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AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON MARCH 5, 1997
REGISTRATION NO. 333-
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
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BLAZER ENERGY CORP.
(Exact name of Registrant as specified in its charter)
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<C> <C> <C>
DELAWARE 1311 61-1093943
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of incorporation or organization) Classification Code Number) Identification No.)
W. P. TIEFEL
PRESIDENT AND CHIEF EXECUTIVE OFFICER
14701 ST. MARY'S LANE BLAZER ENERGY CORP.
SUITE 200 14701 ST. MARY'S LANE
HOUSTON, TEXAS 77079 SUITE 200
(281) 531-2900 HOUSTON, TEXAS 77079
(Address, including zip code, and telephone number, (281) 531-2900
Including area code, of Registrant's principal (Address, including zip code, and telephone number,
executive offices) Including area code, of agent for service)
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Copies to:
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<C> <C>
ROBERT H. WHILDEN, JR., ESQ. SUSAN WEBSTER, ESQ.
VINSON & ELKINS L.L.P. CRAVATH, SWAINE & MOORE
2300 FIRST CITY TOWER WORLDWIDE PLAZA
1001 FANNIN 825 EIGHTH AVENUE
HOUSTON, TEXAS 77002-6760 NEW YORK, NEW YORK 10019
(713) 758-2222 (212) 474-1000
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APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after this Registration Statement becomes effective.
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If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, please check the following box. [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ] ---------------
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ] ---------------
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
CALCULATION OF REGISTRATION FEE
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PROPOSED
TITLE OF EACH CLASS OF MAXIMUM AGGREGATE AMOUNT OF
SECURITIES TO BE REGISTERED OFFERING PRICE(1)(2) REGISTRATION FEE
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Common Stock, $.01 par value......................... $85,000,000 $25,757.58
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(1) Calculated pursuant to Rule 457(o) under the Securities Act of 1933.
Includes shares subject to an over-allotment option.
(2) Estimated solely for the purpose of calculating the registration fee.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a),
MAY DETERMINE.
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<PAGE> 2
INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A
REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR MAY
OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT BECOMES
EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR THE
SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE SECURITIES
IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE UNLAWFUL PRIOR
TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS OF ANY SUCH STATE.
SUBJECT TO COMPLETION, DATED MARCH 5, 1997
PROSPECTUS
3,100,000 SHARES
BLAZER ENERGY CORP.
COMMON STOCK
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All of the shares of Common Stock, par value $.01 per share ("Common
Stock"), offered hereby (the "Offering") are being sold by Blazer Energy Corp.
(formerly Ashland Exploration, Inc.) (the "Company"). The Company is a
wholly-owned subsidiary of Ashland Inc. ("Ashland"). Upon completion of the
Offering, Ashland will own approximately 82.3% (80.2% if the Underwriters'
over-allotment option is exercised in full) of the outstanding Common Stock of
the Company. Ashland has announced that, after the Offering and subject to
certain conditions described herein, it intends to distribute to its
stockholders its remaining shares of Common Stock of the Company in a tax-free
distribution. See "Relationship Between the Company and Ashland -- Intended Spin
Off by Ashland."
Prior to this Offering, there has been no public market for the Common
Stock. It is currently estimated that the initial public offering price will be
between $ and $ per share. For a discussion of the factors
that will be considered in determining the initial public offering price, see
"Underwriting."
Application will be made to list the Common Stock on the New York Stock
Exchange under the symbol " ."
SEE "RISK FACTORS" BEGINNING ON PAGE 12 FOR CERTAIN CONSIDERATIONS RELEVANT
TO AN INVESTMENT IN THE COMMON STOCK OFFERED HEREBY.
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THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS.
ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
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UNDERWRITING PROCEEDS TO
PRICE TO PUBLIC DISCOUNT(1) COMPANY(2)
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Per Share......................... $ $ $
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Total(3).......................... $ $ $
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(1) The Company has agreed to indemnify the several Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as
amended. See "Underwriting."
(2) Before deducting expenses payable by the Company estimated at $ .
(3) The Company has granted the Underwriters an option for 30 days to purchase
up to an additional 465,000 shares of Common Stock at the Price to Public,
less Underwriting Discount, solely to cover over-allotments, if any. If such
option is exercised in full, the total Price to Public, Underwriting
Discount and Proceeds to Company will be $ , $ and
$ , respectively. See "Underwriting."
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The shares of Common Stock are offered by the several Underwriters, subject
to prior sale, when, as and if issued to and accepted by them, and subject to
approval of certain legal matters by counsel for the Underwriters and certain
other conditions. The Underwriters reserve the right to withdraw, cancel or
modify such offer and to reject orders in whole or in part. It is expected that
delivery of the shares of Common Stock will be made in New York, New York on or
about , 1997.
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MERRILL LYNCH & CO.
CREDIT SUISSE FIRST BOSTON
GOLDMAN, SACHS & CO.
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The date of this Prospectus is , 1997.
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[MAPS]
Map 1: Map of the United States, including the Company's properties in the
Appalachian Region and the New Albany Shale Formation, with an expanded view of
the Company's properties in the Gulf of Mexico Region, including the Vermilion
410 complex.
Map 2: Map of Africa with an expanded view of the Company's Nigerian properties,
including OPL 98, OPL 118 and OPLs 90/225.
CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN, OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK
OFFERED HEREBY, INCLUDING STABILIZING TRANSACTIONS, SYNDICATE COVERING
TRANSACTIONS AND PENALTY BIDS. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE
"UNDERWRITING."
2
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PROSPECTUS SUMMARY
The following summary is qualified in its entirety by, and should be read
in conjunction with, the more detailed information and consolidated financial
statements, including the notes thereto, appearing elsewhere in this Prospectus.
Unless otherwise indicated, all information in this Prospectus assumes the
Underwriters' over-allotment option is not exercised and gives effect to a
1,440,000 for 1 split of the Common Stock effected in March 1997. All references
to the "Company" herein refer to Blazer Energy Corp., its consolidated
subsidiaries and its predecessors. Except as indicated otherwise, all reserve
information set forth in this Prospectus is based upon the reserve reports of
Netherland, Sewell & Associates, Inc. ("Netherland Sewell"). Certain oil and gas
industry terms used in this Prospectus are defined herein in the "Glossary of
Oil and Gas Terms."
THE COMPANY
Blazer Energy Corp. (formerly Ashland Exploration, Inc.) is an independent
energy company engaged in the exploration for and the development, production,
acquisition and marketing of natural gas and oil in the United States and in
Nigeria. The Company is currently a wholly-owned subsidiary of Ashland Inc.
("Ashland").
The Company has been active in the natural gas and oil business in the
United States for over 80 years and in Nigeria for over 20 years. In the United
States, the Company's production is concentrated in the Appalachian Basin and in
the Gulf of Mexico. Internationally, the Company operates both onshore and
offshore Nigeria in the deltaic region of the Niger River. All of the Company's
natural gas production comes from the United States, while substantially all of
its crude oil production comes from Nigeria. The Company also owns mineral
royalty interests in oil and gas properties throughout the United States.
At September 30, 1996, the Company's net proved reserves were 770.6 Bcfe,
which was comprised of 576.9 Bcf of gas and 32.3 MMBbls of oil. During the five
fiscal years ended September 30, 1996, the Company increased its net proved
reserves by 54%, from 499.1 Bcfe at September 30, 1991 to 770.6 Bcfe at
September 30, 1996, through a successful exploration and development program and
a series of strategic property acquisitions. The Company's average net natural
gas production over the same period increased by 38%, from 78.3 MMcf per day in
fiscal 1992 to 108.4 MMcf per day in fiscal 1996. For the quarter ended December
31, 1996, total average net natural gas and oil production was 214.8 MMcfe per
day, consisting of 105.8 MMcf per day of natural gas and 18.2 MBbls of oil per
day. The Company's average oil production decreased from 26.9 MBbls per day in
fiscal 1992 to 18.1 MBbls per day in fiscal 1996 due to a period of relatively
low capital investment by the Company in Nigeria in prior years. To reverse this
trend, the Company began in fiscal 1995 to increase significantly its Nigerian
capital expenditures for exploration and development. The SEC Present Value of
the Company's proved reserves before U.S. income taxes was $350 million as of
September 30, 1996. For the purpose of comparing the SEC Present Value of the
Company's reserves with those of companies having a calendar year end, if the
Company's SEC Present Value before U.S. income taxes were calculated using
September 30, 1996 reserve quantities but using gas and oil prices in effect at
December 31, 1996, such value would have been $889 million, although natural gas
and oil prices are currently at levels more similar to September 30, 1996
prices. See "Business and Properties -- Reserves."
The Company intends to continue its reserve and production growth in the
Appalachian Basin and to accelerate such growth in the Gulf of Mexico and
Nigeria. The Company spent approximately $87 million for exploration and
development for the year ended September 30, 1996 and plans to spend
approximately $112 million and $134 million during the 1997 and 1998 fiscal
years, respectively.
In December 1996, the Company significantly enhanced its existing Gulf of
Mexico operations with the initiation of production from the Vermilion 410
field, from which the Company averaged net natural gas production of 29.4 MMcf
per day for the month of February 1997. In Nigeria, the Company recently filed a
development plan with respect to what it believes to be a commercial oilfield
discovery called the Okwori South field, from which the Company expects to begin
production in the second half of calendar 1998.
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The Company owns working interests in approximately 1,425 gross wells that
qualify for unconventional fuel tax credits ("Section 29 tax credits") which
have generated $59.8 million of tax credits for Ashland through September 30,
1996, including $10.5 million in fiscal 1996. The Company recently entered into
a letter of intent under which it will monetize these tax credits to maximize
their benefit to the Company (the "Section 29 Monetization"). Under the terms of
the agreement, the Company will sell its properties that are eligible for
Section 29 tax credits (the "Section 29 Tax Credit Properties") but continue to
operate and be entitled to all of the cash flow from the properties until
approximately 94% of the net present value of the reserves have been produced.
The proposed transaction contemplates that the Company will receive a cash
payment of $6.5 million at closing, plus additional quarterly payments through
2002 reflecting the value of the Section 29 tax credits generated from the
properties, which payments are expected to be approximately $2.5 million per
quarter in 1997, declining to approximately $2.0 million per quarter in 2002. In
connection with the transaction, the buyer will apply for a ruling from the
Internal Revenue Service with regard to certain aspects of the transaction. In
the event a favorable ruling is not received on or before September 15, 1997,
the buyer will have the right to rescind the transaction. Closing of the
transaction, which is expected to occur in April 1997, is subject to
contingencies, including completion of due diligence, receipt of certain
consents and negotiation of definitive documents. See "Business and
Properties -- Section 29 Tax Credits."
COMPANY STRENGTHS
STABILITY OF APPALACHIAN PRODUCTION. The Company has been a leading
producer and operator in the Appalachian Basin for over 80 years. Over the past
five fiscal years, the Company has drilled 493 net wells in Appalachia with a
99% success rate, and through its drilling and acquisition projects, has
increased net proved reserves by 45% while extending the boundaries of
productive areas. At September 30, 1996, the Company had net proved reserves of
541.0 Bcfe in Appalachia, of which 461.1 Bcfe, or 85%, were proved developed.
The Company has an average working interest of 89% in approximately 1,050,000
gross acres in Appalachia. The Company's properties have extensive production
histories, and the Company believes that such properties contain significant
reserve and production enhancement opportunities. The Company plans to further
exploit opportunities on its properties and has identified approximately 400
development well locations that it intends to pursue over the next five years.
The Company's 1,200 mile gas gathering system in Appalachia is interconnected
with various intrastate and interstate transmission lines, which gives the
Company access to both local markets and major northeastern United States
markets. The long-life, stable production and cash flow from the Company's
properties in Appalachia help to offset the risks of and fund the Company's
higher return opportunities in the Gulf of Mexico and Nigeria.
OVER 20 YEARS OF SUCCESSFUL NIGERIAN OPERATIONS. The Company has been
active in Nigeria since 1973, with oil production commencing in and continuing
uninterrupted since 1975, notwithstanding periods of political instability in
the region. The Company believes the stability of its operations during this
period can be attributed to its long-standing relationship with the Nigerian
National Petroleum Corporation (the "NNPC"), the Nigerian state-owned petroleum
company, and the recognition by successive Nigerian administrations of the oil
sector's importance to Nigeria's economy, which has been evidenced by Nigeria's
continued administrative support and consistent economic policies that serve to
preserve the petroleum industry. The Company believes it is one of only two
foreign independent energy companies with production in Nigeria and one of
several foreign operators in the country, which include subsidiaries or
affiliates of Shell Oil Company ("Shell"), Chevron Corporation ("Chevron"),
Mobil Corporation ("Mobil"), Texaco Inc. ("Texaco"), Elf Aquitaine ("Elf") and
Agip SpA ("Agip"). In Nigeria, the Company operates under two production sharing
contracts ("PSCs"), the first of which was originally signed in 1973 and the
second of which was signed in 1992. The 1973 PSC, in which the Company owns a
100% working interest, pertains to oil prospecting licenses ("OPLs") 98 and 118,
which together cover 177,000 acres. The Company commenced production under the
1973 PSC in 1975, had peak daily production of 46.5 MBbls of oil per day in
November 1989 and has had cumulative production from the 1973 PSC acreage of
approximately 161 MMBbls of oil through September 30, 1996. The 1992 PSC, which
the Company operates with a 50% partner, Total Exploration Nigeria Ltd.
("Total"), pertains to OPLs 90 and 225, which together cover 450,000 gross acres
and include the Okwori South field discovery.
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EXPERTISE IN DELTAIC ENVIRONMENTS. The Company has conducted significant
exploration activities in the Mississippi River deltaic region since 1984 and in
the Niger River deltaic region in Nigeria since 1973. These two environments
have similar geologic characteristics, which gives the Company flexibility in
the utilization of its geoscience staff. An important factor in successful
exploration in these environments is the computer-aided interpretation of 3-D
seismic surveys and the integration of such data with subsurface data. The
Company has a staff of 13 geoscientists who are experienced at using such
technology to evaluate opportunities in these deltaic environments. The
Company's operating personnel have expertise in conventional, high angle and
horizontal drilling and producing in these environments. The Company's recent
discoveries of the Vermilion 410 field in the Gulf of Mexico and the Okwori
South field in Nigeria were the result of the use of these technologies. The
Company believes that its skills in geoscience evaluation and operations would
be easily transferrable to deltaic areas in other West African countries.
EFFICIENT OPERATOR. The Company operates approximately 93% of its
production, which provides a significant advantage in controlling costs,
allocating capital and timing the development and exploitation of its
properties. The Company's personnel have considerable expertise in planning and
conducting a variety of oil and gas operations, ranging from air drilling and
stimulation in the tight formations in Appalachia to offshore projects with
complex technical and logistical requirements. The Company's lease operating
expenses in the U.S. averaged $0.47 per Mcfe for the fiscal year ended September
30, 1996 and $0.43 per Mcfe for the quarter ended December 31, 1996. The Company
also believes it is a low-cost developer of reserves in Appalachia, and over the
past three fiscal years has reduced its drilling cost per well in the region by
approximately 28%.
SUCCESSFUL ACQUISITION HISTORY. Since 1990, the Company has spent a total
of approximately $172 million to acquire properties in Appalachia from Oxy
U.S.A., Inc., UMC Petroleum Corp. and Waco Oil & Gas Co., Inc. The acreage
acquired in these transactions is in close proximity to the Company's existing
operations in Appalachia, allowing the Company to reduce expenses on a per Mcf
basis through efficient consolidation. The Company has increased both reserves
and production by drilling a total of 532 successful net wells on these acquired
properties through December 31, 1996. The Company's selective acquisition
strategy has made these acquisitions attractive rate of return ventures.
BUSINESS STRATEGY
The Company's strategy is to capitalize on its strengths to increase cash
flow and shareholder value by increasing both its reserves and production
through the development and exploration of existing properties and the
acquisition of additional properties with development and exploration potential.
The Company intends to implement this strategy as described below.
ENHANCING APPALACHIAN POSITION. The Company is continuing to develop its
large leasehold position in the Appalachian Basin, where it has approximately
900,000 net acres and 256 net proved undeveloped drilling locations at September
30, 1996. The Company expects to drill approximately 85 wells per year over each
of the next two years, which are expected to require approximately $17 million
per year in capital spending. The Company is also currently evaluating
opportunities for infill drilling in the Appalachian Basin that could enhance
both its reserves and production in the area. The long-life, stable reserves in
Appalachia provide a source of cash for the Company to invest in higher return
opportunities in the Gulf of Mexico and international locations.
INCREASING EXPLORATION AND EXPLOITATION OF HIGH POTENTIAL AREAS. The
Company intends to increase its level of exploration and exploitation drilling
and currently has attractive leads and prospects on its existing acreage in the
Gulf of Mexico and Nigeria. The Company evaluates almost all of its prospects
with 3-D seismic data prior to drilling, which the Company believes enhances the
potential for returns and lowers dry hole exposure.
In the Gulf of Mexico, the Company has interests in 62 offshore blocks, or
about 150,000 net acres, with an average working interest of 51%. The Company
has an inventory of approximately 17 prospects in the Gulf of Mexico and plans
to participate in eight wells in the 1997 fiscal year. The Company currently has
rights to approximately 148 square miles of 3-D seismic data on 19 of its 62
offshore leases in the Gulf of Mexico and
5
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over 63,000 linear miles of 2-D seismic data in the Gulf of Mexico, primarily
offshore Louisiana. Capital expenditures in the Gulf of Mexico for fiscal 1997
and 1998 are expected to be approximately $31 million and $36 million,
respectively.
In Nigeria, the Company has identified approximately 30 leads and prospects
on the 177,000 acres covered by the 1973 PSC, in which it holds a 100% working
interest. In the third calendar quarter of 1997, the Company expects to commence
a new drilling program of at least six wells on OPL 98. Under the 1992 PSC, the
Company has identified nine leads and prospects on the approximately 450,000
gross acres in OPLs 90/225. In OPL 90, a development plan has been filed with
Nigerian authorities for the recently discovered Okwori South field, from which
the Company expects to begin production in the second half of calendar 1998. The
Company expects the Okwori South field to provide cash flow as well as tax
advantages to help fund the exploration of the other prospects on the 1992 PSC
acreage. The Company expects to begin additional exploratory drilling on OPLs
90/225 in 1998. On the 1973 PSC, approximately 67% of the acreage will be
covered with new 3-D seismic data by May 1997, and this data should be processed
and fully interpreted by September 1997. On the 1992 PSC, the Company has
acquired and evaluated 3-D seismic data on approximately 34% of the acreage,
including the Okwori South field. Capital expenditures in Nigeria for fiscal
1997 and 1998 are budgeted to be approximately $53 million and $67 million,
respectively.
EXPANDING FROM CORE HOLDINGS. The Company will seek new exploration
opportunities outside its core holdings in areas where its competitive strengths
can be applied. For example, the Company has recently acquired approximately
100,000 net acres of leasehold interests in Indiana and Kentucky in the New
Albany Shale formation, where the Company believes it can benefit from the
application of its Appalachian expertise in producing natural gas from tight
formations. The Company will also seek to expand its holdings in the Gulf of
Mexico through lease acquisitions and farm-ins, focusing primarily in the
Louisiana offshore area in an effort to replicate its success at its Vermilion
410 field in building its Gulf of Mexico reserve base. The Company farmed in the
Vermilion 410 block in order to drill its original prospect and subsequently
leased five nearby blocks and farmed in two other adjacent blocks. As a result,
the Company has compiled an eight block complex and has identified additional
exploration prospects. Further, the Company believes that its expertise in
Nigerian ventures can be successfully applied to other international regions.
The Company has begun preliminary analysis of other West African countries known
to have hydrocarbon resources. In international areas, the Company intends to
manage the future risks of exploration by participating generally at interest
levels of 20% to 50% in basins known to contain hydrocarbons that can be
developed with conventional technology.
PURSUING GROWTH THROUGH TARGETED ACQUISITIONS. The Company is continually
evaluating opportunities to acquire producing properties that possess, among
others, one or more of the following characteristics: (i) close proximity to the
Company's existing operations, (ii) potential opportunities to increase reserves
through drilling and additional recovery or enhancement techniques and (iii)
potential opportunities to reduce production expenses through more efficient
operations. The Company has benefited from the deemphasis of conventional
domestic exploration and production operations by the major and large
independent energy companies in favor of large capital intensive projects, which
in turn has resulted in such oil companies offering for sale a number of
attractive properties. Company personnel have substantial training, experience
and in-depth knowledge of the Company's core areas, as well as established
relationships with a number of major and large independent energy companies
operating in the regions, which the Company believes will help it complete
successful acquisitions.
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CONTROL BY ASHLAND; TRANSACTIONS RELATED TO THE OFFERING
CONTROL BY ASHLAND. The Company is currently a wholly-owned subsidiary of
Ashland. Ashland is a publicly-owned company engaged in petroleum refining and
marketing, chemical distribution and manufacturing, coal production, highway
construction and, through the Company, oil and gas exploration and production.
Immediately after the Offering, Ashland will own 14,400,000 shares of Common
Stock of the Company, which will represent approximately 82.3% of the Company's
outstanding Common Stock (80.2% if the Underwriters' over-allotment option is
exercised in full). As the owner of such shares, Ashland will control the
Company's Board of Directors and be in a position to control all matters
affecting 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, the Company's incurrence of debt, any dividends
payable on Common Stock and any matters submitted to a vote of the Company's
stockholders.
PROPOSED SPIN OFF. Ashland has announced that after the Offering it intends
to distribute pro rata to its common stockholders all of the shares of Common
Stock of the Company it then owns by means of a tax-free distribution (the "Spin
Off"). Ashland's final declaration of the Spin Off will not be made until
certain conditions are satisfied, many of which are beyond the control of
Ashland, including receipt by Ashland of a favorable ruling from the Internal
Revenue Service as to the tax-free nature of the Spin Off and the absence of any
future changes in market or economic conditions (including developments in the
capital markets) or Ashland's or the Company's business or financial condition
that causes Ashland's Board of Directors to conclude that the Spin Off is not in
the best interests of Ashland's stockholders. As a result, no assurance can be
given that the Spin Off will occur. Ashland intends to file its request for a
ruling from the Internal Revenue Service as to the tax-free nature of the Spin
Off and has advised the Company that it does not expect the Spin Off to occur
prior to September 1997. If Ashland effects the Spin Off, it is possible that
the increased number of shares of Common Stock of the Company available in the
market may have an adverse effect on the market price of the Company's Common
Stock. See "Risk Factors -- Intended Spin Off by Ashland" and "-- Control by
Ashland and Potential Conflicts of Interest." For a description of Ashland's
reasons for the Offering and the Spin Off, see "The Company."
AGREEMENTS BETWEEN THE COMPANY AND ASHLAND. In anticipation of the Offering
and in view of Ashland's intention to undertake the Spin Off, the Company and
Ashland will enter into a number of agreements governing the future relationship
between the parties, including a Tax Agreement, a Services Agreement, a
Registration Rights Agreement and an Indemnification Agreement. The Tax
Agreement will provide for certain indemnities with respect to representations
made by the Company to the Internal Revenue Service to obtain a ruling on the
tax-free nature of the Spin Off, as well as providing for the filing of tax
returns and the allocation of taxes. The Services Agreement will specify the
terms on which Ashland will continue to provide the Company with certain
corporate and administrative services after the Spin Off. The Registration
Rights Agreement will give Ashland certain rights to require the Company to
effect registrations under the Securities Act of 1933, as amended (the
"Securities Act"), of the Common Stock owned by Ashland and to bear the expenses
of such registrations. The Indemnification Agreement will provide generally that
the Company will indemnify Ashland for liabilities associated with its and its
predecessors' operations and that Ashland will agree to indemnify the Company
for liabilities relating to Ashland's operations and certain other matters. For
a summary of the terms of these agreements, see "Relationship Between the
Company and Ashland -- Contractual Arrangements."
TRANSACTIONS AT CLOSING. Prior to consummation of this Offering, the Board
of Directors of the Company declared a $195.4 million dividend payable to
Ashland, as its current sole stockholder (the "Ashland Dividend"), of which
$15.4 million was satisfied by elimination of the net intercompany receivable
owed by Ashland to the Company as of January 31, 1997. The remaining $180.0
million portion of the Ashland Dividend is payable in cash upon consummation of
the Offering and will be paid using all of the net proceeds of the Offering plus
an amount to be borrowed under a revolving credit facility to be entered into
immediately prior to the Offering (the "Credit Facility"). The net proceeds of
the Offering are expected to be approximately $70.0 million after deducting the
underwriting discount and other expenses (based on an assumed initial public
offering price of $ per share), which would result in the Company borrowing
an aggregate of $110.0 million under the Credit Facility to fund the remainder
of the Ashland Dividend. See
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"Use of Proceeds." Ashland and the Company have agreed that the net cash flows
generated by the Company after January 31, 1997 will be retained by the Company.
THE OFFERING
Common Stock offered........................ 3,100,000 shares
Common Stock to be outstanding after the
Offering.................................... 17,500,000 shares(1)
Use of Proceeds............................. The net proceeds of the Offering
will be used, together with an
amount borrowed under the Credit
Facility, to pay the $180.0
million cash portion of the
previously declared $195.4
million Ashland Dividend. See
"Use of Proceeds."
Listing..................................... An application will be made to
have the Common Stock approved
for listing on the New York
Stock Exchange (the "NYSE").
Proposed NYSE trading
symbol.................................... " "
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(1) Does not include an aggregate of approximately 875,000 shares of Common
Stock subject to stock options to be granted to certain employees and
directors upon completion of the Offering. See "Management -- Company
Benefit Plans -- 1997 Stock Incentive Plan."
8
<PAGE> 10
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA
The following table sets forth summary historical and pro forma financial
data for the Company as of and for the periods indicated. The summary historical
financial data as of and for the years ended September 30, 1994, 1995 and 1996
have been derived from the audited consolidated financial statements of the
Company. The summary historical financial data for the three months ended
December 31, 1995 and 1996 have been derived from unaudited financial statements
of the Company. The summary pro forma financial data set forth below give effect
to (i) the Offering, (ii) the payment of the Ashland Dividend using the proceeds
of the Offering, an amount borrowed under the Credit Facility and the
elimination of an intercompany receivable, and (iii) the Section 29
Monetization, all as described in the Pro Forma Consolidated Financial
Statements and the Notes thereto included elsewhere in this Prospectus. The
results for the three months ended December 31, 1996 are not necessarily
indicative of the results which may be expected for any other period or for the
full year. The following information should be read in conjunction with the
Consolidated Financial Statements of the Company and the Notes thereto, the Pro
Forma Consolidated Financial Statements of the Company and the Notes thereto,
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations." The Company currently contemplates that, after the Spin Off, it
will change its fiscal year to a calendar year.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED SEPTEMBER 30, DECEMBER 31,
------------------------------------------ -------------------------------
PRO FORMA PRO FORMA
1994 1995 1996 1996 1995 1996 1996
-------- -------- -------- --------- -------- -------- ---------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues................................ $196,300 $190,293 $230,932 $241,432 $ 54,044 $ 73,274 $ 75,774
Columbia Gas settlement(1)(3)........... -- -- 73,139 73,139 73,139 -- --
-------- -------- -------- -------- -------- -------- --------
Total revenues.................. 196,300 190,293 304,071 314,571 127,183 73,274 75,774
Operating expenses, including foreign
production taxes...................... 106,524 106,223 148,077 148,077 34,208 35,120 35,120
NORM reclamation/litigation(2)(3)....... -- -- 3,049 3,049 -- 11,126 11,126
Depreciation, depletion and
amortization.......................... 32,876 41,001(4) 30,978 32,878 7,983 7,933 8,408
General and administrative expenses..... 15,048 10,083 16,317 17,317 4,571 4,098 4,098
Exploration costs, including dry
holes................................. 14,219 38,837 11,649 11,649 1,330 10,356 10,356
-------- -------- -------- -------- -------- -------- --------
Total costs and expenses........ 168,667 196,144 210,070 212,970 48,092 68,633 69,108
Operating income (loss)................. 27,633 (5,851) 94,001 101,601 79,091 4,641 6,666
Interest expense, net of interest
income................................ 709 319 222 8,276 54 53 2,066
-------- -------- -------- -------- -------- -------- --------
Income (loss) before income taxes....... 26,924 (6,170) 93,779 93,325 79,037 4,588 4,600
Income tax expense (benefit)............ (7,438) (16,089) 18,418 28,758 23,835 (1,720) 784
-------- -------- -------- -------- -------- -------- --------
Net income.............................. $ 34,362 $ 9,919 $ 75,361 $ 64,567 $ 55,202 $ 6,308 $ 3,816
======== ======== ======== ======== ======== ======== ========
Net income per share of Common Stock.... $ 3.69 $ 0.22
======== ========
Average shares outstanding.............. 17,500 17,500
OTHER FINANCIAL DATA:
EBITDE(5)............................... $ 74,728 $ 73,987 $136,628 $146,128 $ 88,404 $ 22,930 $ 25,430
Net cash provided by (used for)
operating activities.................. 110,292 59,029 112,909 29,026 (4,378)
Capital expenditures.................... 55,917 157,927 93,648 9,524 25,414
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital......................... $129,472 $ 54,166 $ 85,579 $113,715 $ 37,808 $ 22,369
Oil and gas properties, net............. 306,418 375,364 420,359 374,539 426,604 419,629
Total assets............................ 492,506 483,778 595,151 528,676 533,211 511,272
Total long-term debt.................... -- -- -- -- -- 120,260
Stockholders' equity.................... 323,754 333,867 409,228 389,069 359,398 233,959
</TABLE>
(See notes on following page)
9
<PAGE> 11
(1) In 1995 the Company entered into a settlement agreement with Columbia Gas
Transmission Company ("Columbia Gas") to resolve claims involving natural
gas sales contracts that were abrogated by Columbia Gas in its 1991
bankruptcy, pursuant to which the Company received a net payment of $73.1
million. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations."
(2) During 1996, the U.S. Environmental Protection Agency ("EPA") and the State
of Kentucky approved the Company's plan of reclamation (including disposal
off site) of naturally occurring radioactive material ("NORM") at a formerly
operated oil field in Kentucky. Subsequent to September 30, 1996, and based
on actual reclamation work done during the quarter ended December 31, 1996,
the Company reevaluated the NORM project and estimated the total cost of
remediation and reclamation to be $12 million, of which approximately $3.9
million has been expended and the remaining amounts expected to be expended
have been accrued. The Company believes that the remediation and reclamation
project will be completed in calendar 1997. In addition, in January 1997 the
Company made an offer of $10.8 million to settle litigation related to NORM.
The Company believes that it is probable it will recover 30% of all
reclamation and litigation costs pursuant to settlements with Ashland's
insurance carriers. See also "Business and Properties -- Environmental
Matters."
(3) The Columbia Gas settlement and the NORM reclamation/litigation are
nonrecurring activities. Summary financial data excluding these items is as
follows:
<TABLE>
<CAPTION>
YEAR ENDED THREE MONTHS ENDED
SEPTEMBER 30, DECEMBER 31,
-------------------- --------------------------------
PRO PRO
FORMA FORMA
1996 1996 1995 1996 1996
-------- ----- -------- -------- -----
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
Operating income............ $23,911 $31,511 $ 5,952 $15,767 $17,792
Net income.................. 29,803 19,009 7,662 13,540 10,048
Net income per share of
Common Stock.............. $ 1.09 $ 0.63
EBITDE...................... 66,538 76,038 15,265 34,056 36,556
Net cash provided by (used
for) operating
activities................ 67,351 (18,514) 2,854
</TABLE>
(4) Effective September 30, 1995, the Company adopted Statement of Financial
Accounting Standards Board ("SFAS No. 121"), Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. As a
result, the Company recorded a charge of $4.4 million (included in
depreciation, depletion and amortization) to write down certain assets to
their fair values.
(5) EBITDE, as presented herein, is defined as the sum of income before
provision for U.S. income taxes, interest, depreciation, depletion,
amortization and exploration costs, including dry holes. EBITDE does not
represent funds available for discretionary use. EBITDE should not be
considered in isolation or as a substitute for net income, net cash flow
provided by operating activities or other income or cash flow data prepared
in accordance with generally accepted accounting principles or as a measure
of a company's profitability or liquidity. Further, EBITDE, as presented
herein, may not be comparable to similarly titled measures reported by other
companies.
10
<PAGE> 12
SUMMARY RESERVE AND OPERATING DATA
The following table sets forth certain summary reserve and operating
information as of and for the periods indicated. Unless otherwise noted, all
information in this Prospectus relating to natural gas and crude oil reserves is
based upon estimates prepared by Netherland Sewell and reviewed by the Company's
petroleum engineering staff and reflects the Company's net interest. For
additional information regarding the Company's proved reserves as determined by
Netherland Sewell and certain other information regarding the Company's gas and
oil reserves, see "Business and Properties -- Reserves," the "Supplemental
Disclosures About Oil and Gas Producing Activities" in Note 15 to the
Consolidated Financial Statements of the Company presented elsewhere in this
Prospectus and the summary reports of Netherland Sewell dated December 9, 1996,
and February 20, 1997, copies of which are included as Annex A-1 to this
Prospectus. See "Risk Factors -- Uncertainty of Reserve Information and Future
Net Revenue Estimates" for a discussion of the uncertainties inherent in
estimating natural gas and oil reserves and their estimated values.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED SEPTEMBER 30, DECEMBER 31,
-------------------------- ------------------
1994 1995 1996 1995 1996
------ ------ ------ ------- -------
(DOLLARS IN MILLIONS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C>
NET PROVED RESERVES (AT END OF PERIOD):
Natural gas (Bcf)....................... 349.2 507.4 576.9
Crude oil and condensates (MMBbls)(1)... 8.5(2) 15.7(2) 32.3(3)
Total proved reserves (Bcfe)............ 400.2 601.6 770.6
Percent proved developed reserves....... 92.8% 86.7% 83.9%
SEC Present Value before U.S. income
taxes(4)............................. $ 204 $ 258 $ 350(5)
SEC Present Value after taxes(4)........ $ 207 $ 269 $ 322(5)(6)
U.S. reserve to production ratio(7)..... 9.8 13.2 14.3
International reserve to production
ratio(7)............................. 1.1 2.1 4.8
AVERAGE DAILY PRODUCTION:
Natural gas (MMcf per day).............. 94.3 102.9 108.4 111.0 105.8
Crude oil and condensates (MBbls per
day)................................. 19.5 19.4 18.1 18.8 18.2
Total production (MMcfe per day)........ 211.4 219.3 216.9 223.7 214.8
AVERAGE NET SALES PRICES (HEDGED):
Natural gas ($/Mcf)..................... $ 2.42 $ 1.89 $ 2.39 $ 2.18 $ 3.20
Crude oil and condensates ($/Bbl)....... 14.98 16.17 18.45 16.19 23.17
</TABLE>
- ---------------
(1) The Nigerian crude oil reserves included herein represent gross volumes
before any reduction for the Nigerian government's share of such reserves,
which is paid in the form of royalties and production taxes. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" for a description of the Nigerian fiscal and cost recovery
regime applicable to the Company.
