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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, 1996
[ ] 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)
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DELAWARE 47-0684736
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
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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:
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NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock, $.01 par value New York Stock Exchange
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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 nonaffiliates of the
registrant, based on the closing sale price in the daily composite list for
transactions on the New York Stock Exchange on February 28, 1997 was
$1,461,482,413. As of March 1, 1997, there were 158,792,746 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 6, 1997 Annual Meeting of Shareholders
("Proxy Statement") are incorporated in Part III by reference.
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TABLE OF CONTENTS
PART I
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PAGE
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Item 1. Business
General..................................................... 1
Business Segments........................................... 2
Exploration and Production.................................. 2
Marketing................................................... 5
Wellhead Volumes and Prices, and Lease and Well Expenses.... 7
Other Natural Gas Marketing Volumes and Prices.............. 8
Competition................................................. 8
Regulation.................................................. 8
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........................................... 17
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......................................... 18
Item 6. Selected Financial Data..................................... 19
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of
Operations.................................................. 20
Item 8. Financial Statements and Supplementary Data................. 26
Item 9. Disagreements on Accounting and Financial Disclosure........ 26
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 27
Item 11. Executive Compensation...................................... 27
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 27
Item 13. Certain Relationships and Related Transactions.............. 27
PART IV
Item 14. Financial Statements and Financial Statement Schedule,
Exhibits and Reports on Form 8-K............................ 27
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PART I
ITEM 1. BUSINESS
GENERAL
Enron Oil & Gas Company (the "Company"), a Delaware corporation organized
in 1985, 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, 1996, the Company's estimated net proved
natural gas reserves were 3,675 billion cubic feet ("Bcf"), including 1,180 Bcf
of proved undeveloped methane reserves in the Big Piney deep Paleozoic
formations, and estimated net proved crude oil, condensate and natural gas
liquids reserves were 55 million barrels ("MMBbl"). (See "Supplemental
Information to Consolidated Financial Statements"). At such date, approximately
74% of the Company's reserves (on a natural gas equivalent basis) was located in
the United States, 9% in Canada, 10% in Trinidad and 7% in India. As of December
31, 1996, the Company employed approximately 800 persons.
The Company's business strategy is to maximize the rate of return on
investment of capital by controlling both operating and capital costs and
enhancing the certainty of future revenues through the selective use of various
marketing mechanisms. This strategy enhances the generation of both income and
cash flow from each unit of production and allows for the growth of production
on a cost-effective basis by optimizing the reinvestment of cash flow. The
Company refocused its 1996 drilling activity toward natural gas deliverability
in addition to natural gas reserve enhancement and crude oil exploitation in the
United States in response to the higher United States natural gas prices in
recent periods. The Company also is focusing on the cost-effective utilization
of advances in technology associated with gathering, processing and
interpretation of 3-D seismic data, developing reservoir simulation models and
drilling operations through the use of new and/or improved drill bits, mud
motors, mud additives, formation logging techniques and reservoir fracturing
methods. These advanced technologies are used, as appropriate, throughout the
Company to reduce the risks associated with all aspects of oil and gas reserve
exploration, exploitation and development. The Company implements its strategy
by emphasizing the drilling of internally generated prospects in order to find
and develop low cost reserves. Achieving and maintaining the lowest possible
operating cost structure are also important goals in the implementation of the
Company's strategy. Consistent with the Company's desire to optimize the use of
its assets, it also maintains a strategy of selling selected oil and gas
properties that for various reasons may no longer fit into future operating
plans, or which 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 substantial level of proceeds related
to such sales which proceeds are available for general corporate use.
Enron Corp. currently owns 53% of the outstanding shares of the 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 interests 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
predecessors and 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.
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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 AMERICA OPERATIONS
United States. The Company's eight principal United States producing areas
are the Big Piney area of Wyoming, South Texas area, East Texas area, Offshore
Gulf of Mexico area, Canyon/Strawn Trend area of West Texas, Sand Tank and
Pitchfork Ranch areas of New Mexico and Vernal area of Utah. Properties in these
areas comprised approximately 79% of the Company's United States reserves (on a
natural gas equivalent basis) and 81% of the Company's United States net natural
gas deliverability as of December 31, 1996 and are substantially all operated by
the Company.
The Company's other United States natural gas and crude oil producing
properties are located primarily in other areas of Texas, Utah, New Mexico,
Oklahoma, Mississippi, California and Kansas.
At December 31, 1996, 94% of the Company's proved United States reserves,
including the reserves in the Big Piney deep Paleozoic formations (on a natural
gas equivalent basis), was natural gas and 6% was crude oil, condensate and
natural gas liquids. A substantial portion of the Company's United States
natural gas reserves is in long-lived fields with well-established production
histories. The Company believes that opportunities exist 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 248,400 net acres under lease directly within field limits. The
Company operates approximately 560 natural gas wells in this area in which it
owns an 84% average working interest. Deliveries from the area net to the
Company averaged 112 million cubic feet ("MMcf") per day of natural gas and 2.4
thousand barrels ("MBbl") per day of crude oil, condensate, and natural gas
liquids in 1996. At December 31, 1996, natural gas deliverability net to the
Company was approximately 130 MMcf per day.
The current principal producing intervals are the Frontier and Mesaverde
formations. The Frontier formation, which occurs at 6,500 to 10,000 feet,
contains approximately 65% of the Company's Big Piney proved developed reserves.
The Company drilled 55 wells in the Big Piney area in 1996 and anticipates an
active drilling program will continue for several years.
In 1995, the Company recorded as proved undeveloped reserves 1,180 Bcf of
methane contained, along with high concentrations of carbon dioxide as well as
small amounts of other gaseous substances, in the deep Wyoming Paleozoic
formation located under acreage leased by the Company and held by production in
the Big Piney area. The Company is actively pursuing the consummation of a
market or markets from several different potential sources to facilitate
realizing the value of these reserves.
South Texas Area. The Company's activities in South Texas are focused in
the Lobo, Wilcox and Frio producing horizons. The principal areas of activity
are in the Lobo and Wilcox Trends which occur primarily in Webb, Zapata and
Starr counties.
Effective October 1, 1996, the Company acquired all of the South Texas Lobo
Trend properties of another operator. The acquisition also included producing
properties in Atascosa and Kleberg counties. Net production from the acquired
properties as of December 31, 1996 was 23 million cubic feet of natural gas
equivalent per day, located on more than 65,000 net leasehold and mineral fee
acres. The Company now operates approximately 330 wells in the South Texas area.
Production is primarily from the Upper Wilcox and Lobo sands at depths ranging
from 5,000 to 13,000 feet. The Company has approximately 200,000 net
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leasehold acres and more than 40,000 net mineral fee acres in this area. Natural
gas deliveries net to the Company averaged approximately 149 MMcf per day in
1996. At December 31, 1996, natural gas deliverability from this area net to the
Company was approximately 180 MMcf per day. The Company drilled 50 wells in the
South Texas area in 1996 and participated in sizable 3-D seismic acquisition
efforts. An active drilling program in this area is anticipated to continue for
several years.
East Texas Area. The Company's activities in the East Texas area are
primarily in the Carthage field, located in Panola County, and the North Milton
field, located in northern Harris County.
The Carthage field production is primarily from the Cotton Valley, Travis
Peak and Pettit formations. The Company holds approximately 17,900 net acres
under lease with an average 77% working interest in this area. The Company
drilled 52 wells in the East Texas area in 1996 and anticipates an active
drilling program will continue for several years. The Company has continued its
activity in the North Milton field where it now operates 22 wells and holds a
100% working interest in the acreage. Further drilling is planned for 1997. At
December 31, 1996, deliverability from the East Texas area was approximately 50
MMcf per day of natural gas with 1.8 MBbl per day of crude oil, condensate and
natural gas liquids both net to the Company.
Offshore Gulf of Mexico Area. During 1996, the Company participated in four
lease sales (two Texas State and two Federal) offering leases in the Gulf of
Mexico and acquired approximately 127,700 net acres (47 leases). Such leases
acquired included the Company's first acreage in the deeper waters (600 feet to
2,700 feet water depths) in the Gulf of Mexico consisting of seven leases in the
Garden Banks and East Breaks areas. At December 31, 1996, the Company held an
interest in 184 blocks in the Offshore Gulf of Mexico area totaling
approximately 504,000 net acres. Of the 184 blocks, 132 are operated by the
Company. These interests are located predominantly in federal waters offshore
Texas and Louisiana. Natural gas deliveries from this area averaged 125 MMcf per
day during 1996 net to the Company. A substantial portion of such deliveries was
from interests in the Matagorda trend with significant volumes also coming from
the Mustang Island area. The Company is currently evaluating development plans
for Eugene Island Block 135, and anticipates initial production to begin flowing
from this discovery and subsequent development wells in the third quarter of
1997. Deliverability from this area at December 31, 1996 was approximately 130
MMcf per day net to the Company sourced principally as noted above. The Company
has maintained an active drilling program in the Offshore Gulf of Mexico area
during 1996 and anticipates a similar program to continue for several years.
Canyon/Strawn Trend Area. The Company's activities in this area have been
concentrated in Crockett, Terrell and Val Verde Counties, Texas where the
Company drilled 51 natural gas wells during 1996. The Company holds
approximately 57,000 net acres and now operates approximately 170 natural gas
wells in this area in which it owns a 75% average working interest. Production
is from the Canyon sands and Strawn limestone at depths from 5,500 to 12,500
feet. During April 1996, the Company sold 311 Sutton County wells with daily
production of 15 MMcf per day. At December 31, 1996, natural gas deliverability
net to the Company was approximately 36 MMcf per day. The Company plans an
aggressive program on several new prospects, including the potential for some
horizontal drilling, in 1997.
Sand Tank Area. The Sand Tank area located in Eddy County, New Mexico
produces from the Chester, Morrow, and Atoko formations. In 1996, the Company
acquired 85 square miles of 3-D seismic and drilled seven wells, adding natural
gas deliverability of 16 MMcf per day. The Company holds 11,500 net acres and
has an average working interest of approximately 60%. Several wells are planned
in 1997 for this stacked-pay area.
Pitchfork Ranch Area. The Pitchfork Ranch area located in Lea County, New
Mexico, produces primarily from the Bone Spring, Atoka and Morrow formations. In
1996, deliveries net to the Company averaged 24 MMcf per day of natural gas and
approximately 2.3 MBbl per day of crude oil, condensate and natural gas liquids.
At December 31, 1996, deliverability net to the Company was approximately 21
MMcf per day of natural gas and 2.2 MBbl per day of crude oil, condensate and
natural gas liquids. The Company holds approximately 36,000 net acres and is
continuing to interpret a 3-D seismic survey shot over this entire area. The
Company expects to maintain a drilling program in this area.
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Vernal Area. In the Vernal area, located primarily in Uintah County, Utah,
the Company operates approximately 220 producing wells and presently controls
approximately 73,400 net acres. In 1996, natural gas deliveries net to the
Company from the Vernal area averaged 20 MMcf per day which also represents
deliverability at December 31, 1996. Production is from the Green River and
Wasatch formations located at depths between 4,500 and 8,000 feet. The Company
has an average working interest of approximately 60%. Numerous drilling
opportunities will be available in this area for several years.
Canada. The Company is engaged in the exploration for and the development,
production and marketing 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 four major areas. The Sandhills field in southwestern
Saskatchewan is the largest single producing area where 70 wells were drilled in
1996 resulting in deliverability net to the Company from the field of
approximately 37 MMcf per day at December 31, 1996. Canadian natural gas
deliverability net to the Company at December 31, 1996 was approximately 102
MMcf per day, and the Company held approximately 321,000 net undeveloped acres
in Canada. The Company expects to maintain an active drilling program for
several years.
OUTSIDE NORTH AMERICA OPERATIONS
The Company has producing 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 proved reserves and
production outside of North America at year end 1996.
Trinidad. In November 1992, the Company was awarded a 95% working interest
concession in the South East Coast Consortium ("SECC") Block offshore Trinidad,
encompassing three undeveloped fields, previously held by three government-owned
energy companies. The Kiskadee field has been developed, the Ibis field is under
development and the Oil Bird field is anticipated to be developed over the next
several years. Existing surplus processing and transportation capacity at the
Pelican field facilities owned and operated by Trinidad and Tobago
government-owned 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. In 1996,
deliveries net to the Company averaged 124 MMcf per day of natural gas and 5.2
MBbl per day of crude oil and condensate. At December 31, 1996, natural gas
deliverability net to the Company was approximately 182 MMcf per day and the
Company held approximately 168,000 net undeveloped acres in Trinidad.
In 1995, the Company was awarded the right to develop the modified U(a)
block adjacent to the SECC Block. A production sharing contract was signed with
the Government of Trinidad and Tobago in 1996. A 3-D seismic data gathering
project has been completed and is being evaluated. Initial drilling may occur in
late 1997 or early 1998.
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
retained a 40% working interest. The 363,000 acre Tapti Block contains two major
proved natural gas accumulations delineated by 22 expendable exploration wells
that have been plugged. The Company has initiated a development plan for the
Tapti Block accumulations and expects production to begin during the first half
of 1997. The 106,000 acre Panna Block and the 192,000 acre Mukta Block are
partially developed with 24 wells producing from five production platforms
located in the Panna and Mukta fields. The fields were producing approximately
3.3 MBbl per day of crude oil net to the Company as of December 31, 1996; all
associated natural gas is currently 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.
Venezuela. The Company was awarded exploration, exploitation and
development rights for a block offshore the eastern state of Soucre, Venezuela
in early 1996. The Company signed agreements with the government of Venezuela
and partners associated with a concession awarded in the Gulf of Paria East. The
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Company holds an initial 90 percent working interest in the joint venture. A 3-D
seismic data gathering project is currently underway and initial drilling is
anticipated in 1998.
Other International. The Company continues to evaluate other selected
conventional natural gas and crude oil opportunities outside North America by
pursuing other exploitation opportunities in countries where indigenous natural
gas and crude oil reserves have been identified, particularly where synergies in
natural gas transportation, processing and power generation can be optimized
with other Enron Corp. affiliated companies. In early 1995, the Company, an
Enron Corp. affiliate 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 a block within the North
Dome Field. The Company and the Enron Corp. affiliate may jointly hold up to a
35% equity interest in the project. In June 1996, the Company signed a
cooperative agreement with the Chinese National Petroleum Corporation ("CNPC")
to evaluate the potential for increasing production of crude oil in the Sichuan
Basin of the People's Republic of China. If successful, the project could
culminate in a joint development agreement with CNPC covering the Chuanzhong
Block. The Company has also completed the extension and enhancement of an
existing Memorandum of Understanding with Uzbekneftigaz covering the pursuit of
marketing opportunities for proven hydrocarbon reserves in eleven fields in the
Surhandarya and Bukhara regions of Uzbekistan as well as the fields joint
venture development. The Company is also participating in discussions concerning
the potential for conventional crude oil and natural gas development
opportunities in Mozambique and Algeria, as well as other opportunities in
Trinidad, India and Venezuela.
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
Australia and the San Jiao area and Hedong Basin in China.
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 annual
escalations. Under terms of the production sharing contract, natural gas volumes
in India are to be sold to a nominee of the Government of India at a price
linked to a basket of world market fuel oil quotations with floor and ceiling
limits. Approximately 20% of the Company's wellhead natural gas production is
currently being sold to pipeline and marketing subsidiaries of Enron Corp. The
Company believes that the terms of its transactions and agreements with Enron
Corp. are and intends that future such transactions and agreements will be at
least as favorable to the Company as could be obtained from third parties.
Substantially all of the Company's wellhead crude oil and condensate is
sold under various terms and arrangements at market responsive prices.
Approximately 30% of the Company's wellhead crude oil and condensate production
is currently being sold to affiliated companies.
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 the Company and EOGM utilize other short and long-term
hedging and trading mechanisms including sales and purchases utilizing
NYMEX-related commodity market transactions. These marketing activities have
provided an effective balance in managing a portion of the Company's exposure to
commodity price risks for both natural gas and crude oil and condensate wellhead
prices. (See "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Capital Resources and Liquidity - Hedging
Transactions.")
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In September 1992, the Company sold a volumetric production payment for
$326.8 million to a limited partnership. (See "Management's Discussion and
Analysis of Financial Condition and Capital Resources and Liquidity - Sale of
Volumetric Production Payment.")
In March 1995, in a series of transactions with Enron Corp., the Company
exchanged all of its fuel supply and purchase contracts and related price swap
agreements associated with a Texas City cogeneration plant (the "Cogen
Contracts") for certain natural gas price swap agreements (the "Swap
Agreements") of equivalent value. As a result of the transactions, the Company
was relieved of all performance obligations associated with the Cogen Contracts.
The Company will realize net operating revenues and receive corresponding cash
payments of approximately $91 million during the period extending through
December 31, 1999, under the terms of the Swap Agreements. The estimated fair
value of the Swap Agreements was approximately $81 million at the date the Swap
Agreements were received. The net effect of this series of transactions has
resulted in increases in net operating revenues and cash receipts for the
Company during 1995 and 1996 of approximately $13 million and $7 million,
respectively, with offsetting decreases in 1998 and 1999 versus that anticipated
under the Cogen Contracts.
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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 Bbl of crude oil and condensate or natural gas liquids)
delivered during each of the three years in the period ended December 31, 1996:
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YEAR ENDED DECEMBER 31,
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1996 1995 1994
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VOLUMES (PER DAY)
Natural Gas (MMcf)
United States(1)....................................... 608 560 614
Canada................................................. 98 76 72
Trinidad............................................... 124 107 63
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Total............................................. 830 743 749
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Crude Oil and Condensate (MBbl)
United States.......................................... 9.2 9.1 8.0
Canada................................................. 2.4 2.4 2.0
Trinidad............................................... 5.2 5.1 2.5
India.................................................. 2.8 2.5 .1
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Total............................................. 19.6 19.1 12.6
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Natural Gas Liquids (MBbl)
United States.......................................... 1.3 1.0 .3
Canada................................................. 1.2 .4 .4
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Total............................................. 2.5 1.4 .7
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AVERAGE PRICES
Natural Gas ($/Mcf)
United States(2)....................................... $ 2.04 $ 1.39 $ 1.71
Canada................................................. 1.15 .97 1.42
Trinidad............................................... 1.00 .97 .93
Composite......................................... 1.78 1.29 1.62
Crude Oil and Condensate ($/Bbl)
United States.......................................... $21.88 $17.32 $16.06
Canada................................................. 18.01 16.22 14.05
Trinidad............................................... 19.76 16.07 15.50
India.................................................. 20.17 16.81 15.70
Composite......................................... 20.60 16.78 15.62
Natural Gas Liquids ($/Bbl)
United States.......................................... $14.67 $11.88 $12.45
Canada................................................. 9.14 9.74 8.45
Composite......................................... 11.99 11.31 9.90
LEASE AND WELL EXPENSES ($/MCFE)
United States............................................. $ .19 $ .19 $ .19
Canada.................................................... .34 .35 .34
Trinidad.................................................. .16 .15 .17
India..................................................... .99 1.25(3) .13(3)
Composite......................................... .22 .22 .20
</TABLE>
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(1) Includes 48 MMcf per day in 1996, 1995 and 1994 delivered under the terms of
a volumetric production payment agreement effective October 1, 1992, as
amended.
(2) Includes an average equivalent wellhead value of $1.17 per Mcf in 1996, $.80
per Mcf in 1995 and $1.27 per Mcf in 1994 for the volumes described in note
(1), net of transportation costs.
