or completed after May 24,
1989 and before September 1, 1996 in tight formations in Texas qualifies for a
ten-year exemption, ending August 31, 2001, from Texas severance taxes, subject
to certain limitations.
OTHER. All of the Company's oil and gas activities are subject to the risks
normally incident to the exploration for and development and production of
natural gas and crude oil, including blowouts, cratering and fires, each of
which could result in damage to life and property. Offshore operations are
subject to usual marine perils, including hurricanes and other adverse weather
conditions, and governmental regulations as well as interruption or termination
by governmental authorities based on environmental and other considerations. In
accordance with customary industry practices, insurance is maintained by the
Company against some, but not all, of the risks. Losses and liabilities arising
from such events could reduce revenues and increase costs to the Company to the
extent not covered by insurance.
The Company's operations outside of North America are subject to certain
risks, including expropriation of assets, risks of increases in taxes and
government royalties, renegotiation of contracts with foreign governments,
political instability, payment delays, limits on allowable levels of production
and current exchange and repatriation losses, as well as changes in laws,
regulations and policies governing operations of foreign companies generally.
CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT
The current executive officers of the Company and their names and ages are
as follows:
NAME AGE POSITION
---- --- --------
Forrest E. Hoglund................. 61 Chairman of the Board, President and
Chief Executive Officer; Director
Joe Michael McKinney............... 55 President-International Operations
Mark G. Papa....................... 48 President-North American Operations
George E. Uthlaut.................. 61 Senior Vice President-Operations
Walter C. Wilson................... 52 Senior Vice President and Chief
Financial Officer
Ben B. Boyd........................ 53 Vice President and Controller
Dennis M. Ulak..................... 41 Vice President and General Counsel
Forrest E. Hoglund joined the Company as Chairman of the Board, Chief
Executive Officer and Director in September 1987. Since May 1990, he has also
served as President of the Company. Mr. Hoglund was a director of USX
Corporation from February 1986 until September 1987. He joined Texas Oil & Gas
Corp. ("TXO") in 1977 as president, was named Chief Operating Officer in 1979,
Chief Executive Officer in 1982, and served TXO in those capacities until
September 1987. Mr. Hoglund is also a director of Texas Commerce Bancshares,
Inc.
Joe Michael McKinney has been President-International Operations since
February 1994 with responsibilities for all exploration, drilling, production
and engineering activities for the Company's international ventures outside
North America. Mr. McKinney joined Enron Oil & Gas International, Inc., a
wholly-owned subsidiary of the Company, in December 1991 as Senior Vice
President of Operations and was elected President and Chief Operating Officer of
Enron Oil & Gas International, Inc. in April 1993, a capacity in which he
continues to serve. Prior to joining the Company, Mr. McKinney held operations
management positions with Union Texas Petroleum Company, The Superior Oil
Company and Exxon Company, USA.
14
Mark G. Papa has been President-North American Operations since February
1994. From May 1986 through January 1994, Mr. Papa served as Senior Vice
President-Operations. Mr. Papa joined Belco Petroleum Corporation, a
predecessor of the Company, in 1981 as Division Production Coordinator and
served as Senior Vice President-Drilling and Production, BelNorth Petroleum
Corporation from May 1984 until May 1986.
George E. Uthlaut has been Senior Vice President-Operations of the Company
since November 1987. Mr. Uthlaut was previously employed by Exxon Corporation
(and affiliates) for 29 years in a number of managerial and technical
positions. His last position was Headquarters Operations Manager, Production
Department, Exxon Company, USA.
Walter C. Wilson has been Senior Vice President and Chief Financial Officer
since May 1991. Mr. Wilson joined the Company in November 1987 as Vice President
and Controller and was named Senior Vice President-Finance in October 1988.
Prior to joining the Company Mr. Wilson held financial management positions with
Exxon Company, USA for 16 years and The Superior Oil Company for 4 years.
Ben B. Boyd has been Vice President and Controller since March 1991. Mr.
Boyd joined the Company in March 1989 as Director of Accounting and was named
Controller in May 1990. Prior to joining the Company, Mr. Boyd held financial
management positions with DeNovo Oil & Gas, Inc., Scurlock Oil Company and
Coopers & Lybrand.
Dennis M. Ulak has been Vice President and General Counsel since March
1992. Mr. Ulak joined the Company in March 1987 as Senior Counsel and was
named Assistant General Counsel in August 1990. Prior to joining the Company,
Mr. Ulak held various legal positions with Enron Corp. and Northern Natural
Gas Company.
ITEM 2. PROPERTIES
OIL AND GAS EXPLORATION AND PRODUCTION PROPERTIES AND RESERVES
RESERVE INFORMATION. For estimates of the Company's net proved and proved
developed reserves of natural gas and liquids, including crude oil, condensate
and natural gas liquids, see "Supplemental Information to Consolidated
Financial Statements."
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the producer. The
reserve data set forth in Supplemental Information to Consolidated Financial
Statements represent only estimates. Reserve engineering is a subjective process
of estimating underground accumulations of natural gas and liquids, including
crude oil, condensate and natural gas liquids, that cannot be measured in an
exact manner. The accuracy of any reserve estimate is a function of the amount
and quality of available data and of engineering and geological interpretation
and judgment. As a result, estimates of different engineers normally vary. In
addition, results of drilling, testing and production subsequent to the date of
an estimate may justify revision of such estimate. Accordingly, reserve
estimates are often different from the quantities ultimately recovered. The
meaningfulness of such estimates is highly dependent upon the accuracy of the
assumptions upon which they were based.
In general, the volume of production from oil and gas properties owned by
the Company declines as reserves are depleted. Except to the extent the Company
acquires additional properties containing proved reserves or conducts successful
exploration and development activities, or both, the proved reserves of the
Company will decline as reserves are produced. Volumes generated from future
activities of the Company are therefore highly dependent upon the level of
success in acquiring or finding additional reserves and the costs incurred in
doing so.
The Company's estimates of reserves filed with other federal agencies agree
with the information set forth in Supplemental Information to Consolidated
Financial Statements.
15
ACREAGE. The following table summarizes the Company's developed and
undeveloped acreage at December 31, 1994. Excluded is acreage in which the
Company's interest is limited to owned royalty, overriding royalty and other
similar interests.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
------------------------ ---------------------------- ----------------------------
GROSS NET GROSS NET GROSS NET
------------ ---------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C>
United States
California....................... 1,142 935 683,350 633,424 684,492 634,359
Texas............................ 345,558 265,039 234,057 218,862 579,615 483,901
Federal Offshore................. 195,009 94,960 424,823 388,236 619,832 483,196
Wyoming.......................... 160,364 113,540 312,323 234,423 472,687 347,963
Oklahoma......................... 104,844 59,502 69,664 62,434 174,508 121,936
Utah............................. 59,620 48,085 36,525 31,187 96,145 79,272
New Mexico....................... 81,416 36,852 67,460 35,563 148,876 72,415
Kansas........................... 12,215 11,482 35,892 33,729 48,107 45,211
Michigan......................... 11 10 34,810 34,810 34,821 34,820
Colorado......................... 10,111 1,490 34,037 16,674 44,148 18,164
Mississippi...................... 1,942 1,853 10,100 9,262 12,042 11,115
Montana.......................... 1,301 1,169 6,689 4,961 7,990 6,130
Other............................ 4,894 2,953 2,926 2,151 7,820 5,104
------------ ---------- ------------- ------------- ------------- -------------
Total........................ 978,427 637,870 1,952,656 1,705,716 2,931,083 2,343,586
Canada
Alberta.......................... 330,932 152,360 228,043 148,731 558,975 301,091
Saskatchewan..................... 158,870 145,891 207,660 202,999 366,530 348,890
Manitoba......................... 11,531 9,581 1,820 1,820 13,351 11,401
British Columbia................. 656 164 - - 656 164
------------ ---------- ------------- ------------- ------------- -------------
Total Canada................. 501,989 307,996 437,523 353,550 939,512 661,546
Other International
Australia........................ - - 9,600,000 9,600,000 9,600,000 9,600,000
China............................ - - 1,700,000 850,000 1,700,000 850,000
Russia........................... - - 1,425,000 712,500 1,425,000 712,500
France........................... - - 1,015,000 507,500 1,015,000 507,500
India 60,000 18,000 602,207 180,662 662,207 198,662
Trinidad......................... 4,200 3,990 74,851 71,108 79,051 75,098
United Kingdom................... - - 173,600 86,800 173,600 86,800
------------ ---------- ------------- ------------- ------------- -------------
Total Other International.... 64,200 21,990 14,590,658 12,008,570 14,654,858 12,030,560
------------ ---------- ------------- ------------- ------------- -------------
Total.................... 1,544,616 967,856 16,980,837 14,067,836 18,525,453 15,035,692
============ ========== ============= ============= ============= =============
</TABLE>
PRODUCING WELL SUMMARY. The following table reflects the Company's ownership
in gas wells in 390 fields and oil wells in 87 fields located in Texas, offshore
Texas and Louisiana in the Gulf of Mexico, Oklahoma, New Mexico, Utah, Wyoming,
and various other states, Canada, Trinidad and India at December 31, 1994. Gross
oil and gas wells include 188 with multiple completions.
PRODUCTIVE WELLS
---------------------
GROSS NET
------ ------
Gas.................................. 4,501 3,246
Oil.................................. 933 564
------ ------
Total............................ 5,434 3,810
====== ======
16
DRILLING AND ACQUISITION ACTIVITIES. During the years ended December 31,
1994, 1993 and 1992 the Company spent approximately $493.9, $430.1 and $395.7
million, respectively, for exploratory and development drilling and acquisition
of leases and producing properties. The Company drilled, participated in the
drilling of or acquired wells as set out in the table below for the periods
indicated:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------
1994 1993 1992
----------------- ----------------- -----------------
GROSS NET GROSS NET GROSS NET
----- ------- ----- ------- ----- -------
<S> <C> <C> <C> <C> <C> <C>
Development Wells Completed
Domestic
Gas.......................... 308 244.23 352 279.00 484 399.06
Oil.......................... 34 29.57 45 19.01 19 10.80
Dry.......................... 41 32.15 59 46.83 64 56.12
----- ------- ----- ------- ----- -------
Total...................... 383 305.95 456 344.84 567 465.98
International
Gas.......................... 250 190.30 227 190.10 2 2.00
Oil.......................... 11 5.10 4 3.50 13 11.70
Dry.......................... 13 11.50 11 7.60 5 4.05
----- ------- ----- ------- ----- -------
Total...................... 274 206.90 242 201.20 20 17.75
----- ------- ----- ------- ----- -------
Total Development................ 657 512.85 698 546.04 587 483.73
----- ------- ----- ------- ----- -------
Exploratory Wells Completed
Domestic
Gas.......................... 13 9.80 14 10.03 11 8.72
Oil.......................... 3 2.57 3 2.50 1 .40
Dry.......................... 23 18.17 32 22.08 16 13.42
----- ------- ----- ------- ----- -------
Total...................... 39 30.54 49 34.61 28 22.54
International
Gas.......................... 9 7.90 14 11.40 7 5.75
Oil.......................... 1 .50 2 .90 4 3.69
Dry.......................... 14 12.50 10 7.35 4 2.85
----- ------- ----- ------- ----- -------
Total...................... 24 20.90 26 19.65 15 12.29
----- ------- ----- ------- ----- -------
Total Exploratory................ 63 51.44 75 54.26 43 34.83
----- ------- ----- ------- ----- -------
Total...................... 720 564.29 773 600.30 630 518.56
Wells in Progress at end of period... 45 28.79 82 61.09 82 60.75
----- ------- ----- ------- ----- -------
Total...................... 765 593.08 855 661.39 712 579.31
===== ======= ===== ======= ===== =======
Wells Acquired
Gas.............................. 41 40.90* 44 26.44* 641 597.29*
Oil.............................. 60 38.99* - 12.80* 28 25.80*
----- ------- ----- ------- ----- -------
Total...................... 101 79.89 44 39.24 669 623.09
===== ======= ===== ======= ===== =======
- ---------
* Includes the acquisition of additional interests in certain wells in which
the Company previously held an interest.
</TABLE>
All of the Company's drilling activities are conducted on a contract basis
with independent drilling contractors. The Company owns no drilling equipment.
17
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries and related companies are named defendants
in numerous lawsuits and named parties in numerous governmental proceedings
arising in the ordinary course of business. While the outcome of lawsuits or
other proceedings against the Company cannot be predicted with certainty,
management does not expect these matters to have a material adverse effect on
the financial condition or results of operations of the Company. TransAmerican
Natural Gas Corporation ("TransAmerican") has filed a petition against the
Company and Enron Corp. alleging breach of contract, tortious interference with
contract, misappropriation of trade secrets and violation of state antitrust
laws. The petition, as amended, seeks actual damages of $100 million plus
exemplary damages of $300 million. The Company has answered the petition and is
actively defending the matter; in addition, the Company has filed counterclaims
against TransAmerican and a third-party claim against its sole shareholder, John
R. Stanley, alleging fraud, negligent misrepresentation and breach of state
antitrust laws. On April 6, 1994, Enron Corp. was granted summary judgement,
wherein the court ordered that TransAmerican can take nothing on its claims
against Enron Corp. Trial, which was set most recently for September 12, 1994
has been continued, and there is no current setting. Although no assurances can
be given, the Company believes that the claims made by TransAmerican are totally
without merit, that the ultimate resolution of the matter will not have a
materially adverse effect on its financial condition or results of operations,
and that such ultimate resolution could result in a recovery to the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
fourth quarter of 1994.
18
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS
The following table sets forth, for the periods indicated, the high and low
sale prices per share for the common stock of the Company, as reported on the
New York Stock Exchange Composite Tape, and the amount of cash dividends paid
per share. The 1992, 1993, and First Quarter and Second Quarter 1994 sales
prices and cash dividends per share have been restated to reflect the
two-for-one stock split declared in May 1994 by the Board of Directors. Shares
were issued on June 15, 1994 to shareholders of record as of May 31, 1994.
PRICE RANGE
-------------------- CASH
HIGH LOW DIVIDENDS
--------- --------- ---------
1992
First Quarter.................... 10.94 8.31 .025
Second Quarter................... 13.63 10.25 .025
Third Quarter.................... 17.94 12.69 .025
Fourth Quarter................... 17.19 13.75 .025
1993
First Quarter.................... 20.31 13.38 .030
Second Quarter................... 22.50 17.88 .030
Third Quarter.................... 26.81 19.88 .030
Fourth Quarter................... 27.00 17.06 .030
1994
First Quarter.................... 23.75 19.31 .030
Second Quarter................... 24.63 22.38 .030
Third Quarter.................... 23.00 18.50 .030
Fourth Quarter................... 22.75 17.38 .030
As of March 2, 1995, there were approximately 291 record holders of the
Company's common stock, including individual participants in security position
listings. There are an estimated 5,600 beneficial owners of the Company's common
stock, including shares held in street name.
Following the initial public offering and sale of its common stock in
October 1989, the Company paid quarterly dividends of $0.025 per share beginning
with an initial dividend paid in January 1990 with respect to the fourth quarter
of 1989. Beginning in January 1993 with respect to the fourth quarter of 1992,
the Company has paid quarterly dividends of $0.03 per share. The Company
currently intends to continue to pay quarterly cash dividends on its outstanding
shares of common stock. However, the determination of the amount of future cash
dividends, if any, to be declared and paid will depend upon, among other things,
the financial condition, funds from operations, level of exploration and
development expenditure opportunities and future business prospects of the
Company.
19
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------
1994 1993 1992 1991 1990
------------- ------------- ------------- ------------- -------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
STATEMENT OF INCOME DATA:
Net operating revenues............... $ 625,823 $ 581,020 $ 459,026 $ 402,588 $ 403,137
Operating expenses
Lease and well................... 60,384 59,344 49,406 49,922 43,806
Exploration...................... 41,811 36,921 33,278 31,470 35,031
Dry hole......................... 17,197 18,355 10,764 14,698 12,986
Impairment of unproved oil and
gas properties................. 24,936 20,467 15,136 12,791 20,571
Depreciation, depletion and
amortization................... 242,182 249,704 179,839 160,885 155,877
General and administrative....... 51,418 45,274 36,648 36,216 38,254
Taxes other than income.......... 28,254 35,396 28,346 18,222 22,966
------------- ------------- ------------- ------------- -------------
Total........................ 466,182 465,461 353,417 324,204 329,491
------------- ------------- ------------- ------------- -------------
Operating income..................... 159,641 115,559 105,609 78,384 73,646
Other income (expense)............... 2,783 6,635 (3,476) (3,215) (2,153)
Interest expense (net of interest
capitalized)....................... 8,489 9,921 22,289 29,500 36,879
------------- ------------- ------------- ------------- -------------
Income before income taxes........... 153,935 112,273 79,844 45,669 34,614
Income tax provision (benefit)<F1>... 5,937<F2> (25,752)<F3> (17,736) (2,247) (10,854)
------------- ------------- ------------- ------------- -------------
Net income........................... $ 147,998 $ 138,025 $ 97,580 $ 47,916 $ 45,468
============= ============= ============= ============= =============
Earnings per share of common
stock<F4>.......................... $ .93 $ .86 $ .63 $ .32 $ .30
============= ============= ============= ============= =============
Average number of common
shares<F4>......................... 159,845 159,966 154,533 151,800 151,800
============= ============= ============= ============= =============
AT DECEMBER 31,
-------------------------------------------------------------------------
1994 1993 1992 1991 1990
------------- ------------- ------------- ------------- -------------
(IN THOUSANDS)
BALANCE SHEET DATA:
Oil and gas properties - net......... $ 1,684,811 $ 1,546,045 $ 1,468,011 $ 1,339,666 $ 1,305,136
Total assets......................... 1,861,867 1,811,162 1,731,012 1,455,608 1,417,939
Long-term debt
Affiliate.......................... 25,000 - - <F5> 132,836 277,918
Other.............................. 165,337 153,000 150,000<F5> 289,556 140,442
Shareholders' equity................. 1,043,419 933,073 826,986<F5> 643,185 610,042
- ---------
<FN>
<F1> Includes benefits of approximately $36 million, $65 million, $43 million
and $17 million in 1994, 1993, 1992 and 1991, respectively, relating to
tight gas sand federal income tax credits and $7 million and $25 million
in 1991 and 1990, respectively, associated with the utilization of a net
operating loss carryforward.
<F2> Includes a benefit of approximately $8 million related to reduced
estimated state income taxes and certain franchise taxes, a portion of
which is treated as income tax under Statement of Financial Accounting
Standards (SFAS) No. 109 - "Accounting for Income Taxes", and a $5 million
benefit from the reduction of the Company's deferred federal income tax
liability resulting from a reevaluation of deferred tax requirements.
<F3> Includes a benefit of $12 million from the reduction of the Company's
deferred federal income tax liability resulting from a reevaluation of
deferred tax requirements partially offset by an approximate $7 million
predominantly non-cash charge primarily to adjust the Company's
accumulated deferred federal income tax liability for the increase in the
corporate federal income tax rate from 34% to 35%.
20
<F4> In May 1994, the Board of Directors declared a two-for-one split of the
Company's common stock to be effected as a non-taxable dividend of one
share for each share outstanding. Shares were issued on June 15, 1994 to
shareholders of record as of May 31, 1994. All per share amounts presented
herein are reflected on a post-split basis.
<F5> In August 1992, the Company completed the sale of an additional 8.2
million shares of common stock resulting in aggregate net proceeds to the
Company of approximately $112 million used primarily to repay long-term
debt. In September 1992, the Company completed the sale of a volumetric
production payment, resulting in net proceeds of approximately $327
million used to repay long-term debt and for other general corporate
purposes.
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following review of operations for each of the three years in the period
ended December 31, 1994 should be read in conjunction with the consolidated
financial statements of the Company and notes thereto beginning with page F-1.
RESULTS OF OPERATIONS
NET OPERATING REVENUES. Volume and price statistics for the specified
years were as follows:
YEAR ENDED DECEMBER 31,
-------------------------------
1994 1993 1992
--------- --------- ---------
Wellhead Volumes
Natural Gas (MMcf per day)(1).... 749 709 564
Crude Oil and Condensate (MBbl
per day)....................... 12.6 8.9 8.5
Natural Gas Liquids (MBbl per
day)........................... 0.7 0.6 0.7
Wellhead Average Prices
Natural Gas ($/Mcf)(2)........... $ 1.62 $ 1.92 $ 1.58
Crude Oil and Condensate
($/Bbl)........................ 15.62 16.37 17.90
Natural Gas Liquids ($/Bbl)...... 9.90 11.12 10.69
Other Natural Gas Marketing
Volumes (MMcf per day)(1)........ 324 293 255
Average Gross Revenue
($/Mcf)(3)..................... $ 2.38 $ 2.57 $ 2.62
Associated Costs
($/Mcf) (4)(5)................. 2.06 2.32 1.99
--------- --------- ---------
Margin ($/Mcf)................... $ 0.32 $ 0.25 $ 0.63
========= ========= =========
- ---------
(1) Includes 48 MMcf per day in 1994, 81 MMcf per day in 1993 and 28 MMcf per
day in 1992 delivered under the terms of volumetric production payment and
exchange agreements effective October 1, 1992, as amended.
(2) Includes an average equivalent wellhead value of $1.27 per Mcf in 1994,
$1.57 per Mcf in 1993 and $1.70 per Mcf in 1992 for the volumes detailed
in note (1), net of transportation costs.
(3) Includes per unit deferred revenue amortization for the volumes detailed
in note (1) at an equivalent of $2.46 per Mcf ($2.36 per million British
thermal units) in 1994, $2.50 per Mcf ($2.40 per million British thermal
units) in 1993 and $2.51 per Mcf ($2.40 per million British thermal units)
in 1992.
(4) Includes an average value of $1.92 per Mcf in 1994, $2.20 per Mcf in 1993
and $2.37 per Mcf in 1992, including average equivalent wellhead value,
any applicable transportation costs and exchange differentials, for the
volumes detailed in note (1).
(5) Including transportation and exchange differentials.
21
During 1994, net operating revenues increased to $626 million, up $45
million as compared to 1993.
Average wellhead natural gas volumes increased approximately 6% compared to
1993 primarily reflecting the effects of development activities in Trinidad and
Canada partially offset by voluntary curtailments of production in the United
States in 1994. The volume reductions in the United States as a result of
voluntary curtailments were more than offset by the new natural gas deliveries
from the Kiskadee field offshore Trinidad and increased deliveries in Canada.
The increase in wellhead natural gas volumes added $28 million to net operating
revenues. Average wellhead natural gas prices were down significantly from 1993
reducing net operating revenues by approximately $83 million. This 16% reduction
in average wellhead natural gas prices reflects the overall decline in the
United States natural gas markets during the last half of 1994 and increased
volumes from Trinidad sold under a long-term contract at a price considerably
below North American spot market prices. A 42% increase in wellhead crude oil
and condensate volumes over 1993 added $22 million to net operating revenues
primarily reflecting development activities in Trinidad and increased production
in the United States. A 5% decrease in wellhead crude oil and condensate average
prices decreased net operating revenues by approximately $3 million.
Other marketing activities associated with sales and purchases of natural
gas, natural gas and crude oil price swap transactions, other commodity price
hedging of natural gas and crude oil prices utilizing NYMEX-related commodity
market transactions, and margins relating to the volumetric production payment
added $50 million to net operating revenues during 1994. This increase of $42
million from the same period in 1993 primarily results from a gain of $11
million on natural gas commodity price hedging activities utilizing
NYMEX-related commodity market transactions in 1994 versus an $18 million loss
during 1993 and increased margins associated with other natural gas marketing
activities. The average associated costs of natural gas marketing, price swap
and volumetric production payment transactions, including, where appropriate,
average wellhead value, transportation costs and exchange differentials,
decreased $.26 per Mcf. The average price received for these transactions
decreased $.19 per Mcf. Related other natural gas marketing volumes increased
10%.
The impact of these other marketing activities, a substantial portion of
which serve as hedges of commodity price risks for a portion of wellhead
deliveries, are more than offset by increases or reductions in revenues
associated with market responsive prices for wellhead deliveries. (See Note 2 to
Consolidated Financial Statements.)
Gains on sales of selected oil and gas reserves and related assets were $54
million in 1994 as compared to $13 million in 1993. While the quantity of
equivalent reserves sold in 1994 was slightly less than 1993, higher average
proceeds received per equivalent unit in 1994 as compared to 1993 primarily
contributed to the increased gain recognition. In continuing its strategy of
fully utilizing its assets in optimizing profitability, cash flow and return on
investments, the Company expects to continue the sale of similar properties from
time to time.
During 1993, net operating revenues increased to $581 million, up $122
million as compared to 1992.
Average wellhead natural gas volumes increased approximately 26% compared to
1992 primarily reflecting the effects of exploration and development activities
relating to tight gas sand formations. Wellhead natural gas delivered volumes
were curtailed less during portions of 1993 than for the comparable periods in
1992 due to the significant increases realized in wellhead natural gas prices in
1993. Average wellhead natural gas prices were up approximately 22% in 1993 over
those received in 1992, adding approximately $87 million to net operating
revenues. Increases in wellhead natural gas volumes in 1993 added $83 million to
net operating revenues compared to 1992. Average wellhead crude oil and
condensate prices in 1993 were down 9% compared to 1992, reducing net operating
revenues by $5 million. Increases in wellhead crude oil and condensate volumes
in 1993 added approximately $2 million to net operating revenues compared to
1992.
22
Other marketing activities associated with sales and purchases of natural
gas, natural gas price swap transactions, other commodity price hedging of
natural gas and crude oil and condensate prices utilizing NYMEX-related
commodity market transactions, and margins relating to the volumetric production
payment added $8 million to net operating revenues during 1993. This decrease of
$54 million from 1992 primarily results from shrinking margins associated with
sales under long-term fixed price contracts and amortization of volumetric
production payment deferred revenue due to increases in market responsive
natural gas prices associated with volumes supplying these dispositions and
losses on natural gas commodity price hedging activities utilizing NYMEX-related
commodity market transactions. The average associated costs of natural gas
marketing, price swap and volumetric production payment transactions, including,
where appropriate, average wellhead value, transportation costs and exchange
differentials, increased $.33 per Mcf. Related other natural gas marketing
volumes increased 15%.
OPERATING EXPENSES. During 1994, total operating expenses of $466 million
were approximately $1 million higher than the $465 million incurred in 1993.
Lease and well expenses of $60 million were approximately $1 million higher than
last year primarily due to increased expenses related to new operations offshore
Trinidad partially offset by cost reductions in North America. Exploration
expenses of $42 million increased $5 million from the previous year primarily
due to an increased level of exploration activities. Impairment of unproved oil
and gas properties increased $4 million from 1993 primarily due to impairments
associated with certain offshore Gulf of Mexico leases. Depreciation, depletion
and amortization ("DD&A") expense decreased from $250 million in 1993 to $242
million in 1994 reflecting a $.09 per Mcfe decrease in the average DD&A rate to
$.80 per Mcfe. The rate decrease is primarily due to increased production from
offshore Trinidad at an average DD&A rate significantly less than the North
American operations DD&A rate and a $.03 per Mcfe reduction in the North
American operations DD&A rate. General and administrative expenses increased $6
million to $51 million primarily due to overall higher costs associated with
expanded international and domestic operations. Taxes other than income
decreased approximately $7 million from 1993 primarily due to lower taxable
United States wellhead volumes and prices and reductions included in 1994
related to revisions of certain prior year production taxes. Included in 1994
and 1993 are benefits associated with reductions in state franchise taxes of $4
million and $3 million, respectively. The Company continues to benefit from
certain state severance tax exemptions allowed on high cost natural gas volumes.
Total per unit operating costs for lease and well expense, DD&A, general and
administrative expense, interest expense, and taxes other than income decreased
$.14 per Mcfe, averaging $1.29 per Mcfe during 1994 compared to $1.43 per Mcfe
for 1993. The decrease was primarily due to per unit reductions in DD&A and
taxes other than income as discussed above.
During 1993, total operating expenses of $465 million were $112 million
higher than the $353 million incurred in 1992. Lease and well expenses increased
approximately $10 million primarily due to expanded domestic and international
operations. Exploration expenses increased approximately $4 million primarily
due to increased exploration activities in North America. An unsuccessful Gulf
of Mexico well added nearly $4 million to dry hole expenses and a related $3
million to lease impairments in 1993. Dry hole expenses also reflect the impact
of increased drilling activity outside North America. DD&A expense increased $70
million to $250 million reflecting an increase in production volumes and an
average DD&A rate increase from $.79 per Mcfe in 1992 to $.89 per Mcfe for 1993.
The DD&A rate increase is primarily due, as expected, to factors associated with
the tight gas sands drilling program which costs are being more than offset by
benefits realized in the form of tight gas sand federal income tax credits and
certain state severance tax exemptions. General and administrative expenses
increased almost $9 million to $45 million primarily reflecting cost reductions
included in 1992 related to changes associated with certain employee
compensation plans and overall higher costs in 1993 due to an expansion of
domestic and international operations. Taxes other than income increased $7
million primarily due to increased production volumes and revenues in 1993,
partially offset by continuing benefits associated with certain state severance
tax
23
exemptions allowed on high cost natural gas volumes and a $3 million reduction
of state franchise taxes resulting from refunds of prior year payments received
in 1993.
Total per unit operating costs for lease and well expense, DD&A, general and
administrative expense, interest expense, and taxes other than income increased
$.03 per Mcfe, averaging $1.43 per Mcfe during 1993 compared to $1.40 per Mcfe
for 1992. The total increase was associated with DD&A expense which was up $.10
per Mcfe as noted above being partially offset by a reduction of $.07 Mcfe in
all other costs.
OTHER INCOME. Other income for 1993 includes $4 million in interest income
associated with the investment of funds temporarily surplus to the Company (See
Note 4 to Consolidated Financial Statements) and $4 million associated with
settlements related to the termination of certain long-term
natural gas contracts.
INTEREST EXPENSE. Net interest expense in 1994 decreased approximately $1
million to $8 million as compared to 1993 primarily due to favorable interest
rates on new financing acquired by a subsidiary of the Company in Trinidad and
the retirement of higher interest rate debt. The estimated fair value of
outstanding interest rate swap agreements at December 31, 1994 was a negative
$0.5 million based on termination values obtained from third parties. (See Note
13 to Consolidated Financial Statements).
Net interest expense decreased $12 million, or 55%, to $10 million in 1993
as compared to 1992 reflecting the repayment of a substantial portion of the
Company's long-term debt in 1992 with proceeds from the sale of common stock in
August 1992 and the sale of a volumetric production payment in September 1992.
The estimated fair value of outstanding interest rate swap agreements at
December 31, 1993 was a negative $3.3 million based upon termination values
obtained from third parties.
INCOME TAXES. Income tax provision in 1994 includes a benefit of
approximately $36 million associated with tight gas sand federal income tax
credit utilization, a benefit of approximately $8 million related to reduced
estimated state income taxes and a portion of certain franchise taxes which is
treated as income tax under SFAS No. 109, and a $5 million benefit from the
reduction of the Company's deferred federal income tax liability resulting from
a reevaluation of deferred tax requirements.
Income tax benefit in 1993 includes a benefit of approximately $65 million
associated with tight gas sand federal income tax credit utilization, an
approximate $7 million predominantly one-time non-cash charge recorded in the
third quarter of 1993 primarily to adjust the Company's accumulated deferred
federal income tax liability for the increase in the corporate federal income
tax rate from 34% to 35% and a $12 million benefit from the reduction of the
Company's deferred federal income tax liability resulting from a reevaluation of
deferred tax requirements.
CAPITAL RESOURCES AND LIQUIDITY
CASH FLOW. The primary sources of cash for the Company during the three-year
period ended December 31, 1994 included funds generated from operations, the
sale of common stock, the sale of a volumetric production payment, proceeds from
the sale of selected oil and gas reserves and related assets and the issuance of
new debt. Primary cash outflows included funds used in operations, exploration
and development expenditures, dividends, and the repayment of debt.
Discretionary cash flow, a frequently used measure of performance for
exploration and production companies, is generally derived by adjusting net
income to eliminate the effects of depreciation, depletion and amortization,
impairment of unproved oil and gas properties, deferred taxes, gains on sales of
oil and gas reserves and related assets, certain other miscellaneous non-cash
amounts, except for amortization of deferred revenue, and exploration and dry
hole expenses. However, based on the continuing practice of the Company of
selling selected oil and gas reserves and related assets in furtherance of its
strategy of fully utilizing its assets in optimizing profitability, cash flow
and return on investments, it believes that net proceeds from these transactions
should also be considered as available discretionary cash flow and is so
presenting those values for 1994. Values for prior years have also been
reclassified for consistency. In the case of the Company, the elimination of
revenues
24
associated with the amortization of deferred revenues created by the sale by the
Company of a volumetric production payment is reflected in investing cash flows.
The Company generated discretionary cash flow of approximately $514 million in
1994, $521 million in 1993 and $346 million in 1992. The 1993 amount includes
$50 million associated with a federal income tax refund resulting from the
settlement of an audit of federal income taxes paid in prior years.
Net operating cash flows were approximately $426 million in 1994, $480
million in 1993 and $306 million in 1992. Decreased 1994 net operating cash
flows were primarily due to proceeds in 1993 from the receipt of a refund on
settlement of an audit of federal income taxes discussed above. Increased 1993
net operating cash flows were primarily due to increased net operating revenues
and a decrease in provision for current taxes resulting from both increased
tight gas sand federal income tax credit utilization and proceeds from the
receipt of a refund on settlement of an audit of federal income taxes paid in
prior years. In accordance with the requirements of SFAS No. 95 - "Statement of
Cash Flows", net proceeds from the sale of selected oil and gas reserves and
related assets are not included in the determination of cash from operations.
SALE OF SELECTED OIL AND GAS RESERVES AND RELATED ASSETS. During 1994, the
Company received proceeds of $91 million from the sale of selected oil and gas
reserves and related assets compared to $42 million received in 1993. While the
quantity of equivalent reserves sold in 1994 was slightly less than 1993, higher
average proceeds received per equivalent unit of reserves sold in 1994 as
compared to 1993 resulted in significantly higher 1994 proceeds. Taxable gains
resulting from the 1994 sales generated income taxes of $20 million, leaving net
proceeds of $71 million. Taxable gains resulting from the 1993 sales generated
federal income taxes of $8 million, leaving net proceeds of $34 million.
SALE OF VOLUMETRIC PRODUCTION PAYMENT. In September 1992, the Company sold a
volumetric production payment for $326.8 million to a limited partnership. (See
"Business - Marketing - Other Marketing" and Note 5 to Consolidated Financial
Statements). Under the terms of the production payment agreements, the Company
conveyed a real property interest in approximately 124 Bcfe (136 trillion
British thermal units) of certain natural gas and other hydrocarbons to the
purchaser. Effective October 1, 1993, the agreements were amended providing for
the extension of the original term of the volumetric production payment through
March 31, 1999 and including a revised schedule of daily quantities of
hydrocarbons to be delivered which is approximately one-half of the original
schedule. The revised schedule will total approximately 89.1 Bcfe (97.8 trillion
British thermal units) versus approximately 87.9 Bcfe (96.4 trillion British
thermal units) remaining to be delivered under the original agreement. Daily
quantities of hydrocarbons no longer required to be delivered under the revised
schedule during the period from October 1, 1993 through June 30, 1996 are
available for sale by the Company. The Company retains responsibility for its
working interest share of the cost of operations. In accordance with generally
accepted accounting principles, the Company accounted for the proceeds received
in the transaction as deferred revenue which is being amortized into revenue and
income as natural gas and other hydrocarbons are produced and delivered to the
purchaser during the term, as revised, of the volumetric production payment
thereby matching those revenues with the depreciation of asset values which
remained on the balance sheet following the sale and the operating expenses
incurred for which the Company retained responsibility. The Company expects the
above transaction, as amended, to have minimal impact on future earnings.
However, cash made available by the sale of the volumetric production payment
has provided considerable financial flexibility for the pursuit of investment
alternatives.
25
EXPLORATION AND DEVELOPMENT EXPENDITURES. The table below sets out
components of actual exploration and development expenditures for the years
ended December 31, 1994, 1993 and 1992, along with those budgeted for the year
1995.
ACTUAL
------------------------------- BUDGETED
EXPENDITURE CATEGORY 1994 1993 1992 1995
- -------------------- --------- --------- --------- -------
(IN MILLIONS)
Capital
Drilling and Facilities......... $ 342 $ 331 $ 260 $ 345
Leasehold Acquisitions.......... 52 29 23 25
Producing Property
Acquisitions.................. 34 9 65 15
Capitalized Interest and Other.. 14 14 14 15
--------- --------- --------- -------
Total....................... 442 383 362 400
Exploration Expenses................ 59 55 44 50
--------- --------- --------- -------
Total............................... $ 501 $ 438 $ 406 $ 450
========= ========= ========= =======
Exploration and development expenditures increased $63 million, or 14%, in
1994 compared to 1993. The increase primarily reflects the acquisitions of
selected properties to compliment existing North American producing areas and
the addition of new international activities in India. (See "Business -
Exploration and Production" for additional information detailing the specific
geographic locations of the Company's drilling programs and "Outlook" below for
a discussion related to 1995 exploration and development expenditure plans).
Exploration and development expenditures in 1993 increased to $438 million,
an 8% increase, as compared to the $406 million expended in 1992. The increase
was attributable to increased domestic drilling activity with reduced emphasis
on development drilling expenditures associated with tight gas sand formations.
The Company also implemented its first development program outside of North
America. During 1993, the Company installed a jacket, platform and production
facilities and initiated natural gas production from the Kiskadee field offshore
the southeast coast of Trinidad.
FINANCING. The Company's long-term debt-to-total-capital ratio was 15% and
14% as of December 31, 1994 and 1993, respectively. The Company has entered into
an agreement with Enron Corp. pursuant to which the Company may borrow funds
from Enron Corp. at a representative market rate of interest on a revolving
basis. During 1994, there were no funds borrowed by the Company under this
agreement. Under a promissory note effective January 1, 1993 at a fixed interest
rate of 7%, the Company may advance funds temporarily surplus to the Company to
Enron Corp. for investment purposes. Daily outstanding balances of funds
advanced to Enron Corp. under the note averaged $69 million during 1994 with no
balance outstanding at December 31, 1994. There was a balance of $7 million
outstanding at December 31, 1994 under a commercial paper program initiated in
1990. Proceeds from the commercial paper program were used to fund current
transactions. During 1994, total long-term debt increased $37 million to $190
million as a result of $23 million of new borrowings related to certain
international drilling activities, a $7 million increase in commercial paper,
and the recording of a $7 million capital lease obligation. (See Note 4 to the
Consolidated Financial Statements). The estimated fair value of the Company's
long-term debt, including current maturities of $2 million and $30 million, at
December 31, 1994 and 1993 was $186 million and $192 million, respectively,
based upon quoted market prices and, where such prices were not available, upon
interest rates currently available to the Company at year end. (See Note 13 to
the Consolidated Financial Statements).
OUTLOOK. There continues to exist a good deal of uncertainty as to the
direction of future North America natural gas price trends and a rather wide
divergence in the opinions held by some in the industry. However, recent history
would tend to support, and it seems there is emerging among a larger number of
industry representatives somewhat of a consensus, that natural gas prices will
remain below parity with crude oil, condensate and natural gas liquids for some
time. This situation is being impacted by improvements in the technology used in
drilling and completing oil and gas
26
wells that are tending to mitigate the impacts of fewer oil and gas wells being
drilled, the deregulation of the natural gas market under Federal Energy
Regulatory Commission Order 636 and subsequent related orders, and improvements
being realized in the availability and utilization of natural gas storage
capacity. However, the continually increasing recognition of natural gas as a
more environmentally friendly source of energy along with the availability of
significant domestically sourced supplies should result in further increases in
demand and a supporting/strengthening of the overall natural gas market over
time. Being primarily a natural gas producer, the Company is more significantly
impacted by changes in natural gas prices than by changes in crude oil and
condensate prices. (See "Business - Other Matters - Energy Prices"). Based on
the portion of the Company's anticipated natural gas volumes for which prices
have not, in effect, been hedged using NYMEX-related commodity market
transactions, long-term marketing contracts and the sale of a volumetric
production payment, the Company's net income and cash flow sensitivity to
changing natural gas prices is approximately $10 million for each $.10 per Mcf
change in average wellhead natural gas prices. Using various commodity price
hedging mechanisms, the Company has, in effect, locked in prices for an average
of about one-half of its anticipated wellhead natural gas volumes and about
one-third of its anticipated wellhead crude oil and condensate volumes for the
year 1995 and about one-third of its anticipated wellhead natural gas volumes
and about one-sixth of its anticipated wellhead crude oil and condensate volumes
for the year 1996. The percentage of volumes hedged may change during the
remainder of 1995 and will change in future years.
Other factors representing positive impacts that are more certain continue
to hold good potential for the Company in future periods. While the drilling
qualification period for the tight gas sand federal income tax credit expired as
of December 31, 1992, the Company has continued in 1994, and should continue in
the future, to realize significant benefits associated with production from
wells drilled during the qualifying period as it will be eligible for the
federal income tax credit through the year 2002. However, all other factors
remaining equal, the annual benefit, which was $36 million in 1994 and is
estimated to be approximately $21 million for 1995, is expected to continue to
decline in future periods as production from the qualified wells declines. The
drilling qualification period for a certain state severance tax exemption
available on qualifying high cost natural gas revenues continues through the
latter part of 1996. Consequently, new qualifying production will be added
prospectively to that qualified at year end 1994. (See "Business - Other Matters
- - Tight Gas Sand Tax Credit (Section 29) and Severance Tax Exemption"). Other
natural gas marketing activities are also expected to continue to contribute
meaningfully to financial results. The Company completed a fairly significant
restructure of its other natural gas marketing portfolio during 1992 with the
sale of a volumetric production payment of approximately 124 Bcfe (136 trillion
British thermal units) for $326.8 million that was subsequently revised in 1993
(See "Business - Marketing - Other Marketing" and Note 5 to Consolidated
Financial Statements) and elimination of most delivery obligations under four
long-term fixed price marketing contracts. The proceeds from the sale of the
volumetric production payment added substantially to the financial flexibility
of the Company supporting future development while the combined effect of all
elements of the restructuring on net income has not been, and will not in the
future be, significant. These factors are expected to contribute significantly
to earnings, cash flow, and the ability of the Company to pursue the
continuation of an active exploration, development and selective acquisition
program.
The Company plans to continue to focus a substantial portion of its
development and certain exploration expenditures in its major producing areas in
North America. However, based on the continuing uncertainty associated with
North America natural gas prices and the current weakness in that market, and as
a result of the recent success realized in Trinidad and opportunities available
to the Company in conjunction with the recent signing of agreements in India,
the Company anticipates expending an increasing portion of its available funds
in the further development of these opportunities. In addition, the Company
expects to include limited but meaningful exploratory exposure in other areas
outside of North America in its expenditure plans. (See "Business - Exploration
and Production" for additional information detailing the specific geographic
locations of the related drilling programs). Early-in-year activity will be
managed within an annual expected expenditure
27
level of approximately $450 million. This early-in-year planning will address
the continuing uncertainty with regard to the future of the North America
natural gas price environment and will be structured to maintain the flexibility
necessary under the Company strategy of funding exploration, development and
acquisition activities primarily from available internally generated cash flow.
The continuation of expenditures in other areas outside of North America, will
be primarily for additional evaluation of coalbed methane recovery potential in
the U.K., France, Australia, China, Russia and certain other countries.
The level of exploration and development expenditures may vary in 1995 and
will vary in future periods depending on energy market conditions and other
related economic factors. Based upon existing economic and market conditions,
the Company believes net operating cash flow and available financing
alternatives in 1995 will be sufficient to fund its net investing cash
requirements for the year. However, the Company has significant flexibility with
respect to its financing alternatives and adjustment of its exploration and
development expenditure plans as circumstances warrant. While the Company has
certain continuing commitments associated with expenditure plans related to
operations in India, they are not anticipated to be material when considered in
relation to the total financial capacity of the Company.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is included in this report as set forth
in the "Index to Financial Statements" on page F-1.
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item regarding directors is set forth in
the Proxy Statement under the caption entitled "Election of Directors", and is
incorporated herein by reference.
See list of "Current Executive Officers of the Registrant" in Part I located
elsewhere herein.
There are no family relationships among the officers listed, and there are
no arrangements or understandings pursuant to which any of them were elected as
officers. Officers are appointed or elected annually by the Board of Directors
at its first meeting following the Annual Meeting of Shareholders, each to hold
office until the corresponding meeting of the Board in the next year or until a
successor shall have been elected, appointed or shall have qualified.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is set forth in the Proxy Statement
under the caption "Compensation of Directors and Executive Officers", and is
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is set forth in the Proxy Statement
under the captions "Election of Directors" and "Compensation of Directors and
Executive Officers", and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is set forth in the Proxy Statement
under the caption "Certain Transactions", and is incorporated herein by
reference.
28
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K
(a)(1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
See "Index to Financial Statements" set forth on page F-1.
(a)(3) EXHIBITS
See pages E-1 through E-5 for a listing of the exhibits.
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed by the Company during the last quarter of
1994.
29
INDEX TO FINANCIAL STATEMENTS
ENRON OIL & GAS COMPANY
PAGE
----
Consolidated Financial Statements:
Management's Responsibility for Financial Reporting.... F-2
Reports of Independent Public Accountants.............. F-3
Consolidated Statements of Income for Each of the
Three Years in the Period Ended December 31, 1994.... F-4
Consolidated Balance Sheets - December 31, 1994
and 1993............................................. F-5
Consolidated Statements of Shareholders' Equity
for Each of the Three Years in the Period
Ended December 31, 1994.............................. F-6
Consolidated Statements of Cash Flows for Each of the
Three Years in the Period Ended December 31, 1994.... F-7
Notes to Consolidated Financial Statements............. F-8
Supplemental Information to Consolidated Financial
Statements............................................... F-21
Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts
and Reserves......................................... S-1
Other financial statement schedules have been
omitted because they are inapplicable or the
information required therein is included
elsewhere in the consolidated financial
statements or notes thereto.
F-1
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The following consolidated financial statements of Enron Oil & Gas Company
and its subsidiaries were prepared by management which is responsible for their
integrity, objectivity and fair presentation. The statements have been prepared
in conformity with generally accepted accounting principles and accordingly
include some amounts that are based on the best estimates and judgements of
management.
Arthur Andersen LLP, independent public accountants, was engaged to audit
the consolidated financial statements of Enron Oil & Gas Company and its
subsidiaries and issue a report thereon. In the conduct of the audit, Arthur
Andersen LLP was given unrestricted access to all financial records and related
data including minutes of all meetings of shareholders, the Board of Directors
and committees of the Board. Management believes that all representations made
to Arthur Andersen LLP during the audit were valid and appropriate. Their audits
of the years presented included developing an overall understanding of the
Company's accounting systems, procedures and internal controls, and conducting
tests and other auditing procedures sufficient to support their opinion on the
financial statements. Arthur Andersen LLP was also engaged to examine and report
on management's assertion about the effectiveness of the system of internal
controls of Enron Oil & Gas Company and its subsidiaries. The reports of Arthur
Andersen LLP appear on the following page.
The system of internal controls of Enron Oil & Gas Company and its
subsidiaries is designed to provide reasonable assurance as to the reliability
of financial statements and the protection of assets from unauthorized
acquisition, use or disposition. This system includes, but is not limited to,
written policies and guidelines including a published code for the conduct of
business affairs, conflicts of interest and compliance with laws regarding
antitrust, anti-boycott and foreign corrupt practices policies, the careful
selection and training of qualified personnel, and a documented organizational
structure outlining the separation of responsibilities among management
representatives and staff groups.
The adequacy of financial controls of Enron Oil & Gas Company and its
subsidiaries and the accounting principles employed in financial reporting by
the Company are under the general oversight of the Audit Committee of the Board
of Directors. No member of this committee is an officer or employee of the
Company. The independent public accountants have direct access to the Audit
Committee and meet with the committee from time to time to discuss accounting,
auditing and financial reporting matters.
It should be recognized that there are inherent limitations to the
effectiveness of any system of internal control, including the possibility of
human error and circumvention or override. Accordingly, even an effective system
can provide only reasonable assurance with respect to the preparation of
reliable financial statements and safeguarding of assets. Furthermore, the
effectiveness of an internal control system can change with circumstances.
It is management's opinion that, considering the criteria for effective
internal control over financial reporting and safeguarding of assets which
consists of interrelated components including the control environment,
risk-assessment process, control activities, information and communication
systems, and monitoring, the Company maintained an effective system of internal
control as to the reliability of financial statements and the protection of
assets against unauthorized acquisition, use or disposition for all periods
presented.
BEN B. BOYD WALTER C. WILSON FORREST E. HOGLUND
Vice President and Senior Vice President and Chairman of the Board,
Controller Chief Financial Officer President and Chief
Executive Officer
Houston, Texas
February 17, 1995
F-2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Enron Oil & Gas Company:
We have examined management's assertion that the system of internal control
of Enron Oil & Gas Company and its subsidiaries for the year ended December 31,
1994, was adequate to provide reasonable assurance as to the reliability of
financial statements and the protection of assets against unauthorized
acquisition, use or disposition, included in the accompanying report on
Management's Responsibility for Financial Reporting.
Our examination was made in accordance with standards established by the
American Institute of Certified Public Accountants and, accordingly, included
obtaining an understanding of the system of internal control, testing and
evaluating the design and operating effectiveness of the system of internal
control, and such other procedures as we considered necessary in the
circumstances. We believe that our examination provides a reasonable basis for
our opinion.
Because of inherent limitations in any system of internal control, errors or
irregularities may occur and not be detected. Also, projections of any
evaluation of the system of internal control to future periods are subject to
the risk that the system of internal control may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our opinion, management's assertion that the system of internal control
of Enron Oil & Gas Company and its subsidiaries for the year ended December 31,
1994, was adequate to provide reasonable assurance as to the reliability of
financial statements and the protection of assets against unauthorized
acquisition, use or disposition is fairly stated in all material respects, based
upon the control criteria therein.
ARTHUR ANDERSEN LLP
Houston, Texas
February 17, 1995
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Enron Oil & Gas Company:
We have audited the accompanying consolidated balance sheets of Enron Oil &
Gas Company (a Delaware corporation) and subsidiaries as of December 31, 1994
and 1993, and the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1994. These financial statements and the schedule referred to below are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and the schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Enron Oil & Gas Company and
subsidiaries as of December 31, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The financial statement schedule listed
in the index to financial statements is presented for purposes of complying with
the Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
ARTHUR ANDERSEN LLP
Houston, Texas
February 17, 1995
F-3
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
-------------------------------------
1994 1993 1992
----------- ----------- -----------
NET OPERATING REVENUES
Natural Gas
Associated Companies........... $ 267,997 $ 279,921 $ 280,501
Trade.......................... 221,896 225,241 108,487
Crude Oil, Condensate and Natural
Gas Liquids
Associated Companies........... 46,782 38,953 38,775
Trade.......................... 29,556 16,881 20,152
Gains on Sales of Reserves and
Related Assets.................. 54,014 13,318 6,037
Other............................. 5,578 6,706 5,074
----------- ----------- -----------
Total.................... 625,823 581,020 459,026
OPERATING EXPENSES
Lease and Well.................... 60,384 59,344 49,406
Exploration....................... 41,811 36,921 33,278
Dry Hole.......................... 17,197 18,355 10,764
Impairment of Unproved Oil and Gas
Properties...................... 24,936 20,467 15,136
Depreciation, Depletion and
Amortization.................... 242,182 249,704 179,839
General and Administrative........ 51,418 45,274 36,648
Taxes Other Than Income........... 28,254 35,396 28,346
----------- ----------- -----------
Total.................... 466,182 465,461 353,417
----------- ----------- -----------
OPERATING INCOME..................... 159,641 115,559 105,609
OTHER INCOME (EXPENSE)............... 2,783 6,635 (3,476)
----------- ----------- -----------
INCOME BEFORE INTEREST EXPENSE AND
TAXES.............................. 162,424 122,194 102,133
INTEREST EXPENSE
Incurred
Affiliate...................... 629 - 1,747
Other.......................... 13,984 15,378 24,122
Capitalized....................... (6,124) (5,457) (3,580)
----------- ----------- -----------
Net Interest Expense........... 8,489 9,921 22,289
----------- ----------- -----------
INCOME BEFORE INCOME TAXES........... 153,935 112,273 79,844
INCOME TAX PROVISION (BENEFIT)....... 5,937 (25,752) (17,736)
----------- ----------- -----------
NET INCOME........................... $ 147,998 $ 138,025 $ 97,580
=========== =========== ===========
EARNINGS PER SHARE OF COMMON STOCK... $ .93 $ .86 $ .63
=========== =========== ===========
AVERAGE NUMBER OF COMMON SHARES...... 159,845 159,966 154,533
=========== =========== ===========
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
ENRON OIL & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
AT DECEMBER 31,
----------------------------
1994 1993
------------- -------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents......... $ 5,810 $ 103,129
Accounts Receivable
Associated Companies........... 57,352 59,143
Trade.......................... 68,781 66,109
Inventories....................... 15,731 14,082
Other............................. 8,744 6,962
------------- -------------
Total....................... 156,418 249,425
OIL AND GAS PROPERTIES (Successful
Efforts Method)...................... 3,015,435 2,772,220
Less: Accumulated Depreciation,
Depletion and Amortization...... 1,330,624 1,226,175
------------- -------------
Net Oil and Gas
Properties................ 1,684,811 1,546,045
OTHER ASSETS......................... 20,638 15,692
------------- -------------
TOTAL ASSETS......................... $ 1,861,867 $ 1,811,162
============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable
Associated Companies........... $ 13,353 $ 13,250
Trade.......................... 117,791 143,542
Accrued Taxes Payable............. 17,631 17,354
Dividends Payable................. 4,800 4,795
Current Maturities of Long-Term
Debt............................ 1,718 30,000
Other............................. 9,308 8,989
------------- -------------
Total....................... 164,601 217,930
LONG-TERM DEBT
Affiliate......................... 25,000 -
Other............................. 165,337 153,000
OTHER LIABILITIES.................... 10,035 9,477
DEFERRED INCOME TAXES................ 269,292 270,154
DEFERRED REVENUE..................... 184,183 227,528
COMMITMENTS AND CONTINGENCIES
(Note 9)
SHAREHOLDERS' EQUITY
Common Stock, $.01 Par,
160,000,000 Shares Authorized
and Issued at December 31, 1994
and No Par, 160,000,000 Shares
Authorized and Issued at
December 31, 1993............... 201,600 200,800
Additional Paid In Capital........ 403,488 417,531
Cumulative Foreign Currency
Translation Adjustment.......... (15,298) (6,855)
Retained Earnings................. 453,810 324,995
Common Stock Held in Treasury,
9,173 shares at December 31,
1994 and 160,000 shares at
December 31, 1993............... (181) (3,398)
------------- -------------
Total Shareholders'
Equity...................... 1,043,419 933,073
------------- -------------
TOTAL LIABILITIES AND SHAREHOLDERS'
EQUITY............................. $ 1,861,867 $ 1,811,162
============= =============
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
CUMULATIVE
FOREIGN COMMON
ADDITIONAL CURRENCY STOCK TOTAL
COMMON PAID IN TRANSLATION RETAINED HELD IN SHAREHOLDERS'
STOCK CAPITAL ADJUSTMENT EARNINGS TREASURY EQUITY
----------- ----------- ------------ ----------- ----------- --------------
<S> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1991......... $ 200,759 $ 310,504 $ 6,947 $ 124,975 $ - $ 643,185
Net Income........................ - - - 97,580 - 97,580
Shares Issued by Public Offering.. 41 111,820 - - - 111,861
Dividends Paid, $.025 Per Share in
April, July and October, and
Declared, $.03 in December...... - - - (16,390) - (16,390)
Translation Adjustment............ - - (8,673) - - (8,673)
Treasury Stock Purchased.......... - - - - (1,827) (1,827)
Treasury Stock Issued Under Stock
Option Plan..................... - (577) - - 1,827 1,250
----------- ----------- ------------ ----------- ----------- --------------
Balance at December 31, 1992......... 200,800 421,747 (1,726) 206,165 - 826,986
Net Income........................ - - - 138,025 - 138,025
Dividends Paid/Declared, $.12 Per
Share........................... - - - (19,195) - (19,195)
Translation Adjustment............ - - (5,129) - - (5,129)
Treasury Stock Purchased.......... - - - - (16,698) (16,698)
Treasury Stock Issued Under Stock
Option Plan..................... - (4,216) - - 13,300 9,084
----------- ----------- ------------ ----------- ----------- --------------
Balance at December 31, 1993......... 200,800 417,531 (6,855) 324,995 (3,398) 933,073
Net Income........................ - - - 147,998 - 147,998
Two-for-One Stock Split........... 800 (800) - - - -
Dividends Paid/Declared, $.12 Per
Share............................. - - - (19,183) - (19,183)
Translation Adjustment............. - - (8,443) - - (8,443)
Treasury Stock Purchased/
Tendered.......................... - - - - (35,960) (35,960)
Treasury Stock Issued Under Stock
Option Plan....................... - (13,243) - - 39,177 25,934
----------- ----------- ------------ ----------- ----------- --------------
Balance at December 31, 1994......... $ 201,600 $ 403,488 $ (15,298) $ 453,810 $ (181) $ 1,043,419
=========== =========== ============ =========== =========== ==============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
-------------------------------------
1994 1993 1992
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of Net Income to
Net Operating Cash Inflows:
Net Income........................ $ 147,998 $ 138,025 $ 97,580
Items Not Requiring (Providing)
Cash
Depreciation, Depletion and
Amortization................. 242,182 249,704 179,839
Impairment of Unproved Oil and
Gas Properties............... 24,936 20,467 15,136
Deferred Income Taxes.......... 1,788 25,612 (17,917)
Other, Net..................... (2,735) 1,768 5,713
Exploration Expenses.............. 41,811 36,921 33,278
Dry Hole Expenses................. 17,197 18,355 10,764
Gains On Sales of Reserves and
Related Assets.................. (54,014) (13,318) (6,037)
Other, Net........................ 4,490 1,242 (6,147)
Changes in Components of Working
Capital and Other Liabilities
Accounts Receivable............ (883) (24,586) (12,732)
Inventories.................... (2,163) (4,548) 3,687
Accounts Payable............... (25,648) 26,208 46,327
Accrued Taxes Payable.......... 277 7,443 247
Other Liabilities.............. 1,086 772 (2,886)
Other, Net..................... (1,463) (44,443) 33,784
Changes in Components of Working
Capital Associated with
Investing and Financing
Activities...................... 31,038 40,042 (74,232)
--------- --------- ---------
NET OPERATING CASH INFLOWS........... 425,897 479,664 306,404
INVESTING CASH FLOWS
Additions to Oil and Gas
Properties...................... (442,078) (383,064) (362,403)
Exploration Expenses.............. (41,811) (36,921) (33,278)
Dry Hole Expenses................. (17,197) (18,355) (10,764)
Proceeds from Sales of Reserves
and Related Assets (Note 10).... 90,515 41,815 33,412
Proceeds from Sale of Volumetric
Production Payment.............. - -} 326,775
Amortization of Deferred
Revenue......................... (43,345) (73,867) (25,380)
Changes in Components of Working
Capital Associated with
Investing Activities............ (32,120) (37,256) 74,232
Other, Net........................ (8,758) (4,905) (3,686)
--------- --------- ---------
NET INVESTING CASH OUTFLOWS.......... (494,794) (512,553) (1,092)
FINANCING CASH FLOWS
Long-Term Debt
Affiliate...................... 25,000 - (132,836)
Other.......................... (25,300) 33,000 (139,556)
Common Stock Issued............... - - 111,861
Dividends Paid.................... (19,178) (19,200) (15,385)
Treasury Stock Purchased.......... (14,139) (16,698) (1,827)
Proceeds from Sales of Treasury
Stock........................... 4,113 9,084 1,250
Other, Net........................ 1,082 (2,786) -
--------- --------- ---------
NET FINANCING CASH INFLOWS
(OUTFLOWS)......................... (28,422) 3,400 (176,493)
--------- --------- ---------
INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS........................ (97,319) (29,489) 128,819
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR.................. 103,129 132,618 3,799
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF
YEAR............................... $ 5,810 $ 103,129 $ 132,618
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements of Enron
Oil & Gas Company (the "Company"), 80% of the outstanding common stock of which
is owned by Enron Corp., include the accounts of all domestic and foreign
subsidiaries. All material intercompany accounts and transactions have been
eliminated. Certain reclassifications have been made to consolidated financial
statements for prior years to conform with the current presentation.
CASH EQUIVALENTS. The Company records as cash equivalents all highly
liquid short-term investments with maturities of three months or less. (See
Note 4 "Long-Term Debt - Financing Arrangements with Enron Corp.")
OIL AND GAS OPERATIONS. The Company accounts for its natural gas and
crude oil exploration and production activities under the successful efforts
method of accounting.
Oil and gas lease acquisition costs are capitalized when incurred. Unproved
properties with significant acquisition costs are assessed quarterly on a
property-by-property basis and any impairment in value is recognized.
Amortization of any remaining costs of such leases begins at a point prior to
the end of the lease term depending upon the length of such term. Unproved
properties with acquisition costs that are not individually significant are
aggregated, and the portion of such costs estimated to be nonproductive, based
on historical experience, is amortized over the average holding period. If the
unproved properties are determined to be productive, the appropriate related
costs are transferred to proved oil and gas properties. Lease rentals are
expensed as incurred.
Oil and gas exploration costs, other than the costs of drilling exploratory
wells, are charged to expense as incurred. The costs of drilling exploratory
wells are capitalized pending determination of whether they have discovered
proved commercial reserves. If proved commercial reserves are not discovered,
such drilling costs are expensed. The costs of all development wells and related
equipment used in the production of crude oil and natural gas are capitalized.
Depreciation, depletion and amortization of the cost of proved oil and gas
properties is calculated using the unit-of-production method. Estimated future
dismantlement, restoration and abandonment costs (classified as long-term
liabilities), net of salvage values, are taken into account. Certain other
assets are depreciated on a straight-line basis.
Inventories, consisting primarily of tubular goods and well equipment held
for use in the exploration for, and development and production of crude oil and
natural gas reserves, are carried at cost with selected adjustments made from
time to time to recognize changes in condition value.
Natural gas revenues are recorded to recognize that during the course of
normal production operations joint interest owners will, from time to time, take
more or less than their ultimate share of natural gas volumes from jointly owned
reservoirs. These volumetric imbalances are monitored over the life of the
reservoir to achieve balancing, or minimize imbalances, by the time reserves are
depleted. Final cash settlements are made, generally at the time a property is
depleted, under one of a variety of arrangements generally accepted by the
industry depending on the specific circumstances involved. The Company accrues
revenues associated with undertakes and defers revenues associated with
overtakes to recognize these potential ultimate imbalances.
Based on the Company's strategy of maximizing the economic value of its
assets through a combination of both developing and producing over time, crude
oil and natural gas reserves and the sale of such reserves in place with related
assets; effective for 1994, gains and losses associated with such sales in place
are being classified as Net Operating Revenues in the consolidated statements of
income.
F-8
ACCOUNTING FOR INTEREST AND PRICE RISK MANAGEMENT The Company engages in
price and interest rate risk management activities for primarily non-trading
purposes. Such activities consist of transactions to hedge commodity prices
associated with the sales and purchases of natural gas and crude oil in order to
mitigate the risk of market price fluctuations and interest rate swap agreements
to effectively convert portions of floating rate debt to a fixed rate basis,
thereby reducing the impact of interest rate changes on future income. Changes
in the market value of commodity price and interest rate swap transactions
entered into as hedges are deferred so that the gain or loss is recognized in
the period in which the revenues or expenses associated with the hedged
transactions are applicable.
In certain situations, the Company has designated portions of and may in the
future designate certain commodity price swap transactions or portions thereof
as for trading purposes. These transactions are accounted for using the
mark-to-market method of accounting. Under this method, unrealized gains or
losses resulting from the impact of price movements are recognized as net gains
or losses in Net Operating Revenues in the consolidated statements of income.
CAPITALIZED INTEREST COSTS. Certain interest costs have been capitalized as
a part of the historical cost of unproved oil and gas properties. Interest costs
capitalized during each of the three years in the period ended December 31, 1994
are set out in the consolidated statements of income.
INCOME TAXES. Taxable income of the Company, excluding that of any foreign
subsidiaries, is included in the consolidated federal income tax return filed by
Enron Corp. Pursuant to a tax allocation agreement between the Company, the
Company's subsidiaries and Enron Corp., either Enron Corp. will pay to the
Company and each subsidiary an amount equal to the tax benefit realized in the
Enron Corp. consolidated federal income tax return resulting from the
utilization of the Company's or the subsidiary's net operating losses and/or tax
credits, or the Company and each subsidiary will pay to Enron Corp. an amount
equal to the federal income tax computed on its separate taxable income less the
tax benefits associated with any net operating losses and/or tax credits
generated by the Company or the subsidiary which are utilized in the Enron Corp.
consolidated return. Enron Corp. will pay the Company and each subsidiary for
the tax benefits associated with their net operating losses and tax credits
utilized in the Enron Corp. consolidated return, provided that a tax benefit was
realized even if such benefits could not have been used by the Company or the
subsidiary on a separately filed tax return.
The Company has entered into an agreement with Enron Corp. providing for the
Company to be paid for all realizable benefits associated with tight gas sand
federal income tax credits concurrent with tax reporting and settlement for the
periods in which they are generated.
The tax allocation agreement applies to the Company and each of its
subsidiaries for all years in which the Company or any of its subsidiaries are
or were included in the Enron Corp. consolidated return. Taxes for any foreign
subsidiaries of the Company are calculated on a separate return basis.
The Company accounts for income taxes under the provisions of Statement of
Financial Accounting Standards (SFAS) No. 109 - "Accounting for Income Taxes".
SFAS No. 109 requires the asset and liability approach for accounting for income
taxes. Under this approach, deferred tax assets and liabilities are recognized
based on anticipated future tax consequences attributable to differences between
financial statement carrying amounts of assets and liabilities and their
respective tax bases (See Note 8 "Income Taxes").
FOREIGN CURRENCY TRANSLATION. For subsidiaries whose functional currency is
deemed to be other than the U.S. dollar, asset and liability accounts are
translated at year-end exchange rates and revenue and expenses are translated at
average exchange rates prevailing during the year. Translation adjustments are
included as a separate component of shareholders' equity.
EARNINGS PER SHARE. Earnings per share is computed on the basis of the
average number of common shares outstanding during the periods.
F-9
2. NATURAL GAS AND CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET
OPERATING REVENUES
Natural Gas Net Operating Revenues are comprised of the following:
1994 1993 1992
----------- ----------- -----------
Wellhead Natural Gas Revenues
Associated Companies(1)(2)....... $ 279,339 $ 340,508 $ 223,249
Trade............................ 162,553 156,301 103,288
----------- ----------- -----------
Total.................... $ 441,892 $ 496,809 $ 326,537
=========== =========== ===========
Other Natural Gas Marketing
Activities
Gross Revenues from:
Associated Companies(3)...... $ 159,726 $ 139,576 $ 186,600
Trade(4)..................... 121,965 135,606 57,482
----------- ----------- -----------
Total.................... 281,691 275,182 244,082
Associated Costs from:
Associated
Companies(1)(5)(6)........... 181,756 182,456 133,170
Trade........................ 62,513 66,273 52,283
----------- ----------- -----------
Total.................... 244,269 248,729 185,453
----------- ----------- -----------
Net...................... 37,422 26,453 58,629
Commodity Price Hedging Gain
(Loss)(7)...................... 10,579 (18,100) 3,822
----------- ----------- -----------
Total.................... $ 48,001 $ 8,353 $ 62,451
=========== =========== ===========
Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues are
comprised of the following:
1994 1993 1992
----------- ----------- -----------
Wellhead Crude Oil, Condensate and
Natural Gas Liquids Revenues
Associated Companies............. $ 44,979 $ 38,953 $ 38,474
Trade............................ 29,556 16,881 20,152
----------- ----------- -----------
Total........................ $ 74,535 $ 55,834 $ 58,626
=========== =========== ===========
Other Crude Oil and Condensate
Marketing Activities
Commodity Price Hedging
Gain(7)........................ $ 1,803 $ - $ 301
=========== =========== ===========
- ---------
(1) Wellhead Natural Gas Revenues in 1994, 1993 and 1992 include $126,783,
$129,504 and $84,317, respectively, associated with deliveries by Enron
Oil & Gas Company to Enron Oil & Gas Marketing, Inc., a wholly-owned
subsidiary, reflected as a cost in Other Natural Gas Marketing Activities
- Associated Costs.
(2) Includes $22,434, $46,358 and $17,173 in 1994, 1993 and 1992,
respectively, associated with the equivalent wellhead value of volumes
delivered under the terms of a volumetric production payment agreement
effective October 1, 1992, as amended, net of transportation.
(3) Includes the effect of a price swap agreement with an Enron Corp.
affiliated company which in effect fixed the price of certain sales.
(4) Includes $43,345, $73,867 and $25,380 in 1994, 1993 and 1992,
respectively, associated with the amortization of deferred revenues under
the terms of volumetric production payment and exchange agreements
effective October 1, 1992, as amended.
(5) Includes the effect of a price swap agreement with a third party which in
effect fixed the price of certain purchases.
(6) Includes $33,779, $65,042 and $23,977 in 1994, 1993 and 1992,
respectively, for volumes delivered under volumetric production payment
and exchange agreements effective October 1, 1992, as amended, including
equivalent wellhead value, any applicable transportation costs and
exchange differentials.
(7) Represents gain or loss associated with commodity price swap transactions
primarily with Enron Corp. affiliated companies based on NYMEX-related
commodity prices in effect on dates of execution, less customary
transaction fees.
F-10
3. OTHER ASSETS
Other Assets at December 31, 1994 includes an investment in 349,387 shares
of Enron Corp. common stock purchased for $10 million, at an average of $28.62
per share from Enron Corp. (the fair market value of such shares on the dates of
acquisition), in connection with an anticipated acquisition of certain oil and
gas properties by a subsidiary of the Company which is scheduled to close in
March 1995. The Enron Corp. common stock will be used in connection with the
future redemption of redeemable preferred stock to be issued by the subsidiary.
4. LONG-TERM DEBT
REVOLVING CREDIT AGREEMENT. The Company is a party to a Revolving Credit
Agreement dated as of March 11, 1994, among the Company and the banks named
therein (the "Credit Agreement"). The Credit Agreement provides for aggregate
borrowings of up to $100 million, with provisions for increases, at the option
of the Company, up to $300 million. Advances under the Credit Agreement bear
interest, at the option of the Company, based on a base rate, an adjusted CD
rate or a Eurodollar rate. Each advance under the Credit Agreement matures on a
date selected by the Company at the time of the advance, but in no event after
January 15, 1998. There were no advances outstanding under the Credit Agreement
at December 31, 1994.
FINANCING ARRANGEMENTS WITH ENRON CORP. The Company engages in various
transactions with Enron Corp. that are characteristic of a consolidated group
under common control. Activities of the Company not internally funded from
operations have been and may be funded from time to time by advances from Enron
Corp. The Company entered into an agreement with Enron Corp., effective October
12, 1989 (as amended effective September 29, 1992), under which the Company may
borrow funds from Enron Corp. at a representative market rate of interest on a
revolving basis. During 1994 and 1993, there were no funds borrowed by the
Company under this agreement. Any loan balance that may be outstanding from time
to time is payable on demand but no later than September 29, 1995, the maturity
date of this agreement. Any balances outstanding would be classified as
long-term based on the Company's intent and ability to refinance such amounts
using available borrowing capacity.
The Company also entered into an agreement with Enron Corp., effective
October 12, 1989 (as amended effective September 29, 1992), which provides the
Company the option of depositing any excess funds that may be available from
time to time with Enron Corp. with interest at a representative market rate
during the periods the funds were held by Enron Corp. Effective January 1, 1993,
the Company executed a promissory note at a fixed interest rate of 7% with Enron
Corp. providing for the investment of funds temporarily surplus to the Company
from time to time with Enron Corp. Daily outstanding balances of funds advanced
to Enron Corp. under this note averaged $68.8 million and $60.3 million during
1994 and 1993, respectively. There were no advances outstanding at December 31,
1994 and $96.6 million outstanding at December 31, 1993 under this agreement,
which amounts are classified as cash equivalents on the consolidated balance
sheets. Interest income recorded in 1994 and 1993 under the terms of this note
totaled $4.7 million and $4.4 million, respectively.
In July 1994, the Company prepaid $25 million of loans payable due in April
1995 with proceeds from a promissory note payable to Enron Corp. which note is
in the same amount and with essentially the same terms as the loan prepaid. The
promissory note is classified as long-term based on the Company's intent and
ability to refinance such note upon maturity with other long-term debt. The
interest rate swap agreement which effectively fixed the interest rate of the
original loan payable at 8.98% through maturity remains in effect for the
promissory note payable to Enron Corp.
F-11
LONG-TERM DEBT, OTHER. Long-Term Debt, Other at December 31 consisted of
the following:
1994 1993
----------- -----------
Loan(s) Payable.................. $ 25,000 $ 50,000
Senior Notes..................... 70,000 70,000
Promissory Notes................. 56,000 33,000
Commercial Paper................. 6,700 -
Capitalized Lease Obligation..... 7,637 -
----------- -----------
Total................ $ 165,337 $ 153,000
=========== ===========
The Loan Payable is due in 1995 and bears interest at a variable rate based
on the London Interbank Offered Rate which has, in effect, been converted to a
fixed interest rate of 8.92% through maturity using an interest rate swap
agreement in equivalent dollar amounts. The note is classified as long-term
based on the Company's intent and ability to replace such loan upon maturity
with other long-term debt.
The Senior Notes bear interest at 9.1% with principal repayments of $30
million due in 1996 and $20 million due in 1997 and 1998.
In March 1994, a subsidiary of the Company received two advances, evidenced
by promissory notes, aggregating $31 million under a credit agreement dated as
of March 8, 1994 between the subsidiary and a financial institution. One of the
advances is in the amount of $16 million, bears interest at a fixed rate of
4.52% and is due in 1998. The other advance is in the amount of $15 million,
bears interest at a floating rate that resets quarterly equal to 84% of the
London Interbank Bid Rate which is 1/8 of 1% less than the London Interbank
Offered Rate and is due in 1998. Both advances are collateralized with a letter
of credit issued by a bank on behalf of the subsidiary and guaranteed by the
Company. The advances were used to partially repay a promissory note payable to
a bank by the subsidiary.
In May 1994, the subsidiary received a $25 million advance, evidenced by a
promissory note, under a credit agreement dated May 27, 1994 between the
subsidiary and a financial institution. The credit agreement provides for
aggregate borrowings of up to $44 million and is due in 1999. The advances bear
interest based on various interest rate options, as defined in the credit
agreement, which ranged from 4.03% to 5.59% during 1994. The advance is
guaranteed by the Company and was used to partially repay temporary advances
from the Company to the subsidiary for qualified development costs.
There was a $6.7 million balance outstanding at December 31, 1994, under a
commercial paper program initiated in 1990. The proceeds from the commercial
paper program outstanding from time to time are used to fund current
transactions and are classified as long-term based on the Company's intent and
ability to replace such obligation with other long-term debt. The interest rate
for the obligation at December 31, 1994 was 6.33%.
Certain of the borrowings described above contain covenants requiring the
maintenance of certain financial ratios and limitations on liens, debt issuance
and dispositions of assets.
In 1991, the Company filed with the Securities and Exchange Commission a
registration statement providing for the issuance and sale from time to time of
up to $250 million of debt securities to the public. As of December 31, 1994, no
debt securities had been issued under this registration statement.
FAIR VALUE OF LONG-TERM DEBT. At December 31, 1994, the Company had $190
million of long-term debt and $2 million of current maturities outstanding. At
December 31, 1993, there was $153 million of long-term debt and $30 million of
current maturities outstanding. The estimated fair value of such debt, including
current maturities, at December 31, 1994 and 1993 was approximately $186 million
and $192 million, respectively. The fair value of long-term debt is the value
the Company would have to pay to retire the debt, including any premium or
discount to the debtholder
F-12
for the differential between the stated interest rate and the year-end market
rate. The fair value of long-term debt is based upon quoted market prices and,
where such quotes were not available, upon interest rates available to the
Company at year-end.
5. DEFERRED REVENUE
In September 1992, the Company sold a volumetric production payment for
$326.8 million to a limited partnership of which an Enron Corp. affiliated
company is general partner with a 1% interest. Under the terms of the production
payment agreements, the Company conveyed a real property interest of
approximately 124 billion cubic feet equivalent ("Bcfe") (136 trillion British
thermal units) of natural gas and other hydrocarbons. The natural gas and other
hydrocarbons were originally scheduled to be produced and delivered over a
period of forty-five months which period commenced October 1, 1992. Effective
October 1, 1993, the agreements were amended providing for the extension of the
original term of the volumetric production payment through March 31, 1999 and
including a revised schedule of daily quantities of hydrocarbons to be delivered
which is approximately one-half of the original schedule. The revised schedule
will total approximately 89.1 Bcfe (97.8 trillion British thermal units) versus
approximately 87.9 Bcfe (96.4 trillion British thermal units) remaining to be
delivered under the original agreement. Daily quantities of hydrocarbons no
longer required to be delivered under the revised schedule during the period
from October 1, 1993 through June 30, 1996 are available for sale by the
Company. The Company retains responsibility for its working interest share of
the cost of operations. The Company also entered into a separate agreement with
the same limited partnership whereby it has agreed to exchange volumes owned by
the Company for equivalent volumes produced and owned by the limited
partnership. The costs incurred, if any, to effect redeliveries pursuant to such
exchange are borne by the Company. A portion of the proceeds of the sale was
used to repay a portion of the Company's long-term debt, with surplus funds
advanced to Enron Corp. under a note agreement which facilitates the deposit of
funds temporarily surplus to the Company. The Company accounted for the proceeds
received in the transaction as deferred revenue which is being amortized into
revenue and income as natural gas and other hydrocarbons are produced and
delivered during the term, as revised, of the volumetric production payment
agreement. Annual remaining amortization of deferred revenue, based on revised
scheduled deliveries under the volumetric production payment agreement, as
amended, at December 31, 1994 was as follows:
1995................................. $ 43,344
1996................................. 43,463
1997................................. 43,344
1998................................. 43,344
1999................................. 10,688
---------
Total........................ $ 184,183
=========
6. SHAREHOLDERS' EQUITY
The Board of Directors of the Company approved in December 1992, as amended
in September 1994, the purchasing and holding in treasury at any time of up to
500,000 shares of common stock of the Company for, but not limited to, meeting
obligations associated with stock option grants to qualified employees pursuant
to the Company's stock option plans. (See Note 9 "Commitments and Contingencies
- - Stock Option Plans"). At December 31, 1994 and 1993, 9,173 shares and 160,000
shares, respectively, were held in treasury under this authorization.
On May 3, 1994, the shareholders of the Company approved and the Board of
Directors subsequently declared a two-for-one split of the Company's common
stock to be effected as a non-taxable dividend of one share for each share
outstanding. Shares were issued on June 15, 1994 to shareholders of record as of
May 31, 1994. An amendment to the Restated Certificate of Incorporation of the
Company to increase the total number of authorized shares of the common stock of
the Company from 80 million to 160 million shares and to change the par value of
common stock from
F-13
no par to $.01 par per share was filed with the Secretary of State of Delaware.
All share and per share amounts in the financial statements and supplemental
financial information have been restated to consider the effect of the
two-for-one stock split.
7. TRANSACTIONS WITH ENRON CORP. AND RELATED PARTIES
NATURAL GAS AND CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET OPERATING
REVENUES. Wellhead Natural Gas and Crude Oil, Condensate and Natural Gas Liquids
Revenues and Other Natural Gas and Other Crude Oil and Condensate Marketing
Activities include revenues from and associated costs paid to various
subsidiaries and affiliates of Enron Corp. pursuant to contracts which, in the
opinion of management, are no less favorable than could be obtained from third
parties. Other Natural Gas and Other Crude Oil and Condensate Marketing
Activities also include certain commodity price swap and NYMEX-related commodity
transactions with Enron Corp. affiliated companies which, in the opinion of
management, are no less favorable than could be obtained from third parties.
(See Note 2 "Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net
Operating Revenues").
GENERAL AND ADMINISTRATIVE EXPENSES. The Company is charged by Enron Corp.
for all direct costs associated with its operations. Such direct charges,
excluding benefit plan charges (See Note 9 "Commitments and Contingencies -
Employee Benefit Plans"), totaled $13.7 million, $11.5 million and $4.9 million
for the years ended December 31, 1994, 1993 and 1992, respectively. Management
believes that these charges are reasonable.
Additionally, certain administrative costs not directly charged to any Enron
Corp. operations or business segments are allocated to the entities of the
consolidated group. Allocation percentages are generally determined utilizing
weighted average factors derived from property gross book value, net operating
revenues and payroll costs. Effective January 1, 1994, the Company entered into
an agreement with Enron Corp. with an initial term of five years through
December 1998, which agreement replaced a similar previous agreement, providing
for services substantially identical in nature and quality to those services
previously provided and for allocated indirect costs incurred in rendering such
services up to a maximum of $6.7 million for 1994, such cap to be increased in
subsequent years for inflation and certain changes in the Company's allocation
bases with any increase not to exceed 7.5% per year. Management believes the
indirect allocated charges for the numerous types of support services provided
by the corporate staff are reasonable. Approximately $6.6 million, $7.9 million
and $9.5 million were charged to the Company for indirect general and
administrative expenses for the years ended December 31, 1994, 1993 and 1992,
respectively.
FINANCING. See Note 4 "Long-Term Debt - Financing Arrangements with Enron
Corp." for a discussion of financing arrangements with Enron Corp.
F-14
8. INCOME TAXES
The principal components of the Company's net deferred income tax liability
at December 31, 1994 and 1993 were as follows:
1994 1993
----------- -----------
Deferred Income Tax Assets
Non-Producing Leasehold Costs...... $ 7,685 $ 5,234
Seismic Costs Capitalized for
Tax.............................. 4,683 5,643
Other.............................. 4,194 6,337
----------- -----------
Total Deferred Income Tax
Assets....................... 16,562 17,214
Deferred Income Tax Liabilities
Oil and Gas Exploration and
Development Costs Deducted for
Tax Over Book Depreciation,
Depletion and Amortization....... 252,599 276,422
Capitalized Interest............... 5,763 6,866
Volumetric Production Payment Book
Revenue Over Income for Tax...... 26,777 1,288
Other.............................. 715 2,792
----------- -----------
Total Deferred Income Tax
Liabilities.................. 285,854 287,368
----------- -----------
Net Deferred Income Tax
Liability.................... $ 269,292 $ 270,154
=========== ===========
The components of income (loss) before income taxes were as follows:
1994 1993 1992
----------- ----------- -----------
United States........................ $ 125,510 $ 117,460 $ 74,226
Foreign.............................. 28,425 (5,187) 5,618
----------- ----------- -----------
Total........................ $ 153,935 $ 112,273 $ 79,844
=========== =========== ===========
Total income tax provision (benefit) was as follows:
1994 1993 1992
----------- ----------- -----------
Current:
Federal.......................... $ 113 $ (52,555) $ (292)
State............................ 2,745 5 2
Foreign.......................... 1,291 1,186 471
----------- ----------- -----------
Total........................ 4,149 (51,364) 181
Deferred:
Federal.......................... 3,818 20,845 (21,729)
State............................ (14,414) 4,357 3,119
Foreign.......................... 12,384 410 693
----------- ----------- -----------
Total........................ 1,788 25,612 (17,917)
----------- ----------- -----------
Income Tax Provision (Benefit)..... $ 5,937 $ (25,752) $ (17,736)
=========== =========== ===========
F-15
The differences between taxes computed at the U.S. federal statutory tax
rate and the Company's effective rate were as follows:
1994 1993 1992
----------- ----------- -----------
Statutory Federal Income Tax Rate.... 35.00% 35.00% 34.00%
State Income Tax, Net of Federal
Benefit............................ (4.93) 2.53 2.58
Income Tax Related to Foreign
Operations......................... 3.44 3.08 (2.07)
Tight Gas Sand Federal Income Tax
Credits............................ (23.71) (58.05) (54.24)
Revision of Prior Years' Tax
Estimates.......................... (3.25) (10.73) -
Amended Return Recoveries............ (2.62) - (0.84)
Federal Tax Rate Increase............ - 5.23 -
Other................................ (0.07) - (1.64)
----------- ----------- -----------
Effective Income Tax Rate........ 3.86% (22.94)% (22.21)%
=========== =========== ===========
Current income tax receivable from (payable to) Enron Corp. at December 31,
1994, 1993 and 1992 amounted to $(506), $(6,892) and $5,619, respectively.
The Company has an alternative minimum tax ("AMT") credit carryforward of
$2.7 million which can be used to offset regular income taxes payable in future
years. The AMT credit carryforward has an indefinite carryforward period.
The Company's foreign subsidiaries' undistributed earnings of approximately
$64 million at December 31, 1994 are considered to be indefinitely invested
outside the U.S. and, accordingly, no U.S. federal or state income taxes have
been provided thereon. Upon distribution of those earnings in the form of
dividends, the Company may be subject to both foreign withholding taxes and U.S.
income taxes, net of allowable foreign tax credits. Determination of any
potential amount of unrecognized deferred income tax liabilities is not
practicable.
9. COMMITMENTS AND CONTINGENCIES
EMPLOYEE BENEFIT PLANS. Employees of the Company are covered by various
retirement, stock purchase and other benefit plans of Enron Corp. During each of
the years ended December 31, 1994, 1993 and 1992, the Company was charged $5.1
million, $4.5 million and $3.6 million, respectively, for all such benefits,
including pension expense totaling $0.3 million, $0.5 million and $0.5 million,
respectively, by Enron Corp.
As of September 30, 1994, the most recent valuation date, the plan net
assets of the Enron Corp. defined benefit plan in which the employees of the
Company participate exceeded the actuarial present value of projected plan
benefit obligations by approximately $18.9 million. The assumed discount rate,
rate of return on plan assets and rate of increases in wages used in determining
the actuarial present value of projected plan benefits were 8.0%, 10.5% and
4.0%, respectively.
The Company also has in effect pension and savings plans related to its
Canadian and Trinidadian subsidiaries. Activity related to these plans is not
significant to the Company's operations.
The Company provides certain medical, life insurance and dental benefits to
eligible employees who retire under the Enron Corp. Retirement Plan and their
eligible surviving spouses. Benefits are provided under the provisions of a
contributory defined dollar benefit plan. The Company accrues the cost of these
postretirement benefits over the service lives of the employees expected to be
eligible to receive such benefits. The transition obligation existing at January
1, 1993 is being amortized over an average period of 19 years. The accumulated
postretirement benefit obligation ("APBO") existing at December 31, 1994 totaled
$106.7 million, of which $91.0 million is applicable to current retirees and
current employees eligible to retire. The measurement of the APBO assumes an 8%
discount rate and a health care cost trend rate of 12.3% in 1994 decreasing to
5% by the year 2006 and beyond. A 1% increase in the health care cost trend rate
would have the effect of increasing the APBO and the
F-16
net periodic expense by approximately $7.9 million and $0.8 million,
respectively. The Company does not currently intend to prefund its obligations
under its postretirement welfare benefit plans.
STOCK OPTION PLANS. The Company has various stock option plans ("the Plans")
under which employees of the Company and its subsidiaries and non-employee
members of the Board of Directors have been or may be granted rights to purchase
shares of common stock of the Company generally at a price not less than the
market price of the stock at the date of grant. Options granted under the Plans
vest over a period of time based on the nature of the grants and as defined in
the individual grant agreements.
The following table sets forth the transactions for the Plans for the years
ended December 31:
NUMBER OF STOCK OPTIONS
-----------------------------------------
1994 1993 1992
------------- ------------ ------------
Outstanding at January 1............ 4,124,800 3,908,050 -
Granted......................... 5,128,095(1) 920,600 4,048,050
Exercised....................... (1,967,920) (671,850) (127,500)
Forfeited....................... (70,420) (32,000) (12,500)
------------- ------------ ------------
Outstanding at December 31 (Grant
Prices of $9.25-$23.81 per
Share)............................ 7,214,555 4,124,800 3,908,050
============= ============ ============
Available for Grant at December 31.. 3,218,175 1,075,850 1,964,450
============= ============ ============
- ---------
(1) Includes 1,920,275 options granted on December 30, 1994 under an all
employee stock option grant.
At December 31, 1994, 1,826,880 options outstanding were vested. Of the
remaining unvested options, 2,802,530, 892,780, 727,030, 581,280 and 384,055
vest in the years 1995, 1996, 1997, 1998 and 1999, respectively.
During 1994, 1993 and 1992, the Company purchased or was tendered 1,817,093,
831,850 and 127,500 of its common shares, respectively, and delivered such
shares upon the exercise of stock options, except for shares held in treasury at
December 31, 1994 and 1993 as set out below. The difference between the cost of
the treasury shares and the exercise price of the options, net of federal income
tax benefit of $7.2 million and $2.8 million for the years 1994 and 1993,
respectively, is reflected as an adjustment to Additional Paid In Capital. In
October 1993, as amended in September 1994, the Company commenced a stock
repurchase program authorized by the Board of Directors to facilitate the
availability of treasury shares of common stock for, but not limited to, the
settlement of employee stock option exercises pursuant to the Plans. At December
31, 1994 and 1993, 9,173 and 160,000 shares, respectively, were held in treasury
under this authorization.
(See Note 6 "Shareholders' Equity").
LETTERS OF CREDIT. At December 31, 1994 and 1993, the Company had letters of
credit outstanding totaling approximately $32.2 and $46.2 million, respectively.
The letters of credit outstanding at December 31, 1994 and December 31, 1993
include $31.9 million issued in connection with a loan between one of the
Company's subsidiaries and a trust and $33 million issued in connection with a
promissory note between the subsidiary and a bank, respectively.
CONTINGENCIES. There are various suits and claims against the Company having
arisen in the ordinary course of business. However, management does not believe
these suits and claims will individually or in the aggregate have a material
adverse effect on the Company's financial condition or results of operations.
TransAmerican Natural Gas Corporation ("TransAmerican") has filed a petition
against the Company and Enron Corp. alleging breach of contract, tortious
interference with contract, misappropriation of trade secrets and violation of
state antitrust laws. The petition, as amended, seeks actual damages of $100
million plus exemplary damages of $300 million. The Company has answered the
petition and is actively defending the matter; in addition, the Company has
filed counterclaims against TransAmerican and a third-party claim against its
sole shareholder,
F-17
John R. Stanley, alleging fraud, negligent misrepresentation and breach of state
antitrust laws. On April 6, 1994, Enron Corp. was granted summary judgment
wherein the court ordered that TransAmerican can take nothing on its claims
against Enron Corp. Trial, which was set most recently for September 12, 1994
has been continued and there is no current setting. Although no assurances can
be given, the Company believes that the claims made by TransAmerican are totally
without merit, that the ultimate resolution of the matter will not have a
materially adverse effect on its financial condition or results of operations,
and that such ultimate resolution could result in a recovery to the Company. The
Company has been named as a potentially responsible party in certain
Comprehensive Environmental Response Compensation and Liability Act proceedings.
However, management does not believe that any potential assessments resulting
from such proceedings will individually or in the aggregate have a materially
adverse effect on the financial condition or results of operations of the
Company.
10. CASH FLOW INFORMATION
Gains on sales of certain oil and gas reserves and related assets in the
amount of $54.0 million, $13.3 million and $6.0 million for the years ended
December 31, 1994, 1993 and 1992, respectively, are required by current
accounting guidelines to be removed from Net Income in connection with
determining Net Operating Cash Inflows while the related proceeds are required
to be classified as investing cash inflows. The Company believes that proceeds
from the sales of reserves and related assets should be considered in analyzing
the elements of operating cash inflows. The current federal income tax impact of
these sales transactions was calculated by the Company to be $19.8 million, $8.2
million and $8.2 million for the years ended December 31, 1994, 1993 and 1992,
respectively, which entered into the overall calculation of current federal
income tax. The Company believes that this federal income tax impact should also
be considered in analyzing the elements of the cash flow statement.
Cash paid for interest and paid (received) for income taxes was as follows
for the years ended December 31:
1994 1993 1992
---------- ---------- ----------
Interest (net of amount
capitalized)....................... $ 10,436 $ 10,517 $ 21,576
Income taxes......................... 1,352 (65,543) 7,365
11. BUSINESS SEGMENT INFORMATION
The Company's operations are all natural gas and crude oil exploration and
production related. Accordingly, such operations are classified as one business
segment. Financial information by geographic area is presented below for the
years ended December 31, or at December 31:
<TABLE>
<CAPTION>
1994 1993 1992
------------- ------------- -------------
<S> <C> <C> <C>
Gross Operating Revenues
United States.................... $ 656,546 $ 653,929 $ 527,165
Foreign.......................... 86,763 46,316 32,997
------------- ------------- -------------
Total<F1>.................... $ 743,309 $ 700,245 $ 560,162
============= ============= =============
Operating Income (Loss)
United States.................... $ 138,001 $ 126,410 $ 115,552
Foreign.......................... 21,640 (10,851) (9,943)
------------- ------------- -------------
Total........................ $ 159,641 $ 115,559 $ 105,609
============= ============= =============
Identifiable Assets
United States.................... $ 1,505,926 $ 1,564,330 $ 1,568,093
Foreign.......................... 355,941 246,832 162,919
------------- ------------- -------------
Total........................ $ 1,861,867 $ 1,811,162 $ 1,731,012
============= ============= =============
- ---------
<FN>
<F1> Not deducted are natural gas associated costs of $117,486, $119,225 and
$101,136 in 1994, 1993 and 1992, respectively.
</TABLE>
F-18
12. OTHER INCOME (EXPENSE)
Other income (expense) consisted of the following for the years ended
December 31:
1994 1993 1992
----------- ----------- -----------
Interest Income...................... $ 4,990 $ 5,789 $ 1,555
Reserve Accruals..................... (3,143) (2,520) (2,194)
Contract Settlements................. - 4,248 -
Other, Net........................... 936 (882) (2,837)
----------- ----------- -----------
Total........................ $ 2,783 $ 6,635 $ (3,476)
=========== =========== ===========
13. PRICE AND INTEREST RATE RISK MANAGEMENT
Periodically, the Company enters into certain trading and non-trading
activities including NYMEX-related commodity market transactions and other
contracts. The non-trading portions of these activities have been designated to
hedge the impact of market price fluctuations on anticipated commodity delivery
volumes or other contractual commitments. Gains and losses relating to trading
transactions were not material to the accompanying consolidated financial
statements. All trading positions were closed subsequent to year-end.
INTEREST RATE SWAP AGREEMENTS. In early 1992, the Company entered into
interest rate swap agreements to hedge certain floating interest rate exposure
in 1992 and 1993. This floating rate exposure arises from debt with interest
payments subject to floating interest rates. (See Note 4 "Long-Term Debt"). The
notional value of these interest rate swap agreements was $75 million. Effective
January 1, 1993, Enron Corp. assumed the Company's remaining obligations under
these swap agreements.
At December 31, 1994, the Company had outstanding interest rate swap
agreements with notional principal amounts of $50 million which terminate in
April 1995. The interest rate swap agreements were entered into to hedge certain
floating rate obligations and effectively fix the interest rate on the notional
amount of debt at 8.98% and 8.92%. The estimated fair value of the outstanding
swap agreements at December 31, 1994 was a negative $0.5 million. The fair value
of interest rate swap agreements is based upon termination values obtained from
third parties.
FOREIGN CURRENCY CONTRACTS. The Company enters into foreign currency
contracts from time to time to hedge specific currency exposure from commercial
transactions. At December 31, 1994, there were no foreign currency contracts
outstanding.
ENERGY COMMODITY PRICE SWAPS. The Company entered into certain commodity
price swap agreements to, in effect, hedge the market risk caused by
fluctuations in the cost of natural gas. The agreements call for the Company to
make payments to (or receive payments from) counterparties based upon the
differential between a fixed and a variable price for natural gas volumes
specified by the contracts. Such natural gas price swap agreements run for
periods of up to ten years expiring in 1999. The Company is the fixed price
payor on a notional quantity of 66 trillion British thermal units ("TBtu") of
natural gas with a fair value of negative $103.7 million at December 31, 1994.
The agreements were entered into to, in effect, fix the price of certain
purchases which are used to supply a fixed price sales contract. Inclusive of
the effect of the price swap, the differential between the escalating fixed
purchase price and the escalating fixed sales price results in profit margins
ranging from $1.15 per million British thermal unit ("MMBtu") to $1.44 per MMBtu
on approximately 66 TBtu to be purchased and delivered for sale over the
remaining term of the contracts.
From time to time, the Company enters into primarily NYMEX-related commodity
market transactions with affiliates of Enron Corp. to, in effect, mitigate the
risk of market price fluctuations on future deliveries of certain portions of
its natural gas and crude oil and condensate. At December 31, 1994, the Company
had outstanding positions covering notional volumes of approximately 50 TBtu and
51 TBtu of natural gas for the years 1995 and 1996, respectively and
approximately 2.5 million barrels ("MMBbl") of crude oil for the year 1995, 1.3
MMBbl of crude oil for the year 1996 and 1.1 MMBbl of crude oil for each of the
years 1997 through 1999. The fair value of the positions was $30.7 million at
December 31, 1994.
F-19
The following table summarizes the estimated fair value of financial
instruments and related transactions for non-trading activities at December 31,
1994:
CARRYING ESTIMATED
AMOUNT FAIR VALUE(1)
-------- -------------
(IN MILLIONS)
Long-Term Debt(2).................... $ 190.3 $ 185.7
Interest Rate Swap Agreements(2)..... - (0.5)
Foreign Currency Contracts........... - -
Energy Commodity Price Swaps(3)...... - (103.7)
Related Fixed Price Sales
Contract(3)........................ - 170.8
NYMEX-Related Commodity Market
Positions.......................... - 30.7
- ---------
(1) Estimated fair values have been determined by using available market data
and valuation methodologies. Judgment is necessarily required in
interpreting market data and the use of different market assumptions or
estimation methodologies may affect the estimated fair value amounts.
(2) See Note 4 "Long-Term Debt."
(3) The fair value of the Energy Commodity Price Swaps should be considered
with the fair value of the Related Fixed Price Sales Contract in
determining the overall market risk of these related business
transactions.
CREDIT RISK. While notional contract amounts are used to express the
magnitude of price and interest rate swap agreements, the amounts potentially
subject to credit risk, in the event of nonperformance by the other parties, are
substantially smaller. The Company does not anticipate nonperformance by the
other parties.
14. CONCENTRATION OF CREDIT RISK
Substantially all of the Company's accounts receivable at December 31, 1994
result from crude oil and natural gas sales and/or joint interest billings to
affiliate and third party companies in the oil and gas industry. This
concentration of customers and joint interest owners may impact the Company's
overall credit risk, either positively or negatively, in that these entities may
be similarly affected by changes in economic or other conditions. In determining
whether or not to require collateral from a customer or joint interest owner,
the Company analyzes the entity's net worth, cash flows, earnings, and credit
ratings. Receivables are generally not collateralized. Historical credit losses
incurred on receivables by the Company have been immaterial.
F-20
ENRON OIL & GAS COMPANY
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS UNLESS OTHERWISE INDICATED)
(UNAUDITED EXCEPT FOR RESULTS OF OPERATIONS FOR OIL AND GAS
PRODUCING ACTIVITIES)
OIL AND GAS PRODUCING ACTIVITIES
The following disclosures are made in accordance with SFAS No. 69 -
"Disclosures about Oil and Gas Producing Activities":
OIL AND GAS RESERVES. Users of this information should be aware that the
process of estimating quantities of "proved" and "proved developed" crude oil
and natural gas reserves is very complex, requiring significant subjective
decisions in the evaluation of all available geological, engineering and
economic data for each reservoir. The data for a given reservoir may also change
substantially over time as a result of numerous factors including, but not
limited to, additional development activity, evolving production history, and
continual reassessment of the viability of production under varying economic
conditions. Consequently, material revisions to existing reserve estimates occur
from time to time. Although every reasonable effort is made to ensure that
reserve estimates reported represent the most accurate assessments possible, the
significance of the subjective decisions required and variances in available
data for various reservoirs make these estimates generally less precise than
other estimates presented in connection with financial statement disclosures.
Proved reserves represent estimated quantities of crude oil, condensate,
natural gas and natural gas liquids that geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in future years from
known reservoirs under economic and operating conditions existing at the time
the estimates were made.
Proved developed reserves are proved reserves expected to be recovered,
through wells and equipment in place and under operating methods being utilized
at the time the estimates were made.
Canadian provincial royalties are determined based on a graduated percentage
scale which varies with prices and production volumes. Canadian reserves, as
presented on a net basis, assume prices and royalty rates in existence at the
time the estimates were made, and the Company's estimate of future production
volumes. Future fluctuations in prices, production rates, or changes in
political or regulatory environments could cause the Company's share of future
production from Canadian reserves to be materially different from that
presented.
Estimates of proved and proved developed reserves at December 31, 1994, 1993
and 1992 were based on studies performed by the Company's engineering staff for
reserves in the United States, Canada, Trinidad and India. Opinions by DeGolyer
and MacNaughton, independent petroleum consultants, for the years ended December
31, 1994, 1993 and 1992 covering producing areas containing 59%, 65% and 69%,
respectively, of proved reserves of the Company on a
net-equivalent-cubic-feet-of-gas basis, indicate that the estimates of proved
reserves prepared by the Company's engineering staff for the properties reviewed
by DeGolyer and MacNaughton, when compared in total on a
net-equivalent-cubic-feet-of-gas basis, do not differ materially from the
estimates prepared by DeGolyer and MacNaughton. Such estimates by DeGolyer and
MacNaughton in the aggregate varied by not more than 5% from those prepared by
the Company's engineering staff. All reports by DeGolyer and MacNaughton were
developed utilizing geological and engineering data provided by the Company.
No major discovery or other favorable or adverse event subsequent to
December 31, 1994 is believed to have caused a material change in the estimates
of proved or proved developed reserves as of that date.
F-21
The following table sets forth the Company's net proved and proved developed
reserves at December 31 for each of the four years in the period ended December
31, 1994, and the changes in the net proved reserves for each of the three years
in the period then ended as estimated by the Company's engineering staff.
NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
<TABLE>
<CAPTION>
UNITED STATES CANADA TRINIDAD INDIA TOTAL
------------- ------ -------- --------- ---------
<S> <C> <C> <C> <C> <C>
Natural Gas (Bcf)<F1>
Proved reserves at December 31,
1991........................... 1,455.9 128.9 - - 1,584.8
Revisions of previous
estimates.................. (46.3) (4.1) - - (50.4)
Purchases in place........... 30.5 112.6 - - 143.1
Extensions, discoveries and
other additions............ 228.0 6.3 - - 234.3
Sales in place............... (27.7) - - - (27.7)
Production................... (200.0) (11.2) - - (211.2)
------------- ------ -------- --------- ---------
Proved reserves at December 31,
1992........................... 1,440.4<F2> 232.5 - - 1,672.9
Revisions of previous
estimates.................. (31.3) 11.0 - - (20.3)
Purchases in place........... 9.2 2.6 - - 11.8
Extensions, discoveries and
other additions............ 234.9 47.7 101.3 - 383.9
Sales in place............... (12.5) (1.5) - - (14.0)
Production................... (240.0) (21.3) (.8) - (262.1)
------------- ------ -------- --------- ---------
Proved reserves at December 31,
1993........................... 1,400.7<F2> 271.0 100.5 - 1,772.2
Revisions of previous
estimates.................. (17.1) (6.5) 15.0 - (8.6)
Purchases in place........... 18.8 9.2 - 29.3 57.3
Extensions, discoveries and
other additions............ 233.8 50.2 113.9 - 397.9
Sales in place............... (29.3) (1.0) - - (30.3)
Production................... (228.6) (26.3) (23.2) - (278.1)
------------- ------ -------- --------- ---------
Proved reserves at December 31,
1994........................... 1,378.3<F2> 296.6 206.2 29.3 1,910.4
============= ====== ======== ========= =========
Liquids (MBbl)<F3><F4>
Proved reserves at December 31,
1991........................... 13,822 6,512 - - 20,334
Revisions of previous
estimates.................. 365 (885) - - (520)
Purchases in place........... 65 - - - 65
Extensions, discoveries and
other additions............ 2,320 698 - - 3,018
Sales in place............... (296) (4) - - (300)
Production................... (2,411) (963) - - (3,374)
------------- ------ -------- --------- ---------
Proved reserves at December 31,
1992........................... 13,865<F2> 5,358 - - 19,223
Revisions of previous
estimates.................. 1,490 (536) - - 954
Purchases in place........... 15 489 - - 504
Extensions, discoveries and
other additions............ 3,552 1,115 2,251 - 6,918
Sales in place............... (3,230) (23) - - (3,253)
Production................... (2,520) (932) (33) - (3,485)
------------- ------ -------- --------- ---------
Proved reserves at December 31,
1993........................... 13,172<F2> 5,471 2,218 - 20,861
Revisions of previous
estimates.................. 2,179 (177) 455 - 2,457
Purchases in place........... 358 - - 7,617 7,975
Extensions, discoveries and
other additions............ 5,332 2,848 2,687 - 10,867
Sales in place............... (257) - - - (257)
Production................... (2,997) (905) (931) (32) (4,865)
------------- ------ -------- --------- ---------
Proved reserves at December 31,
1994........................... 17,787<F2> 7,237 4,429 7,585 37,038
============= ====== ======== ========= =========
F-22
Proved developed reserves at
Natural Gas (Bcf)
December 31, 1991............ 1,138.5 113.0 - - 1,251.5
December 31, 1992............ 1,168.4<F2> 194.4 - - 1,362.8
December 31, 1993............ 1,167.3<F2> 250.6 71.4 - 1,489.3
December 31, 1994............ 1,199.1<F2> 288.3 206.2 - 1,693.6
Liquids (MBbl)<F4>
December 31, 1991............ 13,002 6,484 - - 19,486
December 31, 1992............ 12,762<F2> 5,329 - - 18,091
December 31, 1993............ 11,165<F2> 5,409 1,591 - 18,165
December 31, 1994............ 16,770<F2> 7,073 4,429 7,585 35,857
<FN>
<F1> Billion cubic feet
<F2> Includes approximately 71 billion cubic feet equivalent (78 trillion
British thermal units) in 1994, 87 billion cubic feet equivalent (96
trillion British thermal units) in 1993 and 114 billion cubic feet
equivalent (126 trillion British thermal units) in 1992 associated with a
volumetric production payment sold effective October 1, 1992 to be
delivered over a seventy-eight month period, as revised, which period
commenced October 1, 1992.
<F3> Thousand barrels
<F4> Includes crude oil, condensate and natural gas liquids.
</TABLE>
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES. The
following table sets forth the capitalized costs relating to the Company's
natural gas and crude oil producing activities at December 31, 1994 and 1993:
1994 1993
-------------- --------------
Proved properties.................... $ 2,889,242 $ 2,675,419
Unproved properties.................. 126,193 96,801
-------------- --------------
Total............................ 3,015,435 2,772,220
Accumulated depreciation, depletion
and amortization................... (1,330,624) (1,226,175)
-------------- --------------
Net capitalized costs................ $ 1,684,811 $ 1,546,045
============== ==============
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND
DEVELOPMENT ACTIVITIES. The acquisition, exploration and development costs
disclosed in the following tables are in accordance with definitions in SFAS
No. 19 - "Financial Accounting and Reporting by Oil and Gas Producing
Companies".
Acquisition costs include costs incurred to purchase, lease, or otherwise
acquire property.
Exploration costs include exploration expenses, additions to exploration
wells in progress, and depreciation of support equipment used in exploration
activities.
Development costs include additions to production facilities and equipment,
additions to development wells in progress and related facilities, and
depreciation of support equipment and related facilities used in development
activities.
The following tables set forth costs incurred related to the Company's oil
and gas activities for the years ended December 31:
<TABLE>
<CAPTION>
FOREIGN
----------------------------------------------
UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL
------------- ---------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
1994
Acquisition Costs of Properties
Unproved......................... $ 45,776 $ 6,618 $ - $ - $ (17) $ 52,377
Proved........................... 17,367 4,523 - 12,300 - 34,190
------------- ---------- ---------- ---------- ---------- -----------
Total........................ 63,143 11,141 - 12,300 (17) 86,567
Exploration Costs.................... 70,669 8,210 850 2,302 11,242 93,273
Development Costs.................... 223,241 35,896 60,778 767 564 321,246
------------- ---------- ---------- ---------- ---------- -----------
Total........................ $ 357,053 $ 55,247 $ 61,628 $ 15,369 $ 11,789 $ 501,086
============= ========== ========== ========== ========== ===========
F-23
1993
Acquisition Costs of Properties
Unproved......................... $ 23,686 $ 4,556 $ - $ - $ 887 $ 29,129
Proved........................... 6,625 2,598 - - - 9,223
------------- ---------- ---------- ---------- ---------- -----------
Total........................ 30,311 7,154 - - 887 38,352
Exploration Costs.................... 53,918 9,096 1,367 - 18,595 82,976
Development Costs.................... 247,705 28,045 41,262 - - 317,012
------------- ---------- ---------- ---------- ---------- -----------
Total........................ $ 331,934 $ 44,295 $ 42,629 $ - $ 19,482 $ 438,340
============= ========== ========== ========== ========== ===========
1992
Acquisition Costs of Properties
Unproved......................... $ 21,844 $ 1,173 $ - $ - $ 3 $ 23,020
Proved........................... 25,958 39,281 - - - 65,239
------------- ---------- ---------- ---------- ---------- -----------
Total........................ 47,802 40,454 - - 3 88,259
Exploration Costs.................... 38,547 5,787 151 - 10,990 55,475
Development Costs.................... 256,814 5,162 735 - - 262,711
------------- ---------- ---------- ---------- ---------- -----------
Total........................ $ 343,163 $ 51,403 $ 886 $ - $ 10,993 $ 406,445
============= ========== ========== ========== ========== ===========
</TABLE>
<TABLE>
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES<F1>. The
following tables set forth results of operations for oil and gas producing
activities for the years ended December 31:
<CAPTION>
FOREIGN
--------------------------------------------
UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL
------------- --------- -------- -------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
1994
Operating Revenues
Associated Companies............. $ 315,866 $ 8,452 $ - $ - $ - $ 324,318
Trade............................ 115,375 42,017 35,908 509 - 193,809
Gains (Losses) on Sales of
Reserves and Related Assets.... 54,026 (12) - - - 54,014
------------- --------- -------- -------- --------- -----------
Total........................ 485,267 50,457 35,908 509 - 572,141
Exploration Expenses, including Dry
Hole............................... 42,242 4,503 836 2,302 9,125 59,008
Production Costs..................... 68,998 12,776 5,083 26 - 86,883
Impairment of Unproved Oil and Gas
Properties......................... 23,862 1,074 - - - 24,936
Depreciation, Depletion and
Amortization....................... 218,433 16,572 6,572 - 281 241,858
------------- --------- -------- -------- --------- -----------
Income (Loss) before Income Taxes.... 131,732 15,532 23,417 (1,819) (9,406) 159,456
Income Tax Provision (Benefit)....... (8,617) 6,175 12,804 (910) (2,873) 6,579
------------- --------- -------- -------- --------- -----------
Results of Operations................ $ 140,349 $ 9,357 $ 10,613 $ (909) $ (6,533) $ 152,877
============= ========= ======== ======== ========= ===========
F-24
1993
Operating Revenues
Associated Companies............. $ 369,824 $ 9,637 $ - $ - $ - $ 379,461
Trade............................ 140,552 33,228 1,209 - - 174,989
Gains (Losses) on Sales of
Reserves and Related Assets.... 13,724 (406) - - - 13,318
------------- --------- -------- -------- --------- -----------
Total........................ 524,100 42,459 1,209 - - 567,768
Exploration Expenses, including Dry
Hole............................... 35,029 6,657 1,367 - 12,223 55,276
Production Costs..................... 75,767 14,063 1,496 - - 91,326
Impairment of Unproved Oil and Gas
Properties......................... 19,499 968 - - - 20,467
Depreciation, Depletion and
Amortization....................... 234,292 14,630 387 - 154 249,463
------------- --------- -------- -------- --------- -----------
Income (Loss) before Income Taxes.... 159,513 6,141 (2,041) - (12,377) 151,236
Income Tax Provision (Benefit)....... (15,525) 2,265 (1,020) - (1,742) (16,022)
------------- --------- -------- -------- --------- -----------
Results of Operations................ $ 175,038 $ 3,876 $ (1,021) $ - $ (10,635) $ 167,258
============= ========= ======== ======== ========= ===========
1992
Operating Revenues
Associated Companies............. $ 251,649 $ 10,074 $ - $ - $ - $ 261,723
Trade............................ 106,633 19,313 - - - 125,946
Gains on Sales of Reserves and
Related Assets................. 6,037 - - - - 6,037
------------- --------- -------- -------- --------- -----------
Total........................ 364,319 29,387 - - - 393,706
Exploration Expenses, including Dry
Hole............................... 29,705 3,829 151 - 10,357 44,042
Production Costs..................... 63,571 9,271 - - - 72,842
Impairment of Unproved Oil and Gas
Properties......................... 12,001 1,034 - - 2,101 15,136
Depreciation, Depletion and
Amortization....................... 167,767 11,719 - - 327 179,813
------------- --------- -------- -------- --------- -----------
Income (Loss) before Income Taxes.... 91,275 3,534 (151) - (12,785) 81,873
Income Tax Provision (Benefit)....... (13,977) 1,202 (75) - (4,323) (17,173)
------------- --------- -------- -------- --------- -----------
Results of Operations................ $ 105,252 $ 2,332 $ (76) $ - $ (8,462) $ 99,046
============= ========= ======== ======== ========= ===========
<FN>
<F1> Excludes net revenues associated with other marketing activities, interest
charges, general corporate expenses and certain gathering and handling
fees for each of the three years in the period ended December 31, 1994.
The gathering and handling fees and other marketing net revenues are
directly associated with oil and gas operations with regard to segment
reporting as defined in SFAS No. 14 - "Financial Reporting for Segments of
a Business Enterprise", but are not part of Disclosures about Oil and Gas
Producing Activities as defined in SFAS No. 69.
</TABLE>
F-25
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
OIL AND GAS RESERVES. The following information has been developed utilizing
procedures prescribed by SFAS No. 69 and based on crude oil and natural gas
reserve and production volumes estimated by the engineering staff of the
Company. It may be useful for certain comparison purposes, but should not be
solely relied upon in evaluating the Company or its performance. Further,
information contained in the following table should not be considered as
representative of realistic assessments of future cash flows, nor should the
Standardized Measure of Discounted Future Net Cash Flows be viewed as
representative of the current value of the Company.
The future cash flows presented below are based on sales prices, cost rates,
and statutory income tax rates in existence as of the date of the projections.
It is expected that material revisions to some estimates of crude oil and
natural gas reserves may occur in the future, development and production of the
reserves may occur in periods other than those assumed, and actual prices
realized and costs incurred may vary significantly from those used.
Management does not rely upon the following information in making investment
and operating decisions. Such decisions are based upon a wide range of factors,
including estimates of probable as well as proved reserves, and varying price
and cost assumptions considered more representative of a range of possible
economic conditions that may be anticipated.
The following table sets forth the standardized measure of discounted future
net cash flows from projected production of the Company's crude oil and natural
gas reserves at December 31, for the years ended December 31:
<TABLE>
<CAPTION>
1994 UNITED STATES CANADA TRINIDAD INDIA TOTAL
- ---- ------------- --------- -------- --------- -----------
<S> <C> <C> <C> <C> <C>
Future revenues<F1>.................. $2,411,087<F2> $ 487,050 $317,758 $ 168,370 $ 3,384,265
Future production costs.............. (606,932) (196,275) (87,479) (105,840) (996,526)
Future development costs............. (135,768) (9,596) (1,781) (4,500) (151,645)
---------- --------- -------- --------- -----------
Future net cash flows before income
taxes.............................. 1,668,387 281,179 228,498 58,030 2,236,094
Discount to present value at 10%
annual rate........................ (617,960) (106,353) (54,380) (29,460) (808,153)
---------- --------- -------- --------- -----------
Present value of future net cash
flows before income taxes.......... 1,050,427 174,826 174,118 28,570 1,427,941
Future income taxes discounted at 10%
annual rate<F3>.................... (27,353) (17,885) (70,688) (7,752) (123,678)
---------- --------- -------- --------- -----------
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves<F1>.... $1,023,074<F4> $ 156,941 $103,430 $ 20,818 $ 1,304,263
========== ========= ======== ========= ===========
F-26
1993
Future revenues<F1>.................. $3,343,900<F2> $ 592,845 $147,542 $ - $ 4,084,287
Future production costs.............. (639,760) (230,230) (45,385) - (915,375)
Future development costs............. (165,473) (21,001) (7,582) - (194,056)
---------- --------- -------- --------- -----------
Future net cash flows before income
taxes.............................. 2,538,667 341,614 94,575 - 2,974,856
Discount to present value at 10%
annual rate........................ (951,748) (143,992) (20,097) - (1,115,837)
---------- --------- -------- --------- -----------
Present value of future net cash
flows before income taxes.......... 1,586,919 197,622 74,478 - 1,859,019
Future income taxes discounted at 10%
annual rate<F3>.................... (219,228) (37,851) (24,899) - (281,978)
---------- --------- -------- --------- -----------
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves<F1>.... $1,367,691<F4> $ 159,771 $ 49,579 $ - $ 1,577,041
========== ========= ======== ========= ===========
1992
Future revenues<F1>.................. $3,017,188<F2> $ 363,284 - - $ 3,380,472
Future production costs.............. (573,763) (105,802) - - (679,565)
Future development costs............. (194,246) (12,881) - - (207,127)
---------- --------- -------- --------- -----------
Future net cash flows before income
taxes.............................. 2,249,179 244,601 - - 2,493,780
Discount to present value at 10%
annual rate........................ (790,027) (91,126) - - (881,153)
---------- --------- -------- --------- -----------
Present value of future net cash
flows before income taxes.......... 1,459,152 153,475 - - 1,612,627
Future income taxes discounted at 10%
annual rate<F3>.................... (147,736) (28,056) - - (175,792)
---------- --------- -------- --------- -----------
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves<F1>.... $1,311,416<F4> $ 125,419 $ - $ - $ 1,436,835
========== ========= ======== ========= ===========
- ---------
<FN>
<F1> Based on year end market prices determined at the point of delivery from
the producing unit.
<F2> "Future revenues" includes approximately $95.9 million ($77.9 million
discounted at 10% annual rate) for 1994, $189.1 million ($146.9 million
discounted at 10% annual rate) for 1993 and $203.5 million ($174.5 million
discounted at 10% annual rate) for 1992 related to volumes associated with
a volumetric production payment sold effective October 1, 1992, as
amended, to be delivered over a seventy-eight month period, as revised,
which period commenced October 1, 1992.
<F3> Future income taxes before discount were $230.0 million U.S., $57.2
million Canada, $102.2 million Trinidad, $22.5 million India and $411.9
million total; $540.3 million U.S., $91.7 million Canada, $35.5 million
Trinidad and $667.5 million total and $394.1 million U.S., $63.0 million
Canada and $457.1 million total for the years ended December 31, 1994,
1993 and 1992, respectively.
<F4> Includes approximately $49.3 million, $92.6 million and $111.2 million in
1994, 1993 and 1992, respectively representing the discounted present
value at a discount rate of 10% of the "Future revenues" detailed in note
(2) after deducting future income taxes.
</TABLE>
F-27
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The
following table sets forth the changes in the standardized measure of discounted
future net cash flows at December 31, for each of the three years in the period
ended December 31, 1994.
<TABLE>
<CAPTION>
UNITED STATES CANADA TRINIDAD INDIA TOTAL
------------- ----------- ----------- ----------- -------------
<S> <C> <C> <C> <C> <C>
December 31, 1991.................... $ 1,061,821 $ 94,256 $ - $ - $ 1,156,077
Sales and transfers of oil and gas
produced, net of production
costs........................... (294,711) (20,116) - - (314,827)
Net changes in prices and
production costs................ 257,572 8,190 - - 265,762
Extensions, discoveries, additions
and improved recovery net of
related costs................... 275,231 8,999 - - 284,230
Development costs incurred........ 49,668 177 - - 49,845
Revisions of estimated development
costs........................... (19,540) 1,406 - - (18,134)
Revisions of previous quantity
estimates....................... (45,863) (7,539) - - (53,402)
Accretion of discount............. 118,901 12,224 - - 131,125
Net change in income taxes........ (20,548) (77) - - (20,625)
Purchases of reserves in place.... 28,884 32,533 - - 61,417
Sales of reserves in place........ (34,984) (15) - - (34,999)
Changes in timing and other....... (65,015) (4,619) - - (69,634)
------------ ----------- ----------- ----------- -------------
December 31, 1992.................... 1,311,416 125,419 - - 1,436,835
Sales and transfers of oil and gas
produced, net of production
costs........................... (434,609) (28,802) 287 - (463,124)
Net changes in prices and
production costs................ 180,240 28,400 - - 208,640
Extensions, discoveries, additions
and improved recovery net of
related costs................... 275,722 27,785 74,191 - 377,698
Development costs incurred........ 58,500 13,900 - - 72,400
Revisions of estimated development
costs........................... 32,196 (1,345) - - 30,851
Revisions of previous quantity
estimates....................... (26,118) 5,668 - - (20,450)
Accretion of discount............. 145,915 15,348 - - 161,263
Net change in income taxes........ (71,492) (9,795) (24,899) - (106,186)
Purchases of reserves in place.... 9,462 2,707 - - 12,169
Sales of reserves in place........ (38,498) (1,140) - - (39,638)
Changes in timing and other....... (75,043) (18,374) - - (93,417)
------------ ----------- ----------- ----------- -------------
December 31, 1993.................... 1,367,691 159,771 49,579 - 1,577,041
Sales and transfers of oil and gas
produced, net of production
costs........................... (362,243) (37,693) (30,825) (483) (431,244)
Net changes in prices and
production costs................ (566,358) (65,287) 11,002 - (620,643)
Extensions, discoveries, additions
and improved recovery net of
related costs................... 225,366 51,006 96,515 - 372,887
Development costs incurred........ 69,900 6,700 7,582 - 84,182
Revisions of estimated development
costs........................... 6,792 5,931 - - 12,723
Revisions of previous quantity
estimates....................... (2,909) (3,407) 14,077 - 7,761
Accretion of discount............. 158,692 19,762 7,448 - 185,902
Net change in income taxes........ 191,875 19,966 (45,789) (7,752) 158,300
Purchases of reserves in place.... 16,651 3,404 - 29,053 49,108
Sales of reserves in place........ (27,980) (461) - - (28,441)
Changes in timing and other....... (54,403) (2,751) (6,159) - (63,313)
------------ ----------- ----------- ----------- -------------
December 31, 1994.................... $ 1,023,074 $ 156,941 $ 103,430 $ 20,818 $ 1,304,263
============ =========== =========== =========== =============
</TABLE>
F-28
UNAUDITED QUARTERLY FINANCIAL INFORMATION
<TABLE>
<CAPTION>
QUARTER ENDED
------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
1994
Net Operating Revenues............... $ 158,208 $ 155,449 $ 160,683 $ 151,483
========= ========= ========= =========
Operating Income..................... $ 38,938 $ 39,081 $ 52,020 $ 29,602
========= ========= ========= =========
Income before Income Taxes........... $ 39,088 $ 36,581 $ 50,497 $ 27,769
Income Tax Provision (Benefit)....... 8,830 2,369 9,529 (14,791)
--------- --------- --------- ---------
Net Income........................... $ 30,258 $ 34,212 $ 40,968 $ 42,560
========= ========= ========= =========
Earnings Per Share of Common Stock... $ .19 $ .21 $ .26 $ .27
========= ========= ========= =========
Average Number of Common Shares...... 159,840 159,859 159,777 159,902
========= ========= ========= =========
1993
Net Operating Revenues............... $ 136,834 $ 140,486 $ 152,647 $ 151,053
========= ========= ========= =========
Operating Income..................... $ 29,633 $ 31,517 $ 38,451 $ 15,958
========= ========= ========= =========
Income before Income Taxes........... $ 28,955 $ 29,598 $ 37,168 $ 16,552
Income Tax Provision (Benefit)....... (1,253) (3,923) 1,412 (21,988)
--------- --------- --------- ---------
Net Income........................... $ 30,208 $ 33,521 $ 35,756 $ 38,540
========= ========= ========= =========
Earnings Per Share of Common Stock... $ .19 $ .21 $ .22 $ .24
========= ========= ========= =========
Average Number of Common Shares...... 160,000 160,000 160,000 159,865
========= ========= ========= =========
1992
Net Operating Revenues............... $ 98,630 $ 106,490 $ 111,840 $ 142,066
========= ========= ========= =========
Operating Income..................... $ 20,936 $ 19,855 $ 24,374 $ 40,444
========= ========= ========= =========
Income before Income Taxes........... $ 14,079 $ 11,665 $ 18,639 $ 35,461
Income Tax Benefit................... (8,208) (2,900) (1,960) (4,668)
--------- --------- --------- ---------
Net Income........................... $ 22,287 $ 14,565 $ 20,599 $ 40,129
========= ========= ========= =========
Earnings Per Share of Common Stock... $ .15 $ .10 $ .13 $ .25
========= ========= ========= =========
Average Number of Common Shares...... 151,800 151,800 154,533 160,000
========= ========= ========= =========
</TABLE>
F-29
SCHEDULE II
ENRON OIL & GAS COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
(IN THOUSANDS)
<TABLE>
<CAPTION>
===================================================================================================
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ---------------------------------------------------------------------------------------------------
ADDITIONS DEDUCTIONS
BALANCE AT CHARGED TO FOR PURPOSE FOR BALANCE AT
BEGINNING OF COSTS AND WHICH RESERVES END OF
DESCRIPTION YEAR EXPENSES WERE CREATED YEAR
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1994
Reserves deducted from assets to
which they apply -
Revaluation of Accounts
Receivable..................... $ 1,020 $ 2 $ - $ 1,022
======== ======== ========= ========
Litigation Reserve<F1>............... $ 2,000 $ 3,143 $ 3,143 $ 2,000
======== ======== ========= ========
1993
Reserves deducted from assets to
which they apply -
Revaluation of Accounts
Receivable..................... $ - $ 1,020 $ - $ 1,020
======== ======== ========= ========
Litigation Reserve<F1>............... $ 2,030 $ 2,520 $ 2,550 $ 2,000
======== ======== ========= ========
1992
Reserves deducted from assets to
which they apply -
Revaluation of Accounts
Receivable..................... $ 5,656 $ 600 $ 6,256 $ -
======== ======== ========= ========
Litigation Reserve<F1>............... $ 1,082 $ 2,194 $ 1,246 $ 2,030
======== ======== ========= ========
- ---------
<FN>
<F1> Included in Other Liabilities on the consolidated balance sheets.
</TABLE>
S-1
EXHIBITS
Exhibits not incorporated herein by reference to a prior filing are
designated by an asterisk (*) and are filed herewith; all exhibits not so
designated are incorporated herein by reference to the Company's Form S-1
Registration Statement, Registration No. 33-30678, filed on August 24, 1989
("Form S-1"), or as otherwise indicated.
3.1(a) - Restated Certificate of Incorporation of Enron Oil & Gas
Company (Exhibit 3.1 to Form S-1).
3.1(b) - Certificate of Amendment of Restated Certificate of
Incorporation of Enron Oil & Gas Company (Exhibit 4.1(b)
to Form S-8 Registration Statement, Registration No.
33-52201, filed on February 8, 1994).
3.1(c) - Certificate of Amendment of Restated Certificate of
Incorporation of Enron Oil & Gas Company (Exhibit 4.1(c)
to Form S-8 Registration Statement, Registration No.
33-58103, filed on March 15, 1995).
3.2* - Bylaws of Enron Oil & Gas Company.
3.3 - Specimen of Certificate evidencing the Common Stock
(Exhibit 3.3 to Form S-1).
4.1 - Promissory Note due May 1, 1996, dated May 1, 1991
(Exhibit 4.1 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1991).
4.3 - Amended and Restated Enron Oil & Gas Company 1994 Stock
Plan (Exhibit 4.3 to Form S-8 Registration Statement,
Registration No. 33-58103, filed on March 15, 1995).
10.1 - Services Agreement, dated as of January 1, 1994, between
Enron Oil & Gas Company and Enron Corp. (Exhibit 10.1 to
the Company's Annual Report on Form 10-K for the year
ended December 31, 1993).
10.2 - Stock Restriction and Registration Agreement dated as of
August 23, 1989 (Exhibit 10.2 to Form S-1).
10.3 - Tax Allocation Agreement dated as of August 23, 1989
(Exhibit 10.3 to Form S-1), and First Amended and Restated
Tax Allocation Agreement dated as of August 9, 1991, as
amended on February 6, 1992 (Exhibit 10.3 to Form S-1
Registration Statement, Registration No. 33-50462, filed
on August 5, 1992).
10.4 - Enron Corp. Deferral Plan dated December 10, 1985 (Exhibit
10.12 to Form S-1).
10.5 - Enron Corp. 1988 Stock Plan (Exhibit 10.13 to Form S-1).
10.7 - Enron Corp. 1984 Stock Option Plan (Exhibit 10.15 to
Form S-1).
10.8 - Enron Corp. 1986 Stock Option Plan (Exhibit 10.16 to
Form S-1).
10.9(a) - Employment Agreement between Enron Oil & Gas Company and
Forrest Hoglund, dated as of September 1, 1987, as amended
(Exhibit 10.19 to Form S-1), and Second and Third
Amendments to Employment Agreement dated June 30, 1989 and
February 14, 1992, respectively (Exhibit 10.10 to Form S-1
Registration Statement, Registration No. 33-50462, filed
on August 5, 1992).
10.9(b)* - 4th Amendment to Employment Agreement dated December 14,
1994, among Enron Corp., Enron Oil & Gas Company and
Forrest Hoglund.
10.10 - Fuel Supply Contract, dated as of June 30, 1986, by and
between Enron Oil & Gas Company, HNG Oil Company, BelNorth
Petroleum Corporation and Enron Cogenration One Company,
as amended (Exhibit 10.23 to Form S-1).
10.11 - Gas Sales Contract dated September 2, 1987 between Enron
Oil & Gas Company and Cogenron Inc., as amended (Exhibit
10.24 to Form S-1).
10.12 - Letter Agreement dated August 20, 1987 between Enron Oil &
Gas Company and Panhandle Gas Company (Exhibit 10.25 to
Form S-1).
E-1
10.13 - Pension Program for Enron Corp. Deferral Plan
Participants, effective January 1, 1985, as amended
(Exhibit 10.29 to Form S-1).
10.14 - Enron Oil & Gas Company 1993 Nonemployee Director Stock
Option Plan (Exhibit 10.14 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1992).
10.15(a) - Credit Agreement, dated as of March 11, 1994, among Enron
Oil & Gas Company, the Banks named therein and Texas
Commerce Bank, National Association, as Administrative
Agent and Promissory Note due January 15, 1998, dated
March 11, 1994 to the order of Texas Commerce Bank
National Association, Promissory Note due January 15,
1998, dated March 11, 1994 to the order of The Bank of New
York, Promissory Note due January 15, 1998, dated March
11, 1994 to the order of The Bank of Nova Scotia,
Promissory Note due January 15, 1998, dated March 11, 1994
to the order of Credit Lyonnais Cayman Islands Branch,
Promissory Note due January 15, 1998, dated March 11, 1994
to the order of Credit Suisse, Promissory Note due January
15, 1998, dated March 11, 1994 to the order of The First
National Bank of Chicago, and Promissory Note due January
15, 1998, dated March 11, 1994 to the order of Bank of
America National Trust and Savings Association (Exhibit
10.15 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1993).
10.15(b)* - Assignment and Acceptance dated April 14, 1994, between
Texas Commerce Bank National Association and Royal Bank of
Canada and Promissory Note due January 15, 1998, dated
April 14, 1994, to the order of Texas Commerce Bank
National Association and Promissory Note due January 15,
1998, dated April 14, 1994, to the order of Royal Bank of
Canada.
10.16 - Interest Rate and Currency Exchange Agreement, dated as of
June 1, 1991, between Enron Risk Management Services Corp.
and Enron Oil & Gas Market- ing, Inc. (Exhibit 10.17 to
the Company's Annual Report on Form 10-K for the year
ended December 31, 1991), Confirmation dated June 14, 1992
(Exhibit 10.17 to Form S-1 Registration Statement,
Registration No. 33-50462, filed on August 5, 1992) and
Confirmations dated March 25, 1991, April 25, 1991, and
September 23, 1992 (assigned to Enron Risk Management
Services Corp. by Enron Finance Corp. pursuant to an
Assignment and Assumption Agreement, dated as of November
1, 1993, by and between Enron Finance Corp., Enron Risk
Management Services Corp. and Enron Oil & Gas Marketing,
Inc.). (Exhibit 10.16 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1993).
10.17 - Assignment and Assumption Agreement, dated as of November
1, 1993, by and between Enron Oil & Gas Marketing, Inc.,
Enron Oil & Gas Company and Enron Risk Management Services
Corp. (Exhibit 10.17 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1993).
10.18 - ISDA Master Agreement, dated as of November 1, 1993,
between Enron Oil & Gas Company and Enron Risk Management
Services Corp., and Confirmation Nos. 1268.0, 1286.0,
1291.0, 1292.0, 1304.0, 1305.0, 1321.0, 1335.0, 1338.0,
1370.0, 1471.0, 1485.0, 1486.0, 1494.0, 1495.0, 1509.0,
1514.0, 1533.01, 1569.0, 1986.0, 2217.0, 2227.0, 2278.0,
2299.0, 2372.0, 2647.0 (Exhibit 10.18 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1993).
10.19 - Letter Agreement between Colorado Interstate Gas Company
and Enron Oil & Gas Marketing, Inc. dated November 1, 1990
(Exhibit 10.18 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1990).
10.22 - Gas Sales Agreement between Enron Gas Marketing, Inc. and
Enron Oil & Gas Marketing, Inc. dated August 22, 1989
(Exhibit 10.38 to Form S-1).
10.23 - Gas Purchase Agreement between Enron Oil & Gas Company and
Enron Oil & Gas Marketing, Inc. dated August 22, 1989
(Exhibit 10.41 to Form S-1).
10.24 - Gas Purchase Agreement between Enron Oil & Gas Company and
Enron Oil & Gas Marketing, Inc. dated August 22, 1989
(Exhibit 10.42 to Form S-1).
E-2
10.25 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Corp.
Annual Report on Form 10-K for the year ended
December 31, 1991).
10.26 - Enron Corp. 1988 Deferral Plan (Exhibit 10.49 to
Form S-1).
10.27 - Form of Enron Corp. Long-Term Incentive Plan Effective as
of January 1, 1987 (Exhibit 10.50 to Form S-1).
10.28 - Enron Executive Supplemental Survivor Benefits Plan
Effective January 1, 1987 (Exhibit 10.51 to Form S-1).
10.29 - 1988 FlexPerq Program Summary (Exhibit 10.52 to Form S-1).
10.30 - Credit Agreement between Enron Corp. and Enron Oil & Gas
Company dated September 29, 1992 (Exhibit 10.28 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1992).
10.31 - Credit Agreement between Enron Oil & Gas Company and Enron
Corp. dated September 29, 1992 (Exhibit 10.29 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1992).
10.33 - Swap Agreement between Banque Paribas and Enron Oil & Gas
Company, dated as of December 5, 1990 (Exhibit 10.37 to
the Company's Annual Report on Form 10-K for the year
ended December 31, 1990), and Confirmations dated March
25, 1991 and April 25, 1991 (Exhibit 10.37 to Form S-1
Registration Statement, Registration No. 33-50462, filed
on August 5, 1992).
10.34 - Enron Oil & Gas Company 1992 Stock Plan (Exhibit 10.40 to
the Company's Annual Report on Form 10-K for the year
ended December 31, 1991).
10.35 - Enron Corp. 1992 Deferral Plan (Exhibit 10.41 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1991).
10.36(a) - Conveyance of Production Payment, dated September 25,
1992, between Enron Oil & Gas Company and Cactus
Hydrocarbon 1992-A Limited Partnership (Exhibit 10.34 to
the Company's Annual Report on Form 10-K for the year
ended December 31, 1992).
10.36(b) - First Amendment to Conveyance of Production Payment, dated
effective April 1, 1993 between Enron Oil & Gas Company
and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit
10.36(b) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1993).
10.36(c) - Second Amendment to Conveyance of Production Payment,
dated effective July 1, 1993 between Enron Oil & Gas
Company and Cactus Hydrocarbon 1992-A Limited Partnership
(Exhibit 10.36(c) to the Company's Annual Report on Form
10-K for the year ended December 31, 1993).
10.36(d) - Third Amendment to Conveyance of Production Payment, dated
effective October 1, 1993 between Enron Oil & Gas Company
and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit
10.36(d) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1993).
10.37(a) - Hydrocarbon Exchange Agreement dated September 25, 1992,
between Enron Oil & Gas Company and Cactus Hydrocarbon
1992-A Limited Partnership (Exhibit 10.35 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1992).
10.37(b)* - Amendment to Hydrocarbon Exchange Agreement dated
effective as of January 1, 1993, between Enron Oil & Gas
Company and Cactus Hydrocarbon 1992-A Limited Partnership.
10.37(c)* - First Amendment to Hydrocarbon Exchange Agreement dated
effective as of April 1, 1993, between Enron Oil & Gas
Company and Cactus Hydrocarbon 1992-A Limited Partnership.
10.37(d)* - Second Amendment to Hydrocarbon Exchange Agreement dated
effective as of July 1, 1993, between Enron Oil & Gas
Company and Cactus Hydrocarbon 1992-A Limited Partnership.
10.37(e)* - Amendment to Hydrocarbon Exchange Agreement dated
effective as of August 1, 1993, between Enron Oil & Gas
Company and Cactus Hydrocarbon 1992-A Limited Partnership.
E-3
10.37(f) - Fourth Amendment to Hydrocarbon Exchange Agreement, dated
effective October 1, 1993, between Enron Oil & Gas Company
and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit
10.37 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1993).
10.38 - Purchase and Sale Agreement, dated September 25, 1992,
between Enron Oil & Gas Company and Cactus Hydrocarbon
1992-A Limited Partnership (Exhibit 10.36 to the Company's
Annual Report on Form 10-K for the year ended
December 31, 1992).
10.39(a) - Production and Delivery Agreement, dated September 25,
1992, between Enron Oil & Gas Company and Cactus
Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37 to
the Company's Annual Report on Form 10-K for the year
ended December 31, 1992).
10.39(b) - First Amendment to Production and Delivery Agreement,
dated effective April 1, 1993 between Enron Oil & Gas
Company and Cactus Hydrocarbon 1992-A Limited Partnership
(Exhibit 10.39(b) to the Company's Annual Report on Form
10-K for the year ended December 31, 1993).
10.39(c) - Second Amendment to Production and Delivery Agreement,
dated effective July 1, 1993 between Enron Oil & Gas
Company and Cactus Hydrocarbon 1992-A Limited Partnership
(Exhibit 10.39(c) to the Company's Annual Report on Form
10-K for the year ended December 31, 1993).
10.39(d) - Third Amendment to Production and Delivery Agreement,
dated effective October 1, 1993 between Enron Oil & Gas
Company and Cactus Hydrocarbon 1992-A Limited Partnership
(Exhibit 10.39(d) to the Company's Annual Report on Form
10-K for the year ended December 31, 1993).
10.40 - Credit Agreement, dated as of March 8, 1994 between Enron
Gas & Oil Trinidad Limited and Caribbean Regional
Development Investment Trust, and Request for Advance No.
1, dated March 4, 1993, and Request for Advance No. 2,
dated March 4, 1993 (Exhibit 10.40 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1993).
10.41 - Promissory Note due May 1, 1998, dated as of March 8,
1994, to the order of Caribbean Regional Development
Investment Trust (Exhibit 10.41 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1993).
10.42 - Promissory Note due May 1, 1998, dated as of March 8, 1994
to the order of Caribbean Regional Development Investment
Trust (Exhibit 10.42 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1993).
10.43 - Letter of Credit and Reimbursement Agreement, dated March
8, 1994, between Enron Gas & Oil Trinidad Limited and
Credit Suisse (Exhibit 10.43 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1993).
10.44 - Parent Guaranty, dated March 8, 1994 between Enron Oil &
Gas Company and Credit Suisse (Exhibit 10.44 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1993).
10.45(a)* - Letter Loan Agreement dated as of May 27, 1994, between
Enron Gas & Oil Trinidad Limited and The Bank of Nova
Scotia.
10.45(b)* - Promissory Note due May 27, 1999, dated as of May 31,
1994, to the order of The Bank of Nova Scotia.
10.45(c)* - Promissory Note due May 27, 1999, dated as of January 10,
1995, to the order of The Bank of Nova Scotia.
10.46* - Guaranty dated as of May 27, 1994, between Enron Oil & Gas
Company and The Bank of Nova Scotia.
10.47* - Attorney Opinion Letter of Enron Oil & Gas International,
Inc. dated December 18, 1994 (Panna and Mukta Fields).
10.48* - Certificate of Enron Oil & Gas India Ltd. dated December
22, 1994 (Panna and Mukta Fields).
E-4
10.49* - Financial and Performance Guarantee of Enron Oil & Gas
International, Inc. dated December 22, 1994 (Panna and
Mukta Fields).
10.50* - Joint Operating Agreement effective as of December 22,
1994, among Oil & Natural Gas Corporation Limited, Enron
Oil & Gas India Ltd. and Reliance Industries Limited for
contract area identified as Panna and Mukta Fields
(Appendices B-1 and B-2 have been intentionally omitted.
The Company hereby agrees to furnish a copy of either
appendix to the Commission upon request).
10.51* - Production Sharing Contract dated as of December 22, 1994,
among The Government of India, Oil & Natural Gas
Corporation Limited, Reliance Industries Limited and Enron
Oil & Gas India Ltd., for contract area identified as
Panna and Mukta Fields [Appendices B-1 and B-2 and
Appendix G (Figures G-1, VIIA-1 to 10, VIIB-1 to 20 and
VIII-3) have all been intentionally omitted. The Company
hereby agrees to furnish a copy of any such appendix
and/or figure to the Commission upon request].
10.52* - Attorney Opinion Letter of Enron Oil & Gas International,
Inc. dated December 18, 1994 (Tapti Fields).
10.53* - Certificate of Enron Oil & Gas India Ltd. dated December
22, 1994 (Tapti Fields).
10.54* - Financial and Performance Guarantee of Enron Oil & Gas
International, Inc. dated December 22, 1994 (Tapti
Fields).
10.55* - Joint Operating Agreement effective as of December 22,
1994, among Oil & Natural Gas Corporation Limited, Enron
Oil & Gas India Ltd. and Reliance Industries Limited, for
contract area identified as Mid-Tapti and South-Tapti Gas
Fields [Appendix B (Figure B-1) has been intentionally
omitted. The Company hereby agrees to furnish a copy of
such appendix to the Commission upon request].
10.56* - Production Sharing Contract dated as of December 22, 1994,
among The Government of India, Oil & Natural Gas
Corporation Limited, Reliance Industries Limited and Enron
Oil & Gas India Ltd., for contract area identified as Mid
and South Tapti Field [Appendix B, Appendix G (Figures
G-1, VII-1 to 11, VIII-2 to 4 and Appendix 3) have all
been intentionally omitted. The Company hereby agrees to
furnish a copy of any such appendix, to the Commission
upon request].
22* - List of subsidiaries.
23.1* - Consent of DeGolyer and MacNaughton.
23.2* - Opinion of DeGolyer and MacNaughton dated
January 13, 1995.
23.3* - Consent of Arthur Andersen LLP.
24* - Powers of Attorney.
27* - Financial Data Schedule.
E-5
SIGNATURES
]PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, ON THE 22ND DAY OF
MARCH, 1995.
ENRON OIL & GAS COMPANY
(REGISTRANT)
By /s/ WALTER C. WILSON
(WALTER C. WILSON)
SENIOR VICE PRESIDENT AND CHIEF
FINANCIAL OFFICER
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BY THE FOLLOWING PERSONS ON BEHALF OF REGISTRANT AND IN
THE CAPACITIES WITH ENRON OIL & GAS COMPANY INDICATED AND ON THE 22ND DAY OF
MARCH, 1995.
SIGNATURE TITLE
- ----------------------- --------------------------------
/s/FORREST E. HOGLUND Chairman of the Board, President
(FORREST E. HOGLUND) and Chief Executive
Officer and Director
(Principal Executive Officer)
/s/WALTER C. WILSON Senior Vice President and Chief
(WALTER C. WILSON) Financial Officer
(Principal Financial Officer)
/s/BEN B. BOYD Vice President and Controller
(BEN B. BOYD) (Principal Accounting Officer)
FRED C. ACKMAN* Director
(FRED C. ACKMAN)
RICHARD D. KINDER* Director
(RICHARD D. KINDER)
KENNETH L. LAY* Director
(KENNETH L. LAY)
EDWARD RANDALL, III* Director
(EDWARD RANDALL, III)
*By /s/ANGUS H. DAVIS
(ANGUS H. DAVIS)
(ATTORNEY-IN-FACT FOR PERSONS INDICATED)
EXHIBIT 3.2
BYLAWS
OF
ENRON OIL & GAS COMPANY
A Delaware Corporation
Date of Adoption
August 23, 1989
As Amended
December 12, 1990
and
February 8, 1994
<PAGE>
BYLAWS
Table of Contents
Page
----
Article I. OFFICES
Section 1. Registered Office 1
Section 2. Other Offices 1
Article II. STOCKHOLDERS
Section 1. Place of Meetings 1
Section 2. Quorum; Adjournment of Meetings 1
Section 3. Annual Meetings 2
Section 4. Special Meetings 2
Section 5. Record Date 2
Section 6. Notice of Meeting 3
Section 7. Stockholder List 3
Section 8. Proxies 3
Section 9. Voting; Elections; Inspectors 4
Section 10. Conduct of Meetings 5
Section 11. Treasury Stock 5
Section 12. Business to Be Brought Before
the Annual Meeting 5
Article III. BOARD OF DIRECTORS
Section 1. Power; Number; Term of Office 6
Section 2. Quorum; Voting 7
Section 3. Place of Meetings; Order of Business 7
Section 4. First Meeting 7
Section 5. Regular Meetings 7
Section 6. Special Meetings 7
Section 7. Nomination of Directors 8
Section 8. Removal 9
Section 9. Vacancies; Increases in the Number
of Directors 9
Section 10. Compensation 9
Section 11. Action Without a Meeting; Telephone
Conference Meeting 9
Section 12. Approval or Ratification of Acts or
Contracts by Stockholders 10
Article IV. COMMITTEES
Section 1. Executive Committee 10
Section 2. Audit Committee 11
Section 3. Other Committees 11
Section 4. Procedure; Meetings; Quorum 11
Section 5. Substitution and Removal of Members;
Vacancies 11
Article V. OFFICERS
Section 1. Number, Titles and Term of Office 12
Section 2. Powers and Duties of the Chairman
of the Board 12
Section 3. Powers and Duties of the President,
President-North American Operations,
and President-International Operations 12
Section 4. Powers and Duties of Vice Chairman
of the Board 13
Section 5. Vice Presidents 13
Section 6. General Counsel 13
Section 7. Secretary 14
Section 8. Deputy Corporate Secretary and
Assistant Secretaries 14
Section 9. Treasurer 14
Section 10. Assistant Treasurers 14
Section 11. Action with Respect to Securities
of Other Corporations 15
Section 12. Delegation 15
Article VI. CAPITAL STOCK
Section 1. Certificates of Stock 15
Section 2. Transfer of Shares 16
Section 3. Ownership of Shares 16
Section 4. Regulations Regarding Certificates 16
Section 5. Lost or Destroyed Certificates 16
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Article VII. MISCELLANEOUS PROVISIONS
Section 1. Fiscal year 16
Section 2. Corporate Seal 17
Section 3. Notice and Waiver of Notice 17
Section 4. Facsimile Signatures 17
Section 5. Reliance upon Books, Reports and
Records 17
Section 6. Application of Bylaws 18
Article VIII. AMENDMENTS 18
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BYLAWS
OF
ENRON OIL & GAS COMPANY
Article I
OFFICES
SECTION 1. REGISTERED OFFICE. The registered office of the Corporation
required by the General Corporation Law of the State of Delaware to be
maintained in the State of Delaware shall be the registered office named in the
original Certificate of Incorporation of the Corporation, or such other office
as may be designated from time to time by the Board of Directors in the manner
provided by law.
SECTION 2. OFFICES. The Corporation may also have offices at such other
places both within and without the state of incorporation of the Corporation as
the Board of Directors may from time to time determine or the business of the
Corporation may require.
Article II
STOCKHOLDERS
SECTION 1. PLACE OF MEETINGS. All meetings of the stockholders shall be
held at the principal office of the Corporation, or at such other place within
or without the state of incorporation of the Corporation as shall be specified
or fixed in the notices or waivers of notice thereof.
SECTION 2. QUORUM; ADJOURNMENT OF MEETINGS. Unless otherwise required by
law or provided in the Certificate of Incorporation or these Bylaws, (i) the
holders of a majority of the stock issued and outstanding and entitled to vote
thereat, present in person or represented by proxy, shall constitute a quorum at
any meeting of stockholders for the transaction of business, (ii) in all matters
other than election of directors, the affirmative vote of the holders of a
majority of such stock so present or represented at any meeting of stockholders
at which a quorum is present shall constitute the act of the stockholders, and
(iii) where a separate vote by a class or classes is required, a majority of the
outstanding shares of such class or classes, present in person or represented by
proxy shall constitute a quorum entitled to take action with respect to that
vote on that matter and the affirmative vote of the majority of the shares of
such class or classes present in person or represented by proxy at the meeting
shall be the act of such class. The stockholders present at a duly organized
meeting may continue to transact business until adjournment, notwithstanding the
withdrawal of enough stockholders to leave less than a quorum, subject to the
provisions of clauses (ii) and (iii) above.
Directors shall be elected by a plurality of the votes of the shares
present in person or represented by proxy at the meeting and entitled to vote on
the election of directors.
Notwithstanding the other provisions of the Certificate of Incorporation or
these Bylaws, the chairman of the meeting or the holders of a majority of the
issued and outstanding stock, present in person or represented by proxy and
entitled to vote thereat, at any meeting of stockholders, whether or not a
quorum is present, shall have the power to adjourn such meeting from time to
time, without any notice other than announcement at the meeting of the time and
place of the holding of the adjourned meeting. If the adjournment is for more
than thirty (30) days, or if after the adjournment a new record date is fixed
for the adjourned meeting, a notice of the adjourned meeting shall be given to
each stockholder of record entitled to vote at such meeting. At such adjourned
meeting at which a quorum shall be present or represented any business may be
transacted which might have been transacted at the meeting as originally called.
SECTION 3. ANNUAL MEETINGS. An annual meeting of the stockholders, for the
election of directors to succeed those whose terms expire and for the
transaction of such other business as may properly come before the meeting,
shall be held at such place (within or without the state of incorporation of the
Corporation), on such date, and at such time as the Board of Directors shall fix
and set forth in the notice of the meeting, which date shall be within thirteen
(13) months subsequent to the last annual meeting of stockholders.
SECTION 4. SPECIAL MEETINGS. Unless otherwise provided in the Certificate
of Incorporation, special meetings of the stockholders for any purpose or
purposes may be called at any time by the Chairman of the Board, by the
President, by the Vice Chairman of the Board, by a majority of the Board of
Directors, or by a majority of the executive committee (if any), at such time
and at such place as may be stated in the notice of the meeting. A special
meeting of stockholders shall be called by the Chairman of the Board, the
President or the Secretary upon written request therefor, stating the purpose(s)
of the meeting, delivered to such officer and signed by the holder(s) of at
least ten percent (10%) of the issued and outstanding stock entitled to vote at
such meeting. Business transacted at a special meeting shall be confined to the
purpose(s) stated in the notice of such meeting.
-2-
SECTION 5. RECORD DATE. For the purpose of determining stockholders
entitled to notice of or to vote at any meeting of stockholders, or any
adjournment thereof, or entitled to receive payment of any dividend or other
distribution or allotment of any rights, or entitled to exercise any rights in
respect of any change, conversion or exchange of stock or for the purpose of any
other lawful action, the Board of Directors of the Corporation may fix a date as
the record date for any such determination of stockholders, which record date
shall not precede the date on which the resolutions fixing the record date are
adopted and which record date shall not be more than sixty (60) days nor less
than ten (10) days before the date of such meeting of stockholders, nor more
than sixty (60) days prior to any other action.
If the Board of Directors does not fix a record date for any meeting of the
stockholders, the record date for determining stockholders entitled to notice of
or to vote at such meeting shall be at the close of business on the day next
preceding the day on which notice is given, or, if in accordance with Article
VII, Section 3 of these Bylaws notice is waived, at the close of business on the
day next preceding the day on which the meeting is held. The record date for
determining stockholders for any other purpose shall be at the close of business
on the day on which the Board of Directors adopts the resolution relating
thereto. A determination of stockholders of record entitled to notice of or to
vote at a meeting of stockholders shall apply to any adjournment of the meeting;
provided, however, that the Board of Directors may fix a new record date for the
adjourned meeting.
SECTION 6. NOTICE OF MEETINGS. Written notice of the place, date and hour
of all meetings, and, in case of a special meeting, the purpose or purposes for
which the meeting is called, shall be given by or at the direction of the
Chairman of the Board, the President, the Vice Chairman of the Board, the
Secretary or the other person(s) calling the meeting to each stockholder
entitled to vote thereat not less than ten (10) nor more than sixty (60) days
before the date of the meeting. Such notice may be delivered either personally
or by mail. If mailed, notice is given when deposited in the United States mail,
postage prepaid, directed to the stockholder at such stockholder's address as it
appears on the records of the Corporation.
SECTION 7. STOCKHOLDER LIST. A complete list of stockholders entitled to
vote at any meeting of stockholders, arranged in alphabetical order for each
class of stock and showing the address of each such stockholder and the number
of shares registered in the name of such stockholder, shall be open to the
examination of any stockholder, for any purpose germane to the meeting, during
ordinary business hours, for a period of at least ten (10) days prior to the
meeting, either at a place within the city where the meeting is to be held,
which place shall be specified in the notice of the meeting, or if not so
specified, at the place where the meeting is to be held. The stockholder list
shall also be produced and kept at the time and place of the meeting during the
whole time thereof, and may be inspected by any stockholder who is present.
-3-
SECTION 8. PROXIES. Each stockholder entitled to vote at a meeting of
stockholders may authorize another person or persons to act for him by proxy.
Proxies for use at any meeting of stockholders shall be filed with the
Secretary, or such other officer as the Board of Directors may from time to time
determine by resolution, before or at the time of the meeting. All proxies shall
be received and taken charge of and all ballots shall be received and canvassed
by the secretary of the meeting, who shall decide all questions touching upon
the qualification of voters, the validity of the proxies, and the acceptance or
rejection of votes, unless an inspector or inspectors shall have been appointed
by the chairman of the meeting, in which event such inspector or inspectors
shall decide all such questions.
No proxy shall be valid after three (3) years from its date, unless the
proxy provides for a longer period. Each proxy shall be revocable unless
expressly provided therein to be irrevocable and coupled with an interest
sufficient in law to support an irrevocable power.
Should a proxy designate two or more persons to act as proxies, unless such
instrument shall provide the contrary, a majority of such persons present at any
meeting at which their powers thereunder are to be exercised shall have and may
exercise all the powers of voting or giving consents thereby conferred, or if
only one be present, then such powers may be exercised by that one; or, if an
even number attend and a majority do not agree on any particular issue, each
proxy so attending shall be entitled to exercise such powers in respect of such
portion of the shares as is equal to the reciprocal of the fraction equal to the
number of proxies representing such shares divided by the total number of shares
represented by such proxies.
SECTION 9. VOTING; ELECTIONS; INSPECTORS. Unless otherwise required by law
or provided in the Certificate of Incorporation, each stockholder shall on each
matter submitted to a vote at a meeting of stockholders have one vote for each
share of stock entitled to vote which is registered in his name on the record
date for the meeting. For the purposes hereof, each election to fill a
directorship shall constitute a separate matter. Shares registered in the name
of another corporation, domestic or foreign, may be voted by such officer, agent
or proxy as the bylaws (or comparable instrument) of such corporation may
prescribe, or in the absence of such provision, as the Board of Directors (or
comparable body) of such corporation may determine. Shares registered in the
name of a deceased person may be voted by the executor or administrator of such
person's estate, either in person or by proxy.
All voting, except as required by the Certificate of Incorporation or where
otherwise required by law, may be by a voice vote; provided, however, upon
request of the chairman of the meeting or upon demand therefor by stockholders
holding a majority of the issued and outstanding stock present in person or by
proxy at any meeting a stock
-4-
vote shall be taken. Every stock vote shall be taken by written ballots, each of
which shall state the name of the stockholder or proxy voting and such other
information as may be required under the procedure established for the meeting.
All elections of directors shall be by written ballots, unless otherwise
provided in the Certificate of Incorporation.
At any meeting at which a vote is taken by written ballots, the chairman of
the meeting may appoint one or more inspectors, each of whom shall subscribe an
oath or affirmation to execute faithfully the duties of inspector at such
meeting with strict impartiality and according to the best of such inspector's
ability. Such inspector shall receive the written ballots, count the votes and
make and sign a certificate of the result thereof. The chairman of the meeting
may appoint any person to serve as inspector, except no candidate for the office
of director shall be appointed as an inspector.
Unless otherwise provided in the Certificate of Incorporation, cumulative
voting for the election of directors shall be prohibited.
SECTION 10. CONDUCT OF MEETINGS. The meetings of the stockholders shall be
presided over by the Chairman of the Board, or if the Chairman of the Board is
not present, by the President, or if the President is not present, by the Vice
Chairman of the Board, or if neither the Chairman of the Board, the President
nor the Vice Chairman of the Board is present, by a chairman elected at the
meeting. The Secretary of the Corporation, if present, shall act as secretary of
such meetings, or if the Secretary is not present, the Deputy Corporate
Secretary or an Assistant Secretary shall so act; if neither the Secretary or
the Deputy Corporate Secretary or an Assistant Secretary is present, then a
secretary shall be appointed by the chairman of the meeting. The chairman of any
meeting of stockholders shall determine the order of business and the procedure
at the meeting, including such regulation of the manner of voting and the
conduct of discussion as seem to the chairman in order.
SECTION 11. TREASURY STOCK. The Corporation shall not vote, directly or
indirectly, shares of its own stock owned by it and such shares shall not be
counted for quorum purposes. Nothing in this Section 11 shall be construed as
limiting the right of the Corporation to vote stock, including but not limited
to its own stock, held by it in a fiduciary capacity.
SECTION 12. BUSINESS TO BE BROUGHT BEFORE THE ANNUAL MEETING. To be
properly brought before the annual meeting of stockholders, business must be
either (a) specified in the notice of meeting (or any supplement thereto) given
by or at the direction of the Board of Directors, (b) otherwise brought before
the meeting by or at the direction of the Board of Directors, or (c) otherwise
properly brought before the meeting by a stockholder of the Corporation who is a
stockholder of record at the time of giving of notice provided for in this
Section 12 of Article II, who shall be entitled to vote at such
-5-
meeting and who complies with the notice procedures set forth in this Section 12
of Article II. In addition to any other applicable requirements, for business to
be brought before an annual meeting by a stockholder of the Corporation, the
stockholder must have given timely notice thereof in writing to the Secretary of
the Corporation. To be timely, a stockholder's notice must be delivered to or
mailed and received at the principal executive offices of the Corporation not
less than 90 days prior to the anniversary date of the immediately preceding
annual meeting of stockholders of the Corporation. A stockholder's notice to the
Secretary shall set forth as to each matter the stockholder proposes to bring
before the annual meeting (i) a brief description of the business desired to be
brought before the annual meeting and the reasons for conducting such business
at the annual meeting, (ii) the name and address, as they appear on the
Corporation's books, of the stockholder proposing such business, (iii) the
acquisition date, the class and the number of shares of voting stock of the
Corporation which are owned beneficially by the stockholder, (iv) any material
interest of the stockholder in such business, and (v) a representation that the
stockholder intends to appear in person or by proxy at the meeting to bring the
proposed business before the meeting.
Notwithstanding anything in these Bylaws to the contrary, no business shall
be conducted at the annual meeting except in accordance with the procedures set
forth in this Section 12.
The chairman of the annual meeting shall, if the facts warrant, determine
and declare to the meeting that business was not properly brought before the
meeting in accordance with the provisions of this Section 12 of Article II, and
if the chairman should so determine, the chairman shall so declare to the
meeting and any such business not properly brought before the meeting shall not
be transacted.
Notwithstanding the foregoing provisions of this Section 12 of Article II,
a stockholder shall also comply with all applicable requirements of the
Securities Exchange Act of 1934, as amended, and the rules and regulations
thereunder with respect to the matters set forth in this Section 12.