(2) All Nigerian crude oil reserves for 1994 and 1995 are from a
Company-generated reserve report not reviewed by Netherland Sewell.
(3) Crude oil reserves of 32.3 MMBbls at September 30, 1996 are as estimated by
Netherland Sewell. Such reserves are 10.7 MMBbls greater than the amount
previously reported as of such date in filings made with the Securities and
Exchange Commission (the "Commission") by Ashland, the amounts included in
such filings being derived from a Company-generated reserve report prior to
the availability of an estimate from Netherland Sewell.
(4) Calculation of SEC Present Values are made using a 10% discount rate in
accordance with the rules and regulations of the Commission.
(5) Gas and oil prices used in calculating estimated values at September 30,
1996 were $1.85 per MMBtu (Henry Hub, Louisiana) and $22.75 per Bbl of oil
(West Texas Intermediate ("WTI")). If the SEC Present Value before U.S.
income taxes and the SEC Present Value after taxes were presented using
September 30, 1996 reserve quantities but using gas and oil prices in effect
at December 31, 1996 ($3.90 per MMBtu (Henry Hub, Louisiana) and $24.25 per
Bbl (WTI), respectively), without making any price-related adjustment to
reserve quantities, the SEC Present Value before U.S. income taxes and the
SEC Present Value after taxes would be $889 million and $673 million,
respectively.
(6) Assuming completion of the Section 29 Monetization as of April 1, 1997, the
SEC Present Value after taxes would be $311 million if it were calculated
using September 30, 1996 reserve quantities and gas and oil prices, and
would be $662 million if it were calculated using September 30, 1996 reserve
quantities but using December 31, 1996 gas and oil prices without any
price-related reserve adjustments.
(7) Represents fiscal year-end reserves divided by that fiscal year's
production.
11
<PAGE> 13
RISK FACTORS
Prospective purchasers of the Common Stock should carefully consider the
risk factors set forth below, as well as the other information contained in this
Prospectus, before purchasing the shares of Common Stock offered hereby.
This Prospectus includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act, and Section 21E of the Securities Exchange
Act of 1934, as amended (the "Exchange Act"). All statements other than
statements of historical facts included in this Prospectus, including without
limitation, statements under "Prospectus Summary," "Risk Factors," "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
"Business and Properties," regarding planned capital expenditures, increases in
oil and gas production, the number of anticipated wells to be drilled after the
date of this Prospectus, leads and prospects, the Company's financial position,
business strategy and other plans and objectives for future operations, are
forward-looking statements. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, it can give no
assurance that such expectations will prove to have been correct. In particular,
given the inherently subjective nature of the estimation of oil and gas reserves
and the values thereof, actual production, revenues and expenditures with
respect to the Company's reserves will likely vary from estimates set forth in
this Prospectus, possibly materially so, as more fully described below under
"-- Uncertainty of Reserve Information and Future Net Revenue Estimates."
VOLATILITY OF NATURAL GAS AND OIL PRICES
Revenues generated from the Company's operations are highly dependent upon
the price of, and demand for, natural gas and oil. In addition, the Company's
profitability is determined in large part by the difference between the prices
received for the natural gas and oil that it produces and the costs of finding,
developing and producing such resources. Historically, the markets for natural
gas and oil have been volatile, and such markets are likely to continue to be
volatile in the future. Prices for natural gas and oil are subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for natural gas and oil, market uncertainty and a variety of additional factors
that are beyond the control of the Company. These factors include the level of
consumer product demand, weather conditions, domestic and foreign governmental
regulations, the price and availability of alternative fuels, political
conditions in the Middle East, the Organization of Petroleum Exporting Countries
("OPEC"), the former Soviet Union and other producing countries, the foreign
supply of natural gas and oil, the price of foreign imports and overall economic
conditions. It is impossible to predict future natural gas and oil price
movements with any certainty. Declines in natural gas and oil prices may
materially adversely affect the Company's financial condition, liquidity,
ability to finance planned capital expenditures, results of operations and value
and quantity of proved reserves. Proved reserves of natural gas and oil are
estimated quantities that geological and engineering data demonstrate with
reasonable certainty to be economically producible under existing circumstances.
Changes in prices directly affect the Company's determination to proceed with
exploration and development activities. Lower natural gas and oil prices may
reduce the amount of natural gas and oil that the Company can produce
economically. Historically, the Company has hedged a significant proportion of
its gas production primarily through covered forward sales contracts, in an
effort to reduce the exposure of the Company to fluctuations in the price of
gas. This practice has limited the Company's potential gains from increases in
gas prices. After the Spin Off, the Company intends to hedge its natural gas
production to a more limited extent to permit it to realize the potential
benefits of upward movements in gas prices. However, such a practice would also
increase the Company's exposure to decreases in gas prices. Based on 1996
production volumes and excluding the impact of hedging, the Company estimates
that a $0.10 per Mcf change in the average domestic natural gas sales price
would result in corresponding changes of approximately $3.8 million in income
from operations and approximately $2.5 million in net income. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
12
<PAGE> 14
UNCERTAINTY OF RESERVE INFORMATION AND FUTURE NET REVENUE ESTIMATES
There are numerous uncertainties inherent in estimating natural gas and oil
reserves and their estimated values, including many factors beyond the control
of the Company. The reserve data set forth in this Prospectus represent only
estimates. Reservoir engineering is a subjective process of estimating
underground accumulations of natural gas and oil that cannot be measured in an
exact manner. Estimates of economically recoverable natural gas and oil reserves
and of future net cash flows necessarily depend upon a number of variable
factors and assumptions, such as historical production from the area compared
with production from other producing areas, the assumed effects of regulations
by governmental agencies and assumptions concerning future production levels,
future natural gas and oil prices, future operating costs, severance and excise
taxes, development costs and workover and remedial costs, all of which may in
fact vary considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of natural gas and oil attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected therefrom
prepared by different engineers or by the same engineers but at different times
may vary substantially and such reserve estimates may be subject to downward or
upward adjustment based upon such factors. Actual production, revenues and
expenditures with respect to the Company's reserves will likely vary from
estimates, and such variances may be material. See "Business and
Properties -- Reserves."
Actual future net cash flows from production of the Company's reserves will
be affected by factors such as actual production, supply and demand for oil and
natural gas, curtailments or increases in consumption by oil and gas purchasers,
changes in governmental regulations or taxation and the impact of inflation on
costs. The timing of actual future net revenue from proved reserves, and thus
their actual present value, can be affected by the timing of the incurrence of
expenditures in connection with development of oil and gas properties. The 10%
discount factor, which is required by the Commission to be used to calculate
present value for reporting purposes, is not necessarily the most appropriate
discount factor based on interest rates in effect from time to time and risks
associated with the oil and gas industry. Discounted present value, no matter
what discount rate is used, is materially affected by assumptions as to the
amount and timing of future production, which may and often do prove to be
inaccurate.
RESERVE REPLACEMENT RISK
Natural gas and oil reserves are depleting assets. In general, the volume
of production from natural gas and oil properties declines as reserves are
depleted. The rate of decline depends on reservoir characteristics, and varies
from the more rapid decline rate characteristic of Gulf of Mexico and Nigerian
reservoirs to the relatively slow decline rate characteristic of the
longer-lived fields in the Appalachian Basin. Therefore, unless the Company
acquires properties containing proved reserves or conducts successful
exploration and development activities, or both, the proved reserves and
production of the Company will decline as reserves are produced. The Company's
future natural gas and oil production is, therefore, highly dependent upon its
level of success in finding or acquiring additional reserves. The business of
exploring for, developing or acquiring reserves is capital intensive. To the
extent cash flow from operations is reduced and external sources of capital
become limited or unavailable, the Company's ability to make the necessary
capital investment to maintain or expand its asset base of natural gas and oil
reserves will be impaired and its ability to service and incur debt, including
under the Company's Credit Facility, will be reduced. There can be no assurance
that the Company's future exploration, development and acquisition activities
will result in additional proved reserves to replace its current and future
production or that the Company will be able to drill productive wells at
acceptable costs. In addition, exploration and development involve numerous
risks, including geological uncertainties or other conditions that may result in
dry holes, the failure to produce natural gas and oil in commercial quantities
or the inability to fully produce discovered reserves. Furthermore, while the
Company's revenues may increase if prevailing natural gas and oil prices
increase significantly, the Company's finding costs for additional reserves
could also increase. For a discussion of the Company's reserves, see "Business
and Properties -- Reserves."
13
<PAGE> 15
CONTROL BY ASHLAND AND POTENTIAL CONFLICTS OF INTEREST
The Company is currently a wholly-owned subsidiary of Ashland. Following
the Offering, Ashland will own approximately 82.3% of the outstanding Common
Stock (80.2% if the Underwriters' over-allotment option is exercised in full).
After the Offering, through its ability to elect all directors of the Company,
Ashland will control all matters affecting 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, the
Company's incurrence of debt and any dividends payable on Common Stock. Although
Ashland has announced its intention to distribute its shares of Common Stock to
its stockholders through the Spin Off, such Spin Off is subject to satisfaction
of certain conditions, see "-- Intended Spin Off by Ashland." Conflicts of
interest may arise in the future between the Company and Ashland in a number of
areas relating to their past and ongoing relationship, including allocation of
capital, dividends, incurrence of indebtedness, tax matters, financial
commitments, registration rights, administration of benefit plans, service
arrangements, potential acquisitions of businesses or oil and gas properties and
other corporate opportunities, the issuance and sale of capital stock of the
Company and the election of directors. The Company has also granted Ashland
certain demand and piggyback registration rights with respect to the Common
Stock owned by Ashland. See "Relationship Between the Company and
Ashland -- Contractual Arrangements."
After the Offering, Messrs. James R. Boyd, Thomas L. Feazell, Philip W.
Block and Dr. Robert B. Stobaugh will be directors of the Company. Each of such
persons is an officer or director of Ashland, and will comprise a majority of
the Board of Directors of the Company. See "-- Intended Spin Off by Ashland" and
"Management -- Directors and Executive Officers." The Company and Ashland have
entered into a number of agreements for the purpose of defining the ongoing
relationship between them. As a result of Ashland's ownership interest in the
Company, the terms of such agreements were not, and the terms of any future
amendments to those agreements may not be, the result of arm's length
negotiations. In addition, notwithstanding the Tax Agreement, under ERISA and
federal income tax law each member of a consolidated group (for federal income
tax and ERISA purposes) is also jointly and severally liable for the federal
income tax liability, certain funding and termination liabilities, certain
benefit plan taxes and certain other liabilities of each other member of the
consolidated group. Similar rules may apply under state income tax laws.
Although Ashland has advised the Company that it does not currently intend to
engage in the exploration for natural gas, natural gas liquids and crude oil
except through its ownership of Common Stock of the Company, there are no
restrictions, contractual or otherwise, on Ashland's engaging in such
activities. Accordingly, if Ashland changes its current strategy, or makes an
acquisition, it may compete with the Company. See "Relationship Between the
Company and Ashland."
INTENDED SPIN OFF BY ASHLAND
Ashland has announced that after the Offering it intends to distribute pro
rata to its common stockholders all of the shares of Common Stock of the Company
that it owns by means of the Spin Off. Ashland's final determination to proceed
with the Spin Off will require a declaration of the Spin Off by Ashland's Board
of Directors. Such a declaration is not expected to be made until certain
conditions, many of which are beyond the control of Ashland, are satisfied
including receipt by Ashland of a favorable ruling from the Internal Revenue
Service as to the tax-free nature of the Spin Off and the absence of any future
change in market or economic conditions (including developments in the capital
markets) or Ashland's or the Company's business or financial condition that
causes Ashland's Board to conclude that the Spin Off is not in the best
interests of Ashland's stockholders. The Company has been advised by Ashland
that it does not expect the Spin Off to occur prior to September 1997. If
Ashland consummates the Spin Off, the increased number of shares of Common Stock
available in the market may have an adverse effect on the market price of the
Common Stock. See "Relationship Between the Company and Ashland." No assurance
can be given that the conditions to the Spin Off will be satisfied or that, in
any event, Ashland's Board of Directors will determine to declare the Spin Off
or that Ashland will not sell its shares of Common Stock. Failure of the Spin
Off to occur could adversely affect the liquidity of the market for the Common
Stock and, accordingly, the market price of the Common Stock.
14
<PAGE> 16
ASHLAND LESOP TO BE A SIGNIFICANT SHAREHOLDER OF THE COMPANY
As of December 31, 1996, the Ashland Inc. Leveraged Employee Stock
Ownership Plan (the "Ashland LESOP") held 8,401,243 shares of Ashland common
stock. Based upon the number of shares of Ashland outstanding at December 31,
1996, upon consummation of the Spin Off, the Ashland LESOP would own
approximately 1,855,000 shares of Common Stock of the Company, representing
10.6% of the outstanding shares of Common Stock at the time of the Spin Off
(10.4% if the Underwriters' over-allotment option is exercised), which would
make the Ashland LESOP the largest shareholder of the Company. The Company has
been advised that after the Spin Off, the Ashland LESOP intends to sell part or
all of the shares of Company Common Stock it receives in the Spin Off, after
expiration of a 180 day post-Offering lockup agreement. Such sales may have an
adverse effect on the market price of the Common Stock.
RESTRICTIONS ON COMPANY OPERATIONS AFTER THE SPIN OFF
Ashland's request for a ruling from the Internal Revenue Service that the
Spin Off will be a tax-free distribution to Ashland and it shareholders was
based on certain representations made to the Internal Revenue Service with
respect to the Company, including representations to the effect that the
Company, at the time of the Spin Off, will have no plan or intention to (i)
merge or consolidate with or into any other corporation, (ii) liquidate or
partially liquidate, (iii) sell or transfer all or substantially all of its
assets, (iv) redeem or otherwise repurchase any of the Company's capital stock,
or (v) issue additional shares of the Company's capital stock other than
pursuant to certain employee stock option plans. Other representations may also
be necessary in order to obtain the ruling. To protect Ashland from federal and
state income taxes that would be incurred by it if the Spin Off were determined
to be a taxable event, the Tax Agreement to be entered into in connection with
this Offering provides that the Company will indemnify Ashland with respect to
tax liabilities resulting from any breach by the Company of any representations
made in connection with the ruling. The Company intends that, at the time of the
Spin Off, the representations in the ruling request will be accurate. However,
because such representations will be based on a subjective "current intent"
standard, the Company may refrain from taking actions after the Spin Off, such
as those listed above, that might otherwise be beneficial to the Company that
might call into question its current intent at the time of the Spin Off. If the
Company is required to make payments pursuant to the Tax Agreement, the amount
of such payments would have a material adverse effect on the Company's business,
financial condition and results of operations. See "Relationship Between the
Company and Ashland -- Contractual Arrangements -- Tax Agreement."
COMPANY TO USE OFFERING PROCEEDS TO PAY DIVIDEND TO ASHLAND
Prior to consummation of this Offering, the Board of Directors of the
Company declared the Ashland Dividend, of which $15.4 million was satisfied by
elimination of the net intercompany receivable owed by Ashland to the Company as
of January 31, 1997. The remaining $180.0 million portion of the dividend is
payable in cash upon consummation of the Offering and will be paid using all of
the net proceeds of the Offering plus an amount to be borrowed under the Credit
Facility. See "Use of Proceeds."
LEVERAGE
To pay a portion of the cash dividend to Ashland upon completion of the
Offering as described under "Use of Proceeds," the Company will incur
approximately $110.0 million of indebtedness under the Credit Facility. The
Credit Facility provides a total of $200 million of credit availability. The
Company's level of indebtedness will have several important effects on its
operations, including (i) a portion of the Company's cash flow from operations
must be dedicated to the payment of principal and interest on its indebtedness
and will not be available for other purposes, (ii) the covenants contained in
the Company's Credit Facility require the Company to meet certain financial
tests, other restrictions limit its ability to borrow additional funds or to
dispose of assets and may affect the Company's flexibility in planning for, and
reacting to, changes in business conditions and other provisions in the
Company's Credit Facility will require the Company to prepay indebtedness
outstanding thereunder upon certain change in control events and (iii) the
Company's ability to obtain additional financing in the future for working
capital, capital expenditures, acquisitions, general corporate purposes or other
purposes may be impaired. The Company's ability to meet its debt service
15
<PAGE> 17
obligations and to reduce its total indebtedness will be dependent upon the
Company's future performance, which will be subject to general economic
conditions and to financial, business and other factors affecting the operations
of the Company, many of which are beyond the Company's control. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company has made, and will continue to make, substantial capital
expenditures for exploration, development and acquisition of natural gas and oil
reserves. Historically, the Company has financed these expenditures primarily
with cash provided by operating activities, supplemented from time to time by
advances from Ashland. During 1995 and for the quarter ended December 31, 1996,
the Company's operating needs and capital expenditure programs required advances
from Ashland in excess of the Company's cash flow in the amounts of $53.9
million and $19.0 million, respectively. During 1994 and 1996, the Company's
cash flows exceeded its operating needs and capital expenditures in the amounts
of $77.8 million and $34.7 million (including the Columbia Gas settlement),
respectively. The Company currently plans to increase capital expenditures from
approximately $94 million in fiscal 1996 to approximately $112 million in fiscal
1997 and approximately $134 million in 1998, principally for anticipated
exploration and development costs in the Gulf of Mexico and Nigeria. Management
believes that it will have sufficient cash provided by operating activities and
availability under the Credit Facility to fund planned capital expenditures in
1997. If revenues decrease as a result of lower natural gas and oil prices or
otherwise, the Company may have limited ability to expend the capital necessary
to replace its reserves or to maintain production at current levels, resulting
in a decrease in production over time. The amount and timing of the Company's
expenditures have been, and until the consummation of the Spin Off, will likely
continue to be, subject to considerations affecting Ashland's overall business
requirements and strategy. See "-- Control by Ashland and Potential Conflicts of
Interest" and "-- Intended Spin Off by Ashland." If the Company's cash flow from
operations is not sufficient to satisfy its capital expenditure requirements,
there can be no assurance that additional debt or equity financing will be
available to meet these requirements. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Liquidity and Capital
Resources."
INTERNATIONAL OPERATIONS
International operations accounted for approximately 24% of the Company's
total net proved reserves at September 30, 1996. Substantially all of the
Company's international operations are currently being conducted in Nigeria.
Such operations are subject to political, economic and other uncertainties,
including, among others, risk of war, revolution, border disputes,
expropriation, renegotiation or modification of existing contracts, import,
export and transportation regulations and tariffs, taxation policies, including
royalty and tax increases and retroactive tax claims, exchange controls, limits
on allowable levels of production, currency fluctuations, labor disputes and
other uncertainties arising out of foreign government sovereignty over the
Company's international operations. The Company's international operations may
also be adversely affected by laws and policies of the United States affecting
foreign trade, taxation and investment. Furthermore, in the event of a dispute
arising from international operations, the Company may be subject to the
exclusive jurisdiction of foreign courts or may not be successful in subjecting
foreign persons to the jurisdiction of courts in the United States. On occasion,
certain countries, including Nigeria, have asserted rights to land, including
oil and natural gas properties, through border disputes. Certain regions of
Africa and other regions of the world have a history of political and economic
instability. Such instability could result in new governments or the adoption of
new policies that might assume a substantially more hostile attitude toward
foreign investment. In an extreme case, such a change could result in voiding
pre-existing contracts and/or expropriation of foreign-owned assets. To date,
the Nigerian government has not voided any pre-existing contracts with the
Company nor has it expropriated any Company-owned assets, and the Company is not
aware of any intention of the Nigerian government to do so. However, there can
be no assurance that political, economic and other uncertainties will not
develop in Nigeria or elsewhere that may have a material adverse effect on the
Company's business, financial position or results of operations.
16
<PAGE> 18
Recent events have put Nigerian political policies under increased scrutiny
by the international community. In the fall of 1995, the British Commonwealth of
Nations suspended Nigeria's membership for two years pending the holding of
democratic elections. The United States, Canada and other trading partners also
have considered the imposition of trade sanctions against Nigeria. Following the
execution of nine democracy activists in 1995, the United States temporarily
recalled the U.S. ambassador and announced several sanctions, including a
military equipment ban and a reduction in humanitarian aid. Following such
events, legislation was introduced in Congress that would have prohibited most
new U.S. investments in Nigeria. Although Congress did not vote on the
legislation, recent newspaper reports have indicated that such legislation may
be reintroduced in Congress this year. In addition, such newspaper reports have
indicated the possibility of a U.S. or international embargo on Nigerian oil
sales or other sanctions against Nigeria. If new U.S. investments in Nigeria are
restricted or trade sanctions are imposed and significantly reduce the amount of
oil purchased from Nigeria or impede the ability of producers in Nigeria to
market their production or receive market prices for such production, such
sanctions could adversely affect Nigeria's oil producers and the country's
overall economy. There can be no assurance that actions taken by the United
States or the international community or future political unrest will not have a
material adverse effect on Nigeria and in turn, on the Company's business,
financial condition or results of operations.
Nigeria is a member of OPEC, which imposes quotas on the production of oil
by member countries. From time to time, these quotas are adjusted, although such
adjustments have not materially affected the Company's oil production in the
past. However, any reductions in production quotas imposed upon Nigeria by OPEC
could limit the ability of the Company to produce oil in Nigeria and adversely
affect the financial condition of the Company.
EXTENSION OF NIGERIAN 1992 PSC
The Company's 1992 PSC in Nigeria will expire in July 1997 if the Company
has not discovered oil reserves capable of producing commercial quantities on or
prior to such date. Upon satisfaction of this requirement, the term of the PSC
would be continued to 2017. The Company believes it has satisfied such
requirement with its Okwori South field discovery, and has notified the NNPC to
that effect. However, the Company has not yet received acknowledgment from the
NNPC that the requirement for extension of the PSC has been satisfied. The
Company expects to receive such acknowledgment in due course, although no
assurance can be given as to when or if it will receive such acknowledgment.
Expiration of the 1992 PSC would have a material adverse effect on the Company's
future results of operations.
POSSIBLE IMPAIRMENT OF GAS AND OIL PROPERTIES
The Company follows the successful efforts method of accounting for its gas
and oil exploration and production activities. Under this method, costs (both
tangible and intangible) of development wells, as well as the costs of
prospective acreage, are capitalized. The costs of drilling and equipping
exploratory wells which do not result in proved reserves are expensed upon the
determination that the well does not justify commercial development. Other
exploratory costs, including geological and geophysical costs, are expensed as
incurred. The Company periodically reviews its proved properties to determine if
the carrying value of such properties as reflected in its accounting records
exceeds the estimated undiscounted future net revenues from proved oil and gas
reserves attributable to such properties. Based on this review and the
continuing evaluation of development plans, economics and other factors, if
appropriate, the Company records impairments (additional depletion and
depreciation) pursuant to SFAS No. 121 to the extent that the net book values of
its properties exceed the expected discounted future net revenues. Such
impairments constitute a charge to earnings which does not impact the Company's
cash flow from operating activities. However, such writedowns impact the amount
of the Company's stockholders' equity and, therefore, the ratio of debt to
equity. The risk that the Company will be required to write down the carrying
value of its oil and natural gas properties increases when oil and natural gas
prices are depressed. No assurance can be given that the Company will not
experience impairments in the future. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations."
17
<PAGE> 19
DRILLING RISKS
Drilling involves numerous risks, including the risk that no commercially
productive natural gas or oil reservoirs will be encountered. The cost of
drilling, completing and operating wells is often uncertain, and drilling
operations may be curtailed, delayed or canceled as a result of a variety of
factors, many of which are beyond the Company's control, including unexpected
drilling conditions, pressure or irregularities in formations, equipment
failures or accidents, adverse weather conditions and shortages or delays in the
delivery of drilling rigs and other equipment. The Company believes that there
currently is a shortage of available drilling rigs in the Gulf of Mexico and
Nigeria, which could adversely affect the timing or cost of planned drilling
projects. The Company's future drilling activities may not be successful and, if
unsuccessful, such failure will have an adverse effect on the Company's
business, results of operations and financial condition.
OPERATING RISKS OF GAS AND OIL OPERATIONS
The natural gas and oil business involves certain operating hazards such as
well blowouts, explosions, uncontrollable flows of oil, natural gas or well
fluids, fires, formations with abnormal pressures, pollution, releases of toxic
gas and other environmental hazards and risks, any of which could result in loss
of human life, significant damage to property of the Company and others,
environmental pollution, impairment of the Company's operations and substantial
losses to the Company. In addition, the Company may be liable for environmental
damages caused by previous owners of property purchased and leased by the
Company. As a result, substantial liabilities to third parties or governmental
entities may be incurred, the payment of which could reduce or eliminate the
funds available for exploration, development or acquisitions or result in the
loss of the Company's properties. In accordance with customary industry
practices, the Company maintains (currently under policies held by Ashland)
insurance against some, but not all, of such risks and losses. The Company does
not carry business interruption insurance. After the Spin Off, the Company will
be required to obtain its own insurance coverage. The occurrence of an event not
fully covered by insurance could have a material adverse effect on the business,
financial condition and results of operations of the Company. In addition to the
risks of environmental harm, the availability of a ready market for the
Company's natural gas and oil production depends on the proximity of reserves
to, and the capacity of, natural gas and oil gathering systems, pipelines and
trucking or terminal facilities. See "Business and Properties -- Operating
Hazards and Uninsured Risks."
LACK OF INDEPENDENT OPERATING HISTORY
Prior to the consummation of the Offering, the business of the Company was
operated as a subsidiary of Ashland. Accordingly, no financial or operating
history of the Company as an independent entity is available for a potential
investor to evaluate. Following the Offering, the Company will be expected,
among other things, to incur significantly higher interest expense as a result
of amounts expected to be borrowed under the Company's Credit Facility and to
incur additional general and administrative expenses. Following the consummation
of the Spin Off, the Company will operate as a stand-alone entity and will no
longer benefit from the direct operational, financial and other support
previously provided by Ashland to the Company, although the Company and Ashland
will enter into a Services Agreement pursuant to which Ashland will provide
certain corporate and administrative services to the Company. Upon termination
of such agreement or the elimination of any services to be provided thereunder,
the Company will be responsible for obtaining such services on its own. If the
Company is unable to perform such services or obtain them on acceptable terms,
the Company's business, financial condition and results of operations could be
adversely affected. See "Relationship Between the Company and
Ashland -- Contractual Arrangements."
DEPENDENCE ON KEY PERSONNEL
The Company depends to a large extent on the services of certain senior
management personnel. The loss of the services of such management personnel
could have a material adverse effect on the Company's business, financial
condition and results of operations. The Company does not maintain key man
insurance for the Company's benefit on any of its employees. Although the
Company will enter into employment agreements with certain of its executive
officers prior to the completion of the Offering, there can be no assurance that
the
18
<PAGE> 20
Company can retain key management personnel. The Company believes that its
success is also dependent upon its ability to continue to employ and retain
skilled technical personnel, and there can be no assurance that the Company will
be able to attract and retain such personnel. See "Management -- Employment
Agreements."
GOVERNMENT REGULATION AND ENVIRONMENTAL MATTERS
The Company's business is regulated by certain local, state and federal
laws and regulations relating to the exploration for, and the development,
production, marketing, pricing, transportation and storage of, natural gas and
oil. The Company's domestic and international operations are subject to
extensive federal, state and local laws and regulations relating to the
generation, storage, handling, emission, transportation and discharge of
materials into the environment or otherwise relating to environmental
protection. Permits are required for the operation of various Company
facilities, and these permits can be subject to revocation, modification and
renewal by issuing authorities. Governmental authorities can enforce compliance
with their regulations and permit terms through administrative, civil and/or
criminal penalties. Increasingly strict requirements may be imposed by future
changes to environmental laws and agency enforcement policies. In particular,
the implementation of new, or the modification of existing, laws or regulations,
including regulations which may be promulgated under the Oil Pollution Act of
1990, could have a material adverse effect on the Company. Although the Company
does not expect to expend amounts that are material in relation to its total
capital expenditure program for environmental compliance in the near future,
because environmental laws and regulations frequently change, the Company is
unable to predict the ultimate cost of compliance over the life of any of the
Company's operating leases. Such costs could be substantial. The Company
believes, however, that continued compliance with regulatory standards will not
substantially affect its ability to compete with similarly situated oil and gas
companies. The Company is subject to remediation costs associated with the
Company's clean-up of a previously operated oil field in eastern Kentucky, for
which the Company has spent $3.9 million through December 31, 1996 and for which
it has established a reserve of $8.1 million as of December 31, 1996 to cover
its estimate of future clean-up costs expected to be incurred. The Company
believes this reserve will be sufficient to cover the Company's remaining
clean-up obligations at the oil field based upon such estimate, although no
assurance can be given that actual costs will not be higher, possibly materially
so. The Company and Ashland have entered into an indemnity agreement that
provides, in part, that the Company will indemnify Ashland for all liabilities
associated with governmental requirements respecting the remediation of the
field. If actual clean-up costs for the oil field clean-up are significantly
higher than the amounts reserved, such costs could have a material adverse
effect on the Company's results of operations. See "Business and
Properties -- Government Regulation" and "-- Environmental Matters."
COMPETITION
The oil and gas industry is highly competitive. The Company encounters
competition from other oil and gas companies in all areas of its operations,
including the acquisition of producing properties. The Company's competitors
include major integrated oil and gas companies and numerous independent oil and
gas companies and state-owned energy companies. Many of its competitors are
large, well-established companies with substantially larger operating staffs and
greater capital resources than the Company's and which, in many instances, have
been engaged in the oil and gas business for a much longer time than the
Company. Such companies may be able to pay more for productive natural gas and
oil properties and exploratory prospects and to define, evaluate, bid for and
purchase a greater number of properties and prospects than the Company's
financial or human resources permit. The Company's ability to acquire additional
properties and to discover reserves in the future will be dependent upon its
ability to evaluate and select suitable properties and to consummate
transactions in this highly competitive environment. See "Business and
Properties -- Competition."
ABSENCE OF DIVIDENDS ON COMMON STOCK
The Company currently intends to retain its cash for the operation and
expansion of its business, including exploration, development and acquisition
activities and currently does not intend to pay dividends on
19
<PAGE> 21
the Common Stock (except for the Ashland Dividend). The terms of the Company's
Credit Facility will also contain certain restrictions on the payment of
dividends to holders of Common Stock. Accordingly, the Company's ability to pay
dividends in the future will depend upon such restrictions and the Company's
results of operations, financial condition, capital requirements and other
factors deemed relevant by the Board of Directors. See "Dividend Policy."
CERTAIN ANTI-TAKEOVER PROVISIONS
Certain provisions of the Company's Restated Certificate of Incorporation
and Bylaws and the Delaware General Corporation Law could have the effect of
delaying, preventing or deterring an attempt to acquire control of the Company,
including provisions that (i) establish a classified Board of Directors, (ii)
prevent stockholders from calling special meetings of stockholders, (iii) impose
certain restrictions on nominations or other proposals by stockholders at annual
or special meetings of stockholders and (iv) impose restrictions on business
combinations with certain interested parties. See "Description of Capital
Stock -- Certain Anti-Takeover Provisions." In addition, the Board of Directors
is authorized to issue shares of preferred stock in one or more series, and to
fix the voting powers, preferences and other rights and limitations thereof.
Accordingly, the Company may issue shares of preferred stock with a preference
over the Common Stock with respect to dividends or distributions on liquidation
or dissolution, or that may otherwise adversely affect the voting or other
rights of the holders of Common Stock. See "Description of Capital
Stock -- Preferred Stock." In addition, concurrently with consummation of the
Spin Off, the Company intends to adopt a stockholder rights plan pursuant to
which, in the event of certain events that may precede an attempted change of
control of the Company, each holder of Common Stock will have the right to
acquire additional shares of Common Stock (or capital stock of an acquiror) at a
substantial discount to market price. The effect of the stockholder rights plan
would be to deter third parties from attempting to acquire control of the
Company without the consent of the Board of Directors. See "Description of
Capital Stock -- Certain Anti-Takeover Provisions -- Stockholder Rights Plan."
In addition, certain provisions included in the Company's Credit Facility will
require the Company to prepay indebtedness outstanding thereunder upon a change
in control (as defined therein) of the Company. The Company will enter into
employment agreements with certain of its executive officers providing for cash
payments following a change in control of the Company. See
"Management -- Employment Agreements."
NO PRIOR PUBLIC MARKET
Prior to this Offering, there has been no public market for the shares of
the Company's Common Stock. Although an application will be made to list the
Common Stock on the NYSE, there can be no assurance that an active trading
market for such shares will develop or be sustained after the Offering, or that
purchasers of the Common Stock will be able to resell their Common Stock at
prices equal to or greater than the initial public offering price. The initial
public offering price for the Common Stock will be determined by negotiations
among the Company and the Underwriters, and may not be indicative of the market
price of the Common Stock after this Offering. See "Underwriting" for a
description of the factors to be considered in determining the initial public
offering price of the Common Stock. Factors such as variations in the Company's
operating results or natural gas and oil prices, announcements by the Company or
others and developments affecting the Company, the oil and gas industry or
general market conditions could cause the market price of the Common Stock to
fluctuate significantly.