(3) Based on expense estimates for nine days of production for 1994. Expenses
for 1995 include certain nonrecurring startup costs.
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OTHER NATURAL GAS MARKETING VOLUMES AND PRICES
The following table sets forth certain information regarding the Company's
volumes of natural gas delivered under other marketing and volumetric production
payment arrangements, and resulting average per unit gross revenue and per unit
amortization of deferred revenues along with associated costs during each of the
three years in the period ended December 31, 1996. (See "Marketing" for a
discussion of other natural gas marketing arrangements and agreements).
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YEAR ENDED DECEMBER 31,
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1996 1995 1994
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Volume (MMcf per day)(1).................................... 285 264 324
Average Gross Revenue ($/Mcf)(2)............................ $2.24 $1.88 $2.38
Associated Costs ($/Mcf)(3)(4).............................. 2.07 1.51 2.06
----- ----- -----
Margin ($/Mcf).............................................. $ .17 $ .37 $ .32
===== ===== =====
</TABLE>
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(1) Includes 48 MMcf per day in 1996, 1995 and 1994 delivered under the terms of
a volumetric production payment agreement 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 ("MMBtu") in 1996, 1995 and 1994.
(3) Includes an average value of $2.12 per Mcf in 1996, $1.57 per Mcf in 1995
and $1.92 per Mcf in 1994, for the volumes detailed in note (1) including
average wellhead value and any transportation costs and exchange
differentials.
(4) Including transportation and exchange differentials.
COMPETITION
The Company actively competes for reserve acquisitions and
exploration/exploitation 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, such as natural gas from Canada.
REGULATION
United States 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.
United States 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
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.
8
<PAGE> 11
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.
Since 1985, the FERC has endeavored to make natural gas transportation more
accessible to natural gas buyers and sellers on an open and nondiscriminatory
basis. These efforts have significantly altered the marketing and pricing of
natural gas. Commencing in April 1992, the FERC issued Order Nos. 636, 636A and
636B ("Order No. 636"), which mandate a fundamental restructuring of interstate
natural gas pipeline sales and transportation services, including the
"unbundling" by interstate natural gas pipelines of the sales, transportation,
storage, and other components of their previously 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. 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. The FERC issued final orders
accepting most pipelines' Order No. 636 compliance filings, and has commenced a
series of one-year reviews of individual pipeline implementations of Order No.
636. Appeals are pending and 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 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 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 natural gas by the
Company, such as those of natural gas purchased from third parties, are now
jurisdictional sales subject to a blanket sales certificate issued by the FERC
under the NGA. 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.
The FERC has 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. 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,
9
<PAGE> 12
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 1995 enacted legislation that essentially requires gatherers to
provide open access, non-discriminatory service. In addition, the FERC has
reiterated 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 manner in which interstate
pipelines release transportation capacity under Order No. 636, and has announced
new policies concerning the use of alternative, non-cost based methods for
setting rates for interstate natural 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 FERC has also recently initiated a proceeding in which it intends to
evaluate its current regulatory treatment of pipeline facilities constructed in
offshore federal waters. The ultimate outcome of such proceeding cannot be
predicted at this time, but it is possible that it could result in more active
oversight by the FERC of such offshore facilities.
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 during 1994 and 1995, 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
10
<PAGE> 13
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.
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 may have 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.
Other 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 producing 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 53% of the outstanding shares
of common stock of the Company. Through its ability to elect all of the
directors of the Company, Enron Corp. has the ability to control all matters
relating to the management and policies 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. 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. The Company has filed a registration statement which would allow
Enron Corp. to sell from time to time up to 4.94 million shares of common stock
of the Company in secondary offerings of outstanding shares.
Effective December 14, 1995, the Company ceased to be included in the
consolidated federal income tax return filed by Enron Corp., and the tax
allocation agreement previously in effect between the Company and Enron Corp.
was terminated. In addition, effective December 14, 1995, the Company and Enron
Corp. entered into a new tax allocation agreement pursuant to which, among other
things, Enron Corp. agreed (in exchange for the payment of $13 million by the
Company) to be liable for, and indemnify the Company against, all U.S. federal
and state income taxes and certain foreign taxes imposed on the Company for
periods prior to the date Enron Corp. reduced its ownership in the Company to
less than 80%. The Company does not believe that the cessation of consolidated
tax reporting with Enron Corp., the termination of the tax allocation agreement
concurrent with deconsolidation and the signing of the new tax allocation
agreement with Enron Corp. will have a material adverse effect on its financial
condition or results of operations.
Contractual Arrangements. The Company entered into a Services Agreement
(the "Services Agreement") with Enron Corp. effective January 1, 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 approximately $7.5 million in 1996
and $7 million for 1995. The limit on cost for the allocated indirect services
provided by Enron Corp. to the Company will increase in subsequent years for
inflation and certain changes in the Company's allocation bases, but such
increase will not 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.
11
<PAGE> 14
In March 1995, in a series of transactions with Enron Corp., the Company
exchanged all of its fuel supply and purchase contracts and related price swap
agreements associated with a Texas City cogeneration plant (the "Cogen
Contracts") for certain natural gas price swap agreements (the "Swap
Agreements") of equivalent value. As a result of the transactions, the Company
was relieved of all performance obligations associated with the Cogen Contracts.
The Company will realize net operating revenues and receive corresponding cash
payments of approximately $91 million during the period extending through
December 31, 1999 under the terms of the Swap Agreements. The estimated fair
value of the Swap Agreements was approximately $81 million at the date the Swap
Agreements were received. The net effect of this series of transactions has
resulted in increases in net operating revenues and cash receipts for the
Company during 1995 and 1996 of approximately $13 million and $7 million,
respectively, with offsetting decreases in 1998 and 1999 versus that anticipated
under the Cogen Contracts.
Conflicts of Interest. The nature of the respective businesses of the
Company and Enron Corp. is such as to potentially give rise to conflicts of
interest between the 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., potential
acquisitions of businesses or crude oil and natural 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 crude oil and natural 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. provides or arranges
financing, including debt or equity financing, for exploration and production
companies that compete with the Company. In connection with such activities,
Enron Corp. may make investments in the debt or equity of such companies. In its
financing activities, Enron Corp. may make loans secured by crude oil and
natural gas properties or securities of crude oil and natural gas companies, may
acquire production payments or may receive interests in crude oil and natural
gas properties as equity components of lending transactions. As a result of its
lending activities, Enron Corp. may also acquire crude oil and natural 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. 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.
In connection with the finance and trading business of Enron Capital &
Trade Resources Corp. ("ECT"), a wholly-owned subsidiary of Enron Corp.,
affiliates of ECT may make investments in the debt or equity of companies
engaged in the exploration for, and the development, production and marketing
of, natural gas and crude oil. Conflicts may arise between these companies and
the Company, and Enron Corp. will be required to resolve such conflicts in a
manner that is consistent with its fiduciary and contractual duties to other
investors in these companies and its fiduciary duties to the Company.
The Company and Enron Corp. have in the past entered into material
intercompany transactions and agreements incident to their respective
businesses, and they may be expected to enter into such transactions and
agreements in the future. Such transactions and agreements have related to,
among other things, the purchase and sale of natural gas and crude oil, 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. have been at least as favorable to
the Company as could be obtained from third parties, and the
12
<PAGE> 15
Company intends that the terms of any future transactions and agreements between
the Company and Enron Corp. 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 or natural gas liquids. During recent periods,
domestic natural gas has been priced significantly below parity with crude oil
and condensate based on the energy equivalency of, and differences in
transportation and processing costs associated with, the respective products
although that relationship improved during 1996. 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 be resolved 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 a decrease in average wellhead natural gas prices realized by the
Company of 13% from 1993 to 1994 and 20% from 1994 to 1995, the average North
America wellhead natural gas price received by the Company increased 43% from
1995 to 1996. Wellhead natural gas volumes from Trinidad are sold at prices that
are based on a fixed schedule with periodic escalations. Natural gas deliveries
in India are scheduled to commence in early 1997 and under the terms of the
Production Sharing Contract, the price of such deliveries, when initiated, is to
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 various terms and arrangements at market responsive prices. Crude oil
and condensate prices also have fluctuated during the last three years. 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 from time to
time engages in certain price risk management activities to hedge commodity
prices associated with a portion of the Company's sales and purchases of natural
gas and crude oil. (See "Management's Discussion and Analysis of Financial
Condition and Results of Operations").
Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption. United
States federal 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 after
November 5, 1990 and 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 (similarly
adjusted). Under this formula, the commencement of phaseout would be triggered
if the average price for crude oil rose above approximately $46 per barrel in
current dollars. Significant benefits from the tax credit have accrued and
continue to accrue 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.
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 severance
13
<PAGE> 16
taxes, subject to certain limitations. In 1995, the drilling qualification
period was extended in a modified and somewhat reduced form from September 1996
through August 2002. Consequently, new qualifying production will be added
prospectively to that presently qualified.
Other. All of the Company's natural gas and crude oil 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:
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Forrest E. Hoglund..................... 63 Chairman of the Board and Chief
Executive Officer; Director
Mark G. Papa........................... 50 President and President - North
American Operations
Dennis M. Ulak......................... 43 President - International Operations
Barry Hunsaker, Jr..................... 46 Senior Vice President and General
Counsel
Walter C. Wilson....................... 54 Senior Vice President and Chief
Financial Officer
Ben B. Boyd............................ 55 Vice President and Controller
</TABLE>
Forrest E. Hoglund joined the Company as Chairman of the Board, Chief
Executive Officer and Director in September 1987. He also served as President of
the Company from May 1990 until December 1996. Mr. Hoglund is an advisory
director of Texas Commerce Bancshares, Inc.
Mark G. Papa was elected President of the Company in December 1996 and 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.
Dennis M. Ulak has been President - International Operations since January
1996 with responsibility for activities outside North America. Mr. Ulak also
serves as President and Chief Operating Officer of Enron Oil & Gas
International, Inc. Mr. Ulak joined the Company in March 1987 as Senior Counsel
and was named Assistant General Counsel for international operations in February
1989, Assistant General Counsel in August 1990 and Vice President and General
Counsel in March 1992.
Barry Hunsaker, Jr. has been Senior Vice President and General Counsel
since he joined the Company in May 1996. Prior to joining the Company, Mr.
Hunsaker was a partner in the law firm of Vinson & Elkins L.L.P.
Walter C. Wilson joined the Company in November 1987 and has been Senior
Vice President and Chief Financial Officer since May 1991.
Ben B. Boyd joined the Company in March 1984 and has been Vice President
and Controller since March 1991.
14
<PAGE> 17
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 finding or acquiring additional reserves and the costs incurred in so
doing.
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
<PAGE> 18
Acreage. The following table summarizes the Company's developed and
undeveloped acreage at December 31, 1996. 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............... 13,030 8,341 658,089 654,054 671,119 662,395
Offshore Gulf of
Mexico................ 310,886 147,446 463,408 356,346 774,294 503,792
Texas.................... 285,706 198,579 232,543 205,704 518,249 404,283
Wyoming.................. 154,736 111,979 302,474 235,762 457,210 347,741
Oklahoma................. 176,218 94,222 68,270 58,944 244,488 153,166
New Mexico............... 72,278 35,328 82,962 48,611 155,240 83,939
Utah..................... 57,819 46,511 32,437 26,939 90,256 73,450
Kansas................... 10,418 8,875 15,974 14,670 26,392 23,545
Colorado................. 8,313 1,219 26,485 13,697 34,798 14,916
Mississippi.............. 1,942 1,853 12,695 12,498 14,637 14,351
Louisiana................ 6,054 5,909 1,360 1,295 7,414 7,204
Pennsylvania............. 1,443 962 6,749 4,538 8,192 5,500
Other.................... 5,385 3,352 7,719 5,741 13,104 9,093
--------- --------- ---------- --------- ---------- ---------
Total............ 1,104,228 664,576 1,911,165 1,638,799 3,015,393 2,303,375
Canada
Alberta.................. 365,797 174,932 196,936 157,639 562,733 332,571
Saskatchewan............. 180,623 156,548 184,504 160,013 365,127 316,561
Manitoba................. 11,371 9,622 4,213 3,333 15,584 12,955
British Columbia......... 656 164 - - 656 164
--------- --------- ---------- --------- ---------- ---------
Total Canada..... 558,447 341,266 385,653 320,985 944,100 662,251
Other International
Australia................ - - 7,680,000 3,840,000 7,680,000 3,840,000
China.................... - - 1,208,805 604,403 1,208,805 604,403
Venezuela................ - - 268,413 241,572 268,413 241,572
India.................... 98,300 29,490 564,307 169,292 662,607 198,782
Trinidad................. 4,200 3,990 171,459 167,716 175,659 171,706
France................... - - 168,032 168,032 168,032 168,032
United Kingdom........... - - 173,600 86,000 173,600 86,000
--------- --------- ---------- --------- ---------- ---------
Total Other
International... 102,500 33,480 10,234,616 5,277,015 10,337,116 5,310,495
--------- --------- ---------- --------- ---------- ---------
Total.......... 1,765,175 1,039,322 12,531,434 7,236,799 14,296,609 8,276,121
========= ========= ========== ========= ========== =========
</TABLE>
Producing Well Summary. The following table reflects the Company's
ownership in gas and oil wells located in Texas, the Gulf of Mexico, Oklahoma,
New Mexico, Utah, Wyoming, and various other states, Canada, Trinidad and India
at December 31, 1996. Gross gas and oil wells include 200 with multiple
completions.
<TABLE>
<CAPTION>
PRODUCTIVE WELLS
----------------
GROSS NET
------ ------
<S> <C> <C>
Gas......................................................... 5,021 3,427
Oil......................................................... 886 516
----- -----
Total............................................. 5,907 3,943
===== =====
</TABLE>
16
<PAGE> 19
Drilling and Acquisition Activities. During the years ended December 31,
1996, 1995 and 1994 the Company spent approximately $599 million, $514 million
and $494 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,
------------------------------------------------
1996 1995 1994
-------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
----- ------ ----- ------ ----- ------
<S> <C> <C> <C> <C> <C> <C>
Development Wells Completed
North America
Gas....................................... 396 325.04 334 251.06 554 430.73
Oil....................................... 80 57.46 69 55.16 45 34.67
Dry....................................... 80 68.77 61 49.21 54 43.65
--- ------ --- ------ --- ------
Total................................ 556 451.27 464 355.43 653 509.05
Outside North America
Gas....................................... - - 3 2.85 4 3.80
Oil....................................... 1 .30 3 2.85 - -
Dry....................................... - - 1 .95 - -
--- ------ --- ------ --- ------
Total................................ 1 .30 7 6.65 4 3.80
--- ------ --- ------ --- ------
Total Development............................ 557 451.57 471 362.08 657 512.85
--- ------ --- ------ --- ------
Exploratory Wells Completed
North America
Gas....................................... 14 10.36 5 4.13 22 17.70
Oil....................................... 1 .78 8 3.61 4 3.07
Dry....................................... 26 19.00 21 13.28 37 30.67
--- ------ --- ------ --- ------
Total................................ 41 30.14 34 21.02 63 51.44
Outside North America
Gas....................................... - - 6 4.90 - -
Oil....................................... - - - - - -
Dry....................................... 1 .50 - - - -
--- ------ --- ------ --- ------
Total................................ 1 .50 6 4.90 - -
--- ------ --- ------ --- ------
Total Exploratory............................ 42 30.64 40 25.92 63 51.44
--- ------ --- ------ --- ------
Total................................ 599 482.21 511 388.00 720 564.29
Wells in Progress at end of period............. 87 61.08 52 32.71 45 28.79
--- ------ --- ------ --- ------
Total................................ 686 543.29 563 420.71 765 593.08
=== ====== === ====== === ======
Wells Acquired
Gas....................................... 350 148.20* 277 101.70* 41 40.90*
Oil....................................... 5 .65 5 .46 60 38.99*
--- ------ --- ------ --- ------
Total................................ 355 148.85 282 102.16 101 79.89
=== ====== === ====== === ======
</TABLE>
- ---------------
* Includes the acquisition of additional interests in certain wells in which the
Company previously held an interest.
All of the Company's drilling activities are conducted on a contract basis
with independent drilling contractors. The Company owns no drilling equipment.
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.
17
<PAGE> 20
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 1996.
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
sales 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 First and Second Quarter 1994 sales prices and cash dividends per
share have been restated to reflect a two-for-one stock split on May 31, 1994.
<TABLE>
<CAPTION>
PRICE RANGE
---------------- CASH
HIGH LOW DIVIDENDS
------ ------ ---------
<S> <C> <C> <C>
1994
First Quarter......................................... $23.75 $19.31 $.03
Second Quarter........................................ 24.63 20.88 .03
Third Quarter......................................... 23.75 18.50 .03
Fourth Quarter........................................ 22.75 17.38 .03
1995
First Quarter......................................... $24.88 $17.13 $.03
Second Quarter........................................ 24.75 20.25 .03
Third Quarter......................................... 25.38 20.00 .03
Fourth Quarter........................................ 24.88 18.75 .03
1996
First Quarter......................................... $28.50 $22.38 $.03
Second Quarter........................................ 28.63 23.88 .03
Third Quarter......................................... 30.63 22.88 .03
Fourth Quarter........................................ 28.38 23.25 .03
</TABLE>
As of March 1, 1997, there were approximately 280 record holders of the
Company's common stock, including individual participants in security position
listings. There are an estimated 15,500 beneficial owners of the Company's
common stock, including shares held in street name.
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.
18
<PAGE> 21
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
STATEMENT OF INCOME DATA:
Net operating revenues....... $ 730,648 $ 648,702 $ 625,823 $ 581,020 $ 459,026
Operating expenses
Lease and well............. 76,618 69,463 60,384 59,344 49,406
Exploration................ 55,009 42,044 41,811 36,921 33,278
Dry hole................... 13,193 12,911 17,197 18,355 10,764
Impairment of unproved oil
and gas properties...... 21,226 23,715 24,936 20,467 15,136
Depreciation, depletion and
amortization............ 251,278 216,047 242,182 249,704 179,839
General and
administrative.......... 56,405 56,626 51,418 45,274 36,648
Taxes other than income.... 48,089 32,587 28,254 35,396 28,346
---------- ---------- ---------- ---------- ----------
Total.............. 521,818 453,393 466,182 465,461 353,417
---------- ---------- ---------- ---------- ----------
Operating income............. 208,830 195,309 159,641 115,559 105,609
Other income(expense), net
........................... (5,007) 669 2,783 6,635 (3,476)
Interest expense (net of
interest capitalized)...... 12,861 11,924 8,489 9,921 22,289
---------- ---------- ---------- ---------- ----------
Income before income taxes... 190,962 184,054 153,935 112,273 79,844
Income tax provision
(benefit)(1)............... 50,954(2) 41,936(3) 5,937(4) (25,752)(5) (17,736)
---------- ---------- ---------- ---------- ----------
Net income................... $ 140,008 $ 142,118 $ 147,998 $ 138,025 $ 97,580
========== ========== ========== ========== ==========
Earnings per share of common
stock(6)................... $ .88 $ .89 $ .93 $ .86 $ .63
========== ========== ========== ========== ==========
Average number of common
shares(6).................. 159,853 159,917 159,845 159,966 154,533
========== ========== ========== ========== ==========
</TABLE>
<TABLE>
<CAPTION>
AT DECEMBER 31,
------------------------------------------------------------------
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Oil and gas
properties - net........... $2,099,589 $1,881,545 $1,684,811 $1,546,045 $1,468,011
Total assets................. 2,458,353 2,147,258 1,861,867 1,811,162 1,731,012
Long-term debt
Affiliate.................. - 141,520 25,000 - -(7)
Other...................... 466,089 147,559 165,337 153,000 150,000(7)
Deferred revenue............. 56,383 205,453 184,183 227,528 301,395(7)
Shareholders' equity......... 1,265,090 1,163,659 1,043,419 933,073 826,986(7)
</TABLE>
- ---------------
(1) Includes benefits of approximately $16 million, $22 million, $36 million,
$65 million, and $43 million in 1996, 1995, 1994, 1993, and 1992,
respectively, relating to tight gas sand federal income tax credits.