Article III
BOARD OF DIRECTORS
SECTION 1. POWER; NUMBER; TERM OF OFFICE. The business and affairs of the
Corporation shall be managed by or under the direction of the Board of
Directors, and subject to the restrictions imposed by law or the Certificate of
Incorporation, the Board of Directors may exercise all the powers of the
Corporation.
The number of directors which shall constitute the whole Board of Directors
shall
-6-
be determined from time to time by the Board of Directors (provided that no
decrease in the number of directors which would have the effect of shortening
the term of an incumbent director may be made by the Board of Directors). If the
Board of Directors makes no such determination, the number of directors shall be
three. Each director shall hold office for the term for which such director is
elected, and until such Director's successor shall have been elected and
qualified or until such Director's earlier death, resignation or removal.
Unless otherwise provided in the Certificate of Incorporation, directors
need not be stockholders nor residents of the state of incorporation of the
Corporation.
SECTION 2. QUORUM; VOTING. Unless otherwise provided in the Certificate of
Incorporation, a majority of the total number of directors shall constitute a
quorum for the transaction of business of the Board of Directors and the vote of
a majority of the directors present at a meeting at which a quorum is present
shall be the act of the Board of Directors.
SECTION 3. PLACE OF MEETINGS; ORDER OF BUSINESS. The directors may hold
their meetings and may have an office and keep the books of the Corporation,
except as otherwise provided by law, in such place or places, within or without
the state of incorporation of the Corporation, as the Board of Directors may
from time to time determine. At all meetings of the Board of Directors business
shall be transacted in such order as shall from time to time be determined by
the Chairman of the Board, or in the Chairman of the Board's absence by the
President (should the President be a director), or in the President's absence by
the Vice Chairman of the Board, or by the Board of Directors.
SECTION 4. FIRST MEETING. Each newly elected Board of Directors may hold
its first meeting for the purpose of organization and the transaction of
business, if a quorum is present, immediately after and at the same place as the
annual meeting of the stockholders. Notice of such meeting shall not be
required. At the first meeting of the Board of Directors in each year at which a
quorum shall be present, held next after the annual meeting of stockholders, the
Board of Directors shall elect the officers of the Corporation.
SECTION 5. REGULAR MEETINGS. Regular meetings of the Board of Directors
shall be held at such times and places as shall be designated from time to time
by the Chairman of the Board or, in the absence of the Chairman of the Board, by
the President (should the President be a director), or in the President's
absence, by the Vice Chairman of the Board. Notice of such regular meetings
shall not be required.
SECTION 6. SPECIAL MEETINGS. Special meetings of the Board of Directors may
be called by the Chairman of the Board, the President (should the President be a
director)
-7-
or the Vice Chairman of the Board or, on the written request of any two
directors, by the Secretary, in each case on at least twenty-four (24) hours
personal, written, telegraphic, cable or wireless notice to each director. Such
notice, or any waiver thereof pursuant to Article VII, Section 3 hereof, need
not state the purpose or purposes of such meeting, except as may otherwise be
required by law or provided for in the Certificate of Incorporation or these
Bylaws. Meetings may be held at any time without notice if all the directors are
present or if those not present waive notice of the meeting in writing.
SECTION 7. NOMINATION OF DIRECTORS. Only persons who are nominated in
accordance with the following procedures shall be eligible for election as
directors. Nominations of persons for election to the Board of Directors of the
Corporation may be made at a meeting of stockholders (a) by or at the direction
of the Board of Directors or (b) by any stockholder of the Corporation who is a
stockholder of record at the time of giving of notice provided for in this
Section 7 of Article III, who shall be entitled to vote for the election of
directors at the meeting and who complies with the notice procedures set forth
in this Section 7 of Article III. Such nominations, other than those made by or
at the direction of the Board of Directors, shall be made pursuant to timely
notice in writing to the Secretary of the Corporation. To be timely, a
stockholder's notice shall be delivered to or mailed and received at the
principal executive offices of the Corporation (i) with respect to an election
to be held at the annual meeting of the stockholders of the Corporation, 90 days
prior to the anniversary date of the immediately preceding annual meeting of
stockholders of the Corporation, and (ii) with respect to an election to be held
at a special meeting of stockholders of the Corporation for the election of
directors, not later than the close of business on the 10th day following the
day on which such notice of the date of the meeting was mailed or public
disclosure of the date of the meeting was made, whichever first occurs. Such
stockholder's notice to the Secretary shall set forth (a) as to each person whom
the stockholder proposes to nominate for election or re-election as a director,
all information relating to the person that is required to be disclosed in
solicitations for proxies for election of directors, or is otherwise required,
pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended
(including the written consent of such person to be named in the proxy statement
as a nominee and to serve as a director if elected); and (b) as to the
stockholder giving the notice (i) the name and address, as they appear on the
Corporation's books, of such stockholder, and (ii) the class and number of
shares of capital stock of the Corporation which are beneficially owned by the
stockholder. At the request of the Board of Directors, any person nominated by
the Board of Directors for election as a director shall furnish to the Secretary
of the Corporation that information required to be set forth in a stockholder's
notice of nomination which pertains to the nominee.
In the event that a person is validly designated as nominee to the Board
and shall thereafter become unable or unwilling to stand for election to the
Board of Directors,
-8-
the Board of Directors or the stockholder who proposed such nominee, as the case
may be, may designate a substitute nominee.
No person shall be eligible to serve as a director of the Corporation
unless nominated in accordance with the procedures set forth in this Section 7
of Article III. The chairman of the meeting of stockholders shall, if the facts
warrant, determine and declare to the meeting that a nomination was not made in
accordance with the procedures prescribed by the Bylaws, and if the chairman
should so determine, the chairman shall so declare to the meeting and the
defective nomination shall be disregarded.
Notwithstanding the foregoing provisions of this Section 7 of Article III,
a stockholder shall also comply with all applicable requirements of the
Securities Exchange Act of 1934, as amended, and the rules and regulations
thereunder with respect to the matters set forth in this Section 7 of Article
III.
SECTION 8. REMOVAL. Any director or the entire Board of Directors may be
removed, with or without cause, by the holders of a majority of the shares then
entitled to vote at an election of directors.
SECTION 9. VACANCIES; INCREASES IN THE NUMBER OF DIRECTORS. Unless
otherwise provided in the Certificate of Incorporation, vacancies existing on
the Board of Directors for any reason and newly created directorships resulting
from any increase in the authorized number of directors may be filled by the
affirmative vote of a majority of the directors then in office, although less
than a quorum, or by a sole remaining director; and any director so chosen shall
hold office until the next annual election and until such Director's successor
shall have been elected and qualified, or until such Director's earlier death,
resignation or removal.
SECTION 10. COMPENSATION. Directors and members of standing committees may
receive such compensation as the Board of Directors from time to time shall
determine to be appropriate, and shall be reimbursed for all reasonable expenses
incurred in attending and returning from meetings of the Board of Directors.
SECTION 11. ACTION WITHOUT A MEETING; TELEPHONE CONFERENCE MEETING. Unless
otherwise restricted by the Certificate of Incorporation, any action required or
permitted to be taken at any meeting of the Board of Directors, or any committee
designated by the Board of Directors, may be taken without a meeting if all
members of the Board of Directors or committee, as the case may be, consent
thereto in writing, and the writing or writings are filed with the minutes of
proceedings of the Board of Directors or committee. Such consent shall have the
same force and effect as a unanimous vote at a meeting, and may be stated as
such in any document or instrument filed with the Secretary of State of the
state of incorporation of the Corporation.
-9-
Unless otherwise restricted by the Certificate of Incorporation, subject to
the requirement for notice of meetings, members of the Board of Directors, or
members of any committee designated by the Board of Directors, may participate
in a meeting of such Board of Directors or committee, as the case may be, by
means of a conference telephone connection or similar communications equipment
by means of which all persons participating in the meeting can hear each other,
and participation in such a meeting shall constitute presence in person at such
meeting, except where a person participates in the meeting for the express
purpose of objecting to the transaction of any business on the ground that the
meeting is not lawfully called or convened.
SECTION 12. APPROVAL OR RATIFICATION OF ACTS OR CONTRACTS BY STOCKHOLDERS.
The Board of Directors in its discretion may submit any act or contract for
approval or ratification at any annual meeting of the stockholders, or at any
special meeting of the stockholders called for the purpose of considering any
such act or contract, and any act or contract that shall be approved or be
ratified by the vote of the stockholders holding a majority of the issued and
outstanding shares of stock of the Corporation entitled to vote and present in
person or by proxy at such meeting (provided that a quorum is present) shall be
as valid and as binding upon the Corporation and upon all the stockholders as if
it has been approved or ratified by every stockholder of the Corporation.
Article IV
COMMITTEES
SECTION 1. EXECUTIVE COMMITTEE. The Board of Directors may, by resolution
passed by a majority of the whole Board of Directors, designate an Executive
Committee consisting of one or more of the directors of the Corporation, one of
whom shall be designated chairman of the Executive Committee. During the
intervals between the meetings of the Board of Directors, the Executive
Committee shall possess and may exercise all the powers of the Board of
Directors, including the power to authorize the seal of the Corporation to be
affixed to all papers which may require it; provided, however, that the
Executive Committee shall not have the power or authority of the Board of
Directors in reference to amending the Certificate of Incorporation, adopting an
agreement of merger or consolidation, recommending to the stockholders the sale,
lease or exchange of all or substantially all of the Corporation's property and
assets, recommending to the stockholders a dissolution of the Corporation or a
revocation of a dissolution of the Corporation, amending, altering or repealing
these Bylaws or adopting new bylaws for the Corporation or otherwise acting
where action by the Board of Directors is specified by the Delaware General
Corporation Law. The Executive Committee shall also have, and may exercise, all
the powers of the Board of Directors, except as aforesaid, whenever a quorum of
the Board of Directors shall fail to be
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present at any meeting of the Board.
SECTION 2. AUDIT COMMITTEE. The Board of Directors may, by resolution
passed by a majority of the whole Board of Directors, designate an Audit
Committee consisting of one or more of the directors of the Corporation, one of
whom shall be designated chairman of the Audit Committee. The Audit Committee
shall have and may exercise such powers and authority as provided in the
resolution creating it and as determined from time to time by the Board of
Directors.
SECTION 3. OTHER COMMITTEES. The Board of Directors may, by resolution
passed from time to time by a majority of the whole Board of Directors,
designate such other committees as it shall see fit consisting of one or more of
the directors of the Corporation, one of whom shall be designated chairman of
each such committee. Any such committee shall have and may exercise such powers
and authority as provided in the resolution creating it and as determined from
time to time by the Board of Directors.
SECTION 4. PROCEDURE; MEETINGS; QUORUM. Any committee designated pursuant
to this Article IV shall keep regular minutes of its actions and proceedings in
a book provided for that purpose and report the same to the Board of Directors
at its meeting next succeeding such action, shall fix its own rules or
procedures, and shall meet at such times and at such place or places as may be
provided by such rules, or by such committee or the Board of Directors. Should a
committee fail to fix its own rules, the provisions of these Bylaws, pertaining
to the calling of meetings and conduct of business by the Board of Directors,
shall apply as nearly as may be. At every meeting of any such committee, the
presence of a majority of all the members thereof shall constitute a quorum,
except as provided in Section 5 of this Article IV, and the affirmative vote of
a majority of the members present shall be necessary for the adoption by it of
any resolution.
SECTION 5. SUBSTITUTION AND REMOVAL OF MEMBERS; VACANCIES. The Board of
Directors may designate one or more directors as alternate members of any
committee, who may replace any absent or disqualified member at any meeting of
such committee. In the absence or disqualification of a member of a committee,
the member or members present at any meeting and not disqualified from voting,
whether or not constituting a quorum, may unanimously appoint another member of
the Board of Directors to act at the meeting in the place of the absent or
disqualified member. The Board of Directors shall have the power at any time to
remove any member(s) of a committee and to appoint other directors in lieu of
the person(s) so removed and shall also have the power to fill vacancies in a
committee.
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Article V
OFFICERS
SECTION 1. NUMBER, TITLES AND TERM OF OFFICE. The officers of the
Corporation shall be a Chairman of the Board, a President, a President-North
American Operations, a President-International Operations, one or more Vice
Presidents (any one or more of whom may be designated Executive Vice President
or Senior Vice President), a General Counsel, a Treasurer, a Secretary and such
other officers as the Board of Directors may from time to time elect or appoint
(including, but not limited to, a Vice Chairman of the Board, a Deputy Corporate
Secretary, one or more Assistant Secretaries and one or more Assistant
Treasurers). Each officer shall hold office until such officer's successor shall
be duly elected and shall qualify or until such officer's death or until such
officer shall resign or shall have been removed. Any number of offices may be
held by the same person, unless the Certificate of Incorporation provides
otherwise. Except for the Chairman of the Board and the Vice Chairman of the
Board, no officer need be a director.
SECTION 2. POWERS AND DUTIES OF THE CHAIRMAN OF THE BOARD. The Chairman of
the Board shall be the chief executive officer of the Corporation. Subject to
the control of the Board of Directors and the Executive Committee (if any), the
Chairman of the Board shall have general executive charge, management and
control of the properties, business and operations of the Corporation with all
such powers as may be reasonably incident to such responsibilities; may agree
upon and execute all leases, contracts, evidences of indebtedness and other
obligations in the name of the Corporation and may sign all certificates for
shares of capital stock of the Corporation; and shall have such other powers and
duties as designated in accordance with these Bylaws and as from time to time
may be assigned to the Chairman of the Board by the Board of Directors. The
Chairman of the Board shall preside at all meetings of the stockholders and of
the Board of Directors.
SECTION 3. POWERS AND DUTIES OF THE PRESIDENT, PRESIDENT-NORTH AMERICAN
OPERATIONS, AND PRESIDENT-INTERNATIONAL OPERATIONS.
(a) Unless the Board of Directors otherwise determines, the President shall
have the authority to agree upon and execute all leases, contracts, evidences of
indebtedness and other obligations in the name of the Corporation; and, unless
the Board of Directors otherwise determines, the President shall, in the absence
of the Chairman of the Board or if there be no Chairman of the Board, preside at
all meetings of the stockholders and (should the President be a director) of the
Board of Directors; and the President shall have such other powers and duties as
designated in accordance with these Bylaws and as from time to time may be
assigned to the President by the Board of Directors or the Chairman of the
Board.
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(b) Unless the Board of Directors otherwise determines, the President-North
American Operations shall have the authority to agree upon and execute all
leases, contracts, evidences of indebtedness and other obligations in the name
of the Corporation pertaining to the Corporation's North American operations;
and the President-North American Operations shall have such other powers and
duties as designated in accordance with these Bylaws and as from time to time
may be assigned to the President-North American Operations by the Board of
Directors or the Chairman of the Board.
(c) Unless the Board of Directors otherwise determines, the
PresidentInternational Operations shall have the authority to agree upon and
execute all leases, contracts, evidences of indebtedness and other obligations
in the name of the Corporation pertaining to the Corporation's international
operations; and the PresidentInternational Operations shall have such other
powers and duties as designated in accordance with these Bylaws and as from time
to time may be assigned to the President-International Operations by the Board
of Directors or the Chairman of the Board.
SECTION 4. POWERS AND DUTIES OF THE VICE CHAIRMAN OF THE BOARD. The Board
of Directors may assign areas of responsibility to the Vice Chairman of the
Board, and, in such event, and subject to the overall direction of the Chairman
of the Board and the Board of Directors, the Vice Chairman of the Board shall be
responsible for supervising the management of the affairs of the Corporation and
its subsidiaries within the area or areas assigned and shall monitor and review
on behalf of the Board of Directors all functions within the corresponding area
or areas of the Corporation and each such subsidiary of the Corporation. In the
absence of the President, or in the event of the President's inability or
refusal to act, the Vice Chairman of the Board shall perform the duties of the
President, and when so acting shall have all the powers of and be subject to all
the restrictions upon the President. Further, the Vice Chairman of the Board
shall have such other powers and duties as designated in accordance with these
Bylaws and as from time to time may be assigned to the Vice Chairman of the
Board by the Board of Directors or the Chairman of the Board.
SECTION 5. VICE PRESIDENTS. Each Vice President shall at all times possess
power to sign all certificates, contracts and other instruments of the
Corporation, except as otherwise limited in writing by the Chairman of the
Board, the President or the Vice Chairman of the Board or of the Corporation.
Each Vice President shall have such other powers and duties as from time to time
may be assigned to such Vice President by the Board of Directors, the Chairman
of the Board, the President or the Vice Chairman of the Board.
SECTION 6. GENERAL COUNSEL. The General Counsel shall act as chief legal
advisor
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to the Corporation. The General Counsel may have one or more staff attorneys and
assistants, and may retain other attorneys to conduct the legal affairs and
litigation of the Corporation under the General Counsel's supervision.
SECTION 7. SECRETARY. The Secretary shall keep the minutes of all meetings
of the Board of Directors, committees of the Board of Directors and the
stockholders, in books provided for that purpose; shall attend to the giving and
serving of all notices; may in the name of the Corporation affix the seal of the
Corporation to all contracts of the Corporation and attest the affixation of the
seal of the Corporation thereto; may sign with the other appointed officers all
certificates for shares of capital stock of the Corporation; shall have charge
of the certificate books, transfer books and stock ledgers, and such other books
and papers as the Board of Directors may direct, all of which shall at all
reasonable times be open to inspection of any director upon application at the
office of the Corporation during business hours; shall have such other powers
and duties as designated in these Bylaws and as from time to time may be
assigned to the Secretary by the Board of Directors, the Chairman of the Board,
the President or the Vice Chairman of the Board; and shall in general perform
all acts incident to the office of Secretary, subject to the control of the
Board of Directors, the Chairman of the Board, the President or the Vice
Chairman of the Board.
SECTION 8. DEPUTY CORPORATE SECRETARY AND ASSISTANT SECRETARIES. The Deputy
Corporate Secretary and each Assistant Secretary shall have the usual powers and
duties pertaining to such offices, together with such other powers and duties as
designated in these Bylaws and as from time to time may be assigned to the
Deputy Corporate Secretary or an Assistant Secretary by the Board of Directors,
the Chairman of the Board, the President, the Vice Chairman of the Board, or the
Secretary. The Deputy Corporate Secretary shall exercise the powers of the
Secretary during that officer's absence or inability or refusal to act.
SECTION 9. TREASURER. The Treasurer shall have responsibility for the
custody and control of all the funds and securities of the Corporation, and
shall have such other powers and duties as designated in these Bylaws and as
from time to time may be assigned to the Treasurer by the Board of Directors,
the Chairman of the Board, the President or the Vice Chairman of the Board. The
Treasurer shall perform all acts incident to the position of Treasurer, subject
to the control of the Board of Directors, the Chairman of the Board, the
President and the Vice Chairman of the Board; and the Treasurer shall, if
required by the Board of Directors, give such bond for the faithful discharge of
the Treasurer's duties in such form as the Board of Directors may require.
SECTION 10. ASSISTANT TREASURERS. Each Assistant Treasurer shall have the
usual powers and duties pertaining to such office, together with such other
powers and duties as designated in these Bylaws and as from time to time may be
assigned to each Assistant Treasurer by the Board of Directors, the Chairman of
the Board, the President,
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the Vice Chairman of the Board, or the Treasurer. The Assistant Treasurers shall
exercise the powers of the Treasurer during that officer's absence or inability
or refusal to act.
SECTION 11. ACTION WITH RESPECT TO SECURITIES OF OTHER CORPORATIONS. Unless
otherwise directed by the Board of Directors, the Chairman of the Board, the
President or the Vice Chairman of the Board, together with the Secretary, the
Deputy Corporate Secretary or any Assistant Secretary shall have power to vote
and otherwise act on behalf of the Corporation, in person or by proxy, at any
meeting of security holders of or with respect to any action of security holders
of any other corporation in which this Corporation may hold securities and
otherwise to exercise any and all rights and powers which this Corporation may
possess by reason of its ownership of securities in such other corporation.
SECTION 12. DELEGATION. For any reason that the Board of Directors may deem
sufficient, the Board of Directors may, except where otherwise provided by
statute, delegate the powers or duties of any officer to any other person, and
may authorize any officer to delegate specified duties of such officer to any
other person. Any such delegation or authorization by the Board shall be
effected from time to time by resolution of the Board of Directors.
Article VI
CAPITAL STOCK
SECTION 1. CERTIFICATES OF STOCK. The certificates for shares of the
capital stock of the Corporation shall be in such form, not inconsistent with
that required by law and the Certificate of Incorporation, as shall be approved
by the Board of Directors. Every holder of stock represented by certificates
shall be entitled to have a certificate signed by or in the name of the
Corporation by the Chairman of the Board, President, Vice Chairman of the Board
or a Vice President and the Secretary, Deputy Corporate Secretary or an
Assistant Secretary or the Treasurer or an Assistant Treasurer of the
Corporation representing the number of shares (and, if the stock of the
Corporation shall be divided into classes or series, certifying the class and
series of such shares) owned by such stockholder which are registered in
certified form; provided, however, that any of or all the signatures on the
certificate may be facsimile. The stock record books and the blank stock
certificate books shall be kept by the Secretary, or at the office of such
transfer agent or transfer agents as the Board of Directors may from time to
time determine. In case any officer, transfer agent or registrar who shall have
signed or whose facsimile signature or signatures shall have been placed upon
any such certificate or certificates shall have ceased to be such officer,
transfer agent or registrar before such certificate is issued by the
Corporation, such certificate may nevertheless be issued by the Corporation with
the same effect as if such person were such officer, transfer
-15-
agent or registrar at the date of issue. The stock certificates shall be
consecutively numbered and shall be entered in the books of the Corporation as
they are issued and shall exhibit the holder's name and number of shares.
SECTION 2. TRANSFER OF SHARES. The shares of stock of the Corporation shall
be transferable only on the books of the Corporation by the holders thereof in
person or by their duly authorized attorneys or legal representatives upon
surrender and cancellation of certificates for a like number of shares. Upon
surrender to the Corporation or a transfer agent of the Corporation of a
certificate for shares duly endorsed or accompanied by proper evidence of
succession, assignment or authority to transfer, it shall be the duty of the
Corporation to issue a new certificate to the person entitled thereto, cancel
the old certificate and record the transaction upon its books.
SECTION 3. OWNERSHIP OF SHARES. The Corporation shall be entitled to treat
the holder of record of any share or shares of capital stock of the Corporation
as the holder in fact thereof and, accordingly, shall not be bound to recognize
any equitable or other claim to or interest in such share or shares on the part
of any other person, whether or not it shall have express or other notice
thereof, except as otherwise provided by the laws of the state of incorporation
of the Corporation.
SECTION 4. REGULATIONS REGARDING CERTIFICATES. The Board of Directors shall
have the power and authority to make all such rules and regulations as they may
deem expedient concerning the issue, transfer and registration or the
replacement of certificates for shares of capital stock of the Corporation.
SECTION 5. LOST OR DESTROYED CERTIFICATES. The Board of Directors may
determine the conditions upon which the Corporation may issue a new certificate
of stock in place of a certificate theretofore issued by it which is alleged to
have been lost, stolen or destroyed and may require the owner of such
certificate or such owner's legal representative to give bond, with surety
sufficient to indemnify the Corporation and each transfer agent and registrar
against any and all losses or claims which may arise by reason of the alleged
loss, theft or destruction of any such certificate or the issuance of such new
certificate in the place of the one so lost, stolen or destroyed.
Article VII
MISCELLANEOUS PROVISIONS
SECTION 1. FISCAL YEAR. The fiscal year of the Corporation shall begin on
the first day of January of each year.
SECTION 2. CORPORATE SEAL. The corporate seal shall be circular in form and
shall have inscribed thereon the name of the Corporation and the state of its
incorporation,
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which seal shall be in the charge of the Secretary and shall be affixed to
certificates of stock, debentures, bonds, and other documents, in accordance
with the direction of the Board of Directors or a committee thereof, and as may
be required by law; however, the Secretary may, if the Secretary deems it
expedient, have a facsimile of the corporate seal inscribed on any such
certificates of stock, debentures, bonds, contracts or other documents.
Duplicates of the seal may be kept for use by the Deputy Corporate Secretary or
any Assistant Secretary.
SECTION 3. NOTICE AND WAIVER OF NOTICE. Whenever any notice is required to
be given by law, the Certificate of Incorporation or under the provisions of
these Bylaws, said notice shall be deemed to be sufficient if given (i) by
telegraphic, cable or wireless transmission (including by telecopy or facsimile
transmission) or (ii) by deposit of the same in a post office box or by delivery
to an overnight courier service company in a sealed prepaid wrapper addressed to
the person entitled thereto at such person's post office address, as it appears
on the records of the Corporation, and such notice shall be deemed to have been
given on the day of such transmission or mailing or delivery to courier, as the
case may be.
Whenever notice is required to be given by law, the Certificate of
Incorporation or under any of the provisions of these Bylaws, a written waiver
thereof, signed by the person entitled to notice, whether before or after the
time stated therein, shall be deemed equivalent to notice. Attendance of a
person, including without limitation a director, at a meeting shall constitute a
waiver of notice of such meeting, except when the person attends a meeting for
the express purpose of objecting, at the beginning of the meeting, to the
transaction of any business because the meeting is not lawfully called or
convened. Neither the business to be transacted at, nor the purpose of, any
regular or special meeting of the stockholders, directors, or members of a
committee of directors need be specified in any written waiver of notice unless
so required by the Certificate of Incorporation or these Bylaws.
SECTION 4. FACSIMILE SIGNATURES. In addition to the provisions for the use
of facsimile signatures elsewhere specifically authorized in these Bylaws,
facsimile signatures of any officer or officers of the Corporation may be used
whenever and as authorized by the Board of Directors.
SECTION 5. RELIANCE UPON BOOKS, REPORTS AND RECORDS. A member of the Board
of Directors, or a member of any committee designated by the Board of Directors,
shall, in the performance of such person's duties, be fully protected in relying
in good faith upon the records of the Corporation and upon such information,
opinion, reports or statements presented to the Corporation by any of the
Corporation's officers or employees, or committees of the Board of Directors, or
by any other person as to matters the member reasonably believes are within such
other person's professional or expert competence and who has been selected with
reasonable care by or on behalf of
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the Corporation.
SECTION 6. APPLICATION OF BYLAWS. In the event that any provisions of these
Bylaws is or may be in conflict with any law of the United States, of the state
of incorporation of the Corporation or of any other governmental body or power
having jurisdiction over this Corporation, or over the subject matter to which
such provision of these Bylaws applies, or may apply, such provision of these
Bylaws shall be inoperative to the extent only that the operation thereof
unavoidably conflicts with such law, and shall in all other respects be in full
force and effect.
Article VIII
AMENDMENTS
The Board of Directors shall have the power to adopt, amend and repeal from
time to time Bylaws of the Corporation, subject to the right of the stockholders
entitled to vote with respect thereto to amend or repeal such Bylaws as adopted
or amended by the Board of Directors.
-18-
EXHIBIT 10.9(b)
4TH AMENDMENT TO EMPLOYMENT AGREEMENT
This Agreement, made and entered into and effective as of the 14th day
of December, 1994, by and among Enron Corp. ("Enron" or "Parent") and Enron Oil
& Gas Company ("Company"), and Forrest E. Hoglund ("Employee"), is an amendment
to that certain Employment Agreement made and entered into among the parties the
28th day of August, 1987 and made effective as of September 1, 1987 (the
"Employment Agreement"), as amended to date.
WHEREAS, the parties desire to amend the Employment Agreement;
NOW, THEREFORE, in consideration of the Employee's continued engagement
with Company, and of the covenants contained herein, and for other good and
valuable consideration, the parties agree as follows:
1. Article 2: TERM OF EMPLOYMENT is amended to read as follows:
"Unless sooner terminated pursuant to other provisions hereof,
Employee's period of employment under this Agreement shall extend from
the effective date of this Agreement through September 1, 1998 (the
"Initial Term")."
2. Before December 31, 1994, the Company shall cause Employee to
receive a grant of an option under the Enron Oil & Gas Company 1992
Stock Plan (the "Plan") to purchase one million eight hundred twenty
thousand (1,820,000) shares of common stock of the Company (the
"Shares") at a price equal to the Fair Market Value (as defined in the
Plan) of such shares on the date of grant; PROVIDED, HOWEVER, said grant
shall be contingent upon and subject to the Company's shareholders
approving before May 15, 1995 an amendment to the Plan that increases
the number of shares available for granting Awards under the Plan by a
number not less than said number of Shares. If for any reason after the
grant is made such shareholder approval is not obtained before May 15,
1995, this Agreement shall be rescinded and the grant made hereunder
shall become null and void as though it never existed.
3. This Agreement is an amendment to the Employment Agreement,
and the parties agree that all other terms, conditions and stipulations
contained in the Employment Agreement shall remain in full force and
effect and without any change or modification, except as provided
herein.
IN WITNESS WHEREOF, the parties have duly executed this Agreement
as of the date first above written.
Forrest E. Hoglund
/S/ FORREST E. HOGLUND
ENRON OIL & GAS COMPANY
By: /S/ WALTER E. WILSON
Name: Walter E. Wilson
Title: Sr. V.P. & CFO
EXHIBIT 10.15(b)
ASSIGNMENT AND ACCEPTANCE
Dated April 14, 1994
Reference is made to the Revolving Credit Agreement dated as of March
11, 1994 (the "CREDIT AGREEMENT"), among Enron Oil & Gas Company, a Delaware
corporation (the "BORROWER"), the Banks (as defined in the Credit Agreement)
named therein, and Texas Commerce Bank National Association, as administrative
agent ("the Administrative Agent"). Capitalized terms used herein and not
otherwise defined shall have the meanings assigned to such terms in the Credit
Agreement.
Texas Commerce Bank National Association (the "ASSIGNOR") and Royal Bank
of Canada (the "ASSIGNEE") agree as follows:
1. The Assignor hereby sells and assigns to the Assignee, without
recourse, and the Assignee hereby purchases and assumes from the Assignor, a
33.3333333% interest in and to all the Assignor's rights and obligations under
the Credit Agreement as of the Assignment Date (as defined below) (including,
without limitation, such percentage interest in the Advances owing to the
Assignor outstanding on the Assignment Date together with such percentage
interest in all unpaid interest with respect to such Advances and facility fees
accrued to the Assignment Date and such percentage interest in the Note held by
the Assignor).
2. The Assignor (i) represents that as of the date hereof, its
Commitment (without giving effect to assignments thereof which have not yet
become effective) is $30,000,000 and the outstanding balance of its Advances
(unreduced by any assignments thereof which have not yet become effective) is
$0; (ii) makes no representation or warranty and assumes no responsibility with
respect to any statements, warranties or representations made in or in
connection with the Credit Agreement or the execution, legality, validity,
enforceability, genuineness, sufficiency or value of the Credit Agreement or any
other instrument or document furnished pursuant thereto, other than that it is
the legal and beneficial owner of the interest being assigned by it hereunder
and that such interest is free and clear of any adverse claim: (iii) makes no
representation or warranty and assumes no responsibility with respect to the
financial condition of the Borrower or the performance or observance by the
Borrower of any of its respective obligations under the Credit Agreement or any
other instrument or document furnished pursuant thereto; and (iv) requests that
the Administrative Agent exchange such Note for a new Note executed by the
Borrower and payable to the Assignor in a principal amount equal to $20,000,000
and a new Note executed by the Borrower and payable to the Assignee in a
principal amount equal to $10,000,000.
3. The Assignee (i) represents and warrants that it is legally
authorized to enter into this Assignment and Acceptance; (ii) confirms that it
has received a copy of the Credit Agreement, together with copies of the most
recent financial statements delivered pursuant to Section 5.1 thereof and such
other documents and information as it has deemed appropriate to make its own
credit analysis and decision to enter into this Assignment and Acceptance; (iii)
agrees that it will, independently and without reliance upon the Assignor or any
other Bank and based on such documents and information as it shall deem
appropriate at the time, continue to make its own credit decisions in taking or
not taking action under the Credit Agreement; (iv) appoints and authorizes the
Administrative Agent to take such action as agent on its behalf and to exercise
such powers under the Credit Agreement as are delegated to such Administrative
Agent by the terms thereof, together with such powers as are reasonably
incidental thereto; (v) agrees that it will perform in accordance with their
terms all the obligations which by the terms of the Credit Agreement are
required to be performed by it as a Bank; (vi) agrees that it will keep
confidential all information with respect to the Borrower furnished to it by a
Borrower or the Assignor (other than information generally available to the
public or otherwise available to the Assignor on a nonconfidential basis); and
(vii) confirms that it has delivered a completed Administrative Questionnaire to
the Administrative Agent.
4. The effective date for this Assignment and Acceptance shall be April
21, 1994 (the "ASSIGNMENT DATE"). Following the execution of this Assignment and
Acceptance, it will be delivered to the Administrative Agent for acceptance and
recording by the Administrative Agent.
5. Upon such acceptance and recording, from and after the Assignment
Date, (i) the Assignee shall be a party to the Credit Agreement and, to the
extent provided in this Assignment and Acceptance, have the rights and
obligations of a Bank thereunder and (ii) the Assignor shall, to the extent
provided in this Assignment and Acceptance, relinquish its rights and be
released from its obligations under the Credit Agreement.
6. Upon such acceptance and recording, from and after the Assignment
Date, the Administrative Agent shall make all payments in respect of the
interest assigned hereby (including payments of all principal, interest, fees
and other amounts) to the Assignee. The Assignor and the Assignee shall make all
appropriate adjustments in payments for periods prior to the Assignment Date by
the Administrative Agent or with respect to the making of this Assignment and
Acceptance directly between themselves.
7. THIS ASSIGNMENT AND ACCEPTANCE SHALL BE GOVERNED BY, AND CONSTRUED
AND INTERPRETED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS.
Texas Commerce Bank National Association
Commitment: $20,000,000 By: /S/ JAMES R. McBRIDE
Name: James R. McBride
Title: Managing Director
Royal Bank of Canada
Commitment: $10,000,000 By: /S/ GIL J. BENARD
Name: Gil J. Benard
Title: Senior Manager
Telecopy Number: (718) 522-6292
DOMESTIC LENDING OFFICE:
Royal Bank of Canada New York
Loans Administration
Pierrepont Plaza
300 Cadman Plaza West, 14th Flr.
Brooklyn, New York 10201-2701
Attn: Linda Swanston
EURODOLLAR LENDING OFFICE:
Royal Bank of Canada New York
Loans Administration
Pierrepont Plaza
300 Cadman Plaza West, 14th Flr.
Brooklyn, New York 10201-2701
Attn: Linda Swanston
Accepted:
Enron Oil & Gas Company
By: /S/ WALTER C. WILSON
Name: Walter C. Wilson
Title: Senior Vice President and
Chief Financial Officer
PROMISSORY NOTE
U. S. $10,000,000.00 Houston, Texas April 14, 1994
FOR VALUE RECEIVED, the undersigned, Enron Oil & Gas Company, a Delaware
corporation (the "BORROWER"), HEREBY PROMISES TO PAY to the order of Royal Bank
of Canada (the "Bank") for the account of its Applicable Lending Office (as
defined in the Credit Agreement referred to below) on or before January 15, 1998
the principal sum of ten million U.S. dollars (U.S. $10,000,000.00) or, if less,
the aggregate unpaid principal amount of the Advances (as defined in the
Revolving Credit Agreement of even date herewith among the Borrower, the Bank,
certain other lenders parties thereto and Texas Commerce Bank National
Association, as Administrative Agent for the Bank and such other lenders; such
Credit Agreement, as amended from time to time being herein referred to as the
"CREDIT AGREEMENT") owing to the Bank outstanding on the Termination Date;
PROVIDED that for the full term of this Promissory Note the interest rate
produced by the aggregate of all sums paid or agreed to be paid to the holder of
this Promissory Note for the use, forbearance or detention of the debt evidenced
hereby shall not exceed the Highest Lawful Rate (as defined in the Credit
Agreement).
The Borrower promises to pay interest on the unpaid principal amount of
each Advance owing to the Bank from the date of such Advance until such
principal amount is paid in full, at such interest rates, and due at such times,
as are specified in the Credit Agreement.
Both principal and interest are payable in lawful money of the United
States of America to Texas Commerce Bank National Association, as Administrative
Agent, at 712 Main Street, Houston, Texas, in same day funds. Each Advance owed
to the Bank by the Borrower pursuant to the Credit Agreement, and all payments
made on account of principal thereof, shall be recorded by the Bank, and prior
to any transfer hereof, endorsed on the grid attached hereto which is part of
this Promissory Note; PROVIDED that the failure of the Bank to make any such
recordation or endorsement shall not affect the obligations of the Borrower
hereunder or under the Credit Agreement.
This Promissory Note is one of the Notes referred to in, and is subject
to and is entitled to the benefits of, the Credit Agreement. The Credit
Agreement, among other things, (a) provides for the making of Advances by the
Bank to the Borrower from time to time in an aggregate amount not to exceed at
any one time outstanding the U.S. dollar amount first above mentioned, the
indebtedness of the Borrower resulting from each Advance owing to the Bank being
evidenced by this Promissory Note, and (b) contains provisions for acceleration
of the maturity hereof upon the happening of certain stated events and also for
prepayments on account of principal hereof prior to the maturity hereof upon the
terms and conditions therein specified. Unless otherwise defined herein, any
term used in this Promissory Note and defined in the Credit Agreement shall have
the meaning ascribed to it in the Credit Agreement.
Except only for any notices which are specifically required by the
Credit Agreement, the Borrower waives notice (including, but not limited to,
notice of intent to accelerate and notice of acceleration, notice of protest and
notice of dishonor), demand, presentment for payment and protest.
THIS PROMISSORY NOTE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE
WITH, THE LAWS OF THE STATE OF TEXAS.
ENRON OIL & GAS COMPANY, a
Delaware corporation
By: /s/ W. C. WILSON
W. C. Wilson
Title: Senior Vice President &
Chief Financial Officer
<PAGE>
ADVANCES AND PAYMENTS OF PRINCIPAL
Amount of
Amount Principal Unpaid
of Type of Paid or Principal Notation
Date Advance Advance Prepaid Balance Made By
- ---- ------- ------- --------- --------- --------
PROMISSORY NOTE
U. S. $20,000,000.00 Houston, Texas April 14, 1994
FOR VALUE RECEIVED, the undersigned, Enron Oil & Gas Company, a Delaware
corporation (the "BORROWER"), HEREBY PROMISES TO PAY to the order of Texas
Commerce Bank National Association (the "Bank") for the account of its
Applicable Lending Office (as defined in the Credit Agreement referred to below)
on or before January 15, 1998 the principal sum of twenty million U.S. dollars
(U.S. $20,000,000.00) or, if less, the aggregate unpaid principal amount of the
Advances (as defined in the Revolving Credit Agreement of even date herewith
among the Borrower, the Bank, certain other lenders parties thereto and Texas
Commerce Bank National Association, as Administrative Agent for the Bank and
such other lenders; such Credit Agreement, as amended from time to time being
herein referred to as the "CREDIT AGREEMENT") owing to the Bank outstanding on
the Termination Date; PROVIDED that for the full term of this Promissory Note
the interest rate produced by the aggregate of all sums paid or agreed to be
paid to the holder of this Promissory Note for the use, forbearance or detention
of the debt evidenced hereby shall not exceed the Highest Lawful Rate (as
defined in the Credit Agreement).
The Borrower promises to pay interest on the unpaid principal amount of
each Advance owing to the Bank from the date of such Advance until such
principal amount is paid in full, at such interest rates, and due at such times,
as are specified in the Credit Agreement.
Both principal and interest are payable in lawful money of the United
States of America to Texas Commerce Bank National Association, as Administrative
Agent, at 712 Main Street, Houston, Texas, in same day funds. Each Advance owed
to the Bank by the Borrower pursuant to the Credit Agreement, and all payments
made on account of principal thereof, shall be recorded by the Bank, and prior
to any transfer hereof, endorsed on the grid attached hereto which is part of
this Promissory Note; PROVIDED that the failure of the Bank to make any such
recordation or endorsement shall not affect the obligations of the Borrower
hereunder or under the Credit Agreement.
This Promissory Note is one of the Notes referred to in, and is subject
to and is entitled to the benefits of, the Credit Agreement. The Credit
Agreement, among other things, (a) provides for the making of Advances by the
Bank to the Borrower from time to time in an aggregate amount not to exceed at
any one time outstanding the U.S. dollar amount first above mentioned, the
indebtedness of the Borrower resulting from each Advance owing to the Bank being
evidenced by this Promissory Note, and (b) contains provisions for acceleration
of the maturity hereof upon the happening of certain stated events and also for
prepayments on account of principal hereof prior to the maturity hereof upon the
terms and conditions therein specified. Unless otherwise defined herein, any
term used in this Promissory Note and defined in the Credit Agreement shall have
the meaning ascribed to it in the Credit Agreement.
Except only for any notices which are specifically required by the
Credit Agreement, the Borrower waives notice (including, but not limited to,
notice of intent to accelerate and notice of acceleration, notice of protest and
notice of dishonor), demand, presentment for payment and protest.
THIS PROMISSORY NOTE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE
WITH, THE LAWS OF THE STATE OF TEXAS.
ENRON OIL & GAS COMPANY, a
Delaware corporation
By: /s/ W. C. WILSON
W. C. Wilson
Title: Senior Vice President &
Chief Financial Officer
<PAGE>
ADVANCES AND PAYMENTS OF PRINCIPAL
Amount of
Amount Principal Unpaid
of Type of Paid or Principal Notation
Date Advance Advance Prepaid Balance Made By
- ---- ------- ------- --------- --------- --------
EXHIBIT 10.37(b)
AMENDMENT TO HYDROCARBON
EXCHANGE AGREEMENT
This Amendment to Hydrocarbon Exchange (this "Amendment") is entered
into this 17th day of February, 1993, effective January 1, 1993, by and between
ENRON OIL & GAS COMPANY ("EOG") and CACTUS HYDROCARBON 1992-A LIMITED
PARTNERSHIP ("Cactus"). Where the context requires, EOG and Cactus shall be
referred to individually as a "Party and collectively as the "Parties."
W I T N E S S E T H
WHEREAS, Cactus and EOG entered into the certain Hydrocarbon Exchange
Agreement dated September 25, 1992 filed for record (i) in the office of the
county Clerk of Lincoln County, Wyoming, under File No. 755520 and recorded in
Volume 318 PR, Page 1, on October 8, 1992 and (ii) in the office of the County
Clerk of Sublette County, Wyoming, under File No. 238876 and recorded in Volume
90 O&G, Page 224, on October 2, 1992 (the "Exchange Agreement"); and
WHEREAS, Cactus and EOG desire to amend the Exchange Agreement to add
additional Cactus' Points of Receipt.
NOW, THEREFORE, in consideration of the premises and mutual covenants
herein contained, and other good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged, the Parties mutually agree as
follows:
1. Reference is made to the Exchange Agreement for all purposes. All
references in the Exchange Agreement and this Amendment to the defined
term Exchange Agreement or Agreement shall include and refer to the
Exchange Agreement as amended by this Amendment. Unless otherwise
defined herein, capitalized terms used herein shall have the same
meanings given to them in the Exchange Agreement.
2. The parties hereby agree to amend Exhibit C of the Exchange Agreement to
add under the heading "Matagorda" and "South Texas" as additional Cactus
Points of Receipt the following point "MOPS"/FGT Interconnect near
Tivoli, Refugio County, Texas. Exhibit C of the Exchange Agreement is
hereby amended to delete Exhibit C in its entirely and substitute the
attached Exhibit C.
3. Except as amended herein, the Exchange Agreement shall be and
remain in force and effect as originally written.
IN WITNESS WHEREOF, EOG and Cactus have caused this Amendment to be
executed this 17th day of February, effective January 1, 1993.
CACTUS HYDROCARBON 1992-A
LIMITED PARTNERSHIP
By Enron Big Piney Corp., General Partner
ATTEST
By: /s/ ELAINE OVERTURF By: /s/ GENE E. HUMPHREY
Name: Elaine Overturf Name: Gene E. Humphrey
Title: Deputy Corporate Secretary Title: Vice President,
Structured Finance
ENRON OIL & GAS COMPANY
ATTEST
By: /s/ J. JEFFERS SPENCER By: /s/ ANDREW N. HOYLE
Name: J. Jeffers Spencer Name: Andrew N. Hoyle
Title: Senior Counsel Title: Vice President,
Marketing
STATE OF TEXAS
COUNTY OF HARRIS
On this 5th day of February, 1993, before me, a Notary Public in and for
said state, personally appeared Gene E. Humphrey, Vice President, Structured
Finance of Enron Piney Corp., General Partner of Cactus Hydrocarbon 1992-A
Limited Partnership, known to me to be the person who executed the within
Amendment to Hydrocarbons Exchange Agreement on behalf of said corporation,
acting as General Partner of said partnership and acknowledged to me that he
executed the same for the purposes therein stated.
Given under my hand and notarial seal.
/s/ DEBORAH KORKMAS
Deborah Korkmas
[Seal] Notary Public
My Commission expires: May 21, 1993
STATE OF TEXAS ss.
ss.
COUNTY OF HARRIS ss.
On this 17th day of February, 1993, before me personally appeared Andrew
N. Hoyle to me personally known, who, being by me duly sworn, did say that he is
the V.P., Mktg. of Enron Oil & Gas Company and that the seal affixed to said
instrument is the corporate seal of said corporation, and that said instrument
was signed and sealed on behalf of said corporation by authority of its Board of
Directors and said Andrew N. Hoyle acknowledged said instrument to be the free
act and deed of said corporation.
Given under my hand and notarial seal.
/s/ MICHELLE C. VALASEK
[Seal] Michelle C. Valasek
Notary Public
My Commission expires: June 30, 1993
PAGE 1
<TABLE>
EXHIBIT C
TO HYDROCARBON EXCHANGE AGREEMENT
CACTUS' POINTS OF RECEIPT
<CAPTION>
TOMAHAWK BIG BLUE MATAGORDA
----------------------- -------------------------- ------------------------
DAILY DAILY DAILY
VOL. MONTHLY VOL. VOL. MONTHLY VOL. VOL. MONTHLY VOL.
DAYS (MMBTU'S) (MMBTU'S) (MMBTU'S) (MMBTU'S) (MMBTU'S) (MMBTU'S)
---- --------- ----------- --------- ----------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Oct-92 ............. 31 31,500 976,500 13,500 418,500 45,000 1,395,000
Nov-92 ............. 30 31,500 945,000 13,500 405,000 22,500 675,000
Dec-92 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Jan-93 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Feb-93 ............. 28 31,500 882,000 13,500 378,000 22,500 630,000
Mar-93 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Apr-93 ............. 30 31,500 945,000 13,500 405,000 22,500 675,000
May-93 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Jun-93 ............. 30 31,500 945,000 13,500 405,000 22,500 675,000
Jul-93 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Aug-93 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Sep-93 ............. 30 31,500 945,000 13,500 405,000 22,500 675,000
Oct-93 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Nov-93 ............. 30 31,500 945,000 13,500 405,000 22,500 675,000
Dec-93 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Jan-94 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Feb-94 ............. 28 31,500 882,000 13,500 378,000 22,500 630,000
Mar-94 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Apr-94 ............. 30 31,500 945,000 13,500 405,000 22,500 675,000
May-94 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Jun-94 ............. 30 31,500 945,000 13,500 405,000 22,500 675,000
Jul-94 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Aug-94 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Sep-94 ............. 30 31,500 945,000 13,500 405,000 22,500 675,000
Oct-94 ............. 31 31,500 976,500 13,500 418,500 22,500 697,500
Nov-94 ............. 30 25,983 779,490 13,500 405,000 22,500 675,000
Dec-94 ............. 31 25,983 805,473 13,500 418,500 22,500 697,500
Jan-95 ............. 31 25,983 805,473 13,500 418,500 22,500 697,500
Feb-95 ............. 28 25,983 727,524 13,500 378,000 22,500 630,000
Mar-95 ............. 31 25,983 805,473 13,500 418,500 22,500 697,500
Apr-95 ............. 30 25,983 779,490 13,500 405,000 22,500 675,000
May-95 ............. 31 25,983 805,473 13,500 418,500 22,500 697,500
Jun-94 ............. 30 25,983 779,490 13,500 405,000 22,500 675,000
Jul-95 ............. 31 25,983 805,473 13,500 418,500 22,500 697,500
Aug-95 ............. 31 25,983 805,473 13,500 418,500 22,500 697,500
Sep-95 ............. 30 25,983 779,490 13,500 405,000 22,500 675,000
Oct-95 ............. 31 25,983 805,473 13,500 418,500 22,500 697,500
Nov-95 ............. 30 22,212 666,360 13,500 405,000 22,500 675,000
Dec-95 ............. 31 22,212 688,572 13,500 418,500 22,500 697,500
Jan-96 ............. 31 22,212 688,572 13,500 418,500 22,500 697,500
Feb-96 ............. 29 22,212 644,148 13,500 391,500 22,500 652,500
Mar-96 ............. 31 22,212 688,572 13,500 418,500 22,500 697,500
Apr-96 ............. 30 22,212 666,360 13,500 405,000 22,500 675,000
May-96 ............. 31 22,212 688,572 13,500 418,500 22,500 697,500
Jun-96 ............. 30 22,212 666,360 13,500 405,000 22,500 675,000
---------- --------- ----------
38,852,811 18,481,500 31,500,000
========== ========== ==========
</TABLE>
SOUTH TEXAS TOTAL
------------------------- ------------------------
DAILY DAILY
VOL. MONTHLY VOL. VOL. MONTHLY VOL.
(MMBTU'S) (MMBTU'S) (MMBTU'S) (MMBTU'S)
--------- ------------ --------- ------------
Oct-92 ........... 40,000 1,240,000 130,000 4,030,000
Nov-92 ........... 40,000 1,200,000 107,500 3,225,000
Dec-92 ........... 40,000 1,240,000 107,500 3,332,500
Jan-93 ........... 40,000 1,240,000 107,500 3,332,500
Feb-93 ........... 40,000 1,120,000 107,500 3,010,000
Mar-93 ........... 40,000 1,240,000 107,500 3,332,500
Apr-93 ........... 40,000 1,200,000 107,500 3,225,000
May-93 ........... 40,000 1,240,000 107,500 3,332,500
Jun-93 ........... 40,000 1,200,000 107,500 3,225,000
Jul-93 ........... 40,000 1,240,000 107,500 3,332,500
Aug-93 ........... 40,000 1,240,000 107,500 3,332,500
Sep-93 ........... 40,000 1,200,000 107,500 3,225,000
Oct-93 ........... 40,000 1,240,000 107,500 3,332,500
Nov-93 ........... 40,000 1,200,000 107,500 3,225,000
Dec-93 ........... 40,000 1,240,000 107,500 3,332,500
Jan-94 ........... 40,000 1,240,000 107,500 3,332,500
Feb-94 ........... 40,000 1,120,000 107,500 3,010,000
Mar-94 ........... 40,000 1,240,000 107,500 3,332,500
Apr-94 ........... 40,000 1,200,000 107,500 3,225,000
May-94 ........... 40,000 1,240,000 107,500 3,332,500
Jun-94 ........... 40,000 1,200,000 107,500 3,225,000
Jul-94 ........... 40,000 1,240,000 107,500 3,332,500
Aug-94 ........... 40,000 1,240,000 107,500 3,332,500
Sep-94 ........... 40,000 1,200,000 107,500 3,225,000
Oct-94 ........... 40,000 1,240,000 107,500 3,332,500
Nov-94 ........... 40,000 1,200,000 101,983 3,059,490
Dec-94 ........... 40,000 1,240,000 101,983 3,161,473
Jan-95 ........... 40,000 1,240,000 101,983 3,161,473
Feb-95 ........... 40,000 1,120,000 101,983 2,855,524
Mar-95 ........... 40,000 1,240,000 101,983 3,161,473
Apr-95 ........... 40,000 1,200,000 101,983 3,059,490
May-95 ........... 40,000 1,240,000 101,983 3,161,473
Jun-94 ........... 40,000 1,200,000 101,983 3,059,490
Jul-95 ........... 40,000 1,240,000 101,983 3,161,473
Aug-95 ........... 40,000 1,240,000 101,983 3,161,473
Sep-95 ........... 40,000 1,200,000 101,983 3,059,490
Oct-95 ........... 40,000 1,240,000 101,983 3,161,473
Nov-95 ........... 40,000 1,200,000 98,212 2,946,360
Dec-95 ........... 40,000 1,240,000 98,212 3,044,572
Jan-96 ........... 0 0 58,212 1,804,572
Feb-96 ........... 0 0 58,212 1,688,148
Mar-96 ........... 0 0 58,212 1,804,572
Apr-96 ........... 0 0 58,212 1,746,360
May-96 ........... 0 0 58,212 1,804,572
Jun-96 ........... 0 0 58,212 1,746,360
---------- -----------
47,480,000 136,314,311
========== ===========
<PAGE>
PAGE 2
<TABLE>
EXHIBIT C (CONTINUED)
TO HYDROCARBON EXCHANGE AGREEMENT
CACTUS' POINTS OF RECEIPT
<CAPTION>
TOMAHAWK BIG BLUE MATAGORDA
- ---------------------------- ------------------------ ------------------------------------
<S> <C> <C>
POINT OF RECEIPT: POINT OF RECEIPT: POINTS OF RECEIPT:
Trailblazer/CIG Interconnect El Paso/CIG Interconnect 1. Seagull Shoreline/HPL
Weld County, Colorado Moore County, Texas Interconnect, Oyster Lake, Texas
2. Seagull/TETCO Interconnect,
Blessing, Texas
3. HPL/TOMCAT Tailgate, Calhoun
County, Texas
4. Seagull/Matagorda Gas Processing
Plant, Matagorda, TX
5. 'MOPS'/HPL Interconnect, near
Tivoll, Refugio County, TX
6. 'MOPS'/FGT Interconnect, near
Tivoll, Refugio County, TX
</TABLE>
SOUTH TEXAS
-------------------------------------
POINTS OF RECEIPT:
1. Seagull Shoreline/HPL
Interconnect, Oyster Lake, Texas
2. Seagull/TETCO Interconnect,
Blessing, Texas
3. HPL/TOMCAT Tailgate, Calhoun
County, Texas
4. Seagull/Matagorda Gas Processing
Plant, Matagorda, TX
5. 'MOPS'/HPL Interconnect, near
Tivoll, Refugio County, TX
6. HPL 'Vonnie Cook' Facilities,
Hidalgo County , TX
7. HPL 'Pillsbury' Facilities,
McMullen County, TX
8. HPL/Transco Interconnect @ Bammel
Storage Facility, Harris County,
TX
9. HPL/NGPL Interconnect near Devers,
Liberty County, TX
10. HPL/Exxon Interconnect near Katy,
Waller County, TX
11. HPL/Lonestar Interconnect near
Katy, Waller County, TX
12. HPL/UTTCO Interconnect near Katy,
Waller County, TX
13. HPL/Oasis Interconnect near Katy,
Waller County, TX
14. 'MOPS'/FGT Interconnect, near
Tivoll, Refugio County, TX
EXHIBIT 10.37(c)
FIRST AMENDMENT
TO
HYDROCARBON EXCHANGE AGREEMENT
Reference for all purposes in hereby made to that certain Hydrocarbon
Exchange Agreement (the "Exchange Agreement"), Dated September 25, 1992, by and
between ENRON OIL & GAS COMPANY, a Delaware corporation ("EOG") to CACTUS
HYDROCARBON 1992-A LIMITED PARTNERSHIP, a Delaware limited partnership, whose
address in 1400 Smith Street, P.O. Box 1188, Houston, Texas 77251-1188
("Cactus"), pertaining to certain Hydrocarbons, which Exchange Agreement is
recorded as set forth on Exhibit C hereto under the caption "Hydrocarbon
Exchange Agreement."
WHEREAS, EOG and Cactus desire to amend the Exchange Agreement as
hereinafter set forth as of April 1, 1993 (the "Effective Date") to release
certain oil and gas leases, wells and related interests as sources of supply
from the Exchange Agreement and to add certain additional oil and gas leases and
related interests as sources of supply and to make other changes as provided
herein:
NOW, THEREFORE, for and in consideration of the premises and of the sum
of Ten Dollars and no/100ths ($10.00) and other good and valuable consideration,
cash in hand paid to EOG by Cactus, EOG and Cactus do hereby amend the Exchange
Agreement as follows:
1. Capitalized terms as used herein shall have the meanings given to
them in the Exchange Agreement unless otherwise defined herein.
2. Exhibit A to the Exchange Agreement is hereby amended by deleting
those oil and gas leases and related interests set forth on Exhibit A-1 hereto
and those wells set forth on Exhibit A-2 hereto and adding those oil and gas
leases and related interests set forth on Exhibit B hereto.
3. Except as expressly amended hereby, the Exchange Agreement shall
remain in full force and effect as heretofore entered into and amended. EOG and
Cactus ratify and confirm the Exchange Agreement as hereby amended.
EXECUTED in multiple originals this 21st day of May, 1993, but effective
as of the Effective Date.
EOG:
WITNESSES: ENRON OIL & GAS COMPANY
By: /s/ D. WEAVER
Name: D. Weaver
Title: Agent and Attorney-in-fact
Cactus:
WITNESSES: CACTUS HYDROCARBON 1992-A LIMITED
PARTNERSHIP
/s/ MARY NELL BROWNING
Mary Nell Browning By: Enron Big Piney Corp.
General Partner
/s/ CINDY WALTON
Cindy Walton By: /s/ ANDREW S. FASTOW
Name: Andrew S. Fastow
Title: Vice President
EXHIBIT "A-1" - Description of Deleted Leases
EXHIBIT "A-2" - Description of Deleted Wells
EXHIBIT "B" - Description of Added Leases
EXHIBIT "C" - Recordation Schedule-Hydrocarbon Exchange
Agreement
Please return to:
Crystal L. Lightfield
2500 First City Tower
1001 Fannin
Houston, Texas 77002
STATE OF COLORADO )
) ss.
COUNTY OF DENVER )
The foregoing instrument was acknowledged before me this 21st day of
May, 1993, by D. Weaver as Agent and Attorney-in-Fact of Enron Oil & Gas
Company.
WITNESS my hand and official seal.
My Commission Expires: /s/ DEBBIE CHRISTY
3-27-97 Debbie Christy
Notary Public
STATE OF TEXAS ss.
ss.
COUNTY OF HARRIS ss.
On this 20th day of May, 1993, before me, the undersigned Notary Public
in and for the State of Texas, personally appeared Andrew S. Fastow, to me
personally known, who, being by me duly sworn, did say that he is the Vice
President of Enron Big Piney Corp., General Partner of CACTUS HYDROCARBON 1992-A
LIMITED PARTNERSHIP, a Delaware limited partnership, and that the instrument was
signed on behalf of said corporation, acting as General Partner of said limited
partnership and that he acknowledged the instrument to be the free act and deed
of the limited partnership.
/s/ SUSAN LOUISE W. WADLE
Susan Louise W. Wadle
NOTARY PUBLIC, IN AND FOR
THE STATE OF TEXAS
Printed Name of Notary
EXHIBIT A-1
Attached to and made a part of that certain First Amendment to Hydrocarbon
Exchange Agreement effective as of the 1st day of April, 1993 between Enron Oil
& Gas Company ("EOG") and Cactus Hydrocarbon 1992-A Limited Partnership
("Cactus").
<TABLE>
DELETED LEASES
SUBLETTE COUNTY, WYOMING
<CAPTION>
ENRON LEASE
LEASE NO. LESSOR LEGAL DESCRIPTION DATE RECORDING
- ---------- ------ ----------------- ---- ---------
<S> <C> <C> <C> <C>
0050097-000 EV-023584 TOWNSHIP 28 NORTH, RANGE 113 WEST, 6TH P.M. 6/1/48 Not Recorded
Section 23: Lot 4 (27,24), W/2NW/4
Below 1500' above the top of the Frontier
formation
0050109-000 State WY- TOWNSHIP 29 NORTH, RANGE 113 WEST, 6TH P.M. 9/16/48 Not Recorded
07395 Section 16: E/2
Below 1500' above the top of the Frontier
formation
0050115-000 WY-04732 TOWNSHIP 28 NORTH, RANGE 113 WEST, 6TH P.M. 2/1/51 Not Recorded
Section 4: Lots 7 (35.76), 8 (36.27),
S/2NW/4, SW/4
Below 1500' above the top of the Frontier
formation
0050116-000 W-026038-A TOWNSHIP 29 NORTH, RANGE 113 WEST, 6TH P.M. 2/1/50 BK 31, PG 206
Section 21: E/2
Section 27: NW/4NW/4
Section 28: N/2NE/4
Below 1500' above the top of the Frontier
formation
0050125-000 McGinnis, TOWNSHIP 28 NORTH, RANGE 113 WEST 6TH P.M. 7/1/46 BK2, PG 101
Mary et al Section 27: Resurvey Tract 48
From 1500' above the top of the Frontier
formation to the base of the Frontier
formation
</TABLE>
<TABLE>
LINCOLN COUNTY, WYOMING
<CAPTION>
ENRON LEASE
LEASE NO. LESSOR LEGAL DESCRIPTION DATE RECORDING
--------- ------ ----------------- ---- ---------
<S> <C> <C> <C> <C>
0050272-000 EV-09156-B TOWNSHIP 26 NORTH, RANGE 113 WEST, 6TH P.M. 6/1/48 BK 17, PG 283
Section 5: E/2SE/4
No depth limitations
</TABLE>
EXHIBIT A-2
Attached to and made a part of that certain First Amendment to
Hydrocarbon Exchange Agreement effective as of the 1st day of
April, 1993 between Enron Oil & Gas Company ("EOG") and Cactus
Hydrocarbon 1992-A Limited Partnership ("Cactus").
<TABLE>
DELETED WELLS
<CAPTION>
WELL WELL LEGAL WI NRI WI NRI
NAME NUMBER DESCRIPTION BPO BPO APO APO
---- ------ ----------- --- --- --- ---
<S> <C> <C> <C> <C> <C> <C>
SHU 65-05G 06152-00-00-1 TOWNSHIP 26 NORTH, RANGE 25.000% 20.350% 25.000% 20.3500%
113 WEST, 6TH P.M.
Section 5: E/2
Lincoln County, Wyoming
Tip Top Unit 06144-00-00-1 TOWNSHIP 27 NORTH, RANGE 1.4233% 1.0870% 1.4233% 1.0870%
Participating 113 WEST 6TH P.M.
Area "B" Parts of Sections 5 and 6
TOWNSHIP 28 NORTH, RANGE 113
WEST, 6TH P.M.
Portions of Sections 6-8,
16, 17 and 18
TOWNSHIP 28 NORTH RANGE
114 WEST, 6TH P.M.
Portions of Sections 1 and 12
Sublette County, Wyoming
</TABLE>
<PAGE>
EXHIBIT B
Attached to and made a part of the certain First Amendment to
Hydrocarbon Exchange Agreement effective as of the 1st day of
April, 1993 between Enron Oil & Gas Company ("EOG") and Cactus
Hydrocarbon 1992-A Limited Partnership ("Cactus").
<TABLE>
ADDED LEASES
SUBLETTE COUNTY, WYOMING
<CAPTION>
MOBIL LEASE
LEASE NO. LESSOR LEGAL DESCRIPTION DATE RECORDING
- --------- ------ ----------------- ---- ---------
<S> <C> <C> <C> <C>
W-2645 E-02577 TOWNSHIP 28 NORTH, RANGE 113 WEST 1/1/48 Not Available
6TH P.M.
Section 22: Lot 2 (23.91)
From the surface to 1500' above
the top of the Frontier formation
W-2579 E-02396 TOWNSHIP 28 NORTH, RANGE 113 WEST 7/1/48 Not Available
6TH P.M.
Section 27: Lots 2 (13.62), 3 (9.19)
Section 29: W/2NW/4
From the surface to 1500' above the
top of the Frontier formation
W-2571 E-02376 TOWNSHIP 28 NORTH, RANGE 113 WEST 12/1/47 BK 31, PG 429
6TH P.M.
Section 20: SW/4SW/4
From the surface to 1500' above the
top of the Frontier formation
W-2569 E-02287 TOWNSHIP 28 NORTH, RANGE 113 WEST 7/1/47 Not Available
6TH P.M.
Section 19: Lots 6, 7, 8, 9, 10,
11, 12, 13, 14, 15, 16 and 17
From the surface to 1500' above
the top of the Frontier formation
W-2568 E-02332 TOWNSHIP 28 NORTH, RANGE 113 WEST 10/1/48 Not Available
6TH P.M.
Section 30: N/2NE/4
From the surface to 1500' above the
top of the Frontier formation
W-2566 E-02355 TOWNSHIP 28 NORTH, RANGE 113 WEST 6/1/48 Not Available
6TH P.M.
Section 30: S/2NE/4
From the surface to 1500' above the
top of the Frontier formation
</TABLE>
<PAGE>
<TABLE>
EXHIBIT B
(continued)
ADDED LEASES
<CAPTION>
MOBIL LEASE
LEASE NO. LESSOR LEGAL DESCRIPTION DATE RECORDING
- --------- ------ ----------------- ---- ---------
<S> <C> <C> <C> <C>
W-2586 W-01495 TOWNSHIP 28 NORTH, RANGE 113 WEST 2/1/50 Not Available
6TH P.M.
Section 18: Lots 11, 12, 13, 14, 15,
16, 17, 18 (W/2SE/4)
From the surface to 1500' above the top of
the Frontier formation
</TABLE>
<PAGE>
EXHIBIT C
Attached to and made a part of that certain First Amendment to
Hydrocarbon Exchange Agreement effective as of the 1st day of
April, 1993 between Enron Oil & Gas Company ("EOG") and Cactus
Hydrocarbon 1992-A Limited Partnership ("Cactus").
DOCUMENT FILING ENTITY RECORDING REFERENCE
-------- ------------- -------------------
Hydrocarbon Exchange Agreement Lincoln County Book 318 PR, Page 1
dated September 25, 1992 between File No. 755520
EOG and Cactus October 8, 1992
Sublette County Book 90 O&G, Page 224
File No. 238876
October 2, 1992
EXHIBIT 10.37(d)
SECOND AMENDMENT
TO
HYDROCARBON EXCHANGE AGREEMENT
Reference for all purposes is hereby made to that certain Hydrocarbon
Exchange Agreement dated September 25, 1992, by and between ENRON OIL & GAS
COMPANY, a Delaware corporation ("EOG") to CACTUS HYDROCARBON 1992-A LIMITED
PARTNERSHIP, a Delaware limited partnership, whose address is 1400 Smith Street,
P.O. Box 1188, Houston, Texas 77251-1188 ("Cactus"), as amended by that certain
First Amendment to Hydrocarbon Exchange Agreement (the "Exchange Agreement"),
dated effective April 1, 1993, pertaining to certain Hydrocarbons, which
Exchange Agreement is recorded as set forth on Exhibit C hereto.
WHEREAS, EOG and Cactus desire to amend the Exchange Agreement as
hereinafter set forth as of July 1, 1993 (the "Effective Date") to release
certain oil and gas leases, wells and related interests as sources of supply
from the Exchange Agreement and to add certain additional oil and gas leases,
wells and related interests as sources of supply and to make other changes as
provided herein:
NOW, THEREFORE, for and in consideration of the premises and of the sum
of Ten Dollars and no/100ths ($10.00) and other good and valuable consideration,
cash in hand paid to EOG by Cactus, EOG and Cactus do hereby amend the Exchange
Agreement as follows:
1. Capitalized terms as used herein shall have the meanings given to
them in the Exchange Agreement unless otherwise defined herein.
2. Exhibit A to the Exchange Agreement is hereby amended by deleting
those oil and gas leases and related interests set forth on Exhibit A-1 hereto
and those wells set forth on Exhibit A-2 hereto and adding those oil and gas
leases and related interests set forth on Exhibit B-1 hereto and those wells set
forth on Exhibit B-2 hereto.
3. Except as expressly amended hereby, the Exchange Agreement shall
remain in full force and effect as heretofore entered into and amended. EOG and
Cactus ratify and confirm the Exchange Agreement as hereby amended.
4. This instrument is being executed in several counterparts, all of
which are identical. Each of such counterparts shall for all purposes be deemed
to be an original and all such counterparts shall together constitute but one
and the same instrument.
WITNESS THE EXECUTION HEREOF, this 24th day of September 1993, to be
effective as of the Effective Date.
EOG:
WITNESSES: ENRON OIL & GAS COMPANY
/s/ CINDY WALTON By: /s/ G.E. UTHLANT
Cindy WALTON Name: G.E. Uthlant
Title: Senior Vice President
/s/ MARY NELL BROWNING
Mary Nell Browning
Cactus:
WITNESSES: CACTUS HYDROCARBON 1992-A LIMITED
PARTNERSHIP
/s/ MARY NELL BROWNING By: Enron Big Piney Corp.
Mary Nell Browning General Partner
By: /s/ ANDREW S. FASTOW
/s/ DEBORAH KORKMAS Name: Andrew S. Fastow
Deborah Korkmas Title: Vice President
EXHIBIT "A-1" - Description of Deleted Leases
EXHIBIT "A-2" - Description of Deleted Wells
EXHIBIT "B-1" - Description of Added Leases
EXHIBIT "B-2" - Description of Added Wells
EXHIBIT "C" - Recordation Schedule - Hydrocarbon Exchange
Agreement and First Amendment to Hydrocarbon
Exchange Agreement
STATE OF TEXAS ss.
ss.
COUNTY OF HARRIS ss.
On this 29th day of September, 1993, before me, the undersigned Notary
Public in and for the state of Texas, personally appeared G.E. Uthlant, to me
personally known, who being by me duly sworn, did say that he is the Senior Vice
President of ENRON OIL & GAS COMPANY, a Delaware corporation, and that the
instrument was signed in behalf of the corporation by authority of its Board of
Directors and that he acknowledged the instrument to be the free act and deed of
the corporation.
/s/ SUSAN LOUISE W. WADLE
Susan Louise W. Wadle
NOTARY PUBLIC, IN AND FOR
STATE OF TEXAS
Printed Name of Notary
STATE OF TEXAS ss.
ss.
COUNTY OF HARRIS ss.
On this 29th day of September, 1993, before me, the undersigned Notary
Public in and for the State of Texas, personally appeared Andrew S. Faston to me
personally known, who being by me duly sworn, did say that he is the Vice
President of Enron Big Piney Corp., General Partner of CACTUS HYDROCARBON 1992-A
LIMITED PARTNERSHIP, a Delaware limited partnership, and that the instrument was
signed on behalf of said corporation, acting as General Partner of said limited
partnership and the he acknowledged the instrument to be the free act and deed
of the limited partnership.
/s/ SUSAN LOUISE W. WADLE
Susan Louise W. Wadle
NOTARY PUBLIC, IN AND FOR
THE STATE OF TEXAS
Printed Name of Notary
EXHIBIT A-1
Attached to and made a part of that certain Second Amendment to
Hydrocarbon Exchange Agreement effective as of the 1st day of
July, 1993 between Enron Oil & Gas Company ("EOG") as Grantor and
Cactus Hydrocarbon 1992-A Limited Partnership ("Cactus") as
Grantee.
<TABLE>
DELETED LEASES
SUBLETTE COUNTY, WYOMING
<CAPTION>
ENRON LEASE
LEASE NO. LESSOR LEGAL DESCRIPTION DATE RECORDING
- --------- ------ ----------------- ---- ---------
<S> <C> <C> <C> <C>
50427-000 W-05527 TOWNSHIP 26 NORTH, RANGE 112 WEST, 6TH P.M. 2/1/59 Not Recorded
Section 22: NE/4NE/4, SE/4, S/2NE/4
Section 23: NW/4NW/4, SW/4NW/4,3 E/2NW/4, SW/4
Limited to only the Frontier formation under
said lands.
</TABLE>
EXHIBIT A-2
Attached to and made a part of that certain Second Amendment to
Hydrocarbon Exchange Agreement effective as of the 1st day of
July, 1993 between Enron Oil & Gas Company ("EOG") as Grantor and
Cactus Hydrocarbon 1992-A Limited Partnership ("Cactus") as
Grantee.
<TABLE>
DELETED WELLS
LINCOLN COUNTY, WYOMING
<CAPTION>
WELL NAME WELL NUMBER LEGAL DESCRIPTION WI BPO NRI BPO WI APO NRI APO
- --------- ----------- ----------------- ------ ------- ------ -------
<S> <C> <C> <C> <C> <C> <C>
Fontenelle 11-3 0912100001 TOWNSHIP 26 NORTH, RANGE 112 WEST .0170308 .0148326 .0195606 .0161375
6TH P.M.
Section 36: NW/4NW/4
Formation: Consl. Frontier ABCD
Fontenelle 12-03 0912200001 TOWNSHIP 25 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 3: SW/4NW/4
Formation: Consl. Frontier ABCD
Fontenelle 13-11 0912300001 TOWNSHIP 25 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 11: NW/4SW/4
Formation Consl. Frontier ABCD
Fontenelle 13-24 0912400001 TOWNSHIP 26 NORTH, RANGE 112 WEST .0134239 .0118418 .0195597 .0184859
6TH P.M.
Section 24: NW/4SW/4
Formation Consl. Frontier ABCD
Fontenelle 13-34 0012400001 TOWNSHIP 26 NORTH, RANGE 112 WEST .0134239 .0118418 .0195597 .0184859
6TH P.M.
Section 34: NW/4SW/4
Formation Consl. Frontier ABCD
Fontenelle 14-01 0912500001 TOWNSHIP 25 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 1: SW/4SW/4
Formation Consl. Frontier ABCD
Fontenelle 14-02 0912600001 TOWNSHIP 25 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 2: SW/4SW/4
Formation Consl. Frontier ABCD
Fontenelle 14-04 0912800001 TOWNSHIP 25 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 4: SW/4NW/4
Formation Consl. Frontier ABCD
Fontenelle 14-06 0912900001 TOWNSHIP 25 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 6: Lot 7
Formation Consl. Frontier ABCD
Fontenelle 14-27 0912700001 TOWNSHIP 26 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 27: SW/4SW/4
Formation Consl. Frontier ABCD
Fontenelle 22-36 0913100001 TOWNSHIP 26 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 36: SE/4NW/4
Formation Consl. Frontier ABCD
Fontenelle 23-07F 0913400001 TOWNSHIP 25 NORTH, RANGE 111 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 7: NE/4SW/4
Formation Consl. Frontier ABCD
Fontenelle 23-25 0913200001 TOWNSHIP 26 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 25: NE/4SW/4
Formation Consl. Frontier ABCD
Fontenelle 23-33 0913300001 TOWNSHIP 26 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 33: Lot 7
Formation Consl. Frontier ABCD
Fontenelle 31-04 0913500001 TOWNSHIP 25 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 4: NW/4NE/4
Formation Consl. Frontier ABCD
Fontenelle 31-05 0913600001 TOWNSHIP 25 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 4: NW/4NE/4
Formation Consl. Frontier ABCD
Fontenelle 31-06F 0913700001 TOWNSHIP 25 NORTH, RANGE 111 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 6: NW/4NE/4
Formation Consl. Frontier ABCD
Fontenelle 32-10 0913800001 TOWNSHIP 25 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 10: SW/4NE/4
Formation Consl. Frontier ABCD
Fontenelle 33-04 0914100001 TOWNSHIP 25 NORTH, RANGE 112 WEST .0148326 .0148326 .0195606 .0161375
6TH P.M.
Section 4: NW/4SE/4
Formation Consl. Frontier ABCD
Fontenelle 33-12 0128800001 TOWNSHIP 15 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 12: NW/4SE/4
Formation Consl. Frontier ABCD
Fontenelle 33-13 0913900001 TOWNSHIP 25 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 13: NW/4SE/4
Formation Consl. Frontier ABCD
Fontenelle 33-24 0914000001 TOWNSHIP 26 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 25: NW/4SE/4
Formation Consl. Frontier ABCD
Fontenelle 34-03 0914000001 TOWNSHIP 15 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 3: SW/4SE/4
Formation Consl. Frontier ABCD
Fontenelle 34-09 0914500001 TOWNSHIP 25 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 9: SW/4SE/4
Formation Consl. Frontier ABCD
Fontenelle 34-23 0914200001 TOWNSHIP 26 NORTH, RANGE 111 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 23: SW/4SE/4
Formation Consl. Frontier ABCD
Fontenelle 34-28 0914300001 TOWNSHIP 26 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 28: Lot 9
Formation Consl. Frontier ABCD
Fontenelle 41-09 0914900001 TOWNSHIP 25 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 9: NE/4NE/4
Formation Consl. Frontier ABCD
Fontenelle 41-24 0914600001 TOWNSHIP 26 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 24: Lot 1
Formation Consl. Frontier ABCD
Fontenelle 41-26 0914800001 TOWNSHIP 26 NORTH, RANGE 112 WEST .0134239 .0118418 .0195606 .0161375
6TH P.M.
Section 36: Lot 1
Formation Consl. Frontier ABCD
</TABLE>
<PAGE>
EXHIBIT B-1
Attached to and made a part of that certain Second Amendment to
Hydrocarbon Exchange Agreement effective as of the 1st day of
July, 1993 between Enron Oil & Gas Company ("EOG) as Grantor and
Cactus Hydrocarbon 1992-A Limited Partnership ("Cactus") as
Grantee.
<TABLE>
ADDED LEASES
LINCOLN COUNTY, WYOMING
<CAPTION>
ENRON
LEASE NO. LESSOR LEGAL DESCRIPTION DATE RECORDED
- --------- ------ ----------------- ---- --------
<S> <C> <C> <C> <C>
75237-000 ST of WY TOWNSHIP 26 NORTH, RANGE 112 WEST, 2/2/86 Book 236 PR,
86-00117 6TH P.M. Page 170
Section 16: NW/4, NW/4NE/4,
S/2NE/4,S1/2
</TABLE>
<PAGE>
EXHIBIT B-2
Attached to and made a part of that certain Second Amendment to
Hydrocarbon Exchange Agreement effective as of the 1st day of
July, 1993 between Enron Oil & Gas Company ("EOG") as Grantor and
Cactus Hydrocarbon 1992-A Limited Partnership ("Cactus") as
Grantee.
<TABLE>
ADDED WELLS
LINCOLN COUNTY, WYOMING
<CAPTION>
WELL NAME WELL NUMBER LEGAL DESCRIPTION WI BPO NRI BPO WI APO NRI APO
--------- ----------- ----------------- ------ ------- ------ -------
<S> <C> <C> <C> <C> <C> <C>
Spur Canyon #1 0236940001 TOWNSHIP 26 NORTH, RANGE 112 WEST 100% 75% 100% 75%
6TH P.M.
Section 16: NE/4NW/4
West Stead
Canyon #22-16 0240000001 TOWNSHIP 26 NORTH, RANGE 112 WEST 100% 75% 100% 75%
6TH P.M.
Section 16: SW/4NE/4
</TABLE>
<PAGE>
EXHIBIT C
Attached to and made a part of that certain Second Amendment to
Hydrocarbon Exchange Agreement effective as of the 1st day of May, 1993
between Enron Oil & Gas Company ("EOG") as Grantor and Cactus
Hydrocarbon 1992-A Limited Partnership ("Cactus") as Grantee.
DOCUMENT FILING ENTITY RECORDING REFERENCE
-------- ------------- -------------------
Hydrocarbon Exchange Agreement Lincoln County Book 318 PR, Page 1
dated September 25, 1992 between File No. 755520
EOG and Cactus October 8, 1992
Sublette County Book 90 O&G, Page 224
File No. 238876
October 2, 1992
First Amendment to Hydrocarbon Lincoln County Book 330 PR, Page 39
Exchange Agreement dated File No. 765868
effective April 1, 1993 between June 4, 1993
Sublette County Book 92 O&G, Page 333
File No. 241741
May 28, 1993
EXHIBIT 10.37(e)
AMENDMENT TO HYDROCARBON
EXCHANGE AGREEMENT
This Amendment to Hydrocarbon Exchange Agreement (this "AMENDMENT") is
entered into this 17th day of June 1994, effective August 1, 1993, by and
between ENRON OIL & GAS COMPANY ("EOG") and CACTUS HYDROCARBON 1992-A LIMITED
PARTNERSHIP ("CACTUS"). Where the context requires, EOG and Cactus shall be
referred to individually as a "PARTY" and collectively as the "PARTIES."
W I T N E S S E T H :
WHEREAS, Cactus and EOG entered into that certain Hydrocarbon Exchange
Agreement dated September 25, 1992, as amended by instrument dated effective
January 1, 1993 (collectively, the "EXCHANGE AGREEMENT"); and
WHEREAS, Cactus and EOG desire to amend the Exchange Agreement to change
the Index for the Matagorda Point of Receipt;
NOW, THEREFORE, in consideration of the premises and mutual covenants
herein contained, and other good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged, the Parties mutually agree as
follows:
1. Reference is made to the Exchange Agreement for all
purposes. All references in this exchange agreement and
this Amendment to the defined term Exchange Agreement or
Agreement shall include and refer to the Exchange
Agreement as amended by this Amendment. Unless otherwise
defined herein, capitalized terms used herein shall have
the same meanings given to them in the Exchange
Agreement.
2. The Parties hereby agree to amend Exhibit D of the Exchange
Agreement to delete the reference to "Texas Eastern Transmission
Co.-Texas" under heading "Index" for the Matagorda Point of
Receipt and replace it with "Texas Eastern Transmission Co.-South
Texas."
3. Except as amended herein, the Exchange Agreement shall be
and remain in force and effect as originally written.
IN WITNESS WHEREOF, EOG and Cactus have caused this Amendment to be
executed this 17th day of June, 1994.
ENRON OIL & GAS COMPANY
ATTEST:
By: /S/ J. JEFFERS SPENCER By: /S/ ANDREW N. HOYLE
Name: J. Jeffers Spencer Name: Andrew N. Hoyle
Title: Assistant Secretary Title: Vice President,
Marketing
CACTUS HYDROCARBON 1992-A
LIMITED PARTNERSHIP
BY: ENRON BIG PINEY CORP.,
GENERAL PARTNER
ATTEST:
By: /S/ JOAN QUICK By: /S/ JERE C. OVERDYKE, JR.
Name: Joan Quick Name: Jere C. Overdyke, Jr.
Title: Contract Admin. Title: Vice President
STATE OF TEXAS ss.
ss.
COUNTY OF HARRIS ss.
On this 17th day of June, 1994, before me personally appeared Andrew N.
Hoyle, to me personally known, who, being by me duly sworn, did say that he is
the Vice President, Mktg. of Enron Oil & Gas Company and that the seal affixed
to said instrument is the corporate seal of said corporation, and that said
instrument was signed and sealed on behalf of said corporation by authority of
its Board of Directors and said Andrew N. Hoyle acknowledged said instrument to
be the free act and deed of said corporation.
Given under my hand and notarial seal.
/S/ MICHELLE GREEN
Michelle Green
Notary Public
My Commission Expires: September 2, 1997
STATE OF TEXAS ss.
ss.
COUNTY OF HARRIS ss.
On this 14th day of June 1994, before me personally appeared Jere C.
Overdyke, Jr., Vice President, of Enron Piney Corp., General Partner of Cactus
Hydrocarbon 1992-A Limited Partnership, known to me to be the person who
executed the within Amendment to Hydrocarbons Exchange Agreement on behalf of
said corporation, acting as General Partner of said partnership and acknowledged
to me that he executed the same for the purposes therein stated.
Given under my hand and notarial seal.
/S/ BERTHA M. FRAZIER
Bertha M. Frazier
Notary Public
My Commission Expires: 4-19-96
EXHIBIT 10.45(a)
THE BANK OF NOVA SCOTIA Cable Address
Hato Rey Branch 'Scotiabank'
Plaza Scotiabank
273 Ponce De Leon Ave. 4th Floor Address Your
Hato Rey, Puerto Rico Reply To
G.P.O Box 6262
May 27, 1994 San Juan, P.R. 00936
Enron Gas & Oil Trinidad Limited
Second Floor, The Mutual Centre
16 Queen's Park West
Port of Spain
Republic of Trinidad & Tobago
British West Indies
ATTN: MANAGING DIRECTOR
Dear Sirs:
We hereby submit this Letter Loan Agreement (the "Agreement") setting out
the terms and conditions under which The Bank of Nova Scotia's Hato Rey Branch
(the "Bank") agrees to extend to Enron Gas & Oil Trinidad Limited (the
"Borrower") the credit facilities referred to herein:
LETTER LOAN AGREEMENT
1. BORROWER: Enron Gas & Oil Trinidad Limited
2. TYPE OF CREDIT: Non-Revolving Term Credit available by way of direct
advances. Although the credit facility is a non-revolving facility, the
Borrower will be allowed to borrow, repay and reborrow the Working Capital
Amount (as defined hereinafter) within the term of the Loan as provided
hereunder.
3. LOAN AMOUNT: Up to an aggregate amount not to exceed at any time
outstanding US$44,000,000 (the "Commitment").
4. PURPOSES: To finance (or refinance or replace with Advances funded with
936 Deposits as permitted by paragraphs (c)(7)(i) and (c)(7)(ii) of the
Federal CBI Regulations) the costs of the Borrower's exploration for and
development and production of natural gas and crude oil from the Kiskadee
and Ibis Fields in the South East Coast Consortium Block offshore Trinidad
& Tobago,
including without limitation, the constructing of off-shore platforms,
laying of pipelines, drilling of wells and installation of all related
equipment and facilities (the "Active Business Assets"). The proceeds of
the Loan may also be used for working capital purposes, provided that the
amount used for such purposes may not exceed 10% of the amount invested in
Active Business Assets (the "Working Capital Amount").
5. DEFINITIONS: "936 Deposits" means deposits of eligible funds by exempted
businesses under the Puerto Rico Industrial Incentives Acts and/or the
Puerto Rico Tax Incentive Act.
"936 Option Rate" shall have the meaning described in Section 8(a) hereof.
"Active Business Assets" shall have the meaning described in Section 4
hereof.
"Advance" means an advance from the Bank to the Borrower pursuant to
Section 7 hereof.
"Base Rate" means the variable per annum reference rate of interest, as
announced and adjusted by The Bank of Nova Scotia from time to time in the
City of New York as its base rate, for United States dollar loans made by
such bank in the United States and Puerto Rico. No representation is made
by the Bank that such rate is the lowest or most favorable rate offered by
The Bank of Nova Scotia.
"Business Day" means (i) as to LIBOR funded portions of the Loan, a day of
the year on which dealings are carried on in the London interbank market
and banks are open for business in London and not required or authorized
to close in New York City, Puerto Rico or Trinidad & Tobago and (ii) as to
the 936 Deposits and Base Rate funded portions of the Loan, a day in which
the Bank is not required or authorized to close for business in Puerto
Rico or Trinidad & Tobago.
"Commissioner" shall have the meaning described in Section 18.3(a) hereof.
"Date of this Agreement" means the date on which the Borrower accepts this
Agreement by execution of the original and one counterpart.
"Event of Default" shall have the meaning described in Section 19 hereof.
"Federal CBI Regulations" shall have the meaning described in Section
18.3(b) hereof.
"Funding Period" means one of the successive periods into which the period
between the date of the first Advance and the Maturity Date shall be
divided. The termination date of each such Funding Period shall be
referred to as a Rollover Date.
"Governmental Authority" means (a) the United States of America, (b) the
Commonwealth of Puerto Rico, (c) Trinidad & Tobago, (d) any political
subdivision of any jurisdiction referenced in clauses (a) through (c) of
this sentence and (e) any court, agency, department, commission, board,
bureau or instrumentality of any jurisdiction referenced in clauses (a)
through (c) of this sentence.
"Guarantor" shall mean Enron Oil & Gas Company.
"Guaranty" shall have the meaning described in Section 13 hereof.
"Interest Payment Date" shall mean the first day of each of the months of
January, April, July and October.
"LIBOR" means the rate of interest per annum at which deposits of equal or
like amounts in United States dollars are offered by the principal office
of The Bank of Nova Scotia in London, England, to prime banks in the
London interbank market at 11:00 a.m. (London time), two (2) business days
before the first day of the particular Funding Period for a period equal
to such Funding Period, as adjusted by the Bank to reflect the impact of
the municipal license taxes upon the Bank.
"LIBOR Option Rate" shall have the meaning described in Section 8(b)
hereof.
"Loan" means the principal sum of US$44,000,000, or, if less, the
aggregate unpaid principal amount of the Advances owing to the Bank
outstanding from time to time.
"Loan Documents" means this Agreement with its Exhibits, the Promissory
Notes, the Non Revolving Term Note, and the Guaranty.
"Non Revolving Term Note" shall have the meaning described in Section 7(b)
hereof.
"Promissory Note" means a promissory note of the Borrower payable to the
order of the Bank, in the form and substance of Exhibit "A" attached
hereto and incorporated herein, evidencing the indebtedness of the
Borrower resulting from each Advance made hereunder by the Bank.
"Regulation 3582" shall have the meaning described in Section 18.3(a)
hereof.
"Regulation 5002" shall have the meaning described in Section 18.3(a)
hereof.
"Termination Date" means the date that is the earlier of 5 years from the
Date of this Agreement or the date that the Agreement terminates pursuant
to Section 19 hereof.
"Working Capital Amount" shall have the meaning described in Section 4
hereof.
6. TERMS/MATURITY: The Borrower shall repay the Bank the outstanding
principal amount of the Loan due hereunder in full on the fifth
anniversary date of the Date of this Agreement (the "Maturity Date").
7. EVIDENCING AVAILMENTS/DRAWINGS:
(a) The Bank agrees, on the terms and conditions set forth herein, to make
one or more Advances to the Borrower from time to time on any Business Day
during the period from the Date of this Agreement until the Termination
Date in an aggregate amount not to exceed at any time outstanding the
Commitment. Each Advance shall reduce the amount of the
Commitment by the principal amount of such Advance. Each Advance shall be
in an aggregate amount of not less than US$500,000 and integral multiples
of US$500,000 above such amount, and shall be evidenced by a Promissory
Note. Within the limits of the Commitment, the Borrower may borrow the
Working Capital Amount, prepay such amount pursuant to Section 12 hereof
and reborrow such amount under this Section 7(a).
(b) When the Commitment has been fully drawn or if no further draws are to
be made hereunder, all Promissory Notes outstanding shall be substituted
and replaced by one Non-Revolving Term Note. The Non-Revolving Term Note
shall be in the form and substance of Exhibit "B" attached hereto and
incorporated herein.
8. INTEREST RATES: The Borrower shall have the following interest rate
options on each Advance:
(a) The cost of 30, 60, 90 or 180 day 936 Deposits (as determined by the
Bank and adjusted for the cost to the Bank of the municipal license
taxes), plus 50 basis points per annum (subject to the availability of 936
Deposits and to the continuing qualification of the Loan for 936 funding)
(the "936 Option Rate");
(b) 1, 2, 3, or 6 months cost of LIBOR plus 50 basis points per annum
(subject to the availability of LIBOR funds) (the "LIBOR Option Rate");
(c) If both 936 Deposits and LIBOR funds become unavailable or may not be
used, the Base Rate interest rate will apply fluctuating concurrently with
any changes in such Base Rate;
(d) Notwithstanding anything to the contrary provided in paragraphs (a)
and (b) above, at any time during the term of the Loan, the Borrower may
request the Bank to fix the rate of interest on all or any portion of the
Loan, effective on a Rollover Date, for a period not to exceed the then
remaining
term of the Loan, subject to the availability to the Bank of 936 Deposits
or LIBOR funds with the same maturity as the term of the fixed rate, at a
rate mutually agreeable to the Borrower and the Bank. Any prepayment by
the Borrower of all or any portion of the Loan with a fixed interest rate,
shall be subject to the payment by the Borrower of the breakage costs
described in Section 12 hereof;
(e) Notwithstanding anything to the contrary herein provided, the interest
rate applicable to any principal under the Loan outstanding after the
Maturity Date or after the Loan is declared due and payable pursuant to
Section 19 hereof shall be 2% per annum over the Base Rate;
(f) Upon the first Advance and thereafter three Business Days prior to the
first day of each new Funding Period, the Bank shall notify to the
Borrower the following rates of interest on such Business Day (a) subject
to the availability to the Bank of 936 Deposits and to the eligibility of
the Advance to be funded with 936 Deposits, the 936 Option Rate; and (b)
subject to the availability to the Bank of LIBOR funds for such Funding
Period, the LIBOR Option Rate. In the case of 936 Deposit funding, the
Borrower must advise the Bank not later than 12 noon Puerto Rico time on
the first Business Day of the ensuing Funding Period, and in the case of
LIBOR funding two (2) Business Days before such Business Day which of the
two funding options it selects for the ensuing Funding Period. The
interest rate applicable to such Funding Period shall be the interest rate
applicable on the first day of the Funding Period to the funding option
selected by the Borrower. If the Borrower fails to make such timely notice
of election then the interest rate beginning on the first day of such
Funding Period shall be computed on the basis of the 30 day 936 Option
Rate until a new Funding Period is established, or, if 936 Deposits are
not available, on the basis of 30 day LIBOR Option Rate or, if LIBOR funds
are not available, on the basis of the Base Rate.
9. FEES:
(a) The Borrower shall pay to the Bank on the Date of this Agreement a
one-time front end fee of 15 basis points times the Commitment amount.
This fee includes the Bank's cost of presenting the necessary applications
for 936 funding to the Puerto Rico government agencies.
(b) On each anniversary date from the Date of this Agreement, the Borrower
shall pay the Bank an annual administration fee of US$10,000.00.
(c) On each Interest Payment Date, the Borrower shall pay the Bank a
Standby Fee amounting to 15 basis points of the unutilized portion of the
Commitment, computed on a daily basis, on the basis of a 365/366 days
year.
9.A VARIATIONS ININTEREST RATES AND STANDBY FEE: The interest rates and the
Standby Fee set forth in Sections 8 and 9(c) hereof, shall be increased
and reduced concurrently with any increases or reductions in the
Guarantor's senior unsecured long term debt rating by Standard and Poor's
("S&P") or Moody's, as follows:
S&P or Standby LIBOR 936
Moody's Rating Fee Plus Plus
-------------- -------- ----- ----
A or A2, or better 12.5 bp 37.5 bp 37.5 bp
BBB+ or Baa1, or
better 15 bp 50 bp 50 bp
BBB and Baa2 17.5 bp 55 bp 55 bp
BBB- or Baa3 20 bp 62.5 bp 62.5 bp
BBB- and Baa3 25 bp 75 bp 75 bp
BB+ or lower and
Ba1 or lower 37.5 bp 112.5 bp 112.5 bp
10. CALCULATION AND PAYMENT OF INTEREST: The Borrower shall pay interest
quarterly in arrears on each Interest Payment Date, or on Rollover Dates,
whichever is earlier, on the actual daily unpaid principal balance of the
Loan and calculated on each such day on the basis of (i) a 365/366 day
calendar year for the actual number of days elapsed with respect to Base
Rate Advances, and (ii) a 360-day calendar year for the actual number of
days elapsed with respect to 936 Option Rate and/or LIBOR Option Rate
Advances.
11. REPAYMENT: The principal amount of the Loan or the outstanding balance
thereof shall be repaid in full on the Maturity Date. Payments hereunder
shall be made by the Borrower at the Bank's Hato Rey Branch located at
Plaza Scotiabank, Hato Rey, Puerto Rico or by wire transfer to the
following account: Federal Reserve Bank of New York, Account the Bank of
Nova Scotia, New York, ABA No. 02600-2-532, Account The Bank of Nova
Scotia, Hato Rey, Transit 13185. In the event that the day in which a
payment due under this Agreement is not a Business Day, such payment shall
be due on the immediately succeeding Business Day.
12. PREPAYMENT: No prepayment of all or any portion of the Loan shall be
permitted at any time in whole or in part when Advances are funded with
936 Deposits or LIBOR funds, except on a Rollover Date. If a prepayment is
made on a date other than a Rollover Date, the Borrower shall pay to the
Bank an amount equal to the additional costs and/or losses incurred by the
Bank as a result of the prepayment, as determined solely by the Bank. A
certificate by the Bank showing the computation of the additional costs
and/or losses shall be conclusive evidence of the amount thereof, in the
absence of manifest error.
13. SECURITY: The unconditional in solidum guaranty of Enron Oil & Gas Company
in favor of the Bank, dated as of the Date of this Agreement, in the form
of Exhibit C (the "Guaranty"), shall be in full force and effect before
any Advance is made pursuant to this Agreement, and such security shall
remain in full force and effect until all principal and interest due
hereunder is fully paid and all other obligations of the Borrower
hereunder have been fully satisfied.
14. REPRESENTATIONS AND WARRANTIES OF BORROWER: In order to induce the Bank
to lend hereunder, the Borrower represents and warrants as follows:
14.1 ORGANIZATION AND STANDING OF BORROWER The Borrower has been duly
organized and is validly existing in good standing under the laws of
Trinidad & Tobago.
14.2 AUTHORITY AND NO VIOLATION The Borrower has the corporate power and
authority to execute, deliver and perform its obligations under this
Agreement, the Promissory Notes and the Non Revolving Term Note
(hereinafter collectively with the Promissory Notes referred to as
the "Notes") to be delivered by it and to make the borrowings
hereunder. The execution, delivery and performance of this Agreement
and the Notes, and the borrowings hereunder (a) have been duly
authorized by all requisite corporate or shareholder action, (b) do
not conflict with or result in a violation or breach of the
corporate documents of the Borrower or of any agreement, instrument,
statute, regulation, rule, order, writ, judgment or decree to which
the Borrower or its property is directly or indirectly a party or is
directly or indirectly subject and (c) will not give cause for
acceleration of any indebtedness of the Borrower.
14.3 NO CONSENT REQUIRED No approval, authorization or other action by,
or filings with any Governmental Authority or other entity is
required in connection with the execution, delivery and performance
by the Borrower of this Agreement, the borrowings hereunder and the
execution and delivery of the Notes.
14.4 FINANCIAL CONDITION OF BORROWER The Borrower has heretofore
furnished to the Bank the audited balance sheet of the Borrower's
operations in Trinidad & Tobago as of December 31, 1993 and the
related statements of income, retained earnings and cash flows for
the period ended December 31, 1993. Such financial statements were
prepared in accordance with generally accepted accounting principles
consistently applied by the Borrower, and present fairly the
financial condition and results of operations at the dates and for
the periods indicated therein.
14.5 NO MATERIAL ADVERSE CHANGE There has been no material adverse change
(not in the ordinary course of business) in the financial condition
of the Borrower since December 31, 1993.
14.6 LITIGATION There are no lawsuits or other claims or proceedings
pending or, to the knowledge of the Borrower, threatened, against or
affecting the Borrower or any of its properties, by or before any
Governmental Authority, which, if adversely determined (individually
or in the aggregate), would have a material adverse effect on the
financial condition of the Borrower, or which involve this Agreement
or any of the transactions contemplated hereby. The Borrower is not
in default with respect to any order, writ, injunction, decree, rule
or regulation of any Governmental Authority, which default would
have a material adverse effect upon the financial condition of the
Borrower.
14.7 COMPLIANCE WITH LAWS, ETC. The Borrower is in compliance and shall
comply with all applicable laws, rules, regulations and orders, to
the extent noncompliance therewith would have a material adverse
effect on the financial condition of the Borrower.
15. AFFIRMATIVE COVENANTS: From the date of this Agreement and for so long as
the same shall be in effect or any amount shall remain outstanding under
any Note made pursuant to this Agreement and for so long as Borrower owes
any obligation whatsoever to the Bank pursuant to this Agreement, the
Borrower agrees that it shall:
15.1 CORPORATE EXISTENCE Do or cause to be done all things necessary
to preserve, renew and keep in full force and effect its corporate
existence, material rights, licenses, permits and franchises and
comply in all material respects with all laws and regulations
applicable to it provided, however, that the Borrower shall not be
required to preserve any right, license, permit or franchise if the
Borrower shall determine that the preservation thereof is no longer
desirable in the conduct of the business of the Borrower, and that
the loss thereof is not disadvantageous in any material respects to
the Bank.
15.2 INSURANCE Maintain insurance with responsible and reputable
insurance companies or associations in such amounts and covering
such risks as is usually carried by companies engaged in similar
businesses and owning similar properties as the Borrower, provided,
that self-insurance by the Borrower shall not be deemed a violation
of this covenant to the extent that companies engaged in similar
businesses and owning similar properties as the Borrower
self-insure.
15.3. NOTICE OF EVENT OF DEFAULT Promptly give to the Bank notice in
writing of the occurrence of any Event of Default.
15.4. NOTICE OF JUDGMENTS AND CHANGE IN CONTROL Promptly give to the Bank
notice in writing of (i) any final judgment(s) in excess of
US$10,000,000 in the aggregate entered against the Borrower which
are not vacated, discharged, paid or stayed pending appeal within a
period of 30 days after entry of such judgment, or vacated,
discharged or paid within
30 days after entry of final order of affirmance on appeal and (ii)
a change in control of the Borrower. For purposes of this section a
change in control shall be deemed to occur if the Guarantor ceases
to own directly or indirectly at least 50% of the Borrower's issued
and outstanding common stock and any other voting stock.
16. NEGATIVE COVENANTS: From the Date of this Agreement and for so long as the
same shall be in effect or any amount shall remain outstanding under any
Note made pursuant to this Agreement, the Borrower agrees that it will
not, directly or indirectly:
16.1 MERGER, ACQUISITION OR SALE OF ASSETS Consolidate or merge into or
transfer its properties and assets substantially as an entirety to
another person, unless (i) the surviving person, if other than the
Borrower, assumes by supplemental agreement satisfactory in form and
substance to the Bank all the obligations under this Agreement; (ii)
after giving effect to such assumption, there would not exist any
Event of Default hereunder; and (iii) the Guaranty remains in full
force and effect.
16.2 NEGATIVE PLEDGES Borrower shall not constitute, permit or allow to
remain in effect, any liens or encumbrances of any type or nature on
its assets, including Active Business Assets, except, (i) mortgages,
deeds of trust, pledges, liens, security interests, assignments,
deposit arrangements or other preferential arrangements, charges or
encumbrances in favor of the Bank, (ii) liens for taxes or
assessments or other governmental charges or levies if not yet due
and payable or, if due and payable, if they are being contested in
good faith by appropriate proceedings and for which appropriate
reserves are maintained; (iii) pledges in favor of the Guarantor;
(iv) undetermined or inchoate liens or charges incidental to the
construction, operation, maintenance or development of oil and gas
reserves off the coast of Trinidad &
Tobago by the Borrower; (v) obligations or duties of the Borrower to
any municipality or Governmental Authority with respect to any
franchise, grant, license, permit or similar arrangement; (vi)
judgment liens, the aggregate of which does not exceed
US$10,000,000, or the aggregate amount of which is greater, if such
greater amount is stayed by appeal, or which has been appealed and
secured, if necessary, by the filing of an appeal bond; (vii) the
pledge of hydrocarbons produced or recovered from any property, an
interest in which is owned or leased by the Borrower; (viii) the
pledge of current assets to secure current liabilities, if in the
ordinary course of business; and (ix) mechanics' and/or
materialmen's liens. Borrower shall not dispose of any of its assets
financed with the proceeds of the Loan, except in the ordinary
course of its trade or business.
16.A 936 INDEMNITY AND HOLD HARMLESS: The Borrower agrees, upon demand,
to indemnify and hold harmless the Bank against and from all taxes
(plus interest assessed thereon), cost, damage, liability, fine,
penalty, claim, cause of action, judgment, court cost and legal or
other expense, including attorneys' fees, relating directly or
indirectly to Section 936 of the Internal Revenue Code, the Federal
CBI Regulations or Regulations 3582 or 5002 by reason of any of the
following:
(a) any act of commission or omission by the Borrower;
(b) any adverse determination made by the United States Internal
Revenue Service, the Commissioner of Financial Institution of Puerto
Rico (the "Commissioner") or any Governmental Authority in the
United States or the Commonwealth as to the qualification of any of
the Advances or any transactions related thereto as an eligible
activity or an investment in Active Business Assets under Section
936 of the Internal Revenue Code, the Federal CBI Regulations or
Regulations 3582 or 5002; or
(c) any failure by the Borrower to permit the Bank to discharge or
fulfill its duties or obligations under the Federal CBI Regulations
or Regulations 3582 or 5002; or
(d) any change to Section 936 of the Internal Revenue Code or the
regulations thereunder or in the interpretation thereof, that
results in any adverse consequence to the Bank due to any Advance
funded with 936 Deposits being outstanding; provided, however, an
indemnity under this clause (d) shall be limited to the excess of
the actual losses over the amount of any other adjustments or
indemnities provided for such losses elsewhere in this Agreement.
17. REPORTING REQUIREMENTS:
(a) Borrower shall provide to the Bank audited financial statements within
120 days after the end of each fiscal year. Such financial statements will
include the Borrower's balance sheet and the related statements of income,
cash flows and retained earnings, with related notes, as of the close of
such fiscal year and for the year then ended, the foregoing financial
statements to be in form consistent with that theretofore released by the
Borrower on an annual basis. The audited financial statements must be
accompanied by the audit report from the Borrower's independent public
accountants;
(b) Concurrently with the financial statements referred above, a
certificate of a director of the Borrower knowledgeable about the
Borrower's financial affairs, certifying that to the best of his knowledge
no Event of Default has occurred and is continuing or, if such an event
has occurred and is continuing, specifying the nature and the extent
thereof.
18. CONDITIONS PRECEDENT:
18.1 CONDITIONS PRECEDENT TO INITIAL ADVANCE The obligation of the Bank
to make its initial Advance hereunder is subject to the conditions
precedent that the Bank shall have received on or before the day of
the initial Advance the following, all in form and substance
satisfactory to the Bank:
(a) the Promissory Note or the Non-Revolving Term Note properly
executed by the Borrower to the order of the Bank:
(b) the Guaranty of Enron Oil & Gas Company;
(c) a certificate of the Secretary or an Assistant Secretary of the
Borrower dated the date of the initial Advance and certifying (A)
that attached thereto is a true and complete copy of the Memorandum
and Articles of Association of the Borrower as in effect on the date
of such certification, (B) that attached thereto is a true and
complete copy of resolutions adopted by the Board of Directors of
the Borrower authorizing the borrowings hereunder, the execution,
delivery and performance in accordance with their respective terms
of this Agreement, the Promissory Note, the Non Revolving Term Note
and any other documents required or contemplated hereunder or
thereunder, and (C) as to the incumbency and specimen signature of
each authorized signature of the Borrower executing this Agreement,
the Promissory Note, the Non-Revolving Term Note or any other
document delivered by it in connection herewith.
(d) a certificate of the Secretary of State of Delaware, dated as of
a recent date as to the good standing of the Guarantor and as to the
charter documents on file in the office of such Secretary of State.
(e) a certificate of the Secretary or an Assistant Secretary of the
Guarantor dated the date of the initial Advance and certifying (A)
that attached thereto is a true and complete copy of the by-laws of
the Guarantor as in effect on the date of such certification, (B)
that attached thereto is a true and complete copy of resolutions
adopted by the Board of Directors of the Guarantor authorizing the
execution, delivery and performance in accordance with its terms of
the Guaranty (C) that the certificate of incorporation of the
Guarantor has not been amended since the date of the last amendment
thereto indicated on the certificate of the Secretary of State
furnished pursuant to clause (d) above and (D) as to the incumbency
and specimen signature of each officer of the Guarantor executing
the Guaranty.
(f) Opinions of Borrower's Trinidad & Tobago counsel and of
Guarantor's general counsel in form and substance satisfactory to
the Bank.
(g) a favorable opinion of Axtmayer Adsuar Muniz & Goyco, counsel
for the Bank, as to the validity and enforceability of this
Agreement, and as to the qualification of the Loan for funding with
936 Deposits under the Federal CBI Regulations and Regulation 3582
and 5002 in form and substance acceptable to the Bank.
18.2 CONDITIONS PRECEDENT TO ALL ADVANCES: The obligation of the
Bank to make each Advance, including the initial Advance is subject
to the following conditions precedent:
(a) The representations and warranties set forth in Section 14
hereof shall be true and correct in all material respects on and as
of the date of each borrowing hereunder with the same effect as if
made on and as of such date.
(b) On the date of each borrowing hereunder, the Borrower shall be
in compliance with all of the terms and provisions set forth herein
to be observed or performed and no Event of Default shall have
occurred and be continuing.
Each borrowing hereunder shall be deemed to be a representation and
warranty by the Borrower on the date of such borrowing as to the
matters specified in paragraph (a) and (b) of this section.
18.3 ADDITIONAL REPRESENTATIONS, WARRANTIES, COVENANTS AND CONDITIONS
PRECEDENT TO 936 ADVANCES:
The obligation of the Bank to make advances funded with 936 Deposits
shall be subject to the conditions set forth in Sections 18.1 and
18.2 and to the following representations, warranties, covenants and
conditions:
(a) All the necessary Governmental Authority approvals as to the
qualification of the Loan under Section 936(d)(4) of the Internal
Revenue Code and the Federal CBI Regulations (as defined
hereinafter) and Regulations 3582 and 5002 issued by the
Commissioner pursuant to the Puerto Rico Industrial Incentive Acts,
including without limitation the Commissioner's
confirmation of its approval given to Citibank, have been obtained.
(b) The Bank shall make the Loan available to the Borrower subject
to the terms and conditions of this Agreement and induced by and
relying on the Borrower's warranty that, for the purpose of
complying with Regulation 5002 and with Section 936(d)(4) of the
United States Internal Revenue Code and Section 1.936-10(c) of the
regulations promulgated thereunder (the "Federal CBI Regulations"),
the Loan shall be used solely for the acquisition of Active Business
Assets. The proceeds of the Loan may also be used for working
capital purposes provided that the amount used for such purposes may
not exceed 10% of the amount invested in Active Business Assets.
(c) On the Date of this Agreement and on each anniversary date of
this Agreement, the Borrower will submit (i) a certification to the
Bank in the form of Exhibit "D" hereto as to Borrower's
qualification as a qualified recipient under Section 1.936-10(c)(9)
of the Federal CBI Regulations and (ii) a 936 representation letter
in the form of Exhibit "E" hereto.
(d) Borrower will use the proceeds of the Loan at all times during
the period that the Loan is outstanding solely for the acquisition
of Active Business Assets or for working capital purposes in full
compliance under the provisions of Section 1.936-10(c)(4) of the
Federal CBI Regulations.
(e) Borrower will be the owner of the Active Business Assets for
United States tax purposes and will not lease back the assets to the
person from whom the assets are acquired.
(f) Borrower agrees to expend the proceeds of the Loan in the
acquisition of Active Business Assets or for working capital
purposes no later than six (6) months from the date the funds are
disbursed by the Bank. During this six-month period the proceeds of
the Loan and proceeds from the investment thereof will be invested
in compliance with the temporary investment requirements set forth
in the Federal CBI Regulations.
(g) Borrower agrees to notify the Assistant Commissioner
(International) of the United States Internal Revenue Service (the
"Assistant Commissioner of the IRS"), the Bank, and the Commissioner
if it no longer is a qualified recipient under Section
1.936-10(c)(9) of the Federal CBI Regulations, or if for any other
reason the investment has ceased to qualify as a qualified
investment under the Federal CBI Regulations or under Regulation
5002, promptly upon the occurrence of such disqualifying event.
(h) Borrower will permit examination by the Office of the Assistant
Commissioner of the IRS (or by the office of any District Director
authorized by the Assistant Commissioner of the IRS) and by the
Commissioner or his delegate, of all necessary books and records
that are sufficient to verify that the funds were used for
investment in Active Business Assets or for working capital purposes
in conformity with the terms of this Agreement.
(i) Borrower will submit annually to the Bank, together with the
certified financial statements required pursuant to Section 17(a)
hereof, an opinion of its independent auditors disclosing the amount
of the Loan and the business activity in which such assets are used
and stating that there is no reason to doubt that the proceeds of
the Loan have been properly used pursuant to Section 1.936-10 of the
Federal CBI Regulations and to Regulation 5002 and continue to be
properly used pursuant to such regulations.
(j) Prior to the first Advance the Bank and the Borrower will submit
to the Assistant Commissioner of the IRS and to the Commissioner a
certificate in the form of Exhibit "F", hereto, pursuant to the
provisions of Section 1.936-10(c)(12) of the Federal CBI
Regulations.
(k) The Bank will comply with the due diligence requirements imposed
upon the Bank by Section 1.936-10(c)(13) of the Federal CBI
Regulations and by Article 6 of Regulation 5002.
19. EVENTS OF DEFAULT: If any of the following events (herein each called an
"Event of Default") shall occur and be continuing:
(a) any material representation or warranty made by (i) the Borrower
under or in connection with this Agreement or in the Notes or any
material statement or representation made in any report, financial
statement, certificate or other document furnished to the Bank under
or in connection with this Agreement, or (ii) the Guarantor under or
in connection with the Guaranty, shall prove to have been false or
misleading in any material respect when made or delivered and such
materiality is continuing;
(b) the Borrower shall fail to make any payment of any principal of
or interest on the Promissory Notes or on the Non-Revolving Term
Note, or of any fees or other amounts payable by the Borrower
hereunder, when and as the same shall become due and payable, and,
in the case of payments other than of any principal amount of the
Promissory Notes or the Non-Revolving Term Note, such default shall
continue unremedied for five days;
(c) default shall be made by the Borrower in the due observance and
performance of any covenant, condition or agreement contained in
Sections 15 or 16 hereof in any material respect;
(d) default shall be made by the Guarantor in the due observance and
performance of any material covenant, condition or agreement of the
Guaranty;
(e) default shall be made by the Borrower in the due observance or
performance of any other covenant, condition or agreement to be
observed or performed pursuant to the terms of this Agreement and
such default shall continue unremedied for 30 days after written
notice thereof shall be given to the Borrower by the Bank;
(f) the Borrower shall generally not pay its debts as such debts
become due, or shall admit in writing its inability to pay its debts
generally, or shall make a general assignment for the benefit of
creditors; or any proceeding shall be instituted by or against the
Borrower seeking to adjudicate it as bankrupt or insolvent, or
seeking liquidation, winding up, reorganization,
arrangement, adjustment, protection, relief, or composition of it or
its debts under applicable bankruptcy, insolvency or similar law or
laws of Trinidad & Tobago, or of any other jurisdiction, or seeking
the entry of an order for relief or the appointment of a receiver,
trustee, or other similar official for it or for any substantial
part of its property and, in the case of any such proceeding
instituted against it (but not instituted by it), shall remain
undismissed or unstayed for a period of 60 days; or a firm, final
and unappealable order, judgment or decree approving or ordering any
of the foregoing shall be entered in any such proceeding or case;
(g) there is a material adverse change in the financial position of
Borrower;
(h) the validity of the Guaranty shall be contested by the Guarantor
or the Guarantor shall deny liability under the Guaranty or any
material provision of the Guaranty shall be deemed invalid or
unenforceable for any reason;
(i) the Guarantor ceases to own, directly or indirectly, a
controlling interest in the Borrower;
then in every such event and at any time thereafter during the
continuance of such event, the Bank may, by notice to the Borrower,
declare the principal of and the interest on the Loan and all other
amounts payable hereunder to be forthwith due and payable, whereupon
all outstanding principal and interest thereon accruing up to the
date of payment and all such other amounts shall become and be
forthwith due and payable, without presentment, demand, protest or
other notice of any kind, all of which are hereby expressly waived,
anything in this Agreement or in the Notes to the contrary
notwithstanding, and the obligations of the Bank to make Advances
hereunder shall thereupon forthwith terminate.
20. PAYMENT NET OF TAXES AND INDEMNIFICATION: Any and all payments by
the Borrower hereunder and under the the Loan Documents shall be made free
and clear of and without deduction for any and all present and future
taxes and withholdings of any type and nature imposed by a Governmental
Authority of Trinidad & Tobago or of any other country in which Borrower
conducts operations. If Borrower is required by law to deduct any such
taxes or withholdings from or in respect to payments under this Agreement
or under the Loan Documents such payments shall be increased as necessary
so that the Bank receives an amount equal to the sum it would have
received had no such deduction been made, and Borrower shall pay such
taxes and withholdings to the relevant taxing authority and provide to the
Bank acceptable evidence of such payment.
In the event that the Bank receives any credit or refund of any such taxes
or withholdings included in any payment made by the Borrower pursuant to
this Section 20, the Bank shall thereupon reimburse the Borrower for the
amount of such credit or refund actually received. A certificate by the
Bank as to the amount of the credit or refund shall constitute conclusive
evidence of the amount thereof, absent manifest error.
Promptly after the close of its fiscal year, the Bank will provide the
Borrower an annual statement certifying whether or not any credit or
refund of any taxes or withholdings has been obtained by the Bank and the
amount thereof, if any.
21. CHANGE IN LAW: If any change in applicable law or regulations or in the
interpretation thereof by a court of justice or any Governmental Authority
charged with the administration thereof shall make it unlawful for the
Bank to continue to maintain all or a portion of the credit facilities
provided herein or for the Borrower to comply with its obligations as
contemplated by this Agreement, the Borrower shall forthwith, upon demand
by the Bank to the Borrower, prepay in full the principal amount of the
illegal portion of the Loan then outstanding together with accrued
interest thereon; provided, that if such unlawfulness is only applicable
with respect to certain type(s) of Advance(s), the
Borrower shall have the option of selecting another funding option which
will not be illegal, instead of prepaying the Loan in full or in part.
22. INCREASED COSTS CAPITAL ADEQUACY, ETC.:
(a) If due to either (1) the introduction of or any change in or in the
interpretation of any law or regulation by any Governmental Authority,
central bank or comparable agency charged with the interpretation or
administration thereof or (2) the compliance with any guideline or request
from any Governmental Authority, central bank or comparable agency
(whether or not having the force of law), there shall be any increase in
the cost to the Bank of agreeing to make or making, funding or maintaining
Advances (other than the increased costs described in clause (c) below),
the Borrower shall from time to time, upon demand by the Bank pay to the
Bank additional amounts sufficient to compensate the Bank for such
increased cost. A certificate in reasonable detail as to the basis for and
the amount of such increased cost, submitted to the Borrower by the Bank,
shall be conclusive and binding for all purposes, absent manifest error.
Promptly after the Bank becomes aware of any such introduction, change or
proposed compliance, the Bank shall notify the Borrower thereof. No Bank
shall be permitted to recover increased costs incurred or accrued more
than 90 days prior to such notice to the Borrower.
(b) If the Borrower so notifies the Bank within five Business Days after
any Bank notifies the Borrower of any increased cost pursuant to the
provisions of Section 22(a), the Borrower shall convert all Advances of
the type affected by such increased cost then outstanding into Advances of
another type in accordance with Sections 8 and 12 and, additionally,
reimburse such Bank for such increased cost in accordance with Section
22(a).
(c) If the Bank shall have determined that, after the date hereof, the
adoption of any applicable law, rule, regulation or treaty regarding
capital adequacy, or any change therein, or any change in the
interpretation or administration thereof by any Governmental Authority,
central bank or comparable agency
charged with the interpretation or administration thereof, or compliance
by the Bank (or its lending office) with any requestor directive regarding
capital adequacy (whether or not having the force of law) of any such
authority, central bank or comparable agency (except to the extent such
request or directive arises as a result of the individual creditworthiness
of such Bank), has or would have the effect of increasing the amount of
capital required or expected to be maintained as a result of its
Commitment hereunder, the Bank shall have the right to give prompt written
notice thereof to the Borrower which notice shall show in reasonable
detail the calculation of such additional amounts as shall be required to
compensate the Bank for the increased cost to the Bank as a result of such
increase in capital and shall certify that such costs are generally being
charged by the Bank to other similarly situated borrowers under similar
credit facilities, which notice shall be conclusive and binding for all
purposes, absent manifest error, although the failure to give any such
notice shall not, unless such notice fails to set forth the information
required above or except as otherwise expressly provided in Section 22(d),
release or diminish any of the Borrower's obligations to pay additional
amounts pursuant to Section 22(d).
(d) The Bank agrees that, upon giving notice specified in Section 22(c),
at the request of the Borrower, it will promptly enter into good faith
negotiations with the Borrower with respect to the method of reimbursement
for the additional costs specified in such notice. No later than 15 days
after the date of the giving of any such notice, and assuming the Bank has
made itself available for the aforesaid good faith negotiations, the
Borrower shall have the option, to be exercised in writing, to (1)
compensate such Bank for the specified additional costs on the basis, if
any, negotiated between the Bank and the Borrower, (2) select a new
funding option for the outstanding Advances, if any, that will not be
subject to the additional costs or (3) terminate the Bank's commitment to
maintain and fund Advances of the type subject to the increased costs set
forth in Section 22(c) to the extent, and on the terms and conditions,
specified in Section 22(e); provided that if the Borrower fails to
exercise the
option to terminate or if all of the funding options are subject to the
additional costs, it shall be deemed to have agreed to reimburse the Bank
from time to time on demand the additional costs specified in the Bank's
notice delivered pursuant to Section 22(c). Notwithstanding the foregoing,
the Borrower shall not be obligated to reimburse the Bank pursuant to this
Section 22(d) or Section 22(e) for any additional costs under Section
22(c) incurred or accruing more than 90 days prior to the date on which
the Bank gave the written notice specified in Section 22(c).
(e) In the event that the Borrower has given notice to the Bank pursuant
to Section 22(d) that it elects to terminate the Bank's commitment to
maintain and fund Advances of the type subject to the increased costs set
forth in section 22(c), such termination shall become effective at the
Borrower's option 15 days thereafter or at the end of the current Funding
Period, unless the Bank withdraws its request for additional compensation.
On the date of the termination, (x) the Borrower shall deliver notice of
the effectiveness of the termination to the Bank, (y) the Borrower shall
pay all amounts owed by the Borrower to the Bank under this Agreement in
connection with the Advances subject to the increased costs set forth in
Section 22(c) (including principal of
and interest on such Advances owed to the Bank, accrued facility fees and
amounts specified in the Bank's notice delivered pursuant to Section 22(c)
with respect to the period prior to such termination). The Borrower may
elect to terminate the Bank's Commitment pursuant to Section 22(d) only if
at such time no Event of Default is then in existence or would be in
existence but for requirement that notice be given or time elapse or both.
(f) The Bank shall use its reasonable efforts (consistent with its
internal policies and legal and regulatory restrictions) to select a
jurisdiction for its lending office or change the jurisdiction of its
lending office , as the case may be, so as to avoid the
imposition of any increased costs under this Section 22 or to eliminate
the amount of any such increased cost which may thereafter accrue;
provided that no such selection or change of the jurisdiction for its
lending office shall be made if, in the reasonable judgment of the Bank,
such selection or change would be disadvantageous to the Bank.
23. COVENANT TO PROVIDE DOCUMENTATION: The Borrower agrees to provide the Bank
with a copy of the Memorandum of Articles of Association certified as of a
recent date by the appropriate officer of Trinidad & Tobago not later than
90 days after the initial Advance hereunder.
24. PLACE AND ADMINISTRATION OF LOAN: The Loan will be made at and
administered by the Bank's Plaza Scotiabank Hato Rey, Puerto Rico branch
to whom all notices in connection with this Agreement and the Loan shall
be given in the manner set out below.
25. LEGAL FEES: The Borrower shall pay the fees of the Bank's legal counsel
related to the execution of the Loan Documents, such legal fees not to
exceed US$25,000.
26. ADDRESS FOR NOTICES TO PARTIES: Unless either party advises the other in
writing to the contrary all notices under this Agreement shall be made to
the parties by mail, personal delivery or facsimile transmission to their
following respective addresses in writing:
26.1 To the Borrower:
Enron Gas & Oil Trinidad Limited
Second Floor, The Mutual Centre
16 Queen's Park West
Port of Spain
Republic of Trinidad & Tobago
British West Indies
ATTN: MANAGING DIRECTOR
Telephone: (809) 622-8653
Telecopier: (809) 628-4218
with copy to:
Enron Gas & Oil Trinidad Limited
PO Box 1188
Houston, Texas 77251-1188
ATTN: WALTER C. WILSON, DIRECTOR
Telephone: (713) 853-5012
Telecopier: (713) 646-8062
26.2 To the Bank:
The Bank of Nova Scotia
273 Ponce de Leon Avenue
Hato Rey, PR 00917
ATTN: MR. ARTURO NUNEZ
with copy to:
The Bank of Nova Scotia
1100 Louisiana, Suite 3000
Houston, Texas
Telephone: (713) 752-0900
Telecopier: (713) 752-2425
27. AMENDMENTS: This Agreement may not be amended or modified except by
a writing, signed by or on behalf of the Bank and the Borrower.
28. ASSIGNMENT; BINDING UPON SUCCESSORS: The Bank shall have the
absolute right to assign this Agreement. This Agreement shall be binding
upon and inure to the benefit of the Bank and the Borrower and their
successors and assigns.
29. SECTION HEADINGS: The section headings contained in this Agreement are
for reference purposes only and shall not affect in any way the meaning or
interpretation of this Agreement.
30. REASONABLE EFFORTS: Subject to the terms and conditions herein provided,
and unless otherwise stated to the contrary the parties hereto agree to
use all reasonable efforts to take, or cause to be taken, all actions and
to do, or cause to be done, all things necessary, proper or advisable
under applicable laws and regulations to consummate and make effective, as
soon as reasonably practicable, the transactions contemplated by this
Agreement.
31. RIGHTS OF THIRD PARTIES: Nothing in this Agreement shall be construed as
giving any person, firm, corporation or other entity, other than the
parties hereto and their respective successors and permitted assigns, any
rights, remedy or claim under or in respect of this Agreement or any
provision hereof.
32. NO WAIVER: No waiver shall be deemed to be made by the Bank of any of its
rights hereunder unless the same shall be in writing and signed on behalf
of the Bank. A waiver, if any, shall be a waiver only with respect to the
specific instance involved and shall in no way impair the rights of the
Bank or the obligations of the Borrower to the Bank in any other respect
at any other time.
33. APPLICABLE LAW: This Agreement shall be governed by, and construed and
interpreted in accordance with the laws of the Commonwealth of Puerto
Rico. The Bank and the Borrower submit themselves irrevocably to the
jurisdiction of the courts of the Commonwealth of Puerto Rico for any
actions or proceedings related to this Agreement.
Please evidence the Borrower's acceptance of this Agreement by causing the
execution of the original and one counterpart of same by an authorized corporate
officer.
Yours very truly,
/s/ Arturo Nunez
ACCEPTED THIS 27th DAY OF May, 1994.
BY: Enron Gas & Oil Trinidad Limited
By: /s/ W. C. Wilson
Its: Director
<PAGE>
EXHIBIT A
PROMISSORY NOTE
US$ Maturity: , 1999
FOR THE VALUE RECEIVED, Enron Gas & Oil Trinidad Limited (the "Borrower"),
a corporation organized under the laws of Trinidad & Tobago, promises to pay to
the order of The Bank of Nova Scotia (the "Bank"), a banking corporation
organized and existing under the laws of Canada, at the principal offices of the
Bank, Plaza Scotiabank Building, 273 Ponce de Leon Avenue, Hato Rey, San Juan,
Puerto Rico, or such other place that the Bank may designate, the principal sum
of US$______________ in lawful currency of the United States of America or, if
less, the aggregate unpaid principal amount of the Advance (as defined in the
Letter Loan Agreement dated May , 1994 between the Borrower and the Bank, such
Letter Loan Agreement as amended from time to time being herein referred to as
the "Loan Agreement") owing to the Bank outstanding on the Maturity Date.
The principal of this obligation will be repaid in one installment due
on , 1999.
Interest will accrue and be payable on the outstanding principal balance of
this obligation from this date on at the following alternative rates:
1. The cost of 30, 60, 90, or 180 day 936 Deposits to the Bank (as
determined by the Bank and adjusted for the cost to the Bank of
municipal license taxes), plus
50 basis points per annum (subject to the availability of 936
Deposits and to the continuing qualification of the Loan for 936
funding) (the "936 Option Rate");
2. 1, 2, 3, or 6 months cost of LIBOR to the Bank plus 50 basis points
per annum (subject to the availability of LIBOR funds) ( the "LIBOR
Option Rate").
3. If both 936 Deposits and LIBOR funds become unavailable or may not
be used, the applicable interest rate will be the Base Rate
fluctuating concurrently with any changes in such Base Rate.
4. Notwithstanding anything to the contrary provided in paragraphs
(1) and (2) above, at any time during the term of the Loan, the
Borrower may request the Bank to fix the rate of interest on all or
any portion of the Loan for a period not to exceed the then
remaining term of the Loan, subject to the availability to the Bank
of 936 Deposits or LIBOR funds with a term at least equal to such
term, at a rate mutually agreeable to the Borrower and the Bank. Any
prepayment by the Borrower of all or any portion of the principal
amount of the Loan with a fixed interest rate shall be subject to
payment by the Borrower of the breakage costs set forth in Section
12 of the Loan Agreement.
5. Notwithstanding anything to the contrary herein provided, the
interest rate applicable to any overdue principal under the Loan
shall be 2% over the Base Rate per annum.
The interest rates set forth herein shall be increased and reduced
concurrently with any increases or reductions in the Guarantor's
senior unsecured long term debt rating by Standard and Poor's
("S&P") or Moody's as follows:
S&P or Moody's Rating LIBOR Plus 936 Plus
- --------------------- ---------- --------
A or A2, or better 37.5 bp 37.5 bp
BBB+ or Baa1, or
better 50 bp 50 bp
BBB and Baa2 55 bp 55 bp
BBB- or Baa3 62.5 bp 62.5 bp
BBB- and Baa3 75 bp 75 bp
BB+ or lower and
Ba1 or lower 112.5 bp 112.5 bp
Upon the first Advance and thereafter three Business Days prior to the
first day of each new Funding Period, the Bank shall notify to the Borrower the
following rates of interest on such Business Day (a) subject to the availability
to the Bank of 936 Deposits and to the eligibility of the Advance to be funded
with 936 Deposits, the 936 Option Rate; and (b) subject to the availability to
the Bank of LIBOR funds for such Funding Period, the LIBOR Option Rate. In the
case of 936 Deposit funding, the Borrower must advise the Bank not later than 12
noon Puerto Rico time on the first Business Day of the ensuing Funding Period,
and in the case of LIBOR funding two (2) Business Days before such Business Day
which of the two funding options it selects for the ensuing Funding Period. The
interest rate applicable to such Funding Period shall be the interest rate
applicable on the first day of the Funding Period to the funding option selected
by the Borrower. If the Borrower fails to make such timely notice of election
then the interest rate beginning on the first day of such Funding Period shall
be computed on the basis of the 30 day 936 Option Rate until a new Funding
Period is established, or, if 936
Deposits are not available, on the basis of 30 day LIBOR Option Rate or, if
LIBOR funds are not available, on the basis of the Base Rate.
The Borrower shall pay interest quarterly in arrears on each Interest
Payment Date, or on a Rollover Date, whichever is earlier, on the actual daily
unpaid principal balance of the Loan and calculated on each such day on the
basis of (i) a 365/366 day calendar year for the actual number of days elapsed
with respect to Base Rate Advances, and (ii) a 360-day calendar year for the
actual number of days elapsed with respect to 936 Option Rate and/or LIBOR
Option Rate Advances.
Up to an amount equal to the Working Capital Amount may be repaid and
reborrowed hereunder prior to the Maturity Date provided that repayments of such
amount shall be allowed only on Rollover Dates.
Upon failure to pay principal, or interest, or the occurrence of any other
event of default as stipulated in the Loan Agreement, the Bank may at its option
declare the full unpaid balance of this obligation to be immediately due and
payable together with any accrued and unpaid interest, and may proceed to
enforce the security under the Loan Agreement and/or interpose judicial
proceedings to collect said sums plus costs, expenses and a reasonable sum for
attorney's fees.
The Borrower hereby waives presentment, protest, demand and notice of
non-payment and submits itself to the jurisdiction of the courts of the
Commonwealth of Puerto Rico for any judicial proceeding hereunder.
The terms "the Borrower" and "the Bank" as used herein include their
respective successors or assigns.
This Promissory Note has been issued under and pursuant to the Loan
Agreement which is supplementary as to any matter pertinent to this Promissory
Note not expressly provided herein. All capitalized terms used herein shall have
the meaning ascribed to such terms in the Loan Agreement.
Dated as of May 31, 1994.
Enron Gas & Oil Trinidad Limited
<PAGE>
EXHIBIT B
NON-REVOLVING TERM NOTE
US$44,000,000 Maturity: , 1999
FOR THE VALUE RECEIVED, Enron Gas & Oil Trinidad Limited (the "Borrower"),
a corporation organized under the laws of Trinidad & Tobago, promises to pay to
the order of The Bank of Nova Scotia (the "Bank"), a banking corporation
organized and existing under the laws of Canada, at the principal offices of the
Bank, Plaza Scotiabank Building, 273 Ponce de Leon Avenue, Hato Rey, San Juan,
Puerto Rico, or such other place that the Bank may designate, the principal sum
of US$44,000,000 in lawful currency of the United States of America or, if less,
the aggregate unpaid principal amount of the Advance (as defined in the Letter
Loan Agreement dated May , 1994 between the Borrower and the Bank, such Letter
Loan Agreement as amended from time to time being herein referred to as the
"Loan Agreement") owing to the Bank outstanding on the Maturity Date.
The principal of this obligation will be repaid in one installment due
on , 1999.
Interest will accrue and be payable on the outstanding principal balance
of this obligation from this date on at the following alternative rates:
1. The cost of 30, 60, 90, or 180 day 936 Deposits to the Bank (as
determined by the Bank and adjusted for the cost to the Bank of
municipal license taxes), plus 50 basis points per annum (subject to
the availability of 936 Deposits and to the continuing qualification
of the Loan for 936 funding) (the "936 Option Rate");
2. 1, 2, 3, or 6 months cost of LIBOR to the Bank plus 50 basis points
per annum (subject to the availability of LIBOR funds) ( the "LIBOR
Option Rate").
3. If both 936 Deposits and LIBOR funds become unavailable or may not
be used, the applicable interest rate will be the Base Rate
fluctuating concurrently with any changes in such Base Rate.
4. Notwithstanding anything to the contrary provided in paragraphs (1)
and (2) above, at any time during the term of the Loan, the Borrower
may request the Bank to fix the rate of interest on all or any
portion of the Loan for a period not to exceed the then remaining
term of the Loan, subject to the availability to the Bank of 936
Deposits or LIBOR funds with a term at least equal to such term, at
a rate mutually agreeable to the Borrower and the Bank. Any
prepayment by the Borrower of all or any portion of the principal
amount of the Loan with a fixed interest rate shall be subject to
payment by the Borrower of the breakage costs set forth in Section
12 of the Loan Agreement.
5. Notwithstanding anything to the contrary herein provided, the
interest rate applicable to any overdue principal under the Loan
shall be 2% over the Base Rate per annum.
The interest rates set forth herein shall be increased and reduced
concurrently with any increases or reductions in the Guarantor's
senior unsecured long term debt rating by Standard and Poor's
("S&P") or Moody's as follows:
S&P or Moody's Rating LIBOR Plus 936 Plus
- --------------------- ---------- --------
A or A2, or better 37.5 bp 37.5 bp
BBB+ or Baa1, or
better 50 bp 50 bp
BBB and Baa2 55 bp 55 bp
BBB- or Baa3 62.5 bp 62.5 bp
BBB- and Baa3 75 bp 75 bp
BB+ or lower and
Ba1 or lower 112.5 bp 112.5 bp
Upon the first Advance and thereafter three Business Days prior to the
first day of each new Funding Period, the Bank shall notify to the Borrower the
following rates of interest on such Business Day (a) subject to the availability
to the Bank of 936 Deposits and to the eligibility of the Advance to be funded
with 936 Deposits, the 936 Option Rate; and (b) subject to the availability to
the Bank of LIBOR funds for such Funding Period, the LIBOR Option Rate. In the
case of 936 Deposit funding, the Borrower must advise the Bank not later than 12
noon Puerto Rico time on the first Business Day of the ensuing Funding Period,
and in the case of LIBOR funding two (2) Business Days before such Business Day
which of the two funding options it selects for the ensuing Funding Period. The
interest rate applicable to such Funding
Period shall be the interest rate applicable on the first day of the Funding
Period to the funding option selected by the Borrower. If the Borrower fails to
make such timely notice of election then the interest rate beginning on the
first day of such Funding Period shall be computed on the basis of the 30 day
936 Option Rate until a new Funding Period is established, or, if 936 Deposits
are not available, on the basis of 30 day LIBOR Option Rate or, if LIBOR funds
are not available, on the basis of the Base Rate.
The Borrower shall pay interest quarterly in arrears on each Interest
Payment Date, or on a Rollover Date, whichever is earlier, on the actual daily
unpaid principal balance of the Loan and calculated on each such day on the
basis of (i) a 365/366 day calendar year for the actual number of days elapsed
with respect to Base Rate Advances, and (ii) a 360-day calendar year for the
actual number of days elapsed with respect to 936 Option Rate and/or LIBOR
Option Rate Advances.
Up to an amount equal to the Working Capital Amount may be repaid and
reborrowed hereunder prior to the Maturity Date provided that repayments of such
amount shall be allowed only on Rollover Dates.
Upon failure to pay principal, or interest, or the occurrence of any other
event of default as stipulated in the Loan Agreement, the Bank may at its option
declare the full unpaid balance of this obligation to be immediately due and
payable together with any accrued and unpaid interest, and may proceed to
enforce the security under the Loan Agreement and/or interpose
judicial proceedings to collect said sums plus costs, expenses and a reasonable
sum for attorney's fees.
The Borrower hereby waives presentment, protest, demand and notice of
non-payment and submits itself to the jurisdiction of the courts of the
Commonwealth of Puerto Rico for any judicial proceeding hereunder.
The terms "the Borrower" and "the Bank" as used herein include their
respective successors or assigns.
This Promissory Note has been issued under and pursuant to the Loan
Agreement which is supplementary as to any matter pertinent to this Promissory
Note not expressly provided herein. All capitalized terms used herein shall have
the meaning ascribed to such terms in the Loan Agreement.
Dated as of May 31, 1994.
Enron Gas & Oil Trinidad Limited
<PAGE>
EXHIBIT C
GUARANTY
THIS GUARANTY (this "Guaranty"), dated as of May 27, 1994, made by Enron
Oil & Gas Company, a Delaware corporation (the "Guarantor"), in favor of The
Bank of Nova Scotia, ("BNS"),
W I T N E S S E T H:
WHEREAS, pursuant to a Letter Loan Agreement, dated as of _______, 1994
(together with all amendments and other modifications, if any, from time to time
thereafter made thereto, the "Letter Loan Agreement"), between Enron Gas & Oil
Trinidad, Limited, a company organized and existing under the laws of Trinidad
and Tobago (the "Borrower") and BNS, BNS has extended a commitment to make loans
(the "Loans") to the Borrower; and
WHEREAS, BNS and the Borrower may now or in the future enter into one or
more interest rate swap, hedge, collar, floor or similar agreements
(collectively, together with all amendments and other modifications, if any,
from time to time thereafter made thereto, and together with any and all
Confirmations ("Confirmations") thereunder, the "Swap Agreement", such interest
rate swaps, hedges, collars, floors or similar agreements with the Borrower
herein collectively the "Swaps"); and
WHEREAS, as a condition precedent to the making of the Loans under the
Letter Loan Agreement and entering into the Swaps pursuant to the Swap
Agreement, the Guarantor is required to execute and deliver this Guaranty;
WHEREAS, the Guarantor has duly authorized the execution, delivery and
performance of this Guaranty;
WHEREAS, it is in the best interests of the Guarantor to execute this
Guaranty inasmuch as the Guarantor will derive substantial direct and indirect
benefits from the Loans made from time to time and the Swaps from time to time
entered into with the Borrower by BNS pursuant to the Letter Loan Agreement or
the Swap Agreement, as the case may be;
NOW, THEREFORE, for good and valuable consideration the receipt of which
is hereby acknowledged, and in order to induce BNS to make the Loans to the
Borrower pursuant to the Letter Loan Agreement and to enter into the Swaps, if
any, pursuant to the Swap Agreement, the Guarantor agrees, for the benefit of
BNS, as follows:
ARTICLE I
DEFINITIONS
SECTION 1.1. Certain Terms. The following terms (whether or not
underscored) when used in this Guaranty, including its preamble and recitals,
shall have the following meanings (such definitions to be equally applicable to
the singular and plural forms thereof):
"Borrower" is defined in the first recital.
"Business Day" means any day of the year except Saturday, Sunday and any
day on which banks are required or authorized to close in Houston, Texas; New
York, New York; San Juan, Puerto Rico; or Trinidad and Togabo.
"Code" means the Internal Revenue Code of 1986, as amended.
"Consolidated" refers to the consolidation of the accounts of the
Guarantor and its Subsidiaries in accordance with GAAP.
"Consolidated Net Worth" means at any date the Consolidated shareholders'
equity of the Guarantor and its Consolidated subsidiaries.
"Credit Agreement" means the Revolving Credit Agreement dated as of March
11, 1994 between the Guarantor as Borrower, the Banks party thereto, and Texas
Commerce Bank National Association, as Administrative Agent.
"Debt" of any Person means, at any date, without duplication, (a)
obligations for the repayment of money borrowed which (1) are evidenced by
bonds, notes, debentures, loan agreements, credit agreements or similar
instruments or agreements and (2) are or should be shown on a balance sheet as
debt in accordance with GAAP, (b) obligations as lessee under leases which, in
accordance with GAAP, are capital leases, and (c) guaranties of payment or
collection of any obligations described in clauses (a) and (b) of other Persons,
provided, that clauses (a) and (b) include, in the case of obligations of the
Borrower or any Subsidiary, only such obligations as are or should be shown as
debt or capital lease liabilities on a Consolidated balance sheet in accordance
with GAAP; provided, further, that none of the following shall constitute Debt:
(A) transfers of accounts receivable pursuant to a receivables purchase facility
considered a sale under GAAP (and indemnification, recourse or repurchase
obligations thereunder as are reasonable given market standards for transactions
of similar type), (B) the liability of any Person as a general partner of a
partnership for Debt of such partnership, if the partnership is not a Subsidiary
of such Person, and (C) obligations (other than borrowings, capital leases or
financial guaranties by the Guarantor
or any Subsidiary) related to the sale, purchase or delivery of hydrocarbons in
respect of volumetric production payments conveyed in transfers constituting
sales of real property interests for which proceeds are accounted for as
deferred revenues under GAAP.
"ERISA" means the Employee Retirement Income Security Act of 1974, as
amended from time to time, and any successor statute of similar import, together
with the regulations thereunder, as in effect from time to time.
"ERISA Affiliate" means any trade or business (whether or not
incorporated) which is a member of a group of which the Guarantor is a member
and which is under common control within the meaning of the regulations under
Section 414 of the Code.
"GAAP" means generally accepted accounting principles consistent with
those applied in the preparation of the audited Consolidated financial
statements referred to in Section 3.1(d).
"Guarantor" is defined in the preamble.
"Guaranty" is defined in the preamble.
"Insufficiency" means, with respect to any Plan, the amount, if any, by
which the present value of the accrued benefits under such Plan exceeds the fair
market value of the assets of such Plan allocable to such benefits.
"Lender" is defined in the preamble.
"Letter Loan Agreement" is defined in the first recital.
"Loan Documents" means the Letter Loan Agreement, the notes thereunder and
the other documents delivered to BNS under the Letter Loan Agreement together
with any Swap Agreement, any Confirmation and any other documents delivered to
BNS thereunder.
"Multiemployer Plan" means a "multiemployer plan" as defined in Section
4001(a)(3) of the ERISA to which the Guarantor or any ERISA Affiliate is making
or accruing an obligation to make contributions, or has within any of the
preceding five plan years made or accrued an obligation to make contributions.
"Multiple Employer Plan" means an employee benefit plan, other than a
Multiemployer Plan, subject to Title IV of ERISA to which the Guarantor or any
ERISA Affiliate, and more than one employer other than the Guarantor or an ERISA
Affiliate, is making or accruing an obligation to make contributions or, in the
event that any such plan has been terminated, to which the Guarantor or any
ERISA Affiliate made or accrued an obligation to make contributions
during any of the five plan years preceding the date of termination of such
plan.
"Note" means a Promissory Note or Non-Revolving Term Note as those terms
are defined in the Letter Loan Agreement.
"Other Taxes" is defined in clause (b) of Section 2.8.
"PBGC" means the Pension Benefit Guaranty Corporation, or any federal
agency or authority of the United States from time to time succeeding to its
function.
"Person" means an individual, partnership, corporation, limited liability
company, business trust, joint stock company, trust, unincorporated association,
joint venture, firm or other entity, or a government or any political
subdivision or agency, department or instrumentality thereof.
"Plan" means an employee benefit plan (other than a Multiemployer Plan)
which is (or, in the event that any such plans has been terminated within five
years after a transaction described in Section 4069 of ERISA, was) maintained
for employees of the Guarantor or any ERISA Affiliate and covered by Title IV or
ERISA.
"Principal Subsidiary" means at any time of determination any Subsidiary
having total assets in excess of $100,000,000. For purposes of this definition,
total assets shall be determined based on the most recent quarterly or annual
financial statements available prior to such determination.
"Rating Level" means the applicable category of rating level which is
based on the rating of the Guarantor's senior unsecured long-term debt as
classified by Moody's and/or Standard & Poor's and which shall be the highest
applicable Rating Level I, Rating Level II, Rating Level III, Rating Level IV,
Rating Level V or Rating Level VI, as the case may be, as set forth in Schedule
I.
"Subsidiary" means any corporation, partnership, joint venture or other
entity of which more than 50% of the outstanding capital stock or other equity
interests having ordinary voting power (irrespective of whether or not at the
time capital stock or other equity interest of any other class or classes of
such corporation, partnership, joint venture or other entity shall or might have
voting power upon the occurrence of any contingency) is at the time directly or
indirectly owned by the Guarantor.
"Swap" is defined in the preamble.
"Swap Agreement" is defined in the preamble.
"Taxes" is defined in clause (a) of Section 2.8.
"Termination Event" means (a) a "reportable event", as such term is
described in Section 4043 of ERISA (other than a "reportable event" not subject
to the provision for 30-day notice to the PBGC), or an event described in
Section 4062(e) of ERISA, or (b) the withdrawal of the Guarantor or any ERISA
Affiliate from a Multiple Employer Plan during a plan year in which it was a
"substantial employer", as such term is defined in Section 4001(a)(2) of ERISA,
or the incurrence of liability by the Guarantor or any ERISA Affiliate under
Section 4064 of ERISA upon the termination of a Multiple Employer Plan, or (c)
the distribution of a notice of intent to terminate a Plan pursuant to Section
4041(a)(2) of ERISA or the treatment of a Plan amendment as a termination under
Section 4041 of ERISA, or (d) the institution of proceedings to terminate a Plan
by the PBGC under Section 4042 of ERISA, or (e) any other event or condition
which might constitute grounds under Section 4042 of ERISA for the termination
of, or the appointment of a trustee to administer, any Plan.
"Total Capitalization" means, at any time, the sum (without duplication)
of (a) Total Debt, and (b) Consolidated Net Worth less any amount thereof
attributable to "minority interests" (as defined below). For the purpose of this
definition, "minority interests" means any investment or interest of the
Guarantor in any corporation, partnership or other entity to the extent that the
total amount thereof owned by the Guarantor (directly or indirectly) constitutes
50% or less of all outstanding interests or investments in such corporation,
partnership or entity.
"Total Debt" means, at any time, all Consolidated Debt of the Guarantor
and its Consolidated Subsidiaries.
"Withdrawal Liability" shall have the meaning given such term under Part I
of Subtitle E of Title IV of ERISA.
SECTION 1.2. Letter Loan Definitions. Unless otherwise defined herein or
the context otherwise requires, terms used in this Guaranty, including its
preamble and recitals, have the meanings provided in the Letter Loan Agreement.
ARTICLE II
GUARANTY PROVISIONS
SECTION 2.1. Guaranty. The Guarantor hereby absolutely, unconditionally
and irrevocably
(a) guarantees the full and punctual payment when due, whether at
stated maturity, by required prepayment, declaration, acceleration, demand
or otherwise, of all indebtedness, obligations and liabilities of the
Borrower to
BNS arising out of, under, or in connection with the Letter Loan Agreement
or any of the other Loan Documents (collectively the "Guaranteed
Obligations") of the Borrower, whether for principal, interest, fees,
expenses or otherwise (including all such amounts which would become due
but for the operation of the automatic stay under Section 362(a) of the
United States Bankruptcy Code, 11 U.S.C. ss.362(a)), and the operation of
Sections 502(b) and 506(b) of the United States Bankruptcy Code, 11 U.S.C.
ss.502(b) and ss.506(b), and
(b) indemnifies and holds harmless BNS and each holder of a Note for
any and all costs and expenses (including reasonable attorney's fees and
expenses) incurred by BNS or such holder, as the case may be, in enforcing
any of its rights under this Guaranty.
This Guaranty constitutes a guaranty of payment when due and not of collection,
and the Guarantor specifically agrees that it shall not be necessary or required
that BNS or any holder of any Note exercise any right, assert any claim or
demand or enforce any remedy whatsoever against the Borrower (or any other
Person) before or as a condition to the obligations of the Guarantor hereunder.
SECTION 2.2. Acceleration of Guaranty. The Guarantor agrees that, in the
event of the occurrence and continuation of an Event of Default under Section
5.1 and if such Event of Default shall occur at a time when any of the
Guaranteed Obligations may not then be due and payable, then, immediately and
without further action by BNS, in the event of an Event of Default of the type
referred to in Section 5.1(e) or upon demand by BNS in the event of an Event of
Default (other than an Event of Default of the type referred to in Section
5.1(e)) the Guarantor will pay to BNS forthwith the full amount which would be
payable hereunder by the Guarantor if all such Guaranteed Obligations were then
due and payable.
SECTION 2.3. Guaranty Absolute, etc. This Guaranty shall in all respects
be a continuing, absolute, unconditional and irrevocable guaranty of payment,
and shall remain in full force and effect until all Guaranteed Obligations have
been paid in full, all obligations of the Guarantor hereunder shall have been
paid in full and all Commitments shall have terminated. The Guarantor guarantees
that the Guaranteed Obligations will be paid strictly in accordance with the
terms of the Letter Loan Agreement or the Swap Agreement, as the case may be,
and each other Loan Document under which they arise, regardless of any law,
regulation or order now or hereafter in effect in any jurisdiction affecting any
of such terms or the rights of BNS or any holder of any Note with respect
thereto. The liability of the Guarantor under this Guaranty shall be absolute,
unconditional and irrevocable irrespective of:
(a) any lack of validity, legality or enforceability of the Letter
Loan Agreement, any Note, any other Loan Document, the Swap Agreement or
any Confirmation;
(b) the failure of BNS or any holder of any Note (i) to assert any
claim or demand or to enforce any right or remedy against the Borrower or
any other Person (including any other guarantor) under the provisions of
the Letter Loan Agreement, any Note, any other Loan Document, the Swap
Agreement or any Confirmation or otherwise, or (ii) to exercise any right
or remedy against any other guarantor of, or collateral (if any) securing,
any Guaranteed Obligations;
(c) any change in the time, manner or place of payment of, or in any
other term of, all or any of the Guaranteed Obligations, or any other
extension, compromise or renewal of any Guaranteed Obligation;
(d) any reduction, limitation, impairment or termination of the
Guaranteed Obligations for any reason, including any claim of waiver,
release, surrender, alteration or compromise, and shall not be subject to
(and the Guarantor hereby waives any right to or claim of) any defense or
setoff, counterclaim, recoupment or termination whatsoever by reason of
the invalidity, illegality, nongenuineness, irregularity, compromise,
unenforceability of, or any other event or occurrence affecting, the
Guaranteed Obligations or otherwise;
(e) any amendment to, rescission, waiver, or other modification of,
or any consent to departure from, any of the terms of the Letter Loan
Agreement, any Note or any other Loan Document or the Swap Agreement or
any Confirmation, as the case may be;
(f) any addition, exchange, release, surrender or nonperfection of
any collateral (if any), or any amendment to or waiver or release or
addition of, or consent to departure from, any other guaranty, held by BNS
or any holder of any Note securing any of the Guaranteed Obligations; or
(g) any other circumstance which might otherwise constitute a
defense available to, or a legal or equitable discharge of, the Borrower,
any surety or any other guarantor.
SECTION 2.4. Reinstatement, etc. The Guarantor agrees that this Guaranty
shall continue to be effective or be reinstated, as the case may be, if at any
time any payment (in whole or in part) of any of the Guaranteed Obligations is
rescinded or must otherwise be restored by BNS or any holder of any Note, upon
the insolvency, bankruptcy or reorganization of the Borrower or otherwise, as
though such payment had not been made.
SECTION 2.5. Waiver, etc. The Guarantor hereby waives promptness,
diligence, notice of acceptance and any other notice with respect to any of the
Guaranteed Obligations and this Guaranty and any requirement that BNS or any
holder of any Note protect, secure, perfect or insure any security interest or
lien, or any property subject thereto, or exhaust any right or take any action
against the Borrower or any other Person (including any other guarantor) or
entity or any collateral (if any) securing the Guaranteed Obligations.
SECTION 2.6. Subrogation, etc. The Guarantor will not exercise any rights
which it may acquire by way of subrogation under this Guaranty, by any payment
made hereunder or otherwise, until the prior payment, in full and in cash, of
all Guaranteed Obligations. Any amount paid to the Guarantor on account of any
such subrogation rights prior to the payment in full of all Guaranteed
Obligations shall be held in trust for the benefit of BNS and each holder of a
Note and shall immediately be paid to BNS and each holder of a Note and credited
and applied against the Guaranteed Obligations whether matured or unmatured, in
accordance with the terms of the Letter Loan Agreement or the Swap Agreement, as
the case may be. In furtherance of the foregoing, for so long as any Guaranteed
Obligations or Commitments remain outstanding, the Guarantor shall refrain from
taking any action or commencing any proceeding against the Borrower (or its
successors or assigns, whether in connection with a bankruptcy proceeding or
otherwise) to recover any amounts in the respect of payments made under this
Guaranty to BNS or any holder of a Note.
SECTION 2.7. Successors, Transferees and Assigns; Transfers of Notes, etc.
This Guaranty shall: (a) be binding upon the Guarantor, and its successors,
transferees and assigns; and (b) inure to the benefit of and be enforceable by
BNS, each holder of a Note and each of their respective successors, transferees
and assigns. Without limiting the generality of clause (b), BNS may assign or
otherwise transfer (in whole or in part) any Note or Loan or Swap held by it to
any other Person or entity, and such other Person or entity shall thereupon
become vested with all rights and benefits in respect thereof granted to BNS
under any Loan Document (including this Guaranty) or otherwise.
SECTION 2.8. Payments Free and Clear of Taxes, etc. The Guarantor hereby
agrees that:
(a) Any and all payments made by the Guarantor hereunder shall be
made in accordance with Section 20 of the Letter Loan Agreement or the
relevant section or sections of the Swap Agreement and any Confirmations
thereunder free and clear of, and without deduction for, any and all
present or future taxes, levies, imposts, deductions, charges or
withholdings, and all liabilities with respect thereto, excluding, in the
case of BNS and each holder of a Note, (i) taxes imposed on its income,
(ii) franchise taxes imposed on it by the jurisdiction under the laws of
which BNS or such holder, as the case may be, is organized and by any
political subdivision thereof and, in the case of BNS, taxes imposed on
its income, and franchise taxes imposed on it, by the jurisdiction of
BNS's Puerto Rico office and any political subdivision thereof and (iii)
any taxes imposed by the United States of America by means of withholding
at the source if an to the extent that such taxes shall be in effect and
shall be applicable, to payments to be made to BNS (all such taxes,
levies, imposts, deductions, charges, withholdings and liabilities other
than those referred to in the foregoing clauses (i), (ii) and (iii) being
hereinafter referred to as "Taxes"). If the Guarantor shall be required by
law to deduct any Taxes from or in respect of any sum payable hereunder to
BNS or any holder of a Note (i) the sum payable shall be increased as may
be necessary so that after making all required deductions (including
deductions applicable to additional sums payable under this Section) BNS
or such holder, as the case may be, receives an amount equal to the sum it
would have received had no such deductions been made, (ii) the Guarantor
shall make such deductions, and (iii) the Guarantor shall pay the full
amount deducted to the relevant taxation authority or other authority in
accordance with applicable law.
(b) The Guarantor shall pay any present or future stamp or
documentary taxes or any other excise or property taxes, charges or
similar levies which arise from any payment made hereunder or from the
execution, delivery or registration of, or otherwise with respect to, this
Guaranty (hereinafter referred to as "Other Taxes").
(c) The Guarantor hereby indemnifies and holds harmless BNS and each
holder of a Note for the full amount of Taxes or Other Taxes (including,
without limitation, any Taxes or Other Taxes imposed by any jurisdiction
on amounts payable under this Section) paid by BNS or such holder, as the
case may be, and any liability (including penalties, interest and
expenses) arising therefrom or with respect thereto, whether or not such
Taxes or Other Taxes were
correctly or legally assessed (expressly including such amounts paid as a
result of the ordinary, sole or contributory negligence of BNS or such
holder of a Note, but excluding such amounts paid as a result of the gross
negligence or willful misconduct of BNS or such holder of a Note). This
indemnification shall be made within thirty (30) days from the date BNS or
such holder of a Note, as the case may be, makes written demand therefor.
BNS or the holder of a Note shall not be indemnified for Taxes or Other
Taxes incurred or accrued unless within 90 days of the date
that BNS or such holder of a Note knew or should have known thereof, it
notifies the Guarantor thereof.
(d) Within 30 days after the date of any payment of Taxes or Other
Taxes, the Guarantor will furnish to BNS the original or a certified copy
of a receipt evidencing payment thereof. Should BNS or the holder of a
Note ever receive any refund, credit or deduction from any taxing
authority to which BNS or such holder of a Note would not be entitled but
for the payment by the Guarantor of Taxes or Other Taxes as required by
this Section 2.8 (it being understood that the decision as to whether or
not to claim, and if claimed, as to the amount of any such refund, credit
or deduction shall be made by BNS or such holder of a Note in its sole
discretion), BNS or such holder of a Note, as the case may be, thereupon
shall repay to the Guarantor an amount with respect to such refund, credit
or deduction equal to any net reduction in Taxes or Other Taxes actually
obtained by BNS or such holder of a Note, as the case may be, and
determined by BNS or such holder of a Note, as the case may be, to be
attributable to such refund, credit or deduction.
(e) Without prejudice to the survival of any other agreement of the
Guarantor hereunder (but subject to the expiration of any applicable
statute of limitations), the agreements and obligations of the Guarantor
contained in this Section 2.8 shall survive the payment in full of the
principal of and interest on the Loans.
SECTION 2.9. Judgment. The Guarantor hereby agrees that:
(a) If, for the purposes of obtaining a judgment in any court, it is
necessary to convert a sum due hereunder from one currency into another
currency, the rate of exchange used shall be the best available rate at
which in accordance with normal banking procedures BNS could purchase such
currency with such other currency on the Business Day preceding that on
which final judgment is given.
(b) The obligation of the Guarantor in respect of any sum due from
it to BNS or any holder of a Note hereunder shall, notwithstanding any
judgment in a currency, be discharged only to the extent that on the
Business Day following receipt by BNS or such holder, as the case may be,
of any sum adjudged to be so due in such other currency BNS or such
holder, as the case may be, may, in accordance with normal banking
procedures using the best available exchange rate, purchase the relevant
currency with such other currency; in the event that the currency so
purchased is less than the sum originally due to BNS
or such holder in such currency, the Guarantor, as a separate obligation
and notwithstanding any
such judgment, hereby indemnifies and holds harmless BNS and such holder
against such loss, and if the such currency, so purchased exceeds the sum
originally due to BNS or such holder in the relevant currency, BNS or such
holder, as the case may be, shall remit to the Guarantor such excess.
ARTICLE III
REPRESENTATIONS AND WARRANTIES
SECTION 3.1. Representations and Warranties. The Guarantor hereby
represents and warrants unto BNS as follows:
(a) The Guarantor and each Principal Subsidiary are corporations
duly incorporated, validly existing and in good standing under the laws of
their respective jurisdictions of incorporation. The Guarantor and each
Principal Subsidiary have all corporate powers and all material
governmental licenses, authorizations, consents and approvals required in
each case to carry on its business as now conducted except where failure
to have such would not, in the aggregate, have a material adverse effect
on the Guarantor or on the ability of the Guarantor to perform its
obligations under this Guaranty.
(b) The execution, delivery and performance by the Guarantor of this
Guaranty is within the Guarantor's corporate powers, have been duly
authorized by all necessary corporate action of the Guarantor, require, in
respect of the Guarantor, no action by or in respect of, or filing with,
any governmental body, agency or official and do not contravene, or
constitute a default under, any provision of law or regulation applicable
to the Guarantor or the restated certificate of incorporation or by-laws
of the Guarantor or any judgment, injunction, order, decree or material
("material" for the purposes of this representation meaning creating a
liability of $50,000,000 or more) agreement binding upon the Guarantor or
result in the creation or imposition of any lien, security interest or
other charge or encumbrance on any asset of the Guarantor or any of its
Subsidiaries.