SHARES ELIGIBLE FOR FUTURE SALE
Future sales, or the availability for sale, of substantial amounts of
Common Stock in the public market following the Offering could materially
adversely affect the market price of the Common Stock. The Company, Ashland, the
Ashland LESOP and each officer and director of the Company have agreed that they
will not for a period of 180 days from the date of this Prospectus, without the
prior written consent of the Representatives, directly or indirectly (i) offer,
pledge, sell, contract to sell, sell any option or contract to purchase,
purchase any option or contract to sell, grant any option, right or warrant for
the sale of, or otherwise dispose of or transfer any shares of the Common Stock
or any securities convertible into or exchangeable or
20
<PAGE> 22
exercisable for Common Stock (except that Ashland may effect the Spin Off), or
file any registration statement under the Securities Act with respect to any of
the foregoing or (ii) enter into any swap or any other agreement or any
transaction that transfers, in whole or in part, directly or indirectly, the
economic consequences of ownership of the Common Stock, whether any such swap or
transaction is to be settled by delivery of Common Stock or other securities, in
cash or otherwise. See "Underwriting." If not sooner available for resale by
Ashland's stockholders upon consummation of the Spin Off, after expiration of
the lockup period, the 14,400,000 currently outstanding shares of Common Stock
that are held by Ashland will be eligible for resale by Ashland subject to the
volume and other limitations of Rule 144 under the Securities Act or in
registered sales under the Securities Act pursuant to the exercise of demand
registration rights. Ashland has advised the Company that it currently intends
to distribute its shares of Common Stock in the Spin Off, subject to certain
conditions described under "Relationship Between the Company and
Ashland -- Intended Spin Off by Ashland." In addition, upon completion of the
Offering, there will be 875,000 shares of Common Stock subject to options issued
to management, employees and directors. No prediction can be made as to the
effect, if any, that the future sales of shares or the availability of shares
for sale will have on the market price for Common Stock prevailing from time to
time. Sales of substantial amounts of Common Stock in the public market, or the
perception of the availability of shares for sale, could adversely affect the
prevailing market price of the Common Stock and could impair the Company's
ability to raise capital through the sale of its equity securities. See "Shares
Eligible for Future Sale."
21
<PAGE> 23
THE COMPANY
The Company is an independent energy company engaged in the exploration
for, and the development, production, acquisition and marketing of, natural gas
and oil in the United States and in Nigeria. The Company is currently a
wholly-owned subsidiary of Ashland. The Company has been active in the natural
gas and oil business in the United States for over 80 years and in Nigeria for
over 20 years. In the United States, the Company's production is concentrated in
the Appalachian Basin and in the Gulf of Mexico. Internationally, the Company
operates onshore and offshore Nigeria in the deltaic region of the Niger River.
The Company was formed to conduct upstream oil and gas activities and own
the related properties of Ashland. The Board of Directors of Ashland has
determined that the Company should be separated into an independent business in
order to allow it to more efficiently pursue upstream business opportunities.
This determination was made in part because the capital requirements and risk
profile of the upstream oil and gas business are sometimes divergent from those
of Ashland's other businesses. Ashland also believes that the separation of the
Company into a separate business will enable the Company to compete more
effectively for acquisitions that may require the use of marketable securities
as consideration, and will allow the Company to offer incentives to its
employees that are more closely linked to the Company's performance. Given these
beliefs, Ashland plans to separate the Company through the Offering and the Spin
Off, assuming the conditions thereto are satisfied as described in "Relationship
Between the Company and Ashland -- Intended Spin Off by Ashland."
The Company was incorporated in Delaware in 1985 as a subsidiary of Ashland
under the name PAMCO, Inc. (later Ashland Gas Marketing, Inc.). In 1996, the
Company acquired all of the exploration and production assets of Ashland, which
had been held by other subsidiaries of Ashland, after which the Company changed
its name to Ashland Exploration, Inc. In March 1997, the Company changed its
name from Ashland Exploration, Inc. to Blazer Energy Corp. Its principal
executive offices are located at 14701 St. Mary's Lane, Suite 200, Houston,
Texas 77079, and its telephone number at such address is (281) 531-2900.
USE OF PROCEEDS
The net proceeds to the Company from the sale of the shares of Common Stock
offered hereby, after deducting underwriting discounts and commissions and
estimated Offering expenses payable by the Company, are estimated to be
approximately $70.0 million (assuming an initial public offering price of $
per share), or $ if the Underwriters' over-allotment option is exercised in
full.
Prior to consummation of this Offering, the Board of Directors of the
Company declared the $195.4 million Ashland Dividend payable to Ashland, as its
current sole stockholder, of which $15.4 million was satisfied by elimination of
the net intercompany receivable owed by Ashland to the Company as of January 31,
1997. The remaining $180.0 million portion of the dividend is payable in cash
upon consummation of the Offering and will be paid using all of the net proceeds
of the Offering plus approximately $110.0 million to be borrowed under the
Credit Facility. Ashland and the Company have agreed that the net cash flows
generated by the Company after January 31, 1997 will be retained by the Company.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" for a description of the Credit
Facility.
DIVIDEND POLICY
The Company intends to retain its earnings to finance the growth and
development of its business and currently does not intend to pay any dividends
on the Common Stock, other than the Ashland Dividend. In addition, the Credit
Facility will contain certain restrictions on the payment of dividends to
holders of the Common Stock. The Company's dividend policy will be reviewed by
the Board of Directors of the Company from time to time, in light of, among
other things, the Company's earnings and financial position and the limitations
imposed by the Credit Facility.
22
<PAGE> 24
CAPITALIZATION
The following table sets forth the historical debt and capitalization of
the Company as of December 31, 1996, and as adjusted to give effect to (i) the
Offering and (ii) the payment of the Ashland Dividend, using the net proceeds of
the Offering, an amount borrowed under the Credit Facility and the elimination
of a $15.4 million net intercompany receivable as set forth under "Use of
Proceeds". The information presented below is unaudited and should be read in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations," the Consolidated Financial Statements of the Company
and the Notes thereto and the Pro Forma Consolidated Financial Statements of the
Company and the Notes thereto included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
DECEMBER 31, 1996
-----------------------
ACTUAL AS ADJUSTED
-------- -----------
(IN THOUSANDS)
<S> <C> <C>
Long-term debt
Commercial bank loan, less current maturities............. $ -- $110,000
Other, less current maturities............................ -- --
-------- --------
Total long-term debt.............................. -- 110,000
-------- --------
Stockholders' equity
Preferred stock, $.01 par value, 20,000,000 shares
authorized, none issued or outstanding................. -- --
Common Stock, $.01 par value, 100,000,000 shares
authorized, 14,400,000 issued and outstanding;
17,500,000 as adjusted for the Offering(1)............. 144 175
Additional paid-in capital................................ 24,255 94,224
Retained earnings......................................... 334,999 139,560
-------- --------
Total stockholders' equity........................ 359,398 233,959
-------- --------
Total capitalization.............................. $359,398 $343,959
======== ========
</TABLE>
- ---------------
(1) Excludes 875,000 shares of Common Stock reserved for issuance under stock
options expected to be granted to directors and employees upon completion of
the Offering. See "Management -- Company Benefit Plans -- 1997 Stock
Incentive Plan."
23
<PAGE> 25
SELECTED HISTORICAL AND PRO FORMA FINANCIAL INFORMATION
The following table sets forth, for the periods indicated, selected
historical and pro forma financial data for the Company. The selected historical
financial data as of and for the years ended September 30, 1994, 1995 and 1996
have been derived from the audited consolidated financial statements of the
Company. The selected historical financial data as of and for the years ended
September 30, 1992 and 1993 and the three months ended December 31, 1995 and
1996 have been derived from unaudited financial statements of the Company. The
quarterly results include, in the opinion of management, adjustments (consisting
only of normal recurring adjustments) necessary to present fairly the financial
data for such periods. The selected pro forma financial data set forth below
give effect to the adjustments described in the Pro Forma Consolidated Financial
Statements included elsewhere in this Prospectus. The results for the three
months ended December 31, 1996 are not necessarily indicative of the results
which may be expected for any other period or the results for the full year. The
following information should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations," the
Consolidated Financial Statements of the Company and the Notes thereto and the
Pro Forma Consolidated Financial Statements and the Notes thereto presented
elsewhere in this Prospectus. The Company currently contemplates that, after the
Spin Off, it will change its fiscal year to a calendar year.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED SEPTEMBER 30, DECEMBER 31,
---------------------------------------------------------------- -------------------------------
PRO FORMA PRO FORMA
1992 1993 1994 1995 1996 1996 1995 1996 1996
-------- -------- -------- -------- -------- --------- -------- -------- ---------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues
Crude oil................... $190,816 $142,439 $109,095 $117,854 $134,505 $134,505 $ 31,468 $ 41,452 $ 41,452
Natural gas................. 66,573 95,046 83,583 70,901 94,750 105,250 21,971 31,173 33,673
Columbia Gas
settlement(1)(3).......... -- -- -- -- 73,139 73,139 73,139 -- --
Other....................... 2,325 3,052 3,622 1,538 1,677 1,677 605 649 649
-------- -------- -------- -------- -------- -------- -------- -------- --------
Total revenues........ 259,714 240,537 196,300 190,293 304,071 314,571 127,183 73,274 75,774
Costs and expenses
Operating expenses,
including foreign
production taxes.......... 187,307 136,173 106,524 106,223 148,077 148,077 34,208 35,120 35,120
NORM reclamation/
litigation(2)(3).......... 1,000 750 -- -- 3,049 3,049 -- 11,126 11,126
Depreciation, depletion and
amortization.............. 28,183 33,620 32,876 41,001(4) 30,978 32,878 7,983 7,933 8,408
General and administrative
expenses.................. 15,644 14,573 15,048 10,083 16,317 17,317 4,571 4,098 4,098
Exploration costs, including
dry holes................. 11,063 19,321 14,219 38,837 11,649 11,649 1,330 10,356 10,356
-------- -------- -------- -------- -------- -------- -------- -------- --------
Total costs and
expenses............ 243,197 204,437 168,667 196,144 210,070 212,970 48,092 68,633 69,108
Operating income (loss)...... 16,517 36,100 27,633 (5,851) 94,001 101,601 79,091 4,641 6,666
Interest expense, net of
interest income............. 3,619 533 709 319 222 8,276 54 53 2,066
-------- -------- -------- -------- -------- -------- -------- -------- --------
Income (loss) before income
taxes....................... 12,898 35,567 26,924 (6,170) 93,779 93,325 79,037 4,588 4,600
Income tax expense
(benefit)................... (15,360) (107) (7,438) (16,089) 18,418 28,758 23,835 (1,720) 784
-------- -------- -------- -------- -------- -------- -------- -------- --------
Net income................... $ 28,258 $ 35,674 $ 34,362 $ 9,919 $ 75,361 $ 64,567 $ 55,202 $ 6,308 $ 3,816
======== ======== ======== ======== ======== ======== ======== ======== ========
Net income per share of
Common Stock................ $ 3.69 $ 0.22
======== ========
Average shares outstanding... 17,500 17,500
OTHER FINANCIAL DATA:
EBITDE(5).................... $ 58,182 $ 71,686 $ 74,728 $ 73,987 $136,628 $146,128 $ 88,404 $ 22,930 $ 25,180
Net cash provided by (used
for) operating activities... 58,789 71,565 110,292 59,029 112,909 29,026 (4,378)
Capital expenditures......... 91,903 61,402 55,917 157,927 93,648 9,524 25,414
BALANCE SHEET DATA
(AT END OF PERIOD):
Working capital.............. $ 20,712 $ 50,892 $129,472 $ 54,166 $ 85,579 $113,715 $ 37,808 $ 22,369
Oil and gas properties,
net......................... 300,568 304,090 306,418 375,364 420,359 374,539 426,604 419,629
Total assets................. 412,105 413,238 492,506 483,778 595,151 528,676 533,211 511,272
Total long-term debt......... -- -- -- -- -- -- -- 120,260
Stockholders' equity......... 258,652 294,326 323,754 333,867 409,228 389,069 359,398 233,959
</TABLE>
(see notes on next page)
24
<PAGE> 26
- ---------------
(1) In 1995 the Company entered into a settlement agreement with Columbia Gas to
resolve claims involving natural gas sales contracts that were abrogated by
Columbia Gas in its 1991 bankruptcy pursuant to which the Company received a
net payment of $73.1 million. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
(2) During 1996, the EPA and the State of Kentucky approved the Company's plan
of reclamation (including disposal off site) of NORM at a formerly operated
oil field in Kentucky. Subsequent to September 30, 1996, and based on actual
reclamation work done during the quarter ended December 31, 1996, the
Company reevaluated the NORM project and estimated the total cost of
remediation and reclamation to be $12 million, of which approximately $3.9
million has been expended and the remaining amounts expected to be expended
have been accrued. The Company believes that the remediation and reclamation
project will be completed in calendar 1997. In addition, in January 1997 the
Company made an offer of $10.8 million to settle litigation related to NORM.
The Company believes that it is probable it will recover 30% of all
reclamation and litigation costs pursuant to settlements with Ashland's
insurance carriers. See also "Business and Properties -- Environmental
Matters."
(3) The Columbia Gas settlement and the NORM reclamation/litigation are
nonrecurring activities. Summary financial data excluding these items is as
follows:
<TABLE>
<CAPTION>
YEAR ENDED THREE MONTHS ENDED
SEPTEMBER 30, DECEMBER 31,
------------------- ------------------------------
PRO PRO
FORMA FORMA
1996 1996 1995 1996 1996
-------- ----- -------- -------- -----
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
Operating income................. $23,911 $31,511 $ 5,952 $15,767 $17,792
Net income....................... 29,803 19,009 7,662 13,540 11,048
Net income per share of Common
Stock.......................... $ 1.09 $ 0.63
EBITDE........................... 66,538 76,038 15,265 34,056 36,556
Net cash provided by (used for)
operating activities........... 67,351 (18,514) 2,854
</TABLE>
(4) Effective September 30, 1995, the Company adopted SFAS No. 121, Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of. As a result, the Company recorded a charge of $4.4 million
(included in depreciation, depletion and amortization) to write down certain
assets to their fair values.
(5) EBITDE, as presented herein, is defined as the sum of income before
provision for U.S. income taxes, interest, depreciation, depletion,
amortization and exploration costs, including dry holes. EBITDE does not
represent funds available for discretionary use. EBITDE should not be
considered in isolation or as a substitute for net income, net cash flow
provided by operating activities or other income or cash flow data prepared
in accordance with generally accepted accounting principles or as a measure
of a company's profitability or liquidity. Further, EBITDE, as presented
herein, may not be comparable to similarly titled measures reported by other
companies.
25
<PAGE> 27
SELECTED OPERATING DATA
The following table sets forth selected operating data for the Company for
the periods indicated.
<TABLE>
<CAPTION>
THREE MONTHS
ENDED
YEAR ENDED SEPTEMBER 30, DECEMBER 31,
--------------------------- ----------------
1994 1995 1996 1995 1996
------- ------- ------- ------- ------
<S> <C> <C> <C> <C> <C>
NET SALES VOLUMES:
Natural gas (MMcf)
Appalachia................................... 24,078 27,026 29,964 7,726 7,832
Gulf of Mexico............................... 9,027 9,180 8,439 2,181 1,596
Mineral royalty.............................. 1,304 1,341 1,272 305 310
------- ------- ------- ------- ------
Total natural gas....................... 34,409 37,547 39,675 10,212 9,738
Average MMcf per day.................... 94.3 102.9 108.4 111.0 105.8
Crude oil and condensate (MBbls)
Appalachia................................... 26 67 58 22 17
Gulf of Mexico............................... 192 70 42 8 5
Mineral royalty.............................. 82 85 106 25 26
------- ------- ------- ------- ------
Total domestic.......................... 300 222 206 55 48
Nigeria...................................... 6,828 6,859 6,412 1,673 1,622
------- ------- ------- ------- ------
Total crude oil and condensate.......... 7,128 7,081 6,618 1,728 1,670
Average MBbls per day................... 19.5 19.4 18.1 18.8 18.2
AVERAGE NET SALES PRICES:
Natural gas ($/Mcf) (hedged)
Appalachia................................... $ 2.60 $ 2.06 $ 2.60 $ 2.33 $ 3.33
Gulf of Mexico............................... 2.04 1.46 1.74 1.72 2.63
Mineral royalty.............................. 1.93 1.44 1.91 1.60 1.90
Average natural gas (hedged)............ 2.42 1.89 2.39 2.18 3.20
Average natural gas (unhedged).......... 2.37 1.91 2.74 2.21 3.30
Crude oil and condensate ($/Bbl) (hedged)
Appalachia................................... $ 14.25 $ 15.96 $ 18.46 $ 15.77 $21.33
Gulf of Mexico............................... 14.19 16.20 17.72 15.37 19.68
Mineral royalty.............................. 14.46 15.98 18.29 15.91 21.19
Average domestic crude oil and
condensate (hedged)................... 14.29 15.96 18.22 15.77 21.07
Average domestic crude oil and
condensate (unhedged)................. 14.29 15.71 18.17 15.60 21.21
Nigeria...................................... 15.01 16.17 18.46 16.21 23.23
Average crude oil and condensate
(hedged).............................. 14.98 16.17 18.45 16.19 23.17
Average crude oil and condensate
(unhedged)............................ 14.98 16.17 18.45 16.19 23.17
</TABLE>
26
<PAGE> 28
PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
The Pro Forma Consolidated Financial Statements presented below reflect
adjustments to the Company's historical Consolidated Financial Statements and
Notes thereto necessary to give pro forma effect to (i) the Offering, (ii)
payment of the $195.4 million Ashland Dividend using the proceeds of the
Offering, an amount borrowed under the Credit Facility and elimination of a
$15.4 million net intercompany receivable as of January 31, 1997, and (iii) the
Section 29 Monetization, as if such transactions had occurred as of December 31,
1996, for purposes of the Pro Forma Consolidated Balance Sheet, and as of
October 1, 1995, for purposes of the Pro Forma Statements of Consolidated
Income. The Pro Forma Consolidated Financial Statements are not necessarily
indicative of the current or future financial position or results of operations
of the Company had the Offering, the payment of the Ashland Dividend and the
Section 29 Monetization occurred earlier and such statements should be read in
the context of the related historical Consolidated Financial Statements and
Notes thereto appearing elsewhere herein.
The pro forma adjustments are based upon currently available information
and contain estimates and assumptions. Management believes that the estimates
and assumptions provide a reasonable basis for presenting the significant
effects of the transactions as contemplated and that the pro forma adjustments
give appropriate effect to these estimates and assumptions and are properly
applied in the Pro Forma Consolidated Financial Statements.
The following assumptions have been utilized to determine the adjustments
included in the Pro Forma Consolidated Financial Statements of the Company:
(i) Upon consummation of this Offering, the Company will pay the
$180.0 million cash portion of the previously declared $195.4 million
Ashland Dividend (of which $15.4 million was satisfied by elimination of a
net intercompany receivable as of January 31, 1997), which will be funded
from the net proceeds of the Offering, expected to be approximately $70.0
million, and borrowing of approximately $110.0 million under the Credit
Facility.
(ii) Upon completion of this Offering, the Company expects to incur
additional expenses for administrative costs above the levels experienced
in prior periods as a result of becoming a separate company.
(iii) The Company has entered into a letter of intent under which it
will monetize its Section 29 tax credits prior to consummation of the
Offering through the Section 29 Monetization under which it will receive
(i) cash of approximately $6.5 million, (ii) the right to receive all of
the cash flows from the Section 29 Tax Credit Properties, and (iii)
quarterly payments measured by the Section 29 tax credits generated by the
Section 29 Tax Credit Properties. The Company has historically received
credit from Ashland for the face amount of such tax credits. Under the
proposed transaction, the payments received for the value of the Section 29
tax credits will be taxable as additional sales proceeds. Additionally, the
Company will be required to reimburse Ashland for approximately $29.3
million as the result of the taxable gain from this transaction. Of that
amount, the Company expects approximately $12.6 million will be deferred
until Ashland ceases to be an alternative minimum taxpayer, which is not
expected to occur during the next year.
27
<PAGE> 29
BLAZER ENERGY CORP. AND SUBSIDIARIES
PRO FORMA CONSOLIDATED BALANCE SHEET
(UNAUDITED)
<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1996
----------------------------------------------------------
<S> <C> <C> <C> <C>
ADJUSTMENTS
--------------------------------
EFFECTS OF THE SECTION 29
HISTORICAL OFFERING/DIVIDEND MONETIZATION PRO FORMA
---------- --------- -------- ----------
<CAPTION>
(IN THOUSANDS)
<S> <C> <C> <C> <C>
ASSETS
Current assets:
Net obligations with affiliated
companies.......................... $ 15,439 $ (15,439)(B) $ -- $ --
Accounts receivable, less allowance
for doubtful accounts of $249...... 44,577 -- -- 44,577
Inventories........................... 25,464 -- -- 25,464
Prepaids and other current assets..... 5,406 -- -- 5,406
---------- --------- -------- ----------
Total current assets.......... 90,886 (15,439) -- 75,447
Other assets............................ 8,356 -- -- 8,356
Property, plant and equipment, at cost:
Oil and gas properties and
equipment.......................... 1,062,136 -- (6,500)(C) 1,055,636
Unproved properties, net of
accumulated amortization of
$6,147............................. 16,426 -- -- 16,426
Other................................. 14,802 -- -- 14,802
---------- --------- -------- ----------
1,093,364 -- (6,500) 1,086,864
Accumulated depreciation, depletion
and amortization................... 659,395 -- -- 659,395
---------- --------- -------- ----------
Property, plant and equipment, net...... 433,969 -- (6,500) 427,469
---------- --------- -------- ----------
Total assets.................. $ 533,211 $ (15,439) $ (6,500) $ 511,272
========== ========= ======== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Trade accounts payable................ $ 42,369 $ -- $ -- $ 42,369
Income taxes payable.................. 7,481 -- -- 7,481
Accrued liabilities................... 3,228 -- -- 3,228
---------- --------- -------- ----------
Total current liabilities..... 53,078 -- -- 53,078
Noncurrent liabilities:
Long term debt........................ -- 110,000(A) (6,500)(C) 120,260
16,760(D)
Tax reimbursement due Ashland......... -- -- 12,570(D) 12,570
Deferred income....................... 31,715 -- -- 31,715
Deferred income taxes................. 36,505 -- (29,330)(D) 7,175
Other................................. 52,515 -- -- 52,515
---------- --------- -------- ----------
Total noncurrent
liabilities................. 120,735 110,000 (6,500) 224,235
Commitments and contingencies
Stockholders' equity:
Common stock -- $.01 par value,
100,000,000 shares authorized;
14,400,000 issued and outstanding
historical; 17,500,000 issued and
outstanding pro forma.............. 144 31(A) -- 175
Additional paid-in capital............ 24,255 69,969(A) -- 94,224
Retained earnings..................... 334,999 (180,000)(A) -- 139,560
(15,439)(B)
---------- --------- -------- ----------
Total stockholders' equity.... 359,398 (125,439) -- 233,959
---------- --------- -------- ----------
Total liabilities and
stockholders' equity........ $ 533,211 $ (15,439) $ (6,500) $ 511,272
========== ========= ======== ==========
</TABLE>
28
<PAGE> 30
BLAZER ENERGY CORP. AND SUBSIDIARIES
PRO FORMA STATEMENT OF CONSOLIDATED INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
YEAR ENDED SEPTEMBER 30, 1996
------------------------------------------------------------
ADJUSTMENTS
---------------------------------
EFFECTS OF THE SECTION 29
HISTORICAL OFFERING/DIVIDEND MONETIZATION PRO FORMA
---------- ----------------- ------------ ---------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
Revenues:
Sales and operating revenues:
Crude oil........................... $ 134,505 $ -- $ -- $134,505
Natural gas......................... 94,750 -- 10,500(e) 105,250
Columbia Gas settlement................ 73,139 -- -- 73,139
Other.................................. 1,677 -- -- 1,677
--------- -------- ------- --------
304,071 -- 10,500 314,571
Cost and expenses:
Operating expenses, including foreign
production taxes.................... 148,077 -- -- 148,077
NORM reclamation/litigation............ 3,049 -- -- 3,049
Depreciation, depletion and
amortization........................ 30,978 -- 1,900(f) 32,878
General and administrative expenses.... 16,317 1,000(a) -- 17,317
Exploration costs, including dry
holes............................... 11,649 -- -- 11,649
--------- -------- ------- --------
210,070 1,000 1,900 212,970
--------- -------- ------- --------
Operating income......................... 94,001 (1,000) 8,600 101,601
Interest expense, net of interest
income................................. 222 7,370(b) 684(g) 8,276
--------- -------- ------- --------
Income before income taxes............... 93,779 (8,370) 7,916 93,325
Income tax expense (benefit)............. 18,418 (2,930)(c) 2,770(h) 28,758
10,500(d)
--------- -------- ------- --------
Net income............................... $ 75,361 $ (5,440) $(5,354) $ 64,567
========= ======== ======= ========
Net income per share of Common Stock..... $ 3.69
========
Average shares outstanding (in
thousands)............................. 14,400 3,100 17,500
</TABLE>
29
<PAGE> 31
BLAZER ENERGY CORP. AND SUBSIDIARIES
PRO FORMA STATEMENT OF CONSOLIDATED INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED DECEMBER 31, 1996
------------------------------------------------------------
ADJUSTMENTS
---------------------------------
EFFECTS OF THE SECTION 29
HISTORICAL OFFERING/DIVIDEND MONETIZATION PRO FORMA
---------- ----------------- ------------ ---------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
Revenues:
Sales and operating revenues:
Crude oil............................ $41,452 $ -- $ -- $41,452
Natural gas.......................... 31,173 -- 2,500(e) 33,673
Other................................... 649 -- -- 649
------- ------- ------- -------
73,274 -- 2,500 75,774
Cost and expenses:
Operating expenses, including foreign
production taxes..................... 35,120 -- -- 35,120
NORM reclamation/litigation............. 11,126 -- -- 11,126
Depreciation, depletion and
amortization......................... 7,933 -- 475(f) 8,408
General and administrative expenses..... 4,098 -- -- 4,098
Exploration costs, including dry
holes................................ 10,356 -- -- 10,356
------- ------- ------- -------
68,633 -- 475 69,108
------- ------- ------- -------
Operating income.......................... 4,641 -- 2,025 6,666
Interest expense, net of interest
income.................................. 53 1,842(b) 171(g) 2,066
------- ------- ------- -------
Income before income taxes................ 4,588 (1,842) 1,854 4,600
Income tax expense (benefit).............. (1,720) (645)(c) 649(h) 784
2,500(d)
------- ------- ------- -------
Net income................................ $ 6,308 $(1,197) $(1,295) $ 3,816
======= ======= ======= =======
Net income per share of Common Stock...... $ 0.22
=======
Average shares outstanding (in
thousands).............................. 14,400 3,100 17,500
</TABLE>
30
<PAGE> 32
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
PRO FORMA ADJUSTMENTS -- CONSOLIDATED BALANCE SHEET
The pro forma adjustments to the unaudited Pro Forma Consolidated Balance
Sheet as of December 31, 1996 are set forth below:
To record the pro forma effects of the Offering and the $195.4 million
Ashland Dividend:
(A) Debt incurred under the Credit Facility to pay the $180.0 million cash
portion of the Ashland Dividend less net proceeds of $70.0 million from
the Offering.
(B) Non-cash portion of the Ashland Dividend paid to Ashland by elimination
of the balance of the net intercompany receivable at January 31, 1997.
To record the pro forma effects of the Section 29 Monetization:
(C) Cash proceeds from the Section 29 Monetization.
(D) Estimated liability on the tax gain from the above, borrowings to fund
the amounts currently due and establishment of a long-term liability
for the balance of the tax reimbursement due to Ashland.
PRO FORMA ADJUSTMENTS -- STATEMENT OF CONSOLIDATED INCOME
The pro forma adjustments to the unaudited Pro Forma Statements of
Consolidated Income for the year ended September 30, 1996 and the three months
ended December 31, 1996 are set forth below:
To record the pro forma effects of the Offering to reflect the following
transactions as if effective at October 1, 1995:
(a) Additional general and administrative costs associated with the costs
of functioning as a stand-alone entity for the year. No additional
costs were accrued for the three month period as additional
administrative costs allocated by Ashland beginning October 1, 1996 is
believed to approximate the level of such additional costs.
(b) Net interest expense on additional debt at the borrowing rate in the
Credit Facility as follows:
<TABLE>
<CAPTION>
THREE MONTHS
YEAR ENDED ENDED
SEPTEMBER 30, DECEMBER 31,
1996 1996
------------- ------------
(IN THOUSANDS)
<S> <C> <C>
Net borrowings of $110.0 million under Credit Facility... $ 7,370 $ 1,842
======= =======
</TABLE>
(c) Income tax impact of the above transactions.
To record the pro forma effects of the Section 29 Monetization to reflect
the following transactions as if effective at October 1, 1995:
(d) Additional book income tax expense caused by the Section 29
Monetization.
(e) Payments received for Section 29 tax credits generated from properties.
(f) Additional depreciation, depletion and amortization charges incurred
due to the sale and related reduction of reserves from the Section 29
Monetization.
31
<PAGE> 33
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
(g) Net interest expense on additional debt at the borrowing rate in the
Credit Facility as follows:
<TABLE>
<CAPTION>
THREE MONTHS
YEAR ENDED ENDED
SEPTEMBER 30, DECEMBER 31,
BORROWING (REDUCTION) 1996 1996
--------------------- ------------- ------------
(IN THOUSANDS)
<S> <C> <C>
Estimated liability on the tax gain from the above
monetization of $16.7 million.......................... $1,119 $ 280
Estimated cash proceeds from the sale of properties of
$6.5 million........................................... (435) (109)
------ -----
$ 684 $ 171
====== =====
</TABLE>
(h) Additional book tax expense of the above transactions.
32
<PAGE> 34
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following information should be read in conjunction with the
information contained in the Consolidated Financial Statements of the Company
and the Notes thereto included elsewhere in this Prospectus.
OVERVIEW
As an independent energy producer, the Company is engaged in the
exploration for and the development, production, acquisition and marketing of
natural gas and crude oil in the United States and in Nigeria. The Company
emphasizes natural gas in its exploration and production activities in the
United States where it has been active in the natural gas and oil business for
over 80 years. The Company has been an oil producer and operator in Nigeria for
over 20 years. In addition, the Company has mineral royalty and overriding
royalty interests in approximately 240,000 net acres throughout the lower 48
states, Alaska and the Gulf of Mexico.
In the United States, the Company is principally a natural gas producer,
with natural gas making up 97% of the Company's net domestic revenue for the
three months ended December 31, 1996. Average natural gas production in the
United States has increased from 94.3 MMcf per day in 1994 to 108.4 MMcf per day
in the fiscal year ended September 30, 1996. Average crude oil production in the
United States has declined from 822 Bbls per day in fiscal 1994 to 564 Bbls per
day in the fiscal year ended September 30, 1996 and 523 Bbls per day in the
three months ended December 31, 1996, primarily as a result of the sale of
certain properties.
In Nigeria, crude oil makes up 100% of the Company's production. The
production has declined from a peak of 46.5 MBbls per day in November of 1989 to
an average of 17.5 MBbls per day for the year ended September 30, 1996 due to a
period of relatively low investment from 1990 through 1994. Production for the
three months ended December 31, 1996 averaged 17.6 MBbls per day. In recent
years, however, the Company has changed its strategy and, as a result, expects
production from Nigeria to increase as the Company increases its emphasis on the
exploration and development of its Nigerian properties.
The Company's results of operations are determined in large part by the
differences between the prices received for the natural gas and crude oil
produced and the cost to find, develop, produce and market such resources.
Changes in sales prices received for the Company's production directly affect
the Company's determination to proceed with the exploration for and development
of natural gas and crude oil and the Company's quantity of proved reserves.
Natural gas and crude oil prices are influenced by seasonal factors, natural gas
transportation and storage infrastructure, imports, political and regulatory
developments and competition from other sources of energy and have been volatile
over the last three years. Final prices for prompt month natural gas contracts
traded on the NYMEX for delivery of gas at Henry Hub, Louisiana, have ranged
from a low of $1.25 per MMBtu to a high of $3.72 per MMBtu during the period
from January 1, 1994 to December 31, 1996. The Company's production volume
growth in recent years has occurred through exploration and development of its
core United States holdings, as well as from producing property purchases, the
most significant of which were the acquisitions of Appalachian producing
properties of Waco Oil & Gas Co., Inc. and UMC Petroleum Corp. in the first
calendar quarter of 1995 for $68.8 million, as well as those of OXY USA, Inc. in
1990 and 1992 for $102.6 million.
Historically, the Company has followed a strategy of maximizing return on
investment through substantial hedging activities relating to natural gas price
volatility. While this strategy has in the past achieved the income goals of
Ashland, it has limited the Company's potential gains from increases in market
prices for gas. The Company intends to hedge its natural gas production on a
more limited basis in the future in order to retain the potential for greater
upside from increases in gas prices. However, such a policy would also increase
the Company's exposure to declines in natural gas prices. See "Risk
Factors -- Volatility of Natural Gas and Oil Prices." In fiscal years 1994, 1995
and 1996, the Company hedged 52%, 8% and 68%, respectively, of its natural gas
production. At January 31, 1997, the Company had open natural gas hedges on (i)
an average of 76,776 MMBtu per day for the period March 1, 1997 through
September 30, 1997 at an average price of $2.16 per MMBtu and (ii) provided that
the NYMEX natural gas final settlement price is greater than $2.05 per MMBtu
during any month from April 1997 to September 1997, an additional volume of
33
<PAGE> 35
20,000 MMBtu per day at $2.05 per MMBtu during those respective monthly periods.
In addition to its natural gas hedges, the Company has hedged a small amount of
its domestic oil production, but does not hedge any of its Nigerian oil
production. As of January 31, 1997, the Company had open hedges on an average of
290 Bbls of oil per day at an average price of $20.31 per Bbl.
Based upon the results of operations for the year ended September 30, 1996,
and excluding the effect of the Company's hedging program, a change of $0.10 per
Mcf in the average price of natural gas throughout such period would result in
corresponding changes in operating and net income of $3.8 million and $2.5
million, respectively. Because of the nature of the Nigerian PSCs, as described
below, the Company's results are less sensitive to changes in oil prices. The
Company intends to continue to utilize hedging to limit its exposure to
significant declines in market prices and to ensure minimum levels of cash flow
from its sales of natural gas and domestic crude oil. See "Business and
Properties -- Marketing and Contracts -- Risk Management."