(2) Includes a benefit of $9 million primarily associated with a reassessment of
deferred tax requirements and the successful resolution on audit of Canadian
income taxes for certain prior years.
(3) Includes a benefit of approximately $14 million associated with the
successful resolution on audit of federal income taxes for certain prior
years.
(4) 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
19
<PAGE> 22
from the reduction of the Company's deferred federal income tax liability
resulting from a reevaluation of deferred tax requirements.
(5) 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 noncash 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%.
(6) In May 1994, the Board of Directors declared a two-for-one split of the
common stock of the Company to be effected as a nontaxable 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.
(7) 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 $327 million used to
repay long-term debt and for other general corporate purposes.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following review of operations for each of the three years in the
period ended December 31, 1996 should be read in conjunction with the
consolidated financial statements of the Company and notes thereto beginning
with page F-1.
RESULTS OF OPERATIONS
Net Operating Revenues. Wellhead volume and price statistics for the
specified years were as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1996 1995 1994
------ ------ ------
<S> <C> <C> <C>
Natural Gas Volumes (MMcf per day)
North America(1)....................................... 706 636 686
Trinidad............................................... 124 107 63
------ ------ ------
Total.......................................... 830 743 749
====== ====== ======
Average Natural Gas Prices ($/Mcf)
North America(2)....................................... $ 1.92 $ 1.34 $ 1.68
Trinidad............................................... 1.00 .97 .93
Composite...................................... 1.78 1.29 1.62
Crude Oil/Condensate Volumes (MBbl per day)
North America.......................................... 11.6 11.5 10.0
Trinidad............................................... 5.2 5.1 2.5
India.................................................. 2.8 2.5 .1
------ ------ ------
Total.......................................... 19.6 19.1 12.6
====== ====== ======
Average Crude Oil/Condensate Prices ($/Bbl)
North America.......................................... $21.08 $17.09 $15.65
Trinidad............................................... 19.76 16.07 15.50
India.................................................. 20.17 16.81 15.70
Composite...................................... 20.60 16.78 15.62
</TABLE>
- ---------------
(1) Includes 48 MMcf per day in 1996, 1995 and 1994 delivered under the terms of
volumetric production payment agreement effective October 1, 1992, as
amended.
(2) Includes an average equivalent wellhead value of $1.17 per Mcf in 1996, $.80
per Mcf in 1995, and $1.27 per Mcf in 1994 for the volumes detailed in note
(1), net of transportation costs.
1996 compared to 1995. During 1996, net operating revenues increased $82
million to $731 million as compared to 1995.
20
<PAGE> 23
Average wellhead natural gas prices for 1996 were up approximately 38% from
the comparable period in 1995 increasing net operating revenues by approximately
$150 million. A 12% increase in wellhead natural gas volumes from 1995 added net
operating revenues of approximately $42 million. The increase in North America
wellhead natural gas volumes was primarily the result of eliminating voluntary
curtailments in the United States during 1996 due to significant increases
realized in average wellhead natural gas prices over the prices realized in
1995. Wellhead crude oil and condensate average prices increased 23% adding
approximately $27 million to net operating revenues over 1995. Wellhead crude
oil and condensate volumes increased 3% from the comparable period a year ago
adding approximately $4 million to net operating revenues.
Gain on the sales of reserves and related assets totaled $20 million in
1996 as compared to $63 million realized in 1995, reflecting a lower level of
sales activity.
Other marketing activities associated with sales and purchases of natural
gas, natural gas and crude oil price hedging and trading transactions, and
margins related to the volumetric production payment increased net operating
revenues by only $4 million during 1996, a decrease of approximately $101
million from 1995. This decrease primarily resulted from a lower revenue
increase on natural gas commodity price hedging activities utilizing
NYMEX-related commodity market transactions in 1996 of $13 million compared to a
$65 million revenue increase on similar transactions in 1995. The Company also
incurred a $13 million revenue reduction related to certain trading transactions
in 1996 compared to a $3 million revenue increase in 1995. A decrease in margins
associated with sales and purchases of natural gas and the volumetric production
payment reduced net revenues by approximately $17 million as compared to 1995 as
a result of the higher costs of natural gas delivered. Additionally, the Company
incurred a $13 million revenue reduction on its NYMEX-related crude oil price
swap transactions in 1996 compared to $2 million revenue increase in 1995.
1995 compared to 1994. During 1995, net operating revenues increased $23
million to $649 million as compared to 1994.
Average wellhead natural gas prices for 1995 were down approximately 20%
from 1994 reducing net operating revenues by approximately $89 million. In
addition, a decrease of 1% in wellhead natural gas volumes from 1994 reduced net
operating revenues by approximately $4 million. The Company voluntarily
curtailed its United States wellhead natural gas delivered volumes by an average
of approximately 105 MMcf per day during 1995 compared to approximately 70 MMcf
per day during 1994 due to significantly lower United States wellhead natural
gas prices. In addition, the impact of reduced drilling for U.S. natural gas
deliverability and the sales of oil and gas reserves and related assets (net of
purchases of similar assets) resulted in a reduction of approximately 20 MMcf
per day in U.S. delivered volumes for 1995 as compared to 1994. The Company
refocused its 1995 drilling activity away from natural gas deliverability and
toward natural gas reserve enhancement and crude oil exploitation in the United
States in response to the significant decline in United States wellhead natural
gas prices, in the latter part of 1994 and early 1995, resulting in the drilling
of 189 fewer net natural gas wells and 24 more net oil wells during 1995 as
compared to 1994. Wellhead crude oil and condensate average prices increased 7%
adding approximately $8 million to net operating revenues compared to 1994.
Crude oil and condensate wellhead volumes increased 52% adding approximately $37
million to net operating revenues compared to a year ago primarily reflecting
new production on stream offshore India and higher volumes offshore Trinidad and
in North America.
Gains on sales of reserves and related assets during 1995 increased $9
million to $63 million when compared to 1994.
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 volumetric production payment-related margins
added approximately $105 million to net operating revenues during 1995, an
increase of approximately $55 million from 1994. This increase primarily
resulted from a gain of $65 million on natural gas commodity price hedging
activities utilizing NYMEX-related commodity market transactions in 1995
compared to an $11 million gain during 1994. The average associated costs of
natural gas marketing, price swap and production exchange transactions,
including, where appropriate, average wellhead value, transportation costs and
exchange differentials, decreased $.55 per Mcf. The average price received for
these transactions decreased $.50 per
21
<PAGE> 24
Mcf. Related other natural gas marketing volumes decreased 19%. The reduction in
other natural gas marketing volumes and prices relates primarily to the exchange
of the fuel contracts noted below, lower wellhead market prices and decreased
other marketing activities. The reduction in other natural gas marketing
volumes, partially offset by the $.05 per Mcf margin increase, resulted in a
decrease in net operating revenues of approximately $2 million compared to 1994.
The Company realized an $11 million revenue increase in 1995 related to certain
natural gas commodity price swap transactions with an Enron Corp. affiliated
company that were designated for trading purposes in late 1994. This revenue
increase was partially offset by a revenue reduction of approximately $3 million
related to call option transactions and a revenue reduction of $6 million
associated with certain NYMEX-related natural gas commodity market transactions
that were marked-to-market due to loss of correlation between the NYMEX and the
wellhead natural gas prices that such transactions were designated to hedge.
(See "Capital Resources and Liquidity - Hedging Transactions.")
In March 1995, the Company exchanged existing fuel supply and purchase
contracts and related price swap agreements associated with a Texas City
cogeneration plant for certain natural gas price swap agreements of equivalent
value issued by an Enron Corp. affiliated company. As a result of these
transactions, the Company realized a $13 million increase in net operating
revenues in 1995 over the amount realized from the exchanged fuel supply and
purchase contracts in 1994 (See "Relationship Between the Company and Enron
Corp. - Contractual Agreements".)
Operating Expenses
1996 as compared to 1995. During 1996, operating expenses of $522 million
were approximately $69 million higher than the $453 million incurred in 1995.
Lease and well expenses increased approximately $7 million to $77 million
primarily due to continually expanding operations and increases in production
activity. Exploration expense increased approximately $13 million to $55 million
primarily due to increased exploratory drilling activities in North America.
Depreciation depletion and amortization ("DD&A") expense increased $35 million
to $251 million primarily reflecting increased production volumes and an
increase in the average DD&A rate from $.68 per thousand cubic feet equivalent
("Mcfe") in 1995 to $.71 per Mcfe in 1996 due to a change in volume mix by field
and geographic location and the impact of the adoption of SFAS No.
121 - "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of". Taxes other than income were approximately $16
million higher in 1996 as compared to 1995 primarily due to higher state
severance taxes associated with higher taxable wellhead revenues resulting from
higher United States volumes and average prices and lower applicable exploration
cost deductions in Trinidad in 1996.
The Company's total per unit operating costs increased in 1996 for lease
and well, DD&A, general and administrative, interest expense, and taxes other
than income by $.04 per Mcfe, averaging $1.26 per Mcfe during 1996 compared to
$1.22 per Mcfe during 1995. This increase is primarily attributable to increases
in per unit DD&A expense and taxes other than income partially offset by a
decrease in per unit general and administrative expense.
1995 as compared to 1994. During 1995, operating expenses of $453 million
were $13 million lower than the $466 million incurred in 1994.
Lease and well expenses increased approximately $9 million to $69 million
primarily due to expanded international operations including the initiation of
operations in India in late December 1994 and certain nonrecurring costs
incurred related to those operations during 1995. DD&A expense decreased $26
million to $216 million reflecting a decrease in the average DD&A rate from $.80
per Mcfe in 1994 to $.68 per Mcfe in 1995. The DD&A rate decrease is primarily
attributable to an overall decrease of $.09 per Mcfe in certain North America
DD&A rates and an increase in the proportion of production from international
operations with lower average DD&A rates than incurred in North America
operations. General and administrative expenses increased approximately $5
million to $57 million primarily due to expanded international activities. Taxes
other than income were $4 million higher in 1995 compared to 1994 primarily due
to higher production related taxes associated with new production in India in
1995.
22
<PAGE> 25
The Company reduced its total per unit operating costs for lease and well
expense, DD&A, general and administrative expense, interest expense, and taxes
other than income by $.07 per Mcfe, averaging $1.22 per Mcfe during 1995
compared to $1.29 per Mcfe in 1994. This decrease is primarily attributable to
the reduction in the average DD&A rate as noted above partially offset by slight
increases in per unit lease and well, general and administrative expenses, and
taxes other than income which increase reflects primarily lower volumes
associated with the curtailment of natural gas volumes in the U.S. due to the
reduction in wellhead natural gas prices.
Other Income (Expense). The 1996 $5 million net expense is primarily
comprised of miscellaneous financial reserves partially offset by interest
income.
Interest Expense. The increase in net interest expense of $1 million from
1995 to 1996 and of $3 million from 1994 to 1995 primarily reflects a higher
level of debt outstanding in each subsequent period. (See Note 3 to Consolidated
Financial Statements).
Income Taxes. Income tax provision increased $9 million for 1996 as
compared to 1995 primarily as a result of lower benefits associated with tight
gas sands federal income tax credits utilized in 1996 as compared to 1995. Tax
benefits associated with a reassessment of deferred tax requirements and the
successful resolution on audit of Canadian income taxes for certain prior years
of $9 million and other miscellaneous benefits in 1996 were essentially equal to
an unrelated $14 million benefit in 1995.
Income tax provision increased $36 million for 1995 as compared to 1994
primarily resulting from higher income before income taxes, higher foreign
income taxed at rates in excess of the U.S. rate and lower benefits associated
with tight gas sand federal income tax credits utilized in 1995 as compared to
1994 partially offset by a $14 million benefit associated with the successful
resolution on audit of federal income taxes for certain prior years.
CAPITAL RESOURCES AND LIQUIDITY
Cash Flow. The primary sources of cash for the Company during the
three-year period ended December 31, 1996 included funds generated from
operations, proceeds from the sales of selected oil and gas reserves and related
assets, proceeds from new borrowings and proceeds from the sales of treasury
stock in conjunction with the exercise of stock options. Primary cash outflows
included funds used in operations, exploration and development expenditures,
common stock repurchases, dividends paid to Company shareholders 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 income 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 and to include proceeds from sales of reserves and related
assets. The Company generated discretionary cash flow of approximately $543
million in 1996, $525 million in 1995 and $514 million in 1994.
Net operating cash flows of $365 million for 1996 increased approximately
$30 million as compared to 1995 primarily due to higher production related net
operating revenues net of cash operating expenses partially offset by higher
current federal income taxes and increased working capital requirements
primarily associated with higher accounts receivable due to higher wellhead
prices and an increase in international activities, net of higher accounts
payable, at year end 1996. Net operating cash flows of $335 million for 1995
decreased approximately $47 million as compared to 1994 primarily reflecting
higher accounts receivable arising from international activities, and the
settlement in December 1995 of January 1996 NYMEX-related natural gas commodity
positions. 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 net operating cash
flows.
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
23
<PAGE> 26
Note 4 to Consolidated Financial Statements). Under the terms of the production
payment agreements, the Company conveyed a real property interest in
approximately 124 Bcfe (136 TBtu) 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 TBtu) versus approximately 87.9 Bcfe (96.4 TBtu) remaining to be delivered
under the original agreement. 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.
Exploration and Development Expenditures. The table below sets out
components of actual exploration and development expenditures for the years
ended December 31, 1996, 1995 and 1994, along with those budgeted for the year
1997.
<TABLE>
<CAPTION>
ACTUAL
-------------------- BUDGETED
EXPENDITURE CATEGORY 1996 1995 1994 1997
-------------------- ---- ---- ---- --------
(IN MILLIONS)
<S> <C> <C> <C> <C>
Capital Drilling and Facilities..................... $408 $303 $342
Leasehold Acquisitions............................ 45 22 52
Producing Property Acquisitions................... 69 127 34
Capitalized Interest and Other.................... 18 12 14
---- ---- ----
Total..................................... 540 464 442
Exploration Expenses................................ 68 55 59
---- ---- ----
Total............................................... $608 $519 $501 $600
==== ==== ==== ====
</TABLE>
Exploration and development expenditures increased $89 million in 1996 as
compared to 1995 primarily due to increased development expenditures in the
United States and India and increased exploration expenditures in the United
States. Partially offsetting these increases were the reduction in 1996 of
development expenditures in Trinidad due to the completion of a large
development drilling program in 1995 and reduced property acquisition
expenditures.
Exploration and development expenditures increased $18 million in 1995 as
compared to 1994. Differences in components reflect a significant increase in
producing property acquisitions to complement existing United States producing
areas. One such property acquisition was for non-cash consideration of $19
million of redeemable preferred stock of a subsidiary of the Company. (See Note
9 to Consolidated Financial Statements). (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 1997 exploration and development expenditure plans).
Hedging Transactions. With the objective of enhancing the certainty of
future revenues, the Company enters into NYMEX-related commodity price swaps
from time to time. Using NYMEX-related commodity price swaps, the Company
receives a fixed price for the respective commodity hedged and pays a floating
market price, as defined for each transaction, to the counterparty at
settlement. In 1996, prices for approximately 65% of the natural gas delivered
volumes were hedged using NYMEX-related commodity price swaps compared to 35% in
1995. The Company's 1996 NYMEX-related natural gas and crude oil commodity price
swaps closed with "other marketing revenue" reductions of $18 million pretax and
$13 million pretax, respectively.
24
<PAGE> 27
During December 1996, the Company closed a significant portion of its
NYMEX-related natural gas commodity price swaps for 1997. The removal of these
hedges resulted in a deferred "other marketing revenue" reduction of $56.1
million pretax to be realized during 1997. At December 31, 1996, there were open
commodity price swaps for 1997 covering approximately 10 TBtu of natural gas at
a weighted average price of $2.26 per MMBtu, predominantly in the first quarter
and approximately 2 million barrels of crude oil at a weighted average price of
$19.01 per barrel.
Financing. The Company's long-term debt-to-total-capital ratio was 27% and
20% as of December 31, 1996 and 1995, respectively. The Company has entered into
agreements with Enron Corp. pursuant to which the Company may borrow funds from
or invest funds with Enron Corp. at representative market rates of interest on a
revolving basis. There was no balance outstanding under either agreement at
December 31, 1996 and $142 million outstanding at December 31, 1995 under the
terms of the borrowing agreement.
During 1996, total long-term debt increased $177 million to $466 million as
a result of borrowings related to increased domestic drilling activities,
international facilities construction and certain producing property
acquisitions. (See Note 3 to the Consolidated Financial Statements). The
estimated fair value of the Company's long-term debt at December 31, 1996 and
1995 was $464 million and $294 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 12 to the Consolidated Financial
Statements).
Outlook. Uncertainty continues to exist as to the direction of future North
America natural gas price trends, and there remains a rather wide divergence in
the opinions held by some in the industry. This divergence in opinion is caused
by various factors including improvements in the technology used in drilling and
completing crude oil and natural gas wells that are tending to mitigate the
impacts of fewer crude oil and natural gas wells being drilled, the deregulation
of the natural gas market under Federal Energy Regulatory Commission Order 636
and subsequent related orders, improvements being realized in the availability
and utilization of natural gas storage capacity and colder weather experienced
in the latter part of 1995 and 1996 than in prior years. 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"). At December 31, 1996,
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 and long-term marketing contracts, the Company's net income and
cash flow sensitivity to changing natural gas prices is approximately $13
million for each $.10 per Mcf change in average wellhead natural gas prices.
While the Company is not impacted as significantly by changing crude oil prices,
for those volumes not otherwise hedged, its net income and cash flow sensitivity
is approximately $4 million for each $1.00 per barrel change in average wellhead
crude oil prices.
The Company plans to continue to focus a substantial portion of its
development and exploration expenditures in its major producing areas in North
America. However, based on the continuing uncertainty associated with North
America natural gas prices and as a result of the recent success realized in
Trinidad, the opportunities available to the Company in conjunction with the
late 1994 signing of agreements in India, the winning in 1996 of a concession in
Venezuela, and the award of the modified U(a) block offshore Trinidad, the
Company anticipates expending an increasing portion of its available funds in
the further development of these opportunities outside North America. In
addition, the Company expects to conduct limited exploratory activity in other
areas outside of North America in its expenditure plans and will continue to
evaluate the potential for involvement in other exploitation type opportunities.
(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
level of approximately $600 million for 1997. 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's continuing strategy of funding
exploration, exploitation, development and acquisition activities primarily from
available internally generated cash flow. The continuation of expenditures
25
<PAGE> 28
in other areas outside of North America in the near term is expected to be
primarily for the evaluation of conventional oil and gas exploitation
opportunities in China. Other prospects in various locations including coalbed
methane recovery projects will also attract the expenditure of some funds.