(c) This Guaranty is the legal, valid and binding obligation of the
Guarantor enforceable against the Guarantor in accordance with its terms,
except as the enforceability thereof may be limited by the effect of any
applicable bankruptcy, insolvency, reorganization, moratorium or similar
laws affecting creditors' rights generally and by general principles of
equity.
(d) The audited Consolidated balance sheet of the Guarantor as of
December 31, 1993 and the related audited Consolidated statements of
income, cash flows and changes in shareholders' equity accounts for the
fiscal year then ended and the unaudited Consolidated balance sheet of the
Guarantor as of March 31, 1994, and the related unaudited Consolidated
statements of income and cash flows for the fiscal quarter then ended,
certified by the chief financial or accounting officer of the Guarantor,
copies of which have been delivered to BNS, fairly present, in conformity
with GAAP except as otherwise expressly noted therein, the Consolidated
financial position of the Guarantor as of such dates and its Consolidated
results of operations and as applicable changes in financial position for
such fiscal periods, subject (in the case of the unaudited balance sheet
and statements) to changes resulting from audit and normal year-end
adjustments.
(e) Since December 31, 1993 there has been no material adverse
change in the Consolidated financial position or Consolidated results of
operations of the Guarantor and its Subsidiaries, considered as a whole.
(f) Except as disclosed in the Guarantor's Form 10-K for the year
ended December 31, 1993 or the Guarantor's Form 10-Q for the quarter ended
March 31, 1994, which were delivered to BNS prior to the date hereof,
there is no action, suit or proceeding pending against the Guarantor or
any of its Subsidiaries, or to the knowledge of the Guarantor threatened
against the Guarantor or any of its Subsidiaries, before any court or
arbitrator or any governmental body, agency or official in which there is
a reasonable possibility of an adverse decision which could materially
adversely affect the Consolidated financial position or Consolidated
results of operations of the Guarantor and its Subsidiaries taken as a
whole or which in any manner draws into question the validity of this
Agreement.
(g) No Termination Event has occurred or is reasonably expected to
occur with respect to any Plan for which an Insufficiency in excess of
$50,000,000 exists. Neither the Guarantor nor any ERISA Affiliate has
received any notification (or has knowledge of any reason to expect) that
any Multiemployer Plan is in reorganization or has been terminated, within
the meaning of Title IV of ERISA, for which a Withdrawal Liability in
excess of $50,000,000 exists.
(h) United States federal income tax returns of the Guarantor and
its Subsidiaries have been examined and closed through the fiscal year
ended December 31, 1987. The Guarantor and its Subsidiaries have filed or
caused to be filed all United Sates federal income tax returns and all
other material domestic tax returns which to the knowledge of the
Guarantor are required to be filed by them and have paid or provided for
the payment, before the same become delinquent, of all taxes due pursuant
to such returns or pursuant to any assessment received by the Guarantor or
any Subsidiary, other than those taxes contested in good faith by
appropriate proceedings. The charges, accruals and reserves on the
books of the Guarantor and its Subsidiaries in respect of taxes are, in
the opinion of the Guarantor, adequate to the extent required by GAAP.
(i) Neither the Guarantor nor any Subsidiary is an "investment
company" within the meaning of the Investment Company Act of 1940, as
amended.
(j) The Guarantor is not a "holding company", a "subsidiary company"
of a "holding company", an "affiliate" of a "holding company", or an
"affiliate" of a "subsidiary company" of a "holding company", in each case
as such terms are defined in the Public Utility Holding Company Act of
1935, as amended.
ARTICLE IV
COVENANTS, ETC.
SECTION 4.1. Affirmative Covenants. The Guarantor covenants and agrees
that so long as any portion of the Guaranteed Obligations shall remain unpaid or
BNS shall have any outstanding Commitment, the Guarantor will, unless BNS shall
otherwise consent in writing, perform the following obligations:
(a) Reporting Requirements. Furnish to BNS:
(1) (A) promptly after the sending or filing thereof, a copy
of each of the Guarantor's reports on Form 8-K (or any comparable
form), (B) promptly after the filing or sending thereof, and in any
event within 75 days after the end of each of the first three fiscal
quarters of each fiscal year of the Guarantor, a copy of the
Guarantor's report on Form 10-Q (or any comparable form) for such
quarter, which report will include the Guarantor's quarterly
unaudited Consolidated financial statements as of the end of and for
such quarter, and (C) promptly after the filing or sending thereof,
and in any event within 135 days after the end of each fiscal year
of the Guarantor, a copy of the Guarantor's annual report which it
sends to its public security holders, and a copy of the Guarantor's
annual report on Form 10-K (or any comparable form) for such year,
which annual report on Form 10-K will include the Guarantor's annual
audited Consolidated financial statements as of the end of and for
such year;
(2) simultaneously with the delivery of each of the annual or
quarterly reports referred to in clause (1) above, a certificate of
the chief financial officer or the chief accounting officer of the
Guarantor in a form acceptable to BNS (x) setting forth in
reasonable detail the calculations required to establish whether the
Guarantor was in compliance with the requirements of Section 4.2(b)
on the date of the
financial statements contained in such report, and (y) stating
whether there exists on the date of such certificate any Event of
Default or event which, with the giving of notice or lapse of time,
or both, would constitute an Event of Default, and, if so, setting
forth the details thereof and the action which the Guarantor has
taken and proposes to take with respect thereto;
(3) as soon as is possible and in any event within five days
after a change in, or issuance of, any rating of any of the
Guarantor's senior unsecured long-term debt by Standard & Poor's or
Moody's which causes a change in the applicable Rating Level, notify
BNS of such change;
(4) as soon as possible and in any event within five days
after an executive officer of the Guarantor having obtained
knowledge thereof, notice of the occurrence of any Event of Default
or any event which, with the giving of notice or lapse of time, or
both, would constitute an Event of Default, continuing on the date
of such notice, and a statement of the chief financial officer of
the Guarantor setting forth details of such Event of Default or
event and the action, if any, which the Guarantor has taken and
proposes to take with respect thereto;
(5) as soon as possible and in any event(A) within 30 Business
Days after the Guarantor or any ERISA Affiliate knows or has reason
to know that any Termination Event described in clause (a) of the
definition of Termination Event with respect to any Plan for which
an Insufficiency in excess of $50,000,000 exists, has occurred and
(B) within 10 Business Days after the Guarantor or any ERISA
Affiliate knows or has reason to know that any other Termination
Event with respect to any Plan for which an Insufficiency in excess
of $50,000,000 exists, has occurred or is reasonably expected to
occur, a statement of the chief financial officer or chief
accounting officer of the Guarantor describing such Termination
Event and the action, if any, which the Guarantor or such ERISA
Affiliate proposes to take with respect thereto;
(6) promptly and in any event within five Business Days after
receipt thereof by the Guarantor or any ERISA Affiliate, copies of
each notice received by the Guarantor or any ERISA Affiliate from
the PBGC stating its intention to terminate any Plan for which an
Insufficiency in excess of $50,000,000 exists or to have a trustee
appointed to administer any Plan for which an Insufficiency in
excess of $50,000,000 exists;
(7) promptly and in any event within five Business Days after
receipt thereof by the Guarantor or any ERISA Affiliate from the
sponsor of a Multiemployer Plan, a copy of each
notice received by the Guarantor or any ERISA Affiliate indicating
liability in excess of $50,000,000 incurred or expected to be
incurred by the Guarantor or any ERISA Affiliate in connection with
(A) the imposition of a Withdrawal Liability by a Multiemployer
Plan, (B) the determination that a Multiemployer Plan is, or is
expected to be, in reorganization within the meaning of Title IV of
ERISA, or (C) the termination of a Multiemployer Plan within the
meaning of Title IV of ERISA; and
(8) such other information respecting the Consolidated
financial position or Consolidated results of operations of the
Guarantor that BNS may from time to time reasonably request.
(b) Compliance with Laws, Etc. Comply, and cause each of its
Subsidiaries to comply, with all applicable laws, rules, regulations and
orders to the extent noncompliance therewith would have a material adverse
effect on the Guarantor and its Subsidiaries taken as a whole, such
compliance to include, without limitation, the paying before the same
shall become due of all taxes, assessments and governmental charges
imposed upon it or upon its property except to the extent contested in
good faith by appropriate proceedings.
(c) Maintenance of Insurance. Maintain, and cause each of its
Principal Subsidiaries to maintain, insurance with responsible and
reputable insurance companies or associations in such amounts and covering
such risks as is usually carried by companies engaged in similar
businesses and owning similar properties as the Guarantor or such
Principal Subsidiary, provided, that self-insurance by the Guarantor or
any such Principal Subsidiary shall not be deemed a violation of this
covenant to the extent that companies engaged in similar businesses and
owning similar properties as the Guarantor or such Principal Subsidiary
self-insure. The Guarantor may maintain the Principal Subsidiaries'
insurance on behalf of them.
(d) Preservation of Corporate Existence, Etc. Preserve and maintain,
and cause each of its Principal Subsidiaries to preserve and maintain, its
corporate existence, rights (charter and statutory), and franchises;
provided, however, that this Section 4.1(d) shall not apply to any
transactions permitted by Section 4.2(c) or (d) and shall not prevent the
termination of existence, rights and franchises of any Principal
Subsidiary pursuant to any merger or consolidation to which such Principal
Subsidiary is a party, and provided, further, that the Guarantor or any
Principal Subsidiary shall not be required to preserve any right or
franchise if the Guarantor or such Principal Subsidiary shall determine
that the preservation thereof is no longer desirable in the conduct of the
business of the Guarantor or such Principal Subsidiary, as the
case may be, and that the loss thereof is not disadvantageous in any
material respect to BNS.
(e) Visitation Rights. At any reasonable time and from time to time,
after reasonable written notice, permit BNS or any agents or
representatives thereof to examine the records and books of account of,
and visit the properties of, the Guarantor and any of the Principal
Subsidiaries and to discuss the affairs, finances and accounts of the
Guarantor and any of the Principal Subsidiaries with any of the officers
of the Guarantor.
SECTION 4.2. Negative Covenants. The Guarantor covenants and agrees that,
so long as any portion of the Guaranteed Obligations shall remain unpaid or BNS
shall have any outstanding Commitment, the Guarantor will not, without the prior
written consent of BNS, do anything prohibited below:
(a) Negative Pledge. Fail to perform or observe any term, covenant,
or agreement contained in Section 5.01 or 5.02 of the Credit Agreement.
The terms, covenants, or agreements in Section 5.01 and 5.02 shall have
the same force and effect as if fully recited herein, shall be deemed to
have been made in favor of BNS, shall survive the termination or
expiration of the Credit Agreement (or the Guarantor's obligations
thereunder) and, notwithstanding any such termination or expiration of the
Credit Agreement (or the Guarantor's obligations thereunder), shall
continue to inure to the benefit of BNS. Any amendment or modification to
any of the terms, covenants, or agreements contained in Sections 5.01 and
5.02 of the Credit Agreement shall not be operative and shall have no
force and effect with respect to the Guarantor and BNS pursuant to this
Guaranty and such terms, covenants, and agreements contained in Sections
5.01 and 5.02 shall be deemed to remain as written without regard to any
such amendment or modification.
(b) Total Debt to Capitalization. Have a ratio of (i) Total Debt to
(ii) Total Capitalization greater than 50%.
(c) Disposition of Assets. Lease, sell, transfer or otherwise
dispose of, voluntarily or involuntarily, all or substantially all of its
assets.
(d) Mergers, Etc. Merge or consolidate with or into, any Person,
unless (1) the Guarantor is the survivor or (2) the surviving Person, if
not the Guarantor, is organized under the laws of the United States or a
state thereof and assumes all obligations of the Guarantor under this
Guaranty, provided, in each case that both immediately before and after
giving effect to such proposed transaction, no Event of Default or event
which, with the giving of notice or the lapse of time, or both, would
constitute an Event of Default exists, or would exist or result.
(e) Compliance with ERISA. (1) Terminate, or permit any ERISA
Affiliate to terminate, any Plan so as to result in any liability in
excess of $50,000,000 of the Guarantor or any ERISA Affiliate to the PBGC,
or (2) permit circumstances which give rise to a Termination Event
described in clauses (b), (d) or (e) of the definition of Termination
Event with respect to a Plan so as to result in any liability in excess of
$50,000,000 of the Guarantor or any ERISA Affiliate to the PBGC.
ARTICLE V
EVENTS OF DEFAULT
SECTION 5.1. Events of Default. Each of the following events which shall
occur and be continuing shall constitute Events of Default:
(a) The Guarantor shall fail to pay any amount hereunder when due
and payable; or
(b) Any representation or warranty made by the Guarantor (or any of
its officers) under or in connection with this Guaranty shall prove to
have been incorrect in any material respect when made or deemed made and
such materiality is continuing; or
(c) The Guarantor shall fail to perform or observe any term,
covenant or agreement contained in Section 4.2 or shall fail to perform or
observe any other term, covenant or agreement contained herein on its part
to be performed or observed if, in the case of such other term, covenant
or agreement, such failure shall remained unremedied for 30 days after
written notice thereof shall have been given to the Guarantor by BNS; or
(d) The Guarantor or any Principal Subsidiary shall (1) fail to pay
any principal of or premium or interest on any Debt (other than Debt
described in clause (c) of the definition of Debt) which is outstanding in
the principal amount of at least $50,000,000 in the aggregate, of the
Guarantor or such Principal Subsidiary (as the case may be), when the same
becomes due and payable (whether by scheduled maturity, required
prepayment, acceleration, demand or otherwise), and such failure shall
continue after the applicable grace period, if any, specified in the
agreement or instrument relating to such Debt; or any other event shall
occur or condition shall exist under any agreement or instrument relating
to any such Debt and shall continue after the applicable grace period, if
any, specified in such agreement or instrument, if the effect of such
event or condition is to accelerate the maturity of such Debt; or any
such Debt shall be declared to be due and payable, or required to be
prepaid (other than by a regularly scheduled required prepayment or as a
result of the giving of notice of a voluntary prepayment), prior to the
stated maturity thereof, or (2) with respect to Debt described in clause
(c) of the definition of Debt, fail to pay any such Debt which is
outstanding in the principal amount of at least $50,000,000 in the
aggregate, of the Guarantor or such Principal Subsidiary (as the case may
be), when the same becomes due and payable, and such failure shall
continue after the applicable grace period, if any, specified in the
agreement or instrument relating to such Debt, or
(e) The Guarantor or any Principal Subsidiary shall generally not
pay its debts as such debts become due, or shall admit in writing its
inability to pay its debts generally, or shall make a general assignment
for the benefit of creditors; or any proceeding shall be instituted by or
against the Guarantor or any Principal Subsidiary seeking to adjudicate it
as bankrupt or insolvent, or seeking liquidation, winding up,
reorganization, arrangement, adjustment, protection, relief or composition
of it or its debts under any law relating to bankruptcy, insolvency or
reorganization or relief of debtors, or seeking the entry of an order for
relief or the appointment of a receiver, trustee or other similar official
for it or for any substantial part of its property and, in the case of any
such proceeding instituted against it (but not instituted by it), shall
remain undismissed or unstayed for a period of 60 days; or the Guarantor
or any Principal Subsidiary shall take any corporate action to authorize
any of the actions set forth above in this subsection (e); or
(f) Any judgment, decree or order for the payment of money in excess
of $50,000,000 shall be rendered against the Guarantor or any Principal
Subsidiary and shall remain unsatisfied and either (1) enforcement
proceedings shall have been commenced by any creditor upon such judgment,
decreed or order or (2) there shall be any period longer than (i) 30
consecutive days or (ii) such longer period as allowed by applicable law
during which a stay of enforcement of such judgment, decree or order, by
reason of a pending appeal or otherwise, shall not be in effect; or
(g) Any Termination Event as defined in clause (b), (d) or (e) of
the definition thereof with respect to a Plan shall have occurred and, 30
days after notice thereof shall have been given to the Guarantor by BNS,
(1) such Termination Event shall continue to exist and (2) the sum
(determined as of the date of occurrence of such Termination Event) of the
liabilities to the PBGC resulting from all such Termination Events is
equal to or greater than $100,000,000; or
(h) The Guarantor or any ERISA Affiliate shall have been notified by
the sponsor of a Multiemployer Plan that it has incurred Withdrawal
Liability to such Multiemployer Plan in an amount which, when aggregated
with all other amounts required to be paid to the Multiemployer Plan in
connection with Withdrawal Liabilities (determined as of the date of such
notification), exceeds $100,000,000 or requires payments exceeding
$50,000,000 in any year; or
(i) The Guarantor or any ERISA Affiliate shall have been notified by
the sponsor of a Multiemployer Plan that such Multiemployer Plan is in
reorganization or is being terminated, within the meaning of Title IV of
ERISA, if as a result of such reorganization or termination the aggregate
annual contributions of the Guarantor and its ERISA Affiliates to all
Multiemployer Plans which are then in reorganization or being terminated
have been or will be increased over the amounts contributed to such
Multiemployer Plans for the respective plan years which include the date
hereof by an amount exceeding $50,000,000 in the aggregate.
ARTICLE VI
MISCELLANEOUS PROVISIONS
SECTION 6.1. Binding on Successors, Transferees and Assigns; Assignment of
Guaranty. In addition to, and not in limitation of, Section 2.7, this Guaranty
shall be binding upon the Guarantor and its successors, transferees and assigns
and shall inure to the benefit of and be enforceable by BNS and each holder of a
Note and their respective successors and assigns (to the full extent provided
pursuant to Section 2.7); provided, however, that the Guarantor may not assign
any of its obligations hereunder without the prior written consent of BNS and
each holder of a Note.
SECTION 6.2. Amendments, etc. No amendment to or waiver of any provision
of this Guaranty, nor consent to any departure by the Guarantor herefrom, shall
in any event be effective unless the same shall be in writing and signed by BNS
and the Guarantor, and then such waiver or consent shall be effective only in
the specific instance and for the specific purpose for which given.
SECTION 6.3. Addresses for Notices to the Guarantor. All notices and other
communications hereunder to the Guarantor shall be in writing and mailed or
delivered to it, addressed to it at the address set forth below its signature
hereto or at such other address as shall be designated by the Guarantor in a
written notice to BNS at
The Bank of Nova Scotia
273 Ponce de Leon Avenue
Hato Rey, Puerto Rico 00917
or such other address specified in a notice complying as to delivery with the
terms of this Section. All such notices and other communications shall, when
mailed, be effective when deposited in the mails, addressed as aforesaid.
SECTION 6.4. No Waiver; Remedies. In addition to, and not in limitation
of, Section 2.3 and Section 2.5, no failure on the part of BNS or any holder of
a Note to exercise, and no delay in exercising, any right hereunder shall
operate as a waiver thereof; nor shall any single or partial exercise of any
right hereunder preclude any other or further exercise thereof or the exercise
of any other right. The remedies herein provided are cumulative and not
exclusive of any remedies provided by law.
SECTION 6.5. Section Captions. Section captions used in this Guaranty are
for convenience of reference only, and shall not affect the construction of this
Guaranty.
SECTION 6.6. Severability. Wherever possible each provision of this
Guaranty shall be interpreted in such manner as to be effective and valid under
applicable law, but if any provision of this Guaranty shall be prohibited by or
invalid under such law, such provision shall be ineffective to the extent of
such prohibition or invalidity, without invalidating the remainder of such
provision or the remaining provisions of this Guaranty.
SECTION 6.7. Governing Law. THIS GUARANTY SHALL BE GOVERNED BY
AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS.
IN WITNESS WHEREOF, the Guarantor has caused this Guaranty to be duly
executed and delivered by its officer thereunto duly authorized as of the date
first above written.
Enron Oil & Gas Company
By:____________________________
Title:
Address: ______________________
Attention: _____________________
Telex:_________________________
Telecopy: ______________________
<PAGE>
<TABLE>
<CAPTION>
Schedule 1
ENRON GAS & OIL TRINIDAD LIMITED
PRICING APPENDIX
Level I Level II Level III Level IV Level V Level VI
------- -------- --------- -------- ------- --------
<S> <C> <C> <C> <C> <C>
Basis for If the If the If the If the If the If the
Pricing Guarantor's Guarantor's Guarantor's Guarantor's Guarantor's Guarantor's
Senior Senior Senior Senior Senior Senior
Unsecured Unsecured Unsecured Unsecured Unsecured Unsecured
Long Term Long Term Long Term Long Term Long Term Long Term
Debt is rated Debt is rated Debt is rated Debt is rated Debt is rated Debt is rated
A or better BBB+ or better BBB by S&P BBB- by S&P BBB- by S&P BB+ or lower
by S&P or A2 by S&P or Baa1 and Baa2 by or Baa3 by and Baa3 by by S&P and Ba1
or better by or better by Moody's. Moody's. Moody's. or lower by
Moody's. Moody's. Moody's.
Commitment 12.5bp 15.0bp 17.5bp 20.0bp 25.0bp 37.5bp
Fee
LIBOR+ 37.5bp 50.0bp 55.0bp 62.5bp 75bp 112.5bp
936+ 37.5bp 50.0bp 55.0bp 62.5bp 75bp 112.5bp
</TABLE>
<PAGE>
EXHIBIT D
CERTIFICATE ISSUED PURSUANT TO SECTION 1.936-10(c)(11)
OF THE REGULATION PROMULGATED UNDER THE PROVISIONS OF
SECTION 936(d)(4) OF THE UNITED STATES INTERNAL REVENUE CODE
Enron Gas & Oil Trinidad Limited ("EGOTL") hereby certifies that, for
purposes of the Letter Loan Agreement with The Bank of Nova Scotia dated
_______________________, 1994, EGOTL is a "qualified recipient" under the
provisions of Section 1.936-10(c)(9) of the regulations promulgated under the
provisions of Section 936(d)(4) of the United States Internal Revenue Code.
ENRON GAS & OIL TRINIDAD LIMITED
<PAGE>
EXHIBIT E
(Enron Gas & Oil Trinidad Limited Letterhead)
___________________ ,1994
The Bank of Nova Scotia
273 Ponce de Leon Avenue
Hato Rey, Puerto Rico
Re: LOAN OF US$44,000,000 GRANTED BY THE BANK OF NOVA SCOTIA TO ENRON GAS &
OIL TRINIDAD LIMITED
Gentlemen:
We hereby acknowledge that the proceeds of the loan or loans up to
aggregate principal amount of US$44,000,000 may be funded in whole or in part
with "eligible funds", as the term is defined in Regulation 3582, and all
amendments or substitutes thereof. We certify that the proceeds of the loan or
loans will be used solely for the acquisition of Active Business Assets that
qualify as such under Section 1.936-10(c)(4) of the regulations promulgated
under Section 936(d)(4) of the United States Internal Revenue Code (the "Federal
CBI Regulations"), to be used by us to finance (or refinance or replace with
Advances funded with 936 Deposits as permitted by paragraphs (c)(7)(i) and
(c)(7)(ii) of the Federal CBI Regulations) the costs of the Company's
exploration, development and production of natural gas and crude oil fields from
the Kiskadee and Ibis Fields in the South East Consortium Block offshore
Trinidad & Tobago, including without limitation the constructing of offshore
platforms, laying of pipelines, drilling of wells and installation of all
related equipment and facilities (the "Active Answers Assets"), and for working
capital purposes in full compliance with the Federal CBI Regulations.
The collateral provided by us for the loan consists of a guaranty of Enron
Oil & Gas Company.
Cordially,
ENRON GAS & OIL TRINIDAD LIMITED
By: ____________________________
<PAGE>
EXHIBIT F
CERTIFICATE ISSUED PURSUANT TO SECTION 1.936-10(c)(12)
OF THE REGULATIONS PROMULGATED UNDER THE PROVISIONS OF
SECTION 936(d)(4) OF THE UNITED STATES INTERNAL REVENUE CODE
In order to comply with the certification requirement of Section 936
(d)(4)(c)(i) of the United States Internal Revenue Code (the "Code"), and as
required by Section 1.936-10(c)(12) of the regulations promulgated thereunder
(the "Federal CBI Regulations"), The Bank of Nova Scotia, Hato Rey Branch (the
"Bank") and Enron Gas & Oil Trinidad Limited (the"Company") hereby certify to
the Assistant Commissioner (International) of the United States Internal Revenue
Service and to the Commissioner of Financial Institutions of Puerto Rico as
follows:
(1) As of the date hereof the Company has complied with the provisions of
Section 1.936-10(c)(11) of the Federal CBI Regulations.
(2) The loan to the Company is a non-revolving loan of Us$44,000,000 (the
"Loan") and may be drawn in one or more advances in minimum principal amounts of
US$500,000. The maturity of the Loan will be on _________________________, 1999.
The proceeds of the Loan will be used by the Company solely to finance (or
refinance or replace with Advances funded with 936 Deposits as permitted by
paragraphs (c)(7)(i) and (c)(7)(ii) of the Federal CBI Regulations) the costs of
the Company's exploration for and development and production of natural gas and
crude oil from the Kiskadee and Ibis Fields in the South East Coast Consortium
Block offshore Trinidad & Tobago, including without limitation, the constructing
of off-shore platforms, laying of pipelines, drilling of wells and installation
of all related equipment and facilities (the "Active Business Assets"). The
proceeds of the Loan may also be used for working capital purposes, provided
that the amount used for such purposes may not exceed 10% of the amount invested
in Active Business Assets (the "Working Capital Amount"). The Loan is secured by
the unconditional guarantee of Enron Oil & Gas Company.
(3) The Company is a corporation organized under the laws of Trinidad &
Tobago and is an indirect wholly owned subsidiary of Enron Oil & Gas Company.
The Company is engaged in the exploration and development, production and
marketing of oil and gas reserves in Trinidad & Tobago.
(4) Trinidad & Tobago qualifies as a "beneficiary country" within the
meaning of Section 212(a)(1)(A) of the Caribbean Basin Economic Recovery Act. In
addition, (i) there is in effect an agreement for the exchange of tax
information between Trinidad & Tobago and the
United States and (ii) there is not in effect a finding by the United States
Secretary of the Treasury that the tax laws of Trinidad & Tobago discriminate
against conventions held in the United States.
(5) The Loan qualifies as a qualified investment in a qualified Caribbean
Basin country under Section 1.936-10(c) of the Federal CBI Regulations because
of the following:
(a) the Loan will be made by the Bank a banking institution
organized under the laws of Canada, that has been designated as an "eligible
institution" under Section 4.2.13 of Regulation 3582. Thus, the requirement that
the Loan be made by a "qualified institution," as defined in Section
1.936-10(c)(3) is met;
(b) the Loan will be made to the Company, a corporation engaged in
the exploration for and the development, production and marketing of oil and gas
reserves in Trinidad & Tobago, that has complied with the agreement and
representation requirements of Section 1.936- 10(c)(11)(i) of the Federal CBI
Regulations. Thus, the requirement that the Loan be made to a "qualified
recipient," as defined in Section 1.936-10(c)(9) is met;
(c) the proceeds of the Loan will be used by the Company for the
acquisition of the Active Business Assets and/or to refinance the acquisition of
Active Business Assets in compliance with the provisions of the Federal CBI
Regulations, which Active Business Assets are to be used exclusively in the
Company's operation in Trinidad & Tobago. Not more than 3.5% of the principal
amount of the Loan will be used to finance costs associated with the arranging
of the financing and not more than 10% of the amount of the Loan invested in
Active Business Assets will be used for working capital purposes. Thus, the
requirement that the Loan be made to the qualified recipient for investment in
"active business assets", as defined in Section 1.936-10(c)(4) is met;
(d) the investment of the Loan proceeds will be made in Trinidad &
Tobago which, as stated above, (i) has been designated as a "beneficiary
country" under the Caribbean Basin Economic Recovery Act; (ii) has an agreement
in effect for the exchange of tax information with the United States; and (iii)
is a country with respect to which there is not in effect a finding by the
Secretary of the Treasury that its tax laws discriminate against conventions
held in the United States. Thus, the requirement that the investment be made in
a "qualified Caribbean Basin" country, as defined in Section
1.936-10(c)(10)(C)(ii) is met; and
(e) the Loan has been approved by the Commissioner of Financial
Institutions of Puerto Rico and the agreement, representations, certification
and due diligence requirements of Section 1.936-10(c)(11), (c)(12), and (c)(13)
have been or will be met.
(6) The Bank agrees to permit examination by the Assistant Commissioner
(International) of the United States Internal Revenue Service (or by the Office
of any District Director authorized by the Assistant Commissioner
(International)) and by the Commissioner of Financial Institutions of Puerto
Rico of all of its necessary books and records that are sufficient to verify
that the proceeds of the Loan were used for investments in Active Business
Assets, as referred to above.
In San Juan, Puerto Rico this _______th day of ________________________,
1994.
ENRON GAS & OIL THE BANK OF NOVA SCOTIA
TRINIDAD LIMITED
__________________________ _____________________________
By: By:
Title: Title:
EXHIBIT 10.45(b)
PROMISSORY NOTE
US$25,000,000 Maturity: May 27, 1999
FOR THE VALUE RECEIVED, Enron Gas & Oil Trinidad Limited (the "Borrower"),
a corporation organized under the laws of Trinidad & Tobago, promises to pay to
the order of The Bank of Nova Scotia (the "Bank"), a banking corporation
organized and existing under the laws of Canada, at the principal offices of the
Bank, Plaza Scotiabank Building, 273 Ponce de Leon Avenue, Hato Rey, San Juan,
Puerto Rico, or such other place that the Bank may designate, the principal sum
of US$25,000,000 in lawful currency of the United States of America or, if less,
the aggregate unpaid principal amount of the Advance (as defined in the Letter
Loan Agreement dated May 27, 1994 between the Borrower and the Bank, such Letter
Loan Agreement as amended from time to time being herein referred to as the
"Loan Agreement") owing to the Bank outstanding on the Maturity Date.
The principal of this obligation will be repaid in one installment due on
May 27, 1999.
Interest will accrue and be payable on the outstanding principal balance
of this obligation from this date on at the following alternative rates:
1. The cost of 30, 60, 90 or 180 day 936 Deposits to the Bank (as
determined by the Bank and adjusted for the cost to the Bank of
municipal license taxes), plus 50 basis points per annum (subject to
the availability of 936 Deposits and to the continuing qualification
of the Loan for 936 funding) (the "936 Option Rate");
2. 1, 2, 3, or 6 months cost of LIBOR to the Bank plus 50 basis points
per annum (subject to the availability of LIBOR funds) ( the "LIBOR
Option Rate").
3. If both 936 Deposits and LIBOR funds become unavailable or may not
be used, the applicable interest rate will be the Base Rate
fluctuating concurrently with any changes in such Base Rate.
4. Notwithstanding anything to the contrary provided in paragraphs (1)
and (2) above, at any time during the term of the Loan, the Borrower
may request the Bank to fix the rate of interest on all or any
portion of the Loan for a period not to exceed the then remaining
term of the Loan, subject to the availability to the Bank of 936
Deposits or LIBOR funds with a term at least equal to such term, at
a rate mutually agreeable to the Borrower and the Bank. Any
prepayment by the Borrower of all or any portion of the principal
amount of the Loan with a fixed interest rate shall be subject to
payment by the Borrower of the breakage costs set forth in Section
12 of the Loan Agreement.
5. Notwithstanding anything to the contrary herein provided, the
interest rate applicable to any overdue principal under the Loan
shall be 2% over the Base Rate per annum.
The interest rates set forth herein shall be increased and reduced
concurrently with any increases or reductions in the Guarantor's
senior unsecured long term debt rating by Standard and Poor's
("S&P") or Moody's as follows:
S & P or Moody's LIBOR Plus 936 Plus
Rating
- ---------------- ---------- --------
A or A2, or better 37.5 bp 37.5 bp
BBB+ or Baa1, or
better 50 bp 50 bp
BBB and Baa2 55 bp 55 bp
BBB- or Baa3 62.5 bp 62.5 bp
BBB- and Baa3 75 bp 75 bp
BB+ or lower and
Ba1 or lower 112.5 bp 112.5 bp
Upon the first Advance and thereafter three Business Days prior to the
first day of each new Funding Period, the Bank shall notify to the Borrower the
following rates of interest on such Business Day (a) subject to the availability
to the Bank of 936 Deposits and to the eligibility of the Advance to be funded
with 936 Deposits, the 936 Option Rate; and (b) subject to the availability to
the Bank of LIBOR funds for such Funding Period, the LIBOR Option Rate. In the
case of 936 Deposit funding, the Borrower must advise the Bank not later than 12
noon Puerto Rico time on the first Business Day of the ensuing Funding Period,
and in the case of LIBOR funding two (2) Business Days before such Business Day
which of the two funding options it selects for the ensuing Funding Period. The
interest rate applicable to such Funding
Period shall be the interest rate applicable on the first day of the Funding
Period to the funding option selected by the Borrower. If the Borrower fails to
make such timely notice of election then the interest rate beginning on the
first day of such Funding Period shall be computed on the basis of the 30 day
936 Option Rate until a new Funding Period is established, or, if 936 Deposits
are not available, on the basis of 30 day LIBOR Option Rate or, if LIBOR funds
are not available, on the basis of the Base Rate.
The Borrower shall pay interest quarterly in arrears on each Interest
Payment Date, or on a Rollover Date, whichever is earlier, on the actual daily
unpaid principal balance of the Loan and calculated on each such day on the
basis of (i) a 365/366 day calendar year for the actual number of days elapsed
with respect to Base Rate Advances, and (ii) a 360-day calendar year for the
actual number of days elapsed with respect to 936 Option Rate and/or LIBOR
Option Rate Advances.
Up to an amount equal to the Working Capital Amount may be repaid and
reborrowed hereunder prior to the Maturity Date provided that repayments of such
amount shall be allowed only on Rollover Dates.
Upon failure to pay principal, or interest, or the occurrence of any other
event of default as stipulated in the Loan Agreement, the Bank may at its option
declare the full unpaid balance of this obligation to be immediately due and
payable together with any accrued and unpaid interest, and may proceed to
enforce the security under the Loan Agreement and/or interpose
judicial proceedings to collect said sums plus costs, expenses and a reasonable
sum for attorney's fees.
The Borrower hereby waives presentment, protest, demand and notice of non-
payment and submits itself to the jurisdiction of the courts of the Commonwealth
of Puerto Rico for any judicial proceeding hereunder.
The terms "the Borrower" and "the Bank" as used herein include their
respective successors or assigns.
This Promissory Note has been issued under and pursuant to the Loan
Agreement which is supplementary as to any matter pertinent to this Promissory
Note not expressly provided herein. All capitalized terms used herein shall have
the meaning ascribed to such terms in the Loan Agreement.
Dated as of May 31, 1994.
Enron Gas & Oil Trinidad Limited
/s/ W. C. Wilson
EXHIBIT 10.45(c)
PROMISSORY NOTE
US$15,000,000 MATURITY: May 27, 1999
FOR THE VALUE RECEIVED, Enron Gas & Oil Trinidad Limited (the "Borrower"),
a corporation organized under the laws of Trinidad & Tobago, promises to pay to
the order of The Bank of Nova Scotia (the "Bank"), a banking corporation
organized and existing under the laws of Canada, at the principal offices of the
Bank, Plaza Scotiabank Building, 273 Ponce de Leon Avenue, Hato Rey, San Juan,
Puerto Rico, or such other place that the Bank may designate, the principal sum
of US$15,000,000 in lawful currency of the United States of America, or, if
less, the aggregate unpaid principal amount of the Advance (as defined in the
Letter Loan Agreement dated May 27, 1994 between the Borrower and the Bank, such
Letter Loan Agreement as amended from time to time being herein referred to as
the "Loan Agreement") owing to the Bank outstanding on the Maturity Date.
The principal of this obligation will be repaid in one installment due on
May 27, 1999.
Interest will accrue and be payable on the outstanding principal balance
of this obligation from this date on at the following alternative rates:
1. The cost of 30, 60, 90 or 180 day 936 Deposits to the Bank (as
determined by the Bank and adjusted for the cost to the Bank of
municipal license taxes), plus 50 basis points per annum (subject to
the availability of 936 Deposits and to the continuing qualification
of the Loan for 936 funding) (the "936 Option Rate");
1
2. 1, 2, 3, or 6 months cost of LIBOR to the Bank plus 50 basis points
per annum (subject to the availability of LIBOR funds) (the "LIBOR
Option Rate").
3. If both 936 Deposits and LIBOR funds become unavailable or may not
be used, the applicable interest rate will be the Base Rate
fluctuating concurrently with any changes in such Base Rate.
4. Notwithstanding anything to the contrary provided in paragraphs (1)
and (2) above, at any time during the term of the Loan, the Borrower
may request the Bank to fix the rate of interest on all or any
portion of the Loan for a period not to exceed the then remaining
term of the Loan, subject to the availability to the Bank of 936
Deposits or LIBOR funds with a term at least equal to such term, at
a rate mutually agreeable to the Borrower and the Bank. Any
prepayment by the Borrower of all or any portion of the principal
amount of the Loan with a fixed interest rate shall be subject to
payment by the Borrower of the breakage costs set forth in Section
12 of the Loan Agreement.
5. Notwithstanding anything to the contrary herein provided, the
interest rate applicable to any overdue principal under the Loan
shall be 2% over the Base Rate per annum.
The interest rates set forth herein shall be increased and reduced
concurrently with any increases or reductions in the Guarantor's
senior unsecured long term debt rating by Standard and Poor's
("S&P") or Moody's as follows:
2
S&P OR MOODY'S RATING LIBOR PLUS 936 PLUS
--------------------- ---------- --------
A or A2, or better 37.5 bp 37.5 bp
BBB+ or Baa1, or
better 50 bp 50 bp
BBB and Baa2 55 bp 55 bp
BBB- or Baa3 62.5 bp 62.5 bp
BBB- and Baa3 75 bp 75 bp
BB+ or lower and Ba1
or lower 112.5 bp 112.5 bp
Upon the first Advance and thereafter three Business Days prior to the
first day of each new Funding Period, the Bank shall notify to the Borrower the
following rates of interest on such Business Day (a) subject to the availability
to the Bank of 936 Deposits and to the eligibility of the Advance to be funded
with 936 Deposits, the 936 Option Rate; and (b) subject to the availability to
the Bank of LIBOR funds for such Funding Period, the LIBOR Option Rate. In the
case of 936 Deposit funding, the Borrower must advise the Bank not later than 12
noon Puerto Rico time on the first Business Day of the ensuing Funding Period,
and in the case of LIBOR funding two (2) Business Days before such Business Day
which of the two funding options it selects for the ensuing Funding Period. The
interest rate applicable to such Funding Period shall be the interest rate
applicable on the first day of the Funding Period to the funding option selected
by the Borrower. If the Borrower fails to make such timely notice of election
then the interest rate beginning on the first day of such Funding Period shall
be computed on the basis of the 30 day 936 Option Rate until a new Funding
Period is established, or, if 936 Deposits are not available, on the basis of 30
day LIBOR Option Rate, or, if LIBOR funds are not available, on the basis of the
Base Rate.
3
The Borrower shall pay interest quarterly in arrears on each Interest
Payment Date, or on a Rollover Date, whichever is earlier, on the actual daily
unpaid principal balance of the Loan and calculated on each such day on the
basis of (i) a 365/366 day calendar year for the actual number of days elapsed
with respect to Base Rate Advances, and (ii) a 360-day calendar year for the
actual number of days elapsed with respect to 936 Option Rate and/or LIBOR
Option Rate Advances.
Up to an amount equal to the Working Capital Amount may be repaid and
reborrowed hereunder prior to the Maturity Date provided that repayments of such
amount shall be allowed only on Rollover Dates.
Upon failure to pay principal, or interest, or the occurrence of any other
event of default as stipulated in the Loan Agreement, the Bank may at its option
declare the full unpaid balance of this obligation to be immediately due and
payable together with any accrued and unpaid interest, and may proceed to
enforce the security under the Loan Agreement and/or interpose judicial
proceedings to collect said sums plus costs, expenses and a reasonable sum for
attorney's fees.
The Borrower hereby waives presentment, protest, demand and notice of
non-payment and submits itself to the jurisdiction of the courts of the
Commonwealth of Puerto Rico for any judicial proceeding hereunder.
The terms "the Borrower" and "the Bank" as used herein include their
respective successors or assigns.
4
This Promissory Note has been issued under and pursuant to the Loan
Agreement which is supplementary as to any matter pertinent to this Promissory
Note not expressly provided herein. All capitalized terms used herein shall have
the meaning ascribed to such terms in the Loan Agreement.
Dated as of January 10, 1995.
Enron Gas & Oil Trinidad Limited
/s/ W. C. Wilson
5
EXHIBIT 10.46
GUARANTY
THIS GUARANTY (this "GUARANTY"), dated as of May 27, 1994, made by Enron
Oil & Gas Company, a Delaware corporation (the "GUARANTOR"), in favor of The
Bank of Nova Scotia, ("BNS"),
W I T N E S S E T H:
WHEREAS, pursuant to a Letter Loan Agreement, dated as of May 27, 1994
(together with all amendments and other modifications, if any, from time to time
thereafter made thereto, the "LETTER LOAN AGREEMENT"), between Enron Gas & Oil
Trinidad, Limited, a company organized and existing under the laws of Trinidad
and Tobago (the "BORROWER") and BNS, BNS has extended a commitment to make loans
(the "Loans") to the Borrower; and
WHEREAS, BNS and the Borrower may now or in the future enter into one or
more interest rate swap, hedge, collar, floor or similar agreements
(collectively, together with all amendments and other modifications, if any,
from time to time thereafter made thereto, and together with any and all
Confirmations ("CONFIRMATIONS") thereunder, the "Swap Agreement", such interest
rate swaps, hedges, collars, floors or similar agreements with the Borrower
herein collectively the "Swaps"); and
WHEREAS, as a condition precedent to the making of the Loans under the
Letter Loan Agreement and entering into the Swaps pursuant to the Swap
Agreement, the Guarantor is required to execute and deliver this Guaranty;
WHEREAS, the Guarantor has duly authorized the execution, delivery and
performance of this Guaranty;
WHEREAS, it is in the best interests of the Guarantor to execute this
Guaranty inasmuch as the Guarantor will derive substantial direct and indirect
benefits from the Loans made from time to time and the Swaps from time to time
entered into with the Borrower by BNS pursuant to the Letter Loan Agreement or
the Swap Agreement, as the case may be;
NOW, THEREFORE, for good and valuable consideration the receipt of which
is hereby acknowledged, and in order to induce BNS to make the Loans to the
Borrower pursuant to the Letter Loan Agreement and to enter into the Swaps, if
any, pursuant to the Swap Agreement, the Guarantor agrees, for the benefit of
BNS, as follows:
ARTICLE I
DEFINITIONS
SECTION 1.1. CERTAIN TERMS. The following terms (whether or not
underscored) when used in this Guaranty, including its preamble and recitals,
shall have the following meanings (such definitions to be equally applicable to
the singular and plural forms thereof):
"BORROWER" is defined in the FIRST RECITAL.
"BUSINESS DAY" means any day of the year except Saturday, Sunday and any
day on which banks are required or authorized to close in Houston, Texas; New
York, New York; San Juan, Puerto Rico; or Trinidad and Togabo.
"CODE" means the Internal Revenue Code of 1986, as amended.
"CONSOLIDATED" refers to the consolidation of the accounts of the
Guarantor and its Subsidiaries in accordance with GAAP.
"CONSOLIDATED NET WORTH" means at any date the Consolidated shareholders'
equity of the Guarantor and its Consolidated subsidiaries.
"CREDIT AGREEMENT" means the Revolving Credit Agreement dated as of March
11, 1994 between the Guarantor as Borrower, the Banks party thereto, and Texas
Commerce Bank National Association, as Administrative Agent.
"DEBT" of any Person means, at any date, without duplication, (a)
obligations for the repayment of money borrowed which (1) are evidenced by
bonds, notes, debentures, loan agreements, credit agreements or similar
instruments or agreements and (2) are or should be shown on a balance sheet as
debt in accordance with GAAP, (b) obligations as lessee under leases which, in
accordance with GAAP, are capital leases, and (c) guaranties of payment or
collection of any obligations described in CLAUSES (A) and (B) of other Persons,
PROVIDED, that CLAUSES (A) and (B) include, in the case of obligations of the
Borrower or any Subsidiary, only such obligations as are or should be shown as
debt or capital lease liabilities on a Consolidated balance sheet in accordance
with GAAP; PROVIDED, FURTHER, that none of the following shall constitute Debt:
(A) transfers of accounts receivable pursuant to a receivables purchase facility
considered a sale under GAAP (and indemnification, recourse or repurchase
obligations thereunder as are reasonable given market standards for transactions
of similar type), (B) the liability of any Person as a general partner of a
partnership for Debt of such partnership, if the partnership is not a Subsidiary
of such Person, and (C) obligations (other than borrowings, capital leases or
financial guaranties by the Guarantor
or any Subsidiary) related to the sale, purchase or delivery of hydrocarbons in
respect of volumetric production payments conveyed in transfers constituting
sales of real property interests for which proceeds are accounted for as
deferred revenues under GAAP.
"ERISA" means the Employee Retirement Income Security Act of 1974, as
amended from time to time, and any successor statute of similar import, together
with the regulations thereunder, as in effect from time to time.
"ERISA AFFILIATE" means any trade or business (whether or not
incorporated) which is a member of a group of which the Guarantor is a member
and which is under common control within the meaning of the regulations under
Section 414 of the Code.
"GAAP" means generally accepted accounting principles consistent with
those applied in the preparation of the audited Consolidated financial
statements referred to in SECTION 3.1(D).
"GUARANTOR" is defined in the PREAMBLE.
"GUARANTY" is defined in the PREAMBLE.
"INSUFFICIENCY" means, with respect to any Plan, the amount, if any, by
which the present value of the accrued benefits under such Plan exceeds the fair
market value of the assets of such Plan allocable to such benefits.
"LENDER" is defined in the PREAMBLE.
"LETTER LOAN AGREEMENT" is defined in the FIRST RECITAL.
"LOAN DOCUMENTS" means the Letter Loan Agreement, the notes thereunder and
the other documents delivered to BNS under the Letter Loan Agreement together
with any Swap Agreement, any Confirmation and any other documents delivered to
BNS thereunder.
"MULTIEMPLOYER PLAN" means a "multiemployer plan" as defined in Section
4001(a)(3) of the ERISA to which the Guarantor or any ERISA Affiliate is making
or accruing an obligation to make contributions, or has within any of the
preceding five plan years made or accrued an obligation to make contributions.
"MULTIPLE EMPLOYER PLAN" means an employee benefit plan, other than a
Multiemployer Plan, subject to Title IV of ERISA to which the Guarantor or any
ERISA Affiliate, and more than one employer other than the Guarantor or an ERISA
Affiliate, is making or accruing an obligation to make contributions or, in the
event that any such plan has been terminated, to which the Guarantor or any
ERISA Affiliate made or accrued an obligation to make contributions
during any of the five plan years preceding the date of termination of such
plan.
"NOTE" means a Promissory Note or Non-Revolving Term Note as those terms
are defined in the Letter Loan Agreement.
"OTHER TAXES" is defined in CLAUSE (B) of SECTION 2.8.
"PBGC" means the Pension Benefit Guaranty Corporation, or any federal
agency or authority of the United States from time to time succeeding to its
function.
"PERSON" means an individual, partnership, corporation, limited liability
company, business trust, joint stock company, trust, unincorporated association,
joint venture, firm or other entity, or a government or any political
subdivision or agency, department or instrumentality thereof.
"PLAN" means an employee benefit plan (other than a Multiemployer Plan)
which is (or, in the event that any such plans has been terminated within five
years after a transaction described in Section 4069 of ERISA, was) maintained
for employees of the Guarantor or any ERISA Affiliate and covered by Title IV or
ERISA.
"PRINCIPAL SUBSIDIARY" means at any time of determination any Subsidiary
having total assets in excess of $100,000,000. For purposes of this definition,
total assets shall be determined based on the most recent quarterly or annual
financial statements available prior to such determination.
"RATING LEVEL" means the applicable category of rating level which is
based on the rating of the Guarantor's senior unsecured long-term debt as
classified by Moody's and/or Standard & Poor's and which shall be the highest
applicable Rating Level I, Rating Level II, Rating Level III, Rating Level IV,
Rating Level V or Rating Level VI, as the case may be, as set forth in SCHEDULE
I.
"SUBSIDIARY" means any corporation, partnership, joint venture or other
entity of which more than 50% of the outstanding capital stock or other equity
interests having ordinary voting power (irrespective of whether or not at the
time capital stock or other equity interest of any other class or classes of
such corporation, partnership, joint venture or other entity shall or might have
voting power upon the occurrence of any contingency) is at the time directly or
indirectly owned by the Guarantor.
"SWAP" is defined in the PREAMBLE.
"SWAP AGREEMENT" is defined in the PREAMBLE.
"TAXES" is defined in CLAUSE (A) of SECTION 2.8.
"TERMINATION EVENT" means (a) a "reportable event", as such term is
described in Section 4043 of ERISA (other than a "reportable event" not subject
to the provision for 30-day notice to the PBGC), or an event described in
Section 4062(e) of ERISA, or (b) the withdrawal of the Guarantor or any ERISA
Affiliate from a Multiple Employer Plan during a plan year in which it was a
"substantial employer", as such term is defined in Section 4001(a)(2) of ERISA,
or the incurrence of liability by the Guarantor or any ERISA Affiliate under
Section 4064 of ERISA upon the termination of a Multiple Employer Plan, or (c)
the distribution of a notice of intent to terminate a Plan pursuant to Section
4041(a)(2) of ERISA or the treatment of a Plan amendment as a termination under
Section 4041 of ERISA, or (d) the institution of proceedings to terminate a Plan
by the PBGC under Section 4042 of ERISA, or (e) any other event or condition
which might constitute grounds under Section 4042 of ERISA for the termination
of, or the appointment of a trustee to administer, any Plan.
"TOTAL CAPITALIZATION" means, at any time, the sum (without duplication)
of (a) Total Debt, and (b) Consolidated Net Worth less any amount thereof
attributable to "minority interests" (as defined below). For the purpose of this
definition, "minority interests" means any investment or interest of the
Guarantor in any corporation, partnership or other entity to the extent that the
total amount thereof owned by the Guarantor (directly or indirectly) constitutes
50% or less of all outstanding interests or investments in such corporation,
partnership or entity.
"TOTAL DEBT" means, at any time, all Consolidated Debt of the Guarantor
and its Consolidated Subsidiaries.
"WITHDRAWAL LIABILITY" shall have the meaning given such term under Part I
of Subtitle E of Title IV of ERISA.
SECTION 1.2. LETTER LOAN DEFINITIONS. Unless otherwise defined herein or
the context otherwise requires, terms used in this Guaranty, including its
preamble and recitals, have the meanings provided in the Letter Loan Agreement.
ARTICLE II
GUARANTY PROVISIONS
SECTION 2.1. GUARANTY. The Guarantor hereby absolutely, unconditionally
and irrevocably
(a) guarantees the full and punctual payment when due, whether at
stated maturity, by required prepayment, declaration, acceleration, demand
or otherwise, of all indebtedness, obligations and liabilities of the
Borrower to
BNS arising out of, under, or in connection with the Letter Loan Agreement
or any of the other Loan Documents (collectively the "Guaranteed
Obligations") of the Borrower, whether for principal, interest, fees,
expenses or otherwise (including all such amounts which would become due
but for the operation of the automatic stay under Section 362(a) of the
United States Bankruptcy Code, 11 U.S.C. ss.362(a)), and the operation of
Sections 502(b) and 506(b) of the United States Bankruptcy Code, 11 U.S.C.
ss.502(b) and ss.506(b), and
(b) indemnifies and holds harmless BNS and each holder of a Note for
any and all costs and expenses (including reasonable attorney's fees and
expenses) incurred by BNS or such holder, as the case may be, in enforcing
any of its rights under this Guaranty.
This Guaranty constitutes a guaranty of payment when due and not of collection,
and the Guarantor specifically agrees that it shall not be necessary or required
that BNS or any holder of any Note exercise any right, assert any claim or
demand or enforce any remedy whatsoever against the Borrower (or any other
Person) before or as a condition to the obligations of the Guarantor hereunder.
SECTION 2.2. ACCELERATION OF GUARANTY. The Guarantor agrees that, in the
event of the occurrence and continuation of an Event of Default under Section
5.1 and if such Event of Default shall occur at a time when any of the
Guaranteed Obligations may not then be due and payable, then, immediately and
without further action by BNS, in the event of an Event of Default of the type
referred to in Section 5.1(e) or upon demand by BNS in the event of an Event of
Default (other than an Event of Default of the type referred to in Section
5.1(e)) the Guarantor will pay to BNS forthwith the full amount which would be
payable hereunder by the Guarantor if all such Guaranteed Obligations were then
due and payable.
SECTION 2.3. GUARANTY ABSOLUTE, ETC. This Guaranty shall in all respects
be a continuing, absolute, unconditional and irrevocable guaranty of payment,
and shall remain in full force and effect until all Guaranteed Obligations have
been paid in full, all obligations of the Guarantor hereunder shall have been
paid in full and all Commitments shall have terminated. The Guarantor guarantees
that the Guaranteed Obligations will be paid strictly in accordance with the
terms of the Letter Loan Agreement or the Swap Agreement, as the case may be,
and each other Loan Document under which they arise, regardless of any law,
regulation or order now or hereafter in effect in any jurisdiction affecting any
of such terms or the rights of BNS or any holder of any Note with respect
thereto. The liability of the Guarantor under this Guaranty shall be absolute,
unconditional and irrevocable irrespective of:
(a) any lack of validity, legality or enforceability of the Letter Loan
Agreement, any Note, any other Loan Document, the Swap Agreement or any
Confirmation;
(b) the failure of BNS or any holder of any Note (i) to assert any claim
or demand or to enforce any right or remedy against the Borrower or any other
Person (including any other guarantor) under the provisions of the Letter Loan
Agreement, any Note, any other Loan Document, the Swap Agreement or any
Confirmation or otherwise, or (ii) to exercise any right or remedy against any
other guarantor of, or collateral (if any) securing, any Guaranteed Obligations;
(c) any change in the time, manner or place of payment of, or in any other
term of, all or any of the Guaranteed Obligations, or any other extension,
compromise or renewal of any Guaranteed Obligation;
(d) any reduction, limitation, impairment or termination of the Guaranteed
Obligations for any reason, including any claim of waiver, release, surrender,
alteration or compromise, and shall not be subject to (and the Guarantor hereby
waives any right to or claim of) any defense or setoff, counterclaim, recoupment
or termination whatsoever by reason of the invalidity, illegality,
nongenuineness, irregularity, compromise, unenforceability of, or any other
event or occurrence affecting, the Guaranteed Obligations or otherwise;
(e) any amendment to, rescission, waiver, or other modification of, or any
consent to departure from, any of the terms of the Letter Loan Agreement, any
Note or any other Loan Document or the Swap Agreement or any Confirmation, as
the case may be;
(f) any addition, exchange, release, surrender or nonperfection of any
collateral (if any), or any amendment to or waiver or release or addition of, or
consent to departure from, any other guaranty, held by BNS or any holder of any
Note securing any of the Guaranteed Obligations; or
(g) any other circumstance which might otherwise constitute a defense
available to, or a legal or equitable discharge of, the Borrower, any surety or
any other guarantor.
SECTION 2.4. REINSTATEMENT, ETC. The Guarantor agrees that this Guaranty
shall continue to be effective or be reinstated, as the case may be, if at any
time any payment (in whole or in part) of any of the Guaranteed Obligations is
rescinded or must otherwise be restored by BNS or any holder of any Note, upon
the insolvency, bankruptcy or reorganization of the Borrower or otherwise, as
though such payment had not been made.
SECTION 2.5. WAIVER, ETC. The Guarantor hereby waives promptness,
diligence, notice of acceptance and any other notice with respect to any of the
Guaranteed Obligations and this Guaranty and any requirement that BNS or any
holder of any Note protect, secure, perfect or insure any security interest or
lien, or any property subject thereto, or exhaust any right or take any action
against the Borrower or any other Person (including any other guarantor) or
entity or any collateral (if any) securing the Guaranteed Obligations.
SECTION 2.6. SUBROGATION, ETC. The Guarantor will not exercise any rights
which it may acquire by way of subrogation under this Guaranty, by any payment
made hereunder or otherwise, until the prior payment, in full and in cash, of
all Guaranteed Obligations. Any amount paid to the Guarantor on account of any
such subrogation rights prior to the payment in full of all Guaranteed
Obligations shall be held in trust for the benefit of BNS and each holder of a
Note and shall immediately be paid to BNS and each holder of a Note and credited
and applied against the Guaranteed Obligations whether matured or unmatured, in
accordance with the terms of the Letter Loan Agreement or the Swap Agreement, as
the case may be. In furtherance of the foregoing, for so long as any Guaranteed
Obligations or Commitments remain outstanding, the Guarantor shall refrain from
taking any action or commencing any proceeding against the Borrower (or its
successors or assigns, whether in connection with a bankruptcy proceeding or
otherwise) to recover any amounts in the respect of payments made under this
Guaranty to BNS or any holder of a Note.
SECTION 2.7. SUCCESSORS, TRANSFEREES AND ASSIGNS; TRANSFERS OF NOTES, ETC.
This Guaranty shall: (a) be binding upon the Guarantor, and its successors,
transferees and assigns; and (b) inure to the benefit of and be enforceable by
BNS, each holder of a Note and each of their respective successors, transferees
and assigns. Without limiting the generality of CLAUSE (B), BNS may assign or
otherwise transfer (in whole or in part) any Note or Loan or Swap held by it to
any other Person or entity, and such other Person or entity shall thereupon
become vested with all rights and benefits in respect thereof granted to BNS
under any Loan Document (including this Guaranty) or otherwise.
SECTION 2.8. PAYMENTS FREE AND CLEAR OF TAXES, ETC. The Guarantor hereby
agrees that:
(a) Any and all payments made by the Guarantor hereunder shall be
made in accordance with SECTION 20 of the Letter Loan Agreement or the
relevant section or sections of the Swap Agreement and any Confirmations
thereunder free and clear of, and without deduction for, any and all
present or future taxes, levies, imposts, deductions, charges or
withholdings, and all liabilities with respect thereto, excluding, in the
case of BNS and each holder of a Note, (i) taxes imposed on its income,
(ii) franchise taxes imposed on it by the jurisdiction under the laws of
which BNS or such holder, as the case may be, is organized and by any
political subdivision thereof and, in the case of BNS, taxes imposed on
its income, and franchise taxes imposed on it, by the jurisdiction of
BNS's Puerto Rico office and any political subdivision thereof and (iii)
any taxes imposed by the United States of America by means of withholding
at the source if an to the extent that such taxes shall be in effect and
shall be applicable, to payments to be made to BNS (all such taxes,
levies, imposts, deductions, charges, withholdings and liabilities other
than those referred to in the foregoing clauses (i), (ii) and (iii) being
hereinafter referred to as "TAXES"). If the Guarantor shall be required by
law to deduct any Taxes from or in respect of any sum payable hereunder to
BNS or any holder of a Note (i) the sum payable shall be increased as may
be necessary so that after making all required deductions (including
deductions applicable to additional sums payable under this Section) BNS
or such holder, as the case may be, receives an amount equal to the sum it
would have received had no such deductions been made, (ii) the Guarantor
shall make such deductions, and (iii) the Guarantor shall pay the full
amount deducted to the relevant taxation authority or other authority in
accordance with applicable law.
(b) The Guarantor shall pay any present or future stamp or
documentary taxes or any other excise or property taxes, charges or
similar levies which arise from any payment made hereunder or from the
execution, delivery or registration of, or otherwise with respect to, this
Guaranty (hereinafter referred to as "OTHER TAXES").
(c) The Guarantor hereby indemnifies and holds harmless BNS and each
holder of a Note for the full amount of Taxes or Other Taxes (including,
without limitation, any Taxes or Other Taxes imposed by any jurisdiction
on amounts payable under this Section) paid by BNS or such holder, as the
case may be, and any liability (including penalties, interest and
expenses) arising therefrom or with respect thereto, whether or not such
Taxes or Other Taxes were correctly or legally assessed (expressly
including such amounts paid as a result of the ordinary, sole or
contributory negligence of BNS or such holder of a Note, but excluding
such amounts paid as a result of the gross negligence or
willful misconduct of BNS or such holder of a Note). This indemnification
shall be made within thirty (30) days from the date BNS or such holder of
a Note, as the case may be, makes written demand therefor. BNS or the
holder of a Note shall not be indemnified for Taxes or Other Taxes
incurred or accrued unless within 90 days of the date
that BNS or such holder of a Note knew or should have known thereof, it
notifies the Guarantor thereof.
(d) Within 30 days after the date of any payment of Taxes or Other
Taxes, the Guarantor will furnish to BNS the original or a certified copy
of a receipt evidencing payment thereof. Should BNS or the holder of a
Note ever receive any refund, credit or deduction from any taxing
authority to which BNS or such holder of a Note would not be entitled but
for the payment by the Guarantor of Taxes or Other Taxes as required by
this Section 2.8 (it being understood that the decision as to whether or
not to claim, and if claimed, as to the amount of any such refund, credit
or deduction shall be made by BNS or such holder of a Note in its sole
discretion), BNS or such holder of a Note, as the case may be, thereupon
shall repay to the Guarantor an amount with respect to such refund, credit
or deduction equal to any net reduction in Taxes or Other Taxes actually
obtained by BNS or such holder of a Note, as the case may be, and
determined by BNS or such holder of a Note, as the case may be, to be
attributable to such refund, credit or deduction.
(e) Without prejudice to the survival of any other agreement of the
Guarantor hereunder (but subject to the expiration of any applicable
statute of limitations), the agreements and obligations of the Guarantor
contained in this SECTION 2.8 shall survive the payment in full of the
principal of and interest on the Loans.
SECTION 2.9. JUDGMENT. The Guarantor hereby agrees that:
(a) If, for the purposes of obtaining a judgment in any court, it is
necessary to convert a sum due hereunder from one currency into another
currency, the rate of exchange used shall be the best available rate at
which in accordance with normal banking procedures BNS could purchase such
currency with such other currency on the Business Day preceding that on
which final judgment is given.
(b) The obligation of the Guarantor in respect of any sum due from
it to BNS or any holder of a Note hereunder shall, notwithstanding any
judgment in a currency, be discharged only to the extent that on the
Business Day following receipt by BNS or such holder, as the case may be,
of any sum adjudged to be so due in such other currency BNS or such
holder, as the case may be, may, in accordance with normal banking
procedures using the best available exchange rate, purchase the relevant
currency with such other currency; in the event that the currency so
purchased is less than the sum originally due to BNS or such holder in
such currency, the Guarantor, as a separate obligation and notwithstanding
any
such judgment, hereby indemnifies and holds harmless BNS and such holder
against such loss, and if the such currency, so purchased exceeds the sum
originally due to BNS or such holder in the relevant currency, BNS or such
holder, as the case may be, shall remit to the Guarantor such excess.
ARTICLE III
REPRESENTATIONS AND WARRANTIES
SECTION 3.1. REPRESENTATIONS AND WARRANTIES. The Guarantor hereby
represents and warrants unto BNS as follows:
(a) The Guarantor and each Principal Subsidiary are corporations
duly incorporated, validly existing and in good standing under the laws of
their respective jurisdictions of incorporation. The Guarantor and each
Principal Subsidiary have all corporate powers and all material
governmental licenses, authorizations, consents and approvals required in
each case to carry on its business as now conducted except where failure
to have such would not, in the aggregate, have a material adverse effect
on the Guarantor or on the ability of the Guarantor to perform its
obligations under this Guaranty.
(b) The execution, delivery and performance by the Guarantor of this
Guaranty is within the Guarantor's corporate powers, have been duly
authorized by all necessary corporate action of the Guarantor, require, in
respect of the Guarantor, no action by or in respect of, or filing with,
any governmental body, agency or official and do not contravene, or
constitute a default under, any provision of law or regulation applicable
to the Guarantor or the restated certificate of incorporation or by-laws
of the Guarantor or any judgment, injunction, order, decree or material
("material" for the purposes of this representation meaning creating a
liability of $50,000,000 or more) agreement binding upon the Guarantor or
result in the creation or imposition of any lien, security interest or
other charge or encumbrance on any asset of the Guarantor or any of its
Subsidiaries.
(c) This Guaranty is the legal, valid and binding obligation of the
Guarantor enforceable against the Guarantor in accordance with its terms,
except as the enforceability thereof may be limited by the effect of any
applicable bankruptcy, insolvency, reorganization, moratorium or similar
laws affecting creditors' rights generally and by general principles of
equity.
(d) The audited Consolidated balance sheet of the Guarantor as of
December 31, 1993 and the related audited Consolidated statements of
income, cash flows and changes in shareholders' equity accounts for the
fiscal year then ended and the unaudited
Consolidated balance sheet of the Guarantor as of March 31, 1994, and the
related unaudited Consolidated statements of income and cash flows for the
fiscal quarter then ended, certified by the chief financial or accounting
officer of the Guarantor, copies of which have been delivered to BNS,
fairly present, in conformity with GAAP except as otherwise expressly
noted therein, the Consolidated financial position of the Guarantor as of
such dates and its Consolidated results of operations and as applicable
changes in financial position for such fiscal periods, subject (in the
case of the unaudited balance sheet and statements) to changes resulting
from audit and normal year-end adjustments.
(e) Since December 31, 1993 there has been no material adverse
change in the Consolidated financial position or Consolidated results of
operations of the Guarantor and its Subsidiaries, considered as a whole.
(f) Except as disclosed in the Guarantor's Form 10-K for the year
ended December 31, 1993 or the Guarantor's Form 10-Q for the quarter ended
March 31, 1994, which were delivered to BNS prior to the date hereof,
there is no action, suit or proceeding pending against the Guarantor or
any of its Subsidiaries, or to the knowledge of the Guarantor threatened
against the Guarantor or any of its Subsidiaries, before any court or
arbitrator or any governmental body, agency or official in which there is
a reasonable possibility of an adverse decision which could materially
adversely affect the Consolidated financial position or Consolidated
results of operations of the Guarantor and its Subsidiaries taken as a
whole or which in any manner draws into question the validity of this
Agreement.
(g) No Termination Event has occurred or is reasonably expected to
occur with respect to any Plan for which an Insufficiency in excess of
$50,000,000 exists. Neither the Guarantor nor any ERISA Affiliate has
received any notification (or has knowledge of any reason to expect) that
any Multiemployer Plan is in reorganization or has been terminated, within
the meaning of Title IV of ERISA, for which a Withdrawal Liability in
excess of $50,000,000 exists.
(h) United States federal income tax returns of the Guarantor and
its Subsidiaries have been examined and closed through the fiscal year
ended December 31, 1987. The Guarantor and its Subsidiaries have filed or
caused to be filed all United Sates federal income tax returns and all
other material domestic tax returns which to the knowledge of the
Guarantor are required to be filed by them and have paid or provided for
the payment, before the same become delinquent, of all taxes due pursuant
to such returns or pursuant to any assessment received by the Guarantor or
any Subsidiary, other than those taxes contested in good faith by
appropriate proceedings. The charges, accruals and reserves on the
books of the Guarantor and its Subsidiaries in respect of taxes are, in
the opinion of the Guarantor, adequate to the extent required by GAAP.
(i) Neither the Guarantor nor any Subsidiary is an "investment
company" within the meaning of the Investment Company Act of 1940, as
amended.
(j) The Guarantor is not a "holding company", a "subsidiary company"
of a "holding company", an "affiliate" of a "holding company", or an
"affiliate" of a "subsidiary company" of a "holding company", in each case
as such terms are defined in the Public Utility Holding Company Act of
1935, as amended.
ARTICLE IV
COVENANTS, ETC.
SECTION 4.1. AFFIRMATIVE COVENANTS. The Guarantor covenants and agrees
that so long as any portion of the Guaranteed Obligations shall remain unpaid or
BNS shall have any outstanding Commitment, the Guarantor will, unless BNS shall
otherwise consent in writing, perform the following obligations:
(a) REPORTING REQUIREMENTS. Furnish to BNS:
(1) (A) promptly after the sending or filing thereof, a copy
of each of the Guarantor's reports on Form 8-K (or any comparable
form), (B) promptly after the filing or sending thereof, and in any
event within 75 days after the end of each of the first three fiscal
quarters of each fiscal year of the Guarantor, a copy of the
Guarantor's report on Form 10-Q (or any comparable form) for such
quarter, which report will include the Guarantor's quarterly
unaudited Consolidated financial statements as of the end of and for
such quarter, and (C) promptly after the filing or sending thereof,
and in any event within 135 days after the end of each fiscal year
of the Guarantor, a copy of the Guarantor's annual report which it
sends to its public security holders, and a copy of the Guarantor's
annual report on Form 10-K (or any comparable form) for such year,
which annual report on Form 10-K will include the Guarantor's annual
audited Consolidated financial statements as of the end of and for
such year;
(2) simultaneously with the delivery of each of the annual or
quarterly reports referred to in CLAUSE (1) above, a certificate of
the chief financial officer or the chief accounting officer of the
Guarantor in a form acceptable to BNS (x) setting forth in
reasonable detail the calculations required to establish whether the
Guarantor was in compliance with the requirements of SECTION 4.2(B)
on the date of the
financial statements contained in such report, and (y) stating
whether there exists on the date of such certificate any Event of
Default or event which, with the giving of notice or lapse of time,
or both, would constitute an Event of Default, and, if so, setting
forth the details thereof and the action which the Guarantor has
taken and proposes to take with respect thereto;
(3) as soon as is possible and in any event within five days
after a change in, or issuance of, any rating of any of the
Guarantor's senior unsecured long-term debt by Standard & Poor's or
Moody's which causes a change in the applicable Rating Level, notify
BNS of such change;
(4) as soon as possible and in any event within five days
after an executive officer of the Guarantor having obtained
knowledge thereof, notice of the occurrence of any Event of Default
or any event which, with the giving of notice or lapse of time, or
both, would constitute an Event of Default, continuing on the date
of such notice, and a statement of the chief financial officer of
the Guarantor setting forth details of such Event of Default or
event and the action, if any, which the Guarantor has taken and
proposes to take with respect thereto;
(5) as soon as possible and in any event(A) within 30 Business
Days after the Guarantor or any ERISA Affiliate knows or has reason
to know that any Termination Event described in CLAUSE (A) of the
definition of Termination Event with respect to any Plan for which
an Insufficiency in excess of $50,000,000 exists, has occurred and
(B) within 10 Business Days after the Guarantor or any ERISA
Affiliate knows or has reason to know that any other Termination
Event with respect to any Plan for which an Insufficiency in excess
of $50,000,000 exists, has occurred or is reasonably expected to
occur, a statement of the chief financial officer or chief
accounting officer of the Guarantor describing such Termination
Event and the action, if any, which the Guarantor or such ERISA
Affiliate proposes to take with respect thereto;
(6) promptly and in any event within five Business Days after
receipt thereof by the Guarantor or any ERISA Affiliate, copies of
each notice received by the Guarantor or any ERISA Affiliate from
the PBGC stating its intention to terminate any Plan for which an
Insufficiency in excess of $50,000,000 exists or to have a trustee
appointed to administer any Plan for which an Insufficiency in
excess of $50,000,000 exists;
(7) promptly and in any event within five Business Days after
receipt thereof by the Guarantor or any ERISA Affiliate from the
sponsor of a Multiemployer Plan, a copy of each
notice received by the Guarantor or any ERISA Affiliate indicating
liability in excess of $50,000,000 incurred or expected to be
incurred by the Guarantor or any ERISA Affiliate in connection with
(A) the imposition of a Withdrawal Liability by a Multiemployer
Plan, (B) the determination that a Multiemployer Plan is, or is
expected to be, in reorganization within the meaning of Title IV of
ERISA, or (C) the termination of a Multiemployer Plan within the
meaning of Title IV of ERISA; and
(8) such other information respecting the Consolidated
financial position or Consolidated results of operations of the
Guarantor that BNS may from time to time reasonably request.
(b) COMPLIANCE WITH LAWS, ETC. Comply, and cause each of its
Subsidiaries to comply, with all applicable laws, rules, regulations and
orders to the extent noncompliance therewith would have a material adverse
effect on the Guarantor and its Subsidiaries taken as a whole, such
compliance to include, without limitation, the paying before the same
shall become due of all taxes, assessments and governmental charges
imposed upon it or upon its property except to the extent contested in
good faith by appropriate proceedings.
(c) MAINTENANCE OF INSURANCE. Maintain, and cause each of its
Principal Subsidiaries to maintain, insurance with responsible and
reputable insurance companies or associations in such amounts and covering
such risks as is usually carried by companies engaged in similar
businesses and owning similar properties as the Guarantor or such
Principal Subsidiary, PROVIDED, that self-insurance by the Guarantor or
any such Principal Subsidiary shall not be deemed a violation of this
covenant to the extent that companies engaged in similar businesses and
owning similar properties as the Guarantor or such Principal Subsidiary
self-insure. The Guarantor may maintain the Principal Subsidiaries'
insurance on behalf of them.
(d) PRESERVATION OF CORPORATE EXISTENCE, ETC. Preserve and maintain,
and cause each of its Principal Subsidiaries to preserve and maintain, its
corporate existence, rights (charter and statutory), and franchises;
PROVIDED, HOWEVER, that this SECTION 4.1(D) shall not apply to any
transactions permitted by SECTION 4.2(C) OR (D) and shall not prevent the
termination of existence, rights and franchises of any Principal
Subsidiary pursuant to any merger or consolidation to which such Principal
Subsidiary is a party, and PROVIDED, FURTHER, that the Guarantor or any
Principal Subsidiary shall not be required to preserve any right or
franchise if the Guarantor or such Principal Subsidiary shall determine
that the preservation thereof is no longer desirable in the conduct of the
business of the Guarantor or such Principal Subsidiary, as the
case may be, and that the loss thereof is not disadvantageous in any
material respect to BNS.
(e) VISITATION RIGHTS. At any reasonable time and from time to time,
after reasonable written notice, permit BNS or any agents or
representatives thereof to examine the records and books of account of,
and visit the properties of, the Guarantor and any of the Principal
Subsidiaries and to discuss the affairs, finances and accounts of the
Guarantor and any of the Principal Subsidiaries with any of the officers
of the Guarantor.
SECTION 4.2. NEGATIVE COVENANTS. The Guarantor covenants and agrees that,
so long as any portion of the Guaranteed Obligations shall remain unpaid or BNS
shall have any outstanding Commitment, the Guarantor will not, without the prior
written consent of BNS, do anything prohibited below:
(a) NEGATIVE PLEDGE. Fail to perform or observe any term, covenant,
or agreement contained in Section 5.01 or 5.02 of the Credit Agreement.
The terms, covenants, or agreements in Section 5.01 and 5.02 shall have
the same force and effect as if fully recited herein, shall be deemed to
have been made in favor of BNS, shall survive the termination or
expiration of the Credit Agreement (or the Guarantor's obligations
thereunder) and, notwithstanding any such termination or expiration of the
Credit Agreement (or the Guarantor's obligations thereunder), shall
continue to inure to the benefit of BNS. Any amendment or modification to
any of the terms, covenants, or agreements contained in Sections 5.01 and
5.02 of the Credit Agreement shall not be operative and shall have no
force and effect with respect to the Guarantor and BNS pursuant to this
Guaranty and such terms, covenants, and agreements contained in Sections
5.01 and 5.02 shall be deemed to remain as written without regard to any
such amendment or modification.
(b) TOTAL DEBT TO CAPITALIZATION. Have a ratio of (i) Total Debt to
(ii) Total Capitalization greater than 50%.
(c) DISPOSITION OF ASSETS. Lease, sell, transfer or otherwise
dispose of, voluntarily or involuntarily, all or substantially all of its
assets.
(d) MERGERS, ETC. Merge or consolidate with or into, any Person,
unless (1) the Guarantor is the survivor or (2) the surviving Person, if
not the Guarantor, is organized under the laws of the United States or a
state thereof and assumes all obligations of the Guarantor under this
Guaranty, PROVIDED, in each case that both immediately before and after
giving effect to such proposed transaction, no Event of Default or event
which, with the giving of notice or the lapse of time, or both, would
constitute an Event of Default exists, or would exist or result.
(e) COMPLIANCE WITH ERISA. (1) Terminate, or permit any ERISA
Affiliate to terminate, any Plan so as to result in any liability in
excess of $50,000,000 of the Guarantor or any ERISA Affiliate to the PBGC,
or (2) permit circumstances which give rise to a Termination Event
described in CLAUSES (B), (D) or (E) of the definition of Termination
Event with respect to a Plan so as to result in any liability in excess of
$50,000,000 of the Guarantor or any ERISA Affiliate to the PBGC.
ARTICLE V
EVENTS OF DEFAULT
SECTION 5.1. EVENTS OF DEFAULT. Each of the following events which shall
occur and be continuing shall constitute Events of Default:
(a) The Guarantor shall fail to pay any amount hereunder when due
and payable; or
(b) Any representation or warranty made by the Guarantor (or any of
its officers) under or in connection with this Guaranty shall prove to
have been incorrect in any material respect when made or deemed made and
such materiality is continuing; or
(c) The Guarantor shall fail to perform or observe any term,
covenant or agreement contained in SECTION 4.2 or shall fail to perform or
observe any other term, covenant or agreement contained herein on its part
to be performed or observed if, in the case of such other term, covenant
or agreement, such failure shall remained unremedied for 30 days after
written notice thereof shall have been given to the Guarantor by BNS; or
(d) The Guarantor or any Principal Subsidiary shall (1) fail to pay
any principal of or premium or interest on any Debt (other than Debt
described in CLAUSE (C) of the definition of Debt) which is outstanding in
the principal amount of at least $50,000,000 in the aggregate, of the
Guarantor or such Principal Subsidiary (as the case may be), when the same
becomes due and payable (whether by scheduled maturity, required
prepayment, acceleration, demand or otherwise), and such failure shall
continue after the applicable grace period, if any, specified in the
agreement or instrument relating to such Debt; or any other event shall
occur or condition shall exist under any agreement or instrument relating
to any such Debt and shall continue after the applicable grace period, if
any, specified in such agreement or instrument, if the effect of such
event or condition is to accelerate the maturity of such Debt; or any
such Debt shall be declared to be due and payable, or required to be
prepaid (other than by a regularly scheduled required prepayment or as a
result of the giving of notice of a voluntary prepayment), prior to the
stated maturity thereof, or (2) with respect to Debt described in CLAUSE
(C) of the definition of Debt, fail to pay any such Debt which is
outstanding in the principal amount of at least $50,000,000 in the
aggregate, of the Guarantor or such Principal Subsidiary (as the case may
be), when the same becomes due and payable, and such failure shall
continue after the applicable grace period, if any, specified in the
agreement or instrument relating to such Debt, or
(e) The Guarantor or any Principal Subsidiary shall generally not
pay its debts as such debts become due, or shall admit in writing its
inability to pay its debts generally, or shall make a general assignment
for the benefit of creditors; or any proceeding shall be instituted by or
against the Guarantor or any Principal Subsidiary seeking to adjudicate it
as bankrupt or insolvent, or seeking liquidation, winding up,
reorganization, arrangement, adjustment, protection, relief or composition
of it or its debts under any law relating to bankruptcy, insolvency or
reorganization or relief of debtors, or seeking the entry of an order for
relief or the appointment of a receiver, trustee or other similar official
for it or for any substantial part of its property and, in the case of any
such proceeding instituted against it (but not instituted by it), shall
remain undismissed or unstayed for a period of 60 days; or the Guarantor
or any Principal Subsidiary shall take any corporate action to authorize
any of the actions set forth above in this SUBSECTION (E); or
(f) Any judgment, decree or order for the payment of money in excess
of $50,000,000 shall be rendered against the Guarantor or any Principal
Subsidiary and shall remain unsatisfied and either (1) enforcement
proceedings shall have been commenced by any creditor upon such judgment,
decreed or order or (2) there shall be any period longer than (i) 30
consecutive days or (ii) such longer period as allowed by applicable law
during which a stay of enforcement of such judgment, decree or order, by
reason of a pending appeal or otherwise, shall not be in effect; or
(g) Any Termination Event as defined in CLAUSE (B), (D) or (E) of
the definition thereof with respect to a Plan shall have occurred and, 30
days after notice thereof shall have been given to the Guarantor by BNS,
(1) such Termination Event shall continue to exist and (2) the sum
(determined as of the date of occurrence of such Termination Event) of the
liabilities to the PBGC resulting from all such Termination Events is
equal to or greater than $100,000,000; or
(h) The Guarantor or any ERISA Affiliate shall have been notified by
the sponsor of a Multiemployer Plan that it has incurred Withdrawal
Liability to such Multiemployer Plan in an amount which, when aggregated
with all other amounts required to be paid to the Multiemployer Plan in
connection with Withdrawal Liabilities (determined as of the date of such
notification), exceeds $100,000,000 or requires payments exceeding
$50,000,000 in any year; or
(i) The Guarantor or any ERISA Affiliate shall have been notified by
the sponsor of a Multiemployer Plan that such Multiemployer Plan is in
reorganization or is being terminated, within the meaning of Title IV of
ERISA, if as a result of such reorganization or termination the aggregate
annual contributions of the Guarantor and its ERISA Affiliates to all
Multiemployer Plans which are then in reorganization or being terminated
have been or will be increased over the amounts contributed to such
Multiemployer Plans for the respective plan years which include the date
hereof by an amount exceeding $50,000,000 in the aggregate.
ARTICLE VI
MISCELLANEOUS PROVISIONS
SECTION 6.1. BINDING ON SUCCESSORS, TRANSFEREES AND ASSIGNS; ASSIGNMENT OF
GUARANTY. In addition to, and not in limitation of, SECTION 2.7, this Guaranty
shall be binding upon the Guarantor and its successors, transferees and assigns
and shall inure to the benefit of and be enforceable by BNS and each holder of a
Note and their respective successors and assigns (to the full extent provided
pursuant to SECTION 2.7); PROVIDED, HOWEVER, that the Guarantor may not assign
any of its obligations hereunder without the prior written consent of BNS and
each holder of a Note.
SECTION 6.2. AMENDMENTS, ETC. No amendment to or waiver of any provision
of this Guaranty, nor consent to any departure by the Guarantor herefrom, shall
in any event be effective unless the same shall be in writing and signed by BNS
and the Guarantor, and then such waiver or consent shall be effective only in
the specific instance and for the specific purpose for which given.
SECTION 6.3. ADDRESSES FOR NOTICES TO THE GUARANTOR. All notices and other
communications hereunder to the Guarantor shall be in writing and mailed or
delivered to it, addressed to it at the address set forth below its signature
hereto or at such other address as shall be designated by the Guarantor in a
written notice to BNS at
The Bank of Nova Scotia
273 Ponce de Leon Avenue
Hato Rey, Puerto Rico 00917
or such other address specified in a notice complying as to delivery with the
terms of this Section. All such notices and other communications shall, when
mailed, be effective when deposited in the mails, addressed as aforesaid.
SECTION 6.4. NO WAIVER; REMEDIES. In addition to, and not in limitation
of, SECTION 2.3 and SECTION 2.5, no failure on the part of BNS or any holder of
a Note to exercise, and no delay in exercising, any right hereunder shall
operate as a waiver thereof; nor shall any single or partial exercise of any
right hereunder preclude any other or further exercise thereof or the exercise
of any other right. The remedies herein provided are cumulative and not
exclusive of any remedies provided by law.
SECTION 6.5. SECTION CAPTIONS. Section captions used in this Guaranty are
for convenience of reference only, and shall not affect the construction of this
Guaranty.
SECTION 6.6. SEVERABILITY. Wherever possible each provision of this
Guaranty shall be interpreted in such manner as to be effective and valid under
applicable law, but if any provision of this Guaranty shall be prohibited by or
invalid under such law, such provision shall be ineffective to the extent of
such prohibition or invalidity, without invalidating the remainder of such
provision or the remaining provisions of this Guaranty.
SECTION 6.7. GOVERNING LAW. THIS GUARANTY SHALL BE GOVERNED BY
AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS.
IN WITNESS WHEREOF, the Guarantor has caused this Guaranty to be duly
executed and delivered by its officer thereunto duly authorized as of the date
first above written.
Enron Oil & Gas Company
By: /s/ Ben B. Boyd
Title: Vice President and Controller
Address: P. O. Box 1188, Houston, TX
77251-1188
Attention: Ben B. Boyd
Telex:_________________________
Telecopy: 713-646-2353
<TABLE>
<CAPTION>
Schedule 1
ENRON GAS & OIL TRINIDAD LIMITED
PRICING APPENDIX
Level I Level II Level III Level IV Level V Level VI
------- -------- --------- -------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
Basis for If the If the If the If the If the If the
Pricing Guarantor's Guarantor's Guarantor's Guarantor's Guarantor's Guarantor's
Senior Senior Senior Senior Senior Senior
Unsecured Unsecured Unsecured Unsecured Unsecured Unsecured
Long Term Long Term Long Term Long Term Long Term Long Term
Debt is rated Debt is rated Debt is rated Debt is rated Debt is rated Debt is rated
A or better BBB+ or better BBB by S&P BBB- by S&P BBB- by S&P BB+ or lower
by S&P OR A2 by S&P OR Baa1 AND Baa2 by OR Baa3 by AND Baa3 by by S&P AND Ba1
or better by or better by Moody's. Moody's. Moody's. or lower by
Moody's. Moody's. Moody's.
Commitment 12.5bp 15.0bp 17.5bp 20.0bp 25.0bp 37.5bp
Fee
LIBOR+ 37.5bp 50.0bp 55.0bp 62.5bp 75bp 112.5bp
936+ 37.5bp 50.0bp 55.0bp 62.5bp 75bp 112.5bp
</TABLE>
EXHIBIT 10.47
ENRON
OIL & GAS INTERNATIONAL, INC.
P. O. Box 4672 Houston, Texas 77210-4672 (713) 853-6161
Telex 765443 Answerback: ENRONCORP
December 18, 1994
Secretary of the Government of India
Ministry of Petroleum and Natural Gas
Shastri Bhavan
New Delhi 110 001
INDIA
Gentlemen:
Based upon my review of the records of Enron Oil & Gas International,
Inc. I have determined that the guarantees issued by it in favor of the
Government, pursuant to Article Twenty-nine of two certain Production Sharing
Contracts of even date, are legally valid and enforceable.
Very truly yours,
/s/ E. J. VANDERMARK
E. J. Vandermark
Legal Advisor
EXHIBIT 10.48
CERTIFICATE
ENRON OIL & GAS INDIA LTD., formerly known as ENRON INDIA EXPLORATION
COMPANY, pursuant to its articles of incorporation and by-laws, has, by the
unanimous consent of its directors, authorized its chairman, directors,
secretary, assistant secretary, proper officers and its counsel (any one of them
acting alone), to negotiate production sharing contracts for the Tapti, Panna
and Mukta Fields, offshore India, and to execute, deliver and perform for, in
the name of and on behalf of ENRON OIL & GAS INDIA LTD.
Dated this 22nd day of December 1994.
/s/ E. J. VANDERMARK
E. J. Vandermark
Assistant Secretary
EXHIBIT 10.49
FINANCIAL AND PERFORMANCE GUARANTEE
WHEREAS ENRON OIL & GAS INTERNATIONAL, INC., a Company duly organized and
existing under the laws of Delaware, U.S.A., having its registered office at
1400 Smith Street, Houston, Texas, U.S.A., (hereinafter referred to as "the
Guarantor" which expression shall include its successors and assigns) is the
indirect owner of 100% of the capital stock of ENRON OIL & GAS INDIA LIMITED
("Company") and direct owner of its parent company; and
WHEREAS Company is signatory to a Production Sharing Contract of even date of
this guarantee in respect of an Offshore area identified as Panna and Mukta
Fields (hereinafter referred to as "the Contract") made between the Government
of India (hereinafter referred to as "the Government"), Company, RELIANCE
INDUSTRIES LIMITED and OIL & NATURAL GAS CORPORATION LIMITED (hereinafter
referred to as "Contractor" which expression shall include its successors and
permitted assigns); and
WHEREAS the Guarantor wishes to guarantee the performance of Company or its
Affiliate Assignee under the Contract as required by the terms of the Contract;
NOW, THEREFORE, this Deed hereby provides as follows:
1. The Guarantor hereby unconditionally and irrevocably
guarantees to the Government that it will make available, or
cause to be made available, to Company or any other directly
or indirectly owned Affiliate of Company to which any part or
all of Company's rights or interest under the Contract may
subsequently be assigned ('Affiliate Assignee'), to ensure
that Company or any Affiliate Assignee can carry out its work
commitment as set forth in the Contract.
2. The Guarantor further unconditionally and irrevocably guarantees to the
Government reasonable compliance by Company or any Affiliate Assignee,
of any obligations of Company or any Affiliate Assignee under the
Contract.
3. The Guarantor hereby undertakes to the Government that if
Company, or any Affiliate Assignee, shall, in any respect,
fail to perform its work commitments under the Contract or
commit any material breach of such obligations, then the
Guarantor shall fulfill or cause to be fulfilled the
obligations in place of Company or any Affiliate Assignee, and
will indemnify the Government against all actual losses,
damages, costs, expenses, or otherwise which may result
directly from such failure to perform or breach on the part of
Company. In no event shall Guarantor be liable for any
special consequential, indirect, incidental or punitive
damages of any kind or character, including, but not limited
to, loss of profits or revenues, loss of product or loss of
use arising out of or related to a material breach by Company
of its obligations under the Contract.
4. This guarantee shall take effect from the Effective Date and shall
remain in full force and effect for the duration of the Contract and
thereafter until no sum remains payable by Company, or its Affiliate
Assignee, under the Contract or as a result of any decision or award
made by any expert or arbitration tribunal thereunder.
5. This guarantee shall not be affected by any change in the
Articles of Association and by-laws of Company or the Guarantor
or in any instrument establishing the Licensee.
6. The liabilities of the Guarantor shall not be discharged or
affected by (a) any time indulgence, waiver or consent given
to Company; (b) any amendment to the Contract or to any
security or other guarantee or indemnity to which Company has
agreed; (c) the enforcement or waiver of any terms of the
Contract or of any security, other guarantee or indemnity; or
(d) the dissolution, amalgamation, reconstruction or
reorganization of Company.
7. This guarantee shall be governed by and construed in accordance
with the laws of India.
IN WITNESS WHEREOF the Guarantor, through its duly authorized
representatives, has caused its seal to be duly affixed hereto and this
guarantee to be duly executed the 22nd day of December 1994.
The seal of Enron Oil and Gas International, Inc. was hereto duly affixed by
E. J. Vandermark this 22nd day of December 1994 in accordance with its by-laws
and this guarantee was duly signed by J. A. Kopecky and E. J. Vandermark as
required by the said by-laws.
/s/ E. J. VANDERMARK /s/ J. A. KOPECKY
E. J. Vandermark J. A. Kopecky
Asst. Secretary Vice President
Witness:
- -----------------------
EXHIBIT 10.50
JOINT OPERATING AGREEMENT
AMONG
OIL & NATURAL GAS CORPORATION LIMITED
AND
ENRON OIL & GAS INDIA LTD.
AND
RELIANCE INDUSTRIES LIMITED
WITH RESPECT TO CONTRACT AREA IDENTIFIED AS
PANNA AND MUKTA FIELDS
<PAGE>
TABLE OF CONTENTS
ARTICLE PAGE
I Definitions ........................................................... 1
II Effective Date and Term ............................................... 5
III Participating Interest ................................................ 6
3.1 Participating Interest ........................................... 6
3.2 Ownership, Obligations and Liabilities ........................... 6
IV Operator .............................................................. 6
4.1 Designation of Operator .......................................... 6
4.2 Rights and Duties of Operator .................................... 6
4.3 Employees of Operator ............................................ 8
4.4 Information Supplied by Operator ................................. 8
4.5 Settlement of Claims and Lawsuits ................................ 8
4.6 Liability of Operator ............................................ 9
4.7 Insurance Obtained by Operator ................................... 9
4.8 Commingling of Funds ............................................. 10
4.9 Resignation of Operator .......................................... 11
4.10 Removal of Operator ............................................. 11
4.11 Appointment of Successor ........................................ 11
V Operating Committee ................................................... 12
5.1 Establishment of Operating Committee ............................. 12
5.2 Powers and Duties of Operating Committee ......................... 12
5.3 Authority to Vote ................................................ 13
5.4 Subcommittees .................................................... 13
5.5 Notice of Meeting ................................................ 13
5.6 Contents of Meeting Notice ....................................... 13
5.7 Location and Frequency of Meetings ............................... 14
5.8 Operator's Duties for Meetings ................................... 14
5.9 Voting Procedure ................................................. 14
5.10 Record of Votes ................................................. 14
5.11 Minutes ......................................................... 14
5.12 Voting by Notice ................................................ 14
5.13 Effect of Vote .................................................. 15
VI Work Programs and Budgets ............................................. 16
6.1 Preparation of Work Program and Budget ........................... 16
6.2 Adoption of Work Program and Budget and
Submission to Management Committee ............................... 16
6.3 Subdivision of Work Program and
Budget Items and Transfers ....................................... 16
6.4 Fulfillment of Minimum Work Obligations .......................... 17
6.5 Exploration and Appraisal ........................................ 17
6.6 Development of New Discovery ..................................... 18
6.7 Itemization of Expenditures ...................................... 18
6.8 Contract Awards .................................................. 19
6.9 Authorization for Expenditure ("AFE") Procedure .................. 20
6.10 Supplementary AFEs .............................................. 21
6.11 Approval of AFEs ................................................ 21
6.12 Approval of AFE Not to be Unreasonably Withheld ................. 22
6.13 Overexpenditures of Work Programs and Budgets ................... 22
6.14 Work Program and Budget for Initial Period ...................... 22
VII Operations By Less Than All Parties ................................... 22
7.1 Limitation on Applicability ...................................... 22
7.2 Procedure to Propose Exclusive Operations ...................... 22
7.3 Responsibility for Exclusive Operations ........................ 23
7.4 Consequences of Exclusive Operations ........................... 24
7.5 Premium to Participate in Exclusive Operations ................. 25
7.6 Order of Preference of Operations .............................. 26
7.7 Stand-By Costs ................................................. 26
7.8 Special Considerations Regarding
Deepening and Sidetracking .................................... 27
7.9 Miscellaneous .................................................. 28
VIII Default ............................................................. 29
8.1 Default and Notice ............................................. 29
8.2 Operating Committee Meetings and Data .......................... 29
8.3 Allocation of Defaulted Accounts ............................... 29
8.4 Transfer of Interest ........................................... 30
8.5 Continuation of Interest ....................................... 31
8.6 Abandonment .................................................... 31
8.7 Sale of Hydrocarbons ........................................... 32
8.8 No Right of Set Off ............................................ 32
8.9 Minor Default .................................................. 32
8.10 Reinstatement of Rights ....................................... 32
IX Disposition of Production ........................................... 32
9.1 Right and Obligation to Take in Kind ........................... 32
9.2 Offtake Agreement for Crude Oil ................................ 33
9.3 Separate Agreement for Natural Gas ............................. 34
X Abandonment of Wells ................................................ 34
10.1 Abandonment of Wells Drilled as Joint Operations ............... 34
10.2 Abandonment of Exclusive Operations ............................ 34
XI Surrender ........................................................... 35
11.1 Surrender ...................................................... 35
XII Transfer of Interest or Rights ...................................... 35
12.1 Obligations .................................................... 35
12.2 Rights ......................................................... 36
XIII Withdrawal from Agreement by Transfer or Assignment ................. 36
13.1 Right of Withdrawal ............................................ 36
13.2 Partial or Complete Withdrawal ................................. 36
13.3 Voting ......................................................... 37
13.4 Obligations and Liabilities .................................... 37
13.5 Emergency ...................................................... 37
13.6 Assignment ..................................................... 37
13.7 Approvals ...................................................... 37
13.8 Abandonment Security ........................................... 37
13.9 Withdrawal or Abandonment by all Parties ....................... 38
XIV Relationship of Parties and Tax ..................................... 38
14.1 Relationship of Parties ........................................ 38
14.2 Tax ............................................................ 38
XV Confidential Information - Proprietary Technology ................... 38
15.1 Confidential Information ....................................... 38
15.2 Continuing Obligations ......................................... 39
15.3 Proprietary Technology ......................................... 39
15.4 Trades ......................................................... 39
XVI Force Majeure ....................................................... 39
16.1 Obligations .................................................... 39
16.2 Definition of Force Majeure .................................... 40
XVII Notices ............................................................. 40
XVIII Applicable Law and Dispute Resolution ............................... 41
18.1 Applicable Law ................................................. 41
18.2 Dispute Resolution ............................................. 41
XIX Allocation of Cost Recovery Rights .................................. 42
19.1 Allocation of Total Production ................................. 42
19.2 Allocation of Cost Petroleum ................................... 42
19.3 Allocation of Profit Petroleum ................................. 42
19.4 Allocation of Excess Cost Petroleum ............................ 42
XX General Provisions .................................................. 43
20.1 Conflicts of Interest .......................................... 43
20.2 Public Announcements ........................................... 43
20.3 Successors and Assigns ......................................... 43
20.4 Waiver ......................................................... 43
20.5 Severance of Invalid Provisions ................................ 44
20.6 Modifications .................................................. 44
20.7 Headings ....................................................... 44
20.8 Singular and Plural ............................................ 44
20.9 Gender ......................................................... 44
20.10 Counterpart Execution ......................................... 44
20.11 Conflict with Contract ........................................ 44
20.12 Entirety ...................................................... 44
Signature Page................................................. 44
Exhibit "A" - Accounting Procedure
Exhibit "B" - Description of Contract Area
Exhibit "C" - Example
Exhibit "D" - Budget Format
Exhibit "D-1" - Budget Summary
Exhibit "D-2" - Geophysical and Geological Expense
Exhibit "D-3" - Development Drilling (Firm Wells)
Exhibit "D-4" - Production Facilities Costs
Exhibit "D-5" - Production Costs
Exhibit "D-6" - General and Administrative Expense
Exhibit "D-7" - Fixed Assets and Deposits
Exhibit "D-8" - Revenue
Exhibit "E" - Data to be Provided to Non-Operators
<PAGE>
JOINT OPERATING AGREEMENT
THIS AGREEMENT is made as of the Effective Date among OIL & NATURAL GAS
CORPORATION LIMITED, having its registered office at Tower II, 8th Floor, Jeevan
Bharti, 124 Connaught Circus, New Delhi, 110 001, India, a company incorporated
in India (hereinafter referred to as "ONGC"); ENRON OIL & GAS INDIA LTD., a
company incorporated in the Cayman Islands, having its registered office at 1400
Smith Street, Houston, Texas, 77002, U.S.A. (hereinafter referred to as
"EOGIL"), a wholly owned subsidiary of ENRON EXPLORATION COMPANY; and RELIANCE
INDUSTRIES LIMITED, a company incorporated in India, having its registered
office at 3rd Floor, Maker Chamber IV, 222 Nariman Point, Bombay, 400 021, India
(hereinafter referred to as "RIL"). The companies named above may sometimes
individually be referred to as "Party" and collectively as the "Parties".
WITNESSETH:
WHEREAS, the Parties have entered into a Production Sharing Contract (the
"Contract") with the Government of India (hereinafter referred to as
"Government") covering certain areas located offshore India known as the Panna
and Mukta Fields, referred to as the "Contract Area", and more particularly
described in Exhibit B to this Agreement; and
WHEREAS, the Parties desire to define their respective rights and
obligations with respect to their operations under the Contract.
NOW, THEREFORE, in consideration of the premises and the mutual covenants
and agreements and obligations set out below and to be performed, the Parties
agree as follows:
ARTICLE I - DEFINITIONS
As used in this Agreement, the following words and terms shall have the
meaning ascribed to them below:
1.1 ACCOUNTING PROCEDURE means the rules, provisions and conditions set
forth and contained in Exhibit A to this Agreement.
1.2 AFE means an authorization for expenditure pursuant to Article 6.9.
1.3 AFFILIATE means a company that directly or indirectly controls or is
controlled by a Party to this Agreement or a company which directly
or indirectly controls or is controlled by a company which controls a
Party to this Agreement, it being understood that "control" means
ownership by one company of more than fifty percent (50%) of the
voting securities of the other company, or the power to direct,
administer and dictate policies of the other company even where the
voting securities held by such company exercising such effective
control in that other company is less than fifty percent (50%) and
the term "controlled" shall have a corresponding meaning.
1.4 AGREED INTEREST RATE means interest, compounded on a monthly basis,
at the rate per annum equal to the one (1) month term, LIBOR rate for
U.S. dollar deposits, as published by THE WALL STREET JOURNAL or if
not published, then by the FINANCIAL TIMES OF LONDON, plus fixed
amounts as specified in Article 8.1, applicable on the first Business
Day prior to the due date of payment and thereafter on the first
Business Day of each succeeding one (1) month term. If the aforesaid
rate is contrary to any applicable usury law, the rate of interest to
be charged shall be the maximum rate permitted by such applicable
law.
1.5 AGREEMENT means this Agreement, together with the Exhibits attached
to this Agreement.
1.6 APPRAISAL WELL means any well whose purpose at the time of
commencement of drilling such well is the determination of the extent
or the volume of Hydrocarbon reserves contained in a New Discovery or
an Existing Discovery.
1.7 BARREL means a quantity consisting of forty-two (42) United States
gallons, corrected to a temperature of sixty (60) degrees Fahrenheit
under one (1) atmosphere of pressure.
1.8 BUSINESS DAY means a day on which the banks in India are open for
business and carrying out normal business transactions.
1.9 CALENDAR QUARTER means a period of three (3) months commencing with
January 1st and ending on the following March 31st, a period of three
(3) months commencing with April 1st and ending on the following June
30th, a period of three (3) months commencing with July 1st and
ending on the following September 30th, or a period of three (3)
months commencing with October 1st and ending on the following
December 31st according to the Gregorian Calendar.
1.10 CALENDAR YEAR means a period of twelve (12) months commencing with
January 1st and ending on the following December 31st according to
the Gregorian Calendar.
1.11 CASH CALL means any request for payment of cash made by the Operator,
in accordance with this Agreement, an approved Work Program and
Budget, AFEs (wherever applicable) and progress of the work, to the
Parties in connection with the Joint Operations. The Cash Call format
(Exhibit "C") may be revised by the Operating Committee.
1.12 CASH PREMIUM means the payment made pursuant to Article 7.5(B) by a
Non-Consenting Party to reinstate its rights to participate in an
Exclusive Operation.
1.13 COMMERCIAL DISCOVERY means a Discovery of Petroleum reserves which,
when produced, are likely to yield a reasonable profit on the funds
invested in petroleum operations, after deduction of Contract costs,
and which has been declared a Commercial Discovery in accordance with
the provisions of Article 9 and/or Article 21 of the Contract, after
consideration of all pertinent operating and financial data such as
recoverable reserves, sustainable production levels, estimated
development and production expenditures, prevailing prices and other
relevant technical and economic factors according to generally
accepted practices in the international petroleum industry.
1.14 COMPLETION means an operation intended to complete a well through the
Christmas tree as a producer of Hydrocarbons in one or more Zones,
including, but not limited to, the setting of production casing,
perforating, stimulating the well and production testing conducted in
such operation. COMPLETE and other derivatives shall be construed
accordingly.
1.15 CONSENTING PARTY means a Party who agrees to participate in and pay
its share of the cost of an Exclusive Operation.
1.16 CONTRACT means the Production Sharing Contract dated between the
Government and the Parties identified in this Agreement and any
extension, renewal or amendment thereof agreed to in writing by the
Parties.
1.17 CONTRACT AREA means as of the Effective Date the area which is
described and delineated in Exhibit B to this Agreement. The
perimeter or perimeters of the Contract Area shall correspond to that
area covered by the Contract, as such area may vary from time to time
during the term of validity of the Contract.
1.18 COST PETROLEUM means the portion of the total volume of Petroleum
produced and saved from the Contract Area which the Contractor is
entitled to take from the Contract Area in a particular period for
the recovery of Contract costs as provided in Article 13 of the
Contract.
1.19 DAY means a calendar day unless otherwise specifically provided.
1.20 DEFAULTING PARTY shall have the meaning ascribed in Article 8.1.
1.21 DEEPENING means an operation whereby a well is drilled to an
objective Zone below the deepest Zone in which the well was
previously drilled, or below the deepest Zone proposed in the
associated AFE, whichever is the deeper. DEEPEN and other derivatives
shall be construed accordingly.
1.22 DELIVERY POINT shall have the meaning given in the Contract.
1.23 DEVELOPMENT AREA means that part of the Contract Area corresponding
to the area of an Oil Field or Gas Field delineated in simple
geometric shape, together with a reasonable margin of additional area
surrounding the Field consistent with petroleum industry practice and
approved by the Management Committee or the Government, as the case
may be.
1.24 DEVELOPMENT PLAN means a plan submitted by the Contractor containing
proposals required under Article 9 or Article 21 of the Contract for
the development of a Commercial Discovery which has been approved by
the Management Committee or Government.
1.25 DEVELOPMENT WELL means a well drilled, deepened, completed or
Recompleted after the date of approval of the Development Plan
pursuant to development operations or production operations for the
purposes of producing Petroleum, increasing production, sustaining
production or accelerating extraction of Petroleum including
production wells, injection wells and dry wells.
1.26 DISCOVERY means the finding, during exploration operations, of a
deposit of Petroleum not previously known to have existed, which can
be recovered at the surface in a flow measurable by conventional
petroleum industry testing methods.
1.27 EFFECTIVE DATE means the date of signing of the Contract by all
parties thereto.
1.28 ENTITLEMENT means a quantity of Hydrocarbons of which a Party has the
right and obligation to take delivery pursuant to the Contract or, if
applicable, an offtake agreement, and shall be derived from that
Party's Participating Interest in the Hydrocarbons produced after
adjustment for overlifts and underlifts.
1.29 EXCESS COST PETROLEUM shall have the meaning ascribed in Article
19.4.
1.30 EXCLUSIVE OPERATION means those operations and activities carried out
by Operator, pursuant to this Agreement, the costs of which are
chargeable to the account of less than all the Parties.
1.31 EXCLUSIVE WELL means a well drilled pursuant to an Exclusive
Operation.
1.32 EXPLOITATION AREA means the Development Area which is established
pursuant to the Contract or if the Contract does not establish an
Exploitation Area, then that part of the Contract Area which is
delineated in a Development Plan approved as a Joint Operation or as
an Exclusive Operation.
1.33 EXPLOITATION PERIOD means any and all periods of exploitation during
which the production and removal of Hydrocarbons is permitted under
the Contract.
1.34 EXPLORATION PERIOD means any and all periods of exploration set out
in the Contract.
1.35 EXPLORATION WELL means a well drilled for the purpose of searching
for undiscovered Hydrocarbon accumulations on any geological entity
(be it of structural,stratigraphic, facies or pressure nature) to at
least a depth or stratigraphic level specified in the Work Program
and Budget.
1.36 FIELD means an Oil Field or a Gas Field in the Contract Area in
respect of which a Development Plan has been duly approved in
accordance with Article 9 and Article 21 of the Contract.
1.37 FINANCIAL YEAR means the period from April 1st through March 31st of
the following Calendar Year.
1.38 G & G DATA means only geological, geophysical and geochemical data
and other information that is not obtained through a well bore.
1.39 GAS FIELD means an area within the Contract Area consisting of a
single Gas reservoir or multiple Gas reservoirs all grouped on or
related to the same individual geological structure or stratigraphic
conditions, designated by the Contractor and approved by the
Government and/or Management Committee, as the case may be (to
include the maximum area of potential productivity in the Contract
Area in a simple geometric shape) in respect of which a Commercial
Discovery has been declared or a Development Plan has been approved
in accordance with Article 9 or Article 21 of the Contract.
1.40 GOVERNMENT means the Government of India and/or any state government
as the case may be.
1.41 GROSS NEGLIGENCE means any act or failure to act (whether sole, joint
or concurrent) which was intended to cause, or which was in reckless
disregard of or wanton indifference to, harmful consequences such
Party knew, or should have known, such act or failure would have had
on the safety or property of another person or entity, but shall not
include any error of judgment or mistake made by such Party in the
exercise in good faith of any function, authority or discretion
conferred on the Party employing such under this Agreement.
1.42 HYDROCARBONS means all substances including liquid and gaseous
hydrocarbons which are subject to and covered by the Contract.
1.43 JOINT ACCOUNT means the accounts maintained by Operator in accordance
with the provisions of this Agreement and of the Accounting Procedure
for Joint Operations.
1.44 JOINT OPERATIONS means those operations and activities carried out by
Operator pursuant to this Agreement, the costs of which are
chargeable to all Parties.
1.45 JOINT PROPERTY means, at any point in time, all wells, facilities,
equipment, materials, information, funds and the property held for
the Joint Account.
1.46 MANAGEMENT COMMITTEE means the committee constituted pursuant to
Article 5 of the Contract.
1.47 MINIMUM WORK OBLIGATIONS means those items contained in Exhibit "G"
of the Contract, phased year-wise as determined by the Operating
Committee and the Management Committee.
1.48 NEW DISCOVERY means a Discovery made after the Effective Date.
1.49 NON-CONSENTING PARTY means a Party who elects not to participate in
an Exclusive Operation.
1.50 NON-OPERATOR(S) means the Party or Parties to this Agreement other
than Operator.
1.51 OIL FIELD means an area within the Contract Area consisting of a
single oil reservoir or multiple oil reservoirs all grouped on or
related to the same individual geological structure, or stratigraphic
conditions, designated by the Contractor and approved by the
Government and/or the Management Committee, as the case may be (to
include the maximum area of potential productivity in the Contract
Area in a simple geometric shape) in respect of which a Commercial
Discovery has been declared and a Development Plan has been approved
in accordance with Article 9 of the Contract and a reference to an
Oil Field shall include a reference to the production of associated
natural gas from that Oil Field.
1.52 OPERATING COMMITTEE means the committee constituted in accordance
with Article V.
1.53 OPERATOR means the Party designated or otherwise appointed under
Article 4.1 to conduct Joint Operations or any successor appointed
pursuant to Article 4.11.
1.54 PARTICIPATING INTEREST means the undivided percentage interest of
each Party in the rights and obligations derived from the Contract
and this Agreement.
1.55 PARTY means any Party to this Agreement and, where the Contract so
permits, any respective successors or assigns in accordance with the
provisions of this Agreement.
1.56 PETROLEUM means crude oil and/or natural gas existing in their
natural condition (Hydrocarbons).
1.57 PETROLEUM COSTS means costs and expenses incurred by the Parties and
allowed to be recovered pursuant to the Contract.
1.58 PLUGGING BACK means a single operation whereby a deeper Zone is
abandoned in order to attempt a Completion in a shallower Zone. Plug
Back and other derivatives shall be construed accordingly.
1.59 PRODUCTION COSTS means those costs and expenditures incurred in
carrying out production operations as classified and defined in
Section 2 of the Accounting Procedure of the Contract and allowed to
be recovered in terms of Section 3 thereof.
1.60 PROFIT PETROLEUM means Petroleum produced and saved from the Contract
Area in a particular period as reduced by Cost Petroleum and
calculated as provided in Article 14 of the Contract.
1.51 RECOMPLETION means an operation whereby a Completion in one Zone is
abandoned in order to attempt a Completion in a different Zone within
the existing wellbore. RECOMPLETE and other derivatives shall be
construed accordingly.
1.62 REWORKING means an operation conducted in the wellbore of a well
after it is Completed to secure, restore or improve production in a
Zone which is currently open to production in the wellbore. Such
operations include, but are not limited to, well stimulation
operations, wire line operations, hydraulic pump-down operations,
water shut off operations, coil tubing operations, but excluding any
routine maintenance work. REWORK and other derivatives shall be
construed accordingly.
1.63 SIDETRACKING means the directional control and intentional deviation
of a well from vertical so as to change the bottom hole location
unless done to straighten the hole or to drill around junk in the
hole or to overcome other mechanical difficulties. SIDETRACK and
other derivatives shall be construed accordingly.
1.64 SUPERVISORY PERSONNEL means any supervisory employee of a Party who
functions as a Party's designated manager or supervisor who is
responsible for, or in charge of onsite drilling, construction or
production and related operations, or any other field operations.
1.65 TESTING, with reference to a well, means an operation intended to
evaluate the capacity of a Zone to produce Hydrocarbons. TEST and
other derivatives shall be construed accordingly.
1.66 WILLFUL MISCONDUCT means in relation to the Operator intentional and
conscious or reckless disregard by supervisory or management staff of
the Operator of the terms of this Agreement or of good international
oil field practice but shall not include any act or omission
reasonably required to meet emergency conditions, including without
limitation the safeguarding of life, property and Joint Operations or
for the avoidance of doubt any error of judgment or mistake made by
any director, employee, agent or contractor of Operator in the
exercise, in good faith of any function, authority or discretion
conferred upon the Operator.
1.67 WORK PROGRAM AND BUDGET means a work program for Joint Operations and
budget therefor, including the production plan, as described and
approved in accordance with Article VI and as illustrated in Exhibit
"D". Exhibit "D" may be modified by the Operating Committee.
1.68 ZONE means a stratum of earth containing or thought to contain a
common accumulation of Hydrocarbons separately producible from any
other common accumulation of Hydrocarbons.
ARTICLE II - EFFECTIVE DATE AND TERM
This Agreement shall have effect from the 22 day of December, 1994 and
shall, subject always to the Parties' continuing obligations under Article XV,
continue in effect until the Contract terminates or, otherwise until all
materials, equipment and personal property used in connection with the Joint
Operations have been removed and disposed of, and final settlement has been made
among the Parties.
For the avoidance of doubt, portions of this Agreement as described in (A),
(B) and (C) below shall remain in effect until:
(A) all wells have been properly abandoned in accordance with Article X;
and
(B) all obligations, claims, arbitrations and lawsuits have been settled
or otherwise disposed of in accordance with Article 4.5 and Article
XVIII; and
(C) the time relating to the protection of confidential information and
proprietary technology has expired in accordance with Article XV.
The scope and purpose of the Joint Operations are to carry out the
petroleum operations as per Contract. As defined in the Contract, petroleum
operations means, as the context may require, exploration operations,
development operations or production operations or any combination of such
operations, including, but not limited to, collection of seismic information,
drilling and completion and recompletion of wells, construction, operation and
maintenance of all necessary facilities, plugging and abandonment of wells,
environmental protection, transportation, storage or disposition of Petroleum to
the Delivery Point, site restoration and all other incidental operations or
activities as may be necessary.
ARTICLE III - PARTICIPATING INTEREST
3.1 PARTICIPATING INTEREST
(A) The Participating Interests of the Parties as of the Effective Date
are:
ONGC 40%
EOGIL 30%
RIL 30%
(B) If a Party transfers all or part of its Participating Interest
pursuant to the provisions of this Agreement and the Contract, the
Participating Interests of the Parties shall be revised accordingly.
3.2 OWNERSHIP, OBLIGATIONS AND LIABILITIES
(A) Unless otherwise provided in this Agreement, all the rights and
interests in and under the Contract, all Joint Property and any
Hydrocarbons produced from the Contract Area shall, subject to the
terms of the Contract, be owned by the Parties in accordance with
their respective Participating Interests.
(B) Unless otherwise provided in this Agreement, the obligations of the
Parties under the Contract and all liabilities and expenses incurred
by Operator in connection with Joint Operations shall be charged to
the Joint Account and all credits to the Joint Account shall be
shared by the Parties, as among themselves, in accordance with their
respective Participating Interests.
(C) Unless otherwise provided in this Agreement, all liabilities incurred
by any Party in connection with Joint Operations shall be borne by
the Parties in accordance with their respective Participating
Interests.
(D) Each Party shall pay when due, in accordance with the Accounting
Procedure, its Participating Interest share of Joint Account
expenses, including cash advances and interest, accrued pursuant to
this Agreement. The Accounting Procedure shall govern the accrual and
satisfaction of the respective obligations, liabilities and credits
among the Parties.
ARTICLE IV - OPERATOR
4.1 DESIGNATION OF OPERATOR
EOGIL is designated as Operator, and agrees to act as an Operator in
accordance with the terms and conditions of the Contract and this
Agreement, which terms and conditions shall also apply to any
successor Operator.
4.2 RIGHTS AND DUTIES OF OPERATOR
(A) Subject to the terms and conditions of this Agreement, Operator shall
have all of the rights, functions and duties of Operator under the
Contract and shall have exclusive charge of and shall conduct all
Joint Operations. Operator may employ independent contractors,
Affiliates and/or agents in such Joint Operations. Contracts will be
awarded pursuant to Article 6.8.
(B) In the conduct of Joint Operations, Operator shall:
(1) Perform Joint Operations in accordance with the provisions
of the Contract, this Agreement and the instructions of the
Operating Committee;
(2) Conduct all Joint Operations in a diligent, safe and
efficient manner in accordance with good and prudent
international petroleum industry practices and conservation
principles generally followed by the international petroleum
industry under similar circumstances;
(3) Subject to Article 4.6, neither gain a profit nor suffer a
loss as a result of being the Operator in its conduct of
Joint Operations;
(4) Perform the duties for the Operating Committee set out in
Article V, and prepare and submit to the Operating Committee
the proposed Work Programmes and Budgets and AFEs as
provided in Article VI;
(5) Acquire all permits, consents, approvals, surface or other
rights that may be required for or in connection with the
conduct of Joint Operations;
(6) Permit the representatives of any of the Parties to have at
all reasonable times and at their own risk and expense
reasonable access to the Joint Operations with the right to
observe all such Joint Operations and to inspect all Joint
Property and to conduct financial audits as provided in the
Accounting Procedure. In the case of offshore operations,
transportation and accommodations shall be made available
from existing facilities if, in the sole discretion of
Operator, no additional cost will be incurred by Operator.
In addition, provide for two (2) permanent representatives
of each of the Non-Operators to have access to the Contract
Area and/or to the Joint Operations at all times and provide
all facilities including, but not limited to, transportation
and offshore accommodations at the cost of the Joint
Operations. Such representatives shall look after the
interests of Non-Operators/Joint Operation, but shall not
interfere with operations;
(7) Maintain the Contract in full force and effect. Operator
shall promptly pay and discharge all liabilities and
expenses incurred in connection with Joint Operations and
use its reasonable efforts to keep and maintain the Joint
Property free from all liens, charges and encumbrances
arising out of Joint Operations;
(8) Pay to the Government for the Joint Account, within the
periods and in the manner prescribed by the Contract and all
applicable laws and regulations, all periodic payments,
royalties, taxes, fees and other payments pertaining to
Joint Operations, but excluding any taxes measured by the
incomes of the Parties;
(9) Carry out the obligations of Operator pursuant to the
Contract, including, but not limited to, preparing and
furnishing such reports, records and information as may be
required pursuant to the Contract;
(10) Have in accordance with the decisions of the Operating
Committee, the exclusive right and obligation to represent
the Parties in all dealings with the Government with respect
to matters arising under the Contract and Joint Operations.
Operator shall notify the other Parties as soon as possible
of such meetings. Non-Operators shall have the right to
attend such meetings. Nothing contained in this Agreement
shall restrict any Party from holding discussions with the
Government with respect to any issue peculiar to its
particular business interests arising under this Agreement,
but in such event such Party shall promptly advise the
Parties, if possible, before and in any event promptly after
such discussions, provided that such Party shall not be
required to divulge to the Parties any matters discussed to
the extent the same involve proprietary information on
matters not affecting the Parties; and
(11) Take all necessary and proper measures for the protection of
life, health, the environment and property in the case of an
emergency; provided, however, that Operator shall
immediately notify the Parties of the details of such
emergency and measures.
(12) Include, to the extent practical, in its contracts with
independent contractors and to the extent lawful, provisions
which:
(a) ensure such contractors can only enforce their
contracts against Operator;
(b) permit Operator, on behalf of itself and Non-Operators,
to enforce contractual indemnities against, and recover
losses and damages suffered by them (insofar as
recovered under their contracts) from such contractors;
and
(c) require such contractors to take insurance required by
Article 4.7(F).
(13) Carry out all Petroleum operations as per the standard
offshore safety practices following the environmental/mining
regulations/statutory laws.
(14) Provide liaison between field operations and gas/oil
purchasers and transporters.
4.3 EMPLOYEES OF OPERATOR
Subject to the Contract and this Agreement, Operator shall determine the
number of employees, the selection of such employees, the hours of work and the
compensation to be paid to all such employees in connection with Joint
Operations. Operator shall employ only such employees, agents and contractors as
are reasonably necessary to conduct Joint Operations.
4.4 INFORMATION SUPPLIED BY OPERATOR
(A) Operator shall provide Non-Operators the following data and reports
as they are currently produced or compiled from the Joint Operations
as well as the reports listed in Exhibit "E":
(1) Copies of all logs or surveys;
(2) Daily drilling progress reports;
(3) Copies of all drill stem tests and core analysis reports;
(4) Copies of the plugging reports;
(5) Engineering studies, development schedules and annual
progress reports on development projects;
(6) Field and well performance reports, including reservoir
studies;
(7) Copies of all reports and data relating to Joint
Operations furnished by Operator to the Government, except
magnetic tapes which shall be stored by Operator and made
available for inspection and/or copying at the sole
expense of the Non-Operator requesting same;
(8) Other reports as frequently as is justified by the
activities or as instructed by the Operating Committee;
and
(9) Subject to Article 15.3, such additional information for
Non- Operators as they or any of them may request,
provided that the requesting Party or Parties pay the
costs of preparation of such information and that the
preparation of such information will not unduly burden
Operator's administrative and technical personnel. Only
Non-Operators who pay such costs shall receive such
additional information.
(B) Operator shall give Non-Operators access at all reasonable times to
all other data acquired in the conduct of Joint Operations. Any Non-
Operator may make copies of such other data at its sole expense.
(C) ONGC shall provide all of the information identified above and
currently in its possession relating to the Contract Area to the
Operator upon payment of mutually agreed costs.
4.5 SETTLEMENT OF CLAIMS AND LAWSUITS
(A) Operator shall promptly notify the Parties of any and all material
claims or suits and such other claims and suits as the Operating
Committee may direct which arise out of Joint Operations or relate in
any way to Joint Operations. Operator shall represent the Parties and
defend or oppose the claim or suit. Operator may in its sole
discretion compromise or settle any such claim or suit or any related
series of claims or suits for an amount not to exceed the equivalent
of U.S. dollars fifty thousand (US$50,000) exclusive of legal fees.
Operator shall obtain the approval and direction of the Operating
Committee on amounts in excess of the above stated amount. Each
Non-Operator shall have the right to be represented by its counsel at
its expense in the settlement, compromise or defense of such claims
or suits.
(B) Any Non-Operator shall promptly notify the other Parties of any claim
made against such Non-Operator by a third party relating to or which
may affect the Joint Operations and insofar as such claim relates to
or affects the Joint Operations such Non-Operator shall defend or
settle the same in accordance with any directions given by the
Operating Committee and such costs, expenses and damages as are
payable pursuant to such defense or settlement shall be for the Joint
Account.
(C) Notwithstanding Article 4.5(A) and Article 4.5(B), each Party shall
have the right to participate in any such pursuit, prosecution,
defense or settlement conducted in accordance with Article 4.5(A)
and/or Article 4.5(B) at its sole cost and expense; provided always
that no Party may settle its Participating Interest share of any
claim without first satisfying the Operating Committee that it can do
so without prejudicing the interests of the Joint Operations.
4.6 LIABILITY OF OPERATOR
(A) Except as set out in this Article 4.6, the Party designated as
Operator shall bear no cost, expense or liability resulting from
performing the duties and functions of the Operator. Nothing in this
Article shall, however, be deemed to relieve the Party designated as
Operator from any cost, expense or liability for its Participating
Interest share of Joint Operations.
(B) The Parties shall be liable in proportion to their Participating
Interests and shall defend and indemnify Operator, Non-Operator and
their agents, employees, officers and directors (the "Indemnitees")
from any and all costs, expenses (including reasonable attorneys'
fees) and liabilities incident to claims, demands or causes of action
of every kind and character brought by or on behalf of any person or
entity for damage to or loss of property or the environment, or for
injury to, illness or death of any person or entity, which damage,
loss, injury, illness or death arises out of or is incident to any
act or failure to act by Indemnitees in the conduct of or in
connection with Joint Operations regardless of the cause of such
damage, loss, injury, illness or death and even though caused in
whole or in part by a pre-existing defect, the negligence (whether
sole, joint or concurrent), Gross Negligence, strict liability or
other legal fault of Operator or Non- Operator (or any such Affiliate
performing services for Operator or Non- Operator pursuant to
Sections 2.4.2 and 3 of the Accounting Procedure); provided that if
any Supervisory or management Personnel of Operator or Non-Operator
or any such Affiliates, engage in Gross Negligence and/or Willful
Misconduct that proximately causes the Parties to incur cost, expense
or liability for such damage, loss, injury, illness or death, then
Operator or Non-Operator, as the case may be, shall bear all such
costs, expenses and liabilities.
4.7 INSURANCE OBTAINED BY OPERATOR
(A) Operator shall procure and maintain or cause to be procured and
maintained for the Joint Account all insurance in the types and
amounts required by the Contract and applicable laws, rules and
regulations.
(B) Operator shall obtain such further insurance, at competitive rates,
as the Operating Committee may from time to time require.
(C) Any Party may elect not to participate in the insurance to be
procured under Article 4.7(B) provided such Party:
(1) gives prompt written notice to that effect to Operator;
(2) does nothing which may interfere with Operator's
negotiations for such insurance for the other Parties; and
(3) obtains and maintains such insurance (in respect of which an
annual certificate of adequate coverage from a reputable
insurance broker shall be sufficient evidence) or other
evidence of financial responsibility which fully covers its
Participating Interest share of the risks that would be
covered by the insurance procured under Article 4.7 (B), and
which the Operating Committee may determine to be
acceptable. No such determination of acceptability shall in
any way absolve a non-participating Party from its
obligation to meet each cash call including any cash call in
respect of damages and losses and/or the costs of remedying
the same in accordance with the terms of this Agreement. If
such Party obtains other insurance, such insurance shall
contain a waiver of subrogation in favor of all the other
Parties, but only in respect of their interests under this
Agreement.
(D) The cost of insurance in which all the Parties are participating
shall be for the Joint Account and the cost of insurance in which
less than all the Parties are participating shall be charged to the
Parties participating in proportion to their respective Participating
Interests.
(E) Operator shall, in respect of all insurance obtained pursuant to this
Article:
(1) promptly inform the participating Parties when such
insurance is obtained and supply them with copies of the
relevant policies when the same are issued;
(2) arrange for the participating Parties, according to their
respective Participating Interests, to be named as
co-insureds on the relevant policies with waivers of
subrogation in favor of all the Parties; and
(3) duly file all claims and take all necessary and proper steps
to collect any proceeds and credit any proceeds to the
participating Parties in proportion to their respective
Participating Interests.
(F) Operator shall use its reasonable efforts to require all contractors
performing work in respect of Joint Operations to obtain and maintain
any and all insurance in the types and amounts required by any
applicable laws, rules and regulations or any decision of the
Operating Committee and shall use its reasonable efforts to require
all such contractors to name the Parties as additional insureds on
contractor's insurance policies or to obtain from their insurers
waivers of all rights or recourse against Operator and Non-Operators.
4.8 COMMINGLING OF FUNDS
Operator shall not commingle with its funds the monies which it receives
for the Joint Account pursuant to this Agreement. The Operator shall account to
the Non-Operators for the monies of a Non-Operator advanced or paid to Operator,
whether for the conduct of Joint Operations or as proceeds from the sale of
production under this Agreement. Such monies shall be applied only to their
intended use and shall in no way be deemed to be funds belonging to Operator.
The Operator shall open and maintain dedicated current and/or deposit accounts
in respect of funds in Indian Rupees, United States Dollars and/or any other
currency at a bank or banks in India, the United States or elsewhere, in order
to deposit and hold funds on behalf of the Parties exclusively for Joint
Operations. Where possible, such accounts shall be interest bearing.
Upon opening a bank account, the Operator shall notify the Non- Operators
the name and address of the bank and the account number. Any changes thereafter
should be promptly notified by the Operator to the Non-Operators.
4.9 RESIGNATION OF OPERATOR
Subject to Article 4.11, Operator may resign as Operator at any time after
completion of the Minimum Work Obligation, unless the Parties agree to an
earlier date, by so notifying the other Parties at least one hundred and twenty
(120) Days prior to the effective date of such resignation.
4.10 REMOVAL OF OPERATOR
(A) Subject to Article 4.11, Operator shall be removed upon receipt of
notice from any Non-Operator if:
(1) An order is made by a court or an effective resolution is
passed for the dissolution, liquidation, winding up, or
reorganization of Operator;
(2) Operator dissolves, liquidates or terminates its corporate
existence;
(3) Operator becomes insolvent, bankrupt or makes an assignment
for the benefit of creditors; or
(4) A receiver is appointed for a substantial part of Operator's
assets.
(5) Operator, together with any Affiliate of Operator, is or
becomes the holder of a Participating Interest of less then
twenty percent (20%).
(6) There is a direct or indirect change in control of Operator
(other than a transfer of control to an Affiliate of
Operator). For purposes of this Article control means the
ownership directly or indirectly of more than fifty percent
(50%).
(B) Subject to Article 4.11, Operator may be removed by the decision of
the Non-Operators if Operator has committed a material breach of this
Agreement which Operator has failed to rectify within ninety (90)
Days of receipt of a notice from Non-Operators detailing the alleged
breach.
Any decision of Non-Operators to give notice of breach to Operator
or to remove Operator under this Article 4.10(B) shall be made by an
affirmative vote of two (2) or more of the total number of
Non-Operators holding a combined Participating Interest of at least
fifty percent (50%). Notwithstanding the above, in case of
disagreement between the Non- Operators on giving notice to the
Operator, any Non-Operator may, with the approval of the Government,
give notice to the Operator. 4.11 APPOINTMENT OF SUCCESSOR When a
change of Operator occurs pursuant to Article 4.9 or Article 4.10:
(A) The Operating Committee shall meet as soon as possible to appoint a
successor Operator pursuant to the voting procedure of Article 5.9.
However, no Party may be appointed successor Operator against its
will.
(B) If the Operator disputes commission of or failure to rectify a
material breach alleged pursuant to Article 4.10(B) and proceedings
are initiated pursuant to Article XVIII, no successor Operator may be
appointed pending the conclusion or abandonment of such proceedings
provided, however, if the arbitrators determine that the Joint
Operations are likely to suffer material and/or irreparable harm,
they shall have the right to issue an interim order suspending the
Operator and appointing a successor Operator.
(C) If an Operator is removed neither Operator nor any Affiliate of
Operator shall have the right to vote for itself on the appointment
of a successor Operator, nor be considered as a candidate for the
successor Operator.
(D) A resigning or removed Operator shall be compensated out of the Joint
Account for its reasonable expenses directly related to its
resignation or removal, except in the case of Article 4.10.
(E) The Operating Committee shall arrange for the taking of an
independent inventory of all Joint Property and Hydrocarbons, and an
audit of the books and records of the removed or resigned Operator.
Such inventory and audit shall be completed, if possible, no later
than the effective date of the change of Operator. The liabilities
and expenses of such inventory and audit shall be charged to the
Joint Account.
(F) The resignation or removal of Operator and its replacement by the
successor Operator shall not become effective prior to receipt of any
necessary governmental approvals.
(G) Upon the effective date of the resignation or removal, the successor
Operator shall succeed to all duties, rights and authority prescribed
for Operator. The former Operator shall transfer to the successor
Operator custody of all Joint Property, books of account, records and
other documents maintained by Operator pertaining to the Contract
Area and to Joint Operations. Upon delivery of the above-described
property and data, the former Operator shall be released and
discharged from all obligations and liabilities as Operator accruing
after such date.
ARTICLE V - OPERATING COMMITTEE
5.1 ESTABLISHMENT OF OPERATING COMMITTEE
To provide for the overall supervision and direction of Joint Operations,
there is established an Operating Committee composed of representatives of each
Party holding a Participating Interest. Each Party shall appoint one (1)
representative and one (1) alternate representative to serve on the Operating
Committee. Each Party shall as soon as possible after the date of this Agreement
give notice in writing to the other Parties of the name and address of its
representative and alternate representative to serve on the Operating Committee.
Each Party shall have the right to change its representative and alternate at
any time by giving proper notice to such effect to the other Parties.
5.2 POWERS AND DUTIES OF OPERATING COMMITTEE
The Operating Committee shall have power and duty to authorize and
supervise Joint Operations that are necessary or desirable to fulfill the
Contract and properly explore and exploit the Contract Area in accordance with
this Agreement and in a manner appropriate in the circumstances. The Operating
Committee is the coordinating body for the direction, control and administration
of the Joint Operations. The principal functions of the Operating Committee
shall be:
(A) To establish policies from time to time governing various aspects or
activities of the Joint Operations.
(B) To review, approve and revise annual exploration Work Programs and
corresponding budgets, as proposed by the Operator.
(C) To review reports on Joint Operations conducted in the Contract Area
including the status of all existing facilities, safety,
environmental aspects and equipment availability.
(D) To review and approve any proposal for the appraisal of an area.
(E) To review, revise and approve Work Programs and Budgets for petroleum
operations as defined in the Contract and as proposed by the
Operator.
(F) To review and approve Exploration, Appraisal and Development Wells
and locations (including locations for wells required for any
purposes whatsoever), and transfer of exploitation objectives,
Reworking and abandonment of wells.
(G) To review and approve well stimulation programs.
(H) To review and determine the area to be relinquished, if any.
(I) To approve appointment of contractors for carrying out any petroleum
operations by Operator beyond the authority vested in the Operator
under this Agreement.
(J) To review and approve such other matters with respect to petroleum
operations in the Contract Area as may be referred to the Operating
Committee by any member of the Operating Committee.
(K) To refer to the Management Committee and/or the Government whenever
applicable matters which require advice or approval of the Management
Committee and/or the Government pursuant to the Contract.
(L) To review summary operating costs.
5.3 AUTHORITY TO VOTE
(A) The representative of a Party, or in his absence his alternate
representative, shall be authorized to represent and bind such Party
with respect to any matter which is within the powers of the
Operating Committee and is properly brought before the Operating
Committee. Each such representative shall have a vote equal to the
Participating Interest of the Party such person represents. Each
alternate representative shall be entitled to attend all Operating
Committee meetings but shall have no vote at such meetings except in
the absence of the representative for whom he is the alternate. In
addition to the representative and alternate representative, each
Party may also bring to any Operating Committee meetings such
technical and other advisors as it may deem appropriate.
(B) Any representative shall be entitled, if either he or his alternate
is unable to attend a meeting, to cast his vote by telex or facsimile
transmission received prior to the time that the vote is taken in the
course of the meeting.
(C) Any representative may by notice to all other representatives,
appoint a representative of another Party who consents to such
appointment as its proxy to attend a meeting and to exercise the
appointing representative's right to vote at that meeting whether as
directed by the appointing representative or otherwise. A
representative appointed as a proxy and attending a meeting may be
present in two (2) separate capacities and may vote accordingly.
5.4 SUBCOMMITTEES
The Operating Committee may establish such subcommittees, including
technical subcommittees, as the Operating Committee may deem
appropriate. The functions of such subcommittees shall be in an
advisory capacity or as otherwise determined unanimously by the
Parties.
5.5 NOTICE OF MEETING
(A) Operator may call a meeting of the Operating Committee by giving
notice to the Parties at least fifteen (15) Days in advance of such
meeting.
(B) Any Non-Operator may request a meeting of the Operating Committee by
giving proper notice to all the other Parties. Upon receiving such
request, Operator shall call such meeting for a date not less than
fifteen (15) Days nor more than twenty (20) Days after receipt of the
request.
(C) The notice periods above may be waived at the request of Operator or
any Non-Operator with the unanimous consent of all the Parties. In
the event of a likely material adverse financial impact to the Joint
Operation, no Party may unreasonably withhold waiving the notice
period.
5.6 CONTENTS OF MEETING NOTICE
(A) Each notice of a meeting of the Operating Committee as provided by
Operator shall contain:
(1) The date, time and location of the meeting; and
(2) An agenda of the matters and proposals to be considered
and/or voted upon.
(B) A Party, by notice to the other Parties given not less than seven (7)
Days prior to a meeting, may add additional matters to the agenda for
a meeting.
(C) On the request of a Party, and with the unanimous consent of all
Parties, the Operating Committee may consider at a meeting a proposal
not contained in such meeting agenda.
5.7 LOCATION AND FREQUENCY OF MEETINGS
All meetings of the Operating Committee shall be held in Bombay, India, or
elsewhere as may be decided by the Operating Committee. The Operating Committee
shall meet at least once each two (2) months during the first six (6) months
following the Effective Date unless otherwise agreed. Thereafter, the Operating
Committee shall meet once every three (3) months unless otherwise agreed.
5.8 OPERATOR'S DUTIES FOR MEETINGS
(A) With respect to meetings of the Operating Committee and any
subcommittee, Operator's duties shall include, but not be limited to:
(1) Timely preparation and distribution of the agenda;
(2) Organization and conduct of the meeting; and
(3) Preparation of a written record or minutes of each meeting.
(B) Operator shall have the right to appoint the chairman of the
Operating Committee and all subcommittees.
5.9 VOTING PROCEDURE
Except as otherwise expressly provided in this Agreement, all decisions,
approvals and other actions of the Operating Committee on all proposals coming
before it under this Agreement shall be decided by the affirmative vote of the
Parties then having collectively one hundred percent (100%) of the Participating
Interests. In the event the Operating Committee cannot agree upon a Work Program
and Budget relating to the Minimum Work Obligation, the matter shall be referred
to the Management Committee by any Party for review and decision. The Management
Committee shall decide such issue within twenty (20) Days or as otherwise
mutually agreed. If all of the Parties do not agree with the Management
Committee decision, the Parties in agreement shall be entitled to proceed in
accordance with Article VII hereof. If the Management Committee cannot agree,
the matter shall be referred to arbitration or a sole expert.
5.10 RECORD OF VOTES
The chairman of the Operating Committee shall appoint a secretary who shall
make a record of each proposal voted on and the results of such voting at each
Operating Committee meeting. Each representative shall sign and be provided a
copy of such record at the end of such meeting and it shall be considered the
final record of the decisions of the Operating Committee.
5.11 MINUTES
The secretary shall provide each Party with a copy of the minutes of the
Operating Committee meeting within ten (10) Days after the end of the meeting.
Each Party shall have ten (10) Days after receipt of such minutes to give notice
of its objections to the minutes to the secretary. A failure to give notice
specifying objection to such minutes within said ten (10) Day period shall be
deemed to be approval of such minutes. In any event, the votes recorded under
Article 5.10 shall take precedence over the minutes described above.
5.12 VOTING BY NOTICE
(A) In lieu of a meeting, Operator may submit any proposal for a decision
of the Operating Committee by giving each representative proper
notice describing the proposal so submitted. Each Party shall
communicate its vote by proper notice to Operator and the other
Parties within one of the following appropriate time periods after
receipt of Operator's notice:
(1) Twenty-four (24) hours in the case of operations which
involve the use of a drilling rig that is standing by in the
Contract Area.
(2) Thirty (30) Days in the case of all other proposals.
(3) Thirty (30) Days in the case of an AFE or supplemental AFE
if submitted pursuant to Article 6.9(A).
(B) Except in the case of Article 5.12(A)(1), any Non-Operator may by
notice delivered to all Parties within twenty (20) Days of receipt of
Operator's notice request that the proposal be decided at a meeting
rather than by notice. In such an event, that proposal shall be
decided at a meeting duly called for that purpose.
(C) Except as provided in Article X, any Party failing to communicate its
vote in a timely manner shall be deemed to have voted against such
proposal.
(D) If a meeting is not requested, then at the expiration of the
appropriate time period, Operator shall give each Party a
confirmation notice stating the tabulation and results of the vote.
5.13 EFFECT OF VOTE
All decisions taken by the Operating Committee pursuant to this Article,
shall be conclusive and binding on all the Parties, except that:
(A) If pursuant to this Article, a Joint Operation has been properly
proposed to the Operating Committee and the Operating Committee has
not approved such proposal in a timely manner, then any Party shall
have the right for the appropriate period specified below to propose
in accordance with Article VII, an Exclusive Operation involving
operations essentially the same as those proposed for such Joint
Operation. No Exclusive Operation shall be conducted which conflicts
with a Joint Operation.
(1) For proposals involving the use of a drilling rig that is
standing by in the Contract Area, such right shall be
exercisable for twenty-four (24) hours after the time
specified in Article 5.12(A)(1) has expired.
(2) For proposals to develop a Discovery, such right shall be
exercisable for ten (10) Days after the date the Operating
Committee was required to consider such proposal pursuant to
Article 5.6 or Article 5.12;
(3) For all other proposals, such right shall be exercisable for
five (5) Days after the date the Operating Committee was
required to consider such proposal pursuant to Article 5.6
or Article 5.12.
(B) If a Party voted against any proposal to be conducted as an Exclusive
Operation pursuant to Article VII, then such Party shall have the
right not to participate in the operation contemplated by such
approval. Any such Party wishing to exercise its right of non-consent
must give notice of non-consent to all other Parties within five (5)
Days (or within twenty-four (24) hours if the drilling rig to be used
in such operation is standing by in the Contract Area) following
Operating Committee approval of such proposal. The Parties that were
not entitled to give or did not give notice of non-consent shall be
Consenting Parties as to the operation contemplated by the Operating
Committee approval, and shall conduct such operation as an Exclusive
Operation under Article VII. Any Party that gave notice of
non-consent shall be a Non-Consenting Party as to such Exclusive
Operation.
(C) If the Consenting Parties to an Exclusive Operation under Article
5.13(A) or Article 5.13(B) concur, then the Operating Committee may,
at any time, pursuant to this Article, reconsider and approve, decide
or take action on any proposal that the Operating Committee declined
to approve earlier, or modify or revoke an earlier approval, decision
or action.
(D) Once a Joint Operation for the drilling, Deepening, Testing,
Sidetracking, Plugging Back, Completing, Recompleting, Reworking or
plugging of a well, has been approved and commenced, such operation
shall not be discontinued without the consent of the Operating
Committee; provided, however, that such operation may be
discontinued, if:
(1) an impenetrable substance or other condition in the hole is
encountered which in the reasonable judgment of Operator,
after consultation with the Non-Operators, causes the
continuation of such operation to be impractical; or
(2) other circumstances occur which in the reasonable judgment
of Operator causes the continuation of such operation to be
unwarranted and after notice the Operating Committee within
the period required under Article 5.12(A)(1) approves
discontinuing such operation.
On the occurrence of either of the events listed under Article
5.13(D)(1) or Article 5.13(D)(2), Operator shall promptly notify the
Parties with all available details that such operation is being
discontinued pursuant to the foregoing, and any Party shall have the
right to propose in accordance with Article VII an Exclusive
Operation to continue such operation.
ARTICLE VI - WORK PROGRAMS AND BUDGETS
In the conduct of Joint Operations, Operator shall perform Joint Operations
in accordance with the provisions of the Contract, this Agreement and the
instructions of the Operating Committee and conduct all Joint Operations in a
diligent, safe and efficient manner in accordance with international petroleum
industry practices and conservation principles generally followed by the
international petroleum industry under similar circumstances.
6.1 PREPARATION OF WORK PROGRAM AND BUDGET
Subject to Article 6.14, on or before the first (1st) Day of November of
each Year, the Operator shall submit to the Parties a recommended Work Program
and Budget containing the Minimum Work Obligation for the Contract Area for the
subsequent Financial Year as per Exhibit "D". At the same time as that Financial
Year's Work Program and Budget is submitted, a provisional Work Program and
Budget containing the Minimum Work Obligation for the next succeeding Financial
Year shall be presented by the Operator.
6.2 ADOPTION OF WORK PROGRAM AND BUDGET AND SUBMISSION TO MANAGEMENT
COMMITTEE
Subject to Article 6.14, on or before the first (1st) of December of each
year, the Operating Committee shall agree upon and adopt a Work Program and
Budget for the subsequent Financial Year. At the time of agreeing upon and
adopting a Work Program and Budget, the Operating Committee shall provisionally
consider, but not act upon or adopt, a Work Program and Budget for the next
succeeding Financial Year. As soon as possible after the adoption of a Work
Program and Budget, Operator shall provide a copy thereof to each Party. The
Operator shall timely submit such Work Programs and Budgets to the Management
Committee as required pursuant to Articles 4.2 and 5.6 of the Contract. Any
proposed revision of a Work Program and Budget submitted to the Operating
Committee shall be considered by the Operating committee within twenty- eight
(28) Days after its submission and, to the extent same is approved, shall be
submitted by the Operator for consideration by the Management Committee pursuant
to Article 4.3 of the Contract.
6.3 SUBDIVISION OF WORK PROGRAM AND BUDGET AND BUDGET ITEMS AND TRANSFERS
Each Work Program and Budget shall be subdivided, as illustrated in Exhibit
"D", to include three (3) major functional categories: Exploration and
Appraisal, Development and Production; and each of those categories shall be
further subdivided into subcategories consisting of one or more individual
projects/programmed activities. Purchases of materials and supply inventory not
specifically made for a designated project/programmed activity shall be budgeted
as a separate item. Each individual project/programmed activity shall be
identified as either "Firm" or "Contingent" depending upon the degree of
complete details furnished at the time of presentation of the Work Program and
Budget.
(A) For a project to be considered "Firm" within the budget, it will
require program description, objectives and cost estimate along with
the basis therefor, sufficiently complete and in such detail as to
allow thorough evaluation of the project.
(B) Projects which do not meet the requirements of Article 6.3(A) at the
time the Work Program and Budget is approved by the Operating
Committee may also be included in the Work Program and Budget for
approval in principle and such projects shall be considered
"Contingent". Such projects shall not be implemented without approval
of the Operating Committee except as provided in this Article 6.3(B).
Any project or group of projects shall be transferred from Contingent
to Firm upon approval of the Operating Committee. From time to time
throughout the Financial Year, the Operator shall endeavour to
provide further specific information necessary for the Operating
Committee to evaluate Contingent projects for the purpose of such
transfer. Upon receipt of such information, Parties may not
unreasonably withhold approval for the transfer of a project from the
Contingent to the Firm category. In the event the Operating Committee
is unable to agree, the matter shall be submitted by any Party to the
Management Committee for approval. A project not in the Minimum Work
Obligation which fails to obtain Operating Committee approval for
transfer may be transferred by any Party provided that Party is
prepared to undertake the project as an Exclusive Operation pursuant
to Article VII.
6.4 FULFILLMENT OF MINIMUM WORK OBLIGATION
Parties shall not unreasonably withhold approval of the projects/programmed
activities covered in the annual Work Program and Budget as Minimum Work
Obligations or at least that part of such Minimum Work Obligations required to
be carried out to maintain the Contract in force. In case of failure of the
Operating Committee to approve the Work Program and Budget related to
projects/programmed activities included under Minimum Work Obligations, any
Party may refer the issue to the Management Committee for approval.
6.5 EXPLORATION AND APPRAISAL
Parties acknowledge and agree that neither exploration nor appraisal work
may be conducted within any Field which is so designated as of the Effective
Date.
(A) Notwithstanding the foregoing, Exploration and/or Appraisal Wells may
be proposed without limitation as to location, provided, however,
that if such location is within a Development Area, such well shall
not be commenced without prior approval of the Operating Committee.
In the event such well within the Development Area includes an
objective Zone which is the stratigraphic equivalent of the Zone or
Zones included in the Field and the location is outside the Field,
then, provided that production from such Zone does not interfere with
production from the Zone/Zones developed or to be developed in the
Field, Operating Committee approval shall not be unreasonably
withheld.
(B) If the proposed Work Program and Budget includes an Exploration Well
and/or Appraisal Well, the budget approval shall include the cost of
drilling, completing and testing such Exploration/Appraisal Well. For
this purpose the Operator shall provide necessary details/information
required for the Operating Committee to assess the need/desirability
of such Exploration/Appraisal Well.
(C) If a New Discovery is made, Operator shall deliver any notice of New
Discovery required under the Contract and shall, as soon as possible,
submit to the Parties a report containing available details
concerning the New Discovery and Operator's recommendation as to
whether the New Discovery merits appraisal. The Operating Committee
shall meet and decide within forty-five (45) Days whether the New
Discovery merits appraisal. If the Operating Committee determines
that the New Discovery merits appraisal, Operator, within thirty (30)
Days, shall deliver to the Parties a proposed Work Program and Budget
for the appraisal of the New Discovery. Within twenty (20) Days of
such delivery, or earlier if necessary to meet any applicable
deadline under the Contract, the Operating Committee shall meet to
consider, modify and then either approve or reject the appraisal Work
Program and Budget. If the appraisal Work Program and Budget is
approved by the Operating Committee, Operator shall take such steps
as may be required under the Contract to secure approval of the
appraisal Work Program and Budget by the Management Committee and/or
the Government, whichever is applicable. In the event the Management
Committee and/or the Government, whichever is applicable, requires
changes in the appraisal Work Program and Budget,the matter shall be
resubmitted to the Operating Committee for further consideration.
(D) Any Party desiring to propose a Completion attempt, or an alternative
Completion attempt, must do so within the time period provided in
Article 5.12(A)(1) by notifying all other Parties. The Operator shall
prepare the AFE for such Completion costs and provide same to the
Parties.
6.6 DEVELOPMENT OF NEW DISCOVERY
(A) If the Operating Committee determines that a Discovery may be
commercial, the Operator shall, as soon as practicable, but not later
than ninety (90) Days after completing the appraisal referred to in
Article 6.5(C), deliver to the Parties a Development Plan together
with the Work Program and Budget for the remainder of the Financial
Year and a provisional Work Program and Budget for the next
succeeding Financial Year along with annual projections for the
remainder of the development of the New Discovery. The Work Programs
and Budgets proposed by the Operator shall contain, inter alia:
(1) Details of the proposed work to be undertaken, personnel
required and expenditures to be incurred, including the
timing of same, on a Financial Year basis;
(2) An estimated date for the commencement of production;
(3) A delineation of the proposed Exploitation Area; and
(4) Any other information requested by the Operating Committee.
(B) After receipt of the Development Plan, or earlier if necessary to
meet any applicable deadline under the Contract, the Operating
Committee shall meet to consider, modify and then either approve or
reject within ninety (90) Days the Development Plan and the Work
Program and Budget for the remainder of the Financial Year for the
development submitted by Operator. If the Development Plan is
approved by the Operating Committee, Operator shall, as soon as
possible, deliver any notice of Commercial Discovery required under
the Contract and take such other steps as may be required under the
Contract to secure approval of the Development Plan by the Management
Committee and/or Government, whichever is applicable. In the event
the Management Committee and/or Government, whichever is applicable,
requires changes in the Development Plan, the matter shall be
resubmitted to the Operating Committee for further consideration. If
the Development Plan is approved, such work shall be incorporated
into and form part of the annual Work Programs and Budgets.
6.7 ITEMIZATION OF EXPENDITURES
(A) During the preparation of the proposed Work Programs and Budgets and
Development Plans contemplated in this Article, Operator shall
consult with the Operating Committee regarding the contents of such
Work Programs and Budgets and Development Plans.
(B) Each Work Program and Budget and Development Plan submitted by
Operator shall contain an itemized estimate of the costs of Joint
Operations and all other expenditures to be made for the Joint
Account during the Financial Year in question.
(C) The Work Program and Budget shall designate the portion or portions
of the Contract Area in which Joint Operations itemized in such Work
Program and Budget are to be conducted and shall specify the kind and
extent of such operations in such detail as the Operating Committee
may deem suitable.
6.8 CONTRACT AWARDS
(A) Operator shall award, except for an award to an Affiliate, each
contract for Joint Operations on the following basis (the amounts
stated are in thousands of U.S. dollars):
PROCEDURE A PROCEDURE B PROCEDURE C
Applicable to Exploration,
Appraisal, Development
and Production $100 to $500 $500 to $3,000 >=$3,000
Operations
Operator shall not award a contract exceeding US$20,000 to an
Affiliate without prior approval of the Operating Committee,
provided, however, that the service agreement under which EOGIL
secures technical, administrative and related support subject to
Sections 2.4.2 and 3.1 of Exhibit "A", Accounting Procedure, shall
not be subject to the provisions of this Article 6.8.
For contracts valued less than the lower limit of Procedure A,
Operator shall award the contract to the best qualified contractor as
determined in accordance with Operator's purchasing policies set
forth in EOGIL's purchasing policy and procedure, Number 9401.
Operator shall inform the Non-Operators of such awards every month.
PROCEDURE A
Operator shall:
(1) Provide the Parties with a list of all the entities approved
by the Operating Committee as per Article 6.8(C) for the
applicable category of the contract, along with other
entities, if any, from whom the Operator proposes to invite
tender;
(2) Add to such list entities whom a Party requests to be added
within five (5) Business Days of receipt of such list;
(3) If and when any Party so requests, Operator shall evaluate
any entity listed in (1) and (2) above to assure that entity
is qualified as based on the qualification criteria agreed
in accordance with Article 6.8(B), to perform under the
contract;
(4) Complete the tendering process within a reasonable period of
time;
(5) Circulate to all Parties a comparative bid analysis stating
Operator's choice of the entity for award of contract.
Provide also reasons for such choice in case entity chosen
is not the lowest bidder;
(6) Inform all the Parties of the entities to whom the contract
has been awarded; and (7) Upon the request of a Party,
provide such Party with a copy of the final version of the
contract awarded.
PROCEDURE B
Operator shall:
(1) Provide the Parties with a list of all the entities approved
by the Operating Committee as per Article 6.8(C) for the
applicable category of the contract, along with other
entities, if any, from whom the Operator proposes to invite
tender;
(2) Add to such list entities whom a Party requests to be added
within five (5) Business Days of receipt of such list;
(3) If and when any Party so requests, Operator shall evaluate
any entity listed in (1) and (2) above to assure that entity
is qualified as based on the qualification criteria agreed
in accordance with Article 6.8(B), to perform under the
contract;
(4) Complete the tendering process within a reasonable period of
time;
(5) Circulate to all Parties a comparative bid analysis stating
Operator's choice of the entity for award of contract.
Provide also reasons for such choice in case the entity
chosen is not the lowest bidder. If the bid selected is not
the lowest bid, obtain prior approval of the Operating
Committee for award of contract;
(6) Award the contract accordingly and inform all the Parties of
the entities to whom the contract has been awarded; and
(7) Upon the request of a Party, provide such Party with a copy
of the final version of the contract awarded.
PROCEDURE C
Operator shall:
(1) Publish invitations for parties to pre-qualify for the
proposed contract in one (1) daily national India newspaper,
provide to Non-Operators a list of responding parties and an
analysis of their qualifications for the contract being
contemplated, and include those who qualify, as per the
pre-qualification criteria approved as per Article 6.8(B),
in the list of entities whom Operator proposes to invite to
tender for the said contract;
(2) Provide the Parties with a total list of all the entities
selected as (1) above and all the entities approved by the
Operating Committee as per Article 6.8(C) for the applicable
category of the contract, along with other entities, if any,
from whom the Operator proposes to invite tender;
(3) Add to such list entities whom a Party requests to be added
within five (5) Business Days of receipt of such list;
(4) If and when any Party so requests, Operator shall evaluate
any entity listed in (2) and (3) above to assure that entity
is qualified as based on the qualification criteria agreed
in accordance with Article 6.8(B), to perform under the
contract;
(5) Prepare and dispatch the tender documents to the entities on
the list as aforesaid and to Non-Operators;
(6) After the expiration of the period allowed for tendering,
consider and analyze the details of all bids received;
(7) Prepare and circulate to the Parties a comparative bid
analysis, stating Operator's recommendation as to the entity
to whom the contract should be awarded, the reasons
therefor, and the technical, commercial and contractual
terms to be agreed upon;
(8) Obtain the approval of the Operating Committee to the
recommended bid. However, failing Operating Committee
approval, any Party may refer the issue to Management
Committee for decision; and
(9) Award the contract accordingly and upon the request of a
Party, provide such Party with a copy of the final version
of the contract.
(B) A set of vendor qualification criteria for each major category of
vendor shall be proposed by the Operator and approved by the
Operating Committee within thirty (30) Days of its submittal. In the
event the Operating Committee fails to approve vendor qualification
criteria within thirty (30) Days of the date the same is first
submitted by the Operator, the matter shall be referred to the
Management Committee for decision. The Operating Committee may revise
the qualification criteria.
(C) It is anticipated that, in order to expedite Joint Operations,
contracts will be awarded to qualified vendors who are identified as
approved vendors as to specified activities, supplies and/or work as
per the applicable Agreement procedure. A list of such approved
vendors shall first be established as follows: Operator shall:
(1) Provide the Parties with a list of the entities whom
Operator proposes to invite to tender for contracts; and
(2) Add to such list entities whom a Party requests to be added
within fourteen (14) Days of receipt of such list; and
obtain approval of the Operating Committee within thirty
(30) Days of its submittal to the Operating Committee by the
Operator. Such list shall thereafter be maintained by the
Operator. The Operating Committee may add to or delete
vendors from such list.
6.9 AUTHORIZATION FOR EXPENDITURE ("AFE") PROCEDURE
(A) Prior to incurring any commitment or expenditure which exceeds the
expenditure guidelines specified in this Article 6.9, Operator shall
send to each Non-Operator an AFE containing Operator's best estimate
of the total funds required to carry out such work, the estimated
timing of expenditures, and any other necessary supportive
information. The Operator shall send to each Non-Operator an AFE
containing the information specified above for the following:
(1) Each project involving seismic acquisition and processing;
(2) Each Exploration and Appraisal Well;
(3) Each Development Well or group of Development Wells;
(4) Deepening of any well below original total depth, involving
exploratory footage;
(5) Workovers or Reworking a well costing in excess of
US$200,000 for any well, including deepening into
development Zones;
(6) Each platform or group of platforms;
(7) Each subsea pipeline/major pipeline;
(8) Equipping of Wells exceeding One Hundred Thousand U.S.
Dollars (US$100,000) if not already included in an AFE.
Equipping of wells includes generally the purchase and
installation of equipment and material for lifting, heating,
storing and otherwise handling production;
(9) Individual construction projects and equipment not already
included in an AFE, exceeding One Hundred Thousand U.S.
Dollars (US$100,000) each;
(10) Commitments for purchases of advance materials for projects
not yet approved shall be aggregated and included in an AFE
covering a Calendar Quarter;
(11) Any other project/programmed expenditure not included above
in this Article 6.9 estimated to be in excess of One Hundred
Fifty Thousand U.S. Dollars (US$150,000).
(B) The restrictions contained in this Article shall be without prejudice
to Operator's rights to make expenditures as set out in Article
4.2(B)(11) and Article 13.5.
(C) Parties agree that, except as otherwise provided in Article
6.9(A)(5), operating costs and deposits as further specified below in
this Article 6.9(C) shall not require AFEs. Such costs shall be
reported as against the appropriate budget line item and variances
from the budgeted amounts shall be reviewed by the Operating
Committee. Operating cost means costs and expenditures of a recurring
nature, incurred after the commencement of production in the
operation and maintenance of property and necessary for production
and handling of produced Petroleum. Costs of a similar nature
incurred prior to production commencement shall be provided for in
the appropriate AFE(s) in accordance with Article 6.9(A)(1) through
(A)(9). Deposits mean non-recurring refundable or adjustable payments
toward security/ surety including, but not limited to, expatriate
employee housing and office building rental deposits. Operating costs
are categorized and detailed as Production Costs [except that
workovers or Reworking a well shall be subject to Article
6.9(A)(5)]and general and administrative costs, which costs are
contained in categories III and IV of Exhibit "D", Work Program and
Budget. Deposits are listed in the "Deposit" section of category V of
Exhibit "D".
6.10 SUPPLEMENTARY AFES
Operator shall submit a supplemental AFE for approval when it is
anticipated that an AFE will be overexpended by more than ten percent (10%),
which approval shall not be unreasonably withheld.
6.11 APPROVAL OF AFES
Except as herein otherwise provided, Operator shall be required to obtain
approval of an AFE prior to undertaking the work. AFE approval shall be
confirmed by returning a signed copy of the AFE to the Operator. Parties shall
respond to requests for approval of AFEs within fourteen (14) Days of receipt. A
failure to respond to an AFE within this time period shall be deemed an approval
of such AFE.
6.12 APPROVAL OF AFE NOT TO BE UNREASONABLY WITHHELD
After approval of the Work Program and Budget by the Operating Committee
and the Management Committee, no Party may withhold approval of an AFE for any
project contained in the Firm budget category unless there is a material
variance between the AFE and the project so approved.
6.13 OVEREXPENDITURES OF WORK PROGRAMS AND BUDGETS
Cumulative total of all overexpenditures for a Financial Year shall not
exceed five percent (5%) of the total Work Program and Budget as currently
approved.
6.14 WORK PROGRAM AND BUDGET FOR INITIAL PERIOD
The Development Plan together with the corresponding Work Program and
Budget for the period ending 31 March 1996 ("Initial Period") shall be submitted
to the Operating Committee for approval as soon as possible following the
Effective Date. The Operating Committee shall approve the Development Plan and
corresponding Work Program and Budget within thirty (30) Days and as soon as
practicable thereafter, the Operator shall submit same to the Management
Committee. In the event the Operating Committee is unable to approve the Work
Program and Budget for the Initial Period by the due date specified in this
Article 6.14, any Party may refer the matter to the Management Committee for
decision.