In general, under the Company's PSCs with Nigeria, royalties on oil
production are paid to the Nigerian government and then the Company is allocated
an allowance for specified costs incurred in the development and operation of
its concessions. After the payment of royalties and the recovery of specified
costs, petroleum profit taxes ("PPT") are payable to the government. The Company
participates with the Nigerian government in any profits remaining.
The royalty rates for OPL 118, OPL 98, and OPLs 90/225 are 20%, 18.5% and
16.67%, respectively. The PPT rates are 65.75% for the first five years of
production from each new field and 85% thereafter. The ultimate amount payable
to the government is the lesser of (i) the sum of royalties and PPT based on the
rates outlined above (the "Government Take") and (ii) the Revised Government
Take ("RGT"). The RGT amount is calculated by a series of formulas in an
agreement between the government and industry known as the Memorandum of
Understanding ("MOU"). The effect of the formulas is to adjust, or revise, the
Government Take in order to maintain a constant notional margin ("Notional
Margin") as prices vary between $12.50 and $23 per Bbl. The Notional Margin set
by the MOU is $2.30 per Bbl and can be increased to $2.50 per Bbl if sufficient
capital is spent in a given year. The Notional Margin of $2.30 per Bbl is
predicated on the assumed operating expenses, intangible drilling costs and
capital allowance ("Technical Costs") not exceeding $2.50 per Bbl. Similarly,
the Notional Margin of $2.50 per Bbl is predicated on the assumed Technical
Costs not exceeding $3.50 per Bbl. The Company's actual margin will erode if
Technical Costs exceed these levels. The profit margin realized by the Company
on its Nigerian production in the past several years has been lower than the
Notional Margin because actual costs have exceeded allowable Technical Costs
primarily as a result of increased fixed costs per Bbl of production due to
natural declines in production. The Notional Margin is subject to profit sharing
between the Company and the NNPC, with the Company's share varying from 40% to
80% depending on monthly production levels.
Oil values for the purposes of determining amounts payable to the Nigerian
government under the PSCs are based on assumed indexed prices. The Company takes
all of the oil produced under the PSCs and assumes the risk of selling the oil
in world markets, and then remits payment to the Nigerian government. Gains or
losses on such trading activities are realized by the Company and reflected in
crude oil sales. Because the Company sells its Nigerian oil production in U.S.
dollars, the Company is not subject to material foreign currency exposure with
respect to its Nigerian operations.
The Company follows the successful efforts method of accounting for its
natural gas and crude oil exploration and production activities. Under this
method, the Company capitalizes all costs incurred to acquire mineral interests
in natural gas and oil properties, to drill and equip exploratory wells in which
proved reserves are discovered and to drill and equip development wells.
Geological and geophysical costs, delay rentals and technical support costs are
expensed as incurred. The costs of drilling and equipping exploratory wells in
which proved reserves are not discovered are expensed upon determination that a
well does not justify commercial development. The capitalized costs of producing
natural gas and oil properties are depreciated and depleted by the
units-of-production method based on estimated proved reserves. Unproved natural
gas and oil properties are periodically assessed for impairment of value and are
expensed in the period in which the impairment is recognized. The successful
efforts method of accounting could affect the Company's operating
34
<PAGE> 36
and net income depending upon the Company's level of exploration drilling and
the results of such drilling in any year.
The Company has deferred revenue from its Nigerian producing operations
(OPLs 98/118) in order to appropriately match revenues earned with costs
incurred. The 1973 PSC and MOU generally provide for capital cost and expense
recovery early in the field life as recoverable contract costs are, in part,
based on defined margins per barrel. Since the Company incurs significant fixed
costs over the contract term, income deferral has been required to avoid
inappropriately recording income in the early portion of the field life and to
provide for recovery of capitalized costs. The Company at least annually reviews
the overall profitability under OPLs 98/118 to assess the anticipated net
profits over the remaining field life for the Company. Net profits reflect
projected revenues to be realized in excess of capital and operating costs to be
incurred and the remaining net book value of the Company's property, plant and
equipment related to those blocks. Operating costs to be incurred include
production and lifting costs, as well as royalty, PPT, and profit share payable
to the Nigerian government. Net profits are recognized on a unit-of-production
basis as the remaining reserves are produced.
The Company periodically reviews its proved properties to determine whether
the carrying value of such properties as reflected in its accounting records
exceeds the estimated undiscounted future net revenues from proved gas and oil
reserves attributable to such properties. Based on this review and the
continuing evaluation of development plans, economics and other factors, if
appropriate, the Company records impairments (additional depletion and
depreciation) pursuant to SFAS No. 121, "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to Be Disposed of," to the extent that
the net book values of its properties exceed the expected discounted future net
revenues. Such impairments constitute a charge to earnings which does not impact
the Company's cash flow from operating activities. However, such write-downs
impact the amount of the Company's stockholders' equity and, therefore, the
ratio of debt to equity. The risk that the Company will be required to write
down the carrying value of its natural gas and oil properties can increase when
natural gas and oil prices are depressed. The Company experienced impairments of
$4.4 million in 1995 when SFAS No. 121 was initially adopted. There have been no
further write-downs since that time. No assurance can be given that the Company
will not experience additional impairments in the future.
Columbia Gas and the Company were parties to long-term contracts for the
sale by the Company to Columbia Gas of substantial volumes of natural gas at
above market prices. In July 1991, Columbia Gas filed for protection from its
creditors under Chapter 11 of the bankruptcy laws. Shortly after the filing,
Columbia Gas rejected most of its gas purchase contracts, including the
Company's, which left the Company and nearly 2,000 other gas producers as
unsecured creditors. In April 1995, Columbia Gas filed a Plan of Reorganization
(the "Reorganization Plan") which included a claim settlement among the largest
creditors, including the Company. The Reorganization Plan, which was confirmed
later in 1995, provided for a $78.5 million payment to the Company, of which 5%
was withheld by Columbia Gas to satisfy any claims of nonsettling producers. In
the event that any portion of the amount withheld by Columbia Gas is not used to
satisfy such nonsettling claims, the Company and Ashland have agreed that such
amount will be paid to Ashland.
During 1996, the EPA and the State of Kentucky approved the Company's plan
of reclamation (including disposal off site) of naturally occurring radioactive
material ("NORM") at a formerly operated oil field in Kentucky. Subsequent to
September 30, 1996, and based on actual reclamation work done during the quarter
ended December 31, 1996, the Company revaluated the NORM project and estimates
the total cost of remediation and reclamation to be $12.0 million, of which
approximately $3.9 million has been expended and the remaining amounts expected
to be expended have been accrued. The Company believes that the remediation and
reclamation project will be completed in calendar 1997. In addition, in January
1997 the Company made an offer of $10.8 million to settle litigation related to
NORM. The Company believes that it is probable it will recover 30% of all
reclamation and litigation costs pursuant to settlement with Ashland's insurance
carriers. See also "Business and Properties -- Environmental Matters."
Under its tax allocation arrangement with Ashland, the Company is allocated
the benefit of Section 29 tax credits and foreign tax credits expected to be
utilized by Ashland in its consolidated tax return.
35
<PAGE> 37
Historically, the full amount of the tax credits generated have been allocated
to the Company. The Company has entered into a letter of intent to monetize its
Section 29 tax credits. The transaction will include an initial down payment at
closing for the "tail" portion of the reserves. This will be recorded as a
reduction in costs on the balance sheet for oil and gas properties and
equipment. The Company will also receive a production payment equal to 100% of
the production, revenue and expenses until a specified quantity of gas is
produced. In addition, compensation for the tax credits will be received by the
Company on a quarterly basis as the credits are generated and will be recorded
as other revenues. The Company will have the option to repurchase the "tail"
reserves at fair market value after January 1, 2003. The accounting impacts of
this transaction, which include an increase of approximately $1.9 million per
year of depreciation, depletion and amortization, are reflected in the Unaudited
Pro Forma Consolidated Financial Statements included elsewhere in this
Prospectus. See also "Business and Properties -- Section 29 Tax Credits." The
Company anticipates that it could have realized foreign tax credit benefits on a
separate Company basis approximately equal to the value allocated by Ashland.
RESULTS OF OPERATIONS
Operating results for the Company's Domestic and International segments are
presented in the tables and analyses that follow. The tables also show
significant items that affect operating and net income comparisons. Each
significant item is discussed in the respective segment discussions.
OPERATING INCOME (LOSS)
<TABLE>
<CAPTION>
THREE MONTHS
ENDED
YEAR ENDED SEPTEMBER 30, DECEMBER 31,
-------------------------- ---------------
1994 1995 1996 1995 1996
----- ------ ----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Domestic....................................... $ 3.8 $(14.5) $81.8 $75.6 $ 2.0
International.................................. 23.8 8.6 12.2 3.5 2.6
----- ------ ----- ----- -----
Total................................ $27.6 $ (5.9) $94.0 $79.1 $ 4.6
===== ====== ===== ===== =====
</TABLE>
DOMESTIC OPERATING INCOME (LOSS) AND SIGNIFICANT ITEMS
<TABLE>
<CAPTION>
THREE MONTHS
ENDED
YEAR ENDED SEPTEMBER 30, DECEMBER 31,
-------------------------- ---------------
1994 1995 1996 1995 1996
----- ----- ------ ----- -----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Revenues....................................... $91.3 $75.8 $173.3 $96.6 $32.8
Operating expenses............................. 26.2 29.3 35.7 7.6 18.5
Depreciation, depletion and amortization....... 32.5 39.7 28.9 7.6 7.3
General and administrative expenses............ 14.3 9.2 15.7 4.5 4.0
Exploration costs, including dry holes......... 14.5 12.1 11.2 1.3 1.0
----- ----- ------ ----- -----
Operating income (loss)........................ 3.8 (14.5) 81.8 75.6 2.0
Significant items (expense)
Columbia Gas settlement...................... -- -- 73.1 73.1 --
NORM costs................................... -- -- (3.0) -- (11.1)
SFAS No. 121................................. -- (4.4) -- -- --
NORM/Columbia Gas legal costs................ (1.1) (0.6) (2.0) (0.4) (0.5)
----- ----- ------ ----- -----
Total significant items.............. (1.1) (5.0) 68.1 72.7 (11.6)
----- ----- ------ ----- -----
Operating income (loss) excluding significant
items........................................ $ 4.9 $(9.5) $ 13.7 $ 2.9 $13.6
===== ===== ====== ===== =====
</TABLE>
As explained above, the Company's Nigerian PSCs generally provide the
Company with margins based on production. As such, the Company does not believe
that an analysis of Nigerian revenues and costs is meaningful and accordingly
has presented the discussion of international operations in the context of
operating income only.
36
<PAGE> 38
INTERNATIONAL OPERATING INCOME
<TABLE>
<CAPTION>
THREE MONTHS
ENDED
YEAR ENDED SEPTEMBER 30, DECEMBER 31,
-------------------------- ------------
1994 1995 1996 1995 1996
------ ------ ------ ---- ----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Operating income (loss):
Nigeria OPLs 98/118................................ $20.3 $10.1 $ 9.2 $2.4 $1.8
Nigeria OPLs 90/225................................ (1.9) (4.7) (1.7) (0.4) (0.4)
Other international................................ 5.4 3.2 4.7 1.5 1.2
----- ----- ----- ---- ----
Total...................................... $23.8 $ 8.6 $12.2 $3.5 $2.6
===== ===== ===== ==== ====
</TABLE>
THREE MONTHS ENDED DECEMBER 31, 1996,
COMPARED TO THREE MONTHS ENDED DECEMBER 31, 1995
Domestic
Revenues. Total domestic revenues decreased to $32.8 million for the three
months ended December 31, 1996, from $96.6 million in the three months ended
December 31, 1995. Revenues in the December 1995 quarter included $73.1 million
of net proceeds received in the Columbia Gas settlement. Natural gas and crude
oil revenues increased 41% to $32.2 million for the three months ended December
31, 1996, compared to $22.8 million for the three months ended December 31,
1995, principally due to higher natural gas prices. The Company's average price
realized for natural gas in the first three months of 1997 increased $1.02 per
Mcf, or 47%, to $3.20 per Mcf, compared to $2.18 per Mcf for the comparable
period in the prior year. The Company's natural gas hedging activities
unfavorably affected price realizations by $1.0 million and $0.4 million in the
three month periods ended December 31, 1996 and 1995, respectively. Excluding
the impact of natural gas hedging activity, the price increase was $1.09 per
Mcf, or 49% higher than the prior comparable period's average price. Average
crude oil prices for the period rose $5.30 per Bbl, or 34%, to $21.07 per Bbl
and also reflected the effects of hedging activities. Excluding hedges, crude
oil prices were up $5.61 per barrel or 36% from the prior year period. Because
of the small volumes of domestic crude oil production, the aggregate impact of
domestic crude oil hedging was not significant in either period.
The favorable impact of higher prices was somewhat offset by a 5% reduction
in natural gas volumes to 105.8 MMcf per day reflecting lower volumes in the
Gulf of Mexico Region from normal production declines. However, on December 23,
1996, production commenced from the Vermilion 410 platform in the Gulf of
Mexico. Production from that field continues to increase and added approximately
29.4 MMcf per day to the Company's net natural gas production in February 1997.
Expenses. Operating expenses increased to $18.5 million for the three
months ended December 31, 1996 from $7.6 million for the three months ended
December 31, 1995. Production costs and taxes were relatively unchanged from the
prior period. A reserve for $10.8 million was established in the 1996 period in
anticipation of the settlement of outstanding litigation regarding NORM. In
addition, the Company incurred expenses of $2.7 million and recorded additional
reserves of $4.5 million in 1996 in connection with the reclamation program for
the remediation of NORM. These costs were partially offset by an accrual of
probable insurance recoveries for such litigation and reclamation of $6.8
million. See "Business and Properties -- Environmental Matters."
Depreciation, depletion and amortization decreased 3% to $7.3 million for
the three months ended December 31, 1996, compared to $7.6 million for the three
months ended December 31, 1995, primarily reflecting the lower production
volumes noted above.
General and administrative expenses decreased 12% to $4.0 million for the
three months ended December 31, 1996 from $4.5 million for the three months
ended December 31, 1995, primarily as a result of a $1.0 million reduction in
incentive compensation accruals partially offset by higher allocations of
corporate expenses from Ashland and higher legal costs associated with the NORM
litigation. A substantial portion of
37
<PAGE> 39
1996 incentive compensation expense was recorded in the quarter ended December
31, 1995, in conjunction with the receipt of the Columbia Gas settlement.
Exploration costs, including dry holes, decreased 23% to $1.0 million in
the three months ended December 31, 1996, compared to $1.3 million in the prior
year period reflecting a $0.4 million reduction in lease impairment charges
offset partially by a $0.1 million increase in geological and geophysical
("G&G") expenses.
International
The Company generated operating income of $2.6 million from its
international operations for the three months ended December 31, 1996, compared
to $3.5 million in the comparable prior year period. The $0.9 million, or 26%,
decline reflects lower volumes and profitability from its producing operations
on OPLs 98/118 in Nigeria and decreased earnings from other international, which
consists of crude oil trading activities.
Operating income from OPLs 98/118 totaled $1.8 million in the three months
ended December 31, 1996, a $0.6 million decline from the three months ended
December 31, 1995. Crude oil volumes declined 3% to 17.6 MBbls per day compared
to 18.2 MBbls per day in the prior year period. The average price recorded for
Nigerian production for the 1996 quarter was $23.23 per Bbl, a $7.02 or 43%
increase from the same period last year. Net profits were recognized at the rate
of $1.11 per Bbl and $1.43 per Bbl in the 1996 and 1995 periods, respectively,
in accordance with the Company's policy of assessing overall profitability of
the PSC based on the remaining field life to the Company. The $0.32 per Bbl
reduction in the recognition rate in 1996 as compared to 1995 resulted in the
reduction of $0.5 million in operating income, while the lower volumes produced
were responsible for the remaining $0.1 million decrease in operating income as
compared to the prior period.
The operating loss of $0.4 million on OPLs 90/225 for the three months
ended December 31, 1996, was the same as reported in the comparable prior year
period, as exploration costs and administrative expenses remained unchanged.
Operating income from other international principally reflects the results
of crude oil trading activity, which generated a $0.9 million operating profit
in the three months ended December 31, 1996, compared to a $1.3 million
operating profit in the previous year's period. Volumes traded rose 2% in the
1996 quarter to 1.8 MMBbls.
Consolidated Net Income
Net income for the three months ended December 31, 1996, declined $48.9
million, or 89%, to $6.3 million from $55.2 million in the comparable prior year
period. The Columbia Gas settlement recorded in the period ended December 31,
1995 was responsible for approximately $47.5 million of the total decrease. In
addition, the NORM-related litigation and reclamation costs recorded in 1996,
partially offset by an accrual for insurance recoveries, reduced net income by
approximately $7.2 million. Excluding these two significant items, domestic
operations added $9.2 million to net income, more than double the contribution
from the same period in 1995. Included in domestic net income were $2.5 million
and $2.7 million of Section 29 tax credits in the 1996 and 1995 periods,
respectively.
International operations contributed $2.5 million and $3.5 million of net
income for the three month periods ended December 31, 1996 and 1995,
respectively, for the reasons described above. No U.S. tax expense was
calculated on foreign income as the Company was allocated the benefits of
foreign tax credits expected to be utilized.
38
<PAGE> 40
FISCAL YEAR ENDED SEPTEMBER 30, 1996
COMPARED TO FISCAL YEAR ENDED SEPTEMBER 30, 1995
Domestic
Revenues. Total domestic revenues increased to $173.3 million for the year
ended September 30, 1996, from $75.8 million in the year ended September 30,
1995. Revenues in 1996 include $73.1 million of net proceeds received in
conjunction with the settlement of the Columbia Gas bankruptcy proceedings.
Natural gas and crude oil revenues increased 32% to $98.5 million in 1996 from
$74.4 million in 1995. Average natural gas production of 108.4 MMcf per day for
the year ended September 30, 1996, was 5.5 MMcf per day or 5% higher than the
102.9 MMcf per day average for the year ended September 30, 1995. The increase
in volumes principally reflects a full year of production from the acquisitions
made during the second quarter of 1995.
The Company's average price realized for natural gas in 1996 increased
$0.50 per Mcf, or 26%, to $2.39 per Mcf, compared to $1.89 per Mcf in the prior
year. The Company's natural gas hedging activities affected price realizations
in both 1996 and 1995. Results for 1996 include $13.8 million of hedging losses,
while results for 1995 include hedging losses of $0.6 million. Excluding the
impact of gas hedging activity, the 1996 average price was higher by $0.83 per
Mcf, or 43%, over the 1995 average price. Crude oil prices rose $2.26 per Bbl to
$18.22 per Bbl in 1996, a 14% increase from 1995. Excluding the effects of
hedging, crude oil prices were 16% higher. Because of the small volume of
domestic production, crude oil hedging's favorable impact on revenues was not
significant in either period.
Other revenues increased to $1.7 million for the year ended September 30,
1996, compared to $1.5 million for the year ended September 30, 1995. Net
margins generated from the purchase and resale of third-party natural gas
totaled $0.5 and $0.4 million in 1996 and 1995, respectively. Miscellaneous
other revenues, such as net gains and losses on sales of assets, remained
essentially flat from period to period.
Expenses. Operating expenses increased 22% to $35.7 million for the year
ended September 30, 1996 from $29.3 million for the year ended September 30,
1995, largely a result of production tax increases of $3.3 million to $8.6
million for the year ended September 30, 1996, primarily reflecting the impact
of higher natural gas volumes and prices. Operating expenses in 1996 also
reflect $3.0 million of NORM-related reclamation costs.
Depreciation, depletion and amortization decreased 27% to $28.9 million for
the year ended September 30, 1996, compared to $39.7 million for the year ended
September 30, 1995, despite increased production volumes in 1996. Decreased
charges for depreciation, depletion and amortization principally resulted from
favorable reserve revisions at the end of fiscal 1995. In addition, 1995 results
included a $4.4 million charge to expense in conjunction with the adoption of
SFAS No. 121.
General and administrative expenses increased 70% to $15.7 million for the
year ended September 30, 1996 from $9.2 million for the year ended September 30,
1995, principally as a result of a $1.5 million increase in legal costs
primarily associated with the Company's NORM litigation and a $2.0 million
increase in accruals under the Company's incentive compensation programs. In
addition, prior year expenses were reduced as a result of the renegotiation of
the headquarters office lease in Houston, which resulted in a one-time gain of
$0.9 million.
Exploration costs, including dry holes, decreased 7% to $11.2 million for
the year ended September 30, 1996, compared to $12.1 million for the year ended
September 30, 1995, primarily reflecting $1.2 million of lower dry hole, G&G and
technical staff expenses partially offset by a $0.1 million increase in charges
for the impairment of unproved properties.
International
The Company recorded international operating income of $12.2 million in the
year ended September 30, 1996, a 42% increase from the $8.6 million reported for
the year ended September 30, 1995. Lower per barrel profitability from the
Company's producing operations on OPLs 98/118 in Nigeria combined with a $0.5
39
<PAGE> 41
decline in earnings from crude oil trading activities reduced operating income
by $1.4 million. This was more than offset, however, by reductions in dry hole,
G&G, and other technical staff expenses in other areas.
Operating income from OPLs 98/118 totaled $9.2 million in 1996, a $0.9
million or 9% decrease from the $10.1 million earned in the prior year. Crude
oil production volumes declined 7% to 17.5 MBbls per day while the average price
recorded in 1996 rose 14% or $2.29 per Bbl to $18.46 per Bbl. Net profits were
recognized at the rate of $1.44 per Bbl and $1.46 per Bbl for 1996 and 1995,
respectively, in accordance with the Company policy of assessing overall
profitability of the 1973 PSC based on the remaining field life to the Company.
The $0.02 per Bbl reduction in the recognition rate in 1996 as compared to 1995
resulted in a reduction of $0.7 million in operating income, while the lower
volumes produced were responsible for the remaining $0.2 million decrease in
operating results as compared to the prior year.
The operating loss incurred on OPLs 90/225 declined to $1.7 million in
1996, a reduction of $3.0 million from the loss reported in 1995. Dry hole and
G&G expenses declined by $3.5 million and $0.5 million, respectively, from the
previous year. The favorable effect of these items was partially offset by
higher charges for technical and administrative staff expenses associated with
ongoing exploration activity occurring on these blocks.
Operating income from other international of $4.7 million rose $1.5 million
from 1995. Exploration costs declined $2.0 million reflecting a $0.4 million
reduction in dry hole and G&G expenses in Australia coupled with reduced
administrative and technical staff expenses. Crude oil trading activity
generated $4.2 million of operating income in 1996, a $0.5 million reduction
from the prior year. The reduction principally reflects a 12% decrease in
volumes traded to 6.6 MMBbls.
Consolidated Net Income
Net income for the year ended September 30, 1996, totaled $75.4 million, a
$65.5 million increase from the $9.9 million of net income for the year ended
September 30, 1995. The Columbia Gas settlement recorded in 1996 was responsible
for $47.5 million of the total increase. Excluding this significant item,
domestic net income rose $13.7 million to $15.0 million, primarily for the
reasons described above. Included in domestic net income were $10.5 million and
$9.6 million of Section 29 tax credits in 1996 and 1995, respectively.
Net income from international operations was $12.8 million and $8.6 million
in 1996 and 1995, respectively, for the reasons described above. No U.S. tax
expense was calculated on foreign income as the Company was allocated the
benefits of foreign tax credits expected to be utilized. In the year ended
September 30, 1996, the Company also received a $0.7 million allocation of
income tax credits from Ashland for its share of benefits associated with the
filing of a combined tax return in Australia for 1994 and 1995. In the year
ended September 30, 1995, the Company received a credit of $0.2 million related
to the combined Australian tax return for 1993.
FISCAL YEAR ENDED SEPTEMBER 30, 1995
COMPARED TO FISCAL YEAR ENDED SEPTEMBER 30, 1994
Domestic
Revenues. Total domestic revenues decreased by 17% for the year ended
September 30, 1995, to $75.8 million, from $91.3 million in the year ended
September 30, 1994. Natural gas and crude oil revenues declined by 15% to $74.4
million in 1995 from $87.9 million in 1994. A 9% increase in natural gas
production to 102.9 MMcf per day for the year ended September 30, 1995, compared
to 94.3 MMcf per day for the year ended September 30, 1994, was offset by
significantly lower natural gas prices. The increased production reflects in
part the acquisition of the Waco Oil & Gas Co., Inc. and UMC Petroleum Corp.
properties during the second quarter of 1995, which provided additional natural
gas production in the Appalachian Region.
The Company's average price realized for natural gas in 1995 declined $0.53
per Mcf, or 22%, to $1.89 per Mcf, compared to $2.42 per Mcf in the prior year.
The Company's natural gas hedging activities affected price realizations in both
1995 and 1994. Results for 1995 include $0.6 million of hedging losses, while
results
40
<PAGE> 42
for 1994 include hedging gains of $1.8 million. Excluding the impact of natural
gas hedging activity, the average price in 1995 declined $0.46 per Mcf, or 19%,
from the $2.37 per Mcf average price in 1994.
Oil prices rose 12% in 1995 to $15.96 per Bbl from $14.29 per Bbl in 1994,
but the favorable impact of the increase was offset by a 26% decrease in daily
crude oil production from 822 Bbls per day in 1994 to 609 Bbls per day in 1995
as the Company continued to dispose of miscellaneous underperforming properties.
Crude oil hedging had a favorable impact on revenues, but due to the small
volume of domestic production, the aggregate effect was immaterial in both
periods.
Other revenues decreased 59% to $1.4 million for the year ended September
30, 1995 from $3.4 million for the year ended September 30, 1994. Gains on sales
of assets declined as the program to dispose of underperforming crude oil
producing properties came to a close. In addition, other revenues for 1994
included the reversal of an $0.8 million reserve established several years
earlier related to a pricing issue with a natural gas purchaser as well as $0.8
million in compensatory payments received from various coal companies for the
plugging of certain wells. Net margins of $0.4 million generated from the
purchase and resale of third-party natural gas were essentially flat from period
to period.
Expenses. Operating expenses increased 12% to $29.3 million for the year
ended September 30, 1995 from $26.2 million for the year ended September 30,
1994. The increase principally reflects higher production costs associated with
the increased volumes from the properties acquired in the second quarter of
1995.
Depreciation, depletion and amortization increased 22% to $39.7 million for
the year ended September 30, 1995, from $32.5 million for the year ended
September 30, 1994. Higher charges for depreciation, depletion and amortization
resulted from unfavorable price-driven reserve revisions at the end of fiscal
1994 as well as from higher production volumes in fiscal 1995. In addition, the
Company incurred a $4.4 million charge to depreciation, depletion, and
amortization expense in 1995 in conjunction with the adoption of SFAS No. 121.
General and administrative expenses decreased 36% to $9.2 million for the
year ended September 30, 1995 from $14.3 million for the year ended September
30, 1994, primarily as a result of the renegotiation of the headquarters office
lease in Houston which resulted in a one-time gain of $0.9 million, combined
with a $2.5 million reduction in accruals under the Company's performance based
incentive compensation programs and a $0.5 million decrease in expenses for
legal services. Incentive compensation expense in 1994 included $0.6 million
related to the termination of a royalty-based discretionary incentive plan.
Exploration costs, including dry holes, decreased $2.4 million to $12.1
million for the year ended September 30, 1995, from $14.5 million for the year
ended September 30, 1994, primarily reflecting lower dry hole, G&G and lease
impairment expenses, partially offset by higher delay rentals and technical
staff expenses. G&G declined 53% to $1.6 million from $3.3 million in the prior
year period.
International
The Company recorded international operating income of $8.6 million in the
year ended September 30, 1995, a 64% decrease from the $23.8 million recorded
for the year ended September 30, 1994. Lower per barrel profitability from the
Company's producing operations on OPLs 98/118 in Nigeria combined with increased
exploration expenses in other international areas and a reduction in operating
profits from crude oil trading activities were responsible for the $15.2 million
decline in operating profit.
Operating income from OPLs 98/118 totaled $10.1 million in 1995, a $10.2
million decline from the $20.3 million earned in the prior year. Crude oil
production rose slightly to 18.8 MBbls per day in 1995 compared to 18.7 MBbls
per day in 1994. The average price recorded also increased, rising 8% to $16.17
per Bbl in 1995. Net profits were recognized at the rate of $1.46 per Bbl and
$2.89 per Bbl for 1995 and 1994, respectively, in accordance with the Company
policy of assessing overall profitability of the PSC based on the remaining
field life to the Company. The $1.43 per Bbl reduction in the recognition rate
in 1995 as compared to 1994 was responsible for the entire reduction in
operating income, while the slightly higher volumes had an insignificant impact
on results compared to the prior year. The substantial drop in the rate of
income recognition reflects the Company's decision to increase its capital
investment on OPLs 98/118 in an effort to
41
<PAGE> 43
sustain existing production until such time as new production could be added on
either these blocks or on OPLs 90/225. The reduction in the rate of recording
net profits reflects the fixed cost nature of operating expenses to be incurred
during the transition to new production.
Operating losses from OPLs 90/225 rose $2.8 million in 1995 to $4.7
million. Exploration costs of $4.0 million increased $4.8 million in 1995
compared to 1994 reflecting $3.7 million of dry hole expenses and a $1.5 million
increase in G&G related to these blocks. G&G expense in 1994 included a $1.0
million credit for reimbursement by the Company's partner for G&G incurred in
prior years. Partially offsetting these increases was a $2.2 million reduction
in administrative and technical staff expenses charged to the operation. Results
for 1994 included $2.4 million of prior period administrative and technical
staff costs which were reallocated to OPLs 90/225 from other international to
more properly reflect the source and nature of those expenses.
Operating income from the Company's other international activities declined
by 41% to $3.2 million in 1995 from $5.4 million in 1994, despite a $1.4 million
decrease in exploration costs, principally in Australia. Results for 1994
included $0.8 million of lease impairment to fully impair the book value of the
Company's Australian leasehold, as well as $0.8 million of dry hole expenses.
Dry hole expenses in Australia during 1995 totaled $0.4 million. Crude oil
trading activity produced $4.8 million of operating income in 1995 compared to
operating income of $5.8 million in 1994 despite a 7% increase in volumes traded
to 7.5 MMBbls. Trading results for 1994 included $1.8 million of operating
income related to the final resolution of pricing issues pertaining to prior
period transactions. Results for 1994 also included a $2.4 million credit for
reallocation of certain prior period administrative and technical staff expenses
to OPLs 90/225 as discussed above.
Consolidated Net Income
Net income for the year ended September 30, 1995 decreased $24.4 million,
or 71%, to $9.9 million from $34.4 million for the year ended September 30,
1994. Domestic net income in 1995 included a $2.9 million charge for the
adoption of SFAS No. 121. Excluding this unusual item, domestic net income
declined $6.8 million to $4.1 million, principally reflecting the industry-wide
weakness in natural gas prices and other operating factors as described above.
Domestic net income included $9.6 million and $10.3 million of Section 29 tax
credits in 1995 and 1994, respectively. Domestic income tax expense in 1994 also
included approximately $1.0 million related to the reclassification of certain
prior period administrative expenses from domestic to international operations.
Net income from international operations declined by 63% to $8.6 million in
1995 from $23.3 million in 1994 for the reasons described above. No U. S. tax
expense was calculated on foreign income as the Company was allocated the
benefits of foreign tax credits expected to be utilized. In the years ended
September 30, 1995 and 1994, the Company also received credits from Ashland for
$0.2 million and $0.1 million, respectively, for its share of benefits
associated with the filing of a combined company return in Australia for 1993
and 1992, respectively.
LIQUIDITY AND CAPITAL RESOURCES
During the three month period ended December 31, 1996, net cash used for
operating activities totalled $4.4 million as compared to net cash provided by
operating activities of $29.0 million for the same period in 1995. Net cash
provided by operating activities for the fiscal years ended September 30, 1996
and 1995 was $112.9 million and $59.0 million, respectively. The primary reason
for the large increase in net cash provided by operating activities for fiscal
1996 as compared to fiscal 1995 (and corresponding decrease in the quarter ended
December 31, 1996) was the $73.1 million payment received in November 1995 in
connection with the Columbia Gas settlement.
Net cash used in investing activities of $14.6 million for the first three
months of fiscal 1997 increased $6.7 million from the first quarter of fiscal
1996, reflecting higher development expenditures in both the Gulf of Mexico
Region and Nigeria. Capital increases of $2.5 million in the Gulf of Mexico
Region reflect activity associated with the development of the Vermilion 410
field, which began production on December 23, 1996. For the fiscal years 1996
and 1995, cash used in investing activities was $78.2 million and $112.9
million, respectively.
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<PAGE> 44
The Company's capital expenditures in fiscal years 1994, 1995 and 1996 were
$55.9 million, $157.9 million and $93.6 million, respectively. The decrease in
capital expenditures of $64.3 million for the fiscal year ended September 30,
1996 from the prior fiscal year was primarily due to the acquisition in the
second quarter of fiscal 1995 of the Appalachian producing properties of Waco
Oil & Gas Co., Inc. and UMC Petroleum Corp. for $68.7 million. The $23.6 million
increase in fiscal 1996 development spending is a result of construction of
Vermilion 410 facilities and development drilling in Nigeria. Unsuccessful
exploratory drilling in Nigeria in fiscal 1995 accounted for $24.2 million of
exploratory drilling expense. Exploration expenditures in the first quarter of
fiscal 1997 were $11.9 million greater than the same period in the prior year.
The increase was principally due to higher geophysical and geological spending
in Nigeria.