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 continued in 1996, and should continue in the
future, to realize significant but declining 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, the annual benefit,
which was approximately $16 million in 1996 and is estimated to be approximately
$11 million for 1997, is expected to continue to decline in future periods as
production from the qualified wells declines. The drilling qualification period
for a Texas severance tax exemption available on qualifying high cost natural
gas revenues continued through August 1996 in its original form and in a
modified and somewhat reduced form from that point through August 2002.
Consequently, new qualifying production will be added prospectively to that
presently qualified. (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 level of exploration and development expenditures may vary in 1997 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 1997 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,
exploitation, development and acquisition expenditure plans if circumstances
warrant. While the Company has certain continuing commitments associated with
expenditure plans related to operations in India, Trinidad and Venezuela, such
commitments are not anticipated to be material when considered in relation to
the total financial capacity of the Company.
Other. The cost of environmental compliance has not been material to the
Company.
INFORMATION REGARDING FORWARD LOOKING STATEMENTS
This Annual Report on Form 10-K includes forward looking statements within
the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. Although the Company believes that its
expectations are based on reasonable assumptions, it can give no assurance that
such expectations will be achieved. Important factors that could cause actual
results to differ materially from those in the forward looking statements herein
include, but are not limited to, the timing and extent of changes in commodity
prices for crude oil, natural gas and related products and interest rates, the
extent of the Company's success in discovering, developing and producing
reserves and in acquiring oil and gas properties, political developments around
the world and conditions of the capital and equity markets during the periods
covered by the forward looking statements.
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.
26
<PAGE> 29
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.
PART IV
ITEM 14. FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE, EXHIBITS 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
The Company filed a Report on Form 8-K on December 3, 1996 reporting the
sale on November 18, 1996 of $150 million principal amount of 6.70% Notes due
November 15, 2006 pursuant to an underwritten public offering.
27
<PAGE> 30
INDEX TO FINANCIAL STATEMENTS
ENRON OIL & GAS COMPANY
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
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, 1996...................................... F-4
Consolidated Balance Sheets - December 31, 1996 and
1995................................................... F-5
Consolidated Statements of Shareholders' Equity for Each
of the Three Years in the Period Ended December 31,
1996................................................... F-6
Consolidated Statements of Cash Flows for Each of the
Three Years in the Period Ended December 31, 1996...... F-7
Notes to Consolidated Financial Statements................ F-8
Supplemental Information to Consolidated Financial
Statements................................................ F-23
Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts and
Reserves............................................... S-1
</TABLE>
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
<PAGE> 31
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 judgments 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, antiboycott 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 the year ended December
31, 1996.
<TABLE>
<S> <C> <C>
BEN B. BOYD WALTER C. WILSON FORREST E. HOGLUND
Chairman of the
Vice President and Senior Vice President and Board and
Chief Executive
Controller Chief Financial Officer Officer
</TABLE>
Houston, Texas
February 17, 1997
F-2
<PAGE> 32
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,
1996 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,
1996 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 current standards of control criteria.
Houston, Texas ARTHUR ANDERSEN LLP
February 17, 1997
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, 1996
and 1995, and the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1996. 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, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, 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.
Houston, Texas ARTHUR ANDERSEN LLP
February 17, 1997
F-3
<PAGE> 33
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
NET OPERATING REVENUES
Natural Gas
Associated Companies.................................. $164,745 $229,997 $267,997
Trade................................................. 393,129 222,118 221,896
Crude Oil, Condensate and Natural Gas Liquids
Associated Companies.................................. 37,539 58,233 46,782
Trade................................................. 108,365 66,145 29,556
Gains on Sales of Reserves and Related Assets............ 20,358 62,821 54,014
Other.................................................... 6,512 9,388 5,578
-------- -------- --------
Total............................................ 730,648 648,702 625,823
OPERATING EXPENSES
Lease and Well........................................... 76,618 69,463 60,384
Exploration.............................................. 55,009 42,044 41,811
Dry Hole................................................. 13,193 12,911 17,197
Impairment of Unproved Oil and Gas Properties............ 21,226 23,715 24,936
Depreciation, Depletion and Amortization................. 251,278 216,047 242,182
General and Administrative............................... 56,405 56,626 51,418
Taxes Other Than Income.................................. 48,089 32,587 28,254
-------- -------- --------
Total............................................ 521,818 453,393 466,182
-------- -------- --------
OPERATING INCOME........................................... 208,830 195,309 159,641
OTHER INCOME (EXPENSE), NET................................ (5,007) 669 2,783
-------- -------- --------
INCOME BEFORE INTEREST EXPENSE AND TAXES................... 203,823 195,978 162,424
INTEREST EXPENSE
Incurred
Affiliate............................................. 1,614 1,360 629
Other................................................. 20,383 17,054 13,984
Capitalized.............................................. (9,136) (6,490) (6,124)
-------- -------- --------
Net Interest Expense.................................. 12,861 11,924 8,489
-------- -------- --------
INCOME BEFORE INCOME TAXES................................. 190,962 184,054 153,935
INCOME TAX PROVISION....................................... 50,954 41,936 5,937
-------- -------- --------
NET INCOME................................................. $140,008 $142,118 $147,998
======== ======== ========
EARNINGS PER SHARE OF COMMON STOCK......................... $ .88 $ .89 $ .93
======== ======== ========
AVERAGE NUMBER OF COMMON SHARES............................ 159,853 159,917 159,845
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE> 34
ENRON OIL & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
AT DECEMBER 31,
--------------------------
1996 1995
----------- -----------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents................................. $ 7,644 $ 23,039
Accounts Receivable
Associated Companies................................... 82,059 60,777
Trade.................................................. 195,239 107,737
Inventories............................................... 20,746 11,697
Other..................................................... 20,222 14,582
----------- -----------
Total............................................. 325,910 217,832
OIL AND GAS PROPERTIES (Successful Efforts Method).......... 3,753,199 3,380,924
Less: Accumulated Depreciation, Depletion and
Amortization........................................... (1,653,610) (1,499,379)
----------- -----------
Net Oil and Gas Properties........................ 2,099,589 1,881,545
OTHER ASSETS................................................ 32,854 47,881
----------- -----------
TOTAL ASSETS................................................ $ 2,458,353 $ 2,147,258
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
>Accounts Payable
Associated Companies................................... $ 77,522 $ 12,902
Trade.................................................. 200,069 120,756
Accrued Taxes Payable..................................... 18,554 19,595
Dividends Payable......................................... 4,818 4,795
Other..................................................... 16,397 11,249
----------- -----------
Total............................................. 317,360 169,297
LONG-TERM DEBT
Affiliate................................................. - 141,520
Other..................................................... 466,089 147,559
OTHER LIABILITIES........................................... 44,483 11,629
DEFERRED INCOME TAXES....................................... 308,948 308,141
DEFERRED REVENUE............................................ 56,383 205,453
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY
Common Stock, $.01 Par, 320,000,000 Shares Authorized and
160,000,000 Shares Issued.............................. 201,600 201,600
Additional Paid In Capital................................ 388,212 399,379
Unearned Compensation..................................... (5,727) -
Cumulative Foreign Currency Translation Adjustment........ (10,179) (10,747)
Retained Earnings......................................... 697,564 576,740
Common Stock Held in Treasury, 242,882 shares at December
31, 1996 and 150,045 shares at December 31, 1995....... (6,380) (3,313)
----------- -----------
Total Shareholders' Equity........................ 1,265,090 1,163,659
----------- -----------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY.................. $ 2,458,353 $ 2,147,258
=========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE> 35
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 UNEARNED TRANSLATION RETAINED HELD IN SHAREHOLDERS'
STOCK CAPITAL COMPENSATION ADJUSTMENT EARNINGS TREASURY EQUITY
-------- ---------- ------------ ----------- -------- -------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
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 Plans............ - (13,243) - - - 39,177 25,934
-------- -------- ------- -------- -------- -------- ----------
Balance at December 31, 1994...... 201,600 403,488 - (15,298) 453,810 (181) 1,043,419
Net Income - - - - 142,118 - 142,118
Dividends Paid/Declared, $.12
Per Share..................... - - - - (19,188) - (19,188)
Translation Adjustment.......... - - - 4,551 - - 4,551
Treasury Stock Purchased/
Tendered...................... - - - - - (17,855) (17,855)
Treasury Stock Issued Under
Stock Option Plans............ - (4,109) - - - 14,438 10,329
Other........................... - - - - - 285 285
-------- -------- ------- -------- -------- -------- ----------
Balance at December 31, 1995...... 201,600 399,379 - (10,747) 576,740 (3,313) 1,163,659
Net Income...................... - - - - 140,008 - 140,008
Dividends Paid/Declared, $.12
Per Share..................... - - - - (19,184) - (19,184)
Translation Adjustment.......... - - - 568 - - 568
Treasury Stock Purchased/
Tendered...................... - - - - - (63,004) (63,004)
Treasury Stock Issued Under
Stock Option Plans............ - (11,167) (7,085) - - 59,937 41,685
Amortization of Unearned
Compensation.................. - - 1,358 - - - 1,358
-------- -------- ------- -------- -------- -------- ----------
Balance at December 31, 1996...... $201,600 $388,212 $(5,727) $(10,179) $697,564 $ (6,380) $1,265,090
======== ======== ======= ======== ======== ======== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
<PAGE> 36
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1996 1995 1994
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of Net Income to Net Operating Cash
Inflows:
Net Income.............................................. $ 140,008 $ 142,118 $ 147,998
Items Not Requiring (Providing) Cash Depreciation,
Depletion and Amortization........................... 251,278 216,047 242,182
Impairment of Unproved Oil and Gas Properties........ 21,226 23,715 24,936
Deferred Income Taxes................................ 2,276 45,173 1,788
Other, Net........................................... 7,830 2,910 (2,735)
Exploration Expenses.................................... 55,009 42,044 41,811
Dry Hole Expenses....................................... 13,193 12,911 17,197
Gains On Sales of Reserves and Related Assets........... (20,358) (62,821) (54,014)
Other, Net.............................................. 8,871 720 4,490
Changes in Components of Working Capital and Other
Liabilities
Accounts Receivable................................ (120,370) (17,525) (883)
Inventories........................................ (9,049) 4,034 (2,163)
Accounts Payable................................... 87,495 2,514 (25,648)
Accrued Taxes Payable.............................. (1,041) 1,964 277
Other Liabilities.................................. 3,752 1,544 1,086
Other, Net......................................... 270 (18,791) (1,463)
Amortization of Deferred Revenue........................ (43,463) (43,344) (43,345)
Changes in Components of Working Capital Associated with
Investing and Financing Activities................... (31,817) (17,858) 31,038
--------- --------- ---------
NET OPERATING CASH INFLOWS................................ 365,110 335,355 382,552
INVESTING CASH FLOWS
Additions to Oil and Gas Properties..................... (539,330) (445,047) (442,078)
Exploration Expenses.................................... (55,009) (42,044) (41,811)
Dry Hole Expenses....................................... (13,193) (12,911) (17,197)
Proceeds from Sales of Reserves and Related Assets (Note
9)................................................... 63,951 102,006 90,515
Changes in Components of Working Capital Associated with
Investing Activities................................. 37,402 18,391 (32,120)
Other, Net.............................................. (5,381) (11,689) (8,758)
--------- --------- ---------
NET INVESTING CASH OUTFLOWS............................... (511,560) (391,294) (451,449)
FINANCING CASH FLOWS
Long-Term Debt
Affiliate............................................ (141,520) 116,520 25,000
Other................................................ 320,580 (16,100) (25,300)
Dividends Paid.......................................... (19,161) (19,193) (19,178)
Treasury Stock Purchased................................ (43,507) (17,855) (14,139)
Proceeds from Sales of Treasury Stock................... 22,188 10,329 4,113
Other, Net.............................................. (7,525) (533) 1,082
--------- --------- ---------
NET FINANCING CASH INFLOWS (OUTFLOWS)..................... 131,055 73,168 (28,422)
--------- --------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.......... (15,395) 17,229 (97,319)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR............ 23,039 5,810 103,129
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF YEAR.................. $ 7,644 $ 23,039 $ 5,810
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
<PAGE> 37
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"), 53% 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 the consolidated
financial statements for prior years to conform with the current presentation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expenses during the reporting
period. Actual results could differ from those estimates.
Cash Equivalents. The Company records as cash equivalents all highly liquid
short-term investments with maturities of three months or less.
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 natural gas and crude oil 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. In the first quarter of 1996,
the Company adopted Statement of Financial Accounting Standards ("SFAS") No.
121 - "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of", which resulted in a non-cash impairment charge that
was immaterial to and is included in depreciation, depletion and amortization.
Inventories, consisting primarily of tubular goods and well equipment held
for use in the exploration for, and development and production of natural gas
and crude oil reserves, are carried at cost with adjustments made from time to
time to recognize changes in condition value.
Natural gas revenues are recorded on the entitlement method based on the
Company's percentage ownership of current production. Each working interest
owner in a well generally has the right to a specific percentage of production,
although actual production sold may differ from an owner's ownership percentage.
Under entitlement accounting, a receivable is recorded when underproduction
occurs and a payable when overproduction occurs.
F-8
<PAGE> 38
Gains and losses associated with the sale in place of natural gas and crude
oil reserves and related assets are classified as net operating revenues in the
consolidated statements of income based on the Company's strategy of continuing
such sales in maximizing the economic value of its assets.
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 sale 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 and in work in
progress for exploratory drilling with significant cash outlays. Interest costs
capitalized during each of the three years in the period ended December 31, 1996
are set out in the consolidated statements of income.
Income Taxes. The closing on December 13, 1995 of the sale by Enron Corp.
of approximately 31 million outstanding shares of the common stock of the
Company reduced Enron Corp.'s ownership interest in the Company from 80% to 61%
with the result that (i) the Company ceased, effective December 14, 1995, to be
included in the consolidated federal income tax return filed by Enron Corp. and
(ii) a tax allocation agreement previously in effect between the Company and
Enron Corp. was terminated. In addition effective December 14, 1995, the Company
and its subsidiaries and Enron Corp. entered into a new tax agreement pursuant
to which, among other things, Enron Corp. has agreed (in exchange for the
payment of $13.0 million by the Company) to be liable for, and indemnify the
Company against all U.S. federal and state income taxes and certain foreign
taxes imposed on the Company for periods prior to the date Enron Corp. reduced
its ownership in the Company to less than 80%. The Company does not believe that
the cessation of consolidated tax reporting with Enron Corp., the termination of
the tax allocation agreement concurrent with deconsolidation and/or the signing
of the new tax agreement with Enron Corp. has or will have in the future a
material adverse effect on its financial condition or results of operations.
Prior to December 14, 1995, the Company was included in the consolidated
federal income tax return filed by Enron Corp. as the common parent for itself
and its subsidiaries and the resulting taxes, including taxes for any state or
other taxing jurisdiction that required or permitted a consolidated, combined,
or unitary tax return to be filed and in which the Company and/or any of its
subsidiaries was included, were apportioned as between the Company and/or any of
its subsidiaries and Enron Corp. based on the terms of the tax allocation
agreement in effect prior to December 14, 1995.
The Company accounts for income taxes under the provisions of 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 7 "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.
F-9
<PAGE> 39
Earnings Per Share. Earnings per share is computed on the basis of the
average number of common shares outstanding during the periods.
2. NATURAL GAS AND CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET OPERATING
REVENUES
Natural Gas Net Operating Revenues are comprised of the following:
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Wellhead Natural Gas Revenues
Associated Companies(1)(2)....................... $216,676 $173,864 $279,339
Trade............................................ 323,642 174,732 162,553
-------- -------- --------
Total.................................... $540,318 $348,596 $441,892
======== ======== ========
Other Natural Gas Marketing Activities
Gross Revenues from:
Associated Companies.......................... $ 92,471 $ 78,985 $159,726
Trade(3)...................................... 142,149 102,904 121,965
-------- -------- --------
Total.................................... 234,620 181,889 281,691
Associated Costs from:
Associated Companies(1)(5).................... 143,871 90,121(4) 181,756(4)
Trade......................................... 72,633.. 56,221.. 62,513
-------- -------- --------
Total.................................... 216,504 146,342 244,269
-------- -------- --------
Net...................................... 18,116 35,547 37,422
Commodity Price Transaction Gain (Loss)
Trading....................................... (13,222)(6) 2,688(7) -
Non-Trading(8)................................ 12,662 65,284 10,579
-------- -------- --------
Total.................................... (560) 67,972 10,579
-------- -------- --------
Total.................................... $ 17,556 $103,519 $ 48,001
======== ======== ========
</TABLE>
Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues are
comprised of the following:
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Wellhead Crude Oil, Condensate and Natural Gas
Liquids Revenues
Associated Companies.......................... $ 50,668 $ 56,681 $ 44,979
Trade......................................... 108,365 66,145 29,556
-------- -------- --------
Total.................................... $159,033 $122,826 $ 74,535
======== ======== ========
Other Crude Oil and Condensate Marketing Activities
Commodity Price Hedging Gain (Loss)(8)........... $(13,129) $ 1,552 $ 1,803
======== ======== ========
</TABLE>
- ---------------
(1) Wellhead Natural Gas Revenues in 1996, 1995 and 1994 include $119,009,
$80,369 and $126,783, 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 $20,656, $14,022 and $22,434 in 1996, 1995 and 1994, 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 $43,463, $43,344 and $43,345 in 1996, 1995 and 1994, respectively,
associated with the amortization of deferred revenues under the terms of a
volumetric production payment agreement effective October 1, 1992, as
amended.
F-10
<PAGE> 40
(4) Includes the effect of a price swap agreement with a third party which in
effect fixed the price of certain purchases through February 1995.
(5) Includes $37,483, $27,549 and $33,779 in 1996, 1995 and 1994, respectively,
for volumes delivered under a volumetric production payment agreement
effective October 1, 1992, as amended, including equivalent wellhead value,
any applicable transportation costs and exchange differentials.
(6) Includes a non-cash charge of $12,000 related to the value of natural gas
price swap options exercisable by a counterparty during 1997, 1998, 1999 and
2000. The options for 1997 and 1998 remained open at December 31, 1996;
however, "buy" price swap positions in the same notional quantities and
maturities are in place. The option agreements for 1999 and 2000 were
terminated during the fourth quarter of 1996. See Note 12 for a discussion
of the options.
(7) Includes an $11,255 revenue increase associated with certain NYMEX-related
commodity market transactions designated for trading purposes partially
offset by a $2,567 revenue reduction related to call option transactions and
a $6,000 revenue reduction associated with certain NYMEX-related natural gas
commodity market transactions that were marked-to-market due to loss of
correlation between the NYMEX and the wellhead natural gas prices that the
positions were designated to hedge. (See Note 12 "Price and Interest Rate
Risk Management").
(8) Represents revenue increase (reduction) 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. These transactions serve as price hedges for a
portion of wellhead sales.