ARTICLE VII - OPERATIONS BY LESS THAN ALL PARTIES
7.1 LIMITATION ON APPLICABILITY
(A) Subject to the Contract, any operation beyond the Minimum Work
Obligation can be proposed as a Joint Operation. In the event of
difference of opinion among the Parties for taking the operation as
Joint Operation, the same may be conducted as Exclusive Operation by
the willing Parties subject to provisions of Article VII. All
operations shall be conducted as Joint Operations under Article V, or
as Exclusive Operations under this Article. No Exploration Well or
Appraisal Well which is an Exclusive Well may be Completed in any
Field which is so designated as of the Effective Date. If a proposal
for an Exploration Well/Appraisal Well for Zones other than those in
the Field leads to an Exclusive Operation and such well is located in
the Development Area of a Field but outside the Field which is so
designated as of the Effective Date, then, in such case, each
Non-Consenting Party/Parties shall have a right to place a
representative at the site during drilling, Completion and testing
and recompleting and Reworking of such a well. No Exclusive Operation
shall be conducted which conflicts with Joint Operations.
Determination as to whether or not a conflict exists shall be made by
the unanimous vote of the Operating committee. If the Operating
Committee cannot agree, the matter can be referred to a sole expert
or arbitration.
(B) Except as otherwise herein provided, operations which are required to
fulfill the Minimum Work Obligations must be proposed and conducted
as Joint Operations under Article V, and shall not be proposed or
conducted as Exclusive Operations under this Article.
(C) No Party may propose or conduct an Exclusive Operation under this
Article, unless and until such Party has properly exercised its right
to propose an Exclusive Operation pursuant to Article 5.13, or is
entitled to conduct an Exclusive Operation pursuant to Article X.
7.2 PROCEDURE TO PROPOSE EXCLUSIVE OPERATIONS
(A) Subject to Article 7.1, if any Party proposes to conduct an Exclusive
Operation, such Party shall give notice of the proposed operation to
all Parties, other than Parties who have relinquished their
Participating Interest in the Exploitation Area in which the proposed
operation is to be conducted. Such notice shall specify that such
operation is proposed as an Exclusive Operation, the work to be
performed, the location, the objectives, and estimated cost of such
operation.
(B) Any Party entitled to receive such notice shall have the right to
participate in the proposed operation.
(1) For proposals to Deepen, Test, Complete, Sidetrack, Plug
Back, Recomplete or Rework involving the use of a drilling
rig that is standing by in the Contract Area, any such Party
wishing to exercise such right must so notify Operator
within twenty-four (24) hours after receipt of the notice
proposing the Exclusive Operation.
(2) For proposals to develop a Discovery, any Party wishing to
exercise such right must so notify the Party proposing to
develop within twenty (20) Days after receipt of the notice
proposing the Exclusive Operation.
(3) For all other proposals, any such Party wishing to exercise
such right must so notify Operator within ten (10) Days
after receipt of the notice proposing the Exclusive
Operation;
(C) Failure of a Party to whom a proposal notice is delivered to properly
reply within the period specified above shall constitute an election
by that Party not to participate in the proposed operation.
(D) If all Parties properly exercise their rights to participate, then
the proposed operation shall be conducted as a Joint Operation. The
Operator shall commence such Joint Operation as promptly as
practicable and conduct it with due diligence.
(E) If less than all Parties entitled to receive such proposal notice
properly exercise their rights to participate, then:
(1) The Party proposing the Exclusive Operation, together with
any other Consenting Parties, shall have the right
exercisable for the applicable notice period set out in
Article 7.2(B), to instruct Operator (subject to Article
7.9(G)) to conduct the Exclusive Operation.
(2) If the Exclusive Operation is conducted, the Consenting
Parties shall bear the sole liability and expense of such
Exclusive Operation in a fraction, the numerator of which is
such Consenting Party's Participating Interest as stated in
Article 3.1(A) and the denominator of which is the aggregate
of the Participating Interests of the Consenting Parties as
stated in Article 3.1(A), or in such other proportion
totaling one hundred percent (100%) of such liability and
expense as the Consenting Parties may agree.
(3) If such Exclusive Operation has not been commenced within
ninety (90) Days (excluding any extension specifically
agreed by all Parties or allowed by the force majeure
provisions of Article XVI), the right to conduct such
Exclusive Operation shall terminate. If any Party still
desires to conduct such Exclusive Operation, written notice
proposing such operation must be resubmitted to the Parties
in accordance with Article V, as if no proposal to conduct
an Exclusive Operation had been previously made.
7.3 RESPONSIBILITY FOR EXCLUSIVE OPERATIONS
(A) The Consenting Parties shall bear in accordance with the
Participating Interests agreed under Article 7.2(E) the entire cost
and liability of conducting an Exclusive Operation and shall
indemnify the Non-Consenting Parties from any and all costs and
liabilities incurred incident to such Exclusive Operation (including
but not limited to all costs, expenses or liabilities for
environmental, consequential, punitive or any other similar indirect
damages or losses arising from business interruption, reservoir or
formation damage, inability to produce petroleum, loss of profits,
pollution control and environmental amelioration or rehabilitation)
and shall keep the Contract Area free and clear of all liens and
encumbrances of every kind created by or arising from such Exclusive
Operation.
(B) Notwithstanding Article 7.3(A), each Party shall continue to bear its
Participating Interest share of the cost and liability incident to
the operations in which it participated, including but not limited to
plugging and abandoning and restoring the surface location, but only
to the extent those costs were not increased by the Exclusive
Operation.
7.4 CONSEQUENCES OF EXCLUSIVE OPERATIONS
(A) With regard to any Exclusive Operation, for so long as a Non-
Consenting Party has the option to re-instate the rights it
relinquished under Article 7.4(B) below, such Non-Consenting Party
shall be entitled to have access concurrently with the Consenting
Parties, to all data and other information relating to such Exclusive
Operation, other than G & G Data obtained in an Exclusive Operation.
If a Non-Consenting Party desires to receive and acquire the right to
use such G & G Data, then such Non-Consenting Party shall have the
right to do so by paying to the Consenting Parties its Participating
Interest share as set out in Article 3.1(A) of the cost incurred in
obtaining such G & G Data.
(B) With regard to any Exclusive Operation and subject to Article 7.4(C)
and Article 7.8 below, each Non-Consenting Party shall be deemed to
have relinquished to the Consenting Parties, and the Consenting
Parties shall be deemed to own, in proportion to their respective
Participating Interests in the Exclusive Operation:
(1) All of each such Non-Consenting Party's right to participate
in further operations on any Discovery made in the course of
such Exclusive Operation; and
(2) All of each such Non-Consenting Party's right pursuant to
the Contract to take and dispose of Hydrocarbons produced
and saved:
(a) From the well in which such Exclusive Operation was
conducted, and
(b) From any wells drilled to appraise or develop a
Discovery.
(C) A Non-Consenting Party shall have the following and only the
following options to reinstate the rights it relinquished pursuant to
Article 7.4(B):
(1) If the Consenting Parties decide to appraise a Discovery
made in the course of an Exclusive Operation, the Consenting
Parties shall submit to each Non-Consenting Party the
approved appraisal program. For thirty (30) Days (or
forty-eight (48) hours if the drilling rig which is to be
used in such appraisal program is standing by in the
Contract Area) from receipt of such appraisal program, each
Non- Consenting Party shall have the option to reinstate the
rights it relinquished pursuant to Article 7.4(B) and to
participate in such appraisal program. The Non-Consenting
Party may exercise such option by notifying Operator within
the period specified above that such Non-Consenting Party
agrees to bear its Participating Interest share of the
expense and liability of such appraisal program, to pay the
lump sum amount as set out in Article 7.5(A) and to pay the
Cash Premium as set out in Article 7.5(B).
(2) If the Consenting Parties decide to develop a Discovery made
or appraised in the course of an Exclusive Operation, the
Consenting Parties shall submit to the Non-Consenting
Parties a Development Plan substantially in the form
intended to be submitted to the Government under the
Contract. For sixty (60) Days from receipt of such
Development Plan or such lesser period of time prescribed by
the Contract, each Non-Consenting Party shall have the
option to reinstate the rights it relinquished pursuant to
Article 7.4(B) and to participate in such Development Plan.
The Non-Consenting Party may exercise such option by
notifying the Party proposing to act as Operator for such
Development Plan within the period specified above that such
Non-Consenting Party agrees to bear its Participating
Interest share of the liability and expense of such
Development Plan and such future operating and producing
costs, to pay the lump sum amount as set out in Article
7.5(A) and to pay the Cash Premium as set out in Article
7.5(B).
(D) If a Non-Consenting Party does not properly and in a timely manner
exercise such option, including paying in a timely manner in
accordance with Article 7.5, all lump sum amounts and Cash Premiums,
if any, due to the Consenting Parties, such Non-Consenting Party
shall have forfeited the options as set out in Article 7.4(C) and the
right to participate in the proposed program, unless such program,
plan or operation is materially modified or expanded.
(E) A Non-Consenting Party shall become a Consenting Party with regard to
an Exclusive Operation at such time as the Non-Consenting Party gives
proper notice pursuant to Article 7.4(C); provided that such
Non-Consenting Party shall in no way be deemed to be entitled to any
lump sum amount Cash Premium paid incident to such Exclusive
Operation. The Participating Interest of such Non-Consenting Party in
such Exclusive Operation shall be its Participating Interest set out
in Article 3.1(A).
The Consenting Parties shall contribute in proportion to their
respective Participating Interests in such Exclusive Operation, the
Participating Interest of the Non-Consenting Party. If all Parties
participate in the proposed operation, then such operation shall be
conducted as a Joint Operation pursuant to Article V.
(F) If after the expiry of the period in which a Non-Consenting Party may
exercise its option to participate in a Development Plan, the
Consenting Parties desire to proceed with the said Development Plan,
the Party chosen by the Consenting Parties to act as Operator for
such development, shall give notice to the Government under the
appropriate provision of the Contract requesting a meeting to advise
the Government that the Consenting Parties consider the Discovery to
be a Commercial Discovery. Following such meeting such Operator for
such development shall apply for an Exploitation Area. Unless the
Development Plan is materially modified or expanded prior to the
commencement of operations under such plan, each Non-Consenting Party
to such Development Plan shall not participate in such Exploitation
Area covering such development and shall forfeit all interest in such
Exploitation Area. Such Non-Consenting Party shall be deemed to have
withdrawn from this Agreement to the extent it relates to such
Exploitation Area, even if the Development Plan is modified or
expanded subsequent to the commencement of operations under such
Development Plan.
7.5 PREMIUM TO PARTICIPATE IN EXCLUSIVE OPERATIONS
(A) Within thirty (30) Days of the exercise of its option under Article
7.4(C), each such Non-Consenting Party shall pay in immediately
available funds to the Consenting Parties who took the risk of such
Exclusive Operations in proportion to their respective Participating
Interests in such Exclusive Operations a lump sum amount payable in
the currency designated by such Consenting Parties. Such lump sum
amount shall be equal to such Non-Consenting Party's Participating
Interest share of all liabilities and expenses, including overhead,
that were incurred in Exclusive Operations relating to the Discovery,
or well, as the case may be, in which the Non-Consenting Party
desires to reinstate the rights it relinquished pursuant to Article
7.4(B), and that were not previously paid by such Non-Consenting
Party.
(B) In addition to Article 7.5(A), if a Cash Premium is due, then within
thirty (30) Days of the exercise of its option under Article 7.4(C)
each such Non-Consenting Party shall pay in immediately available
funds, in the currency designated by the Consenting Parties who took
the risk of such Exclusive Operations, to such Consenting Parties in
proportion to their respective Participating Interests a Cash Premium
equal to the total of:
(1) Two hundred percent (200%) of such Non-Consenting Party's
Participating Interest share of all liabilities and
expenses, including overhead, that were incurred in any
Exclusive Operations relating to the obtaining of the
portion of the G & G Data which pertains to the Discovery,
and that were not previously paid by such Non-Consenting
Party; plus
(2) Eight hundred percent (800%) of such Non-Consenting Party's
Participating Interest share of all liabilities and
expenses, including overhead, that were incurred in any
Exclusive Operations relating to the drilling, Deepening,
Testing, Completing, Sidetracking, Plugging Back,
Recompleting and Reworking of the Exploration Well which
made the Discovery in which the Non- Consenting Party
desires to reinstate the rights it relinquished pursuant to
Article 7.4(B), and that were not previously paid by such
Non-Consenting Party; plus
(3) Five hundred percent (500%) of the Non-Consenting Party's
Participating Interest share of all liabilities and
expenses, including overhead, that were incurred in any
Exclusive Operations relating to the drilling, Deepening,
Testing, Completing, Sidetracking, Plugging Back,
Recompleting and Reworking of the Appraisal Well(s) which
delineated the Discovery in which the Non- Consenting Party
desires to reinstate the rights it relinquished pursuant to
Article 7.4(B), and that were not previously paid by such
Non-Consenting Party.
7.6 ORDER OF PREFERENCE OF OPERATIONS
(A) Except as otherwise specifically provided in this Agreement, if any
Party desires to propose the conduct of an operation that will
conflict with an existing proposal for an Exclusive Operation, such
Party shall have the right exercisable for five (5) Days, or
twenty-four (24) hours if the drilling rig to be used is standing by
in the Contract Area, from receipt of the proposal for the Exclusive
Operation, to deliver to all Parties entitled to participate in the
proposed operation such Party's alternative proposal. Such
alternative proposal shall contain the information required under
Article 7.2(A).
(B) Each Party receiving such proposals shall elect by delivery of notice
to Operator within the appropriate response period set out in Article
7.2(B) to participate in one of the competing proposals. Any Party
not notifying Operator within the response period shall be deemed not
to have voted.
(C) The proposal receiving the largest aggregate Participating Interest
vote shall have priority over all other competing proposals. In the
case of a tie vote, the Operator shall choose among the proposals
receiving the largest aggregate Participating Interest vote. Operator
shall deliver notice of such result to all Parties entitled to
participate in the operation within five (5) Days of the end of the
response period, or twenty-four (24) hours if the drilling rig to be
used is standing by in the Contract Area.
(D) Each Party shall then have two (2) Days (or twenty-four (24) hours if
the drilling rig to be used is standing by in the Contract Area) from
receipt of such notice to elect by delivery of notice to Operator
whether such Party will participate in such Exclusive Operation, or
will relinquish its interest pursuant to Article 7.4(B). Failure by a
Party to deliver such notice within such period shall be deemed an
election not to participate in the prevailing proposal.
7.7 STAND BY COSTS
(A) When an operation has been performed, all tests have been conducted
and the results of such tests furnished to the Parties, stand by
costs incurred pending response to any Party's notice proposing an
Exclusive Operation for Deepening, Testing, Sidetracking, Completing,
Plugging Back, Recompleting, Reworking or other further operation in
such well (including the period required under Article 7.6 to resolve
competing proposals) shall be charged and borne as part of the
operation just completed. Stand by costs incurred subsequent to all
Parties responding, or expiration of the response time permitted,
whichever first occurs, shall be charged to and borne by the Parties
proposing the Exclusive Operation in proportion to their
Participating Interests, regardless of whether such Exclusive
Operation is actually conducted.
(B) If a further operation is proposed while the drilling rig to be
utilized is on location, any Party may request and receive up to five
(5) additional Days after expiration of the applicable response
period specified in Article 7.2(B) within which to respond by
notifying Operator that such Party agrees to bear all stand by costs
and other costs incurred during such extended response period.
Operator may require such Party to pay the estimated stand by time in
advance as a condition to extending the response period. If more than
one Party requests such additional time to respond to the notice,
stand by costs shall be allocated between such Parties on a
Day-to-Day basis in proportion to their Participating Interests.
7.8 SPECIAL CONSIDERATION REGARDING DEEPENING AND SIDETRACKING
(A) An Exclusive Well shall not be deepened or sidetracked without first
affording the Non-Consenting Parties in accordance with this Article
the opportunity to participate in such operation.
(B) In the event any Consenting Party desires to Deepen or Sidetrack an
Exclusive Well, such Party shall initiate the procedure contemplated
by Article 7.2. If a Deepening or Sidetracking operation is approved
pursuant to such provisions, and if any Non-Consenting Party to the
Exclusive Well elects to participate in such Deepening or
Sidetracking operation, the payment, if any, pursuant to Article 7.5
of such Non- Consenting Party shall be calculated based on the
following liabilities and expenses:
(1) If the proposal is to Deepen or Sidetrack and is made prior
to the Completion of such well as a Commercial Discovery,
then payment shall be based on such Non-Consenting Party's
Participating Interest share of the liabilities and expenses
incurred in connection with drilling the Exclusive Well from
the surface to the depth previously drilled which such
Non-Consenting Party would have paid had such Non-Consenting
Party agreed to participate in such Exclusive Well, plus the
Non-Consenting Party's Participating Interest share of the
liabilities and expenses of Deepening or Sidetracking and of
participating in any further operations on such Exclusive
Well in accordance with the other provisions of this
Agreement; provided, however, all liabilities and expenses
for Testing and Completing or attempting Completion of the
well incurred by Consenting Parties prior to the
commencement of actual operations to Deepen or Sidetrack
beyond the depth previously drilled shall be for the sole
account of Consenting Parties in the proportion their
Participating Interest bears to the aggregate of their
Participating Interests.
(2) If the proposal is to Deepen or Sidetrack and is made for an
Exclusive Well that has been previously Completed as a
Commercial Discovery, but is no longer producing, then
payment shall be based on the Non-Consenting Party's
Participating Interest share of all costs of drilling and
Completing said well from the surface to the depth
previously drilled, calculated in the manner provided in
Article 7.8(B)(1), less those costs recouped by the
Consenting Parties from the sale of production from such
Exclusive Well, plus the Non-Consenting Party's
Participating Interest share of all costs of re-entering
said well, plus the Non-Consenting Party's proportionate
part (based on the percentage of the Exclusive Well such
Non-Consenting Party would have owned had it previously
participated in such Exclusive Well) of the costs of
salvable materials and equipment remaining in the hole and
salvable surface equipment used in connection with such well
shall be determined in accordance with the Accounting
Procedure. If at the time such Deepening or Sidetracking
operation is conducted the Consenting Parties have recouped
from the Exclusive Well the amount calculated pursuant to
Article 7.5, then a Non-Consenting Party may participate in
the Deepening or Sidetracking of the Exclusive Well with no
payment for liabilities and expenses incurred prior to
re-entering the well for Deepening or Sidetracking.
7.9 MISCELLANEOUS
(A) Each Exclusive Operation shall be carried out by the Operator on
behalf of and at the expense of the Consenting Parties. For Exclusive
Operations, the Consenting Parties shall act as the Operating
Committee, subject to the provisions of this Agreement applied
mutatis mutandis to such Exclusive Operation and subject to the terms
and conditions of the Contract.
(B) The computation of liabilities and expenses incurred in Exclusive
Operations, including the liabilities and expenses of Operator for
conducting such operations, shall be made in accordance with the
principles set out in the Accounting Procedure.
(C) Operator shall maintain separate books, financial records and
accounts for Exclusive Operations which shall be subject to the same
rights of audit and examination as the Joint Account and related
records, all as provided in the Accounting Procedure. Said rights of
audit and examination shall extend to each of the Consenting Parties
and each of the Non-Consenting Parties so long as the latter are, or
may be, entitled to elect to participate in such operations.
(D) Operator, if it is not a Consenting Party and it is conducting an
Exclusive Operation for the Consenting Parties, shall be entitled to
request cash advances and shall not be required to use its own funds
to pay any cost and expense and shall not be obliged to commence or
continue Exclusive Operations until cash advances requested have been
made, and the Accounting Procedure shall apply to Operator in respect
of any Exclusive Operations conducted by it.
(E) Should the submission of a Development Plan be approved in accordance
with Article 5.9, or should any Party propose a development in
accordance with Article VII, with either proposal not calling for the
conduct of additional appraisal drilling, and should any Party wish
to drill an additional Appraisal Well prior to development, then the
Party proposing the Appraisal Well as an Exclusive Operation shall be
entitled to proceed first, but without the right to future
reimbursement of costs or to any Premium, pursuant to Article 7.5.
If, as the result of drilling such Appraisal Well as an Exclusive
Operation, the Party proposing to apply for an Exploitation Area
decides to not develop the reservoir, then each Non-Consenting Party
who voted in favor of such Development Plan prior to the drilling of
such Appraisal Well shall pay to the Consenting Party the amount such
Non-Consenting Party would have paid had such Appraisal Well been
drilled as a Joint Operation.
(F) In the case of any Exclusive Operation for Deepening, Testing,
Completing, Sidetracking, Plugging Back, Recompleting or Reworking,
the Consenting Parties shall be permitted to use, free of cost, all
casing, tubing and other equipment in the well, that is not needed
for Joint Operations, but the ownership of all such equipment shall
remain unchanged. On abandonment of a well after such Exclusive
Operation, the Consenting Parties shall account for all such
equipment to the Parties who shall receive their respective
Participating Interest shares, in value, less cost of salvage.
(G) If the Operator is a Non-Consenting Party to an Exclusive Operation
to develop a new Discovery, then subject to obtaining any necessary
Government approval the Operator may resign, but in any event shall
resign on the request of the Consenting Parties, as Operator for the
Exploitation Area for such Discovery and the Consenting Parties shall
select a Party to serve as Operator.
ARTICLE VIII - DEFAULT
8.1 DEFAULT AND NOTICE
Any Party that fails to pay when due its Participating Interest share of
Joint Account expenses including cash advances and interest, if any, accrued
pursuant to this Agreement, subject to Section 1.6.2, (a "Defaulting Party")
shall be in default under this Agreement. Operator, or any other Party in the
case of the default of Operator, shall promptly give written notice of such
default to such Party and each of the non-defaulting Parties, but not later than
the third Business Day from the due date. If the Operator is in default, it
shall issue notice to the other Parties on the third Business Day after the due
date. The amount not paid by the Defaulting Party shall bear interest from the
date due until paid in full. Interest "Agreed Interest Rate" will be calculated
using the rates specified below:
From due date through fifth Business Day, interest is LIBOR + 0.5
From sixth through thirtieth Business Day, interest is LIBOR + 1.5
From thirty-first through forty-sixth Business Day, interest is LIBOR + 3.0
Beyond forty-sixth Business Day, interest is LIBOR + 5.0
8.2 OPERATING COMMITTEE MEETINGS AND DATA
After any default has continued for thirty (30) Business Days from the date
of written notice of default under Article 8.1, and for as long thereafter as
the Defaulting Party remains in default on any payment due under this Agreement,
the Defaulting Party shall not be entitled to vote on any matter coming before
the Operating Committee during the period such default continues. Unless agreed
otherwise by the non-defaulting Parties, the voting interest of each
non-defaulting Party shall be in the proportion which its Participating Interest
bears to the total of the Participating Interest of all the non-defaulting
Parties. Any matters requiring unanimous vote of the Parties shall be deemed to
exclude the Defaulting Party. Notwithstanding the foregoing, the Defaulting
Party shall be deemed to have approved, and shall join with the non-defaulting
Parties in taking any action to maintain and preserve the Contract.
8.3 ALLOCATION OF DEFAULTED ACCOUNTS
(A) Operator shall, either at the time of giving notice of default as
provided in Article 8.1, or by separate notice, notify each
non-defaulting Party of the sum of money it is to pay as its portion
(such portion being in the ratio that each non-defaulting Party's
Participating Interest bears to the Participating Interests of all
non-defaulting Parties) of such amount in default. Each
non-defaulting Party shall, if such default continues, pay Operator,
within ten (10) Business Days after receipt of such notice, its share
of the amount which the Defaulting Party failed to pay. If any
non-defaulting Party fails to pay its share of the amount in default
as aforesaid, such non-defaulting Party shall thereupon be in default
and shall be a Defaulting Party subject to the provisions of this
Article. The non-defaulting Parties which pay the amount owed by any
Defaulting Party shall be entitled to receive their respective share
of the principal and interest payable by such Defaulting Party
pursuant to Article 8.1.
(B) The total of all amounts paid by the non-defaulting Parties for the
Defaulting Party, together with interest accrued on such amounts
shall constitute a debt due and owing by the Defaulting Party to the
non-defaulting Parties in proportion to such amounts paid. In
addition, the non-defaulting Parties may in the manner contemplated
by this Article, satisfy such debt (together with interest) and may
accrue an amount equal to the Defaulting Party's Participating
Interest share of the estimated cost to abandon any Joint Property.
(C) A Defaulting Party may remedy its default by paying to Operator the
total amount due, together with interest calculated as provided in
Article 8.1, at any time prior to a transfer of its interest pursuant
to Article 8.4, and, upon receipt of such payment, Operator shall
remit to each non-defaulting Party its proportionate share of such
amount.
(D) The rights granted to each non-defaulting Party pursuant to this
Article shall be in addition to and not in substitution for any other
rights or remedies which each non-defaulting Party may have at law or
equity or pursuant to the other provisions of this Agreement.
8.4 TRANSFER OF INTEREST
(A) For thirty (30) Days after each failure by the Defaulting Party to
remedy its default by the ninetieth (90th) Day following notice of
default without prejudice to any other rights of the non-defaulting
Parties to recover the amounts paid for the Defaulting Party,
together with interest accrued on such amount, each non-defaulting
Party shall have the option to give notice to the Defaulting Party
requiring the Defaulting Party to transfer, as specified in Article
8.4(E), its interest to the non-defaulting Parties. To that end if
any of the non-defaulting Parties so elect, the Defaulting Party
shall be deemed to have transferred and to have empowered the
electing non-defaulting Parties to execute on said Defaulting Party's
behalf any documents required to effect a transfer of all of its
right, title and beneficial interest in and under this Agreement and
the Contract and in all wells and Joint Property to the electing
non-defaulting Parties. If requested, each Party shall execute a
Power of Attorney in the form prescribed by the Operating Committee.
The Defaulting Party shall, without delay following any request from
the non-defaulting Parties, do any and all acts required to be done
by applicable law or regulation in order to render such transfer
legally valid, including, without limitation, the obtaining of all
governmental consents and approvals, and shall execute any and all
documents and take such other actions as may be necessary in order to
effect prompt and valid transfer of the interests described above,
free of all liens and encumbrances. In the event all Government
approvals are not timely obtained, the Defaulting Party shall hold
its Participating Interest in trust for such non-defaulting Parties
who elected to assume such Defaulting Party's Participating Interest.
(B) In the absence of an agreement among the non-defaulting Parties to
the contrary, any such transfer to the non-defaulting Parties shall
be in the proportion that the non-defaulting Parties have paid the
amounts due from the Defaulting Party.
(C) Subject to Article 12.1(C), on the effective date of transfer of all
its Participating Interest, the Defaulting Party shall forthwith
cease to be a Party to this Agreement to the extent of the
Participating Interest so transferred. The acceptance or
non-acceptance by a non-defaulting Party of any portion of a
Defaulting Party's Participating Interest shall be without prejudice
to any rights or remedies such non-defaulting Parties have to recover
the outstanding debts (including interest) owed by the Defaulting
Party.
(D) Notwithstanding the above, if pursuant to any mutual agreement
between any of the Parties, one of the Parties makes an additional
contribution on behalf of another Party, the same will not be treated
as a Default of the other Party under this Agreement and Contract.
Such contribution shall not change the Participating Interest of the
Parties.
(E) In the event that the default continues for more than ninety (90)
days (the "Default Period") and the Defaulting Party does not pay the
amount in default plus accrued interest by the end of such time, a
proportion of the Participating Interest of such Defaulting Party
shall, at the sole election of the Non-Defaulting Parties who wish to
acquire such interest, be forfeited to such Non-Defaulting Parties to
reflect the ratio that the cumulative contributions of the Defaulting
Party bears to the total cumulative contributions of all the Parties
to Joint Operations costs, so that following such forfeiture the
remaining Participating Interest of the Defaulting Party as a
proportion of the total Participating Interests of all the Parties is
equal to the said ratio. Following such forfeiture, the reduced
Participating Interest of the Defaulting Party shall be in accordance
with the following formula:
A = B/C where:
A = the reduced Participating Interest of the Defaulting Party, and
B = the total contributions to Joint Operations costs of the Defaulting
Party up to but not including the amount in default, and
C = the total contributions to Joint Operations costs of all the Parties up
to and including the amount in default.
Such forfeiture will not restore the Defaulting Party's powers and
rights forfeited under Article 8.2 until such Defaulting Party has
paid, in full, the first Cash Call following the date of such
forfeiture. The Defaulting Party shall execute such documents as are
necessary to transfer its Participating Interest at its sole cost.
Notwithstanding the provisions of this Article, in the event that as
a result of a forfeiture by the Defaulting Party of a part of its
Participating Interest pursuant to the provisions of this Article,
the remaining Participating Interest the Defaulting Party falls below
ten percent (10%) the Non-Defaulting Parties shall assume such
Participating Interest of the Defaulting Party in proportion to their
Participating Interest or in such other proportion as may be agreed
by them. The Defaulting Party shall execute such documents as are
necessary to transfer its remaining Participating Interest at its
sole cost.
8.5 CONTINUATION OF INTEREST
If within thirty (30) Days after each failure by the Defaulting Party to
remedy its default by the ninetieth (90th) Day following notice of default the
non-defaulting Parties elect to not acquire the Defaulting Party's Participating
Interest as provided in Article 8.4 and to continue to bear the Defaulting
Party's Participating Interest share of liabilities and expenses, then the
non-defaulting Parties shall accumulate all such liabilities and expenses as a
debt pursuant to Article 8, but the Defaulting Party shall continue to be a
Party subject to Article 8.2 and Article 8.7. If Operator disposes of any Joint
Property or any other credit or adjustment is made to the Joint Account, or if
Operator sells any of the Defaulting Party's Participating Interest share of
Hydrocarbons, then, in respect of the Defaulting Party's Participating Interest
share of the proceeds of such disposal, credit or adjustment or sale, Operator
shall be entitled to retain and to set off the same against all amounts,
together with interest accrued on such amount, due and owing from the Defaulting
Party plus an accrued amount equal to the Defaulting Party's Participating
Interest share of the estimated cost to abandon any Joint Property. Any surplus
remaining after setting off the same as aforesaid shall be paid promptly to the
Defaulting Party.
8.6 ABANDONMENT
If, within thirty (30) Days after the failure by the Defaulting Party to
remedy its default by the ninetieth (90th) Day as aforesaid, no non-defaulting
Party elects to acquire the Defaulting Party's Participating Interest as
provided in Article 8.4, or to bear the Defaulting Party's Participating
Interest share of liabilities and expenses as provided in Article 8.5, then no
transfer shall be made and Joint Operations shall be abandoned subject to any
necessary consents and notices being given and each Party, including the
Defaulting Party shall pay its Participating Interest share of all costs of
abandoning and relinquishing the Contract. If abandonment occurs as aforesaid,
all monies paid by the non-defaulting Parties for the Defaulting Party pursuant
to Article 8.3, together with interest accrued on such amount, shall remain a
debt due and owing by the Defaulting Party.
8.7 SALE OF HYDROCARBONS
Notwithstanding anything here else contained in this Agreement, if a Party
defaults after the commencement of commercial production and has not remedied
the default by the ninetieth (90th) Day as aforesaid, then, during the
continuance of such default, the Defaulting Party shall not be entitled to its
Participating Interest share of Hydrocarbons which shall vest in and be the
property of the non-defaulting Parties, and Operator shall be authorized to sell
such Hydrocarbons at the best price obtainable under the circumstances, and,
after deducting all costs, charges and expenses incurred by Operator in
connection with such sale, pay the proceeds proportionately to the
non-defaulting Parties, which proceeds shall be credited against all monies
advanced pursuant to Article 8.3, together with interest accrued thereon. Any
surplus remaining shall be paid to the Defaulting Party, and any deficiency
shall remain a debt due from the Defaulting Party to the non-defaulting Parties.
As soon as the deficiency is satisfied, the Defaulting Party's rights shall be
restored.
8.8 NO RIGHT OF SET OFF
Each Party acknowledges and accepts that a fundamental principle of this
Agreement is that each Party pays its Participating Interest share of all
amounts due under this Agreement as and when required. Accordingly, any Party
which becomes a Defaulting Party undertakes that, in respect of either any
exercise by the non-defaulting Parties of any rights under or the application of
any of the provisions of this Article, such Party shall not raise by way of set
off or invoke as a defense, whether in law or equity, any failure to pay amounts
due and owing under this Agreement or any alleged or unliquidated claim that
such Party may have against Operator or any Non-Operator, whether such claim
arises under this Agreement or otherwise. Such Party further undertakes not to
raise by way of defense, whether in law or in equity, that the nature or the
amount of the remedies granted to the non-defaulting Parties is unreasonable or
excessive.
8.9 MINOR DEFAULT
Notwithstanding the provisions of this Article 8, Articles 8.2 and 8.4
shall have no effect provided the total amount of funds in default is less than
One Million United States Dollars (US$1,000,000).
8.10 REINSTATEMENT OF RIGHTS
In the event that the default is found to be in error, either through
arbitration or otherwise, the Defaulting Party's rights shall be reinstated as
determined by the arbitrators or, if not subjected to arbitration, as otherwise
found to be reasonably appropriate.
ARTICLE IX - DISPOSITION OF PRODUCTION
9.1 RIGHT AND OBLIGATION TO TAKE IN KIND
Except as otherwise provided in this Article, each Party shall have the
right and obligation to own, take in kind and separately dispose of its
Participating Interest share of total production available to the Parties
pursuant to the Contract from any Exploitation Area in such quantities and in
accordance with such procedures as may be set forth in the offtake agreement
referred to in Article 9.2 or in the special arrangements for natural gas
referred to in Article 9.3. If Government is party to the offtake agreement,
then the Parties shall endeavor to obtain its agreement to the principles set
forth in this Article.
9.2 OFFTAKE AGREEMENT FOR CRUDE OIL
If crude oil is to be produced from an Exploitation Area, the Parties shall
in good faith, negotiate and conclude the terms of an agreement to cover the
offtake of crude oil produced under the Contract. The Government may, if
necessary and practicable, also be party to the offtake agreement. This offtake
agreement shall, to the extent consistent with the Contract, make provision for:
(A) The delivery point, at which title and risk of loss of Participating
Interest shares of crude oil shall pass to the Parties interested (or
as the Parties may otherwise agree);
(B) Operator's regular periodic advice to the Parties of estimates of
total available production for succeeding periods, Participating
Interest shares, and grades of crude oil for as far ahead as is
necessary for Operator and the Parties to plan offtake arrangements.
Such advice shall also cover for each grade of crude oil total
available production and deliveries for the preceding period,
inventory and overlifts and underlifts;
(C) Nomination by the Parties to Operator of acceptance of their
Participating Interest share of total available production for the
succeeding period. Such nominations shall in any one period be for
each Party's entire Participating Interest share arising during that
period subject to operational tolerances and agreed minimum economic
cargo sizes or as the Parties may otherwise agree;
(D) Elimination of overlifts and underlifts;
(E) If offshore loading or a shore terminal for vessel loading is
involved, risks regarding acceptability of tankers, demurrage and (if
applicable) availability of berths;
(F) Distribution to the Parties of Entitlements to ensure, to the extent
Parties take delivery of their Entitlements in proportion to the
accrual of such Entitlements, that each Party shall receive currently
Entitlements of grades, gravities and qualities of Hydrocarbons
similar to Hydrocarbons received by each other Party.
(G) To the extent that distribution of Entitlements on such basis is
impracticable due to availability of facilities and minimum cargo
sizes, a method of making periodic adjustments; and
(H) The option and the right of the other Parties to sell an Entitlement
which a Party fails to nominate for acceptance pursuant to (C) above
or of which a Party fails to take delivery, in accordance with
applicable agreed procedures, provided that such failure either
constitutes a breach of Operator's or Parties' obligations under the
terms of the Contract, or is likely to result in the curtailment or
shut-in of production. Such sales shall be made only to the limited
extent necessary to avoid disruption in Joint Operations. Operator
shall give all Parties as much notice as is practicable of such
situation and that a sale option has arisen. Any sale shall be of the
unnominated or undelivered Entitlement as the case may be and for
reasonable periods of time as are consistent with the minimum needs
of the industry and in no event to exceed twelve (12) months. The
right of sale shall be revocable at will subject to any prior
contractual commitments. Sales to non-affiliated third parties shall
be for the realized price f.o.b. the delivery point. Sales to any of
the Parties or their Affiliates shall be at current market value
f.o.b. the delivery point. The Party arranging the sale shall pay to
the Party whose Entitlement is involved the above price after
deduction of all costs, including storage costs, incurred in respect
of such sale and a marketing fee of an agreed percentage of the
applicable price less deductions, reflecting actual costs of disposal
at immediate notice. Current market value shall be the value of the
Entitlement in international markets (unless the Entitlement was
required to be delivered into the Government's domestic market, in
which case it shall be the value therein) between a willing buyer and
a willing seller and shall be agreed between the two Parties
concerned, or failing agreement, determined by an expert to be
appointed in accordance with procedures set forth in the offtake
agreement.
9.3 SEPARATE AGREEMENT FOR NATURAL GAS
The Parties recognize that it may be necessary for the Parties to enter
into special arrangements for the disposal of the natural gas, which are
consistent with the Development Plan and subject to the terms of the Contract.
ARTICLE X - ABANDONMENT OF WELLS
10.1 ABANDONMENT OF WELLS DRILLED AS JOINT OPERATIONS
(A) Any well which has been drilled as a Joint Operation and which is
proposed to be plugged and abandoned shall not be plugged and
abandoned without the consent of all Parties.
(B) Should any such Party fail to reply within the period prescribed in
Article 5.12(A)(1) or Article 5.12(A)(2), whichever is applicable,
after delivery of notice of the Operator's proposal to plug and
abandon such well, such Party shall be deemed to have consented to
the proposed abandonment. If all the Parties consent to abandonment,
such well shall be plugged and abandoned in accordance with
applicable regulations and at the cost, risk and expense of the
Parties who participated in the cost of drilling such well.
(C) If there is a disagreement amongst the Parties regarding the
abandonment of such well, those wishing to continue operations shall
assume financial responsibility over the well and shall be deemed to
be Consenting Parties conducting an Exclusive Operation pursuant to
Article VII. In the case of a producing well, the Consenting Parties
shall be entitled to continue producing only from the Zone open to
production at the time they assumed responsibility for the well.
(D) Consenting Parties taking over a well as provided above shall tender
to each of the Non-Consenting Parties such Non-Consenting Parties'
Participating Interest share of the value of the well's salvable
material and equipment, determined in accordance with the Accounting
Procedure, less the estimated cost of salvaging and the estimated
cost of plugging and abandoning as of the date the Consenting Party
assumed responsibility for the well; provided, however, that in the
event the estimated cost of plugging and abandoning and the estimated
cost of salvaging are higher than the value of the well's salvable
material and equipment, each of the abandoning Parties shall continue
to be liable pursuant to Article 7.3(B) for their respective
Participating Interest shares of the estimated excess cost.
(E) Each Non-Consenting Party shall be deemed to have relinquished to the
Consenting Parties in proportion to their Participating Interests all
of its interest in the wellbore of a produced well and related
equipment in accordance with Article 7.4(B), insofar and only insofar
as such interest covers the right to obtain production from that
wellbore in the Zone then open to production.
(F) Subject to Article 7.9(G), Operator shall continue to operate a
produced well for the account of the Consenting Parties at the rates
and charges contemplated by this Agreement, plus any additional cost
and charges which may arise as the result of the separate allocation
of interest in such well.
10.2 ABANDONMENT OF EXCLUSIVE OPERATIONS
This Article shall apply mutatis mutandis to the abandonment of an
Exclusive Well or any well in which an Exclusive Operation has been conducted;
provided that no well shall be permanently plugged and abandoned unless and
until all Parties having the right to conduct further operations in such well
have been notified of the proposed abandonment and afforded the opportunity to
elect to take over the well in accordance with the provisions of this Article X.
ARTICLE XI - SURRENDER
11.1 SURRENDER
(A) If the Contract requires the Parties to surrender any portion of the
Contract Area, Operator shall advise the Operating Committee of such
requirement at least one hundred and twenty (120) Days in advance of
the earlier of the date for filing irrevocable notice of such
surrender or the date of such surrender. Prior to the end of such
period, the Operating Committee shall determine pursuant to Article
V, the size and shape of the surrendered area, consistent with the
requirements of the Contract. If no proposal attains the support of
one hundred percent (100%) of the Participating Interests, then the
proposal receiving the largest aggregate Participating Interest vote
shall be adopted. The Parties shall execute any and all documents and
take such other actions as may be necessary to effect the surrender.
Each Party renounces all claims and causes of action against Operator
and any other Parties on account of any area surrendered in
accordance with the foregoing but against its recommendation if
Hydrocarbons are subsequently discovered under the surrendered area.
(B) A surrender of all or any part of the Contract Area which is not
required by the Contract shall require the unanimous consent of the
Parties.
ARTICLE XII - TRANSFER OF INTEREST OR RIGHTS
12.1 OBLIGATIONS
(A) Subject always to the requirements of the Contract, the transfer of
all or part of a Party's Participating Interest shall be effective
only if it satisfies the terms and conditions of this Article.
(B) Except in the case of a Party transferring all of its Participating
Interest, no transfer shall be made by any Party which results in the
transferor or the transferee holding a Participating Interest of less
than ten percent (10%) or holding any Interest other than a
Participating Interest in the Contract, the Contract Area and this
Agreement.
(C) The transferring Party shall, notwithstanding the transfer, be liable
to the other Parties for any obligations, financial or otherwise,
which have vested, matured or accrued under the provision of the
Contract or this Agreement prior to such transfer. Such obligations
shall include, without limitation, any proposed expenditure approved
by the Operating Committee, prior to the transferring Party notifying
the other Parties of its proposed transfer.
(D) The transferee shall have no rights in and under the Contract, the
Contract Area or this Agreement unless and until it obtains any
necessary Government approval and expressly undertakes in writing to
perform the obligations of the transferor under the Contract and this
Agreement in respect of the Participating Interest being transferred,
to the satisfaction of the Parties and furnishes any guarantees
required by the Government or the Contract.
(E) The transferee shall have no rights in and under the Contract, the
Contract Area or this Agreement unless each Party has consented in
writing to such transfer, which consent shall be denied only if such
transferee fails to establish to the reasonable satisfaction of each
Party its financial or technical capability to perform its
obligations under the Contract and this Agreement.
(F) Nothing contained in this Article shall prevent a Party from
mortgaging, pledging, charging or otherwise encumbering all or part
of its interest in the Contract Area in and under this Agreement for
the purpose of security relating to finance provided that:
(1) such Party shall remain liable for all obligations relating
to such interest;
(2) the encumbrance shall be subject to the approval of the
Management Committee and any necessary approval under the
Contract and be expressly subordinated to the rights of the
other Parties under this Agreement; and
(3) such Party shall ensure that any such mortgage, pledge,
charge or encumbrance shall be expressed to be without
prejudice to the provisions of this Agreement.
(G) In the event a Party receives an offer to purchase all or a part of
its Participating Interest, it shall so notify the other Parties and
they shall have the right for a period of ten (10) days to make an
offer. If a Party elects to sell all or a part of its Participating
Interest, it shall so notify the other Parties upon offering the
Participating Interest for sale. 12.2 RIGHTS Each Party shall have
the right, subject to the provisions of Article 12.1, to freely
transfer its Participating Interest.
ARTICLE XIII - WITHDRAWAL FROM AGREEMENT BY TRANSFER OR ASSIGNMENT
13.1 RIGHT OF WITHDRAWAL
(A) Subject to the provisions of the Contract and this Article, any Party
may withdraw from this Agreement and the Contract by giving notice to
all other Parties stating its decision to withdraw and specifying a
proposed effective date of withdrawal which shall be at least sixty
(60) Days, but not more than one hundred eighty (180) Days after the
date of such notice. Such notice shall be unconditional and
irrevocable when given.
(B) Notwithstanding Article 13.1(A) a Party shall not have the right to
withdraw from this Agreement and the Contract until the Minimum Work
Obligation set forth in the Contract has been fulfilled. However, if
the Operating Committee or any Party decides to accept new Minimum
Work Obligations under the Contract, a Party that voted against such
decision shall not be prevented from withdrawing; provided that such
Party delivers notice of its withdrawal to all Parties within thirty
(30) Days of such vote and fully satisfies its outstanding Minimum
Work Obligation, if any.
(C) Subject to Articles 13.1(A) and (B) and Article 13.5, the effective
date of withdrawal for a withdrawing Party shall be the later of:
(1) The date proposed in the notice of withdrawal; or
(2) The date that the withdrawing Party has fulfilled its
obligations under this Article.
13.2 PARTIAL OR COMPLETE WITHDRAWAL
(A) Within thirty (30) Days of receipt of each withdrawing Party's
notification, each of the other Parties may also give notice that it
desires to withdraw from this Agreement and the Contract. Should all
Parties give notice of withdrawal, the Parties shall proceed to
abandon the Contract Area and terminate the Contract and this
Agreement. If less than all of the Parties give such notice of
withdrawal, then the withdrawing Parties shall take all steps to
withdraw from the Contract and this Agreement on the earliest
possible date and execute and deliver all necessary instruments and
documents to assign their Participating Interest to the Parties which
are not withdrawing, without any compensation whatsoever, in
accordance with the provisions of Article 13.6.
(B) If any part of the withdrawing Party's Participating Interest remains
unclaimed after sixty (60) Days from the date of the first notice of
withdrawal, the Parties shall be deemed to have decided to withdraw
from the Contract and this Agreement, unless at least one Party
agrees to accept the unclaimed Participating Interest.
(C) Any Party withdrawing under this Article shall withdraw from all
exploration activities under the Contract, but not from any
Exploitation Area, Commercial Discovery, or Discovery whether
appraised or not, made prior to such withdrawal. Such withdrawing
Party shall retain its rights in the Joint Property but only insofar
as they relate to any Exploitation Area, Commercial Discovery or
Discovery whether appraised or not, and shall abandon all other
rights in the Joint Property.
13.3 VOTING
After giving its notification of withdrawal, a Party shall not be entitled
to vote on any matters coming before the Operating Committee, other than matters
for which such Party has financial responsibility.
13.4 OBLIGATIONS AND LIABILITIES
(A) A withdrawing Party, prior to its withdrawal, shall satisfy all
obligations and liabilities it has incurred or attributable to it
prior to its withdrawal, including, without limitation, any
expenditures budgeted and/or approved by the Operating Committee
prior to its written notification of withdrawal (development projects
included), and any liability for acts, occurrences or circumstances
taking place or existing prior to its withdrawal. Furthermore, any
liens, charges and other encumbrances which the withdrawing Party
placed on such Party's Participating Interest prior to its withdrawal
shall be fully satisfied or released, at the withdrawing Party's
expense, prior to its withdrawal. A Party's withdrawal shall not
relieve it from liability to the non-withdrawing Parties with respect
to any obligations or liabilities attributable to the withdrawing
Party which are not identified or identifiable at the time of
withdrawal.
(B) Notwithstanding the foregoing, a Party shall not be liable for any
operations or expenditures it voted against if it sends notification
of its withdrawal within five (5) Days (or within twenty-four (24)
hours if the drilling rig to be used in such operation is standing by
on the Contract Area) of the Operating Committee vote approving such
operation or expenditure, nor shall such Party be liable for any
operations or expenditures approved by the Operating Committee,
excluding those approved pursuant to Article 13.5, after notice has
been given pursuant to Article 13.1.
13.5 EMERGENCY
A Party's notification of withdrawal shall not become effective if prior to
the proposed date of withdrawal a well goes out of control or a fire, blowout,
sabotage or other emergency occurs. The notification of withdrawal shall become
effective only after the emergency has been contained and the withdrawing Party
has paid, or has provided security satisfactory to the Parties, for its
Participating Interest share of the costs of such emergency.
13.6 ASSIGNMENT
A withdrawing Party shall assign its Participating Interest to each of the
non-withdrawing Parties which shall be allocated to them in the proportion which
each of their Participating Interests (prior to the withdrawal) bears to the
total Participating Interests of all the non- withdrawing Parties (prior to the
withdrawal), unless the non- withdrawing Parties agree otherwise. The expenses
associated with the withdrawal and assignments shall be borne by the withdrawing
Party.
13.7 APPROVALS
A withdrawing Party shall promptly join in such actions as may be necessary
or desirable to obtain any Government approvals required in connection with the
withdrawal and assignments, and any penalties or expenses incurred by the
Parties in connection with such withdrawal shall be borne by the withdrawing
Party.
13.8 ABANDONMENT SECURITY
(A) A withdrawing Party shall provide Security satisfactory to the other
Parties to satisfy any such obligations or liabilities which were
approved or accrued prior to notice of withdrawal, but which become
due after its withdrawal, including, without limitation, Security to
cover the costs of an abandonment, if applicable.
(B) Failure to provide Security shall constitute default under this
Agreement.
(C) "Security" means a standby letter of credit issued by a bank or an on
demand bond issued by a corporation, such bank or corporation having
a credit rating indicating it has sufficient worth to pay its
obligations in all reasonably foreseeable circumstances, or, failing
the provision of either of those, cash contributed to a secure fund
administered by independent trustees and invested in short term
securities.
13.9 WITHDRAWAL OR ABANDONMENT BY ALL PARTIES
In the event all Parties decide to withdraw or are required to do so
pursuant to this Article, the Parties agree that they shall be bound by the
terms and conditions of this Agreement and the Contract for so long as may be
necessary to wind up the affairs of the Parties with the Government, to satisfy
any requirements of applicable law and facilitate the sale, disposition or
abandonment of property or interests held by the Joint Account.
ARTICLE XIV - RELATIONSHIP OF PARTIES AND TAX
14.1 RELATIONSHIP OF PARTIES
Unless otherwise specified, the rights, duties, obligations and liabilities
of the Parties under this Agreement shall be individual, not joint or
collective. It is not the intention of the Parties to create, nor shall this
Agreement be deemed or construed to create a mining or other partnership, joint
venture, association or trust, or as authorizing any Party to act as an agent,
servant or employee for any other Party for any purpose whatsoever except as
explicitly set forth in this Agreement. In their relations with each other under
this Agreement, the Parties shall not be considered fiduciaries except as
expressly provided in this Agreement.
14.2 TAX
Each Party shall be responsible for reporting and discharging its own tax
measured by the income of the Party and the satisfaction of such Party's share
of all contract obligations under the Contract and under this Agreement. Each
Party shall protect, defend and indemnify each other Party from any and all
loss, cost or liability arising from a failure or refusal to report and
discharge such taxes or satisfy such obligations.
ARTICLE XV - CONFIDENTIAL INFORMATION - PROPRIETARY TECHNOLOGY
15.1 CONFIDENTIAL INFORMATION
(A) Subject to the provisions of the Contract, the Parties agree that all
information and data acquired or obtained by any Party in respect of
Joint Operations shall be considered confidential and shall be kept
confidential and not be disclosed during the term of the Contract and
for a period of one (1) year after expiration of the Contract to any
person or entity not a Party to this Agreement, except:
(1) To an Affiliate, in connection with Petroleum Operations,
provided such Affiliate maintains confidentiality as
provided in this Article;
(2) To a governmental agency or other entity when required by
the Contract;
(3) To the extent such data and information is required to be
furnished in compliance with any applicable laws or
regulations, or pursuant to any legal proceedings or because
of any order of any court binding upon a Party;
(4) Subject to Article 15.1(B), to potential contractors,
contractors, consultants and attorneys employed by any Party
where disclosure of such data or information is essential to
such contractor's, consultant's or attorney's work;
(5) Subject to Article 15.1(B), to a bona fide prospective
transferee of a Party's Participating Interest (including an
entity with whom a Party or its Affiliates is conducting
bona fide negotiations directed toward a merger,
consolidation or the sale of a majority of its or an
Affiliate's shares);
(6) Subject to Article 15.1(B), to a bank or other financial
institution to the extent appropriate to a Party arranging
for funding for its obligations under this Agreement;
(7) To the extent such data and information must be disclosed
pursuant to any rules or requirements of any government or
stock exchange having jurisdiction over such Party, or its
Affiliates; provided that if any Party desires to disclose
information in an annual or periodic report to its or its
Affiliates' shareholders and to the public and such
disclosure is not required pursuant to any rules or
requirements of any government or stock exchange, then such
Party shall comply with Article 20.2;
(8) To its respective employees for the purposes of Joint
Operations, subject to each Party taking customary
precautions to ensure such data and information is kept
confidential;
(9) Where any data or information which, through no fault of a
Party, becomes a part of the public domain.
(B) Disclosure as pursuant to Article 15.1(A)(4), (5), and (6) shall not
be made unless prior to such disclosure the disclosing Party has
obtained a written undertaking from the recipient party to keep the
data and information strictly confidential and not to use or disclose
the data and information except for the express purpose for which
disclosure is to be made.
15.2 CONTINUING OBLIGATIONS
Any Party ceasing to own a Participating Interest during the term of this
Agreement shall nonetheless remain bound by the obligations of confidentiality
and any disputes shall be resolved in accordance with Article XVIII.
15.3 PROPRIETARY TECHNOLOGY
(A) Nothing in this Agreement shall require a Party to divulge
proprietary technology to the other Parties; provided that where the
cost of development of proprietary technology has been charged to the
Joint Account, such proprietary technology shall be disclosed to all
Parties bearing a portion of such cost and may be used by such Party
or its Affiliates in other operations. Operator will not charge for
the use of its proprietary technology. Operator will use reasonable
efforts to keep Non-Operators informed of the use of the proprietary
technology.
(B) Non-Operators shall have access to basic field data obtained through
Operator's utilization of proprietary technology and to final maps,
data and information resulting from such utilization, with
entitlement to copies of such basic final data, maps and information
as provided for in this Agreement.
15.4 TRADES
Notwithstanding the foregoing provisions of this Article, Operator may,
with approval of the Management Committee, make data trades for the benefit of
the Parties, with any data, the cost of which has been charged to the Joint
Account, so obtained to be furnished to all Parties. In such event, Operator
must enter into an undertaking with any third party to such trade to keep such
information confidential.
ARTICLE XVI - FORCE MAJEURE
16.1 OBLIGATIONS
If as a result of Force Majeure any Party is rendered unable, wholly or in
part, to carry out its obligations under this Agreement, other than the
obligation to pay any amounts due or to furnish security, then the obligations
of the Party giving such notice, so far as and to the extent that the
obligations are affected by such Force Majeure, shall be suspended during the
continuance of any inability so caused, but for no longer period. The Party
claiming Force Majeure shall notify the other Parties of the Force Majeure
situation within seven (7) days, unless prevented from so doing, after the
occurrence of the facts relied on and shall keep all Parties informed of all
significant developments. Such notice shall give particulars establishing the
event of Force Majeure, and also estimate the period of time which said Party
will probably require to remedy the Force Majeure. The affected Party shall use
all reasonable diligence to remove or overcome the Force Majeure situation as
quickly as possible in an economic manner, but shall not be obligated to settle
any labor dispute except on terms acceptable to it and all such disputes shall
be handled within the sole discretion of the affected Party.
16.2 DEFINITION OF FORCE MAJEURE
(A) For the purpose of this Agreement, the term Force Majeure means any
cause or event, other than the unavailability of funds, whether
similar to or different from those enumerated herein, beyond the
reasonable control of, and unanticipated and unforeseeable by, and
not brought about at the instance of the Party claiming to be
affected by such event, or which, if anticipated or foreseeable,
could not be avoided or provided for and which has caused the
non-performance or delay in performance. Without limitation to the
generality of the foregoing, the term Force Majeure shall include
natural phenomena or calamities, earthquakes, typhoons, fires, wars
declared or undeclared, hostilities, invasion, blockades and civil
disturbances.
(B) Where a Party is prevented from exercising any rights or performing
any obligations under this Agreement due to Force Majeure, the time
for the performance of the obligations affected thereby and for
performance of any obligation or the exercise of any right dependent
thereon, and the term of this Agreement, may be extended by such
additional period as may be agreed by the Parties.
(C) Notwithstanding anything contained hereinabove, if any event of Force
Majeure occurs and is likely to continue for a period in excess of
thirty (30) days, the Parties shall meet to discuss the consequences
of the Force Majeure and the course of action to be taken to mitigate
the effects thereof or to be adopted in the circumstances.
ARTICLE XVII - NOTICES
Except as otherwise specifically provided, all notices authorized or
required between the Parties by any of the provisions of this Agreement, shall
be in writing, in English and delivered in person or by registered mail or by
courier service or by any electronic means of transmitting written
communications which provides confirmation of complete transmission, with the
date and time, and addressed to such Parties as designated below. The
originating notice given under any provision of this Agreement shall be deemed
delivered only when received by the Party to whom such notice is directed, and
the time for such Party to deliver any notice in response to such originating
notice shall run from the date the originating notice is received. The second or
any responsive notice shall be deemed delivered when received. "Received" for
purposes of this Article with respect to written notice delivered pursuant to
this Agreement shall be actual delivery of the notice to the address of the
Party to be notified specified in accordance with this Article. Each Party shall
have the right to change its address at any time and/or designate that copies of
all such notices be directed to another person at another address, by giving
written notice thereof to all other Parties. Any notice to be provided hereunder
shall be deemed to be received by the sending Party upon delivery of such notice
to the other Parties. Operator shall, in the event of its failure to meet cash
calls or make timely payments when due to the Non-Operators, be deemed to have
received notice as if it had been timely sent to Operator.
Enron Oil & Gas India Ltd. Oil & Natural Gas Corporation Limited
Amiya Apartments, 1st Floor Tower II, 8th Floor, Jeevan Bharati
63A Linking Road, Santa Cruz (W) 124 Connaught Circus
Bombay 400 054, INDIA New Delhi 110001, INDIA
Attention: Managing Director Attention: General Manager
Telecopy: 91-22-604-9119 Telecopy: 91-11-331-6413
Reliance Industries Limited
Maker Chambers IV, 3rd Floor
222 Nariman Point
Bombay 400021, INDIA
Attention: Chief Executive Officer Oil & Gas
Telecopy: 022-2042268
ARTICLE XVIII - APPLICABLE LAW AND DISPUTE RESOLUTION
18.1 APPLICABLE LAW
This Agreement shall be governed by, construed, interpreted and applied in
accordance with the laws of India.
18.2 DISPUTE RESOLUTION
(A) Disputes and claims, if any, arising out of or relating to this
Agreement or the interpretation or performance of provisions of any
of the Articles of this Agreement and which cannot be settled
amicably within a reasonable time may be submitted to the decision of
a sole expert timely selected by the Operating Committee or a board
of arbitrators.
(B) The board of arbitrators shall consist of three (3) arbitrators.
(C) The Party or Parties instituting the arbitration shall appoint one
arbitrator and the Party or Parties responding shall appoint another
arbitrator and both Parties shall so advise the other Parties. The
two (2) arbitrators appointed by the Parties shall appoint the third
arbitrator.
(D) If the responding Party or Parties fails to appoint an arbitrator
within thirty (30) Days of the receipt of the written request to do
so, such arbitrator may, at the request of the first Party, be
appointed by the Secretary General of the Permanent Court of
Arbitration at The Hague, which arbitrator shall not be the national
of the country of either Party.
(E) If the two (2) arbitrators fail to agree on the appointment of the
third arbitrator within thirty (30) days of the appointment of the
second arbitrator and if the Parties do not otherwise agree,the
Secretary General of the Permanent Court of Arbitration at the Hague
may, at the request of either Party and in consultation with both,
appoint the third arbitrator who shall not be a national of the
country of either Party.
(F) If any arbitrator fails or is unable to act, his successor shall be
appointed in the manner set out in this Article as if he was the
first appointment.
(G) The decision of the board of arbitrators, and in case of difference
amongst the arbitrators, the decision of the majority shall be final
and binding upon the Parties. Such decision may be entered into the
Indian court having jurisdiction thereof.
(H) Arbitration proceedings shall be in accordance with the arbitration
rules of the United Nations Commission on International Trade Laws
("UNCITRAL") of 1985 except that in the event of any conflict between
these rules and the provisions of Article 18, the provisions of
Article 18 shall govern.
(I) The venue of arbitration shall be in London, England and shall be
conducted in the English language. The arbitration agreement
contained in this Article 18 shall be governed by the laws of
England.
(J) Assessment of costs of arbitration including incidental expenses and
liability for the payment thereof shall be at the discretion of the
arbitrators.
(K) The right to arbitrate disputes and claims under this Agreement shall
survive the termination of this Agreement.
(L) The arbitrators shall make reasoned award.
(M) The sole expert, if any, shall be an independent and impartial person
of international standing with relevant qualifications and experience
appointed by agreement between the Parties. Any sole expert appointed
shall be acting as an expert and not as an arbitrator and the
decision of the sole expert on matters referred to him shall be final
and binding on the Parties and not subject to arbitration. If the
Parties are unable to agree on a sole expert, the disputed subject
matter may be referred to arbitration.
(N) The fees and expenses of a sole expert appointed by the Parties shall
be borne equally by the Parties.
ARTICLE XIX - ALLOCATION OF COST RECOVERY RIGHTS
19.1 ALLOCATION OF TOTAL PRODUCTION
For the purposes of recovery of Petroleum Costs, the total quantity of
Hydrocarbons which are produced and saved from all Development Areas in a
Calendar Quarter and to which the Parties are entitled under the Contract shall
be designated as either Cost Petroleum or Profit Petroleum. Such Cost Petroleum
and Profit Petroleum shall be allocated among the Development Areas in
proportion to each Development Area's total quantity of Hydrocarbons produced
and saved in such Calendar Quarter with adjustments in quantities to reflect the
differences in value if different qualities of Hydrocarbons are produced,
segregated and sold separately.
19.2 ALLOCATION OF COST PETROLEUM
Cost Petroleum allocated to each Development Area pursuant to Article 19.1
shall be allocated to the Parties in proportion to their respective
Participating Interests in each such Development Area to the extent required to
recover in the sequence incurred all Petroleum Costs which are specifically
attributable to each such Development Area and which are recoverable in such
Calendar Quarter.
19.3 ALLOCATION OF PROFIT PETROLEUM
Profit Petroleum allocated to each Development Area pursuant to Article
19.1, if any, shall be allocated among the Parties in proportion to their
respective Participating Interests in each such Development Area.
19.4 ALLOCATION OF EXCESS COST PETROLEUM
Subject to the Contract, to the extent that the value, determined in
accordance with Article 9.2(H), of the Cost Petroleum allocated to each
Development Area pursuant to Article 19.1 exceeds the Petroleum Costs which were
specifically attributable to each such Development Area and which were recovered
pursuant to Article 19.2, the excess ("Excess Cost Petroleum") shall be
allocated as follows:
(A) First, a percentage (equal to the percentage of Profit Petroleum, if
any, to which the Parties would have been entitled during such
Calendar Quarter if the Contract applied separately to each such
Development Area) of the Excess Cost Petroleum shall be allocated
among the Parties in proportion to their respective Participating
Interests in each such Development Area;
(B) Second, the Excess Cost Petroleum that is not allocated pursuant to
Article 19.4(A) shall be allocated among the Parties in proportion to
their respective Participating Interests as set out in Article 3.1(A)
in order to recover in the sequence incurred any Petroleum Costs
which were incurred in the conduct of Joint Operations and which are
recoverable in such Calendar Quarter; and
(C) Third, the Excess Cost Petroleum that is not allocated pursuant to
Article 19.4(A) or Article 19.4(B) shall be allocated among the
Parties in proportion to their respective Participating Interests in
each Exclusive Operation in order to recover in the sequence incurred
any Petroleum Costs which were incurred in the conduct of Exclusive
Operations and which are recoverable in such Calendar Quarter.
ARTICLE XX - GENERAL PROVISIONS
20.1 CONFLICTS OF INTEREST
(A) Each Party undertakes that it shall avoid any conflict of interest
between its own interests (including the interests of Affiliates) and
the interests of the other Parties in dealing with suppliers,
customers and all other organizations or individuals doing or seeking
to do business with the Parties in connection with activities
contemplated under this Agreement.
(B) The provisions of the preceding paragraph shall not apply to:
(1) A Party's performance which is in accordance with the local
preference laws or policies of the host government; or
(2) A Party's acquisition of products or services from an
Affiliate, or the sale thereof to an Affiliate, made in
accordance with rules and procedures established by the
Operating Committee.
(C) Each Party shall conduct all of its activities pursuant to this
Agreement and the Contract in compliance with all laws, rules and
regulations applicable to such Party. Each of the Parties warrants
that it has not made and will not make, with respect of the matters
provided for hereunder, any payments, loans, gifts or promises of
payments, loans or gifts, directly or indirectly to or for the use or
benefit of any official or employee of the Government or to or for
the use of any political party. Each Party shall respond promptly,
and in reasonable detail, to any Notice from any other Party or the
auditors pertaining to the above stated warranty and shall furnish
documentary support for such response upon request from such Party.
20.2 PUBLIC ANNOUNCEMENTS
(A) Operator shall be responsible for the preparation and release of all
public announcements and statements regarding this Agreement or the
Joint Operations; provided that, no public announcement or statement
shall be issued or made unless prior to its release all the Parties
have been furnished with a copy of such statement or announcement and
the unanimous approval of the Parties has been obtained. Where a
public announcement or statement becomes necessary or desirable
because of danger to or loss of life, damage to property or pollution
as a result of activities arising under this Agreement, Operator is
authorized to issue and make such announcement or statement without
prior approval of the Parties, but shall promptly furnish all the
Parties with a copy of such announcement or statement.
(B) If a Party wishes to issue or make any public announcement or
statement regarding this Agreement or the Joint Operations, it shall
not do so unless prior to its release, such Party furnishes all the
Parties with a copy of such announcement or statement, and obtains
the unanimous approval of the Parties; provided that, notwithstanding
any failure to obtain such approval, no Party shall be prohibited
from issuing or making any such public announcement or statement if
it is necessary to do so in order to comply with the applicable laws,
rules or regulations of any government, legal proceedings or stock
exchange having jurisdiction over such Party as set forth in Articles
15.1(A)(3) and (7).
20.3 SUCCESSORS AND ASSIGNS
Subject to the limitations on transfer contained in Article XII, this
Agreement shall inure to the benefit of and be binding upon the successors and
assigns of the Parties.
20.4 WAIVER
No waiver by any Party of any one or more defaults by another Party in the
performance of this Agreement shall operate or be construed as a waiver of any
future default or defaults by the same Party, whether of a like or of a
different character. Except as expressly provided in this Agreement no Party
shall be deemed to have waived, released or modified any of its rights under
this Agreement unless such Party has expressly stated, in writing, that it does
waive, release or modify such right.
20.5 SEVERANCE OF INVALID PROVISIONS
If and for so long as any provision of this Agreement shall be deemed to be
judged invalid for any reason whatsoever, such invalidity shall not affect the
validity or operation of any other provision of this Agreement except only so
far as shall be necessary to give effect to the construction of such invalidity,
and any such invalid provision shall be deemed severed from this Agreement
without affecting the validity of the balance of this Agreement.
20.6 MODIFICATIONS
Except as is provided in Article 20.5, there shall be no modification of
this Agreement except by written consent of all Parties.
20.7 HEADINGS
The topical headings used in this Agreement are for convenience only and
shall not be construed as having any substantive significance or as indicating
that all of the provisions of this Agreement relating to any topic are to be
found in any particular Article.
20.8 SINGULAR AND PLURAL
Reference to the singular includes a reference to the plural and vice
versa.
20.9 GENDER
Reference to any gender includes a reference to all other genders.
20.10 COUNTERPART EXECUTION
This Agreement may be executed in any number of counterparts and each such
counterpart shall be deemed an original Agreement for all purposes; provided no
Party shall be bound to this Agreement unless and until all Parties have
executed a counterpart. For purposes of assembling all counterparts into one
document, Operator is authorized to detach the signature page from one or more
counterparts and, after signature thereof by the respective Party, attach each
signed signature page to a counterpart.
20.11 CONFLICT WITH CONTRACT
In the event of any inconsistency between the provisions of the Contract
and this Agreement, the provisions of the Contract shall prevail.
20.12 ENTIRETY
This Agreement is the entire agreement of the Parties and supersedes all
prior understandings and negotiations of the Parties.
IN WITNESS of their agreement each Party has caused its duly authorized
representative to sign this instrument on the date indicated below such
representative's signature.
ENRON OIL & GAS INDIA LTD.
By: /s/ A. KOPECKY
A. Kopecky
(Print or type name)
Title: Vice President - Operations
Date: 22 Dec 94
RELIANCE INDUSTRIES LIMITED
By: /s/ AKHIL GUPTA
Akhil Gupta
(Print or type name)
Title: CEO (Oil & Gas)
Date: 22-12-94
OIL & NATURAL GAS CORPORATION LIMITED
By: /s/ Iswari Datt
ISWARI DATT
(Print or type name)
Title: Director Operations (on leave)
Date: 22-12-94
<PAGE>
EXHIBIT A
ACCOUNTING PROCEDURE
Attached to and made part of the Joint Operating Agreement, hereinafter
called the "Agreement," by and between OIL & NATURAL GAS CORPORATION LIMITED,
ENRON OIL & GAS INDIA LTD. AND RELIANCE INDUSTRIES LIMITED.
SECTION I.
GENERAL PROVISIONS
1.1 PURPOSE.
1.1.1 The purpose of this Accounting Procedure is to
establish equitable methods for determining charges and
credits applicable to operations under the Agreement
which reflect the costs of Joint Operations to the end
that no Party shall gain or lose in relation to other
Parties.
1.1.2 The Parties agree, however, that if the methods prove
unfair or inequitable to Operator or Non-Operators, the
Parties will meet and in good faith endeavor to agree
on changes in methods deemed necessary to correct any
unfairness or inequity.
1.2 CONFLICT WITH AGREEMENT. In the event of a conflict between the provi
sions of this Accounting Procedure and the provisions of the
Agreement to which this Accounting Procedure is attached, the
provisions of the Agreement shall prevail.
1.3 DEFINITIONS. The definitions contained in Article I of the Agreement
to which this Accounting Procedure is attached shall apply to this
Accounting Procedure and have the same meanings when used herein.
Certain terms used herein are defined as follows:
"COUNTRY OF OPERATIONS" shall mean India.
"MATERIAL" shall mean property, not including real property, acquired and
held for use in Joint Operations.
1.4 JOINT ACCOUNT RECORDS AND CURRENCY EXCHANGE.
1.4.1 All accounts, records, books, reports and statements
shall be maintained on an accrual basis and prepared in
the English language. The accounts shall be maintained
in United States Dollars, which shall be the
controlling currency of account for cost recovery,
production sharing and participation purposes. Metric
units and Barrels shall be employed for measurements
required under the Contract. Operator shall maintain
accounts and records in Indian Rupees also.
1.4.2 Operator shall maintain accounting records pertaining
to Joint Operations in accordance with generally
accepted accounting practices used in the international
petroleum industry and any applicable statutory
obligations of the Country of Operations as well as the
provisions of this Contract and the Agreement.
1.4.3 For translation purposes between United States Dollars
and India Rupees or any other currency, the previous
month's average of the daily means of the buy and
selling rates of exchange as quoted by the State Bank
of India (or any other financial body as may be
mutually agreed between the Parties) shall be used for
the month in which the revenues, costs, expenditures,
receipts or income are recorded. However, in the case
of any single non-United States Dollar transaction in
excess of the equivalent of One Hundred Thousand United
States Dollars (US$100,000), the conversion into United
States Dollars shall be performed on the basis of the
average of the applicable exchange rates for the Day on
which the transaction occurred.
1.4.4 Any currency exchange gains or losses shall be credited
or charged to the Joint Account, except as otherwise
specified in this Accounting Procedure.
1.4.5 This Accounting Procedure shall apply, mutatis
mutandis, to Exclusive Operations in the same manner
that it applies to Joint Operations; provided, however,
that the charges and credits applicable to Consenting
Parties shall be distinguished by an Exclusive
Operation Account. For the purpose of determining and
calculating the remuneration of the Consenting Parties,
including the premiums for Exclusive Operations, the
costs and expenditures shall be expressed in U.S.
currency (irrespective of the currency in which the
expenditure was incurred).
1.5 STATEMENTS AND BILLINGS.
1.5.1 Unless otherwise agreed by the Parties, Operator shall
submit monthly to each Party, on or before the 25th Day
of each month, statements of the costs and expenditures
incurred during the prior month, indicating by
appropriate classification the nature thereof and the
portion of such costs charged to each of the Parties.
These statements shall contain the following
information:
- advances of funds setting forth the currencies
received from each Party
- the share of each Party in total expenditures on a
cash and accrual basis
- the current account cash balance of each Party
- summary of costs, credits, and expenditures on a cur
rent month, year-to-date, and inception-to-date
basis or other periodic basis, as agreed by the
Parties for each line item of the approved Work
Program and Budget
- unusual charges and credits in excess of U.S.
dollars one hundred thousand (U.S.$100,000.00) and
all adjustments arising out of audit shall be
detailed.
1.5.2 Operator shall, upon request, furnish a description of
the accounting classifications used by it.
1.5.3 Amounts included in the statements and billings shall
be expressed in U.S. currency and reconciled to the
currencies advanced. Other currency equivalents may be
presented as agreed between the Parties.
1.5.4 Each Party shall be responsible for preparing its own
accounting and tax reports to meet the Country of
Operations and other country requirements. Operator, to
the extent that the information is reasonably available
from the Joint Account records, will provide in a
timely manner Non-Operators with the necessary
statements to facilitate the discharge of such
responsibility.
1.5.5 The billing statement is to be accompanied by billing
schedules which shall be schedules dividing such
expenditure and income into main classifications of
expenditure as indicated by approved budget and AFEs
issued. The billing schedules shall also show
cumulative totals of all payments linked to AFEs and
budget categories and receipts.
1.6 PAYMENTS AND ADVANCES.
1.6.1 Upon approval of any Work Program and Budget, if Opera
tor so requests, all Parties, including the Operator,
shall advance its share of estimated cash requirements
for the succeeding month's operations. Each such cash
call shall be equal to the Operator's estimate of the
money to be spent in the currencies required to perform
its duties under the approved Work Program and Budget
during the month concerned. For informational purposes
the cash call shall contain an estimate of the funds
required for the succeeding two (2) months. All such
cash calls shall be related to the progress/activities
achieved and to planned progress/activities to be
achieved during the period concerned.
1.6.2 Each such cash call, detailed by major budget
categories and AFEs (where applicable), shall be made
in writing and delivered to all Non-Operators not less
than fifteen (15) Days before the payment due date.
Except as otherwise provided in Section 1.6.4, the due
date for payment of such advances shall be set by
Operator but shall be no sooner than the first Business
Day of the month for which the advances are required.
If, and only if, a Non-Operator believes that the cash
call or a portion thereof is not as per the approved
Work Program and Budget and AFE (where applicable), the
Party may inform its view to all Parties within five
(5) Business Days of the receipt of such cash call.
Operator may issue a revised cash call. If no revision
is issued, payment to the Operator shall be made by the
due date as follows: as to the Non-Operator who raised
the dispute, the non- disputed amount; and as to other
Parties, the amount as determined by such Party's
original cash call prior to the dispute, plus a portion
of the disputed amount determined by the ratio of each
such Party's Participating Interest to the sum of all
Participating Interests of the Parties who did not
dispute the cash call within the said five (5) Business
Days. Notwithstanding the provisions of Article 8.9,
the amount in dispute shall be paid date by the
disputing Party by the due date to an interest bearing
joint escrow account where such funds will be held
until the matter in dispute has been resolved. The
issue arising out of such disputed cash call shall be
resolved as soon as practicable by any appropriate
means including, but not limited to, discussing the
issue in the next Operating Committee meeting so as to
assist in resolving the matter, failing which, the
matter may be submitted to arbitration by any Party and
the arbitrator shall determine appropriate distribution
of the escrow account, plus, if appropriate, penal
interest specified in Article 8.1.
1.6.3 Each Non-Operator shall remit its share of the full
amount of each such cash call to Operator on or before
the due date, in the currencies requested which must be
freely convertible or any other currencies acceptable
to Operator, and at a bank designated by Operator for
the purpose of Joint Operations. If currency provided
by a Non-Operator is other than the requested currency,
then the entire cost of converting to the requested
currency shall be charged to that Non-Operator. Nothing
herein shall relieve any Non- Operator from the
obligation to provide immediately available funds, in
full, by the due date.
1.6.4 Should Operator be required to pay any sums of money
for the Joint Operations as per the approved Work
Program and Budget which were unforeseen at the time of
providing the Non-Operators with said estimates of its
requirements, the Operator may make a written request
of the Non-Operators for special advances covering the
Non-Operators' share of such payments. Each such
Non-Operator shall make its proportional special
advances within ten (10) Business Days after receipt of
such notice.
1.6.5 When the total of cash calls for any month is one
million U.S. dollars (U.S.$1,000,000.00) or less, each
Party, including the Operator, shall advance its share
thereof in accordance with this Section 1.6. When the
total cash requirements exceed the aforesaid amount,
each Party, including the Operator, shall advance its
share of the estimated funds required in three (3)
installments of amounts to be specified by the
Operator, the first installment to be paid not later
than the first Business Day of the month for which the
advance is required and the second installment to be
paid not later than the tenth Day of the month for
which the advance is required or if such Day is not a
Business Day, then the following Business Day and the
third installment to be paid not later than the
twentieth Day of the month for which the advance is
required or if such Day is not a Business Day, then the
following Business Day. The third installment can be
adjusted by the Operator by notifying the Parties,
including the Operator, of the adjusted amount no later
than the fifteenth Day of the month for which the
advance is required.
1.6.6 If a Non-Operator's advances exceed its share of cash
expenditures, succeeding month's cash requirements,
after such determination, shall be reduced accordingly.
A Non- Operator may request that its excess advances be
refunded. Operator shall make such refund within ten
(10) Business Days after receipt of the Non-Operator's
request provided that the amount is in excess of the
cash requirements for the month of such determination.
If the Operator does not make such refund within ten
(10) Business Days, then the Operator shall pay each
Party requesting a refund the difference between the
Agreed Interest Rate and the interest earned on the
Joint Account.
1.6.7 If Non-Operator's advances are less than its share of
cash expenditures, the deficiency shall, at Operator's
option, be added to subsequent cash advance
requirements or be paid by Non-Operator within eight
(8) Business Days following the receipt of Operator's
billing to Non-Operator for such deficiency. Along with
notice of payment due, the Operator shall provide
details supporting that the Non- Operator's advance is
less than its share of cash expenditures.
1.6.8 Any interest received by Operator from interest-bearing
accounts containing funds received from the Parties
shall be credited to the Parties. The interest earned
will be allocated to the Parties on an equitable basis
taking into consideration date of funding by each Party
to the accounts in proportion to the total funding into
the account. A monthly statement summarizing receipts,
disbursements, transfers to each joint bank account and
beginning and ending balances thereof shall be provided
by the Operator to the Parties.
1.6.9 Payments of cash calls or billings as per approved Work
Program and Budget shall be made on or before the due
date. If these payments are not received by the due
date the unpaid balance shall bear and accrue interest
from the due date until the payment is received by the
Operator at the Agreed Interest Rate. For the purpose
of determining the unpaid balance and interest owed,
Operator shall translate to U.S. currency all amounts
owed in other currencies using the currency exchange
rate readily available to Operator at the close of the
last banking Day prior to the due date for the unpaid
balance as quoted by the applicable authority
identified in Section 1.4.3.
1.6.10 Subject to governmental regulation, Operator shall have
the right, at any time and from time to time, to
convert the funds advanced or any part thereof to other
currencies to the extent that such currencies are then
required for operations. The cost of any such
conversion shall be charged to the Joint Account.
However, such conversions should be avoided as far as
practical.
1.6.11 Operator shall endeavor to maintain funds held in bank
accounts for the Joint Account at a level consistent
with that required for the prudent conduct of Joint
Operations.
1.7 ADJUSTMENTS. Payments of any advances or billings shall not
prejudice the right of any Non-Operator to protest or question the
correctness thereof; provided, however, all bills and statements ren
dered to Non-Operators by Operator during any Financial Year shall
conclusively be presumed to be true and correct after twenty-four
(24) months following the end of such Financial Year, unless within
the said twenty-four (24) month period a Non-Operator takes written
exception thereto and makes claim on Operator for adjustment. Failure
on the part of a Non-Operator to make claim on Operator for
adjustment within such period shall establish the correctness thereof
and preclude the filing of exceptions thereto or making claims for
adjustment thereon. No adjustment favorable to Operator shall be made
unless it is made within the same prescribed period. The provisions
of this paragraph shall not prevent adjustments resulting from a
physical inventory of the Property as provided for in Section VI. The
Operator shall be allowed to make adjustments to the Joint Account
after such twenty-four (24) month period if these adjustments result
from audit exceptions outside of this agreement, third party claims,
or Government requirements. Any such adjustments shall be subject to
audit within the time period specified in Section 1.8.1.
1.8 AUDITS.
1.8.1 A Non-Operator, upon at least sixty (60) Days advance
notice in writing to Operator and all other
Non-Operators, shall have the right to audit the Joint
Accounts and records of Operator relating to the
accounting hereunder for any Financial Year within the
twenty-four (24) month period following the end of such
Financial Year. The cost of each such audit shall be
borne by Non-Operators conducting the audit. It is
provided, however, that Non- Operators must take
written exception to and make claim upon the Operator
for all discrepancies disclosed by said audit within
said twenty-four (24) month period. Where there are two
or more Non-Operators, the Non-Operators shall make
every reasonable effort to conduct joint or
simultaneous audits in a manner which will result in a
minimum of inconvenience to the Operator. Operator and
Non-Operators shall make every effort to resolve any
claim resulting from an audit within a reasonable
period of time.
A Non-Operator may audit the records of an Affiliate of
Operator relating to that Affiliate's charges. The
provisions of this Accounting Procedure shall apply
mutatis mutandis to such audits.
1.8.2 Any information obtained by a Non-Operator under the
provisions of this Section 1.8 which does not relate
directly to the Joint Operations shall be kept
confidential and shall not be disclosed to any party,
except as would otherwise be permitted by Article
15.1(A)(3) and (9) of the Agreement.
1.8.3 The Operator is required by Contract to employ a
qualified independent firm of internationally
recognized chartered accountants registered in India to
audit the Contract Account Books and records of
Operator relating to the accounting hereunder, the cost
thereof shall be a charge against the Joint Account,
and a copy of the accounting reports and audit report
shall be furnished to each Party within ninety (90)
days of the close of a Financial Year.
1.9 ALLOCATIONS. If it becomes necessary to allocate any common costs
or expenditures to or between Joint Operations and any other
operations, such allocation shall be made on an equitable basis in
accordance with international accounting standards. Upon request,
Operator shall furnish a description of its allocation procedures
pertaining to these costs and expenditures. A Non-Operator may cause
Operating Committee to review such allocation basis and Operating
Committee may decide a revision to the allocation, failing which, the
matter may be referred to a sole expert or arbitration.
SECTION II.
DIRECT CHARGES
Operator shall charge the Joint Account with all costs and
expenditures incurred in connection with Joint Operations. It is also
understood that charges for services normally provided by an Operator
such as those contemplated in Section 2.4.2.2 which are provided by
Operator's Affiliates shall reflect the cost to the Affiliate,
excluding profit, for performing such services, except as otherwise
provided in Section 2.4.2 and Section 2.4.2.3 if selected.
The costs and expenditures will be recorded as required for the
settlement of accounts between the Parties hereto in connection with
the rights and obligations under this Agreement and for purposes of
complying with Country of Operations and United States tax laws.
Without in any way limiting the generality of the foregoing,
chargeable costs and expenditures shall include:
2.1 LICENSES, PERMITS, ETC.
All costs, if any, attributable to the acquisition, maintenance,
renewal or relinquishment of licenses, permits, contractual and/or
surface rights acquired for Joint Operations and bonuses paid in
accordance with the Contract when paid by Operator in accordance with
the provisions of the Agreement.
2.2 LABOR AND ASSOCIATED COSTS.
2.2.1 OPERATOR'S LOCALLY RECRUITED EMPLOYEES BASED IN INDIA.
Costs of all Operator's locally recruited employees who
are directly engaged in the conduct of Petroleum
Operations under the Contract in India. Such costs
shall include the costs of employee benefits and
Government benefits for employees and levies imposed on
the Operator as an employer, transportation and
relocation costs within India of the employee and such
members of the employee's family (limited to spouse and
dependent children) as required by law or customary
practice in India. If such employees are engaged in
other activities in India, in addition to Petroleum
Operations, the cost of such employees shall be
apportioned on a time sheet basis according to sound
and acceptable accounting and costing principles.
2.2.2 ASSIGNED PERSONNEL.
Costs of salaries and wages, including bonuses, of the
Operator's employees directly and necessarily engaged
in the conduct of the Petroleum Operations under the
Contract, whether temporarily or permanently assigned,
irrespective of the location of such employees, it
being understood that in the case of those personnel
only a portion of whose time is wholly dedicated to
Petroleum Operations under the Contract, only that pro
rata portion of applicable salaries, wages and other
costs, as specified in Sections 2.2.3, 2.2.4, 2.2.5,
2.2.6 and 2.2.7 shall be charged and the basis of such
pro rata allocation shall be specified.
2.2.3 The Operator's costs regarding holiday, vacation,
sickness and disability benefits and living and housing
and other customary allowances applicable to the
salaries and wages chargeable under Section 2.2.2
above.
2.2.4 Expenses or contributions made pursuant to assessments
or obligations imposed under the laws of India which
are applicable to the Operator's cost of salaries and
wages chargeable under Section 2.2.2 above.
2.2.5 The Operator's cost of established plans for employees'
group life insurance, hospitalization, pension,
retirement and other benefit plans of a like nature
customarily granted to the Operator's employees
provided, however, that such costs are in accordance
with generally accepted standards in the international
petroleum industry, applicable to salaries and wages
chargeable to petroleum operations under Section 2.2.2
above.
2.2.6 Personal Income taxes where and when they are paid by
the Operator to the Government of India for the
employee, in accordance with the Contractor's standard
personnel policies.
2.2.7 Reasonable transportation and travel expenses of
employees of the Operator, including those made for
travel and relocation of the expatriate employees,
including their dependent family and personal effects,
assigned to India whose salaries and wages are
chargeable to petroleum operations under Section 2.2.2.
Actual transportation expenses of personnel transferred
to petroleum operations from their country of origin
and/or relocation to their country of origin expenses
shall be charged to the petroleum operations.
2.2.8 Transportation cost as used in this Section shall mean
the cost of freight and passenger service and any
accountable incidental expenditures related to transfer
travel and authorized under Operator's standard
personnel policies. Operator shall ensure that all
expenditures related to transportation costs are
equitably allocated to the activities which have
benefited from the personnel concerned.
2.3 TRANSPORTATION COSTS.
The reasonable cost of transportation of equipment, materials and
supplies within India and from outside India to India necessary for
the conduct of petroleum operations under the Contract, including,
but not limited to, directly related costs such as unloading charges,
dock fees and inland and ocean freight charges.
2.4 CHARGES FOR SERVICES.
2.4.1 THIRD PARTIES.
The actual costs of contract services, services of
professional consultants, utilities and other services
necessary for the conduct of petroleum operations under
the Contract performed by third parties other than an
Affiliate of the Operator, provided that the
transactions resulting in such costs are undertaken
pursuant to arms length transactions.
2.4.2 AFFILIATES OF OPERATOR.
2.4.2.1 PROFESSIONAL AND ADMINISTRATIVE SERVICES AND
EXPENSES.
Cost of professional and 78 administrative
services provided by any Affiliate for the
direct benefit of petroleum operations,
including, but not limited to, services
provided by the produc tion, exploration,
legal, financial, insurance, accounting and
computer services divisions other than those
covered by Section 2.4.2.2 which Operator may
use in lieu of having its own employees.
Charges shall be equal to the actual cost of
providing their services, shall not include any
element of profit and shall not be any higher
than the most favorable prices charged by the
Affiliate to third parties for comparable
services under similar terms and conditions
elsewhere and will be fair and reasonable in
the light of prevailing international oil
industry practice and experience.
2.4.2.2 SCIENTIFIC OR TECHNICAL PERSONNEL.
Cost of scientific or technical personnel
services provided by any Affiliate of Operator
for the direct benefit of petroleum operations,
which cost shall be charged on a cost of
service basis without element of profit.
Charges therefor shall not exceed charges for
comparable services currently provided by
outside technical service organizations of
comparable qualifications. Unless the work to
be done by such personnel is covered by an
approved budget and Work Programme, Operator
shall not authorize work by such personnel
without approval of the Management Committee.
2.4.2.3 Equipment, facilities and property owned and
furnished by the Operator's Affiliates, at
rates commensurate with the cost of ownership
and operation provided, however, that such
rates shall not exceed those currently
prevailing for the supply of like equipment,
facilities and property on comparable terms in
the area where the petroleum operations are
being conducted. The equipment and facilities
referred to herein shall exclude major
investment items such as (but not limited to)
drilling rigs, producing platforms, oil
treating facilities, oil and gas loading and
transportation systems, storage and terminal
facilities and other major facilities, rates
for which shall be subject to separate
agreement with the Government.
2.5 COMMUNICATIONS.
Cost of acquiring, leasing, installing, operating, repairing and
maintaining communication systems including satellite, radio and
microwave facilities between the Contract Area and the Operator's
base facility, offices, helicopter bases, port and railway yards.
2.6 OFFICE, SHORE BASES AND MISCELLANEOUS FACILITIES.
Net cost to Operator of establishing, maintaining and operating any
office, sub-office, shore base facility, warehouse, housing or other
facility directly serving the petroleum operations. If any such
facility services contract areas other than the Contract Area, or any
business other than petroleum operations, the net costs thereof shall
be allocated on an equitable and consistent basis.
2.7 ENVIRONMENTAL STUDIES AND PROTECTION.
Costs incurred in conducting the environmental impact studies for the
Contract Area, and in taking environmental protection measures
pursuant to the terms of the Contract.
2.8. INSURANCE.
Premiums paid for insurance required by law, the Contract or the
Agreement to be carried for the benefit of the Joint Operations.
2.9. DAMAGES AND LOSSES TO PROPERTY.
2.9.1 All costs or expenditures necessary to replace or
repair damages or losses incurred by fire, flood,
storm, theft, accident, or any other cause. Operator
shall furnish Non- Operators written notice of damages
or losses incurred in excess of Fifty Thousand U.S.
Dollars (U.S.$50,000) as soon as practical after report
of the same has been received by Operator. All losses
in excess of Fifty Thousand U.S. Dollars (U.S.$50,000)
shall be listed separately in the monthly statement of
costs and expenditures.
2.9.2. Credits for settlements received from insurance carried
for the benefit of Joint Operations and from others for
losses or damages to Joint Property or Materials. Each
Party shall be credited with its Participating Interest
share thereof except where such receipts are derived
from insurance purchased by Operator for less than all
Parties in which event such proceeds shall be credited
to those Parties for whom the insurance was purchased
in the proportion of their respective contributions
toward the insurance coverage.
2.9.3. Expenditures incurred in the settlement of all losses,
claims, damages, judgements and other expenses for the
benefit of Joint Operations.
2.10 LITIGATION AND LEGAL EXPENSES.
2.10.1 Legal services necessary or expedient for the
protection of the Joint Operations, and all costs and
expenses of litigation, arbitration or other
alternative dispute resolution procedure, including
reasonable attorneys' fees and expenses, together with
all judgments obtained against the Parties or any of
them arising from the Joint Operations.
2.10.2. If the Parties hereunder shall so agree, actions or
claims affecting the Joint Operations hereunder may be
handled by the legal staff of one or any of the Parties
hereto; and a charge commensurate with the reasonable
costs of providing and furnishing such services
rendered may be made against the Joint Account, but no
such charges shall be made until approved by the
Parties.
2.11 TAXES AND DUTIES.
All taxes, duties, assessments and governmental charges, of every
kind and nature, assessed or levied upon or in connection with the
Joint Operations, other than any that are measured by or based upon
the revenues, income and net worth of a Party.
If Operator or an Affiliate is subject to income or withholding tax
as a result of services performed at cost for the operations under
the Agreement, its charges for such services may be increased by the
amount of such taxes incurred (grossed up).
2.12 OTHER EXPENDITURES.
Any other costs and expenditures incurred by the Operator for the
necessary and proper conduct of the Joint Operations in accordance
with approved Work Programs and Budgets and not covered in this
Section II or in Section III.
SECTION III.
INDIRECT CHARGES
3.1 Operator shall charge the Joint Account monthly for the cost of
indirect services and related office costs of Operator and its
Affiliates not otherwise provided in this Accounting Procedure. No
cost or expenditure included under Section II shall be included or
duplicated under this Section III. Indirect services and related
office costs of Operator and its Affiliates outside the Country of
Operations include but are not limited to the cost of the following
functions which are of benefit to the Joint Operations:
Executive, Administrative, & Managerial
Treasury and Financial Services
Tax and Legal
Human Resources
Insurance
Accounting and Internal Control
Employee Training and Medical
Safety and Security
Budgeting and Forecasting
Communications
3.2 The charge for the period beginning with the Financial Year through
the end of the period covered by Operator's invoice ("Year- to-Date")
under Section 3.1 above shall be a percentage of the Year- to-Date
Parties' total direct expenditures, charged to the Joint Account,
calculated on the following scale (U.S. Dollars):
ANNUAL EXPENDITURES
One percent (1%) of expenditures
3.3 The expenditures used to calculate the monthly indirect charge
shall not include the indirect charge (calculated either as a
percentage of expenditures or as a minimum monthly charge), rentals
on surface rights acquired and maintained for the Joint Account,
guarantee deposits, concession acquisition costs, bonuses paid in
accordance with the Contract, royalties and taxes paid under the
Contract, settlement of claims, proceeds from the sale of assets (in
cluding division in kind) amounting to more than U.S.$10,000 per
transaction, and similar items mutually agreed upon by the Parties.
Credits arising from any government subsidy payments and disposi tion
of Joint Account property shall not be deducted from total
expenditures in determining such charge.
3.4 The indirect charges provided for in this Section III may be amended
periodically by mutual agreement between the Parties if, in practice,
these charges are found to be insufficient or excessive.
SECTION IV.
ACQUISITION OF MATERIAL AND EQUIPMENT
4.1 MATERIALS AND EQUIPMENT.
4.1.1 GENERAL.
So far as is practicable and consistent with efficient
and economical operation, only such material shall be
purchased or furnished by the Operator for use in the
petroleum operations as may be required for use in the
reasonably foreseeable future and the accumulation of
surplus stocks shall be avoided to the extent possible.
4.1.2 WARRANTY.
In the case of defective material or equipment, any
adjustment received by the Operator from the suppliers
or manufacturers or their agents in respect of any
warranty on material or equipment shall be credited to
the accounts under the Agreement.
4.1.3 VALUE OF MATERIALS CHARGED TO THE ACCOUNTS UNDER THE
CONTRACT.
4.1.3.1 Except as otherwise provided in subparagraph
4.1.2, materials purchased by the Operator and
used in the petroleum operations shall be
valued to include invoice price less trade and
cash discounts, if any, purchase and
procurement fees plus freight and forwarding
charges between point of supply and point of
shipment, freight to port of destination,
insurance, taxes, customs duties, consular
fees, other items chargeable against imported
material and, where applicable, handling and
transportation costs from point of importation
to warehouse or operating site, and these costs
shall not exceed those currently prevailing in
normal arms length transactions on the open
market.
4.1.3.2 Material purchased from or sold to Affiliates
or transferred to or from activities of the
Operator other than petroleum operations under
the Contract.
4.1.3.2.1 new material (hereinafter referred to as
condition A) shall be valued at the current
international price which shall not exceed the
price prevailing in normal arms length
transactions on the open market;
4.1.3.2.2 used material which is in sound and
serviceable condition and is suitable for reuse
without reconditioning (hereinafter referred to
as condition B) shall be priced at not more
than seventy five percent (75%) of the current
price of the above mentioned new materials;
4.1.3.2.3 used material which cannot be classified as
condition B, but which, after reconditioning,
will be further serviceable for original
function as good second-hand condition B
material or is serviceable for original
function, but substantially not suitable for
reconditioning (hereinafter referred to as
condition C) shall be priced at not more than
fifty per cent (50%) of the current price of
the new material referred to above as condition
A.
The cost of reconditioning shall be charged to the
reconditioned material, provided that the condition C
material value plus the cost of reconditioning does not
exceed the value of condition B material.
Material which cannot be classified as condition B or
condition C shall be priced at a value commensurate
with its use.
Material involving erection expenditure shall be
charged at the applicable condition percentage
(referred to above) of the current knocked-down price
of new material referred to above as condition A.
When the use of material is temporary and its service
to the Petroleum Operations does not justify the
reduction in price in relation to materials referred to
above as conditions B and C, such material shall be
priced on a basis that will result in a net charge to
the accounts under the Contract consistent with the
value of the service rendered.
4.2 PREMIUM PRICES.
Whenever Material is not readily obtainable at prices specified in
Section 4.1 of this Section IV because of national emergencies,
strikes or other unusual causes over which the Operator has no
control, the Operator may charge the Joint Account for the required
Material at the Operator's actual cost incurred procuring such
Material, in making it suitable for use, and moving it to the
Contract Area, provided that notice in writing, including a detailed
description of the Material required and the required delivery date,
is furnished to Non-Operators of the proposed charge at least 10 Days
(or such shorter period as may be specified by Operator) before the
Material is projected to be needed for operations and prior to
billing Non-Operators for such Material the cost of which exceeds two
hundred thousand U.S. Dollars (U.S. $200,000.00). Each Non-Operator
shall have the right, by so electing and notifying Operator within 5
Days (or such shorter period as may be specified by Operator) after
receiving notice from Operator, to furnish in kind all or part of his
share of such Material per the terms of the notice which is suitable
for use and acceptable to Operator both as to quality and time of
delivery. Such acceptance by Operator shall not be unreasonably
withheld. If a Non-Operator fails to properly submit an election
notification within the designated period, the Operator is not
required to accept Material furnished in kind by that Non-Operator.
If the Operator fails to submit proper notification prior to billing
Non-Operators for such Material, Operator shall only charge the Joint
Account on the basis of the price allowed during a "normal" pricing
period in effect at time of movement. If Material furnished is deemed
unsuitable for use by the Operator, all costs incurred in disposing
of such Material or returning Material to owner shall be borne by the
Non-Operator furnishing the same unless otherwise agreed by the
Parties.
SECTION V.
DISPOSAL OF MATERIALS
5.1 The Operator shall be under no obligation to purchase the interest
of Non-Operators in new or used surplus Materials. Operator shall
have the right to dispose of Materials but shall advise and secure
prior agreement of the Operating Committee of any proposed
disposition of Materials having an original cost to the Joint Account
either individually or in the aggregate of Fifty Thousand U.S.
Dollars (US$50,000) or more. Credits for Material sold by the
Operator shall be made to the Joint Account in the month in which
payment is received for the Material. Any Material sold or disposed
of under this Section shall be on an "as is, where is" basis without
guarantees or warranties of any kind or nature. Costs and
expenditures incurred by Operator in the disposition of Materials
shall be charged to the Joint Account.
5.2 Division of Materials in kind, if made between Operator and Non-
Operators, shall be in proportion to their respective interests in
such Material. Each Party will thereupon be charged individually
with its share of the agreed volume of Material received or
receivable by each Party, and corresponding credits will be made by
Operator to the Joint Account. Such credits shall appear in the
monthly statement of Joint Operations.
SECTION VI.
RECORDS AND INVENTORIES OF ASSETS
6.1 RECORDS.
6.1.1 The Operator shall keep and maintain detailed records
of property and assets in use for or in connection with
petroleum operations under the Agreement in accordance
with normal practices in exploration and production
activities of the international petroleum industry.
Such records shall include information on quantities,
location and condition of such property and assets, and
whether such property or assets are leased or owned.
6.1.2 The Operator shall furnish annually particulars to the
Non-Operator, by notice in writing as provided in the
Agreement, of all major assets acquired by the Operator
to be used for or in connection with petroleum
operations.
6.2 INVENTORIES.
6.2.1 The Operator shall:
6.2.1.1 not less than once every twelve (12) Months
with respect to movable assets take an
inventory of the controllable assets used for
or in connection with petroleum operations in
terms of the Contract and address and deliver
such inventory to the non-operators with a
statement of the principles upon which
valuation of the assets mentioned in such
inventory has been based. Controllable assets
means those assets the operators submit to
detailed record keeping.
6.2.1.2 not less than once every three (3) years with
respect to immovable assets, take an inventory
of the assets used for or in connection with
petroleum operations in terms of the Contract
and address and deliver such inventory to the
Non- Operators together with a written
statement of the principles upon which
valuation of the assets mentioned in such
inventory has been based. Immovable assets
means those assets which are placed in service
and have an original cost in excess of Fifty
Thousand United States Dollars (US$50,000).
6.2.1.3 Reconciliation of inventory with charges to the
Joint Account shall be made by Operator and the
Operator shall furnish to the Non-Operators a
copy of the inventory and a priced list of
excesses and shortages.
<PAGE>
EXHIBIT "B"
DESCRIPTION OF CONTRACT AREA
The area comprising approximately 430 sq. km offshore India identified as
Panna Block and the area comprising approximately 777 sq. km offshore India
identified as the Mukta Block described herein and shown under map attached as
Appendix B-1 and B-2.
Longitude and Latitude measurements are as follows:
MUKTA (about 100 km Northwest of Bombay) See Appendix B-2.
LATITUDE LONGITUDE
A. 19 Degrees 27'00"N 71 Degrees 38'00"E
B. 19 Degrees 27'00"N 71 Degrees 54'00"E
C. 19 Degrees 12'00"N 71 Degrees 54'00"E
D. 19 Degrees 12'00"N 71 Degrees 38'00"E
PANNA (about 95 km Northwest of Bombay) See Appendix B-1.
LATITUDE LONGITUDE
A. 19 Degrees 28'00"N 71 Degrees 54'00"E
B. 19 Degrees 28'00"N 72 Degrees 05'00"E
C. 19 Degrees 19'30"N 72 Degrees 05'00"E
D. 19 Degrees 15'00"N 72 Degrees 00'00"E
E. 19 Degrees 15'00"N 71 Degrees 54'00"E
APPENDIX - B1
MAP OF CONTRACT AREA
PANNA BLOCK
WESTERN INDIA
OFFSHORE BOMBAY BASIN
[MAP AND INSET OF CONTRACT AREA]
APPENDIX - B2
MAP OF CONTRACT AREA
MUKTA BLOCK
WESTERN INDIA
OFFSHORE BOMBAY BASIN
[MAP AND INSET OF CONTRACT AREA]
<PAGE>
EXHIBIT "C"
EXAMPLE
FROM ENRON OIL & GAS INDIA LTD.
CASH CALL FOR: JUNE 1, 199
JUNE JULY AUGUST
I. Exploration/Appraisal Costs
Geological and Geophysical 10 X
Core Hole Drilling 10 X
Exploration Wells
Wells A 20
Wells B 20 40
Facilities Costs 5 X
Subtotal
II. Development Costs
Development Wells
Wells A 20 X
Wells B 20 40 X
Production Facilities
Platforms 50
Pipeline/Flow Lines 10 60
Engineering Studies 2 X
Service Costs 3 X X
Subtotal
III Production Costs
Lease and Well 5 X
IV. General and Administrative Costs 15 X X
V. Fixed Assets and Deposits X X X
-------------------------------
Grand Total 190 XX XX
April 1994 Cash Call 200
April 1994 Actual (190)
-----
Net Over (Under) Call 10 (10)
---
Total Cash Due June 1, 1994 180
====
ONGC 40% Share US$72
EOGIL 30% Share US$54
RIL 30% Share US$54
NOTE: The cash call for June 1 is expected to be issued on or before May 15.
EXHIBIT "D"
BUDGET FORMAT
(FOR EXAMPLE ONLY)
ENRON OIL & GAS INDIA LTD.
FINANCIAL YEAR 1994/95
I. Exploration/Appraisal Costs
*Geological and Geophysical X
*Core Hole Drilling X
*Exploration Wells
(1) Wells A (Firm; Specifically defined) X
(2) Wells B (Contingent; Funds provided, but X
specifics to be approved by
Operating Committee)
Sub-Total XX
II. Development Costs
*Development Wells
(1) Wells A (Firm; Specifically defined) X
(2) Wells B (Contingent; Funds provided, but X
specifics to be approved by
Operating Committee)
*Production Facilities
(1) Platforms
(a) Firm X
(b) Contingent; Funds provided, but X
specifics to be approved by
Operating Committee
(2) Storage Facilities X
(3) Terminals X
(4) Pipelines/Flow Lines X
*Engineering Studies X
*Service Costs X
---
Sub-Total XX
III. Production Costs
*Lease and Well X
---
Sub-Total XX
IV. General and Administrative XX
V. Fixed Assets and Deposits XX
Grand Total Costs XXX
===
NOTE 1: Each line above represents budget line items. Each budget line item
shall be supplemented, if appropriate, by explanatory schedules,
unquantified examples of which follow as Tables D-1 through D-8, showing
magnitude and timing of expenditures and description of the work to be
achieved. It is intended that the Operating Committee shall have full
authority to reclassify funds from Contingent to Firm.
VI. Revenue XXX
===
NOTE 2: Categories III and IV are considered operating cost and are not
subject to AFEs, except that some items in category III may require AFEs
for workovers as per Article 6.9.
APPROVALS
For EOGIL _______________________
(signature)
_______________________
(print name and date)
For RIL _______________________
(signature)
_______________________
(print name and date)
For ONGC _______________________
(signature)
_______________________
(print name and date)
<PAGE>
TABLE D-1
ENRON OIL & GAS INDIA LTD. (FOR APPROVAL)
BUDGET AND WORK PROGRAM
BUDGET SUMMARY
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95
ITEM 1994 1994 1994 1995 FINANCIAL YEAR REMAIN TOTAL
CODE DESCRIPTION QTR 2 QTR 3 QTR 4 QTR 1 * PROJECT PROJECT
<S> <C>
</TABLE>
I. Exploration/Appraisal Costs
Geophysical and Geological
Core Hole Drilling
Exploration Drilling
(Firm Wells)
(Contingent Wells)
Total Exploration Costs
II. Development Costs
Development Drilling
(Firm Wells)
(Contingent Wells)
Production Facilities Costs
Total Development Costs
III. Production Costs
IV. General and Administrative
V. Fixed Assets and Deposits
Total Project Costs
VI. Revenue
*If X in this column, the item is a Minimum Work Obligation item.
NOTE: Categories III and IV are considered operating cost and are not subject
to AFEs, except that certain items in category III may require AFEs for
workovers as per Article 6.9.
FOR EOGIL FOR RIL FOR ONGC
_____________________ _____________________ _____________________
_____________________ _____________________ _____________________
TABLE D-2
ENRON OIL & GAS INDIA LTD. (FOR INFORMATION)
BUDGET AND WORK PROGRAM
Geophysical and Geological Expense
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95
FINANCIAL YEAR 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 * YEAR YEAR
<S><C>
</TABLE>
Geophysical Costs
Seismic Survey (Firm)
Positioning (Firm)
Field Supervision (Firm)
Scouting/Chase Boats/Misc. (Firm)
Data Processing (See Note) (Firm)
Data Reprocessing (Firm)
Supervisory/Support Costs (Firm)
Technical Service (Firm)
Total Geophysical Costs
Geological Costs
Geochem and Biostrat Analysis (Firm)
Core Analysis (Firm)
Special Studies and Consultation (Firm)
PVT Fluid Analysis (Firm)
Supervisory/Support Costs (Firm)
Technical Service (Firm)
Total Geological Costs
Communications Costs (Firm)
Total Geophysical and Geological
*If X in this column, the item is a Minimum Work Obligation item.
TABLE D-3
ENRON OIL & GAS INDIA LTD. (FOR INFORMATION)
BUDGET AND WORK PROGRAM
Development Drilling (Firm Wells)
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95
FINANCIAL YEAR 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 * YEAR YEAR
<S><C>
</TABLE>
Drilling (Firm wells)
Drilling and Completion Intangibles
Drilling and Completion Tangibles
Drilling (Contingent wells)
Total Drilling
Shore Base (1) (Firm)
Communications Expense (2) (Firm)
Supervisory/Support Staff (Firm)
Total Drilling/Operations Costs
*If X in this column, the item is a Minimum Work Obligation item.
NOTE: (1) Lease costs only of $ /day
(2) Monthly communications expense allocated as follows:
Drilling
Construction
Exploration
G&A
(3) Inventory costs included in Fixed Assets
Additional Note:
Specifics to be added which would clearly delineate each individual "Firm" well
proposed. A separate page following this format would be provided for
"Contingent" wells for which funds are proposed but technical specifications are
not available until a future Operating Committee meeting.
TABLE D-4
ENRON OIL & GAS INDIA LTD. (FOR INFORMATION)
BUDGET AND WORK PROGRAM
Production Facilities Costs
Financial Year 1994/95
<TABLE>
<CAPTION>
(In '000 U.S. Dollars) TOTAL 94/95
FINANCIAL YEAR 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 * YEAR YEAR
<S><C>
</TABLE>
PANNA FIELD DEVELOPMENT
CCP Jacket (Contingent)
CCP Deck (Contingent)
Platform PF (Contingent)
Platform PG (Contingent)
WH Decks (Contingent)
Pipeline (Contingent)
Living Quarters/Platform (Contingent)
Flare Tripod Structure (Contingent)
Total Panna/Mukta Development
TAPTI FIELD DEVELOPMENT
Preliminary Engineering (Firm)
Platform STB (Firm)
Platform STC (Firm)
Platform STF (Firm)
TPP Jacket (Firm)
TPP Deck/Bridge (Firm)
Pipeline (Firm)
Total Tapti Development
Supervisory/Support Costs (Firm)
Technical Services (Firm)
TOTAL PRODUCTION FACILITIES
*If X in this column, the item is a Minimum Work Obligation item.
TABLE D-5
ENRON OIL & GAS INDIA LTD. (FOR INFORMATION)
BUDGET AND WORK PROGRAM
Production Costs
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95
FINANCIAL YEAR 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 * YEAR YEAR
<S><C>
</TABLE>
Panna/Mukta
EPS
FSO
PA
PB
PQ
PE
MA
Sub-Total
PPA
PQ
PC
PF
PG
Sub-Total
Total Panna/Mukta (Firm)
Tapti
TPP, STB, STC, STF (Firm)
Total Tapti
Communications (Firm)
Supervision and Support (Firm)
Technical Services (Firm)
Total Production Costs
*If X in this column, the item is a Minimum Work Obligation item.
TABLE D-6
ENRON OIL & GAS INDIA LTD. (FOR INFORMATION)
BUDGET AND WORK PROGRAM
General and Administrative Expense
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL YEAR FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 * YEAR YEAR
<S><C>
</TABLE>
Salaries and Benefits
Expat Salary and Benefits
National Salary and Benefits
Total Salaries and Benefits (Firm)
Other G&A
Moving Costs
Travel and Entertainment Subscriptions and Memberships Office
Rental Telephone and Telecommunications Utilities Repair and
Maintenance Security Office Supplies Legal and Accounting
Insurance Technical Services Technical Publications, Books, Maps
Other Outside Services Bank Fees Training
Total Other G&A (Firm)
Total General and Administrative
*If X in this column, the item is a Minimum Work Obligation item.
NOTE: Other G&A costs apply to all other departments accumulating costs
not budgeted elsewhere.
vii
TABLE D-7
ENRON OIL & GAS INDIA LTD. (FOR INFORMATION)
BUDGET AND WORK PROGRAM
Fixed Assets and Deposits
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL YEAR FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 * YEAR YEAR
<S> <C> <C>
</TABLE>
Office Furniture/Fixtures
Office Furniture
Office Equipment
Drafting Equipment
Computer Equipment
Communication Equipment
Expat Housing Furniture/Appliances
Other Leasehold Improvements
Total Furniture/Fixture/Equipment (Firm)
Motor Vehicles
Inventory
Warehouse and Yard
Deposits
Office
Expat Housing/Apartments
Warehouse
Telephone, Fax, Other
Total Deposits/Prepaids (Firm)
Total Fixed Assets and Deposits
*If X in this column, the item is a Minimum Work Obligation item.
TABLE D-8
ENRON OIL & GAS INDIA LTD. (FOR INFORMATION)
BUDGET AND WORK PROGRAM
Revenue
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL YEAR FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 * YEAR YEAR
<S><C>
</TABLE>
Revenues
Oil Production
Gas Production
Other Income
Total Revenues
<PAGE>
EXHIBIT "E"
DATA TO BE PROVIDED TO NON-OPERATORS
Operator shall provide the following data to Non-Operators:
A. DAILY PROGRESS REPORTS
1. Daily drilling progress report for each well which shall include the brief
description of work performed, the interval drilled, the type and depth of
the formation penetrated, the size and landed depth of any casing landed
and cementation details thereof, the results of any tests made and any
problems encountered.
2. Daily production report giving field-wise information on the oil, gas,
condensate and water produced, number of wells flowing, the quantity of
produced oil and gas handed over for custody transfer, available data
describing quality of the crude transferred (including, as available,
gravity, water content, salinity, pour point for oil and dew point and
calorific value), H2S content of gas handed over as available, and any
lighterage details as and when it takes place.
3. Daily cash statements.
4. Water injection reports, if any, giving quantity and quality of water
injected, number of wells/strings on injection, wellhead injection
pressures, etc.
5. Workover and well servicing reports covering the details of workover
operations and well stimulations/activation operations (well-wise).
6. Construction reports covering the details of the activities, if any,
carried out at offshore for installation of well platforms, pipelines,
process platforms and other activities with details of barges deployed,
etc.
B. OTHER PERIODIC REPORTS
Other reports will cover the following aspects and will be provided at
frequencies (monthly, quarterly or otherwise) as appropriate:
1. Exploration: Status of various surveys carried out vis-a-vis plan, data
acquisition and data processing details vs. plan, any discovery made with
details of the test data of the discovery well zone-wise.
2. Drilling:
(a) Summary report on each well drilled after drilling is concluded.
(b) Cumulative drilling meterage (both development and exploratory)
achieved during the month against plan (wellwise), idle and productive
time of rigs, details of the material consumption (casing, mud
chemicals and other well completion equipments).
3. Production:
(a) Cumulative production of oil, gas, condensate, water and water
injection including, as available, field-wise, layer- wise and
well-wise actual results vs. plan of production/injection. Cumulative
quantity of crude oil, condensate and gas sold. Party-wise share of
the sold oil, gas and condensate.
(b) (i) The quantity of gas internally consumed and flared, details of
material consumption for various production activities (chemicals,
tubulars, completion equipment, etc.).
(ii) Average quantity of produced crude oil (if applicable), gas,
effluent discharge and water injected.
(iii) Status reports on major/critical equipments/facilities and
maintenance thereof.
(c) Monthly test data of the wells.
(d) Daily ullage of tanker at SBM (if applicable).
(e) Daily Report on deployment of personnel on board.
4. Developmental/Construction Activities: Major construction/development
activities in progress. Status of progress of these activities with respect
to schedule.
5. Capital and operating expenditure against plan (to be reported quarterly
containing information on monthly and year-to-date expenditures).
6. Copies of various well logs and surveys as they become available.
7. Reports of DST (including basic data), core analysis and any other special
studies conducted as they become available.
8. Well completion and work-over reports as they become available.
9. Copies of all geological, geochemical, petrophysical and geophysical
data/reports and, when finalized, maps prepared by the Operator or by the
subcontractor except the magnetic tapes which shall be stored by the
Operator and made available for inspection and/or copying at the sole
expense of the non-operating Parties requesting same.
10. Copies of reservoir management reports including field and well performance
reports and reservoir studies reports and estimate reports as they become
available.
11. Reports on sub-sea soil surveys, environmental surveys, sub-sea pipelines
and risers inspection, reports on repair and maintenance of sub-sea
pipeline and risers as they become available.
12. Any emergency shutdown of operations affecting oil/gas production/dispatch,
drilling operations, etc., must be reported as soon as practicable on
telephone followed by telex, facsimile, etc., giving the details of effect
on production/drilling and the likely duration of shutdown.
A normalization report also to be sent when the operations resume and
become normal.
13. Reports on all incidents of: pipeline and riser leakage/failure, oil
spills, fire, any structural failures, blow-out, explosion, sabotage, other
accidents involving loss of property.life, etc., strikes/riots affecting
operations/production, etc., should be sent as soon as practicable by the
Operator to the non-operating Parties, Government and other agencies such
as Oil Industries Safety Directorate ("OISD"), Director General
Hydrocarbon, Oil Co- ordination Committee ("OCC"), Offshore Defense
Advisory Group ("ODAG") and other statutory bodies whichever is applicable,
on telephone followed by telex/facsimile giving the details.
14. Fortnightly cash balance report.
C. INFORMATION, DATA, CONFIDENTIALITY, INSPECTION AND SECURITY
The Contractor shall, promptly after they become available make available
to the Government in its offices all data obtained as a result of petroleum
operations under the Contract including, but not limited to, geological,
geophysical, geochemical, petrophysical, engineering, well logs, maps, magnetic
tapes, cores and production data as well as all interpretative and derivative
data, including reports, analyses, interpretations and evaluation prepared in
final form in respect of petroleum operations (hereinafter referred to as
("Data"). Data shall be the property of the Government, provided however, that
the Contractor shall have the right to make use of such Data, free of cost, for
the purpose of petroleum operations under this Agreement as provided herein.
<PAGE>
GRAPHICAL CONTENT APPENDIX
Appendix - B1 Map of Contract Area - Panna Block
Appendix - B2 Map of Contract Area - Mukta Block
EXHIBIT 10.51
PRODUCTION SHARING CONTRACT
AMONG
THE GOVERNMENT OF INDIA
AND
OIL & NATURAL GAS CORPORATION LIMITED
AND
RELIANCE INDUSTRIES LIMITED
AND
ENRON OIL & GAS INDIA LTD.
WITH RESPECT TO CONTRACT AREA
IDENTIFIED AS PANNA AND MUKTA FIELDS
<PAGE>
TABLE OF CONTENTS
ARTICLE CONTENTS
Preamble
1. Definitions
2. Duration
3. Relinquishment
4. Work Programme
5. Management Committee
6. Operatorship and Operating Agreement
7. General Rights and Obligations of the Parties
8. Government Assistance
9. Discovery, Development and Production
10. Unit Development
11. Measurement of Petroleum
12. Protection of the Environment
13. Recovery of Costs
14. Production Sharing of Petroleum between Contractor
and Government
15. Taxes, Royalties, Rentals, etc.
16. Payment
17. Customs Duties
18. Domestic Supply, Sale, Disposal and Export of Crude Oil
19. Valuation of Oil
20. Currency and Exchange Control Provisions
21. Natural Gas
22. Employment, Training and Transfer of Technology
23. Local Goods and Services
24. Insurance and Indemnification
25. Records, Reports, Accounts and Audit
26. Information, Data, Confidentiality, Inspection
and Security
27. Title to Petroleum, Data and Assets
28. Assignment of Interest
29. Guarantee
30. Termination of Contract
31. Force Majeure
32. Applicable Law and Language of the Contract
33. Sole Expert, Conciliation and Arbitration
34. Entire Agreement, Amendments, Waiver and Miscellaneous
35. Certificates
36. Notices
APPENDICES:
Appendix A - Description of Contract Area
Appendix B - Map of Contract Area
Appendix C - Accounting Procedure to Production Sharing
Contract
Appendix D - Calculation of the Investment Multiple for
Production Sharing Purposes
Appendix E - Form of Financial and Performance Guarantee
Appendix F - Equipment
Appendix G - Development Commitment Specified by the
Companies
Appendix H - Production Profile of the Panna and Mukta
Fields
<PAGE>
This Contract made and entered into as of the 22nd day of December 1994
by and among:
THE PRESIDENT OF INDIA, acting through the Joint Secretary
(Exploration), Ministry of Petroleum and Natural Gas (hereinafter
referred as Government);
AND
OIL & NATURAL GAS CORPORATION LIMITED (ONGC), a body corporate established under
the provisions of the Companies Act, 1956, which expression shall include its
successors and such assigns as are permitted under Article 28 hereof acting
through its duly authorized Chairman & Managing Director;
AND
RELIANCE INDUSTRIES LTD. ("RIL"), a body corporate established under the laws of
India, which expression shall include its 35 successors and such assigns as are
permitted under Article 28 hereof acting through its duly authorized Chief
Executive Officer (Oil & Gas);
AND
ENRON OIL & GAS INDIA LTD. ("EOGIL"), a body corporate established under the
laws of the Cayman Islands, which expression shall include its successors and
such assigns as are permitted under Article 28 hereof acting through its duly
authorized (Vice) President;
WITNESSETH:
WHEREAS
1. By virtue of Article 297 of the Constitution of India,
Petroleum in its natural state in the Territorial Waters and
the Continental Shelf of India is vested in the Union of
India;
2. The Territorial Waters, Continental Shelf, Exclusive Economic Zone And
Other Maritime Zones Act, 1976 (No. 80 of 1976) provides for the grant
of a Lease or letter of authority by the Government to explore and
exploit the resources of the Continental Shelf;
3. The Oil Fields (Regulation and Development) Act, 1948, (53 of 1948)
(hereinafter referred to as "the Act") and the Petroleum and Natural
Gas Rules, 1959, made thereunder (hereinafter referred to as "the
Rules") make provision inter alia for the regulation of Petroleum
Operations and the grant of petroleum exploration licenses and mining
leases for exploration and development of Petroleum in India;
4. The Act and the Rules provide for the grant by the Government of mining
leases in respect of the Territorial Waters and the Continental Shelf,
and the Contractor is being duly granted a mining lease to carry out
Petroleum Operations in that area offshore identified as Panna and
Mukta Fields, more particularly described in Appendices A and B;
5. The Government desires that the Petroleum resources which may exist in
the Contract Area be discovered and exploited with the utmost
expedition in the overall interest of India in accordance with sound
international petroleum industry practices;
6. The Government is satisfied that it is in the public interest to enter
into this Contract on terms different from those specified in Section
12 of the Oil Fields (Regulations and Development) Act, 1948, and the
Government is entering into this Agreement on the terms and conditions
specified herein.
7. EOGIL and RIL have represented that they have, or will acquire
and make available, the necessary financial and technical
resources and the technical and industrial competence and
experience necessary for proper discharge and/or performance
of all obligations required to be performed under this
Contract in accordance with good international petroleum
industry practices and will provide guarantees as required in
Article 29 for the due performance of their undertakings
hereunder;
8. The Parties desire to enter into this Contract with respect to the
Contract Area referred to in Appendices A and B on the terms and
conditions herein set forth.
NOW, THEREFORE, in consideration of the premises and covenants and conditions
herein contained, IT IS HEREBY AGREED between the Parties as follows:
2
ARTICLE 1
D E F I N I T I O N S
In this Contract, unless the context requires otherwise, the
following terms shall have the meaning ascribed to them hereunder:
1.1 "Accounting Procedure" means the principles and procedures
of accounting set out in Appendix C.
1.2 "Affiliate" means a company that directly or indirectly controls or
is controlled by a Party to this Contract or a company which
directly or indirectly controls or is controlled by a company which
controls a Party to this Contract, it being understood that
"control" means ownership by one company of more than fifty percent
(50%) of the voting securities of the other company, or the power
to direct, administer and dictate policies of the other company
even where the voting securities held by such company exercising
such effective control in that other company is less than fifty
percent (50%) and the term "controlled" shall have a corresponding
meaning.
1.3 "Appendix" means an Appendix attached to this Contract and
made a part hereof.
1.4 "Appraisal Programme" means a programme, approved by the Management
Committee for the appraisal of an Existing or New Discovery of
Petroleum in the Contract Area for the purpose of delineating the
Petroleum Reservoirs to which the Discovery relates in terms of
thickness and lateral extent and determining the characteristics
thereof and the quantity and quality of recoverable Petroleum
therein.
1.5 "Appraisal Well" means a Well drilled within the Contract Area
pursuant to an approved Appraisal Programme.
1.6 "Arms Length Sales" means sales of Petroleum made freely on the
open international market, in freely convertible currencies,
between willing and unrelated sellers and buyers and in which such
buyers and sellers have no contractual or other relationship,
directly or indirectly, or any common or joint interest as is
reasonably likely to influence selling prices and shall, inter
alia, exclude sales (whether direct or indirect, through brokers or
otherwise) involving Affiliates, sales between entities comprising
the Contractor, sales between governments and government-owned
entities, counter trades, restricted or distress sales, sales
involving barter arrangements and generally any transactions
motivated in whole or in part by considerations other than normal
commercial practices.
1.7 "Article" means an article of this Contract and the term
"Articles" means more than one Article.
3
1.8 "Associated Natural Gas" or "ANG" means Natural Gas
occurring in association with Crude Oil either as free Gas
or in solution, if such Crude Oil can by itself be
commercially produced.
1.9 "Barrel" means a quantity or unit equal to 158.9074 litres
(forty-two (42) United States gallons) liquid measure, at a
temperature of sixty (60) degrees Fahrenheit (15.56 degrees
Centigrade) under one atmosphere of pressure (14.7 psia).
1.10 "Basement" means any igneous or metamorphic rock, or rock or any
stratum of such nature, in and below which the geological structure
or physical characteristics of the rock sequence do not have the
properties necessary for the accumulation of Petroleum in
commercial quantities and which reflects the maximum depth at which
any such accumulation can be reasonably expected in accordance with
the knowledge generally accepted in the international petroleum
industry.
1.11 "Calendar Month" means any of the twelve (12) months of the
Calendar Year unless specified otherwise.
1.12 "Calendar Quarter" means a period of three consecutive Calendar
Months commencing on the first day of January, April, July and
October of each Calendar Year.
1.13 "Calendar Year" means a period of twelve consecutive months
according to the Gregorian calendar commencing with the first day
of January and ending with the thirty-first day of December.
1.14 "Commercial Discovery" means a Discovery which, when produced, is
likely to yield a reasonable profit on the funds invested in
Petroleum Operations, after deduction of Contract Costs, and which
has been declared a Commercial Discovery in accordance with the
provisions of Article 9 and/or Article 21, after consideration of
all pertinent operating and financial data such as recoverable
reserves, sustainable production levels, estimated development and
production expenditures, prevailing prices and other relevant
technical and economic factors according to generally accepted
practices in the international petroleum industry.
1.15 "Commercial Production" means production of Crude Oil or Natural
Gas or both from a Field within the Contract Area and delivery of
the same at the relevant Delivery Point under a programme of
regular production and sale.
1.16 "Company" means either EOGIL or RIL.
1.17 "Companies" means EOGIL and RIL.
1.18 "Condensate" means those low vapour pressure hydrocarbons
obtained from Natural Gas through condensation or extraction
4
and refers solely to those hydrocarbons that are liquid at normal
surface temperature and pressure conditions (provided that in the
event Condensate is produced from an Oil Field and is segregated
and transported separately to the Delivery Point, then the
provisions of this Contract shall apply to such Condensate as if it
were Crude Oil.)
1.19 "Contract" means this agreement and the Appendices attached hereto
and made a part hereof and any amendments made thereto pursuant to
the terms hereof.
1.20 "Contract Area" means the area described in Appendix A and
delineated on the map attached as Appendix B, or any portion of the
area remaining after relinquishment or surrender from time to time
pursuant to the terms of this Contract.
1.21 "Contract Costs" means Exploration Costs, Development Costs,
Production costs, and all other costs related to Petroleum
Operations as set forth in Section 3 of the Accounting Procedure.
1.22 "Contract Year" means a period of twelve consecutive months counted
from the Effective Date or from the anniversary of the Effective
Date.
1.23 "Contractor" means EOGIL, RIL and ONGC.
1.24 "Cost Petroleum" means the portion of the total volume of Petroleum
produced and saved from the Contract Area which the Contractor is
entitled to take from the Contract Area in a particular period for
the recovery of Contract Costs as provided in Article 13.
1.25 "Cost Recovery Limit" shall have the meaning given in
Article 13.1.2.
1.26 "Crude Oil" means crude mineral oil, asphalt, ozokerite and all
kinds of hydrocarbons and bitumens, both in solid and in liquid
form, in their natural state or obtained from Natural Gas by
condensation or extraction, including distillate and Condensate
when commingled with the heavier hydrocarbons and delivered as a
blend at the Delivery Point but excluding verified Natural Gas.
1.27 "Delivery Point" means, except as otherwise herein provided or as
may be otherwise agreed between the Government and the Contractor,
the point at which Petroleum reaches the upstream weld of the
outlet flange of the delivery facility, either offshore or onshore
and different Delivery Points may be established for purposes of
sales to the Government, export or domestic sales.
1.28 "Development Area" means that part of the Contract Area
corresponding to the area of an Oil Field or Gas Field delineated
in simple geometric shape, together with a
5
reasonable margin of additional area surrounding the Field
consistent with international petroleum industry practice and
approved by the Management Committee or the Government, as the case
may be.
1.29 "Development Costs" means those costs and expenditures
incurred in carrying out Development Operations, as
classified and defined in Section 2 of the Accounting
Procedure and allowed to be recovered in terms of Section 3
thereof.
1.30 "Development Operations" means operations conducted in accordance
with the Development Plan and shall include, but not be limited to,
the purchase, shipment or storage of equipment and materials used
in developing Petroleum accumulations, the drilling, completion,
Recompletion and testing of Development Wells, the drilling,
completion and Recompletion of Wells for Gas or water injection,
the laying of gathering lines, the installation of offshore
platforms and installations, the installation, hook up and
commissioning of separators, tankage, pumps, artificial lifting and
other producing and injection facilities required to produce,
process and transport Petroleum into main oil storage or Gas
processing facilities, either onshore or offshore, including the
laying of pipelines within or outside the Contract Area, storage
and Delivery Point or Points, the installation of storage or Gas
processing facilities, the installation of export and loading
facilities and other facilities required for development and
production of the Petroleum accumulations and for the delivery of
Crude Oil and/or Gas at the Delivery Point(s) and also including
incidental operations not specifically referred to herein as
required for the most efficient and economic development and
production of the Petroleum accumulations in accordance with good
international petroleum industry practices.
1.31 "Development Plan" means a plan containing proposals
required under Article 9 or Article 21.
1.32 "Development Well" means a Well drilled, deepened, completed, or
Recompleted after the date of approval of the Development Plan
pursuant to Development Operations or Production Operations for the
purposes of producing Petroleum, increasing production, sustaining
production or accelerating extraction of Petroleum including
production Wells, injection Wells and dry Wells.
1.33 "Discovery" means the finding, during Exploration Operations, of a
deposit of Petroleum not previously known to have existed, which
can be recovered at the surface in a flow measurable by
conventional petroleum industry testing methods, including an
Existing Discovery and a New Discovery.
6
1.34 "Discovery Area" means that part of the Contract Area about which,
based upon Discovery and the results obtained from a Well or Wells
drilled in such part, both the Government and the Contractor are of
the opinion that Petroleum exists and is likely to be produced in
commercial quantities.
1.35 "Effective Date" means the date on which this Contract is
executed.
1.36 "Environmental Clearance" means permission granted in writing by
the Government to the Contractor to perform all activities
necessary and appropriate to conduct Petroleum Operations subject
to conditions specified with regard to protection of the
environment and minimizing Environmental Damage.
1.37 "Environmental Damage" means soil erosion, removal of vegetation,
destruction of wildlife, pollution of groundwater or surface water,
land contamination, air pollution, noise pollution, bush fire,
disruption to water supplies, to natural drainage or natural flow
of rivers or streams, damage to archaeological, palaeontological
and cultural sites and shall include any damage or injury to, or
destruction of, soil or water in their physical aspects together
with vegetation associated therewith, aquatic or terrestrial
mammals, fish, avifauna or any plant or animal life whether in the
sea or in any other water or on, in or under land provided such
damage is in violation of legislation relating to the protection of
the environment.
1.38 "Excess ANG" shall have the meaning given in Article 21.4.
1.39 "Existing Discovery" means a Discovery made by ONGC before the
Effective Date and accepted by the Parties as a Commercial
Discovery.
1.40 "Exploration Costs" means those costs and expenditures
incurred in carrying out Exploration Operations, as
classified and defined in Section 2 of the Accounting
Procedure and allowed to be recovered in terms of Section 3
thereof.
1.41 "Exploration Operations" means operations conducted in the Contract
Area pursuant to this Contract in searching for Petroleum or in the
course of an Appraisal Programme and shall include but not be
limited to aerial, geological, geophysical, geochemical,
palaeontological, palynological, topographical and seismic surveys,
analysis, studies and their interpretation, investigations relating
to the subsurface geology including structure test drilling,
stratigraphic test drilling, drilling of Exploration Wells or
Appraisal Wells and other related activities such as testing,
surveying, drill site preparation and all work necessarily
connected therewith that is conducted in connection with Petroleum
exploration.
7
1.42 "Exploration Well" means a Well drilled for the purpose of
searching for undiscovered Petroleum accumulations on any
geological entity (be it of structural, stratigraphic, facies or
pressure nature) to at least a depth or stratigraphic level
specified in the Work Programme.
1.43 "Field" means an Oil Field or a Gas Field in the Contract Area in
respect of which a Development Plan has been duly approved in
accordance with Article 9 or Article 21 hereof.
1.44 "Financial Year" means the period from the first day of April
through the thirty-first day of March of the following Calendar
Year.
1.45 "Foreign Company" means a Company within the meaning of Section 591
of the Companies Act, 1956, as amended from time to time.
1.46 "Gas" means Natural Gas.
1.47 "Gas Field" means an area within the Contract Area consisting of a
single Gas Reservoir or multiple Gas Reservoirs all grouped on or
related to the same individual geological structure or
stratigraphic conditions, designated by the Contractor and approved
by the Government or Management Committee, as the case may be, (to
include the maximum area of potential productivity in the Contract
Area in a simple geometric shape) in respect of which a Commercial
Discovery has been declared or a Development Plan has been approved
in accordance with Article 9 or Article 21 hereof.
1.48 "Investment" shall have the meaning assigned in paragraph 3
of Appendix D.
1.49 "Investment Multiple" means the ratio of accumulated Net Cash
Income to accumulated Investment in the Contract Area, earned by
the Companies, as determined in accordance with Appendix D.
1.50 "LIBOR" means the London Inter-Bank Offering Rate for six-month
deposits of United States Dollars as quoted by the London office of
the Bank of America (or such other Bank as the Parties may agree)
for the day or days in question.
1.51 "Lessee" means any person or body corporate, including the
Contractor, which holds a mining lease under the Petroleum and
Natural Gas Rules, 1959, for the purpose of carrying out Petroleum
Operations in the Contract Area and their successors and permitted
assigns.
1.52 "Management Committee" means the committee constituted
pursuant to Article 5 hereof.
1.53 "Minimum Work Obligation" means the Work Programme related
8
to those items specified in Appendix G as approved by the
Management Committee.
1.54 "Natural Gas" means wet Gas, dry Gas, all other gaseous
hydrocarbons, and all substances contained therein, including
sulphur and helium, which are produced from Oil or Gas Wells,
excluding those condensed or extracted liquid hydrocarbons that are
liquid at normal temperature and pressure conditions, and including
the residue Gas remaining after the condensation or extraction of
liquid hydrocarbons from Gas.
1.55 "Net Cash Income" shall have the meaning assigned in
paragraph 2 of Appendix D.
1.56 "New Discovery" means a Discovery made after the Effective
Date.
1.57 "Non Associated Natural Gas" or "NANG" means Natural Gas which is
produced either without association with Crude Oil or in
association with Crude Oil which by itself cannot be commercially
produced.
1.58 "Oil" means "Crude Oil".
1.59 "Oil Field" means an area within the Contract Area consisting of a
single Oil Reservoir or multiple Oil Reservoirs all grouped on or
related to the same individual geological structure, or
stratigraphic conditions, designated by the Contractor and approved
by the Government or the Management Committee, as the case may be
(to include the maximum area of potential productivity in the
Contract Area in a simple geometric shape) in respect of which a
Commercial Discovery has been declared and a Development Plan has
been approved in accordance with Article 9 hereof and a reference
to an Oil Field shall include a reference to the production of
Associated Natural Gas from that Oil Field.
1.60 "Operating Agreement" means the Joint Operating Agreement entered
into by the Parties constituting Contractor in accordance with
Article 6, with respect to the conduct of Petroleum Operations.
1.61 "Operating Committee" means the committee established by
that name in the Operating Agreement.
1.62 "Operator" means the Party so designated in Article 6.
1.63 "Participating Interest" means the percentage of participation of
the constituents of the Contractor at any given time in the rights
and obligations under this Contract. Initially the Participating
Interest of the constituents of Contractor are as follows:
9
1. ONGC 40%
2. RIL 30%
3. EOGIL 30%
1.64 "Parties" means the Parties signatory to this Contract including
their successors and permitted assigns under this Contract and the
term "Party" means any of the Parties.
1.65 "Petroleum" means Crude Oil and/or Natural Gas existing in
their natural condition.
1.66 "Petroleum Operations" means, as the context may require,
Exploration Operations, Development Operations or Production
Operations or any combination of such operations, including, but
not limited to, collection of seismic information, drilling and
completion and Recompletion of Wells, construction, operation and
maintenance of all necessary facilities, plugging and abandonment
of Wells, environmental protection, transportation, storage, sale
or disposition of Petroleum to the Delivery Point, Site Restoration
and all other incidental operations or activities as may be
necessary.
1.67 "Production Costs" means those costs and expenditures incurred in
carrying out Production Operations as classified and defined in
Section 2 of the Accounting Procedure and allowed to be recovered
in terms of Section 3 thereof.
1.68 "Production Operations" means all operations conducted for the
purpose of producing Petroleum from the Contract Area after the
commencement of production from the Contract Area, including the
operation and maintenance of all necessary facilities therefor.
1.69 "Profit Petroleum" means all Petroleum produced and saved from the
Contract Area in a particular period as reduced by Cost Petroleum
and calculated as provided in Article 14.
1.70 "Recompletion" means an operation whereby a completion in one zone
is abandoned in order to attempt a completion in a different zone
within the existing wellbore.
1.71 "Reservoir" means a naturally occurring discrete
accumulation of Petroleum.
1.72 "Section" means a section of the Accounting Procedure.
1.73 "Self-Sufficiency" means, in relation to any Financial Year, that
the volume of Crude Oil and Crude Oil equivalent of Petroleum
products exported from India during that Financial Year either
equals or exceeds the volume of Crude Oil and Crude Oil equivalent
of Petroleum products imported into India during the same Financial
Year.
1.74 "Site Restoration" shall mean all activities required to
10
return a site to its state as of the Effective Date pursuant to the
Contractor's environmental impact study or to render a site
compatible with its intended after-use (to the extent reasonable)
after cessation of Petroleum Operations in relation thereto and
shall include, where appropriate, proper abandonment of Wells or
other facilities, removal of equipment and structures (whether
installed before or after the Effective Date), and debris,
establishment of compatible contours and drainage, replacement of
top soil, revegetation, slope stabilization, infilling of
excavations or any other appropriate actions in the circumstances.
1.75 "Subcontractor" means any company or person contracted by
the Operator to provide services with respect to the
Petroleum Operations.
1.76 "Well" means a borehole, made by drilling in the course of
Petroleum Operations, but does not include a seismic shot hole.
1.77 "Work Programme" means all the plans formulated for the
performance of the Petroleum Operations.
1.78 "Year" means Financial Year.
11
ARTICLE 2
DURATION
2.1 The term of this Contract shall be for a period of twenty-
five (25) years from the Effective Date, unless the Contract
is terminated earlier in accordance with its terms, but may
be extended on such terms and conditions as may be mutually
agreed by the Parties hereto.
12
ARTICLE 3
RELINQUISHMENT
3.1 The Contractor may, with the approval of the Management Committee,
voluntarily relinquish a portion of the Contract Area other than an
area for which a Development Plan has been approved. Contractor
shall give the Government written notice of relinquishments thirty
(30) days prior to the end of any Calendar Year.
3.2 Relinquishment of less than all of the Contract Area shall
be in blocks of not less than one hundred square kilometres
(100 sq. kms.) and be of such shape and location as the
Government may deem appropriate for enabling effective
exploration and exploitation of such area.
3.3 Relinquishment of all or a part of the Contract Area or termination
of the Contract shall not be construed as absolving the Contractor
of any liability undertaken or incurred by the Contractor in
respect of the Contract Area prior to the date of such
relinquishment or termination.
13
ARTICLE 4
WORK PROGRAMME
4.1 The Contractor shall commence Petroleum Operations not later than
six (6) months from the Effective Date.
4.2 As soon as possible after the Effective Date, in respect of the
period ending with the last day of the Financial Year in which the
Effective Date falls and thereafter ninety (90) days before
commencement of each following Financial Year, the Contractor shall
submit to the Management Committee, through the Operating
Committee, the Work Programmes and budgets relating to Petroleum
Operations, including the Minimum Work Obligations, to be carried
out during the ensuing Financial Year.
4.3 The Contractor may propose amendments to the details of an approved
Work Programme and budget in the light of the then existing
circumstances and shall submit to the Management Committee, through
the Operating Committee, modifications or revisions to the Work
Programme and budgets.
14
ARTICLE 5
MANAGEMENT COMMITTEE
5.1 For the purpose of proper and expeditious performance of
Petroleum Operations under the provisions of this Contract,
there shall be constituted a committee to be called the
Management Committee.
5.2 The Management Committee shall consist of four (4) members, one (1)
member nominated by and representing Government and one (1) member
nominated by and representing each constituent of the Contractor.
The member nominated by ONGC shall act as chairman.
5.3 A representative of the Operator acting as the convenor
shall call the meetings of the Management Committee.
5.4 Government and the Contractor may nominate alternate members with
full authority to act in the absence and on behalf of the members
nominated under Article 5.2 and may, at any time, nominate another
member or alternate member to replace any member nominated earlier
by notice to other members of the Management Committee.
5.5 A quorum of the Management Committee shall consist of three
(3) members.
5.6 The following matters shall be submitted to the Management
Committee for approval:
(a) annual Work Programmes and budgets and any modifications
or revisions thereto, as proposed by the Operating
Committee, for Exploration Operations, Development
Operations and/or Production Operations;
(b) proposals for an Appraisal Programme, the declaration of a
New Discovery as a Commercial Discovery and the approval
of Development Plans as may be required under this
Contract, or revisions or additions to an Appraisal
Programme or a Development Plan;
(c) delineation of a Field and a Development Area;
(d) appointment of auditors;
(e) collaboration with lessees or contractors of other
areas;
(f) claims or settlement of claims for or on behalf of or
against the Contractor in excess of limits specified in
the Operating Agreement or fixed by the Management
Committee from time to time;
(g) any proposed mortgage, charge or encumbrance on
petroleum assets, petroleum reserves or production of
15
Petroleum;
(h) any other matter required by the terms of this Contract
to be submitted for the approval of the Management
Committee;
(i) any other matter which the Contractor or the Operating
Committee decides to submit to it.
5.7 The Management Committee shall not take any decision without
obtaining prior approval of the Government, where such
approval is required under this Contract.
5.8 The Management Committee shall meet at least once every three (3)
months or more frequently at the request of any member. Operator
shall convene each meeting by notifying the members at least twenty
eight (28) days prior to such meeting (or a shorter period of
notice if the members unanimously so agree) of the time and place
of such meeting and the purpose thereof and shall include in such
notice a provisional agenda for such meeting. The Operator shall be
responsible for processing the final agenda for such meeting and
the agenda shall include all items of business requested by the
members to be included, provided such requests are received by the
Operator at least ten (10) days prior to the date fixed for the
meeting. The Operator shall forward the agenda to the members at
least nine (9) days prior to the date fixed for the meeting.
Matters not included in the agenda may be taken up at the meeting
by any member with the unanimous consent of all the members.
5.9 The Chairman, and in his absence any other member nominated by
ONGC, shall preside over the meetings of the Management Committee.
5.10 The Operator shall appoint one of the members nominated by the
constituents of the Contractor as secretary to the Management
Committee with responsibility, inter alia, for preparation of the
minutes of every meeting in the English language and provision to
every member of the Management Committee with two (2) copies of the
minutes not later than twenty-eight (28) days after the date of the
meeting.
5.11 Within twenty-one (21) days of the receipt of the minutes of a
meeting, members shall notify the Operator and the other members of
their approval of the minutes by putting their signatures on one
copy of the minutes and returning the same to the Operator or by
indicating such approval to the Operator by telex, cable, or
facsimile, with copies to the other members. Any member may suggest
any modification, amendment or addition to the minutes by telex,
cable or facsimile to the Operator and other members or by
indicating such suggestions when returning the copy of the minutes
to the Operator. If the Operator or any other member does not agree
with the modification, amendment or addition to the
16
minutes suggested by any member, the matter shall be brought to the
attention of the other members and resubmitted to the Management
Committee for approval at the next meeting and the minutes shall
stand approved as to all other matters. If a member fails to
appropriately respond within the aforesaid twenty-one (21) day
period as herein provided, the minutes shall be deemed approved by
such member.
5.12 The meetings of the Management Committee shall be held in New
Delhi, India unless otherwise mutually agreed by the members of the
Management Committee.
5.13 All matters requiring the approval of the Management Committee
shall be approved by a vote of three (3) or more members of the
Management Committee one (1) of whom shall be the Government
representative.
17
ARTICLE 6
OPERATORSHIP AND OPERATING AGREEMENT
6.1 EOGIL shall be the Operator for purposes of this Contract.
6.2 No change in operatorship shall be effected without the consent of
the Government, which consent shall not be unreasonably withheld.
6.3 The operating functions required of the Contractor under this
Contract shall be performed by the Operator on behalf of all
constituents of the Contractor subject to, and in accordance with,
the terms and provisions of this Contract, and generally accepted
international petroleum industry practice.
6.4 The constituents of the Contractor shall execute a mutually
agreed Operating Agreement. The Agreement shall be
consistent with the provisions of this Contract and shall
provide for, among other things:
(a) the appointment, resignation, removal and
responsibilities of the Operator;
(b) the establishment of an Operating Committee;
(c) functions of the Operating Committee taking into
account the provisions of the Contract, procedures for
decision making, frequency and place of meetings; and
(d) contribution to costs, default, sole risk, disposal of
petroleum and assignment as between the parties to the
Operating Agreement.
18
ARTICLE 7
GENERAL RIGHTS AND OBLIGATIONS OF THE PARTIES
7.1 Subject to the provisions of this Contract, the Contractor
shall have, but not be limited to, the following rights:
(a) the exclusive right during the term hereof to carry out
Petroleum Operations in the Contract Area and to
recover costs and expenses as provided in this
Contract;
(b) the right to use, free of charge, such quantities of
Petroleum produced from any Field as are reasonably
required for conducting Petroleum Operations in the
Contract Area in accordance with generally accepted
practices in the international petroleum industry;
(c) the right to lay, build, construct or install
pipelines, roads, bridges, ferries, aerodromes,
landing fields, radio telephones, satellite
communications and related communication and
infrastructure facilities and exercise other ancillary
rights as may be reasonably necessary for the conduct
of Petroleum Operations subject to such approvals as
may be required, which shall not be unreasonably
withheld, under the applicable laws and/or regulations
in force from time to time for the regulation and
control thereof;
(d) the right to have an expatriate work force as required
and necessary together with their required personal
effects;
(e) the right to flare Gas temporarily when and as necessary,
provided the Operator shall give notice thereof to the
Government within forty-eight (48) hours of the start of
such flaring and the issue shall be discussed in the next
meeting of the Management Committee;
(f) the right to use all wells, equipment and facilities
installed as of the Effective Date in the Contract Area
("Assets") free of any additional cost or charges or
encumbrances and assignment of such Assets to Operator on
behalf of the Contractor;
(g) such other rights as are specified in this Contract.
7.2 The Government reserves the right to itself, or to grant to the
Lessee or others, the right to prospect for and mine minerals or
substances other than Petroleum within the Contract Area; provided,
however, that if after the Effective Date, the Lessee or others are
issued rights, or the Government proceeds directly to prospect for
and mine in the Contract Area for any minerals or substances other
than
19
Petroleum, the Contractor shall use reasonable efforts to avoid
obstruction to or interference with such operations within the
Contract Area and, in either case, the Government shall use
reasonable efforts to ensure that operations carried out do not
obstruct or unduly interfere with Petroleum Operations in the
Contract Area. In the event of any conflict, Petroleum Operations
shall take preference.
7.3 The Contractor shall:
(a) except as otherwise expressly provided in this Contract,
conduct all Petroleum Operations at its sole risk, cost
and expense and provide all funds necessary for the
conduct of Petroleum Operations including funds for the
purchase or lease of equipment, materials or supplies
required for Petroleum Operations as well as for making
payments to employees and Subcontractors;
(b) conduct all Petroleum Operations within the Contract Area
diligently, expeditiously, efficiently and in a safe and
workmanlike manner in accordance with good international
petroleum industry practice pursuant to the approved Work
Programmes;
(c) ensure provision of all information, data, samples etc.
which the Contractor may be required to furnish under
the applicable laws;
(d) ensure that all equipment, materials, supplies, plant and
installations used for Petroleum Operations comply with
generally accepted standards in the international
petroleum industry and are of proper construction and kept
in good working order;
(e) in the preparation and implementation of Work Programmes
and in the conduct of Petroleum Operations, follow good
international petroleum industry practices with such
degree of diligence and prudence reasonably and ordinarily
exercised by experienced parties engaged in a similar
activity under similar circumstances and conditions;
(f) after the designation of a Field and a Development Area,
pursuant to this Contract, forthwith proceed to take all
necessary action for prompt and orderly development of the
Field and the Development Area and for the production of
Petroleum in accordance with the terms of this Contract;
(g) appoint a technically competent and sufficiently
experienced representative, and, in his absence, a
suitably qualified replacement therefor, who shall be
resident in India and who shall have full authority to
take such steps as may be necessary to implement this
Contract and whose names shall, on appointment within
20
ninety (90) days after commencement of the first
Contract Year, be made known to the Government;
(h) provide acceptable working conditions, living
accommodation and access to medical attention and nursing
care in the Contract Area for all personnel employed in
Petroleum Operations and extend these benefits to other
persons who are engaged in or assisting in the conduct of
Petroleum Operations in the Contract Area;
(i) be always mindful of the rights and interests of India
in the conduct of Petroleum Operations;
7.4 The infrastructure such as pipelines as may be
developed/established by the Contractor within the country may, to
the extent capacity is available, be available to the Government or
any other entity upon payment of compensation which shall include,
but not be limited to, cost of operation, repair, maintenance,
interest and profit. The Government and any other entity using any
of Contractor's facilities shall indemnify and hold harmless
Contractor from and against any and all loss, damage or injury
arising out of or connected with such use.
21
ARTICLE 8
GOVERNMENT ASSISTANCE
8.1 Upon application in the prescribed manner, and subject to
compliance with applicable laws and relevant procedures, the
Government will without any cost to itself:
(a) provide the right of ingress and egress from the Contract
Area and any facilities used in Petroleum Operations,
wherever located, and which may be within their control;
(b) use their good offices, when necessary, to assist
Contractor in procurement of facilities and services
required for execution of Petroleum Operations
including necessary approvals, permits, consents,
authorisations, visas, work permits, licenses, rights
of way, easement, surface rights and security
protection, required pursuant to this Contract and
which may be available from resources within the
Government's control;
(c) use their good offices to assist in identifying and
making available necessary priorities for obtaining
local goods and services;
(d) in the event that onshore facilities are required
outside the Contract Area for Petroleum Operations
including, but not limited to, storage, loading and
processing facilities, pipelines and offices, use their
good offices in assisting the Contractor to obtain from
the authorities of the state government in the state in
which such facilities are required, such licenses,
permits, authorizations, consents, security protection,
surface rights and easements as are required for the
construction and operation of the said facilities by
the Contractor;
(e) in the event there is no economical passage other than
through national parks, sanctuaries, mangroves, wetlands
of national importance, biosphere reserves or other
biologically sensitive areas, assist in obtaining the
prior written permission of the concerned authorities.
8.2 ONGC shall provide data, if any, related to the Contract
Area to the Contractor which has not been previously
provided.
8.3 Environmental Clearance(s), if any, at the Effective Date shall be
assigned to EOGIL without obligation to remediate or correct any
prior commission of omission by ONGC, but obligations, after the
Effective Date, shall be binding on Contractor.
22
ARTICLE 9
DISCOVERY, DEVELOPMENT AND PRODUCTION
9.1 If and when a New Discovery is made within the Contract
Area, the Contractor shall:
(a) forthwith inform the Government of the Discovery;
(b) promptly thereafter, but in no event later than a period
of thirty (30) days from the date of such Discovery,
furnish to the Government particulars, in writing, of the
Discovery;
(c) promptly run tests to determine whether the New
Discovery is of potential commercial interest and,
within a period of sixty (60) days after completion of
such tests and analysis of results, submit a report to
the Management Committee and the Government containing
data obtained from such tests and its analysis and
interpretation thereof, together with a written
notification to the Government of whether, in the
Contractor's opinion, such New Discovery is of
potential commercial interest and merits appraisal.
9.2 If, pursuant to Article 9.1(c), the Contractor notifies the
Government that a New Discovery is of potential commercial
interest, the Contractor shall prepare and submit to the Management
Committee, within one hundred and twenty (120) days of such
notification, a proposed Appraisal Programme with a Work Programme
and budget to carry out an adequate and effective appraisal of such
New Discovery designed to achieve both the following objectives:
(a) determine without delay, and, in any event, within the
period specified in Article 9.5, whether such New
Discovery is a Commercial Discovery; and
(b) determine, with reasonable precision, the boundaries of
the area to be delineated as a Field.
9.3 The proposed Appraisal Programme for a New Discovery shall be
considered by the Management Committee within forty-five (45) days
after submission thereof pursuant to Article 9.2. The Appraisal
Programme, together with the Work Programme and budget submitted by
the Contractor, revised in accordance with any agreed amendments or
additions thereto, approved by the Management Committee, shall be
adopted as the Appraisal Programme and the Contractor shall
promptly commence implementation thereof; and the Yearly budget
adopted pursuant to Article 4, shall be revised accordingly. Where,
in the case of an Existing Discovery, Contractor desires to carry
out additional appraisal work, the Contractor shall submit its
proposed Appraisal Programme in respect of the Existing Discovery
with a Work Programme and budget to the Management Committee for
its approval within
23
one hundred twenty (120) days of the Effective Date.
9.4 The Contractor shall, unless otherwise agreed, in respect of a New
Discovery of Crude Oil, advise the Management Committee, by notice
in writing within a period of twenty-four (24) months from the date
on which the notice provided for in Article 9.1 was delivered,
whether such New Discovery is a Commercial Discovery or not. Such
notice shall be accompanied by a report on the New Discovery
setting forth all relevant technical and economic data as well as
all evaluations, interpretations and analysis of such data and
feasibility studies relating to the New Discovery prepared by or
for the Contractor, with respect to the Discovery. If the
Contractor is of the opinion that Petroleum has been discovered in
commercial quantities, it shall propose that the Government or
Management Committee, as the case may be, declare the New Discovery
as a Commercial Discovery based on the report submitted. In respect
of a New Discovery of Gas, the provisions of Article 21 shall
apply.
9.5 The Management Committee shall, within forty-five (45) days of the
date of the notice referred to in Article 9.4, consider the
proposal of the Contractor and request any other additional
information it may reasonably require so as to reach a decision on
whether or not to declare the New Discovery as a Commercial
Discovery. Such decision shall be made within the later of (a)
ninety (90) days from the date of notice referred to in Article 9.4
or (b) ninety (90) days of receipt of such other information as may
be reasonably required under this Article 9.5. In the case of an
Existing Discovery, Contractor shall within ninety (90) days of the
Effective Date propose a Development Plan following the plan
brought out in Appendix G, intended to achieve the production
profile brought out in Appendix H, containing the detailed
information required in Article 9.6, with supporting budget. Where
a Development Plan is so agreed it shall be the approved
Development Plan pursuant to Article 9 hereof.
9.6 If a New Discovery is declared commercial the Contractor shall
submit to the Management Committee, a comprehensive plan for the
development of the Commercial Discovery within two hundred (200)
days of the declaration of the Discovery as a Commercial Discovery.
Such plan shall contain detailed proposals by the Contractor for
the construction, establishment and operation of all facilities and
services for and incidental to the recovery, storage and
transportation of the Petroleum from the proposed Development Area
to the Delivery Point together with all data and supporting
information including but not limited to:
(a) Description of the nature and characteristics of the
24
Reservoir, data, statistics, interpretations, and
conclusions on all aspects of the geology, reservoir
evaluation, petroleum engineering factors, reservoir
models, estimates of reserves in place, possible
production magnitude, nature and ratio of Petroleum fluids
and analysis of producible Petroleum;
(b) Outlines of the development project and/or alternative
development projects, if any, describing the production
facilities to be installed and the number of wells to be
drilled under such development project and/or alternative
development projects, if any;
(c) Estimate of the rate of production to be established
and projection of the possible sustained rate of
production in accordance with generally accepted
international petroleum industry practice under such
development project and/or alternative development
project, if any, which will ensure that the area does
not suffer an excessive rate of decline of production
or an excessive loss of reservoir pressure;
(d) estimates of Development Costs and Production Costs
under such development project and/or alternative
development projects, if any;
(e) Contractor's recommendations as to the particular
project that it would prefer, if any;
(f) Work Programme and budget for Development and
Production Operations;
(g) anticipated adverse impact on the environment and
measures to be taken for prevention or minimization
thereof and for general protection of the environment
in conduct of operations; and
(h) production profiles, financial / commercial analysis of
the project proposal.
9.7 Any proposed Development Plan submitted by the Contractor pursuant
to Articles 9.5 and/or 9.6 will be approved by the Management
Committee with such amendments and modifications as may be agreed
upon by the Contractor, within seventy-five (75) days of submission
of the Development Plan, which approval shall not be unreasonably
withheld. If such a Development Plan has not been approved by the
Management Committee within the seventy-five (75) day period, the
Contractor shall have the right to submit such plan directly to the
Government for approval, which approval shall not be unreasonably
withheld. The submission will be answered within sixty (60) days of
receipt.
9.8 The Management Committee shall obtain such approvals from
25
the Government as may be required, except where this Contract
provides that the Contractor may obtain such approvals directly.
9.9 If the Management Committee fails to declare a New Discovery of Oil
to be commercial while the Contractor consider that it is
commercial or the Management Committee fails to declare the New
Discovery as a Commercial Discovery within the time limit
stipulated in Article 9.5 hereof, the Contractor may declare the
New Discovery as a Commercial Discovery and submit development and
production plans in respect of the Discovery to the Management
Committee as per the provisions of Article 9.6 and after such plans
have been approved by the Management Committee, the Contractor
shall, acting solely, provide the entire Development Costs and
undertake development of the Oil Field. If, however, the Field
turns out to be non-commercial, the entire Development Cost of the
Field shall be borne solely by the Contractor and shall not be
recoverable as Cost Petroleum from any other Field or Contract Area
but shall be recoverable solely from such Field.
9.10 In the event that the Government considers a New Discovery to be
commercial but the Contractor considers the same as non-commercial,
the Government shall give notice to the Contractor to that effect
and thereafter the Field relating to such New Discovery shall be
excluded from the Contract Area for all purposes. In this event,
the Contractor shall have no claim on the production from such
Field.
9.11 Work Programmes and budgets for Development and Production
Operations shall be submitted to the Management Committee, as soon
as possible after the designation of a Development Area and
thereafter not later than 31st December each Calendar Year in
respect of the Financial Year immediately following.
9.12 The Management Committee, when considering any Work Programme and
budget, may require the Contractor to prepare an estimate of
potential production to be achieved through the implementation of
the programme and budget for each of the three (3) Financial Years
following the Financial Year to which the Work Programme and budget
relate. If major changes in Financial Year to Financial Year
estimates of potential production are required, these shall be
based on concrete evidence necessitating such changes.
9.13 Not later than the fifteenth (15) day of January each Calendar
Year, in respect of the Financial Year immediately following, the
Contractor shall determine the "Programme Quantity". The Programme
Quantity for any Financial Year shall be the maximum quantity of
Petroleum based on Contractor's estimates, as approved by the
Management Committee, which can be produced from a Field consistent
with sound international petroleum industry practices and
26
minimizing unit production cost, taking into account the capacity
of the producing Wells, gathering lines, separators, storage
capacity and other production facilities available for use during
the relevant Financial Year, as well as the transportation
facilities up to the Delivery Point.
9.14 Proposed revisions to the details of a Development Plan or an
annual Work Programme or budget in respect of Development and
Production Operations shall, for good cause and if the
circumstances so justify, be submitted to the Management Committee
for approval, through the Operating Committee.
27
ARTICLE 10
UNIT DEVELOPMENT
10.1 If a Reservoir in a New Discovery Area is situated partly within
the Contract Area and partly in an area in India over which other
parties have a contract or license/lease to conduct Petroleum
Operations, the Government may, for securing the most effective
recovery of Petroleum from such Reservoir, by notice in writing to
the Contractor, require that the Contractor:
(a) collaborate and agree with such other parties on the
joint development of the Reservoir;
(b) submit such agreement between the Contractor and such
other parties to the Government for approval; and
(c) prepare a plan for such joint development of the
Reservoir, within one hundred and eighty (180) days of the
approval of the agreement referred to in (b) above.