The table below sets forth the components of the Company's historical
capital expenditures for the three-year period ended September 30, 1996 and the
three-month periods ended December 31, 1995 and 1996.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED SEPTEMBER 30, DECEMBER 31,
---------------------------- ------------------
EXPENDITURE CATEGORY 1994 1995 1996 1995 1996
-------------------- ------- -------- ------- ------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Exploration.................................. $20,019 $ 47,859 $24,085 $1,564 $13,450
Development.................................. 33,448 39,333 62,945 5,864 11,362
Lease acquisition............................ 1,581 2,124 4,531 76 602
Proved property acquisition.................. 869 68,611 2,087 2,020 --
------- -------- ------- ------ -------
Total.............................. $55,917 $157,927 $93,648 $9,524 $25,414
======= ======== ======= ====== =======
</TABLE>
The Company's ability to maintain and grow its operating income and cash
flow is dependent upon continued capital spending. The Company expects that its
fiscal 1997 and fiscal 1998 capital expenditures will be approximately $112
million and $134 million, respectively. The Company has spent $25.4 million of
its fiscal 1997 capital expenditure budget through December 31, 1996. In fiscal
1997, the Company plans to drill 85 net development wells in the Appalachian
Basin, four net exploratory wells in the Gulf of Mexico, and one development
well in Nigeria on OPLs 98/118. In addition, the development plan for the Okwori
South field offshore Nigeria located on OPLs 90/225, has been approved by the
Company and Total. The next step is to obtain approval from the NNPC so that
development can commence in 1997. The Company's level of capital expenditures
may vary in the future depending on a number of factors, including energy market
conditions and other related economic factors. There are no material long-term
commitments associated with expenditure plans.
Historically, the Company's operating needs as well as its capital spending
programs have been funded through cash flow from operations as well as through
advances from Ashland. Under a system of intercompany accounts, all cash
received by the Company was advanced to Ashland, which in turn advanced cash to
the Company to fund its operating needs. See Note (9) to the Consolidated
Financial Statements of the Company. During fiscal 1995 and for the quarter
ended December 31, 1996, the Company's operating needs and capital expenditure
programs required advances from Ashland in excess of the Company's cash flow in
the amounts of $53.9 million and $19.0 million, respectively. During fiscal 1994
and fiscal 1996, the Company's cash flows exceeded its operating needs and
capital expenditures in the amounts of $77.8 million and $34.7 million
(including the Columbia Gas settlement), respectively. Upon the completion of
the Offering, this system of non-interest bearing intercompany accounts will be
discontinued and the Company will no longer receive advances from Ashland for
the Company's spending requirements in excess of its cash flow and will depend
on external sources of funding, although the Company will continue to utilize
certain cash management functions of Ashland until the Spin Off.
The Company has entered into a letter agreement with The Chase Manhattan
Bank ("Chase") under which, prior to consummation of the Offering, the Company
will enter into a $200 million Credit Facility with Chase as both agent (the
"Agent") and lender. Chase has committed to underwrite and provide the entire
Credit Facility and has the right to syndicate the Credit Facility to a group of
lenders (together with Chase,
43
<PAGE> 45
the "Lenders") whose participants will be chosen by Chase in consultation with
the Company. The Credit Facility will permit the Company to obtain unsecured
revolving credit loans (the "Loans") and the issuance of letters of credit
("Letters of Credit") for a five year period in an aggregate amount not to
exceed $200 million (with a sublimit of $50 million for Letters of Credit) at
any time outstanding (the "Commitment"). Commitment availability will be
governed by a Borrowing Base (as defined in the Credit Facility). The initial
Borrowing Base has been set at $250 million, thus providing the Company
availability of the entire Commitment. Subsidiaries of the Company may borrow
under the Credit Facility if such obligations are guaranteed by the Company, and
such borrowings by the Company's subsidiaries will be limited in the aggregate
to $125 million. At the Company's option, each Loan to the Company will bear
interest at (i) the higher of the federal funds effective rate plus 0.5% or
Chase's prime rate, or (ii) at the eurodollar rate, plus a margin ranging from
0.5% to 1.25%, depending upon the degree of current usage under the Credit
Facility. Loans to the Company's subsidiaries will carry a fixed margin of 0.75%
over the selected eurodollar rate. The Company will also pay to the Lenders a
fee on the unused portion of the Commitment ranging from 0.20% to 0.35%. The
Credit Facility will contain various restrictive covenants customarily found in
such facilities, including limitations on the Company's ability to incur
additional indebtedness and its ability to pay cash dividends unless certain
conditions are met. In addition, the Credit Facility will require the Company to
maintain a minimum consolidated net worth equal initially to 80% of the
Company's consolidated net worth on the date the Credit Facility becomes
effective. The Company expects to be in compliance with the requirement that the
Company maintain a ratio of EBITDA (as defined in the Credit Facility) to
interest expense of at least 2.75 times on a four-quarter rolling basis after
the Offering.
The Company intends to borrow approximately $110.0 million under the Credit
Facility to pay a portion of the $180.0 million cash portion of the Ashland
Dividend. See "Use of Proceeds."
The Company believes its capital resources are adequate to meet the
requirements of its business. Because future cash flows are subject to a number
of variables, such as the level of production of natural gas and oil and the
sales price of natural gas and oil, there can be no assurance that the Company's
operations will provide cash in sufficient amounts to maintain current levels of
capital expenditures or to meet the Company's debt service requirements. See
"Risk Factors -- Leverage," "-- International Operations," "-- Volatility of
Natural Gas and Oil Prices" and "-- Reserve Replacement Risk."
POST-OFFERING MATTERS
The Company anticipates that administrative costs will be somewhat higher
in fiscal 1997 and fiscal 1998 as a result of the new and additional costs the
Company will incur as a result of becoming a stand-alone enterprise. Such cost
increases will include additional administrative personnel, additional
third-party fees, Credit Facility fees and incremental insurance costs. In
addition, interest expense will also increase for fiscal 1997 by approximately
$3.3 million as a result of the Company's borrowings under the new Credit
Facility. As a subsidiary of Ashland, the Company has been able to utilize the
administrative services and personnel of Ashland. Those services are generally
provided at cost and have included legal, tax, risk management and insurance
administration, employee benefits assistance, cash management and certain other
treasury functions, corporate accounting, information systems and other
services. The Company was allocated a charge of $1.1 million in the quarter
ended December 31, 1996, and $2.3 million, $2.4 million, and $2.3 million in the
fiscal years ended September 30, 1996, 1995 and 1994, respectively, in
connection with the provision of these services. The allocation in the quarter
ended December 31, 1996, reflected an additional charge of $0.4 million as a
result of Ashland's decision to allocate more of the costs of doing business to
its operating divisions effective October 1, 1996.
In the future, the Company intends to develop the internal capacity to
provide these services and functions (or purchase them from third-party vendors)
and will cease to rely on Ashland. The Company anticipates that its operating
and general and administrative costs will increase for fiscal 1997 by
approximately $1.0 million over fiscal 1996 levels as it assumes full
responsibility for each of these services and functions. In addition, the
Company anticipates that its insurance costs will increase by approximately $1.0
million per year following the Spin Off.
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<PAGE> 46
BUSINESS AND PROPERTIES
OVERVIEW
The Company is an independent energy company engaged in the exploration for
and the development, production, acquisition and marketing of natural gas and
oil in the United States and in Nigeria. The Company is currently a wholly-owned
subsidiary of Ashland.
The Company has been active in the natural gas and oil business in the
United States for over 80 years and in Nigeria for over 20 years. In the United
States, the Company's production is concentrated in the Appalachian Basin and in
the Gulf of Mexico. Internationally, the Company operates both onshore and
offshore Nigeria in the deltaic region of the Niger River. All of the Company's
natural gas production comes from the United States, while substantially all of
its crude oil production comes from Nigeria. The Company also owns mineral
royalty interests in oil and gas properties throughout the United States.
At September 30, 1996, the Company's net proved reserves were 770.6 Bcfe,
which was comprised of 576.9 Bcf of gas and 32.3 MMBbls of oil. During the five
fiscal years ended September 30, 1996, the Company increased its net proved
reserves by 54%, from 499.1 Bcfe at September 30, 1991 to 770.6 Bcfe at
September 30, 1996, through a successful exploration and development program and
a series of strategic property acquisitions. The Company's average net natural
gas production over the same period increased by 38%, from 78.3 MMcf per day in
fiscal 1992 to 108.4 MMcf per day in fiscal 1996. For the quarter ended December
31, 1996, total average net natural gas and oil production was 214.8 MMcfe per
day, consisting of 105.8 MMcf per day of natural gas and 18.2 MBbls of oil per
day. The Company's average oil production decreased from 26.9 MBbls per day in
fiscal 1992 to 18.1 MBbls per day in fiscal 1996 due to a period of relatively
low capital investment by the Company in Nigeria in prior years. To reverse this
trend, the Company began in fiscal 1995 to increase significantly its Nigerian
capital expenditures for exploration and development. The SEC Present Value of
the Company's proved reserves before U.S. income taxes was $350 million as of
September 30, 1996. For the purpose of comparing the SEC Present Value of the
Company's reserves with those of companies having a calendar year end, if the
Company's SEC Present Value before U.S. income taxes were calculated using
September 30, 1996 reserve quantities but using gas and oil prices in effect at
December 31, 1996, such value would have been $889 million, although natural gas
and oil prices are currently at levels more similar to September 30, 1996
prices. See "-- Reserves."
The Company intends to continue its reserve and production growth in the
Appalachian Basin and to accelerate such growth in the Gulf of Mexico and
Nigeria. The Company spent approximately $87 million for exploration and
development for the year ended September 30, 1996 and plans to spend
approximately $112 million and $134 million during the 1997 and 1998 fiscal
years, respectively.
In December 1996, the Company significantly enhanced its existing Gulf of
Mexico operations with the initiation of production from the Vermilion 410
field, from which the Company averaged net natural gas production of 29.4 MMcf
per day for the month of February 1997. In Nigeria, the Company recently filed a
development plan with respect to what it believes to be a commercial oilfield
discovery called the Okwori South field, from which the Company expects to begin
production in the second half of calendar 1998.
The Company owns working interests in approximately 1,425 gross wells that
qualify for Section 29 tax credits, which have generated $59.8 million of tax
credits for Ashland through September 30, 1996, including $10.5 million in
fiscal 1996. The Company recently entered into a letter of intent under which it
will monetize these tax credits to maximize their benefit to the Company. Under
the terms of the agreement, the Company will sell the Section 29 Tax Credit
Properties but continue to operate and be entitled to all of the cash flow from
the properties until approximately 94% of the net present value of the reserves
have been produced. The proposed transaction contemplates that the Company will
receive a cash payment of $6.5 million at closing, plus additional quarterly
payments through 2002 reflecting the value of the Section 29 tax credits
generated from the properties, which payments are expected to be approximately
$2.5 million per quarter in 1997, declining to approximately $2.0 million per
quarter in 2002. In connection with the transaction, the buyer will apply for a
ruling from the Internal Revenue Service with regard to certain aspects of the
transaction. In the event a favorable ruling is not received on or before
September 15, 1997, the buyer will have the right to
45
<PAGE> 47
rescind the transaction. Closing of the transaction, which is expected to occur
in April 1997, is subject to contingencies, including completion of due
diligence, receipt of certain consents and negotiation of definitive documents.
See "-- Section 29 Tax Credits."
COMPANY STRENGTHS
STABILITY OF APPALACHIAN PRODUCTION. The Company has been a leading
producer and operator in the Appalachian Basin for over 80 years. Over the past
five fiscal years, the Company has drilled 493 net wells in Appalachia with a
99% success rate, and through its drilling and acquisition projects, has
increased net proved reserves by 45% while extending the boundaries of
productive areas. At September 30, 1996, the Company had net proved reserves of
541.0 Bcfe in Appalachia, of which 461.1 Bcfe, or 85%, were proved developed.
The Company has an average working interest of 89% in approximately 1,050,000
gross acres in Appalachia. The Company's properties have extensive production
histories, and the Company believes that such properties contain significant
reserve and production enhancement opportunities. The Company plans to further
exploit opportunities on its properties and has identified approximately 400
development well locations that it intends to pursue over the next five years.
The Company's 1,200 mile gas gathering system in Appalachia is interconnected
with various intrastate and interstate transmission lines, which gives the
Company access to both local markets and major northeastern United States
markets. The long-life, stable production and cash flow from the Company's
properties in Appalachia help to offset the risks of and fund the Company's
higher return opportunities in the Gulf of Mexico and Nigeria.
OVER 20 YEARS OF SUCCESSFUL NIGERIAN OPERATIONS. The Company has been
active in Nigeria since 1973, with oil production commencing in and continuing
uninterrupted since 1975, notwithstanding periods of political instability in
the region. The Company believes the stability of its operations during this
period can be attributed to its long-standing relationship with the NNPC, the
Nigerian state-owned petroleum company, and the recognition by successive
Nigerian administrations of the oil sector's importance to Nigeria's economy,
which has been evidenced by Nigeria's continued administrative support and
consistent economic policies that serve to preserve the petroleum industry. The
Company believes it is one of only two foreign independent energy companies with
production in Nigeria and one of several foreign operators in the country, which
include subsidiaries or affiliates of Shell, Chevron, Mobil, Texaco, Elf and
Agip. In Nigeria, the Company operates under two PSCs, the first of which was
originally signed in 1973 and the second of which was signed in 1992. The 1973
PSC, in which the Company owns a 100% working interest, pertains to OPLs 98 and
118, which together cover 177,000 acres. The Company commenced production under
the 1973 PSC in 1975, had peak daily production of 46.5 MBbls of oil per day in
November 1989 and has had cumulative production from the 1973 PSC acreage of
approximately 161 MMBbls of oil through September 30, 1996. The 1992 PSC, which
the Company operates with a 50% partner, Total, pertains to OPLs 90 and 225,
which together cover 450,000 gross acres and include the Okwori South field
discovery.
EXPERTISE IN DELTAIC ENVIRONMENTS. The Company has conducted significant
exploration activities in the Mississippi River deltaic region since 1984 and in
the Niger River deltaic region in Nigeria since 1973. These two environments
have similar geologic characteristics, which gives the Company flexibility in
the utilization of its geoscience staff. An important factor in successful
exploration in these environments is the computer-aided interpretation of 3-D
seismic surveys and the integration of such data with subsurface data. The
Company has a staff of 13 geoscientists who are experienced at using such
technology to evaluate opportunities in these deltaic environments. The
Company's operating personnel have expertise in conventional, high angle and
horizontal drilling and producing in these environments. The Company's recent
discoveries of the Vermilion 410 field in the Gulf of Mexico and the Okwori
South field in Nigeria were the result of the use of these technologies. The
Company believes that its skills in geoscience evaluation and operations would
be easily transferrable to deltaic areas in other West African countries.
EFFICIENT OPERATOR. The Company operates approximately 93% of its
production, which provides a significant advantage in controlling costs,
allocating capital and timing the development and exploitation of its
properties. The Company's personnel have considerable expertise in planning and
conducting a variety of oil and gas operations, ranging from air drilling and
stimulation in the tight formations in Appalachia to offshore projects with
complex technical and logistical requirements. The Company's lease operating
expenses in the
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<PAGE> 48
U.S. averaged $0.47 per Mcfe for the fiscal year ended September 30, 1996 and
$0.43 per Mcfe for the quarter ended December 31, 1996. The Company also
believes it is a low-cost developer of reserves in Appalachia, and over the past
three fiscal years has reduced its drilling cost per well in the region by
approximately 28%.
SUCCESSFUL ACQUISITION HISTORY. Since 1990, the Company has spent a total
of approximately $172 million to acquire properties in Appalachia from Oxy
U.S.A., Inc., UMC Petroleum Corp. and Waco Oil & Gas Co., Inc. The acreage
acquired in these transactions is in close proximity to the Company's existing
operations in Appalachia, allowing the Company to reduce expenses on a per Mcf
basis through efficient consolidation. The Company has increased both reserves
and production by drilling a total of 532 successful net wells on these acquired
properties through December 31, 1996. The Company's selective acquisition
strategy has made these acquisitions attractive rate of return ventures.
BUSINESS STRATEGY
The Company's strategy is to capitalize on its strengths to increase cash
flow and shareholder value by increasing both its reserves and production
through the development and exploration of existing properties and the
acquisition of additional properties with development and exploration potential.
The Company intends to implement this strategy as described below.
ENHANCING APPALACHIAN POSITION. The Company is continuing to develop its
large leasehold position in the Appalachian Basin, where it has approximately
900,000 net acres and 256 net proved undeveloped drilling locations at September
30, 1996. The Company expects to drill approximately 85 wells per year over each
of the next two years, which are expected to require approximately $17 million
per year in capital spending. The Company is also currently evaluating
opportunities for infill drilling in the Appalachian Basin that could enhance
both its reserves and production in the area. The long-life, stable reserves in
Appalachia provide a source of cash for the Company to invest in higher return
opportunities in the Gulf of Mexico and international locations.
INCREASING EXPLORATION AND EXPLOITATION OF HIGH POTENTIAL AREAS. The
Company intends to increase its level of exploration and exploitation drilling
and currently has attractive leads and prospects on its existing acreage in the
Gulf of Mexico and Nigeria. The Company evaluates almost all of its prospects
with 3-D seismic data prior to drilling, which the Company believes enhances the
potential for returns and lowers dry hole exposure.
In the Gulf of Mexico, the Company has interests in 62 offshore blocks, or
about 150,000 net acres, with an average working interest of 51%. The Company
has an inventory of approximately 17 prospects in the Gulf of Mexico and plans
to participate in eight wells in the 1997 fiscal year. The Company currently has
rights to approximately 148 square miles of 3-D seismic data on 19 of its 62
offshore leases in the Gulf of Mexico and over 63,000 linear miles of 2-D
seismic data in the Gulf of Mexico, primarily offshore Louisiana. Capital
expenditures in the Gulf of Mexico for fiscal 1997 and 1998 are expected to be
approximately $31 million and $36 million, respectively.
In Nigeria, the Company has identified approximately 30 leads and prospects
on the 177,000 acres covered by the 1973 PSC, in which it holds a 100% working
interest. In the third calendar quarter of 1997, the Company expects to commence
a new drilling program of at least six wells on OPL 98. Under the 1992 PSC, the
Company has identified nine leads and prospects on the approximately 450,000
gross acres in OPLs 90/225. In OPL 90, a development plan has been filed with
Nigerian authorities for the recently discovered Okwori South field, from which
the Company expects to begin production in the second half of calendar 1998. The
Company expects the Okwori South field to provide cash flow as well as tax
advantages to help fund the exploration of the other prospects on the 1992 PSC
acreage. The Company expects to begin additional exploratory drilling on OPLs
90/225 in 1998. On the 1973 PSC, approximately 67% of the acreage will be
covered with new 3-D seismic data by May 1997, and this data should be processed
and fully interpreted by September 1997. On the 1992 PSC, the Company has
acquired and evaluated 3-D seismic data on approximately 34% of the acreage,
including the Okwori South field. Capital expenditures in Nigeria for fiscal
1997 and 1998 are budgeted to be approximately $53 million and $67 million,
respectively.
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<PAGE> 49
EXPANDING FROM CORE HOLDINGS. The Company will seek new exploration
opportunities outside its core holdings in areas where its competitive strengths
can be applied. For example, the Company has recently acquired approximately
100,000 net acres of leasehold interests in Indiana and Kentucky in the New
Albany Shale formation, where the Company believes it can benefit from the
application of its Appalachian expertise in producing natural gas from tight
formations. The Company will also seek to expand its holdings in the Gulf of
Mexico through lease acquisitions and farm-ins, focusing primarily in the
Louisiana offshore area in an effort to replicate its success at its Vermilion
410 field in building its Gulf of Mexico reserve base. The Company farmed in the
Vermilion 410 block in order to drill its original prospect and subsequently
leased five nearby blocks and farmed in two other adjacent blocks. As a result,
the Company has compiled an eight block complex and has identified additional
exploration prospects. Further, the Company believes that its expertise in
Nigerian ventures can be successfully applied to other international regions.
The Company has begun preliminary analysis of other West African countries known
to have hydrocarbon resources. In international areas, the Company intends to
manage the future risks of exploration by participating generally at interest
levels of 20% to 50% in basins known to contain hydrocarbons that can be
developed with conventional technology.
PURSUING GROWTH THROUGH TARGETED ACQUISITIONS. The Company is continually
evaluating opportunities to acquire producing properties that possess, among
others, one or more of the following characteristics: (i) close proximity to the
Company's existing operations, (ii) potential opportunities to increase reserves
through drilling and additional recovery or enhancement techniques and (iii)
potential opportunities to reduce production expenses through more efficient
operations. The Company has benefited from the deemphasis of conventional
domestic exploration and production operations by the major and large
independent energy companies in favor of large capital intensive projects, which
in turn has resulted in such oil companies offering for sale a number of
attractive properties. Company personnel have substantial training, experience
and in-depth knowledge of the Company's core areas, as well as established
relationships with a number of major and large independent energy companies
operating in the regions, which the Company believes will help it complete
successful acquisitions.
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<PAGE> 50
OIL AND GAS PROPERTIES AND DEVELOPMENT ACTIVITIES
The following table summarizes the Company's net proved reserves as of
September 30, 1996, based on the report of Netherland Sewell, for each of its
most significant producing fields based on the SEC Present Value before U.S.
income taxes:
<TABLE>
<CAPTION>
SEPTEMBER 30, 1996 PROVED RESERVES
--------------------------------------------------------
NATURAL
GAS OIL TOTAL SEC PV(1)(2) % OF TOTAL
REGION FIELD NAME (MMCF) (MBBLS) (MMCFE) (IN MILLIONS) SEC PV
------ ---------- ------- ------- ------- ------------- ----------
<S> <C> <C> <C> <C> <C> <C>
Appalachia....... Eastern Kentucky Gas, KY.... 245,888 52 246,199 $113.6 32.4%
Logan/Wyoming, WV........... 55,911 -- 55,911 28.9 8.2
Gilbert/Island Creek, WV.... 48,691 -- 48,691 28.8 8.2
Paint Creek, WV............. 51,161 -- 51,161 27.2 7.8
Other....................... 134,949 685 139,061 64.2 18.3
Gulf of Mexico... Vermilion 410............... 20,157 -- 20,157 24.2 6.9
Other....................... 12,754 41 12,999 12.7 3.6
International.... Nigeria OPLs 98/118(3)...... -- 30,644 183,864 33.5 9.6
Royalty.......... Various..................... 7,374 859 12,530 17.4 5.0
------- ------ ------- ------ -----
Total................................ 576,885 32,281 770,573 $350.5 100.0%
======= ====== ======= ====== =====
</TABLE>
- ---------------
(1) SEC Present Value before U.S. income taxes as of September 30, 1996.
(2) Does not include the value of Section 29 tax credits.
(3) As of September 30, 1996, all of the Company's proved reserves in Nigeria
were in OPL 98/118. The Nigerian crude oil reserves included herein
represent gross volumes before any reduction for the Nigerian government's
share of such reserves, which is paid in the form of royalties and
production taxes. Crude oil reserves of 32.3 MMBbls at September 30, 1996
are as estimated by Netherland Sewell. Such reserves are 10.7 MMBbls greater
than the amount previously reported as of such date in filings made with the
Commission by Ashland, the amounts included in such filings being derived
from a Company-generated reserve report prior to the availability of an
estimate from Netherland Sewell.
Appalachian Region
The Company is one of the largest producers of natural gas in the
Appalachian Basin, where it has conducted operations for over 80 years. At
September 30, 1996, the Company's total net proved reserves in the region were
541.0 Bcfe or 70% of the Company's total net proved reserves. Net proved gas
reserves were 536.6 Bcf, which represents 93% of total Company net proved gas
reserves. At September 30, 1996, Netherland Sewell had identified 256 additional
net proved undeveloped drilling locations, many of which will be drilled as part
of the Company's planned 400 well drilling program over the next five years. The
Company's total net gas production from this area in fiscal 1996 averaged
approximately 81.9 MMcf per day, with minimal associated oil or water
production. The Company has an average working interest of 91% (81% average net
revenue interest) in its wells in the Appalachian Region. Natural gas produced
in the Appalachian Region contains an average of 1,137 Btu per cubic foot, and
consequently receives premium pricing on a volumetric basis.
The Company operates 3,768 gross wells, 1,200 miles of gathering pipelines,
and 57 compressor stations in the Appalachian Region. The Company operates 93.4%
of its gross wells in the region. Operations are conducted in 46 counties in
three states. Wells produce from geologic formations that are of Silurian age or
younger at depths ranging from 1,500 to 7,000 feet. Individual wells often have
economic lives in excess of 50 years. The costs to develop Appalachian reserves
are low compared to other regions of the U.S. because of the relatively shallow
reservoir depths and the low incidence of dry holes. Over the past five fiscal
years, the Company has drilled 493 net wells in the Appalachian Region, with a
99% success rate. The Company believes that it gains operational efficiency and
therefore maximizes the return on its investment in the Appalachian Basin
because of its large acreage position, its substantial ongoing drilling program
conducted
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<PAGE> 51
over a number of years, and its extensive gas gathering system. The Company's
Appalachian gas gathering system is interconnected with various intrastate and
interstate transmission lines that allow access to both local and major markets
in the northeastern United States. Some of the Company's Appalachian natural gas
production is connected directly to end users through the Company's pipelines.
The Company has acquired and is continuing to acquire gathering facilities from
transmission companies to allow for direct connection to transmission pipelines.
The Company's gas gathering system is also used to carry third-party natural gas
to market through purchase/resale or transport arrangements.
Operations of the Appalachian Region are directed from a regional office in
Russell, Kentucky with field offices in Pikeville, Kentucky; Danville, West
Virginia; and Weston, West Virginia. A total of 58 employees are located in
Russell, consisting of geologists, engineers, land agents, gas marketing and
measurement representatives and support staff. An additional 154 non-union
employees conduct field operations.
The Company's principal Appalachian properties are as follows:
Eastern Kentucky Gas Area, Kentucky. The Eastern Kentucky Gas area includes
approximately 32% of the Company's total net proved reserves. The Company's
interests in this area are concentrated in Pike, Knott, Breathitt and Rowan
counties, Kentucky on 150,325 net acres. Natural gas is produced primarily from
the Lee, Maxton, Big Lime and Berea sandstone and Devonian Shale formations at
depths ranging from 900 to 5,500 feet. Production attributable to the Company's
net interest averaged 26.5 MMcf per day of natural gas and 142 Bbls per day of
crude oil during the first quarter of fiscal 1997. The Company drilled 232 net
wells in this area during the five year period ended September 30, 1996.
Significant development potential still remains, with 208 net proved undeveloped
locations identified for exploitation. Initial results of infill and directional
drilling test programs have been promising and may result in significant
additions to the existing reserve base.
Logan/Wyoming Area, West Virginia. The Logan/Wyoming area includes
approximately 7% of the Company's total net proved reserves. The Company's
interests are located in Logan and Wyoming counties in southern West Virginia on
124,088 net acres. Natural gas is produced from the Mississippian Maxton, Big
Lime and Berea sandstone formations at depths ranging from 2,100 to 4,400 feet.
Production attributable to the Company's net interest averaged 10.5 MMcf per day
of natural gas for the first quarter of fiscal 1997. The Company drilled and
completed eight successful net wells in the area during fiscal 1996, including
one that is currently producing at a rate of approximately 1.1 MMcf per day.
Gilbert/Island Creek Field, West Virginia. The Gilbert/Island Creek field
includes approximately 6% of the Company's total net proved reserves. The
Company's interests are located in Logan, Mingo and McDowell counties in
southern West Virginia on 140,676 net acres. Natural gas is produced from the
Mississippian Big Lime and Berea sandstone and the Devonian shale formations at
depths ranging from 1,700 to 6,000 feet. Production attributable to the
Company's net interest averaged 11.6 MMcf per day of natural gas for the first
quarter of fiscal 1997. The Company drilled and completed seven successful net
wells during fiscal 1996, two of which are currently producing at a combined
rate of approximately 2.0 MMcf per day.
Paint Creek Field, West Virginia. The Paint Creek field includes
approximately 7% of the Company's total net proved reserves. The Company's
interests are located in Fayette, Raleigh, Boone and Kanawha counties in south
central West Virginia on 148,342 net acres. Natural gas is produced from the
Mississippian Weir and Maxton sandstone formations at depths ranging from 1,800
to 3,600 feet. Production attributable to the Company's net interest averaged
7.3 MMcf per day of gas for the first quarter of fiscal 1997. The Company
drilled and completed four successful net wells in the field during fiscal 1996.
Gulf of Mexico Region
Substantially all of the Company's domestic producing properties outside
the Appalachian Basin are located in relatively shallow waters (less than 400
feet) of the Gulf of Mexico. The Company's 150,000 net acre holdings in the Gulf
of Mexico Region include interests in 62 blocks, of which 31 are operated by the
Company. The Company's activities in the region are concentrated offshore
Louisiana and Texas. At September 30, 1996, the Company's total net proved
reserves in the Gulf of Mexico Region were 33.1 Bcfe, or
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<PAGE> 52
4% of the Company's total net proved reserves, and approximately 99% of such
reserves were natural gas. In fiscal 1996, the Company's net gas production from
the Gulf of Mexico Region averaged 23.1 MMcf per day, or 21% of the Company's
total average daily net gas production. The Company's current production in the
region is from 51 gross (15.9 net) wells, with 76% of such production in the
region being operated by the Company in February 1997. Operations for the Gulf
of Mexico Region are managed from the Company's corporate headquarters in
Houston, Texas.
Vermilion 410, Offshore Louisiana. Beginning in December 1996, the
Company's principal producing property in the Gulf of Mexico Region is the
Vermilion 410 field, which consists of eight producing wells located on four
contiguous federal leases (Vermilion 389, Vermilion 409, Vermilion 410 and East
Cameron 362) located 110 miles off the Louisiana coast in a water depth of 360
feet. The Company operates and owns a 50% working interest (39% net revenue
interest) in the Vermilion 410 field. Natural gas is produced from the Trim A
sandstone formation at depths ranging from 2,100 to 3,800 feet. The initial
exploratory well within the Vermilion 410 field was drilled in July 1994. The
field was subsequently developed with two platforms, one located within
Vermilion 410 and one within Vermilion 389, with four producing wells on each
platform. The Vermilion 410 platform began production in December 1996 and the
Vermilion 389 platform began production in January 1997. Total production
attributable to the Company's net interest from the Vermilion 410 field averaged
29.4 MMcf per day of natural gas during February 1997.
International
Nigeria. Substantially all of the Company's international operations are
conducted onshore and offshore Nigeria in the Niger River deltaic region. In
1973, the Company signed Nigeria's first PSC, which covered OPLs 98 (offshore)
and 118 (onshore). In 1975, production commenced at 6.5 MBbls of oil per day on
OPL 118. In response to improved tax and PSC terms, in 1979 the Company began a
10 year exploration and development program on OPL 98, which began production in
1984. Two years later, the Company installed Nigeria's first floating,
production, storage and offloading unit (a "FPSO") on OPL 98, which is a
permanently moored, converted tanker ship with 1.5 MMBbls of capacity.
From 1990 to 1994, Ashland decided to harvest the Company's reserves by
reducing capital investment in Nigeria to a total of $8 million over that
period, resulting in a decrease in average daily production from 41.9 MBbls per
day in fiscal 1990 to 18.1 MBbls per day in fiscal 1996. In 1992, the Company
signed a PSC for OPLs 90 and 225, both of which are offshore, and in 1994 farmed
out a 50% interest in the 1992 PSC to Total. During 1995 and 1996, the Company's
exploration activities resumed in Nigeria, and it invested $47 million over that
period. Total net proved oil reserves were 30.6 MMBbls at the end of fiscal
1996, up 23.0 MMBbls from the 7.6 MMBbls reported at 1994 fiscal year-end. With
a renewed focus on Nigeria coupled with newly obtained 3-D seismic data, and
advanced drilling and production technology, the Company is well positioned to
increase its Nigerian production and reserve volumes.
Key Provisions of PSCs. The Company operates in Nigeria under two PSCs,
which provide that the Company funds all of the operating and capital
expenditures and recovers its costs and profits from the proceeds of the oil,
which is marketed and sold by the Company. The proceeds of the oil sales are
received abroad, usually in U.S. dollars, and then distributed to the government
of Nigeria. The PSC structure differs from the joint venture arrangements of
many other foreign oil and gas operators in Nigeria in that, under its PSCs, the
Company does not have to depend on the NNPC for reimbursement of costs. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
The Company's 1973 PSC originally had two terms that totaled 25 years.
However, in 1994 the second term was extended by the NNPC for an additional 15
years to the year 2013. The 1992 PSC has a total term of 25 years expiring in
2017, provided that the agreement would expire automatically in July 1997 unless
oil reserves capable of producing in commercial quantities have been discovered.
The Company, and its partner Total, believe that such requirement has been
satisfied by the discovery and development plan of the Okwori South field and
have notified the NNPC to that effect. However, the Company has not received
acknowledgment from the NNPC that the commerciality requirement has been
satisfied. The Company expects to receive such acknowledgment in due course,
although no assurance can be given as to when or if it will receive such
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<PAGE> 53
acknowledgment. See "Risk Factors -- Extension of Nigerian 1992 PSC." As is
common in international production sharing agreements, the 1973 PSC and the 1992
PSC have relinquishment provisions. The 1992 PSC required a relinquishment of
25% of the original acreage in 1995 and will require the relinquishment of
another 25% of the original acreage in July 1997. Under these relinquishment
provisions, the Company is entitled to choose the acreage to be relinquished,
subject to certain guidelines, and does not believe the acreage to be
relinquished will affect the Company's identified prospects. Under the 1973 PSC,
all relinquishment requirements have been satisfied.
Nigerian Political Climate. Since the Company began producing oil in
Nigeria in 1975, the Company's production has not been interrupted by political
or economic events. Oil is a valuable resource for Nigeria, with the oil
industry providing approximately 12% of the country's GDP and 93% of its foreign
exchange. Accordingly, the Nigerian authorities have strived to keep the
political evolution of the country from impacting the oil industry. The Company
works to maintain good relationships with the Nigerian authorities and the local
population residing near onshore operating areas. Operations are conducted in
accordance with all environmental laws and regulations, and the Company provides
benefits, such as fresh water supply, road improvements and scholarships, to the
local residents near its onshore operations. Shell, Chevron, Texaco, Elf, Mobil
and Agip have all made commitments to large capital programs in Nigeria. In
addition, Exxon Corporation, Amoco Corporation, Conoco Inc., Statoil Norge A.S.
and Total have recently signed PSCs or have become partners in existing PSCs.