In March 1995, in a series of transactions with Enron Corp. and an
affiliate of Enron Corp., the Company exchanged all of its fuel supply and
purchase contracts and related price swap agreements associated with a Texas
City cogeneration plant (the "Cogen Contracts") for certain natural gas price
swap agreements of equivalent value issued by the affiliate that are designated
as hedges (the "Swap Agreements"). Such Swap Agreements were closed on March 31,
1995. As a result of the transactions, the Company was relieved of all
performance obligations associated with the Cogen Contracts. Such operating
revenues and associated costs through February 28, 1995 were classified as Other
Natural Gas Marketing Activities-Gross Revenues and Associated Costs from
Associated Companies. The Company will realize net operating revenues classified
as Other Natural Gas Marketing Activities-Commodity Price Transaction Gain
(Loss), Non-Trading, and receive corresponding cash payments of approximately
$91 million during the period extending through December 31, 1999, under the
terms of the closed Swap Agreements. The estimated fair value of the Swap
Agreements was approximately $81 million at the date the Swap Agreements were
received in exchange for the Cogen Contracts. The net effect of this series of
transactions has resulted in increases in net operating revenues and cash
receipts for the Company during 1995 and 1996 of approximately $13 million and
$7 million, respectively, with offsetting decreases in 1998 and 1999 versus that
anticipated under the Cogen Contracts. The total cash payments receivable under
the terms of the Swap Agreements were approximately $33 million and $60 million
at December 31, 1996 and 1995, respectively, and are presented in the
accompanying balance sheet as Accounts Receivable - Associated Companies for the
$20 million and $25 million current portion, respectively, and as Other Assets
for the $13 million and $35 million noncurrent portion, respectively. The
corresponding total future revenue of approximately $33 million and $63 million,
respectively, is classified as Deferred Revenue. (See Note 12 "Price and
Interest Rate Risk Management").
F-11
<PAGE> 41
3. LONG-TERM DEBT
Long-Term Debt at December 31 consisted of the following:
<TABLE>
<CAPTION>
1996 1995
-------- --------
<S> <C> <C>
Commercial Paper and/or Uncommitted Credit Facilities....... $ 65,700 $ -
6.70% Notes due 2006........................................ 150,000 -
9.10% Notes due 1998........................................ 40,000 70,000
Bank Debt due 1999.......................................... 30,000 -
Subsidiary Bank Debt due 1998-1999.......................... 71,000 71,000
Subsidiary Bank Debt due 2001............................... 105,000 -
Capitalized Lease/Other..................................... 4,389 6,559
-------- --------
466,089 147,559
Affiliate................................................... - 141,520
-------- --------
Total............................................. $466,089 $289,079
======== ========
</TABLE>
In June 1996, the Company cancelled an existing revolving credit agreement
and replaced it with a new revolving credit agreement entered into with a group
of banks. The new agreement provides for aggregate borrowings of up to $200
million and matures on June 28, 2001. Advances under the agreement bear
interest, at the option of the Company, based on a base rate, an adjusted CD
rate or a Eurodollar rate. At December 31, 1996, there were no advances
outstanding under the agreement.
The Company has uncommitted credit facilities, of which approximately $66
million was outstanding as of December 31, 1996. Advances under these credit
facilities bear interest based on market rates. The proceeds of the Company's
credit facilities are used to fund current transactions and are classified as
long-term debt based on the Company's intent and ability to replace such amounts
with other long-term debt.
The 6.70% Notes were issued through a public offering in November 1996 and
are due November 15, 2006. These notes have an effective interest rate of 6.83%.
The 9.10% Notes have scheduled principal repayments of $20 million due
February 15, 1997 and 1998. The $20 million repayment due on February 15, 1997
is classified as long-term based on the Company's intent and ability to replace
such amount upon maturity with other long-term debt.
The Bank Debt due 1999 bears interest at a variable rate based on the
London Interbank Offered Rate.
The Subsidiary Bank Debt due 1998-1999 represents multiple advances bearing
interest at a fixed rate or at a variable rate based on the London Interbank Bid
Rate with $31 million due in 1998 and $40 million due in 1999.
The Subsidiary Bank Debt due 2001 bears interest at a variable rate based
on the London Interbank Offered Rate.
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. All subsidiary bank debt is guaranteed by the
Company.
Shelf Registration. The Company may sell from time to time up to an
aggregate of $313 million in debt securities and/or common stock pursuant to an
effective "shelf" registration statement filed with the Securities and Exchange
Commission.
Financing Arrangements With Enron Corp. The Company engages in various
transactions with Enron Corp. that are characteristic of a consolidated group
under common control. Accordingly, the Company maintains agreements with Enron
Corp. that provide for the borrowing by the Company of up to $200 million
through December 31, 1998 and investing by the Company of surplus funds of up to
$200 million through December 31, 1998 at market rates from time to time. There
were no borrowings from or investments with Enron Corp. under these agreements
at December 31, 1996. Borrowings of $142 million were outstanding at
F-12
<PAGE> 42
December 31, 1995, and such balance was classified as long-term based on the
Company's intent and ability to replace such amount with other long-term debt.
Fair Value Of Long-Term Debt. At December 31, 1996 and 1995, the Company
had $466 million and $289 million, respectively, of long-term debt which had
fair values of approximately $464 million and $294 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 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.
4. VOLUMETRIC PRODUCTION PAYMENT
In September 1992, the Company sold a volumetric production payment for
$326.8 million to a limited partnership. Under the terms of the production
payment, as amended October 1, 1993, the Company conveyed a real property
interest of certain natural gas and other hydrocarbons to the purchaser. At
December 31, 1996 and 1995 there were approximately 41 trillion British thermal
units ("TBtu") and 60 TBtu, respectively, remaining to be delivered under the
agreement. Such quantities are scheduled to be delivered at the rate of 50
billion British thermal units per day through March 31, 1999.
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 of the
volumetric production payment agreement. Annual remaining amortization of
deferred revenue under the volumetric production payment agreement, as amended,
at December 31, 1996 was as follows:
<TABLE>
<S> <C>
1997............................................... $43,344
1998............................................... 43,344
1999............................................... 10,688
-------
Total.................................... $97,376
=======
</TABLE>
5. SHAREHOLDERS' EQUITY
On May 3, 1994, the shareholders of the Company approved and the Board of
Directors subsequently declared a two-for-one split of the common stock of the
Company to be effected as a nontaxable dividend of one share for each share
outstanding. Shares were issued on June 15, 1994 to shareholders of record as of
May 31, 1994. At such time, 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 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.
In March 1995, a subsidiary of the Company issued to an unrelated third
party 19,000 shares of the subsidiary's non-voting redeemable preferred stock,
with a liquidation/redemption value of $1,000 per share and dividends payable
semi-annually at an annual rate of $70.00 per share, in exchange for certain oil
and gas properties. In November 1995, the Company exchanged 633,333 shares of
Enron Corp. common stock which had been acquired in 1994 and 1995 for the
redeemable preferred stock.
On May 7, 1996, the shareholders of the Company approved a resolution
submitted by the Board of Directors to amend the Restated Certificate of
Incorporation of the Company to increase the total number of authorized shares
of the common stock of the Company from 160 million to 320 million shares.
The Board of Directors of the Company approved in December 1992, and
amended in September 1994 and December 1996, the authorization for purchasing
and holding in treasury at any time of up to 1,000,000 shares of common stock of
the Company for the purpose of, but not limited to, meeting obligations
associated with the exercise of stock options granted to qualified employees
pursuant to the Company's stock option plans. (See Note 8 "Commitments and
Contingencies - Stock Option Plans"). In December 1996, the Board
F-13
<PAGE> 43
of Directors of the Company approved the selling from time to time, subject to
certain conditions, of put options on the common stock of the Company. The
1,000,000 shares limit mentioned above applies to shares held in treasury and
unexpired put options outstanding. At December 31, 1996 and 1995, 242,882 shares
and 150,045 shares, respectively, were held in treasury under this
authorization, and there were no put options outstanding.
In February 1997, the Board of Directors of the Company authorized the
additional purchase of up to an aggregate maximum of 5 million shares of common
stock of the Company from time to time in the open market to be held in treasury
for the purpose of, but not limited to, fulfilling any obligations arising under
the Company's stock option plans and any other approved transactions or
activities for which such common stock shall be required.
6. 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 8 "Commitments and
Contingencies - Employee Benefit Plans"), totaled $17.0 million, $16.4 million
and $13.4 million for the years ended December 31, 1996, 1995 and 1994,
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 approximately $7.5 million, $7.0 million and $6.7
million for 1996, 1995 and 1994, respectively. The limit on cost for the
allocated indirect services provided by Enron Corp. to the Company will increase
in subsequent years for inflation and certain changes in the Company's
allocation bases, but such increase will not 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 $7.5
million, $6.8 million and $6.6 million were charged to the Company for indirect
general and administrative expenses for the years ended December 31, 1996, 1995
and 1994, respectively.
Financing. See Note 3 "Long-Term Debt - Financing Arrangements with Enron
Corp." for a discussion of financing arrangements with Enron Corp.
F-14
<PAGE> 44
7. INCOME TAXES
The principal components of the Company's net deferred income tax liability
at December 31, 1996 and 1995 were as follows:
<TABLE>
<CAPTION>
1996 1995
-------- --------
<S> <C> <C> <C>
Deferred Income Tax Assets
Non-Producing Leasehold Costs.................... $ 9,832 $ 8,469
Seismic Costs Capitalized for Tax................ 7,037 5,316
Alternative Minimum Tax Credit Carryforward...... 7,516 -
Other............................................ 5,013 1,460
-------- --------
Total Deferred Income Tax Assets......... 29,398 15,245
Deferred Income Tax Liabilities
Oil and Gas Exploration and Development Costs
Deducted for Tax Over Book Depreciation,
Depletion and Amortization.................... 278,094 274,219
Capitalized Interest............................. 7,401 6,265
Volumetric Production Payment Book Revenue Over
Income for Tax................................ 51,499 40,591
Other............................................ 1,352 2,311
-------- --------
Total Deferred Income Tax Liabilities.... 338,346 323,386
-------- --------
Net Deferred Income Tax Liability........ $308,948 $308,141
======== ========
</TABLE>
The components of income before income taxes were as follows:
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
United States...................................... $146,335 $157,174 $125,510
Foreign............................................ 44,627 26,880 28,425
-------- -------- --------
Total.................................... $190,962 $184,054 $153,935
======== ======== ========
</TABLE>
Total income tax provision (benefit) was as follows:
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Current:
Federal.......................................... $ 21,064 $ (6,983) $ 113
State............................................ (916) 130 2,745
Foreign.......................................... 28,530 3,616 1,291
-------- -------- --------
Total.................................... 48,678 (3,237) 4,149
Deferred:
Federal.......................................... 13,620 24,733 3,818
State............................................ (1,826) 855 (14,414)
Foreign.......................................... (9,518) 19,585 12,384
-------- -------- --------
Total.................................... 2,276 45,173 1,788
-------- -------- --------
Income Tax Provision............................... $ 50,954 $ 41,936 $ 5,937
======== ======== ========
</TABLE>
F-15
<PAGE> 45
The differences between taxes computed at the U.S. federal statutory tax
rate and the Company's effective rate were as follows:
<TABLE>
<CAPTION>
1996 1995 1994
----- ------ ------
<S> <C> <C> <C>
Statutory Federal Income Tax Rate......................... 35.00% 35.00% 35.00%
State Income Tax, Net of Federal Benefit.................. (0.76) 0.35 (4.93)
Income Tax Related to Foreign Operations.................. 6.16 7.21 3.44
Tight Gas Sand Federal Income Tax Credits................. (8.22) (12.19) (23.71)
Revision of Prior Years' Tax Estimates.................... (4.46) (6.52) (3.25)
Amended Return Recoveries................................. - (1.09) (2.62)
Other..................................................... (1.04) 0.02 (0.07)
----- ------ ------
Effective Income Tax Rate....................... 26.68% 22.78% 3.86%
===== ====== ======
</TABLE>
The Company's foreign subsidiaries' undistributed earnings of approximately
$119 million at December 31, 1996 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.
The Company has an alternative minimum tax ("AMT") credit carryforward of
$7.5 million which can be used to offset regular income taxes payable in future
years. The AMT credit carryforward has an indefinite carryforward period.
8. 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, 1996, 1995 and 1994, the Company was charged $5.0
million, $6.6 million and $5.1 million, respectively, for all such benefits,
including pension expense totaling $1.0 million, $0.8 million and $0.3 million,
respectively, by Enron Corp.
As of September 30, 1996, 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 $5 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 7.5%, 10.5% and 4.0%,
respectively.
The Company also has in effect pension and savings plans related to its
Canadian, Trinidadian and Indian subsidiaries. Activity related to these plans
is not material relative to the Company's operations.
The Company provides certain medical, life insurance and dental benefits to
eligible employees and their eligible dependents. Benefits are provided under
the provisions of contributory defined dollar benefit plans of Enron Corp. The
Company accrues the cost of these post-retirement benefits over the service
lives of the employees expected to be eligible to receive such benefits. The
transition obligation is being amortized over an average period of 19 years.
Stock Option Plans. The Company has various stock option plans ("the
Plans") under which employees of the Company and its subsidiaries and
nonemployee 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. Options granted under the Plans have
not exceeded a maximum term of 10 years.
In January 1996, 301,500 shares of common stock of the Company with a
market value of $23.50 per share were granted to certain officers and key
employees of the Company under the Plans. Such shares are restricted and vest,
subject to continued employment and certain net income performance goals, on the
F-16
<PAGE> 46
anniversary date of grant which could begin as early as 1998, but in any event
no later than January 2002. The fair value of the shares at date of grant has
been recorded in shareholders' equity as unearned compensation and is being
amortized as compensation expense. Related compensation expense for 1996 was
approximately $1 million.
The Company accounts for the Plans under the provisions and related
interpretations of Accounting Principles Board Opinion No. 25 ("APB No.
25") - "Accounting for Stock Issued to Employees". No compensation expense is
recognized for such options. In accordance with SFAS No. 123 - "Accounting for
Stock-Based Compensation" issued in 1995, the Company intends to continue to
apply APB No. 25 for purposes of determining net income and to present the pro
forma disclosures required by SFAS No. 123.
The following table sets forth the option transactions for the Plans for
the years ended December 31 (shares in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
---------------- ---------------- ----------------
AVERAGE AVERAGE AVERAGE
GRANT GRANT GRANT
SHARES PRICE SHARES PRICE SHARES PRICE
------ ------- ------ ------- ------ -------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at January 1........... 8,019 $18.61 7,215 $18.15 4,125 $11.49
Granted.......................... 2,941 24.53 1,650 18.57 5,128 20.23
Exercised........................ (1,989) 17.95 (622) 13.01 (1,968) 9.46
Forfeited........................ (175) 20.28 (224) 19.27 (70) 19.95
------ ----- ------
Outstanding at December 31......... 8,796 20.70 8,019 18.61 7,215 18.15
====== ===== ======
Shares Exercisable at December
31............................... 4,402 19.13 4,716 18.23 1,822 15.57
====== ===== ======
Shares Available for Future
Grant............................ 3,741 3,792 3,218
====== ===== ======
Average Fair Value of Shares
Granted During Year.............. $ 9.29 $6.39
====== =====
</TABLE>
The fair value of each option grant is estimated using the Black-Scholes
option-pricing model with the following weighted-average assumptions used for
grants in 1996 and 1995, respectively: (1) dividend yield of 0.5% and 0.5%, (2)
expected volatility of 31% and 31%, (3) risk-free interest rate of 5.8% and
7.2%, and (4) expected life of 5.5 years and 4.1 years.
The following table summarizes certain information for the shares
outstanding at December 31, 1996 (shares in thousands):
<TABLE>
<CAPTION>
SHARES OUTSTANDING SHARES EXERCISABLE
----------------------------- -------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
RANGE OF REMAINING GRANT GRANT
GRANT PRICES SHARES LIFE PRICE SHARES PRICE
------------ ------ --------- -------- ------- ---------
<S> <C> <C> <C> <C> <C>
$ 9.00 to $13.00........................ 529 4 years $ 9.89 529 $ 9.89
13.00 to 18.00........................ 1,195 6 17.83 689 17.80
18.00 to 23.00........................ 4,040 6 20.10 2,560 20.30
23.00 to 29.00........................ 3,032 9 24.53 624 23.61
----- -----
9.00 to 29.00........................ 8,796 7 20.70 4,402 19.13
===== =====
</TABLE>
F-17
<PAGE> 47
The Company's pro forma net income and earnings per share of common stock
for 1996 and 1995, had compensation costs been recorded in accordance with SFAS
No. 123, are presented below (in millions except per share data):
<TABLE>
<CAPTION>
1996 1995
--------------------- ---------------------
AS AS
REPORTED PRO FORMA REPORTED PRO FORMA
-------- --------- -------- ---------
<S> <C> <C> <C> <C>
Net Income................................ $140.0 $135.5 $142.1 $139.0
Earnings per Share of Common Stock........ $ .88 $ .85 $ .89 $ .87
</TABLE>
The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts. SFAS No. 123 does not apply to awards prior to
1995, and additional awards in future years are anticipated.
The Black-Scholes model used by the Company to calculate option values, as
well as other currently accepted option valuation models, were developed to
estimate the fair value of freely tradable, fully transferable options without
vesting and/or trading restrictions, which significantly differ from the
Company's stock option awards. These models also require highly subjective
assumptions, including future stock price volatility and expected time until
exercise, which greatly affect the calculated values. Accordingly, management
does not believe that this model provides a reliable single measure of the fair
value of the Company's stock option awards.
During 1996, 1995 and 1994, the Company purchased or was tendered
2,383,727, 762,799 and 1,817,093 of its common shares, respectively, and
delivered such shares upon the exercise of stock options and awards of
restricted stock, except for shares held in treasury at December 31, 1996, 1995
and 1994. The difference between the cost of the treasury shares and the
exercise price of the options, net of federal income tax benefit of $6.1
million, $2.2 million and $7.2 million for the years 1996, 1995 and 1994,
respectively, is reflected as an adjustment to Additional Paid In Capital. In
October 1993, as amended in September 1994 and December 1996, 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, 1996 and 1995, 242,882 and 150,045 shares, respectively,
were held in treasury under this authorization. (See Note 5 "Shareholders'
Equity").
Letters Of Credit. At December 31, 1996 and 1995, the Company had letters
of credit outstanding totaling approximately $213 million and $32 million,
respectively.
Contingencies. There are various suits and claims against the Company that
have 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. 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.
9. CASH FLOW INFORMATION
Gains on sales of certain oil and gas reserves and related assets in the
amount of $20.4 million, $62.8 million and $54.0 million for the years ended
December 31, 1996, 1995 and 1994, 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 flows. The Company believes the proceeds from
the sales of reserves and related assets should be considered in analyzing the
elements of operating cash flows. The current federal income tax impact of these
sales transactions was calculated by the Company to be $8.5 million, $24.4
million and $19.8 million for the years ended December 31, 1996, 1995 and 1994,
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.
F-18
<PAGE> 48
Non-cash investing and financing activities for 1995 include the issuance
by a subsidiary of the Company of redeemable preferred stock with a
liquidation/redemption value of $19 million in exchange for certain oil and gas
properties (See Note 5 "Shareholders' Equity"). An approximate $7 million
step-up in property basis was made relating to deferred tax liabilities
associated with the difference between the tax and book bases of acquired
properties as required by SFAS No. 109 for a nontaxable business combination.
Cash paid for interest and income taxes was as follows for the years ended
December 31:
<TABLE>
<CAPTION>
1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Interest (net of amount capitalized)........... $ 14,237 $ 11,307 $ 10,436
Income taxes................................... 42,014 10,140 1,352
</TABLE>
Included in 1995 income taxes paid is $13 million paid to Enron Corp. for
the indemnification of any future liability associated with all federal and
state income taxes and certain foreign taxes imposed on the Company for periods
prior to the date Enron Corp. reduced its ownership in the Company to below 80%.