10.2 If no plan is submitted within the period specified in Article
10.1(c) or such longer period as the Contractor and other parties
may agree or, if such plan as submitted is not acceptable to the
Government and the parties cannot agree on amendments to the
proposed joint development plan, the Government may cause to be
prepared, at the expense of the Contractor and the other parties
referred to in Article 10.1, a plan for such joint development
consistent with generally accepted practices in the international
petroleum industry which shall take into consideration any plans
and presentations made by the Contractor and the aforementioned
other parties.
10.3 If the Parties are unable to agree on the plan for joint
development, then any of them may refer the matter to a sole expert
for final determination pursuant to Article 33, provided that the
Contractor may in case of any disagreement on the issue of joint
development or the proposed joint development plan, or within sixty
(60) days of determination by a sole expert, notify the Management
Committee that it elects to surrender its rights in the New
Discovery Area in lieu of participation in a joint development.
10.4 If a proposed joint development plan is agreed and adopted by the
parties, or adopted following determination by the sole expert, the
plan as finally adopted shall be the approved joint development
plan and the Contractor shall comply with the terms of the
Development Plan as if the Commercial Discovery is established.
10.5 The provisions of Articles 10.1, 10.2, 10.3 and 10.4 shall apply
MUTATIS MUTANDIS to a New Discovery of a Reservoir located partly
within the Contract Area, which, although not equivalent to a
Commercial Discovery if developed alone,
28
would be a Commercial Discovery if developed together with that
part of the Reservoir which extends outside the Contract Area to
areas subject to contract or given on license/lease for Petroleum
Operations by other parties.
10.6 If a New Discovery is situated partly within the Contract Area and
partly outside the Contract Area, the area outside the Contract
Area over which, at the time of the making of the New Discovery by
the Contractor, no production sharing contract similar to this
Contract has been granted or is under negotiation and/or no
license/lease to conduct petroleum operations has been granted, the
Government will favourably consider the extension of the Contract
Area to include the entire area of the Reservoir if so requested by
the Contractor.
29
ARTICLE 11
MEASUREMENT OF PETROLEUM
11.1 The volume and quality of Petroleum produced and saved from a Field
shall be measured by methods and appliances generally accepted and
customarily used in generally accepted international petroleum
industry practice.
11.2 The Government may, at all reasonable times, inspect and test the
appliances used for measuring the volume and determining the
quality of Petroleum, provided that any such inspection or testing
shall be carried out in such a manner so as not to unduly interfere
with Petroleum Operations.
11.3 Before commencement of production in a Field, except for the
Fields which are producing as of the Effective Date, the
Parties shall mutually agree on:
(a) methods to be employed to optimize the measurement of
volumes of Petroleum;
(b) the point at which Petroleum shall be measured and the
respective shares allocated to the Parties in
accordance with the terms of this Contract;
(c) the frequency of inspections and testing of measurement
appliances and relevant procedures relating thereto;
and
(d) the consequences of a determination of an error in
measurement.
In the case of existing Fields, this Article 11.3 shall be given
force as soon as practicable after the Effective Date, but in any
case, not later than one hundred eighty (180) days after the
Effective Date.
11.4 The Contractor shall undertake to measure the volume and quality of
the Petroleum produced and saved from a Field at the agreed
measurement point consistent with generally accepted practices in
the international petroleum industry. The Contractor shall not make
any alteration in the agreed method or procedures for measurement
or to any of the approved appliances used for the purpose without
the written consent of the Government.
11.5 The Contractor shall give the Government timely notice of its
intention to conduct calibration operations or any agreed
alteration for such operations and the Government shall have the
right to be present and observe, either directly or through
authorized representatives, such operations.
30
ARTICLE 12
PROTECTION OF THE ENVIRONMENT
12.1 The Government and the Contractor recognise that Petroleum
Operations will cause some impact on the environment in the
Contract Area. Accordingly, in performance of the Contract, the
Contractor shall conduct its Petroleum Operations with due regard
to concerns with respect to protection of the environment and
conservation of natural resources. In the furtherance of any laws,
regulations and rules promulgated by the Government, the Contractor
shall:
(a) employ generally accepted industrial standards, including
as required, advanced techniques, practices and methods of
operation for the prevention of Environmental Damage in
conducting its Petroleum
Operations;
(b) take necessary and adequate steps to prevent Environmental
Damage and, where some adverse impact on the environment
is unavoidable, to minimize such damage and the
consequential effects thereof on property and people; and
(c) adhere to the guidelines, limitations or restrictions, if
any, imposed by Environmental Clearance as applicable on
the Effective Date and as such Environmental Clearance may
be revised, expanded or replaced as a result of
Contractor's application(s) duly submitted after the
Effective Date.
12.2 If the Contractor fails to substantially comply with the provisions
of Article 12.1 or materially contravenes any relevant law, and
such failure or contravention results in substantial Environmental
Damage, the Contractor shall forthwith take all necessary and
reasonable measures to remedy the failure and the effects thereof.
12.3 If the Government has, on reasonable grounds, reason to believe
that any works or installations erected by the Contractor or any
operations conducted by the Contractor are endangering or may
endanger persons or any property of any person, or are causing
avoidable pollution, or are harming fauna and flora or the
environment to a degree which is unlawful, the Government may,
pursuant to applicable law, require the Contractor to take remedial
measures within such reasonable period as may be determined by the
Government and, if appropriate, repair such damage. The Government
may, pursuant to applicable law, require the Contractor to
discontinue Petroleum Operations in whole or in part until the
Contractor has taken such action.
12.4 The Contractor shall, within one hundred twenty (120) days of the
Effective Date, cause a person or persons with special knowledge on
environmental matters, approved by the
31
Government, to carry out an environmental impact study in order:
(a) to determine, at the time of the study, the prevailing
situation relating to the environment, human beings and
local communities, the wildlife and marine life in the
Contract Area and in the adjoining or neighbouring areas;
and
(b) to establish the likely effect on the environment, human
beings and local communities, the wildlife and marine life
in the Contract Area and in the adjoining or neighbouring
areas in consequence of the relevant phase of Petroleum
Operations to be conducted under this Contract.
12.5 The Contractor shall ensure that:
(a) Petroleum Operations are conducted in an environmentally
acceptable and safe manner consistent with good
international petroleum industry practice and that such
Petroleum Operations are properly monitored;
(b) the pertinent completed environmental impact studies are
made available to its employees and to its Subcontractors
to develop adequate and proper awareness of the measures
and methods of environmental protection to be used in
carrying out the Petroleum Operations; and
(c) the contracts entered into between the Contractor and its
Subcontractors relating to its Petroleum Operations shall
include the provisions stipulated herein and any
established measures and methods for the implementation of
the Contractor's obligations in relation to the
environment under this Contract.
12.6 The Contractor shall, prior to conducting any drilling activities,
prepare and submit for review by the Government contingency plans
for dealing with oil spills, fires, accidents and emergencies,
designed to achieve rapid and effective emergency response. The
plans referred to above shall be discussed with the Government and
concerns expressed shall be taken into account.
12.6.1 In the event of an emergency, accident, oil spill
or fire arising from Petroleum Operations
affecting the environment, the Contractor shall
forthwith notify the Government and shall
promptly implement the relevant contingency plan
and perform such Site Restoration as may be
necessary.
12.6.2 In the event of any other emergency or accident
arising from the Petroleum Operations affecting
32
the environment, the Contractor shall take such
action as may be prudent and necessary in
accordance with good international petroleum
industry practice in such circumstances.
12.7 In the event that the Contractor fails to take necessary action to
comply with any of the terms contained in Article 12.5 and Article
12.6 within a reasonable period specified by the Government, the
Government, after giving the Contractor reasonable notice in the
circumstances, may take any action which may be necessary to ensure
compliance with such terms and recover from the Contractor,
immediately after having taken such action, all costs and
expenditures incurred in connection with such action together with
such interest as may be determined in accordance with Section 1.7
of Appendix C of this Contract.
12.8 Contractor shall notify the Government upon determination by it
that the estimated remaining recoverable reserves of any Field net
of operating costs equal two and one-half (2 1/2) times the
estimated abandonment cost whereupon the Government shall, within
sixty (60) days, take control of the Field and the abandonment
obligation or, failing which, the Contractor may then proceed to
recover the abandonment cost from the remaining production and
abandon such Field.
12.9 Any and all costs incurred by Contractor pursuant to this Article
shall be cost recoverable including, but not limited to, sinking
funds established for abandonment.
12.10 The responsibility of the Contractor for the environment
hereunder shall be limited to damage to the environment
which:
(a) occurs after the date of the environmental impact
assessment ("EIA") made to establish the benchmark
condition. The EIA will be conducted as soon after the
Effective Date as is reasonably possible;
(b) results from an act or omission of Contractor in
violation of existing law; and
(c) notwithstanding the above, Contractor shall be responsible
for any damage to the environment because of any evidence
of Oil spill, blow-out, fire, etc., during the course of
Joint Operations from the Effective Date.
33
ARTICLE 13
RECOVERY OF COSTS
13.1 The Contractor shall be entitled to recover Contract Costs
out of the total volume of Petroleum produced and saved from
the Contract Area in each Financial Year in accordance with
the provisions of this Article, and, in respect of sole risk
or exclusive operations, Article VII of the Operating
Agreement.
13.1.1 Development Costs incurred by the Contractor in
the Contract Area shall be aggregated, and the
Contractor shall be entitled to recover out of
Cost Petroleum the aggregate of such Development
Costs at the rate of one hundred percent (100%)
per annum, provided, however, that, subject to the
remaining provisions of this Article 13.1, the
Contractor shall not, for the purposes only of
determining the volume of Petroleum to which
Contractor shall be entitled under Article 13.1 as
Cost Petroleum, claim as Contract Costs
Contractor's Development Costs incurred after the
Effective Date in connection with Development
Operations under the Development Plan for Panna
and Mukta Fields (as those Fields are determined
in the Development Plan first approved by the
Management Committee) which exceed Contractor's
Cost Recovery Limit (as hereinafter defined).
13.1.2 For the purposes of this Article 13.1,
Contractor's "Cost Recovery Limit" means costs
incurred after the Effective Date relating to the
construction and/or establishment of such
facilities as are necessary to produce, process,
store and transport Petroleum from within the
Existing Discoveries, in order to enable Oil
production of thirty-eight thousand three hundred
barrels per day (38,300 BOPD) in accordance with
the Development Plan for the Panna and Mukta
Fields. Such costs shall include costs incurred
in relation to those items illustrated in
Appendix G and matters in connection therewith.
Appendix G, Annex G-1, further describes
Companies' development concept based on an
assumed project start date of 1st July, 1993, and
Parties understand and agree that the schedules
and activities contained in such assessment shall
be revised, subject to Management Committee
approval, by the Contractor in Contractor's
Development Plan first submitted pursuant to this
Contract.
The Parties agree that for the purposes of this
Article 13.1 the Contractor's Cost Recovery Limit
shall be the sum of Five Hundred Seventy-seven
Million Five Hundred Thousand U.S. Dollars
(US$577,500,000).
34
13.1.3 The Parties acknowledge that the amount
representing Contractor's Cost Recovery Limit has
been agreed by Contractor on the basis of the
following assumptions and/or factors and/or
information:
(a) Included in calculations for the Cost
Recovery Limit are costs relating to Gas
compression offshore required for
delivering Gas into ONGC's pipeline;
excluded from the Cost Recovery Limit are
Site Restoration and exploration or
appraisal drilling;
(b) the Cost Recovery Limit does not include
any costs for the development of any
satellite Fields;
(c) the Contractor being able to obtain all
necessary approvals (including Government
and state government approvals) to enable
Contractor to carry out the Development
Operations contemplated by the Development
Plan for the Panna and Mukta Fields in
accordance with the timing set out in such
plan;
(d) the data relating to the Contract Area
provided by ONGC from time to time prior to
the Effective Date inclusive of the data
package pertaining to the Contract Area
prepared by ONGC and made available for
inspection and purchase by the Companies
pursuant to the Government's "Notice
Inviting Offers for Joint Ventures to
Develop Medium- Sized Oil and Gas Field in
India, 1992";
(e) international market conditions relating to
the availability and cost of materials and
services in the international petroleum
industry in constant 1993 United States
Dollars;
(f) the range of physical reservoir
characteristics in respect of the Oil and
Gas Fields comprising the Existing
Discoveries not being materially different
from the ranges for such characteristics as
revealed in the data referred to in Article
13.1.3(d) on which Companies based their
assessment as described in Annex G-1 to
Appendix G;
(g) with regard to onshore facilities not
included in the Cost Recovery Limit as per
Articles 13.1.3(a) and 13.1.4(a), ONGC and
Companies will determine a fee,terms and
35
conditions for the referenced facilities,
which fee shall be determined by an
internationally recognized expert in the
field, who shall be selected by two members
of the Operating Committee from a group of
three internationally recognized experts
selected by ONGC and the cost of the
facilities shall be cost recoverable and
not subject to the Cost Recovery Limit; and
(h) no capital investment of a material nature
is required on the Equipment contained in
Appendix F.
13.1.4 Having regard, inter alia, to the matters
referred to in Article 13.1.3, the Parties agree
as follows:
(a) Included in calculations for the Cost
Recovery Limit are costs relating to Gas
compression offshore required for
delivering Gas into ONGC's pipeline system;
excluded from the Cost Recovery Limit are
water injection; Site Restoration and
exploration or appraisal drilling and
capital investment, if any, of a material
nature, on the Equipment contained in
Exhibit F shall not be subject to the Cost
Recovery Limit;
(b) the costs of developing the reserves and/or
potential reserves and/or satellite Fields
referred to in Article 13.1.3(b) shall not
be subject to the Cost Recovery Limit,
notwithstanding that the development,
within the Contract Area, of such reserves
and/or potential reserves and/or satellite
Fields may include shared flowlines,
injection lines, Gas-lift lines and other
facilities with those constructed as part
of the Development Plan for the Panna and
Mukta Fields;
(c) in the event that the Contractor's Cost
Recovery Limit is exceeded as a result of:
(i) delays in carrying out the
Development Operations referred
to in Article 13.1.3(c) due to a
delay in obtaining any necessary
approval;
(ii) material changes to the
Development Plan for the Panna
and Mukta Fields
36
necessitated by Contractor's
review of data provided, if any,
to the Companies by the
Government and/or ONGC after the
Effective Date where the
Companies are able to establish
that had such data been available
prior to the Effective Date then
the Companies, acting reasonably,
would have included such changes
in the Development Plan for the
Panna and Mukta Fields;
(iii) a material change to the
international market conditions
referred to in Article 13.1.3(e);
(iv) a variation to the Development
Plan for the Panna and Mukta
Fields approved by the Management
Committee; or
(v) an event of force majeure as
provided in Article 31;
(vi) capital investments of a material
nature, reasonably required as at
the Effective Date on the
Equipment shown in Appendix F;
then the Management Committee shall, at the
request of the Operator, in a meeting
convened under Article 5.8, promptly
consider what, if any, increase should be
made to the Contractor's Cost Recovery
Limit to fairly reflect the circumstances
in question PROVIDED THAT in the case of
delays referred to in Article 13.1.3(c) the
Management Committee shall not be obligated
to consider any increase where, and to the
extent that, such delay has been caused by
the Companies' failure to act in a diligent
manner.
13.1.5 In the event that:
(a) there is any dispute between the Parties
whether or to what extent a circumstance
referred to in Article 13.1.4(c) has arisen
or resulted in the Contractor's Cost
Recovery Limit being exceeded; or
(b) the Management Committee is unable to agree
whether an increase should be made to the
Contractor's Cost Recovery Limit or is
unable to agree on the amount of any such
increase;
37
then, at any time after thirty (30) days from the
date of the Management Committee meeting referred
to in Article 13.1.4(c), any Party shall be at
liberty to refer the matter to arbitration in
accordance with the provisions of Article 33.
13.1.6 Costs incurred by the Companies prior to the
Effective Date hereof which have been approved by
the Government, in writing, shall be cost
recoverable for purposes hereof after approval of
the Management Committee.
13.2 Exploration Costs (if any) incurred by the Contractor in respect of
the Contract Area up to the date of Commercial Production of
Petroleum from the Contract Area shall be aggregated, and the
Contractor shall be entitled to recover the aggregate of such
Exploration Costs out of the Cost Petroleum from the Contract Area
at the rate of one hundred percent (100%) per annum of such
Exploration Costs beginning from the date of such Commercial
Production.
13.3 The Contractor shall be entitled to recover out of the Cost
Petroleum from the Contract Area the Exploration Costs which it has
incurred in that Contract Area in any Financial Year after the date
of Commercial Production from the Contract Area at the rate of one
hundred percent (100%) per annum of such Exploration Costs
beginning from the date such Exploration Costs are incurred.
13.4 The Contractor shall be entitled to recover Exploration Costs as
provided in Articles 13.2 and 13.3 in relation to the values of the
quantity of Petroleum produced, saved and sold from the Contract
Area, in the relevant year, provided that such Exploration Costs
once recovered shall not be allowable for recovery against any
other contract area.
13.5 Development Costs incurred by the Contractor in the Contract Area
up to the date of Commercial Production from the Contract Area
shall be aggregated, and the Contractor shall be entitled to
recover out of the Cost Petroleum from that Contract Area the
aggregate of such Development Costs at the rate of one hundred
percent (100%) per annum of such Development Costs beginning from
the date of such Commercial Production from the Contract Area.
13.6 The Contractor shall be entitled to recover out of the Cost
Petroleum produced from the Contract Area the Development Costs
which it has incurred on such Contract Area after the date of
Commercial Production from the Contract Area at the rate of one
hundred percent (100%) per annum of such Development Costs
beginning from the date such Development Costs are incurred.
13.7 The Contractor shall be entitled to recover in full during
any Financial Year the Production Costs incurred in the
38
Contract Area out of the Cost Petroleum.
13.8 If during any Financial Year the Cost Petroleum is not sufficient
to enable the Contractor to recover in full the Contract Costs due
for recovery in that Financial Year in accordance with the
provisions of Articles 13.1 through 13.7, then, subject to the
provisions of Article 13.1:
a) recovery shall first be made of the Production Costs;
and
b) recovery shall next be made of the Exploration Costs;
and
c) recovery shall then be made of the Development Costs.
The unrecovered portions of Contract Costs shall be carried forward
to the following Financial Year and the Contractor shall be
entitled to recover such Costs in such Financial Year or the
subsequent Financial Years as if such costs were due for recovery
in that Financial Year, or the succeeding Financial Years, until
the unrecovered costs have been fully recovered out of Cost
Petroleum from the Contract Area.
13.9 For the purposes of this Article, as well as Article 14, costs,
receipts and income shall be converted into production unit
equivalents, and vice versa, using the relevant prices established
pursuant to Article 19 for Crude Oil and Article 21 for Natural
Gas.
13.10 Pending completion of the calculations required to establish
definitively the Contractor's entitlement to Cost Petroleum from
the Contract Area in any Financial Year, the Contractor shall take
delivery, provisionally, of volumes of Crude Oil and/or Natural Gas
representing its estimated Cost Petroleum entitlement calculated
with reference to estimated production quantities, costs and prices
for the Contract Area as established by the Contractor and approved
by the Management Committee. Such provisional determination of Cost
Petroleum shall be made every quarter on a cumulative basis. Within
sixty days of the end of each Financial Year, a final calculation
of the Contractor's entitlement to Cost Petroleum, based on actual
production quantities, costs and prices for the entire Financial
Year, shall be undertaken and any necessary adjustments to the Cost
Petroleum entitlement shall be agreed upon between the Government
and the Contractor and made as soon as practicable thereafter.
13.11 Nothing herein contained shall provide for the recovery of costs by
ONGC which were incurred prior to the Effective Date.
39
ARTICLE 14
PRODUCTION SHARING OF PETROLEUM BETWEEN
CONTRACTOR AND GOVERNMENT
14.1 The Contractor and the Government shall share in the Profit
Petroleum from the Contract Area in accordance with the provisions
of this Article. The share of Profit Petroleum, in any Financial
Year, shall be calculated for the Contract Area on the basis of the
Investment Multiple actually achieved by the Companies at the end
of the preceding Financial Year for the Contract Area as provided
in Appendix D.
14.2 Profit Petroleum
14.2.1 When the Investment Multiple of the Companies at
the end of any Financial Year is less than two
(2.0), the Government shall be entitled to take
and receive five percent (5%) and the Contractor
shall be entitled to take and receive ninety-five
percent (95%) of the total Profit Petroleum from
the Contract Area with effect from the start of
the succeeding Financial Year.
14.2.2 When the Investment Multiple of the Companies at
the end of any Financial Year in respect of any
Contract Area is equal to or more than two (2.0)
but is less than two and one-half (2.5), the
Government shall be entitled to take and receive
fifteen percent (15%) and the Contractor shall be
entitled to take and receive eighty-five percent
(85%) of the total Profit Petroleum from the
Contract Area with effect from the start of the
succeeding Financial Year.
14.2.3 When the Investment Multiple of the Companies at
the end of any Financial Year in respect of the
Contract Area is equal to or more than two and
one-half (2.5) but is less than three (3.0), the
Government shall be entitled to take and receive
twenty-five percent (25%) and the Contractor
shall be entitled to take and receive seventy-
five percent (75%) of the total Profit Petroleum
from the Contract Area with effect from the start
of the succeeding Financial Year.
14.2.4 When the Investment Multiple of the Companies at
the end of any Financial Year in respect of the
Contract Area is equal to or more than three
(3.0) but is less than three and one-half (3.5),
the Government shall be entitled to take and
receive forty percent (40%) and the Contractor
shall be entitled to take and receive sixty
percent (60%) of the total Profit Petroleum from
the Contract Area with effect from the start of
40
the succeeding Financial Year.
14.2.4 When the Investment Multiple of the Companies at
the end of any Financial Year in respect of the
Contract Area is equal to or more than three and
one-half (3.5), the Government shall be entitled
to take and receive fifty percent (50%) and the
Contractor shall be entitled to take and receive
fifty percent (50%) of the total Profit Petroleum
from the Contract Area with effect from the start
of the succeeding Financial Year.
14.3 The value of the Companies' Investment Multiple at the end of any
Financial Year in respect of the Contract Area shall be calculated
in the manner provided for, and on the basis of net cash flows
specified, in Appendix D to this Contract. However, the volume of
Profit Petroleum to be shared between the Government and the
Contractor shall be determined for each quarter on a cumulative
basis. As regards the period from the Effective Date through the
end of the first full Financial Year, in view of the vagaries of
short-term financial records and to assure equitable calculation of
the Investment Multiple based on reasonable historical records, the
Investment Multiple calculated at the end of the first full
Financial Year shall be applied retroactively to the Effective
Date, and until the actual value can be determined, the provisional
Investment Multiple for that period shall be calculated on the
basis of Contractor's estimate of revenues and expenditures as
provided in the Development Plan. Pending finalization of accounts,
delivery of Profit Petroleum shall be taken by the Government and
the Contractor on the basis of provisional estimated figures of
Contract Costs, production, prices, receipts, income and any other
income or allowable deductions and on the basis of the value of the
Investment Multiple achieved at the end of the preceding Financial
Year. All such provisional estimates shall be finally approved by
the Management Committee but are deemed valid until such time as
the Management Committee reaches a decision or a decision is
rendered under Article 33. When it is necessary to convert monetary
units into physical units of production equivalents or vice versa,
the price or prices determined pursuant to Articles 19 and 21 for
Crude Oil and Natural Gas, respectively, shall be used. Within
sixty (60) days of the end of each Financial Year, a final
calculation of Profit Petroleum based on actual costs, quantities,
prices and income for the entire Financial Year shall be undertaken
and any necessary adjustments to the sharing of Profit Petroleum
shall be agreed upon between the Government and the Contractor and
made as soon as is practicable thereafter.
14.4 The Profit Petroleum due to the Contractor in any Financial Year
from the Contract Area shall be divided between the Parties
constituting the Contractor in proportion to their
41
respective Participating Interests.
42
ARTICLE 15
TAXES, ROYALTIES, RENTALS, ETC.
15.1 The Companies and the operations under this Contract shall be
subject to all fiscal legislation in India, except where, pursuant
to any authority granted under any applicable law, they are exempt
wholly or partly from the application of the provisions of a
particular law or as otherwise provided herein.
15.2.1 For the purpose of computing profits or gains of the business
consisting of and prospecting for or extraction or production of
Petroleum, there shall be made in lieu of the allowances admissible
under the Income Tax Act, 1961, such allowances as are specified in
this Agreement pursuant to Section 42 in relation to:
(a) expenditure by way of infructuous or abortive
exploration expenses in respect of any area surrendered
prior to the beginning of Commercial Production; and
(b) after the beginning of commercial production, to
expenditure incurred, whether before or after such
Commercial Production, in respect of drilling or
exploration activities or services or in respect of
physical assets used in that connection.
15.2.2 Payments made by the Companies pursuant to Article 16 shall be
deductible for income tax purpose in the year in which payment is
made by the Companies, as permissible under Section 42 of the
Income Tax Act, 1961.
15.3.1 In respect of matters not covered above, deduction shall be allowed
in accordance with other provisions of Income Tax Act, 1961, and
the rules framed thereunder.
15.3.2 The revenue from the Business consisting of Petroleum
Operations shall be determined in accordance with Article 19
for its Participating Interest share of Crude Oil saved and
sold, or otherwise disposed of, from each Field and from any
revenue realized on the sale of ANG or NANG referred to in
Article 21 as well as any other gains or receipts from
Petroleum Operations as reduced by the deductions as
specified within this Article, and, except as herein
provided, all the provisions of the Income Tax Act, 1961,
shall apply.
43
15.4 The following terms used in Section 42 of the Income Tax Act, 1961,
and Articles 15.2 and 15.3 shall have the meanings corresponding to
the terms used in this Contract and defined in Article 1 as
follows:
(a) "Previous Year" means the year as defined in Section
2(34) of the Income Tax Act, 1961.
(b) The other terms used herein and not defined in the Income
Tax Act, 1961 shall have the meaning therein ascribed in
Article 1.
15.5 Except for income tax as otherwise provided in this Article, the
Government covenants to the Companies that the Companies shall not
be liable to the Government for payment of:
(a) any taxes calculated by reference to income from or
sale of Petroleum; or
(b) any customs or excise duties, export duties or any other
statutory charge on the import or re-export of machinery,
plant, equipment, materials or supplies imported by or on
behalf of Contractor or its subcontractors solely and
exclusively for use in Petroleum Operations.
Any such payment, if the Companies are made liable shall be
reimbursed by the Government.
15.6.1 The constituents of the Contractor shall be liable to pay
royalties and cess on their Participating Interest share of
Crude Oil and Natural Gas saved and sold in accordance with
the provisions of this Agreement. The royalty on Oil saved
and sold will be paid at Rs. 481 per metric ton and cess on
Oil saved and sold will be paid at Rs. 900 per metric ton.
Royalty on Gas saved and sold will be paid at ten percent
(10%) of the value at wellhead. No cess shall be payable on
Gas or Condensate or other Natural Gas liquids produced in
association with Gas. Royalty and cess shall not exceed the
herein above amounts throughout the term of the Contract.
Royalty and cess shall be payable in Indian Rupees. Any such
additional payment shall be made by the Government.
15.6.2 All payments (except income tax) made by Contractor or its
constituents as applicable under appropriate law including, but not
limited to, taxes whether levied by the Central Government or state
government, or any other local or statutory authority, royalties,
cess, levies, duties, rentals, lease rent, license fees, export
duties,
44
countervailing duties, provision for sinking fund for environmental
or abandonment costs, or any other charges whatsoever, directly
attributable to Petroleum Operations shall be cost recoverable.
15.7 If any change in or to any Indian law, rule or regulation by any
authority dealing with income tax or other corporate tax,
export/import tax, customs duty, or tax imposed upon Petroleum or
dependent on the value of Petroleum (including Royalty and cess)
results in a material change to the economic benefits accruing to
any of the Parties to this Contract after the Effective Date, the
Parties shall consult promptly to make necessary revisions and
adjustments to the Contract in order to maintain such expected
benefits to each of the Parties.
45
ARTICLE 16
PAYMENT
16.1 The Companies shall pay to ONGC in consideration of the right to
commence and carry out exploration and drilling activities in the
Contract Area, pursuant to and in accordance with the Notice
Inviting Offers for Joint Ventures to Develop Medium Size Oil and
Gas Fields in India- 1992 and the bid submitted in response
thereto, as follows:
(a) within two (2) days following the Effective Date,
excluding days on which the banks in India or the
United States are closed, Three Million Six Hundred
Thousand United States Dollars (US$3,600,000). EOGIL
shall pay One Million Eight Hundred Thousand United
States Dollars (US$1,800,000) and RIL shall pay One
Million Eight Hundred Thousand United States Dollars
(US$1,800,000). ONGC's bank wire transfer instructions
are as follows:
ACCOUNT NUMBER: 01 00000 3054
OIL & NATURAL GAS CORPORATION LIMITED
STATE BANK OF INDIA, OVERSEAS BRANCH
VIJAYA BUILDING,
BARAKHAMBA ROAD,
NEW DELHI, INDIA 110 001
(b) When and if the hereinafter set forth production
quantities are reached, the Companies will within fifteen
(15) days following such attainment pay ONGC in accordance
with the following schedule:
(i) Another Six Million United States Dollars
(US$6,000,000) after achieving a cumulative
production of fifty million barrels of Oil;
(ii) Another Nine Million United States Dollars
(US$9,000,000) after achieving a cumulative
production of one hundred million barrels
of Oil; and
(iii) Another Fifteen Million United States
Dollars (US$15,000,000) after achieving a
cumulative production of two hundred
million barrels of Oil.
16.2 Cumulative production shall, for purposes of this Article,
mean Oil produced.
16.3 Each Company shall pay its share of the payment in the
proportion that it received Petroleum.
46
ARTICLE 17
CUSTOMS DUTIES
17.1 Machinery, plant, equipment, materials and supplies imported by a
Contractor or its Subcontractors for use in Petroleum Operations
shall be exempted from customs duties subject to compliance with
procedures, if any, as may be determined pursuant to applicable
customs duty legislation, Article 23 and the terms herein
specified.
17.2 Contractor shall, from time to time and as required, submit to the
Government a list of Subcontractors who are engaged by it for the
purpose of obtaining the various categories of items pursuant to
the conduct of Petroleum Operations and who may claim exemptions
hereunder.
17.3 In order to qualify for the exemption from customs duties as
provided for in Article 17.1, all imported items for which duty
exemption is being claimed shall be certified, by a representative
of the Contractor, to be imported under the terms of this Contract
for use in carrying out Petroleum Operations and shall be certified
by a representative of the Government to be eligible for such
exemption pursuant to the terms of the Contract. In order to
expedite such exemption, Contractor may submit a certified list of
qualified items up to sixty (60) days in advance of anticipated
import.
17.4 The Government shall have the right to inspect the records and
documents of the physical item or items for which an exemption is
or has been provided under Article 17.1 to determine that such item
or items are being or have been imported for the purpose for which
the exemption was granted. The Government shall also be entitled to
inspect such physical items wherever located to ensure that such
items are being used or held for the purpose herein specified and
any item not being so used shall immediately become subject to
payment of the applicable customs duties.
17.5 Subject to Article 27, the Contractor and its Subcontractors may
sell or otherwise transfer in India or sell for export all imported
items which are no longer required for Petroleum Operations,
subject to applicable laws governing customs duties and sale or
disposal of such items.
47
ARTICLE 18
DOMESTIC SUPPLY, SALE, DISPOSAL AND
EXPORT OF CRUDE OIL
18.1 Until such time as the total availability to the Government and
government companies of Crude Oil from all Petroleum production
activities in India meets the total national demand, as determined
by the Government, each constituent of the Contractor shall be
required to offer to the Government or its nominee all of the
Contractor's entitlement to Crude Oil from each Field in order to
assist in satisfying the national demand, provided, however, that
nothing contained in any contract entered into by the Contractor
for the supply, sale or disposal of Petroleum, with any nominee of
the Government pursuant to this Contract shall in any manner
abrogate the obligation of the Government contained herein.
18.2 Pursuant to Article 18.1 and subject to Articles 18.4 and 18.6,
each constituent of Contractor shall offer to sell to the
Government (or its nominee) its total Participating Interest share
of Crude Oil to which it is entitled under Articles 13 and 14 at
the price determined in accordance with Article 19 for sales to
Government and the Government shall have the option to purchase the
whole or any portion thereof at the said price.
18.3 The aforementioned offer shall be made by each constituent of
Contractor, in writing, at least six (6) months preceding the
Financial Year in which the sale is to be made, specifying the
estimated quantities and grade of Crude Oil being offered (based
upon estimates which shall be adjusted within ninety (90) days of
the end of each Financial Year on the basis of actual quantities
produced and saved). The Government shall exercise its option to
purchase, in writing, not later than ninety days (90) preceding the
Financial Year in respect of which the sale is to be made,
specifying the quantity and grade of Crude Oil which it elects to
take in the ensuing year. Failure by the Government to give such
notice within the period specified shall be conclusively deemed an
election to take all of the Crude Oil offered (adjusted as provided
herein) in the ensuing Financial Year.
Notwithstanding the above, during the first six (6) months
commencing with the Effective Date of this Contract, notices cited
in Article 18.3 shall be given as soon as practicable and are
deemed to satisfy the notice obligations of this Article 18.3.
18.4 If, during any Financial Year, India attains Self-Sufficiency, the
Government shall promptly thereafter, but in no event later than
the end of that Financial Year, so advise the Contractor by written
notice. In such event, as from the end of the first quarter of the
following Financial Year, or such earlier date as the Parties may
48
mutually agree, Government's option to purchase shall be suspended
and each constituent of Contractor shall have the right to lift and
export their Participating Interest share of Crude Oil until such
time, if any, as Self-Sufficiency shall have ceased to exist. If
Self-Sufficiency ceases to exist during a Financial Year, the
Government shall recover its option to purchase under Article 18.2
in respect of the following Financial Year by giving notice thereof
to the Contractor as provided in Article 18.3.
18.5 All payments in respect of sales to the Government pursuant to
provisions of this Article 18 shall be made by the Government
within the period for credit applicable in the calculation of the
price pursuant to Article 19. If no time frame for credit is
applicable in such calculation, payment shall be made within forty
five (45) days from the date the invoice is delivered to the
Government. Contractor shall submit a monthly invoice to the
Government for the quantity of Crude Oil delivered. Payment shall
be made in United States Dollars by bank wire to the credit of the
Foreign Company's designated account with a bank within or outside
India. All amounts unpaid by the Government by the due date shall,
from the due date, bear interest calculated on a day-to-day basis
at the LIBOR plus one percentage (1%) point from the due date
compounded daily until paid.
18.6 If full payment is not received by Contractor when due as provided
in Article 18.5, the Contractor shall, at any time thereafter,
notify the Government of the default and, unless such default is
remedied within fifteen (15) days from the date of the notice, the
Contractor shall have the right, unless otherwise agreed, upon
written notice to the Government and without prejudice to the
Contractor's right to recover all costs, charges, expenses and
losses, incurred by the Contractor:
a) to suspend the Government's option to purchase under
Article 18.2 and transport the Petroleum to any onshore
facility and sell as each constituent of Contractor may
in its absolute discretion deem fit;
b) without prejudice to the foregoing, to freely lift,
sell and export all its Participating Interest share of
Crude Oil subject to the destination restrictions
specified in Article 18.7, until the Government has
paid the due amount plus interest as provided herein;
c) if the payment plus interest is not received by the
Contractor within one hundred and eighty (180) days
from the date the payment was due, to receive and
export the Government's share of Profit Oil until such
time as either Government has paid all amounts due plus
interest, or the value, based on the price as deter-
mined in accordance with Article 19, of Government's
share of Profit Oil so sold is equal to all amounts due
49
plus interest, whichever first occurs; provided, however,
that if the Government makes a payment to the Contractor
after the Contractor has commenced sale of Government's
share of Profit Oil and such payment together with the
value of Government's share of Profit Oil sold (based on
the price determined in accordance with Article 19)
exceeds the amount due plus interest, necessary adjustment
shall be carried out to refund to the Government forthwith
the excess amount received by the Contractor.
18.7 The Contractor shall be entitled to freely lift, sell and export
any Crude Oil which the Government is unable to take or has elected
not to purchase pursuant to this Article 18 subject to Government's
generally applicable destination restrictions to countries with
which the Government, for policy reasons, has severed or restricted
trade.
18.8 No later than sixty (60) days prior to the commencement of
production in a Field (or Fields where production is from more than
one Field), and thereafter no less than sixty (60) days before the
commencement of each Financial Year, the Contractor shall cause to
be prepared and submitted to the Parties a production forecast
setting out the total quantity of Crude Oil that it estimates can
be produced from a Field during the succeeding year, based on the
maximum efficient rate of recovery of Crude Oil from that Field in
accordance with good petroleum industry practice. No later than
thirty (30) days prior to the commencement of each Calendar
Quarter, the Contractor shall advise its estimate of production for
the succeeding Calendar Quarter and shall endeavour to produce the
forecast quantity for each Calendar Quarter.
Notwithstanding the above, during the first six (6) months
commencing with the Effective Date of this Contract, notices cited
in Article 18.8 shall be given as soon as practicable and are
deemed to satisfy the notice obligations of this Article 18.8.
18.9 Each Party comprising the Contractor shall, throughout the term of
this Contract, have the right to separately take in kind and
dispose of all its share of Cost Petroleum and Profit Petroleum and
shall have the obligation to lift the Cost Petroleum and Profit
Petroleum on a current basis and in such quantities so as not to
cause a restriction of production or inconvenience to the other
Parties.
18.10 The Government shall, throughout the term of this Contract, have
the right to separately take in kind and dispose of its share of
Profit Petroleum and of such portion of the Contractor's share of
Petroleum as is purchased by the Government pursuant to Article 18,
subject to Article 18.6 and shall have the obligation to lift all
of the Oil on a current basis and in such quantities so as not to
cause a
50
restriction of production or inconvenience to the other Parties.
Subject to Force Majeure, any Party with an obligation to lift Oil
and failing to do so shall compensate the other Parties for any
loss of revenue due to such failure and will, at its own cost and
risk, be liable for all incident expenses, including demurrage, if
any.
18.11 For the purpose of implementing the provisions of Articles 18.9 and
18.10, a Crude Oil lifting procedure shall be agreed upon by the
Parties as soon as practicable but no later than two (2) months
after the Effective Date of this Contract. Such lifting procedure
shall include, but not necessarily be limited to:
(a) a procedure for notification by the Operator to the
Government, and to each Party comprising the
Contractor, of projected Crude Oil production;
(b) a procedure for notification by the Government, and by
each Party comprising the Contractor, to the Operator, of
its expected offtake and the consequences of inability or
failure to offtake.
51
ARTICLE 19
VALUATION OF OIL
19.1 For the purpose of this Contract, the value of Crude Oil shall be
based on the price determined as provided herein.
19.2 A price for Crude Oil shall be determined for each Calendar Month
or such other period as the Parties may agree (hereinafter referred
to as "the Delivery Period") in terms of United States Dollars per
Barrel, FOB Delivery Point for Crude Oil produced and sold or
otherwise disposed of from each Contract Area, for each Delivery
Period, in accordance with the appropriate basis for that type of
sale or disposal specified below.
19.3 In the event that some or all of Contractor's total sales of Crude
Oil during a Delivery Period are made to third parties in Arms
Length Sales, all sales so made shall be valued at the weighted
average of the prices actually received by Contractor, calculated
by dividing the total receipts from all such sales FOB the Delivery
Point by the total number of Barrels of the Crude Oil sold in such
sales.
19.3.1 In the event that a portion of such third party
Arms Length Sales are made on a basis other than
an FOB basis as herein specified, the portion
shall be valued at the prices equivalent to the
prices FOB the Delivery point for such sales
determined by deducting all costs (such as
transportation, demurrage, loss of Crude Oil in
transit and similar costs) incurred downstream of
the Delivery Point, and the prices so determined
shall be deemed to be the actual prices received
for the purpose of calculation of the weighted
average of the prices for all third party Arms
Length Sales for the Delivery Period.
19.3.2 Each constituent of Contractor shall separately
submit to the Government, within fifteen (15)
days of the end of each Delivery Period, a report
containing the actual prices obtained in their
respective Arms Length Sales to third parties of
any Crude Oil. Such reports shall distinguish
between term sales and spot sales and itemize
volumes, customers, prices received and credit
terms, and the constituent of the Contractor
shall allow the Government to examine the
relevant sales contracts.
19.4 In the event that some or all of a constituent of Contractor's
total sales of Crude Oil during a Calendar Month are made to the
Government, the price of all sales so made shall, unless otherwise
agreed between the Parties, be determined on the basis of either
the FOB selling price per Barrel of one or more crude oils which,
at the time of
52
calculation, are being freely and actively traded in the
international market and are similar in characteristics and quality
to the Crude Oil and/or Condensate in respect of which the price is
being determined, such FOB selling price to be ascertained from
Platt's Crude Oil Market Wire daily publication ("Platt's"), or the
spot market for the same crude oils ascertained in the same manner,
whichever price, in the opinion of the Parties, more truly reflects
the current value of such crude oils. For any Calendar Month in
which sales take place, the price shall be the arithmetic average
price per Barrel determined by calculating the average for the
preceding Calendar Month of the mean of the high and low FOB or
spot prices for each day of the crude oil(s) selected for
comparison adjusted for differences in the Crude Oil and the crude
oil(s) being compared for quality, transportation costs, delivery
time, quantity, payment terms, the market area into which the Crude
Oil is being sold, other contract terms to the extent known and
other relevant factors. In the event that Platt's ceases to be
published or is not published for a period of thirty (30)
consecutive days, the Parties shall agree on an alternative daily
publication.
19.4.1 Notwithstanding anything herein otherwise
provided, the price paid for such sales shall be,
in any Calendar Month,the FOB selling price for a
Marker Crude ("Marker Crude") which shall be Brent
(DTD) on a United States Dollar per Barrel basis
less US$0.10 per Barrel.
19.4.2 The Marker Crude price will be based on the
previous Calendar Month's average of the daily
low and high quotations of Marker Crude as
published by Platts' Market wire. The average is
to be calculated up to three (3) decimals to
arrive at a United States Dollar per Barrel
price, which will be applicable for the month of
supply.
19.4.3 The Government and/or its nominee shall pay any
and all sales tax payable on the sale of Oil to
the Government or its nominee.
19.4.4 The Government and/or its nominee shall enter into
a Crude Oil sales agreement with the Constituents
of the Contractor which shall contain terms and
conditions normally contained in international
Crude Oil sales agreements of a similar nature.
19.5 In the event that in any Delivery Period some but not all of a
constituent of Contractor's sales of Crude Oil from the Contract
Area are made to the Government or a Government company and some
but not all of a constituent of Contractor's sales of Crude Oil
from the Contract Area are
53
made to third parties in Arms Length Sales and the price as
established in accordance with Article 19.4 differs by more than
one percent (1%) from the price as determined in accordance with
Article 19.3 for the same Delivery Period, the Parties shall meet,
upon notice from any Party, to determine if the prices established
for the relevant Delivery Period for sales to the Government should
be adjusted taking into account third party Arms Length Sales made
by a constituent of Contractor of the same or similar Crude Oil
from the relevant Field or other fields and published information
in respect of other genuine third party Arms Length Sales of the
same or similar crude oil for that Delivery Period. Until the
matter of an adjustment for the relevant Delivery Period is finally
determined , the price as established in accordance with this
Article will apply for that Delivery Period. Any adjustment, if
necessary, will be made within thirty (30) days from the date the
adjustment for that Delivery Period is finally determined.
19.6 A constituent of Contractor shall determine the relevant prices in
accordance with this Article and the calculation, basis of
calculation and the price determined shall be supplied to the
Government and shall be subject to agreement by the Government
before it is finally determined. Pending final determination, the
last established price, if any, for the Crude Oil shall be used.
19.7 In the event that the Parties fail to reach agreement on any matter
concerning selection of the crude oil(s) for comparison, the
calculation, the basis of, or mechanism for the calculation of the
prices, the prices arrived at, the adjustment of any price or
generally about the manner in which the prices are determined
according to the provisions of this Article within thirty (30)
days, or such longer period as may be mutually agreed between the
parties, from the date of commencement of Commercial Production or
the end of each Delivery Period thereafter, any Party may refer the
matter or matters in issue for final determination by a sole expert
appointed as provided in Article 33.
19.7.1 Within ten (10) days of the said appointment, the
Parties shall provide the expert with all
information they deem necessary or as the expert
may reasonably require.
19.7.2 Within fifteen (15) days from the date of his
appointment, the expert shall report to the
Parties on the issue(s) referred to him for
determination, applying the criteria or mechanism
set forth herein and indicate his decision
thereon to be applicable for the relevant
Delivery Period for Crude Oil and such decision
shall be accepted as final and binding by the
Parties.
54
19.7.3 Except for the adjustment referred to in
Article 19.5, any price or pricing mechanism
agreed by the Parties pursuant to the provisions
of this Article shall not be changed
retroactively.
19.8 Any sale or disposal to Affiliates or other sale or disposal of
Crude Oil produced from a Field, other than to the Government or
Government companies or to third parties in Arms Length Sales, in
any Delivery Period, shall be valued on the same basis as sales to
the Government or a Government company. In the event of such a sale
or disposal by a Company, such Company shall submit to the
Government, within fifteen (15) days of the end of each Delivery
Period, all relevant information concerning such sales or
disposals.
19.9 In the event that in any Delivery Period there is more than one
type of sales referred to in Articles 19.3, 19.4 and 19.8, then,
for the purpose of calculating Cost Petroleum and Profit Petroleum
entitlement pursuant to Articles 13 and 14, a single price per
Barrel of Crude Oil for all the sales for the relevant Delivery
Period shall be used. Such single price shall be the weighted
average of the prices determined for each type of sale, weighted by
the respective volumes of Crude Oil sold in each type of sale in
the relevant Delivery Period.
19.10 In this Article the term "Government" shall include any other
agency or nominee of the Government to whom Crude Oil is to be
sold.
19.11 The provisions specified above for the determination of the price
of sales of Crude Oil shall apply mutatis mutandis to Condensates.
19.12 The Parties shall meet annually, or sooner upon notice served by
any Party on the others, to review the list of selected Crude Oils
or the mechanism established pursuant to this Article 19 in light
of any new facts since the date of selection of such Crude Oils or
establishment of such mechanism and to determine what adjustment
(if any) should be made to the said selection or mechanism by
mutual agreement of the Parties.
55
ARTICLE 20
CURRENCY AND EXCHANGE CONTROL PROVISIONS
20.1 Subject to the provisions herein, and to compliance with the
relevant provisions of the laws of general application in India
governing currency and foreign exchange and related administrative
instructions and procedures issued thereunder on a
non-discriminatory basis, each Foreign Company comprising the
Contractor shall, during the term of this Contract have the right
to:
(a) repatriate funds relating to Petroleum Operations abroad,
in United States Dollars or any other freely convertible
currency acceptable to the Government and the Foreign
Company;
(b) receive, retain and use abroad the proceeds of any
export sales of Petroleum under the contract;
(c) open, maintain and operate bank accounts with reputable
banks, both inside and outside India, for the purpose
of this Contract;
(d) freely import, through normal banking channels, funds
necessary for carrying out the Petroleum Operations;
(e) convert into foreign exchange and repatriate sums
imported pursuant to (d) above in excess (if any) of
its requirements; and
(f) make payments of interest and principal outside of India
for purchases, services and loans obtained abroad without
the requirement that funds used in making such payments
must come from or originate in India.
Provided however, that repatriation pursuant to sub-paragraphs (a)
and (e) and payments pursuant to sub-paragraph (f) shall be subject
to the provisions of any treaties or bilateral arrangements between
the Government and any country with respect to payments to that
country.
20.2 The rates of exchange for the purchase and sale of currency by the
Contractor shall be the prevailing rates of general application
determined by the State Bank of India or such other financial body
as may be mutually agreed by the Parties and in accordance with
prevailing currency and exchange regulations and, for accounting
purposes under this Contract, these rates shall apply as provided
in Section 1.6 of Appendix C.
20.3 Domestic Companies shall be subject to the relevant provisions of
the applicable laws in India governing currency and foreign
exchange and related administrative instructions and procedures
issued thereunder.
56
ARTICLE 21
NATURAL GAS
21.1 Subject to Article 21.2, the Indian domestic market shall have the
first call on the utilisation of Natural Gas discovered pursuant to
Petroleum Operations and produced from the Contract Area.
Accordingly, any proposal by the Contractor relating to Discovery
and production of Natural Gas from the Contract Area shall be made
in the context of the Government's policy for the utilisation of
Natural Gas and shall take into account the objectives of the
Government to develop its resources in the most efficient manner
and to promote conservation measures.
21.2 Contractor shall have the right to use Natural Gas produced from
the Contract Area for the purpose of Petroleum Operations
including, but not limited to, reinjection for pressure maintenance
in the Oil Fields, Gas lifting and power generation.
21.3 For the purpose of sales to the domestic market pursuant to this
Article 21, the Delivery Point shall be the Delivery Point set
forth in the Gas sales contract entered into by the Contractor.
21.4 ASSOCIATED NATURAL GAS (ANG)
21.4.1 In the event that a New Discovery of Crude Oil
contains ANG, Contractor shall declare in the
proposal for the declaration of the New Discovery
as a Commercial Discovery as specified in
Article 9, whether (and by what amount) the
estimated production of ANG is anticipated to
exceed the quantities of ANG which will be used
in accordance with Article 21.2 (hereinafter
referred to as "the Excess ANG"). In such event
the Contractor shall indicate whether, on the
basis of the available data and information, it
has reasonable grounds for believing that the
Excess ANG could be commercially exploited in
accordance with the terms of this Contract along
with the Commercial Production of the Crude Oil
from the Oil Field, and whether the Contractor
intends to so exploit the Excess ANG.
21.4.2 Based on the principle of full utilization and
minimum flaring of ANG, a proposed development
plan for an Oil Field (or Oil Fields), shall, to
the extent economically reasonable, include a
plan for utilisation of the ANG from the Existing
Discovery and New Discovery, including estimated
quantities to be flared, reinjected, and to be
used for Petroleum Operations; and, if the
Contractor proposes to commercially exploit the
Excess ANG for sale in the domestic market in
57
accordance with Government's policy, or
elsewhere, the proposed plans for such
exploitation.
If an Existing Discovery is determined to possess
Excess ANG, and such Existing Discovery is
producing or capable of producing as of the
Effective Date of this Contract, Contractor is
granted the right to flare, without penalty or
limitation, such Excess ANG until Gas
transportation facilities, if any, can be provided
for, and such right shall be extended to such
future time or times as such Gas transportation
facilities may become unavailable or their
capacity would restrict or limit production of
Crude Oil. Government will use its good offices to
effect early reduction and/or elimination of such
flaring by causing Gas transportation to be made
available at reasonable rates if a proposal to
that effect is proposed by Contractor or a Company
and approved by the Management Committee.
21.4.3 If the Contractor wishes to exploit the Excess
ANG (whether from an Existing or New Discovery),
such ANG shall first be offered for sale to the
Government (or its nominee) in writing in
accordance with the terms of this Contract. On
receipt of such offer, the Government (or its
nominee) shall, within three (3) months of the
date of receipt thereof, notify the Contractor,
in writing, whether or not it wishes to exercise
its option to purchase the Excess ANG.
21.4.4 If the Government exercises its option to
purchase the Excess ANG as provided in
Article 21.4.3:
(a) the Government shall indicate in the notice
exercising the option, a date, within two
(2) years of the date of the Contractor's
offer, for commencement of purchase of the
Excess ANG;
(b) within six (6) months of the date of
notification of the exercise of the
Government's option pursuant to Article
21.4.3., the Contractor and the Government
(or its nominee) shall agree on the terms
for the sale to Government (or its nominee)
of the Excess ANG.
21.4.5 If the Government does not exercise its option to
purchase the Excess ANG the Contractor shall be
58
free to explore markets for the commercial
exploitation of the Excess ANG.
21.4.6 Where the Contractor is of the view that Excess
ANG cannot be commercially exploited, and chooses
not to exploit ANG, or is unable to find a market
for the Excess ANG pursuant to Article 21.4.5, the
Government shall be entitled to take and utilise
such Excess ANG.
21.4.7 If the Government elects to take the Excess ANG
as provided in Article 21.4.6:
(a) the Contractor shall deliver such Excess
ANG to the Government (or its nominee) free
of cost, at the downstream flange of the
Gas/Oil separation facilities;
(b) the Government or its nominee shall bear
all costs including gathering, treating,
processing and transporting costs beyond
the downstream flange of the Gas/Oil
separation facilities;
(c) the delivery of such Excess ANG shall be
subject to procedures to be agreed between
the Government or its nominee and the
Contractor prior to such delivery, such
procedures to include matters relating to
timing of off-take of such Excess ANG,
which procedures shall not, in any way,
restrict Oil production.
21.4.8 Excess ANG which is not commercially exploited by
the Contractor, or taken by the Government or its
nominee pursuant to this Article 21, shall be
returned to the subsurface structure or flared
where such flaring is approved in the Development
Plan, which approval shall not be unreasonably
withheld, for the relevant Oil Field or where
reinjection is uneconomical or inadvisable in
accordance with good reservoir engineering prac-
tices.
21.4.9 Where the Contractor is of the view that there is
economic merit in flaring Gas in the absence of a
Gas transmission system or during such time as
the pipeline is inoperable or lacks capacity to
take all available Gas, Contractor shall have the
right to flare Gas. In any such event,
Contractor shall notify the Management Committee
within forty-eight (48) hours to obtain its
approval for continuing operations.
59
21.4.10 As soon as practicable after the New Discovery
referred to in Article 21.4.1 or the submission
to the Government of the proposal for the
declaration of the New Discovery as a Commercial
Discovery as therein specified, the Contractor
and the Government or its nominee shall meet to
discuss the sale and/or disposal of any ANG
discovered with a view to giving effect to the
provisions of this Article 21 in a timely manner.
21.4.11 Notwithstanding the above, during the first six
(6) months commencing with the Effective Date of
this Contract, notices cited in Article 21.4 shall
be given as soon as practicable and are deemed to
satisfy the notice obligations of this Article
21.4.
21.5 NON ASSOCIATED NATURAL GAS (NANG)
21.5.1 In the event of a New Discovery of NANG, the
Contractor shall promptly report such New
Discovery to the Management Committee and the
provisions of Articles 9.1 and 9.2 shall apply.
The remaining provisions of Article 9 would apply
to the New Discovery and development of NANG only
in so far as they are not inconsistent with the
provisions of Articles 21.5.1 to 21.5.13.
21.5.2 If, pursuant to Article 9.1, the Contractor gives
notification that a New Discovery is of potential
commercial interest, the Contractor shall submit
to the Management Committee, within one (1)
Calendar Year from the date of notification of
the above New Discovery, the proposed Appraisal
Programme, including a Work Programme and budget
to carry out an adequate and effective appraisal
of such New Discovery, to determine (i) without
delay, whether such New Discovery is a Commercial
Discovery and (ii) with reasonable precision, the
boundaries of the area to be delineated as a
Field. Such programme shall be supported by all
relevant data such as Well data, Contractor's
best estimate of reserve range and production
potential and shall indicate the date of
commencement of the proposed Appraisal Programme.
Where in the case of an Existing Discovery,
Contractor desires to carry out additional
appraisal work, the Contractor shall submit its
proposed Appraisal Programme with a Work
Programme and budget to the Management Committee
within one hundred twenty (120) days of the
Effective Date for approval.
21.5.3 The proposed Appraisal Programme for an Existing
Discovery or a New Discovery shall be considered
60
by the Management Committee within sixty (60) days
of its submission by the Contractor and the
programme together with the Work Programme and
budget submitted by the Contractor revised in
accordance with any agreed amendments or additions
thereto approved by the Management Committee,
shall be adopted as the Appraisal Programme and
the Contractor shall promptly proceed with
implementation of such programme.
21.5.4. If on the basis of the results of the Appraisal
Programme, the Contractor is of the opinion that
NANG has been discovered in commercial
quantities, it shall submit to the Management
Committee, as soon as practicable but not later
than five (5) years from the date of notification
of the aforementioned New Discovery, a proposal
for the declaration of the New Discovery as a
Commercial Discovery. Such proposal shall take
into account the Government's policies on Gas
utilisation and propose alternative options (if
any) for use or consumption of the NANG and be
supported by, inter alia, technical and economic
data, evaluations, interpretations and analyses
of such data, feasibility studies relating to the
New Discovery prepared by or on behalf of the
Contractor and other relevant information.
21.5.5 In the case of a New Discovery, simultaneously
with the Contractor's Appraisal Programme,
Government and the Contractor shall seek to reach
an agreement on the development, production,
processing, utilisation and sale of the NANG, in
the context of Article 21.1, within thirty-six
(36) months of the date of notification of the
Discovery referred to in Article 21.5. If no
proposal is submitted to the Management Committee
by the Contractor within five (5) years from the
date of notification of such New Discovery, the
Contractor shall relinquish its rights to develop
such New Discovery and the area relating to such
New Discovery shall be excluded from the Contract
Area.
21.5.6 Where the Contractor has submitted a proposal for
the declaration of a New Discovery as a
Commercial Discovery, the Management Committee
shall consider the proposal of the Contractor
with reference to commercial utilisation of the
NANG in the domestic market or elsewhere and in
the context of Government's policy on Gas
utilisation and the chain of activities required
to bring the NANG from the Delivery Point to
61
potential consumers in the domestic market or
elsewhere. The Management Committee may, within
ninety (90) days, request that the Contractor
submit any additional information on the New
Discovery and the related Appraisal Programme that
it may reasonably require to facilitate a decision
on whether or not to declare the New Discovery as
a Commercial Discovery.
21.5.7 The Management Committee shall make a decision
regarding the declaration of a New Discovery as a
Commercial Discovery within the latter of:
(a) one hundred eighty (180) days of receipt of
such proposal; or
(b) one hundred eighty (180) days of receipt of
the additional information referred to
above.
21.5.8 If the Management Committee, with the approval of
the Government, declares a New Discovery a
Commercial Discovery, such declaration shall be
accompanied by an indication of the probable
date(s) by when the market(s) would be ready to
receive the Gas and an estimate of the quantities
of Gas that could be so utilised. The
Contractor, in such an event, shall, within One
(1) Calendar Year of the declaration of the New
Discovery as a Commercial Discovery, submit a
Development Plan for the development of the Gas
Field to the Management Committee for its
approval. Such plan shall be supported by all
relevant information including, inter alia, the
information required in Article 9.6. In the case
of an Existing Discovery, Contractor shall within
ninety (90) days of the Effective Date propose a
Development Plan following the plan brought out
in Appendix G, intended to achieve the production
profile brought out in Appendix H, containing the
detailed information required in Article 9.6,
with supporting budget and the Management
Committee shall render its decision regarding
such proposal within thirty (30) days of such
submittal. Where a Development Plan is so
agreed, it shall be an approved Development Plan
pursuant to this Article.
62
21.5.9 If the Development Plan has not been approved by
the Management Committee within one hundred and
eighty (180) days of its submission, the
Contractor shall have the right to submit such
plan or plans directly to the Government for
approval, within sixty (60) days of the expiry of
the time provided to the Management Committee to
approve the plan or plans. The Government shall
respond to the submission within ninety (90) days
of receipt thereof. If the Government rejects
the Contractor's proposed plan or plans, the
Government shall state in writing the reasons for
such rejection and the Contractor shall have the
right to resubmit, within sixty (60) days of
written notice of such rejection, such plan or
plans duly amended to meet the Government's
objections thereto. Such right of resubmission
of each proposed plan or plans shall be
exercisable by the Contractor only once. If the
Parties are unable to agree, any Party shall have
the right to submit the matter to arbitration.
If no such plan or plans is/are submitted to the
Government within the aforesaid period, the
Contractor shall relinquish its right to develop
such Gas Field and such Gas Field shall be
excluded from the Contract Area.
21.5.10 If the Management Committee is unable to agree on
the declaration of a New Discovery as a
Commercial Discovery within the time limit
prescribed in Article 21.5.7, the Contractor, or
any of its constituents, shall be entitled to
submit such proposal directly to the Government
for approval. In such event, the Contractor, or
any of its constituents, shall also submit a
comprehensive plan or plans for development of
such New Discovery, which shall detail the
proposed Development Plan for utilisation of the
NANG produced in the domestic market giving,
inter alia, the data specified in Article 21.5.8.
The proposal for declaration of the New Discovery
as a Commercial Discovery as well as the proposed
Development Plan shall be submitted to the
Government within one hundred and eighty (180)
days of the expiry of the time given to the
Management Committee to reach a decision on the
proposal for declaration of the New Discovery as
a Commercial Discovery and Government shall
respond to the said submission within one hundred
63
twenty (120) days of its receipt. If the
Government disapproves the proposed plan or plans,
the Government shall state in writing the reasons
for such disapproval and the concerned Parties
shall have the right to resubmit, within sixty
(60) days, such plan or plans duly amended to meet
the Government's objections thereto. Such right of
resubmission of each proposed plan or plans shall
be exercisable by the Contractor only once. In the
event the Government does not approve such plan or
plans, any Party shall have the right to submit
the matter to arbitration. If no such plan (plans)
is (are) submitted to the Government within the
aforesaid period, the Contractor shall relinquish
its rights to develop such Gas Field and such Gas
Field shall be excluded from the Contract Area.
21.5.11 In the event the Management Committee , or
Government, as the case may be, approves the
Contractor's proposal for declaration of the New
Discovery as a Commercial Discovery and also the
comprehensive plan or plans for development of
such New Discovery and for the utilisation of
NANG produced in the domestic market, the Gas
Field shall be promptly developed by the
Contractor in accordance with the approved plan
which shall be the Development Plan for the
Field.
21.5.12 In the event the Contractor does not commence
development of a New Discovery within ten (10)
years from the date of completion of the first
Discovery Well, the Contractor shall relinquish
its rights to develop such New Discovery and the
area relating to such New Discovery shall be
excluded from the Contract Area.
21.5.13 The price of the ANG and NANG produced from the
Oil or Gas Field for use in India shall be
specified in the Gas sales contract, which shall
be in accordance with the provisions of this
Article 21.5.13, between the Contractor and the
nominee of the Government.
(a) Unless the context otherwise requires, the
following words and terms wherever and
whenever used or appearing in this
64
Article 21.5.13 shall have the following
meaning:
(i) "British Thermal Unit" or "BTU"
means the amount of energy
required to raise the temperature
of one (1) pound (avoirdupois) of
pure water, at sixty degrees
(60(degree)) Fahrenheit, one
degree (1(degree)) Fahrenheit at
an absolute pressure of 14.73
pounds per square inch.
(ii) "Buyer" means the Government of
India or as Authority of India
Limited ("GAIL").
(iii) "Deliverability" means the lesser
of the maximum aggregate rate of
all wells in the Contract Area or
the maximum delivery capacity of
the processing facility, subject
to generally accepted
international petroleum industry
practices.
(iv) "Delivery Point" means the
upstream weld at the underwater
connection between
Seller'spipeline and ONGC's
underwater Gas transmission line
or lines which transport Gas from
the Bassein Field to the Hazira
area.
(v) "Maximum Delivery Pressure" has
the meaning set forth in Article
21.5.13(c).
(vi) "MMBTU" means one million
(1,000,000) BTU's on a net
heating value basis.
(vii) "Seller" means Contractor.
(b) The Seller agrees to produce and deliver,
on a daily basis, to the Buyer one hundred
percent (100%) of the Deliverability of ANG
and NANG and Condensate delivered therewith
at the Delivery Point and the Buyer,
provided the Gas and Condensate are made
available and tendered for delivery by the
Seller, agrees to take and purchase, on a
daily basis, one hundred percent (100%) of
the Deliverability of ANG and NANG and
Condensate delivered therewith, provided,
however, that Seller, at Seller's sole
discretion, subject to generally accepted
operator practices in the international
petroleum industry, may adjust deliveries
to provide for necessary maintenance,
service and testing. Buyer may request that
Seller vary deliveries to accommodate
similar circumstances in the
65
Buyer's operation and Seller's approval
shall not be unreasonably withheld.
Communications procedures shall be mutually
agreed in the Gas sales contract in
accordance with internationally accepted
industry standards.
(c) The Gas and Condensate sold hereunder shall
be separated into Gas and Condensate at the
offshore processing facility, measured
separately, and recombined and delivered at
the Delivery Point at the operating
pressure of the Buyer's owned or contracted
pipeline up to a maximum pressure ("Maximum
Delivery Pressure") of one thousand (1000)
psig.
(d) Subject to the provisions hereof, the Buyer
shall pay the Seller for each MMBTU of Gas
delivered hereunder, or for each MMBTU of
Gas for which the Buyer is obligated to pay
hereunder, a price calculated as follows:
The Base Price ("Base Price") in United
States Dollars (US$) per MMBTU is fixed on
the basis of ninety-nine percent (99%) of a
Low Sulfur Fuel Oil Basket ("LSFO Basket")
calculated as the average of the daily mean
value for low and high prices of fuel oil
taking into account equal parts of:
(1) bulk residual fuel oil,
containing one percent (1%)
sulfur, quoted for barges at
Northwest Europe, (Barges, FOB
Rotterdam); and
(2) bulk residual fuel oil,
containing one percent (1%)
sulfur, quoted for Mediterranean,
basis Italy, (Cargoes, FOB Med,
basis Italy); and
(3) a theoretical blend of residual
fuel oil composed of Singapore
Cargoes made up of seventy-four
percent (74%) of LSWR-SR 0.3%,
(three-tenths percent (0.3%)
sulfur), and twenty-six percent
(26%) of HSFO 180, three and
one-half percent (3.5%) sulfur,
viscosity 180 centistokes.
The Base Price is calculated on the basis
of the arithmetic average of the monthly
values of the prices of the listed products
as published in Platt's Oilgram Price
Report for the eighteen (18) months of May,
1992 through October, 1993, inclusive.
(These values are derived from the mean of
the daily
66
ranges on days the postings are published
to give a monthly value.) For the purpose
of this Contract, Base Price will be equal
to $ 2.32/MMBTU.
The price of Gas for each MMBTU for each
Calendar Quarter thereafter shall be
determined by the following formula:
Price = Base Price x (A/B)
Where:
A = a value calculated for the
HS/LSFO Basket, defined in this
Article 21.5.13 (d), evaluated for
the twelve (12) months preceding
the Calendar Quarter using the
method for averaging as described
for calculating the Base Price,
and
B = A value calculated for the
HS/LSFO Basket, evaluate for the
twelve (12) months April 1993
through March 1994.
The High Sulfur/Low Sulfur Fuel Oil Basket
("HS/LSFO Basket") is valued as equal parts
of:
(1) bulk residual fuel oil, containing
one percent (1%) sulphur, quoted
for Mediterranean, basis Italy,
(Cargoes, FOB Med, basis Italy);
and
(2) bulk residual fuel oil, containing
one percent (1%) sulfur, quoted
for Northwest Europe Cargoes, CIF,
basis ARA, (Cargoes CIF NWE, Basis
ARA), and
(3) bulk residual fuel oil, Singapore
Cargoes, containing three and
one-half percent (3.5%) sulfur,
viscosity 180 centistokes,
(Singapore HSFO, 180 cst), and
(4) bulk residual fuel oil, Cargoes,
FOB Arab Gulf, viscosity 180
centistokes, (Arab Gulf, FOB HSFO
180 cst)
using the method for averaging as described
for calculating the Base Price.
The Floor Price ("Floor Price") shall be
ninety percent (90%) of the monthly values
of
67
the prices of the LSFO Basket as published
in Platt's Oilgram Price Report for the
eighteen (18) months of May, 1992 through
October, 1993, inclusive. (These values are
derived from the mean of the daily ranges
on days the postings are published to give
a monthly value.) For the purpose of this
Contract, Floor Price will be equal to $
2.11/MMBTU.
Notwithstanding results of the calculations
for price as shown in this Article 21.5.13
(d), the actual price shall in no event be
less than a Floor Price ("Floor Price")
which is calculated as US$2.11/MMBTU, nor
more than a Ceiling ("Ceiling") of the
Floor Price plus US$1.00/MMBTU, provided
that after seven (7) years from the
Effective Date, the Seller shall have the
option to revise the Ceiling to one hundred
fifty percent (150%) of ninety percent
(90%) of the same or equivalent basket of
fuel oils used in calculating the Base
Price averaged over the immediately
preceeding eighteen (18) months.
Parties agree to convert US$/barrel prices
for fuel oil as published in Platt's
Oilgram to US$/MMBTU using a factor of
6.28.
If Platt's Oilgram is no longer published,
an alternate publication shall be mutually
agreed upon.
(e) Parties acknowledge that Gas is to be
eceived by GAIL at Hazira downstream of
separation and sweetening facilities owned
and operated by ONGC. In order to
compensate ONGC for cost of ownership and
operations of these facilities, Contractor
shall make payments to ONGC on the basis of
the costs fixed on an incremental basis by
an internationally recognised expert who
shall be selected by two members of the
Operating Committee from a panel of three
internationally recognised experts selected
by ONGC. In case there is no agreement
between the Companies and ONGC on the
advice tendered, the matter shall be
referred to Government. The decision of
Government shall be final and binding on
all the Parties.
21.5.14 Nothing contained in any contract entered into by
the Contractor for the supply, sale or disposal
68
of Gas, with any nominee of the Government shall
in any manner abrogate the obligation of the
Government contained herein.
21.5.15 The Government and/or its nominee shall pay any
and all sales tax payable on the sale of Gas to
the Government or its nominee.
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70
ARTICLE 22
EMPLOYMENT, TRAINING AND TRANSFER OF TECHNOLOGY
22.1 Without prejudice to the right of the Contractor to select and
employ personnel in numbers and with the qualifications as, in the
opinion of the Contractor, are required for carrying out Petroleum
Operations in a safe, cost effective and efficient manner, the
Contractor shall, to the maximum extent reasonably possible,
employ, and require the Operator and Subcontractors to employ,
citizens of India having appropriate qualifications and experience,
taking into account the experience required and the level and
nature of the Petroleum Operations.
22.2 Contractor shall offer up to two (2) man months per year of
on-the-job training and practical experience in skilled, management
and executive positions of their ongoing Petroleum Operations to
Indian nationals of the Government's choice.
22.3 Contractor shall associate and involve mutually agreed numbers of
citizens of India designated by the Government, which shall in no
event exceed three (3) people at any one time, in the technological
aspects of the then ongoing Petroleum Operations for up to two man
months per year.
Such aspects shall include:
(a) seismic data acquisition, processing and
interpretation;
(b) computerized formation evaluation using well logs;
(c) computerized analysis of geological data for basin
analysis;
(d) laboratory core analysis;
(e) reservoir simulation and modelling;
(f) geochemistry, including analytical methods, source rock
studies, hydrocarbon generation, modelling;
(g) measurement-while-drilling techniques;
(h) stimulation of wells;
(i) production engineering including, optimization methods
for surface and subsurface facilities (e.g. NODAL
analysis and implementation);
(j) reservoir engineering and management including gas and
water injection;
(k) enhanced oil recovery techniques;
71
(l) gas production technology;
(m) pipeline technology;
(n) well design and drilling technology;
(o) design of offshore facilities.
22.4 Except as herein provided, no Party shall be obliged to disclose by
virtue of this Article 22 any data, process or information, whether
owned by itself, any of its Affiliates or a third party, of a
proprietary nature.
22.5 At the request of the Government the Contractor shall separately
endeavour to negotiate, in good faith, technical assistance
agreements with the Government setting forth the terms by which
each constituent of the Contractor may render technical assistance
and make available commercially proven technical information of a
proprietary nature for use in India by the Government. The issues
to be addressed in negotiating such technical assistance agreements
shall include, but not be limited to, licensing issues, royalty
conditions, confidentiality restrictions, liabilities, costs and
method of payment.
72
ARTICLE 23
LOCAL GOODS AND SERVICES
23.1 In the conduct of Petroleum Operations, the Contractor
shall:
(a) give preference to the purchase and use of goods
manufactured, produced or supplied in India provided that
such goods are available on terms equal to or better than
imported goods with respect to timing of delivery, quality
and quantity required, price and other terms;
(b) employ Indian Subcontractors having the required skills
or expertise, to the extent reasonably possible, in so
far as their services are available on comparable
standards with those obtained elsewhere and at
competitive prices and on competitive terms; provided
that where no such Subcontractors are available,
preference shall be given to non-Indian Subcontractors
who utilise Indian goods to the maximum extent possible
subject however to the proviso in paragraph (a) above;
(c) cooperate to the extent possible and without financial
obligation with domestic companies in India to enable them
to develop skills and technology to service the petroleum
industry;
(d) ensure that provisions in terms of paragraphs (a) to
(c) above are contained in contracts between the
Operator and its Subcontractors.
23.2 The Contractor shall establish appropriate procedures, including
tender procedures, for the acquisition of goods and services which
shall ensure that suppliers and Subcontractors in India are given
adequate opportunity to compete for the supply of goods and
services. The tender procedures shall include, inter alia, the
financial amounts or value of contracts which will be awarded on
the basis of selective bidding or open competitive bidding, the
procedures for such bidding, and the exceptions to bidding in cases
of emergency.
23.3 Within one hundred and twenty (120) days after the end of each
Calendar Year, the Contractor shall provide the Government with a
report outlining its achievements in utilising Indian resources
during that Calendar Year.
23.4 In this Article "goods" means equipment, materials and
supplies.
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ARTICLE 24
INSURANCE AND INDEMNIFICATION
24.1 INSURANCE
24.1.1 The Contractor shall, during the term of this
Contract, obtain and maintain insurance coverage
for and in relation to Petroleum Operations for
such amount and against such risks in accordance
with generally accepted international operating
practices as are set forth herein, and shall
furnish to the Government certificates evidencing
that such coverage is in effect. Such insurance
policies shall include the Government as
additional insured and shall waive subrogation
against the Government. The insurance shall,
without prejudice to the generality of the
foregoing, cover:
(a) Loss or damage to all installations,
equipment and other assets for so long as
they are used in or in connection with
Petroleum Operations; provided, however, if
Contractor fails to insure any such
installation, equipment or assets, it shall
replace any loss thereof or repair any
damage caused thereto;
(b) Loss, damage or injury caused by pollution
in the course of or as a result of
Petroleum Operations;
(c) Loss or damage to property or bodily injury
suffered by any third party in the course
of or as a result of Petroleum Operations
for which the Contractor may be liable;
(d) With respect to Petroleum Operations
offshore, the cost of removing wrecks and
cleaning up operations following any
accident in the course of or as a result of
Contractor's Petroleum Operations;
(e) The Contractor's and/or Operator's
liability to its employees engaged in
Petroleum Operations.
24.1.2 The Contractor shall require its Subcontractors to
obtain and maintain insurance against the risks
referred to in Article 24.1.1 relating mutatis
mutandis to such Subcontractors.
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24.2 INDEMNITY
The Contractor shall indemnify, defend and hold the Government
harmless against all claims, losses and damages of any nature
whatsoever, including without limitation, claims for loss or damage
to property or injury or death to persons caused by or resulting
from any Petroleum Operations conducted by or on behalf of the
Contractor.
24.3 ONGC shall indemnify and hold the Companies harmless against all
claims, losses and damages of any nature whatsoever, including, but
not by way of limitation, claims for loss or damage to property or
injury or death to persons or Environmental Damage caused by or
resulting from and attributable to any operations in the nature of
Petroleum Operations conducted by or on behalf of ONGC or failure
to comply with any Environmental Clearance(s) prior to the
Effective Date.
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ARTICLE 25
RECORDS, REPORTS, ACCOUNTS AND AUDIT
25.1 The Contractor shall prepare and maintain at an office in India
accurate and current books, records, reports and accounts of its
activities for and in connection with Petroleum Operations so as to
present a fair, clear and accurate record of all its activities,
expenditures and receipts. The Contractor shall also keep
representative samples of cores and cuttings.
25.2 Based on generally accepted and recognised accounting principles
and modern petroleum industry practices, records, books, accounts
and accounting procedures in respect of Petroleum Operations shall
be maintained on behalf of the Contractor by the Operator, at its
business office in India.
25.3 The annual audit of accounts shall be carried out on behalf of the
Contractor by a qualified, independent firm of internationally
recognised chartered accountants, registered in India and selected
by the Contractor.
25.4 Accounts, together with the auditor's report thereon, shall be
submitted to the Parties for approval not later than the thirtieth
(30th) day of September following the Financial Year.
25.5 The Government shall have the right to audit the accounting records
of the Contractor in respect of Petroleum Operations as provided in
the Accounting Procedure.
25.6 The accounting and auditing provisions and procedures specified in
this Contract are without prejudice to any other requirements
imposed by any statute in India, including, without limitation, any
specific requirements of the statues relating to taxation of
companies.
25.7 For the purpose of any audit referred to in Article 25.5, the
Operator or the Contractor shall make available to the auditor all
such books, records, accounts and other documents and information
as may be reasonably required by the auditor during normal business
hours.
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ARTICLE 26
INFORMATION, DATA, CONFIDENTIALITY, INSPECTION AND SECURITY
26.1 The Contractor shall, promptly after they become available, make
available to the Government in its offices all data obtained as a
result of Petroleum Operations under the Contract including, but
not limited to, geological, geophysical, geochemical,
petrophysical, engineering, well logs, maps, magnetic tapes, cores
and production data as well as all interpretative and derivative
data, including reports, analyses, interpretations and evaluations
prepared in respect of Petroleum Operations (hereinafter referred
to as "Data"). Data shall be the property of the Government,
provided however, that the Contractor shall have the right to make
use of such Data, free of cost, for the purpose of Petroleum
Operations under this Contract as provided herein.
26.2 Contractor shall keep the Government currently advised of all
developments taking place during the course of Petroleum Operations
and shall furnish the Government with such progress reports
containing full and accurate information relating to Petroleum
Operations (on a periodic basis) as the Government may reasonably
require, provided that this obligation shall not extend to
proprietary technology. Without prejudice to the generality of the
foregoing, the Contractor shall submit regular statements and
reports relating to Petroleum Operations as provided in Appendix C.
Contractor shall meet with the Government at a mutually convenient
location to present the results of all geological and geophysical
work carried out as well as the results of all engineering and
drilling operations as soon as practical after such Data becomes
available to the Contractor.
26.3 All Data, information and reports obtained or prepared by, for or
on behalf of, the Contractor pursuant to this Contract shall be
treated as confidential and, subject to the provisions hereinbelow,
the Parties shall not disclose the contents thereof to any third
party without the consent in writing of the other Parties.
26.4 The obligation specified in Article 26.3 shall not operate
so as to prevent disclosure:
(a) to Affiliates, Contractors, or Subcontractors for the
purpose of Petroleum Operations;
(b) to employees, professional consultants, advisers, data
processing centres and laboratories, where required, for
the performance of functions in connection with Petroleum
Operations for any Party comprising the Contractor;
(c) to banks or other financial institutions, in connection
with Petroleum Operations;
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(d) to bona fide intending assignees or transferees of an
interest hereunder of a Party comprising the Contractor
or in connection with a sale of stock of a Party
comprising the Contractor;
(e) to the extent required by any applicable law or in
connection with any legal proceedings or by the
regulations of any stock exchange upon which the shares of
a Party comprising Contractor are quoted;
(f) to Government departments for, or in connection with, the
preparation by or on behalf of the Government of
statistical reports with respect to Petroleum Operations,
or in connection with the administration of this Contract
or any relevant law or for any purpose connected with
Petroleum Operations;
(g) by a Party with respect to any Data or information
which, without disclosure by such Party, is generally
known to the public.
26.5 Any Data, information or reports disclosed by the Parties
comprising the Contractor to any person other than pursuant to
Article 26.4 (a), (b) and (g) shall be disclosed on the terms that
such Data, information or reports shall be treated as confidential
by the recipient. Prompt notice of disclosures made by the
Contractor pursuant to Article 26.5 shall be given to the
Government.
26.6 Any Data, information and reports relating to the Contract Area,
which, in the opinion of the Government, might have significance in
connection with offers by the Government of open acreage or an
exploration programme to be conducted by a third party in another
area, may be disclosed by the Government for such purposes on
conditions to be agreed upon between the Government and the
Contractor.
26.7 Where an area ceases to be part of the Contract Area, the
Contractor shall continue to treat Data and information with
respect to the area as confidential and shall deliver to the
Government copies or originals of all Data and information in its
possession with respect to the area. The Government shall, however,
have the right to freely use the Data and information thereafter.
26.8 The Government shall, at all reasonable times, through duly
authorised representatives, be entitled to observe Petroleum
Operations and to inspect all assets, books, records, reports,
accounts, contracts, samples and Data kept by the Contractor or the
Operator in respect of Petroleum Operations under the Contract,
provided, however, that the Contractor shall not be required to
disclose any proprietary technology. The duly authorised
representatives shall be given reasonable assistance by the
Contractor for such functions and the Contractor shall afford such
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representatives all facilities and privileges afforded to its own
personnel in the field including the use of office space and
housing, free of charge. The representatives shall be entitled to
make a reasonable number of surveys, measurements, drawings, tests
and copies of documents, take samples, and make a reasonable use of
the equipment and instruments of the Contractor provided that such
functions shall not unduly interfere with the Contractor's
Petroleum Operations.
26.9 Contractor shall give reasonable advance notice to the Government,
or to any other authority designated by the Government for such
purpose, of its programme of conducting surveys by aircraft or by
ships, indicating, inter alia, the name of the survey to be
conducted, approximate extent of the area to be covered, the
duration of the survey, the commencement date, and the name of the
airport or port from which the survey aircraft or ship will
commence its voyage.
26.10 The Government, or the authority designated by the Government for
such purpose, shall have the right to inspect any aircraft or ship
used by the Contractor or a Subcontractor carrying out any survey
or other operations in the Contract Area and shall have the right
to put on board such aircraft or ship Government officers in such
number as may reasonably be necessary to ensure compliance by the
Contractor or the Subcontractor with the security requirements of
India.
26.11 Expatriate employees and Subcontractors shall, for national
security purposes, be subject to the approval of the Government,
such approval not to be unreasonably withheld.
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ARTICLE 27
TITLE TO PETROLEUM, DATA AND ASSETS
27.1 The Government is the sole owner of Petroleum underlying the
Contract Area and shall remain the sole owner of Petroleum produced
pursuant to the provisions of this Contract except that part of
Crude Oil or Gas the title whereof has passed to each constituent
of the Contractor or any other person in accordance with the
provisions of this Contract.
27.2 Title to Crude Oil and/or Gas to which each constituent of the
Contractor is entitled under this Contract, and title to Crude Oil
and/or Gas sold to Government or its nominee by the constituents of
the Contractor shall pass to the relevant Party, or as the case may
be, to Government or its nominee at the Delivery Point. Contractor
shall be responsible for all costs and risks prior to the Delivery
Point and each Party shall be responsible for all costs and risks
associated with such Party's share after the Delivery Point. Where
the Government or its nominee purchases all or some of the
Contractor's share of Crude Oil or Condensate, the Government or
its nominee shall be responsible for all costs and risks in respect
of the amount purchased, after the Delivery Point.
27.3 Title to all Data specified in Article 26 shall be vested in the
Government and the Contractor shall have the right of use thereof
as therein provided.
27.4 Assets in place or contracted for use in or on the Contract Area
purchased by the Contractor for use in Petroleum Operations shall
be owned by the Parties comprising Contractor in proportion to
their Participating Interest provided that the Government, or its
nominee, shall have the right to require vesting of full title and
ownership including abandonment obligations, if any, in it, free of
cost, charge and encumbrances, of any or all assets, whether fixed
or movable, acquired and owned by the Contractor for use in
Petroleum Operations inside or outside the Contract Area, except
assets required by a Party for ongoing operations in the nature of
Petroleum Operations in India, such right to be exercisable by the
Government, or its nominee, upon expiry or earlier termination of
the Contract.
27.5 Contractor shall be responsible in accordance with international
petroleum standards for proper maintenance, insurance and safety of
all assets acquired for Petroleum Operations for keeping them in
good repair, order and working condition at all times, and the
costs thereof shall be recoverable as Contract Costs in accordance
with Appendix C.
27.6 So long as this Contract remains in force, the Contractor shall,
free of any charge for the purpose of carrying out Petroleum
Operations hereunder, have the exclusive use of
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the assets which have become or are the property of the Government
including, without limitation, those identified in Appendix F
except that the Sagar Laxmi shall be released to ONGC as soon as
alternate facilities are available, but not later than thirty (30)
months after the Effective Date unless agreed otherwise by the
Parties. During the period Contractor is using the Sagar Laxmi
Contractor shall pay to ONGC, as rental, a price to be based upon a
mutually agreed daily rate. The daily rate shall be determined in
accordance with competitive prices for like type of service. In the
event the daily rate cannot be mutually agreed upon it shall be
determined by an internationally recognized expert in the field
selected by two members of the Operating Committee from a group of
three internationally recognized experts selected by ONGC. If the
parties do not agree, the Government shall make the determination.
27.7 Equipment and assets no longer required for Petroleum Operations
shall first be offered free of cost, charge and encumbrance to the
Government, or its nominee, and, if not required by the Government,
or its nominee, will be so indicated in writing within thirty (30)
days of such offer. Failure to so indicate will be deemed to be a
rejection of the offer by the Government.
27.8 Assets not acquired by the Government, or its nominee, may
be sold or otherwise disposed of subject to the terms of
this Contract.
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ARTICLE 28
ASSIGNMENT OF INTEREST
28.1 Subject to the terms of this Article and other terms of this
Contract, any Party comprising the Contractor may assign, or
transfer, a part or all of its Participating Interest, with the
prior written consent of the Government, which consent shall not be
unreasonably withheld, provided that the Government is satisfied
that:
(a) the prospective assignee or transferee has the financial
standing, technical competence, capacity and ability to
meet its obligations hereunder, and is willing to provide
an unconditional undertaking to assume its Participating
Interest share of obligations and to provide a guarantee
in respect thereof as provided in the Contract.
(b) the prospective assignee or transferee is not a company
incorporated in a country with which the Government,
for policy reasons, has restricted trade or business;
(c) the prospective assignor or transferor and assignee or
transferee respectively are willing to comply with any
reasonable conditions of the Government as may be
necessary in the circumstances with a view to ensuring
performance under the Contract; and
(d) the assignment or transfer will not adversely affect the
performance or obligations under this Contract or be
contrary to the interests of India.
28.2 An application by a Company for consent to assign or transfer shall
be accompanied by all relevant information concerning the proposed
assignment or transfer including detailed information on the
proposed assignee or transferee and its shareholding and corporate
structure, as was earlier required from the Companies constituting
the Contractor, the terms of the proposed assignment or transfer
and the unconditional undertaking referred to in Article 28.1(a)
above. The applicant shall also submit such information relating to
the prospective assignee or transferee of the assignment or
transfer as the Government may reasonably require to enable proper
consideration and disposal of the application.
28.3 No assignment or transfer shall be effective until the approval of
the Government is received, which approval may be given by the
Government on such terms as it may deem fit. Upon assignment or
transfer of its interest in this Contract, the assignor or
transferor shall be released and discharged from its obligations
hereunder only to the extent that such obligations are assumed by
the assignee or transferee with the approval of the Government.
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28.4 The assignor shall clearly state in its deed of assignment, that
the assignee shall be liable for all future obligations, under the
Contract, to the extent of assignment.
28.5 Upon prior notice to the Contractor, the Government may assign or
transfer all or any part of its rights and interest under this
Contract to any Government company wholly or partly owned by the
Government and authorised by the Government to explore for and
exploit Petroleum in the Contract Area. Upon prior notice to the
Government, a Company may assign or transfer all or any part of its
rights and interest under this Contract to an Affiliate subject to
Article 6.2 and the parent company guarantee shall apply.
28.6 An assignment or transfer shall not be made so as to reduce the
Participating Interest of a constituent of the Contractor, at any
time, to less than ten percent (10%) of the total Participating
Interest of all the constituents of the Contractor, except where
the Government may, in special circumstances, so permit.
28.7 Nothing herein contained shall prohibit a Company in the normal
course of business from pledging its Participating Interest share
for purposes of financing, such as a mortgage, charge or
encumbrance on Petroleum assets or production of Petroleum at its
own risk, cost and responsibility. The Contractor shall provide the
Government with fifteen (15) days prior written notice before
entering into any such financing arrangements.
28.8 No assignment or pledge under this Article shall have the effect of
decreasing the benefits accruing to Government under this Contract
in any manner whatsoever.
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ARTICLE 29
GUARANTEE
29.1 Each of the Companies shall deliver to the Government on
the Effective Date of this Contract:
(a) a financial and performance guarantee, for the performance
of all obligations under the Contract, in the case of
EOGIL from a parent company of good financial standing
acceptable to the Government, in favour of the Government,
in the form and substance set out in Appendix E;
(b) a legal opinion from its legal advisors, in a form
satisfactory to the Government, to the effect that the
aforesaid guarantee has been duly signed and delivered on
behalf of the guarantors with due authority and is legally
valid and enforceable and binding upon them.
29.2 If any of the documents referred to in Article 29.1 are not
delivered within the period specified herein, this Contract may be
cancelled by the Government upon ninety (90) days written notice of
its intention to do so.
29.3 Notwithstanding any change in the composition or shareholding of
the parent company furnishing the guarantees herein, it shall,
under no circumstances, be absolved of its obligations contained in
the guarantees provided pursuant to this Article.
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ARTICLE 30
TERMINATION OF CONTRACT
30.1 This Contract may, subject to the provisions hereinbelow and
Article 31, be terminated by the Government without any financial
liability upon giving ninety (90) days written notice of its
intention to do so in the following circumstances, namely, that a
Company :
(a) has knowingly submitted any false statement to the
Government in any manner which was a material
consideration in the execution of this Contract; or
(b) has intentionally and knowingly extracted or authorised
the extraction of any mineral not authorised to be
extracted by the Contract or without the authority of
the Government except such extractions as may be
unavoidable as a result of operations conducted
hereunder in accordance with generally accepted
international petroleum industry practice which, when
so extracted, were immediately notified to the
Government; or
(c) is adjudged bankrupt by a competent court or enters
into any agreement or scheme of composition with its
creditors or takes advantage of any law for the benefit
of debtors; or
(d) has passed a resolution to apply to a competent court for
liquidation of the Company unless the liquidation is for
the purpose of amalgamation or reconstruction of which the
Government has been given notice and the Government is
satisfied that the Company's performance under this
Contract would not be adversely affected thereby and has
given its approval thereto; or
(e) has assigned any interest in the Contract without the
prior consent of the Government as provided in
Article 28; or
(f) fails to make any monetary payment required by law or
under this Contract by the due date or within the
specified period after the due date; or
(g) fails to comply with or contravenes the provisions of
this Contract in a material particular; or
(h) fails to comply with any final determination or award
made by a sole expert or arbitrators pursuant to
Article 33; or
(i) has been served a notice of cancellation pursuant to
Article 29.2.
PROVIDED THAT
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where the Contractor comprises two or more Companies, the
Government shall not exercise its rights of termination pursuant to
Article 30.1, on the occurrence, in relation to one or more, but
not all, of the Companies, of an event entitling the Government to
terminate the Contract, if any other Company or Companies
constituting the Contractor satisfies the Government that it, or
they, is/are willing and would be able to carry out the obligations
of the Contractor.
30.2 This Contract may also be terminated by the Government on giving
the requisite notice specified above if the events specified in
Article 30.1 (c) and (d) occur with respect to a company which has
given a guarantee pursuant to Article 29 subject, however, to
Article 30.3.
30.3 If the circumstances that give rise to the right of termination
under Article 30.1 (f) or (g) or Article 29.2 are remedied by the
Contractor within the ninety (90) day period or such extended
period as may be granted by the Government, following the notice of
the Government's intention to terminate the Contract as aforesaid,
such termination shall not become effective.
30.4 If the circumstance or circumstances that would otherwise result in
termination are the subject matter of proceedings under Article 33,
then termination shall not take place so long as such proceedings
continue and thereafter may only take place when and if consistent
with the arbitral award.
30.5 On termination of this Contract, for any reason whatsoever, the
rights and obligations of the Contractor shall cease but such
termination shall not affect any rights of any Party which may have
accrued or any obligations undertaken, or incurred, pursuant to
this Contract, by Government or the Contractor or any Party
comprising the Contractor and not discharged by the Contractor or
the Party prior to the date of termination.
30.6 In the event of termination pursuant to Articles 30.1 or
30.2:
(a) the Government may require the Contractor, for a period
not exceeding one hundred and eighty (180) days from the
date of termination, to continue, for the account and at
the cost of the Government, Crude Oil or Natural Gas
production activities until the right to continue such
production has been transferred to another entity;
(b) A Foreign Company, which is a constituent of the
Contractor, shall, subject to the provisions hereof, have
the right to remove and export all its property which has
not vested in the Government provided that in the event
that ownership of any property is in doubt,
86
or disputed, such property shall not be exported unless
and until the doubt or dispute has been settled in favour
of the Foreign Company.
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ARTICLE 31
FORCE MAJEURE
31.1 Performance by any Party hereto of any of its obligations under
this Contract, or in fulfilling any condition of any lease granted
to such Party, or any lease issued thereunder, shall, except for
the payment of monies due under this Contract or under the Act and
the Rules or any law, be suspended or excused if, and to the extent
that, such non-performance or delay in performance is caused by
Force Majeure as defined in this Article.
31.2 For the purpose of this Contract, the term Force Majeure means any
cause or event, other than the unavailability of funds, whether
similar to or different from those enumerated herein, beyond the
reasonable control of, and unanticipated or unforeseeable by, and
not brought about at the instance of the Party claiming to be
affected by such event, or which, if anticipated or foreseeable,
could not be avoided or provided for, and which has caused the
non-performance or delay in performance. Without limitation to the
generality of the foregoing, the term Force Majeure shall include
natural phenomena or calamities, earthquakes, typhoons, fires, wars
declared or undeclared, hostilities, invasions, blockades, riots,
insurrection and civil disturbances.
31.3 Where a Party is claiming suspension of its obligations on account
of Force Majeure, it shall promptly, but in no case later than
seven (7) days after the occurrence of the event of Force Majeure,
notify the other Parties in writing giving full particulars of the
Force Majeure, the estimated duration thereof, the obligations
affected and the reasons for its suspension.
31.4 A Party claiming Force Majeure shall exercise reasonable diligence
to seek to overcome the Force Majeure event and to mitigate the
effects thereof on the performance of its obligations under this
Contract provided, however, that the settlement of strikes or
differences with employees shall be within the discretion of the
Party having the difficulty. The Party affected shall promptly
notify the other Parties as soon as the Force Majeure event has
been removed and no longer prevents it from complying with the
obligations which have been suspended and shall thereafter resume
compliance with such obligations as soon as possible. The period of
work commitment or this Contract may be extended by such additional
period as may be agreed by the Parties.
31.5 Notwithstanding anything contained herein, if an event of Force
Majeure occurs and is likely to continue for a period in excess of
thirty (30) days, the Parties shall meet to discuss the
consequences of the Force Majeure and the course of action to be
taken to mitigate the effects thereof or to be adopted in the
circumstances.
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ARTICLE 32
APPLICABLE LAW AND LANGUAGE OF THE CONTRACT
32.1 Subject to the provisions of Article 33.12, this Contract
shall be governed and interpreted in accordance with the
laws of India.
32.2 Nothing in this Contract shall entitle the Government or the
Contractor to exercise the rights, privileges and powers conferred
upon it by this Contract in a manner which will contravene the laws
of India.
32.3 The English language shall be the language of this Contract and
shall be used in arbitral proceedings. All communication, hearings
or visual materials or documents relating to this Contract shall be
in English.
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ARTICLE 33
SOLE EXPERT, CONCILIATION AND ARBITRATION
33.1 The Parties shall use their best efforts to settle amicably all
disputes, differences or claims arising out of or in connection
with any of the terms and conditions of this Contract or concerning
the interpretation or performance thereof.
33.2 Except for matters which, by the terms of this Contract, the
Parties have agreed to refer to a sole expert and any other matters
which the Parties may agree to so refer, any dispute, difference or
claim arising between the Parties hereunder which cannot be settled
amicably may be submitted by any Party to arbitration pursuant to
Article 33.3. Such sole expert shall be an independent and
impartial person of international standing with relevant
qualifications and experience appointed by agreement between the
Parties. Any sole expert appointed shall be acting as an expert and
not as an arbitrator and the decision of the sole expert on matters
referred to him shall be final and binding on the Parties and not
subject to arbitration. If the Parties are unable to agree on a
sole expert, the disputed subject matter may be referred to
arbitration.
33.3 Subject to the provisions herein, any unresolved dispute,
difference or claim which cannot be settled amicably within a
reasonable time may, except for those referred to in Article 33.2,
be submitted to an arbitral tribunal for final decision as
hereinafter provided.
33.4 The arbitral tribunal shall consist of three arbitrators. The Party
or Parties instituting the arbitration shall appoint one arbitrator
and the Party or Parties responding shall appoint another
arbitrator and both Parties shall so advise the other Parties. The
two arbitrators appointed by the Parties shall appoint the third
arbitrator.
33.5 Any Party may, after appointing an arbitrator, request the other
Party(ies) in writing to appoint the second arbitrator. If such
other Party fails to appoint an arbitrator within forty-five (45)
days of receipt of the written request to do so, such arbitrator
may, at the request of the first Party, be appointed by the
Secretary General of the Permanent Court of Arbitration at the
Hague, within forty-five (45) days of the date of receipt of such
request, from amongst persons who are not nationals of the country
of any of the Parties to the arbitration proceedings.
33.6 If the two arbitrators appointed by the Parties fail to agree on
the appointment of the third arbitrator within thirty (30) days of
the appointment of the second arbitrator and if the Parties do not
otherwise agree, the Secretary General of the Permanent Court of
Arbitration at the Hague
90
may, at the request of either Party and in consultation with both,
appoint the third arbitrator who shall not be a national of the
country of any Party.
33.7 If any of the arbitrators fails or is unable to act, his successor
shall be appointed in the manner set out in this Article as if he
was the first appointment.
33.8 The decision of the arbitration tribunal and, in the case of
difference among the arbitrators, the decision of the majority,
shall be final and binding upon the Parties.
33.9 Arbitration proceedings shall be conducted in accordance with the
arbitration rules of the United Nations Commission on International
Trade Law (UNCITRAL) of 1985 except that in the event of any
conflict between these rules and the provisions of this Article 33,
the provisions of this Article 33 shall govern.
33.10 The right to arbitrate disputes and claims under this Contract
shall survive the termination of this Contract.
33.11 Prior to submitting a dispute to arbitration, a Party may submit
the matter for conciliation under the UNCITRAL conciliation rules
by mutual agreement of the Parties. If the Parties fail to agree on
a conciliator (or conciliators) in accordance with the rules, the
matter may be submitted for arbitration. No arbitration proceedings
shall be instituted while conciliation proceedings are pending and
such proceedings shall be concluded within sixty (60) days.
33.12 The venue of conciliation or arbitration proceedings pursuant to
this Article, unless the Parties otherwise agree, shall be London,
England and shall be conducted in the English language. The
arbitration agreement contained in this Article 33 shall be
governed by the laws of England. Insofar as practicable, the
Parties shall continue to implement the terms of this Contract
notwithstanding the initiation of arbitral proceedings and any
pending claim or dispute.
33.13 The fees and expenses of a sole expert or conciliator appointed by
the Parties shall be borne equally by the Parties. Assessment of
the costs of arbitration including incidental expenses and
liability for the payment thereof shall be at the discretion of the
arbitrators.
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ARTICLE 34
ENTIRE AGREEMENT, AMENDMENTS, WAIVER AND MISCELLANEOUS
34.1 This Contract supersedes and replaces any previous agreement or
understanding between the Parties, whether oral or written, on the
subject matter hereof, prior to the Effective Date of this
Contract.
34.2 This Contract shall not be amended, modified, varied or
supplemented in any respect except by an instrument in writing
signed by all the Parties, which shall state the date upon which
the amendment or modification shall become effective.
34.3 No waiver by any Party of any one or more obligations or defaults
by any other Party in the performance of this Contract shall
operate or be construed as a waiver of any other obligations or
defaults whether of a like or of a different character.
34.4 The provisions of this Contract shall inure to the benefit of and
be binding upon the Parties and their permitted assigns and
successors in interest.
34.5 In the event of any conflict between any provisions in the main
body of this Contract and any provision in the Appendices, the
provision in the main body shall prevail.
34.6 The headings of this Contract are for convenience of reference only
and shall not be taken into account in interpreting the terms of
this Contract.
92
ARTICLE 35
CERTIFICATES
35.1 A Company shall furnish, prior to execution of this Contract, a
duly authorised copy of a resolution properly and legally passed by
the Board of Directors of the Company specifying the person
authorised to execute this Contract along with a Certificate duly
signed by the Secretary or an Assistant Secretary of the Company
under its seal in this regard and to the effect that the Company
has the power and authority to enter into this Contract and to
perform its obligations thereunder and has taken all necessary
action to authorise the execution, delivery and performance of the
Contract.
93
ARTICLE 36
NOTICES
36.1 All notices, statements, and other communications to be given,
submitted or made hereunder by any Party to another shall be
sufficiently given if given in writing in the English language and
sent by registered post, postage paid, or by telegram, telex,
facsimile, radio or cable, to the address or addresses of the other
Party or Parties as follows:
a) To the President of India through the
Secretary to the Government of India
Ministry of Petroleum and Natural Gas
Shastri Bhavan
Dr. Rajendra Prasad Marg
New Delhi 110 001, India
Attention: Joint Secretary
Facsimile No. : 91-11-384-787
b) The Secretary
Oil & Natural Gas Corporation Limited
Tower II, 8th Floor, Jeevan Bharati
124 Connaught Circus
New Delhi 110 001, India
Facsimile No. : 91-11-331-6413
c) Reliance Industries Limited
Maker Chambers IV, 3rd Floor
222 Nariman Point
Bombay 400 021 INDIA
Attention: Chief Executive Officer Oil & Gas
Facsimile No. : 022-204-2268
d) Enron Oil & Gas India Ltd.
Amiya Apartments, 1st Floor
63A Linking Road, Santa Cruz (W)
Bombay 400 054 INDIA
Attention: Managing Director
Facsimile No.: 011-91-22-604-9119
with a copy to:
Enron Oil & Gas India Ltd.
1400 Smith Street
Houston, Texas 77002, U.S.A.
Attention: Vice President, Operations
Facsimile No. : 713-646-8115
36.2 Notices when given in terms of Article 36.1 shall be effective when
delivered if offered at the address of the other Parties as under
Article 36.1 during business hours on working days and, if received
outside business hours, on the next following working day.
36.3 Any Party may, by reasonable notice as provided hereunder to
94
the other Parties, change its address and other particulars
for notice purpose.
IN WITNESS WHEREOF, the representatives of the Parties to
this Contract being duly authorised have hereunto set their hands
and have executed these presents this 22 day of December 1994.
Signed for and on
behalf of the
President of India By NAJERB JR.
In the presence of
V. RAMANI
Signed for and on behalf
of Oil & Natural Gas
Corporation Limited By S. K. MANGLIK
In the presence of
R. N. DESAI
Signed for and on behalf
of Reliance Industries
Limited By AKHIL GUPTA
In the presence of
Ba La SAGRAMANIA
Signed for and on behalf
of Enron Oil & Gas India Ltd. By J. A. KOPECKY
In the presence of
E. J. VANDERMARK
95
<PAGE>
APPENDIX A
DESCRIPTION OF CONTRACT AREA
The area comprising approximately 430 sq. km offshore India identified as
Panna Block and the area comprising approximately 777 sq. km offshore India
identified as the Mukta Block described herein and shown under map attached as
Appendix B-1 and B- 2.
Longitude and Latitude measurements are as follows:
MUKTA (about 100 km Northwest of Bombay) See Appendix B-2.
LATITUDE LONGITUDE
A. 19 degrees 27'00"N 71 degrees 38'00"E
B. 19 degrees 27'00"N 71 degrees 54'00"E
C. 19 degrees 12'00"N 71 degrees 54'00"E
D. 19 degrees 12'00"N 71 degrees 38'00"E
PANNA (about 95 km Northwest of Bombay) See Appendix B-1.
LATITUDE LONGITUDE
A. 19(degree)28'00"N 71(degree)54'00"E
B. 19(degree)28'00"N 72(degree)05'00"E
C. 19(degree)19'30"N 72(degree)05'00"E
D. 19(degree)15'00"N 72(degree)00'00"E
E. 19(degree)15'00"N 71(degree)54'00"E
96
APPENDIX B-1
MAP OF CONTRACT AREA
PANNA BLOCK
WESTERN INDIA OFFSHORE
BOMBAY BASIN
97A
APPENDIX B-2
MAP OF CONTRACT AREA
MUKTA BLOCK
WESTERN INDIA OFFSHORE
BOMBAY BASIN
97B
<PAGE>
APPENDIX C
ACCOUNTING PROCEDURE
TO
PRODUCTION SHARING CONTRACT
BETWEEN
THE GOVERNMENT OF INDIA
AND
ONGC/RIL/EOGIL
98
TABLE OF CONTENTS
SECTIONS CONTENT
SECTION 1: GENERAL PROVISIONS
1.1 Purpose
1.2 Definitions
1.3 Inconsistency
1.4 Documentation and Statements to be Submitted by
the Contractor
1.5 Language and Units of Account
1.6 Currency Exchange Rates
1.7 Payments
1.8 Arms Length Transactions
1.9 Audit and Inspection Rights of the Government
1.10 Revision of Accounting Procedure
SECTION 2: CLASSIFICATION, DEFINITION AND ALLOCATION OF
COSTS AND EXPENDITURES
2.1 Segregation of Costs
2.2 Exploration Costs
2.3 Development Costs
2.4 Production Costs
2.5 Service Costs
2.6 General and Administrative Costs
SECTION 3: COSTS, EXPENSES, EXPENDITURES AND INCIDENTAL
INCOME OF THE CONTRACTOR
3.1 Costs Recoverable and Allowable Without Further
Approval of the Government
3.1.1 Surface Rights
3.1.2 Labor & Associated Costs
3.1.3 Transportation Costs
3.1.4 Charges for Services
(a) Third Party Contracts
(b) Affiliated Company Contracts
3.1.5 Communications
3.1.6 Office, Shore Bases and
Miscellaneous Facilities
3.1.7 Environmental Studies and Protection
3.1.8 Materials and Equipment
(a) General
(b) Warranty
(c) Value of Materials Charged to
the Account
3.1.9 Duties, Fees and Other Charges
3.1.10 Insurance and Losses
3.1.11 Legal Expenses
3.1.12 Training Costs
3.1.13 General and Administrative Costs
3.2 Costs Not Recoverable and Not Allowable under the
Contract
3.3 Other Costs Recoverable and Allowable
3.4 Incidental Income and Credits
3.5 Non-Duplication of Charges and Credits
99
SECTION 4: RECORDS AND INVENTORIES OF ASSETS
4.1 Records
4.2 Inventories
SECTION 5: PRODUCTION STATEMENT AND ROYALTY AND CESS
STATEMENT
SECTION 6: VALUE OF PRODUCTION AND PRICING STATEMENT
SECTION 7: STATEMENT OF COSTS, EXPENDITURES AND RECEIPTS
SECTION 8: COST RECOVERY STATEMENT
SECTION 9: PRODUCTION SHARING STATEMENT
SECTION 10: END OF YEAR STATEMENT
SECTION 11: BUDGET STATEMENT
100
ACCOUNTING PROCEDURE
SECTION 1
GENERAL PROVISIONS
1.1 PURPOSE
Generally, the purpose of this Accounting Procedure is to set out
principles and procedures of accounting which will enable the
Government of India to monitor effectively the Contractor's costs,
expenditures, production and income so that the Government's
entitlement to Profit Petroleum, royalty, cess, etc., as well as
Contractor's entitlement to Cost Petroleum and Profit Petroleum can
be accurately determined pursuant to the terms of the Contract.
More specifically, the purpose of the Accounting Procedure is to:
- classify costs and expenditures and to define which
costs and expenditures shall be allowable for cost
recovery, production sharing and participation
purposes;
- specify the manner in which the Contractor's accounts
shall be prepared and approved.
This Accounting Procedure is intended to apply to the provisions of
the Contract and is without prejudice to the computation of income
tax under applicable provisions of the Income Tax Act, 1961, as
amended.
1.2 DEFINITIONS
For purposes of this Accounting Procedure, the terms used herein
which are defined in the Contract shall have the same meaning when
used in this Accounting Procedure.
1.3 INCONSISTENCY
In the event of any inconsistency or conflict between the
provisions of this Accounting Procedure and the other provisions of
the Contract, the other provisions of the Contract shall prevail.
1.4 DOCUMENTATION AND STATEMENTS TO BE SUBMITTED BY THE
CONTRACTOR
1.4.1 Within thirty (30) days of the Effective Date of
the Contract, the Contractor shall submit to and
discuss with the Government a proposed outline of
charts of accounts, operating records and
reports, which outline shall reflect each of the
categories and sub-categories of costs and income
specified in Sections 2 and 3 and shall be in
accordance with generally accepted standards and
recognized accounting systems and consistent with
normal petroleum industry practice and procedures
101
for joint venture operations.
Within ninety (90) days of receiving the above
submission, the Government shall either provide
written notification of its approval of the
proposal or request, in writing, revisions to the
proposal.
Within one hundred and eighty (180) days from the
Effective Date of the Contract, the Contractor and
the Government shall agree on the outline of
charts of accounts, records and reports which
shall also describe the basis of the accounting
system and procedures to be developed and used
under this Contract. Following such agreement, the
Contractor shall expeditiously prepare and provide
the Government with formal copies of the
comprehensive charts of accounts, records and
reports and allow the Government to examine the
manuals and to review procedures which are, and
shall be, observed under the Contract.
1.4.2 Notwithstanding the generality of the foregoing,
the Contractor shall make regular Statements
relating to the Petroleum Operations as follows :
(i) Production Statement and Royalty and
Cess Statement (see Section 5 of this
Accounting Procedure)
(ii) Value of Production and Pricing
Statement (see Section 6 of this
Accounting Procedure)
(iii) Statement of Costs, Expenditures and
Receipts (see Section 7 of this
Accounting Procedure)
(iv) Cost Recovery Statement (see Section 8
of this Accounting Procedure)
(v) Production Sharing Statement (see
Section 9 of this Accounting Procedure)
(vi) End of Year Statement (see Section 10
of this Accounting Procedure)
(vii) Budget Statement (see Section 11 of
this Accounting Procedure)
1.4.3 All reports and statements shall be prepared in
accordance with the Contract and the laws of India
and, where there are no relevant provisions in
either of these, in accordance with generally
accepted practices in the international petroleum
102
industry.
1.4.4 Each of the entities constituting the Contractor
shall be responsible for maintaining its own
accounting records in order to comply with all
legal requirements and to support all returns or
any other accounting reports required by any
Government authority in relation to the Petroleum
Operations. However, for the purposes of giving
effect to this Accounting Procedure, the
Contractor shall appoint, and notify the
Government in writing thereof, one of the Parties
constituting Contractor who shall be responsible
for maintaining, at its business office in India,
on behalf of the Contractor, all the accounts of
the Petroleum Operations in accordance with the
provisions of the Accounting Procedure and the
Contract.
1.5 LANGUAGE AND UNITS OF ACCOUNT
All accounts, records, books, reports and statements shall be
maintained on an accrual basis and prepared in the English
language. The accounts shall be maintained in United States
Dollars, which shall be the controlling currency of account for
cost recovery, production sharing and participation purposes.
Metric units and Barrels shall be employed for measurements
required under the Contract. Where necessary for clarification, the
Contractor may also maintain accounts and records in other
languages, currencies and units. Following any new discovery of
Petroleum the Parties shall meet to establish specific principles
and procedures for identifying all costs, expenditures, receipts
and income with respect to the Contract Area.
1.6 CURRENCY EXCHANGE RATES
1.6.1 For translation purposes between United States
Dollars and Indian Rupees or any other currency,
the previous month's average of the daily means
of the buying and selling rates of exchange as
quoted by the State Bank of India (or any other
financial body as may be mutually agreed between
the Parties) shall be used for the month in which
the revenues, costs, expenditures, receipts or
income are recorded. However, in the case of any
single non-US Dollar transaction in excess of the
equivalent of one hundred thousand US Dollars
(US$100,000), the conversion into US Dollars
shall be performed on the basis of the average of
the applicable exchange rates for the day on
which the transaction occurred.
1.6.2 Any realized or unrealized gains or losses from
the exchange of currency in respect of Petroleum
Operations shall be credited or charged to the
accounts. A record of the exchange rates used in
converting Indian Rupees or any other currencies
103
into United States Dollars as specified in Section
1.6.1 shall be maintained by the Contractor and
shall be identified in the relevant statements
required to be submitted by the Contractor in
accordance with Section 1.4.2.
1.7 PAYMENTS
1.7.1 Subject to the foreign exchange laws and
regulations prevailing from time to time, all
payments between the Parties shall, unless
otherwise agreed, be in United States Dollars and
shall be made through a bank designated by each
receiving Party.
1.7.2 Unless otherwise specified, all sums due under the
Contract shall be paid within forty-five (45) days
from the date on which the obligation to pay was
incurred.
1.7.3 Unless otherwise specified, all sums due by one
Party to the other under the Contract during any
month shall, for each day such sums are overdue
during such month, bear interest compounded daily
at the applicable LIBOR plus one percentage (1%)
point.
1.8 ARMS LENGTH TRANSACTIONS
Unless otherwise specifically provided for in the Contract, all
transactions giving rise to revenues, costs or expenditures which
will be credited or charged to the accounts prepared, maintained or
submitted hereunder shall be conducted at arms length or on such a
basis as will assure that all such revenues, costs or expenditures
will be equal to or better than, as the case may be, would result
from a transaction conducted at arms length on a competitive basis
with third parties. For the purposes of clarification, this means
revenues would be equal to or higher and costs would be equal to or
lower.
1.9 AUDIT AND INSPECTION RIGHTS OF THE GOVERNMENT
1.9.1 Without prejudice to statutory rights, the
Government, upon at least ninety (90) days
advance written notice to the Contractor, shall
have the right to inspect and audit, during
normal business hours , all records and documents
supporting costs, expenditures, expenses,
receipts and income, such as Contractor's
accounts, books, records, invoices, cash
vouchers, debit notes, price lists or similar
documentation with respect to the Petroleum
Operations conducted hereunder in each Financial
Year, within two (2) years (or such longer period
104
as may be required in exceptional circumstances)
from the end of such Financial Year.
1.9.2 The Government may undertake the conduct of the
audit either through its own representatives or
through a qualified firm of recognized
international chartered accountants, registered in
India, appointed for the purpose by the
Government.
1.9.3 In conducting the audit, the Government or its
auditors shall be entitled to examine and verify,
at reasonable times, all charges and credits
relating to Contractor's activities under the
Contract and all books of account, accounting
entries, material records and inventories,
vouchers, payrolls, invoices and any other
documents, correspondence and records considered
necessary by the Government to audit and verify
the charges and credits. The auditors shall also
have the right, in connection with such audit, to
visit and inspect, at reasonable times, all
sites, plants, facilities, warehouses and offices
of the Contractor directly or indirectly serving
the Petroleum Operations, and to physically
examine other property, facilities and stocks
used in Petroleum Operations, wherever located
and to question personnel associated with those
operations. Where the Government requires
verification of charges made by an Affiliate, the
Government shall have the right to obtain an
audit certificate from an internationally
recognized firm of public accountants acceptable
to both the Government and the Contractor, which
may be the Contractor's statutory auditor. Any
and all such costs shall be for the Government's
account.
1.9.4 Any audit exceptions shall be made by the
Government in writing and notified to the
Contractor within one hundred and twenty (120)
days following completion of the audit in
question.
1.9.5 The Contractor shall answer any notice of
exception under Section 1.9.4 within one hundred
and twenty (120) days of the receipt of such
notice. Where the Contractor has, after the one
hundred and twenty (120) days, failed to answer a
notice of exception, the exception shall prevail.
1.9.6 All agreed adjustments resulting from an audit and
all adjustments required by prevailing exceptions
shall be promptly made in the Contractor's
accounts and any consequential
105
adjustments to the Government's entitlement to
Petroleum shall be made as promptly as
practicable.
1.9.7 If the Contractor and the Government are unable
to reach final agreement on proposed audit
adjustments, either Party may refer any dispute
thereon to a sole expert as provided for in the
Contract. So long as any issues are outstanding
with respect to an audit, the Contractor shall
maintain the relevant documents and permit
inspection thereof until the issue is resolved.
1.10 REVISION OF THE ACCOUNTING PROCEDURE
1.10.1 By mutual agreement between the Government and the
Contractor, this Accounting Procedure may be
revised from time to time, in writing, signed by
the Parties, stating the date upon which the
amendments shall become effective.
106
SECTION 2
CLASSIFICATION, DEFINITION AND ALLOCATION
OF COSTS AND EXPENDITURES
2.1 SEGREGATION OF COSTS
Costs shall be segregated in accordance with the purposes for which
such expenditures are made. All costs and expenditures allowable
under Section 3, relating to Petroleum Operations, shall be
classified, defined and allocated as set out below in this Section.
Expenditure records shall be maintained in such a way as to enable
proper allocation.
2.2 EXPLORATION COSTS
Exploration Costs are all direct and allocated indirect
expenditures incurred in the search for Petroleum in an area which
is, or was at the time when such costs were incurred, part of the
Contract Area, including expenditures incurred in respect of:
2.2.1 Aerial, geophysical, geochemical,
palaeontological, geological, topographical and
seismic surveys, analyses and studies and their
interpretation.
2.2.2 Core hole drilling and water well drilling.
2.2.3 Labor, materials, supplies and services used in
drilling Wells with the object of finding
Petroleum or in drilling Appraisal Wells provided
that if such Wells are completed as producing
Wells, the costs of completion thereof shall be
classified as Development Costs.
2.2.4 Facilities used solely in support of the purposes
described in Sections 2.2.1, 2.2.2 and 2.2.3
above, including access roads, all separately
identified.
2.2.5 Any Service Costs and General and Administrative
Costs directly incurred on exploration activities
and identifiable as such and a portion of the
remaining Service Costs and General and
Administrative Costs allocated to Exploration
Operations determined by the proportionate share
of total Contract Costs (excluding General and
Administrative Costs and Service Costs) repre-
sented by all other Exploration Costs.
2.2.6 Geological and geophysical information purchased
or acquired in connection with Exploration
Operations.
107
2.2.7 Any other expenditure incurred in the search for
Petroleum not covered under Sections 2.3 or 2.4.
2.3 DEVELOPMENT COSTS
Development Costs are all direct and allocated indirect
expenditures incurred with respect to the development of the
Contract Area including expenditures incurred on account of:
2.3.1 Drilling Development Wells, whether these Wells
are dry or producing and drilling Wells for the
injection of water or Gas to enhance recovery of
Petroleum and Recompletion or working over of
existing or service wells.
2.3.2 Purchase, installation or construction of
production, transport and storage facilities for
production of Petroleum from a Field, such as
pipelines, flow lines, production and treatment
units, wellhead equipment, subsurface equipment,
enhanced recovery systems, offshore and onshore
platforms, export terminals and piers, harbours
and related facilities and access roads for
production activities.
2.3.3 Engineering and design studies for facilities
referred to in Section 2.3.2.
2.3.4 Any Service Costs, joint Development Plans and
General and Administrative Costs directly
incurred in Development Operations and
identifiable as such and a portion of the
remaining Service Costs and General and
Administrative Costs allocated to development
activities, determined by the proportionate share
of total Contract Costs (excluding General and
Administrative Costs and Service Costs) repre-
sented by all other Development Costs.
2.4 PRODUCTION COSTS
2.4.1 Production Costs are expenditures incurred on
Production Operations in respect of the Contract
Area after the start of production from the Field
(which are other than Exploration and Development
Costs). The balance of General and Adminis-
trative Costs and Service Costs not allocated to
Exploration Costs or Development Costs shall be
allocated to Production Costs.
2.4.2 Production Costs shall include costs for
completion of Exploration Wells by way of
installation of casing or equipment or otherwise
or for the purpose of bringing a Well into use as
a producing Well or as a Well for the injection
108
of water or Gas to enhance recovery of Petroleum
and Recompletion or working over of existing or
service wells.
2.5 SERVICE COSTS
Service Costs are direct and indirect expenditures incurred in
support of Petroleum Operations in the Contract Area, including
expenditures on insurance, environmental protection, warehouses,
piers, marine vessels, vehicles, motorized rolling equipment,
aircraft, fire and security stations, workshops, water and sewerage
plants, power plants, housing, community and recreational
facilities and furniture and tools and equipment used in these
activities. Service Costs in any Year shall include the costs
incurred in such Year to purchase and/or construct the facilities
as well as the annual costs of maintaining and operating the same,
each to be identified separately. All Service Costs shall be
regularly allocated as specified in Sections 2.2.5, 2.3.4 and 2.4
to Exploration Costs, Development Costs and Production Costs and
shall be separately shown under each of these categories. Where
Service Costs are made in respect of shared facilities, the basis
of allocation of costs to Petroleum Operations hereunder shall be
on the basis of gross expenditures.
2.6 GENERAL AND ADMINISTRATIVE COSTS
General and Administrative Costs are expenditures incurred on
general administration and management primarily and principally
related to Petroleum Operations in or in connection with the
Contract Area, and shall include:
2.6.1 main office, field office and general
administrative expenditures in India, including
supervisory, accounting and employee relations
services;
2.6.2 an annual overhead charge for services rendered
by the parent company or an Affiliate of the
Operator outside India to support and manage
Petroleum Operations under the Contract, and for
staff advice and assistance including financial,
legal, accounting and employee relations
services, but excluding any remuneration for
services charged separately under this Accounting
Procedure calculated on the basis of one percent
(1%) of expenditures.
2.6.3 The expenditures used to calculate the monthly
indirect charge shall not include the indirect
charge (calculated either as a percentage of
expenditures or as a minimum monthly charge),
rentals on surface rights acquired and maintained
for the joint account, guarantee deposits,
109
concession acquisition costs, bonuses paid in
accordance with the Contract, royalties, value
added taxes and taxes paid under the Contract,
settlement of claims, proceeds from the sale of
assets (including division in kind) amounting to
more than US$10,000 per transaction, and similar
items mutually agreed upon by the parties.
Credits arising from any government subsidy
payment and disposition of joint account property
shall not be deducted from total expenditures in
determining such charge.
2.6.4 The indirect charges provided for in this Section
may be amended periodically by mutual agreement
between the Parties if, in practice, these charges
are found to be insufficient or
excessive.
110
SECTION 3
COSTS, EXPENSES, EXPENDITURES AND INCIDENTAL
INCOME OF THE CONTRACTOR
3.1 COSTS RECOVERABLE AND ALLOWABLE WITHOUT FURTHER APPROVAL OF
THE GOVERNMENT.
Costs incurred by the Contractor on Petroleum Operations pursuant
to the Contract as classified under the headings referred to in
Section 2 shall be allowable for the purposes of the Contract
except to the extent provided in Section 3.2 or elsewhere in this
Accounting Procedure, and subject to audit as provided for herein.
3.1.1 Surface Rights
All direct costs necessary for the acquisition,
renewal or relinquishment of surface rights
acquired and maintained in force for the purposes
of the Contract except as provided in Section
3.1.9. Why expected? How applicable?
3.1.2 Labor and Associated Costs
(a) Costs of all Contractor's locally recruited
employees who are directly engaged in the
conduct of Petroleum Operations under the
Contract in India. Such costs shall include
the costs of employee benefits and
Government benefits for employees and
levies imposed on the Contractor as an
employer, transportation and relocation
costs within India of the employee and such
members of the employee's family (limited
to spouse and dependent children) as
required by law or customary practice in
India. If such employees are engaged in
other activities in India, in addition to
Petroleum Operations, the cost of such
employees shall be apportioned on a time
sheet basis according to sound and
acceptable accounting principles.
(b) Assigned Personnel
Costs of salaries and wages, including
bonuses, of the Contractor's employees
directly and necessarily engaged in the
conduct of the Petroleum Operations under
the Contract, whether temporarily or
permanently assigned, irrespective of the
location of such employees, it being
understood that in the case of those
personnel only a portion of whose time is
wholly dedicated to Petroleum Operations
under the Contract, only that pro rata
portion of applicable salaries, wages
111
and other costs, as specified in Sections
3.1.2(c), (d), (e)and (f) shall be charged
and the basis of such pro rata allocation
shall be specified.
(c) Expenses or contributions made pursuant to
assessments or obligations imposed under
the laws of India which are applicable to
the Contractor's cost of salaries and
wages.
(d) The Contractor's cost of established plans
for employees' group life insurance,
hospitalization, pension, retirement and
other benefit plans of a like nature
customarily granted to the Contractor's
employees provided, however, that such
costs are in accordance with generally
accepted standards in the international
petroleum industry, applicable to salaries
and wages chargeable to Petroleum
Operations under Section 3.1.2(b) above.
(e) Personal Income taxes where and when they
are paid by the Contractor to the
Government of India for the employee, in
accordance with the Contractor's standard
personnel policies.
(f) Reasonable transportation and travel
expenses of employees of the Contractor,
including those made for travel and
relocation of the expatriate employees,
including their dependent family and
personal effects, assigned to India whose
salaries and wages are chargeable to
Petroleum Operations under Section
3.1.2(b). Actual transportation expenses of
personnel transferred to Petroleum
Operations from their country of origin
and/or relocation to their country of
origin shall be charged to the Petroleum
Operations. Where such transfer or
relocation is to or from a country other
than the country of origin there shall be
no reimbursement.
Transportation cost as used in this Section shall
mean the cost of freight and passenger service and
any accountable incidental expenditures related to
transfer travel and authorized under Contractor's
standard personnel policies. Contractor shall
ensure that all expenditures related to
transportation costs are equitably allocated to
the activities which have benefited from the
personnel concerned.
112
3.1.3 Transportation Costs
The reasonable cost of transportation of
equipment, materials and supplies within India and
from outside India to India necessary for the
conduct of Petroleum Operations under the
Contract, including, but not limited to, directly
related costs such as unloading charges, dock fees
and inland and ocean freight charges.
3.1.4 Charges for Services
(a) Third Party Contracts
The actual costs of contract services,
services of professional consultants,
utilities and other services necessary for
the conduct of Petroleum Operations under
the Contract performed by third parties
other than an Affiliate of the Contractor,
provided that the transactions resulting in
such costs are undertaken pursuant to
Section 1.8 of this Accounting Procedure.
(b) Affiliated Company Contracts
(i) Professional and Administrative
Services and Expenses
Cost of professional and
administrative services provided
by any Affiliate for the direct
benefit of Petroleum Operations,
including, but not limited to,
services provided by the
production, exploration, legal,
financial, insurance, accounting
and computer services divisions
other than those covered by
Section 3.1.4(b)(ii) which
Contractor may use in lieu of
having its own employees.
Charges shall be equal to the
actual cost of providing their
services, shall not include any
element of profit and shall not
be any higher than the most
favorable prices charged by the
Affiliate to third parties for
comparable services under
similar terms and conditions
elsewhere and will be fair and
reasonable in the light of
prevailing international
petroleum industry practice and
experience.
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(ii) Scientific or Technical
Personnel
Cost of scientific or technical
personnel services provided by
any Affiliate of Contractor for
the direct benefit of Petroleum
Operations, which cost shall be
charged on a cost of service
basis. Charges therefor shall
not exceed charges for
comparable services currently
provided by outside technical
service organizations of
comparable qualifications.
Unless the work to be done by
such personnel is covered by an
approved Work Programme and
Budget, Operator shall not
authorize work by such personnel
without approval of the
Management Committee.
(c) Equipment, facilities and property owned
and furnished by the Contractor's
Affiliates, at rates commensurate with the
cost of ownership and operation provided,
however, that such rates shall not exceed
those currently prevailing for the supply
of like equipment, facilities and property
on comparable terms in the area where the
Petroleum Operations are being conducted.
The equipment and facilities referred to
herein shall exclude major investment items
such as (but not limited to) drilling rigs,
producing platforms, oil treating
facilities, oil and gas loading and
transportation systems, storage and
terminal facilities and other major
facilities, rates for which shall be
subject to separate agreement with the
Government.
3.1.5 Communications
Cost of acquiring, leasing, installing, operating,
repairing and maintaining communication systems
including satellite, radio and microwave
facilities between the Contract Area and the
Contractor's base facility, offices, helicopter
bases, port and railway yards.
3.1.6 Office, Shore Bases and Miscellaneous Facilities
Net cost to Contractor of establishing,
maintaining and operating any office, sub-office,
shore base facility, warehouse, housing or other
facility directly serving the Petroleum
Operations. If any such facility services contract
114
areas other than the Contract Area, or any
business other than Petroleum Operations, the net
costs thereof shall be allocated on an equitable
and consistent basis.
3.1.7 Environmental Studies and Protection
Costs incurred in conducting the environmental
impact studies for the Contract Area, and in
taking environmental protection measures pursuant
to the terms of the Contract.
3.1.8 Materials and Equipment
(a) General
So far as is practicable and consistent
with efficient and economical operation,
only such material shall be purchased or
furnished by the Contractor for use in the
Petroleum Operations as may be required for
use in the reasonably foreseeable future
and the accumulation of surplus stocks
shall be avoided to the extent possible.
Material and equipment held in inventory
shall only be charged to the accounts when
such material is removed from inventory and
used in Petroleum Operations. Contractor
shall be allowed to recover interest at the
LIBOR rate plus one percent (1%) for
reasonable inventories it carries. Costs
shall be charged to the accounting records
and books based on the average cost method.
(b) Warranty
In the case of defective material or
equipment, any adjustment received by the
Contractor from the suppliers or
manufacturers or their agents in respect of
any warranty on material or equipment shall
be credited to the accounts under the
Contract.
(c) Value of Materials Charged to the Accounts
Under the Contract.
(i) Except as otherwise provided in
subparagraph (b), materials
purchased by the Contractor and
used in the Petroleum Operations
shall be valued to include
invoice price less trade and
cash discounts, if any, purchase
and procurement fees plus
freight and forwarding charges
between point of
115
supply and point of shipment,
freight to port of destination,
insurance, taxes, customs
duties, consular fees, other
items chargeable against
imported material and, where
applicable , handling and
transportation costs from point
of importation to or from
warehouse or operating site, and
these costs shall not exceed
those currently prevailing in
normal arms length transactions
on the open market.
(ii) Material purchased from or sold to
Affiliates or transferred to or
from activities of the Contractor
other than Petroleum Operations
under the Contract:
(aa) new material (hereinafter
referred to as condition A)
shall be valued at the current
international price which shall
not exceed the price prevailing
in normal arms length transac-
tions on the open market;
(bb) used material which is in sound
and serviceable condition and is
suitable for reuse without
reconditioning (hereinafter
referred to as condition B)
shall be priced at not more than
seventy-five percent (75%) of
the current price of the above
mentioned new materials;
(cc) used material which cannot be
classified as condition B, but
which, after reconditioning,
will be further serviceable for
original function as good
second-hand condition B material
or is serviceable for original
function, but substantially not
suitable for reconditioning
(hereinafter referred to as
condition C) shall be priced at
not more than fifty per cent
(50%) of the current price of
the new material referred to
above as condition A.
The cost of reconditioning shall be charged to the
reconditioned material, provided that the
condition C material value plus the cost of
116
reconditioning does not exceed the value of
condition B material.
Material which cannot be classified as condition B
or condition C shall be priced at a value
commensurate with its use.
Material involving erection expenditure shall be
charged at the applicable condition percentage
(referred to above) of the current knocked-down
price of new material referred to above as
condition A.
When the use of material is temporary and its
service to the Petroleum Operations does not
justify the reduction in price in relation to
materials referred to above as conditions B and C,
such material shall be priced on a basis that will
result in a net charge to the accounts under the
Contract consistent with the value of the service
rendered.
3.1.9 Duties, Fees and Other Charges
Any duties, levies, fees, charges and any other
assessments levied by any governmental or taxing
authority in connection with the Contractor's
activities under the Contract and paid directly by
the Contractor except corporate income tax payable
by the constituents of the Contractor. If Operator
or its Affiliate is subject to income or
withholding tax as a result of service performed
at cost for Petroleum Operations under the
Agreement, its charges for such services may be
increased by the amount of such taxes incurred
("grossed up"), provided such charges have not
been otherwise recovered or a tax credit received.
3.1.10 Insurance and Losses
Insurance premia and costs incurred for insurance
required by law or pursuant to Article 24 of the
Contract, provided that such insurance is
customary, affords prudent protection against risk
and is at a premium no higher than that charged on
a competitive basis by insurance companies which
are not Affiliates. Actual costs and losses
incurred shall be allowable to the extent not made
good by insurance. Such costs may include, but are
not limited to, repair and replacement of property
resulting from damages or losses incurred by fire,
flood, storm, theft, accident or such other cause.
117
3.1.11 Legal Expenses
All reasonable costs and expenses resulting from
the handling, investigating, asserting, defending,
or settling of any claim or legal action necessary
or expedient for the procuring, perfecting,
retention and protection of the Contract Area and
in defending or prosecuting lawsuits involving the
Contract Area or any third party claim arising out
of Petroleum Operations under the Contract, or
sums paid in respect of legal services necessary
for the protection of the joint interest of
Government and the Contractor, shall be allowable.
Such expenditures shall include attorney's fees,
court costs, costs of investigation and
procurement of evidence and amounts paid in
settlement or satisfaction of any such litigation
and claims provided such costs are not covered
elsewhere in the Accounting Procedure. Where legal
services are rendered in such matters by salaried
or regularly retained lawyers of the Contractor or
an Affiliate, such compensation shall be included
instead under Sections 3.1.2 or 3.1.4(b)(i) above
as applicable.
3.1.12 Training Costs
All costs and expenses incurred by the Contractor
in training as is required under Article 22 of the
Contract.
3.1.13 General and Administrative Costs
The costs described in Section 2.6.1 and the
charge described in Section 2.6.2 of this
Accounting Procedure.
3.2 COSTS NOT RECOVERABLE AND NOT ALLOWABLE UNDER THE CONTRACT
The following costs and expenses shall not be recoverable or
allowable (whether directly as such or indirectly as part of any
other charges or expenses) for cost recovery and production sharing
purposes under the Contract:
(i) costs and charges incurred before the Effective
Date including costs in respect of preparation,
signature or ratification of this Contract except
as otherwise provided in Article 13.1;
(ii) expenditures in respect of any financial
transaction to negotiate, float or otherwise
obtain or secure funds for Petroleum Operations
including, but not limited to, interest,
commission, brokerage and fees related to such
118
transactions, and exchange losses on loans or
other financing;
(iii) costs of marketing or transportation of Petroleum
beyond the Delivery Point;
(iv) expenditures incurred in obtaining, furnishing and
maintaining the guarantees required under the
Contract and any other amounts spent on
indemnities with regard to non-fulfillment of
contractual obligations;
(v) attorney's fees and other costs and charges in
connection with arbitration proceedings and sole
expert determination pursuant to the Contract;
(vi) fines and penalties imposed by courts of law of
the Republic of India;
(vii) donations and contributions;
(viii) expenditures for the creation of any partnership
or joint venture arrangement;
(ix) amounts paid with respect to non-fulfillment of
contractual obligations;
(x) costs incurred as a result of failure to insure
where insurance is required pursuant to the
Contract;
(xi) costs and expenditures incurred as a result of
wilful misconduct or gross negligence of the
Contractor's supervisory personnel;
(xii) payments pursuant to Article 16 of the Contract.
3.3 OTHER COSTS RECOVERABLE AND ALLOWABLE.
Any other costs and expenditures not included in Section 3.1 or 3.2
of this Accounting Procedure but which have been incurred by the
Contractor for the necessary and proper conduct of Petroleum
Operations pursuant to an approved Work Programme and Budget.
3.4 INCIDENTAL INCOME AND CREDITS
All incidental income and proceeds received from Petroleum
Operations under the Contract, including but not limited to the
items listed below, shall be credited to the accounts under the
Contract and shall be taken into account for cost recovery,
production sharing and participation purposes in the manner
described in Articles 13 and 14 of the Contract:
(i) The proceeds of any insurance or claim or
119
judicial awards in connection with Petroleum
Operations under the Contract or any assets
charged to the accounts under the Contract where
such operations or assets have been insured and
the premia charged to the accounts under the
Contract;
(ii) Revenue received from third parties for the use
of property or assets, the cost of which has been
charged to the accounts under the Contract;
(iii) Any adjustment received by the Contractor from the
suppliers/manufacturers or their agents in
connection with defective material, the cost of
which was previously charged by the Contractor to
the accounts under the Contract;
(iv) Rentals, refunds or other credits received by the
Contractor which apply to any charge which has
been made to the accounts under the Contract;
(v) Prices originally charged to the accounts under
the Contract for materials subsequently exported
from the Republic of India without being used in
Petroleum Operations under the Contract;
(vi) Proceeds from the sale or exchange by the
Contractor of plant or facilities from a Field,
the acquisition costs of which have been charged
to the accounts under the Contract for the
relevant Field;
(vii) Legal costs charged to the accounts under Section
3.1.11 of this Accounting Procedure and
subsequently recovered by the Contractor.
3.5 NON-DUPLICATION OF CHARGES AND CREDITS
Notwithstanding any provision to the contrary in this Accounting
Procedure, it is the intention that there shall be no duplication
of charges or credits to the accounts under the Contract.
120
SECTION 4
RECORDS AND INVENTORIES OF ASSETS
4.1 RECORDS
4.1.1 The Contractor shall keep and maintain detailed
records of property and assets in use for or in
connection with Petroleum Operations under the
Contract in accordance with normal practices in
exploration and production activities of the
international petroleum industry. Such records
shall include information on quantities, location
and condition of such property and assets, and
whether such property or assets are leased or
owned.
4.1.2 The Contractor shall furnish annually particulars
to the Government, by notice in writing as
provided in the Contract, of all major assets
acquired by the Contractor to be used for or in
connection with Petroleum Operations.
4.2 INVENTORIES
4.2.1 The Contractor shall:
(a) not less than once every twelve (12)
Calendar Months with respect to movable
assets take an inventory of the
controllable assets used for or in
connection with Petroleum Operations in
terms of the Contract and address and
deliver such inventory to the Government
with a statement of the principles upon
which valuation of the assets mentioned in
such inventory has been based. Controllable
assets means those assets the Operator
shall submit to detailed record keeping.
(b) not less than once every three (3) years
with respect to immovable assets, take an
inventory of the assets used for or in
connection with Petroleum Operations in
terms of the Contract and address and
deliver such inventory to the Government
together with a written statement of the
principles upon which valuation of the
assets mentioned in such inventory has been
based. Immovable assets means those assets
which are placed in service and have an
original cost in excess of Fifty Thousand
United States Dollars (US$50,000).
4.2.2 The Contractor shall give the Government at least
thirty (30) days notice in writing in the manner
provided for in the Contract of its intention to
take the inventory referred to in Section 4.2.1
121
and the Government shall have the right to be
represented when such inventory is taken.
4.2.3 When an assignment of rights under the Contract
takes place, a special inventory shall be taken by
the Contractor at the request of the assignee
provided that the cost of such inventory is borne
by the assignee and paid to the Contractor.
4.2.4 In order to give effect to Article 27 of the
Contract, the Contractor shall provide the
Government with a comprehensive list of all
relevant assets when requested by the Government
to do so.
122
SECTION 5
PRODUCTION STATEMENT AND ROYALTY AND CESS STATEMENT
5.1 From the date of first production, after the Effective Date, of
Petroleum from the Contract Area, the Contractor shall submit a
Production Statement for each Calendar Month to Government showing
the following information separately for each producing field and
in aggregate for the Contract Area:
5.1.1 The quantity of Crude Oil produced and saved.
5.1.2 The quality and characteristics of such Crude Oil
produced and saved.
5.1.3 The quantity of Associated Natural Gas and Non
Associated Natural Gas produced and saved.
5.1.4 The quality, characteristics and composition of
such Natural Gas produced and saved.
5.1.5 The quantities of Crude Oil and Natural Gas used
for the purposes of carrying on drilling and
Production Operations and pumping to field
storage, as well as quantities reinjected.
5.1.6 The quantities of Crude Oil and Natural Gas
unavoidably lost.
5.1.7 The quantities of Natural Gas flared and vented.
5.1.8 The size of Petroleum stocks held on the first
day of the Calendar Month in question.
5.1.9 The size of Petroleum stocks held on the last day
of the Calendar Month in question.
5.1.10 The quantities of Natural Gas reinjected into the
Petroleum Reservoir.
5.1.11 The number of days in the Calendar Month during
which Petroleum was produced from each Field.
5.1.12 The Gas/Oil ratio for each Field for the relevant
Calendar Month.
5.1.13 The water/Oil ratio for each Field for the
relevant Calendar Month, if available.
5.2 All quantities shown in this Statement shall be expressed in
both volumetric terms (barrels of oil and cubic metres of
gas) and in weight (metric tonnes).
5.3 The Government may direct in writing that the Contractor
include other particulars relating to the production of
Petroleum in its Production Statement, and the Contractor
123
shall to the extent possible comply with such direction.
5.4 The Production Statement for each Calendar Month shall be submitted
to Government no later than ten (10) days after the end of such
Calendar Month for Oil and the immediately succeeding Calendar
Month for Gas.
5.5 The Contractor shall, for the purposes of Article 15, submit a
statement to Government providing the calculation of the amount of
royalty and cess, separately, paid with respect to each Calendar
Month for each producing Field and in aggregate for the Contract
Area. The statement shall show the following information:
5.5.1 The quantity of Crude Oil and Condensate produced
and saved.
5.5.2 The quantity of ANG and NANG produced and saved.
5.5.3 The amount of royalty and cess, separately, paid
on Crude Oil and Condensate produced, saved and
sold and the particulars of the calculation
thereof.
5.5.4 The amount of royalty paid on ANG and NANG and
the particulars of the calculation thereof.
5.6 The Royalty and Cess Statement for each Calendar Month shall be
submitted to Government no later than twenty-one (21) days after
the end of such Calendar Month for Oil and the most recently
available Calendar Month for Gas.
124
SECTION 6
VALUE OF PRODUCTION AND PRICING STATEMENT
6.1 The Contractor shall prepare a Statement providing
calculations of the value of Crude Oil produced and saved
during each Calendar Month. This Statement shall contain
the following information:
6.1.1 The quantities, prices and receipts realized by
the Contractor as a result of sales of Crude Oil
to third parties (with any sales to Government
being separately identified) made during the
Calendar Month in question.
6.1.2 The quantities, prices and receipts realized
therefor by the Contractor as a result of sales of
Crude Oil made during the Calendar Month in
question, other than to third parties.
6.1.3 The quantities of Crude Oil appropriated by the
Contractor to refining or other processing without
otherwise being disposed of in the form of Crude
Oil.
6.1.4 The value of stocks of Crude Oil on the first day
of the Calendar Month in question.
6.1.5 The value of stocks of Crude Oil on the last day
of the Calendar Month in question.
6.1.6 The percentage volume of total sales of Crude Oil
made by the Contractor during the Calendar Month
that are Arms Length Sales to third parties.
6.1.7 Information available to the Contractor, in so
far as required for the purposes of Article 19 of
the Contract, concerning the prices of
competitive crude oils produced by the main
petroleum producing and exporting countries
including contract prices, discounts and premia,
and prices obtained on the spot markets.
6.2 The Contractor shall prepare a statement providing calculations of
the value of ANG and NANG produced and sold during each Calendar
Month for the most recently available Calendar Month. This
Statement shall contain all information of the type specified in
Section 6.1 for Crude Oil as is applicable to Gas and such other
relevant information as may be required by the Government.
6.3 The Statements required pursuant to Sections 6.1 and 6.2
shall include a detailed breakdown of the calculation of the
prices of Crude Oil, Associated Natural Gas and Non
Associated Natural Gas.
125
6.4 The Value of Production and Pricing Statement for each Calendar
Month shall be submitted to Government not later than twenty-one
(21) days after the end of such Calendar Month for Oil and the most
recently available Calendar Month for Gas.
126
SECTION 7
STATEMENT OF COSTS, EXPENDITURES AND RECEIPTS
7.1 The Contractor shall prepare with respect to each Calendar Quarter
a Statement of Costs, Expenditures and Receipts under the Contract.
The statement shall distinguish between Exploration costs,
Development Costs and Production Costs and shall separately
identify all significant items of costs and expenditure as itemized
in Section 3 of this Accounting Procedure within these categories.
The statement of receipts shall distinguish between income from the
sale of Petroleum and incidental income of the sort itemized in
Section 3.4 of this Accounting Procedure. If the Government is not
satisfied with the categories, it shall be entitled to request a
more detailed breakdown. The Statement shall show the following:
7.1.1 Actual costs, expenditures and receipts for the
Calendar Quarter in question.
7.1.2 Cumulative costs, expenditures and receipts for
the Year in question.
7.1.3 Latest forecast of cumulative costs, expenditures
and receipts at the Year end.
7.1.4 Variations between budget forecast and latest
forecast and explanations thereof.
7.2 The Statement of Costs, Expenditure and Receipts of each Calendar
Quarter shall be submitted to Government not later than sixty (60)
days after the end of such Calendar Quarter.
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SECTION 8
COST RECOVERY STATEMENT
8.1 The Contractor shall prepare with respect to each Calendar
Quarter a Cost Recovery Statement containing the following
information:
8.1.1 Unrecovered Contract Costs carried forward from
the previous Calendar Quarter, if any.
8.1.2 Contract costs for the Calendar Quarter in
question.
8.1.3 Total Contract Costs for the Calendar Quarter in
question (Section 8.1.1 plus Section 8.1.2).
8.1.4 Quantity and value of Cost Petroleum taken and
disposed of by the Contractor for the Calendar
Quarter in question.
8.1.5 Contract Costs recovered during the Calendar
Quarter in question.
8.1.6 Total cumulative amount of Contract Costs
recovered up to the end of the Calendar Quarter
in question.
8.1.7 Amount of Contract Costs to be carried forward
into the next Calendar Quarter.
8.2 Where necessary and possible, the information to be provided under
Section 8.1 shall be identified separately Field by Field and also
separately for Crude Oil, Associated Natural Gas and Non Associated
Natural Gas.
8.3 The cost recovery information required pursuant to
Subsection 8.1 above shall be presented in sufficient detail
so as to enable Government to identify how the cost of
assets are being recovered.
8.4 The Cost Recovery Statement for each Calendar Quarter shall be
submitted to Government not later than sixty (60) days after the
end of such Calendar Quarter.
128
SECTION 9
PRODUCTION SHARING STATEMENT
9.1 The Contractor shall prepare with respect to each Calendar
Quarter a Production Sharing Statement containing the following
information:
9.1.1 The calculation of the applicable net cash flows
as defined in Appendix D for the Calendar Quarter
in question.
9.1.2 The Investment Multiple applicable in the
Calendar Quarter in question.
9.1.3 Based on Section 9.1.2 and Article 14, the
appropriate percentages of Profit Petroleum, if
any, for the Government and Contractor in the
Calendar Quarter in question.
9.1.4 The total amount of Profit Petroleum, if any, to
be shared between the Government and Contractor in
the Calendar Quarter in question.
9.1.5 Based on Sections 9.1.3 and 9.1.4, the amount of
Profit Petroleum due to the Government and
Contractor as well as to each constituent of the
Contractor in the Calendar Quarter in question.
9.1.6 The actual amounts of Petroleum taken by the
Government and Contractor as well as by each
constituent of the Contractor during the Calendar
Quarter in question to satisfy their entitlement
pursuant to Section 9.1.5.
9.1.7 Adjustments to be made, if any, in future
Calendar Quarters in the respective amounts of
Profit Petroleum due to the Government and
Contractor as well as to each constituent of the
Contractor on account of any differences between
the amounts specified in Sections 9.1.5 and
9.1.6, as well as any cumulative adjustments
outstanding from previous Calendar Quarters.
9.2 Where necessary and if possible, the information to be provided
under Section 9.1 shall be identified separately for each Field and
also separately for Crude Oil as distinct from Natural Gas.
9.3 The Production Sharing Statement shall be submitted to
Government not later than sixty (60) days after the end of
such Calendar Quarter.
129
SECTION 10
END OF FINANCIAL YEAR STATEMENT
10.1 The Contractor shall prepare a definitive End of Year Statement.
The statement shall contain aggregated information in the same
format as required in the Production Statement and Royalty and Cess
Statement, Value of Production and Pricing Statement, Statement of
Costs, Expenditure & Receipts, Cost Recovery Statement and
Production Sharing Statement, but shall be based on actual
quantities of Petroleum produced, income received and costs and
expenditures incurred. Based upon this Statement, any adjustments
that are necessary shall be made to the transactions concerned
under the Contract.
10.2 The End of Year Statement for each year shall be submitted to
Government within ninety (90) days of the end of such Year.
130
SECTION 11
BUDGET STATEMENT
11.1 The Contractor shall prepare a Budget Statement for each
Year. This statement shall distinguish between budgeted
Exploration Costs, Development Costs and Production Costs
and shall show the following:
11.1.1 Forecast costs, expenditures and receipts for the
Year in question.
11.1.2 A schedule showing the most important individual
items of total costs, expenditures and receipts
for the Year.
11.2 The Budget Statement shall be submitted to Government with respect
to each Year not less than ninety (90) days before the start of the
Year provided that in the case of the Year in which the Effective
Date falls, the Budget Statement shall be submitted within ninety
(90) days of the Effective Date.
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<PAGE>
APPENDIX D
CALCULATION OF THE
INVESTMENT MULTIPLE FOR PRODUCTION SHARING PURPOSES
1. In accordance with the provisions of Article 14, the share
of the Government and the Contractor respectively of Profit
Petroleum from the Contract Area in any Financial Year shall
be determined by the Investment Multiple earned by the
Companies from the Contract Area at the end of the preceding
Financial Year. These measures of profitability shall be
calculated on the basis of the appropriate net cash flows as
specified in this Appendix D.
INVESTMENT MULTIPLE
2. The "Net Cash Income" of the Companies from the Contract
Area in any particular Financial Year is the aggregate value
for the year of the following:
(i) Cost Petroleum entitlement of the Companies as
provided in Article 13;
PLUS
(ii) Profit Petroleum entitlement of the Companies as
provided in Article 14;
PLUS
(iii) incidental income of the Companies of the type
specified in Section 3.4 of the Accounting
Procedure arising from Petroleum Operations and
apportioned to the Contract Area;
LESS
(iv) the Companies' share of all Production Costs and
royalty/cess payments incurred on or in the
Contract Area;
LESS
(v) the notional income tax, determined in accordance
with paragraph 7 of this Appendix, payable by the
Companies on profits and gains from the Contract
Area.
3. The "Investment" made by the Companies in the Contract Area
in any particular Financial Year is the aggregate value for
the year of:
(i) Exploration Costs incurred by the Companies in the
Contract Area and apportioned to the Contract Area
in the same proportion that said Costs were
recovered pursuant to Articles 13.2 and 13.3.
132
PLUS
(ii) Development Costs incurred by the Companies in
the Contract Area.
4. For the purposes of the calculation of the Investment Multiple,
Costs or expenditures which are not allowable as provided in the
Accounting Procedure shall be excluded from Contract Costs and be
disregarded.
5. The Investment Multiple ratio earned by the Companies as at
the end of any Financial Year from the Contract Area shall
be calculated by dividing the aggregate value of the
addition of each of the annual Net Cash Incomes
(accumulated, without interest, up to and including that
Financial Year starting from the Financial Year in which
Production Costs were first incurred or production first
arose after the Effective Date on or in the Contract Area)
by the aggregate value of the addition of each of the annual
Investments (accumulated, without interest, up to and
including that Financial Year starting from the Financial
Year in which Exploration and Developments Costs were first
incurred).
6. Profit Petroleum from the Contract Area in any Financial Year shall
be shared between the Government and the Contractor in accordance
with the value of the Investment Multiple earned by the Companies
as at the end of the previous Financial Year pursuant to Articles
14.2, 14.3 and 14.4.
GENERAL
7. In determining the amount of notional income tax to be
deducted in the applicable cash flows specified in paragraph
2 of this Appendix, a notional income tax liability in
respect of the Contract Area shall be determined for each
Company, as if the conduct of Petroleum Operations by the
Company in the Contract Area constituted the sole business
of the Company and as if the provisions of the Income Tax
Act, 1961, with respect to the computation of income tax at
a fifty percent (50%) rate applicable to Petroleum
Operations on the basis of the income and deductions
provided for in Article 15 of this Contract were accordingly
applicable separately to the Contract Area, disregarding any
income, allowances, deductions, losses or set-off of losses
from any other Contract Area or business of the Company.
8. Sample Calculation is attached in Appendix "D-1".
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<PAGE>
APPENDIX "D-1"
INVESTMENT MULTIPLE CALCULATION - EXAMPLE PROBLEM
The following example is intended to demonstrate the calculation and impact of
the Investment Multiple. The figures shown would be for the Companies and are
fictitious in this example for demonstration purposes. The investment multiple
is calculated individually for the Companies.
RIL OR EOGIL
Investment Multiple at beginning of 1.96
Financial Year 11
Profit Oil Shares at beginning of 24.00%
Financial Year 11
US$ MILLIONS
A Cumulative Net Cash Income at 100.00
beginning of Financial Year 11
+ Cost Petroleum in Financial Year 11 10.00
+ Profit Petroleum in Financial Year 11 1.00
+ Incidental Income in Financial Year 11 .00
- Production Costs in Financial Year 11 .60
- Oil Royalty and Cess in Financial Year 11 1.57
- Gas Royalty in Financial Year 11 0.41
- Notional Income Tax in Financial Year 11 2.00
B = Cumulative Net Cash Income at end of 106.42
Financial Year 11
C Cumulative Investment at beginning of 51.00
Financial Year 11
+ Exploration Costs in Financial Year 11 0.30
+ Development Costs in Financial Year 11 1.50
+ Service Costs in Financial Year 11 0.00
D = Cumulative Investment at end of 52.80
Financial Year 11
Investment Multiple at beginning of 2.02
Financial Year 12 = (B / D)
Profit Oil Shares at beginning of 18.00%
Financial Year 12
Since the Investment Multiple is calculated to be greater than 2.0 at the
beginning of Financial Year 12, the Profit Petroleum share to be received by RIL
or EOGIL falls from 24% to 18% at the inception of Financial Year 12.
In the event that the Investment Multiple were found to exceed 2.0
during the financial close of Financial Year 11, the Contractor may
have received excess Profit Petroleum during the first sixty (60)
days of Financial Year 12. In this case, the quantity of excess
Profit Petroleum will be calculated and the accounts will be
settled by adjustment to entitlements within sixty (60) days of the following
year (year twelve).
134
<PAGE>
APPENDIX E
FORM OF FINANCIAL AND PERFORMANCE GUARANTEE
(to be furnished pursuant to Article 29 of the Contract)
WHEREAS ENRON EXPLORATION COMPANY, a Company duly organized and existing under
the laws of Delaware, U.S.A., having its registered office at 1400 Smith Street,
Houston, Texas, U.S.A., (hereinafter referred to as "the Guarantor" which
expression shall include its successors and assigns) is the indirect owner of
100% of the capital stock of ENRON OIL & GAS INDIA LIMITED ("Company") and
direct owner of its parent company; and
WHEREAS Company is signatory to a Production Sharing Contract of even date of
this guarantee in respect of an Offshore area identified as Panna and Mukta
Blocks (hereinafter referred to as "the Contract") made between the Government
of India (hereinafter referred to as "the Government"), Company, RELIANCE
INDUSTRIES LIMITED and OIL & NATURAL GAS CORPORATION LIMITED (hereinafter
referred to as "Contractor" which expression shall include its successors and
permitted assigns); and
WHEREAS the Guarantor wishes to guarantee the performance of Company or its
Affiliate Assignee under the Contract as required by the terms of the Contract;
NOW, THEREFORE, this Deed hereby provides as follows:
1. The Guarantor hereby unconditionally and irrevocably guarantees to the
Government that it will make available, or cause to be made available,
to Company or any other directly or indirectly owned Affiliate of
Company to which any part or all of Company's rights or interest under
the Contract may subsequently be assigned ('Affiliate Assignee'), to
ensure that Company or any Affiliate Assignee can carry out its work
commitment as set forth in the Contract.
2. The Guarantor further unconditionally and irrevocably guarantees to the
Government reasonable compliance by Company or any Affiliate Assignee,
of any obligations of Company or any Affiliate Assignee under the
Contract.
3. The Guarantor hereby undertakes to the Government that if Company, or
any Affiliate Assignee, shall, in any respect, fail to perform its work
commitments under the Contract or commit any material breach of such
obligations, then the Guarantor shall fulfill or cause to be fulfilled
the obligations in place of Company or any Affiliate Assignee, and will
indemnify the Government against all actual losses, damages, costs,
expenses, or otherwise which may result directly from such failure to
perform or breach on the part of Company. In no event shall Guarantor be
liable for any special consequential, indirect, incidental or punitive
damages of any kind or character, including, but not limited to, loss of
profits or revenues, loss of product or loss of use arising out of or
related to a material breach by Company of its obligations under the
Contract.
4. This guarantee shall take effect from the Effective Date and shall
remain in full force and effect for the duration of the Contract and
thereafter until no sum remains payable by Company, or its Affiliate
Assignee, under the Contract or as a result of any decision or award
made by any expert or arbitration tribunal thereunder.
5. This guarantee shall not be affected by any change in the Articles of
Association and by-laws of Company or the Guarantor or in any instrument
135
establishing the Licensee.
6. The liabilities of the Guarantor shall not be discharged or affected by
(a) any time indulgence, waiver or consent given to Company; (b) any
amendment to the Contract or to any security or other guarantee or
indemnity to which Company has agreed; (c) the enforcement or waiver of
any terms of the Contract or of any security, other guarantee or
indemnity; or (d) the dissolution, amalgamation, reconstruction or
reorganization of Company.
7. This guarantee shall be governed by and construed in accordance with the
laws of India.
IN WITNESS WHEREOF the Guarantor, through its duly authorized
representatives, has caused its seal to be duly affixed hereto and this
guarantee to be duly executed the _____________ day of _________ 1994.
The seal of ___________ was hereto duly affixed by ___________this_____ day of
________ 1994 in accordance with its by-laws and this guarantee was duly signed
by ________________ and ______________________
as required by the said by-laws.
- ------------------------ --------------------
Secretary Vice President
Witness:
- -----------------------
136
<PAGE>
APPENDIX F
EQUIPMENT
The development plan, illustrated in Figure G-1 is based on the assumption that
ONGC has provided at the Effective Date, as represented in data and information
heretofore provided by ONGC, certain structures and facilities. All Equipment
specified below, including that not yet installed, shall be provided at ONGC's
cost and risk.
The following facilities have been installed and placed into service by ONGC as
of 1st August, 1993:
- 1 well platform PA
- 8 wells (PA-1, PA-2, PA-3, PA-4, PA-5, PA-6, PA-7, PA-8)
- Early Production System ("EPS") jack-up rig SAGAR LAXMI,
including production systems and all fixtures and
appurtenances
- Tanker loading system, loading buoy and appurtenances
- PB, PD, PE (jackets only) installed; well fluid line
connecting each to EPS
- 23 development wells drilled in PB, PD, PE
- MA well platform
- 8 development wells drilled in MA
- 14" well fluid pipeline connects MA to Panna EPS
- Interconnecting Flowlines and Pipelines
The following facilities were assumed by the Companies to be installed and
commissioned by ONGC prior to the Effective Date and Companies' estimate of
project cost does not include the following (ONGC's schedule for installation as
represented to Companies is also shown):
PB Deck and Facilities - Fourth Quarter 1993
PD Deck and Facilities - First Quarter 1994
PE Deck and Facilities - Second Quarter 1994
MA Deck and Facilities - First Quarter 1994
137
<PAGE>
APPENDIX G
DEVELOPMENT COMMITMENT SPECIFIED BY THE COMPANIES
The development plan, illustrated in Figure G-1 is based on the assumption that
ONGC has provided at the Effective Date, as represented in data and information
heretofore provided by ONGC, certain structures and facilities. The development
of the Fields is proposed to be completed by Contractor through its activities
under this Contract. The following describes what facilities, platforms and
wells are provided by ONGC prior to the Effective Date.