The Company has no reason to believe that the oil industry in Nigeria will
be interrupted by the evolution of the country's political process, although
there can be no assurance that interruptions will not occur. Recent political
events have put Nigeria under increased scrutiny by the international community,
and the United States, Canada and other trading partners have from time to time
considered the imposition of significant oil trade sanctions against Nigeria.
Recent news reports have indicated that the U.S. Congress may consider imposing
such oil sanctions on Nigeria. There can be no assurance that actions taken by
the United States or the international community or future political unrest in
Nigeria will not cause interruptions in the Nigerian oil industry and in turn
have a material adverse effect on the Company's business, financial condition
and results of operations. See "Risk Factors -- International Operations" for a
description of certain risks that may be associated with operations in Nigeria
and other foreign countries.
OPLs 98/118. The Company owns a 100% working interest in OPLs 98 and 118,
which are combined for Nigerian fiscal and cost recovery purposes. OPL 98 is
located offshore Nigeria along the Cameroon border in water depths ranging from
10 to 140 feet and comprises 102,750 acres. OPL 98 includes six producing
fields, which produce from a series of Miocene sandstone formations at depths
ranging from 3,500 to 9,000 feet. The Company's production on OPL 98 averaged
10.1 MBbls of oil per day for the first quarter of 1997. In 1996, the Company
drilled three horizontal wells on OPL 98, which have helped mitigate the natural
decline of production from the fields. The Company plans to contract a rig to
initiate a program of six to ten wells on OPL 98 beginning in the third quarter
of calendar 1997. The Company is currently acquiring new 3-D seismic surveys
over all of OPL 98 to better define the geologic potential remaining on the
acreage. OPL 118, comprising 74,083 acres onshore east of the Niger River in Imo
State, includes two producing fields producing from a series of Miocene
sandstone formations ranging from 4,000 to 10,000 feet. The Company's production
from OPL 118 averaged 7.6 MBbls of oil per day for the first quarter of fiscal
1997. The Company has identified a number of workover and drilling opportunities
and other exploration leads in and around OPL 118.
OPLs 90/225. OPLs 90 and 225, which are combined for Nigerian fiscal and
cost recovery purposes, are located 25 miles offshore in water depths ranging
from 200 to 600 feet and comprise 450,000 gross acres. The Company operates the
OPLs and owns a 50% working interest with Total, which became a partner in 1994.
Exploration began on OPL 90/225 in 1994 with the drilling of the Okwori South #1
well, which tested over 6.0 MBbls of oil per day through ten feet of
perforations in a 52 foot thick oil zone in the Pliocene Green sandstone at a
depth of 6,500 feet. In 1996, the Company and Total drilled the Okwori South #2
and Okwori South #3 wells, which encountered several hydrocarbon-bearing
intervals at depths of 5,000 to 9,000 feet (Pleistocene to Miocene). The Company
and Total recently designated the Okwori South field to be commercial for
purposes of the 1992 PSC and have filed a development plan with the NNPC. The
Company expects to begin implementing its development plan in the second half of
calendar 1998 by drilling up to six
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<PAGE> 54
subsea completed wells that will produce to a FPSO. The Company and Total also
have identified numerous exploratory opportunities on OPLs 90/225.
Other. In Australia, the Company owns a 20% interest in one exploration
permit consisting of 335,000 gross acres and a 25% interest in another
exploration permit consisting of 590,000 gross acres, both of which are located
in the North Carnarvon Basin offshore western Australia. The Company has
participated in four gross exploratory wells, two on each block, all of which
have been dry. The Company has no further drilling commitments at this time.
Royalty Properties
The Company owns mineral royalty and override interests in approximately
244,000 net acres in 25 of the lower 48 states, Alaska and the Gulf of Mexico,
including more than 108,000 developed acres and approximately 136,000 acres of
exploration potential. Production attributable to the Company's net interest
averaged 3.5 MMcf of gas per day and 290 Bbls of oil per day during the first
quarter of 1997, and contributed $4.5 million to net revenues in fiscal 1996.
EXPLORATION ACTIVITIES
The Company's exploration efforts are coordinated by its experienced
geoscience staff of 13 professionals with additional support staff. The
Company's exploration efforts focus on three areas: (i) generation of a
portfolio of drilling opportunities on the Company's acreage blocks in Nigeria,
both onshore and offshore, (ii) generation of a portfolio of drilling
opportunities in the Gulf of Mexico (primarily on the Louisiana Outer
Continental Shelf (the "OCS")), and (iii) generation of large scale
opportunities in the Appalachian and related Paleozoic basins, such as the New
Albany Shale formation in the Illinois basin. The operations and reservoir
engineering personnel at the Company work closely with the Company's
geoscientists to evaluate the economics of exploration and exploitation
projects.
Focus Area Concept
The Company's exploration approach focuses on geologic trends or areas in
which the Company has a current acreage holding or can likely obtain acreage via
farm-in, trade, purchase or lease acquisitions, and where appropriate technical
data such as 3-D seismic data is owned or can be acquired. A team of
geoscientists, landmen, reservoir engineers and operations engineers are
assigned to identify the optimal number of opportunities to drill economically
for natural gas and oil within a given focus area. The opportunities can span a
broad range from development drilling, low- to medium-risk exploratory drilling,
exploitation through recompletion or horizontal drilling and acquisition of
producing wells. An example of the successful application of the focus area
approach is the Vermilion 410 complex, which began as a farm-in of a single
lease and has grown to an eight block, 29,000 gross (15,553 net) acre position.
Additional focus areas include the Appalachian producing areas, the New Albany
Shale area and each of the Nigerian acreage blocks (OPL 90/225, OPL 98 and OPL
118). In each example, a team of the Company's technical experts focuses on
defining and recommending all available drilling opportunities in the focus
area, from infill horizontal drilling to deep exploration, and adjusts such
focus to optimize achievement of the Company's objectives.
Exploration Technology
Seismic Data. A principal element of the Company's business strategy
involves the use of advanced technologies to analyze an extensive database of
geological and geophysical data in an effort to increase drilling success and
lower dry hole exposure. The Company currently has rights to approximately 148
square miles of 3-D seismic data on 19 of its 62 offshore leases in the Gulf of
Mexico and over 63,000 linear miles of 2-D seismic data in the Gulf of Mexico.
In Nigeria, the Company expects that approximately 67% of the acreage under the
1973 PSC will be covered with 3-D seismic by May 1997 and this data should be
processed and fully interpreted by September 1997. On the 1992 PSC,
approximately 34% of the acreage has been covered by 3-D seismic data, all of
which has been fully interpreted. To integrate the interpretation of its 3-D
seismic data and analyze potential exploration and exploitation opportunities,
the Company has a network
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<PAGE> 55
of twelve moveable workstations that use the Schlumberger GeoQuest seismic
software, multiple GES GeoGraphix mapping programs and a Schlumberger/GES QLA(2)
well log analysis program.
Horizontal Drilling Technology. Based on its high angle drilling in the
Gulf of Mexico and horizontal drilling operations in Nigeria, the Company
believes it has significant experience in the application of such drilling
technology and the associated skills required to plan and execute successful
high angle or horizontal drilling. Several staff geoscientists and engineers
have on site experience in geo-steering wells through objective formations using
real-time, down-hole information transmitted from the drill string to the rig
floor as drilling is in progress, which allows instantaneous changes in the
wellbore's angle and direction. This technology has wide application to increase
reservoir productivity and to preferentially produce oil (limiting water and gas
influx) in the Company's Nigerian oil fields. The Company believes that the
experience of its staff in using these technologies can also be applied in
certain Gulf of Mexico projects.
Exploration Activity Highlights
Vermilion 410 Field. The Vermilion 410 field is currently producing gas
from eight wells, with gross production from the field having achieved an
average of 75.4 MMcf per day in February 1997 (29.4 MMcf net per day). The
Company operates the Vermilion 410 with a 50% working interest (39% net revenue
interest). The Company drilled the discovery well on this internally generated
prospect in the summer of 1994 after the Company assembled a large acreage
position via farm-in, trades and bidding at federal lease sales. The Company's
partners, McMoRan Oil and Gas (37.5% interest) and Taurus Exploration (12.5%
interest), joined in drilling the initial exploratory well in the Vermilion 410
block on a promoted basis. The Company and its partners then drilled four
successful wells from each of two surface locations, one in the Vermilion 410
block and one in the Vermilion 389 block. A manned four-pile production platform
and satellite platform facility were installed, respectively, on each four-well
group. The Company has assembled a large, contiguous acreage position exceeding
29,000 gross (15,553 net) acres around the Vermilion 410 field, including
several additional prospects related to but separate from the field itself. The
Company expects to drill exploratory wells in 1997 and 1998 on Vermilion Blocks
392 and 408. In 1996, the Company purchased a 100% working interest in Garden
Banks Block 74, located southeast of the Vermilion 410 field in approximately
600 feet of water, which is scheduled to be drilled in late calendar 1998. The
strategy used in the exploration and exploitation of the Vermilion 410 area
serves as a model of the Company's focus area approach, which is to develop
internally generated prospects, acquire acreage via farm-in, purchase or acreage
trade and become the local expert, positioned to evaluate all drilling
opportunities in the area.
Other Gulf of Mexico Focus Areas. The Company plans to use the Vermilion
410 model in other geologic prospects on the edge of the OCS and upper
continental slope in the Gulf of Mexico. The Company is currently assembling an
acreage position in the South Timbalier area in the geologic fairway referred to
as the "flextrend." The Company's other primary area of prospecting focus is the
Miocene trend offshore Louisiana from West Cameron to Main Pass, where several
geoscience staff members have extensive experience. The Company has working
interests in several producing properties in this trend, notably West Cameron
35, West Cameron 141, Vermilion 68 and South Marsh Island 255. Currently, the
Company has a 12.5% interest in a wildcat discovery well on Eugene Island 65 and
has several prospects being developed in the Miocene trend.
Offshore Nigeria (OPLs 90/225). The Company operates and holds a 50%
interest in OPLs 90 and 225, which are located in 200 to 600 foot water depths
near the edge of Nigeria's outer continental shelf. The combined acreage blocks
include over 450,000 gross acres and eight separate identified geologic
prospects and leads. Occidental Petroleum drilled 11 exploratory wells on
several prospects on OPLs 90/225 in the 1970s and 1980s. Several of these wells
found oil reservoirs, including three wells on the Okwori structure. Occidental
did not develop the field, most likely due to low oil prices and less favorable
PSC terms and the lack of availability of 3-D seismic and directional drilling
technology at the time. The Company believes these technologies will be critical
to its development of the field by allowing more accurate mapping of
oil-trapping fault planes and larger oil accumulations, and permitting
production from multiple oil zones within a given well. The Company and Total
have drilled exploratory wells on two prospects in OPLs 90/225, the Nkelu
prospect and the Okwori prospect, resulting in the discovery of the Okwori South
field. The Company and
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<PAGE> 56
Total recently designated the Okwori South field to be commercial for purposes
of the 1992 PSC and intend to proceed with development and production using the
first subsea well completions in the country.
The Company and Total have acquired 3-D seismic data covering approximately
34% of OPLs 90 and 225 and drilled three successful exploration wells in 1995
and 1996, the Okwori South #1, #2 and #3 wells, which encountered multiple oil
and gas reservoirs. The Okwori South #1 well tested one oil zone at rates as
high as 6.2 MBbls of oil per day. Wells #2 and #3 were directionally drilled to
follow trapping fault planes and encountered 297 feet and 380 feet of oil,
respectively, in multiple reservoirs. The Okwori geologic structure is
complicated by faulting. However, 3-D seismic data allows increased accuracy in
mapping the oil bearing compartments. Numerous additional undrilled fault blocks
remain to be tested, which the Company believes may have significant potential
to add reserves to the field. The Company plans to acquire additional 3-D
seismic data on OPL 225 to help finalize additional prospects and leads for
future drilling. One of these, the Shokoloko prospect, was tested by Occidental
Petroleum at 6.0 MBbls of oil per day in 1972. As new 3-D seismic data is
acquired and interpreted, this inventory of prospects will be prioritized for
drilling.
Offshore Nigeria (OPL 98). The Company drilled four successful wells (the
Akam #15H, Ebughu #5, Adanga North #2H, and Adanga Southwest #1 wells) on this
102,750 acre offshore acreage during 1996. Three of these wells were horizontal,
extended-reach boreholes drilled in or near previously penetrated oil
reservoirs. A primary goal of this type of drilling is to produce oil while
minimizing gas and water production, which are common problems in the prolific
sandstone reservoirs typical in Nigeria. The Akam #15H well was drilled
horizontally for 950 feet in the oil column of a proven reservoir and
successfully produced oil with reduced water cut. At least one follow up well is
planned. The Ebughu #5 well was successfully drilled to 1,570 feet in a thicker
oil column than the Akam #15H well and also produced with greatly reduced gas
and water volumes. This well has produced at stabilized rates of approximately
1.5 MBbls of oil per day for over six months. Follow up development and step-out
wells are planned. The Adanga North #2H well was an exploratory horizontal well
drilled laterally 1,440 feet where lower gravity oil had been tested in an
earlier exploratory well. This well successfully tested at rates of 650 Bbls of
oil per day on a short-term production test and additional drilling is planned
in the proven fault block and adjacent fault blocks.
As a result of intensified geologic and geophysical mapping on OPL 98 in
1996, the Company's geoscientists have identified approximately 30 leads and
prospects on OPL 98, including infill development, step-out development and low-
to moderate-risk exploratory prospects. This large diverse inventory of leads
and prospects resulted in a decision by the Company to acquire new 3-D seismic
data on the entire lease block. Data acquisition is currently in progress and
should lead to definitive mapping and finalizing of these locations for drilling
beginning in late 1997. Offset drilling and 3-D seismic acquisition by Mobil,
Elf and Shell indicate that industry activity in general is accelerating in the
area immediately surrounding OPL 98.
Onshore Nigeria (OPL 118). The Company has produced over 81 MMBbls of oil
from two fields (the Izombe and Ossu fields) on this 74,083 acre block under the
1973 PSC. The two fields are related but distinct geologic traps with numerous
prolific reservoirs. The Izombe field has produced a total of approximately 74
MMBbls of oil and the Ossu field approximately 7 MMBbls of oil. Recent
geoscience and reservoir engineering studies by the Company have delineated the
possibility of additional drilling locations within existing fields. The Company
has recently purchased 70 square kilometers of 3-D seismic data over a portion
of OPL 118, which the Company believes will generate drilling opportunities,
including step-out and new field exploratory wells. The Company may also pursue
the acquisition of additional 3-D seismic data if preliminary mapping results
are encouraging.
West Africa Expansion. The Company plans to conduct geologic evaluations
and review outside opportunities in other West African countries, where the
Company believes that the skills and knowledge of its staff from experience in
Nigeria will enhance the Company's ability to evaluate such opportunities. The
Company's geoscientists and reservoir engineers have experience in applying
horizontal drilling technology to develop or re-develop oil fields, and its
operations personnel have extensive experience in the complicated logistical
aspects of oil field operations in foreign locations. The Company's FPSO
terminal in OPL 98 was the first such production system used in Nigeria and has
had ten years of successful operation. The Okwori South
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field is expected to be the first use of subsea well completions in Nigeria. The
Company believes that all of this experience can be applied to new opportunities
in Nigeria and other West African countries.
New Albany Shale Formation. The Company began participation in the Devonian
New Albany Shale formation by purchasing acreage and agreeing to participate
with another company in a pilot drilling project. The Company has acquired an
interest in approximately 100,000 net acres and intends to begin drilling in the
spring of 1997. The New Albany Shale formation is a highly fractured,
organic-rich, black shale in the Illinois Basin at depths ranging from 500 to
2,000 feet, which the Company believes is geologically analogous to the Antrim
Shale formation of the Michigan Basin. The delineation of producible gas
reserves in the New Albany Shale formation would allow application of the
Company's Appalachian expertise with large-scale, low-cost drilling programs and
economic exploitation of shale reservoirs in the core producing areas of eastern
Kentucky and West Virginia. The New Albany Shale project is the initial effort
to export the Company's low cost approach to exploitation of Paleozoic shale gas
reservoirs to a new area where significant potential reserves may exist.
Geoscientists in the Appalachian Region are actively searching for such
opportunities, as well as being integral team members of the Company's
exploitation teams that support the Appalachian Region development drilling
program.
RESERVES
The Company operates producing properties in five states, the Gulf of
Mexico and Nigeria, with most of its proved gas reserves located in two major
natural gas basins of the United States (Appalachian and Gulf of Mexico) and
most of its proved oil reserves located in Nigeria. The following tables set
forth estimates of the net proved natural gas and oil reserves of the Company at
September 30, 1996, as evaluated by Netherland Sewell.
<TABLE>
<CAPTION>
NATURAL GAS (MMCF) OIL (MBBLS) NATURAL GAS EQUIVALENTS (MMCFE)
--------------------------------- -------------------------------- ---------------------------------
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL
--------- ----------- ------- --------- ----------- ------ --------- ----------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Appalachian Region...... 456,831 79,769 536,600 710 27 737 461,090 79,933 541,023
Gulf of Mexico Region... 12,754 20,157 32,911 41 -- 41 12,999 20,157 33,156
Royalty................. 7,374 -- 7,374 859 -- 859 12,530 -- 12,530
Nigeria(1).............. -- -- -- 26,638 4,006 30,644 159,829 24,035 183,864
------- ------ ------- ------ ----- ------ ------- ------- -------
Total................. 476,959 99,926 576,885 28,248 4,033 32,281 646,448 124,125 770,573
======= ====== ======= ====== ===== ====== ======= ======= =======
</TABLE>
- ---------------
(1) As of September 30, 1996, all of the Company's proved reserves in Nigeria
were located in OPLs 98 and 118. The Nigerian crude oil reserves included
herein represent gross volumes before any reduction for the Nigerian
governments share of such reserves, which is paid in the form of royalties
and production taxes. Nigerian crude oil reserves of 30.6 MMBbls at
September 30, 1996 are as estimated by Netherland Sewell. Such reserves are
10.7 MMBbls greater than the amount previously reported as of such date in
filings made with the Commission by Ashland, the amounts included in such
filings being derived from a Company-generated reserve report prior to the
availability of an estimate from Netherland Sewell.
The reserve data set forth in this Prospectus represent only estimates.
Reserve engineering is a subjective process of estimating underground
accumulations of crude oil and natural gas that cannot be measured in an exact
manner. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and adjustment.
As a result, estimates of different engineers often 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 often differ
from the quantities of crude oil and natural gas that are ultimately recovered.
Estimates of economically recoverable oil and natural gas reserves and of future
net revenues are based upon a number of variables and assumptions, all of which
may vary considerably from actual results. The meaningfulness of such estimates
is highly dependent upon the accuracy of the assumptions upon which they were
based. See "Risk Factors -- Uncertainty of Reserve Information and Future Net
Revenue Estimates."
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The following table sets forth, at September 30, 1996, information
regarding the SEC Present Values attributable to the Company's estimated net
proved reserves at such date, as estimated by Netherland Sewell.
<TABLE>
<CAPTION>
DOMESTIC INTERNATIONAL TOTAL
-------- ------------- -------
(IN MILLIONS)
<S> <C> <C> <C>
Future gross revenues....................................... $1,273 $ 669 $ 1,942
Future production costs..................................... (509) (581)(1) (1,090)
Future development costs.................................... (55) (46) (101)
------ ----- -------
Total future costs................................ (564) (627) (1,191)
------ ----- -------
Future net revenues before future income taxes.............. 709 42 751
Discount at 10% per annum................................... (392) (9) (401)
------ ----- -------
SEC Present Value before U.S. income taxes(2)............... 317 33 350
Discounted future income taxes(3)........................... (28) -- (28)
------ ----- -------
SEC Present Value after taxes(2)(4)......................... $ 289 $ 33 $ 322
====== ===== =======
</TABLE>
- ---------------
(1) International future production costs include foreign exploration taxes of
$193 million.
(2) Gas and oil prices used in calculating estimated values at September 30,
1996 were $1.85 per MMBtu (Henry Hub, Louisiana) and $22.75 per Bbl of oil
(WTI). If the SEC Present Value before U.S. income taxes and the SEC Present
Value after taxes were presented using September 30, 1996 reserve quantities
but using gas and oil prices in effect at December 31, 1996 ($3.90 per MMBtu
(Henry Hub, Louisiana) and $24.25 per Bbl (WTI), respectively), without
making any price-related adjustment to reserve quantities, the SEC Present
Value before U.S. income taxes and the SEC Present Value after taxes would
be $889 million and $673 million, respectively.
(3) Future income taxes before discount for the Domestic production were $116
million and include the utilization of $49 million of Section 29 tax
credits.
(4) Assuming completion of the Section 29 Monetization as of April 1, 1997, the
SEC Present Value after taxes would be $311 million if it were calculated
using September 30, 1996 reserve quantities and gas and oil prices and would
be $662 million if it were calculated using September 30, 1996 reserve
quantities but using December 31, 1996 gas and oil prices without any
price-related reserve adjustments.
In computing this data, assumptions and estimates have been utilized, and
no assurance can be given that such assumptions and estimates will be indicative
of future economic conditions. The future net revenues are determined by using
estimated quantities of proved reserves and the periods in which they are
expected to be developed and produced based on September 30, 1996 economic
conditions. The estimated future production is priced at September 30, 1996,
except where fixed and determinable price escalations are provided by contract.
The resulting estimated future gross revenues are reduced by estimated future
costs to develop and produce the proved reserves based on September 30, 1996
costs levels, but not for debt service, general and administrative expenses and
income taxes. Prices for natural gas and crude oil are subject to substantial
fluctuations as a result of numerous factors. The SEC Present Value should not
be construed as the current market value of estimated natural gas and crude oil
reserves. For additional information concerning the discounted future net cash
flows to be derived from these reserves and the disclosure of the SEC Present
Value information in accordance with the provisions of Statement of Financial
Accounting Standards No. 69, see "Supplemental Disclosures About Oil and Gas
Producing Activities" in Note 15 to the Consolidated Financial Statements of the
Company included elsewhere in this Prospectus. See also "Risk Factors --
Uncertainty of Reserve Information and Future Net Revenue Estimates."
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<PAGE> 59
ACREAGE AND PRODUCTIVE WELLS
The following table sets forth the Company's developed and undeveloped
acreage at December 31, 1996.
<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES TOTAL ACRES
--------------------- -------------------- ----------------------
REGION GROSS NET GROSS NET GROSS NET
------ --------- --------- --------- ------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Appalachian Region......... 855,318 787,342 192,623 146,952 1,047,941 934,294
Gulf of Mexico Region...... 105,085 39,339 190,442 110,665 295,527 150,004
Royalty.................... 301,824 108,061 343,986 135,862 645,910 243,923
Nigeria.................... 177,000 177,000 450,000(1) 225,000(1) 627,000(1) 402,000(1)
Australia.................. -- -- 925,000 315,000 925,000 315,000
--------- --------- --------- ------- --------- ---------
Total............ 1,439,227 1,111,742 2,102,051 933,479 3,541,278 2,045,221
========= ========= ========= ======= ========= =========
</TABLE>
- ---------------
(1) Under the terms of the Company's 1992 PSC in Nigeria, an aggregate of
150,000 gross undeveloped acres (75,000 net) are required to be relinquished
by the Company in July 1997. See "-- Oil and Gas Properties and Development
Activities -- International -- Key Provisions of PSCs."
The following table sets forth the Company's ownership in producing wells
at December 31, 1996:
<TABLE>
<CAPTION>
TOTAL PRODUCING
WELLS
----------------
GROSS NET
----- -----
<S> <C> <C>
Domestic natural gas........................................ 4,136 3,757
Domestic oil................................................ 36 22
Nigerian oil................................................ 36 36
----- -----
Total............................................. 4,208 3,815
===== =====
</TABLE>
DRILLING ACTIVITIES
During the periods indicated, the Company drilled or participated in the
drilling of the following exploratory and development wells.
<TABLE>
<CAPTION>
THREE
MONTHS
ENDED
YEAR ENDED SEPTEMBER 30, DECEMBER 31,
------------------------------------------ ------------
1994 1995 1996 1996
------------ ------------ ------------ ------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Exploratory wells:
Productive.................................. 5 2.3 7 3.3 6 3.0 1 0.1
Nonproductive............................... 12 4.9 13 6.5 4 1.4 -- --
Development wells:
Productive.................................. 65 58.9 109 88.0 101 82.0 33 26.4
Nonproductive............................... 1 1.0 -- -- -- -- -- --
-- ---- --- ---- --- ---- -- ----
Total............................... 83 67.1 129 97.8 111 86.4 34 26.5
== ==== === ==== === ==== == ====
</TABLE>
As of February 28, 1997 the Company was participating in the drilling of 2
wells (gross and net) in the Appalachian Region and 1 gross well (0.1 net wells)
in the Gulf of Mexico Region. The Company had no wells being drilled in Nigeria.
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<PAGE> 60
NET PRODUCTION, UNIT PRICES AND COSTS
The following table sets forth information with respect to the Company's
net production and average unit prices and costs for the periods indicated:
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED SEPTEMBER 30, DECEMBER 31,
--------------------------- -------------------
1994 1995 1996 1995 1996
------- ------- ------- -------- --------
<S> <C> <C> <C> <C> <C>
Domestic production:
Oil (MBbls)............................ 300 222 206 55 48
Gas (MMcf)............................. 34,409 37,547 39,675 10,212 9,738
Equivalents (MMcfe).................... 36,209 38,879 40,911 10,542 10,026
Nigerian production:
Oil (MBbls)............................ 6,828 6,859 6,412 1,673 1,622
Average sales price (hedged):
Domestic gas ($/Mcf)................... $ 2.42 $ 1.89 $ 2.39 $ 2.18 $ 3.20
Domestic oil ($/Bbl)................... 14.29 15.96 18.22 15.77 21.07
Average sales price (unhedged):
Domestic gas ($/Mcf)................... $ 2.37 $ 1.91 $ 2.74 $ 2.21 $ 3.30
Domestic oil ($/Bbl)................... 14.29 15.71 18.17 15.60 21.21
Nigerian oil ($/Bbl)................... 15.01 16.17 18.46 16.21 23.23
Average lease operating expenses:
Domestic ($/Mcfe)...................... $ 0.48 $ 0.51 $ 0.47 $ 0.43 $ 0.43
Nigerian ($/Bbl)....................... 4.83 5.02 5.63 5.47 6.36
</TABLE>
MARKETING AND CONTRACTS
General. The Company believes that the proximity of its Appalachian
reserves to the natural gas markets in the northeastern United States, coupled
with its knowledge and understanding of transportation constraints, allows it to
deliver natural gas to markets in the northeastern United States more reliably
than producers of natural gas outside the Appalachian Basin. The close proximity
of the Company's Appalachian production to these markets has provided a premium
to Henry Hub, Louisiana prices averaging $0.26 per MMBtu over the past three
fiscal years. In addition to its location value, the Company's Appalachian gas
production generally has a higher Btu content than natural gas produced in many
other areas of the United States, which results in premium pricing.
The majority of the Company's Gulf of Mexico production is located offshore
Louisiana. The availability and accessibility of several interstate and
intrastate pipelines enables the Company to sell its Louisiana and Texas
offshore production into several primary markets, such as Chicago and the
northeastern United States, as well as intrastate customers in Louisiana and
Texas.
The Company balances its spot and term natural gas sales to end-users and
local distribution companies and utilizes multiple pricing structures. The
Company has four long-term commitments, including one contract with a
cogeneration facility under which it sells 6,300 MMBtu per day at the current
price of $3.07 per MMBtu, with annual escalation provisions. This contract has a
primary term that expires at the end of January 2001 and is subject to renewal
for subsequent five year terms thereafter. The Company has three additional,
market-sensitive contracts, totaling 35,000 MMBtu per day, which are nearing
expiration. The total of these four contracts represents nearly one-quarter of
the Company's natural gas production. Another 25% of the Company's supplies are
sold pursuant to multi-month and/or one-year term agreements. Approximately 70%
of the Company's production is sold to local distribution companies, industrial
end-users, and electric generators.
The Company's Nigerian crude oil production is sold on the spot market.
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<PAGE> 61
Third-Party Services. The Company's 1,200 miles of Appalachian gathering
lines have provided an excellent opportunity to purchase third-party supplies
for delivery into major interstate pipelines. Such purchases generally are made
along the Company's gathering pipeline systems but also are made off-system.
Frequently, the Company markets gas for joint venture partners. The Company's
gathering systems have enabled the Company to generate gross margins averaging
$0.09 per MMBtu over the past three years on third-party volumes. The Company
also provides fuel management services for industrial customers.
Risk Management. Ashland has encouraged the Company to utilize forward
sales of its production in order to lock-in attractive prices and to achieve
certain return on investment targets. In fiscal years 1994, 1995 and 1996, the
Company hedged 52%, 8% and 68%, respectively, of its natural gas production.
This strategy has been successful in achieving the income goals of Ashland.
However, it has limited the Company's potential gains from increases in market
prices. At January 31, 1997, the Company had open natural gas hedges on (i) an
average of 76,776 MMBtu per day for the period March 1, 1997 through September
30, 1997 at an average price of $2.16 per MMBtu and (ii) provided that the NYMEX
natural gas final settlement price is greater than $2.05 per MMBtu during any
month from April 1997 to September 1997, an additional volume of 20,000 MMBtu
per day at $2.05 per MMBtu during those respective monthly periods. In addition
to its natural gas hedges, the Company has hedged a small amount of its domestic
oil production. As of January 31, 1997, the Company had open hedges on an
average of 290 Bbls of oil per day at an average price of $20.31 per Bbl through
September 30, 1997.
The Company plans to hedge its natural gas production in the future on a
more limited basis in order to retain the potential for greater upside from
increases in prices. The Company will still utilize hedges to reduce its
exposure to significant declines in the market price to ensure minimum levels of
cash flow from its sales of oil and gas, but its decreased use of hedges will
increase the Company's exposure to decreases in gas prices. See "Risk
Factors -- Volatility of Natural Gas and Oil Prices" for a discussion of the
risks inherent in the Company's hedging activity.
SECTION 29 TAX CREDITS
The Crude Oil Windfall Profits Tax Act of 1980 amended the Internal Revenue
Code to provide an incentive for certain natural gas production from
unconventional sources such as the Devonian Shale and tight sandstone formations
of the Appalachian Region. Pursuant to Section 29 of the Internal Revenue Code,
an owner of an economic interest in certain natural gas production can qualify
for certain tax credits on qualified production that is produced through
December 31, 2002. The Company owns working interests in approximately 1,425
gross wells that qualify for the Section 29 tax credits (the Section 29 Tax
Credit Properties), which have generated $59.8 million of tax credits for
Ashland through September 30, 1996, including $10.5 million in 1996. The
Company's estimated future Section 29 tax credits presented in the October 1,
1996 Netherland Sewell report are $48.9 million as forecasted through December
31, 2002, as prepared in accordance with Commission guidelines without
escalation.
The Company has entered into a letter of intent under which it will
monetize the value of its future Section 29 tax credits in order to maximize
their value to the Company. The proposed transaction contemplates that the
Company will transfer title to its Section 29 Tax Credit Properties to an
investor. The Company will retain a production payment and a note which will
entitle the Company to all of the cash flow from the properties until
approximately 94% of the pre-tax net present value of the presently projected
future production from the properties has been received, which is expected to
occur in the year 2015. Such transaction will result in a reduction of the
Company's SEC Present Value before U.S. income taxes by $6.5 million and a
reduction in the Company's proved reserves by 69 Bcf, based on the Company's
September 30, 1996 reserves. In addition to the note and production payment, the
Company will receive a fixed cash payment at closing of $6.5 million and will
receive quarterly payments equal to a specified percentage of the Section 29 tax
credits generated from the properties, estimated to decline from approximately
$2.5 million per quarter in 1997 to approximately $2.0 million per quarter in
2002, based upon the values attributed to such credits by Netherland Sewell as
of September 30, 1996. The Company will also retain a reversionary interest in
the properties pursuant to which 100% of the interests in the properties
transferred will revert to the Company when 100% of currently projected future
production from the properties
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<PAGE> 62
has been received. Based on current law, tax credits will be available until
December 31, 2002. The Company will retain the option to repurchase the
properties after December 31, 2002 at the fair market value of the properties at
the time of repurchase less the value of the outstanding note and production
payment and the value of the reversionary interest. The Company will enter into
a management services agreement with the buyer pursuant to which the Company
will manage and operate the properties on behalf of the buyer.
The Section 29 Monetization is expected to close on or about April 1, 1997.
In connection with the transaction, the buyer will apply for a ruling from the
Internal Revenue Service with regard to certain aspects of the transaction. In
the event a favorable ruling is not received on or before September 15, 1997,
the buyer will have the right to rescind the transaction. Closing of the
transaction is subject to contingencies, including completion of due diligence,
obtaining certain consents and negotiation of definitive documents.
COMPETITION
Competition in the Company's primary producing areas is intense. The
Company actively competes against some companies with substantially larger
financial and other resources, particularly in the Gulf of Mexico and Nigeria.
To the extent that the Company's gas supply, gathering systems, organization, or
exploration budget is smaller than those of certain of its competitors, the
Company may be disadvantaged in its competitive activities. The Company believes
that its competitive gas marketing position is based on location, price,
contract terms, quality of service and reliable delivery record. The Company
believes that its extensive acreage position, substantial ongoing drilling
program, and existing gas gathering systems give it a competitive advantage over
other producers in the Appalachian Basin that do not have such systems or
facilities in place. The Company also believes that its competitive position in
the Appalachian Basin is enhanced by the absence of significant competition from
major oil and gas companies. See "Risk Factors -- Competition."
TITLE TO PROPERTIES
As is customary in the natural gas and oil industry, the Company makes only
a cursory review of title to farm-out acreage and to undeveloped natural gas and
oil leases upon execution of the contracts. Prior to the commencement of
drilling operations, a thorough title examination is conducted and curative work
is performed with respect to significant defects. To the extent title opinions
or other investigations reflect title defects, the Company, rather than the
seller of the undeveloped property, is typically responsible to cure any such
title defects at its expense. If the Company were unable to remedy or cure any
title defect of a nature such that it would not be prudent to commence drilling
operations on the property, the Company could suffer a loss of its entire
investment in the property. The Company has obtained title opinions on
substantially all of its producing properties and believes that it has
satisfactory title to such properties in accordance with standards generally
accepted in the oil and gas industry. The Company's natural gas and oil
properties are subject to customary royalty interests, liens for current taxes
and other burdens which the Company believes do not materially interfere with
the use of or affect the value of such properties.