10. 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>
1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Gross Operating Revenues
United States................................ $ 660,804 $ 582,993 $ 656,546
Foreign...................................... 167,340 131,682 86,763
---------- ---------- ----------
Total(1)............................. $ 828,144 $ 714,675 $ 743,309
========== ========== ==========
Operating Income
United States................................ $ 160,109 $ 162,652 $ 138,001
Foreign...................................... 48,721 32,657 21,640
---------- ---------- ----------
Total................................ $ 208,830 $ 195,309 $ 159,641
========== ========== ==========
Identifiable Assets
United States................................ $1,882,900 $1,693,293 $1,505,926
Foreign...................................... 575,453 453,965 355,941
---------- ---------- ----------
Total................................ $2,458,353 $2,147,258 $1,861,867
========== ========== ==========
</TABLE>
- ---------------
(1) Not deducted are natural gas associated costs of $97,496, $65,973 and
$117,486 in 1996, 1995 and 1994, respectively.
11. OTHER INCOME (EXPENSE), NET
Other income (expense), net consisted of the following for the years ended
December 31:
<TABLE>
<CAPTION>
1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Interest Income(1)............................. $ 2,264 $ 556 $ 4,990
Financial Reserve Accruals..................... (6,897) 379 (3,143)
Other, Net..................................... (374) (266) 936
---------- ---------- ----------
Total................................ $ (5,007) $ 669 $ 2,783
========== ========== ==========
</TABLE>
- ---------------
(1) Includes $403, $59 and $4,716 from related parties.
F-19
<PAGE> 49
12. 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.
Trading Activities. During 1995, the Company entered into a NYMEX-related
natural gas price swap covering 73 TBtu for the year ended December 31, 1996.
This swap contained an option to extend the price swap covering 73 TBtu for each
of the years 1997 and 1998 which was exercisable at one time prior to December
31, 1996. The 1996 price swaps were closed in the first quarter of 1996. During
1996, this option was restructured into four options each exercisable, in total,
at one time by the counterparty before December 31, 1996, 1997, 1998 and 1999 to
purchase 37 TBtu of notional natural gas for each of the years 1997, 1998, 1999
and 2000 at an average fixed price of $1.98, $1.98, $1.93 and $1.93 per million
British thermal units ("MMBtu"), respectively. The 1997 and 1998 options were
subsequently restructured to be exercisable monthly at a price of $2.16 and
$2.07 per MMBtu, respectively. These options cover notional volumes averaging 3
TBtu per month during 1997 and 1998. During the fourth quarter of 1996, the 1999
and 2000 options were terminated. In 1996, the Company entered into "buy"
NYMEX-related natural gas price swap positions in the same notional quantities
and maturities as are covered by the 1997 and 1998 options. The Company
recognized a $12 million revenue reduction in 1996 related to these trading
activities.
In 1995, the Company sold a call option with a notional volume of 50
billion British thermal units ("BBtu") per day at a strike price of $2.10 per
MMBtu for each month in the period January 1996 through December 1996. At
December 31, 1995, the approximate market value of the outstanding call option
was $1.8 million. The Company recognized a $2.6 million revenue reduction in
1995 related to this call option. In the first quarter of 1996, the Company
purchased a call option with a notional volume of 50 BBtu per day at a strike
price of $2.10 per MMBtu for the period February 1996 through December 1996 for
$3.0 million to offset the call option discussed above. The purchase resulted in
a $1.2 million revenue reduction recognized in the first quarter of 1996.
The Company realized an $11.3 million revenue increase in 1995 related to
certain NYMEX-related natural gas commodity price swap transactions with an
Enron Corp. affiliated company that were designated for trading purposes in
December 1994 and closed in the first quarter of 1995.
There were no trading gains or losses in 1994.
The following table summarizes the estimated fair value of financial
instruments held for trading purposes at year-end and the average during the
year:
<TABLE>
<CAPTION>
1996(1) 1995(1)
-------------------- -------------------
FAIR AVERAGE FAIR AVERAGE
VALUE FAIR VALUE VALUE FAIR VALUE
------ ---------- ----- ----------
(IN MILLIONS) (IN MILLIONS)
<S> <C> <C> <C> <C>
Options Written................................ $(12.8) $(8.3) $(1.8) $(.3)
NYMEX-related Natural Gas Price Swaps.......... .8 3.4 - .4
</TABLE>
- ---------------
(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.
Interest Rate Swap Agreements and Foreign Currency Contracts. At December
31, 1996, a subsidiary of the Company and the Company are parties to offsetting
foreign currency and interest rate swap agreements with an aggregate notional
principal amount of $210 million. Such swap agreements are scheduled to
terminate in 2001. At December 31, 1996, the composite fair value of the
agreements was not significant based upon termination values obtained from third
parties. At December 31, 1995, there were no interest rate swap agreements or
foreign currency contracts outstanding.
F-20
<PAGE> 50
Hedging Transactions. With the objective of enhancing the certainty of
future revenues, the Company enters into NYMEX-related commodity price swaps
from time to time. Using NYMEX-related commodity price swaps, the Company
receives a fixed price for the respective commodity hedged and pays a floating
market price, as defined for each transaction, to the counterparty at
settlement.
The NYMEX-related natural gas commodity price swaps are priced based on a
Henry Hub, Louisiana delivery point. The Henry Hub price has historically had a
high degree of correlation with a significant portion of the wellhead price
received by the Company which has made such transactions effective natural gas
price hedges. During December 1995, there was a loss of correlation between the
prices paid under the natural gas commodity price swaps and the wellhead natural
gas prices ultimately received for a portion of the Company's hedged natural gas
production. This loss of correlation resulted in the recognition of a $6 million
revenue reduction in 1995.
At December 31, 1996, the Company had outstanding positions covering
notional volumes of approximately 10 TBtu of natural gas for 1997 and
approximately 37 TBtu of natural gas for each of the years 1999 and 2000 and
approximately 2.1 million barrels ("MMBbl"), 1.7 MMBbl, and 1.2 MMBbl of crude
oil and condensate for the years 1997, 1998 and the period 1999 through 2000,
respectively. The fair value of the positions was a negative $27 million at
December 31, 1996. The Company closed substantially all of the NYMEX-related
natural gas commodity price swaps for 1997 by entering into offsetting positions
in the fourth quarter of 1996. At December 31, 1996, the aggregate total of
deferred revenue reduction for 1997 and 1998 closed positions was approximately
$74 million.
At December 31, 1995, the Company had outstanding positions covering
notional volumes of approximately 169 TBtu of natural gas for 1996 and 11 TBtu
of natural gas for each of the years 1997 through 2005 and approximately 3.6
MMBbl, 2.8 MMBbl, 2.8 MMBbl, 2.2 MMBbl, and .9 MMBbl of crude oil and condensate
for the years 1996 through 2000, respectively. The fair value of the positions
was $16 million at December 31, 1995.
The following table summarizes the estimated fair value of financial
instruments and related transactions for non-trading activities at December 31,
1996 and 1995:
<TABLE>
<CAPTION>
1996 1995
------------------------ ------------------------
CARRYING ESTIMATED CARRYING ESTIMATED
AMOUNT FAIR VALUE(1) AMOUNT FAIR VALUE(1)
-------- ------------- -------- -------------
(IN MILLIONS) (IN MILLIONS)
<S> <C> <C> <C> <C>
Long-Term Debt(2)........................... $466.1 $ 464.5 $289.1 $294.0
Swap Agreements............................. 32.8 31.0 62.8 58.8
NYMEX-Related Commodity Market Positions.... (73.8) (105.5) (5.1) 10.9
</TABLE>
- ---------------
(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 3 "Long-Term Debt."
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.
F-21
<PAGE> 51
13. CONCENTRATION OF CREDIT RISK
Substantially all of the Company's accounts receivable at December 31, 1996
and 1995 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-22
<PAGE> 52
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 natural gas, crude oil,
condensate, 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, 1996,
1995 and 1994 were based on studies performed by the engineering staff of the
Company for reserves in the United States, Canada, Trinidad and India. Opinions
by DeGolyer and MacNaughton, independent petroleum consultants, for the years
ended December 31, 1996, 1995 and 1994 covering producing areas containing 64%,
60% and 59%, respectively, of proved reserves, excluding deep Paleozoic methane
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. The deep Paleozoic methane
reserves were covered by the opinion of DeGolyer and MacNaughton for the year
ended December 31, 1995. Such estimates by DeGolyer and MacNaughton in the
aggregate varied by not more than 5% from those prepared by the engineering
staff of the Company. All reports by DeGolyer and MacNaughton were developed
utilizing geological and engineering data provided by the Company.
The presentation of estimated proved reserves excludes, for each of the
years presented, those quantities attributable to future deliveries required
under a volumetric production payment. In order to calculate such amounts, the
Company has assumed that deliveries under the volumetric production payment are
made as scheduled at expected British thermal unit factors, and that delivery
commitments are satisfied through delivery, as scheduled, of the related
volumes.
F-23
<PAGE> 53
The Company has also presented, as additional information, proved reserves
including quantities attributable to future deliveries required under the
volumetric production payment. The Company believes that this information is
informative to readers of its financial statements as the related oil and gas
properties costs and deferred revenue are included in the Company's balance
sheets for each of the years presented. This additional information is not
required to be presented in accordance with SFAS No. 69; however, the Company
believes this additional information is useful in assessing its reserve and
financial position on a comprehensive basis.
No major discovery or other favorable or adverse event subsequent to
December 31, 1996 is believed to have caused a material change in the estimates
of proved or proved developed reserves as of that date.
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, 1996, and the changes in the net proved reserves for each of the
three years in the period then ended as estimated by the engineering staff of
the Company.
NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
<TABLE>
<CAPTION>
UNITED STATES CANADA TRINIDAD INDIA TOTAL
------------- ------ -------- ------ -------
<S> <C> <C> <C> <C> <C>
Natural Gas (Bcf)(1)
Net proved reserves at December 31, 1993.... 1,313.2 271.0 100.5 - 1,684.7
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............................... (212.0) (26.3) (23.2) - (261.5)
------- ------ ------ ------ -------
Net proved reserves at December 31, 1994.... 1,307.4 296.6 206.2 29.3 1,839.5
Additional disclosures:
Volumes attributable to volumetric
production payment..................... 70.9 - - - 70.9
------- ------ ------ ------ -------
Net proved reserves at December 31, 1994,
including volumes attributable to
volumetric production payment............ 1,378.3 296.6 206.2 29.3 1,910.4
======= ====== ====== ====== =======
Net proved reserves at December 31, 1994.... 1,307.4 296.6 206.2 29.3 1,839.5
Revisions of previous estimates.......... 10.1 (8.1) 17.5 (29.3) (9.8)
Purchases in place....................... 174.8 - - - 174.8
Extensions, discoveries and other
additions.............................. 1,391.6(2) 54.8 60.8 75.0 1,582.2
Sales in place........................... (38.1) (1.7) - - (39.8)
Production............................... (191.7) (27.7) (39.0) - (258.4)
------- ------ ------ ------ -------
Net proved reserves at December 31, 1995.... 2,654.1(2) 313.9 245.5 75.0 3,288.5
Additional disclosures:
Volumes attributable to volumetric
production payment..................... 54.2 - - - 54.2
------- ------ ------ ------ -------
Net proved reserves at December 31, 1995,
including volumes attributable to
volumetric production payment............ 2,708.3(2) 313.9 245.5 75.0 3,342.7
======= ====== ====== ====== =======
</TABLE>
(Table continued on following page)
F-24
<PAGE> 54
<TABLE>
<CAPTION>
UNITED STATES CANADA TRINIDAD INDIA TOTAL
------------- ------ -------- ------ -------
<S> <C> <C> <C> <C> <C>
Net proved reserves at December 31, 1995.... 2,654.1(2) 313.9 245.5 75.0 3,288.5
Revisions of previous estimates.......... 3.6 (2.9) 79.6 - 80.3
Purchases in place....................... 100.6 0.9 - - 101.5
Extensions, discoveries and other
additions.............................. 256.8 49.2 90.7 124.6 521.3
Sales in place........................... (58.4) (4.3) - - (62.7)
Production............................... (210.2) (35.9) (45.6) - (291.7)
------- ------ ------ ------ -------
Net proved reserves at December 31, 1996.... 2,746.5(2) 320.9 370.2 199.6 3,637.2
Additional disclosures:
Volumes attributable to volumetric
production payment..................... 37.5 - - - 37.5
------- ------ ------ ------ -------
Net proved reserves at December 31, 1996,
including volumes attributable to
volumetric production payment............ 2,784.0(2) 320.9 370.2 199.6 3,674.7
======= ====== ====== ====== =======
Liquids (MBbl)(3)(4)
Net proved reserves at December 31, 1993.... 13,172 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)
------- ------ ------ ------ -------
Net proved reserves at December 31, 1994.... 17,787 7,237 4,429 7,585 37,038
Revisions of previous estimates.......... (413) (351) 396 4,874 4,506
Purchases in place....................... 4,264 - - - 4,264
Extensions, discoveries and other
additions.............................. 8,703 729 3,896 - 13,328
Sales in place........................... (1,241) (9) - - (1,250)
Production............................... (3,701) (1,021) (1,851) (917) (7,490)
------- ------ ------ ------ -------
Net proved reserves at December 31, 1995.... 25,399 6,585 6,870 11,542 50,396
Revisions of previous estimates.......... 339 191 1,835 - 2,365
Purchases in place....................... 312 2 - - 314
Extensions, discoveries and other
additions.............................. 7,103 2,116 1,388 275 10,882
Sales in place........................... (447) (121) - - (568)
Production............................... (3,830) (1,321) (1,925) (1,026) (8,102)
------- ------ ------ ------ -------
Net proved reserves at December 31, 1996.... 28,876 7,452 8,168 10,791 55,287
======= ====== ====== ====== =======
Bcf Equivalent (Bcfe)
Net proved reserves at December 31, 1993.... 1,392.2(5) 303.8 113.8 - 1,809.8
Revisions of previous estimates.......... (4.0) (7.6) 17.8 - 6.2
Purchases in place....................... 21.0 9.2 - 75.0 105.2
Extensions, discoveries and other
additions.............................. 265.8 67.3 130.0 - 463.1
Sales in place........................... (30.9) (1.0) - - (31.9)
Production............................... (229.9) (31.8) (28.8) (0.2) (290.7)
------- ------ ------ ------ -------
Net proved reserves at December 31, 1994.... 1,414.2(5) 339.9 232.8 74.8 2,061.7
Revisions of previous estimates.......... 7.6 (10.2) 19.8 - 17.2
Purchases in place....................... 200.4 - - - 200.4
Extensions, discoveries and other
additions.............................. 1,443.8(2) 59.2 84.2 75.0 1,662.2
Sales in place........................... (45.5) (1.8) - - (47.3)
Production............................... (213.9) (33.8) (50.1) (5.5) (303.3)
------- ------ ------ ------ -------
</TABLE>
(Table continued on following page)
F-25
<PAGE> 55
<TABLE>
<CAPTION>
UNITED STATES CANADA TRINIDAD INDIA TOTAL
------------- ------ -------- ------ -------
<S> <C> <C> <C> <C> <C>
Net proved reserves at December 31, 1995.... 2,806.6(2)(5) 353.3 286.7 144.3 3,590.9
Revisions of previous estimates.......... 5.7 (1.8) 90.6 - 94.5
Purchases in place....................... 102.5 0.9 - - 103.4
Extensions, discoveries and other
additions.............................. 299.4 61.9 99.0 126.2 586.5
Sales in place........................... (61.0) (5.1) - - (66.1)
Production............................... (233.1) (43.9) (57.1) (6.2) (340.3)
------- ------ ------ ------ -------
Net proved reserves at December 31, 1996.... 2,920.1(2) 365.3 419.2 264.3 3,968.9
Additional disclosures:
Volumes attributable to volumetric
production payment..................... 37.5 - - - 37.5
------- ------ ------ ------ -------
Net proved reserves at December 31, 1996,
including volumes attributable to
volumetric production payment............ 2,957.6 365.3 419.2 264.3 4,006.4
======= ====== ====== ====== =======
Net proved developed reserves at
Natural Gas (Bcf)
December 31, 1993................... 1,079.8 250.6 71.4 - 1,401.8
December 31, 1994................... 1,128.2 288.3 206.2 - 1,622.7
December 31, 1995................... 1,218.1 310.1 233.9 - 1,762.1
December 31, 1996................... 1,325.7 319.5 370.2 124.6 2,140.0
Liquids (MBbl)(4)
December 31, 1993................... 11,165 5,409 1,591 - 18,165
December 31, 1994................... 16,770 7,073 4,429 7,585 35,857
December 31, 1995................... 19,977 6,505 5,607 11,542 43,631
December 31, 1996................... 24,868 7,452 8,168 10,791 51,279
Bcf Equivalents
December 31, 1993................... 1,146.8 283.1 80.9 - 1,510.8
December 31, 1994................... 1,228.8 330.7 232.8 45.5 1,837.8
December 31, 1995................... 1,338.0 349.1 267.5 69.3 2,023.9
December 31, 1996................... 1,474.9 364.2 419.2 189.3 2,447.6
Net proved developed reserves, including
amounts attributable to volumetric
production payment at
Natural Gas (Bcf)
December 31, 1993................... 1,167.3 250.6 71.4 - 1,489.3
December 31, 1994................... 1,199.1 288.3 206.2 - 1,693.6
December 31, 1995................... 1,272.3 310.1 233.9 - 1,816.3
December 31, 1996................... 1,363.2 319.5 370.2 124.6 2,177.5
</TABLE>
- ---------------
(1) Billion cubic feet.
(2) Includes 1,180 Bcf of proved undeveloped methane reserves contained, along
with high concentrations of carbon dioxide and other gases in deep Paleozoic
formations in the Big Piney area of Wyoming. The Company is actively
pursuing the consummation of a market or markets from several different
potential sources to facilitate realizing the value of these reserves.
(3) Thousand barrels.
(4) Includes crude oil, condensate and natural gas liquids.
(5) Excludes approximately 87 Bcfe, 71 Bcfe and 54 Bcfe at December 31, 1993,
1994 and 1995, respectively, related to a volumetric production payment.