The following facilities have been installed and placed into service by ONGC:
- 1 well platform PA
- 8 wells (PA-1, PA-2, PA-3, PA-4, PA-5, PA-6, PA-7, PA-8)
- Early Production System, "EPS" (jack-up)
- Tanker loading system (via SBM)
- PB, PD, PE (jackets only) installed; well fluid line connecting each
to EPS
- 23 development wells drilled in PB, PD, PE
- MA well platform
- 8 development wells drilled in MA - 14" well fluid pipeline connects
MA to Panna EPS
The following facilities were assumed by the Companies to be installed and
commissioned by ONGC prior to the Effective Date and Companies' estimate of
project cost does not include the following (ONGC's schedule for installation as
represented to Companies is also shown):
PB Deck and Facilities - Fourth Quarter 1993
PD Deck and Facilities - First Quarter 1994
PE Deck and Facilities - Second Quarter 1994
MA Deck and Facilities - First Quarter 1994
Drill two horizontal wells from PD - Second half 1993
Drill two horizontal wells from PE - Second half 1993
Complete two horizontal wells from PE - Second half 1993
The following work, intended to complete the development plan contemplated, is
included in Companies plan and only these facilities and wells are subject to
the Cost Recovery Limit as defined in Article 13:
Panna
- Drill two horizontal wells from PD
- Drill two horizontal sections in two suspended wells on
PE and complete same
- Fabricate and install PC and PF jackets
- Fabricate (or refurbish) and install PC and PF deck
packages
- Drill nine horizontal wells from PC
- Drill nine horizontal wells from PF
- Fabricate and install PPA and PQ
138
- Lay necessary well fluid, gaslift and free gas lines
- Lay sour gas export line from PPA to proposed ONGC 42"
pipeline
- Acquire 850 km of 2-D seismic data
- Drill two exploratory wells
- Geophysical, geological and engineering studies
Mukta
- Fabricate and install MB jacket
- Fabricate (or refurbish) and install MB deck package
- Drill six directional wells from MB
- Lay MB-MA well fluid line
- Lay PPA-MA-MB gaslift line
- Drill two exploratory wells
- Geophysical, geological and engineering studies
- Reprocess and interpret the 1988-89 3-D survey and usable
data from the 1991 SBS 2- D survey
Annex G-1 shows Companies' development concept based on an assumed project start
date of 1st July, 1993.
139
<PAGE>
APPENDIX G
ANNEXURE G-1
TECHNICAL INFORMATION
The following analysis is based on information presented by GOI which has
not been independently verified. Hence, the information given here is
without warranty, although we believe it to be accurate. We have accounted
for relevant technical details provided in the Docket and Data Package.
These technical data are subject to different interpretations and may not
necessarily lead to unique results.
VIIA TECHNICAL INFORMATION FOR PANNA FIELD
(a,b,c)
1. LOCATION
The 430 square kilometers Panna block is located in the Offshore Bombay
basin of India about 50 km east of the giant Bombay High field. Panna
field is a large culmination that occurs where the west-plunging axis of
the Heera-Bassein structural block intersects the western flank of the
fault-bound north-south trending Central Graben (FIGURE VIIA-1).
2. STRATIGRAPHY
Commercial hydrocarbons are trapped in porous and permeable shoal
carbonate reservoirs of the Bassein B zone (Middle Eocene) and A zone
(Early Oligocene). The B zone consists of over 300 meters of porous algal
and fusillinid packstones and grainstones. It is the primary oil reservoir
in Panna with up to 27 meters of oil column and 25 meters of gas. The B
zone overlies shales and thin sandstones of the Early Eocene-Paleocene
Basal Clastics formation which have yielded some interesting but
apparently subcommercial tests of oil and gas.
The top of the B-zone is an unconformable surface overlain by 10 to 15
meters of thin shales and argillaceous limestones called the Tight zone.
The Tight zone grades upward into the A zone. It consists of 50 to 60
meters of interbedded tight and porous wackestones and packstones which
are in turn overlain by alternating shales and tight limestones of the
upper Bassein formation. The A zone is primarily a gas reservoir with
upwards of 75 meters of gas column. Mappable seismic reflectors occur at
the top A zone (H3A) and top B zone (H3B) (FIGURE VIIA-2).
3. STRUCTURE
ONGC structure maps on the B and A zones are shown in FIGURES VIIA-3 and
4. A EEC/RIL seismic time map on the H3B reflector is exhibited in FIGURE
VIIA-5. Comparison of the time map with the cited B zone structure map
reveals similarities in the general structural aspects of Panna field
including a large broad low-relief SE structure which was tested by the
BS-1,3,6 and 8 exploration wells; a high-relief WNW structure penetrated
in a flank position by the BN-1 development well; and another high-relief
NW structure that was also penetrated in a flank position by the BS-5
exploration well. Both the BN-1 and BS-5 wells have indicated log pay but
neither was production tested.
The time map exhibits numerous NW-SE oriented faults with upwards of 100
meters of throw on the eastern margin of the field and lesser amounts of
the 5 to 20 meters range in the field proper where they appear to control
the cited high-relief "pop-up" structures. The seismic section, BS-425A,
located on FIGURE VIIA-6 reveals the nature of the faults along a WNW-ESE
transect (FIGURE VIIA-7). Although all appear to have normal throw, their
similar orientation and cross sectional geometry suggest a possible
transtensional wrench component. This is supported by the smaller
conjugate ENE-WSW faults that lie en-echelon along the larger fault
trends.
The large SE structure currently under development by ONGC is considered
as the Base-Case reserve target in this proposal. It will be referred to
by platform designation as the "PA-PF" structure. The two smaller
high-relief structures are considered as upside Success Case targets whose
development would be contingent on the successful outcome of a work
program detailed later in this document. They are referred to as the "PG"
and "PH" structures as shown in FIGURE VIIA-3 which exhibits a conceptual
development scheme overlay to the B zone structure.
4. RESERVOIR CHARACTERIZATION
Core studies indicate that both the A and B zones have been subjected to
sea-level lowering and emergence which brought about diagenetic
dissolution and general enhancement of porosity and permeability (FIGURES
VIIA-8,9). Hydrocarbon fluid contacts appear to be extremely consistent
throughout the greater field area. The W-E diagrammatic cross section of
FIGURE VIIA-10 demonstrates the cross cutting nature of the fluid levels
through formational boundaries.
Well performance data suggest strong pressure support from an active water
drive mechanism associated with the massive B zone aquifer.
Dissolution-enhanced vertical permeability and the cited small-scale
faults are interpreted to have locally breached the sealing capacity of
the Tight zone between the A and B zones. Therefore, concurrent production
of B zone oil and A zone gas is not advised, especially in the early life
of the field.
Detailed petrophysical analysis was done on straight-hole exploration
wells with complete modern log suites including BS-5, BS-6 and BS-8. TABLE
VIIA-1 lists the petrophysical input parameters utilized for the density
porosity and Archie water saturation calculations. The oil/free-water
contact was observed at 1760 meters subsea in analysed wells. Similarly,
the gas/oil contact consistently occurred at 1733 meters subsea as defined
by RFT and log analysis data. In the B zone, up to 50 meters of the upper
hydrocarbon-bearing interval has average density porosity of 29% while the
middle and lower water-wet portions exhibit an average density porosity of
20%. For the A zone, only higher porosity beds were counted as pay with an
average of 13 meters net out of 55 gross and 23% density porosity.
Petrophysical analysis of the B Zone indicates that there is a distinct
zonation of the hydrocarbon interval as depicted on the type log in FIGURE
VIIA-11. These zones include the following:
ZONE BASE SUBSEA ELEVATION(m)
--------- -------------------
Free Gas 1733
Free Oil 1746*
Moveable Oil 1751*
Residual Oil 1760
* Surfaces vary 1-2 meters as a function of reservoir quality
5. VOLUMETRIC RESERVE CALCULATIONS
Volumetric input parameters, depict the maximum, minimum and most likely
values of area under closure, net pay thickness, porosity and water
saturation for each hydrocarbon zone of the A and B intervals. Volumetric
parameters for the Base Case "PA-PF" structure are listed in TABLE VII(d)
i. The Success Case for "PG" and "PH" is set forth in TABLE VII(d) ii. It
bears noting that the distinction of the various hydrocarbon zones in the
A interval are generally inferred from production tests of the BS-4, BS-9
and PBM-2 exploration wells. Determination of the cited hydrocarbon zones
is inhibited by A zone's poorer reservoir quality and interbedded nature.
Fluid properties of A and B zones are listed in TABLE VIIA-2. Of note is
the residual oil (ROS) and gas (RGS) saturation values of 40% and 45%
respectively. The assumed average value for ROS of 40%, which is common
for carbonate reservoirs, compares with values of 32% - 37% from data
provided in the data package for the highest-quality reservoir samples.
The high RGS value of 45% is consistent with the strong water-drive model
where reservoir pressure drawdown remains relatively low through the
field's productive life.
The methodology for volumetric calculations utilizes the B zone and A zone
structure maps to determine the area and resulting rock volume of each
cited hydrocarbon zone in the respective A and B intervals. Average values
for pay, porosity, hydrocarbon saturation were then utilized to calculate
oil and gas in place. Recoverable reserves were calculated by subtracting
ROS and RGS from the hydrocarbon saturation of the respective zones and
assuming a sweep efficiency for the natural water drive as follows:
A zone (gas) sweep efficiency = 70%
A zone (oil) sweep efficiency = 60%
B zone (gas) sweep efficiency = 95%
B zone (oil) sweep efficiency = 60%
Although calculated, no A zone recoverable oil reserves were included in
the Base or Success Cases because the oil occurs in a rim around the outer
perimeter of the field where it is beyond reach with the envisioned
development scheme that targets B zone oil and A zone gas reserves.
Comparison of volume per unit area calculations (e.g. MMt/square
kilometers) indicate that the A zone oil reservoir requires 5X the area of
the B zone oil reservoir to yield an equivalent volume of recoverable
reserves. Stated another way, for a given drainage area, the A zone will
yield 20% of the reserves delivered by the B zone. FIGURE VIIA-12 shows
the recoverable reserve uncertainty for the base case PA-PF structure
expressed as a log normal distribution on a log probability scale. It
indicates the following range:
PROBABILITY RECOVERABLE RECOVERABLE
>or = Oil Gas
----------- ----------- -----------
(%) (MMt) (MMM cubic meters)
Minimum 90 12.1 7.25
Most Likely 50 16.2 10.00
Maximum 10 22.4 13.88
The most likely reserve range was utilized in the Base Case development
plan and production profile. Comparison of the oil inplace for the B zone
and recoverable B zone oil indicates a recovery factor of 23.8%. Gas
recovery for the A and B zones is 27.3%. This low gas recovery is a
function of the relatively high percentage of solution gas to total gas
volume (33.6%) and the relatively poor A zone reservoir quality and high
residual gas saturation assumed for the water drive model. Detailed
reserves by zone are listed in TABLES VIIA-(e)i for the base case, TABLE
VIIA-(e)ii for the upside reserves and TABLE VIIA-(e)iii for the combined
"Success case".
(d,e) PANNA PARAMETERS AND RESERVES
Please refer to TABLES VII A-(d)i, (d)ii, (e)i, (e)ii, (e)iii
(f) PLANS FOR UTILIZATION OF GAS - PANNA
1. The natural water drive characteristics of the Panna field are well
substantiated and therefore, no gas re-injection for pressure
maintenance is necessary. Instead, all effort will be made to avoid
flaring any gas volumes other than as necessary for optimum oil
production. It should be recognised that under some development
scenarios increased gas flaring will result from unavailability of
the GOI-owned gas transmission line. GOI approval for such temporary
flaring is presumed and is a condition of this bid.
2. The need for gas lifting of producing wells is not an immediate
concern due to the flow capability of the producing wells. Adequate
gas lift gas is available and facilities to gather, compress and
distribute for either sale or gas lift is planned.
3. Upon the installation of either a processing platform or other means
of compression and dehydration, gas sales will begin (expected no
later than July, 1995).
4. Flaring until gas processing facilities are installed will be
minimised by flaring only gas associated with oil production.
5. The proposed gas transportation option is a connection to the
planned 42-inch ONGC gas pipeline to Hazira. The connecting pipeline
will be built by the Bidder as part of the cost-recoverable work
program.
VIIB. TECHNICAL INFORMATION FOR MUKTA FIELD
(a,b,c)
1. LOCATION
The 777 square kilometers Mukta block is located in the offshore
Bombay basin of India about 25 km east of the giant Bombay High
field and 25 km west of Panna field. It contains a complex of
relatively small structures that are positioned on the axial crest
of the west-plunging Heera-Bassein structural block. The Mukta block
lies approximately midway between two major NW-SE structural
elements that cut the Heera-Bassein nose. These include the Bombay
High fault to the west and the Central Graben to the east (FIGURE
VIIB-1). The numerous mapped structures of the block have been
geographically subdivided into three structural blocks or areas by
ONGC called B-57, B-19 and B-126. The B-57 and B-19 areas are
jointly called Mukta field. FIGURE VIIB-2 highlights the significant
structural closures and defines the B-57 seismic 3-D map area in
red.
2. STRATIGRAPHY
Commercial hydrocarbons are trapped in multiple porous and permeable
shoal carbonate reservoirs of the Bassein B zone (Middle Eocene) and
sandstones of the underlying Early Eocene-Paleocene Basal Clastics
formation. The Bassen A zone (Early Oligocene) has tested high rates
of gas and condensate in several exploration wells but exhibits low
porosity and is considered to have limited reserve potential. The B
zone consists of 200 to 250 meters of tight mudstones and pelletal
wackestones interbedded with porous algal and fusillinid packstones
and grainstones. The impermeable lithologies form effective seals
for three major reservoir intervals called B upper, B middle and B
lower. No free water level was observed in the porous B zones
suggesting oil columns in excess of 70 meters. However, significant
water tests from apparent pay zones indicate that much of the oil
saturation is residual. The B zone overlies the Basal Clastics
formation which consists of 25 to 35 meters of shale underlain by 25
to 40 meters of porous and permeable sandstone. Hydrocarbon columns
appear to be in the range of 10 to 20 meters with a well defined
oil/ free-water contact.
The top of the B-zone is an unconformable surface overlain by 5 to
10 meters of thin shales and argillaceous limestones called the
Tight zone. The Tight zone grades upwards into the A zone. It
consists of 40 to 50 meters of low-porosity pelletal wackestones
which are in turn overlain by alternating shales and tight
limestones of the upper Bassein formation. The A zone is considered
to be a marginal gas reservoir and was not quantified in this
evaluation. Mappable seismic reflectors occur at the top A zone
(H3A), top B zone (H3B) and top Basal Clastics (H4) (FIGURE VIIA-2).
3. STRUCTURE
FIGURE VIIB-3 is an ONGC structure map on top of the B zone in the
B-57 and B-19 area. The map is based on 2-D seismic data and
exhibits a series of interpreted NE-SW faults that separate and trap
B upper oil pools with columns up to 85 meters in thickness. A
generally-SW-NE diagrammatic cross section through the mapped area
depicts the interpretation (FIGURE VIIB-4). It demonstrates the
sealing nature of the faults and thick multiple hydrocarbons.
The seismic section, BS-423, located in FIGURE VIIB-5, reveals the
structural aspects of the same area shown in FIGURE VIIB-3 following
a WNW-ESE transect oriented normal to the cited fault trend (FIGURE
VIIB-6) and subparallel to the cross section of FIGURE VIIB-4. At
the approximate top of the Bassein (H3), shown in blue, the section
clearly shows a moderate relief structure on the east side that
corresponds to the position of the B-57-1 and B-57-12 exploration
wells and MA development platform. Another low-relief structure can
be seen on the western side which occurs in the B-126 area. The one
critical aspect of the previous interpretation that is not supported
by this hard data is any evidence of faulting in the Bassein
interval.
FIGURE VIIB-8 is a depth structure map on top B zone in the B-57
area. It was interpreted from a recent vintage 3-D seismic survey by
ONGC. It basically covers the same area as the previous 2-D
interpretation (FIGURE VIIB-3) and is mapped at the same structural
level. Areas of structural closure have been colored orange. The two
interpretations are radically different. The 3-D map shows no faults
in support of the hard seismic data (FIGURE VIIB-7) and depicts
relatively small closures on a SW plunging structural nose. The most
significant structure with approximately 30 meters of relief is the
MA platform structure which also agrees with the cited hard seismic
data.
From review of the data package and communications with ONGC
representatives in the negotiating sessions, it is the understanding
of EEC/RIL that reserves quoted by ONGC for the Mukta field do not
reflect the recent 3-D interpretation and are based on the cited 2-D
interpretation designed to account for the apparent large oil
columns. Based on the compelling evidence of the 3-D interpretation,
it is the position of EEC/RIL that the MA structure is the only
quantifiable feature available for a base case analysis at this
time. The subsequent volumetric evaluation of the MA structure
utilizes the ONGC 3-D B zone structure map and detailed log analysis
to derive base case reserves. The upside case assumes two appraisal
tests of features that are exactly 50% of the size of the MA
structure with one success and one dry.
4. RESERVOIR CHARACTERIZATION
Core studies indicate that the B zone reservoirs have roughly half
of the porosity and a fraction of the matrix permeability observed
in the neighboring Panna block. The Mukta area appears to have been
the site of a lower-energy environment of deposition in comparison
to Panna. The sequence exhibits alternating low-energy finer-grained
carbonate and moderate-energy pelletal to fussillinid wackestones,
packstones and grainstones. Core descriptions indicate that like
Panna, the A and B zones have been subjected to sea-level lowering
and emergence which brought about diagenetic dissolution and general
enhancement of porosity and permeability. This secondary
macro-porosity and permeability seem to be critical to the excellent
fluid flow rates exhibited in both the exploration and development
wells in the block.
The occurrence of multiple tight and porous zones in the B interval
suggests cyclic emergence of a restricted shallow marine platform
environment. The stratigraphic thinning of the Bassein formation at
Mukta relative to Panna, 225 versus 325 meters, indicates that the
Mukta area was possibly in a higher paleostructural position during
Bassein deposition. It is located on the landward side of the Bombay
High structural block which is devoid of Bassein age sediments.
These observations suggest that the currently west-plunging
Heera-Bassein nose may have undergone structural rotation from a
previously east-plunging position with stratigraphic thinning and
pinchout of Bassein reservoirs on to the Bombay High block. This
paleostructural and stratigraphic setting provides the mechanism for
the trapping of a large volume of hydrocarbons in the Mukta area
prior to structural rotation in to its current setting.
FIGURES VIIB-7 through 11 show production test results by zone
overlain on the appropriate 3-D structure map for the B-57 area. A
similar set of production overlays are shown in FIGURES VIIB-12 to
15 on the 2-D ONGC structure maps of the B-126 area.
There are 3 water free gas tests of the A zone in the block which
are localized on defined structural closures in the north-east B-57
area in wells B-57-1, 2 and 7 (FIGURES VIIB-7 and 12). Poor or wet A
zone tests were recorded in the remainder of the area.
The B upper and B middle zones are the two most prolific intervals
in the block with 8 water free oil tests each. The B upper tested
rates up to 1900 BOPD and the B middle reported a maximum rate of
2083 BOPD from the BS-57-1. The better tests occur on defined
structural closures in the B-57 and B-126 areas with the exception
of well B-57-10 which tested water free rates of 408 and 1455 BOPD
respectively from the B upper and middle zones. The well is located
on a small WSW-plunging nose with no apparent closure implying a
stratigraphic component to the trapping mechanism. However, it bears
noting that other wells located on the regional SW-plunging nose
that runs diagonally through the B-57 map area are wet or have
tested high water cuts including B-57-5, 6, 17 and 18 (FIGURES
VIIB-8, 9, 13, 14).
The most structurally controlled interval in the Mukta block is the
B lower zone. It has three significant water free oil tests in the
block. Both the B-57-1 and 12 wells in the MA structure tested high
rates of up to 2314 BOPD (FIGURE VIIB-10). Also the structurally
highest mapped well in the B-126 area, B-126-1, reported an
excellent rate of 2286 BOPD (FIGURE VIIB-15). It is the
understanding of EEC/RIL that the MA platform was positioned and the
subsequent 8 development wells were drilled on the basis of the
cited 2-D interpretation in the B-57 area (FIGURE VIIB-3). An
important point to make is that the 3-D map matches extremely well
with the results of the completions in the B lower zone. Wells MA-1,
5, 6 and 7 are clearly at the edge of closure and tested water or
had high water cut except MA 7 which was not tested and has not been
completed. Another well (MA-2?) that was completed as a producer has
quit flowing (due to water encroachment?) leaving only three
currently producing wells. These results indicate that the 3-D maps
are reliable and that the B lower zone reservoir may have at least a
partial water drive mechanism. The pressure drawdown observed in the
development wells has been interpreted by ONGC as evidence for a
depletion drive mechanism. It is the position of EEC/RIL that
accurate bottom hole pressure monitoring and remediation of
cement/mechanical problems is required before accurate determination
of drive mechanism and reservoir modeling can be done. This would
provide the basis for any future pressure maintenance or waterflood
operations.
The Basal Clastics sandstone reservoirs have yielded significant
tests in 3 wells in the B-57 area (B-57-6, 12,18) and B-126 area
(B-126-2,4,5) respectively with rates up to 1540 BOPD (FIGURE B-16).
A certain degree of stratigraphic trapping seems to be occurring in
non-closed areas (FIGURES VIIB-11,15). This indicates reserves may
be difficult to quantify and conversely that all future exploration
and development wells should evaluate this interesting interval. All
development wells proposed in the Mukta base development plan are
scheduled to be Basal Clastics tests.
Detailed petrophysical analysis was done on straight-hole
exploration wells with complete modern log suites. TABLE VIIB-1
lists the petrophysical input parameters utilised for the density
porosity and Waxman-Smit water saturation calculations of the B zone
reservoirs and Archie water saturation calculations for Basal
clastics.
FIGURE VIIB-17 is a cross plot of BQV versus Porosity with an
interpreted trend line that provides an algorithum tying clay
conductance effects into the log analysis through the Waxman-Smit
water saturation model. Petrophysical analysis of the B zone
indicates that there is a distinct zonation of the hydrocarbon
interval as depicted on the type log in FIGURE VIIB-18. These zones
include the following :
ZONE BASE WATER SATURATION RANGE
--------- ----------------------
Free Oil 15 to 30%
Moveable Oil 31 to 59%
Residual Oil 60 to 100%
FIGURE VIIB-19 is a capillary pressure curve from a typical Mukta B
zone reservoir. It demonstrates that for water saturations of 20% or
less, oil columns of more than 100 meters are required to displace
the water from the low permeability matrix. It is clear from the 3-D
mapping that the largest closures at Mukta have around 30 meters of
relief as seen at the location of the type log of well B-57-12.
Clearly, none of the free oil zones exceed 30 meters of thickness in
the type log example nor do they in other exploration wells
examined. This observation combined with the presence of ubiquitous
residual oil saturation and lack of free water level in the Bassein
reservoirs supports the cited hypothesis of a large accumulation
that has been later breached or tilted leaving oil behind in
existing smaller structures and stratigraphic traps. The large oil
colums of a major accumulation would be required to achieve the free
oil saturations seen today and explain the top to bottom residual
oil saturation of the Bassein B zones.
FIGURE VIIB-20 is a diagrammatic Resistivity Index versus Water
Saturation plot. It provides an explanation of the effects on log
analysis of a breached or waterflooded reservoir. The straight line
represents the water drainage cycle of a normal reservoir that has
been filled with hydrocarbons over the course of geologic time. In
essence, oil has displaced water. The arcuate imbibition cycle line
represents a breached or flood reservoir where oil has been
displaced by water. The saturation exponent "N" is derived from the
slope of the lines. Clearly, for a given resistivity, the resulting
water saturation calculated would be much higher if the reservoir
was following the imbibition cycle rather than the water drainage
cycle. It is concluded that much of the original thick oil columns
mapped by ONGC and disappointing wet tests of apparent pay zones are
a product of this breached reservoir phenomena. Restricting pay
counts to the free oil zones provides a realistic minimum case and
gives the analyst a conservative approximation of oil column height.
Inclusion of the moveable pay provides a maximum case.
5. VOLUMETRIC RESERVE CALCULATIONS
Volumetric input parameters, listed in TABLE VIIB-(d), depict the
maximum, minimum and average values of area under closure, net pay
thickness, porosity and water saturation for each hydrocarbon zone
for the B upper, middle, lower and Basal Clastic intervals.
Fluid properties of the B zones and Basal Clastics are listed in
TABLE VIIB-2. Of note is the residual oil (ROS) saturation value of
40% which is the same used at Panna.
The methodology for volumetric calculations of the base case MA
structure utilizes the B upper zone structure map to determine the
area and resulting rock volume of each cited hydrocarbon zone in the
respective B zones and Basal Clastics intervals. Values for pay,
porosity, and hydrocarbon saturation derived from analysis of the
B-57-1 and 12 wells and utilized to estimate oil and gas in place.
Recoverable reserves were calculated by subtracting ROS from the
hydrocarbon saturation of the respective zones and assuming a sweep
efficiency for partial water drive of 60%. Oil in place was
calculated using only the Moveable and Free oil zones. FIGURE
VIIB-21 shows the recoverable reserve uncertainty for the base case
MA-MB structure expressed as a log normal distribution on a log
probability scale. It indicates the following range :
PROBABILITY RECOVERABLE RECOVERABLE
>or = OIL GAS
----------- ----------- -----------
(%) (MMt) (MMM cubic meters)
Minimum 90 4.1 0.46
Most likely 50 5.3 1.85
Maximum 10 6.7 3.57
The base case most-likely reserves represents an average between the
maximum case which combines moveable and free oil zone reserves and
a minimum case of free oil zone reserves only. Gas reserves occur as
solution gas and show a wide range from a maximum value derived from
total oil in place assuming a severe depletion pressure draw down of
the reservoir to a minimum based on pressure supported water drive
mechanism and straight GOR based volume related to oil produced.
Comparison of oil in place for the B zone and recoverable oil
indicates a most likely case recovery factor of 17.2%. Gas recovery
is 51.8% reflecting the partial water drive/depletion drive model
assumed for the reservoir. Reserves for the base case are listed in
TABLE VII B-(e)i. The upside is assumed to be 50% of the Base Case
reserves. The Success Case is a combination of the two as follows:
RECOVERABLE RECOVERABLE
OIL GAS
CASE (MMt) (MMM cubic meters)
---- ----------- -----------
Base 5.37 1.85
Upside 2.68 0.93
Success 8.05 2.78
(d,e) MUKTA PARAMETERS AND RESERVES
Please refer to TABLES VIIB-(d)i, (e)i and (e)ii.
(f) PLANS FOR UTILIZATION OF GAS - MUKTA
(i) A study is needed to justify water-injection pressure maintenance.
No gas re-injection is contemplated.
(ii) After the MA permanent deck is installed at Mukta, appropriate
testing will be undertaken to determine the timing for gas lift gas
installation. Given the water production observed, the need for gas
lifting at some point is considered likely and provisions for this
eventuality have been made in the Base Case work program.
(iii) Apart from the gas requirement for internal use such as
power-generation and technical flaring, the bulk of the gas will be
available for sale after dehydration and compression.
(iv) During the producing life of the field efforts will be continuously
made to minimise flaring. Flaring of associated gas is presumed,
without GOI restriction, until the gas sales line is commissioned.
(v) After hookup, gas not used in operation will be sold via Panna
facilities.
(g) MONITORING SYSTEMS & RESERVOIR MANAGEMENT
1 MONITORING SYSTEM
Production of all fluids will be monitored on a well by well basis,
as well as on an aggregate basis as required by standard oil/gas
field practices. For effective operational control these production
rates will be recorded on a daily basis. For fiscal purposes,
production will be aggregated and reported monthly. An appropriate,
state of the art well testing system will be installed at each unit.
The field will be monitored locally at platforms and remotely from
the shore base. EEC/RIL intend to operate the satellite platforms
unmanned to the extent possible and to use computer-assisted
operations to monitor ongoing performance.
2 RESERVOIR MANAGEMENT
Reservoir Management will be carried out through conventional
surface as well as down hole monitoring systems, such as bottom hole
pressure surveys, production testing and well deliverability testing
at prescribed intervals. This data will be analysed at regular
intervals, but at least once a year to study the reservoir
performance and to ascertain the reservoir drive mechanism. The
operations will be adjusted to maximize economic recovery. It is
envisioned that a suitable mathematical model will be used and
updated as and when required.
VIII PROPOSED PANNA/MUKTA WORK PROGRAMME
(a) CONCEPTUAL DEVELOPMENT PLAN
Data Package material provided by GOI demonstrates a significant potential
for increased reserves at Panna/Mukta in the event of exploration
success(the Success Case). Described below is a staged development scheme
in which Stage I provides a building block towards the expansion needed in
the Success Case. The Success Case arises in the event of positive results
from exploratory wells included in the EEC/RIL firm work commitment. The
fully developed Success Case is described first so that the integrated,
building-block nature of Stage I is apparent. The firm work programme bid
by EEC/RIL commits to all items needed for Stage I(the Base Case); we are
dedicated to full Success Case development in the event of exploration
success. The risk of such exploration work precludes a firm commitment to
additional platforms, pipelines and development wells until the additional
reserves are conclusively demonstrated.
1 SUCCESS CASE DEVELOPMENT (29.5 MMt or 224 MMBO remaining recoverable
oil reserves)
EEC/RIL are proposing four exploratory wells as part of the firm
work programme. We believe, because of exploratory wells previously
drilled in the Panna G and H areas, that both of these areas are
likely to contain commercially viable accumulations. In addition,
several Mukta area wells have shown encouraging results. As a
result, we assume that one of the two exploratory tests proposed at
Mukta will also yield a commercially viable develop the Panna/Mukta
fields will require (See FIGURE VIII-1):
- 8 Well platforms at Panna
- 3 Well platforms at Mukta
- 1 Common 45,000 BOPD processing facility
(INCLUDING LIVING QUARTERS)
- 1 Inter-field (Mukta-Panna) well fluid pipeline and gas lift line
(POSSIBLY ALSO A WATER FLOOD LINE)
- 84 Development wells
- 1 Export gas line
EEC/RIL are capable of developing a highly accelerated production
schedule but, to do so, require the full support and cooperation of
GOI.
2. BASE CASE DEVELOPMENT (155 MMBO or 20.4 MMT or remaining recoverable
oil reserves)
This case corresponds to RIL/EEC's committed work programme and is
not a reflection of our expectations, which are reflected in the
Success Case. The extensive drilling campaign conducted by ONGC has
demonstrated the viability of developing a large area on Panna and
supports the installation of one additional platform at Mukta. The
development plan and schedule are illustrated in FIGURES VIII-2,
VIII-3 and includes:
- 6 Well platforms at Panna
- 2 Well platforms at Mukta
- 1 Common 45,000 BOPD processing facility and living quarters.
- 1 Interfield (Mukta-Panna) well fluid pipeline and gas lifline
(POSSIBLY ALSO A WATERFLOOD LINE)
- 67 Development wells
- 4 Exploratory wells
- 1 Export gas line
The Base Case assumes that a sour gas export line will be laid from
PPA to an interconnect on the proposed ONGC 42-inch sour gas line
and that the 42-inch line will be available no later than April 1,
1995.
3 ACCELERATED DEVELOPMENT
A limited, unique window of opportunity could exist wherein EEC/RIL
may acquire an existing, operating 40,000 BOPD Floating Production
System (FPS) capable of a significant acceleration of the
availability of processing at a major cost saving to GOI/EEC/RIL.
This approach would have positive early cash flow implications to
all concerned and obviously enhances the value of the project to a
major degree (See FIGURE VIII-4). Uncertainty about securing the
facility preclude bidding the project based on acquiring the unit.
However, EEC/RIL commit to a "Best Efforts" ("Reasonable
Endeavours") attempt to acquire the unit if GOI will commit by July
26, 1993 to awarding the requested blocks to EEC/RIL.
(b) PANNA/MUKTA WORK DEVELOPMENT
Since Panna/Mukta development has started, a baseline must be established
so that the transition from ONGC to EEC/RIL is clearly defined.
Accordingly, following are sections defining status of the development,
specifying ONGC activities which we presume will be completed and then
future work which EEC/RIL commit to undertake.
1. STATUS AS OF JULY 1, 1993
The following facilities have been installed and placed into service
by ONGC:
- 1 Well platform PA
- 8 Wells (PA-1, PA-2, PA-3, PA-4, PA-5, PA-6, PA-7, PA-8)
- Early Production System, "EPS" (Jack-up)
- Tanker Loading via SBM
- PB, PD, PE (Jackets only) installed; well fluid line
connecting each to EPS.
- 23 Development wells drilled in PB, PD, PE.
- MA (Jacket only) installed.
- 8 Development wells drilled in MA
- 14" well fluid pipeline connects MA to Panna EPS.
We understand that The Panna EPS is currently processing
approximately 13,000 BOPD derived from the PA, PB, PD, PE and MA
platforms against a design capacity of 10,000 BOPD. Production rates
and bottomhole pressures for individual wells on the PB, PD, PE and
MA platforms cannot currently be measured due to the temporary
decks. Efforts are being made to balance reservoir withdrawals
areally and to minimise gas production, all of which is being
flared.
2. WORK PLANNED AND COMMITTED BY ONGC
We understand that ONGC has work in progress on certain projects
related to ongoing Panna/Mukta development. In formulating the bid,
EEC/RIL have assumed that ONGC will design, fabricate and install
permanent decks and facilities for the PB, PD, PE and MA jackets at
its own cost. The bid assumes that the decks and facilities will be
installed and commissioned according to the following schedule:
PB - fourth quarter, 1993; PD - first quarter, 1994; PE - second
quarter 1994, MA - first quarter 1994. Early installation of these
deck packages is considered imperative to monitor and optimise
reservoir performance.
EEC/RIL would be willing to negotiate the following alternatives to
the above:
- EEC/RIL assumption of responsibility for fabrication of one or
more of the deck packages currently under construction
- EEC/RIL would prefer to manage the deck installation
- EEC/RIL would be willing to locate, purchase and refurbish used
deck packages or fabricate new deck packages to substitute for
those under fabrication by ONGC, if this does not result in any
delay in project timing.
We understand that ONGC has committed to drilling two horizontal
wells from PD and two horizontal wells plus two horizontal
completions from PE in the second half of 1993. The bid assumes
that EEC/RIL will have the option, but not the obligation, to
accept assignment of any or all drilling rig, service and supply
contracts and will perform the work at GOI/EEC/RIL expense
(subject to cost recovery).
WORK TO ACHIEVE BASE CASE DEVELOPMENT
EEC/RIL are committed to proceeding with the Base Case development.
EEC/RIL plan to pursue a very aggressive development schedule
(FIGURE VIII-3) which can only be achieved with the active
assistance of ONGC and GOI authorities.
3. WORK PLAN OFFERED AND COMMITTED BY EEC/RIL
PANNA
- Drill two horizontal wells from PD
- Drill two horizontal wells from PE
- Complete two horizontal wells from PE
- Fabricate and install PC and PF jackets
- Fabricate (or refurbish) and install PC and PF deck
packages
- Drill nine horizontal wells from PC
- Drill nine horizontal wells from PF
- Fabricate and install PPA and PQ
- Lay necessary well fluid, gaslift and free gas lines
- Lay sour gas export line from PPA to proposed ONGC
42-inch pipeline
- Drill two exploratory wells
- Geophysical, geological and engineering studies.
MUKTA
- Fabricate and install MB jacket
- Fabricate (or refurbish) and install MB deck package
- Drill six directional wells from MB
- Lay MB-MA wellfluid line
- Lay PPA-MA-MB gaslift line
- Drill two exploratory wells
- Geophysical, geological and engineering studies
Please note that a second EPS is included in the Base Case
development plan. However, a firm commitment has not been made since
the economics are marginal (if new construction is required) and
highly sensitive to project timing and EPS cost.
(c) DEVELOPMENT WORK COMMITMENT
EEC/RIL will immediately begin, the design and fabrication of a jacket and
deck for location PC. If available, a used deck will be acquired and
refurbished; otherwise, a new deck will be fabricated (EEC/RIL plan to
install used decks wherever possible to minimise costs). A new nine-slot
jacket will be fabricated for PC. At the time of jacket installation, nine
conductors will be driven. As soon as the PC jacket is installed and
drilling on PD and PE is completed, the rig will be moved to PC and nine
horizontal wells will be drilled. EEC/RIL plan to employ a single rig to
drill all Panna horizontal wells to take advantage of the associated
learning curve to minimise drilling time and cost. After drilling is
completed, the rig will be moved to PF and the deck will be installed on
PC. Production will commence from PC as soon as a well fluid line is
installed. Drilling prior to deck installation on PC will allow production
to be significantly accelerated due to the lead time required to prepare
the deck package.
Nine horizontal wells will also be drilled from PF. However, in this case,
the deck package will be available and installed prior to drilling. This
approach has the advantages of allowing produce-while-drilling operations
to accelerate production and raising the wellheads further above the
splash zone.
Work will commence immediately on the design and fabrication of a new
jacket for MB. Six directional wells will be drilled from MB and should be
completed at the time the MB deck package becomes available (pre-monsoon
1995). Production will ensue after the installation of the deck package
and a wellfluid line from MB to MA is installed.
Work will commence immediately on the design and fabrication of a new
45,000 BOPD production processing jacket and deck (PPA) as described
below:
FUNCTIONAL/DESIGN BASIS
- Production and Test Manifolds
- Production and Test Separation
- Gas Compression
- Gas Dehydration
- Chemical Injection (Corrosion Inhibition)
- Produced Water Treatment, Disposal
- Power Generation
- Safety systems
- Fire Protection
- Utilities
STRUCTURAL BASIS
- 8-Pile
- 86'x160' Deck
- Structural Redundancy
- Earthquake Zone IV Design
PPA is expected to be available for installation pre-monsoon 1995.
Work will also commence immediately on design and fabrication of a
separate 100-man quarters platform (PQ).
Although not currently in the Base Case development plan, studies will be
conducted to ascertain the merit of combining PPA and PQ. In addition, the
desirability of a manifolding platform (PLM), possibly combined with PQ,
will be investigated. A manifolding platform may be justified given the
large number of lines associated with the producing platforms, riser loads
on PA and the future connections and disconnections associated with the
Sagar Laxmi (EPS-I), the second early production system (EPS-II) and the
PPA.
Work will begin immediately to secure a jack-up suitable for conversion
(preferably already converted) for service as a second early production
system (EPS-II) of 10,000 BOPD capacity. If such a unit can be secured at
a cost and within a time frame that project economics are enhanced, it
will be implemented. Installation of EPS-II would occur post-monsoon 1994
and would allow Panna/Mukta production processing capacity to be expanded
to 20,000 BOPD at the beginning of 1995. EPS-II will allow considerable
acceleration of oil production prior to the commissioning of PPA. In
addition, the Sagar Laxmi and EPS-II can be retained temporarily after the
installation of PPA to process as much as 65,000 BOPD in the event
production exceeds expectations or the Success Case is achieved. Although
EEC/RIL have included the installation of EPS-II in discussion, additional
economic analysis will be conducted to confirm that the acceleration of
oil production justifies the additional expense.
The need for future gas lift and free gas lines is anticipated. The lines
will be installed when required by field performance and when convenient
in terms of lay barge utilisation. A long gas lift line from PPA to MA and
MB will almost certainly be required, whereas a free gas line should be
unnecessary.
Preliminary EEC/RIL studies indicate that a significant possibility of
communication between the Panna A-zone and B-zone exists. As a result,
EEC/RIL intend to defer production from the A-zone gascap to maximise oil
recovery. However, although every effort will be made to minimise gas
production, elevated gas-oil ratios are inevitable given the thin oil
column and free gas lines may become necessary prior to gascap blowdown.
The Base Case assumes that a gas export line may be laid from PPA to a
connection with the proposed 42-inch ONGC gas pipeline to Hazira. It is
assumed that line installation would occur pre-monsoon 1995 with resulting
gas sales in July, 1995, that 100% of Panna/Mukta gas will be taken and
that oil production will not be restricted by gas flaring considerations.
As an alternative not considered in the Base Case, EEC/RIL is studying the
possibility of constructing a sour gas pipeline to the Bombay area and
constructing onshore sweetening plant.
EEC/RIL assume that suitable shore base facilities (including dock space,
yard space, warehousing, communications) will be made available for lease
to support Panna/Mukta operations.
(d) EXPLORATION WORK COMMITMENT
Two exploratory wells will be drilled at Panna and two at Mukta. These
wells will be drilled as soon as possible by either of the two rigs after
firm locations are established and when the development drilling schedule
allows.The wells must be drilled early enough to allow timely jacket and
deck commitments to be made in the event of success to ensure minimum
delay in the development program. Details of the program are as follows :
PANNA
SEISMIC - Reprocess and interpret all usable data in concession
Commitment : 850 +/- km
DRILLING - Drill and evaluate 2300 +/- meter delineation tests. Penetrate
base of Basal Clastics (Paleocene-Early Eocene) below B Zone (middle
Eocene) limestone. Maintain options to test, complete and suspend at
mudline if results warrant.
Commitment : 2 wells
POTENTIAL RESERVES
Based upon the assumption that both of the above mentioned delineation
tests are successful, inplace and recoverable reserves are provided in
TABLE VIIA-(e). For this purpose, we have assumed that the tests will be
on Panna structures PG and PH (FIGURE VIIA-3). However, after reprocessing
and interpreting seismic (SEE ABOVE WORK COMMITMENT), the best two
structures will be selected and drilled.
MUKTA
SEISMIC - Reprocess and interpret the 1988-89 3D survey (150 sq.km, 4100
+/- line km) and all usable data from 1991 SBS 2D survey (750 +/- km).
Commitment : Processing and interpretation as
noted above.
DRILLING - Drill and evaluate two 2300 +/- meter delineation tests.
Penetrate to base of Basal Clastics (Paleocene-Early Eocene) below B Zone
(middle Eocene) limestone. Maintain options to test, complete and suspend
at mudline if results warrant.
Commitment : 2 wells
POTENTIAL RESERVES Based upon the assumption that one of the above
mentioned delineation tests is successful, inplace and recoverable
reserves are expected to increase by 50% those provided in TABLE
VIIB-(e)ii. After reprocessing and interpreting seismic (SEE ABOVE WORK
COMMITMENT) the best two prospects will be selected and drilled.
f) OTHER COMMITMENTS
EEC/RIL have committed to a Base Case development plan based upon data
packages prepared by GOI. Upon contract signature, it is assumed that all
relevant information will be provided to EEC/RIL and that key ONGC
personnel will be made available to allow optimization of the development
plan. Based upon this information, EEC/RIL will perform the following
technical work the results of which will be shared with GOI.
PANNA
The Panna field oil accumulation is relatively thin and lies between an
active aquifer and a gascap. Optimum oil recovery will be achieved by
minimising gascap gas production thereby minimising movement of the oil
bank into the gascap (which results in unrecoverable residual oil
saturations in the gascap) and maintaining reservoir energy. EEC/RIL
believe that the added expense of drilling horizontal wells will be more
than made up by the increase in productivity index such completions will
achieve.
EEC/RIL intend to conduct single well simulations to determine the optimum
completion interval placement with respect to the fluid contacts, optimum
production rate and optimum horizontal completion length.
The results of detailed geological modeling, PVT analysis, petrophysical
analysis and well performance studies will be used to prepare a 3-D
full-field reservoir simulation model for the Panna field. The model will
be used to optimise areal well placement and platform locations. Analysis
of fluid contact movements and areal balancing of withdrawals will be
conducted. The model will be used to forecast fluid production rates and
pressure changes and will be used to determine the optimum time for gas
cap blowdown. History matching will be complicated by the lack of
individual well data concerning PB, PD and PE and by the lack of current
gas production measurements.
Drilling and completion studies will be conducted to minimise costs and
formation damage. EEC/RIL are experienced in the drilling of horizontal
wells and hope to meet or exceed ONGC performance. In particular, we
believe that great improvements in current cementing and formation damage
control practices can be made.
MUKTA
The drive mechanism controlling the lower B Zone reservoir performance
cannot be conclusively determined at present since the temporary deck at
MA precludes individual well testing and bottomhole pressure measurements.
One of the MA wells has ceased to produce, probably due to water
production, and significant water production is occurring from one or more
of the remaining wells. In addition, flowing wellhead pressures are
declining. Based upon this evidence, as well as geological considerations,
we currently assume that the reservoir is producing with a partial water
drive. Early installation of the permanent MA deck is considered vital to
allow well testing and bottomhole pressure measurement to identify the
drive mechanism.
Once appropriate data has been collected, reservoir engineering studies
will be conducted (probably 3-D reservoir simulation) to optimise the
development plan. Due to the observed water production, gas-lifting will
almost certainly be required and is therefore included in the Base Case
commitment.
Waterflood facilities and pipelines are not included in the Base Case
commitment since the necessity of water injection has not been
established, however, PPA will include deck space and utilities to allow
for subsequent addition of injection facilities if justified. The
requirements for water injection facilities will be identified shortly
after testing the MA wells and measuring bottomhole pressures. The risk of
premature water breakthrough and poor sweep efficiency in the naturally
fractured reservoir must also be assessed. Pressure transient analysis
will probably be used to confirm well interference and analyze dual
porosity behavior. If these preliminary studies indicate that
waterflooding might be beneficial, a pilot waterflood using one of the EPS
units at MA could be conducted. If the above studies indicate that
waterflooding is economically viable, EEC/RIL will proceed to install the
necessary infrastructure.
The MA wells penetrate four reservoirs which appear to be effectively
sealed from each other. EEC/RIL therefore intend to drill directional
wells from MB to penetrate multiple pays. Engineering studies will be
conducted to optimise the completion design and depletion plan - single
completions, single completions with sliding sleeve or tubing selectives
or dual completions. As the reservoir mechanism becomes better understood,
horizontal drilling applications may become evident.
g) PANNA/MUKTA FACILITIES
Systems analysis (nodal analysis) will be conducted to optimise surface
and subsurface equipment design and operation.
<PAGE>
Appendix-3
WORK PROGRAM COMMITTED BY EEC/RIL
PANNA
o Drill and complete two horizontal wells from PD
o Drill and complete two horizontal wells from PE
o Complete two horizontal wells from PE
o Fabricate and install PC and PF jackets
o Fabricate (or refurbish) and install PC and PF deck packages
o Drill nine horizontal wells from PC
o Drill nine horizontal well from PF
o Fabricate and install PPA and PQ
o Lay necessary well fluid, gaslift and free gas lines
o Lay sour gas export line from PPA to proposed ONGC 42-inch pipeline
o Drill two exploratory wells
o Geophysical, geological and engineering studies
MUKTA
o Fabricate and install MB jacket
o Fabricate (or refurbish) and install MB deck package
o Drill six directional wells from MB
o Lay MB-MA wellfluid line
o Lay PPA-MA-MB gaslift line
o Geophysical, geological and engineering studies
<PAGE>
APPENDIX H
ESTIMATED PRODUCTION PROFILE OF THE
PANNA AND MUKTA FIELDS
Oil Gas
YEAR (THOUSAND BARRELS (MILLION CUBIC METERS
PER YEAR) PER YEAR)
1 1098 0
2 1098 0
3 3285 100
4 6256 201
5 13922 566
6 12693 521
7 10954 456
8 9516 402
9 8735 493
10 7913 484
11 7179 479
12 6549 473
13 5997 470
14 5511 467
15 7655 527
16 6502 521
17 5579 513
18 4899 507
19 4407 549
20 3792 581
21 3260 564
22 2834 552
23 2355 354
24 1986 232
25 1695 159
140
<PAGE>
GRAPHICAL CONTENT APPENDIX
Appendix - B1 Map of Contract Area - Panna Block
Appendix - B2 Map of Contract Area - Mukta Block
Appendix G
Figure G-1 Panna and Mukta Field Development Base Case Reserves
Figure VIIA-1 Regional Seismic Map on Early Eocene Top (H4) - Panna Field
Figure VIIA-2 Generalised Stratigraphy - Panna Field
Figure VIIA-3 Structure Contour Map on Top of B Zone - Panna Field
Figure VIIA-4 Structure Contour Map on Top of A Zone - Panna Field
Figure VIIA-5 Time Structure Map H3B - Panna Field
Figure VIIA-6 Scheme of Seismic Profiles - Panna Field
Figure VIIA-7 REA Bombay High INE BS-425A (Migrated) - Panna Field
Figure VIIA-8 B-Schematic View of Ground Water System and Development/
Destruction of Porosity in "B" Zone (Middle Eocene) - Panna
Field
Figure VIIA-9 A-Schemiatic View of Ground Water System and Development/
Destruction of Porosity in "A" Zone (Early Oligocene) - Panna
Field
Figure VIIA-10 Geological Section Across Panna Field
Figure VIIB-1 Regional Map at H4 Level
Figure VIIB-2 Isochron Map at the Top of Basal Clastics (H4) - Mukta and
B 126 Fields
Figure VIIB-3 Structure Map on Top of B-Upper Reservoir - Mukta Field
Figure VIIB-4 Geological Section Across Mukta and B 126 Fields
Figure VIIB-5 Scheme of Seismic Profiles
Figure VIIB-6 Area Bombay High Line BS-423
Figure VIII-3 Panna/Mukta Development Schedule Revised Base Case
Figure VIIB-7 Isochron Map at the Top of A-Zone (H3A) - Mukta Field (Based
on 3D Data)
Figure VIIB-8 Structure Map on B-Upper Top - Mukta Field (Based on 3D Data)
B Upper Zone - Production Test Results
Figure VIIB-9 Structure Map on B-Upper Top - Mukta Field (Based on 3D Data)
B Middle Zone - Production Test Results
Figure VIIB-10 Structure Map on B-Upper Top - Mukta Field (Based on 3D Data)
B Lower Zone - Production Test Results
Figure VIIB-11 Isochron Map at the Top of Basal Clastics (H4) - Mukta Field
(Based on 3D Data)
Figure VIIB-12 Structure Contour Map at the Top of B-Upper - B 126 Field
A Zone - Production Test Results
Figure VIIB-13 Structure Contour Map at the Top of B-Upper - B 126 Field
B Upper Zone - Production Test Results
Figure VIIB-14 Structure Contour Map at the Top of B-Upper - B 126 Field
B Middle Zone - Production Test Results
Figure VIIB-15 Structure Contour Map at the Top of B-Upper - B 126 Field
B Lower Zone - Production Test Results
Figure VIIB-16 Structure Contour Map at the Top of B-Upper - B 126 Field
Basal Clastrics - Production Test Results
Figure VIIB-17 Clay Conductance - Mukta Field
Figure VIIB-18 Type Log - Mukta Field
Figure VIIB-19 Capillary Pressure (Centrifuge) Data - Mukta Field
Figure VIIB-20 I-SW Plot
EXHIBIT 10.52
ENRON
Oil & Gas International, Inc.
P. O. Box 4672 Houston, Texas 77210-4672 (713) 853-6161 Telex 765443
Answerback: ENRONCORP
December 18, 1994
Secretary of the Government of India
Ministry of Petroleum and Natural Gas
Shastri Bhavan
New Delhi 110 001
INDIA
Gentlemen:
Based upon my review of the records of Enron Oil & Gas International,
Inc. I have determined that the guarantees issued by it in favor of the
Government, pursuant to Article Twenty-nine of two certain Production Sharing
Contracts of even date, are legally valid and enforceable.
Very truly yours,
E. J. Vandermark
Legal Advisor
EXHIBIT 10.53
CERTIFICATE
ENRON OIL & GAS INDIA LTD., formerly known as ENRON INDIA EXPLORATION COMPANY,
pursuant to its articles of incorporation and by-laws, has, by the unanimous
consent of its directors, authorized its chairman, directors, secretary,
assistant secretary, proper officers and its counsel (any one of them acting
alone), to negotiate production sharing contracts for the Tapti, Panna and Mukta
Fields, offshore India, and to execute, deliver and perform for, in the name of
and on behalf of ENRON OIL & GAS INDIA LTD.
Dated this 22nd day of December 1994.
/S/ E. J. VANDERMARK
E. J. Vandermark
Assistant Secretary
EXHIBIT 10.54
FINANCIAL AND PERFORMANCE GUARANTEE
WHEREAS ENRON OIL & GAS INTERNATIONAL, INC., a duly organized and existing under
the laws of Delaware, U.S.A., having its registered office at 1400 Smith Street,
Houston, Texas, U.S.A., (hereinafter referred to as "the Guarantor" which
expression shall include its successors and assigns) is the indirect owner of
100% of the capital stock of ENRON OIL & GAS INDIA LIMITED ("Company") and
direct owner of its parent company; and
WHEREAS Company is signatory to a Production Sharing Contract of even date of
this guarantee in respect of an Offshore area identified as Tapti Block
(hereinafter referred to as "the Contract") made between the Government of India
(hereinafter referred to as "the Government"), Company, RELIANCE INDUSTRIES
LIMITED and OIL & NATURAL GAS CORPORATION LIMITED (hereinafter referred to as
"Contractor" which expression shall include its successors and permitted
assigns); and
WHEREAS the Guarantor wishes to guarantee the performance of Company or its
Affiliate Assignee under the Contract as required by the terms of the Contract;
NOW, THEREFORE, this Deed hereby provides as follows:
1. The Guarantor hereby unconditionally and irrevocably
guarantees to the Government that it will make available, or
cause to be made available, to Company or any other directly
or indirectly owned Affiliate of Company to which any part or
all of Company's rights or interest under the Contract may
subsequently be assigned ('Affiliate Assignee'), to ensure
that Company or any Affiliate Assignee can carry out its work
commitment as set forth in the Contract.
2. The Guarantor further unconditionally and irrevocably
guarantees to the Government reasonable compliance by Company
or any Affiliate Assignee, of any obligations of Company or any
Affiliate Assignee under the Contract.
3. The Guarantor hereby undertakes to the Government that if
Company, or any Affiliate Assignee, shall, in any respect,
fail to perform its work commitments under the Contract or
commit any material breach of such obligations, then the
Guarantor shall fulfill or cause to be fulfilled the
obligations in place of Company or any Affiliate Assignee, and
will indemnify the Government against all actual losses,
damages, costs, expenses, or otherwise which may result
directly from such failure to perform or breach on the part of
Company. In no event shall Guarantor be liable for any
special consequential, indirect, incidental or punitive
damages of any kind or character, including, but not limited
to, loss of profits or revenues, loss of product or loss of
use arising out of or related to a material breach by Company
of its obligations under the Contract.
4. This guarantee shall take effect from the Effective Date and
shall remain in full force and effect for the duration of the
Contract and thereafter until no sum remains payable by Company,
or its Affiliate Assignee, under the Contract or as a result of
any decision or award made by any expert or arbitration tribunal
thereunder.
5. This guarantee shall not be affected by any change in the
Articles of Association and by-laws of Company or the Guarantor
or in any instrument establishing the Licensee.
6. The liabilities of the Guarantor shall not be discharged or
affected by (a) any time indulgence, waiver or consent given
to Company; (b) any amendment to the Contract or to any
security or other guarantee or indemnity to which Company has
agreed; (c) the enforcement or waiver of any terms of the
Contract or of any security, other guarantee or indemnity; or
(d) the dissolution, amalgamation, reconstruction or
reorganization of Company.
7. This guarantee shall be governed by and construed in accord-
ance with the laws of India.
IN WITNESS WHEREOF the Guarantor, through its duly authorized
representatives, has caused its seal to be duly affixed hereto and this
guarantee to be duly executed the 22nd day of December 1994.
The seal of Enron Oil & Gas International, Inc.
was hereto duly affixed
by E. J. Vandermark this 22nd
day of December 1994 in
accordance with its by-laws
and this guarantee was duly
signed by J. P. Kopecky
and E.J. Vandermark
as required by the said by-laws.
/S/ E. J. VANDERMARK /S/ J. A. KOPECKY
E. J. Vandermark J. A. Kopecky
Assistant Secretary Vice President
Witness:
2
EXHIBIT 10.55
JOINT OPERATING AGREEMENT
AMONG
OIL & NATURAL GAS CORPORATION LIMITED
AND
ENRON OIL & GAS INDIA LTD.
AND
RELIANCE INDUSTRIES LIMITED
WITH RESPECT TO CONTRACT AREA IDENTIFIED AS
MID-TAPTI AND SOUTH-TAPTI GAS FIELDS
<PAGE>
TABLE OF CONTENTS
ARTICLE PAGE
I Definitions ................................................. 1
II Effective Date and Term...................................... 5
III Participating Interest....................................... 6
3.1 Participating Interest................................. 6
3.2 Ownership, Obligations and Liabilities................. 6
IV Operator..................................................... 6
4.1 Designation of Operator................................ 6
4.2 Rights and Duties of Operator.......................... 6
4.3 Employees of Operator.................................. 8
4.4 Information Supplied by Operator....................... 8
4.5 Settlement of Claims and Lawsuits...................... 8
4.6 Liability of Operator.................................. 9
4.7 Insurance Obtained by Operator......................... 9
4.8 Commingling of Funds................................... 10
4.9 Resignation of Operator................................ 11
4.10 Removal of Operator.................................... 11
4.11 Appointment of Successor............................... 11
V Operating Committee.......................................... 12
5.1 Establishment of Operating Committee................... 12
5.2 Powers and Duties of Operating Committee............... 12
5.3 Authority to Vote...................................... 13
5.4 Subcommittees.......................................... 13
5.5 Notice of Meeting...................................... 13
5.6 Contents of Meeting Notice............................. 13
5.7 Location and Frequency of Meetings..................... 14
5.8 Operator's Duties for Meetings......................... 14
5.9 Voting Procedure....................................... 14
5.10 Record of Votes........................................ 14
5.11 Minutes................................................ 14
5.12 Voting by Notice....................................... 14
5.13 Effect of Vote......................................... 15
VI Work Programs and Budgets.................................... 16
6.1 Preparation of Work Program and Budget................. 16
6.2 Adoption of Work Program and Budget and
Submission to Management Committee..................... 16
6.3 Subdivision of Work Program and
Budget Items and Transfers............................. 16
6.4 Fulfillment of Minimum Work Obligations................ 17
6.5 Exploration and Appraisal.............................. 17
6.6 Development of New Discovery........................... 18
6.7 Itemization of Expenditures............................ 18
6.8 Contract Awards........................................ 19
6.9 Authorization for Expenditure ("AFE") Procedure........ 20
6.10 Supplementary AFEs..................................... 21
6.11 Approval of AFEs....................................... 21
6.12 Approval of AFE Not to be Unreasonably Withheld........ 22
6.13 Overexpenditures of Work Programs and Budgets.......... 22
6.14 Work Program and Budget for Initial Period............. 22
VII Operations By Less Than All Parties.......................... 22
7.1 Limitation on Applicability............................ 22
7.2 Procedure to Propose Exclusive Operations.............. 22
7.3 Responsibility for Exclusive Operations................ 23
7.4 Consequences of Exclusive Operations................... 24
7.5 Premium to Participate in Exclusive Operations......... 25
7.6 Order of Preference of Operations...................... 26
7.7 Stand-By Costs......................................... 26
7.8 Special Considerations Regarding
Deepening and Sidetracking............................. 27
7.9 Miscellaneous.......................................... 28
VIII Default...................................................... 29
8.1 Default and Notice..................................... 29
8.2 Operating Committee Meetings and Data.................. 29
8.3 Allocation of Defaulted Accounts....................... 29
8.4 Transfer of Interest................................... 30
8.5 Continuation of Interest............................... 31
8.6 Abandonment............................................ 31
8.7 Sale of Hydrocarbons................................... 32
8.8 No Right of Set Off.................................... 32
8.9 Minor Default.......................................... 32
8.10 Reinstatement of Rights................................ 32
IX Disposition of Production.................................... 32
9.1 Right and Obligation to Take in Kind................... 32
9.2 Offtake Agreement for Crude Oil........................ 33
9.3 Separate Agreement for Natural Gas..................... 34
X Abandonment of Wells......................................... 34
10.1 Abandonment of Wells Drilled as Joint Operations....... 34
10.2 Abandonment of Exclusive Operations.................... 34
XI Surrender.................................................... 35
11.1 Surrender.............................................. 35
XII Transfer of Interest or Rights............................... 35
12.1 Obligations............................................ 35
12.2 Rights................................................. 36
XIII Withdrawal from Agreement by Transfer or Assignment.......... 36
13.1 Right of Withdrawal.................................... 36
13.2 Partial or Complete Withdrawal......................... 36
13.3 Voting................................................. 37
13.4 Obligations and Liabilities............................ 37
13.5 Emergency.............................................. 37
13.6 Assignment............................................. 37
13.7 Approvals.............................................. 37
13.8 Abandonment Security................................... 37
13.9 Withdrawal or Abandonment by all Parties............... 38
XIV Relationship of Parties and Tax.............................. 38
14.1 Relationship of Parties................................ 38
14.2 Tax.................................................... 38
XV Confidential Information - Proprietary Technology............ 38
15.1 Confidential Information............................... 38
15.2 Continuing Obligations................................. 39
15.3 Proprietary Technology................................. 39
15.4 Trades................................................. 39
XVI Force Majeure................................................ 39
16.1 Obligations............................................ 39
16.2 Definition of Force Majeure............................ 40
XVII Notices...................................................... 40
XVIII Applicable Law and Dispute Resolution........................ 41
18.1 Applicable Law......................................... 41
18.2 Dispute Resolution..................................... 41
XIX Allocation of Cost Recovery Rights........................... 42
19.1 Allocation of Total Production......................... 42
19.2 Allocation of Cost Petroleum........................... 42
19.3 Allocation of Profit Petroleum......................... 42
19.4 Allocation of Excess Cost Petroleum.................... 42
XX General Provisions........................................... 43
20.1 Conflicts of Interest.................................. 43
20.2 Public Announcements................................... 43
20.3 Successors and Assigns................................. 43
20.4 Waiver................................................. 43
20.5 Severance of Invalid Provisions........................ 44
20.6 Modifications.......................................... 44
20.7 Headings............................................... 44
20.8 Singular and Plural.................................... 44
20.9 Gender................................................. 44
20.10 Counterpart Execution.................................. 44
20.11 Conflict with Contract................................. 44
20.12 Entirety............................................... 44
Signature Page......................................... 44
Exhibit "A" - Accounting Procedure
Exhibit "B" - Description of Contract Area
Exhibit "C" - Example
Exhibit "D" - Budget Format
Exhibit "D-1" - Budget Summary
Exhibit "D-2" - Geophysical and Geological Expense
Exhibit "D-3" - Development Drilling (Firm Wells)
Exhibit "D-4" - Production Facilities Costs
Exhibit "D-5" - Production Costs
Exhibit "D-6" - General and Administrative Expense
Exhibit "D-7" - Fixed Assets and Deposits
Exhibit "D-8" - Revenue
Exhibit "E" - Data to be Provided to Non-Operators
<PAGE>
JOINT OPERATING AGREEMENT
THIS AGREEMENT is made as of the Effective Date among OIL & NATURAL GAS
CORPORATION LIMITED, having its registered office at Tower II, 8th Floor, Jeevan
Bharti, 124 Connaught Circus, New Delhi, 110 001, India, a company incorporated
in India (hereinafter referred to as "ONGC"); ENRON OIL & GAS INDIA LTD., a
company incorporated in the Cayman Islands, having its registered office at 1400
Smith Street, Houston, Texas, 77002, U.S.A. (hereinafter referred to as
"EOGIL"), a wholly owned subsidiary of ENRON EXPLORATION COMPANY; and RELIANCE
INDUSTRIES LIMITED, a company incorporated in India, having its registered
office at 3rd Floor, Maker Chamber IV, 222 Nariman Point, Bombay, 400 021, India
(hereinafter referred to as "RIL"). The companies named above may sometimes
individually be referred to as "Party" and collectively as the "Parties".
WITNESSETH:
WHEREAS, the Parties have entered into a Production Sharing Contract (the
"Contract") with the Government of India (hereinafter referred to as
"Government") covering certain areas located offshore India known as the
Mid-Tapti and South-Tapti Gas Fields, referred to as the "Contract Area", and
more particularly described in Exhibit B to this Agreement; and
WHEREAS, the Parties desire to define their respective rights and
obligations with respect to their operations under the Contract.
NOW, THEREFORE, in consideration of the premises and the mutual covenants
and agreements and obligations set out below and to be performed, the Parties
agree as follows:
ARTICLE I - DEFINITIONS
As used in this Agreement, the following words and terms shall have the
meaning ascribed to them below:
1.1 ACCOUNTING PROCEDURE means the rules, provisions and conditions set
forth and contained in Exhibit A to this Agreement.
1.2 AFE means an authorization for expenditure pursuant to Article 6.9.
1.3 AFFILIATE means a company that directly or indirectly controls or is
controlled by a Party to this Agreement or a company which directly or
indirectly controls or is controlled by a company which controls a
Party to this Agreement, it being understood that "control" means
ownership by one company of more than fifty percent (50%) of the
voting securities of the other company, or the power to direct,
administer and dictate policies of the other company even where the
voting securities held by such company exercising such effective
control in that other company is less than fifty percent (50%) and the
term "controlled" shall have a corresponding meaning.
1.4 AGREED INTEREST RATE means interest, compounded on a monthly basis, at
the rate per annum equal to the one (1) month term, LIBOR rate for
U.S. dollar deposits, as published by THE WALL STREET JOURNAL or if
not published, then by the FINANCIAL TIMES OF LONDON, plus fixed
amounts as specified in Article 8.1, applicable on the first Business
Day prior to the due date of payment and thereafter on the first
Business Day of each succeeding one (1) month term. If the aforesaid
rate is contrary to any applicable usury law, the rate of interest to
be charged shall be the maximum rate permitted by such applicable law.
1.5 AGREEMENT means this Agreement, together with the Exhibits attached
to this Agreement.
1.6 APPRAISAL WELL means any well whose purpose at the time of
commencement of drilling such well is the determination of the extent
or the volume of Hydrocarbon reserves contained in a New Discovery or
an Existing Discovery.
1.7 BARREL means a quantity consisting of forty-two (42) United States
gallons, corrected to a temperature of sixty (60) degrees Fahrenheit
under one (1) atmosphere of pressure.
1.8 BUSINESS DAY means a day on which the banks in India are open for
business and carrying out normal business transactions.
1.9 CALENDAR QUARTER means a period of three (3) months commencing with
January 1st and ending on the following March 31st, a period of three
(3) months commencing with April 1st and ending on the following June
30th, a period of three (3) months commencing with July 1st and ending
on the following September 30th, or a period of three (3) months
commencing with October 1st and ending on the following December 31st
according to the Gregorian Calendar.
1.10 CALENDAR YEAR means a period of twelve (12) months commencing with
January 1st and ending on the following December 31st according to the
Gregorian Calendar.
1.11 CASH CALL means any request for payment of cash made by the Operator,
in accordance with this Agreement, an approved Work Program and
Budget, AFEs (wherever applicable) and progress of the work, to the
Parties in connection with the Joint Operations. The Cash Call format
(Exhibit "C") may be revised by the Operating Committee.
1.12 CASH PREMIUM means the payment made pursuant to Article 7.5(B) by a
Non-Consenting Party to reinstate its rights to participate in an
Exclusive Operation.
1.13 COMMERCIAL DISCOVERY means a Discovery of Petroleum reserves which,
when produced, are likely to yield a reasonable profit on the funds
invested in petroleum operations, after deduction of Contract costs,
and which has been declared a Commercial Discovery in accordance with
the provisions of Article 9 and/or Article 21 of the Contract, after
consideration of all pertinent operating and financial data such as
recoverable reserves, sustainable production levels, estimated
development and production expenditures, prevailing prices and other
relevant technical and economic factors according to generally
accepted practices in the international petroleum industry.
1.14 COMPLETION means an operation intended to complete a well through the
Christmas tree as a producer of Hydrocarbons in one or more Zones,
including, but not limited to, the setting of production casing,
perforating, stimulating the well and production testing conducted in
such operation. COMPLETE and other derivatives shall be construed
accordingly.
1.15 CONSENTING PARTY means a Party who agrees to participate in and pay
its share of the cost of an Exclusive Operation.
1.16 CONTRACT means the Production Sharing Contract dated 22nd DECEMBER
1994 between the Government and the Parties identified in this
Agreement and any extension, renewal or amendment thereof agreed to in
writing by the Parties.
1.17 CONTRACT AREA means as of the Effective Date the area which is
described and delineated in Exhibit B to this Agreement. The perimeter
or perimeters of the Contract Area shall correspond to that area
covered by the Contract, as such area may vary from time to time
during the term of validity of the Contract.
1.18 COST PETROLEUM means the portion of the total volume of Petroleum
produced and saved from the Contract Area which the Contractor is
entitled to take from the Contract Area in a particular period for the
recovery of Contract costs as provided in Article 13 of the Contract.
1.19 DAY means a calendar day unless otherwise specifically provided.
1.20 DEFAULTING PARTY shall have the meaning ascribed in Article 8.1.
1.21 DEEPENING means an operation whereby a well is drilled to an objective
Zone below the deepest Zone in which the well was previously drilled,
or below the deepest Zone proposed in the associated AFE, whichever is
the deeper. DEEPEN and other derivatives shall be construed
accordingly.
1.22 DELIVERY POINT shall have the meaning given in the Contract.
1.23 DEVELOPMENT AREA means that part of the Contract Area corresponding to
the area of an Oil Field or Gas Field delineated in simple geometric
shape, together with a reasonable margin of additional area
surrounding the Field consistent with petroleum industry practice and
approved by the Management Committee or the Government, as the case
may be.
1.24 DEVELOPMENT PLAN means a plan submitted by the Contractor containing
proposals required under Article 9 or Article 21 of the Contract for
the development of a Commercial Discovery which has been approved by
the Management Committee or Government.
1.25 DEVELOPMENT WELL means a well drilled, deepened, completed or
Recompleted after the date of approval of the Development Plan
pursuant to development operations or production operations for the
purposes of producing Petroleum, increasing production, sustaining
production or accelerating extraction of Petroleum including
production wells, injection wells and dry wells.
1.26 DISCOVERY means the finding, during exploration operations, of a
deposit of Petroleum not previously known to have existed, which can
be recovered at the surface in a flow measurable by conventional
petroleum industry testing methods.
1.27 EFFECTIVE DATE means the date of signing of the Contract by all
parties thereto.
1.28 ENTITLEMENT means a quantity of Hydrocarbons of which a Party has the
right and obligation to take delivery pursuant to the Contract or, if
applicable, an offtake agreement, and shall be derived from that
Party's Participating Interest in the Hydrocarbons produced after
adjustment for overlifts and underlifts.
1.29 EXCESS COST PETROLEUM shall have the meaning ascribed in Article 19.4.
1.30 EXCLUSIVE OPERATION means those operations and activities carried out
by Operator, pursuant to this Agreement, the costs of which are
chargeable to the account of less than all the Parties.
1.31 EXCLUSIVE WELL means a well drilled pursuant to an Exclusive
Operation.
1.32 EXPLOITATION AREA means the Development Area which is established
pursuant to the Contract or if the Contract does not establish an
Exploitation Area, then that part of the Contract Area which is
delineated in a Development Plan approved as a Joint Operation or as
an Exclusive Operation.
1.33 EXPLOITATION PERIOD means any and all periods of exploitation during
which the production and removal of Hydrocarbons is permitted under
the Contract.
1.34 EXPLORATION PERIOD means any and all periods of exploration set out
in the Contract.
1.35 EXPLORATION WELL means a well drilled for the purpose of searching for
undiscovered Hydrocarbon accumulations on any geological entity (be it
of structural,stratigraphic, facies or pressure nature) to at least a
depth or stratigraphic level specified in the Work Program and Budget.
1.36 FIELD means an Oil Field or a Gas Field in the Contract Area in
respect of which a Development Plan has been duly approved in
accordance with Article 9 and Article 21 of the Contract.
1.37 FINANCIAL YEAR means the period from April 1st through March 31st
of the following Calendar Year.
1.38 G & G DATA means only geological, geophysical and geochemical data and
other information that is not obtained through a well bore.
1.39 GAS FIELD means an area within the Contract Area consisting of a
single Gas reservoir or multiple Gas reservoirs all grouped on or
related to the same individual geological structure or stratigraphic
conditions, designated by the Contractor and approved by the
Government and/or Management Committee, as the case may be (to include
the maximum area of potential productivity in the Contract Area in a
simple geometric shape) in respect of which a Commercial Discovery has
been declared or a Development Plan has been approved in accordance
with Article 9 or Article 21 of the Contract.
1.40 GOVERNMENT means the Government of India and/or any state government
as the case may be.
1.41 GROSS NEGLIGENCE means any act or failure to act (whether sole, joint
or concurrent) which was intended to cause, or which was in reckless
disregard of or wanton indifference to, harmful consequences such
Party knew, or should have known, such act or failure would have had
on the safety or property of another person or entity, but shall not
include any error of judgment or mistake made by such Party in the
exercise in good faith of any function, authority or discretion
conferred on the Party employing such under this Agreement.
1.42 HYDROCARBONS means all substances including liquid and gaseous
hydrocarbons which are subject to and covered by the Contract.
1.43 JOINT ACCOUNT means the accounts maintained by Operator in accordance
with the provisions of this Agreement and of the Accounting Procedure
for Joint Operations.
1.44 JOINT OPERATIONS means those operations and activities carried out by
Operator pursuant to this Agreement, the costs of which are chargeable
to all Parties.
1.45 JOINT PROPERTY means, at any point in time, all wells, facilities,
equipment, materials, information, funds and the property held for the
Joint Account.
1.46 MANAGEMENT COMMITTEE means the committee constituted pursuant to
Article 5 of the Contract.
1.47 MINIMUM WORK OBLIGATIONS means those items contained in Exhibit "G" of
the Contract, phased year-wise as determined by the Operating
Committee and the Management Committee.
1.48 NEW DISCOVERY means a Discovery made after the Effective Date.
1.49 NON-CONSENTING PARTY means a Party who elects not to participate in
an Exclusive Operation.
1.50 NON-OPERATOR(S) means the Party or Parties to this Agreement other
than Operator.
1.51 OIL FIELD means an area within the Contract Area consisting of a
single oil reservoir or multiple oil reservoirs all grouped on or
related to the same individual geological structure, or stratigraphic
conditions, designated by the Contractor and approved by the
Government and/or the Management Committee, as the case may be (to
include the maximum area of potential productivity in the Contract
Area in a simple geometric shape) in respect of which a Commercial
Discovery has been declared and a Development Plan has been approved
in accordance with Article 9 of the Contract and a reference to an Oil
Field shall include a reference to the production of associated
natural gas from that Oil Field.
1.52 OPERATING COMMITTEE means the committee constituted in accordance
with Article V.
1.53 OPERATOR means the Party designated or otherwise appointed under
Article 4.1 to conduct Joint Operations or any successor appointed
pursuant to Article 4.11.
1.54 PARTICIPATING INTEREST means the undivided percentage interest of each
Party in the rights and obligations derived from the Contract and this
Agreement.
1.55 PARTY means any Party to this Agreement and, where the Contract so
permits, any respective successors or assigns in accordance with the
provisions of this Agreement.
1.56 PETROLEUM means crude oil and/or natural gas existing in their natural
condition (Hydrocarbons).
1.57 PETROLEUM COSTS means costs and expenses incurred by the Parties and
allowed to be recovered pursuant to the Contract.
1.58 PLUGGING BACK means a single operation whereby a deeper Zone is
abandoned in order to attempt a Completion in a shallower Zone. Plug
Back and other derivatives shall be construed accordingly.
1.59 PRODUCTION COSTS means those costs and expenditures incurred in
carrying out production operations as classified and defined in
Section 2 of the Accounting Procedure of the Contract and allowed to
be recovered in terms of Section 3 thereof.
1.60 PROFIT PETROLEUM means Petroleum produced and saved from the Contract
Area in a particular period as reduced by Cost Petroleum and
calculated as provided in Article 14 of the Contract.
1.51 RECOMPLETION means an operation whereby a Completion in one Zone is
abandoned in order to attempt a Completion in a different Zone within
the existing wellbore. RECOMPLETE and other derivatives shall be
construed accordingly.
1.62 REWORKING means an operation conducted in the wellbore of a well after
it is Completed to secure, restore or improve production in a Zone
which is currently open to production in the wellbore.
Such operations include, but are not limited to, well stimulation
operations, wire line operations, hydraulic pump-down operations,
water shut off operations, coil tubing operations, but excluding any
routine maintenance work. REWORK and other derivatives shall be
construed accordingly.
1.63 SIDETRACKING means the directional control and intentional deviation
of a well from vertical so as to change the bottom hole location
unless done to straighten the hole or to drill around junk in the hole
or to overcome other mechanical difficulties. Sidetrack and other
derivatives shall be construed accordingly.
1.64 SUPERVISORY PERSONNEL means any supervisory employee of a Party who
functions as a Party's designated manager or supervisor who is
responsible for, or in charge of onsite drilling, construction or
production and related operations, or any other field operations.
1.65 TESTING, with reference to a well, means an operation intended to
evaluate the capacity of a Zone to produce Hydrocarbons. TEST and
other derivatives shall be construed accordingly.
1.66 WILLFUL MISCONDUCT means in relation to the Operator intentional and
conscious or reckless disregard by supervisory or management staff of
the Operator of the terms of this Agreement or of good international
oil field practice but shall not include any act or omission
reasonably required to meet emergency conditions, including without
limitation the safeguarding of life, property and Joint Operations or
for the avoidance of doubt any error of judgment or mistake made by
any director, employee, agent or contractor of Operator in the
exercise, in good faith of any function, authority or discretion
conferred upon the Operator.
1.67 WORK PROGRAM AND BUDGET means a work program for Joint Operations and
budget therefor, including the production plan, as described and
approved in accordance with Article VI and as illustrated in Exhibit
"D". Exhibit "D" may be modified by the Operating Committee.
1.68 ZONE means a stratum of earth containing or thought to contain a
common accumulation of Hydrocarbons separately producible from any
other common accumulation of Hydrocarbons.
<PAGE>
ARTICLE II - EFFECTIVE DATE AND TERM
This Agreement shall have effect from the 22nd day of December, 1994 and
shall, subject always to the Parties' continuing obligations under Article XV,
continue in effect until the Contract terminates or, otherwise until all
materials, equipment and personal property used in connection with the Joint
Operations have been removed and disposed of, and final settlement has been made
among the Parties.
For the avoidance of doubt, portions of this Agreement as described in (A),
(B) and (C) below shall remain in effect until:
(A) all wells have been properly abandoned in accordance with Article X;
and
(B) all obligations, claims, arbitrations and lawsuits have been settled
or otherwise disposed of in accordance with Article 4.5 and Article
XVIII; and
(C) the time relating to the protection of confidential information and
proprietary technology has expired in accordance with Article XV.
The scope and purpose of the Joint Operations are to carry out the
petroleum operations as per Contract. As defined in the Contract, petroleum
operations means, as the context may require, exploration operations,
development operations or production operations or any combination of such
operations, including, but not limited to, collection of seismic information,
drilling and completion and recompletion of wells, construction, operation and
maintenance of all necessary facilities, plugging and abandonment of wells,
environmental protection, transportation, storage or disposition of Petroleum to
the Delivery Point, site restoration and all other incidental operations or
activities as may be necessary.
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ARTICLE III - PARTICIPATING INTEREST
3.1 PARTICIPATING INTEREST
(A) The Participating Interests of the Parties as of the Effective Date
are:
ONGC 40%
EOGIL 30%
RIL 30%
(B) If a Party transfers all or part of its Participating Interest
pursuant to the provisions of this Agreement and the Contract, the
Participating Interests of the Parties shall be revised accordingly.
3.2 OWNERSHIP, OBLIGATIONS AND LIABILITIES
(A) Unless otherwise provided in this Agreement, all the rights and
interests in and under the Contract, all Joint Property and any
Hydrocarbons produced from the Contract Area shall, subject to the
terms of the Contract, be owned by the Parties in accordance with
their respective Participating Interests.
(B) Unless otherwise provided in this Agreement, the obligations of the
Parties under the Contract and all liabilities and expenses incurred
by Operator in connection with Joint Operations shall be charged to
the Joint Account and all credits to the Joint Account shall be shared
by the Parties, as among themselves, in accordance with their
respective Participating Interests.
(C) Unless otherwise provided in this Agreement, all liabilities incurred
by any Party in connection with Joint Operations shall be borne by the
Parties in accordance with their respective Participating Interests.
(D) Each Party shall pay when due, in accordance with the Accounting
Procedure, its Participating Interest share of Joint Account expenses,
including cash advances and interest, accrued pursuant to this
Agreement. The Accounting Procedure shall govern the accrual and
satisfaction of the respective obligations, liabilities and credits
among the Parties.
ARTICLE IV - OPERATOR
4.1 DESIGNATION OF OPERATOR
EOGIL is designated as Operator, and agrees to act as an Operator in
accordance with the terms and conditions of the Contract and this
Agreement, which terms and conditions shall also apply to any
successor Operator.
4.2 RIGHTS AND DUTIES OF OPERATOR
(A) Subject to the terms and conditions of this Agreement, Operator shall
have all of the rights, functions and duties of Operator under the
Contract and shall have exclusive charge of and shall conduct all
Joint Operations. Operator may employ independent contractors,
Affiliates and/or agents in such Joint Operations. Contracts will be
awarded pursuant to Article 6.8.
(B) In the conduct of Joint Operations, Operator shall:
(1) Perform Joint Operations in accordance with the provisions of the
Contract, this Agreement and the instructions of the Operating
Committee;
(2) Conduct all Joint Operations in a diligent, safe and efficient
manner in accordance with good and prudent international
petroleum industry practices and conservation principles
generally followed by the international petroleum industry
under similar circumstances;
(3) Subject to Article 4.6, neither gain a profit nor suffer a loss
as a result of being the Operator in its conduct of Joint
Operations;
(4) Perform the duties for the Operating Committee set out in
Article V, and prepare and submit to the Operating Committee
the proposed Work Programmes and Budgets and AFEs as provided
in Article VI;
(5) Acquire all permits, consents, approvals, surface or other
rights that may be required for or in connection with the
conduct of Joint Operations;
(6) Permit the representatives of any of the Parties to have at all
reasonable times and at their own risk and expense reasonable
access to the Joint Operations with the right to observe all such
Joint Operations and to inspect all Joint Property and to conduct
financial audits as provided in the Accounting Procedure. In the
case of offshore operations, transportation and accommodations
shall be made available from existing facilities if, in the sole
discretion of Operator, no additional cost will be incurred by
Operator. In addition, provide for two (2) permanent
representatives of each of the Non-Operators to have access to
the Contract Area and/or to the Joint Operations at all times and
provide all facilities including, but not limited to,
transportation and offshore accommodations at the cost of the
Joint Operations. Such representatives shall look after the
interests of Non-Operators/Joint Operation, but shall not
interfere with operations;
(7) Maintain the Contract in full force and effect. Operator shall
promptly pay and discharge all liabilities and expenses incurred
in connection with Joint Operations and use its reasonable
efforts to keep and maintain the Joint Property free from all
liens, charges and encumbrances arising out of Joint Operations;
(8) Pay to the Government for the Joint Account, within the periods
and in the manner prescribed by the Contract and all applicable
laws and regulations, all periodic payments, royalties, taxes,
fees and other payments pertaining to Joint Operations, but
excluding any taxes measured by the incomes of the Parties;
(9) Carry out the obligations of Operator pursuant to the Contract,
including, but not limited to, preparing and furnishing such
reports, records and information as may be required pursuant to
the Contract;
(10) Have in accordance with the decisions of the Operating Committee,
the exclusive right and obligation to represent the Parties in
all dealings with the Government with respect to matters arising
under the Contract and Joint Operations. Operator shall notify
the other Parties as soon as possible of such meetings.
Non-Operators shall have the right to attend such meetings.
Nothing contained in this Agreement shall restrict any Party from
holding discussions with the Government with respect to any issue
peculiar to its particular business interests arising under this
Agreement, but in such event such Party shall promptly advise the
Parties, if possible, before and in any event promptly after such
discussions, provided that such Party shall not be required to
divulge to the Parties any matters discussed to the extent the
same involve proprietary information on matters not affecting the
Parties; and
(11) Take all necessary and proper measures for the protection of
life, health, the environment and property in the case of an
emergency; provided, however, that Operator shall immediately
notify the Parties of the details of such emergency and measures.
(12) Include, to the extent practical, in its contracts with
independent contractors and to the extent lawful, provisions
which:
(a) ensure such contractors can only enforce their contracts
against Operator;
(b) permit Operator, on behalf of itself and Non-Operators, to
enforce contractual indemnities against, and recover losses
and damages suffered by them (insofar as recovered under
their contracts) from such contractors; and
(c) require such contractors to take insurance required by
Article 4.7(F).
(13) Carry out all Petroleum operations as per the standard offshore
safety practices following the environmental/mining
regulations/statutory laws.
(14) Provide liaison between field operations and gas/oil purchasers
and transporters.
4.3 EMPLOYEES OF OPERATOR
Subject to the Contract and this Agreement, Operator shall determine the
number of employees, the selection of such employees, the hours of work and the
compensation to be paid to all such employees in connection with Joint
Operations. Operator shall employ only such employees, agents and contractors as
are reasonably necessary to conduct Joint Operations.
4.4 INFORMATION SUPPLIED BY OPERATOR
(A) Operator shall provide Non-Operators the following data and reports as
they are currently produced or compiled from the Joint Operations as
well as the reports listed in Exhibit "E":
(1) Copies of all logs or surveys;
(2) Daily drilling progress reports;
(3) Copies of all drill stem tests and core analysis reports;
(4) Copies of the plugging reports;
(5) Engineering studies, development schedules and annual
progress reports on development projects;
(6) Field and well performance reports, including reservoir
studies;
(7) Copies of all reports and data relating to Joint Operations
furnished by Operator to the Government, except magnetic
tapes which shall be stored by Operator and made available
for inspection and/or copying at the sole expense of the
Non-Operator requesting same;
(8) Other reports as frequently as is justified by the
activities or as instructed by the Operating Committee; and
(9) Subject to Article 15.3, such additional information for
Non-Operators as they or any of them may request, provided
that the requesting Party or Parties pay the costs of
preparation of such information and that the preparation of
such information will not unduly burden Operator's
administrative and technical personnel. Only Non-Operators
who pay such costs shall receive such additional
information.
(B) Operator shall give Non-Operators access at all reasonable times to
all other data acquired in the conduct of Joint Operations. Any
Non-Operator may make copies of such other data at its sole expense.
(C) ONGC shall provide all of the information identified above and
currently in its possession relating to the Contract Area to the
Operator upon payment of mutually agreed costs.
4.5 SETTLEMENT OF CLAIMS AND LAWSUITS
(A) Operator shall promptly notify the Parties of any and all material
claims or suits and such other claims and suits as the Operating
Committee may direct which arise out of Joint Operations or relate in
any way to Joint Operations. Operator shall represent the Parties and
defend or oppose the claim or suit. Operator may in its sole
discretion compromise or settle any such claim or suit or any related
series of claims or suits for an amount not to exceed the equivalent
of U.S. dollars fifty thousand (US$50,000) exclusive of legal fees.
Operator shall obtain the approval and direction of the Operating
Committee on amounts in excess of the above stated amount. Each
Non-Operator shall have the right to be represented by its counsel at
its expense in the settlement, compromise or defense of such claims or
suits.
(B) Any Non-Operator shall promptly notify the other Parties of any claim
made against such Non-Operator by a third party relating to or which
may affect the Joint Operations and insofar as such claim relates to
or affects the Joint Operations such Non-Operator shall defend or
settle the same in accordance with any directions given by the
Operating Committee and such costs, expenses and damages as are
payable pursuant to such defense or settlement shall be for the Joint
Account.
(C) Notwithstanding Article 4.5(A) and Article 4.5(B), each Party shall
have the right to participate in any such pursuit, prosecution,
defense or settlement conducted in accordance with Article 4.5(A)
and/or Article 4.5(B) at its sole cost and expense; provided always
that no Party may settle its Participating Interest share of any claim
without first satisfying the Operating Committee that it can do so
without prejudicing the interests of the Joint Operations.
4.6 LIABILITY OF OPERATOR
(A) Except as set out in this Article 4.6, the Party designated as
Operator shall bear no cost, expense or liability resulting from
performing the duties and functions of the Operator. Nothing in this
Article shall, however, be deemed to relieve the Party designated as
Operator from any cost, expense or liability for its Participating
Interest share of Joint Operations.
(B) The Parties shall be liable in proportion to their Participating
Interests and shall defend and indemnify Operator, Non-Operator and
their agents, employees, officers and directors (the "Indemnitees")
from any and all costs, expenses (including reasonable attorneys'
fees) and liabilities incident to claims, demands or causes of action
of every kind and character brought by or on behalf of any person or
entity for damage to or loss of property or the environment, or for
injury to, illness or death of any person or entity, which damage,
loss, injury, illness or death arises out of or is incident to any act
or failure to act by Indemnitees in the conduct of or in connection
with Joint Operations regardless of the cause of such damage, loss,
injury, illness or death and even though caused in whole or in part by
a pre-existing defect, the negligence (whether sole, joint or
concurrent), Gross Negligence, strict liability or other legal fault
of Operator or Non-Operator (or any such Affiliate performing services
for Operator or Non-Operator pursuant to Sections 2.4.2 and 3 of the
Accounting Procedure); provided that if any Supervisory or management
Personnel of Operator or Non-Operator or any such Affiliates, engage
in Gross Negligence and/or Willful Misconduct that proximately causes
the Parties to incur cost, expense or liability for such damage, loss,
injury, illness or death, then Operator or Non-Operator, as the case
may be, shall bear all such costs, expenses and liabilities.
4.7 INSURANCE OBTAINED BY OPERATOR
(A) Operator shall procure and maintain or cause to be procured and
maintained for the Joint Account all insurance in the types and
amounts required by the Contract and applicable laws, rules and
regulations.
(B) Operator shall obtain such further insurance, at competitive rates, as
the Operating Committee may from time to time require.
(C) Any Party may elect not to participate in the insurance to be procured
under Article 4.7(B) provided such Party:
(1) gives prompt written notice to that effect to Operator;
(2) does nothing which may interfere with Operator's
negotiations for such insurance for the other Parties; and
(3) obtains and maintains such insurance (in respect of which an
annual certificate of adequate coverage from a reputable
insurance broker shall be sufficient evidence) or other
evidence of financial responsibility which fully covers its
Participating Interest share of the risks that would be
covered by the insurance procured under Article 4.7 (B), and
which the Operating Committee may determine to be
acceptable. No such determination of acceptability shall in
any way absolve a non-participating Party from its
obligation to meet each cash call including any cash call in
respect of damages and losses and/or the costs of remedying
the same in accordance with the terms of this Agreement. If
such Party obtains other insurance, such insurance shall
contain a waiver of subrogation in favor of all the other
Parties, but only in respect of their interests under this
Agreement.
(D) The cost of insurance in which all the Parties are participating shall
be for the Joint Account and the cost of insurance in which less than
all the Parties are participating shall be charged to the Parties
participating in proportion to their respective Participating
Interests.
(E) Operator shall, in respect of all insurance obtained pursuant to this
Article:
(1) promptly inform the participating Parties when such
insurance is obtained and supply them with copies of the
relevant policies when the same are issued;
(2) arrange for the participating Parties, according to their
respective Participating Interests, to be named as
co-insureds on the relevant policies with waivers of
subrogation in favor of all the Parties; and
(3) duly file all claims and take all necessary and proper steps
to collect any proceeds and credit any proceeds to the
participating Parties in proportion to their respective
Participating Interests.
(F) Operator shall use its reasonable efforts to require all contractors
performing work in respect of Joint Operations to obtain and maintain
any and all insurance in the types and amounts required by any
applicable laws, rules and regulations or any decision of the
Operating Committee and shall use its reasonable efforts to require
all such contractors to name the Parties as additional insureds on
contractor's insurance policies or to obtain from their insurers
waivers of all rights or recourse against Operator and Non-Operators.
4.8 COMMINGLING OF FUNDS
Operator shall not commingle with its funds the monies which it receives
for the Joint Account pursuant to this Agreement. The Operator shall account to
the Non-Operators for the monies of a Non-Operator advanced or paid to Operator,
whether for the conduct of Joint Operations or as proceeds from the sale of
production under this Agreement. Such monies shall be applied only to their
intended use and shall in no way be deemed to be funds belonging to Operator.
The Operator shall open and maintain dedicated current and/or deposit
accounts in respect of funds in Indian Rupees, United States Dollars and/or any
other currency at a bank or banks in India, the United States or elsewhere, in
order to deposit and hold funds on behalf of the Parties exclusively for Joint
Operations. Where possible, such accounts shall be interest bearing.
Upon opening a bank account, the Operator shall notify the Non-Operators
the name and address of the bank and the account number. Any changes thereafter
should be promptly notified by the Operator to the Non-Operators.
4.9 RESIGNATION OF OPERATOR
Subject to Article 4.11, Operator may resign as Operator at any time after
completion of the Minimum Work Obligation, unless the Parties agree to an
earlier date, by so notifying the other Parties at least one hundred and twenty
(120) Days prior to the effective date of such resignation.
4.10 REMOVAL OF OPERATOR
(A) Subject to Article 4.11, Operator shall be removed upon receipt of
notice from any Non-Operator if:
(1) An order is made by a court or an effective resolution is
passed for the dissolution, liquidation, winding up, or
reorganization of Operator;
(2) Operator dissolves, liquidates or terminates its corporate
existence;
(3) Operator becomes insolvent, bankrupt or makes an assignment
for the benefit of creditors; or
(4) A receiver is appointed for a substantial part of Operator's
assets.
(5) Operator, together with any Affiliate of Operator, is or
becomes the holder of a Participating Interest of less then
twenty percent (20%).
(6) There is a direct or indirect change in control of Operator
(other than a transfer of control to an Affiliate of
Operator). For purposes of this Article control means the
ownership directly or indirectly of more than fifty percent
(50%).
(B) Subject to Article 4.11, Operator may be removed by the decision of
the Non-Operators if Operator has committed a material breach of this
Agreement which Operator has failed to rectify within ninety (90) Days
of receipt of a notice from Non-Operators detailing the alleged
breach. Any decision of Non-Operators to give notice of breach to
Operator or to remove Operator under this Article 4.10(B) shall be
made by an affirmative vote of two (2) or more of the total number of
Non-Operators holding a combined Participating Interest of at least
fifty percent (50%).
Notwithstanding the above, in case of disagreement between the
Non-Operators on giving notice to the Operator, any Non-Operator may, with the
approval of the Government, give notice to the Operator.
4.11 APPOINTMENT OF SUCCESSOR
When a change of Operator occurs pursuant to Article 4.9 or Article 4.10:
(A) The Operating Committee shall meet as soon as possible to appoint a
successor Operator pursuant to the voting procedure of Article 5.9.
However, no Party may be appointed successor Operator against its
will.
(B) If the Operator disputes commission of or failure to rectify a
material breach alleged pursuant to Article 4.10(B) and proceedings
are initiated pursuant to Article XVIII, no successor Operator may be
appointed pending the conclusion or abandonment of such proceedings
provided, however, if the arbitrators determine that the Joint
Operations are likely to suffer material and/or irreparable harm, they
shall have the right to issue an interim order suspending the Operator
and appointing a successor Operator.
(C) If an Operator is removed neither Operator nor any Affiliate of
Operator shall have the right to vote for itself on the appointment of
a successor Operator, nor be considered as a candidate for the
successor Operator.
(D) A resigning or removed Operator shall be compensated out of the Joint
Account for its reasonable expenses directly related to its
resignation or removal, except in the case of Article 4.10.
(E) The Operating Committee shall arrange for the taking of an independent
inventory of all Joint Property and Hydrocarbons, and an audit of the
books and records of the removed or resigned Operator. Such inventory
and audit shall be completed, if possible, no later than the effective
date of the change of Operator. The liabilities and expenses of such
inventory and audit shall be charged to the Joint Account.
(F) The resignation or removal of Operator and its replacement by the
successor Operator shall not become effective prior to receipt of any
necessary governmental approvals.
(G) Upon the effective date of the resignation or removal, the successor
Operator shall succeed to all duties, rights and authority prescribed
for Operator. The former Operator shall transfer to the successor
Operator custody of all Joint Property, books of account, records and
other documents maintained by Operator pertaining to the Contract Area
and to Joint Operations. Upon delivery of the above-described property
and data, the former Operator shall be released and discharged from
all obligations and liabilities as Operator accruing after such date.
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ARTICLE V - OPERATING COMMITTEE
5.1 ESTABLISHMENT OF OPERATING COMMITTEE
To provide for the overall supervision and direction of Joint Operations,
there is established an Operating Committee composed of representatives of each
Party holding a Participating Interest. Each Party shall appoint one (1)
representative and one (1) alternate representative to serve on the Operating
Committee. Each Party shall as soon as possible after the date of this Agreement
give notice in writing to the other Parties of the name and address of its
representative and alternate representative to serve on the Operating Committee.
Each Party shall have the right to change its representative and alternate at
any time by giving proper notice to such effect to the other Parties.
5.2 POWERS AND DUTIES OF OPERATING COMMITTEE
The Operating Committee shall have power and duty to authorize and
supervise Joint Operations that are necessary or desirable to fulfill the
Contract and properly explore and exploit the Contract Area in accordance with
this Agreement and in a manner appropriate in the circumstances. The Operating
Committee is the coordinating body for the direction, control and administration
of the Joint Operations. The principal functions of the Operating Committee
shall be:
(A) To establish policies from time to time governing various aspects or
activities of the Joint Operations.
(B) To review, approve and revise annual exploration Work Programs and
corresponding budgets, as proposed by the Operator.
(C) To review reports on Joint Operations conducted in the Contract Area
including the status of all existing facilities, safety, environmental
aspects and equipment availability.
(D) To review and approve any proposal for the appraisal of an area.
(E) To review, revise and approve Work Programs and Budgets for petroleum
operations as defined in the Contract and as proposed by the Operator.
(F) To review and approve Exploration, Appraisal and Development Wells and
locations (including locations for wells required for any purposes
whatsoever), and transfer of exploitation objectives, Reworking and
abandonment of wells.
(G) To review and approve well stimulation programs.
(H) To review and determine the area to be relinquished, if any.
(I) To approve appointment of contractors for carrying out any petroleum
operations by Operator beyond the authority vested in the Operator
under this Agreement.
(J) To review and approve such other matters with respect to petroleum
operations in the Contract Area as may be referred to the Operating
Committee by any member of the Operating Committee.
(K) To refer to the Management Committee and/or the Government whenever
applicable matters which require advice or approval of the Management
Committee and/or the Government pursuant to the Contract.
(L) To review summary operating costs.
5.3 AUTHORITY TO VOTE
(A) The representative of a Party, or in his absence his alternate
representative, shall be authorized to represent and bind such Party
with respect to any matter which is within the powers of the Operating
Committee and is properly brought before the Operating Committee. Each
such representative shall have a vote equal to the Participating
Interest of the Party such person represents. Each alternate
representative shall be entitled to attend all Operating Committee
meetings but shall have no vote at such meetings except in the absence
of the representative for whom he is the alternate. In addition to the
representative and alternate representative, each Party may also bring
to any Operating Committee meetings such technical and other advisors
as it may deem appropriate.
(B) Any representative shall be entitled, if either he or his alternate is
unable to attend a meeting, to cast his vote by telex or facsimile
transmission received prior to the time that the vote is taken in the
course of the meeting.
(C) Any representative may by notice to all other representatives, appoint
a representative of another Party who consents to such appointment as
its proxy to attend a meeting and to exercise the appointing
representative's right to vote at that meeting whether as directed by
the appointing representative or otherwise. A representative appointed
as a proxy and attending a meeting may be present in two (2) separate
capacities and may vote accordingly.
5.4 SUBCOMMITTEES
The Operating Committee may establish such subcommittees, including
technical subcommittees, as the Operating Committee may deem
appropriate. The functions of such subcommittees shall be in an
advisory capacity or as otherwise determined unanimously by the
Parties.
5.5 NOTICE OF MEETING
(A) Operator may call a meeting of the Operating Committee by giving
notice to the Parties at least fifteen (15) Days in advance of such
meeting.
(B) Any Non-Operator may request a meeting of the Operating Committee by
giving proper notice to all the other Parties. Upon receiving such
request, Operator shall call such meeting for a date not less than
fifteen (15) Days nor more than twenty (20) Days after receipt of the
request.
(C) The notice periods above may be waived at the request of Operator or
any Non-Operator with the unanimous consent of all the Parties. In the
event of a likely material adverse financial impact to the Joint
Operation, no Party may unreasonably withhold waiving the notice
period.
5.6 CONTENTS OF MEETING NOTICE
(A) Each notice of a meeting of the Operating Committee as provided by
Operator shall contain:
(1) The date, time and location of the meeting; and
(2) An agenda of the matters and proposals to be considered
and/or voted upon.
(B) A Party, by notice to the other Parties given not less than seven (7)
Days prior to a meeting, may add additional matters to the agenda for
a meeting.
(C) On the request of a Party, and with the unanimous consent of all
Parties, the Operating Committee may consider at a meeting a proposal
not contained in such meeting agenda.
5.7 LOCATION AND FREQUENCY OF MEETINGS
All meetings of the Operating Committee shall be held in Bombay, India, or
elsewhere as may be decided by the Operating Committee. The Operating Committee
shall meet at least once each two (2) months during the first six (6) months
following the Effective Date unless otherwise agreed. Thereafter, the Operating
Committee shall meet once every three (3) months unless otherwise agreed.
5.8 OPERATOR'S DUTIES FOR MEETINGS
(A) With respect to meetings of the Operating Committee and any
subcommittee, Operator's duties shall include, but not be limited to:
(1) Timely preparation and distribution of the agenda;
(2) Organization and conduct of the meeting; and
(3) Preparation of a written record or minutes of each meeting.
(B) Operator shall have the right to appoint the chairman of the Operating
Committee and all subcommittees.
5.9 VOTING PROCEDURE
Except as otherwise expressly provided in this Agreement, all decisions,
approvals and other actions of the Operating Committee on all proposals coming
before it under this Agreement shall be decided by the affirmative vote of the
Parties then having collectively one hundred percent (100%) of the Participating
Interests. In the event the Operating Committee cannot agree upon a Work Program
and Budget relating to the Minimum Work Obligation, the matter shall be referred
to the Management Committee by any Party for review and decision. The Management
Committee shall decide such issue within twenty (20) Days or as otherwise
mutually agreed. If all of the Parties do not agree with the Management
Committee decision, the Parties in agreement shall be entitled to proceed in
accordance with Article VII hereof. If the Management Committee cannot agree,
the matter shall be referred to arbitration or a sole expert.
5.10 RECORD OF VOTES
The chairman of the Operating Committee shall appoint a secretary who shall
make a record of each proposal voted on and the results of such voting at each
Operating Committee meeting. Each representative shall sign and be provided a
copy of such record at the end of such meeting and it shall be considered the
final record of the decisions of the Operating Committee.
5.11 MINUTES
The secretary shall provide each Party with a copy of the minutes of the
Operating Committee meeting within ten (10) Days after the end of the meeting.
Each Party shall have ten (10) Days after receipt of such minutes to give notice
of its objections to the minutes to the secretary. A failure to give notice
specifying objection to such minutes within said ten (10) Day period shall be
deemed to be approval of such minutes. In any event, the votes recorded under
Article 5.10 shall take precedence over the minutes described above.
5.12 VOTING BY NOTICE
(A) In lieu of a meeting, Operator may submit any proposal for a decision
of the Operating Committee by giving each representative proper notice
describing the proposal so submitted. Each Party shall communicate its
vote by proper notice to Operator and the other Parties within one of
the following appropriate time periods after receipt of Operator's
notice:
(1) Twenty-four (24) hours in the case of operations which
involve the use of a drilling rig that is standing by in the
Contract Area.
(2) Thirty (30) Days in the case of all other proposals.
(3) Thirty (30) Days in the case of an AFE or supplemental AFE
if submitted pursuant to Article 6.9(A).
(B) Except in the case of Article 5.12(A)(1), any Non-Operator may by
notice delivered to all Parties within twenty (20) Days of receipt of
Operator's notice request that the proposal be decided at a meeting
rather than by notice. In such an event, that proposal shall be
decided at a meeting duly called for that purpose.
(C) Except as provided in Article X, any Party failing to communicate its
vote in a timely manner shall be deemed to have voted against such
proposal.
(D) If a meeting is not requested, then at the expiration of the
appropriate time period, Operator shall give each Party a confirmation
notice stating the tabulation and results of the vote.
5.13 EFFECT OF VOTE
All decisions taken by the Operating Committee pursuant to this Article,
shall be conclusive and binding on all the Parties, except that:
(A) If pursuant to this Article, a Joint Operation has been properly
proposed to the Operating Committee and the Operating Committee has
not approved such proposal in a timely manner, then any Party shall
have the right for the appropriate period specified below to propose
in accordance with Article VII, an Exclusive Operation involving
operations essentially the same as those proposed for such Joint
Operation. No Exclusive Operation shall be conducted which conflicts
with a Joint Operation.
(1) For proposals involving the use of a drilling rig that is
standing by in the Contract Area, such right shall be
exercisable for twenty-four (24) hours after the time
specified in Article 5.12(A)(1) has expired.
(2) For proposals to develop a Discovery, such right shall be
exercisable for ten (10) Days after the date the Operating
Committee was required to consider such proposal pursuant to
Article 5.6 or Article 5.12;
(3) For all other proposals, such right shall be exercisable for
five (5) Days after the date the Operating Committee was
required to consider such proposal pursuant to Article 5.6
or Article 5.12.
(B) If a Party voted against any proposal to be conducted as an Exclusive
Operation pursuant to Article VII, then such Party shall have the
right not to participate in the operation contemplated by such
approval. Any such Party wishing to exercise its right of non-consent
must give notice of non-consent to all other Parties within five (5)
Days (or within twenty-four (24) hours if the drilling rig to be used
in such operation is standing by in the Contract Area) following
Operating Committee approval of such proposal. The Parties that were
not entitled to give or did not give notice of non-consent shall be
Consenting Parties as to the operation contemplated by the Operating
Committee approval, and shall conduct such operation as an Exclusive
Operation under Article VII. Any Party that gave notice of non-consent
shall be a Non-Consenting Party as to such Exclusive Operation.
(C) If the Consenting Parties to an Exclusive Operation under Article
5.13(A) or Article 5.13(B) concur, then the Operating Committee may,
at any time, pursuant to this Article, reconsider and approve, decide
or take action on any proposal that the Operating Committee declined
to approve earlier, or modify or revoke an earlier approval, decision
or action.
(D) Once a Joint Operation for the drilling, Deepening, Testing,
Sidetracking, Plugging Back, Completing, Recompleting, Reworking or
plugging of a well, has been approved and commenced, such operation
shall not be discontinued without the consent of the Operating
Committee; provided, however, that such operation may be discontinued,
if:
(1) an impenetrable substance or other condition in the hole is
encountered which in the reasonable judgment of Operator,
after consultation with the Non-Operators, causes the
continuation of such operation to be impractical; or
(2) other circumstances occur which in the reasonable judgment
of Operator causes the continuation of such operation to be
unwarranted and after notice the Operating Committee within
the period required under Article 5.12(A)(1) approves
discontinuing such operation.
On the occurrence of either of the events listed under Article
5.13(D)(1) or Article 5.13(D)(2), Operator shall promptly notify
the Parties with all available details that such operation is
being discontinued pursuant to the foregoing, and any Party shall
have the right to propose in accordance with Article VII an
Exclusive Operation to continue such operation.
ARTICLE VI - WORK PROGRAMS AND BUDGETS
In the conduct of Joint Operations, Operator shall perform Joint Operations
in accordance with the provisions of the Contract, this Agreement and the
instructions of the Operating Committee and conduct all Joint Operations in a
diligent, safe and efficient manner in accordance with international petroleum
industry practices and conservation principles generally followed by the
international petroleum industry under similar circumstances.
6.1 PREPARATION OF WORK PROGRAM AND BUDGET
Subject to Article 6.14, on or before the first (1st) Day of November of
each Year, the Operator shall submit to the Parties a recommended Work Program
and Budget containing the Minimum Work Obligation for the Contract Area for the
subsequent Financial Year as per Exhibit "D". At the same time as that Financial
Year's Work Program and Budget is submitted, a provisional Work Program and
Budget containing the Minimum Work Obligation for the next succeeding Financial
Year shall be presented by the Operator.
6.2 ADOPTION OF WORK PROGRAM AND BUDGET AND SUBMISSION TO MANAGEMENT
COMMITTEE
Subject to Article 6.14, on or before the first (1st) of December of each
year, the Operating Committee shall agree upon and adopt a Work Program and
Budget for the subsequent Financial Year. At the time of agreeing upon and
adopting a Work Program and Budget, the Operating Committee shall provisionally
consider, but not act upon or adopt, a Work Program and Budget for the next
succeeding Financial Year. As soon as possible after the adoption of a Work
Program and Budget, Operator shall provide a copy thereof to each Party. The
Operator shall timely submit such Work Programs and Budgets to the Management
Committee as required pursuant to Articles 4.2 and 5.6 of the Contract. Any
proposed revision of a Work Program and Budget submitted to the Operating
Committee shall be considered by the Operating committee within twenty-eight
(28) Days after its submission and, to the extent same is approved, shall be
submitted by the Operator for consideration by the Management Committee pursuant
to Article 4.3 of the Contract.
6.3 SUBDIVISION OF WORK PROGRAM AND BUDGET AND BUDGET ITEMS AND TRANSFERS
Each Work Program and Budget shall be subdivided, as illustrated in Exhibit
"D", to include three (3) major functional categories: Exploration and
Appraisal, Development and Production; and each of those categories shall be
further subdivided into subcategories consisting of one or more individual
projects/programmed activities. Purchases of materials and supply inventory not
specifically made for a designated project/programmed activity shall be budgeted
as a separate item. Each individual project/programmed activity shall be
identified as either "Firm" or "Contingent" depending upon the degree of
complete details furnished at the time of presentation of the Work Program and
Budget.
(A) For a project to be considered "Firm" within the budget, it will
require program description, objectives and cost estimate along with
the basis therefor, sufficiently complete and in such detail as to
allow thorough evaluation of the project. (B) Projects which do not
meet the requirements of Article 6.3(A) at the time the Work Program
and Budget is approved by the Operating Committee may also be included
in the Work Program and Budget for approval in principle and such
projects shall be considered "Contingent". Such projects shall not be
implemented without approval of the Operating Committee except as
provided in this Article 6.3(B). Any project or group of projects
shall be transferred from Contingent to Firm upon approval of the
Operating Committee. From time to time throughout the Financial Year,
the Operator shall endeavour to provide further specific information
necessary for the Operating Committee to evaluate Contingent projects
for the purpose of such transfer. Upon receipt of such information,
Parties may not unreasonably withhold approval for the transfer of a
project from the Contingent to the Firm category. In the event the
Operating Committee is unable to agree, the matter shall be submitted
by any Party to the Management Committee for approval. A project not
in the Minimum Work Obligation which fails to obtain Operating
Committee approval for transfer may be transferred by any Party
provided that Party is prepared to undertake the project as an
Exclusive Operation pursuant to Article VII.
6.4 FULFILLMENT OF MINIMUM WORK OBLIGATION
Parties shall not unreasonably withhold approval of the projects/programmed
activities covered in the annual Work Program and Budget as Minimum Work
Obligations or at least that part of such Minimum Work Obligations required to
be carried out to maintain the Contract in force. In case of failure of the
Operating Committee to approve the Work Program and Budget related to
projects/programmed activities included under Minimum Work Obligations, any
Party may refer the issue to the Management Committee for approval.
6.5 EXPLORATION AND APPRAISAL
Parties acknowledge and agree that neither exploration nor appraisal work
may be conducted within any Field which is so designated as of the Effective
Date.
(A) Notwithstanding the foregoing, Exploration and/or Appraisal Wells may
be proposed without limitation as to location, provided, however, that
if such location is within a Development Area, such well shall not be
commenced without prior approval of the Operating Committee. In the
event such well within the Development Area includes an objective Zone
which is the stratigraphic equivalent of the Zone or Zones included in
the Field and the location is outside the Field, then, provided that
production from such Zone does not interfere with production from the
Zone/Zones developed or to be developed in the Field, Operating
Committee approval shall not be unreasonably withheld.
(B) If the proposed Work Program and Budget includes an Exploration Well
and/or Appraisal Well, the budget approval shall include the cost of
drilling, completing and testing such Exploration/Appraisal Well. For
this purpose the Operator shall provide necessary details/information
required for the Operating Committee to assess the need/desirability
of such Exploration/Appraisal Well.
(C) If a New Discovery is made, Operator shall deliver any notice of New
Discovery required under the Contract and shall, as soon as possible,
submit to the Parties a report containing available details concerning
the New Discovery and Operator's recommendation as to whether the New
Discovery merits appraisal. The Operating Committee shall meet and
decide within forty-five (45) Days whether the New Discovery merits
appraisal. If the Operating Committee determines that the New
Discovery merits appraisal, Operator, within thirty (30) Days, shall
deliver to the Parties a proposed Work Program and Budget for the
appraisal of the New Discovery. Within twenty (20) Days of such
delivery, or earlier if necessary to meet any applicable deadline
under the Contract, the Operating Committee shall meet to consider,
modify and then either approve or reject the appraisal Work Program
and Budget. If the appraisal Work Program and Budget is approved by
the Operating Committee, Operator shall take such steps as may be
required under the Contract to secure approval of the appraisal Work
Program and Budget by the Management Committee and/or the Government,
whichever is applicable. In the event the Management Committee and/or
the Government, whichever is applicable, requires changes in the
appraisal Work Program and Budget,the matter shall be resubmitted to
the Operating Committee for further consideration.
(D) Any Party desiring to propose a Completion attempt, or an alternative
Completion attempt, must do so within the time period provided in
Article 5.12(A)(1) by notifying all other Parties. The Operator shall
prepare the AFE for such Completion costs and provide same to the
Parties.
6.6 DEVELOPMENT OF NEW DISCOVERY
(A) If the Operating Committee determines that a Discovery may be
commercial, the Operator shall, as soon as practicable, but not later
than ninety (90) Days after completing the appraisal referred to in
Article 6.5(C), deliver to the Parties a Development Plan together
with the Work Program and Budget for the remainder of the Financial
Year and a provisional Work Program and Budget for the next succeeding
Financial Year along with annual projections for the remainder of the
development of the New Discovery. The Work Programs and Budgets
proposed by the Operator shall contain, inter alia:
(1) Details of the proposed work to be undertaken, personnel
required and expenditures to be incurred, including the
timing of same, on a Financial Year basis;
(2) An estimated date for the commencement of production;
(3) A delineation of the proposed Exploitation Area; and
(4) Any other information requested by the Operating Committee.
(B) After receipt of the Development Plan, or earlier if necessary to meet
any applicable deadline under the Contract, the Operating Committee
shall meet to consider, modify and then either approve or reject
within ninety (90) Days the Development Plan and the Work Program and
Budget for the remainder of the Financial Year for the development
submitted by Operator. If the Development Plan is approved by the
Operating Committee, Operator shall, as soon as possible, deliver any
notice of Commercial Discovery required under the Contract and take
such other steps as may be required under the Contract to secure
approval of the Development Plan by the Management Committee and/or
Government, whichever is applicable. In the event the Management
Committee and/or Government, whichever is applicable, requires changes
in the Development Plan, the matter shall be resubmitted to the
Operating Committee for further consideration. If the Development Plan
is approved, such work shall be incorporated into and form part of the
annual Work Programs and Budgets.
6.7 ITEMIZATION OF EXPENDITURES
(A) During the preparation of the proposed Work Programs and Budgets and
Development Plans contemplated in this Article, Operator shall consult
with the Operating Committee regarding the contents of such Work
Programs and Budgets and Development Plans.
(B) Each Work Program and Budget and Development Plan submitted by
Operator shall contain an itemized estimate of the costs of Joint
Operations and all other expenditures to be made for the Joint Account
during the Financial Year in question.
(C) The Work Program and Budget shall designate the portion or portions of
the Contract Area in which Joint Operations itemized in such Work
Program and Budget are to be conducted and shall specify the kind and
extent of such operations in such detail as the Operating Committee
may deem suitable.
6.8 CONTRACT AWARDS
(A) Operator shall award, except for an award to an Affiliate, each
contract for Joint Operations on the following basis (the amounts
stated are in thousands of U.S. dollars):
PROCEDURE A PROCEDURE B PROCEDURE C
Applicable to Exploration,
Appraisal, Development
and Production $100 to $500 $500 to $3,000 $3,000
Operations
Operator shall not award a contract exceeding US$20,000 to an
Affiliate without prior approval of the Operating Committee,
provided, however, that the service agreement under which EOGIL
secures technical, administrative and related support subject to
Sections 2.4.2 and 3.1 of Exhibit "A", Accounting Procedure, shall
not be subject to the provisions of this Article 6.8.
For contracts valued less than the lower limit of Procedure A,
Operator shall award the contract to the best qualified contractor as
determined in accordance with Operator's purchasing policies set
forth in EOGIL's purchasing policy and procedure, Number 9401.
Operator shall inform the Non-Operators of such awards every month.
PROCEDURE A
Operator shall:
(1) Provide the Parties with a list of all the entities approved
by the Operating Committee as per Article 6.8(C) for the
applicable category of the contract, along with other
entities, if any, from whom the Operator proposes to invite
tender;
(2) Add to such list entities whom a Party requests to be added
within five (5) Business Days of receipt of such list;
(3) If and when any Party so requests, Operator shall evaluate
any entity listed in (1) and (2) above to assure that entity
is qualified as based on the qualification criteria agreed
in accordance with Article 6.8(B), to perform under the
contract;
(4) Complete the tendering process within a reasonable period of
time;
(5) Circulate to all Parties a comparative bid analysis stating
Operator's choice of the entity for award of contract.
Provide also reasons for such choice in case entity chosen
is not the lowest bidder;
(6) Inform all the Parties of the entities to whom the contract
has been awarded; and
(7) Upon the request of a Party, provide such Party with a copy
of the final version of the contract awarded.
PROCEDURE B
Operator shall:
(1) Provide the Parties with a list of all the entities approved
by the Operating Committee as per Article 6.8(C) for the
applicable category of the contract, along with other
entities, if any, from whom the Operator proposes to invite
tender;
(2) Add to such list entities whom a Party requests to be added
within five (5) Business Days of receipt of such list;
(3) If and when any Party so requests, Operator shall evaluate
any entity listed in (1) and (2) above to assure that entity
is qualified as based on the qualification criteria agreed
in accordance with Article 6.8(B), to perform under the
contract;
(4) Complete the tendering process within a reasonable period of
time;
(5) Circulate to all Parties a comparative bid analysis stating
Operator's choice of the entity for award of contract.
Provide also reasons for such choice in case the entity
chosen is not the lowest bidder. If the bid selected is not
the lowest bid, obtain prior approval of the Operating
Committee for award of contract;
(6) Award the contract accordingly and inform all the Parties of
the entities to whom the contract has been awarded; and
(7) Upon the request of a Party, provide such Party with a copy
of the final version of the contract awarded.
PROCEDURE C
Operator shall:
(1) Publish invitations for parties to pre-qualify for the
proposed contract in one (1) daily national India newspaper,
provide to Non-Operators a list of responding parties and an
analysis of their qualifications for the contract being
contemplated, and include those who qualify, as per the
pre-qualification criteria approved as per Article 6.8(B),
in the list of entities whom Operator proposes to invite to
tender for the said contract;
(2) Provide the Parties with a total list of all the entities
selected as (1) above and all the entities approved by the
Operating Committee as per Article 6.8(C) for the applicable
category of the contract, along with other entities, if any,
from whom the Operator proposes to invite tender;
(3) Add to such list entities whom a Party requests to be added
within five (5) Business Days of receipt of such list;
(4) If and when any Party so requests, Operator shall evaluate
any entity listed in (2) and (3) above to assure that entity
is qualified as based on the qualification criteria agreed
in accordance with Article 6.8(B), to perform under the
contract;
(5) Prepare and dispatch the tender documents to the entities on
the list as aforesaid and to Non-Operators;
(6) After the expiration of the period allowed for tendering,
consider and analyze the details of all bids received;
(7) Prepare and circulate to the Parties a comparative bid
analysis, stating Operator's recommendation as to the entity
to whom the contract should be awarded, the reasons
therefor, and the technical, commercial and contractual
terms to be agreed upon;
(8) Obtain the approval of the Operating Committee to the
recommended bid. However, failing Operating Committee
approval, any Party may refer the issue to Management
Committee for decision; and
(9) Award the contract accordingly and upon the request of a
Party, provide such Party with a copy of the final version
of the contract.
(B) A set of vendor qualification criteria for each major category of
vendor shall be proposed by the Operator and approved by the Operating
Committee within thirty (30) Days of its submittal. In the event the
Operating Committee fails to approve vendor qualification criteria
within thirty (30) Days of the date the same is first submitted by the
Operator, the matter shall be referred to the Management Committee for
decision. The Operating Committee may revise the qualification
criteria.
(C) It is anticipated that, in order to expedite Joint Operations,
contracts will be awarded to qualified vendors who are identified as
approved vendors as to specified activities, supplies and/or work as
per the applicable Agreement procedure. A list of such approved
vendors shall first be established as follows:
Operator shall:
(1) Provide the Parties with a list of the entities whom
Operator proposes to invite to tender for contracts; and
(2) Add to such list entities whom a Party requests to be added
within fourteen (14) Days of receipt of such list; and
obtain approval of the Operating Committee within thirty
(30) Days of its submittal to the Operating Committee by the
Operator. Such list shall thereafter be maintained by the
Operator. The Operating Committee may add to or delete
vendors from such list.
6.9 AUTHORIZATION FOR EXPENDITURE ("AFE") PROCEDURE
(A) Prior to incurring any commitment or expenditure which exceeds the
expenditure guidelines specified in this Article 6.9, Operator shall
send to each Non-Operator an AFE containing Operator's best estimate
of the total funds required to carry out such work, the estimated
timing of expenditures, and any other necessary supportive
information. The Operator shall send to each Non-Operator an AFE
containing the information specified above for the following:
(1) Each project involving seismic acquisition and processing;
(2) Each Exploration and Appraisal Well;
(3) Each Development Well or group of Development Wells;
(4) Deepening of any well below original total depth, involving
exploratory footage;
(5) Workovers or Reworking a well costing in excess of
US$200,000 for any well, including deepening into
development Zones;
(6) Each platform or group of platforms;
(7) Each subsea pipeline/major pipeline;
(8) Equipping of Wells exceeding One Hundred Thousand U.S.
Dollars (US$100,000) if not already included in an AFE.
Equipping of wells includes generally the purchase and
installation of equipment and material for lifting, heating,
storing and otherwise handling production;
(9) Individual construction projects and equipment not already
included in an AFE, exceeding One Hundred Thousand U.S.
Dollars (US$100,000) each;
(10) Commitments for purchases of advance materials for projects
not yet approved shall be aggregated and included in an AFE
covering a Calendar Quarter; (11) Any other
project/programmed expenditure not included above in this
Article 6.9 estimated to be in excess of One Hundred Fifty
Thousand U.S. Dollars (US$150,000).
(B) The restrictions contained in this Article shall be without prejudice
to Operator's rights to make expenditures as set out in Article
4.2(B)(11) and Article 13.5.
(C) Parties agree that, except as otherwise provided in Article 6.9(A)(5),
operating costs and deposits as further specified below in this
Article 6.9(C) shall not require AFEs. Such costs shall be reported as
against the appropriate budget line item and variances from the
budgeted amounts shall be reviewed by the Operating Committee.
Operating cost means costs and expenditures of a recurring nature,
incurred after the commencement of production in the operation and
maintenance of property and necessary for production and handling of
produced Petroleum. Costs of a similar nature incurred prior to
production commencement shall be provided for in the appropriate
AFE(s) in accordance with Article 6.9(A)(1) through (A)(9). Deposits
mean non-recurring refundable or adjustable payments toward security/
surety including, but not limited to, expatriate employee housing and
office building rental deposits. Operating costs are categorized and
detailed as Production Costs [except that workovers or Reworking a
well shall be subject to Article 6.9(A)(5)]and general and
administrative costs, which costs are contained in categories III and
IV of Exhibit "D", Work Program and Budget. Deposits are listed in the
"Deposit" section of category V of Exhibit "D".
6.10 SUPPLEMENTARY AFES
Operator shall submit a supplemental AFE for approval when it is
anticipated that an AFE will be overexpended by more than ten percent (10%),
which approval shall not be unreasonably withheld.
6.11 APPROVAL OF AFES
Except as herein otherwise provided, Operator shall be required to obtain
approval of an AFE prior to undertaking the work.
AFE approval shall be confirmed by returning a signed copy of the AFE to
the Operator. Parties shall respond to requests for approval of AFEs within
fourteen (14) Days of receipt. A failure to respond to an AFE within this time
period shall be deemed an approval of such AFE.
6.12 APPROVAL OF AFE NOT TO BE UNREASONABLY WITHHELD
After approval of the Work Program and Budget by the Operating Committee
and the Management Committee, no Party may withhold approval of an AFE for any
project contained in the Firm budget category unless there is a material
variance between the AFE and the project so approved.
6.13 OVEREXPENDITURES OF WORK PROGRAMS AND BUDGETS
Cumulative total of all overexpenditures for a Financial Year shall not
exceed five percent (5%) of the total Work Program and Budget as currently
approved.
6.14 WORK PROGRAM AND BUDGET FOR INITIAL PERIOD
The Development Plan together with the corresponding Work Program and
Budget for the period ending 31 March 1996 ("Initial Period") shall be submitted
to the Operating Committee for approval as soon as possible following the
Effective Date. The Operating Committee shall approve the Development Plan and
corresponding Work Program and Budget within thirty (30) Days and as soon as
practicable thereafter, the Operator shall submit same to the Management
Committee. In the event the Operating Committee is unable to approve the Work
Program and Budget for the Initial Period by the due date specified in this
Article 6.14, any Party may refer the matter to the Management Committee for
decision.
ARTICLE VII - OPERATIONS BY LESS THAN ALL PARTIES
7.1 LIMITATION ON APPLICABILITY
(A) Subject to the Contract, any operation beyond the Minimum Work
Obligation can be proposed as a Joint Operation. In the event of
difference of opinion among the Parties for taking the operation as
Joint Operation, the same may be conducted as Exclusive Operation by
the willing Parties subject to provisions of Article VII. All
operations shall be conducted as Joint Operations under Article V, or
as Exclusive Operations under this Article. No Exploration Well or
Appraisal Well which is an Exclusive Well may be Completed in any
Field which is so designated as of the Effective Date. If a proposal
for an Exploration Well/Appraisal Well for Zones other than those in
the Field leads to an Exclusive Operation and such well is located in
the Development Area of a Field but outside the Field which is so
designated as of the Effective Date, then, in such case, each
Non-Consenting Party/Parties shall have a right to place a
representative at the site during drilling, Completion and testing and
recompleting and Reworking of such a well. No Exclusive Operation
shall be conducted which conflicts with Joint Operations.
Determination as to whether or not a conflict exists shall be made by
the unanimous vote of the Operating committee. If the Operating
Committee cannot agree, the matter can be referred to a sole expert or
arbitration.
(B) Except as otherwise herein provided, operations which are required to
fulfill the Minimum Work Obligations must be proposed and conducted as
Joint Operations under Article V, and shall not be proposed or
conducted as Exclusive Operations under this Article.
(C) No Party may propose or conduct an Exclusive Operation under this
Article, unless and until such Party has properly exercised its right
to propose an Exclusive Operation pursuant to Article 5.13, or is
entitled to conduct an Exclusive Operation pursuant to Article X.
7.2 PROCEDURE TO PROPOSE EXCLUSIVE OPERATIONS
(A) Subject to Article 7.1, if any Party proposes to conduct an Exclusive
Operation, such Party shall give notice of the proposed operation to
all Parties, other than Parties who have relinquished their
Participating Interest in the Exploitation Area in which the proposed
operation is to be conducted. Such notice shall specify that such
operation is proposed as an Exclusive Operation, the work to be
performed, the location, the objectives, and estimated cost of such
operation.
(B) Any Party entitled to receive such notice shall have the right to
participate in the proposed operation.
(1) For proposals to Deepen, Test, Complete, Sidetrack, Plug
Back, Recomplete or Rework involving the use of a drilling
rig that is standing by in the Contract Area, any such Party
wishing to exercise such right must so notify Operator
within twenty-four (24) hours after receipt of the notice
proposing the Exclusive Operation.
(2) For proposals to develop a Discovery, any Party wishing to
exercise such right must so notify the Party proposing to
develop within twenty (20) Days after receipt of the notice
proposing the Exclusive Operation.
(3) For all other proposals, any such Party wishing to exercise
such right must so notify Operator within ten (10) Days
after receipt of the notice proposing the Exclusive
Operation;
(C) Failure of a Party to whom a proposal notice is delivered to properly
reply within the period specified above shall constitute an election
by that Party not to participate in the proposed operation.
(D) If all Parties properly exercise their rights to participate, then the
proposed operation shall be conducted as a Joint Operation. The
Operator shall commence such Joint Operation as promptly as
practicable and conduct it with due diligence.
(E) If less than all Parties entitled to receive such proposal notice
properly exercise their rights to participate, then:
(1) The Party proposing the Exclusive Operation, together with
any other Consenting Parties, shall have the right
exercisable for the applicable notice period set out in
Article 7.2(B), to instruct Operator (subject to Article
7.9(G)) to conduct the Exclusive Operation.
(2) If the Exclusive Operation is conducted, the Consenting
Parties shall bear the sole liability and expense of such
Exclusive Operation in a fraction, the numerator of which is
such Consenting Party's Participating Interest as stated in
Article 3.1(A) and the denominator of which is the aggregate
of the Participating Interests of the Consenting Parties as
stated in Article 3.1(A), or in such other proportion
totaling one hundred percent (100%) of such liability and
expense as the Consenting Parties may agree.
(3) If such Exclusive Operation has not been commenced within
ninety (90) Days (excluding any extension specifically
agreed by all Parties or allowed by the force majeure
provisions of Article XVI), the right to conduct such
Exclusive Operation shall terminate. If any Party still
desires to conduct such Exclusive Operation, written notice
proposing such operation must be resubmitted to the Parties
in accordance with Article V, as if no proposal to conduct
an Exclusive Operation had been previously made.
7.3 RESPONSIBILITY FOR EXCLUSIVE OPERATIONS
(A) The Consenting Parties shall bear in accordance with the Participating
Interests agreed under Article 7.2(E) the entire cost and liability of
conducting an Exclusive Operation and shall indemnify the
Non-Consenting Parties from any and all costs and liabilities incurred
incident to such Exclusive Operation (including but not limited to all
costs, expenses or liabilities for environmental, consequential,
punitive or any other similar indirect damages or losses arising from
business interruption, reservoir or formation damage, inability to
produce petroleum, loss of profits, pollution control and
environmental amelioration or rehabilitation) and shall keep the
Contract Area free and clear of all liens and encumbrances of every
kind created by or arising from such Exclusive Operation.
(B) Notwithstanding Article 7.3(A), each Party shall continue to bear its
Participating Interest share of the cost and liability incident to the
operations in which it participated, including but not limited to
plugging and abandoning and restoring the surface location, but only
to the extent those costs were not increased by the Exclusive
Operation.
7.4 CONSEQUENCES OF EXCLUSIVE OPERATIONS
(A) With regard to any Exclusive Operation, for so long as a
Non-Consenting Party has the option to re-instate the rights it
relinquished under Article 7.4(B) below, such Non-Consenting Party
shall be entitled to have access concurrently with the Consenting
Parties, to all data and other information relating to such Exclusive
Operation, other than G & G Data obtained in an Exclusive Operation.
If a Non-Consenting Party desires to receive and acquire the right to
use such G & G Data, then such Non-Consenting Party shall have the
right to do so by paying to the Consenting Parties its Participating
Interest share as set out in Article 3.1(A) of the cost incurred in
obtaining such G & G Data.
(B) With regard to any Exclusive Operation and subject to Article 7.4(C)
and Article 7.8 below, each Non-Consenting Party shall be deemed to
have relinquished to the Consenting Parties, and the Consenting
Parties shall be deemed to own, in proportion to their respective
Participating Interests in the Exclusive Operation:
(1) All of each such Non-Consenting Party's right to participate
in further operations on any Discovery made in the course of
such Exclusive Operation; and
(2) All of each such Non-Consenting Party's right pursuant to
the Contract to take and dispose of Hydrocarbons produced
and saved:
(a) From the well in which such Exclusive Operation
was conducted, and
(b) From any wells drilled to appraise or develop a
Discovery.
(C) A Non-Consenting Party shall have the following and only the following
options to reinstate the rights it relinquished pursuant to Article
7.4(B):
(1) If the Consenting Parties decide to appraise a Discovery
made in the course of an Exclusive Operation, the Consenting
Parties shall submit to each Non-Consenting Party the
approved appraisal program. For thirty (30) Days (or
forty-eight (48) hours if the drilling rig which is to be
used in such appraisal program is standing by in the
Contract Area) from receipt of such appraisal program, each
Non-Consenting Party shall have the option to reinstate the
rights it relinquished pursuant to Article 7.4(B) and to
participate in such appraisal program. The Non-Consenting
Party may exercise such option by notifying Operator within
the period specified above that such Non-Consenting Party
agrees to bear its Participating Interest share of the
expense and liability of such appraisal program, to pay the
lump sum amount as set out in Article 7.5(A) and to pay the
Cash Premium as set out in Article 7.5(B).
(2) If the Consenting Parties decide to develop a Discovery made
or appraised in the course of an Exclusive Operation, the
Consenting Parties shall submit to the Non-Consenting
Parties a Development Plan substantially in the form
intended to be submitted to the Government under the
Contract. For sixty (60) Days from receipt of such
Development Plan or such lesser period of time prescribed by
the Contract, each Non-Consenting Party shall have the
option to reinstate the rights it relinquished pursuant to
Article 7.4(B) and to participate in such Development Plan.
The Non-Consenting Party may exercise such option by
notifying the Party proposing to act as Operator for such
Development Plan within the period specified above that such
Non-Consenting Party agrees to bear its Participating
Interest share of the liability and expense of such
Development Plan and such future operating and producing
costs, to pay the lump sum amount as set out in Article
7.5(A) and to pay the Cash Premium as set out in Article
7.5(B).
(D) If a Non-Consenting Party does not properly and in a timely manner
exercise such option, including paying in a timely manner in
accordance with Article 7.5, all lump sum amounts and Cash Premiums,
if any, due to the Consenting Parties, such Non-Consenting Party shall
have forfeited the options as set out in Article 7.4(C) and the right
to participate in the proposed program, unless such program, plan or
operation is materially modified or expanded.
(E) A Non-Consenting Party shall become a Consenting Party with regard to
an Exclusive Operation at such time as the Non-Consenting Party gives
proper notice pursuant to Article 7.4(C); provided that such
Non-Consenting Party shall in no way be deemed to be entitled to any
lump sum amount Cash Premium paid incident to such Exclusive
Operation. The Participating Interest of such Non-Consenting Party in
such Exclusive Operation shall be its Participating Interest set out
in Article 3.1(A). The Consenting Parties shall contribute in
proportion to their respective Participating Interests in such
Exclusive Operation, the Participating Interest of the Non-Consenting
Party. If all Parties participate in the proposed operation, then such
operation shall be conducted as a Joint Operation pursuant to Article
V.
(F) If after the expiry of the period in which a Non-Consenting Party may
exercise its option to participate in a Development Plan, the
Consenting Parties desire to proceed with the said Development Plan,
the Party chosen by the Consenting Parties to act as Operator for such
development, shall give notice to the Government under the appropriate
provision of the Contract requesting a meeting to advise the
Government that the Consenting Parties consider the Discovery to be a
Commercial Discovery. Following such meeting such Operator for such
development shall apply for an Exploitation Area. Unless the
Development Plan is materially modified or expanded prior to the
commencement of operations under such plan, each Non-Consenting Party
to such Development Plan shall not participate in such Exploitation
Area covering such development and shall forfeit all interest in such
Exploitation Area. Such Non-Consenting Party shall be deemed to have
withdrawn from this Agreement to the extent it relates to such
Exploitation Area, even if the Development Plan is modified or
expanded subsequent to the commencement of operations under such
Development Plan.
7.5 PREMIUM TO PARTICIPATE IN EXCLUSIVE OPERATIONS
(A) Within thirty (30) Days of the exercise of its option under Article
7.4(C), each such Non-Consenting Party shall pay in immediately
available funds to the Consenting Parties who took the risk of such
Exclusive Operations in proportion to their respective Participating
Interests in such Exclusive Operations a lump sum amount payable in
the currency designated by such Consenting Parties. Such lump sum
amount shall be equal to such Non-Consenting Party's Participating
Interest share of all liabilities and expenses, including overhead,
that were incurred in Exclusive Operations relating to the Discovery,
or well, as the case may be, in which the Non-Consenting Party desires
to reinstate the rights it relinquished pursuant to Article 7.4(B),
and that were not previously paid by such Non-Consenting Party.
(B) In addition to Article 7.5(A), if a Cash Premium is due, then within
thirty (30) Days of the exercise of its option under Article 7.4(C)
each such Non-Consenting Party shall pay in immediately available
funds, in the currency designated by the Consenting Parties who took
the risk of such Exclusive Operations, to such Consenting Parties in
proportion to their respective Participating Interests a Cash Premium
equal to the total of:
(1) Two hundred percent (200%) of such Non-Consenting Party's
Participating Interest share of all liabilities and
expenses, including overhead, that were incurred in any
Exclusive Operations relating to the obtaining of the
portion of the G & G Data which pertains to the Discovery,
and that were not previously paid by such Non-Consenting
Party; plus
(2) Eight hundred percent (800%) of such Non-Consenting Party's
Participating Interest share of all liabilities and
expenses, including overhead, that were incurred in any
Exclusive Operations relating to the drilling, Deepening,
Testing, Completing, Sidetracking, Plugging Back,
Recompleting and Reworking of the Exploration Well which
made the Discovery in which the Non-Consenting Party desires
to reinstate the rights it relinquished pursuant to Article
7.4(B), and that were not previously paid by such
Non-Consenting Party; plus
(3) Five hundred percent (500%) of the Non-Consenting Party's
Participating Interest share of all liabilities and
expenses, including overhead, that were incurred in any
Exclusive Operations relating to the drilling, Deepening,
Testing, Completing, Sidetracking, Plugging Back,
Recompleting and Reworking of the Appraisal Well(s) which
delineated the Discovery in which the Non-Consenting Party
desires to reinstate the rights it relinquished pursuant to
Article 7.4(B), and that were not previously paid by such
Non-Consenting Party.
7.6 ORDER OF PREFERENCE OF OPERATIONS
(A) Except as otherwise specifically provided in this Agreement, if any
Party desires to propose the conduct of an operation that will
conflict with an existing proposal for an Exclusive Operation, such
Party shall have the right exercisable for five (5) Days, or
twenty-four (24) hours if the drilling rig to be used is standing by
in the Contract Area, from receipt of the proposal for the Exclusive
Operation, to deliver to all Parties entitled to participate in the
proposed operation such Party's alternative proposal. Such alternative
proposal shall contain the information required under Article 7.2(A).
(B) Each Party receiving such proposals shall elect by delivery of notice
to Operator within the appropriate response period set out in Article
7.2(B) to participate in one of the competing proposals. Any Party not
notifying Operator within the response period shall be deemed not to
have voted.
(C) The proposal receiving the largest aggregate Participating Interest
vote shall have priority over all other competing proposals. In the
case of a tie vote, the Operator shall choose among the proposals
receiving the largest aggregate Participating Interest vote. Operator
shall deliver notice of such result to all Parties entitled to
participate in the operation within five (5) Days of the end of the
response period, or twenty-four (24) hours if the drilling rig to be
used is standing by in the Contract Area.
(D) Each Party shall then have two (2) Days (or twenty-four (24) hours if
the drilling rig to be used is standing by in the Contract Area) from
receipt of such notice to elect by delivery of notice to Operator
whether such Party will participate in such Exclusive Operation, or
will relinquish its interest pursuant to Article 7.4(B). Failure by a
Party to deliver such notice within such period shall be deemed an
election not to participate in the prevailing proposal.
7.7 STAND BY COSTS
(A) When an operation has been performed, all tests have been conducted
and the results of such tests furnished to the Parties, stand by costs
incurred pending response to any Party's notice proposing an Exclusive
Operation for Deepening, Testing, Sidetracking, Completing, Plugging
Back, Recompleting, Reworking or other further operation in such well
(including the period required under Article 7.6 to resolve competing
proposals) shall be charged and borne as part of the operation just
completed. Stand by costs incurred subsequent to all Parties
responding, or expiration of the response time permitted, whichever
first occurs, shall be charged to and borne by the Parties proposing
the Exclusive Operation in proportion to their Participating
Interests, regardless of whether such Exclusive Operation is actually
conducted.
(B) If a further operation is proposed while the drilling rig to be
utilized is on location, any Party may request and receive up to five
(5) additional Days after expiration of the applicable response period
specified in Article 7.2(B) within which to respond by notifying
Operator that such Party agrees to bear all stand by costs and other
costs incurred during such extended response period. Operator may
require such Party to pay the estimated stand by time in advance as a
condition to extending the response period. If more than one Party
requests such additional time to respond to the notice, stand by costs
shall be allocated between such Parties on a Day-to-Day basis in
proportion to their Participating Interests.
7.8 SPECIAL CONSIDERATION REGARDING DEEPENING AND SIDETRACKING
(A) An Exclusive Well shall not be deepened or sidetracked without
first affording the Non-Consenting Parties in accordance with this
Article the opportunity to participate in such operation.
(B) In the event any Consenting Party desires to Deepen or Sidetrack an
Exclusive Well, such Party shall initiate the procedure contemplated
by Article 7.2. If a Deepening or Sidetracking operation is approved
pursuant to such provisions, and if any Non-Consenting Party to the
Exclusive Well elects to participate in such Deepening or Sidetracking
operation, the payment, if any, pursuant to Article 7.5 of such
Non-Consenting Party shall be calculated based on the following
liabilities and expenses:
(1) If the proposal is to Deepen or Sidetrack and is made prior
to the Completion of such well as a Commercial Discovery,
then payment shall be based on such Non-Consenting Party's
Participating Interest share of the liabilities and expenses
incurred in connection with drilling the Exclusive Well from
the surface to the depth previously drilled which such
Non-Consenting Party would have paid had such Non-Consenting
Party agreed to participate in such Exclusive Well, plus the
Non-Consenting Party's Participating Interest share of the
liabilities and expenses of Deepening or Sidetracking and of
participating in any further operations on such Exclusive
Well in accordance with the other provisions of this
Agreement; provided, however, all liabilities and expenses
for Testing and Completing or attempting Completion of the
well incurred by Consenting Parties prior to the
commencement of actual operations to Deepen or Sidetrack
beyond the depth previously drilled shall be for the sole
account of Consenting Parties in the proportion their
Participating Interest bears to the aggregate of their
Participating Interests.
(2) If the proposal is to Deepen or Sidetrack and is made for an
Exclusive Well that has been previously Completed as a
Commercial Discovery, but is no longer producing, then
payment shall be based on the Non-Consenting Party's
Participating Interest share of all costs of drilling and
Completing said well from the surface to the depth
previously drilled, calculated in the manner provided in
Article 7.8(B)(1), less those costs recouped by the
Consenting Parties from the sale of production from such
Exclusive Well, plus the Non-Consenting Party's
Participating Interest share of all costs of re-entering
said well, plus the Non-Consenting Party's proportionate
part (based on the percentage of the Exclusive Well such
Non-Consenting Party would have owned had it previously
participated in such Exclusive Well) of the costs of
salvable materials and equipment remaining in the hole and
salvable surface equipment used in connection with such well
shall be determined in accordance with the Accounting
Procedure. If at the time such Deepening or Sidetracking
operation is conducted the Consenting Parties have recouped
from the Exclusive Well the amount calculated pursuant to
Article 7.5, then a Non-Consenting Party may participate in
the Deepening or Sidetracking of the Exclusive Well with no
payment for liabilities and expenses incurred prior to
re-entering the well for Deepening or Sidetracking.
7.9 MISCELLANEOUS
(A) Each Exclusive Operation shall be carried out by the Operator on
behalf of and at the expense of the Consenting Parties. For Exclusive
Operations, the Consenting Parties shall act as the Operating
Committee, subject to the provisions of this Agreement applied mutatis
mutandis to such Exclusive Operation and subject to the terms and
conditions of the Contract.
(B) The computation of liabilities and expenses incurred in Exclusive
Operations, including the liabilities and expenses of Operator for
conducting such operations, shall be made in accordance with the
principles set out in the Accounting Procedure.
(C) Operator shall maintain separate books, financial records and accounts
for Exclusive Operations which shall be subject to the same rights of
audit and examination as the Joint Account and related records, all as
provided in the Accounting Procedure. Said rights of audit and
examination shall extend to each of the Consenting Parties and each of
the Non-Consenting Parties so long as the latter are, or may be,
entitled to elect to participate in such operations.
(D) Operator, if it is not a Consenting Party and it is conducting an
Exclusive Operation for the Consenting Parties, shall be entitled to
request cash advances and shall not be required to use its own funds
to pay any cost and expense and shall not be obliged to commence or
continue Exclusive Operations until cash advances requested have been
made, and the Accounting Procedure shall apply to Operator in respect
of any Exclusive Operations conducted by it.
(E) Should the submission of a Development Plan be approved in accordance
with Article 5.9, or should any Party propose a development in
accordance with Article VII, with either proposal not calling for the
conduct of additional appraisal drilling, and should any Party wish to
drill an additional Appraisal Well prior to development, then the
Party proposing the Appraisal Well as an Exclusive Operation shall be
entitled to proceed first, but without the right to future
reimbursement of costs or to any Premium, pursuant to Article 7.5. If,
as the result of drilling such Appraisal Well as an Exclusive
Operation, the Party proposing to apply for an Exploitation Area
decides to not develop the reservoir, then each Non-Consenting Party
who voted in favor of such Development Plan prior to the drilling of
such Appraisal Well shall pay to the Consenting Party the amount such
Non-Consenting Party would have paid had such Appraisal Well been
drilled as a Joint Operation.
(F) In the case of any Exclusive Operation for Deepening, Testing,
Completing, Sidetracking, Plugging Back, Recompleting or Reworking,
the Consenting Parties shall be permitted to use, free of cost, all
casing, tubing and other equipment in the well, that is not needed for
Joint Operations, but the ownership of all such equipment shall remain
unchanged. On abandonment of a well after such Exclusive Operation,
the Consenting Parties shall account for all such equipment to the
Parties who shall receive their respective Participating Interest
shares, in value, less cost of salvage.
(G) If the Operator is a Non-Consenting Party to an Exclusive Operation to
develop a new Discovery, then subject to obtaining any necessary
Government approval the Operator may resign, but in any event shall
resign on the request of the Consenting Parties, as Operator for the
Exploitation Area for such Discovery and the Consenting Parties shall
select a Party to serve as Operator.
ARTICLE VIII - DEFAULT
8.1 DEFAULT AND NOTICE
Any Party that fails to pay when due its Participating Interest share of
Joint Account expenses including cash advances and interest, if any, accrued
pursuant to this Agreement, subject to Section 1.6.2, (a "Defaulting Party")
shall be in default under this Agreement. Operator, or any other Party in the
case of the default of Operator, shall promptly give written notice of such
default to such Party and each of the non-defaulting Parties, but not later than
the third Business Day from the due date. If the Operator is in default, it
shall issue notice to the other Parties on the third Business Day after the due
date. The amount not paid by the Defaulting Party shall bear interest from the
date due until paid in full. Interest "Agreed Interest Rate" will be calculated
using the rates specified below:
From due date through fifth Business Day, interest is LIBOR + 0.5
From sixth through thirtieth Business Day, interest is LIBOR + 1.5
From thirty-first through forty-sixth Business Day, interest is LIBOR + 3.0
Beyond forty-sixth Business Day, interest is LIBOR + 5.0
8.2 OPERATING COMMITTEE MEETINGS AND DATA
After any default has continued for thirty (30) Business Days from the date
of written notice of default under Article 8.1, and for as long thereafter as
the Defaulting Party remains in default on any payment due under this Agreement,
the Defaulting Party shall not be entitled to vote on any matter coming before
the Operating Committee during the period such default continues. Unless agreed
otherwise by the non-defaulting Parties, the voting interest of each
non-defaulting Party shall be in the proportion which its Participating Interest
bears to the total of the Participating Interest of all the non-defaulting
Parties. Any matters requiring unanimous vote of the Parties shall be deemed to
exclude the Defaulting Party. Notwithstanding the foregoing, the Defaulting
Party shall be deemed to have approved, and shall join with the non-defaulting
Parties in taking any action to maintain and preserve the Contract.
8.3 ALLOCATION OF DEFAULTED ACCOUNTS
(A) Operator shall, either at the time of giving notice of default as
provided in Article 8.1, or by separate notice, notify each
non-defaulting Party of the sum of money it is to pay as its portion
(such portion being in the ratio that each non-defaulting Party's
Participating Interest bears to the Participating Interests of all
non-defaulting Parties) of such amount in default. Each non-defaulting
Party shall, if such default continues, pay Operator, within ten (10)
Business Days after receipt of such notice, its share of the amount
which the Defaulting Party failed to pay. If any non-defaulting Party
fails to pay its share of the amount in default as aforesaid, such
non-defaulting Party shall thereupon be in default and shall be a
Defaulting Party subject to the provisions of this Article. The
non-defaulting Parties which pay the amount owed by any Defaulting
Party shall be entitled to receive their respective share of the
principal and interest payable by such Defaulting Party pursuant to
Article 8.1.
(B) The total of all amounts paid by the non-defaulting Parties for the
Defaulting Party, together with interest accrued on such amounts shall
constitute a debt due and owing by the Defaulting Party to the
non-defaulting Parties in proportion to such amounts paid. In
addition, the non-defaulting Parties may in the manner contemplated by
this Article, satisfy such debt (together with interest) and may
accrue an amount equal to the Defaulting Party's Participating
Interest share of the estimated cost to abandon any Joint Property.
(C) A Defaulting Party may remedy its default by paying to Operator the
total amount due, together with interest calculated as provided in
Article 8.1, at any time prior to a transfer of its interest pursuant
to Article 8.4, and, upon receipt of such payment, Operator shall
remit to each non-defaulting Party its proportionate share of such
amount.
(D) The rights granted to each non-defaulting Party pursuant to this
Article shall be in addition to and not in substitution for any other
rights or remedies which each non-defaulting Party may have at law or
equity or pursuant to the other provisions of this Agreement.
8.4 TRANSFER OF INTEREST
(A) For thirty (30) Days after each failure by the Defaulting Party to
remedy its default by the ninetieth (90th) Day following notice of
default without prejudice to any other rights of the non-defaulting
Parties to recover the amounts paid for the Defaulting Party, together
with interest accrued on such amount, each non-defaulting Party shall
have the option to give notice to the Defaulting Party requiring the
Defaulting Party to transfer, as specified in Article 8.4(E), its
interest to the non-defaulting Parties. To that end if any of the
non-defaulting Parties so elect, the Defaulting Party shall be deemed
to have transferred and to have empowered the electing non-defaulting
Parties to execute on said Defaulting Party's behalf any documents
required to effect a transfer of all of its right, title and
beneficial interest in and under this Agreement and the Contract and
in all wells and Joint Property to the electing non-defaulting
Parties. If requested, each Party shall execute a Power of Attorney in
the form prescribed by the Operating Committee. The Defaulting Party
shall, without delay following any request from the non-defaulting
Parties, do any and all acts required to be done by applicable law or
regulation in order to render such transfer legally valid, including,
without limitation, the obtaining of all governmental consents and
approvals, and shall execute any and all documents and take such other
actions as may be necessary in order to effect prompt and valid
transfer of the interests described above, free of all liens and
encumbrances. In the event all Government approvals are not timely
obtained, the Defaulting Party shall hold its Participating Interest
in trust for such non-defaulting Parties who elected to assume such
Defaulting Party's Participating Interest.
(B) In the absence of an agreement among the non-defaulting Parties to the
contrary, any such transfer to the non-defaulting Parties shall be in
the proportion that the non-defaulting Parties have paid the amounts
due from the Defaulting Party.
(C) Subject to Article 12.1(C), on the effective date of transfer of all
its Participating Interest, the Defaulting Party shall forthwith cease
to be a Party to this Agreement to the extent of the Participating
Interest so transferred. The acceptance or non-acceptance by a
non-defaulting Party of any portion of a Defaulting Party's
Participating Interest shall be without prejudice to any rights or
remedies such non-defaulting Parties have to recover the outstanding
debts (including interest) owed by the Defaulting Party.
(D) Notwithstanding the above, if pursuant to any mutual agreement between
any of the Parties, one of the Parties makes an additional
contribution on behalf of another Party, the same will not be treated
as a Default of the other Party under this Agreement and Contract.
Such contribution shall not change the Participating Interest of the
Parties.
(E) In the event that the default continues for more than ninety (90) days
(the "Default Period") and the Defaulting Party does not pay the
amount in default plus accrued interest by the end of such time, a
proportion of the Participating Interest of such Defaulting Party
shall, at the sole election of the Non-Defaulting Parties who wish to
acquire such interest, be forfeited to such Non-Defaulting Parties to
reflect the ratio that the cumulative contributions of the Defaulting
Party bears to the total cumulative contributions of all the Parties
to Joint Operations costs, so that following such forfeiture the
remaining Participating Interest of the Defaulting Party as a
proportion of the total Participating Interests of all the Parties is
equal to the said ratio.
Following such forfeiture, the reduced Participating Interest of the
Defaulting Party shall be in accordance with the following formula:
A = B/C
where:
A = the reduced Participating Interest of the Defaulting Party, and
B = the total contributions to Joint Operations costs of the
Defaulting Party up to but not including the amount in
default, and
C = the total contributions to Joint Operations costs of all
the Parties up to and including the amount in default.
Such forfeiture will not restore the Defaulting Party's powers and
rights forfeited under Article 8.2 until such Defaulting Party has
paid, in full, the first Cash Call following the date of such
forfeiture. The Defaulting Party shall execute such documents as are
necessary to transfer its Participating Interest at its sole cost.
Notwithstanding the provisions of this Article, in the event that as
a result of a forfeiture by the Defaulting Party of a part of its
Participating Interest pursuant to the provisions of this Article,
the remaining Participating Interest the Defaulting Party falls below
ten percent (10%) the Non-Defaulting Parties shall assume such
Participating Interest of the Defaulting Party in proportion to their
Participating Interest or in such other proportion as may be agreed
by them. The Defaulting Party shall execute such documents as are
necessary to transfer its remaining Participating Interest at its
sole cost.
8.5 CONTINUATION OF INTEREST
If within thirty (30) Days after each failure by the Defaulting Party to
remedy its default by the ninetieth (90th) Day following notice of default the
non-defaulting Parties elect to not acquire the Defaulting Party's Participating
Interest as provided in Article 8.4 and to continue to bear the Defaulting
Party's Participating Interest share of liabilities and expenses, then the
non-defaulting Parties shall accumulate all such liabilities and expenses as a
debt pursuant to Article 8, but the Defaulting Party shall continue to be a
Party subject to Article 8.2 and Article 8.7. If Operator disposes of any Joint
Property or any other credit or adjustment is made to the Joint Account, or if
Operator sells any of the Defaulting Party's Participating Interest share of
Hydrocarbons, then, in respect of the Defaulting Party's Participating Interest
share of the proceeds of such disposal, credit or adjustment or sale, Operator
shall be entitled to retain and to set off the same against all amounts,
together with interest accrued on such amount, due and owing from the Defaulting
Party plus an accrued amount equal to the Defaulting Party's Participating
Interest share of the estimated cost to abandon any Joint Property. Any surplus
remaining after setting off the same as aforesaid shall be paid promptly to the
Defaulting Party.
8.6 ABANDONMENT
If, within thirty (30) Days after the failure by the Defaulting Party to
remedy its default by the ninetieth (90th) Day as aforesaid, no non-defaulting
Party elects to acquire the Defaulting Party's Participating Interest as
provided in Article 8.4, or to bear the Defaulting Party's Participating
Interest share of liabilities and expenses as provided in Article 8.5, then no
transfer shall be made and Joint Operations shall be abandoned subject to any
necessary consents and notices being given and each Party, including the
Defaulting Party shall pay its Participating Interest share of all costs of
abandoning and relinquishing the Contract. If abandonment occurs as aforesaid,
all monies paid by the non-defaulting Parties for the Defaulting Party pursuant
to Article 8.3, together with interest accrued on such amount, shall remain a
debt due and owing by the Defaulting Party.
8.7 SALE OF HYDROCARBONS
Notwithstanding anything here else contained in this Agreement, if a Party
defaults after the commencement of commercial production and has not remedied
the default by the ninetieth (90th) Day as aforesaid, then, during the
continuance of such default, the Defaulting Party shall not be entitled to its
Participating Interest share of Hydrocarbons which shall vest in and be the
property of the non-defaulting Parties, and Operator shall be authorized to sell
such Hydrocarbons at the best price obtainable under the circumstances, and,
after deducting all costs, charges and expenses incurred by Operator in
connection with such sale, pay the proceeds proportionately to the
non-defaulting Parties, which proceeds shall be credited against all monies
advanced pursuant to Article 8.3, together with interest accrued thereon. Any
surplus remaining shall be paid to the Defaulting Party, and any deficiency
shall remain a debt due from the Defaulting Party to the non-defaulting Parties.
As soon as the deficiency is satisfied, the Defaulting Party's rights shall be
restored.
8.8 NO RIGHT OF SET OFF
Each Party acknowledges and accepts that a fundamental principle of this
Agreement is that each Party pays its Participating Interest share of all
amounts due under this Agreement as and when required. Accordingly, any Party
which becomes a Defaulting Party undertakes that, in respect of either any
exercise by the non-defaulting Parties of any rights under or the application of
any of the provisions of this Article, such Party shall not raise by way of set
off or invoke as a defense, whether in law or equity, any failure to pay amounts
due and owing under this Agreement or any alleged or unliquidated claim that
such Party may have against Operator or any Non-Operator, whether such claim
arises under this Agreement or otherwise. Such Party further undertakes not to
raise by way of defense, whether in law or in equity, that the nature or the
amount of the remedies granted to the non-defaulting Parties is unreasonable or
excessive.
8.9 MINOR DEFAULT
Notwithstanding the provisions of this Article 8, Articles 8.2 and 8.4
shall have no effect provided the total amount of funds in default is less than
One Million United States Dollars (US$1,000,000).
8.10 REINSTATEMENT OF RIGHTS
In the event that the default is found to be in error, either through
arbitration or otherwise, the Defaulting Party's rights shall be reinstated as
determined by the arbitrators or, if not subjected to arbitration, as otherwise
found to be reasonably appropriate.
ARTICLE IX - DISPOSITION OF PRODUCTION
9.1 RIGHT AND OBLIGATION TO TAKE IN KIND
Except as otherwise provided in this Article, each Party shall have the
right and obligation to own, take in kind and separately dispose of its
Participating Interest share of total production available to the Parties
pursuant to the Contract from any Exploitation Area in such quantities and in
accordance with such procedures as may be set forth in the offtake agreement
referred to in Article 9.2 or in the special arrangements for natural gas
referred to in Article 9.3. If Government is party to the offtake agreement,
then the Parties shall endeavor to obtain its agreement to the principles set
forth in this Article.
9.2 OFFTAKE AGREEMENT FOR CRUDE OIL
If crude oil is to be produced from an Exploitation Area, the Parties shall
in good faith, negotiate and conclude the terms of an agreement to cover the
offtake of crude oil produced under the Contract. The Government may, if
necessary and practicable, also be party to the offtake agreement. This offtake
agreement shall, to the extent consistent with the Contract, make provision for:
(A) The delivery point, at which title and risk of loss of Participating
Interest shares of crude oil shall pass to the Parties interested (or
as the Parties may otherwise agree);
(B) Operator's regular periodic advice to the Parties of estimates of
total available production for succeeding periods, Participating
Interest shares, and grades of crude oil for as far ahead as is
necessary for Operator and the Parties to plan offtake arrangements.
Such advice shall also cover for each grade of crude oil total
available production and deliveries for the preceding period,
inventory and overlifts and underlifts;
(C) Nomination by the Parties to Operator of acceptance of their
Participating Interest share of total available production for the
succeeding period. Such nominations shall in any one period be for
each Party's entire Participating Interest share arising during that
period subject to operational tolerances and agreed minimum economic
cargo sizes or as the Parties may otherwise agree;
(D) Elimination of overlifts and underlifts;
(E) If offshore loading or a shore terminal for vessel loading is
involved, risks regarding acceptability of tankers, demurrage and (if
applicable) availability of berths;
(F) Distribution to the Parties of Entitlements to ensure, to the extent
Parties take delivery of their Entitlements in proportion to the
accrual of such Entitlements, that each Party shall receive currently
Entitlements of grades, gravities and qualities of Hydrocarbons
similar to Hydrocarbons received by each other Party.
(G) To the extent that distribution of Entitlements on such basis is
impracticable due to availability of facilities and minimum cargo
sizes, a method of making periodic adjustments; and
(H) The option and the right of the other Parties to sell an Entitlement
which a Party fails to nominate for acceptance pursuant to (C) above
or of which a Party fails to take delivery, in accordance with
applicable agreed procedures, provided that such failure either
constitutes a breach of Operator's or Parties' obligations under the
terms of the Contract, or is likely to result in the curtailment or
shut-in of production. Such sales shall be made only to the limited
extent necessary to avoid disruption in Joint Operations. Operator
shall give all Parties as much notice as is practicable of such
situation and that a sale option has arisen. Any sale shall be of the
unnominated or undelivered Entitlement as the case may be and for
reasonable periods of time as are consistent with the minimum needs of
the industry and in no event to exceed twelve (12) months. The right
of sale shall be revocable at will subject to any prior contractual
commitments. Sales to non-affiliated third parties shall be for the
realized price f.o.b. the delivery point. Sales to any of the Parties
or their Affiliates shall be at current market value f.o.b. the
delivery point. The Party arranging the sale shall pay to the Party
whose Entitlement is involved the above price after deduction of all
costs, including storage costs, incurred in respect of such sale and a
marketing fee of an agreed percentage of the applicable price less
deductions, reflecting actual costs of disposal at immediate notice.