GOVERNMENT REGULATION
Regulation of Natural Gas and Oil Exploration and Production. Exploration
and production operations of the Company are subject to various types of
regulation at the federal, state and local levels. Such regulation includes
requiring permits for the drilling of wells, maintaining bonding requirements in
order to drill or operate wells, and regulating the location of wells, the
method of drilling and casing wells, the surface use and restoration of
properties upon which wells are drilled and the plugging and abandonment of
wells. The Company's operations are also subject to various conservation laws
and regulations. These include the regulation of the size of drilling and
spacing units or proration units and the density of wells which may be drilled
and unitization or pooling of oil and gas properties. In this regard, some
states allow the forced pooling or integration of tracts to facilitate
exploration while other states rely on voluntary pooling of lands and leases. In
addition, state conservation laws establish maximum rates of production from
natural gas and oil wells, generally prohibit the venting or flaring of natural
gas and impose certain requirements regarding the ratability of production. The
effect of these regulations is to limit the amounts of natural gas and oil the
Company's
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<PAGE> 63
operator or the Company can produce from its wells, and to limit the number of
wells or the locations at which the Company can drill. Legislation affecting the
oil and gas industry also is under constant review for amendment or expansion.
Generally, state-established allowables have been influenced by overall natural
gas market supply and demand in the United States, as well as the specific
"nominations" for natural gas from the parties who produce or purchase gas from
the field and other factors deemed relevant by the agency. The Company cannot
predict whether further changes will be made in how these states set allowables
or what impact, if any, such further changes might have. In addition, numerous
departments and agencies, both federal and state, are authorized by statute to
issue rules and regulations binding on the natural gas and oil industry and its
individual members, some of which carry substantial penalties for failure to
comply. The regulatory burden on the natural gas and oil industry increases the
Company's cost of doing business and, consequently, affects its profitability.
Inasmuch as such laws and regulations are frequently expanded, amended or
reinterpreted, the Company is unable to predict the future cost or impact of
complying with such regulations.
Natural Gas Marketing and Transportation. Federal legislation and
regulatory controls in the United States have historically affected the price of
the natural gas produced by the Company and the manner in which such production
is marketed. The Federal Energy Regulatory Commission (the "FERC") regulates the
transportation and sale for resale of natural gas in interstate commerce
pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy
Act of 1978 (the "NGPA"). Although maximum selling prices of natural gas were
formerly regulated, on July 26, 1989, the Natural Gas Wellhead Decontrol Act
("Decontrol Act") was enacted, which amended the NGPA to remove completely by
January 1, 1993 price and nonprice controls for all "first sales" of natural
gas, which will include 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. The FERC's jurisdiction over
natural gas transportation was unaffected by the Decontrol Act. While sales by
producers of natural gas, and all sales of crude oil, condensate and natural gas
liquids can currently be made at uncontrolled market prices, Congress could
reenact price controls in the future.
The FERC also regulates interstate natural gas transportation rates and
service conditions, which affect the marketing of natural gas produced by the
Company, as well as the revenues received by the Company for sales of such
natural gas. Since the latter part of 1985, the FERC has endeavored to make
interstate natural gas transportation more accessible to gas buyers and sellers
on an open and non-discriminatory basis. The FERC's efforts have significantly
altered the marketing and pricing of natural gas. Commencing in April 1992, the
FERC issued Order Nos. 636, 636-A and 636-B (collectively, "Order No. 636"),
which, among other things, require interstate pipelines to "restructure" to
provide transportation separate or "unbundled" from the pipelines' sales of gas.
Also, Order No. 636 requires pipelines to provide open-access transportation on
a basis that is equal for all gas supplies. Order No. 636 has been implemented
through negotiated settlements in individual pipeline service restructuring
proceedings. In many instances, the result of the Order No. 636 and related
initiatives have been to substantially reduce or bring to an end the interstate
pipelines' traditional role as wholesalers of natural gas in favor of providing
only storage and transportation services. The FERC has issued final orders in
all pipeline restructuring proceedings.
Although Order No. 636 does not regulate natural gas producers such as the
Company, the FERC has stated that Order No. 636 is intended to foster increased
competition within all phases of the natural gas industry. It is unclear what
impact, if any, increased competition within the natural gas industry under
Order No. 636 will have on the Company and its natural gas marketing efforts.
Numerous parties have filed petitions for review of Order No. 636, as well as
orders in individual pipeline restructuring proceedings. In July 1996, Order No.
636 was generally upheld on appeal. The portions remanded for further action do
not appear to affect the Company materially. It is difficult to predict when all
appeals of Order No. 636 and orders in individual pipeline restructuring
proceedings will be completed or what their impact will be on the Company.
Although Order No. 636, assuming it is upheld in its entirety, could provide the
Company with additional market access and more fairly applied transportation
service rates, terms and conditions, it could also subject the Company to more
restrictive pipeline imbalance tolerances and greater penalties for violation of
those
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<PAGE> 64
tolerances. The Company does not believe, however, that it will be affected by
any action taken with respect to Order No. 636 any differently than other
natural gas producers and marketers with which it competes.
The FERC has announced several important transportation-related policy
statements and proposed rule changes, including the appropriate manner in which
interstate pipelines release capacity under Order No. 636 and, more recently,
the price which shippers can charge for their released capacity. In addition, in
1995, the FERC issued a policy statement on how interstate natural gas pipelines
can recover the costs of new pipeline facilities. In January 1996, the FERC
issued a policy statement and a request for comments concerning alternatives to
its traditional cost-of-service ratemaking methodology. A number of pipelines
have obtained FERC authorization to charge negotiated rates as one such
alternative. While any additional FERC action on these matters would affect the
Company only indirectly, these policy statements and proposed rule changes are
intended to further enhance competition in natural gas markets. The Company
cannot predict what action the FERC will take on these matters, nor can it
predict whether the FERC's actions will achieve its stated goal of increasing
competition in natural gas markets. However, the Company does not believe that
it will be treated materially differently than other natural gas producers and
marketers with which it competes.
Certain operations the Company conducts are on federal oil and gas leases,
which the Minerals Management Service (the "MMS") administers. The MMS issues
such leases through competitive bidding. These leases contain relatively
standardized terms and require compliance with detailed MMS regulations and
orders pursuant to the Outer Continental Shelf Lands Act ("OCSLA") (which are
subject to change by the MMS). For offshore operations, lessees must obtain MMS
approval for exploration plans and development and production plans prior to the
commencement of such operations. In addition to permits required from other
agencies (such as the U.S. Coast Guard, the Army Corps of Engineers and the
EPA), lessees must obtain a permit from the MMS prior to the commencement of
drilling. The MMS has promulgated regulations requiring offshore production
facilities located on the OCS to meet stringent engineering and construction
specifications. The MMS proposed additional safety-related regulations
concerning the design and operating procedures for OCS production platforms and
pipelines. These regulations were withdrawn pending further discussions among
interested federal agencies. The MMS also administers regulations that restrict
the flaring or venting of natural gas, and, as a result of recent amendments,
prohibit the flaring of liquid hydrocarbons (including oil) without prior
authorization. Similarly, the MMS has promulgated other regulations governing
the plugging and abandonment of wells located offshore and the removal of all
production facilities. To cover the various obligations of lessees on the OCS,
the MMS generally requires that lessees post substantial bonds or other
acceptable assurances that such obligations will be met. The cost of such bonds
or other surety can be substantial and there is no assurance that the Company
can obtain bonds or other surety in all cases. Under certain circumstances, the
MMS may require any Company operations on federal leases to be suspended or
terminated. Any such suspension or termination could materially and adversely
affect the Company's financial condition and results of operations.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any such
proposals might become effective, or their effect, if any, on the Company's
business, financial condition or results of operations. The natural gas industry
historically has been very heavily regulated; therefore, there is no assurance
that the less stringent regulatory approach recently pursued by the FERC and
Congress will continue indefinitely into the future.
Commencing in May 1994, the FERC issued a series of orders in individual
cases that delineate its new gathering policy. Among other matters, the FERC
slightly narrowed its statutory tests for establishing gathering status and
reaffirmed that, except in situations in which the gatherer acts in concert with
an interstate pipeline affiliate to frustrate the FERC's transportation
policies, it does not generally have jurisdiction over natural gas gathering
facilities and services, and that such facilities and services located in state
jurisdictions are properly regulated by state authorities. In addition, the FERC
has approved numerous transfers by interstate pipelines of gathering facilities
to unregulated independent or affiliated gathering companies, subject to the
transferee providing service for two years from the date of transfer to the
pipeline's existing customers pursuant to a default contract or pursuant to
mutually agreeable terms. In August 1996, the Court of Appeals for the District
of Columbia Circuit largely upheld the FERC's new gathering policy, but
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<PAGE> 65
remanded the FERC's default contract condition. The FERC has not yet issued an
order on remand. While this new gathering policy may tend to increase
competition and increase gathering costs for gatherers such as the Company, the
Company does not believe that it will be affected materially differently by such
policy than other producers, gatherers and marketers with which it competes.
Oil Sales and Transportation Rates. Sales of crude oil, condensate and gas
liquids by the Company are not regulated and are made at market prices. The
price the Company receives from the sale of these products is affected by the
cost of transporting the products to market. Effective as of January 1, 1995,
the FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which would generally index such rates
to inflation, subject to certain conditions and limitations. These regulations
could increase the cost of transporting crude oil, liquids and condensates by
pipeline. The Company is not able to predict with certainty what effect, if any,
these regulations will have on it, but other factors being equal, the
regulations may tend to increase transportation costs or reduce wellhead prices
for such commodities.
Safety and Health Regulation. The Company's gathering operations are
subject to occupational safety, health and operational regulations relating to
the design, installation, testing, construction, operation, replacement, and
management of facilities. Pipeline safety issues have recently been the subject
of increasing focus in various political and administrative arenas at both the
state and federal levels. The Company believes its operations, to the extent
they may be subject to current gas pipeline safety or other health and safety
requirements, comply in all material respects with such requirements. The
Company cannot predict what effect, if any, the adoption of this or other
additional pipeline safety or other safety and health legislation might have on
its operations, but the industry could be required to incur additional capital
expenditures and increased costs depending upon future legislative and
regulatory changes.
ENVIRONMENTAL MATTERS
The Company's operations are subject to federal, state and local laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Numerous governmental agencies
issue rules and regulations to implement and enforce such laws which are often
difficult and costly to comply with and which carry substantial penalties for
failure to comply. These laws and regulations may require the acquisition of a
permit before drilling commences, restrict the types, quantities and
concentration of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands and other
protected areas, and impose substantial liabilities for pollution resulting from
the Company's operations. In addition, these laws, rules and regulations may
restrict the rate of oil and natural gas production. These regulations increase
the cost of doing business and consequently affect profitability of the Company
and others in the oil and gas industry. State laws often require some form of
remedial action to prevent pollution from former operations, such as pit closure
and plugging abandoned wells. The Company's expenditures in the near future for
regulatory and environmental compliance are not expected to be material in
relation to its total capital expenditure program; however, the Company cannot
predict the ultimate cost of compliance because such laws and regulations
frequently change. Although the Company believes that its operations and
facilities are in compliance in all material respects with applicable
environmental regulations, risks of substantial costs and liabilities are
inherent in gas and oil operations, and there can be no assurance that
significant costs and liabilities will not be incurred in the future. See "Risk
Factors -- Operating Risks of Gas and Oil Operations" and "-- Government
Regulation and Environmental Matters." The Company believes that continued
compliance with regulatory standards will not substantially affect its ability
to compete with similarly situated oil and gas companies.
CERCLA. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons who are considered to be responsible for the release of a
"hazardous substance" into the environment. These persons include the current or
former owner or operator of the disposal site or sites where the release
occurred and companies that disposed or arranged for the disposal of the
hazardous substances. Under CERCLA, such persons may be subject to joint and
several liability for the costs of cleaning up hazardous substances that have
been released into the environment, for damages to
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natural resources and for the costs of certain health studies. In addition,
where hazardous substance contamination has occurred, it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by hazardous substances or other
pollutants released into the environment.
Stricter standards in environmental legislation may be imposed on the oil
and gas industry in the future. For instance, from time to time legislation has
been proposed in Congress that would reclassify certain oil and natural gas
exploration and production wastes as "hazardous wastes" subject to more
stringent handling, disposal and cleanup requirements. If such legislation were
enacted, it could have a significant impact on the operating costs of the
Company, as well as the oil and gas industry in general. Furthermore, although
petroleum, including crude oil and natural gas, is exempt from CERCLA, at least
two courts have ruled that certain wastes associated with the production of
crude oil may be classified as "hazardous substances" under CERCLA. State
initiatives to regulate further the disposal of oil and natural gas wastes are
pending in several states, and these initiatives could have a similar impact on
the Company.
Solid and Hazardous Waste. The Federal Solid Waste Disposal Act, as amended
by the Resource Conservation and Recovery Act of 1976 ("RCRA"), regulates the
generation, transportation, storage, treatment and disposal of hazardous wastes,
and can require cleanup of hazardous waste disposal sites. RCRA currently
excludes drilling fluids, produced waters and other wastes associated with the
exploration, development, or production of oil and gas from regulation as
"hazardous waste." Disposal of non-hazardous oil and gas exploration,
development and production wastes may be regulated by state law. In addition,
the Company occasionally handles material that may be classified as hazardous
waste not subject to the RCRA exemption. RCRA and state laws impose certain
operational requirements upon the storage, handling and disposal of these
materials.
OPA. The Oil Pollution Act of 1990 (the "OPA") requires persons responsible
for offshore facilities to demonstrate financial responsibility for
environmental cleanup and restoration costs likely to be incurred in connection
with an oil spill. Under recent amendments to the OPA, the responsible person
for an offshore facility located seaward of state waters will be required to
provide evidence of financial responsibility in the amount of $35 million.
Although the financial responsibility requirement for offshore facilities
located landward of the seaward boundary of state waters (including certain
facilities in coastal inland waters) is a lesser amount ($10 million), the
Company currently has offshore facilities and, thus, is subject to the $35
million financial responsibility requirements. The amount of financial
responsibility may be increased, to a maximum of $150 million, if the MMS
determines that a greater amount is justified based on specific risks posed by
the operations. The Company expects that financial responsibility could be
established through insurance, guaranty, indemnity, surety bond, letter of
credit, qualification as a self-insurer or a combination thereof. The Company
cannot predict the final form of any financial responsibility rule that may be
adopted by the MMS under the OPA, but in any event, the impact of the rule is
not expected to be any more burdensome to the Company than it will be to other
similarly situated companies involved in oil and gas exploration and production.
The Company currently satisfies similar requirements for its OCS leases under
OCSLA.
OPA imposes a variety of additional requirements on "responsible parties"
for vessels or onshore and offshore oil and gas facilities related to the
prevention of oil spills and liability for damages resulting from such spills in
waters of the United States. The "responsible party" includes the owner or
operator of an onshore facility or vessel or the lessee or permittee of, or the
holder of a right of use and easement, for the area where an offshore facility
is located. OPA assigns liability to each responsible party for oil spill
removal costs and a variety of public and private damages from oil spills. OPA
establishes a liability limit for onshore facilities of $350 million and for
offshore facilities, all removal costs plus $75 million. A party cannot take
advantage of liability limits, however if the spill is caused by gross
negligence or willful misconduct or resulted from violation of a federal safety,
construction or operating regulation. If a party fails to report a spill or to
cooperate fully in the cleanup, liability limits likewise do not apply. Few
defenses exist to the liability for oil spills imposed by OPA. OPA also imposes
other requirements on facility operators, such as the preparation of an oil
spill contingency plan. Failure to comply with ongoing requirements or
inadequate cooperation in a spill event may subject a responsible party to civil
or criminal enforcement actions.
65
<PAGE> 67
OCSLA. The OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating in the
OCS. Specific design and operational standards may apply to OCS vessels, rigs,
platforms, vehicles and structures. Violations of lease conditions or
regulations issued pursuant to OCSLA can result in substantial civil and
criminal penalties, as well as potential court injunctions curtailing operations
or resulting in the cancellation of leases. Such enforcement liabilities can
result from either governmental or private prosecution.
FWPCA. The Federal Water Pollution Control Act ("FWPCA") imposes
restrictions and strict controls regarding the discharge of produced waters and
other oil and gas wastes into navigable waters. Permits must be obtained to
discharge pollutants to state and federal waters. The FWPCA provides for civil,
criminal and administrative penalties for any unauthorized discharges of
reportable quantities of oil and other hazardous substances and, along with the
OPA, imposes substantial potential liability for the costs of removal,
remediation and damages. State laws for the control of water pollution also
provide varying civil, criminal and administrative penalties and liabilities in
the case of a discharge of petroleum or other pollutants into state waters. Many
state water discharge regulations and the Federal National Pollutant Discharge
Elimination System permits prohibit the discharge of produced water and sand,
drilling fluids, drill cuttings, and certain other substances related to the oil
and gas industry, to coastal waters. Although the costs to comply with
recently-enacted zero discharge mandates under federal or state law may be
significant, the entire industry will experience similar costs and the Company
believes that these costs will not have a material adverse impact on the
Company's financial conditions and operations. Some oil and gas exploration and
production facilities are required to obtain permits for their storm water
discharges. Costs may be associated with treatment of wastewater or developing
and implementing storm water pollution prevention plans. Further, the Coastal
Zone Management Act authorizes state implementation and development of programs
of management measures for non-point source pollution to restore and protect
coastal waters.
EPA Administrative Order. The Company is subject to an Administrative Order
issued by the EPA with respect to allegations that the Company had violated the
Federal Safe Drinking Water Act in conducting its operations in the Martha oil
field in eastern Kentucky, which the Company no longer operates. Substantially
all requirements of the Administrative Order have been satisfied except that the
Company must monitor the water supply in the area of the field by periodic tests
of existing water monitoring wells. The Administrative Order remains open
pending completion of a reclamation program (including disposal off site) for
naturally occurring radioactive material ("NORM"), which was discovered during
abandonment operations for the field. The Kentucky Natural Resources and
Environmental Protection Cabinet (the "Cabinet") and the EPA have approved the
reclamation program, which is now being implemented. Remaining open is the issue
of the permanent disposal of NORM materials. The Company and the operator of the
proposed site for the disposal are currently negotiating with the Cabinet for
certain modifications to the disposal site's permit to accommodate such
disposal. If the permit modifications are approved substantially in the form
submitted to the Cabinet, then the Company believes that the disposal will not
have a material adverse impact on the Company's financial position. While the
Company expects the Cabinet to approve the permit modifications without making
material changes thereto, there is no assurance that this will be the case. The
Company has spent $3.9 million through December 31, 1996 in connection with the
reclamation program and has established a reserve of $8.1 million as of December
31, 1996 to cover future clean-up costs expected to be incurred based on current
estimates. The Company believes this reserve will be sufficient based on such
estimates to cover the Company's remaining clean-up obligation at the field,
although no assurance can be given that actual clean-up costs will not be
higher, possibly materially so. The Company and Ashland have entered into an
indemnity agreement that provides, in part, that the Company will indemnify
Ashland for all liabilities associated with governmental requirements concerning
the remediation of the field. If actual clean-up costs were significantly higher
than the amounts reserved, such costs could have a material adverse effect on
the Company's results of operations. See "Relationship Between the Company and
Ashland -- Contractual Arrangements."
LITIGATION
The Company and its subsidiaries are parties to numerous claims and
lawsuits with respect to various matters. While the Company is contesting these
claims and lawsuits, the outcome of individual matters is not
66
<PAGE> 68
predictable with assurance. Although the ultimate resolution of these actions is
not presently determinable, the Company believes that any liability resulting
from the currently pending lawsuits and claims involving the Company and its
subsidiaries, in excess of insurance coverage or amounts already provided for,
will not have a material adverse effect on the Company's business, financial
position or results of operations.
OPERATING HAZARDS AND UNINSURED RISKS
The Company's operations are subject to hazards and risks inherent in
drilling for and production and transportation of oil and natural gas, such as
fires, natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, cratering, pipeline ruptures, and spills, any of which can
result in loss of hydrocarbons, environmental pollution, personal injury claims,
and other damage to properties of the Company and others. The Company's overseas
operations 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 and policies governing operations of overseas based
companies generally. Additionally, certain of the Company's oil and gas
operations are located in an area that is subject to tropical weather
disturbances, some of which can be severe enough to cause substantial damage to
facilities and possibly interrupt production. As protection against operating
hazards, the Company (through Ashland) maintains insurance coverage against
some, but not all, potential losses. After the Spin Off, the Company will be
required to obtain its own insurance policies. The Company believes that its
insurance is adequate and customary for companies of a similar size engaged in
operations similar to those of the Company, but losses could occur for
uninsurable or uninsured risks or in amounts in excess of existing insurance
coverage. The occurrence of an event that is not fully covered by insurance
could have an adverse impact on the Company's financial condition and results of
operations.
EMPLOYEES
The Company had 313 employees as of February 28, 1997. The Company believes
that its relations with its employees are satisfactory. The Company has not
entered into any collective bargaining agreements with any of its employees.
OFFICES
The Company currently leases approximately 84,500 square feet of office
space for its corporate headquarters in Houston, Texas. The Company also has a
regional office in Ashland, Kentucky, and district offices in Danville, West
Virginia, Weston, West Virginia and Pikeville, Kentucky. In addition, the
Company maintains offices in Lagos, Nigeria and Port Harcourt, Nigeria.
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<PAGE> 69
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
Upon consummation of the Offering, the Company will have a Board of
Directors composed of seven members. In accordance with the Restated Certificate
of Incorporation and Bylaws of the Company, the members of the Board of
Directors will be divided into three classes elected for a term of office
expiring at the third succeeding annual stockholders' meeting following their
election to office or until a successor is duly elected and qualified. The terms
of office of the Class I, Class II and Class III directors expire at the annual
meeting of stockholders in 1998, 1999 and 2000, respectively. The officers of
the Company are elected by and serve until their successors are elected by the
Board of Directors.
The following table sets forth the names, ages and titles of the directors
and executive officers of the Company.
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
James R. Boyd.................. 50 Chairman of the Board (Class II)
W. Paul Tiefel................. 48 Chief Executive Officer, President and Director (Class
III)
Robert C. Bilger............... 44 Executive Vice President, Chief Financial Officer,
Treasurer and Director (Class III)
Bradley W. Fischer............. 50 Senior Vice President Gulf Coast and International
Jeffrey W. Lund................ 49 Vice President Exploration and Land
Mark D. Pierce................. 43 Vice President Eastern Region and Marketing
H. Roger Benedict.............. 47 Vice President and General Manager -- Nigeria
John V. Connolly............... 47 Vice President and Controller
Judy C. Barnes................. 51 Vice President Human Resources and Administration
Thomas L. Feazell.............. 60 Director (Class I)
Philip W. Block(1)............. 49 Director (Class I)
Dr. Robert B. Stobaugh(1)(2)... 69 Director (Class II)
J.W. Stewart(1)(2)............. 53 Director (Class III)
</TABLE>
- ---------------
(1) Member of Compensation Committee.
(2) Member of Audit Committee.
Mr. Tiefel is a Vice President of Ashland and will resign that position
prior to the consummation of the Offering. Messrs. Boyd, Feazell, Block and
Stobaugh are also directors and/or officers of Ashland. After the Spin Off,
Messrs. Block and Feazell will no longer serve as directors of the Company. At
that time, it is expected that they will each be replaced by a director who has
no affiliation with either the Company or Ashland.
Set forth below is a brief description of the business experience of the
directors and executive officers of the Company.
James R. Boyd. Mr. Boyd has been the Chairman of the Board of the Company
since February 1997 and has been a director of the Company since 1987. Since
1990, he has served as Senior Vice President and Group Operating Officer for
Ashland with responsibility for the Company and certain other subsidiaries of
Ashland. He was President of the Company from 1987 to 1990. He joined Ashland in
1981. He is a member of the American Petroleum Institute, the American Nuclear
Society, the Institute of Electrical and Electronic Engineers and the
Independent Petroleum Association of America. He serves as a Director of Arch
Mineral, a 50 percent-owned Ashland affiliate. He is a member of the board of
trustees of Pikeville College in Pikeville, Kentucky and the University of
Kentucky College of Engineering in Lexington, Kentucky; he also serves as
President of the board of trustees of Foxcroft School, Middleburg, Virginia.
W. Paul Tiefel. Mr. Tiefel has been Chief Executive Officer, President and
a Director of the Company and a Vice President of Ashland since February 1997.
He served as Senior Vice President of the Company
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<PAGE> 70
from 1992 to 1997. Prior to joining the Company in 1982, Mr. Tiefel was Drilling
Manager with Adams Resources in Houston, Texas from 1980 to 1982. He was
Drilling Supervisor with Marathon Oil Company from 1978 to 1980 with assignments
in Scotland, Ireland, Nigeria and the United States. He also served in various
capacities with Hytech Energy from 1977 to 1978 and with Texaco Inc. from 1973
to 1977.
Robert C. Bilger. Mr. Bilger has been the Executive Vice President, Chief
Financial Officer, Treasurer and a Director of the Company since February 1997.
He served as Senior Vice President -- Domestic from 1995 to 1997 and
Administrative Vice President Finance and Business Development from 1992 to
1995. Prior to joining the Company in 1987, Mr. Bilger was Director of
Acquisitions with Apache Corporation in Denver, Colorado from 1984 to 1987. Mr.
Bilger served as Manager of Financial Planning and Analysis with Dome Petroleum
from 1980 to 1984. He was with the Island Creek Coal Division of Occidental
Petroleum from 1979 to 1980 and with Marathon Oil Company in Findlay, Ohio from
1975 to 1979.
Bradley W. Fischer. Mr. Fischer has been the Company's Senior Vice
President Gulf Coast and International since February 1997. He served as Vice
President and Regional Manager--Eastern Region for the Company from 1994 to 1997
and served in several capacities with the Company's Nigerian subsidiaries from
1987 to 1994. Prior to joining the Company in 1987, he was with Mitchell Energy
Corporation, serving as Regional Manager from 1982 to 1987 and as District
Manager from 1980 to 1982. Mr. Fischer served in several capacities with Tenneco
Oil Company in Denver, Colorado from 1976 to 1980 and was with Texaco Inc. in
California from 1972 to 1976.
Jeffrey W. Lund. Mr. Lund has been Vice President Exploration and Land for
the Company since 1995. He was Vice President and Regional Manager -- Houston
Region from 1991 to 1995. Prior to joining the Company in 1991, Mr. Lund was
Regional Exploration Manager for Meridian Oil, Inc. in Houston, Texas from 1986
to 1991. Mr. Lund was with Southland Royalty Company as District Exploration
Manager from 1980 to 1986 and as District Geologist from 1978 to 1980. He was
with Clark Oil Producing Company in Houston, Texas from 1973 to 1978 and with
Amoco Production Company from 1969 to 1973.
Mark D. Pierce. Mr. Pierce has been Vice President Eastern Region and
Marketing for the Company since February 1997. He served as Senior Vice
President Finance and Administration from 1995 to 1997 and as Vice President
Marketing and Administration from 1991 to 1995. Prior to joining the Company in
1977, Mr. Pierce was with Texaco Inc. from 1975 to 1977.
H. Roger Benedict. Mr. Benedict has been Vice President of the Company
since February 1997 and serves as General Manager -- Nigeria. Mr. Benedict has
been in Nigeria since 1992, as Deputy General Manager from 1992 to 1993 and as
General Manager since 1993. Before joining the Company in 1979, Mr. Benedict
served in several capacities with Dowell, a Division of Dow Chemical Company,
from 1972 to 1979 and with Quaker State Oil Refining Corporation from 1971 to
1972.
John V. Connolly. Mr. Connolly has been Vice President and Controller of
the Company since September 1995. He has served as the Company's Controller
since 1986. Before joining the Company in 1983, Mr. Connolly was Treasurer and
Director of Accounting for Cashco Oil Company from 1981 to 1983. Prior to
joining Cashco, Mr. Connolly served in several capacities with Aminoil USA, Inc.
from 1976 to 1980, including Manager Financial Planning and Reporting and
Assistant Controller. Mr. Connolly was with Peat, Marwick, Mitchell & Company
from 1972 to 1975 and with Arthur Young & Company from 1971 to 1972.
Judy C. Barnes. Ms. Barnes has been Vice President Human Resources and
Administration of the Company since June 1993. Prior to joining the Company in
1993, she was Director Human Resources for Weingarten Realty Investors, a real
estate investment trust, in Houston, Texas from 1989 to 1993. Before joining
Weingarten Realty Investors, Ms. Barnes was with Union Pacific Resources Company
from 1976 to 1989 as a Senior Employee Relations Representative and a Regional
Planning Analyst.
Philip W. Block. Mr. Block has been a Director of the Company since
February 1997. He is Administrative Vice President -- Human Resources of Ashland
and has served in such capacity since 1992. He has also served as Vice
President -- Corporate Human Resources of Ashland during the past five years.
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<PAGE> 71
Thomas L. Feazell. Mr. Feazell has been a Director of the Company since
February 1997. He is Senior Vice President, General Counsel and Secretary of
Ashland and has served in such capacities since 1992, 1981 and 1992,
respectively. He has also served as Administrative Vice President during the
past five years. Mr. Feazell has been a director of Ashland Coal, Inc., a
publicly-traded subsidiary of Ashland, since 1981.
Dr. Robert B. Stobaugh. Dr. Stobaugh has been a Director of the Company
since February 1997. He is the Charles E. Wilson Professor, Emeritus at the
Harvard Business School in Boston, Massachusetts. He is a Director of the
Susquehanna Pfaltzgraff Company and the National Association of Corporate
Directors (NACD), where he was a member of the 1996 Blue Ribbon Commission on
Director Professionalism and Chairman of the Blue Ribbon Commission on Director
Compensation. Author, co-author or co-editor of ten books, Dr. Stobaugh directed
the Energy Project at the Harvard Business School and is a former President of
the Academy of International Business. He has served as a Director of Ashland
since 1977 and is a member of the Finance Committee and the Committee on
Directors of the Board of Directors of Ashland.
J.W. Stewart. Mr. Stewart has been a Director of the Company since February
1997. He is Chairman of the Board, President and Chief Executive Officer of BJ
Services Company, a publicly-traded oilfield services company, and has served in
such capacity since July 1990. Mr. Stewart has been President of BJ Services
Company since May 1986 and prior to that time served in various capacities for
Hughes Tool Company from 1969 to 1986. Mr. Stewart is a Director of the Alley
Theatre and the Children's Museum in Houston. He is also a Director of the
Petroleum Equipment Suppliers Association.
BOARD COMMITTEES
Prior to consummation of the Offering, the Board of Directors of the
Company plans to establish a Compensation Committee and an Audit Committee, on
which two outside directors will serve. The Compensation Committee will act on
behalf of the Board of Directors with respect to the compensation of directors
and executive officers, and will administer certain of the Company's employee
benefit plans. The Audit Committee will review the scope and results of the
annual audit and other services performed by the Company's independent
accountants and report to the Board of Directors with respect thereto.
COMPENSATION OF DIRECTORS
Directors who are employees of the Company or Ashland are not paid any fees
or additional compensation for service as members of the Board or any committee
thereof. Directors who are not employees of the Company or Ashland will receive
an initial grant of 4,000 non-qualified stock options pursuant to the Company's
1997 Stock Incentive Plan and an annual retainer of $20,000 plus 2,000
non-qualified stock options as well as a fee of $1,000 for each meeting of the
Board or committee of the Board attended. Each chairman of a committee of the
Board will receive an additional annual retainer of $1,000. All directors will
receive reimbursement for their out-of-pocket expenses in attending meetings of
the Board or committees of the Board.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
In fiscal 1996, the Company did not have a Compensation Committee or any
other committee serving a similar function. Decisions as to the compensation of
executive officers were made by Ashland.
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<PAGE> 72
EXECUTIVE COMPENSATION
The following table sets forth information with respect to the President
and Chief Executive Officer of the Company, and each of the four other most
highly compensated executive officers of the Company (the "Named Executive
Officers"), for the fiscal year ended September 30, 1996:
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM
ANNUAL COMPENSATION COMPENSATION
------------------------------- ---------------------
AWARDS
--------
OPTIONS
TO
OTHER PURCHASE PAYOUTS
ANNUAL ASHLAND ---------- ALL OTHER
NAME AND COMPEN- COMMON LTIP COMPEN-
PRINCIPAL POSITION(1) SALARY BONUS(2) SATION(3) STOCK(4) PAYOUTS(5) SATION(6)
--------------------- -------- -------- --------- -------- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
G. Thomas Wilkinson
President (Retired)........... $310,702 $276,154 $3,461 10,000 $245,807 $ 18,397
W. Paul Tiefel
Chief Executive Officer and
President..................... 212,961 134,661 -- 4,000 126,055 11,559
Robert C. Bilger
Executive Vice President,
Chief Financial Officer and
Treasurer..................... 178,617 125,000 -- 4,000 66,698 9,527
Jeffrey W. Lund
Vice President Exploration and
Land.......................... 187,472 67,040 -- 2,000 85,643 9,797
Mark D. Pierce
Vice President Eastern Region
and Marketing................. 170,185 79,721 -- 4,000 57,563 8,732
</TABLE>
- ---------------
(1) All titles indicated in the table are for positions currently held, with the
exception of Mr. Wilkinson. Mr. Wilkinson served as President of the Company
until his retirement from the Company on February 24, 1997. He is expected
to continue as an employee of Ashland until September 30, 1997. All
obligations related to Mr. Wilkinson's employment with the Company and
Ashland are solely the responsibility of Ashland.
(2) Amounts received under Ashland's Incentive Compensation Plan for the fiscal
year ended September 30, 1996.
(3) None of the named executives received perquisites and other personal
benefits, securities or property in excess of the lesser of $50,000 or 10%
of total salary and bonus. The amount shown in this column reflects
reimbursement of taxes paid by Mr. Wilkinson.
(4) The options are options to purchase common stock of Ashland ("Ashland Common
Stock"). Ashland and the Company have agreed that, upon consummation of the
Spin Off, all such options then held by employees of the Company (which
include such options listed in the table) will become fully vested and will
continue to be exercisable for the normal term.