F-26
<PAGE> 56
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, 1996 and 1995:
<TABLE>
<CAPTION>
1996 1995
----------- -----------
<S> <C> <C>
Proved Properties......................................... $ 3,593,230 $ 3,253,593
Unproved Properties....................................... 159,969 127,331
----------- -----------
Total........................................... 3,753,199 3,380,924
Accumulated depreciation, depletion and amortization...... (1,653,610) (1,499,379)
----------- -----------
Net capitalized costs..................................... $ 2,099,589 $ 1,881,545
=========== ===========
</TABLE>
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>
UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL
------------- ------- -------- ------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
1996
Acquisition Costs of Properties
Unproved........................... $ 38,832 $ 3,565 $ 2,000 $ - $ 77 $ 44,474
Proved............................. 68,706 672 - - - 69,378
-------- ------- ------- ------- ------- --------
Total...................... 107,538 4,237 2,000 - 77 113,852
Exploration Costs.................... 60,880 8,069 2,082 4,092 16,490 91,613
Development Costs.................... 283,985 25,705 6,654 78,754 6,969 402,067
-------- ------- ------- ------- ------- --------
Total...................... $452,403 $38,011 $10,736 $82,846 $23,536 $607,532
======== ======= ======= ======= ======= ========
1995
Acquisition Costs of Properties
Unproved........................... $ 16,196 $ 4,645 $ - $ - $ 1,482 $ 22,323
Proved............................. 122,369 116 - 5,000 - 127,485
-------- ------- ------- ------- ------- --------
Total...................... 138,565 4,761 - 5,000 1,482 149,808
Exploration Costs.................... 47,463 7,197 374 (98) 17,948 72,884
Development Costs.................... 217,674 28,611 32,692 16,756 577 296,310
-------- ------- ------- ------- ------- --------
Total...................... $403,702 $40,569 $33,066 $21,658 $20,007 $519,002
======== ======= ======= ======= ======= ========
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
======== ======= ======= ======= ======= ========
</TABLE>
F-27
<PAGE> 57
Results of Operations for Oil and Gas Producing Activities(1). The
following tables set forth results of operations for oil and gas producing
activities for the years ended December 31:
<TABLE>
<CAPTION>
UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL
------------- ------- -------- ------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
1996
Operating Revenues
Associated Companies................................. $253,629 $13,715 $ - $ - $ - $267,344
Trade................................................ 281,522 48,717 83,536 20,691 - 434,466
Gains on Sales of Reserves and Related Assets........ 19,127 670 - - - 19,797
-------- ------- ------- ------- -------- --------
Total.......................................... 554,278 63,102 83,536 20,691 - 721,607
Exploration Expenses, including Dry Hole............... 45,291 5,003 2,082 748 15,078 68,202
Production Costs....................................... 77,352 16,633 14,577 9,890 - 118,452
Impairment of Unproved Oil and Gas Properties.......... 18,571 2,284 - - 371 21,226
Depreciation, Depletion and Amortization............... 208,872 24,935 15,447 611 648 250,513
-------- ------- ------- ------- -------- --------
Income (Loss) before Income Taxes...................... 204,192 14,247 51,430 9,442 (16,097) 263,214
Income Tax Provision (Benefit)......................... 54,412 5,674 28,287 4,721 (50) 93,044
-------- ------- ------- ------- -------- --------
Results of Operations.................................. $149,780 $ 8,573 $23,143 $ 4,721 $(16,047) $170,170
======== ======= ======= ======= ======== ========
1995
Operating Revenues
Associated Companies................................. $223,652 $ 6,893 $ - $ - $ - $230,545
Trade................................................ 122,567 36,815 71,686 15,411 - 246,479
Gains on Sales of Reserves and Related Assets........ 62,737 84 - - - 62,821
-------- ------- ------- ------- -------- --------
Total.......................................... 408,956 43,792 71,686 15,411 - 539,845
Exploration Expenses, including Dry Hole............... 35,298 3,839 374 (98) 15,542 54,955
Production Costs....................................... 63,734 13,825 8,176 10,553 - 96,288
Impairment of Unproved Oil and Gas Properties.......... 21,981 1,734 - - - 23,715
Depreciation, Depletion and Amortization............... 180,788 19,533 14,633 335 368 215,657
-------- ------- ------- ------- -------- --------
Income (Loss) before Income Taxes...................... 107,155 4,861 48,503 4,621 (15,910) 149,230
Income Tax Provision (Benefit)......................... 1,226 1,133 26,677 2,311 (1,335) 30,012
-------- ------- ------- ------- -------- --------
Results of Operations.................................. $105,929 $ 3,728 $21,826 $ 2,310 $(14,575) $119,218
======== ======= ======= ======= ======== ========
1994
Operating Revenues
Associated Companies................................. $315,866 $ 8,452 $ - $ - $ - $324,318
Trade................................................ 115,375 42,017 35,908 509 - 193,809
Gains 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
======== ======= ======= ======= ======== ========
</TABLE>
- ---------------
(1) 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, 1996. 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.
F-28
<PAGE> 58
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 presentation of the standardized measure of discounted future net cash
flows and changes therein excludes, for each of the years presented, amounts
attributable to future deliveries required under a volumetric production payment
at the equivalent wellhead value. In order to calculate such amounts, the
Company has assumed that deliveries under the volumetric production payment are
made as scheduled and that production costs corresponding to the volumes
delivered are incurred by the Company at average rates for the properties
subject to the production payment.
The Company has also presented, as additional information, the standardized
measure of discounted future net cash flows and changes therein including
amounts attributable to future deliveries required under the volumetric
production payment. The Company believes that this information is informative to
readers of its financial statements because the related oil and gas properties
costs and deferred revenue are shown in the Company's balance sheets for each of
the years presented. This additional information is not required to be presented
in accordance with SFAS No. 69; however, the Company believes this additional
information is useful in assessing its reserve and financial position on a
comprehensive basis.
F-29
<PAGE> 59
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>
UNITED
STATES CANADA TRINIDAD INDIA TOTAL
------ ------ -------- ----- -----
<S> <C> <C> <C> <C> <C>
1996
Future cash inflows(1).................................. $ 9,390,661 $ 715,143 $ 709,082 $ 864,386 $11,679,272
Future production costs................................. (1,639,531) (281,244) (236,643) (338,202) (2,495,620)
Future development costs................................ (306,028) (9,014) (1,588) (150) (316,780)
----------- --------- --------- --------- -----------
Future net cash flows before income taxes............... 7,445,102 424,885 470,851 526,034 8,866,872
Future income taxes..................................... (2,260,500) (98,606) (245,577) (227,177) (2,831,860)
----------- --------- --------- --------- -----------
Future net cash flows................................... 5,184,602 326,279 225,274 298,857 6,035,012
Discount to present value at 10% annual rate............ (2,692,833) (100,521) (68,436) (104,672) (2,966,462)
----------- --------- --------- --------- -----------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves(1)............ 2,491,769 225,758 156,838 194,185 3,068,550
Additional disclosures:
Amounts attributable to volumetric production
payment............................................. 75,081 - - - 75,081
----------- --------- --------- --------- -----------
Total discounted future net revenues, including
amounts attributable to volumetric production
payment............................................. $ 2,566,850 $ 225,758 $ 156,838 $ 194,185 $ 3,143,631
=========== ========= ========= ========= ===========
1995
Future cash inflows(1).................................. $ 3,996,029 $ 502,803 $ 395,328 $ 396,130 $ 5,290,290
Future production costs................................. (747,064) (203,906) (152,287) (202,410) (1,305,667)
Future development costs................................ (297,859) (7,153) (3,610) (13,500) (322,122)
----------- --------- --------- --------- -----------
Future net cash flows before income taxes............... 2,951,106 291,744 239,431 180,220 3,662,501
Future income taxes..................................... (695,843) (46,310) (105,188) (81,349) (928,690)
----------- --------- --------- --------- -----------
Future net cash flows................................... 2,255,263 245,434 134,243 98,871 2,733,811
Discount to present value at 10% annual rate............ (1,015,123) (68,861) (19,217) (45,470) (1,148,671)
----------- --------- --------- --------- -----------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves(1)............ 1,240,140 176,573 115,026 53,401 1,585,140
Additional disclosures:
Amounts attributable to volumetric production
payment............................................. 35,957 - - - 35,957
----------- --------- --------- --------- -----------
Total discounted future net revenues, including
amounts attributable to volumetric production
payment............................................. $ 1,276,097 $ 176,573 $ 115,026 $ 53,401 $ 1,621,097
=========== ========= ========= ========= ===========
1994
Future cash inflows(1).................................. $ 2,315,215 $ 487,050 $ 317,758 $ 168,370 $ 3,288,393
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............... 1,572,515 281,179 228,498 58,030 2,140,222
Future income taxes..................................... (208,163) (57,220) (102,171) (22,482) (390,036)
----------- --------- --------- --------- -----------
Future net cash flows................................... 1,364,352 223,959 126,327 35,548 1,750,186
Discount to present value at 10% annual rate............ (401,547) (67,018) (22,897) (14,730) (506,192)
----------- --------- --------- --------- -----------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves(1)............ 962,805 156,941 103,430 20,818 1,243,994
Additional disclosures:
Amounts attributable to volumetric production
payment............................................. 60,269 - - - 60,269
----------- --------- --------- --------- -----------
Total discounted future net revenues, including
amounts attributable to volumetric production
payment............................................. $ 1,023,074 $ 156,941 $ 103,430 $ 20,818 $ 1,304,263
=========== ========= ========= ========= ===========
</TABLE>
- ---------------
(1) Based on year end market prices determined at the point of delivery from the
producing unit.
F-30
<PAGE> 60
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, 1996.
<TABLE>
<CAPTION>
UNITED
STATES CANADA TRINIDAD INDIA TOTAL
------ ------ -------- ----- -----
<S> <C> <C> <C> <C> <C>
December 31, 1993....................................... $1,262,368(1) $159,771 $ 49,579 $ - $1,471,718
Sales and transfers of oil and gas produced,
net of production costs............................. (339,809) (37,693) (30,825) (483) (408,810)
Net changes in prices and production costs............ (506,273) (65,287) 11,002 - (560,558)
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................................. 145,119 19,762 7,448 - 172,329
Net change in income taxes............................ 167,983 19,966 (45,789) (7,752) 134,408
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....................................... 962,805(1) 156,941 103,430 20,818 1,243,994
Sales and transfers of oil and gas produced, net of
production costs.................................... (268,463) (29,883) (63,510) (4,858) (366,714)
Net changes in prices and production costs............ 12,079 (5,698) (37,035) 7,857 (22,797)
Extensions, discoveries, additions and improved
recovery
net of related costs................................ 376,474(2) 38,028 53,674 46,180 514,356
Development costs incurred............................ 29,100 2,600 1,800 - 33,500
Revisions of estimated development costs.............. 920 139 28,771 4,500 34,330
Revisions of previous quantity estimates.............. 5,694 (5,217) 10,142 (29) 10,590
Accretion of discount................................. 97,248 17,483 17,412 2,857 135,000
Net change in income taxes............................ (132,614) 10,592 (8,048) (28,127) (158,197)
Purchases of reserves in place........................ 193,711 - - - 193,711
Sales of reserves in place............................ (54,441) (569) - - (55,010)
Changes in timing and other........................... 17,627 (7,843) 8,390 4,203 22,377
---------- -------- --------- -------- ----------
December 31, 1995....................................... 1,240,140(1)(2) 176,573 115,026 53,401 1,585,140
Sales and transfers of oil and gas produced, net of
production costs.................................... (437,143) (45,799) (68,959) (10,801) (562,702)
Net changes in prices and production costs............ 1,817,466 57,587 60,387 53,676 1,989,116
Extensions, discoveries, additions and improved
recovery
net of related costs................................ 580,417 62,506 62,165 150,475 855,563
Development costs incurred............................ 57,800 2,200 2,200 - 62,200
Revisions of estimated development costs.............. (14,490) (2,696) 1,010 13,500 (2,676)
Revisions of previous quantity estimates.............. 7,002 (1,227) 79,933 - 85,708
Accretion of discount................................. 137,441 18,387 19,376 8,928 184,132
Net change in income taxes............................ (655,801) (29,814) (73,985) (86,627) (846,227)
Purchases of reserves in place........................ 161,454 456 - - 161,910
Sales of reserves in place............................ (102,671) (3,561) - - (106,232)
Changes in timing and other........................... (299,846) (8,854) (40,315) 11,633 (337,382)
---------- -------- --------- -------- ----------
December 31, 1996....................................... 2,491,769(2) 225,758 156,838 194,185 3,068,550
Additional disclosures:
Amounts attributable to volumetric production
payment............................................. 75,081 - - - 75,081
---------- -------- --------- -------- ----------
Total discounted future net revenues relating to
proved oil and gas reserves, including amounts
attributable to volumetric production payment, at
December 31, 1996................................... $2,566,850 $225,758 $ 156,838 $194,185 $3,143,631
========== ======== ========= ======== ==========
</TABLE>
- ---------------
(1) Excludes $105,323, $60,269 and $35,957 at December 31, 1993, 1994 and 1995,
respectively, related to a volumetric production payment.
(2) Includes approximately $77,453 and $344,319, discounted before income taxes,
in 1995 and 1996, respectively, related to the reserves in the Big Piney
deep Paleozoic formations.
F-31
<PAGE> 61
UNAUDITED QUARTERLY FINANCIAL INFORMATION
<TABLE>
<CAPTION>
QUARTER ENDED
-----------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- -------- -------- --------
<S> <C> <C> <C> <C>
1996
Net Operating Revenues...................... $159,026 $197,113 $170,182 $204,327
======== ======== ======== ========
Operating Income............................ $ 31,997 $ 73,643 $ 46,179 $ 57,011
======== ======== ======== ========
Income before Income Taxes.................. $ 27,338 $ 70,332 $ 43,361 $ 49,931
Income Tax Provision........................ 1,415 22,750 11,994 14,795
-------- -------- -------- --------
Net Income.................................. $ 25,923 $ 47,582 $ 31,367 $ 35,136
======== ======== ======== ========
Earnings per Share of Common Stock.......... $ .16 $ .30 $ .20 $ .22
======== ======== ======== ========
Average Number of Common Shares............. 159,934 159,910 159,850 159,719
======== ======== ======== ========
1995
Net Operating Revenues...................... $155,362 $183,974 $153,006 $156,360
======== ======== ======== ========
Operating Income............................ $ 42,829 $ 73,374 $ 37,925 $ 41,181
======== ======== ======== ========
Income before Income Taxes.................. $ 39,500 $ 71,331 $ 33,344 $ 39,879
Income Tax Provision........................ 9,875 23,193 376 8,492
-------- -------- -------- --------
Net Income.................................. $ 29,625 $ 48,138 $ 32,968 $ 31,387
======== ======== ======== ========
Earnings per Share of Common Stock.......... $ .19 $ .30 $ .21 $ .20
======== ======== ======== ========
Average Number of Common Shares............. 159,972 159,965 159,916 159,817
======== ======== ======== ========
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
======== ======== ======== ========
</TABLE>
F-32
<PAGE> 62
SCHEDULE II
ENRON OIL & GAS COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(IN THOUSANDS)
<TABLE>
<CAPTION>
=========================================================================================================
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ---------------------------------------------------------------------------------------------------------
ADDITIONS DEDUCTIONS FOR
BALANCE AT CHARGED TO PURPOSE FOR BALANCE AT
BEGINNING OF COSTS AND WHICH RESERVES END OF
DESCRIPTION YEAR EXPENSES WERE CREATED YEAR
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1996
Reserves deducted from assets to
which they apply -
Revaluation of Accounts Receivable........ $2,571 $6,897 $2,438 $7,030
====== ====== ====== ======
1995
Reserves deducted from assets to
which they apply -
Revaluation of Accounts Receivable........ $1,022 $1,549 $ - $2,571
====== ====== ====== ======
Litigation Reserve(a)....................... $2,000 $ (379)(b) $1,621 $ -
====== ====== ====== ======
1994
Reserves deducted from assets to
which they apply -
Revaluation of Accounts Receivable........ $1,020 $ 2 $ - $1,022
====== ====== ====== ======
Litigation Reserve(a)....................... $2,000 $3,143 $3,143 $2,000
====== ====== ====== ======
</TABLE>
- ---------------
(a) Included in Other Liabilities in the consolidated balance sheets.
(b) Includes reversal of prior year provision in excess of requirement.
S-1
<PAGE> 63
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.
<TABLE>
<C> <S>
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 No. 33-52201, filed
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 No. 33-58103, filed March
15, 1995).
3.1(d) - Certificate of Amendment of Restated Certificate of
Incorporation of Enron Oil & Gas Company, dated June 11,
1996 (Exhibit 3(d) to Form S-3 Registration Statement No.
333-09919, filed August 9, 1996).
3.2* - By-laws of Enron Oil & Gas Company dated August 23, 1989,
as amended December 12, 1990, February 8, 1994, January 19,
1996 and February 13, 1997.
3.3 - Specimen of Certificate evidencing the Common Stock
(Exhibit 3.3 to Form S-1).
4.3(a) - Amended and Restated Enron Oil & Gas Company 1994 Stock
Plan (Exhibit 4.3 to Form S-8 Registration Statement No.
33-58103, filed March 15, 1995).
4.3(b) - Amendment to Amended and Restated Enron Oil & Gas Company
1994 Stock Plan, dated effective as of December 12, 1995
(Exhibit 4.3(a) to the Company's Annual Report on Form 10-K
for the year ended December 31, 1995).
4.3(c) - Amendment to Amended and Restated Enron Oil & Gas Company
1994 Stock Plan, dated effective as of December 10, 1996
(Exhibit 4.3(a) to Form S-8 Registration Statement No.
333-20841, filed January 31, 1997).
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 - 1995 Tax Allocation Agreement, entered into effective as
of December 14, 1995, between Enron Corp., Enron Oil & Gas
Company, and the subsidiaries of Enron Oil & Gas Company
listed therein as additional parties (Exhibit 10.3 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995).
</TABLE>
E-1
<PAGE> 64
<TABLE>
<S> <C>
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 No. 33-50462, filed 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 (Exhibit 10.9(b) to the Company's Annual
Report on Form 10-K for the year ended December 31, 1994).
10.14(a) - Enron Oil & Gas Company 1993 Nonemployee Directors' Stock
Option Plan (Exhibit 10.14 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1992).
10.14(b)* - First Amendment to Enron Oil & Gas Company 1993
Nonemployee Directors' Stock Option Plan.
10.16 - Interest Rate and Currency Exchange Agreement, dated as of
June 1, 1991, between Enron Risk Management Services Corp.
and Enron Oil & Gas Marketing, 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).
10.23 - 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).
</TABLE>
E-2
<PAGE> 65
<TABLE>
<S> <C>
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).
10.28 - Enron Executive Supplemental Survivor Benefits Plan
Effective January 1, 1987 (Exhibit 10.51 to Form S-1).
10.30 - Credit Agreement between Enron Corp. and Enron Oil & Gas
Company dated September 29, 1995 (Exhibit 10.30 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995).
10.31 - Credit Agreement between Enron Oil & Gas Company and Enron
Corp. dated September 29, 1995 (Exhibit 10.31 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995).
10.34 - Enron Oil & Gas Company 1992 Stock Plan (As Amended and
Restated effective December 14, 1994) (incorporated by
reference to Exhibit A to the Company's Proxy Statement,
dated March 27, 1995, with respect to the Company's 1995
Annual Meeting of Shareholders).
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
(Exhibit 10.37(b) to the Company's Annual Report on Form
10-K for the year ended December 31, 1994).
</TABLE>
E-3
<PAGE> 66
<TABLE>
<S> <C>
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
(Exhibit 10.37(c) to the Company's Annual Report on Form
10-K for the year ended December 31, 1994).
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
(Exhibit 10.37(d) to the Company's Annual Report on Form
10-K for the year ended December 31, 1994).
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
(Exhibit 10.37(e) to the Company's Annual Report on Form
10-K for the year ended December 31, 1994).
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).
10.57(a) - Letter Agreement relating to Natural Gas Swap
Transactions, dated March 31, 1995, among Enron Oil & Gas
Company, Enron Corp. and Enron Capital & Trade Resources
Corp (Exhibit 10.57(a) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1995).
</TABLE>
E-4
<PAGE> 67
<TABLE>
<S> <C>
10.57(b) - Amendment to Natural Gas Swap Transactions Letter
Agreement, dated March 31, 1995, among Enron Oil & Gas
Company, Enron Corp. and Enron Capital & Trade Resources
Corp (Exhibit 10.57(b) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1995).