Current market value shall be the value of the Entitlement in
international markets (unless the Entitlement was required to be
delivered into the Government's domestic market, in which case it
shall be the value therein) between a willing buyer and a willing
seller and shall be agreed between the two Parties concerned, or
failing agreement, determined by an expert to be appointed in
accordance with procedures set forth in the offtake agreement.
9.3 SEPARATE AGREEMENT FOR NATURAL GAS
The Parties recognize that it may be necessary for the Parties to enter
into special arrangements for the disposal of the natural gas, which are
consistent with the Development Plan and subject to the terms of the Contract.
ARTICLE X - ABANDONMENT OF WELLS
10.1 ABANDONMENT OF WELLS DRILLED AS JOINT OPERATIONS
(A) Any well which has been drilled as a Joint Operation and which is
proposed to be plugged and abandoned shall not be plugged and
abandoned without the consent of all Parties.
(B) Should any such Party fail to reply within the period prescribed in
Article 5.12(A)(1) or Article 5.12(A)(2), whichever is applicable,
after delivery of notice of the Operator's proposal to plug and
abandon such well, such Party shall be deemed to have consented to the
proposed abandonment. If all the Parties consent to abandonment, such
well shall be plugged and abandoned in accordance with applicable
regulations and at the cost, risk and expense of the Parties who
participated in the cost of drilling such well.
(C) If there is a disagreement amongst the Parties regarding the
abandonment of such well, those wishing to continue operations shall
assume financial responsibility over the well and shall be deemed to
be Consenting Parties conducting an Exclusive Operation pursuant to
Article VII. In the case of a producing well, the Consenting Parties
shall be entitled to continue producing only from the Zone open to
production at the time they assumed responsibility for the well.
(D) Consenting Parties taking over a well as provided above shall tender
to each of the Non-Consenting Parties such Non-Consenting Parties'
Participating Interest share of the value of the well's salvable
material and equipment, determined in accordance with the Accounting
Procedure, less the estimated cost of salvaging and the estimated cost
of plugging and abandoning as of the date the Consenting Party assumed
responsibility for the well; provided, however, that in the event the
estimated cost of plugging and abandoning and the estimated cost of
salvaging are higher than the value of the well's salvable material
and equipment, each of the abandoning Parties shall continue to be
liable pursuant to Article 7.3(B) for their respective Participating
Interest shares of the estimated excess cost.
(E) Each Non-Consenting Party shall be deemed to have relinquished to the
Consenting Parties in proportion to their Participating Interests all
of its interest in the wellbore of a produced well and related
equipment in accordance with Article 7.4(B), insofar and only insofar
as such interest covers the right to obtain production from that
wellbore in the Zone then open to production.
(F) Subject to Article 7.9(G), Operator shall continue to operate a
produced well for the account of the Consenting Parties at the rates
and charges contemplated by this Agreement, plus any additional cost
and charges which may arise as the result of the separate allocation
of interest in such well.
10.2 ABANDONMENT OF EXCLUSIVE OPERATIONS
This Article shall apply mutatis mutandis to the abandonment of an
Exclusive Well or any well in which an Exclusive Operation has been conducted;
provided that no well shall be permanently plugged and abandoned unless and
until all Parties having the right to conduct further operations in such well
have been notified of the proposed abandonment and afforded the opportunity to
elect to take over the well in accordance with the provisions of this Article X.
ARTICLE XI - SURRENDER
11.1 SURRENDER
(A) If the Contract requires the Parties to surrender any portion of the
Contract Area, Operator shall advise the Operating Committee of such
requirement at least one hundred and twenty (120) Days in advance of
the earlier of the date for filing irrevocable notice of such
surrender or the date of such surrender. Prior to the end of such
period, the Operating Committee shall determine pursuant to Article V,
the size and shape of the surrendered area, consistent with the
requirements of the Contract. If no proposal attains the support of
one hundred percent (100%) of the Participating Interests, then the
proposal receiving the largest aggregate Participating Interest vote
shall be adopted. The Parties shall execute any and all documents and
take such other actions as may be necessary to effect the surrender.
Each Party renounces all claims and causes of action against Operator
and any other Parties on account of any area surrendered in accordance
with the foregoing but against its recommendation if Hydrocarbons are
subsequently discovered under the surrendered area.
(B) A surrender of all or any part of the Contract Area which is not
required by the Contract shall require the unanimous consent of the
Parties.
ARTICLE XII - TRANSFER OF INTEREST OR RIGHTS
12.1 OBLIGATIONS
(A) Subject always to the requirements of the Contract, the transfer of
all or part of a Party's Participating Interest shall be effective
only if it satisfies the terms and conditions of this Article.
(B) Except in the case of a Party transferring all of its Participating
Interest, no transfer shall be made by any Party which results in the
transferor or the transferee holding a Participating Interest of less
than ten percent (10%) or holding any Interest other than a
Participating Interest in the Contract, the Contract Area and this
Agreement.
(C) The transferring Party shall, notwithstanding the transfer, be liable
to the other Parties for any obligations, financial or otherwise,
which have vested, matured or accrued under the provision of the
Contract or this Agreement prior to such transfer. Such obligations
shall include, without limitation, any proposed expenditure approved
by the Operating Committee, prior to the transferring Party notifying
the other Parties of its proposed transfer.
(D) The transferee shall have no rights in and under the Contract, the
Contract Area or this Agreement unless and until it obtains any
necessary Government approval and expressly undertakes in writing to
perform the obligations of the transferor under the Contract and this
Agreement in respect of the Participating Interest being transferred,
to the satisfaction of the Parties and furnishes any guarantees
required by the Government or the Contract.
(E) The transferee shall have no rights in and under the Contract, the
Contract Area or this Agreement unless each Party has consented in
writing to such transfer, which consent shall be denied only if such
transferee fails to establish to the reasonable satisfaction of each
Party its financial or technical capability to perform its obligations
under the Contract and this Agreement.
(F) Nothing contained in this Article shall prevent a Party from
mortgaging, pledging, charging or otherwise encumbering all or part of
its interest in the Contract Area in and under this Agreement for the
purpose of security relating to finance provided that:
(1) such Party shall remain liable for all obligations relating
to such interest;
(2) the encumbrance shall be subject to the approval of the
Management Committee and any necessary approval under the
Contract and be expressly subordinated to the rights of the
other Parties under this Agreement; and
(3) such Party shall ensure that any such mortgage, pledge,
charge or encumbrance shall be expressed to be without
prejudice to the provisions of this Agreement.
(G) In the event a Party receives an offer to purchase all or a part of
its Participating Interest, it shall so notify the other Parties and
they shall have the right for a period of ten (10) days to make an
offer. If a Party elects to sell all or a part of its Participating
Interest, it shall so notify the other Parties upon offering the
Participating Interest for sale.
12.2 RIGHTS
Each Party shall have the right, subject to the provisions of Article 12.1,
to freely transfer its Participating Interest.
ARTICLE XIII - WITHDRAWAL FROM AGREEMENT BY TRANSFER OR ASSIGNMENT
13.1 RIGHT OF WITHDRAWAL
(A) Subject to the provisions of the Contract and this Article, any Party
may withdraw from this Agreement and the Contract by giving notice to
all other Parties stating its decision to withdraw and specifying a
proposed effective date of withdrawal which shall be at least sixty
(60) Days, but not more than one hundred eighty (180) Days after the
date of such notice. Such notice shall be unconditional and
irrevocable when given.
(B) Notwithstanding Article 13.1(A) a Party shall not have the right to
withdraw from this Agreement and the Contract until the Minimum Work
Obligation set forth in the Contract has been fulfilled. However, if
the Operating Committee or any Party decides to accept new Minimum
Work Obligations under the Contract, a Party that voted against such
decision shall not be prevented from withdrawing; provided that such
Party delivers notice of its withdrawal to all Parties within thirty
(30) Days of such vote and fully satisfies its outstanding Minimum
Work Obligation, if any.
(C) Subject to Articles 13.1(A) and (B) and Article 13.5, the effective
date of withdrawal for a withdrawing Party shall be the later of:
(1) The date proposed in the notice of withdrawal; or
(2) The date that the withdrawing Party has fulfilled its
obligations under this Article.
13.2 PARTIAL OR COMPLETE WITHDRAWAL
(A) Within thirty (30) Days of receipt of each withdrawing Party's
notification, each of the other Parties may also give notice that it
desires to withdraw from this Agreement and the Contract. Should all
Parties give notice of withdrawal, the Parties shall proceed to
abandon the Contract Area and terminate the Contract and this
Agreement. If less than all of the Parties give such notice of
withdrawal, then the withdrawing Parties shall take all steps to
withdraw from the Contract and this Agreement on the earliest possible
date and execute and deliver all necessary instruments and documents
to assign their Participating Interest to the Parties which are not
withdrawing, without any compensation whatsoever, in accordance with
the provisions of Article 13.6.
(B) If any part of the withdrawing Party's Participating Interest remains
unclaimed after sixty (60) Days from the date of the first notice of
withdrawal, the Parties shall be deemed to have decided to withdraw
from the Contract and this Agreement, unless at least one Party agrees
to accept the unclaimed Participating Interest.
(C) Any Party withdrawing under this Article shall withdraw from all
exploration activities under the Contract, but not from any
Exploitation Area, Commercial Discovery, or Discovery whether
appraised or not, made prior to such withdrawal. Such withdrawing
Party shall retain its rights in the Joint Property but only insofar
as they relate to any Exploitation Area, Commercial Discovery or
Discovery whether appraised or not, and shall abandon all other rights
in the Joint Property.
13.3 VOTING
After giving its notification of withdrawal, a Party shall not be entitled
to vote on any matters coming before the Operating Committee, other than matters
for which such Party has financial responsibility.
13.4 OBLIGATIONS AND LIABILITIES
(A) A withdrawing Party, prior to its withdrawal, shall satisfy all
obligations and liabilities it has incurred or attributable to it
prior to its withdrawal, including, without limitation, any
expenditures budgeted and/or approved by the Operating Committee prior
to its written notification of withdrawal (development projects
included), and any liability for acts, occurrences or circumstances
taking place or existing prior to its withdrawal. Furthermore, any
liens, charges and other encumbrances which the withdrawing Party
placed on such Party's Participating Interest prior to its withdrawal
shall be fully satisfied or released, at the withdrawing Party's
expense, prior to its withdrawal. A Party's withdrawal shall not
relieve it from liability to the non-withdrawing Parties with respect
to any obligations or liabilities attributable to the withdrawing
Party which are not identified or identifiable at the time of
withdrawal.
(B) Notwithstanding the foregoing, a Party shall not be liable for any
operations or expenditures it voted against if it sends notification
of its withdrawal within five (5) Days (or within twenty-four (24)
hours if the drilling rig to be used in such operation is standing by
on the Contract Area) of the Operating Committee vote approving such
operation or expenditure, nor shall such Party be liable for any
operations or expenditures approved by the Operating Committee,
excluding those approved pursuant to Article 13.5, after notice has
been given pursuant to Article 13.1.
13.5 EMERGENCY
A Party's notification of withdrawal shall not become effective if prior to
the proposed date of withdrawal a well goes out of control or a fire, blowout,
sabotage or other emergency occurs. The notification of withdrawal shall become
effective only after the emergency has been contained and the withdrawing Party
has paid, or has provided security satisfactory to the Parties, for its
Participating Interest share of the costs of such emergency.
13.6 ASSIGNMENT
A withdrawing Party shall assign its Participating Interest to each of the
non-withdrawing Parties which shall be allocated to them in the proportion which
each of their Participating Interests (prior to the withdrawal) bears to the
total Participating Interests of all the non-withdrawing Parties (prior to the
withdrawal), unless the non-withdrawing Parties agree otherwise. The expenses
associated with the withdrawal and assignments shall be borne by the withdrawing
Party.
13.7 APPROVALS
A withdrawing Party shall promptly join in such actions as may be necessary
or desirable to obtain any Government approvals required in connection with the
withdrawal and assignments, and any penalties or expenses incurred by the
Parties in connection with such withdrawal shall be borne by the withdrawing
Party.
13.8 ABANDONMENT SECURITY
(A) A withdrawing Party shall provide Security satisfactory to the other
Parties to satisfy any such obligations or liabilities which were
approved or accrued prior to notice of withdrawal, but which become
due after its withdrawal, including, without limitation, Security to
cover the costs of an abandonment, if applicable.
(B) Failure to provide Security shall constitute default under this
Agreement.
(C) "Security" means a standby letter of credit issued by a bank or an on
demand bond issued by a corporation, such bank or corporation having a
credit rating indicating it has sufficient worth to pay its
obligations in all reasonably foreseeable circumstances, or, failing
the provision of either of those, cash contributed to a secure fund
administered by independent trustees and invested in short term
securities.
13.9 WITHDRAWAL OR ABANDONMENT BY ALL PARTIES
In the event all Parties decide to withdraw or are required to do so
pursuant to this Article, the Parties agree that they shall be bound by the
terms and conditions of this Agreement and the Contract for so long as may be
necessary to wind up the affairs of the Parties with the Government, to satisfy
any requirements of applicable law and facilitate the sale, disposition or
abandonment of property or interests held by the Joint Account.
ARTICLE XIV - RELATIONSHIP OF PARTIES AND TAX
14.1 RELATIONSHIP OF PARTIES
Unless otherwise specified, the rights, duties, obligations and liabilities
of the Parties under this Agreement shall be individual, not joint or
collective. It is not the intention of the Parties to create, nor shall this
Agreement be deemed or construed to create a mining or other partnership, joint
venture, association or trust, or as authorizing any Party to act as an agent,
servant or employee for any other Party for any purpose whatsoever except as
explicitly set forth in this Agreement. In their relations with each other under
this Agreement, the Parties shall not be considered fiduciaries except as
expressly provided in this Agreement.
14.2 TAX
Each Party shall be responsible for reporting and discharging its own tax
measured by the income of the Party and the satisfaction of such Party's share
of all contract obligations under the Contract and under this Agreement. Each
Party shall protect, defend and indemnify each other Party from any and all
loss, cost or liability arising from a failure or refusal to report and
discharge such taxes or satisfy such obligations.
ARTICLE XV - CONFIDENTIAL INFORMATION -
PROPRIETARY TECHNOLOGY
15.1 CONFIDENTIAL INFORMATION
(A) Subject to the provisions of the Contract, the Parties agree that all
information and data acquired or obtained by any Party in respect of
Joint Operations shall be considered confidential and shall be kept
confidential and not be disclosed during the term of the Contract and
for a period of one (1) year after expiration of the Contract to any
person or entity not a Party to this Agreement, except:
(1) To an Affiliate, in connection with Petroleum Operations,
provided such Affiliate maintains confidentiality as
provided in this Article;
(2) To a governmental agency or other entity when required by
the Contract;
(3) To the extent such data and information is required to be
furnished in compliance with any applicable laws or
regulations, or pursuant to any legal proceedings or because
of any order of any court binding upon a Party;
(4) Subject to Article 15.1(B), to potential contractors,
contractors, consultants and attorneys employed by any Party
where disclosure of such data or information is essential to
such contractor's, consultant's or attorney's work;
(5) Subject to Article 15.1(B), to a bona fide prospective
transferee of a Party's Participating Interest (including an
entity with whom a Party or its Affiliates is conducting
bona fide negotiations directed toward a merger,
consolidation or the sale of a majority of its or an
Affiliate's shares);
(6) Subject to Article 15.1(B), to a bank or other financial
institution to the extent appropriate to a Party arranging
for funding for its obligations under this Agreement;
(7) To the extent such data and information must be disclosed
pursuant to any rules or requirements of any government or
stock exchange having jurisdiction over such Party, or its
Affiliates; provided that if any Party desires to disclose
information in an annual or periodic report to its or its
Affiliates' shareholders and to the public and such
disclosure is not required pursuant to any rules or
requirements of any government or stock exchange, then such
Party shall comply with Article 20.2;
(8) To its respective employees for the purposes of Joint
Operations, subject to each Party taking customary
precautions to ensure such data and information is kept
confidential;
(9) Where any data or information which, through no fault of a
Party, becomes a part of the public domain.
(B) Disclosure as pursuant to Article 15.1(A)(4), (5), and (6) shall not
be made unless prior to such disclosure the disclosing Party has
obtained a written undertaking from the recipient party to keep the
data and information strictly confidential and not to use or disclose
the data and information except for the express purpose for which
disclosure is to be made.
15.2 CONTINUING OBLIGATIONS
Any Party ceasing to own a Participating Interest during the term of this
Agreement shall nonetheless remain bound by the obligations of confidentiality
and any disputes shall be resolved in accordance with Article XVIII.
15.3 PROPRIETARY TECHNOLOGY
(A) Nothing in this Agreement shall require a Party to divulge proprietary
technology to the other Parties; provided that where the cost of
development of proprietary technology has been charged to the Joint
Account, such proprietary technology shall be disclosed to all Parties
bearing a portion of such cost and may be used by such Party or its
Affiliates in other operations. Operator will not charge for the use
of its proprietary technology. Operator will use reasonable efforts to
keep Non-Operators informed of the use of the proprietary technology.
(B) Non-Operators shall have access to basic field data obtained through
Operator's utilization of proprietary technology and to final maps,
data and information resulting from such utilization, with entitlement
to copies of such basic final data, maps and information as provided
for in this Agreement.
15.4 TRADES
Notwithstanding the foregoing provisions of this Article, Operator may,
with approval of the Management Committee, make data trades for the benefit of
the Parties, with any data, the cost of which has been charged to the Joint
Account, so obtained to be furnished to all Parties. In such event, Operator
must enter into an undertaking with any third party to such trade to keep such
information confidential.
ARTICLE XVI - FORCE MAJEURE
16.1 OBLIGATIONS
If as a result of Force Majeure any Party is rendered unable, wholly or in
part, to carry out its obligations under this Agreement, other than the
obligation to pay any amounts due or to furnish security, then the obligations
of the Party giving such notice, so far as and to the extent that the
obligations are affected by such Force Majeure, shall be suspended during the
continuance of any inability so caused, but for no longer period. The Party
claiming Force Majeure shall notify the other Parties of the Force Majeure
situation within seven (7) days, unless prevented from so doing, after the
occurrence of the facts relied on and shall keep all Parties informed of all
significant developments. Such notice shall give particulars establishing the
event of Force Majeure, and also estimate the period of time which said Party
will probably require to remedy the Force Majeure. The affected Party shall use
all reasonable diligence to remove or overcome the Force Majeure situation as
quickly as possible in an economic manner, but shall not be obligated to settle
any labor dispute except on terms acceptable to it and all such disputes shall
be handled within the sole discretion of the affected Party.
16.2 DEFINITION OF FORCE MAJEURE
(A) For the purpose of this Agreement, the term Force Majeure means any
cause or event, other than the unavailability of funds, whether
similar to or different from those enumerated herein, beyond the
reasonable control of, and unanticipated and unforeseeable by, and not
brought about at the instance of the Party claiming to be affected by
such event, or which, if anticipated or foreseeable, could not be
avoided or provided for and which has caused the non-performance or
delay in performance. Without limitation to the generality of the
foregoing, the term Force Majeure shall include natural phenomena or
calamities, earthquakes, typhoons, fires, wars declared or undeclared,
hostilities, invasion, blockades and civil disturbances.
(B) Where a Party is prevented from exercising any rights or performing
any obligations under this Agreement due to Force Majeure, the time
for the performance of the obligations affected thereby and for
performance of any obligation or the exercise of any right dependent
thereon, and the term of this Agreement, may be extended by such
additional period as may be agreed by the Parties.
(C) Notwithstanding anything contained hereinabove, if any event of Force
Majeure occurs and is likely to continue for a period in excess of
thirty (30) days, the Parties shall meet to discuss the consequences
of the Force Majeure and the course of action to be taken to mitigate
the effects thereof or to be adopted in the circumstances.
ARTICLE XVII - NOTICES
Except as otherwise specifically provided, all notices authorized or
required between the Parties by any of the provisions of this Agreement, shall
be in writing, in English and delivered in person or by registered mail or by
courier service or by any electronic means of transmitting written
communications which provides confirmation of complete transmission, with the
date and time, and addressed to such Parties as designated below. The
originating notice given under any provision of this Agreement shall be deemed
delivered only when received by the Party to whom such notice is directed, and
the time for such Party to deliver any notice in response to such originating
notice shall run from the date the originating notice is received. The second or
any responsive notice shall be deemed delivered when received. "Received" for
purposes of this Article with respect to written notice delivered pursuant to
this Agreement shall be actual delivery of the notice to the address of the
Party to be notified specified in accordance with this Article. Each Party shall
have the right to change its address at any time and/or designate that copies of
all such notices be directed to another person at another address, by giving
written notice thereof to all other Parties. Any notice to be provided hereunder
shall be deemed to be received by the sending Party upon delivery of such notice
to the other Parties. Operator shall, in the event of its failure to meet cash
calls or make timely payments when due to the Non-Operators, be deemed to have
received notice as if it had been timely sent to Operator.
Enron Oil & Gas India Ltd.
Amiya Apartments, 1st Floor
63A Linking Road, Santa Cruz (W)
Bombay 400 054, INDIA
Attention: Managing Director
Telecopy: 91-22-604-9119
Oil & Natural Gas Corporation Limited
Tower II, 8th Floor, Jeevan Bharati
124 Connaught Circus
New Delhi 110001, INDIA
Attention: General Manager
Telecopy: 91-11-331-6413
Reliance Industries Limited
Maker Chambers IV, 3rd Floor
222 Nariman Point
Bombay 400021, INDIA
Attention: Chief Executive Officer Oil & Gas
Telecopy: 022-2042268
ARTICLE XVIII - APPLICABLE LAW AND DISPUTE RESOLUTION
18.1 APPLICABLE LAW
This Agreement shall be governed by, construed, interpreted and applied in
accordance with the laws of India.
18.2 DISPUTE RESOLUTION
(A) Disputes and claims, if any, arising out of or relating to this
Agreement or the interpretation or performance of provisions of any of
the Articles of this Agreement and which cannot be settled amicably
within a reasonable time may be submitted to the decision of a sole
expert timely selected by the Operating Committee or a board of
arbitrators.
(B) The board of arbitrators shall consist of three (3) arbitrators.
(C) The Party or Parties instituting the arbitration shall appoint one
arbitrator and the Party or Parties responding shall appoint another
arbitrator and both Parties shall so advise the other Parties. The two
(2) arbitrators appointed by the Parties shall appoint the third
arbitrator.
(D) If the responding Party or Parties fails to appoint an arbitrator
within thirty (30) Days of the receipt of the written request to do
so, such arbitrator may, at the request of the first Party, be
appointed by the Secretary General of the Permanent Court of
Arbitration at The Hague, which arbitrator shall not be the national
of the country of either Party.
(E) If the two (2) arbitrators fail to agree on the appointment of the
third arbitrator within thirty (30) days of the appointment of the
second arbitrator and if the Parties do not otherwise agree,the
Secretary General of the Permanent Court of Arbitration at the Hague
may, at the request of either Party and in consultation with both,
appoint the third arbitrator who shall not be a national of the
country of either Party.
(F) If any arbitrator fails or is unable to act, his successor shall be
appointed in the manner set out in this Article as if he was the first
appointment.
(G) The decision of the board of arbitrators, and in case of difference
amongst the arbitrators, the decision of the majority shall be final
and binding upon the Parties. Such decision may be entered into the
Indian court having jurisdiction thereof.
(H) Arbitration proceedings shall be in accordance with the arbitration
rules of the United Nations Commission on International Trade Laws
("UNCITRAL") of 1985 except that in the event of any conflict between
these rules and the provisions of Article 18, the provisions of
Article 18 shall govern.
(I) The venue of arbitration shall be in London, England and shall be
conducted in the English language. The arbitration agreement contained
in this Article 18 shall be governed by the laws of England.
(J) Assessment of costs of arbitration including incidental expenses and
liability for the payment thereof shall be at the discretion of the
arbitrators.
(K) The right to arbitrate disputes and claims under this Agreement shall
survive the termination of this Agreement.
(L) The arbitrators shall make reasoned award.
(M) The sole expert, if any, shall be an independent and impartial person
of international standing with relevant qualifications and experience
appointed by agreement between the Parties. Any sole expert appointed
shall be acting as an expert and not as an arbitrator and the decision
of the sole expert on matters referred to him shall be final and
binding on the Parties and not subject to arbitration. If the Parties
are unable to agree on a sole expert, the disputed subject matter may
be referred to arbitration.
(N) The fees and expenses of a sole expert appointed by the Parties shall
be borne equally by the Parties.
ARTICLE XIX - ALLOCATION OF COST RECOVERY RIGHTS
19.1 ALLOCATION OF TOTAL PRODUCTION
For the purposes of recovery of Petroleum Costs, the total quantity of
Hydrocarbons which are produced and saved from all Development Areas in a
Calendar Quarter and to which the Parties are entitled under the Contract shall
be designated as either Cost Petroleum or Profit Petroleum. Such Cost Petroleum
and Profit Petroleum shall be allocated among the Development Areas in
proportion to each Development Area's total quantity of Hydrocarbons produced
and saved in such Calendar Quarter with adjustments in quantities to reflect the
differences in value if different qualities of Hydrocarbons are produced,
segregated and sold separately.
19.2 ALLOCATION OF COST PETROLEUM
Cost Petroleum allocated to each Development Area pursuant to Article 19.1
shall be allocated to the Parties in proportion to their respective
Participating Interests in each such Development Area to the extent required to
recover in the sequence incurred all Petroleum Costs which are specifically
attributable to each such Development Area and which are recoverable in such
Calendar Quarter.
19.3 ALLOCATION OF PROFIT PETROLEUM
Profit Petroleum allocated to each Development Area pursuant to Article
19.1, if any, shall be allocated among the Parties in proportion to their
respective Participating Interests in each such Development Area.
19.4 ALLOCATION OF EXCESS COST PETROLEUM
Subject to the Contract, to the extent that the value, determined in
accordance with Article 9.2(H), of the Cost Petroleum allocated to each
Development Area pursuant to Article 19.1 exceeds the Petroleum Costs which were
specifically attributable to each such Development Area and which were recovered
pursuant to Article 19.2, the excess ("Excess Cost Petroleum") shall be
allocated as follows:
(A) First, a percentage (equal to the percentage of Profit Petroleum, if
any, to which the Parties would have been entitled during such
Calendar Quarter if the Contract applied separately to each such
Development Area) of the Excess Cost Petroleum shall be allocated
among the Parties in proportion to their respective Participating
Interests in each such Development Area;
(B) Second, the Excess Cost Petroleum that is not allocated pursuant to
Article 19.4(A) shall be allocated among the Parties in proportion to
their respective Participating Interests as set out in Article 3.1(A)
in order to recover in the sequence incurred any Petroleum Costs which
were incurred in the conduct of Joint Operations and which are
recoverable in such Calendar Quarter; and
(C) Third, the Excess Cost Petroleum that is not allocated pursuant to
Article 19.4(A) or Article 19.4(B) shall be allocated among the
Parties in proportion to their respective Participating Interests in
each Exclusive Operation in order to recover in the sequence incurred
any Petroleum Costs which were incurred in the conduct of Exclusive
Operations and which are recoverable in such Calendar Quarter.
ARTICLE XX - GENERAL PROVISIONS
20.1 CONFLICTS OF INTEREST
(A) Each Party undertakes that it shall avoid any conflict of interest
between its own interests (including the interests of Affiliates) and
the interests of the other Parties in dealing with suppliers,
customers and all other organizations or individuals doing or seeking
to do business with the Parties in connection with activities
contemplated under this Agreement.
(B) The provisions of the preceding paragraph shall not apply to:
(1) A Party's performance which is in accordance with the local
preference laws or policies of the host government; or
(2) A Party's acquisition of products or services from an
Affiliate, or the sale thereof to an Affiliate, made in
accordance with rules and procedures established by the
Operating Committee.
(C) Each Party shall conduct all of its activities pursuant to this
Agreement and the Contract in compliance with all laws, rules and
regulations applicable to such Party. Each of the Parties warrants
that it has not made and will not make, with respect of the matters
provided for hereunder, any payments, loans, gifts or promises of
payments, loans or gifts, directly or indirectly to or for the use or
benefit of any official or employee of the Government or to or for the
use of any political party. Each Party shall respond promptly, and in
reasonable detail, to any Notice from any other Party or the auditors
pertaining to the above stated warranty and shall furnish documentary
support for such response upon request from such Party.
20.2 PUBLIC ANNOUNCEMENTS
(A) Operator shall be responsible for the preparation and release of all
public announcements and statements regarding this Agreement or the
Joint Operations; provided that, no public announcement or statement
shall be issued or made unless prior to its release all the Parties
have been furnished with a copy of such statement or announcement and
the unanimous approval of the Parties has been obtained. Where a
public announcement or statement becomes necessary or desirable
because of danger to or loss of life, damage to property or pollution
as a result of activities arising under this Agreement, Operator is
authorized to issue and make such announcement or statement without
prior approval of the Parties, but shall promptly furnish all the
Parties with a copy of such announcement or statement.
(B) If a Party wishes to issue or make any public announcement or
statement regarding this Agreement or the Joint Operations, it shall
not do so unless prior to its release, such Party furnishes all the
Parties with a copy of such announcement or statement, and obtains the
unanimous approval of the Parties; provided that, notwithstanding any
failure to obtain such approval, no Party shall be prohibited from
issuing or making any such public announcement or statement if it is
necessary to do so in order to comply with the applicable laws, rules
or regulations of any government, legal proceedings or stock exchange
having jurisdiction over such Party as set forth in Articles
15.1(A)(3) and (7).
20.3 SUCCESSORS AND ASSIGNS
Subject to the limitations on transfer contained in Article XII, this
Agreement shall inure to the benefit of and be binding upon the successors and
assigns of the Parties.
20.4 WAIVER
No waiver by any Party of any one or more defaults by another Party in the
performance of this Agreement shall operate or be construed as a waiver of any
future default or defaults by the same Party, whether of a like or of a
different character. Except as expressly provided in this Agreement no Party
shall be deemed to have waived, released or modified any of its rights under
this Agreement unless such Party has expressly stated, in writing, that it does
waive, release or modify such right.
20.5 SEVERANCE OF INVALID PROVISIONS
If and for so long as any provision of this Agreement shall be deemed to be
judged invalid for any reason whatsoever, such invalidity shall not affect the
validity or operation of any other provision of this Agreement except only so
far as shall be necessary to give effect to the construction of such invalidity,
and any such invalid provision shall be deemed severed from this Agreement
without affecting the validity of the balance of this Agreement.
20.6 MODIFICATIONS
Except as is provided in Article 20.5, there shall be no modification of
this Agreement except by written consent of all Parties.
20.7 HEADINGS
The topical headings used in this Agreement are for convenience only and
shall not be construed as having any substantive significance or as indicating
that all of the provisions of this Agreement relating to any topic are to be
found in any particular Article.
20.8 SINGULAR AND PLURAL
Reference to the singular includes a reference to the plural and vice
versa.
20.9 GENDER
Reference to any gender includes a reference to all other genders.
20.10 COUNTERPART EXECUTION
This Agreement may be executed in any number of counterparts and each such
counterpart shall be deemed an original Agreement for all purposes; provided no
Party shall be bound to this Agreement unless and until all Parties have
executed a counterpart. For purposes of assembling all counterparts into one
document, Operator is authorized to detach the signature page from one or more
counterparts and, after signature thereof by the respective Party, attach each
signed signature page to a counterpart.
20.11 CONFLICT WITH CONTRACT
In the event of any inconsistency between the provisions of the Contract
and this Agreement, the provisions of the Contract shall prevail.
20.12 ENTIRETY
This Agreement is the entire agreement of the Parties and supersedes all
prior understandings and negotiations of the Parties.
IN WITNESS of their agreement each Party has caused its duly authorized
representative to sign this instrument on the date indicated below such
representative's signature.
ENRON OIL & GAS INDIA LTD.
By: /S/ A. KOPECKY
A. Kopecky
(Print or type name)
Title: Vice President - Operations
Date: 22 Dec 94
RELIANCE INDUSTRIES LIMITED
By: /S/ AKHIL GUPTA
Akhil Gupta
(Print or type name)
Title: CEO (oil & gas)
Date: 22-12-94
OIL & NATURAL GAS CORPORATION LIMITED
By: /S/ ISHWARI DATT
Ishwari Datt
(Print or type name)
Title: Director (ops) (on leave)
Date: 22-12-94
-----*****-----
<PAGE>
EXHIBIT "A"
ACCOUNTING PROCEDURE
Attached to and made part of the Joint Operating Agreement, hereinafter
called the "Agreement," by and between OIL & NATURAL GAS CORPORATION LIMITED,
ENRON OIL & GAS INDIA LTD. and RELIANCE INDUSTRIES LIMITED.
SECTION I.
GENERAL PROVISIONS
1.1 PURPOSE.
1.1.1 The purpose of this Accounting Procedure is to establish
equitable methods for determining charges and credits applicable
to operations under the Agreement which reflect the costs of
Joint Operations to the end that no Party shall gain or lose in
relation to other Parties.
1.1.2 The Parties agree, however, that if the methods prove unfair or
inequitable to Operator or Non-Operators, the Parties will meet
and in good faith endeavor to agree on changes in methods deemed
necessary to correct any unfairness or inequity.
1.2 CONFLICT WITH AGREEMENT. In the event of a conflict between the
provisions of this Accounting Procedure and the provisions of the
Agreement to which this Accounting Procedure is attached, the provisions
of the Agreement shall prevail.
1.3 DEFINITIONS. The definitions contained in Article I of the Agreement to
which this Accounting Procedure is attached shall apply to this
Accounting Procedure and have the same meanings when used herein.
Certain terms used herein are defined as follows:
"COUNTRY OF OPERATIONS" shall mean India.
"MATERIAL" shall mean property, not including real property,
acquired and held for use in Joint Operations.
1.4 JOINT ACCOUNT RECORDS AND CURRENCY EXCHANGE.
1.4.1 All accounts, records, books, reports and statements shall be
maintained on an accrual basis and prepared in the English
language. The accounts shall be maintained in United States
Dollars, which shall be the controlling currency of account for
cost recovery, production sharing and participation purposes.
Metric units and Barrels shall be employed for measurements
required under the Contract. Operator shall maintain accounts and
records in Indian Rupees also.
1.4.2 Operator shall maintain accounting records pertaining to Joint
Operations in accordance with generally accepted accounting
practices used in the international petroleum industry and any
applicable statutory obligations of the Country of Operations as
well as the provisions of this Contract and the Agreement.
1.4.3 For translation purposes between United States Dollars and India
Rupees or any other currency, the previous month's average of the
daily means of the buy and selling rates of exchange as quoted by
the State Bank of India (or any other financial body as may be
mutually agreed between the Parties) shall be used for the month
in which the revenues, costs, expenditures, receipts or income
are recorded. However, in the case of any single non-United
States Dollar transaction in excess of the equivalent of One
Hundred Thousand United States Dollars (US$100,000), the
conversion into United States Dollars shall be performed on the
basis of the average of the applicable exchange rates for the Day
on which the transaction occurred.
1.4.4 Any currency exchange gains or losses shall be credited or
charged to the Joint Account, except as otherwise specified in
this Accounting Procedure.
1.4.5 This Accounting Procedure shall apply, mutatis mutandis, to
Exclusive Operations in the same manner that it applies to Joint
Operations; provided, however, that the charges and credits
applicable to Consenting Parties shall be distinguished by an
Exclusive Operation Account. For the purpose of determining and
calculating the remuneration of the Consenting Parties, including
the premiums for Exclusive Operations, the costs and expenditures
shall be expressed in U.S. currency (irrespective of the currency
in which the expenditure was incurred).
1.5 STATEMENTS AND BILLINGS.
1.5.1 Unless otherwise agreed by the Parties, Operator shall submit
monthly to each Party, on or before the 25th Day of each month,
statements of the costs and expenditures incurred during the
prior month, indicating by appropriate classification the nature
thereof and the portion of such costs charged to each of the
Parties.
These statements shall contain the following information:
- advances of funds setting forth the currencies received
from each Party
- the share of each Party in total expenditures on a cash
and accrual basis
- the current account cash balance of each Party
- summary of costs, credits, and expenditures on a current
month, year-to-date, and inception-to-date basis or other
periodic basis, as agreed by the Parties for each line
item of the approved Work Program and Budget
- unusual charges and credits in excess of U.S. dollars one
hundred thousand (U.S.$100,000.00) and all adjustments
arising out of audit shall be detailed.
1.5.2 Operator shall, upon request, furnish a description of the
accounting classifications used by it.
1.5.3 Amounts included in the statements and billings shall be
expressed in U.S. currency and reconciled to the currencies
advanced. Other currency equivalents may be presented as agreed
between the Parties.
1.5.4 Each Party shall be responsible for preparing its own accounting
and tax reports to meet the Country of Operations and other
country requirements. Operator, to the extent that the
information is reasonably available from the Joint Account
records, will provide in a timely manner Non-Operators with the
necessary statements to facilitate the discharge of such
responsibility.
1.5.5 The billing statement is to be accompanied by billing schedules
which shall be schedules dividing such expenditure and income
into main classifications of expenditure as indicated by approved
budget and AFEs issued. The billing schedules shall also show
cumulative totals of all payments linked to AFEs and budget
categories and receipts.
1.6 PAYMENTS AND ADVANCES.
1.6.1 Upon approval of any Work Program and Budget, if Operator so
requests, all Parties, including the Operator, shall advance its
share of estimated cash requirements for the succeeding month's
operations. Each such cash call shall be equal to the Operator's
estimate of the money to be spent in the currencies required to
perform its duties under the approved Work Program and Budget
during the month concerned. For informational purposes the cash
call shall contain an estimate of the funds required for the
succeeding two (2) months. All such cash calls shall be related
to the progress/activities achieved and to planned
progress/activities to be achieved during the period concerned.
1.6.2 Each such cash call, detailed by major budget categories and AFEs
(where applicable), shall be made in writing and delivered to all
Non-Operators not less than fifteen (15) Days before the payment
due date. Except as otherwise provided in Section 1.6.4, the due
date for payment of such advances shall be set by Operator but
shall be no sooner than the first Business Day of the month for
which the advances are required.
If, and only if, a Non-Operator believes that the cash call or a
portion thereof is not as per the approved Work Program and
Budget and AFE (where applicable), the Party may inform its view
to all Parties within five (5) Business Days of the receipt of
such cash call. Operator may issue a revised cash call. If no
revision is issued, payment to the Operator shall be made by the
due date as follows: as to the Non-Operator who raised the
dispute, the non-disputed amount; and as to other Parties, the
amount as determined by such Party's original cash call prior to
the dispute, plus a portion of the disputed amount determined by
the ratio of each such Party's Participating Interest to the sum
of all Participating Interests of the Parties who did not dispute
the cash call within the said five (5) Business Days.
Notwithstanding the provisions of Article 8.9, the amount in
dispute shall be paid by the disputing Party by the due date to
an interest bearing joint escrow account where such funds will be
held until the matter in dispute has been resolved. The issue
arising out of such disputed cash call shall be resolved as soon
as practicable by any appropriate means including, but not
limited to, discussing the issue in the next Operating Committee
meeting so as to assist in resolving the matter, failing which,
the matter may be submitted to arbitration by any Party and the
arbitrator shall determine appropriate distribution of the escrow
account, plus, if appropriate, penal interest specified in
Article 8.1.
1.6.3 Each Non-Operator shall remit its share of the full amount of
each such cash call to Operator on or before the due date, in the
currencies requested which must be freely convertible or any
other currencies acceptable to Operator, and at a bank designated
by Operator for the purpose of Joint Operations. If currency
provided by a Non-Operator is other than the requested currency,
then the entire cost of converting to the requested currency
shall be charged to that Non-Operator. Nothing herein shall
relieve any Non-Operator from the obligation to provide
immediately available funds, in full, by the due date.
1.6.4 Should Operator be required to pay any sums of money for the
Joint Operations as per the approved Work Program and Budget
which were unforeseen at the time of providing the Non-Operators
with said estimates of its requirements, the Operator may make a
written request of the Non-Operators for special advances
covering the Non-Operators' share of such payments. Each such
Non-Operator shall make its proportional special advances within
ten (10) Business Days after receipt of such notice.
1.6.5 When the total of cash calls for any month is one million U.S.
dollars (U.S.$1,000,000.00) or less, each Party, including the
Operator, shall advance its share thereof in accordance with this
Section 1.6. When the total cash requirements exceed the
aforesaid amount, each Party, including the Operator, shall
advance its share of the estimated funds required in three (3)
installments of amounts to be specified by the Operator, the
first installment to be paid not later than the first Business
Day of the month for which the advance is required and the second
installment to be paid not later than the tenth Day of the month
for which the advance is required or if such Day is not a
Business Day, then the following Business Day and the third
installment to be paid not later than the twentieth Day of the
month for which the advance is required or if such Day is not a
Business Day, then the following Business Day. The third
installment can be adjusted by the Operator by notifying the
Parties, including the Operator, of the adjusted amount no later
than the fifteenth Day of the month for which the advance is
required.
1.6.6 If a Non-Operator's advances exceed its share of cash
expenditures, succeeding month's cash requirements, after such
determination, shall be reduced accordingly. A Non-Operator may
request that its excess advances be refunded. Operator shall make
such refund within ten (10) Business Days after receipt of the
Non-Operator's request provided that the amount is in excess of
the cash requirements for the month of such determination. If the
Operator does not make such refund within ten (10) Business Days,
then the Operator shall pay each Party requesting a refund the
difference between the Agreed Interest Rate and the interest
earned on the Joint Account.
1.6.7 If Non-Operator's advances are less than its share of cash
expenditures, the deficiency shall, at Operator's option, be
added to subsequent cash advance requirements or be paid by
Non-Operator within eight (8) Business Days following the receipt
of Operator's billing to Non-Operator for such deficiency. Along
with notice of payment due, the Operator shall provide details
supporting that the Non-Operator's advance is less than its share
of cash expenditures.
1.6.8 Any interest received by Operator from interest-bearing accounts
containing funds received from the Parties shall be credited to
the Parties. The interest earned will be allocated to the Parties
on an equitable basis taking into consideration date of funding
by each Party to the accounts in proportion to the total funding
into the account. A monthly statement summarizing receipts,
disbursements, transfers to each joint bank account and beginning
and ending balances thereof shall be provided by the Operator to
the Parties.
1.6.9 Payments of cash calls or billings as per approved Work Program
and Budget shall be made on or before the due date. If these
payments are not received by the due date the unpaid balance
shall bear and accrue interest from the due date until the
payment is received by the Operator at the Agreed Interest Rate.
For the purpose of determining the unpaid balance and interest
owed, Operator shall translate to U.S. currency all amounts owed
in other currencies using the currency exchange rate readily
available to Operator at the close of the last banking Day prior
to the due date for the unpaid balance as quoted by the
applicable authority identified in Section 1.4.3.
1.6.10 Subject to governmental regulation, Operator shall have the
right, at any time and from time to time, to convert the funds
advanced or any part thereof to other currencies to the extent
that such currencies are then required for operations. The cost
of any such conversion shall be charged to the Joint Account.
However, such conversions should be avoided as far as practical.
1.6.11 Operator shall endeavor to maintain funds held in bank accounts
for the Joint Account at a level consistent with that required
for the prudent conduct of Joint Operations.
1.7 ADJUSTMENTS. Payments of any advances or billings shall not prejudice the
right of any Non-Operator to protest or question the correctness thereof;
provided, however, all bills and statements rendered to Non-Operators by
Operator during any Financial Year shall conclusively be presumed to be
true and correct after twenty-four (24) months following the end of such
Financial Year, unless within the said twenty-four (24) month period a
Non-Operator takes written exception thereto and makes claim on Operator
for adjustment. Failure on the part of a Non-Operator to make claim on
Operator for adjustment within such period shall establish the
correctness thereof and preclude the filing of exceptions thereto or
making claims for adjustment thereon. No adjustment favorable to Operator
shall be made unless it is made within the same prescribed period. The
provisions of this paragraph shall not prevent adjustments resulting from
a physical inventory of the Property as provided for in Section VI. The
Operator shall be allowed to make adjustments to the Joint Account after
such twenty-four (24) month period if these adjustments result from audit
exceptions outside of this agreement, third party claims, or Government
requirements. Any such adjustments shall be subject to audit within the
time period specified in Section 1.8.1.
1.8 AUDITS.
1.8.1 A Non-Operator, upon at least sixty (60) Days advance notice in
writing to Operator and all other Non-Operators, shall have the
right to audit the Joint Accounts and records of Operator
relating to the accounting hereunder for any Financial Year
within the twenty-four (24) month period following the end of
such Financial Year. The cost of each such audit shall be borne
by Non-Operators conducting the audit. It is provided, however,
that Non-Operators must take written exception to and make claim
upon the Operator for all discrepancies disclosed by said audit
within said twenty-four (24) month period. Where there are two or
more Non-Operators, the Non-Operators shall make every reasonable
effort to conduct joint or simultaneous audits in a manner which
will result in a minimum of inconvenience to the Operator.
Operator and Non-Operators shall make every effort to resolve any
claim resulting from an audit within a reasonable period of time.
A Non-Operator may audit the records of an Affiliate of Operator
relating to that Affiliate's charges. The provisions of this
Accounting Procedure shall apply mutatis mutandis to such audits.
1.8.2 Any information obtained by a Non-Operator under the provisions
of this Section 1.8 which does not relate directly to the Joint
Operations shall be kept confidential and shall not be disclosed
to any party, except as would otherwise be permitted by Article
15.1(A)(3) and (9) of the Agreement.
1.8.3 The Operator is required by Contract to employ a qualified
independent firm of internationally recognized chartered
accountants registered in India to audit the Contract Account
Books and records of Operator relating to the accounting
hereunder, the cost thereof shall be a charge against the Joint
Account, and a copy of the accounting reports and audit report
shall be furnished to each Party within ninety (90) days of the
close of a Financial Year.
1.9 ALLOCATIONS. If it becomes necessary to allocate any common costs or
expenditures to or between Joint Operations and any other operations,
such allocation shall be made on an equitable basis in accordance with
international accounting standards. Upon request, Operator shall furnish
a description of its allocation procedures pertaining to these costs and
expenditures. A Non-Operator may cause Operating Committee to review such
allocation basis and Operating Committee may decide a revision to the
allocation, failing which, the matter may be referred to a sole expert or
arbitration.
-----*****-----
SECTION II.
DIRECT CHARGES
Operator shall charge the Joint Account with all costs and expenditures incurred
in connection with Joint Operations. It is also understood that charges for
services normally provided by an Operator such as those contemplated in Section
2.4.2.2 which are provided by Operator's Affiliates shall reflect the cost to
the Affiliate, excluding profit, for performing such services, except as
otherwise provided in Section 2.4.2 and Section 2.4.2.3 if selected.
The costs and expenditures will be recorded as required for the settlement of
accounts between the Parties hereto in connection with the rights and
obligations under this Agreement and for purposes of complying with Country of
Operations and United States tax laws. Without in any way limiting the
generality of the foregoing, chargeable costs and expenditures shall include:
2.1 LICENSES, PERMITS, ETC.
All costs, if any, attributable to the acquisition, maintenance, renewal
or relinquishment of licenses, permits, contractual and/or surface rights
acquired for Joint Operations and bonuses paid in accordance with the
Contract when paid by Operator in accordance with the provisions of the
Agreement.
2.2 LABOR AND ASSOCIATED COSTS.
2.2.1 OPERATOR'S LOCALLY RECRUITED EMPLOYEES BASED IN INDIA.
Costs of all Operator's locally recruited employees who are
directly engaged in the conduct of Petroleum Operations under the
Contract in India. Such costs shall include the costs of employee
benefits and Government benefits for employees and levies imposed
on the Operator as an employer, transportation and relocation
costs within India of the employee and such members of the
employee's family (limited to spouse and dependent children) as
required by law or customary practice in India. If such employees
are engaged in other activities in India, in addition to
Petroleum Operations, the cost of such employees shall be
apportioned on a time sheet basis according to sound and
acceptable accounting and costing principles.
2.2.2 ASSIGNED PERSONNEL.
Costs of salaries and wages, including bonuses, of the Operator's
employees directly and necessarily engaged in the conduct of the
Petroleum Operations under the Contract, whether temporarily or
permanently assigned, irrespective of the location of such
employees, it being understood that in the case of those
personnel only a portion of whose time is wholly dedicated to
Petroleum Operations under the Contract, only that pro rata
portion of applicable salaries, wages and other costs, as
specified in Sections 2.2.3, 2.2.4, 2.2.5, 2.2.6 and 2.2.7 shall
be charged and the basis of such pro rata allocation shall be
specified.
2.2.3 The Operator's costs regarding holiday, vacation, sickness and
disability benefits and living and housing and other customary
allowances applicable to the salaries and wages chargeable under
Section 2.2.2 above.
2.2.4 Expenses or contributions made pursuant to assessments or
obligations imposed under the laws of India which are applicable
to the Operator's cost of salaries and wages chargeable under
Section 2.2.2 above.
2.2.5 The Operator's cost of established plans for employees' group
life insurance, hospitalization, pension, retirement and other
benefit plans of a like nature customarily granted to the
Operator's employees provided, however, that such costs are in
accordance with generally accepted standards in the international
petroleum industry, applicable to salaries and wages chargeable
to petroleum operations under Section 2.2.2 above.
2.2.6 Personal Income taxes where and when they are paid by the
Operator to the Government of India for the employee, in
accordance with the Contractor's standard personnel policies.
2.2.7 Reasonable transportation and travel expenses of employees of the
Operator, including those made for travel and relocation of the
expatriate employees, including their dependent family and
personal effects, assigned to India whose salaries and wages are
chargeable to petroleum operations under Section 2.2.2. Actual
transportation expenses of personnel transferred to petroleum
operations from their country of origin and/or relocation to
their country of origin expenses shall be charged to the
petroleum operations.
2.2.8 Transportation cost as used in this Section shall mean the cost
of freight and passenger service and any accountable incidental
expenditures related to transfer travel and authorized under
Operator's standard personnel policies. Operator shall ensure
that all expenditures related to transportation costs are
equitably allocated to the activities which have benefited from
the personnel concerned.
2.3 TRANSPORTATION COSTS.
The reasonable cost of transportation of equipment, materials and
supplies within India and from outside India to India necessary for the
conduct of petroleum operations under the Contract, including, but not
limited to, directly related costs such as unloading charges, dock fees
and inland and ocean freight charges.
2.4 CHARGES FOR SERVICES.
2.4.1 THIRD PARTIES.
The actual costs of contract services, services of professional
consultants, utilities and other services necessary for the
conduct of petroleum operations under the Contract performed by
third parties other than an Affiliate of the Operator, provided
that the transactions resulting in such costs are undertaken
pursuant to arms length transactions.
2.4.2 AFFILIATES OF OPERATOR.
2.4.2.1 PROFESSIONAL AND ADMINISTRATIVE SERVICES AND EXPENSES.
Cost of professional and administrative services provided
by any Affiliate for the direct benefit of petroleum
operations, including, but not limited to, services
provided by the production, exploration, legal,
financial, insurance, accounting and computer services
divisions other than those covered by Section 2.4.2.2
which Operator may use in lieu of having its own
employees. Charges shall be equal to the actual cost of
providing their services, shall not include any element
of profit and shall not be any higher than the most
favorable prices charged by the Affiliate to third
parties for comparable services under similar terms and
conditions elsewhere and will be fair and reasonable in
the light of prevailing international oil industry
practice and experience.
2.4.2.2 SCIENTIFIC OR TECHNICAL PERSONNEL.
Cost of scientific or technical personnel services
provided by any Affiliate of Operator for the direct
benefit of petroleum operations, which cost shall be
charged on a cost of service basis without element of
profit. Charges therefor shall not exceed charges for
comparable services currently provided by outside
technical service organizations of comparable
qualifications. Unless the work to be done by such
personnel is covered by an approved budget and Work
Programme, Operator shall not authorize work by such
personnel without approval of the Management Committee.
2.4.2.3 Equipment, facilities and property owned and furnished by
the Operator's Affiliates, at rates commensurate with the
cost of ownership and operation provided, however, that
such rates shall not exceed those currently prevailing
for the supply of like equipment, facilities and property
on comparable terms in the area where the petroleum
operations are being conducted. The equipment and
facilities referred to herein shall exclude major
investment items such as (but not limited to) drilling
rigs, producing platforms, oil treating facilities, oil
and gas loading and transportation systems, storage and
terminal facilities and other major facilities, rates for
which shall be subject to separate agreement with the
Government.
2.5 COMMUNICATIONS.
Cost of acquiring, leasing, installing, operating, repairing and
maintaining communication systems including satellite, radio and
microwave facilities between the Contract Area and the Operator's base
facility, offices, helicopter bases, port and railway yards.
2.6 OFFICE, SHORE BASES AND MISCELLANEOUS FACILITIES.
Net cost to Operator of establishing, maintaining and operating any
office, sub-office, shore base facility, warehouse, housing or other
facility directly serving the petroleum operations. If any such facility
services contract areas other than the Contract Area, or any business
other than petroleum operations, the net costs thereof shall be allocated
on an equitable and consistent basis.
2.7 ENVIRONMENTAL STUDIES AND PROTECTION.
Costs incurred in conducting the environmental impact studies for the
Contract Area, and in taking environmental protection measures pursuant
to the terms of the Contract.
2.8. INSURANCE.
Premiums paid for insurance required by law, the Contract or the
Agreement to be carried for the benefit of the Joint Operations.
2.9. DAMAGES AND LOSSES TO PROPERTY.
2.9.1 All costs or expenditures necessary to replace or repair damages
or losses incurred by fire, flood, storm, theft, accident, or any
other cause. Operator shall furnish Non-Operators written notice
of damages or losses incurred in excess of Fifty Thousand U.S.
Dollars (U.S.$50,000) as soon as practical after report of the
same has been received by Operator. All losses in excess of Fifty
Thousand U.S. Dollars (U.S.$50,000) shall be listed separately in
the monthly statement of costs and expenditures.
2.9.2. Credits for settlements received from insurance carried for the
benefit of Joint Operations and from others for losses or damages
to Joint Property or Materials. Each Party shall be credited with
its Participating Interest share thereof except where such
receipts are derived from insurance purchased by Operator for
less than all Parties in which event such proceeds shall be
credited to those Parties for whom the insurance was purchased in
the proportion of their respective contributions toward the
insurance coverage.
2.9.3. Expenditures incurred in the settlement of all losses, claims,
damages, judgements and other expenses for the benefit of Joint
Operations.
2.10 LITIGATION AND LEGAL EXPENSES.
2.10.1 Legal services necessary or expedient for the protection of the
Joint Operations, and all costs and expenses of litigation,
arbitration or other alternative dispute resolution procedure,
including reasonable attorneys' fees and expenses, together with
all judgments obtained against the Parties or any of them arising
from the Joint Operations.
2.10.2. If the Parties hereunder shall so agree, actions or claims
affecting the Joint Operations hereunder may be handled by the
legal staff of one or any of the Parties hereto; and a charge
commensurate with the reasonable costs of providing and
furnishing such services rendered may be made against the Joint
Account, but no such charges shall be made until approved by the
Parties.
2.11 TAXES AND DUTIES.
All taxes, duties, assessments and governmental charges, of every kind
and nature, assessed or levied upon or in connection with the Joint
Operations, other than any that are measured by or based upon the
revenues, income and net worth of a Party.
If Operator or an Affiliate is subject to income or withholding tax as a
result of services performed at cost for the operations under the
Agreement, its charges for such services may be increased by the amount
of such taxes incurred (grossed up).
2.12 OTHER EXPENDITURES.
Any other costs and expenditures incurred by the Operator for the
necessary and proper conduct of the Joint Operations in accordance with
approved Work Programs and Budgets and not covered in this Section II or
in Section III.
-----*****-----
SECTION III.
INDIRECT CHARGES
3.1 Operator shall charge the Joint Account monthly for the cost of indirect
services and related office costs of Operator and its Affiliates not
otherwise provided in this Accounting Procedure. No cost or expenditure
included under Section II shall be included or duplicated under this
Section III. Indirect services and related office costs of Operator and
its Affiliates outside the Country of Operations include but are not
limited to the cost of the following functions which are of benefit to
the Joint Operations:
Executive, Administrative, & Managerial
Treasury and Financial Services
Tax and Legal
Human Resources
Insurance
Accounting and Internal Control
Employee Training and Medical
Safety and Security
Budgeting and Forecasting
Communications
3.2 The charge for the period beginning with the Financial Year through the
end of the period covered by Operator's invoice ("Year-to-Date") under
Section 3.1 above shall be a percentage of the Year-to-Date Parties'
total direct expenditures, charged to the Joint Account, calculated on
the following scale (U.S. Dollars):
ANNUAL EXPENDITURES
One percent (1%) of expenditures
3.3 The expenditures used to calculate the monthly indirect charge shall not
include the indirect charge (calculated either as a percentage of
expenditures or as a minimum monthly charge), rentals on surface rights
acquired and maintained for the Joint Account, guarantee deposits,
concession acquisition costs, bonuses paid in accordance with the
Contract, royalties and taxes paid under the Contract, settlement of
claims, proceeds from the sale of assets (including division in kind)
amounting to more than U.S.$10,000 per transaction, and similar items
mutually agreed upon by the Parties.
Credits arising from any government subsidy payments and disposition of
Joint Account property shall not be deducted from total expenditures in
determining such charge.
3.4 The indirect charges provided for in this Section III may be amended
periodically by mutual agreement between the Parties if, in practice,
these charges are found to be insufficient or excessive.
SECTION IV.
ACQUISITION OF MATERIAL AND EQUIPMENT
4.1 MATERIALS AND EQUIPMENT.
4.1.1 GENERAL.
So far as is practicable and consistent with efficient and
economical operation, only such material shall be purchased or
furnished by the Operator for use in the petroleum operations as
may be required for use in the reasonably foreseeable future and
the accumulation of surplus stocks shall be avoided to the extent
possible.
4.1.2 WARRANTY.
In the case of defective material or equipment, any adjustment
received by the Operator from the suppliers or manufacturers or
their agents in respect of any warranty on material or equipment
shall be credited to the accounts under the Agreement.
4.1.3 VALUE OF MATERIALS CHARGED TO THE ACCOUNTS UNDER THE CONTRACT.
4.1.3.1 Except as otherwise provided in subparagraph 4.1.2,
materials purchased by the Operator and used in the
petroleum operations shall be valued to include invoice
price less trade and cash discounts, if any, purchase
and procurement fees plus freight and forwarding charges
between point of supply and point of shipment, freight
to port of destination, insurance, taxes, customs
duties, consular fees, other items chargeable against
imported material and, where applicable, handling and
transportation costs from point of importation to
warehouse or operating site, and these costs shall not
exceed those currently prevailing in normal arms length
transactions on the open market.
4.1.3.2 Material purchased from or sold to Affiliates or
transferred to or from activities of the Operator other
than petroleum operations under the Contract.
4.1.3.2.1 new material (hereinafter referred to as
condition A) shall be valued at the current
international price which shall not exceed
the price prevailing in normal arms length
transactions on the open market;
4.1.3.2.2 used material which is in sound and
serviceable condition and is suitable for
reuse without reconditioning (hereinafter
referred to as condition B) shall be priced
at not more than seventy five percent (75%)
of the current price of the above mentioned
new materials;
4.1.3.2.3 used material which cannot be classified as
condition B, but which, after reconditioning,
will be further serviceable for original
function as good second-hand condition B
material or is serviceable for original
function, but substantially not suitable for
reconditioning (hereinafter referred to as
condition C) shall be priced at not more than
fifty per cent (50%) of the current price of
the new material referred to above as
condition A.
The cost of reconditioning shall be charged to the reconditioned
material, provided that the condition C material value plus the
cost of reconditioning does not exceed the value of condition B
material.
Material which cannot be classified as condition B or condition C
shall be priced at a value commensurate with its use.
Material involving erection expenditure shall be charged at the
applicable condition percentage (referred to above) of the current
knocked-down price of new material referred to above as condition
A.
When the use of material is temporary and its service to the
Petroleum Operations does not justify the reduction in price in
relation to materials referred to above as conditions B and C,
such material shall be priced on a basis that will result in a net
charge to the accounts under the Contract consistent with the
value of the service rendered.
4.2 PREMIUM PRICES.
Whenever Material is not readily obtainable at prices specified in
Section 4.1 of this Section IV because of national emergencies, strikes
or other unusual causes over which the Operator has no control, the
Operator may charge the Joint Account for the required Material at the
Operator's actual cost incurred procuring such Material, in making it
suitable for use, and moving it to the Contract Area, provided that
notice in writing, including a detailed description of the Material
required and the required delivery date, is furnished to Non-Operators of
the proposed charge at least 10 Days (or such shorter period as may be
specified by Operator) before the Material is projected to be needed for
operations and prior to billing Non-Operators for such Material the cost
of which exceeds two hundred thousand U.S. Dollars (U.S. $200,000.00).
Each Non-Operator shall have the right, by so electing and notifying
Operator within 5 Days (or such shorter period as may be specified by
Operator) after receiving notice from Operator, to furnish in kind all or
part of his share of such Material per the terms of the notice which is
suitable for use and acceptable to Operator both as to quality and time
of delivery. Such acceptance by Operator shall not be unreasonably
withheld. If a Non-Operator fails to properly submit an election
notification within the designated period, the Operator is not required
to accept Material furnished in kind by that Non-Operator. If the
Operator fails to submit proper notification prior to billing
Non-Operators for such Material, Operator shall only charge the Joint
Account on the basis of the price allowed during a "normal" pricing
period in effect at time of movement. If Material furnished is deemed
unsuitable for use by the Operator, all costs incurred in disposing of
such Material or returning Material to owner shall be borne by the
Non-Operator furnishing the same unless otherwise agreed by the Parties.
-----*****-----
SECTION V.
DISPOSAL OF MATERIALS
5.1 The Operator shall be under no obligation to purchase the interest of
Non-Operators in new or used surplus Materials. Operator shall have the
right to dispose of Materials but shall advise and secure prior agreement
of the Operating Committee of any proposed disposition of Materials
having an original cost to the Joint Account either individually or in
the aggregate of Fifty Thousand U.S. Dollars (US$50,000) or more. Credits
for Material sold by the Operator shall be made to the Joint Account in
the month in which payment is received for the Material. Any Material
sold or disposed of under this Section shall be on an "as is, where is"
basis without guarantees or warranties of any kind or nature. Costs and
expenditures incurred by Operator in the disposition of Materials shall
be charged to the Joint Account.
5.2 Division of Materials in kind, if made between Operator and
Non-Operators, shall be in proportion to their respective interests in
such Material. Each Party will thereupon be charged individually with its
share of the agreed volume of Material received or receivable by each
Party, and corresponding credits will be made by Operator to the Joint
Account. Such credits shall appear in the monthly statement of Joint
Operations.
-----*****----
SECTION VI.
RECORDS AND INVENTORIES OF ASSETS
6.1 RECORDS.
6.1.1 The Operator shall keep and maintain detailed records of property
and assets in use for or in connection with petroleum operations
under the Agreement in accordance with normal practices in
exploration and production activities of the international
petroleum industry. Such records shall include information on
quantities, location and condition of such property and assets,
and whether such property or assets are leased or owned.
6.1.2 The Operator shall furnish annually particulars to the
Non-Operator, by notice in writing as provided in the Agreement,
of all major assets acquired by the Operator to be used for or in
connection with petroleum operations.
6.2 INVENTORIES.
6.2.1 The Operator shall:
6.2.1.1 not less than once every twelve (12) Months with respect
to movable assets take an inventory of the controllable
assets used for or in connection with petroleum
operations in terms of the Contract and address and
deliver such inventory to the non-operators with a
statement of the principles upon which valuation of the
assets mentioned in such inventory has been based.
Controllable assets means those assets the operators
submit to detailed record keeping.
6.2.1.2 not less than once every three (3) years with respect to
immovable assets, take an inventory of the assets used
for or in connection with petroleum operations in terms
of the Contract and address and deliver such inventory
to the Non-Operators together with a written statement
of the principles upon which valuation of the assets
mentioned in such inventory has been based. Immovable
assets means those assets which are placed in service
and have an original cost in excess of Fifty Thousand
United States Dollars (US$50,000).
6.2.1.3 Reconciliation of inventory with charges to the Joint
Account shall be made by Operator and the Operator shall
furnish to the Non-Operators a copy of the inventory and
a priced list of excesses and shortages.
-----*****-----
EXHIBIT "B"
DESCRIPTION OF CONTRACT AREA
The area comprising approximately 1471 sq. km offshore India identified
as Tapti Block described herein and shown under map attached as Figure
B-1.
Longitude and Latitude measurements are as follows:
LATITUDE LONGITUDE
A. 20 50'00"N 71 49'00"E
B. 20 50'00"N 72 08'00"E
C. 20 35'00"N 72 08'00"E
D. 20 20'00"N 71 53'00"E
E. 20 20'00"N 71 49'00"E
-----*****-----
APPENDIX - B
MAP OF CONTRACT AREA
TAPTI BLOCK
FIGURE - B1
WESTERN INDIA
OFFSHORE
BOMBAY BASIN
[MAP AND INSERT OF CONTRACT AREA]
<PAGE>
EXHIBIT "C"
EXAMPLE
FROM ENRON OIL & GAS INDIA LTD.
CASH CALL FOR: JUNE 1, 199
JUNE JULY AUGUST
I. Exploration/Appraisal Costs
Geological and Geophysical 10 X
Core Hole Drilling 10 X
Exploration Wells
Wells A 20
Wells B 20 40
Facilities Costs 5 X
Subtotal
II. Development Costs
Development Wells
Wells A 20 X
Wells B 20 40 X
Production Facilities
Platforms 50
Pipeline/Flow Lines 10 60
Engineering Studies 2 X
Service Costs 3 X X
Subtotal
III. Production Costs
Lease and Well 5 X
IV. General and Administrative Costs 15 X X
V. Fixed Assets and Deposits X X X
Grand Total 190 XX XX
April 1994 Cash Call 200
April 1994 Actual (190)
----
Net Over (Under) Call 10 (10)
----
Total Cash Due June 1, 1994 180
====
ONGC 40% Share US$72
EOGIL 30% Share US$54
RIL 30% Share US$54
NOTE: The cash call for June 1 is expected to be issued on or before May 15.
-----*****-----
EXHIBIT "D"
BUDGET FORMAT
(FOR EXAMPLE ONLY)
ENRON OIL & GAS INDIA LTD.
FINANCIAL YEAR 1994/95
I. Exploration/Appraisal Costs
Geological and Geophysical X
Core Hole Drilling X
Exploration Wells
(1) Wells A (Firm; Specifically defined) X
(2) Wells B (Contingent; Funds provided, but X
specifics to be approved by
Operating Committee)
Sub-Total XX
II. Development Costs
Development Wells
(1) Wells A (Firm; Specifically defined) X
(2) Wells B (Contingent; Funds provided, but X
specifics to be approved by
Operating Committee)
Production Facilities
(1) Platforms
(a) Firm X
(b) Contingent; Funds provided, but X
specifics to be approved by
Operating Committee
(2) Storage Facilities X
(3) Terminals X
(4) Pipelines/Flow Lines X
Engineering Studies X
Service Costs X
Sub-Total XX
==
III. Production Costs
Lease and Well X
Sub-Total XXX
===
IV. General and Administrative XX
V. Fixed Assets and Deposits XX
Grand Total Costs XXX
===
NOTE 1: Each line above represents budget line items. Each budget line item
shall be supplemented, if appropriate, by explanatory schedules, unquantified
examples of which follow as Tables D-1 through D-8, showing magnitude and timing
of expenditures and description of the work to be achieved. It is intended that
the Operating Committee shall have full authority to reclassify funds from
Contingent to Firm.
VI. Revenue XXX
===
NOTE 2: Categories III and IV are considered operating cost and are not subject
to AFEs, except that some items in category III may require AFEs for workovers
as per Article 6.9.
APPROVALS
For EOGIL ____________________
(signature)
____________________
(print name and date)
For RIL ____________________
(signature)
____________________
(print name and date)
For ONGC
____________________
(signature)
____________________
(print name and date)
<PAGE>
TABLE D-1
ENRON OIL & GAS INDIA LTD. (FOR APPROVAL)
BUDGET AND WORK PROGRAM
BUDGET SUMMARY
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95
ITEM 1994 1994 1994 1995 FINANCIAL YEAR REMAIN TOTAL
CODE DESCRIPTION QTR 2 QTR 3 QTR 4 QTR 1 * PROJECT PROJECT
<S> <C>
</TABLE>
I. Exploration/Appraisal Costs
Geophysical and Geological
Core Hole Drilling
Exploration Drilling
(Firm Wells)
(Contingent Wells)
Total Exploration Costs
II. Development Costs
Development Drilling
(Firm Wells)
(Contingent Wells)
Production Facilities Costs
Total Development Costs
III. Production Costs
IV. General and Administrative
V. Fixed Assets and Deposits
Total Project Costs
VI. Revenue
*If in this column, the item is a Minimum Work Obligation item.
NOTE: Categories III and IV are considered operating cost and are not subject to
AFEs, except that certain items in category III may require AFEs for workovers
as per Article 6.9.
FOR EOGIL FOR RIL FOR ONGC
__________________ _____________________ ____________________
__________________ _____________________ ____________________
TABLE D-2
ENRON OIL & GAS INDIA LTD. (FOR INFORMATION)
BUDGET AND WORK PROGRAM
Geophysical and Geological Expense
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL YEAR FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 * YEAR YEAR
<S><C>
</TABLE>
Geophysical Costs
Seismic Survey (Firm)
Positioning (Firm)
Field Supervision (Firm)
Scouting/Chase Boats/Misc. (Firm)
Data Processing (See Note) (Firm)
Data Reprocessing (Firm)
Supervisory/Support Costs (Firm)
Technical Service (Firm)
Total Geophysical Costs
Geological Costs
Geochem and Biostrat Analysis (Firm)
Core Analysis (Firm)
Special Studies and Consultation (Firm)
PVT Fluid Analysis (Firm)
Supervisory/Support Costs (Firm)
Technical Service (Firm)
Total Geological Costs
Communications Costs (Firm)
Total Geophysical and Geological
*If in this column, the item is a Minimum Work Obligation item.
TABLE D-3
ENRON OIL & GAS INDIA LTD. (FOR INFORMATION)
BUDGET AND WORK PROGRAM
Development Drilling (Firm Wells)
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL YEAR FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 * YEAR YEAR
<S><C>
Drilling (Firm wells)
Drilling and Completion Intangibles
Drilling and Completion Tangibles
Drilling (Contingent wells)
Total Drilling
Shore Base (1) (Firm)
Communications Expense (2) (Firm)
Supervisory/Support Staff (Firm)
Total Drilling/Operations Costs
*If in this column, the item is a Minimum Work Obligation item.
NOTE: (1) Lease costs only of $ /day
(2) Monthly communications expense allocated as follows: Additional Note:
Drilling
Construction Specifics to be added which would clearly
Exploration delineate each individual "Firm" well
G&A proposed. A separate page following this format
would be provided for "Contingent" wells for which
funds are proposed but technical specifications
are not available until a future Operating
Committee meeting.
(3) Inventory costs included in Fixed Assets
</TABLE>
TABLE D-4
ENRON OIL & GAS INDIA LTD. (FOR INFORMATION)
BUDGET AND WORK PROGRAM
Production Facilities Costs
Financial Year 1994/95
<TABLE>
<CAPTION>
(In '000 U.S. Dollars)
TOTAL 94/95 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL YEAR FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 * YEAR YEAR
<S><C>
</TABLE>
PANNA FIELD DEVELOPMENT
CCP Jacket (Contingent)
CCP Deck (Contingent)
Platform PF (Contingent)
Platform PG (Contingent)
WH Decks (Contingent)
Pipeline (Contingent)
Living Quarters/Platform (Contingent)
Flare Tripod Structure (Contingent)
Total Panna/Mukta Development
TAPTI FIELD DEVELOPMENT
Preliminary Engineering (Firm)
Platform STB (Firm)
Platform STC (Firm)
Platform STF (Firm)
TPP Jacket (Firm)
TPP Deck/Bridge (Firm)
Pipeline (Firm)
Total Tapti Development
Supervisory/Support Costs (Firm)
Technical Services (Firm)
TOTAL PRODUCTION FACILITIES
*If in this column, the item is a Minimum Work Obligation item.
TABLE D-5
ENRON OIL & GAS INDIA LTD (FOR INFORMATION)
BUDGET AND WORK PROGRAM
Production Costs
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL YEAR FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 * YEAR YEAR
<S><C>
</TABLE>
Panna/Mukta
EPS
FSO
PA
PB
PQ
PE
MA
Sub-Total
PPA
PQ
PC
PF
PG
Sub-Total
Total Panna/Mukta (Firm)
Tapti
TPP, STB, STC, STF (Firm)
Total Tapti
Communications (Firm)
Supervision and Support (Firm)
Technical Services (Firm)
Total Production Costs
*If in this column, the item is a Minimum Work Obligation item.
TABLE D-6
ENRON OIL & GAS INDIA LTD. (FOR INFORMATION)
BUDGET AND WORK PROGRAM
General and Administrative Expense
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL YEAR FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 * YEAR YEAR
<S><C>
</TABLE>
Salaries and Benefits
Expat Salary and Benefits
National Salary and Benefits
Total Salaries and Benefits (Firm)
Other G&A
Moving Costs
Travel and Entertainment
Subscriptions and Memberships
Office Rental
Telephone and Telecommunications
Utilities Repair and Maintenance
Security
Office Supplies
Legal and Accounting
Insurance
Technical Services
Technical Publications, Books, Maps
Other Outside Services
Bank Fees
Training
Total Other G&A (Firm)
Total General and Administrative
*If in this column, the item is a Minimum Work Obligation item.
NOTE: Other G&A costs apply to all other departments accumulating costs not
budgeted elsewhere.
TABLE D-7
ENRON OIL & GAS INDIA LTD. (FOR INFORMATION)
BUDGET AND WORK PROGRAM
Fixed Assets and Deposits
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL YEAR FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 * YEAR YEAR
<S><C>
</TABLE>
Office Furniture/Fixtures
Office Furniture
Office Equipment
Drafting Equipment
Computer Equipment
Communication Equipment
Expat Housing Furniture/Appliances
Other Leasehold Improvements
Total Furniture/Fixture/Equipment (Firm)
Motor Vehicles
Inventory
Warehouse and Yard
Deposits
Office
Expat Housing/Apartments
Warehouse
Telephone, Fax, Other
Total Deposits/Prepaids (Firm)
Total Fixed Assets and Deposits
*If in this column, the item is a Minimum Work Obligation item.
TABLE D-8
ENRON OIL & GAS INDIA LTD. (FOR INFORMATION)
BUDGET AND WORK PROGRAM
Revenue
Financial Year 1994/95
(In '000 U.S. Dollars)
<TABLE>
<CAPTION>
TOTAL 94/95 95/96 96/97
ITEM 1994 1994 1995 FINANCIAL YEAR FINANCIAL FINANCIAL
CODE DESCRIPTION QTR 3 QTR 4 QTR 1 YEAR YEAR
<S><C>
</TABLE>
Revenues
Oil Production
Gas Production
Other Income
Total Revenues
-----*****-----
<PAGE>
EXHIBIT "E"
DATA TO BE PROVIDED TO NON-OPERATORS
Operator shall provide the following data to Non-Operators:
A. DAILY PROGRESS REPORTS
1. Daily drilling progress report for each well which shall include the
brief description of work performed, the interval drilled, the type
and depth of the formation penetrated, the size and landed depth of
any casing landed and cementation details thereof, the results of any
tests made and any problems encountered.
2. Daily production report giving field-wise information on the oil, gas,
condensate and water produced, number of wells flowing, the quantity
of produced oil and gas handed over for custody transfer, available
data describing quality of the crude transferred (including, as
available, gravity, water content, salinity, pour point for oil and
dew point and calorific value), H2S content of gas handed over as
available, and any lighterage details as and when it takes place.
3. Daily cash statements.
4. Water injection reports, if any, giving quantity and quality of water
injected, number of wells/strings on injection, wellhead injection
pressures, etc.
5. Workover and well servicing reports covering the details of workover
operations and well stimulations/activation operations (well-wise).
6. Construction reports covering the details of the activities, if any,
carried out at offshore for installation of well platforms, pipelines,
process platforms and other activities with details of barges
deployed, etc.
B. OTHER PERIODIC REPORTS
Other reports will cover the following aspects and will be provided at
frequencies (monthly, quarterly or otherwise) as appropriate:
1. Exploration: Status of various surveys carried out vis-a-vis plan, data
acquisition and data processing details vs. plan, any discovery made with
details of the test data of the discovery well zone-wise.
2. Drilling:
(a) Summary report on each well drilled after drilling is concluded.
(b) Cumulative drilling meterage (both development and exploratory)
achieved during the month against plan (wellwise), idle and
productive time of rigs, details of the material consumption
(casing, mud chemicals and other well completion equipments).
3. Production:
(a) Cumulative production of oil, gas, condensate, water and water
injection including, as available, field-wise, layer-wise and
well-wise actual results vs. plan of production/injection.
Cumulative quantity of crude oil, condensate and gas sold.
Party-wise share of the sold oil, gas and condensate.
(b) (i) The quantity of gas internally consumed and flared, details of
material consumption for various production activities (chemicals,
tubulars, completion equipment, etc.).
(ii) Average quantity of produced crude oil (if applicable),
gas, effluent discharge and water injected.
(iii) Status reports on major/critical equipments/facilities and
maintenance thereof.
(c) Monthly test data of the wells.
(d) Daily ullage of tanker at SBM (if applicable).
(e) Daily Report on deployment of personnel on board.
4. Developmental/Construction Activities: Major construction/development
activities in progress. Status of progress of these activities with
respect to schedule.
5. Capital and operating expenditure against plan (to be reported quarterly
containing information on monthly and year-to-date expenditures).
6. Copies of various well logs and surveys as they become available.
7. Reports of DST (including basic data), core analysis and any other
special studies conducted as they become available.
8. Well completion and work-over reports as they become available.
9. Copies of all geological, geochemical, petrophysical and geophysical
data/reports and, when finalized, maps prepared by the Operator or by
the subcontractor except the magnetic tapes which shall be stored by
the Operator and made available for inspection and/or copying at the
sole expense of the non-operating Parties requesting same.
10. Copies of reservoir management reports including field and well
performance reports and reservoir studies reports and estimate
reports as they become available.
11. Reports on sub-sea soil surveys, environmental surveys, sub-sea
pipelines and risers inspection, reports on repair and maintenance of
sub-sea pipeline and risers as they become available.
12. Any emergency shutdown of operations affecting oil/gas
production/dispatch, drilling operations, etc., must be reported as
soon as practicable on telephone followed by telex, facsimile, etc.,
giving the details of effect on production/drilling and the likely
duration of shutdown.
A normalization report also to be sent when the operations resume and
become normal.
13. Reports on all incidents of: pipeline and riser leakage/failure, oil
spills, fire, any structural failures, blow-out, explosion, sabotage,
other accidents involving loss of property.life, etc., strikes/riots
affecting operations/production, etc., should be sent as soon as
practicable by the Operator to the non-operating Parties, Government
and other agencies such as Oil Industries Safety Directorate
("OISD"), Director General Hydrocarbon, Oil Co-ordination Committee
("OCC"), Offshore Defense Advisory Group ("ODAG") and other statutory
bodies whichever is applicable, on telephone followed by
telex/facsimile giving the details.
14. Fortnightly cash balance report.
C. INFORMATION, DATA, CONFIDENTIALITY, INSPECTION AND SECURITY
The Contractor shall, promptly after they become available make available
to the Government in its offices all data obtained as a result of petroleum
operations under the Contract including, but not limited to, geological,
geophysical, geochemical, petrophysical, engineering, well logs, maps, magnetic
tapes, cores and production data as well as all interpretative and derivative
data, including reports, analyses, interpretations and evaluation prepared in
final form in respect of petroleum operations (hereinafter referred to as
("Data"). Data shall be the property of the Government, provided however, that
the Contractor shall have the right to make use of such Data, free of cost, for
the purpose of petroleum operations under this Agreement as provided herein.
-----*****-----
GRAPHICAL CONTENT APPENDIX
Appendix - B
Figure B-1 Map of Contract Area - Tapti Block
EXHIBIT 10.56
PRODUCTION SHARING CONTRACT
AMONG
THE GOVERNMENT OF INDIA
AND
OIL & NATURAL GAS CORPORATION LIMITED
AND
RELIANCE INDUSTRIES LIMITED
AND
ENRON OIL & GAS INDIA LTD.
WITH RESPECT TO CONTRACT AREA
IDENTIFIED AS MID AND SOUTH TAPTI FIELD
<PAGE>
TABLE OF CONTENTS
ARTICLE CONTENTS
Preamble
1. Definitions
2. Duration
3. Relinquishment
4. Work Programme
5. Management Committee
6. Operatorship and Operating Agreement
7. General Rights and Obligations of the Parties
8. Government Assistance
9. Discovery, Development and Production
10. Unit Development
11. Measurement of Petroleum
12. Protection of the Environment
13. Recovery of Costs
14. Production Sharing of Petroleum between Contractor
and Government
15. Taxes, Royalties, Rentals, etc.
16. Payment
17. Customs Duties
18. Domestic Supply, Sale, Disposal and Export of Crude Oil
19. Valuation of Oil
20. Currency and Exchange Control Provisions
21. Natural Gas
22. Employment, Training and Transfer of Technology
23. Local Goods and Services
24. Insurance and Indemnification
25. Records, Reports, Accounts and Audit
26. Information, Data, Confidentiality, Inspection
and Security
27. Title to Petroleum, Data and Assets
28. Assignment of Interest
29. Guarantee
30. Termination of Contract
31. Force Majeure
32. Applicable Law and Language of the Contract
33. Sole Expert, Conciliation and Arbitration
34. Entire Agreement, Amendments, Waiver and Miscellaneous
35. Certificates
36. Notices
APPENDICES:
Appendix A - Description of Contract Area
Appendix B - Map of Contract Area
Appendix C - Accounting Procedure to Production Sharing
Contract
Appendix D - Calculation of the Investment Multiple for
Production Sharing Purposes
Appendix E - Form of Financial and Performance Guarantee
Appendix F - Equipment
Appendix G - Development Commitment Specified by the
Companies
Appendix H - Production Profile of the Mid and South Tapti
Fields
Appendix I - Payment for Use of Onshore Plant
-----*****-----
This Contract made and entered into as of the 22nd day of December 1994
by and among:
THE PRESIDENT OF INDIA, acting through the the Joint Secretary
(Exploration), Ministry of Petroleum and Natural Gas (hereinafter
referred as Government);
AND
OIL & NATURAL GAS CORPORATION LIMITED (ONGC), a body corporate established under
the provisions of the Companies Act, 1956, which expression shall include its
successors and such assigns as are permitted under Article 28 hereof acting
through its duly authorized Chairman & Managing Director;
AND
RELIANCE INDUSTRIES LTD. ("RIL"), a body corporate established under the laws of
India, which expression shall include its successors and such assigns as are
permitted under Article 28 hereof acting through its duly authorized Chief
Executive Officer (Oil & Gas)
AND
ENRON OIL & GAS INDIA LTD. ("EOGIL"), a body corporate established under the
laws of the Cayman Islands, which expression shall include its successors and
such assigns as are permitted under Article 28 hereof acting through its duly
authorized (Vice) President;
WITNESSETH:
WHEREAS
1. By virtue of Article 297 of the Constitution of India,
Petroleum in its natural state in the Territorial Waters and
the Continental Shelf of India is vested in the Union of
India;
2. The Territorial Waters, Continental Shelf, Exclusive Economic Zone And
Other Maritime Zones Act, 1976 (No. 80 of 1976) provides for the grant of
a Lease or letter of authority by the Government to explore and exploit
the resources of the Continental Shelf;
3. The Oil Fields (Regulation and Development) Act, 1948, (53 of 1948)
(hereinafter referred to as "the Act") and the Petroleum and Natural Gas
Rules, 1959, made thereunder (hereinafter referred to as "the Rules") make
provision inter alia for the regulation of Petroleum Operations and the
grant of petroleum exploration licenses and mining leases for exploration
and development of Petroleum in India;
4. The Act and the Rules provide for the grant by the Government of mining
leases in respect of the Territorial Waters and the Continental Shelf, and
the Contractor is being duly granted a mining lease to carry out Petroleum
Operations in that area offshore identified as Mid and South Tapti Field,
more particularly described in Appendices A and B;
5. The Government desires that the Petroleum resources which may exist in the
Contract Area be discovered and exploited with the utmost expedition in
the overall interest of India in accordance with sound international
petroleum industry practices;
6. The Government is satisfied that it is in the public interest to enter
into this Contract on terms different from those specified in Section 12
of the Oil Fields (Regulations and Development) Act, 1948, and the
Government is entering into this Agreement on the terms and conditions
specified herein.
7. EOGIL and RIL have represented that they have, or will acquire
and make available, the necessary financial and technical
resources and the technical and industrial competence and
experience necessary for proper discharge and/or performance
of all obligations required to be performed under this
Contract in accordance with good international petroleum
industry practices and will provide guarantees as required in
Article 29 for the due performance of their undertakings
hereunder;
8. The Parties desire to enter into this Contract with respect to the
Contract Area referred to in Appendices A and B on the terms and
conditions herein set forth.
NOW, THEREFORE, in consideration of the premises and covenants and conditions
herein contained, IT IS HEREBY AGREED between the Parties as follows:
-----*****-----
2
ARTICLE 1
D E F I N I T I O N S
In this Contract, unless the context requires otherwise, the following
terms shall have the meaning ascribed to them hereunder:
1.1 "Accounting Procedure" means the principles and procedures
of accounting set out in Appendix C.
1.2 "Affiliate" means a company that directly or indirectly controls or is
controlled by a Party to this Contract or a company which directly or
indirectly controls or is controlled by a company which controls a
Party to this Contract, it being understood that "control" means
ownership by one company of more than fifty percent (50%) of the voting
securities of the other company, or the power to direct, administer and
dictate policies of the other company even where the voting securities
held by such company exercising such effective control in that other
company is less than fifty percent (50%) and the term "controlled"
shall have a corresponding meaning.
1.3 "Appendix" means an Appendix attached to this Contract and
made a part hereof.
1.4 "Appraisal Programme" means a programme, approved by the Management
Committee for the appraisal of an Existing or New Discovery of
Petroleum in the Contract Area for the purpose of delineating the
Petroleum Reservoirs to which the Discovery relates in terms of
thickness and lateral extent and determining the characteristics
thereof and the quantity and quality of recoverable Petroleum therein.
1.5 "Appraisal Well" means a Well drilled within the Contract Area pursuant
to an approved Appraisal Programme.
1.6 "Arms Length Sales" means sales of Petroleum made freely on the open
international market, in freely convertible currencies, between willing
and unrelated sellers and buyers and in which such buyers and sellers
have no contractual or other relationship, directly or indirectly, or
any common or joint interest as is reasonably likely to influence
selling prices and shall, inter alia, exclude sales (whether direct or
indirect, through brokers or otherwise) involving Affiliates, sales
between entities comprising the Contractor, sales between governments
and government-owned entities, counter trades, restricted or distress
sales, sales involving barter arrangements and generally any
transactions motivated in whole or in part by considerations other than
normal commercial practices.
1.7 "Article" means an Article of this Contract and the term
"Articles" means more than one Article.
3
1.8 "Associated Natural Gas" or "ANG" means Natural Gas occurring in
association with Crude Oil either as free gas or in solution, if such
Crude Oil can by itself be commercially produced.
1.9 "Barrel" means a quantity or unit equal to 158.9074 litres (forty-two
(42) United States gallons) liquid measure, at a temperature of sixty
(60) degrees Fahrenheit (15.56 degrees Centigrade) under one atmosphere
of pressure (14.7 psia).
1.10 "Basement" means any igneous or metamorphic rock, or rock or any
stratum of such nature, in and below which the geological structure or
physical characteristics of the rock sequence do not have the
properties necessary for the accumulation of Petroleum in commercial
quantities and which reflects the maximum depth at which any such
accumulation can be reasonably expected in accordance with the
knowledge generally accepted in the international petroleum industry.
1.11 "Calendar Month" means any of the twelve (12) months of the
Calendar Year unless specified otherwise.
1.12 "Calendar Quarter" means a period of three consecutive Calendar Months
commencing on the first day of January, April, July and October of each
Calendar Year.
1.13 "Calendar Year" means a period of twelve consecutive months according
to the Gregorian calendar commencing with the first day of January and
ending with the thirty-first day of December.
1.14 "Commercial Discovery" means a Discovery which, when produced, is
likely to yield a reasonable profit on the funds invested in Petroleum
Operations, after deduction of Contract Costs, and which has been
declared a Commercial Discovery in accordance with the provisions of
Article 9 and/or Article 21, after consideration of all pertinent
operating and financial data such as recoverable reserves, sustainable
production levels, estimated development and production expenditures,
prevailing prices and other relevant technical and economic factors
according to generally accepted practices in the international
petroleum industry.
1.15 "Commercial Production" means production of Crude Oil or Natural Gas or
both from a Field within the Contract Area and delivery of the same at
the relevant Delivery Point under a programme of regular production and
sale.
1.16 "Company" means either EOGIL or RIL.
1.17 "Companies" means EOGIL and RIL.
1.18 "Condensate" means those low vapour pressure hydrocarbons
obtained from Natural Gas through condensation or extraction
4
and refers solely to those hydrocarbons that are liquid at normal
surface temperature and pressure conditions (provided that in the event
Condensate is produced from an Oil Field and is segregated and
transported separately to the Delivery Point, then the provisions of
this Contract shall apply to such Condensate as if it were Crude Oil.)
1.19 "Contract" means this agreement and the Appendices attached hereto and
made a part hereof and any amendments made thereto pursuant to the
terms hereof.
1.20 "Contract Area" means the area described in Appendix A and delineated
on the map attached as Appendix B, or any portion of the area remaining
after relinquishment or surrender from time to time pursuant to the
terms of this Contract.
1.21 "Contract Costs" means Exploration Costs, Development Costs, Production
costs, and all other costs related to Petroleum Operations as set forth
in Section 3 of the Accounting Procedure.
1.22 "Contract Year" means a period of twelve consecutive months counted
from the Effective Date or from the anniversary of the Effective Date.
1.23 "Contractor" means EOGIL, RIL and ONGC.
1.24 "Cost Petroleum" means the portion of the total volume of Petroleum
produced and saved from the Contract Area which the Contractor is
entitled to take from the Contract Area in a particular period for the
recovery of Contract Costs as provided in Article 13.
1.25 "Cost Recovery Limit" shall have the meaning given in
Article 13.1.2.
1.26 "Crude Oil" means crude mineral oil, asphalt, ozokerite and all kinds
of hydrocarbons and bitumens, both in solid and in liquid form, in
their natural state or obtained from Natural Gas by condensation or
extraction, including distillate and Condensate when commingled with
the heavier hydrocarbons and delivered as a blend at the Delivery Point
but excluding verified Natural Gas.
1.27 "Delivery Point" means, except as otherwise herein provided or as may
be otherwise agreed between the Government and the Contractor, the
point at which Petroleum reaches the upstream weld of the outlet flange
of the delivery facility, either offshore or onshore and different
Delivery Points may be established for purposes of sales to the
Government, export or domestic sales.
1.28 "Development Area" means that part of the Contract Area corresponding
to the area of an Oil Field or Gas Field delineated in simple geometric
shape, together with a
5
reasonable margin of additional area surrounding the Field consistent
with international petroleum industry practice and approved by the
Management Committee or the Government, as the case may be.
1.29 "Development Costs" means those costs and expenditures
incurred in carrying out Development Operations, as
classified and defined in Section 2 of the Accounting
Procedure and allowed to be recovered in terms of Section 3
thereof.
1.30 "Development Operations" means operations conducted in accordance with
the Development Plan and shall include, but not be limited to, the
purchase, shipment or storage of equipment and materials used in
developing Petroleum accumulations, the drilling, completion,
Recompletion and testing of Development Wells, the drilling, completion
and Recompletion of Wells for Gas or water injection, the laying of
gathering lines, the installation of offshore platforms and
installations, the installation, hook up and commissioning of
separators, tankage, pumps, artificial lifting and other producing and
injection facilities required to produce, process and transport
Petroleum into main oil storage or Gas processing facilities, either
onshore or offshore, including the laying of pipelines within or
outside the Contract Area, storage and Delivery Point or Points, the
installation of storage or Gas processing facilities, the installation
of export and loading facilities and other facilities required for
development and production of the Petroleum accumulations and for the
delivery of Crude Oil and/or Gas at the Delivery Point(s) and also
including incidental operations not specifically referred to herein as
required for the most efficient and economic development and production
of the Petroleum accumulations in accordance with good international
petroleum industry practices.
1.31 "Development Plan" means a plan containing proposals
required under Article 9 or Article 21.
1.32 "Development Well" means a Well drilled, deepened, completed, or
Recompleted after the date of approval of the Development Plan pursuant
to Development Operations or Production Operations for the purposes of
producing Petroleum, increasing production, sustaining production or
accelerating extraction of Petroleum including production Wells,
injection Wells and dry Wells.
1.33 "Discovery" means the finding, during Exploration Operations, of a
deposit of Petroleum not previously known to have existed, which can be
recovered at the surface in a flow measurable by conventional petroleum
industry testing methods, including an Existing Discovery and a New
Discovery.
6
1.34 "Discovery Area" means that part of the Contract Area about which,
based upon Discovery and the results obtained from a Well or Wells
drilled in such part, both the Government and the Contractor are of the
opinion that Petroleum exists and is likely to be produced in
commercial quantities.
1.35 "Effective Date" means the date on which this Contract is
executed.
1.36 "Environmental Clearance" means permission granted in writing by the
Government to the Contractor to perform all activities necessary and
appropriate to conduct Petroleum Operations subject to conditions
specified with regard to protection of the environment and minimizing
Environmental Damage.
1.37 "Environmental Damage" means soil erosion, removal of vegetation,
destruction of wildlife, pollution of groundwater or surface water,
land contamination, air pollution, noise pollution, bush fire,
disruption to water supplies, to natural drainage or natural flow of
rivers or streams, damage to archaeological, palaeontological and
cultural sites and shall include any damage or injury to, or
destruction of, soil or water in their physical aspects together with
vegetation associated therewith, aquatic or terrestrial mammals, fish,
avifauna or any plant or animal life whether in the sea or in any other
water or on, in or under land provided such damage is in violation of
legislation relating to the protection of the environment.
1.38 "Excess ANG" shall have the meaning given in Article 21.4.
1.39 "Existing Discovery" means a Discovery made by ONGC before the
Effective Date and accepted by the Parties as a Commercial Discovery.
1.40 "Exploration Costs" means those costs and expenditures
incurred in carrying out Exploration Operations, as
classified and defined in Section 2 of the Accounting
Procedure and allowed to be recovered in terms of Section 3
thereof.
1.41 "Exploration Operations" means operations conducted in the Contract
Area pursuant to this Contract in searching for Petroleum or in the
course of an Appraisal Programme and shall include but not be limited
to aerial, geological, geophysical, geochemical, palaeontological,
palynological, topographical and seismic surveys, analysis, studies and
their interpretation, investigations relating to the subsurface geology
including structure test drilling, stratigraphic test drilling,
drilling of Exploration Wells or Appraisal Wells and other related
activities such as testing, surveying, drill site preparation and all
work necessarily connected therewith that is conducted in connection
with Petroleum exploration.
7
1.42 "Exploration Well" means a Well drilled for the purpose of searching
for undiscovered Petroleum accumulations on any geological entity (be
it of structural, stratigraphic, facies or pressure nature) to at least
a depth or stratigraphic level specified in the Work Programme.
1.43 "Field" means an Oil Field or a Gas Field in the Contract Area in
respect of which a Development Plan has been duly approved in
accordance with Article 9 or Article 21 hereof.
1.44 "Financial Year" means the period from the first day of April through
the thirty-first day of March of the following Calendar Year.
1.45 "Foreign Company" means a Company within the meaning of Section 591 of
the Companies Act, 1956, as amended from time to time.
1.46 "Gas" means Natural Gas.
1.47 "Gas Field" means an area within the Contract Area consisting of a
single Gas Reservoir or multiple Gas Reservoirs all grouped on or
related to the same individual geological structure or stratigraphic
conditions, designated by the Contractor and approved by the Government
or Management Committee, as the case may be, (to include the maximum
area of potential productivity in the Contract Area in a simple
geometric shape) in respect of which a Commercial Discovery has been
declared or a Development Plan has been approved in accordance with
Article 9 or Article 21 hereof.
1.48 "Investment" shall have the meaning assigned in paragraph 3
of Appendix D.
1.49 "Investment Multiple" means the ratio of accumulated Net Cash Income to
accumulated Investment in the Contract Area, earned by the Companies,
as determined in accordance with Appendix D.
1.50 "LIBOR" means the London Inter-Bank Offering Rate for six-month
deposits of United States Dollars as quoted by the London office of the
Bank of America (or such other Bank as the Parties may agree) for the
day or days in question.
1.51 "Lessee" means any person or body corporate, including the Contractor,
which holds a mining lease under the Petroleum and Natural Gas Rules,
1959, for the purpose of carrying out Petroleum Operations in the
Contract Area and their successors and permitted assigns.
1.52 "Management Committee" means the committee constituted
pursuant to Article 5 hereof.
8
1.53 "Minimum Work Obligation" means the Work Programme related to those
items specified in Appendix G as approved by the Management Committee.
1.54 "Natural Gas" means wet Gas, dry Gas, all other gaseous hydrocarbons,
and all substances contained therein, including sulphur and helium,
which are produced from Oil or Gas Wells, excluding those condensed or
extracted liquid hydrocarbons that are liquid at normal temperature and
pressure conditions, and including the residue Gas remaining after the
condensation or extraction of liquid hydrocarbons from Gas.
1.55 "Net Cash Income" shall have the meaning assigned in
paragraph 2 of Appendix D.
1.56 "New Discovery" means a Discovery made after the Effective
Date.
1.57 "Non Associated Natural Gas" or "NANG" means Natural Gas which is
produced either without association with Crude Oil or in association
with Crude Oil which by itself cannot be commercially produced.
1.58 "Oil" means "Crude Oil".
1.59 "Oil Field" means an area within the Contract Area consisting of a
single Oil Reservoir or multiple Oil Reservoirs all grouped on or
related to the same individual geological structure, or stratigraphic
conditions, designated by the Contractor and approved by the Government
or the Management Committee, as the case may be (to include the maximum
area of potential productivity in the Contract Area in a simple
geometric shape) in respect of which a Commercial Discovery has been
declared and a Development Plan has been approved in accordance with
Article 9 hereof and a reference to an Oil Field shall include a
reference to the production of Associated Natural Gas from that Oil
Field.
1.60 "Operating Agreement" means the Joint Operating Agreement entered into
by the Parties constituting Contractor in accordance with Article 6,
with respect to the conduct of Petroleum Operations.
1.61 "Operating Committee" means the committee established by
that name in the Operating Agreement.
1.62 "Operator" means the Party so designated in Article 6.
1.63 "Participating Interest" means the percentage of participation of the
constituents of the Contractor at any given time in the rights and
obligations under this Contract. Initially the Participating Interest
of the constituents of Contractor are as follows:
9
1. ONGC 40%
2. RIL 30%
3. EOGIL 30%
1.64 "Parties" means the Parties signatory to this Contract including their
successors and permitted assigns under this Contract and the term
"Party" means any of the Parties.
1.65 "Petroleum" means Crude Oil and/or Natural Gas existing in
their natural condition.
1.66 "Petroleum Operations" means, as the context may require, Exploration
Operations, Development Operations or Production Operations or any
combination of such operations, including, but not limited to,
collection of seismic information, drilling and completion and
Recompletion of Wells, construction, operation and maintenance of all
necessary facilities, plugging and abandonment of Wells, environmental
protection, transportation, storage, sale or disposition of Petroleum
to the Delivery Point, Site Restoration and all other incidental
operations or activities as may be necessary.
1.67 "Production Costs" means those costs and expenditures incurred in
carrying out Production Operations as classified and defined in Section
2 of the Accounting Procedure and allowed to be recovered in terms of
Section 3 thereof.
1.68 "Production Operations" means all operations conducted for the purpose
of producing Petroleum from the Contract Area after the commencement of
production from the Contract Area, including the operation and
maintenance of all necessary facilities therefor.
1.69 "Profit Petroleum" means all Petroleum produced and saved from the
Contract Area in a particular period as reduced by Cost Petroleum and
calculated as provided in Article 14.
1.70 "Recompletion" means an operation whereby a completion in one zone is
abandoned in order to attempt a completion in a different zone within
the existing wellbore.
1.71 "Reservoir" means a naturally occurring discrete
accumulation of Petroleum.
1.72 "Section" means a section of the Accounting Procedure.
1.73 "Self-Sufficiency" means, in relation to any Financial Year, that the
volume of Crude Oil and Crude Oil equivalent of Petroleum products
exported from India during that Financial Year either equals or exceeds
the volume of Crude Oil and Crude Oil equivalent of Petroleum products
imported into India during the same Financial Year.
10
1.74 "Site Restoration" shall mean all activities required to return a site
to its state as of the Effective Date pursuant to the Contractor's
environmental impact study or to render a site compatible with its
intended after-use (to the extent reasonable) after cessation of
Petroleum Operations in relation thereto and shall include, where
appropriate, proper abandonment of Wells or other facilities, removal
of equipment and structures (whether installed before or after the
Effective Date), and debris, establishment of compatible contours and
drainage, replacement of top soil, revegetation, slope stabilization,
infilling of excavations or any other appropriate actions in the
circumstances.
1.75 "Subcontractor" means any company or person contracted by
the Operator to provide services with respect to the
Petroleum Operations.
1.76 "Well" means a borehole, made by drilling in the course of Petroleum
Operations, but does not include a seismic shot hole.
1.77 "Work Programme" means all the plans formulated for the
performance of the Petroleum Operations.
1.78 "Year" means Financial Year.
-----*****-----
11
ARTICLE 2
DURATION
2.1 The term of this Contract shall be for a period of twenty-five (25)
years from the Effective Date, unless the Contract is terminated
earlier in accordance with its terms, but may be extended on such terms
and conditions as may be mutually agreed by the Parties hereto.
-----*****-----
12
ARTICLE 3
RELINQUISHMENT
3.1 The Contractor may, with the approval of the Management Committee,
voluntarily relinquish a portion of the Contract Area other than an
area for which a Development Plan has been approved. Contractor shall
give the Government written notice of relinquishments thirty (30) days
prior to the end of any Calendar Year.
3.2 Relinquishment of less than all of the Contract Area shall
be in blocks of not less than one hundred square kilometres
(100 sq. kms.) and be of such shape and location as the
Government may deem appropriate for enabling effective
exploration and exploitation of such area.
3.3 Relinquishment of all or a part of the Contract Area or termination of
the Contract shall not be construed as absolving the Contractor of any
liability undertaken or incurred by the Contractor in respect of the
Contract Area prior to the date of such relinquishment or termination.
-----*****-----
13
ARTICLE 4
WORK PROGRAMME
4.1 The Contractor shall commence Petroleum Operations not later than six
(6) months from the Effective Date.
4.2 As soon as possible after the Effective Date, in respect of the period
ending with the last day of the Financial Year in which the Effective
Date falls and thereafter ninety (90) days before commencement of each
following Financial Year, the Contractor shall submit to the Management
Committee, through the Operating Committee, the Work Programmes and
budgets relating to Petroleum Operations, including the Minimum Work
Obligations, to be carried out during the ensuing Financial Year.
4.3 The Contractor may propose amendments to the details of an approved
Work Programme and budget in the light of the then existing
circumstances and shall submit to the Management Committee, through the
Operating Committee, modifications or revisions to the Work Programme
and budgets.
-----*****-----
14
ARTICLE 5
MANAGEMENT COMMITTEE
5.1 For the purpose of proper and expeditious performance of Petroleum
Operations under the provisions of this Contract, there shall be
constituted a committee to be called the Management Committee.
5.2 The Management Committee shall consist of four (4) members, one (1)
member nominated by and representing Government and one (1) member
nominated by and representing each constituent of the Contractor. The
member nominated by ONGC shall act as chairman.
5.3 A representative of the Operator acting as the convenor
shall call the meetings of the Management Committee.
5.4 Government and the Contractor may nominate alternate members with full
authority to act in the absence and on behalf of the members nominated
under Article 5.2 and may, at any time, nominate another member or
alternate member to replace any member nominated earlier by notice to
other members of the Management Committee.
5.5 A quorum of the Management Committee shall consist of three
(3) members.
5.6 The following matters shall be submitted to the Management
Committee for approval:
(a) annual Work Programmes and budgets and any modifications or
revisions thereto, as proposed by the Operating Committee, for
Exploration Operations, Development Operations and/or Production
Operations;
(b) proposals for an Appraisal Programme, the declaration of a New
Discovery as a Commercial Discovery and the approval of
Development Plans as may be required under this Contract, or
revisions or additions to an Appraisal Programme or a Development
Plan;
(c) delineation of a Field and a Development Area;
(d) appointment of auditors;
(e) collaboration with lessees or contractors of other
areas;
(f) claims or settlement of claims for or on behalf of or against the
Contractor in excess of limits specified in the Operating
Agreement or fixed by the Management Committee from time to time;
15
(g) any proposed mortgage, charge or encumbrance on
petroleum assets, petroleum reserves or production of
Petroleum;
(h) any other matter required by the terms of this Contract
to be submitted for the approval of the Management
Committee;
(i) any other matter which the Contractor or the Operating
Committee decides to submit to it.
5.7 The Management Committee shall not take any decision without obtaining
prior approval of the Government, where such approval is required under
this Contract.
5.8 The Management Committee shall meet at least once every three (3)
months or more frequently at the request of any member. Operator shall
convene each meeting by notifying the members at least twenty eight
(28) days prior to such meeting (or a shorter period of notice if the
members unanimously so agree) of the time and place of such meeting and
the purpose thereof and shall include in such notice a provisional
agenda for such meeting. The Operator shall be responsible for
processing the final agenda for such meeting and the agenda shall
include all items of business requested by the members to be included,
provided such requests are received by the Operator at least ten (10)
days prior to the date fixed for the meeting. The Operator shall
forward the agenda to the members at least nine (9) days prior to the
date fixed for the meeting. Matters not included in the agenda may be
taken up at the meeting by any member with the unanimous consent of all
the members.
5.9 The Chairman, and in his absence any other member nominated by ONGC,
shall preside over the meetings of the Management Committee.
5.10 The Operator shall appoint one of the members nominated by the
constituents of the Contractor as secretary to the Management Committee
with responsibility, inter alia, for preparation of the minutes of
every meeting in the English language and provision to every member of
the Management Committee with two (2) copies of the minutes not later
than twenty-eight (28) days after the date of the meeting.
5.11 Within twenty-one (21) days of the receipt of the minutes of a meeting,
members shall notify the Operator and the other members of their
approval of the minutes by putting their signatures on one copy of the
minutes and returning the same to the Operator or by indicating such
approval to the Operator by telex, cable, or facsimile, with copies to
the other members. Any member may suggest any modification, amendment
or addition to the minutes by telex, cable or facsimile to the Operator
and other members or by indicating such suggestions when returning the
copy of the minutes to
16
the Operator. If the Operator or any other member does not agree with
the modification, amendment or addition to the minutes suggested by any
member, the matter shall be brought to the attention of the other
members and resubmitted to the Management Committee for approval at the
next meeting and the minutes shall stand approved as to all other
matters. If a member fails to appropriately respond within the
aforesaid twenty-one (21) day period as herein provided, the minutes
shall be deemed approved by such member.
5.12 The meetings of the Management Committee shall be held in New Delhi,
India unless otherwise mutually agreed by the members of the Management
Committee.
5.13 All matters requiring the approval of the Management Committee shall be
approved by a vote of three (3) or more members of the Management
Committee one (1) of whom shall be the Government representative.
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17
ARTICLE 6
OPERATORSHIP AND OPERATING AGREEMENT
6.1 EOGIL shall be the Operator for purposes of this Contract.
6.2 No change in operatorship shall be effected without the consent of the
Government, which consent shall not be unreasonably withheld.
6.3 The operating functions required of the Contractor under this Contract
shall be performed by the Operator on behalf of all constituents of the
Contractor subject to, and in accordance with, the terms and provisions
of this Contract, and generally accepted international petroleum
industry practice.
6.4 The constituents of the Contractor shall execute a mutually agreed
Operating Agreement. The Agreement shall be consistent with the
provisions of this Contract and shall provide for, among other things:
(a) the appointment, resignation, removal and
responsibilities of the Operator;
(b) the establishment of an Operating Committee;
(c) functions of the Operating Committee taking into account the
provisions of the Contract, procedures for decision making,
frequency and place of meetings; and
(d) contribution to costs, default, sole risk, disposal of petroleum
and assignment as between the parties to the Operating Agreement.
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18
ARTICLE 7
GENERAL RIGHTS AND OBLIGATIONS OF THE PARTIES
7.1 Subject to the provisions of this Contract, the Contractor
shall have, but not be limited to, the following rights:
(a) the exclusive right during the term hereof to carry out Petroleum
Operations in the Contract Area and to recover costs and expenses
as provided in this Contract;
(b) the right to use, free of charge, such quantities of Petroleum
produced from any Field as are reasonably required for conducting
Petroleum Operations in the Contract Area in accordance with
generally accepted practices in the international petroleum
industry;
(c) the right to lay, build, construct or install
pipelines, roads, bridges, ferries, aerodromes,
landing fields, radio telephones, satellite
communications and related communication and
infrastructure facilities and exercise other ancillary
rights as may be reasonably necessary for the conduct
of Petroleum Operations subject to such approvals as
may be required, which shall not be unreasonably
withheld, under the applicable laws and/or regulations
in force from time to time for the regulation and
control thereof;
(d) the right to have an expatriate work force as required
and necessary together with their required personal
effects;
(e) the right to flare Gas temporarily when and as necessary,
provided the Operator shall give notice thereof to the Government
within forty-eight (48) hours of the start of such flaring and
the issue shall be discussed in the next meeting of the
Management Committee;
(f) the right to use all wells, equipment and facilities installed as
of the Effective Date in the Contract Area ("Assets") free of any
additional cost or charges or encumbrances and assignment of such
Assets to Operator on behalf of the Contractor;
(g) such other rights as are specified in this Contract.
7.2 The Government reserves the right to itself, or to grant to the Lessee
or others the right, to prospect for and mine minerals or substances
other than Petroleum within the Contract Area; provided, however, that
if after the Effective Date, the Lessee or others are issued rights, or
the Government proceeds directly to prospect for and mine in the
Contract Area for any minerals or substances other than
19
Petroleum, the Contractor shall use reasonable efforts to avoid
obstruction to or interference with such operations within the Contract
Area and, in either case, the Government shall use reasonable efforts
to ensure that operations carried out do not obstruct or unduly
interfere with Petroleum Operations in the Contract Area. In the event
of any conflict, Petroleum Operations shall take preference.
7.3 The Contractor shall:
(a) except as otherwise expressly provided in this Contract, conduct
all Petroleum Operations at its sole risk, cost and expense and
provide all funds necessary for the conduct of Petroleum
Operations including funds for the purchase or lease of
equipment, materials or supplies required for Petroleum
Operations as well as for making payments to employees and
Subcontractors;
(b) conduct all Petroleum Operations within the Contract Area
diligently, expeditiously, efficiently and in a safe and
workmanlike manner in accordance with good international
petroleum industry practice pursuant to the approved Work
Programmes;
(c) ensure provision of all information, data, samples etc.
which the Contractor may be required to furnish under
the applicable laws;
(d) ensure that all equipment, materials, supplies, plant and
installations used for Petroleum Operations comply with generally
accepted standards in the international petroleum industry and
are of proper construction and kept in good working order;
(e) in the preparation and implementation of Work Programmes and in
the conduct of Petroleum Operations, follow good international
petroleum industry practices with such degree of diligence and
prudence reasonably and ordinarily exercised by experienced
parties engaged in a similar activity under similar circumstances
and conditions;
(f) after the designation of a Field and a Development Area, pursuant
to this Contract, forthwith proceed to take all necessary action
for prompt and orderly development of the Field and the
Development Area and for the production of Petroleum in
accordance with the terms of this Contract;
(g) appoint a technically competent and sufficiently experienced
representative, and, in his absence, a suitably qualified
replacement therefor, who shall be resident in India and who
shall have full authority to take such steps as may be necessary
to implement this Contract and whose names shall, on appointment
within
20
ninety (90) days after commencement of the first
Contract Year, be made known to the Government;
(h) provide acceptable working conditions, living accommodation and
access to medical attention and nursing care in the Contract Area
for all personnel employed in Petroleum Operations and extend
these benefits to other persons who are engaged in or assisting
in the conduct of Petroleum Operations in the Contract Area;
(i) be always mindful of the rights and interests of India
in the conduct of Petroleum Operations;
7.4 The infrastructure such as pipelines as may be developed/established by
the Contractor within the country may, to the extent capacity is
available, be available to the Government or any other entity upon
payment of compensation which shall include, but not be limited to,
cost of operation, repair, maintenance, interest and profit. The
Government and any other entity using any of Contractor's facilities
shall indemnify and hold harmless Contractor from and against any and
all loss, damage or injury arising out of or connected with such use.
-----*****-----
21
ARTICLE 8
GOVERNMENT ASSISTANCE
8.1 Upon application in the prescribed manner, and subject to compliance
with applicable laws and relevant procedures, the Government will
without any cost to itself:
(a) provide the right of ingress and egress from the Contract Area
and any facilities used in Petroleum Operations, wherever
located, and which may be within their control;
(b) use their good offices, when necessary, to assist
Contractor in procurement of facilities and services
required for execution of Petroleum Operations
including necessary approvals, permits, consents,
authorisations, visas, work permits, licenses, rights
of way, easement, surface rights and security
protection, required pursuant to this Contract and
which may be available from resources within the
Government's control;
(c) use their good offices to assist in identifying and
making available necessary priorities for obtaining
local goods and services;
(d) in the event that onshore facilities are required
outside the Contract Area for Petroleum Operations
including, but not limited to, storage, loading and
processing facilities, pipelines and offices, use their
good offices in assisting the Contractor to obtain from
the authorities of the state government in the state in
which such facilities are required, such licenses,
permits, authorizations, consents, security protection,
surface rights and easements as are required for the
construction and operation of the said facilities by
the Contractor;
(e) in the event there is no economical passage other than through
national parks, sanctuaries, mangroves, wetlands of national
importance, biosphere reserves or other biologically sensitive
areas, assist in obtaining the prior written permission of the
concerned authorities.
8.2 ONGC shall provide data, if any, related to the Contract Area to the
Contractor which has not been previously provided.
-----*****-----
22
ARTICLE 9
DISCOVERY, DEVELOPMENT AND PRODUCTION
9.1 If and when a New Discovery is made within the Contract
Area, the Contractor shall:
(a) forthwith inform the Government of the Discovery;
(b) promptly thereafter, but in no event later than a period of
thirty (30) days from the date of such Discovery, furnish to the
Government particulars, in writing, of the Discovery;
(c) promptly run tests to determine whether the New
Discovery is of potential commercial interest and,
within a period of sixty (60) days after completion of
such tests and analysis of results, submit a report to
the Management Committee and the Government containing
data obtained from such tests and its analysis and
interpretation thereof, together with a written
notification to the Government of whether, in the
Contractor's opinion, such New Discovery is of
potential commercial interest and merits appraisal.
9.2 If, pursuant to Article 9.1(c), the Contractor notifies the Government
that a New Discovery is of potential commercial interest, the
Contractor shall prepare and submit to the Management Committee, within
one hundred and twenty (120) days of such notification, a proposed
Appraisal Programme with a Work Programme and budget to carry out an
adequate and effective appraisal of such New Discovery designed to
achieve both the following objectives:
(a) determine without delay, and, in any event, within the period
specified in Article 9.5, whether such New Discovery is a
Commercial Discovery; and
(b) determine, with reasonable precision, the boundaries of
the area to be delineated as a Field.
9.3 The proposed Appraisal Programme for a New Discovery shall be
considered by the Management Committee within forty-five (45) days
after submission thereof pursuant to Article 9.2. The Appraisal
Programme, together with the Work Programme and budget submitted by the
Contractor, revised in accordance with any agreed amendments or
additions thereto, approved by the Management Committee, shall be
adopted as the Appraisal Programme and the Contractor shall promptly
commence implementation thereof; and the Yearly budget adopted pursuant
to Article 4, shall be revised accordingly. Where, in the case of an
Existing Discovery, Contractor desires to carry out additional
appraisal work, the Contractor shall submit its proposed Appraisal
Programme in respect of the Existing Discovery with a Work Programme
and
23
budget to the Management Committee for its approval within one hundred
twenty (120) days of the Effective Date.
9.4 The Contractor shall, unless otherwise agreed, in respect of a New
Discovery of Crude Oil, advise the Management Committee, by notice in
writing within a period of twenty-four (24) months from the date on
which the notice provided for in Article 9.1 was delivered, whether
such New Discovery is a Commercial Discovery or not. Such notice shall
be accompanied by a report on the New Discovery setting forth all
relevant technical and economic data as well as all evaluations,
interpretations and analysis of such data and feasibility studies
relating to the New Discovery prepared by or for the Contractor, with
respect to the Discovery. If the Contractor is of the opinion that
Petroleum has been discovered in commercial quantities, it shall
propose that the Government or Management Committee, as the case may
be, declare the New Discovery as a Commercial Discovery based on the
report submitted. In respect of a New Discovery of Gas, the provisions
of Article 21 shall apply.
9.5 The Management Committee shall, within forty-five (45) days of the date
of the notice referred to in Article 9.4, consider the proposal of the
Contractor and request any other additional information it may
reasonably require so as to reach a decision on whether or not to
declare the New Discovery as a Commercial Discovery. Such decision
shall be made within the later of (a) ninety (90) days from the date of
notice referred to in Article 9.4 or (b) ninety (90) days of receipt of
such other information as may be reasonably required under this Article
9.5. In the case of an Existing Discovery, Contractor shall within
ninety (90) days of the Effective Date propose a Development Plan
following the plan brought out in Appendix G, intended to achieve the
production profile brought out in Appendix H, containing the detailed
information required in Article 9.6, with supporting budget. Where a
Development Plan is so agreed it shall be the approved Development Plan
pursuant to Article 9 hereof.
9.6 If a New Discovery is declared commercial the Contractor shall submit
to the Management Committee, a comprehensive plan for the development
of the Commercial Discovery within two hundred (200) days of the
declaration of the Discovery as a Commercial Discovery. Such plan shall
contain detailed proposals by the Contractor for the construction,
establishment and operation of all facilities and services for and
incidental to the recovery, storage and transportation of the Petroleum
from the proposed Development Area to the Delivery Point together with
all data and supporting information including but not limited to:
24
(a) Description of the nature and characteristics of the Reservoir,
data, statistics, interpretations, and conclusions on all aspects
of the geology, reservoir evaluation, petroleum engineering
factors, reservoir models, estimates of reserves in place,
possible production magnitude, nature and ratio of Petroleum
fluids and analysis of producible Petroleum;
(b) Outlines of the development project and/or alternative
development projects, if any, describing the production
facilities to be installed and the number of wells to be drilled
under such development project and/or alternative development
projects, if any;
(c) Estimate of the rate of production to be established
and projection of the possible sustained rate of
production in accordance with generally accepted
international petroleum industry practice under such
development project and/or alternative development
project, if any, which will ensure that the area does
not suffer an excessive rate of decline of production
or an excessive loss of reservoir pressure;
(d) estimates of Development Costs and Production Costs under such
development project and/or alternative development projects, if
any;
(e) Contractor's recommendations as to the particular
project that it would prefer, if any;
(f) Work Programme and budget for Development and
Production Operations;
(g) anticipated adverse impact on the environment and measures to be
taken for prevention or minimization thereof and for general
protection of the environment in conduct of operations; and
(h) production profiles, financial/commercial analysis of
the project proposal.
9.7 Any proposed Development Plan submitted by the Contractor pursuant to
Articles 9.5 and/or 9.6 will be approved by the Management Committee
with such amendments and modifications as may be agreed upon by the
Contractor, within seventy-five (75) days of submission of the
Development Plan, which approval shall not be unreasonably withheld. If
such a Development Plan has not been approved by the Management
Committee within the seventy-five (75) day period, the Contractor shall
have the right to submit such plan directly to the Government for
approval, which approval shall not be unreasonably withheld. The
submission will be answered within sixty (60) days of receipt.
25
9.8 The Management Committee shall obtain such approvals from the
Government as may be required, except where this Contract provides that
the Contractor may obtain such approvals directly.
9.9 If the Management Committee fails to declare a New Discovery of Oil to
be commercial while the Contractor consider that it is commercial or
the Management Committee fails to declare the New Discovery as a
Commercial Discovery within the time limit stipulated in Article 9.5
hereof, the Contractor may declare the New Discovery as a Commercial
Discovery and submit development and production plans in respect of the
Discovery to the Management Committee as per the provisions of Article
9.6 and after such plans have been approved by the Management
Committee, the Contractor shall, acting solely,provide the entire
Development Costs and undertake development of the Oil Field. If,
however, the Field turns out to be non-commercial, the entire
Development Cost of the Field shall be borne solely by the Contractor
and shall not be recoverable as Cost Petroleum from any other Field or
Contract Area but shall be recoverable solely from such Field.
9.10 In the event that the Government considers a New Discovery to be
commercial but the Contractor considers the same as non-commercial, the
Government shall give notice to the Contractor to that effect and
thereafter the Field relating to such New Discovery shall be excluded
from the Contract Area for all purposes. In this event, the Contractor
shall have no claim on the production from such Field.
9.11 Work Programmes and budgets for Development and Production Operations
shall be submitted to the Management Committee, as soon as possible
after the designation of a Development Area and thereafter not later
than 31st December each Calendar Year in respect of the Financial Year
immediately following.
9.12 The Management Committee, when considering any Work Programme and
budget, may require the Contractor to prepare an estimate of potential
production to be achieved through the implementation of the programme
and budget for each of the three (3) Financial Years following the
Financial Year to which the Work Programme and budget relate. If major
changes in Financial Year to Financial Year estimates of potential
production are required, these shall be based on concrete evidence
necessitating such changes.
9.13 Not later than the fifteenth (15) day of January each Calendar Year, in
respect of the Financial Year immediately following, the Contractor
shall determine the "Programme Quantity". The Programme Quantity for
any Financial Year shall be the maximum quantity of Petroleum based on
Contractor's estimates, as approved by the Management Committee, which
can be produced from a Field consistent
26
with sound international petroleum industry practices and minimizing
unit production cost, taking into account the capacity of the producing
Wells, gathering lines, separators, storage capacity and other
production facilities available for use during the relevant Financial
Year, as well as the transportation facilities up to the Delivery
Point.
9.14 Proposed revisions to the details of a Development Plan or an annual
Work Programme or budget in respect of Development and Production
Operations shall, for good cause and if the circumstances so justify,
be submitted to the Management Committee for approval, through the
Operating Committee.
-----*****-----
27
ARTICLE 10
UNIT DEVELOPMENT
10.1 If a Reservoir in a New Discovery Area is situated partly within the
Contract Area and partly in an area in India over which other parties
have a contract or license/lease to conduct Petroleum Operations, the
Government may, for securing the most effective recovery of Petroleum
from such Reservoir, by notice in writing to the Contractor, require
that the Contractor:
(a) collaborate and agree with such other parties on the
joint development of the Reservoir;
(b) submit such agreement between the Contractor and such
other parties to the Government for approval; and
(c) prepare a plan for such joint development of the Reservoir,
within one hundred and eighty (180) days of the approval of the
agreement referred to in (b) above.
10.2 If no plan is submitted within the period specified in Article 10.1(c)
or such longer period as the Contractor and other parties may agree or,
if such plan as submitted is not acceptable to the Government and the
parties cannot agree on amendments to the proposed joint development
plan, the Government may cause to be prepared, at the expense of the
Contractor and the other parties referred to in Article 10.1, a plan
for such joint development consistent with generally accepted practices
in the international petroleum industry which shall take into
consideration any plans and presentations made by the Contractor and
the aforementioned other parties.
10.3 If the Parties are unable to agree on the plan for joint development,
then any of them may refer the matter to a sole expert for final
determination pursuant to Article 33, provided that the Contractor may
in case of any disagreement on the issue of joint development or the
proposed joint development plan, or within sixty (60) days of
determination by a sole expert, notify the Management Committee that it
elects to surrender its rights in the New Discovery Area in lieu of
participation in a joint development.
10.4 If a proposed joint development plan is agreed and adopted by the
parties, or adopted following determination by the sole expert, the
plan as finally adopted shall be the approved joint development plan
and the Contractor shall comply with the terms of the Development Plan
as if the Commercial Discovery is established.
10.5 The provisions of Articles 10.1, 10.2, 10.3 and 10.4 shall apply
MUTATIS MUTANDIS to a New Discovery of a Reservoir located partly
within the Contract Area, which, although not equivalent to a
Commercial Discovery if developed alone,
28
would be a Commercial Discovery if developed together with that part of
the Reservoir which extends outside the Contract Area to areas subject
to contract or given on license/lease for Petroleum Operations by other
parties.
10.6 If a New Discovery is situated partly within the Contract Area and
partly outside the Contract Area, the area outside the Contract Area
over which, at the time of the making of the New Discovery by the
Contractor, no production sharing contract similar to this Contract has
been granted or is under negotiation and/or no license/lease to conduct
petroleum operations has been granted, the Government will favourably
consider the extension of the Contract Area to include the entire area
of the Reservoir if so requested by the Contractor.
-----*****-----
29
ARTICLE 11
MEASUREMENT OF PETROLEUM
11.1 The volume and quality of Petroleum produced and saved from a Field
shall be measured by methods and appliances generally accepted and
customarily used in generally accepted international petroleum industry
practice.
11.2 The Government may, at all reasonable times, inspect and test the
appliances used for measuring the volume and determining the quality of
Petroleum, provided that any such inspection or testing shall be
carried out in such a manner so as not to unduly interfere with
Petroleum Operations.
11.3 Before commencement of production in a Field, the Parties
shall mutually agree on:
(a) methods to be employed to optimize the measurement of
volumes of Petroleum;
(b) the point at which Petroleum shall be measured and the respective
shares allocated to the Parties in accordance with the terms of
this Contract;
(c) the frequency of inspections and testing of measurement
appliances and relevant procedures relating thereto;
and
(d) the consequences of a determination of an error in
measurement.
11.4 The Contractor shall undertake to measure the volume and quality of the
Petroleum produced and saved from a Field at the agreed measurement
point consistent with generally accepted practices in the international
petroleum industry. The Contractor shall not make any alteration in the
agreed method or procedures for measurement or to any of the approved
appliances used for the purpose without the written consent of the
Government.
11.5 The Contractor shall give the Government timely notice of its intention
to conduct calibration operations or any agreed alteration for such
operations and the Government shall have the right to be present and
observe, either directly or through authorized representatives, such
operations.
-----*****-----
30
ARTICLE 12
PROTECTION OF THE ENVIRONMENT
12.1 The Government and the Contractor recognise that Petroleum Operations
will cause some impact on the environment in the Contract Area.
Accordingly, in performance of the Contract, the Contractor shall
conduct its Petroleum Operations with due regard to concerns with
respect to protection of the environment and conservation of natural
resources. In the furtherance of any laws, regulations and rules
promulgated by the Government, the Contractor shall:
(a) employ generally accepted industrial standards, including as
required, advanced techniques, practices and methods of operation
for the prevention of Environmental Damage in conducting its
Petroleum
Operations;
(b) take necessary and adequate steps to prevent Environmental Damage
and, where some adverse impact on the environment is unavoidable,
to minimize such damage and the consequential effects thereof on
property and people; and
(c) adhere to the guidelines, limitations or restrictions, if any,
imposed by Environmental Clearance as applicable on the Effective
Date and as such Environmental Clearance may be revised, expanded
or replaced as a result of Contractor's application(s) duly
submitted after the Effective Date.
12.2 If the Contractor fails to substantially comply with the provisions of
Article 12.1 or materially contravenes any relevant law, and such
failure or contravention results in substantial Environmental Damage,
the Contractor shall forthwith take all necessary and reasonable
measures to remedy the failure and the effects thereof.
12.3 If the Government has, on reasonable grounds, reason to believe that
any works or installations erected by the Contractor or any operations
conducted by the Contractor are endangering or may endanger persons or
any property of any person, or are causing avoidable pollution, or are
harming fauna and flora or the environment to a degree which is
unlawful, the Government may, pursuant to applicable law, require the
Contractor to take remedial measures within such reasonable period as
may be determined by the Government and, if appropriate, repair such
damage. The Government may, pursuant to applicable law, require the
Contractor to discontinue Petroleum Operations in whole or in part
until the Contractor has taken such action.
12.4 The Contractor shall, within one hundred twenty (120) days of the
Effective Date, cause a person or persons with special knowledge on
environmental matters, approved by the
31
Government, to carry out an environmental impact study in order:
(a) to determine, at the time of the study, the prevailing situation
relating to the environment, human beings and local communities,
the wildlife and marine life in the Contract Area and in the
adjoining or neighbouring areas; and
(b) to establish the likely effect on the environment, human beings
and local communities, the wildlife and marine life in the
Contract Area and in the adjoining or neighbouring areas in
consequence of the relevant phase of Petroleum Operations to be
conducted under this Contract.
12.5 The Contractor shall ensure that:
(a) Petroleum Operations are conducted in an environmentally
acceptable and safe manner consistent with good international
petroleum industry practice and that such Petroleum Operations
are properly monitored;
(b) the pertinent completed environmental impact studies are made
available to its employees and to its Subcontractors to develop
adequate and proper awareness of the measures and methods of
environmental protection to be used in carrying out the Petroleum
Operations; and
(c) the contracts entered into between the Contractor and its
Subcontractors relating to its Petroleum Operations shall include
the provisions stipulated herein and any established measures and
methods for the implementation of the Contractor's obligations in
relation to the environment under this Contract.
12.6 The Contractor shall, prior to conducting any drilling activities,
prepare and submit for review by the Government contingency plans for
dealing with oil spills, fires, accidents and emergencies, designed to
achieve rapid and effective emergency response. The plans referred to
above shall be discussed with the Government and concerns expressed
shall be taken into account.
12.6.1 In the event of an emergency, accident, oil spill or fire
arising from Petroleum Operations affecting the
environment, the Contractor shall forthwith notify the
Government and shall promptly implement the relevant
contingency plan and perform such Site Restoration as may
be necessary.
12.6.2 In the event of any other emergency or accident
arising from the Petroleum Operations affecting
32
the environment, the Contractor shall take such action as
may be prudent and necessary in accordance with good
international petroleum industry practice in such
circumstances.
12.7 In the event that the Contractor fails to take necessary action to
comply with any of the terms contained in Article 12.5 and Article 12.6
within a reasonable period specified by the Government, the Government,
after giving the Contractor reasonable notice in the circumstances, may
take any action which may be necessary to ensure compliance with such
terms and recover from the Contractor, immediately after having taken
such action, all costs and expenditures incurred in connection with
such action together with such interest as may be determined in
accordance with Section 1.7 of Appendix C of this Contract.
12.8 Contractor shall notify the Government upon determination by it that
the estimated remaining recoverable reserves of any Field net of
operating costs equal two and one-half (2 1/2) times the estimated
abandonment cost whereupon the Government shall, within sixty (60)
days, take control of the Field and the abandonment obligation or,
failing which, the Contractor may then proceed to recover the
abandonment cost from the remaining production and abandon such Field.
12.9 Any and all costs incurred by Contractor pursuant to this Article shall
be cost recoverable including, but not limited to, sinking funds
established for abandonment.
12.10 The responsibility of the Contractor for the environment hereunder
shall be limited to damage to the environment which:
(a) occurs after the date of the environmental impact
assessment ("EIA") made to establish the benchmark
condition. The EIA will be conducted as soon after the
Effective Date as is reasonably possible;
(b) results from an act or omission of Contractor in
violation of existing law; and
(c) notwithstanding the above, Contractor shall be responsible for
any damage to the environment because of any evidence of Oil
spill, blow-out, fire, etc., during the course of Joint
Operations from the Effective Date.
-----*****-----
33
ARTICLE 13
RECOVERY OF COSTS
13.1 The Contractor shall be entitled to recover Contract Costs out of the
total volume of Petroleum produced and saved from the Contract Area in
each Financial Year in accordance with the provisions of this Article,
and, in respect of sole risk or exclusive operations, Article VII of
the Operating Agreement.
13.1.1 Development Costs incurred by the Contractor in the
Contract Area shall be aggregated, and the Contractor shall
be entitled to recover out of Cost Petroleum the aggregate
of such Development Costs at the rate of one hundred
percent (100%) per annum, provided, however, that, subject
to the remaining provisions of this Article 13.1, the
Contractor shall not, for the purposes only of determining
the volume of Petroleum to which Contractor shall be
entitled under Article 13.1 as Cost Petroleum, claim as
Contract Costs Contractor's Development Costs incurred
after the Effective Date in connection with Development
Operations under the Development Plan for midand
south-Tapti Fields (as those Fields are determined in the
Development Plan first approved by the Management
Committee) which exceed Contractor's Cost Recovery Limit
(as hereinafter defined).
13.1.2 For the purposes of this Article 13.1,
Contractor's "Cost Recovery Limit" means costs
incurred after the Effective Date relating to the
construction and/or establishment of such
facilities as are necessary to produce, process,
store and transport Petroleum from within the
Existing Discoveries, in order to enable Gas
production of 4.2 million cubic metres per day in
accordance with the Development Plan for the mid-
and south-Tapti Fields. Such costs shall include
costs incurred in relation to those items
illustrated in Appendix "G", including the 30
additional infill wells, and matters in
connection therewith. Appendix G further
describes Companies' development concept based on
an assumed project start date of July 1, 1993,
and Parties understand and agree that the
schedules and activities contained in such
assessment shall be revised, subject to
Management Committee approval, by the Contractor
in Contractor's Development Plan first submitted
pursuant to this Contract.
The Parties agree that for the purposes of this Article
13.1 the Contractor's Cost Recovery Limit shall be the sum
of Five Hundred Forty-five Million U.S. Dollars
(US$545,000,000).
34
13.1.3 The Parties acknowledge that the amount representing
Contractor's Cost Recovery Limit has been agreed by
Contractor on the basis of the following assumptions and/or
factors and/or
information:
(a) Included in calculations for the Cost Recovery Limit
are costs relating to Gas compression offshore
required for delivering Gas into GAIL's pipeline
system and an onshore pig trap; excluded from the Cost
Recovery Limit are Site Restoration and exploration or
appraisal drilling;
(b) the Cost Recovery Limit does not include any costs for
the development of any satellite Fields;
(c) the Contractor being able to obtain all necessary
approvals (including Government and state government
approvals) to enable Contractor to carry out the
Development Operations contemplated by the Development
Plan for the mid- and south-Tapti Fields in accordance
with the timing set out in such plan;
(d) the data relating to the Contract Area provided by
ONGC from time to time prior to the Effective Date
inclusive of the data package pertaining to the
Contract Area prepared by ONGC and made available for
inspection and purchase by the Companies pursuant to
the Government's "Notice Inviting Offers for Joint
Ventures to Develop Medium- Sized Oil and Gas Field in
India, 1992";
(e) international market conditions relating to the
availability and cost of materials and services in the
international petroleum industry in constant 1993
United States Dollars;
(f) the range of physical reservoir characteristics in
respect of the Oil and Gas Fields comprising the
Existing Discoveries not being materially different
from the ranges for such characteristics as revealed
in the data referred to in Article 13.1.3(d)on which
Companies based their assessment as described in Annex
G-1 to Appendix G; and
35
(g) Companies' development concept contemplated use of
existing ONGC-owned facilities for reseparation and
handling of Condensate and Gas upon it's arrival at
Hazira. ONGC and Companies will determine payment,
terms and conditions for the use of processing and
treating facilities owned by ONGC, which payment shall
be based on the principles detailed in Appendix I, or
alternatively the Contractor install the necessary
facilities, the cost of which shall be cost
recoverable and not subject to the Cost Recovery
Limit.
13.1.4 Having regard, inter alia, to the matters referred to in
Article 13.1.3, the Parties agree as follows:
(a) Included in calculations for the Cost Recovery Limit
are costs relating to Gas compression offshore
required for delivering Gas into GAIL's pipeline
system and an onshore pig trap; excluded from the Cost
Recovery Limit are Site Restoration and exploration or
appraisal drilling;
(b) the costs of developing the reserves and/or potential
reserves and/or satellite Fields referred to in
Article 13.1.3(b) shall not be subject to the Cost
Recovery Limit, notwithstanding that the development,
within the Contract Area, of such reserves and/or
potential reserves and/or satellite Fields may include
shared flowlines, injection lines, Gas-lift lines and
other facilities with those constructed as part of the
Development Plan for the mid- and south-Tapti Fields;
(c) in the event that the Contractor's Cost Recovery Limit
is exceeded as a result of:
(i) delays in carrying out the Development
Operations referred to in Article 13.1.3(c)
due to a delay in obtaining any necessary
approval;
(ii) material changes to the Development Plan for
the mid- and south-Tapti Fields necessitated
by Contractor's review of data provided, if
any, to the Companies by the Government
and/or ONGC after the Effective Date
36
available prior to the Effective Date then
the Companies, acting reasonably, would have
included such changes in the Development
Plan for the mid- and south-Tapti Fields;
(iii) a material change to the international
market conditions referred to in Article
13.1.3(e);
(iv) a variation to the Development Plan for the
mid- and south-Tapti Fields approved by the
Management Committee; or
(v) an event of force majeure as provided in
Article 31;
then the Management Committee shall, at the request of
the Operator, in a meeting convened under Article 5.8,
promptly consider what, if any, increase should be
made to the Contractor's Cost Recovery Limit to fairly
reflect the circumstances in question PROVIDED THAT in
the case of delays referred to in Article 13.1.3(c)
the Management Committee shall not be obligated to
consider any increase where, and to the extent that,
such delay has been caused by the Companies' failure
to act in a diligent manner.
13.1.5 In the event that:
(a) there is any dispute between the Parties whether or to
what extent a circumstance referred to in Article
13.1.4(c) has arisen or resulted in the Contractor's
Cost Recovery Limit being exceeded; or
(b) the Management Committee is unable to agree whether an
increase should be made to the Contractor's Cost
Recovery Limit or is unable to agree on the amount of
any such increase;
then, at any time after thirty (30) days from the date of
the Management Committee meeting referred to in Article
13.1.4(c), any Party shall be at liberty to refer the
matter to arbitration in accordance with the provisions of
Article 33.
13.1.6 Costs incurred by the Companies prior to the Effective Date
hereof which have been approved by the Government, in
writing, shall be cost recoverable for purposes hereof
after approval of the Management Committee.
37
13.2 Exploration Costs (if any) incurred by the Contractor in respect of the
Contract Area up to the date of Commercial Production of Petroleum from
the Contract Area shall be aggregated, and the Contractor shall be
entitled to recover the aggregate of such Exploration Costs out of the
Cost Petroleum from the Contract Area at the rate of one hundred
percent (100%) per annum of such Exploration Costs beginning from the
date of such Commercial Production.
13.3 The Contractor shall be entitled to recover out of the Cost Petroleum
from the Contract Area the Exploration Costs which it has incurred in
that Contract Area in any Financial Year after the date of Commercial
Production from the Contract Area at the rate of one hundred percent
(100%) per annum of such Exploration Costs beginning from the date such
Exploration Costs are incurred.
13.4 The Contractor shall be entitled to recover Exploration Costs as
provided in Articles 13.2 and 13.3 in relation to the values of the
quantity of Petroleum produced, saved and sold from the Contract Area,
in the relevant year, provided that such Exploration Costs once
recovered shall not be allowable for recovery against any other
contract area.
13.5 Development Costs incurred by the Contractor in the Contract Area up to
the date of Commercial Production from the Contract Area shall be
aggregated, and the Contractor shall be entitled to recover out of the
Cost Petroleum from that Contract Area the aggregate of such
Development Costs at the rate of one hundred percent (100%) per annum
of such Development Costs beginning from the date of such Commercial
Production from the Contract Area.
13.6 The Contractor shall be entitled to recover out of the Cost Petroleum
produced from the Contract Area the Development Costs which it has
incurred on such Contract Area after the date of Commercial Production
from the Contract Area at the rate of one hundred percent (100%) per
annum of such Development Costs beginning from the date such
Development Costs are incurred.
13.7 The Contractor shall be entitled to recover in full during any
Financial Year the Production Costs incurred in the Contract Area out
of the Cost Petroleum.
13.8 If during any Financial Year the Cost Petroleum is not sufficient to
enable the Contractor to recover in full the Contract Costs due for
recovery in that Financial Year in accordance with the provisions of
Articles 13.1 through 13.7, then, subject to the provisions of Article
13.1:
a) recovery shall first be made of the Production Costs; and
38
b) recovery shall next be made of the Exploration Costs; and
c) recovery shall then be made of the Development Costs.
The unrecovered portions of Contract Costs shall be carried forward to
the following Financial Year and the Contractor shall be entitled to
recover such Costs in such Financial Year or the subsequent Financial
Years as if such costs were due for recovery in that Financial Year, or
the succeeding Financial Years, until the unrecovered costs have been
fully recovered out of Cost Petroleum from the Contract Area.
13.9 For the purposes of this Article, as well as Article 14, costs,
receipts and income shall be converted into production unit
equivalents, and vice versa, using the relevant prices established
pursuant to Article 19 for Crude Oil and Article 21 for Natural Gas.
13.10 Pending completion of the calculations required to establish
definitively the Contractor's entitlement to Cost Petroleum from the
Contract Area in any Financial Year, the Contractor shall take
delivery, provisionally, of volumes of Crude Oil and/or Natural Gas
representing its estimated Cost Petroleum entitlement calculated with
reference to estimated production quantities, costs and prices for the
Contract Area as established by the Contractor and approved by the
Management Committee. Such provisional determination of Cost Petroleum
shall be made every quarter on a cumulative basis. Within sixty days of
the end of each Financial Year, a final calculation of the Contractor's
entitlement to Cost Petroleum, based on actual production quantities,
costs and prices for the entire Financial Year, shall be undertaken and
any necessary adjustments to the Cost Petroleum entitlement shall be
agreed upon between the Government and the Contractor and made as soon
as practicable thereafter.
13.11 Nothing herein contained shall provide for the recovery of costs by
ONGC which were incurred prior to the Effective Date.
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39
ARTICLE 14
PRODUCTION SHARING OF PETROLEUM BETWEEN
CONTRACTOR AND GOVERNMENT
14.1 The Contractor and the Government shall share in the Profit Petroleum
from the Contract Area in accordance with the provisions of this
Article. The share of Profit Petroleum, in any Financial Year, shall be
calculated for the Contract Area on the basis of the Investment
Multiple actually achieved by the Companies at the end of the preceding
Financial Year for the Contract Area as provided in Appendix D.
14.2 Profit Petroleum
14.2.1 When the Investment Multiple of the Companies at the end of
any Financial Year is less than two (2.0), the Government
shall be entitled to take and receive twenty percent (20%)
and the Contractor shall be entitled to take and receive
eighty percent (80%) of the total Profit Petroleum from the
Contract Area with effect from the start of the succeeding
Financial Year.
14.2.2 When the Investment Multiple of the Companies at the end of
any Financial Year in respect of any Contract Area is equal
to or more than two (2.0) but is less than two and one-half
(2.5), the Government shall be entitled to take and receive
forty percent (40%) and the Contractor shall be entitled to
take and receive sixty percent (60%) of the total Profit
Petroleum from the Contract Area with effect from the start
of the succeeding Financial Year.
14.2.3 When the Investment Multiple of the Companies at the end of
any Financial Year in respect of the Contract Area is equal
to or more than two and one-half (2.5) but is less than
three and one- half (3.5), the Government shall be entitled
to take and receive forty-five percent (45%) and the
Contractor shall be entitled to take and receive fifty-five
percent (55%) of the total Profit Petroleum from the
Contract Area with effect from the start of the succeeding
Financial Year.
14.2.4 When the Investment Multiple of the Companies at the end of
any Financial Year in respect of the Contract Area is equal
to or more than three and one-half (3.5), the Government
shall be entitled to take and receive fifty percent (50%)
and the Contractor shall be entitled to take and receive
fifty percent (50%) of the total Profit Petroleum from the
Contract Area with effect from the start of the succeeding
Financial Year.
40
14.3 The value of the Companies' Investment Multiple at the end of any
Financial Year in respect of the Contract Area shall be calculated in
the manner provided for, and on the basis of net cash flows specified,
in Appendix D to this Contract. However, the volume of Profit Petroleum
to be shared between the Government and the Contractor shall be
determined for each quarter on a cumulative basis. Pending finalization
of accounts, delivery of Profit Petroleum shall be taken by the
Government and the Contractor on the basis of provisional estimated
figures of Contract Costs, production, prices, receipts, income and any
other income or allowable deductions and on the basis of the value of
the Investment Multiple achieved at the end of the preceding Financial
Year. All such provisional estimates shall be approved by the
Management Committee. When it is necessary to convert monetary units
into physical units of production equivalents or vice versa, the price
or prices determined pursuant to Articles 19 and 21 for Crude Oil and
Natural Gas, respectively, shall be used. Within sixty (60) days of the
end of each Financial Year, a final calculation of Profit Petroleum
based on actual costs, quantities, prices and income for the entire
Financial Year shall be undertaken and any necessary adjustments to the
sharing of Profit Petroleum shall be agreed upon between the Government
and the Contractor and made as soon as is practicable thereafter.
14.4 The Profit Petroleum due to the Contractor in any Financial Year from
the Contract Area shall be divided between the Parties constituting the
Contractor in proportion to their respective Participating Interests.
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41
ARTICLE 15
TAXES, ROYALTIES, RENTALS, ETC.
15.1 The Companies and the operations under this Contract shall be subject
to all fiscal legislation of India, except where, pursuant to any
authority granted under any applicable law, they are exempt wholly or
partly from the application of the provisions of a particular law or as
otherwise provided herein.
15.2.1 For the purpose of computing profits or gains of the
business consisting of the prospecting for or extraction or
production of Petroleum, there shall be made in lieu of the
allowances admissible under the Income Tax Act, 1961, such
allowances as are specified in this Agreement pursuant to
Section 42 in relation to:
(a) expenditure by way of infructuous or abortive
exploration expenses in respect of any area
surrendered prior to the beginning of Commercial
Production; and
(b) after the beginning of commercial production, to
expenditure incurred, whether before or after such
Commercial Production, in respect of drilling or
exploration activities or services or in respect of
physical assets used in that connection.
15.2.2 Payments made by the Companies pursuant to Article 16 shall
be deductible for income tax purpose in the year in which
payment is made by the Companies, as permissible under
Section 42 of the Income Tax Act, 1961.
15.3.1 In respect of matters not covered above, deduction shall be
allowed in accordance with other provisions of Income Tax
Act, 1961, and the rules framed thereunder.
15.3.2 The revenue from the Business consisting of Petroleum
Operations shall be determined in accordance with Article
19 for its Participating Interest share of Crude Oil saved
and sold, or otherwise disposed of, from each Field and
from any revenue realized on the sale of ANG or NANG
referred to in Article 21 as well as any other gains or
receipts from Petroleum Operations as reduced by the
deductions as specified within this Article, and, except as
herein provided, all the provisions of the Income Tax Act,
1961, shall apply. 42
15.4 The following terms used in Section 42 of the Income Tax Act, 1961, and
Articles 15.2 and 15.3 shall have the meanings corresponding to the
terms used in this Contract and defined in Article 1 as follows:
(a) "Previous Year" means the year as defined in Section 2(34) of the
Income Tax Act, 1961.
(b) The other terms used herein and not defined in the Income Tax,
1961 shall have the meaning therein ascribed in Article 1.
15.5 Except for income tax as otherwise provided in this Article, the
Government covenants to the Companies that the Companies shall not be
liable for payment of:
(a) any taxes calculated by reference to income from or
sale of Petroleum; or
(b) any customs or excise duties, export duties or any other
statutory charge on the import or re-export of machinery, plant,
equipment, materials or supplies imported by or on behalf of
Contractor or its subcontractors solely and exclusively for use
in Petroleum Operations.
Any such payments, if the Companies are made liable shall be
reimbursed by the Government.
15.6.1 The constituents of the Contractor shall be liable to pay
royalties and cess on their Participating Interest share of
Crude Oil and Natural Gas saved and sold in accordance with
the provisions of this Agreement. The royalty on Oil saved
and sold will be paid at Rs. 481 per metric ton and cess on
Oil saved and sold will be paid at Rs. 900 per metric ton.
Royalty on Gas saved and sold will be paid at ten percent
(10%) of the value at wellhead. No cess shall be payable in
respect of Gas. Royalty and cess shall not exceed the
herein above amounts throughout the term of the Contract.
Royalty and cess shall be payable in Indian Rupees. Any
such additional payment shall be made by the Government.
15.6.2 All payments (except income tax) made by Contractor or its
constituents as applicable under appropriate law including,
but not limited to, taxes whether levied by the Central
Government or state government, or any other local or
statutory authority, royalties, cess, levies, duties,
rentals, lease rent, license fees, export duties,
43
countervailing duties, provision for sinking fund for
environmental or abandonment costs, or any other charges
whatsoever, directly attributable to Petroleum Operations.
15.8 If any change in or to any Indian law, rule or regulation by any
authority results in a material change to the economic benefits
accruing to any of the Parties to this Contract after the Effective
Date, the Parties shall consult promptly to make necessary revisions
and adjustments to the Contract in order to maintain such expected
benefits to each of the Parties.
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44
ARTICLE 16
PAYMENT
16.1 The Companies shall pay to ONGC in consideration of the right to
commence and carry out exploration and drilling activities in the
Contract Area, pursuant to and in accordance with the Notice Inviting
Offers for Joint Ventures to Develop Medium Sized Oil and Gas Fields in
India-1992 and the bid submitted in response thereto, as follows:
(a) within two (2) days following the Effective Date,
excluding days on which the banks in India or the
United States are closed, Twenty-one Million United
States Dollars (US$21,000,000). EOGIL shall pay Ten
Million Five Hundred Thousand United States Dollars
(US$10,500,000) and RIL shall pay Ten Million Five
Hundred Thousand United States Dollars (US$10,500,000).
ONGC's bank wire transfer instructions are as follows:
ACCOUNT NUMBER: 01 00000 3054
OIL & NATURAL GAS CORPORATION LIMITED
STATE BANK OF INDIA, OVERSEAS BRANCH
VIJAYA BUILDING,
BARAKHAMBA ROAD,
NEW DELHI, INDIA 110 001
(b) When and if the hereinafter set forth production quantities are
reached, the Companies will within fifteen (15) days following
such attainment pay ONGC in accordance with the following
schedule:
(i) Another Six Million United States Dollars
(US$6,000,000) after achieving a cumulative
production of five billion cubic meters of
Gas;
(ii) Another Nine Million United States Dollars
(US$9,000,000) after achieving a cumulative
production of ten billion cubic meters of
Gas; and
(iii) Another Fifteen Million United States Dollars
(US$15,000,000) after achieving a cumulative
production of fifteen billion cubic meters of Gas.
16.2 Cumulative production shall, for purposes of this Article,
mean Gas produced, saved and sold.
16.3 Each Company shall pay its share of the payment in the
proportion that it received Petroleum.
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45
ARTICLE 17
CUSTOMS DUTIES
17.1 Machinery, plant, equipment, materials and supplies imported by a
Contractor or its Subcontractors for use in Petroleum Operations shall
be exempted from customs duties subject to compliance with procedures,
if any, as may be determined pursuant to applicable customs duty
legislation, Article 23 and the terms herein specified.
17.2 Contractor shall, from time to time and as required, submit to the
Government a list of Subcontractors who are engaged by it for the
purpose of obtaining the various categories of items pursuant to the
conduct of Petroleum Operations and who may claim exemptions hereunder.
17.3 In order to qualify for the exemption from customs duties as provided
for in Article 17.1, all imported items for which duty exemption is
being claimed shall be certified, by a representative of the
Contractor, to be imported under the terms of this Contract for use in
carrying out Petroleum Operations and shall be certified by a
representative of the Government to be eligible for such exemption
pursuant to the terms of the Contract. In order to expedite such
exemption, Contractor may submit a certified list of qualified items up
to sixty (60) days in advance of anticipated import.
17.4 The Government shall have the right to inspect the records and
documents of the physical item or items for which an exemption is or
has been provided under Article 17.1 to determine that such item or
items are being or have been imported for the purpose for which the
exemption was granted. The Government shall also be entitled to inspect
such physical items wherever located to ensure that such items are
being used or held for the purpose herein specified and any item not
being so used shall immediately become subject to payment of the
applicable customs duties.
17.5 Subject to Article 27, the Contractor and its Subcontractors may sell
or otherwise transfer in India or sell for export all imported items
which are no longer required for Petroleum Operations, subject to
applicable laws governing customs duties and sale or disposal of such
items.
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46
ARTICLE 18
DOMESTIC SUPPLY, SALE, DISPOSAL AND
EXPORT OF CRUDE OIL
18.1 Until such time as the total availability to the Government and
government companies of Crude Oil from all Petroleum production
activities in India meets the total national demand, as determined by
the Government, each constituent of Contractor shall be required to
offer to the Government or its nominee all of the Contractor's
entitlement to Crude Oil from each Field in order to assist in
satisfying the national demand, provided, however, that nothing
contained in any contract entered into by the Contractor for the
supply, sale or disposal of Petroleum, with any nominee of the
Government pursuant to this Contract shall in any manner abrogate the
obligation of the Government contained herein.
18.2 Pursuant to Article 18.1 and subject to Articles 18.4 and 18.6, each
constituent of Contractor shall offer to sell to the Government (or its
nominee) its total Participating Interest share of Crude Oil to which
it is entitled under Articles 13 and 14 at the price determined in
accordance with Article 19 for sales to Government and the Government
shall have the option to purchase the whole or any portion thereof at
the said price.
18.3 The aforementioned offer shall be made by each constituent of
Contractor, in writing, at least six (6) months preceding the Financial
Year in which the sale is to be made, specifying the estimated
quantities and grade of Crude Oil being offered (based upon estimates
which shall be adjusted within ninety (90) days of the end of each
Financial Year on the basis of actual quantities produced and saved).
The Government shall exercise its option to purchase, in writing, not
later than ninety days (90) preceding the Financial Year in respect of
which the sale is to be made, specifying the quantity and grade of
Crude Oil which it elects to take in the ensuing year. Failure by the
Government to give such notice within the period specified shall be
conclusively deemed an election to take all of the Crude Oil offered
(adjusted as provided herein) in the ensuing Financial Year.
18.4 If, during any Financial Year, India attains Self-Sufficiency, the
Government shall promptly thereafter, but in no event later than the
end of that Financial Year, so advise the Contractor by written notice.
In such event, as from the end of the first quarter of the following
Financial Year, or such earlier date as the Parties may mutually agree,
Government's option to purchase shall be suspended and each constituent
of Contractor shall have the right to lift and export its Participating
Interest share of Crude Oil until such time, if any, as
Self-Sufficiency shall have ceased to exist. If Self-Sufficiency ceases
to exist during a Financial Year, the Government shall recover its
47
option to purchase under Article 18.2 in respect of the following
Financial Year by giving notice thereof to the Contractor as provided
in Article 18.3.
18.5 All payments in respect of sales to the Government pursuant to
provisions of this Article 18 shall be made by the Government within
the period for credit applicable in the calculation of the price
pursuant to Article 19. If no time frame for credit is applicable in
such calculation, payment shall be made within forty five (45) days
from the date the invoice is delivered to the Government. Contractor
shall submit a monthly invoice to the Government for the quantity of
Crude Oil delivered. Payment shall be made in United States Dollars by
bank wire to the credit of the Foreign Company's designated account
with a bank within or outside India. All amounts unpaid by the
Government by the due date shall, from the due date, bear interest
calculated on a day-to-day basis at the LIBOR plus one percentage (1%)
point from the due date compounded daily until paid.
18.6 If full payment is not received by Contractor when due as provided in
Article 18.5, the Contractor shall, at any time thereafter, notify the
Government of the default and, unless such default is remedied within
fifteen (15) days from the date of the notice, the Contractor shall
have the right, unless otherwise agreed, upon written notice to the
Government and without prejudice to the Contractor's right to recover
all costs, charges, expenses and losses, incurred by the Contractor:
a) to suspend the Government's option to purchase under
Article 18.2 and transport the Petroleum to any onshore
facility and sell as each constituent of Contractor may
in its absolute discretion deem fit;
b) without prejudice to the foregoing, to freely lift, sell and
export all its Participating Interest share of Crude Oil subject
to the destination restrictions specified in Article 18.7, until
the Government has paid the due amount plus interest as provided
herein;
c) if the payment plus interest is not received by the
Contractor within one hundred and eighty (180) days
from the date the payment was due, to receive and
export the Government's share of Profit Oil until such
time as either Government has paid all amounts due plus
interest, or the value, based on the price as deter-
mined in accordance with Article 19, of Government's
share of Profit Oil so sold is equal to all amounts due
plus interest, whichever first occurs; provided,
however, that if the Government makes a payment to the
Contractor after the Contractor has commenced sale of
Government's share of Profit Oil and such payment
together with the value of Government's share of Profit
Oil sold (based on the price determined in accordance
48
with Article 19) exceeds the amount due plus interest, necessary
adjustment shall be carried out to refund to the Government
forthwith the excess amount received by the Contractor.
18.7 The Contractor shall be entitled to freely lift, sell and export any
Crude Oil which the Government is unable to take or has elected not to
purchase pursuant to this Article 18 subject to Government's generally
applicable destination restrictions to countries with which the
Government, for policy reasons, has severed or restricted trade.
18.8 No later than sixty (60) days prior to the commencement of production
in a Field (or Fields where production is from more than one Field),
and thereafter no less than sixty (60) days before the commencement of
each Financial Year, the Contractor shall cause to be prepared and
submitted to the Parties a production forecast setting out the total
quantity of Crude Oil that it estimates can be produced from a Field
during the succeeding year, based on the maximum efficient rate of
recovery of Crude Oil from that Field in accordance with good petroleum
industry practice. No later than thirty (30) days prior to the
commencement of each Calendar Quarter, the Contractor shall advise its
estimate of production for the succeeding Calendar Quarter and shall
endeavour to produce the forecast quantity for each Calendar Quarter.
18.9 Each Party comprising the Contractor shall, throughout the term of this
Contract, have the right to separately take in kind and dispose of all
its share of Cost Petroleum and Profit Petroleum and shall have the
obligation to lift the Cost Petroleum and Profit Petroleum on a current
basis and in such quantities so as not to cause a restriction of
production or inconvenience to the other Parties.
18.10 The Government shall, throughout the term of this Contract, have the
right to separately take in kind and dispose of its share of Profit
Petroleum and of such portion of the Contractor's share of Petroleum as
is purchased by the Government pursuant to Article 18, subject to
Article 18.6 and shall have the obligation to lift all of the Oil on a
current basis and in such quantities so as not to cause a restriction
of production or inconvenience to the other Parties.
18.11 For the purpose of implementing the provisions of Articles 18.9 and
18.10, a Crude Oil lifting procedure shall be agreed upon by the
Parties as soon as practicable but no later than two (2) months after
the Effective Date of this Contract. Such lifting procedure shall
include, but not necessarily be limited to:
49
(a) a procedure for notification by the Operator to the
Government, and to each Party comprising the
Contractor, of projected Crude Oil production;
(b) a procedure for notification by the Government, and by each Party
comprising the Contractor, to the Operator, of its expected
offtake and the consequences of inability or failure to offtake.
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50
ARTICLE 19
VALUATION OF OIL
19.1 For the purpose of this Contract, the value of Crude Oil shall be based
on the price determined as provided herein.
19.2 A price for Crude Oil shall be determined for each Calendar Month or
such other period as the Parties may agree (hereinafter referred to as
"the Delivery Period") in terms of United States Dollars per Barrel,
FOB Delivery Point for Crude Oil produced and sold or otherwise
disposed of from each Contract Area, for each Delivery Period, in
accordance with the appropriate basis for that type of sale or disposal
specified below.
19.3 In the event that some or all of Contractor's total sales of Crude Oil
during a Delivery Period are made to third parties in Arms Length
Sales, all sales so made shall be valued at the weighted average of the
prices actually received by Contractor, calculated by dividing the
total receipts from all such sales FOB the Delivery Point by the total
number of Barrels of the Crude Oil sold in such sales.