10.58 - Confirmation Letter (revised due to adjustments to the
attached Payment Schedule), dated March 31, 1995, between
Enron Oil & Gas Company and Enron Capital & Trade Resources
Corp. (ECT Transaction Reference No. 15198.00) (Exhibit
10.58 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1995).
10.59 - Confirmation Letter (revised due to Price Change for 1998
and adjustment to the attached Payment Schedule), dated
March 31, 1995, between Enron Oil & Gas Company and Enron
Capital & Trade Resources Corp. (ECT Transaction Reference
No. 15198.01) (Exhibit 10.59 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1995).
21* - List of subsidiaries.
23.1* - Consent of DeGolyer and MacNaughton.
23.2* - Opinion of DeGolyer and MacNaughton dated January 17,
1997.
23.3* - Consent of Arthur Andersen LLP.
24* - Powers of Attorney.
27* - Financial Data Schedule.
</TABLE>
E-5
<PAGE> 68
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 7th day of
March, 1997.
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 7th day of
March, 1997.
<TABLE>
<CAPTION>
SIGNATURE TITLE
--------- -----
<C> <S>
/s/ FORREST E. HOGLUND Chairman of the Board and Chief Executive
- ----------------------------------------------------- Officer and Director (Principal Executive
(Forrest E. Hoglund) Officer)
/s/ WALTER C. WILSON Senior Vice President and Chief Financial
- ----------------------------------------------------- Officer (Principal Financial Officer)
(Walter C. Wilson)
/s/ BEN B. BOYD Vice President and Controller (Principal
- ----------------------------------------------------- Accounting Officer)
(Ben B. Boyd)
FRED C. ACKMAN* Director
- -----------------------------------------------------
(Fred C. Ackman)
KENNETH L. LAY* Director
- -----------------------------------------------------
(Kenneth L. Lay)
EDWARD RANDALL, III* Director
- -----------------------------------------------------
(Edward Randall, III)
EDMUND P. SEGNER, III* Director
- -----------------------------------------------------
(Edmund P. Segner, III)
*By /s/ ANGUS H. DAVIS
-------------------------------------------------
(Angus H. Davis)
(Attorney-in-fact for persons indicated)
</TABLE>
<PAGE> 69
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
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 No. 33-52201, filed
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 No. 33-58103, filed March
15, 1995).
3.1(d) - Certificate of Amendment of Restated Certificate of
Incorporation of Enron Oil & Gas Company, dated June 11,
1996 (Exhibit 3(d) to Form S-3 Registration Statement No.
333-09919, filed August 9, 1996).
3.2* - By-laws of Enron Oil & Gas Company dated August 23, 1989,
as amended December 12, 1990, February 8, 1994, January 19,
1996 and February 13, 1997.
3.3 - Specimen of Certificate evidencing the Common Stock
(Exhibit 3.3 to Form S-1).
4.3(a) - Amended and Restated Enron Oil & Gas Company 1994 Stock
Plan (Exhibit 4.3 to Form S-8 Registration Statement No.
33-58103, filed March 15, 1995).
4.3(b) - Amendment to Amended and Restated Enron Oil & Gas Company
1994 Stock Plan, dated effective as of December 12, 1995
(Exhibit 4.3(a) to the Company's Annual Report on Form 10-K
for the year ended December 31, 1995).
4.3(c) - Amendment to Amended and Restated Enron Oil & Gas Company
1994 Stock Plan, dated effective as of December 10, 1996
(Exhibit 4.3(a) to Form S-8 Registration Statement No.
333-20841, filed January 31, 1997).
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 - 1995 Tax Allocation Agreement, entered into effective as
of December 14, 1995, between Enron Corp., Enron Oil & Gas
Company, and the subsidiaries of Enron Oil & Gas Company
listed therein as additional parties (Exhibit 10.3 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995).
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 No. 33-50462, filed 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 (Exhibit 10.9(b) to the Company's Annual
Report on Form 10-K for the year ended December 31, 1994).
10.14(a) - Enron Oil & Gas Company 1993 Nonemployee Directors' Stock
Option Plan (Exhibit 10.14 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1992).
</TABLE>
<PAGE> 70
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
10.14(b)* - First Amendment to Enron Oil & Gas Company 1993
Nonemployee Directors' Stock Option Plan.
10.16 - Interest Rate and Currency Exchange Agreement, dated as of
June 1, 1991, between Enron Risk Management Services Corp.
and Enron Oil & Gas Marketing, 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).
10.23 - 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).
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).
10.28 - Enron Executive Supplemental Survivor Benefits Plan
Effective January 1, 1987 (Exhibit 10.51 to Form S-1).
10.30 - Credit Agreement between Enron Corp. and Enron Oil & Gas
Company dated September 29, 1995 (Exhibit 10.30 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995).
10.31 - Credit Agreement between Enron Oil & Gas Company and Enron
Corp. dated September 29, 1995 (Exhibit 10.31 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995).
10.34 - Enron Oil & Gas Company 1992 Stock Plan (As Amended and
Restated effective December 14, 1994) (incorporated by
reference to Exhibit A to the Company's Proxy Statement,
dated March 27, 1995, with respect to the Company's 1995
Annual Meeting of Shareholders).
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).
</TABLE>
<PAGE> 71
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
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
(Exhibit 10.37(b) to the Company's Annual Report on Form
10-K for the year ended December 31, 1994).
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
(Exhibit 10.37(c) to the Company's Annual Report on Form
10-K for the year ended December 31, 1994).
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
(Exhibit 10.37(d) to the Company's Annual Report on Form
10-K for the year ended December 31, 1994).
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
(Exhibit 10.37(e) to the Company's Annual Report on Form
10-K for the year ended December 31, 1994).
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).
</TABLE>
<PAGE> 72
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
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).
10.57(a) - Letter Agreement relating to Natural Gas Swap
Transactions, dated March 31, 1995, among Enron Oil & Gas
Company, Enron Corp. and Enron Capital & Trade Resources
Corp (Exhibit 10.57(a) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1995).
10.57(b) - Amendment to Natural Gas Swap Transactions Letter
Agreement, dated March 31, 1995, among Enron Oil & Gas
Company, Enron Corp. and Enron Capital & Trade Resources
Corp (Exhibit 10.57(b) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1995).
10.58 - Confirmation Letter (revised due to adjustments to the
attached Payment Schedule), dated March 31, 1995, between
Enron Oil & Gas Company and Enron Capital & Trade Resources
Corp. (ECT Transaction Reference No. 15198.00) (Exhibit
10.58 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1995).
10.59 - Confirmation Letter (revised due to Price Change for 1998
and adjustment to the attached Payment Schedule), dated
March 31, 1995, between Enron Oil & Gas Company and Enron
Capital & Trade Resources Corp. (ECT Transaction Reference
No. 15198.01) (Exhibit 10.59 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1995).
21* - List of subsidiaries.
23.1* - Consent of DeGolyer and MacNaughton.
23.2* - Opinion of DeGolyer and MacNaughton dated January 17,
1997.
23.3* - Consent of Arthur Andersen LLP.
24* - Powers of Attorney.
27* - Financial Data Schedule.
</TABLE>
<PAGE> 1
EXHIBIT 3.2
BYLAWS
OF
ENRON OIL & GAS COMPANY
A Delaware Corporation
Date of Adoption: August 23, 1989
As Amended: December 12, 1990,
February 8, 1994,
January 19, 1996,
February 13, 1997.
<PAGE> 2
BYLAWS
Table of Contents
<TABLE>
<CAPTION>
Page
----
<S> <C> <C> <C>
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 4
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 8
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
</TABLE>
<PAGE> 3
<TABLE>
<CAPTION>
Page
----
<S> <C> <C> <C>
Section 12. Approval or Ratification of Acts or
Contracts by Stockholders 10
Section 13. Retirement 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 14
Section 6. General Counsel 14
Section 7. Secretary 14
Section 8. Deputy Corporate Secretary and
Assistant Secretaries 14
Section 9. Treasurer 14
Section 10. Assistant Treasurers 15
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
</TABLE>
-3-
<PAGE> 4
<TABLE>
<CAPTION>
Page
----
<S> <C> <C>
Section 3.Ownership of Shares 16
Section 4.Regulations Regarding Certificates 16
Section 5.Lost or Destroyed Certificates 16
Article VII. Miscellaneous Provisions
------------------------
Section 1.Fiscal year 17
Section 2.Corporate Seal 17
Section 3.Notice and Waiver of Notice 17
Section 4.Facsimile Signatures 18
Section 5.Reliance upon Books, Reports and
Records 18
Section 6.Application of Bylaws 18
Article VIII. Amendments 18
----------
</TABLE>
-4-
<PAGE> 5
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
<PAGE> 6
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.
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
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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.
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<PAGE> 8
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
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<PAGE> 9
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 meeting and who
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<PAGE> 10
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.
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<PAGE> 11
The number of directors which shall constitute the whole Board of
Directors shall 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.
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<PAGE> 12
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) 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.
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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, 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
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may be stated as such in any document or instrument filed with the Secretary of
State of the state of incorporation of the Corporation.
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.
Section 13. Retirement. No person serving as a director of the
Corporation on February 13, 1997, shall be eligible to stand for reelection as
a director of the Corporation after such person has attained the age of 73
years.
No person first elected as a director of the Corporation after February
13, 1997, shall be eligible to stand for reelection as a director of the
Corporation after such person has attained the age of 72 years.
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,
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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 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
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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.
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, one or more Presidents-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.
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(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.
(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, each
President-International 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 each President-International 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 each 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.
-13-
<PAGE> 18
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 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
-14-
<PAGE> 19
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, 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
-15-
<PAGE> 20
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 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
-16-
<PAGE> 21
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, 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.
-17-
<PAGE> 22
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 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-
<PAGE> 1
EXHIBIT 10.14(b)
FIRST AMENDMENT TO
ENRON OIL & GAS COMPANY
1993 NONEMPLOYEE DIRECTORS STOCK OPTION PLAN
WHEREAS, Enron Oil & Gas Company (the "Company") has heretofore adopted and
maintains the Enron Oil & Gas Company 1993 Nonemployee Directors Stock Option
Plan (the "Plan"); and
WHEREAS, the Company desires to amend the Plan with respect to Options
granted to Nonemployee Directors;
NOW, THEREFORE, the Plan is hereby amended as follows:
Effective February 13, 1997, Paragraph III of the Plan is deleted in its
entirety and replaced with the following:
"III. Eligibility of Optionee
Options may be granted only to individuals who are Nonemployee
Directors. Each Nonemployee Director who is elected or appointed to the
Board of Directors of the Company (the "Board") for the first time after
the effective date of the Plan shall be granted, as of the date of his or
her election or appointment and without the exercise of the discretion of
any person, an Option exercisable for 7,000 Shares (subject to adjustment
in the same manner as provided in Paragraph VII hereof with respect to
Shares subject to Options then outstanding). As of the date of the annual
meeting of the stockholders of the Company in each year that the Plan is in
effect as provided in Paragraph VI hereof, each Nonemployee Director who is
in office immediately after such meeting and who is not then entitled to
receive an Option pursuant to the preceding provisions of this Paragraph
III shall be granted, without the exercise of the discretion of any person,
an Option exercisable for 7,000 Shares (subject to adjustment in the same
manner as provided in Paragraph VII hereof with respect to Shares subject
to Options then outstanding)."
AS AMENDED HEREBY, the Plan is specifically ratified and reaffirmed.
Dated effective as of February 13, 1997.
<TABLE>
<C> <C>
ATTEST: ENRON OIL & GAS COMPANY
By: /s/ J. CHRIS BRYAN
By: /s/ ANGUS H. DAVIS ----------------------------------------
J. Chris Bryan
- -------------------------------------------- Vice President, Administration &
Angus H. Davis Human Resources
Vice President, Communications and
Corporate Secretary
</TABLE>
<PAGE> 1
ENRON OIL & GAS COMPANY
LIST OF SUBSIDIARIES EXHIBIT 21
<TABLE>
<CAPTION>
Date of Where
Company Name Incorporation Incorporated
- ------------------------------------------------------------------------------- ---------------- --------------------
<S> <C> <C>
International Subsidiaries:
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 Oil & Gas International Finance B.V. 09/27/96 The Netherlands
Enron Gas & Oil Trinidad Limited 11/04/92 Trinidad
Enron Oil & Gas Capital Management I, Ltd. 12/08/95 Cayman Islands
EOGI - Trinidad U(a) Block, Inc. 11/07/95 Delaware
EOGI Trinidad - U(a) Block Company 11/09/95 Cayman Islands
Enron Gas & Oil Trinidad - U(a) Block Limited 11/10/95 Cayman Islands
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-Kazakhstan, Inc. 07/29/93 Delaware
Enron Oil & Gas Kazakhstan Ltd. 08/18/94 Cayman Islands
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
EOGI - Kuwait, Inc. 04/11/95 Delaware
Enron Oil & Gas Kuwait Ltd. 04/12/95 Cayman Islands
EOGI - Algeria, Inc. 11/07/95 Delaware
Enron Oil & Gas Algeria Ltd. 11/09/95 Cayman Islands
Enron Oil & Gas Jordan Ltd. 12/08/95 Cayman Islands
EOGI - Venezuela, Inc. 06/17/96 Delaware
EOGI Venezuela Company 06/20/96 Cayman Islands
Gulf of Paria East Operating Company 06/21/96 Cayman Islands
Enron Oil & Gas Venezuela Ltd. 01/11/96 Cayman Islands
Administradora del Golfo de Paria Este, S.A. 08/07/96 Venezuela
EOGI Venezuela (Guarico), Inc. 05/15/96 Delaware
Enron Oil & Gas Venezuela - Guarico Ltd. 04/03/96 Cayman Islands
EOGI - China (Sichuan), Inc. 05/07/96 Delaware
Enron Oil & Gas China (Sichuan) Ltd. 05/08/96 Cayman Islands
EOGI - Mozambique, Inc. 05/15/96 Delaware
Enron Oil & Gas Mozambique Ltd. 05/16/96 Cayman Islands
</TABLE>
Page 1 of 2
<PAGE> 2
<TABLE>
<CAPTION>
Date of Where
Company Name Incorporation Incorporated
- ------------------------------------------------------------------------------- ---------------- --------------------
<S> <C> <C>
Domestic Subsidiaries:
Enron Oil & Gas Company 06/12/85 Delaware
Enron Oil & Gas - Carthage, Inc. 03/21/95 Delaware
ERSO, Inc. 04/24/67 Texas
Enron Oil & Gas Property Management, Inc. 04/20/95 Delaware
Enron Oil & Gas Investments, Inc. 04/24/95 Delaware
Enron Oil & Gas Acquisitions L.P. 04/24/95 Delaware
EOG Expat Services, Inc. 02/01/96 Delaware
Enron Oil & Gas Marketing, Inc. 04/09/90 Delaware
EOG - Canada, Inc. 03/13/85 Delaware
EOG Company of Canada 12/14/95 Nova Scotia
EOG Canada Company Ltd. 12/12/95 Alberta
Enron Oil Canada Ltd. 04/01/82 Alberta
Nilo Operating Company 04/04/94 Delaware
</TABLE>
Page 2 or 2
<PAGE> 1
EXHIBIT 23.1
DEGOLYER AND MACNAUGHTON
ONE ENERGY SQUARE
DALLAS, TEXAS 75206
March 4, 1997
Enron Oil & Gas Company
1400 Smith Street
Houston, Texas 77002
Gentlemen:
We hereby consent to the references to our firm and to the opinions
delivered to Enron Oil & Gas Company (the Company) regarding our comparison of
estimates prepared by us with those furnished to us by the Company of the proved
oil, condensate, natural gas liquids, and natural gas reserves of certain
selected properties owned by the Company. The opinions are contained in our
letter reports dated January 13, 1995, January 22, 1996, and January 17, 1997,
for estimates as of January 1, 1995, December 31, 1995, and December 31, 1996,
respectively. The opinions are referred to 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, 1996, to be filed with the Securities and Exchange Commission on or
about March 7, 1996. DeGolyer and MacNaughton also consents to the inclusion of
our letter report, dated January 17, 1997, addressed to the Company as Exhibit
(23.2) to the Company's Annual Report on Form 10-K for the year ended December
31, 1996, 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, 33-52201, 33-58103,
33-62005, 33-64055, 333-09919, 333-20841, and 333-18511.
Very truly yours,
/s/ DeGOLYER AND MacNAUGHTON
DeGOLYER and MacNAUGHTON
<PAGE> 1
EXHIBIT 23.2
DEGOLYER AND MACNAUGHTON
ONE ENERGY SQUARE
DALLAS, TEXAS 75206
January 17, 1997
Enron Oil & Gas Company
1400 Smith Street
Houston, Texas 77002
Gentlemen:
Pursuant to your request, we have prepared estimates, as of December 31,
1996, of the proved oil, condensate, natural gas liquids, and natural gas
reserves of certain selected properties in the United States, Canada, and
Trinidad owned by Enron Oil & Gas Company (Enron). The properties consist of
working interests located onshore in the states of New Mexico, Texas, Utah, and
Wyoming and in the offshore waters of Texas, Louisiana, and Alabama, in the
province of Saskatchewan in Canada, and in the offshore waters of Trinidad. The
estimates are reported in detail in our "Report as of December 31, 1996 on
Proved Reserves of Certain Properties in the United States owned by Enron Oil &
Gas Company -- Selected Properties," our "Report as of December 31, 1996 on
Proved Reserves of Certain Properties in Canada owned by Enron Oil & Gas
Company -- Selected Properties," and our "Report as of December 31, 1996 on
Proved Reserves of the Kiskadee Field, SECC Block, Offshore Trinidad for Enron
Oil and Gas Company," hereinafter collectively referred to as the "Reports." We
also have reviewed information provided to us by Enron that it represents to be
Enron's estimates of the reserves, as of December 31, 1996, 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 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 December
31, 1996, net to its leasehold interests in the properties included in the
Reports are as follows, expressed in thousands of barrels (Mbbl) and millions of
cubic feet (MMcf):
<TABLE>
<CAPTION>
OIL, CONDENSATE, AND
NATURAL GAS LIQUIDS NATURAL GAS NET EQUIVALENT
(MBBL) (MMCF) (MMCF)
- --------------------- ----------- --------------
<C> <C> <C>
26,881 1,620,022 1,781,308
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.
</TABLE>
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 December 31, 1996, are as follows, expressed in thousands (Mbbl) and
millions of cubic feet (MMcf):
<PAGE> 1
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 Statements File Nos. 33-42620, 33-62005, 333-18511
and 333-20841.
Houston, Texas ARTHUR ANDERSEN LLP
March 7, 1997
<PAGE> 1
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, 1996, 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 13th day
of February, 1997.
/s/ Fred C. Ackman
--------------------------------------------
Fred C. Ackman
<PAGE> 2
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, 1996, 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 13th day
of February, 1997.
/s/ Edward Randall, III
--------------------------------------------
Edward Randall, III
<PAGE> 3
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, 1996, 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 13th day
of February, 1997.
/s/ Kenneth L. Lay
--------------------------------------------
Kenneth L. Lay
<PAGE> 4
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, 1996, 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 13th day
of February, 1997.
/s/ Edmund P. Segner, III
--------------------------------------------
Edmund P. Segner, III
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
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