19.3.1 In the event that a portion of such third party
Arms Length Sales are made on a basis other than
an FOB basis as herein specified, the portion
shall be valued at the prices equivalent to the
prices FOB the Delivery point for such sales
determined by deducting all costs (such as
transportation, demurrage, loss of Crude Oil in
transit and similar costs) incurred downstream of
the Delivery Point, and the prices so determined
shall be deemed to be the actual prices received
for the purpose of calculation of the weighted
average of the prices for all third party Arms
Length Sales for the Delivery Period.
19.3.2 Each constituent of Contractor shall separately
submit to the Government, within fifteen (15)
days of the end of each Delivery Period, a report
containing the actual prices obtained in their
respective Arms Length Sales to third parties of
any Crude Oil. Such reports shall distinguish
between term sales and spot sales and itemize
volumes, customers, prices received and credit
terms, and the constituent of the Contractor
shall allow the Government to examine the
relevant sales contracts.
19.4 In the event that some or all of a constituent of Contractor's total
sales of Crude Oil during a Calendar Month are made to the Government,
the price of all sales so made shall, unless otherwise agreed between
the Parties, be determined on the basis of either the FOB selling price
per Barrel of one or more crude oils which, at the time of
51
calculation, are being freely and actively traded in the international
market and are similar in characteristics and quality to the Crude Oil
and/or Condensate in respect of which the price is being determined,
such FOB selling price to be ascertained from Platt's Crude Oil Market
Wire daily publication ("Platt's"), or the spot market for the same
crude oils ascertained in the same manner, whichever price, in the
opinion of the Parties, more truly reflects the current value of such
crude oils. For any Calendar Month in which sales take place, the price
shall be the arithmetic average price per Barrel determined by
calculating the average for the preceding Calendar Month of the mean of
the high and low FOB or spot prices for each day of the crude oil(s)
selected for comparison adjusted for differences in the Crude Oil and
the crude oil(s) being compared for quality, transportation costs,
delivery time, quantity, payment terms, the market area into which the
Crude Oil is being sold, other contract terms to the extent known and
other relevant factors. In the event that Platt's ceases to be
published or is not published for a period of thirty (30) consecutive
days, the Parties shall agree on an alternative daily publication.
19.4.1 Notwithstanding anything herein otherwise provided, the
price paid for such sales shall be, in any Calendar
Month,the FOB selling price for a Marker Crude ("Marker
Crude") which shall be Brent (DTD) on a United States
Dollar per Barrel basis less US$0.10 per Barrel.
19.4.2 The Marker Crude price will be based on the
previous Calendar Month's average of the daily
low and high quotations of Marker Crude as
published by Platts' Market wire. The average is
to be calculated up to three (3) decimals to
arrive at a United States Dollar per Barrel
price, which will be applicable for the month of
supply.
19.4.3 The Government and/or its nominee shall pay any
and all sales tax payable on the sale of Oil to
the Government or its nominee.
19.4.4 The Government and/or its nominee shall enter into a Crude
Oil sales agreement with the Constituents of the Contractor
which shall contain terms and conditions normally contained
in international Crude Oil sales agreements of a similar
nature.
19.5 In the event that in any Delivery Period some but not all of a
constituent of Contractor's sales of Crude Oil from the Contract Area
are made to the Government or a Government company and some but not all
of a constituent of Contractor's sales of Crude Oil from the Contract
Area are
52
made to third parties in Arms Length Sales and the price as established
in accordance with Article 19.4 differs by more than one percent (1%)
from the price as determined in accordance with Article 19.3 for the
same Delivery Period, the Parties shall meet, upon notice from any
Party, to determine if the prices established for the relevant Delivery
Period for sales to the Government should be adjusted taking into
account third party Arms Length Sales made by a constituent of
Contractor of the same or similar Crude Oil from the relevant Field or
other fields and published information in respect of other genuine
third party Arms Length Sales of the same or similar crude oil for that
Delivery Period. Until the matter of an adjustment for the relevant
Delivery Period is finally determined , the price as established in
accordance with this Article will apply for that Delivery Period. Any
adjustment, if necessary, will be made within thirty (30) days from the
date the adjustment for that Delivery Period is finally determined.
19.6 A constituent of Contractor shall determine the relevant prices in
accordance with this Article and the calculation, basis of calculation
and the price determined shall be supplied to the Government and shall
be subject to agreement by the Government before it is finally
determined. Pending final determination, the last established price, if
any, for the Crude Oil shall be used.
19.7 In the event that the Parties fail to reach agreement on any matter
concerning selection of the crude oil(s) for comparison, the
calculation, the basis of, or mechanism for the calculation of the
prices, the prices arrived at, the adjustment of any price or generally
about the manner in which the prices are determined according to the
provisions of this Article within thirty (30) days, or such longer
period as may be mutually agreed between the parties, from the date of
commencement of Commercial Production or the end of each Delivery
Period thereafter, any Party may refer the matter or matters in issue
for final determination by a sole expert appointed as provided in
Article 33.
19.7.1 Within ten (10) days of the said appointment, the Parties
shall provide the expert with all information they deem
necessary or as the expert may reasonably require.
19.7.2 Within fifteen (15) days from the date of his
appointment, the expert shall report to the
Parties on the issue(s) referred to him for
determination, applying the criteria or mechanism
set forth herein and indicate his decision
thereon to be applicable for the relevant
Delivery Period for Crude Oil and such decision
shall be accepted as final and binding by the
Parties.
53
19.7.3 Except for the adjustment referred to in
Article 19.5, any price or pricing mechanism
agreed by the Parties pursuant to the provisions
of this Article shall not be changed
retroactively.
19.8 Any sale or disposal to Affiliates or other sale or disposal of Crude
Oil produced from a Field, other than to the Government or Government
companies or to third parties in Arms Length Sales, in any Delivery
Period, shall be valued on the same basis as sales to the Government or
a Government company. In the event of such a sale or disposal by a
Company, such Company shall submit to the Government, within fifteen
(15) days of the end of each Delivery Period, all relevant information
concerning such sales or disposals.
19.9 In the event that in any Delivery Period there is more than one type of
sales referred to in Articles 19.3, 19.4 and 19.8, then, for the
purpose of calculating Cost Petroleum and Profit Petroleum entitlement
pursuant to Articles 13 and 14, a single price per Barrel of Crude Oil
for all the sales for the relevant Delivery Period shall be used. Such
single price shall be the weighted average of the prices determined for
each type of sale, weighted by the respective volumes of Crude Oil sold
in each type of sale in the relevant Delivery Period.
19.10 In this Article the term "Government" shall include any other agency or
nominee of the Government to whom Crude Oil is to be sold.
19.11 The provisions specified above for the determination of the price of
sales of Crude Oil shall apply mutatis mutandis to Condensates.
19.12 The Parties shall meet annually, or sooner upon notice served by any
Party on the others, to review the list of selected Crude Oils or the
mechanism established pursuant to this Article 19 in light of any new
facts since the date of selection of such Crude Oils or establishment
of such mechanism and to determine what adjustment (if any) should be
made to the said selection or mechanism by mutual agreement of the
Parties.
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54
ARTICLE 20
CURRENCY AND EXCHANGE CONTROL PROVISIONS
20.1 Subject to the provisions herein, and to compliance with the relevant
provisions of the laws of general application in India governing
currency and foreign exchange and related administrative instructions
and procedures issued thereunder on a non-discriminatory basis, each
Foreign Company comprising the Contractor shall, during the term of
this Contract have the right to:
(a) repatriate funds relating to Petroleum Operations abroad, in
United States Dollars or any other freely convertible currency
acceptable to the Government and the Foreign Company;
(b) receive, retain and use abroad the proceeds of any
export sales of Petroleum under the contract;
(c) open, maintain and operate bank accounts with reputable banks,
both inside and outside India, for the purpose of this Contract;
(d) freely import, through normal banking channels, funds
necessary for carrying out the Petroleum Operations;
(e) convert into foreign exchange and repatriate sums
imported pursuant to (d) above in excess (if any) of
its requirements; and
(f) make payments of interest and principal outside of India for
purchases, services and loans obtained abroad without the
requirement that funds used in making such payments must come
from or originate in India.
Provided however, that repatriation pursuant to sub-paragraphs (a) and
(e) and payments pursuant to sub-paragraph (f) shall be subject to the
provisions of any treaties or bilateral arrangements between the
Government and any country with respect to payments to that country.
20.2 The rates of exchange for the purchase and sale of currency by the
Contractor shall be the prevailing rates of general application
determined by the State Bank of India or such other financial body as
may be mutually agreed by the Parties and in accordance with prevailing
currency and exchange regulations and, for accounting purposes under
this Contract, these rates shall apply as provided in Section 1.6 of
Appendix C.
20.3 Domestic Companies shall be subject to the relevant provisions of the
applicable laws in India governing currency and foreign exchange and
related administrative instructions and procedures issued thereunder.
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55
ARTICLE 21
NATURAL GAS
21.1 Subject to Article 21.2, the Indian domestic market shall have the
first call on the utilisation of Natural Gas discovered pursuant to
Petroleum Operations and produced from the Contract Area. Accordingly,
any proposal by the Contractor relating to Discovery and production of
Natural Gas from the Contract Area shall be made in the context of the
Government's policy for the utilisation of Natural Gas and shall take
into account the objectives of the Government to develop its resources
in the most efficient manner and to promote conservation measures.
21.2 Contractor shall have the right to use Natural Gas produced from the
Contract Area for the purpose of Petroleum Operations including, but
not limited to, reinjection for pressure maintenance in the Oil Fields,
Gas lifting and power generation.
21.3 For the purpose of sales to the domestic market pursuant to this
Article 21, the Delivery Point shall be the Delivery Point set forth in
the Gas sales contract entered into by the Contractor.
21.4 ASSOCIATED NATURAL GAS (ANG)
21.4.1 In the event that a New Discovery of Crude Oil
contains ANG, Contractor shall declare in the
proposal for the declaration of the New Discovery
as a Commercial Discovery as specified in
Article 9, whether (and by what amount) the
estimated production of ANG is anticipated to
exceed the quantities of ANG which will be used
in accordance with Article 21.2 (hereinafter
referred to as "the Excess ANG"). In such event
the Contractor shall indicate whether, on the
basis of the available data and information, it
has reasonable grounds for believing that the
Excess ANG could be commercially exploited in
accordance with the terms of this Contract along
with the Commercial Production of the Crude Oil
from the Oil Field, and whether the Contractor
intends to so exploit the Excess ANG.
21.4.2 Based on the principle of full utilization and
minimum flaring of ANG, a proposed development
plan for an Oil Field (or Oil Fields), shall, to
the extent economically reasonable, include a
plan for utilisation of the ANG from the Existing
Discovery and New Discovery, including estimated
quantities to be flared, reinjected, and to be
used for Petroleum Operations; and, if the
Contractor proposes to commercially exploit the
Excess ANG for sale in the domestic market in
56
accordance with Government's policy, or
elsewhere, the proposed plans for such
exploitation.
21.4.3 If the Contractor wishes to exploit the Excess
ANG (whether from an Existing or New Discovery),
such ANG shall first be offered for sale to the
Government (or its nominee) in writing in
accordance with the terms of this Contract. On
receipt of such offer, the Government (or its
nominee) shall, within three (3) months of the
date of receipt thereof, notify the Contractor,
in writing, whether or not it wishes to exercise
its option to purchase the Excess ANG.
21.4.4 If the Government exercises its option to
purchase the Excess ANG as provided in
Article 21.4.3:
(a) the Government shall indicate in the notice exercising
the option, a date, within two (2) years of the date
of the Contractor's offer, for commencement of
purchase of the Excess ANG;
(b) within six (6) months of the date of notification of
the exercise of the Government's option pursuant to
Article 21.4.3., the Contractor and the Government (or
its nominee) shall agree on the terms for the sale to
Government (or its nominee) of the Excess ANG.
21.4.5 If the Government does not exercise its option to purchase
the Excess ANG the Contractor shall be free to explore
markets for the commercial exploitation of the Excess ANG.
21.4.6 Where the Contractor is of the view that Excess ANG cannot
be commercially exploited, and chooses not to exploit ANG,
or is unable to find a market for the Excess ANG pursuant
to Article 21.4.5, the Government shall be entitled to take
and utilise such Excess ANG.
21.4.7 If the Government elects to take the Excess ANG
as provided in Article 21.4.6:
(a) the Contractor shall deliver such Excess ANG to the
Government (or its nominee) free of cost, at the downstream
flange of the Gas/Oil separation facilities;
(b) the Government or its nominee shall bear all
costs including gathering, treating, processing
57
and transporting costs beyond the downstream
flange of the Gas/Oil separation facilities;
(c) the delivery of such Excess ANG shall be subject to
procedures to be agreed between the Government or its
nominee and the Contractor prior to such delivery, such
procedures to include matters relating to timing of
off-take of such Excess ANG, which procedures shall not, in
any way, restrict Oil production.
21.4.8 Excess ANG which is not commercially exploited by
the Contractor, or taken by the Government or its
nominee pursuant to this Article 21, shall be
returned to the subsurface structure or flared
where such flaring is approved in the Development
Plan, which approval shall not be unreasonably
withheld, for the relevant Oil Field or where
reinjection is uneconomical or inadvisable in
accordance with good reservoir engineering prac-
tices.
21.4.9 Where the Contractor is of the view that there is
economic merit in flaring Gas in the absence of a
Gas transmission system or during such time as
the pipeline is inoperable or lacks capacity to
take all available Gas, Contractor shall have the
right to flare Gas. In any such event,
Contractor shall notify the Management Committee
within forty-eight (48) hours to obtain its
approval for continuing operations.
21.4.10 As soon as practicable after the New Discovery
referred to in Article 21.4.1 or the submission
to the Government of the proposal for the
declaration of the New Discovery as a Commercial
Discovery as therein specified, the Contractor
and the Government or its nominee shall meet to
discuss the sale and/or disposal of any ANG
discovered with a view to giving effect to the
provisions of this Article 21 in a timely manner.
21.5 NON ASSOCIATED NATURAL GAS (NANG)
21.5.1 In the event of a New Discovery of NANG, the
Contractor shall promptly report such New
Discovery to the Management Committee and the
provisions of Articles 9.1 and 9.2 shall apply.
The remaining provisions of Article 9 would apply
to the New Discovery and development of NANG only
in so far as they are not inconsistent with the
provisions of Articles 21.5.1 to 21.5.13.
21.5.2 If, pursuant to Article 9.1, the Contractor gives
notification that a New Discovery is of potential
58
commercial interest, the Contractor shall submit to the
Management Committee, within one (1) Calendar Year from the
date of notification of the above New Discovery, the
proposed Appraisal Programme, including a Work Programme
and budget to carry out an adequate and effective appraisal
of such New Discovery, to determine (i) without delay,
whether such New Discovery is a Commercial Discovery and
(ii) with reasonable precision, the boundaries of the area
to be delineated as a Field. Such programme shall be
supported by all relevant data such as Well data,
Contractor's best estimate of reserve range and production
potential and shall indicate the date of commencement of
the proposed Appraisal Programme. Where in the case of an
Existing Discovery, Contractor desires to carry out
additional appraisal work, the Contractor shall submit its
proposed Appraisal Programme with a Work Programme and
budget to the Management Committee within one hundred
twenty (120) days of the Effective Date for approval.
21.5.3 The proposed Appraisal Programme for an Existing
Discovery or a New Discovery shall be considered
by the Management Committee within sixty (60)
days of its submission by the Contractor and the
programme together with the Work Programme and
budget submitted by the Contractor revised in
accordance with any agreed amendments or
additions thereto approved by the Management
Committee, shall be adopted as the Appraisal
Programme and the Contractor shall promptly
proceed with implementation of such programme.
21.5.4. If on the basis of the results of the Appraisal
Programme, the Contractor is of the opinion that
NANG has been discovered in commercial
quantities, it shall submit to the Management
Committee, as soon as practicable but not later
than five (5) years from the date of notification
of the aforementioned New Discovery, a proposal
for the declaration of the New Discovery as a
Commercial Discovery. Such proposal shall take
into account the Government's policies on Gas
utilisation and propose alternative options (if
any) for use or consumption of the NANG and be
supported by, inter alia, technical and economic
data, evaluations, interpretations and analyses
of such data, feasibility studies relating to the
New Discovery prepared by or on behalf of the
Contractor and other relevant information.
21.5.5 In the case of a New Discovery, simultaneously
with the Contractor's Appraisal Programme,
59
Government and the Contractor shall seek to reach an
agreement on the development, production, processing,
utilisation and sale of the NANG, in the context of Article
21.1, within thirty-six (36) months of the date of
notification of the Discovery referred to in Article 21.5.
If no proposal is submitted to the Management Committee by
the Contractor within five (5) years from the date of
notification of such New Discovery, the Contractor shall
relinquish its rights to develop such New Discovery and the
area relating to such New Discovery shall be excluded from
the Contract Area.
21.5.6 Where the Contractor has submitted a proposal for
the declaration of a New Discovery as a
Commercial Discovery, the Management Committee
shall consider the proposal of the Contractor
with reference to commercial utilisation of the
NANG in the domestic market or elsewhere and in
the context of Government's policy on Gas
utilisation and the chain of activities required
to bring the NANG from the Delivery Point to
potential consumers in the domestic market or
elsewhere. The Management Committee may, within
ninety (90) days, request that the Contractor
submit any additional information on the New
Discovery and the related Appraisal Programme
that it may reasonably require to facilitate a
decision on whether or not to declare the New
Discovery as a Commercial Discovery.
21.5.7 The Management Committee shall make a decision regarding
the declaration of a New Discovery as a Commercial
Discovery within the latter of:
(a) one hundred eighty (180) days of receipt of
such proposal; or
(b) one hundred eighty (180) days of receipt of
the additional information referred to above.
21.5.8 If the Management Committee, with the approval of
the Government, declares a New Discovery a
Commercial Discovery, such declaration shall be
accompanied by an indication of the probable
date(s) by when the market(s) would be ready to
receive the Gas and an estimate of the quantities
of Gas that could be so utilised. The
Contractor, in such an event, shall, within One
(1) Calendar Year of the declaration of the New
Discovery as a Commercial Discovery, submit a
Development Plan for the development of the Gas
Field to the Management Committee for its
approval. Such plan shall be supported by all
60
relevant information including, inter alia, the information
required in Article 9.6. In the case of an Existing
Discovery, Contractor shall within ninety (90) days of the
Effective Date propose a Development Plan following the
plan brought out in Appendix G, intended to achieve the
production profile brought out in Appendix H, containing
the detailed information required in Article 9.6, with
supporting budget and the Management Committee shall render
its decision regarding such proposal within thirty (30)
days of such submittal. Where a Development Plan is so
agreed, it shall be an approved Development Plan pursuant
to this Article.
21.5.9 If the Development Plan has not been approved by
the Management Committee within one hundred and
eighty (180) days of its submission, the
Contractor shall have the right to submit such
plan or plans directly to the Government for
approval, within sixty (60) days of the expiry of
the time provided to the Management Committee to
approve the plan or plans. The Government shall
respond to the submission within ninety (90) days
of receipt thereof. If the Government rejects
the Contractor's proposed plan or plans, the
Government shall state in writing the reasons for
such rejection and the Contractor shall have the
right to resubmit, within sixty (60) days of
written notice of such rejection, such plan or
plans duly amended to meet the Government's
objections thereto. Such right of resubmission
of each proposed plan or plans shall be
exercisable by the Contractor only once. If the
Parties are unable to agree, any Party shall have
the right to submit the matter to arbitration.
If no such plan or plans is/are submitted to the
Government within the aforesaid period, the
Contractor shall relinquish its right to develop
such Gas Field and such Gas Field shall be
excluded from the Contract Area.
21.5.10 If the Management Committee is unable to agree on
the declaration of a New Discovery as a
Commercial Discovery within the time limit
prescribed in Article 21.5.7, the Contractor, or
any of its constituents, shall be entitled to
submit such proposal directly to the Government
for approval. In such event, the Contractor, or
any of its constituents, shall also submit a
comprehensive plan or plans for development of
such New Discovery, which shall detail the
proposed Development Plan for utilisation of the
61
NANG produced in the domestic market giving, inter alia,
the data specified in Article 21.5.8. The proposal for
declaration of the New Discovery as a Commercial Discovery
as well as the proposed Development Plan shall be submitted
to the Government within one hundred and eighty (180) days
of the expiry of the time given to the Management Committee
to reach a decision on the proposal for declaration of the
New Discovery as a Commercial Discovery and Government
shall respond to the said submission within one hundred
twenty (120) days of its receipt. If the Government
disapproves the proposed plan or plans, the Government
shall state in writing the reasons for such disapproval and
the concerned Parties shall have the right to resubmit,
within sixty (60) days, such plan or plans duly amended to
meet the Government's objections thereto. Such right of
resubmission of each proposed plan or plans shall be
exercisable by the Contractor only once. In the event the
Government does not approve such plan or plans, any Party
shall have the right to submit the matter to arbitration.
If no such plan (plans) is (are) submitted to the
Government within the aforesaid period, the Contractor
shall relinquish its rights to develop such Gas Field and
such Gas Field shall be excluded from the Contract Area.
21.5.11 In the event the Management Committee , or
Government, as the case may be, approves the
Contractor's proposal for declaration of the New
Discovery as a Commercial Discovery and also the
comprehensive plan or plans for development of
such New Discovery and for the utilisation of
NANG produced in the domestic market, the Gas
Field shall be promptly developed by the
Contractor in accordance with the approved plan
which shall be the Development Plan for the
Field.
21.5.12 In the event the Contractor does not commence development
of a New Discovery within ten (10) years from the date of
completion of the first Discovery Well, the Contractor
shall relinquish its rights to develop such New Discovery
and the area relating to such New Discovery shall be
excluded from the Contract Area.
21.5.13 The price of the ANG and NANG produced from the Oil or Gas
Field for use in India shall be specified in the Gas sales
contract, which shall be in accordance with the provisions
of this Article 21.5.13, between the Contractor and the
nominee of the Government.
62
(a) Unless the context otherwise requires, the following
words and terms wherever and whenever used or
appearing in this Article 21.5.13 shall have the
following meaning:
(i) "British Thermal Unit" or "BTU" means the amount
of energy required to raise the temperature of
one (1) pound (avoirdupois) of pure water, at
sixty degrees (60(degree)) Fahrenheit, one
degree (1(degree)) Fahrenheit at an absolute
pressure of 14.73 pounds per square inch.
(ii) "Buyer" means the Government of India or
its nominee.
(iii) "Deliverability" means the lesser of the maximum
aggregate rate of all wells in the Contract Area
or the maximum delivery capacity of the
processing facility, subject to generally
accepted international petroleum industry
practices.
(iv) "Delivery Point" means a point downstream of the
Seller's onshore Gas receiving facility in the
Hazira area and at the upstream weld of the
connection to the Buyer's pipeline in the Hazira
area.
(v) "Maximum Delivery Pressure" has the
meaning set forth in Article 21.5.13(c).
(vi) "MMBTU" means one million (1,000,000)
BTU's on a net heating value basis.
(vii) "Seller" means Contractor.
(b) The Seller agrees to produce and deliver, on
a daily basis, to the Buyer one hundred
percent (100%) of the Deliverability of ANG
and NANG at the Delivery Point and the Buyer,
provided the Gas is made available and
tendered for delivery by the Seller, agrees
to take and purchase, on a daily basis, one
hundred percent (100%) of the Deliverability
of ANG and NANG provided, however, that
Seller, at Seller's sole discretion, subject
to generally accepted operator practices in
the international petroleum industry, may
adjust deliveries to provide for necessary
maintenance, service and testing. Buyer may
63
request that Seller vary deliveries to accommodate
similar circumstances in the Buyer's operation and
Seller's approval shall not be unreasonably withheld.
Communications procedures shall be mutually agreed in
the Gas sales contract in accordance with
internationally accepted industry standards.
(c) The Gas sold hereunder shall be delivered at the
Delivery Point in the Hazira area at the operating
pressure of the Buyer's owned or contracted pipeline
up to a maximum pressure ("Maximum Delivery Pressure")
of one thousand
(1000) psig.
(d) Subject to the provisions hereof, the Buyer shall pay
the Seller for each MMBTU of Gas delivered hereunder,
or for each MMBTU of Gas for which the Buyer is
obligated to pay hereunder, a price calculated as
follows:
The Base Price ("Base Price") in United States Dollars
(US$) per MMBTU is fixed on the basis of ninety-nine
percent (99%) of a Low Sulfur Fuel Oil Basket ("LSFO
Basket") calculated as the average of the daily mean
value for low and high prices of fuel oil taking into
account equal parts of:
(1) bulk residual fuel oil, containing one percent
(1%) sulfur, quoted for barges at Northwest
Europe, (Barges, FOB Rotterdam); and
(2) bulk residual fuel oil, containing one percent
(1%) sulfur, quoted for Mediterranean, basis
Italy, (Cargoes, FOB Med, basis Italy); and
(3) a theoretical blend of residual fuel oil
composed of Singapore Cargoes made up of
seventy-four percent (74%) of LSWR-SR 0.3%,
(three-tenths percent (0.3%) sulfur), and
twenty-six percent (26%) of HSFO 180, three and
one-half percent (3.5%) sulfur, viscosity 180
centistokes.
The Base Price is calculated on the basis of the
arithmetic average of the monthly values of the
prices of the listed products as published in
Platt's Oilgram Price Report for the eighteen
(18) months of May, 1992 through October, 1993,
inclusive. (These values
64
are derived from the mean of the daily ranges on
days the postings are published to give a
monthly value.) For the purpose of this
Contract, Base Price will be equal to
$2.32/MMBTU.
The price of Gas for each MMBTU for each Calendar
Quarter thereafter shall be determined by the
following formula:
Price = Base Price x (A/B)
Where:
A = a value calculated for the HS/LSFO Basket, defined
in this Article 21.5.13 (d), evaluated for the twelve
(12) months preceding the Calendar Quarter using the
method for averaging as described for calculating the
Base Price, and
B = A value calculated for the HS/LSFO Basket, evaluated
for the twelve (12) months April 1993 through March
1994.
The High Sulfur/Low Sulfur Fuel Oil Basket
("HS/LSFO Basket") is valued as equal parts
of:
(1) bulk residual fuel oil, containing one
percent (1%) sulfur, quoted for
Mediterranean, basis Italy, (Cargoes,
FOB Med, basis Italy); and
(2) bulk residual fuel oil, containing one percent
(1%) sulfur, quoted for Northwest Europe
Cargoes, CIF, basis ARA, (Cargoes CIF NWE,
Basis ARA), and
(3) bulk residual fuel oil, Singapore Cargoes,
containing three and one-half percent (3.5%)
sulfur, viscosity 180 centistokes, (Singapore
HSFO, 180 cst), and
(4) bulk residual fuel oil, Cargoes, FOB Arab
Gulf, viscosity 180 centistokes, (Arab Gulf,
FOB HSFO 180 cst)
using the method for averaging as described
for calculating the Base Price.
The Floor Price ("Floor Price") shall be ninety percent
(90%) of the monthly values of the prices of the LSFO
Basket as published in Platt's Oilgram Price Report for
the eighteen
65
(18) months of May, 1992 through October, 1993,
inclusive. (These values are derived from the mean of
the daily ranges on days the postings are published to
give a monthly value.) For the purpose of this Contract,
Floor Price will be equal to $2.11/MMBTU.
Notwithstanding results of the calculations for price as
shown in this Article 21.5.13 (d), the actual price
shall in no event be less than a Floor Price ("Floor
Price") which is calculated as US$2.11/MMBTU, nor more
than a Ceiling ("Ceiling") of the Floor Price plus
US$1.00/MMBTU, provided that after seven (7) years from
the Date of first delivery, the Seller shall have the
option to revise the Ceiling to one hundred fifty
percent (150%) of ninety percent (90%) of the same or
equivalent basket of fuel oils used in calculating the
Base Price averaged over the immediately preceeding
eighteen (18) months.
Parties agree to convert US$/barrel prices for fuel oil
as published in Platt's Oilgram to US$/MMBTU using a
factor of 6.28.
If Platt's Oilgram is no longer published, an alternate
publication shall be mutually agreed upon.
21.5.14 Nothing contained in any contract entered into by the
Contractor for the supply, sale or disposal of Gas, with
any nominee of the Government shall in any manner abrogate
the obligation of the Government contained herein.
21.5.15 The Government and/or its nominee shall pay any and all
sales tax payable on the sale of Gas to the Government or
its nominee.
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66
ARTICLE 22
EMPLOYMENT, TRAINING AND TRANSFER OF TECHNOLOGY
22.1 Without prejudice to the right of the Contractor to select and employ
personnel in numbers and with the qualifications as, in the opinion of
the Contractor, are required for carrying out Petroleum Operations in a
safe, cost effective and efficient manner, the Contractor shall, to the
maximum extent reasonably possible, employ, and require the Operator
and Subcontractors to employ, citizens of India having appropriate
qualifications and experience, taking into account the experience
required and the level and nature of the Petroleum Operations.
22.2 Contractor shall offer up to two (2) man months per year of on-the-job
training and practical experience in skilled, management and executive
positions of their ongoing Petroleum Operations to Indian nationals of
the Government's choice.
22.3 Contractor shall associate and involve mutually agreed numbers of
citizens of India designated by the Government, which shall in no event
exceed three (3) people at any one time, in the technological aspects
of the then ongoing Petroleum Operations for up to two man months per
year.
Such aspects shall include:
(a) seismic data acquisition, processing and
interpretation;
(b) computerized formation evaluation using well logs;
(c) computerized analysis of geological data for basin
analysis;
(d) laboratory core analysis;
(e) reservoir simulation and modelling;
(f) geochemistry, including analytical methods, source rock
studies, hydrocarbon generation, modelling;
(g) measurement-while-drilling techniques;
(h) stimulation of wells;
(i) production engineering including, optimization methods
for surface and subsurface facilities (e.g. NODAL
analysis and implementation);
(j) reservoir engineering and management including gas and
water injection;
(k) enhanced oil recovery techniques;
67
(l) gas production technology;
(m) pipeline technology;
(n) well design and drilling technology;
(o) design of offshore facilities.
22.4 Except as herein provided, no Party shall be obliged to disclose by
virtue of this Article 22 any data, process or information, whether
owned by itself, any of its Affiliates or a third party, of a
proprietary nature.
22.5 At the request of the Government the Contractor shall separately
endeavour to negotiate, in good faith, technical assistance agreements
with the Government setting forth the terms by which each constituent
of the Contractor may render technical assistance and make available
commercially proven technical information of a proprietary nature for
use in India by the Government. The issues to be addressed in
negotiating such technical assistance agreements shall include, but not
be limited to, licensing issues, royalty conditions, confidentiality
restrictions, liabilities, costs and method of payment.
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68
ARTICLE 23
LOCAL GOODS AND SERVICES
23.1 In the conduct of Petroleum Operations, the Contractor
shall:
(a) give preference to the purchase and use of goods manufactured,
produced or supplied in India provided that such goods are
available on terms equal to or better than imported goods with
respect to timing of delivery, quality and quantity required,
price and other terms;
(b) employ Indian Subcontractors having the required skills
or expertise, to the extent reasonably possible, in so
far as their services are available on comparable
standards with those obtained elsewhere and at
competitive prices and on competitive terms; provided
that where no such Subcontractors are available,
preference shall be given to non-Indian Subcontractors
who utilise Indian goods to the maximum extent possible
subject however to the proviso in paragraph (a) above;
(c) cooperate to the extent possible and without financial obligation
with domestic companies in India to enable them to develop skills
and technology to service the petroleum industry;
(d) ensure that provisions in terms of paragraphs (a) to (c) above
are contained in contracts between the Operator and its
Subcontractors.
23.2 The Contractor shall establish appropriate procedures, including tender
procedures, for the acquisition of goods and services which shall
ensure that suppliers and Subcontractors in India are given adequate
opportunity to compete for the supply of goods and services. The tender
procedures shall include, inter alia, the financial amounts or value of
contracts which will be awarded on the basis of selective bidding or
open competitive bidding, the procedures for such bidding, and the
exceptions to bidding in cases of emergency.
23.3 Within one hundred and twenty (120) days after the end of each Calendar
Year, the Contractor shall provide the Government with a report
outlining its achievements in utilising Indian resources during that
Calendar Year.
23.4 In this Article "goods" means equipment, materials and
supplies.
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ARTICLE 24
INSURANCE AND INDEMNIFICATION
24.1 INSURANCE
24.1.1 The Contractor shall, during the term of this
Contract, obtain and maintain insurance coverage
for and in relation to Petroleum Operations for
such amount and against such risks in accordance
with generally accepted international operating
practices as are set forth herein, and shall
furnish to the Government certificates evidencing
that such coverage is in effect. Such insurance
policies shall include the Government as
additional insured and shall waive subrogation
against the Government. The insurance shall,
without prejudice to the generality of the
foregoing, cover:
(a) Loss or damage to all installations,
equipment and other assets for so long as
they are used in or in connection with
Petroleum Operations; provided, however, if
Contractor fails to insure any such
installation, equipment or assets, it shall
replace any loss thereof or repair any damage
caused thereto;
(b) Loss, damage or injury caused by pollution in
the course of or as a result of Petroleum
Operations;
(c) Loss or damage to property or bodily injury suffered
by any third party in the course of or as a result of
Petroleum Operations for which the Contractor may be
liable;
(d) With respect to Petroleum Operations offshore, the
cost of removing wrecks and cleaning up operations
following any accident in the course of or as a result
of Contractor's Petroleum Operations;
(e) The Contractor's and/or Operator's liability
to its employees engaged in Petroleum
Operations.
24.1.2 The Contractor shall require its Subcontractors to obtain
and maintain insurance against the risks referred to in
Article 24.1.1 relating mutatis mutandis to such
Subcontractors.
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24.2 INDEMNITY
The Contractor shall indemnify, defend and hold the Government harmless
against all claims, losses and damages of any nature whatsoever,
including without limitation, claims for loss or damage to property or
injury or death to persons caused by or resulting from any Petroleum
Operations conducted by or on behalf of the Contractor.
24.3 ONGC shall indemnify and hold the Companies harmless against all
claims, losses and damages of any nature whatsoever, including, but not
by way of limitation, claims for loss or damage to property or injury
or death to persons or Environmental Damage caused by or resulting from
and attributable to any operations in the nature of Petroleum
Operations conducted by or on behalf of ONGC prior to the Effective
Date.
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ARTICLE 25
RECORDS, REPORTS, ACCOUNTS AND AUDIT
25.1 The Contractor shall prepare and maintain at an office in India
accurate and current books, records, reports and accounts of its
activities for and in connection with Petroleum Operations so as to
present a fair, clear and accurate record of all its activities,
expenditures and receipts. The Contractor shall also keep
representative samples of cores and cuttings.
25.2 Based on generally accepted and recognised accounting principles and
modern petroleum industry practices, records, books, accounts and
accounting procedures in respect of Petroleum Operations shall be
maintained on behalf of the Contractor by the Operator, at its business
office in India.
25.3 The annual audit of accounts shall be carried out on behalf of the
Contractor by a qualified, independent firm of internationally
recognised chartered accountants, registered in India and selected by
the Contractor.
25.4 Accounts, together with the auditor's report thereon, shall be
submitted to the Parties for approval not later than the thirtieth
(30th) September following the Financial Year.
25.5 The Government shall have the right to audit the accounting records of
the Contractor in respect of Petroleum Operations as provided in the
Accounting Procedure.
25.6 The accounting and auditing provisions and procedures specified in this
Contract are without prejudice to any other requirements imposed by any
statute in India, including, without limitation, any specific
requirements of the statues relating to taxation of companies.
25.7 For the purpose of any audit referred to in Article 25.5, the Operator
or the Contractor shall make available to the auditor all such books,
records, accounts and other documents and information as may be
reasonably required by the auditor during normal business hours.
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ARTICLE 26
INFORMATION, DATA, CONFIDENTIALITY, INSPECTION AND SECURITY
26.1 The Contractor shall, promptly after they become available, make
available to the Government in its offices all data obtained as a
result of Petroleum Operations under the Contract including, but not
limited to, geological, geophysical, geochemical, petrophysical,
engineering, well logs, maps, magnetic tapes, cores and production data
as well as all interpretative and derivative data, including reports,
analyses, interpretations and evaluations prepared in respect of
Petroleum Operations (hereinafter referred to as "Data"). Data shall be
the property of the Government, provided however, that the Contractor
shall have the right to make use of such Data, free of cost, for the
purpose of Petroleum Operations under this Contract as provided herein.
26.2 Contractor shall keep the Government currently advised of all
developments taking place during the course of Petroleum Operations and
shall furnish the Government with such progress reports containing full
and accurate information relating to Petroleum Operations (on a
periodic basis) as the Government may reasonably require, provided that
this obligation shall not extend to proprietary technology. Without
prejudice to the generality of the foregoing, the Contractor shall
submit regular statements and reports relating to Petroleum Operations
as provided in Appendix C. Contractor shall meet with the Government at
a mutually convenient location to present the results of all geological
and geophysical work carried out as well as the results of all
engineering and drilling operations as soon as practical after such
Data becomes available to the Contractor.
26.3 All Data, information and reports obtained or prepared by, for or on
behalf of, the Contractor pursuant to this Contract shall be treated as
confidential and, subject to the provisions hereinbelow, the Parties
shall not disclose the contents thereof to any third party without the
consent in writing of the other Parties.
26.4 The obligation specified in Article 26.3 shall not operate
so as to prevent disclosure:
(a) to Affiliates, Contractors, or Subcontractors for the
purpose of Petroleum Operations;
(b) to employees, professional consultants, advisers, data processing
centres and laboratories, where required, for the performance of
functions in connection with Petroleum Operations for any Party
comprising the Contractor;
(c) to banks or other financial institutions, in connection
with Petroleum Operations;
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(d) to bona fide intending assignees or transferees of an interest
hereunder of a Party comprising the Contractor or in connection
with a sale of stock of a Party comprising the Contractor;
(e) to the extent required by any applicable law or in connection
with any legal proceedings or by the regulations of any stock
exchange upon which the shares of a Party comprising Contractor
are quoted;
(f) to Government departments for, or in connection with, the
preparation by or on behalf of the Government of statistical
reports with respect to Petroleum Operations, or in connection
with the administration of this Contract or any relevant law or
for any purpose connected with Petroleum Operations;
(g) by a Party with respect to any Data or information which, without
disclosure by such Party, is generally known to the public.
26.5 Any Data, information or reports disclosed by the Parties comprising
the Contractor to any person other than pursuant to Article 26.4 (a),
(b) and (g) shall be disclosed on the terms that such Data, information
or reports shall be treated as confidential by the recipient. Prompt
notice of disclosures made by the Contractor pursuant to Article 26.5
shall be given to the Government.
26.6 Any Data, information and reports relating to the Contract Area, which,
in the opinion of the Government, might have significance in connection
with offers by the Government of open acreage or an exploration
programme to be conducted by a third party in another area, may be
disclosed by the Government for such purposes on conditions to be
agreed upon between the Government and the Contractor.
26.7 Where an area ceases to be part of the Contract Area, the Contractor
shall continue to treat Data and information with respect to the area
as confidential and shall deliver to the Government copies or originals
of all Data and information in its possession with respect to the area.
The Government shall, however, have the right to freely use the Data
and information thereafter.
26.8 The Government shall, at all reasonable times, through duly authorised
representatives, be entitled to observe Petroleum Operations and to
inspect all assets, books, records, reports, accounts, contracts,
samples and Data kept by the Contractor or the Operator in respect of
Petroleum Operations under the Contract, provided, however, that the
Contractor shall not be required to disclose any proprietary
technology. The duly authorised representatives shall be given
reasonable assistance by the Contractor for such functions and the
Contractor shall afford such
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representatives all facilities and privileges afforded to its own
personnel in the field including the use of office space and housing,
free of charge. The representatives shall be entitled to make a
reasonable number of surveys, measurements, drawings, tests and copies
of documents, take samples, and make a reasonable use of the equipment
and instruments of the Contractor provided that such functions shall
not unduly interfere with the Contractor's Petroleum Operations.
26.9 Contractor shall give reasonable advance notice to the Government, or
to any other authority designated by the Government for such purpose,
of its programme of conducting surveys by aircraft or by ships,
indicating, inter alia, the name of the survey to be conducted,
approximate extent of the area to be covered, the duration of the
survey, the commencement date, and the name of the airport or port from
which the survey aircraft or ship will commence its voyage.
26.10 The Government, or the authority designated by the Government for such
purpose, shall have the right to inspect any aircraft or ship used by
the Contractor or a Subcontractor carrying out any survey or other
operations in the Contract Area and shall have the right to put on
board such aircraft or ship Government officers in such number as may
reasonably be necessary to ensure compliance by the Contractor or the
Subcontractor with the security requirements of India.
26.11 Expatriate employees and Subcontractors shall, for national security
purposes, be subject to the approval of the Government, such approval
not to be unreasonably withheld.
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ARTICLE 27
TITLE TO PETROLEUM, DATA AND ASSETS
27.1 The Government is the sole owner of Petroleum underlying the Contract
Area and shall remain the sole owner of Petroleum produced pursuant to
the provisions of this Contract except that part of Crude Oil or Gas
the title whereof has passed to each constituent of the Contractor or
any other person in accordance with the provisions of this Contract.
27.2 Title to Crude Oil and/or Gas to which each constituent of the
Contractor is entitled under this Contract, and title to Crude Oil
and/or Gas sold to Government or its nominee by the constituents of the
Contractor shall pass to the relevant Party, or as the case may be, to
Government or its nominee at the Delivery Point. Contractor shall be
responsible for all costs and risks prior to the Delivery Point and
each Party shall be responsible for all costs and risks associated with
such Party's share after the Delivery Point. Where the Government or
its nominee purchases all or some of the Contractor's share of Crude
Oil or Condensate, the Government or its nominee shall be responsible
for all costs and risks in respect of the amount purchased, after the
Delivery Point.
27.3 Title to all Data specified in Article 26 shall be vested in the
Government and the Contractor shall have the right of use thereof as
therein provided.
27.4 Assets in place or contracted for use in or on the Contract Area
purchased by the Contractor for use in Petroleum Operations shall be
owned by the Parties comprising Contractor in proportion to their
Participating Interest provided that the Government, or its nominee,
shall have the right to require vesting of full title and ownership
including abandonment obligations, if any, in it, free of cost, charge
and encumbrances, of any or all assets, whether fixed or movable,
acquired and owned by the Contractor for use in Petroleum Operations
inside or outside the Contract Area, except assets required by a Party
for ongoing operations in the nature of Petroleum Operations in India,
such right to be exercisable by the Government, or its nominee, upon
expiry or earlier termination of the Contract.
27.5 Contractor shall be responsible in accordance with international
petroleum standards for proper maintenance, insurance and safety of all
assets acquired for Petroleum Operations for keeping them in good
repair, order and working condition at all times, and the costs thereof
shall be recoverable as Contract Costs in accordance with Appendix C.
27.6 So long as this Contract remains in force, the Contractor shall, free
of any charge for the purpose of carrying out Petroleum Operations
hereunder, have the exclusive use of
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the assets which have become or are the property of the Government
including, without limitation, those identified in Appendix F.
27.7 Equipment and assets no longer required for Petroleum Operations shall
first be offered free of cost, charge and encumbrance to the
Government, or its nominee, and, if not required by the Government, or
its nominee, will be so indicated in writing within thirty (30) days of
such offer. Failure to so indicate will be deemed to be a rejection of
the offer by the Government.
27.8 Assets not acquired by the Government, or its nominee, may
be sold or otherwise disposed of subject to the terms of
this Contract.
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ARTICLE 28
ASSIGNMENT OF INTEREST
28.1 Subject to the terms of this Article and other terms of this Contract,
any Party comprising the Contractor may assign, or transfer, a part or
all of its Participating Interest, with the prior written consent of
the Government, which consent shall not be unreasonably withheld,
provided that the Government is satisfied that:
(a) the prospective assignee or transferee has the financial
standing, technical competence, capacity and ability to meet its
obligations hereunder, and is willing to provide an unconditional
undertaking to assume its Participating Interest share of
obligations and to provide a guarantee in respect thereof as
provided in the Contract.
(b) the prospective assignee or transferee is not a company
incorporated in a country with which the Government, for policy
reasons, has restricted trade or business;
(c) the prospective assignor or transferor and assignee or transferee
respectively are willing to comply with any reasonable conditions
of the Government as may be necessary in the circumstances with a
view to ensuring performance under the Contract; and
(d) the assignment or transfer will not adversely affect the
performance or obligations under this Contract or be contrary to
the interests of India.
28.2 An application by a Company for consent to assign or transfer shall be
accompanied by all relevant information concerning the proposed
assignment or transfer including detailed information on the proposed
assignee or transferee and its shareholding and corporate structure, as
was earlier required from the Companies constituting the Contractor,
the terms of the proposed assignment or transfer and the unconditional
undertaking referred to in Article 28.1(a) above. The applicant shall
also submit such information relating to the prospective assignee or
transferee of the assignment or transfer as the Government may
reasonably require to enable proper consideration and disposal of the
application.
28.3 No assignment or transfer shall be effective until the approval of the
Government is received, which approval may be given by the Government
on such terms as it may deem fit. Upon assignment or transfer of its
interest in this Contract, the assignor or transferor shall be released
and discharged from its obligations hereunder only to the extent that
such obligations are assumed by the assignee or transferee with the
approval of the Government.
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28.4 The assignor shall clearly state in its deed of assignment, that the
assignee shall be liable for all future obligations, under the
Contract, to the extent of assignment.
28.5 Upon prior notice to the Contractor, the Government may assign or
transfer all or any part of its rights and interest under this Contract
to any Government company wholly or partly owned by the Government and
authorised by the Government to explore for and exploit Petroleum in
the Contract Area. Upon prior notice to the Government, a Company may
assign or transfer all or any part of its rights and interest under
this Contract to an Affiliate subject to Article 6.2 and the parent
company guarantee shall apply.
28.6 An assignment or transfer shall not be made so as to reduce the
Participating Interest of a constituent of the Contractor, at any time,
to less than ten percent (10%) of the total Participating Interest of
all the constituents of the Contractor, except where the Government
may, in special circumstances, so permit.
28.7 Nothing herein contained shall prohibit a Company in the normal course
of business from pledging its Participating Interest share for purposes
of financing, such as a mortgage, charge or encumbrance on Petroleum
assets or production of Petroleum at its own risk, cost and
responsibility. The Contractor shall provide the Government with
fifteen (15) days prior written notice before entering into any such
financing arrangements
28.8 No assignment or pledge under this Article shall have the effect of
decreasing the benefits accruing to Government under this Contract in
any manner whatsoever.
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ARTICLE 29
GUARANTEE
29.1 Each of the Companies shall deliver to the Government on
the Effective Date of this Contract:
(a) a financial and performance guarantee, for the performance of all
obligations under the Contract, in the case of EOGIL from a
parent company of good financial standing acceptable to the
Government, in favour of the Government, in the form and
substance set out in Appendix E;
(b) a legal opinion from its legal advisors, in a form satisfactory
to the Government, to the effect that the aforesaid guarantee has
been duly signed and delivered on behalf of the guarantors with
due authority and is legally valid and enforceable and binding
upon them.
29.2 If any of the documents referred to in Article 29.1 are not delivered
within the period specified herein, this Contract may be cancelled by
the Government upon ninety (90) days written notice of its intention to
do so.
29.3 Notwithstanding any change in the composition or shareholding of the
parent company furnishing the guarantees herein, it shall, under no
circumstances, be absolved of its obligations contained in the
guarantees provided pursuant to this Article.
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ARTICLE 30
TERMINATION OF CONTRACT
30.1 This Contract may, subject to the provisions hereinbelow and Article
31, be terminated by the Government without any financial liability
upon giving ninety (90) days written notice of its intention to do so
in the following circumstances, namely, that a Company :
(a) has knowingly submitted any false statement to the
Government in any manner which was a material
consideration in the execution of this Contract; or
(b) has intentionally and knowingly extracted or authorised
the extraction of any mineral not authorised to be
extracted by the Contract or without the authority of
the Government except such extractions as may be
unavoidable as a result of operations conducted
hereunder in accordance with generally accepted
international petroleum industry practice which, when
so extracted, were immediately notified to the
Government; or
(c) is adjudged bankrupt by a competent court or enters into any
agreement or scheme of composition with its creditors or takes
advantage of any law for the benefit of debtors; or
(d) has passed a resolution to apply to a competent court for
liquidation of the Company unless the liquidation is for the
purpose of amalgamation or reconstruction of which the Government
has been given notice and the Government is satisfied that the
Company's performance under this Contract would not be adversely
affected thereby and has given its approval thereto; or
(e) has assigned any interest in the Contract without the
prior consent of the Government as provided in
Article 28; or
(f) fails to make any monetary payment required by law or under this
Contract by the due date or within the specified period after the
due date; or
(g) fails to comply with or contravenes the provisions of
this Contract in a material particular; or
(h) fails to comply with any final determination or award
made by a sole expert or arbitrators pursuant to
Article 33; or
(i) has been served a notice of cancellation pursuant to
Article 29.2.
PROVIDED THAT
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where the Contractor comprises two or more Companies, the Government
shall not exercise its rights of termination pursuant to Article 30.1,
on the occurrence, in relation to one or more, but not all, of the
Companies, of an event entitling the Government to terminate the
Contract, if any other Company or Companies constituting the Contractor
satisfies the Government that it, or they, is/are willing and would be
able to carry out the obligations of the Contractor.
30.2 This Contract may also be terminated by the Government on giving the
requisite notice specified above if the events specified in Article
30.1 (c) and (d) occur with respect to a company which has given a
guarantee pursuant to Article 29 subject, however, to Article 30.3.
30.3 If the circumstances that give rise to the right of termination under
Article 30.1 (f) or (g) or Article 29.2 are remedied by the Contractor
within the ninety (90) day period or such extended period as may be
granted by the Government, following the notice of the Government's
intention to terminate the Contract as aforesaid, such termination
shall not become effective.
30.4 If the circumstance or circumstances that would otherwise result in
termination are the subject matter of proceedings under Article 33,
then termination shall not take place so long as such proceedings
continue and thereafter may only take place when and if consistent with
the arbitral award.
30.5 On termination of this Contract, for any reason whatsoever, the rights
and obligations of the Contractor shall cease but such termination
shall not affect any rights of any Party which may have accrued or any
obligations undertaken, or incurred, pursuant to this Contract, by
Government or the Contractor or any Party comprising the Contractor and
not discharged by the Contractor or the Party prior to the date of
termination.
30.6 In the event of termination pursuant to Articles 30.1 or
30.2:
(a) the Government may require the Contractor, for a period not
exceeding one hundred and eighty (180) days from the date of
termination, to continue, for the account and at the cost of the
Government, Crude Oil or Natural Gas production activities until
the right to continue such production has been transferred to
another entity;
(b) A Foreign Company, which is a constituent of the Contractor,
shall, subject to the provisions hereof, have the right to remove
and export all its property which has not vested in the
Government provided that in the event that ownership of any
property is in doubt,
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or disputed, such property shall not be exported unless and until
the doubt or dispute has been settled in favour of the Foreign
Company.
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ARTICLE 31
FORCE MAJEURE
31.1 Performance by any Party hereto of any of its obligations under this
Contract, or in fulfilling any condition of any lease granted to such
Party, or any lease issued thereunder, shall, except for the payment of
monies due under this Contract or under the Act and the Rules or any
law, be suspended or excused if, and to the extent that, such
non-performance or delay in performance is caused by Force Majeure as
defined in this Article.
31.2 For the purpose of this Contract, the term Force Majeure means any
cause or event, other than the unavailability of funds, whether similar
to or different from those enumerated herein, beyond the reasonable
control of, and unanticipated or unforeseeable by, and not brought
about at the instance of the Party claiming to be affected by such
event, or which, if anticipated or foreseeable, could not be avoided or
provided for, and which has caused the non-performance or delay in
performance. Without limitation to the generality of the foregoing, the
term Force Majeure shall include natural phenomena or calamities,
earthquakes, typhoons, fires, wars declared or undeclared, hostilities,
invasions, blockades, riots, insurrection and civil disturbances.
31.3 Where a Party is claiming suspension of its obligations on account of
Force Majeure, it shall promptly, but in no case later than seven (7)
days after the occurrence of the event of Force Majeure, notify the
other Parties in writing giving full particulars of the Force Majeure,
the estimated duration thereof, the obligations affected and the
reasons for its suspension.
31.4 A Party claiming Force Majeure shall exercise reasonable diligence to
seek to overcome the Force Majeure event and to mitigate the effects
thereof on the performance of its obligations under this Contract
provided, however, that the settlement of strikes or differences with
employees shall be within the discretion of the Party having the
difficulty. The Party affected shall promptly notify the other Parties
as soon as the Force Majeure event has been removed and no longer
prevents it from complying with the obligations which have been
suspended and shall thereafter resume compliance with such obligations
as soon as possible. The period of work commitment or this Contract may
be extended by such additional period as may be agreed by the Parties.
31.5 Notwithstanding anything contained herein, if an event of Force Majeure
occurs and is likely to continue for a period in excess of thirty (30)
days, the Parties shall meet to discuss the consequences of the Force
Majeure and the course of action to be taken to mitigate the effects
thereof or to be adopted in the circumstances.
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ARTICLE 32
APPLICABLE LAW AND LANGUAGE OF THE CONTRACT
32.1 Subject to the provisions of Article 33.12, this Contract
shall be governed and interpreted in accordance with the
laws of India.
32.2 Nothing in this Contract shall entitle the Government or the Contractor
to exercise the rights, privileges and powers conferred upon it by this
Contract in a manner which will contravene the laws of India.
32.3 The English language shall be the language of this Contract and shall
be used in arbitral proceedings. All communication, hearings or visual
materials or documents relating to this Contract shall be in English.
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ARTICLE 33
SOLE EXPERT, CONCILIATION AND ARBITRATION
33.1 The Parties shall use their best efforts to settle amicably all
disputes, differences or claims arising out of or in connection with
any of the terms and conditions of this Contract or concerning the
interpretation or performance thereof.
33.2 Except for matters which, by the terms of this Contract, the Parties
have agreed to refer to a sole expert and any other matters which the
Parties may agree to so refer, any dispute, difference or claim arising
between the Parties hereunder which cannot be settled amicably may be
submitted by any Party to arbitration pursuant to Article 33.3. Such
sole expert shall be an independent and impartial person of
international standing with relevant qualifications and experience
appointed by agreement between the Parties. Any sole expert appointed
shall be acting as an expert and not as an arbitrator and the decision
of the sole expert on matters referred to him shall be final and
binding on the Parties and not subject to arbitration. If the Parties
are unable to agree on a sole expert, the disputed subject matter may
be referred to arbitration.
33.3 Subject to the provisions herein, any unresolved dispute, difference or
claim which cannot be settled amicably within a reasonable time may,
except for those referred to in Article 33.2, be submitted to an
arbitral tribunal for final decision as hereinafter provided.
33.4 The arbitral tribunal shall consist of three arbitrators. The Party or
Parties instituting the arbitration shall appoint one arbitrator and
the Party or Parties responding shall appoint another arbitrator and
both Parties shall so advise the other Parties. The two arbitrators
appointed by the Parties shall appoint the third arbitrator.
33.5 Any Party may, after appointing an arbitrator, request the other
Party(ies) in writing to appoint the second arbitrator. If such other
Party fails to appoint an arbitrator within forty-five (45) days of
receipt of the written request to do so, such arbitrator may, at the
request of the first Party, be appointed by the Secretary General of
the Permanent Court of Arbitration at the Hague, within forty-five (45)
days of the date of receipt of such request, from amongst persons who
are not nationals of the country of any of the Parties to the
arbitration proceedings.
33.6 If the two arbitrators appointed by the Parties fail to agree on the
appointment of the third arbitrator within thirty (30) days of the
appointment of the second arbitrator and if the Parties do not
otherwise agree, the Secretary General of the Permanent Court of
Arbitration at the Hague
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may, at the request of either Party and in consultation with both,
appoint the third arbitrator who shall not be a national of the country
of any Party.
33.7 If any of the arbitrators fails or is unable to act, his successor
shall be appointed in the manner set out in this Article as if he was
the first appointment.
33.8 The decision of the arbitration tribunal and, in the case of difference
among the arbitrators, the decision of the majority, shall be final and
binding upon the Parties.
33.9 Arbitration proceedings shall be conducted in accordance with the
arbitration rules of the United Nations Commission on International
Trade Law (UNCITRAL) of 1985 except that in the event of any conflict
between these rules and the provisions of this Article 33, the
provisions of this Article 33 shall govern.
33.10 The right to arbitrate disputes and claims under this Contract shall
survive the termination of this Contract.
33.11 Prior to submitting a dispute to arbitration, a Party may submit the
matter for conciliation under the UNCITRAL conciliation rules by mutual
agreement of the Parties. If the Parties fail to agree on a conciliator
(or conciliators) in accordance with the rules, the matter may be
submitted for arbitration. No arbitration proceedings shall be
instituted while conciliation proceedings are pending and such
proceedings shall be concluded within sixty (60) days.
33.12 The venue of conciliation or arbitration proceedings pursuant to this
Article, unless the Parties otherwise agree, shall be London, England
and shall be conducted in the English language. The arbitration
agreement contained in this Article 33 shall be governed by the laws of
England. Insofar as practicable, the Parties shall continue to
implement the terms of this Contract notwithstanding the initiation of
arbitral proceedings and any pending claim or dispute.
33.13 The fees and expenses of a sole expert or conciliator appointed by the
Parties shall be borne equally by the Parties. Assessment of the costs
of arbitration including incidental expenses and liability for the
payment thereof shall be at the discretion of the arbitrators.
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ARTICLE 34
ENTIRE AGREEMENT, AMENDMENTS, WAIVER AND MISCELLANEOUS
34.1 This Contract supersedes and replaces any previous agreement or
understanding between the Parties, whether oral or written, on the
subject matter hereof, prior to the Effective Date of this Contract.
34.2 This Contract shall not be amended, modified, varied or supplemented in
any respect except by an instrument in writing signed by all the
Parties, which shall state the date upon which the amendment or
modification shall become effective.
34.3 No waiver by any Party of any one or more obligations or defaults by
any other Party in the performance of this Contract shall operate or be
construed as a waiver of any other obligations or defaults whether of a
like or of a different character.
34.4 The provisions of this Contract shall inure to the benefit of and be
binding upon the Parties and their permitted assigns and successors in
interest.
34.5 In the event of any conflict between any provisions in the main body of
this Contract and any provision in the Appendices, the provision in the
main body shall prevail.
34.6 The headings of this Contract are for convenience of reference only and
shall not be taken into account in interpreting the terms of this
Contract.
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88
ARTICLE 35
CERTIFICATES
35.1 A Company shall furnish, prior to execution of this Contract, a duly
authorised copy of a resolution properly and legally passed by the
Board of Directors of the Company specifying the person authorised to
execute this Contract along with a Certificate duly signed by the
Secretary or an Assistant Secretary of the Company under its seal in
this regard and to the effect that the Company has the power and
authority to enter into this Contract and to perform its obligations
thereunder and has taken all necessary action to authorise the
execution, delivery and performance of the Contract.
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89
ARTICLE 36
NOTICES
36.1 All notices, statements, and other communications to be given,
submitted or made hereunder by any Party to another shall be
sufficiently given if given in writing in the English language and sent
by registered post, postage paid, or by telegram, telex, facsimile,
radio or cable, to the address or addresses of the other Party or
Parties as follows:
a) To the President of India through the
Secretary to the Government of India
Ministry of Petroleum and Natural Gas
Shastri Bhavan
Dr. Rajendra Prasad Marg
New Delhi 110 001, India
Attention: Joint Secretary
Facsimile No. : 91-11-384-787
b) The Secretary
Oil & Natural Gas Corporation Limited
Tower II, 8th Floor, Jeevan Bharati
124 Connaught Circus
New Delhi 110 001, India
Facsimile No. : 91-11-331-6413
c) Reliance Industries Limited
Maker Chambers IV, 3rd Floor
222 Nariman Point
Bombay 400 021 INDIA
Attention: Chief Executive Officer Oil & Gas
Facsimile No. : 022-204-2268
d) Enron Oil & Gas India Ltd.
Amiya Apartments, 1st Floor
63A Linking Road, Santa Cruz (W)
Bombay 400 054 INDIA
Attention: Managing Director
Facsimile No.: 011-91-22-604-9119
with a copy to:
Enron Oil & Gas India Ltd.
1400 Smith Street
Houston, Texas 77002, U.S.A.
Attention: Vice President, Operations
Facsimile No. : 713-646-8115
36.2 Notices when given in terms of Article 36.1 shall be effective when
delivered if offered at the address of the other Parties as under
Article 36.1 during business hours on working days and, if received
outside business hours, on the next following working day.
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36.3 Any Party may, by reasonable notice as provided hereunder to the other
Parties, change its address and other particulars for notice purpose.
IN WITNESS WHEREOF, the representatives of the Parties to
this Contract being duly authorised have hereunto set their hands
and have executed these presents this 22nd day of December 1994.
Signed for and on
behalf of the
President of India By /s/ NAJERB JR. 22-12-94
Najerb Jr.
In the presence of
/s/ V. RAMANI
V. Ramani
Signed for and on behalf By /s/ S. K. MANGLIK 22-12-94
of Oil & Natural Gas S. K. Manglik
Corporation Limited
In the presence of
/s/ R. N. DESAI 22-12-94
R. N. Desai
Signed for and on behalf By /s/ AKHIL GUPTA 22-12-94
of Reliance Industries Akhil Gupta
Limited
In the presence of
/s/ BA LA SAGRAMANIA
Ba La Sagramania
Signed for and on behalf By /s/ J. A. KOPECKY 22-12-94
of Enron Oil & Gas India Ltd. J. A. Kopecky
In the presence of
/s/ E. J. VANDERMARK
E. J. Vandermark
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APPENDIX A
DESCRIPTION OF CONTRACT AREA
The area comprising approximately 1471 sq. km offshore India identified
as Tapti Block described herein and shown under map attached as
Appendix B.
Longitude and Latitude measurements are as follows:
LATITUDE LONGITUDE
A. 20(degree)50'00"N 71(degree)49'00"E
B. 20(degree)50'00"N 72(degree)08'00"E
C. 20(degree)35'00"N 72(degree)08'00"E
D. 20(degree)20'00"N 71(degree)53'00"E
E. 20(degree)20'00"N 71(degree)49'00"E
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APPENDIX B
MAP OF CONTRACT AREA
TAPTI BLOCK
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93
APPENDIX C
ACCOUNTING PROCEDURE
TO
PRODUCTION SHARING CONTRACT
BETWEEN
THE GOVERNMENT OF INDIA
AND
ONGC/RIL/EOGIL
94
TABLE OF CONTENTS
SECTIONS CONTENT
SECTION 1: GENERAL PROVISIONS
1.1 Purpose
1.2 Definitions
1.3 Inconsistency
1.4 Documentation and Statements to be Submitted by
the Contractor
1.5 Language and Units of Account
1.6 Currency Exchange Rates
1.7 Payments
1.8 Arms Length Transactions
1.9 Audit and Inspection Rights of the Government
1.10 Revision of Accounting Procedure
SECTION 2: CLASSIFICATION, DEFINITION AND ALLOCATION OF
COSTS AND EXPENDITURES
2.1 Segregation of Costs
2.2 Exploration Costs
2.3 Development Costs
2.4 Production Costs
2.5 Service Costs
2.6 General and Administrative Costs
SECTION 3: COSTS, EXPENSES, EXPENDITURES AND INCIDENTAL
INCOME OF THE CONTRACTOR
3.1 Costs Recoverable and Allowable Without Further
Approval of the Government
3.1.1 Surface Rights
3.1.2 Labor & Associated Costs
3.1.3 Transportation Costs
3.1.4 Charges for Services
(a) Third Party Contracts
(b) Affiliated Company Contracts
3.1.5 Communications
3.1.6 Office, Shore Bases and Miscellaneous
Facilities
3.1.7 Environmental Studies and Protection
3.1.8 Materials and Equipment
(a) General
(b) Warranty
(c) Value of Materials Charged to
the Account
3.1.9 Duties, Fees and Other Charges
3.1.10 Insurance and Losses
3.1.11 Legal Expenses
3.1.12 Training Costs
3.1.13 General and Administrative Costs
3.2 Costs Not Recoverable and Not Allowable under the
Contract
3.3 Other Costs Recoverable and Allowable
3.4 Incidental Income and Credits
3.5 Non-Duplication of Charges and Credits
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SECTION 4: RECORDS AND INVENTORIES OF ASSETS
4.1 Records
4.2 Inventories
SECTION 5: PRODUCTION STATEMENT AND ROYALTY AND CESS
STATEMENT
SECTION 6: VALUE OF PRODUCTION AND PRICING STATEMENT
SECTION 7: STATEMENT OF COSTS, EXPENDITURES AND RECEIPTS
SECTION 8: COST RECOVERY STATEMENT
SECTION 9: PRODUCTION SHARING STATEMENT
SECTION 10: END OF YEAR STATEMENT
SECTION 11: BUDGET STATEMENT
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ACCOUNTING PROCEDURE
SECTION 1
GENERAL PROVISIONS
1.1 PURPOSE
Generally, the purpose of this Accounting Procedure is to set out
principles and procedures of accounting which will enable the
Government of India to monitor effectively the Contractor's costs,
expenditures, production and income so that the Government's
entitlement to Profit Petroleum, royalty, cess, etc., as well as
Contractor's entitlement to Cost Petroleum and Profit Petroleum can be
accurately determined pursuant to the terms of the Contract. More
specifically, the purpose of the Accounting Procedure is to:
- classify costs and expenditures and to define which
costs and expenditures shall be allowable for cost
recovery, production sharing and participation
purposes;
- specify the manner in which the Contractor's accounts
shall be prepared and approved.
This Accounting Procedure is intended to apply to the provisions of the
Contract and is without prejudice to the computation of income tax
under applicable provisions of the Income Tax Act, 1961, as amended.
1.2 DEFINITIONS
For purposes of this Accounting Procedure, the terms used herein which
are defined in the Contract shall have the same meaning when used in
this Accounting Procedure.
1.3 INCONSISTENCY
In the event of any inconsistency or conflict between the provisions of
this Accounting Procedure and the other provisions of the Contract, the
other provisions of the Contract shall prevail.
1.4 DOCUMENTATION AND STATEMENTS TO BE SUBMITTED BY THE
CONTRACTOR
1.4.1 Within thirty (30) days of the Effective Date of
the Contract, the Contractor shall submit to and
discuss with the Government a proposed outline of
charts of accounts, operating records and
reports, which outline shall reflect each of the
categories and sub-categories of costs and income
specified in Sections 2 and 3 and shall be in
accordance with generally accepted standards and
recognized accounting systems and consistent with
97
normal petroleum industry practice and procedures
for joint venture operations.
Within ninety (90) days of receiving the above submission,
the Government shall either provide written notification of
its approval of the proposal or request, in writing,
revisions to the proposal.
Within one hundred and eighty (180) days from the Effective
Date of the Contract, the Contractor and the Government
shall agree on the outline of charts of accounts, records
and reports which shall also describe the basis of the
accounting system and procedures to be developed and used
under this Contract. Following such agreement, the
Contractor shall expeditiously prepare and provide the
Government with formal copies of the comprehensive charts
of accounts, records and reports and allow the Government
to examine the manuals and to review procedures which are,
and shall be, observed under the Contract.
1.4.2 Notwithstanding the generality of the foregoing, the
Contractor shall make regular Statements relating to the
Petroleum Operations as follows :
(i) Production Statement and Royalty and
Cess Statement (see Section 5 of this
Accounting Procedure)
(ii) Value of Production and Pricing
Statement (see Section 6 of this
Accounting Procedure)
(iii) Statement of Costs, Expenditures and
Receipts (see Section 7 of this
Accounting Procedure)
(iv) Cost Recovery Statement (see Section 8
of this Accounting Procedure)
(v) Production Sharing Statement (see
Section 9 of this Accounting Procedure)
(vi) End of Year Statement (see Section 10 of
this Accounting Procedure)
(vii) Budget Statement (see Section 11 of this
Accounting Procedure)
1.4.3 All reports and statements shall be prepared in accordance
with the Contract and the laws of India and, where there
are no relevant provisions in either of these, in
accordance with generally
98
accepted practices in the international petroleum
industry.
1.4.4 Each of the entities constituting the Contractor
shall be responsible for maintaining its own
accounting records in order to comply with all
legal requirements and to support all returns or
any other accounting reports required by any
Government authority in relation to the Petroleum
Operations. However, for the purposes of giving
effect to this Accounting Procedure, the
Contractor shall appoint, and notify the
Government in writing thereof, one of the Parties
constituting Contractor who shall be responsible
for maintaining, at its business office in India,
on behalf of the Contractor, all the accounts of
the Petroleum Operations in accordance with the
provisions of the Accounting Procedure and the
Contract.
1.5 LANGUAGE AND UNITS OF ACCOUNT
All accounts, records, books, reports and statements shall be
maintained on an accrual basis and prepared in the English language.
The accounts shall be maintained in United States Dollars, which shall
be the controlling currency of account for cost recovery, production
sharing and participation purposes. Metric units and Barrels shall be
employed for measurements required under the Contract. Where necessary
for clarification, the Contractor may also maintain accounts and
records in other languages, currencies and units. Following any new
discovery of Petroleum the Parties shall meet to establish specific
principles and procedures for identifying all costs, expenditures,
receipts and income with respect to the Contract Area.
1.6 CURRENCY EXCHANGE RATES
1.6.1 For translation purposes between United States
Dollars and Indian Rupees or any other currency,
the previous month's average of the daily means
of the buying and selling rates of exchange as
quoted by the State Bank of India (or any other
financial body as may be mutually agreed between
the Parties) shall be used for the month in which
the revenues, costs, expenditures, receipts or
income are recorded. However, in the case of any
single non-US Dollar transaction in excess of the
equivalent of one hundred thousand US Dollars
(US$100,000), the conversion into US Dollars
shall be performed on the basis of the average of
the applicable exchange rates for the day on
which the transaction occurred.
1.6.2 Any realized or unrealized gains or losses from
the exchange of currency in respect of Petroleum
Operations shall be credited or charged to the
accounts. A record of the exchange rates used in
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converting Indian Rupees or any other currencies into
United States Dollars as specified in Section 1.6.1 shall
be maintained by the Contractor and shall be identified in
the relevant statements required to be submitted by the
Contractor in accordance with Section 1.4.2.
1.7 PAYMENTS
1.7.1 Subject to the foreign exchange laws and regulations
prevailing from time to time, all payments between the
Parties shall, unless otherwise agreed, be in United States
Dollars and shall be made through a bank designated by each
receiving Party.
1.7.2 Unless otherwise specified, all sums due under the Contract
shall be paid within forty-five (45) days from the date on
which the obligation to pay was incurred.
1.7.3 Unless otherwise specified, all sums due by one Party to
the other under the Contract during any month shall, for
each day such sums are overdue during such month, bear
interest compounded daily at the applicable LIBOR plus one
percentage (1%) point.
1.8 ARMS LENGTH TRANSACTIONS
Unless otherwise specifically provided for in the Contract, all
transactions giving rise to revenues, costs or expenditures which will
be credited or charged to the accounts prepared, maintained or
submitted hereunder shall be conducted at arms length or on such a
basis as will assure that all such revenues, costs or expenditures will
be equal to or better than, as the case may be, would result from a
transaction conducted at arms length on a competitive basis with third
parties. For the purposes of clarification, this means revenues would
be equal to or higher and costs would be equal to or lower.
1.9 AUDIT AND INSPECTION RIGHTS OF THE GOVERNMENT
1.9.1 Without prejudice to statutory rights, the
Government, upon at least ninety (90) days
advance written notice to the Contractor, shall
have the right to inspect and audit, during
normal business hours , all records and documents
supporting costs, expenditures, expenses,
receipts and income, such as Contractor's
accounts, books, records, invoices, cash
vouchers, debit notes, price lists or similar
documentation with respect to the Petroleum
Operations conducted hereunder in each Financial
100
Year, within two (2) years (or such longer period as may be
required in exceptional circumstances) from the end of such
Financial Year.
1.9.2 The Government may undertake the conduct of the audit
either through its own representatives or through a
qualified firm of recognized international chartered
accountants, registered in India, appointed for the purpose
by the
Government.
1.9.3 In conducting the audit, the Government or its
auditors shall be entitled to examine and verify,
at reasonable times, all charges and credits
relating to Contractor's activities under the
Contract and all books of account, accounting
entries, material records and inventories,
vouchers, payrolls, invoices and any other
documents, correspondence and records considered
necessary by the Government to audit and verify
the charges and credits. The auditors shall also
have the right, in connection with such audit, to
visit and inspect, at reasonable times, all
sites, plants, facilities, warehouses and offices
of the Contractor directly or indirectly serving
the Petroleum Operations, and to physically
examine other property, facilities and stocks
used in Petroleum Operations, wherever located
and to question personnel associated with those
operations. Where the Government requires
verification of charges made by an Affiliate, the
Government shall have the right to obtain an
audit certificate from an internationally
recognized firm of public accountants acceptable
to both the Government and the Contractor, which
may be the Contractor's statutory auditor. Any
and all such costs shall be for the Government's
account.
1.9.4 Any audit exceptions shall be made by the Government in
writing and notified to the Contractor within one hundred
and twenty (120) days following completion of the audit in
question.
1.9.5 The Contractor shall answer any notice of exception under
Section 1.9.4 within one hundred and twenty (120) days of
the receipt of such notice. Where the Contractor has, after
the one hundred and twenty (120) days, failed to answer a
notice of exception, the exception shall prevail.
1.9.6 All agreed adjustments resulting from an audit
and all adjustments required by prevailing
exceptions shall be promptly made in the
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Contractor's accounts and any consequential
adjustments to the Government's entitlement to
Petroleum shall be made as promptly as
practicable.
1.9.7 If the Contractor and the Government are unable
to reach final agreement on proposed audit
adjustments, either Party may refer any dispute
thereon to a sole expert as provided for in the
Contract. So long as any issues are outstanding
with respect to an audit, the Contractor shall
maintain the relevant documents and permit
inspection thereof until the issue is resolved.
1.10 REVISION OF THE ACCOUNTING PROCEDURE
1.10.1 By mutual agreement between the Government and the
Contractor, this Accounting Procedure may be revised from
time to time, in writing, signed by the Parties, stating
the date upon which the amendments shall become effective.
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SECTION 2
CLASSIFICATION, DEFINITION AND ALLOCATION
OF COSTS AND EXPENDITURES
2.1 SEGREGATION OF COSTS
Costs shall be segregated in accordance with the purposes for which
such expenditures are made. All costs and expenditures allowable under
Section 3, relating to Petroleum Operations, shall be classified,
defined and allocated as set out below in this Section. Expenditure
records shall be maintained in such a way as to enable proper
allocation.
2.2 EXPLORATION COSTS
Exploration Costs are all direct and allocated indirect expenditures
incurred in the search for Petroleum in an area which is, or was at the
time when such costs were incurred, part of the Contract Area,
including expenditures incurred in respect of:
2.2.1 Aerial, geophysical, geochemical, palaeontological,
geological, topographical and seismic surveys, analyses and
studies and their interpretation.
2.2.2 Core hole drilling and water well drilling.
2.2.3 Labor, materials, supplies and services used in drilling
Wells with the object of finding Petroleum or in drilling
Appraisal Wells provided that if such Wells are completed
as producing Wells, the costs of completion thereof shall
be classified as Development Costs.
2.2.4 Facilities used solely in support of the purposes described
in Sections 2.2.1, 2.2.2 and 2.2.3 above, including access
roads, all separately identified.
2.2.5 Any Service Costs and General and Administrative
Costs directly incurred on exploration activities
and identifiable as such and a portion of the
remaining Service Costs and General and
Administrative Costs allocated to Exploration
Operations determined by the proportionate share
of total Contract Costs (excluding General and
Administrative Costs and Service Costs) repre-
sented by all other Exploration Costs.
2.2.6 Geological and geophysical information purchased
or acquired in connection with Exploration
Operations.
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2.2.7 Any other expenditure incurred in the search for
Petroleum not covered under Sections 2.3 or 2.4.
2.3 DEVELOPMENT COSTS
Development Costs are all direct and allocated indirect expenditures
incurred with respect to the development of the Contract Area including
expenditures incurred on account of:
2.3.1 Drilling Development Wells, whether these Wells are dry or
producing and drilling Wells for the injection of water or
Gas to enhance recovery of Petroleum and Recompletion or
working over of existing or service wells.
2.3.2 Purchase, installation or construction of
production, transport and storage facilities for
production of Petroleum from a Field, such as
pipelines, flow lines, production and treatment
units, wellhead equipment, subsurface equipment,
enhanced recovery systems, offshore and onshore
platforms, export terminals and piers, harbours
and related facilities and access roads for
production activities.
2.3.3 Engineering and design studies for facilities
referred to in Section 2.3.2.
2.3.4 Any Service Costs, joint Development Plans and
General and Administrative Costs directly
incurred in Development Operations and
identifiable as such and a portion of the
remaining Service Costs and General and
Administrative Costs allocated to development
activities, determined by the proportionate share
of total Contract Costs (excluding General and
Administrative Costs and Service Costs) repre-
sented by all other Development Costs.
2.4 PRODUCTION COSTS
2.4.1 Production Costs are expenditures incurred on
Production Operations in respect of the Contract
Area after the start of production from the Field
(which are other than Exploration and Development
Costs). The balance of General and Adminis-
trative Costs and Service Costs not allocated to
Exploration Costs or Development Costs shall be
allocated to Production Costs.
2.4.2 Production Costs shall include costs for completion of
Exploration Wells by way of installation of casing or
equipment or otherwise or for the purpose of bringing a
Well into use as a producing Well or as a Well for the
injection
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of water or Gas to enhance recovery of Petroleum and
Recompletion or working over of existing or service wells.
2.5 SERVICE COSTS
Service Costs are direct and indirect expenditures incurred in support
of Petroleum Operations in the Contract Area, including expenditures on
insurance, environmental protection, warehouses, piers, marine vessels,
vehicles, motorized rolling equipment, aircraft, fire and security
stations, workshops, water and sewerage plants, power plants, housing,
community and recreational facilities and furniture and tools and
equipment used in these activities. Service Costs in any Year shall
include the costs incurred in such Year to purchase and/or construct
the facilities as well as the annual costs of maintaining and operating
the same, each to be identified separately. All Service Costs shall be
regularly allocated as specified in Sections 2.2.5, 2.3.4 and 2.4 to
Exploration Costs, Development Costs and Production Costs and shall be
separately shown under each of these categories. Where Service Costs
are made in respect of shared facilities, the basis of allocation of
costs to Petroleum Operations hereunder shall be on the basis of gross
expenditures.
2.6 GENERAL AND ADMINISTRATIVE COSTS
General and Administrative Costs are expenditures incurred on general
administration and management primarily and principally related to
Petroleum Operations in or in connection with the Contract Area, and
shall include:
2.6.1 main office, field office and general
administrative expenditures in India, including
supervisory, accounting and employee relations
services;
2.6.2 an annual overhead charge for services rendered
by the parent company or an Affiliate of the
Operator outside India to support and manage
Petroleum Operations under the Contract, and for
staff advice and assistance including financial,
legal, accounting and employee relations
services, but excluding any remuneration for
services charged separately under this Accounting
Procedure calculated on the basis of one percent
(1%) of expenditures.
2.6.3 The expenditures used to calculate the monthly indirect
charge shall not include the indirect charge (calculated
either as a percentage of expenditures or as a minimum
monthly charge), rentals on surface rights acquired and
maintained for the joint account, guarantee deposits,
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concession acquisition costs, bonuses paid in accordance
with the Contract, royalties, value added taxes and taxes
paid under the Contract, settlement of claims, proceeds
from the sale of assets (including division in kind)
amounting to more than US$10,000 per transaction, and
similar items mutually agreed upon by the parties.
2.6.3 The expenditures used to calculate the monthly
indirect charge shall not include the indirect
charge (calculated either as a percentage of
expenditures or as a minimum monthly charge),
rentals on surface rights acquired and maintained
for the joint account, guarantee deposits,
concession acquisition costs, bonuses paid in
accordance with the Contract, royalties, value
added taxes and taxes paid under the Contract,
settlement of claims, proceeds from the sale of
assets (including division in kind) amounting to
more than US$10,000 per transaction, and similar
items mutually agreed upon by the parties.
Credits arising from any government subsidy payment and
disposition of joint account property shall not be deducted
from total expenditures in determining such charge.
2.6.4 The indirect charges provided for in this Section may be
amended periodically by mutual agreement between the
Parties if, in practice, these charges are found to be
insufficient or
excessive.
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SECTION 3
COSTS, EXPENSES, EXPENDITURES AND INCIDENTAL
INCOME OF THE CONTRACTOR
3.1 COSTS RECOVERABLE AND ALLOWABLE WITHOUT FURTHER APPROVAL OF
THE GOVERNMENT.
Costs incurred by the Contractor on Petroleum Operations pursuant to
the Contract as classified under the headings referred to in Section 2
shall be allowable for the purposes of the Contract except to the
extent provided in Section 3.2 or elsewhere in this Accounting
Procedure, and subject to audit as provided for herein.
3.1.1 Surface Rights
All direct costs necessary for the acquisition, renewal or
relinquishment of surface rights acquired and maintained in
force for the purposes of the Contract except as provided
in
Section 3.1.9.
3.1.2 Labor and Associated Costs
(a) Costs of all Contractor's locally recruited
employees who are directly engaged in the
conduct of Petroleum Operations under the
Contract in India. Such costs shall include
the costs of employee benefits and Government
benefits for employees and levies imposed on
the Contractor as an employer, transportation
and relocation costs within India of the
employee and such members of the employee's
family (limited to spouse and dependent
children) as required by law or customary
practice in India. If such employees are
engaged in other activities in India, in
addition to Petroleum Operations, the cost of
such employees shall be apportioned on a time
sheet basis according to sound and acceptable
accounting principles.
(b) Assigned Personnel
Costs of salaries and wages, including bonuses,
of the Contractor's employees directly and
necessarily engaged in the conduct of the
Petroleum Operations under the Contract, whether
temporarily or permanently assigned,
irrespective of the location of such employees,
it being understood that in the case of those
personnel only a portion of whose time is wholly
dedicated to Petroleum Operations under the
Contract, only that
107
pro rata portion of applicable salaries, wages
and other costs, as specified in Sections
3.1.2(c), (d), (e)and (f) shall be charged and
the basis of such pro rata allocation shall be
specified.
(c) Expenses or contributions made pursuant to assessments
or obligations imposed under the laws of India which
are applicable to the Contractor's cost of salaries
and wages.
(d) The Contractor's cost of established plans
for employees' group life insurance,
hospitalization, pension, retirement and
other benefit plans of a like nature
customarily granted to the Contractor's
employees provided, however, that such costs
are in accordance with generally accepted
standards in the international petroleum
industry, applicable to salaries and wages
chargeable to Petroleum Operations under
Section 3.1.2(b) above.
(e) Personal Income taxes where and when they are paid by
the Contractor to the Government of India for the
employee, in accordance with the Contractor's standard
personnel policies.
(f) Reasonable transportation and travel expenses
of employees of the Contractor, including
those made for travel and relocation of the
expatriate employees, including their
dependent family and personal effects,
assigned to India whose salaries and wages
are chargeable to Petroleum Operations under
Section 3.1.2(b). Actual transportation
expenses of personnel transferred to
Petroleum Operations from their country of
origin and/or relocation to their country of
origin shall be charged to the Petroleum
Operations. Where such transfer or
relocation is to or from a country other than
the country of origin there shall be no
reimbursement.
Transportation cost as used in this Section shall mean the
cost of freight and passenger service and any accountable
incidental expenditures related to transfer travel and
authorized under Contractor's standard personnel policies.
Contractor shall ensure that all expenditures related to
transportation costs are equitably allocated to the
activities which have benefited from the personnel
concerned.
108
3.1.3 Transportation Costs
The reasonable cost of transportation of equipment,
materials and supplies within India and from outside India
to India necessary for the conduct of Petroleum Operations
under the Contract, including, but not limited to, directly
related costs such as unloading charges, dock fees and
inland and ocean freight charges.
3.1.4 Charges for Services
(a) Third Party Contracts
The actual costs of contract services, services of
professional consultants, utilities and other services
necessary for the conduct of Petroleum Operations
under the Contract performed by third parties other
than an Affiliate of the Contractor, provided that the
transactions resulting in such costs are undertaken
pursuant to Section 1.8 of this Accounting Procedure.
(b) Affiliated Company Contracts
(i) Professional and Administrative Services
and Expenses
Cost of professional and administrative services
provided by any Affiliate for the direct benefit
of Petroleum Operations, including, but not
limited to, services provided by the production,
exploration, legal, financial, insurance,
accounting and computer services divisions other
than those covered by Section 3.1.4(b)(ii) which
Contractor may use in lieu of having its own
employees. Charges shall be equal to the actual
cost of providing their services, shall not
include any element of profit and shall not be
any higher than the most favorable prices
charged by the Affiliate to third parties for
comparable services under similar terms and
conditions elsewhere and will be fair and
reasonable in the light of prevailing
international petroleum industry practice and
experience.
(ii) Scientific or Technical Personnel
Cost of scientific or technical
personnel services provided by any
109
Affiliate of Contractor for the direct benefit
of Petroleum Operations, which cost shall be
charged on a cost of service basis. Charges
therefor shall not exceed charges for comparable
services currently provided by outside technical
service organizations of comparable
qualifications. Unless the work to be done by
such personnel is covered by an approved Work
Programme and Budget, Operator shall not
authorize work by such personnel without
approval of the Management Committee.
(c) Equipment, facilities and property owned and
furnished by the Contractor's Affiliates, at
rates commensurate with the cost of ownership
and operation provided, however, that such
rates shall not exceed those currently
prevailing for the supply of like equipment,
facilities and property on comparable terms
in the area where the Petroleum Operations
are being conducted. The equipment and
facilities referred to herein shall exclude
major investment items such as (but not
limited to) drilling rigs, producing
platforms, oil treating facilities, oil and
gas loading and transportation systems,
storage and terminal facilities and other
major facilities, rates for which shall be
subject to separate agreement with the
Government.
3.1.5 Communications
Cost of acquiring, leasing, installing,
operating, repairing and maintaining communication systems
including satellite, radio and microwave facilities between
the Contract Area and the Contractor's base facility,
offices, helicopter bases, port and railway yards.
3.1.6 Office, Shore Bases and Miscellaneous Facilities
Net cost to Contractor of establishing, maintaining and
operating any office, sub-office, shore base facility,
warehouse, housing or other facility directly serving the
Petroleum Operations. If any such facility services
contract areas other than the Contract Area, or any
business other than Petroleum Operations, the net costs
thereof shall be allocated on an equitable and consistent
basis.
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3.1.7 Environmental Studies and Protection
Costs incurred in conducting the environmental impact
studies for the Contract Area, and in taking environmental
protection measures pursuant to the terms of the Contract.
3.1.8 Materials and Equipment
(a) General
So far as is practicable and consistent with efficient
and economical operation, only such material shall be
purchased or furnished by the Contractor for use in
the Petroleum Operations as may be required for use in
the reasonably foreseeable future and the accumulation
of surplus stocks shall be avoided to the extent
possible. Material and equipment held in inventory
shall only be charged to the accounts when such
material is removed from inventory and used in
Petroleum Operations. Contractor shall be allowed to
recover interest at the LIBOR rate plus one percent
(1%) for reasonable inventories it carries. Costs
shall be charged to the accounting records and books
based on the average cost method.
(b) Warranty
In the case of defective material or equipment, any
adjustment received by the Contractor from the
suppliers or manufacturers or their agents in respect
of any warranty on material or equipment shall be
credited to the accounts under the Contract.
(c) Value of Materials Charged to the Accounts
Under the Contract.
(i) Except as otherwise provided in
subparagraph (b), materials purchased by
the Contractor and used in the Petroleum
Operations shall be valued to include
invoice price less trade and cash
discounts, if any, purchase and
procurement fees plus freight and
forwarding charges between point of
supply and point of shipment, freight to
port of destination, insurance, taxes,
customs duties, consular fees, other
items chargeable against imported
material and, where applicable ,
111
handling and transportation costs from point of
importation to or from warehouse or operating
site, and these costs shall not exceed those
currently prevailing in normal arms length
transactions on the open market.
(ii) Material purchased from or sold to Affiliates or
transferred to or from activities of the
Contractor other than Petroleum Operations under
the Contract:
(aa) new material (hereinafter
referred to as condition A)
shall be valued at the current
international price which shall
not exceed the price prevailing
in normal arms length transac-
tions on the open market;
(bb) used material which is in sound
and serviceable condition and
is suitable for reuse without
reconditioning (hereinafter
referred to as condition B)
shall be priced at not more
than seventy-five percent (75%)
of the current price of the
above mentioned new materials;
(cc) used material which cannot be
classified as condition B, but
which, after reconditioning,
will be further serviceable for
original function as good
second-hand condition B
material or is serviceable for
original function, but
substantially not suitable for
reconditioning (hereinafter
referred to as condition C)
shall be priced at not more
than fifty per cent (50%) of
the current price of the new
material referred to above as
condition A.
The cost of reconditioning shall be charged to the
reconditioned material, provided that the condition C
material value plus the cost of reconditioning does not
exceed the value of condition B material.
112
Material which cannot be classified as condition B or
condition C shall be priced at a value commensurate with
its use.
Material involving erection expenditure shall be charged at
the applicable condition percentage (referred to above) of
the current knocked-down price of new material referred to
above as condition A.
When the use of material is temporary and its service to
the Petroleum Operations does not justify the reduction in
price in relation to materials referred to above as
conditions B and C, such material shall be priced on a
basis that will result in a net charge to the accounts
under the Contract consistent with the value of the service
rendered.
3.1.9 Duties, Fees and Other Charges
Any duties, levies, fees, charges and any other assessments
levied by any governmental or taxing authority in
connection with the Contractor's activities under the
Contract and paid directly by the Contractor except
corporate income tax payable by the constituents of the
Contractor. If Operator or its Affiliate is subject to
income or withholding tax as a result of service performed
at cost for Petroleum Operations under the Agreement, its
charges for such services may be increased by the amount of
such taxes incurred ("grossed up"), provided such charges
have not been otherwise recovered or a tax credit received.
3.1.10 Insurance and Losses
Insurance premia and costs incurred for insurance required
by law or pursuant to Article 24 of the Contract, provided
that such insurance is customary, affords prudent
protection against risk and is at a premium no higher than
that charged on a competitive basis by insurance companies
which are not Affiliates. Actual costs and losses incurred
shall be allowable to the extent not made good by
insurance. Such costs may include, but are not limited to,
repair and replacement of property resulting from damages
or losses incurred by fire, flood, storm, theft, accident
or such other cause.
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3.1.11 Legal Expenses
All reasonable costs and expenses resulting from the
handling, investigating, asserting, defending, or settling
of any claim or legal action necessary or expedient for the
procuring, perfecting, retention and protection of the
Contract Area and in defending or prosecuting lawsuits
involving the Contract Area or any third party claim
arising out of Petroleum Operations under the Contract, or
sums paid in respect of legal services necessary for the
protection of the joint interest of Government and the
Contractor, shall be allowable. Such expenditures shall
include attorney's fees, court costs, costs of
investigation and procurement of evidence and amounts paid
in settlement or satisfaction of any such litigation and
claims provided such costs are not covered elsewhere in the
Accounting Procedure. Where legal services are rendered in
such matters by salaried or regularly retained lawyers of
the Contractor or an Affiliate, such compensation shall be
included instead under Sections 3.1.2 or 3.1.4(b)(i) above
as applicable.
3.1.12 Training Costs
All costs and expenses incurred by the Contractor in
training as is required under Article 22 of the Contract.
3.1.13 General and Administrative Costs
The costs described in Section 2.6.1 and the charge
described in Section 2.6.2 of this Accounting Procedure.
3.2 COSTS NOT RECOVERABLE AND NOT ALLOWABLE UNDER THE CONTRACT
The following costs and expenses shall not be recoverable or allowable
(whether directly as such or indirectly as part of any other charges or
expenses) for cost recovery and production sharing purposes under the
Contract:
(i) costs and charges incurred before the Effective Date
including costs in respect of preparation, signature or
ratification of this Contract except as otherwise provided
in Article 13.1;
(ii) expenditures in respect of any financial transaction to
negotiate, float or otherwise obtain or secure funds for
Petroleum Operations including, but not limited to,
interest, commission, brokerage and fees related to such
114
transactions, and exchange losses on loans or
other financing;
(iii) costs of marketing or transportation of Petroleum
beyond the Delivery Point;
(iv) expenditures incurred in obtaining, furnishing and
maintaining the guarantees required under the Contract and
any other amounts spent on indemnities with regard to
non-fulfillment of contractual obligations;
(v) attorney's fees and other costs and charges in
connection with arbitration proceedings and sole
expert determination pursuant to the Contract;
(vi) fines and penalties imposed by courts of law of
the Republic of India;
(vii) donations and contributions;
(viii) expenditures for the creation of any partnership
or joint venture arrangement;
(ix) amounts paid with respect to non-fulfillment of
contractual obligations;
(x) costs incurred as a result of failure to insure
where insurance is required pursuant to the
Contract;
(xi) costs and expenditures incurred as a result of
wilful misconduct or gross negligence of the
Contractor's supervisory personnel;
(xii) payments pursuant to Article 16 of the Contract.
3.3 OTHER COSTS RECOVERABLE AND ALLOWABLE.
Any other costs and expenditures not included in Section 3.1 or 3.2 of
this Accounting Procedure but which have been incurred by the
Contractor for the necessary and proper conduct of Petroleum Operations
pursuant to an approved Work Programme and Budget.
3.4 INCIDENTAL INCOME AND CREDITS
All incidental income and proceeds received from Petroleum Operations
under the Contract, including but not limited to the items listed
below, shall be credited to the accounts under the Contract and shall
be taken into account for cost recovery, production sharing and
participation purposes in the manner described in Articles 13 and 14 of
the Contract:
115
(i) The proceeds of any insurance or claim or judicial awards
in connection with Petroleum Operations under the Contract
or any assets charged to the accounts under the Contract
where such operations or assets have been insured and the
premia charged to the accounts under the Contract;
(ii) Revenue received from third parties for the use
of property or assets, the cost of which has been
charged to the accounts under the Contract;
(iii) Any adjustment received by the Contractor from the
suppliers/manufacturers or their agents in connection with
defective material, the cost of which was previously
charged by the Contractor to the accounts under the
Contract;
(iv) Rentals, refunds or other credits received by the
Contractor which apply to any charge which has
been made to the accounts under the Contract;
(v) Prices originally charged to the accounts under the
Contract for materials subsequently exported from the
Republic of India without being used in Petroleum
Operations under the Contract;
(vi) Proceeds from the sale or exchange by the Contractor of
plant or facilities from a Field, the acquisition costs of
which have been charged to the accounts under the Contract
for the relevant Field;
(vii) Legal costs charged to the accounts under Section 3.1.11 of
this Accounting Procedure and subsequently recovered by the
Contractor.
3.5 NON-DUPLICATION OF CHARGES AND CREDITS
Notwithstanding any provision to the contrary in this Accounting
Procedure, it is the intention that there shall be no duplication of
charges or credits to the accounts under the Contract.
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116
SECTION 4
RECORDS AND INVENTORIES OF ASSETS
4.1 RECORDS
4.1.1 The Contractor shall keep and maintain detailed
records of property and assets in use for or in
connection with Petroleum Operations under the
Contract in accordance with normal practices in
exploration and production activities of the
international petroleum industry. Such records
shall include information on quantities, location
and condition of such property and assets, and
whether such property or assets are leased or
owned.
4.1.2 The Contractor shall furnish annually particulars to the
Government, by notice in writing as provided in the
Contract, of all major assets acquired by the Contractor to
be used for or in connection with Petroleum Operations.
4.2 INVENTORIES
4.2.1 The Contractor shall:
(a) not less than once every twelve (12) Calendar
Months with respect to movable assets take an
inventory of the controllable assets used for
or in connection with Petroleum Operations in
terms of the Contract and address and deliver
such inventory to the Government with a
statement of the principles upon which
valuation of the assets mentioned in such
inventory has been based. Controllable
assets means those assets the Operator shall
submit to detailed record keeping.
(b) not less than once every three (3) years with
respect to immovable assets, take an
inventory of the assets used for or in
connection with Petroleum Operations in terms
of the Contract and address and deliver such
inventory to the Government together with a
written statement of the principles upon
which valuation of the assets mentioned in
such inventory has been based. Immovable
assets means those assets which are placed in
service and have an original cost in excess
of Fifty Thousand United States Dollars
(US$50,000).
4.2.2 The Contractor shall give the Government at least thirty
(30) days notice in writing in the manner provided for in
the Contract of its intention to take the inventory
referred to in Section 4.2.1
117
and the Government shall have the right to be
represented when such inventory is taken.
4.2.3 When an assignment of rights under the Contract takes
place, a special inventory shall be taken by the Contractor
at the request of the assignee provided that the cost of
such inventory is borne by the assignee and paid to the
Contractor.
4.2.4 In order to give effect to Article 27 of the Contract, the
Contractor shall provide the Government with a
comprehensive list of all relevant assets when requested by
the Government to do so.
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118
SECTION 5
PRODUCTION STATEMENT AND ROYALTY AND CESS STATEMENT
5.1 From the date of first production, after the Effective Date, of
Petroleum from the Contract Area, the Contractor shall submit a
Production Statement for each Calendar Month to Government showing the
following information separately for each producing field and in
aggregate for the Contract Area:
5.1.1 The quantity of Crude Oil produced and saved.
5.1.2 The quality and characteristics of such Crude Oil
produced and saved.
5.1.3 The quantity of Associated Natural Gas and Non
Associated Natural Gas produced and saved.
5.1.4 The quality, characteristics and composition of
such Natural Gas produced and saved.
5.1.5 The quantities of Crude Oil and Natural Gas used for the
purposes of carrying on drilling and Production Operations
and pumping to field storage, as well as quantities
reinjected.
5.1.6 The quantities of Crude Oil and Natural Gas
unavoidably lost.
5.1.7 The quantities of Natural Gas flared and vented.
5.1.8 The size of Petroleum stocks held on the first
day of the Calendar Month in question.
5.1.9 The size of Petroleum stocks held on the last day
of the Calendar Month in question.
5.1.10 The quantities of Natural Gas reinjected into the
Petroleum Reservoir.
5.1.11 The number of days in the Calendar Month during which
Petroleum was produced from each Field.
5.1.12 The Gas/Oil ratio for each Field for the relevant
Calendar Month.
5.1.13 The water/Oil ratio for each Field for the
relevant Calendar Month, if available.
5.2 All quantities shown in this Statement shall be expressed in both
volumetric terms (barrels of oil and cubic metres of gas) and in weight
(metric tonnes).
5.3 The Government may direct in writing that the Contractor
include other particulars relating to the production of
119
Petroleum in its Production Statement, and the Contractor shall to the
extent possible comply with such direction.
5.4 The Production Statement for each Calendar Month shall be submitted to
Government no later than ten (10) days after the end of such Calendar
Month for Oil and the immediately succeeding Calendar Month for Gas.
5.5 The Contractor shall, for the purposes of Article 15, submit a
statement to Government providing the calculation of the amount of
royalty and cess, separately, paid with respect to each Calendar Month
for each producing Field and in aggregate for the Contract Area. The
statement shall show the following information:
5.5.1 The quantity of Crude Oil and Condensate produced
and saved.
5.5.2 The quantity of ANG and NANG produced and saved.
5.5.3 The amount of royalty and cess, separately, paid on Crude
Oil and Condensate produced, saved and sold and the
particulars of the calculation thereof.
5.5.4 The amount of royalty paid on ANG and NANG and
the particulars of the calculation thereof.
5.6 The Royalty and Cess Statement for each Calendar Month shall be
submitted to Government no later than twenty-one (21) days after the
end of such Calendar Month for Oil and the most recently available
Calendar Month for Gas.
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120
SECTION 6
VALUE OF PRODUCTION AND PRICING STATEMENT
6.1 The Contractor shall prepare a Statement providing calculations of the
value of Crude Oil produced and saved during each Calendar Month. This
Statement shall contain the following information:
6.1.1 The quantities, prices and receipts realized by the
Contractor as a result of sales of Crude Oil to third
parties (with any sales to Government being separately
identified) made during the Calendar Month in question.
6.1.2 The quantities, prices and receipts realized therefor by
the Contractor as a result of sales of Crude Oil made
during the Calendar Month in question, other than to third
parties.
6.1.3 The quantities of Crude Oil appropriated by the Contractor
to refining or other processing without otherwise being
disposed of in the form of Crude Oil.
6.1.4 The value of stocks of Crude Oil on the first day
of the Calendar Month in question.
6.1.5 The value of stocks of Crude Oil on the last day
of the Calendar Month in question.
6.1.6 The percentage volume of total sales of Crude Oil made by
the Contractor during the Calendar Month that are Arms
Length Sales to third parties.
6.1.7 Information available to the Contractor, in so far as
required for the purposes of Article 19 of the Contract,
concerning the prices of competitive crude oils produced by
the main petroleum producing and exporting countries
including contract prices, discounts and premia, and prices
obtained on the spot markets.
6.2 The Contractor shall prepare a statement providing calculations of the
value of ANG and NANG produced and sold during each Calendar Month for
the most recently available Calendar Month. This Statement shall
contain all information of the type specified in Section 6.1 for Crude
Oil as is applicable to Gas and such other relevant information as may
be required by the Government.
6.3 The Statements required pursuant to Sections 6.1 and 6.2 shall include
a detailed breakdown of the calculation of the prices of Crude Oil,
Associated Natural Gas and Non
Associated Natural Gas.
121
6.4 The Value of Production and Pricing Statement for each Calendar Month
shall be submitted to Government not later than twenty-one (21) days
after the end of such Calendar Month for Oil and the most recently
available Calendar Month for Gas.
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122
SECTION 7
STATEMENT OF COSTS, EXPENDITURES AND RECEIPTS
7.1 The Contractor shall prepare with respect to each Calendar Quarter a
Statement of Costs, Expenditures and Receipts under the Contract. The
statement shall distinguish between Exploration costs, Development
Costs and Production Costs and shall separately identify all
significant items of costs and expenditure as itemized in Section 3 of
this Accounting Procedure within these categories. The statement of
receipts shall distinguish between income from the sale of Petroleum
and incidental income of the sort itemized in Section 3.4 of this
Accounting Procedure. If the Government is not satisfied with the
categories, it shall be entitled to request a more detailed breakdown.
The Statement shall show the following:
7.1.1 Actual costs, expenditures and receipts for the
Calendar Quarter in question.
7.1.2 Cumulative costs, expenditures and receipts for
the Year in question.
7.1.3 Latest forecast of cumulative costs, expenditures
and receipts at the Year end.
7.1.4 Variations between budget forecast and latest
forecast and explanations thereof.
7.2 The Statement of Costs, Expenditure and Receipts of each Calendar
Quarter shall be submitted to Government not later than sixty (60) days
after the end of such Calendar Quarter.
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123
SECTION 8
COST RECOVERY STATEMENT
8.1 The Contractor shall prepare with respect to each Calendar Quarter a
Cost Recovery Statement containing the following information:
8.1.1 Unrecovered Contract Costs carried forward from
the previous Calendar Quarter, if any.
8.1.2 Contract costs for the Calendar Quarter in
question.
8.1.3 Total Contract Costs for the Calendar Quarter in
question (Section 8.1.1 plus Section 8.1.2).
8.1.4 Quantity and value of Cost Petroleum taken and
disposed of by the Contractor for the Calendar
Quarter in question.
8.1.5 Contract Costs recovered during the Calendar
Quarter in question.
8.1.6 Total cumulative amount of Contract Costs
recovered up to the end of the Calendar Quarter
in question.
8.1.7 Amount of Contract Costs to be carried forward
into the next Calendar Quarter.
8.2 Where necessary and possible, the information to be provided under
Section 8.1 shall be identified separately Field by Field and also
separately for Crude Oil, Associated Natural Gas and Non Associated
Natural Gas.
8.3 The cost recovery information required pursuant to Subsection 8.1 above
shall be presented in sufficient detail so as to enable Government to
identify how the cost of assets are being recovered.
8.4 The Cost Recovery Statement for each Calendar Quarter shall be
submitted to Government not later than sixty (60) days after the end of
such Calendar Quarter.
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124
SECTION 9
PRODUCTION SHARING STATEMENT
9.1 The Contractor shall prepare with respect to each Calendar
Quarter a Production Sharing Statement containing the
following information:
9.1.1 The calculation of the applicable net cash flows
as defined in Appendix D for the Calendar Quarter
in question.
9.1.2 The Investment Multiple applicable in the
Calendar Quarter in question.
9.1.3 Based on Section 9.1.2 and Article 14, the appropriate
percentages of Profit Petroleum, if any, for the Government
and Contractor in the Calendar Quarter in question.
9.1.4 The total amount of Profit Petroleum, if any, to be shared
between the Government and Contractor in the Calendar
Quarter in question.
9.1.5 Based on Sections 9.1.3 and 9.1.4, the amount of Profit
Petroleum due to the Government and Contractor as well as
to each constituent of the Contractor in the Calendar
Quarter in question.
9.1.6 The actual amounts of Petroleum taken by the Government and
Contractor as well as by each constituent of the Contractor
during the Calendar Quarter in question to satisfy their
entitlement pursuant to Section 9.1.5.
9.1.7 Adjustments to be made, if any, in future
Calendar Quarters in the respective amounts of
Profit Petroleum due to the Government and
Contractor as well as to each constituent of the
Contractor on account of any differences between
the amounts specified in Sections 9.1.5 and
9.1.6, as well as any cumulative adjustments
outstanding from previous Calendar Quarters.
9.2 Where necessary and if possible, the information to be provided under
Section 9.1 shall be identified separately for each Field and also
separately for Crude Oil as distinct from Natural Gas.
9.3 The Production Sharing Statement shall be submitted to Government not
later than sixty (60) days after the end of such Calendar Quarter.
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125
SECTION 10
END OF FINANCIAL YEAR STATEMENT
10.1 The Contractor shall prepare a definitive End of Year Statement. The
statement shall contain aggregated information in the same format as
required in the Production Statement and Royalty and Cess Statement,
Value of Production and Pricing Statement, Statement of Costs,
Expenditure & Receipts, Cost Recovery Statement and Production Sharing
Statement, but shall be based on actual quantities of Petroleum
produced, income received and costs and expenditures incurred. Based
upon this Statement, any adjustments that are necessary shall be made
to the transactions concerned under the Contract.
10.2 The End of Year Statement for each year shall be submitted to
Government within ninety (90) days of the end of such Year.
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126
SECTION 11
BUDGET STATEMENT
11.1 The Contractor shall prepare a Budget Statement for each
Year. This statement shall distinguish between budgeted
Exploration Costs, Development Costs and Production Costs
and shall show the following:
11.1.1 Forecast costs, expenditures and receipts for the
Year in question.
11.1.2 A schedule showing the most important individual items of
total costs, expenditures and receipts for the Year.
11.2 The Budget Statement shall be submitted to Government with respect to
each Year not less than ninety (90) days before the start of the Year
provided that in the case of the Year in which the Effective Date
falls, the Budget Statement shall be submitted within ninety (90) days
of the Effective Date.
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127
APPENDIX D
CALCULATION OF THE
INVESTMENT MULTIPLE FOR PRODUCTION SHARING PURPOSES
1. In accordance with the provisions of Article 14, the share
of the Government and the Contractor respectively of Profit
Petroleum from the Contract Area in any Financial Year shall
be determined by the Investment Multiple earned by the
Companies from the Contract Area at the end of the preceding
Financial Year. These measures of profitability shall be
calculated on the basis of the appropriate net cash flows as
specified in this Appendix D.
INVESTMENT MULTIPLE
2. The "Net Cash Income" of the Companies from the Contract
Area in any particular Financial Year is the aggregate value
for the year of the following:
(i) Cost Petroleum entitlement of the Companies as
provided in Article 13;
PLUS
(ii) Profit Petroleum entitlement of the Companies as
provided in Article 14;
PLUS
(iii) incidental income of the Companies of the type
specified in Section 3.4 of the Accounting
Procedure arising from Petroleum Operations and
apportioned to the Contract Area;
LESS
(iv) the Companies' share of all Production Costs and
royalty/cess payments incurred on or in the
Contract Area;
LESS
(v) the notional income tax, determined in accordance with
paragraph 7 of this Appendix, payable by the Companies on
profits and gains from the Contract Area.
3. The "Investment" made by the Companies in the Contract Area
in any particular Financial Year is the aggregate value for
the year of:
(i) Exploration Costs incurred by the Companies in the Contract
Area and apportioned to the Contract Area in the same
proportion that said Costs were recovered pursuant to
Articles 13.2 and 13.3.
128
PLUS
(ii) Development Costs incurred by the Companies in
the Contract Area.
4. For the purposes of the calculation of the Investment Multiple, Costs
or expenditures which are not allowable as provided in the Accounting
Procedure shall be excluded from Contract Costs and be disregarded.
5. The Investment Multiple ratio earned by the Companies as at
the end of any Financial Year from the Contract Area shall
be calculated by dividing the aggregate value of the
addition of each of the annual Net Cash Incomes
(accumulated, without interest, up to and including that
Financial Year starting from the Financial Year in which
Production Costs were first incurred or production first
arose after the Effective Date on or in the Contract Area)
by the aggregate value of the addition of each of the annual
Investments (accumulated, without interest, up to and
including that Financial Year starting from the Financial
Year in which Exploration and Developments Costs were first
incurred).
6. Profit Petroleum from the Contract Area in any Financial Year shall be
shared between the Government and the Contractor in accordance with the
value of the Investment Multiple earned by the Companies as at the end
of the previous Financial Year pursuant to Articles 14.2, 14.3 and
14.4.
GENERAL
7. In determining the amount of notional income tax to be
deducted in the applicable cash flows specified in paragraph
2 of this Appendix, a notional income tax liability in
respect of the Contract Area shall be determined for each
Company, as if the conduct of Petroleum Operations by the
Company in the Contract Area constituted the sole business
of the Company and as if the provisions of the Income Tax
Act, 1961, with respect to the computation of income tax at
a fifty percent (50%) rate applicable to Petroleum
Operations on the basis of the income and deductions
provided for in Article 15 of this Contract were accordingly
applicable separately to the Contract Area, disregarding any
income, allowances, deductions, losses or set-off of losses
from any other Contract Area or business of the Company.
8. Sample Calculation is attached in Appendix "D-1".
129
APPENDIX "D-1"
INVESTMENT MULTIPLE CALCULATION - EXAMPLE PROBLEM
The following example is intended to demonstrate the calculation and impact of
the Investment Multiple. The figures shown would be for the Companies and are
fictitious in this example for demonstration purposes. The investment multiple
is calculated individually for the Companies.
RIL OR EOGIL
Investment Multiple at beginning of 1.96
Financial Year 11
Profit Oil Shares at beginning of 24.00%
Financial Year 11
US$ MILLIONS
A Cumulative Net Cash Income at 100.00
beginning of Financial Year 11
+ Cost Petroleum in Financial Year 11 10.00
+ Profit Petroleum in Financial Year 11 1.00
+ Incidental Income in Financial Year 11 .00
- Production Costs in Financial Year 11 .60
- Oil Royalty and Cess in Financial Year 11 1.57
- Gas Royalty in Financial Year 11 0.41
- Notional Income Tax in Financial Year 11 2.00
B = Cumulative Net Cash Income at end of 106.42
Financial Year 11
C Cumulative Investment at beginning of 51.00
Financial Year 11
+ Exploration Costs in Financial Year 11 0.30
+ Development Costs in Financial Year 11 1.50
+ Service Costs in Financial Year 11 0.00
D = Cumulative Investment at end of 52.80
Financial Year 11
Investment Multiple at beginning of 2.02
Financial Year 12 = (B / D)
Profit Oil Shares at beginning of 18.00%
Financial Year 12
Since the Investment Multiple is calculated to be greater than 2.0 at the
beginning of Financial Year 12, the Profit Petroleum share to be received by RIL
or EOGIL falls from 24% to 18% at the inception of Financial Year 12.
In the event that the Investment Multiple were found to exceed 2.0 during the
financial close of Financial Year 11, the Contractor may have received excess
Profit Petroleum during the first sixty (60) days of Financial Year 12. In this
case, the quantity of excess Profit Petroleum will be calculated and the
accounts will be settled by adjustment to entitlements within sixty (60) days of
the following year (year twelve).
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130
APPENDIX E
FORM OF FINANCIAL AND PERFORMANCE GUARANTEE
(to be furnished pursuant to Article 29 of the Contract)
WHEREAS ENRON EXPLORATION COMPANY, a Company duly organized and existing under
the laws of Delaware, U.S.A., having its registered office at 1400 Smith Street,
Houston, Texas, U.S.A., (hereinafter referred to as "the Guarantor" which
expression shall include its successors and assigns) is the indirect owner of
100% of the capital stock of ENRON OIL & GAS INDIA LIMITED ("Company") and
direct owner of its parent company; and
WHEREAS Company is signatory to a Production Sharing Contract of even date of
this guarantee in respect of an Offshore area identified as Tapti Block
(hereinafter referred to as "the Contract") made between the Government of India
(hereinafter referred to as "the Government"), Company, RELIANCE INDUSTRIES
LIMITED and OIL & NATURAL GAS CORPORATION LIMITED (hereinafter referred to as
"Contractor" which expression shall include its successors and permitted
assigns); and
WHEREAS the Guarantor wishes to guarantee the performance of Company or its
Affiliate Assignee under the Contract as required by the terms of the Contract;
NOW, THEREFORE, this Deed hereby provides as follows:
1. The Guarantor hereby unconditionally and irrevocably guarantees
to the Government that it will make available, or cause to be
made available, to Company or any other directly or indirectly
owned Affiliate of Company to which any part or all of
Company's rights or interest under the Contract may
subsequently be assigned ('Affiliate Assignee'), to ensure that
Company or any Affiliate Assignee can carry out its work
commitment as set forth in the Contract.
2. The Guarantor further unconditionally and irrevocably guarantees to the
Government reasonable compliance by Company or any Affiliate Assignee, of
any obligations of Company or any Affiliate Assignee under the Contract.
3. The Guarantor hereby undertakes to the Government that if
Company, or any Affiliate Assignee, shall, in any respect, fail
to perform its work commitments under the Contract or commit
any material breach of such obligations, then the Guarantor
shall fulfill or cause to be fulfilled the obligations in place
of Company or any Affiliate Assignee, and will indemnify the
Government against all actual losses, damages, costs, expenses,
or otherwise which may result directly from such failure to
perform or breach on the part of Company. In no event shall
Guarantor be liable for any special consequential, indirect,
incidental or punitive damages of any kind or character,
including, but not limited to, loss of profits or revenues,
loss of product or loss of use arising out of or related to a
131
material breach by Company of its obligations under the
Contract.
4. This guarantee shall take effect from the Effective Date and shall remain
in full force and effect for the duration of the Contract and thereafter
until no sum remains payable by Company, or its Affiliate Assignee, under
the Contract or as a result of any decision or award made by any expert or
arbitration tribunal thereunder.
5. This guarantee shall not be affected by any change in the Articles of
Association and by-laws of Company or the Guarantor or in any instrument
establishing the Licensee.
6. The liabilities of the Guarantor shall not be discharged or
affected by (a) any time indulgence, waiver or consent given to
Company; (b) any amendment to the Contract or to any security
or other guarantee or indemnity to which Company has agreed;
(c) the enforcement or waiver of any terms of the Contract or
of any security, other guarantee or indemnity; or (d) the
dissolution, amalgamation, reconstruction or reorganization of
Company.
7. This guarantee shall be governed by and construed in accordance
with the laws of India.
IN WITNESS WHEREOF the Guarantor, through its duly authorized
representatives, has caused its seal to be duly affixed hereto and this
guarantee to be duly executed the __________ day of _________ 1994.
The seal of ___________ was hereto duly affixed by ___________this_____ day of
________ 1994 in accordance with its by-laws and this guarantee was duly signed
by ________________ and ______________________
as required by the said by-laws.
- ------------------------ --------------------
Secretary Vice President
Witness:
- -----------------------
-----*****-----
132
APPENDIX F
EQUIPMENT
All Wells drilled by ONGC and associated equipment whether or not plugged and
abandoned except that no liabilities or obligations shall accrue to Companies
from accepting same unless such liabilities or obligations arise as a result of
actions taken after the Effective Date.
-----*****-----
133
APPENDIX G
DEVELOPMENT COMMITMENT SPECIFIED BY THE COMPANIES
The development plan, illustrated in Figure G-1 includes, but may not be limited
to:
- 3D reservoir simulation models
- 6 well platforms at South Tapti
- 4 well platforms at Mid-Tapti
- 1 common 5.1 MMm3/day (180 MMCFPD) processing
facility and living quarters at Mid-Tapti
- Interfield and intrafield pipelines
- 1 export gas pipeline
- 35 Development Wells (directional from well
platforms)
- Geophysical, geological and engineering studies
- The final configuration of physical facilities will
result from optimization studies to which ONGC will contribute
their knowledge and information.
- If drainage area of the 35 primary development wells is
inadequate, an additional 30 (infill) wells may be needed.
Infill wells are not a committed work obligation, but are
included in the Cost Recovery Limit defined in Article 13.1.2.
Annex G-1 shows Companies' development concept based on an assumed project start
date of July 1, 1993.
-----*****-----
134
APPENDIX - G
FIGURE G-1
Mid and South Tapti Fields
Bombay Offshore Basin
[Chart]
135
Appendix G
Annex G-1
VIIa. TECHNICAL INFORMATION FOR THE FIELD
aA. RESERVE ASSESSMENT
Primary objectives in assigning reserves to Mid- and South-Tapti
Fields were two fold: First, verify ONGC's reserves, and second,
assess potential for an increase and a decrease in reserve base.
1. Verification Methodology
Verification was accomplished by adapting reservoir parameters
and various fluid boundaries utilized by ONGC in pay maps
provided in the "Review of Technological Scheme for
Development of Tapti Field" to the Bidders' revised structure
map on the H-3 Marker (Exhibit VII-1). This approach
incorporated significant effects of a complex and aerially
extensive NW-SE extensional fault system into the
interpretation of the primary gas pool geometries in Mid- and
South-Tapti. Structure maps for the various pools were made
for Pay Zones I, II, IX, and XII in Mid-Tapti and Zones I, II,
and III in South-Tapti.
Values from the ONGC pay hydrocarbon volume maps (Sgoh) were
then recontoured to reflect the new structural
interpretations. Major stratigraphic boundaries were also
incorporated in the associated zonal pay maps. At Mid-tapti,
it was necessary to place a generally E-W trending reservoir
pinchout to the north because the MT-3 and MT-4 Wells lie
below the critical structural spill point at the Pay Zone I
and XII levels. A NE-SW trending permeability barrier mapped
by ONGC that separates the MT-3 from adjacent wells in Pay
Zone XII was modified to include the MT-1 Well in the MT-3
Block.
Stratigraphic correlation methods and nomenclature established
by ONGC were utilized in this preliminary evaluation. The
erratic fluviodeltaic depositional character of the sand
bodies and relatively large distances between wells precluded
a more detailed stratigraphic correlation scheme without
additional seismic/well data. A major disagreement in
correlation with ONGC occurs at Pay Zone XII at Mid-Tapti and
will be discussed.
The Bidders are confident that the 3-D seismic survey proposed
in the pre-development work plan will prove to be an excellent
tool for delineation of porous gas-filled reservoirs through
amplitude analysis (DHI).
It will also minimize stratigraphic risk prior to field
development and improve detailed structural definition.
2. Upside Potential
Verification of base reserves in the Tapti Block is considered
essential by the Bidders. Upside potentials is also important
but not quantifiable in this preliminary evaluation.
Hydrocarbon pay volume values calculated by ONGC are
conservative based on preliminary log analysis of the MT-1,
MT-2, MT-5, C2-5, C2-7 and C2-8 Wells. Average shale-corrected
porosity values calculated by the Bidders vary between 22
percent and 30 percent (25 percent average). Gas effect may
impart a small positive error in the Bidders' porosity
calculation.
In Mid-Tapti, average gas saturation porosity values
calculated by the Bidders were 67 to 72 percent in MT-1, 64 to
71 percent in MT-2 and 73 to 76 percent in MT-5. These higher
gas saturations were calculated utilizing a Waxman-Smit log
analysis model assuming cation exchange capacity (CEC) values
between 5 to 10 meq/100gms. Petrographic analyses suggested to
the Bidders that pervasive clay coating of the sands by a
chlorite mineral (chamosite) could cause relatively high CEC's
of 10 to 40 meq/100gms. This CEC effect could result in
preferential conductivity along the clay linings. This
phenomena would increase calculated gas saturations if taken
into account. For this reason, the attached contoured Sgoh
values are considered to be conservative. Proposed
pre-development work will entail a detailed petrophysical
analysis of existing rock/log data to derive zone-specific
formation evaluation models to determine effective porosity,
permeability, and gas saturation parameters.
Aside from log analysis, the fluid contacts and stratigraphic
limits placed on various Pay Zones have a significant margin
for error. Of the seven pools mapped and discussed below by
the Bidders, four have a structurally defined limit based on a
gas/shale contact (GSC) or lowest known gas (LKG) as defined
by the Bidders. The water contact in Pay Zone I at
South-Tapti, the largest pool in the block, is based on a
water test from a same 20 meters stratigraphically lower than
the proven gas productive zone lying immediately below the H-3
marker. Arbitrary stratigraphic limits were required to
explain the trapping mechanism of Zone I and Zone XII pools at
Mid-Tapti. The pools' actual limits on the north side of the
field have yet to be defined.
aB. PAY ZONE STRUCTURE AND (Sgoh) MAPS
The zones mapped by the Bidders include the following:
ZONE MAP FIGURE FIELD
---- --------- ------ ---------------
I Structure VII-2 Mid/South-Tapti
I Sgoh VII-3 Mid/South-Tapti
II Structure VII-4 Mid/South-Tapti
II Sgoh VII-5 Mid/South-Tapti
III Structure VII-6 South-Tapti
III Sgoh VII-7 South-Tapti
IX Structure VII-8 Mid-Tapti
IX Sgoh VII-9 Mid-Tapti
XII Structure VII-10 Mid-Tapti
XII Sgoh VII-11 Mid-Tapti
In the following discussion of the various Pay Zones, stratigraphic
correlation is based on the distance the pay sand in question lies
below the H-3 marker. Zones in different wells with overlapping
stratigraphic depth ranges are considered to be equivalent.
Zone I is the most aerially extensive pay in the Tapti area
occurring in both field areas. At South-Tapti, ONGC placed a
gas/water contact at 1807 meters subsea although none of the
observed tests of this interval in the C2-2, C2-4, C2-5, C2-6, and
C2-7 had water recoveries reported. The C2-6 did test a sand at
1843- 52 meters (1820-1829 meters subsea) which produced water. It
occurs 22 meters below the gas bearing Zone I sand at 1820-1825
meters (1797-1802 meters subsea). This provides the only evidence of
significant water production in the gross Zone I interval at
South-Tapti. The Sgoh map honors this water contact. The numerous
cross-cutting faults at South-Tapti were generally not considered to
separate the accumulation except to the south at the C2-7 Well and
in the north where the high Sgoh values in C2-1, C2-4, and C2-6 are
interpreted to be in a separate fault block.
At Mid-Tapti the gas/shale contact or lowest known gas (LKG) was
placed at a -1650 meters subsea based on the MT-3 Well. Successful
tests were reported from MT-1, MT-3, MT-4, and MT-5 Wells. An
arbitrary stratigraphic pinchout was placed on the north side of the
field because structural spill as mapped occurs at -1610 meters.
This limits the productive area to roughly the same size as that
mapped by ONGC. An untested fault trap on the west side of the field
was contoured using Sgoh values similar to those observed in
adjacent wells. Reserves for the untested fault block were risk
discounted at 50 percent probability of success (POS) in this and
subsequently mapped intervals.
Zone II occurs in both field areas but is aerially limited to the
south end of South- Tapti with successful tests in the C2-2 and C2-7
Wells. The pool is interpreted to be stratigraphically limited to
the north and structurally defined by LKG at -1847 meters in the
C2-7 Well. At Mid-Tapti, successful tests were reported in MT-1 and
MT-5. The gas/water contact at -1650 meters is thought to be occurs
at 1676-1679 meters. The base of the sand is at 1650 meters subsea.
MT-2 contains two untested sands at the Zone II stratigraphic level
that appear potentially productive (1656-1670, 1672-1676). This was
apparently considered by ONGC when assigning a relatively high Sgoh
value of 1.47 to the well.
Zone III is restricted to the northern half of South-Tapti Field. A
stratigraphic limit was placed south of the C2-5 Well and LKG at
-1876 meters subsea corresponding to the base of the productive sand
at 1896-1903.5 meters in C2-5. Successful tests include the C2-1 and
C2-5.
Successfully tested zones that were not quantified at South-Tapti in
this preliminary study include Zones IV and V in C2-8, Zone VIII in
C2-1, Zone IX in C2-5, Zone X in C2-6 and C2-8, and Zone XI in C2-2.
At Mid-Tapti, Pay Zone IX had a successful test in the MT-5 Well
with LKG at -1896 meters subsea. An untested apparent log pay zone
occurs in the MT-1 at 1920-1925 meters that is stratigraphically
equivalent to the MT-5 producer and was assigned an Sgoh value of
0.168 by ONGC.
Zone XII at Mid-Tapti is interpreted to consist of two separate sand
bodies that include a mix of ONGC Zones X and XII. In their map of
Zone XII, ONGC separates a prolific test (498,273 m(3)/day) at
2046-2055 meters in the MT-3 Well with a permeability barrier from
the MT-1, MT-2, MT-4, and MT-5 Wells. The Bidders interpret Zone X
in MT-1, which tested at a rate of 446,355 m(3)/day from 1976-1979
and 1984-1987, to be the stratigraphic equivalent of the prolific
MT-3 Zone XII. This prolific sand body, informally called Zone XII A
is not present in the other Mid-Tapti wells. Approximately 60 meters
stratigraphically lower than Zone XII A is another productive sand
body called Zone XII B. It has successful tests in the MT-2 and MT-5
Wells but with lower rates of 107,000 and 85,535 m(3)/day,
respectively. A significant water recovery in the MT-2 test of 1085
bbl/day caused the Bidders to place a gas/water contact at -2040
meters subsea in Zone XII B. The Sgoh map reflects the difference in
pay quality between the two sand bodies and shows a northern
stratigraphic limit which is required because of structural spill.
Zones not mapped and quantified at Mid-Tapti include Zones XIV and
XV in MT- 1.
aC. ADDITIONAL PAY ZONES NOT MAPPED BY ONGC
In the Bidders' preliminary log analysis, a number of untested
potential pay zones were identified. Future work will integrate all
log defined potential pay zones with 3-D seismic amplitude analysis
and stratigraphic interpretation to provide detailed pay maps.
aD. RESERVE PARAMETERS
The parameters used for estimating reserves for each interval are
believed to be the same parameters employed by ONGC in reserve
estimates available in one of the documents in the data room.
Preliminary log analysis suggests the possibility for variation,
perhaps towards the positive side. This is a high priority item for
further investigation during the pre-development study phase.
FIELD HORIZON NET PAY POROSITY WATER SATURATION
(m) (%) (%)
---------------- ------- -------- ----------------
Mid-Tapti I 6.1 18.0 65
Mid-Tapti II 15.6 18.0 69
Mid-Tapti IX 2.6 18.6 60
Mid-Tapti XII 8.6 21.8 57
South-Tapti I 6.0 18.5 60
South-Tapti II 17.2 19.0 45
South-Tapti III 8.7 21.0 40
aE. RESERVES
Figure VII-12 is a reserve uncertainty distribution plot on log
probability scale for Mid and South Tapti fields combined. It shows
the expected reserve range of gas in place in English units for
unrisked and risked reserves. For each pay zone, individual
fault-defined gas accumulations were risk weighted according to the
degree and proximity of well penetrations as described in section B.
Calculated reserves were placed at the P 50% or most likely
position. Based on alternative log analysis models, the maximum (P
10%) value was determined by increasing porosity 40% (i.e. porosity
value of 10% would change to 14%) and decreasing water saturation
40% as well (i.e. Sw of 60% would change to 36%). A summary of the
distribution in metric units is listed below:
Probability Unrisked Risked
> or = Gas in Place Gas in Place
(MMMm3) (MMMm3)
----------- ------------ ------------
Minimum 90 28.32 20.39
Most Likely 50 48.15 36.82
Mean 42.5 50.98 39.65
Maximum 10 80.71 62.31
Risked mean gas-in-place reserves of 39.65 MMMm3 calculated from the
reserve uncertainty distribution, are utilized in the current bid
proposal yielding mean recoverable reserves of 31.72 MMMm3.
Detailed evaluation of unrisked most-likely reserves by field and
pay horizon were risk weighted and assessed an 80% recovery factor
to derive recoverable most-likely reserves of 29.46 MMMm3.
These were submitted in the March 30,1993 bid proposal as follows:
FIELD SAND ORIGINAL RECOVERABLE
GAS IN PLACE GAS RESERVES
MMMm3 MMMm3
----------- ---- -------- -----------
Mid-Tapti I 5.607 3.490
Mid-Tapti II 7.240 4.682
Mid-Tapti IX 0.583 0.359
Mid-Tapti XII 11.828 6.694
South-Tapti I 7.518 4.939
South-Tapti II 11.005 6.742
South-Tapti III 4.563 3.009
The above volumes are before shrinkage from expected condensate
liquids recovered during normal production operations. Furthermore,
potential reserves exist that cannot be evaluated with the
information available. In particular, those associated with
successful well tests at levels IV, V, VIII, IX, X and XI in
South-Tapti and levels XI and XV in Mid-Tapti. The Bidders expect to
quantify this potential during the initial study phase.
The cited pay zones that were not quantified by RIL/EEC amount to 20
to 30% of ONGC's total gas in place. Should ONGC's estimate be
correct, a success "upside case is included in this proposal to
reflect the potential impact of these reserves on the production
profile with the addition of up to 10.57 MMMm3 of gas reserves to
the base case of 31.72 MMMm3 for a total of 42.29 MMMm3.
VIIb. TECHNICAL INFORMATION FOR GREATER TAPTI EXPLORATION CASE
b1. Concept
Early in the evaluation of the Tapti fields, RIL/EEC became aware of
ONGC's continuing efforts to explore and appraise additional gas
accumulations in the surrounding gas-prone region of the Surat
Depression. At RIL/EEC's request, ONGC provided an excellent
overview of their efforts and results in the area through a series
of meetings in Bombay. This gracious exchange of ideas provided the
basis for the proposed exploration case.
b2. Location
Figure VII-13 is a regional map of the Greater Tapti area. The
boundaries of the proposed exploration area were set up to encompass
the known limits of the Early Miocene to Early Oligocene reservoir
interval proven gas productive at Tapti (Figure VII-14). The
proposed coordinates for the Greater Tapti Exploration area are as
follows:
Corner Latitude Longitude
------ -------------- --------------
A N20(degree)50' E71(degree)30'
B N19(degree)50' E71(degree)30'
C N19(degree)50' E72(degree)50'
D N21(degree)20' E72(degree)50'
E N21(degree)10' E72(degree)10'
A N20(degree)50' E72(degree)10'
b3. Proposed Area Status
It is the intent of RIL/EEC that the Greater Tapti area be considered
under the same terms, conditions and contractual obligations agreed
for the Tapti block proper.
b4. Stratigraphy and Reservoir Characterization
Figure VII-15 is a sketch map of the net sand isopach for the Early
Miocene-Early Oligocene reservoir interval and associated gas
discoveries and prospects. The map is an attempt to demonstrate the
interpretation shown to RIL/EEC by ONGC. It exhibits a northerly point
source of sand supply that was distributed to the south and southwest
in a large lobate delta-like geometry.
Examination of over 15 Tapti cores in Bombay by RIL/EEC gave
conclusive evidence of a robust tidally-influenced deltaic environment
of deposition similar to the modern Irrawady delta (Figure VII-16).
Reservoirs occur in three major depositional environments (Figure
VII-17).
1. The highest quality reservoirs with good visualorosity and
permeability are large distributary channel sands up to 25
meters thick. Modern analogs in the Irrawady delta are 2-6 km
wide and 10's of km long.
2. The second most significant reservoirs are aerially extensive
delta front/chenier-ridge sands that form Pay Zone I at Mid and
South Tapti. They appear to have moderate to
fair visual porosity and permeability with significant amounts
of entrained clay introduced by burrowing organisms.
3. Fair to poor quality reservoirs consisting of tidal channels,
tidal creeks and sandy tidal- delta-plain sands comprise the
third and most volumetrically significant portion of the
sedimentary section. They lack reservoir properties necessary
for commercial completion but may provide significant
gas-storage volume to source adjacent channel and delta-front
sands.
b5. Exploration Activity
Exploration activity by ONGC has been focussed on the eastern and
southern portions of the sand system shown in Figure VII-15 playing
structural and combination structural-stratigraphic traps. Identified
structurally-controlled gas discoveries include North Tapti, C-24,
C-22 and B-12. Reserves of approximately 6.0 MMMm3 have been reported
by ONGC for C-24 and C-22. RIL/EEC understand the broad low-relief
B-12 feature has been tested by two wells to date with moderate flow
rates of gas in the 100,000 to 200,000 m3 range. Like the cited C-24
and C-22 discoveries, total net sand thickness at B-12 is
approximately 30% of that observed in the Tapti fields. The more
poorly defined combination traps with tested gas consist of SD-4,
CA-1, SD-1 and CD-1.
An untested high amplitude structure set up by compressional
reverse-fault movement is informally called the NE prospect. The
feature is located in transitional shallow waters with mudbanks that
are emergent at low tide. It requires seismic coverage on it northeast
side through expensive non-conventional acquisition methods to
establish critical dip. The structure appears to lie in a favorable
position within the sand-rich axis of the reservoir system with
upwards of 160 meters of possible net sand not unlike that seen in the
Tapti field area.
b6. Exploration Results
Aside from the NE prospect which appears to have risky but high
reserve potential, the remaining discoveries were presented by ONGC as
somewhat marginal with smaller reserves and generally thinner and
poorer reservoir quality sands than Tapti. It appears to RIL/EEC that
timely and economic development of these relatively small and
scattered accumulations, outboard of the Tapti block, is not feasible
without linkage to Tapti infrastructure. RIL/EEC are prepared to
design the capacity of the Tapti facilities and pipelines to meet the
additional reserve potential of 15 to 35 MMMm3 envisioned for the
Greater Tapti area.
To insure that rapid exploitation of these discoveries and prospects
can occur, RIL/EEC is prepared to offer an immediate three year work
commitment entailing an estimated $38 million dollars (U.S.) of
expenditure. The plan is detailed in section VIII. To demonstrate the
benefits afforded GOI, an Exploration Case reserve is estimated at 25
MMMm3 for existing prospects and discoveries to provide the basis for
a production profile that can be layered on the Tapti Base and Success
Case Scenarios.
F. PLAN FOR UTILIZATION OF GAS
The purpose of this application is to exploit the non-associated
natural gas reserves in the block. Therefore, except for gas
consumption required for operations, all the gas produced and
associated condensate fluids will be sold.
The Indian Government gas supply/consumption projections include gas
from this block.
The Bidders desire to produce the natural gas to fulfill the
government plan in the anticipated volumes.
G. MONITORING SYSTEMS AND RESERVOIR MANAGEMENT
1. Production Monitoring
Production will be monitored on an individual well basis and on
an aggregate basis consistent with normal good oil field
practices. For effective operational control, production rates
will be monitored frequently and recorded daily; for fiscal
purposes, production will be summarized and reported monthly. We
currently envision installation of a well-test system at each
well platform; however, full well stream "wet" meters may prove
to be a more attractive approach upon further study. Where well
tests are used, individual well production will be ascertained
by allocation on the basis of actual well producing time at a
given choke setting. Key data (e.g., flowing tubing pressure
and, if available, wet meter rate) may be radio transmitted to
the process platform.
2. Reservoir Management
Reservoir management will be carried out through conventional
surface and down hole monitoring systems such as bottom hole
pressure surveys, production testing and well deliverability
testing on a periodic basis.
This data will be analyzed at least once a year to establish a
record of reservoir performance from which the reservoir drive
mechanisms will be established and the operations adjusted
accordingly to maximize recovery.
It is anticipated that a suitable mathematical reservoir model
will be established early in the exploitation stage and that the
reservoir performance would be monitored by periodically
updating the model with the production and pressure data
gathered.
The model would also be utilized for the purpose of reporting
gas reserves and deliverability projections.
A relatively simple single phase, three-dimensional,
multi-layered reservoir model is planned.
VIIIa. WORK PROGRAM - TAPTI BLOCK
A. Base Case Development (30 billion cubic meters recoverable reserves)
1. Seismic Commitment
Mid Tapti 3D Survey 320 km2
4500 km Inline
50 m Crossline Interval
South Tapti 3D Survey 530 km2
11000 km Inline
50 m Crossline Interval
The Mid-Tapti 3D survey acquisition would begin in October
1993, assuming execution of the Letter Agreement in July 1993.
Acquisition, processing and interpretation will require 6-8
months. The South Tapti 3D acquisition would commence in 1994.
2. Development Commitment
The development plan & schedule are illustrated on Figures
VIII-1, -2, -3 and include:
- 3D reservoir simulation models
- 6 well platforms at South Tapti
- 4 well platforms at Mid-Tapti
- 1 common 5.1 MM3/day processing facility and living
quarters at Mid-Tapti
- Interfield & intrafield pipelines
- 1 export gas pipeline
- 35 Development wells(directional from well platforms)
- Geophysical, geological and engineering studies
- The final configuration of physical facilities will result
from optimization studies to which ONGC will contribute
their knowledge and information.
- If drainage area of the 35 primary development wells is
inadequate, an additional 30 (infill) wells may be needed.
Infill wells are not a committed work obligation
3. Gas Sales Profiles
RIL/EEC expect (but cannot guarantee) that the Base Case
development plan will result in the gas sales shown in Figure
VIII-4. If the Success Case discussed in Section VII
materializes, the sales volumes should range between those
indicated in Figure VIII-4 and Figure VIII-5. If volumes
available for sale exceed those shown in Figure VIII-4, the
modular Base Case development plan will be augmented to
accommodate the excess gas production over that contemplated
in the Base Case.
VIIIb. WORK PROGRAM - GREATER TAPTI AREA
A. The RIL/EEC proposal to expand the Tapti block to include the
Greater Tapti area defined above under Addendum Section VIIb is
advantageous to GOI, ONGC and RIL/EEC for reasons shown on Figure
VIII-6.
Seismic and Drilling Commitments shown below are in addition to or
commitments for the Tapti block (Section VIIIa).
Year Activities Est. Cost
------- ------------------------ ----------
1993-94 1000 km 2D seismic 5 MM US $
(primarily in shallow
water "transition zonell
on "NE" and "North Tapti"
prospects.
1995 5 wells 25 MM US $
1996 2 wells 8 MM US $
In addition, all usable existing seismic data will be reprocessed
and interpreted.
The commitment to spend a minimum 38 MM US Dollars in the Greater
Tapti Area (outside the currently defined block) during 1993 through
1996 shall be borne by ONGC, RIL and EEC in proportion to their
working interest in the Area (currently 40%, 30% and 30%
respectively). These and all subsequent expenditures shall be cost
recoverable. The project including Tapti block containing Mid and
South Tapti plus the area identified in Section VIIb-B shall be
considered as one.
Given success in the Greater Tapti Area outside the current Tapti
block, the Bidders' expectation for addition recoverable reserves is
25 billion cubic meters. Assuming that level of success in the
expanded area and the maximum success Case reserves in the current
Tapti block, the total Greater Tapti Area production profile is
shown on Figure VIII-7. These total reserves, 65 billion cubic
meters, represent a maximum and are neither guaranteed nor expected.
B. PRODUCTION BUILD UP PHASE (INITIAL FIELD DEVELOPMENT TO REACH A
PRODUCTION PLATEAU)
The Bidder plans to tailor development work to the gas market. No
capital will be expended unless backed by a firm gas purchase
commitment. This is true not only for the initial plateau currently
contemplated in gas consumption projections, but for production
beyond the original plateau if warranted by the results of the study
phase.
It is anticipated that development will be originally concentrated
in the Mid-Tapti area. The development of the second field, or any
other field, will follow to the extent required to satisfy the
market. Deliverability capacity in excess of the market,
approximately 25 percent, will be built into the development plan.
Development is anticipated to consist of directional wells drilled
form several wellhead platforms. The wells will be drilled with a
jack-up rig. Because of sand production, well completions will be
designed to maximize flow rates yet minimize sand production. To
that extent, gravel pack through several extended perforations is
anticipated. Nevertheless, the final design will be consistent with
the results of the study phase.
The well-head platforms will have testing facilities; they will be
unmanned and controlled (monitored) from a central processing
platform via a communication/control system.
Submarine line network (8" - 12" in diameter) will connect the
platforms to the central processing platform.
The central processing platform will have gas processing facilities
of adequate capacity to handle all the anticipated volumes.
Expansion capabilities will be provided for during the initial
design of the processing platform.
Ability to handle and process condensate fluids and water will be
part of the processing package. Water will be disposed of after
appropriate treatment to insure that it is environmentally safe and
meets any existing specifications in this regard.
No gas will be flared except for technical reasons and then only in
minimum quantities.
After measurement using state-of-the-art gas/liquid metering
systems, which independently measures gas and condensate, the gas
and condensate products will be transported via a submarine line to
a connecting point with the existing Bassein-Hazira pipeline, or the
new planned parallel pipeline.
The Bidders believe that with early award of the block, with proper
planning and with the necessary mechanisms built-in to expedite
approvals (single clearance window concept) first production can be
achieved early in 1995 and that the first plateau could be achieved
in 1996.
C. PLATEAU PRODUCTION AND DECLINE PHASE
Maintenance of the plateau phase for a period of 15 years is
expected to be accomplished by further development drilling and well
recompletions into other sands/reservoirs not originally exposed to
production. These activities will, as explained earlier for the
initial development phase, be tailored to the market demands and
contractual obligations. Depending on future market and provided
enough reserves are proven to safely back-up additional
deliverability, incremental volumes will be added to the original
base plateau. The duration of the incremental volumes will depend
upon reserves and markets.
D. ABANDONMENT PHASE
At the termination of the PSC period, the wells and facilities will
be fully transferred without cost to the designated government
agency for further operations.
Abandonment of wells for mechanical reasons may occur. Those wells
will be abandoned following accepted industry practices.
Appendix - 5
COMMITTED DEVELOPMENT WORK PROGRAMME
FOR TAPTI BLOCK
1. SEISMIC COMMITMENT
Mid Tapti 3D Survey 320 km2
4500 km Inline
50 m Crossline Interval
South Tapti 3D Survey 530 km2
22000 km Inline
50 m Crossline Interval
2. DEVELOPMENT COMMITMENT
- 3D reservoir simulation models
- 6 well platforms at South Tapti
- 4 well platforms at Mid-Tapti
- 1 common 5.1 MM3/day processing facility and living quarters at
Mid-Tapti
- Interfield and intrafield pipelines
- 1 export gas pipeline to Hazira and onshore reseparation facility
- 35 development wells (directional from well platforms)
- Geophysical, geological and engineering studies
- The final configuration of physical facilities will result from
optimization studies to which ONGC will contribute their knowledge
and information; work programme may be adjusted accordingly to, for
example, reroute the export pipe line to the existing 36" line and
possibly eliminate the reseparation facility
If drainage area of the 35 primary development wells proves
inadequate, an additional 30 (infill) wells may be needed. Infill
wells are not a committed work obligation.
Appendix - 6
TAPTI ESTIMATED EXPENDITURE
YEAR CAPEX OPEX
$MM $MM
---- ----- -----
1993 19.5 1.1
1994 122.3 2.75
1995 75.3 8.8
1996 76.4 11
1997 67.2 12.1
1998 0 12.1
1999 34 13.2
2000 18 13.2
2001 0 13.2
2002 20 13.2
2003 18 13.2
2004 22 13.2
2005 42.4 13.2
2006 0 13.2
2007 0 13.2
2008 16 13.2
2009 4.5 13.2
2010 6 13.2
2011 0 13.2
2012 0 13.2
2013 0 13.2
2014 0 13.2
2015 0 13.2
2016 0 13.2
2017 0 13.2
541.6 298.7
Appendix - 7 (Contd.)
TAPTI PRODUCTION PROFILE
(4.2 MM m3/day)
YEAR CONDENSATE SALES GAS SALES
MBbL MM m3
---- ---------------- ---------
1993 0 0
1994 0 0
1995 526 1240
1996 658 1551
1997 658 1551
1998 658 1551
1999 658 1551
2000 658 1551
2001 658 1551
2002 658 1551
2003 658 1551
2004 658 1551
2005 658 1551
2006 658 1551
2007 658 1551
2008 658 1551
2009 658 1551
2010 572 1355
2011 546 1287
2012 472 1111
2013 350 825
2014 259 611
2015 191 449
2016 152 360
2017 79 187
12359 29134
APPENDIX H
PRODUCTION PROFILE OF THE
MID AND SOUTH TAPTI FIELDS
YEAR CONDENSATE SALES GAS SALES
(Thousands Barrels) (Millions Cubic Meters)
1993 0 0
1994 0 0
1995 0 0
1996 165 388
1997 658 1551
1997 658 1551
1998 658 1551
1999 658 1551
2000 658 1551
2001 658 1551
2001 658 1551
2003 658 1551
2004 658 1551
2005 658 1551
2006 658 1551
2007 658 1551
2008 658 1551
2009 658 1551
2010 658 1551
2011 658 1551
2012 572 1355
2013 546 1287
2014 472 1111
2015 350 825
2016 259 611
2017 191 449
2018 152 360
2019 79 187
-----*****-----
APPENDIX I
PAYMENT FOR USE OF ONSHORE PLANT
Parties acknowledge that Gas is to be received by GAIL at Hazira downstream of
receiving and separation facilities owned and operated by ONGC. In order to
compensate ONGC for the cost of ownership and operations of these facilities,
Contractor shall make payments to ONGC on the basis of the costs fixed on an
incremental basis by an internationally recognised expert who shall be selected
by two members of the Operating Committee from a panel of three internationally
recognised experts selected by ONGC. In case there is no agreement between the
Companies and ONGC on the advice tendered, the matter shall be referred to
Government. The decision of Government shall be final and binding on all the
Parties.
GRAPHICAL CONTENT APPENDIX
Appendix - B Map of Contract Area - Tapti Block
Appendix G
Figure G-1 Mid and South Tapti Fields Bombay Offshore Basin
Figure VII-1 Mid and South Tapti Fields Structure Map H-3
Seismic Marker
Figure VII-2 Structure Map on Top Pay I Sand
Figure VII-3 Sg0h Map Pay I
Figure VII-4 Structure Contour Map on Top of Pay II Sand
Figure VII-5 Sg0h Map Pay II
Figure VII-6 Structure Map Pay Level III
Figure VII-7 Sg0h Map Pay Level III
Figure VII-8 Structure May on Pay IX
Figure VII-9 Sg0h May Pay IX
Figure VII-10 Structure Map Pay XII
Figure VII-11 Sg0h Map Pay XII
Figure VIII-2 Enron Exploration Project Schedule Details
Figure VIII-4 Tapti Production Profile
Figure VIII-3 Development Schedule Base Case
Appendix-3 Enron Exploration Project Schedule Details
EXHIBIT 22
<TABLE>
ENRON OIL & GAS COMPANY
AND SUBSIDIARIES
<CAPTION>
Date of Where
Company Name Incorporation Incorporated
------------ ------------- ------------
<S> <C> <C>
Enron Oil & Gas Company ...................................... 06/12/85 Delaware
Enron Oil & Gas International, Inc. ....................... 05/27/93 Delaware
EOGI-Trinidad, Inc. .................................... 06/02/93 Delaware
EOGI Trinidad Company ............................... 06/02/93 Cayman Islands
Enron Gas & Oil Trinidad Limited ................. 11/04/92 Trinidad
EOGI-Australia, Inc. ................................... 06/02/93 Delaware
EOGI Australia Company .............................. 06/02/93 Cayman Islands
Enron Exploration Australia Pty Ltd .............. 11/23/92 Australia
EOGI-France, Inc. ...................................... 06/02/93 Delaware
Enron Exploration France S.A ........................ 11/13/92 France
EOGI-Russia, Inc. ...................................... 07/29/93 Delaware
Enron Exploration and Production (Russia) Limited ... 11/09/92 Cyprus
Kuznetsk Exploration and Production Company ...... 10/20/93 Russian Federation
EOGI-Kazakhstan, Inc. .................................. 07/29/93 Delaware
Enron Exploration and Production (Kazakhstan) Limited 02/08/93 Cyprus
Enron Oil & Gas Kazakhstan Ltd ...................... 08/18/94 Cayman Islands
Enron Exploration Company, South America ............... 08/03/93 Delaware
Enron Exploration S.A ............................... 12/12/91 Argentina
EOGI-United Kingdom, Inc. .............................. 07/29/93 Delaware
EOGI United Kingdom Company B.V ..................... 12/04/81 The Netherlands
Enron Oil U.K. Limited ........................... 05/22/90 England
EOGI-India, Inc. ....................................... 03/17/94 Delaware
Enron Oil & Gas India Ltd ........................... 06/02/93 Cayman Islands
EOGI-China, Inc. ....................................... 08/18/94 Delaware
Enron Oil & Gas China Ltd ........................... 08/19/94 Cayman Islands
EOGI-Qatar, Inc. ....................................... 09/22/94 Delaware
Enron Oil & Gas Qatar Ltd ........................... 09/23/94 Cayman Islands
EOGI-Uzbekistan, Inc. .................................. 01/30/95 Delaware
Enron Oil & Gas Uzbekistan Ltd ...................... 01/31/95 Cayman Islands
Enron Oil & Gas Marketing, Inc. ........................... 04/09/90 Delaware
I N Holdings, Inc. ........................................ 03/13/85 Delaware
Enron Oil Canada Ltd ................................... 04/01/82 Alberta
Nilo Operating Company .................................... 04/04/94 Delaware
Enron Oil & Gas - Carthage, Inc. .......................... 03/21/95 Delaware
</TABLE>
EXHIBIT 23.1
March 16, 1995
Enron Oil & Gas Company
1400 Smith Street
Houston, Texas 77002
Gentlemen:
We hereby consent to the references to our firm and to our opinions
delivered to Enron Oil & Gas Company, hereinafter referred to as the "Company,"
relating to our comparison of estimates prepared by us to those furnished to us
by the Company of proved oil, condensate, natural gas liquids, and natural gas
reserves of certain selected properties owned by the Company as expressed in our
letter reports dated January 20, 1993, January 27, 1994, and January 13, 1995,
for estimates as of January 1, 1993, January 1, 1994, and January 1, 1995,
respectively, to be included in the section "Supplemental Information to
Consolidated Financial Statements - Oil and Gas Producing Activities" in the
Company's Annual Report on Form 10-K for the year ended December 31, 1994, to be
filed with the Securities and Exchange Commission on or about March 22, 1995. We
also consent to the inclusion of our letter report, dated January 13, 1995,
addressed to the Company as Exhibit (23.2) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1994, to be filed with the Securities
and Exchange Commission. Additionally, we hereby consent to the incorporation by
reference of such references to our firm and to our opinions included in the
Company's Form 10-K in the Company's previously filed Registration Statement
nos. 33-42620, 33-48358, 33-52201, and 33-58103.
Very truly yours,
DeGOLYER and MacNAUGHTON
EXHIBIT 23.2
DeGolyer and MacNaughton
One Energy Square
Dallas, texas 75206
January 13, 1995
Enron Oil & Gas Company
1400 Smith Street
Houston, Texas 77002
Gentlemen:
Pursuant to your request, we have prepared estimates, as of January 1,
1995, of the proved oil, condensate, natural gas liquids, and natural gas
reserves of certain selected properties in the United States and Canada owned by
Enron Oil & Gas Company, hereinafter referred to as "Enron." The properties
consist of working interests located in the states of New Mexico, Texas, Utah,
and Wyoming and in the offshore waters of Texas in the United States and in the
province of Saskatchewan in Canada. Our estimates are reported in detail in our
"Report as of January 1, 1995 on Proved Reserves of Certain Properties in the
United States owned by Enron Oil & Gas Company - Selected Properties" and our
"Report as of January 1, 1995 on Proved Reserves of Certain Properties in Canada
owned by Enron Oil & Gas Company - Selected Properties," hereinafter
collectively referred to as the "Reports." We also have reviewed information
provided to us by Enron that it represents to be Enron estimates of the
reserves, as of January 1, 1995, for the same properties as those included in
the Reports.
Proved reserves estimated by us and referred to herein are judged to be
economically producible in future years from known reservoirs under existing
economic and operating conditions and assuming continuation of current
regulatory practices using conventional production methods and equipment. Proved
reserves are defined as those that have been proved to a high degree of
certainty by reason of actual completion, successful testing, or in certain
cases by adequate core analyses and electrical-log interpretation when the
producing characteristics of the formation are known from nearby fields. These
reserves are defined areally by reasonable geological interpretation of
structure and known continuity of oil- or gas-saturated
1
material. This definition is in agreement with the definition of proved reserves
prescribed by the Securities and Exchange Commission.
Enron represents that its estimates of the proved reserves, as of January
1, 1995, net to its leasehold interests in the properties included in the
Reports are as follows:
Oil, Condensate, and
Natural Gas Liquids Natural Gas Net Equivalent
(thousand barrels) (million cubic feet) Million Cubic Feet
- -------------------- -------------------- ------------------
11,280 1,200,900 1,268,580
Note: Net equivalent million cubic feet is based on 1 barrel of oil, condensate,
or natural gas liquids being equivalent to 6,000 cubic feet of gas.
Enron has advised us, and we have assumed, that its estimates of proved
oil, condensate, natural gas liquids, and natural gas reserves are in accordance
with the rules and regulations of the Securities and Exchange Commission.
Proved reserves estimated by us for the properties included in the
Reports, as of January 1, 1995, are as follows:
Oil, Condensate, and
Natural Gas Liquids Natural Gas Net Equivalent
(thousand barrels) (million cubic feet) Million Cubic Feet
- ------------------- -------------------- ------------------
11,721 1,230,633 1,300,959
Note: Net equivalent million cubic feet is based on 1 barrel of oil, condensate,
or natural gas liquids being equivalent to 6,000 cubic feet of gas.
In making a comparison of the detailed estimates prepared by us and by
Enron of the properties involved, we have found differences, both positive and
negative, in reserve estimates for individual properties. These differences
appear to be compensating to a great extent when considering the reserves of
Enron in the properties included in our reports, resulting in overall
differences not being substantial. It is our opinion that the reserves estimates
prepared by Enron on the properties reviewed by us and referred to above, when
compared on the basis of net
2
equivalent million cubic feet of gas, do not differ materially from those
prepared by us.
Submitted,
/S/ DeGOLYER and MacNAUGHTON
DeGOLYER and MacNAUGHTON
[SEAL] /S/ Vernon E. Pringle, Jr., P.E.
VERNON E. PRINGLE, JR., P.E.
Senior Vice President
DeGolyer and MacNaughton
3
EXHIBIT 23.3
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our report on the consolidated financial statements of Enron Oil & Gas
Company and subsidiaries included in this Form 10-K, into the Company's
previously filed Registration Statement File Nos. 33-42620, 33-48358, 33-52201
and 33-58103.
ARTHUR ANDERSEN LLP
Houston, Texas
March 22, 1995
EXHIBIT 24
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS:
The undersigned, as a director of Enron Oil & Gas Company, a Delaware
corporation (the "Company"), in connection with the filing by the Company of its
Annual Report on Form 10-K for the year ended December 31, 1994, with the
Securities and Exchange Commission, does hereby make, constitute and appoint
Forrest E. Hoglund, Walter C. Wilson and Angus H. Davis, each of them with full
power (any one of them acting alone), as true and lawful attorneys-in-fact and
agents, for and on behalf and in the name, place and stead of the undersigned,
in any and all capacities, to sign, execute and file such Annual Report on Form
10-K, together with any amendments or supplements thereto, with all exhibits and
any and all documents required to be filed with respect thereto with any
regulatory authority, granting unto each above-mentioned individual the full
power and authority to do and perform each and every act and action requisite
and necessary to be done in and about the premises in order to effectuate the
same as fully to all intents and purposes as the undersigned might or could do
if personally present, hereby ratifying and confirming all the said
attorneys-in-fact and agents, or any of them, may lawfully do or cause to be
done by virtue hereof.
IN WITNESS WHEREOF, the undersigned has hereto set his hand this 14th day
of February, 1995.
FRED C. ACKMAN
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS:
The undersigned, as a director of Enron Oil & Gas Company, a Delaware
corporation (the "Company"), in connection with the filing by the Company of its
Annual Report on Form 10-K for the year ended December 31, 1994, with the
Securities and Exchange Commission, does hereby make, constitute and appoint
Forrest E. Hoglund, Walter C. Wilson and Angus H. Davis, each of them with full
power (any one of them acting alone), as true and lawful attorneys-in-fact and
agents, for and on behalf and in the name, place and stead of the undersigned,
in any and all capacities, to sign, execute and file such Annual Report on Form
10-K, together with any amendments or supplements thereto, with all exhibits and
any and all documents required to be filed with respect thereto with any
regulatory authority, granting unto each above-mentioned individual the full
power and authority to do and perform each and every act and action requisite
and necessary to be done in and about the premises in order to effectuate the
same as fully to all intents and purposes as the undersigned might or could do
if personally present, hereby ratifying and confirming all the said
attorneys-in-fact and agents, or any of them, may lawfully do or cause to be
done by virtue hereof.
IN WITNESS WHEREOF, the undersigned has hereto set his hand this 14th day
of February, 1995.
EDWARD RANDALL, III
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS:
The undersigned, as a director of Enron Oil & Gas Company, a Delaware
corporation (the "Company"), in connection with the filing by the Company of its
Annual Report on Form 10-K for the year ended December 31, 1994, with the
Securities and Exchange Commission, does hereby make, constitute and appoint
Forrest E. Hoglund, Walter C. Wilson and Angus H. Davis, each of them with full
power (any one of them acting alone), as true and lawful attorneys-in-fact and
agents, for and on behalf and in the name, place and stead of the undersigned,
in any and all capacities, to sign, execute and file such Annual Report on Form
10-K, together with any amendments or supplements thereto, with all exhibits and
any and all documents required to be filed with respect thereto with any
regulatory authority, granting unto each above-mentioned individual the full
power and authority to do and perform each and every act and action requisite
and necessary to be done in and about the premises in order to effectuate the
same as fully to all intents and purposes as the undersigned might or could do
if personally present, hereby ratifying and confirming all the said
attorneys-in-fact and agents, or any of them, may lawfully do or cause to be
done by virtue hereof.
IN WITNESS WHEREOF, the undersigned has hereto set his hand this 14th day
of February, 1995.
KENNETH L. LAY
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS:
The undersigned, as a director of Enron Oil & Gas Company, a Delaware
corporation (the "Company"), in connection with the filing by the Company of its
Annual Report on Form 10-K for the year ended December 31, 1994, with the
Securities and Exchange Commission, does hereby make, constitute and appoint
Forrest E. Hoglund, Walter C. Wilson and Angus H. Davis, each of them with full
power (any one of them acting alone), as true and lawful attorneys-in-fact and
agents, for and on behalf and in the name, place and stead of the undersigned,
in any and all capacities, to sign, execute and file such Annual Report on Form
10-K, together with any amendments or supplements thereto, with all exhibits and
any and all documents required to be filed with respect thereto with any
regulatory authority, granting unto each above-mentioned individual the full
power and authority to do and perform each and every act and action requisite
and necessary to be done in and about the premises in order to effectuate the
same as fully to all intents and purposes as the undersigned might or could do
if personally present, hereby ratifying and confirming all the said
attorneys-in-fact and agents, or any of them, may lawfully do or cause to be
done by virtue hereof.
IN WITNESS WHEREOF, the undersigned has hereto set his hand this 14th day
of February, 1995.
RICHARD D. KINDER
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
The Schedule contains summary financial information extracted from the Company's
unaudited condensed consolidated financial statements for the year ended
December 31, 1994 and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<MULTIPLIER> 1000
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<CASH> 5,810
<SECURITIES> 0
<RECEIVABLES> 126,133
<ALLOWANCES> 0
<INVENTORY> 15,731
<CURRENT-ASSETS> 156,418
<PP&E> 3,015,435
<DEPRECIATION> (1,330,624)
<TOTAL-ASSETS> 1,861,867
<CURRENT-LIABILITIES> 164,601
<BONDS> 0
<COMMON> 201,600
0
0
<OTHER-SE> 841,819
<TOTAL-LIABILITY-AND-EQUITY> 1,861,867
<SALES> 566,231
<TOTAL-REVENUES> 625,823
<CGS> 0
<TOTAL-COSTS> 466,182
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 8,489
<INCOME-PRETAX> 153,935
<INCOME-TAX> 5,937
<INCOME-CONTINUING> 147,998
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 147,998
<EPS-PRIMARY> 0.93
<EPS-DILUTED> 0
</TABLE>