(5) Amounts received under Ashland's Performance Unit Plan for the fiscal year
1993-1996 performance period.
(6) Amounts shown in this column reflect employer matching contributions under
Ashland's Employee Savings Plan and allocations of stock under Ashland's
LESOP as provided on the same basis for all employees and related forfeiture
payments under the Employee Retirement Income Security Act of 1974, as
amended ("ERISA"). For fiscal 1996, these payments were as follows:
<TABLE>
<CAPTION>
ERISA
NAME SAVINGS PLAN LESOP FORFEITURE PAYMENTS
---- ------------ ------ -------------------
<S> <C> <C> <C>
G. Thomas Wilkinson.............................. $1,800 $7,025 $9,572
W. Paul Tiefel................................... 3,161 5,754 2,644
Robert C. Bilger................................. 3,699 4,626 1,202
Jeffery W. Lund.................................. 3,512 4,711 1,574
Mark D. Pierce................................... 3,516 4,368 848
</TABLE>
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<PAGE> 73
STOCK OPTION GRANTS
The following table sets forth certain information concerning options to
purchase Ashland Common Stock granted in fiscal year 1996 to the Named Executive
Officers.
ASHLAND COMMON STOCK OPTION GRANTS IN FISCAL YEAR 1996
<TABLE>
<CAPTION>
INDIVIDUAL GRANTS
-----------------------------------------------------------------------------
POTENTIAL REALIZABLE
% OF TOTAL VALUE AT ASSUMED
OPTIONS ANNUAL RATES OF STOCK
GRANTED PRICE APPRECIATION FOR
OPTIONS TO COMPANY EXERCISE OR OPTION TERM(2)
GRANTED EMPLOYEES IN BASE PRICE EXPIRATION -----------------------
NAME (#) FISCAL YEAR(1) ($/SH) DATE 5% 10%
---- ------- -------------- ----------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
G. Thomas Wilkinson.............. 10,000 23.3% $39.00 10/19/06 $247,857 $629,626
W. Paul Tiefel................... 4,000 9.3% 39.00 10/19/06 99,143 251,850
Robert C. Bilger................. 4,000 9.3% 39.00 10/19/06 99,143 251,850
Jeffery W. Lund.................. 2,000 4.7% 39.00 10/19/06 49,571 125,925
Mark D. Pierce................... 4,000 9.3% 39.00 10/19/06 99,143 251,850
</TABLE>
- ---------------
(1) The figures for percentage of total options are for the percentages in
relation to the total number of options for Ashland Common Stock granted to
employees of the Company. The Company's employees were granted options to
purchase a total of 43,000 shares of Ashland Common Stock during fiscal
1996.
(2) Option Value assuming stock price appreciation rates of 5% and 10%
compounded annually for the 10 year and 1 month term of the options.
STOCK OPTION EXERCISES
The following table sets forth certain information concerning options to
purchase Ashland Common Stock exercised in fiscal year 1996 by each of the Named
Executive Officers and the value of unexercised options to purchase Ashland
Common Stock held by such officers on September 30, 1996.
ASHLAND COMMON STOCK AGGREGATED OPTION EXERCISES IN FISCAL YEAR 1996
AND FISCAL YEAR-END OPTION VALUES
<TABLE>
<CAPTION>
SHARES NUMBER OF VALUE OF UNEXERCISED
ACQUIRED UNEXERCISED OPTIONS AT IN-THE-MONEY OPTIONS
ON FISCAL YEAR-END AT FISCAL YEAR-END(1)
EXERCISE VALUE EXERCISABLE/ EXERCISABLE/
NAME (#) REALIZED ($) UNEXERCISABLE(2) UNEXERCISABLE
---- -------- ------------ ---------------------- ---------------------
<S> <C> <C> <C> <C>
G. Thomas Wilkinson............... -- $ -- 57,000 / 17,500 $474,188 / $46,563
W. Paul Tiefel.................... 1,500 18,844 20,000 / 7,000 146,313 / 18,625
Robert C. Bilger.................. 1,000 7,625 13,500 / 6,500 98,563 / 16,688
Jeffery W. Lund................... -- -- 8,500 / 3,500 75,188 / 9,313
Mark D. Pierce.................... -- -- 10,500 / 6,500 83,125 / 16,688
</TABLE>
- ---------------
(1) Based on the closing price of Ashland Common Stock as reported on the NYSE
Composite Tape on September 30, 1996 of $39.75 per share.
(2) The Company and Ashland have agreed that, upon consummation of the Spin Off,
all Ashland Common Stock options then held by employees of the Company will
become vested by Ashland and continue to be exercisable for the normal terms
of the options.
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<PAGE> 74
ASHLAND BENEFIT AND WELFARE PLANS
The Company and Ashland have agreed that until the Spin Off, Company
employees will continue to participate in Ashland's employee benefit plans, with
the exception of option plans. After the Spin Off, the Company will adopt
benefit plans of its own on such terms as the Board of Directors deems
appropriate.
Retirement Plans. The Company participates in Ashland's qualified pension
plans (the "qualified plans") and will continue such participation after the
Offering until the Spin Off. Effective at the Spin Off, the Company intends to
implement a retirement plan with benefits comparable to peer companies as deemed
appropriate by the Board of Directors. Under Ashland's qualified plans,
executive officers of the Company are entitled to benefits on the same basis as
other employees. Upon a "change in control" of Ashland (as defined in the
plans), the qualified plans will automatically terminate and the funds in such
plans, together with any excess assets, will be distributed to the participants.
To the extent that benefits under the qualified plans exceed limits
established by the Internal Revenue Code of 1986, as amended (the "Code"), they
are payable under a nonqualified excess benefit pension plan (the "non-qualified
plan") which provides for the payment of benefits in excess of certain
limitations imposed by the provisions of ERISA or limitations on compensation or
benefits that may be imposed by the Code. The plan also provides that
participants may, at the discretion of the Personnel and Compensation Committee
of Ashland, receive their retirement benefit under the non-qualified plan in a
lump-sum distribution. The plan also provides that those who are approved to
receive a lump sum may defer the payment of all or any part of it, in 25%
increments, through the Ashland Inc. Deferred Compensation Plan.
The following table shows the estimated annual benefits payable under the
qualified and non-qualified plans assuming continued employment until the normal
date of retirement at age 65, based on a straight-life annuity form of
retirement income. The amounts in the table are not subject to any reductions
for social security benefits received by the participant but are subject to
reductions for the actuarial value of 50% of a participant's Ashland LESOP
account and the actuarial value of 50% of any shares forfeited under the Ashland
LESOP because of the limitations established by the Code.
ESTIMATED ANNUAL RETIREMENT BENEFITS
<TABLE>
<CAPTION>
YEARS OF PARTICIPATION
AVERAGE ANNUAL ---------------------------------------------------------------
EARNINGS* 10 15 20 25 30 35
-------------- -------- -------- -------- -------- -------- --------
<C> <C> <C> <C> <C> <C> <C>
$ 25,000 $ 3,300 $ 4,950 $ 6,601 $ 8,251 $ 9,901 $ 11,552
50,000 7,050 10,575 14,101 17,626 21,151 24,677
100,000 14,550 21,825 29,100 36,376 43,650 50,925
200,000 29,550 44,325 59,100 73,876 88,650 103,425
300,000 44,550 66,825 89,100 111,376 133,650 155,925
400,000 59,550 89,325 119,100 148,876 178,650 208,425
500,000 74,550 111,825 149,100 186,376 223,650 260,925
600,000 89,550 134,325 179,100 223,876 268,650 313,425
800,000 119,550 179,325 239,101 298,876 358,651 418,427
1,000,000 149,550 224,325 299,101 373,876 448,651 523,427
1,200,000 179,550 269,325 359,101 448,876 538,651 628,427
1,400,000 209,550 314,325 419,101 523,876 628,651 733,427
</TABLE>
- ---------------
* Average annual earnings includes a participant's salary during the highest
consecutive 36 month period of the final 120 month period prior to retirement,
but excludes other forms of compensation included in the Summary Compensation
Table.
As of October 1, 1996, Messrs. Wilkinson, Tiefel, Bilger, Lund and Pierce
had credited service in the combined plans of 7, 12, 8, 4 and 18 years,
respectively.
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<PAGE> 75
Supplemental Early Retirement Plan. Under Ashland's Supplemental Early
Retirement Plan (the "SERP"), eligible key executive employees of the Company
may retire prior to their normal retirement date. The maximum total annual
benefit payable to a key executive participant under the SERP is an amount equal
to 50% of the final average annual compensation (salary plus annual incentive
compensation awards) received by the participant during the highest 36 months of
the final 60 month period prior to retirement. The amount payable under the SERP
is reduced to the extent payments are made under the qualified and non-qualified
pension plans of Ashland, subject to reductions for the actuarial value of 50%
of a participant's Ashland LESOP account and the actuarial value of 50% of any
shares forfeited under the Ashland LESOP because of the limitations established
by the Code. The SERP provides that participants may, at the discretion of
Ashland's Personnel and Compensation Committee, receive their retirement benefit
under the plan in a lump-sum distribution. The SERP also provides that those who
are approved to receive a lump sum may defer all or any part of the payment, in
25% increments, through the Ashland Inc. Deferred Compensation Plan. The
retirement benefit received as a lump-sum distribution is equal to the actuarial
present value of all expected future payments if the participant received
monthly payments discounted at the average of the monthly published Pension
Benefit Guaranty Corporation ("PBGC") rates used to value annuities in effect
during the six month period ending on January 1 or July 1 immediately preceding
the calculation date. Certain other key employees who participate in the Ashland
Inc. Incentive Compensation Plan may become eligible to participate in the SERP
and may receive a maximum total annual benefit equal to 50% of the average bonus
paid under the Ashland Inc. Incentive Compensation Plan during the highest 36
months out of the final 60 month period prior to retirement. The SERP offers to
such key employees distribution options similar to those described above.
Effective at the Spin Off and subject to the approval of the Board of Directors,
the Company intends to implement a supplemental early retirement plan comparable
to the Ashland SERP.
Deferred Compensation Plan. The Company participates in the Ashland Inc.
Deferred Compensation Plan and will continue such participation after the
Offering and until the Spin Off. Under such plan, eligible employees may defer
the receipt of all or part of their incentive compensation and any payments made
pursuant to ERISA forfeitures. Effective at the Spin Off and subject to the
approval of the Board of Directors, the Company intends to implement and
maintain a deferred compensation plan comparable to that of Ashland.
Savings Plan. The Company participates in the Ashland Inc. Employee Savings
Plan (the "Ashland Plan") and will continue such participation after the
Offering and until the Spin Off. The Ashland Plan, which is a 401(k) Plan,
offers eligible employees the opportunity to make systematic, long-term
investments through salary contributions on a before-tax or after-tax basis.
Subject to certain plan and IRS restrictions, employees may contribute up to 16%
of pay, with Ashland matching to a total of 4% of pay. On the first 2% of
employee contribution, Ashland matches $1.10 for every $1.00. On the second 2%
of pay contributed, the match is $1.00 for $1.00. A variety of investment
options are offered to which contributions can be allocated by the participants.
Effective at the Spin Off and subject to the approval of the Board of Directors,
the Company intends to implement a savings plan similar to the Ashland Plan
which will qualify as a Section 401(k) plan and will offer eligible employees
the opportunity to make investments on a regular basis through salary
contributions which are supplemented by matching employer contributions.
COMPANY BENEFIT PLANS
1997 Stock Incentive Plan. In March 1997, the Company adopted the Company's
1997 Stock Incentive Plan (the "Plan"). The purpose of the Plan is to provide
directors, employees and consultants of the Company and its subsidiaries
additional incentive and reward opportunities designed to enhance the profitable
growth of the Company. All executives and certain nonexecutive employees who are
key to the Company's growth and profitability will be eligible to receive awards
under the Plan. The Plan provides for the granting of incentive stock options
intended to qualify under Section 422 of the Code, options that do not
constitute incentive stock options and restricted stock awards. The Plan is
administered by a Committee of the Board of Directors. In general, the Committee
is authorized to select the recipients of awards and the terms and conditions of
those awards. The number of shares of Common Stock that may be issued under the
Plan may not exceed 1,800,000 shares (subject to adjustment to reflect stock
dividends, stock splits, recapitalizations and similar changes in
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<PAGE> 76
the Company's capital structure). Shares of Common Stock which are attributable
to awards that have expired, terminated or been canceled or forfeited are
available for issuance or use in connection with future awards. The maximum
number of shares of Common Stock that may be subject to awards granted under the
Plan to any one individual during any calendar year may not exceed 500,000. The
price at which a share of Common Stock may be purchased upon exercise of an
option granted under the Plan will be determined by the Committee, but such
purchase price will not be less than the fair market value of a share of Common
Stock on the date such option is granted.
Shares of Common Stock that are the subject of a restricted stock award
under the Plan will be subject to restrictions on disposition by the holder of
such award and an obligation of such holder to forfeit and surrender the shares
to the Company under certain circumstances (the "Forfeiture Restrictions"). The
Forfeiture Restrictions will be determined by the Committee in its sole
discretion, and the Committee may provide that the Forfeiture Restrictions will
lapse upon (a) the attainment of one or more performance targets established by
the Committee, (b) the award holder's continued employment with the Company or
continued service as a consultant or director for a specified period of time,
(c) the occurrence of any event or the satisfaction of any other condition
specified by the Committee in its sole discretion or (d) a combination of any of
the foregoing. No awards under the Plan may be granted after ten years from the
date the Plan was adopted by the Board of Directors. The Plan will remain in
effect until all awards granted under the Plan have been satisfied or expired.
The Board of Directors in its discretion may terminate the Plan at any time with
respect to any shares of Common Stock for which awards have not been granted.
The Plan may be amended, other than to increase the maximum aggregate number of
shares that may be issued under the Plan or to change the class of individuals
eligible to receive awards under the Plan or to change the manner of determining
the minimum exercise price, by the Board of Directors without the consent of the
stockholders of the Company. No change in any award previously granted under the
Plan may be made which would impair the rights of the holder of such award
without the approval of the holder.
Upon consummation of the Offering, the Company will issue options under the
Plan to purchase an aggregate of 875,000 shares of Common Stock at the initial
public offering price. See "Principal and Management Stock Ownership" for a list
of the number of options to be issued to the directors and executive officers of
the Company.
Incentive Compensation Plan. The Company intends to implement, upon
completion of the Offering and subject to the approval of the Board of
Directors, an annual incentive compensation plan (the "IC Plan") which will
provide for the establishment of annual performance goals, which if achieved,
would result in the payment of additional compensation to the participants for
that year. The IC Plan will be administered by the Compensation Committee of the
Board of Directors ("the Committee") which will have broad discretion in
establishing the parameters of such plan. The annual performance goals will be
selected by the Committee and will be appropriate for an independent oil and gas
company and may include general Company goals, business unit goals, individual
productivity goals or a combination of the aforementioned goals depending on a
participant's responsibilities. The maximum potential award under the IC Plan
will vary depending on a participant's responsibilities but will range from 20%
to 100% of base salary. All executive officers and other key employees will
participate in the IC Plan.
EMPLOYMENT AGREEMENTS
The Company anticipates that during 1997 its most highly compensated
executive officers will be Messrs. Tiefel, Bilger, Fischer, Lund and Pierce.
Each of these executive officers has entered into an employment agreement with
the Company, effective as of March 1, 1997. Effective upon the consummation of
the Offering, Mr. Tiefel's annual salary will be $320,000 with a potential bonus
of 100% of such amount, Mr. Bilger's annual salary will be $260,000 with a
potential bonus of 85% of such amount, Mr. Fischer's annual salary will be
$210,000 with a potential bonus of 70% of such amount, Mr. Lund's annual salary
will be $200,000 with a potential bonus of 70% of such amount, and Mr. Pierce's
annual salary will be $180,000 with a potential bonus of 60% of such amount.
Each employment agreement is for a term of three years, and unless the Company
or the employee terminates the employment agreement or provides notice that the
term should
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<PAGE> 77
not be extended, the term will be extended automatically for an additional one
year period as of each annual anniversary date of the effective date of the
employment agreement.
In the event of the termination of employment by the Company without cause
(as defined) or by the employee due to an uncorrected material breach of the
employment agreement by the Company, the employee is entitled to receive (i) a
lump sum cash payment equal to 200% of the employee's annual base salary as in
effect immediately prior to such termination and (ii) continued coverage under
the Company's medical, dental and group life insurance plans for the employee
and certain of his or her eligible dependents for one year. If, in anticipation
of or within two years following a change in control of the Company, the
employment relationship is terminated by the Company without cause or by the
employee for good reason (as defined), the employee is entitled to receive
continuation coverage under the Company's medical, dental and group life
insurance plans as described above and, in lieu of the lump sum payment
described in the preceding sentence, a lump sum cash payment equal to the sum of
(a) 300% of the employee's annual base salary as in effect immediately prior to
such termination and (b) 225% of the maximum annual bonus amount that the
employee could have earned for the year during which such termination occurs. In
addition, if any payment or distribution to the employee pursuant to a change in
control is subject to the federal excise tax on "excess parachute payments," the
Company would be obligated under the employment agreement to pay to the employee
such additional amount as may be necessary so that the employee realizes, after
the payment of any income or excise tax on such additional amount, an amount
sufficient to pay all such excise taxes.
The Company is not obligated to pay any amounts to the employee other than
pro rata base salary through the date of termination upon (1) voluntary
termination of employment by the employee in the absence of an uncorrected
breach of the employment agreement by the Company, (2) termination of employment
by the Company for cause (as defined), (3) the death of the employee, or (4) the
long-term disability of the employee. During the period of employment and, under
certain circumstances, for a period of 12 months after termination of
employment, the employees are generally prohibited from competing or assisting
others to compete with the Company in its existing or recent business, or
inducing any other employee to terminate employment with the Company.
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<PAGE> 78
PRINCIPAL AND MANAGEMENT STOCK OWNERSHIP
The Company is currently a wholly-owned subsidiary of Ashland. Following
the Offering, Ashland will own 14,400,000 shares of Common Stock of the Company,
which will represent approximately 82.3% of the Company's outstanding Common
Stock (80.2% if the Underwriters' over-allotment option is exercised in full).
After the Offering, through its ability to elect all directors of the Company,
Ashland will control all matters affecting 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, the
Company's incurrence of debt any dividends payable on Common Stock. Ashland's
address is 1000 Ashland Drive, Russell, Kentucky 41169, and its telephone number
at such address is (606) 329-3333.
After the Offering, Ashland has informed the Company that it intends to
distribute pro rata to its common stockholders all of the shares of Common Stock
of the Company it owns by means of the Spin Off, subject to certain conditions.
See "Risk Factors -- Control by Ashland and Potential Conflicts of Interest" and
"Relationship Between the Company and Ashland -- Intended Spin Off by Ashland."
Upon consummation of the Spin Off, based on the number of shares of Ashland
Common Stock outstanding as of December 31, 1996 the Ashland LESOP will own
approximately 1,855,000 shares of Common Stock of the Company, representing
10.6% of the outstanding shares of Common Stock at the time of the Spin Off
(10.4% if the Underwriters over-allotment option is exercised in full), which
will make the Ashland LESOP the largest shareholder of the Company. The Company
has been advised that upon consummation of or after the Spin Off, the Ashland
LESOP intends to sell part or all of the shares of Company Common Stock it
receives in the Spin Off after expiration of a 180 day post-Offering lockup
agreement. Such sales may have an adverse effect on the market price of the
Common Stock. See "Risk Factors -- Ashland LESOP to be a Significant Shareholder
of the Company."
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<PAGE> 79
None of the officers or directors of the Company currently owns any shares
of capital stock of the Company. Set forth below for each director of the
Company, for each Named Executive Officer of the Company and for all directors
and executive officers of the Company as a group, is the number of shares of
Ashland Common Stock beneficially owned by such persons and the number of
options to purchase Company Common Stock to be issued upon consummation of the
Offering.
<TABLE>
<CAPTION>
OPTIONS TO PURCHASE COMPANY
COMMON STOCK TO BE GRANTED
UPON CONSUMMATION OF THE
OFFERING(1)
--------------------------- NUMBER OF SHARES OF
PERCENTAGE ASHLAND COMMON STOCK
NUMBER OF OWNERSHIP BENEFICIALLY OWNED AS OF
NAME SHARES(2) REPRESENTED(3) DECEMBER 31, 1996(4)
---- --------- -------------- ------------------------
<S> <C> <C> <C>
James R. Boyd................................. -- -- 172,129
W. Paul Tiefel................................ 220,000 1.2 16,904
Robert C. Bilger.............................. 150,000 * 16,913
Bradley W. Fischer............................ 90,000 * 6,392
Jeffrey W. Lund............................... 75,000 * 10,437
Mark D. Pierce................................ 30,000 * 15,318
Thomas L. Feazell............................. -- -- 114,577
Philip W. Block............................... -- -- 58,551
Dr. Robert B. Stobaugh........................ 4,000 * 23,840
J.W. Stewart.................................. 4,000 * --
All Directors and executive officers as a
group (13 persons).......................... 643,000 3.6 454,545
</TABLE>
- ---------------
* Less than one percent.
(1) None of the options to purchase Company Common Stock will be exercisable
until one year after the Offering.
(2) It is expected that Mr. Tiefel, Mr. Bilger, Mr. Fischer, and Mr. Lund will
not receive additional stock option grants until the third year after the
Offering.
(3) Assumes the Underwriters' over-allotment option is not exercised.
(4) As of February 24, 1997, includes the following: (i) shares of Ashland
Common Stock held under Ashland's Employee Savings Plan and/or Ashland's
LESOP in which shares participants hold voting rights and, with respect to
the shares in the Employee Savings Plan, control over investment
alternatives, (ii) Ashland Common Stock held by Dr. Stobaugh under the
Ashland Deferred Compensation Plan and the Ashland Stock Incentive Plan for
Non-Employee Directors and by Ashland executive officers under the Deferred
Compensation Plan which stock units are payable in cash or common stock of
Ashland upon termination of service with Ashland and (iii) shares which may
be acquired pursuant to outstanding stock options. Included for Mr. Feazell
are 12,010 shares owned by his wife as to which he disclaims beneficial
ownership.
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<PAGE> 80
RELATIONSHIP BETWEEN THE COMPANY AND ASHLAND
The Company is a wholly-owned subsidiary of Ashland. Immediately after the
closing of the Offering, Ashland will own 14,400,000 shares of Common Stock of
the Company, which will represent approximately 82.3% of the Company's
outstanding Common Stock (80.2% if the Underwriters' over-allotment option is
exercised in full). Through its ability to elect all directors of the Company,
Ashland will control all matters affecting 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, the
Company's incurrence of debt and any dividends payable on Common Stock. See
"Risk Factors -- Control by Ashland and Potential Conflicts of Interest."
INTENDED SPIN OFF BY ASHLAND
Ashland has announced that after the Offering it intends to distribute pro
rata to its common stockholders all of the shares of Common Stock it owns by
means of the Spin Off. Ashland's final determination to proceed with the Spin
Off will require a declaration by Ashland's Board of Directors. Such a
declaration is not expected to be made until certain conditions, many of which
are beyond the control of Ashland, are satisfied, including (i) receipt by
Ashland of a favorable ruling from the Internal Revenue Service as to the
tax-free nature of the Spin Off, and (ii) the absence of any future change in
market or economic conditions (including developments in the capital markets) or
Ashland's or the Company's business or financial condition that causes Ashland's
Board of Directors to conclude that the Spin Off is not in the best interests of
Ashland's stockholders. Ashland has filed its request for a ruling from the
Internal Revenue Service as to the tax-free nature of the Spin Off and has
advised the Company that it would not expect the Spin Off to occur prior to
September 1997. If Ashland effects the Spin Off, it is possible that the
increased number of shares of Common Stock of the Company available in the
market may have an adverse effect on the market price of the Common Stock. See
"Risk Factors -- Intended Spin Off by Ashland."
CONTRACTUAL ARRANGEMENTS
The following is a summary of certain agreements between the Company and
Ashland entered into in contemplation of the Offering and the Spin Off. Each
such summary is qualified in its entirety by reference to the forms of such
agreements, which are filed as exhibits to the Registration Statement of which
this Prospectus is a part.
Tax Agreement. The following is a summary of the Tax Agreement between the
Company and Ashland entered into in contemplation of the Offering and the Spin
Off (the "Tax Agreement"). Ashland's request for a ruling from the Internal
Revenue Service that the Spin Off will be a tax-free distribution to Ashland and
it shareholders was based on certain representations made to the Internal
Revenue Service with respect to the Company, including representations to the
effect that the Company, at the time of the Spin Off, will have no plan or
intention to (i) merge or consolidate with or into any other corporation, (ii)
liquidate or partially liquidate, (iii) sell or transfer all or substantially
all of its assets, (iv) redeem or otherwise repurchase any of the Company's
capital stock, or (v) issue additional shares of the Company's capital stock
other than pursuant to certain employee stock option plans. Other
representations may also be necessary in order to obtain the ruling. To protect
Ashland from federal and state income taxes that would be incurred by it if the
Spin Off were determined to be a taxable event, the Tax Agreement to be entered
into in connection with this Offering provides that the Company will indemnify
Ashland with respect to tax liabilities resulting from any breach by the Company
of any representations made in connection with the ruling. The Company intends
that, at the time of the Spin Off, the representations in the ruling request
will be accurate. However, because such representations will be based on a
subjective "current intent" standard, the Company may refrain from taking
actions after the Spin Off, such as those listed above, that might otherwise be
beneficial to the Company that might call into question its "current intent" at
the time of the Spin Off. The Company believes that if it is required to make
payments pursuant to the Tax Agreement, the amount of such payments would have a
material adverse effect on the Company's business, financial condition and
results of operations.
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<PAGE> 81
In addition, the Tax Agreement provides that for periods between the
Offering and the Spin Off, Ashland will prepare and file all consolidated
federal, combined state and local income or franchise tax returns required to be
filed while the Company is a member of Ashland's consolidated group. Pursuant to
the Tax Agreement the Company generally will be required to pay to Ashland its
tax liability computed on a separate, stand alone basis (with certain
modifications). With respect to federal income taxes, because Ashland currently
is subject to the alternative minimum tax ("AMT"), the Company's tax payment
initially will be based on the AMT rate (20%) and the Company will be required
pay to Ashland the excess of its stand-alone tax liability calculated using the
regular corporate rate (35%) in the year in which Ashland is no longer paying
tax at the AMT rate or utilizing an AMT credit carryover. To the extent that the
Company generates losses or credits, Ashland will pay the Company for such
losses or credits based on either regular corporate tax rates or the AMT rate,
depending on the circumstances. In addition, the Tax Agreement provides that
Ashland will pay the Company for the Company's Australian tax losses to the
extent the Company agrees to allow such losses to be utilized by other
affiliates of Ashland to reduce Australian taxes.
Following the Spin Off, the Company will file its own consolidated federal
income tax return, separate from Ashland. The Tax Agreement provides that
Ashland generally will be responsible for the effect of any adjustments to the
U.S. or state taxable income or tax liability of the Company for periods ending
on or before the date of the Spin Off in which it filed combined or consolidated
reports with Ashland. To the extent any such adjustment results in a benefit to
the Company in a post-Spin Off taxable period, the Company will be required to
pay such benefit to Ashland. Liability for pre-Spin Off tax liabilities or
separate reports filed by the Company prior to the Spin Off in certain states'
foreign jurisdictions will be for the account of the Company.
Services Agreement. In contemplation of the Offering and the Spin Off, the
Company and Ashland have entered into a Services Agreement (the "Services
Agreement") effective on the date the Offering is completed, which provides for
the continued provision of certain corporate and administrative services (the
"Services") by Ashland to the Company, including the administration of employee
benefit plans, the provision of telecommunications, information services,
equipment and cash management. The Services Agreement provides that Ashland will
provide the Services to the Company through the same or similarly qualified
personnel and the same or similar facilities as it has in the past, but the
selection of personnel to perform Services shall be within the sole discretion
of Ashland. Ashland is not required to increase the volume or quality of the
Services beyond the level at which they were performed for the Company in the
past. The Services Agreement is for an initial term beginning on the date the
Offering is completed and continuing for as long as Ashland and its wholly-owned
affiliates own more than 80% of the outstanding shares of Common Stock (the
"Initial Term"). After the Initial Term, the term of the Services Agreement
shall automatically be extended for successive one year period (each, a "Renewal
Term"). The Company has the right to terminate any Service upon at least 30
days' prior written notice to Ashland, and Ashland shall have the right to
terminate any Service upon at least 60 days' prior written notice to the Company
after the expiration of the first Renewal Term and any subsequent Renewal Term.
During the Initial and first Renewal Term, Ashland will charge the Company at
Ashland's cost of rendering the Services performed. For Services provided after
the first Renewal Term, the Company will be charged, depending on the service,
cost or 110% of Ashland's cost of rendering such Services. Costs which have been
passed on to the Company in the past will be calculated in accordance with the
practices in existence prior to the Services Agreement being in operation.
Certain types of insurance coverage provided by Ashland to the Company shall
terminate on the expiration of the Initial Term of the Services Agreement, and
Ashland will have no obligation to provide or procure such coverages for the
Company. Other types of insurance purchased specifically for the Company or one
of its operations or projects will not be knowingly terminated by Ashland
without the consent of the Company.
Registration Rights Agreement. In contemplation of the Offering, the
Company and Ashland have entered into a Registration Rights Agreement, pursuant
to which Ashland has the right to require the Company to effect three
registrations under the Securities Act of all or any part of the Common Stock
owned by Ashland, subject to certain limitations, and to bear the expenses of
such registrations. No such registration may be required by Ashland prior to the
expiration of the 180 day period following the date of the consummation of the
Offering. In addition, the Registration Rights Agreement gives Ashland the right
to include its shares of Common Stock in any registration of shares of Common
Stock initiated by the Company
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<PAGE> 82
following the Offering. The Registration Rights Agreement also contains
provisions whereby the Company and Ashland agree to indemnify each other and
their respective subsidiaries as well as their respective directors, officers,
employees, agents and representatives for certain costs and liabilities relating
to violations of federal and state securities laws in connection with any such
registration of Common Stock owned by Ashland.
Indemnification Agreement. In connection with the Offering and the Spin
Off, the Company and Ashland will enter into an Indemnification Agreement under
which the Company will assume the liabilities and obligations associated with
its and its predecessors' operations, even if attributable to periods prior to
the Offering, and agree to hold Ashland harmless from and against, all
liabilities relating to the Company's operations, including: (i) except as set
forth below, any litigation pending or threatened as of the date of the Offering
or that arises in the future and involves costs incurred after consummation of
the Offering, and (ii) remediation or other environmental liabilities associated
with the Company's operations. In the Indemnification Agreement, Ashland grants
the Company the benefits of any insurance coverage, including any sum recouped
thereunder. Ashland will agree to indemnify the Company and hold it harmless
from and against any costs or liabilities: (i) relating to Ashland's operations
(other than those attributable to the Company's operations) and (ii) associated
with any private litigation claiming damages relating to the Company's operation
of the Martha oil field.
CERTAIN TRANSACTIONS
The Company sells natural gas production to Ashland Petroleum Company and
crude oil production to Scurlock Permian Corp., each of which is an affiliate of
Ashland, at market rates. Sales to Ashland Petroleum Company were $2.5 million,
$1.8 million and $2.7 million for the fiscal years ending 1994, 1995 and 1996,
respectively. Sales to Scurlock Permian Corp. were $1.5 million, $0.5 million
and $0.2 million for the fiscal years ending 1994, 1995 and 1996, respectively.
The Company and Ashland expect that the Company will continue to make such sales
after the Offering.
Certain administrative services are provided to the Company by Ashland. For
these services, the Company receives an allocation of Ashland's general and
administrative expenses which amounted to $2.3 million in 1994, $2.4 million in
1995 and $2.3 million in 1996. These services include, among others, insurance
administration and certain tax and legal administrative activities. It is
Ashland's policy to charge these expenses and all other central administrative
activities costs on the basis of direct usage when identifiable. After the
Offering, these services will be provided under the Services Agreement described
above.
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<PAGE> 83
DESCRIPTION OF CAPITAL STOCK
The authorized capital stock of the Company consists of 100,000,000 shares
of Common Stock, par value $.01 per share, and 20,000,000 shares of preferred
stock, par value $.01 per share (the "Preferred Stock"). Upon consummation of
the Offering, 17,500,000 shares of Common Stock (17,965,000 shares if the
Underwriters' over-allotment option is exercised in full) and no shares of
Preferred Stock will be outstanding. The following summary is qualified in its
entirety by reference to the Company's Restated Certificate of Incorporation and
Bylaws, copies of which have been filed as exhibits to the Registration
Statement of which this Prospectus forms a part.
COMMON STOCK
The Holders of the Common Stock are entitled to one vote per share for each
share held of record on all matters submitted to a vote of stockholders. Holders
of Common Stock do not have the right to cumulate their votes in the election of
directors. Subject to preferential rights with respect to any class or series of
Preferred Stock that may be issued, holders of Common Stock are entitled to
receive ratably such dividends as may be declared by the Board of Directors on
the Common Stock out of funds legally available therefore, and in the event of a
liquidation, dissolution or winding-up of the affairs of the Company, are
entitled to share equally and ratably in all remaining assets and funds of the
Company. The Company currently does not anticipate paying dividends on the
Common Stock. See "Dividend Policy." The Holders of the Common Stock have no
preemptive rights or rights to convert Common Stock into any other securities
and are not subject to future calls or assessments by the Company. All of the
outstanding Common Stock are, and, when issued, the Common Stock offered hereby
will be validly issued, fully paid, and non-assessable by the Company.
An application will be made to list the Common Stock on the NYSE under the
trading symbol " ."
PREFERRED STOCK
The Company, by resolution of the Board of Directors and without any
further vote or action by the stockholders, has the authority to issue Preferred
Stock in one or more classes or series and to fix from time to time the number
of shares to be included in each such class or series and the designations,
preferences, qualifications, limitations, restrictions and special or relative
rights of the shares of each such class or series. The ability of the Company to
issue Preferred Stock, while providing flexibility in connection with possible
acquisitions and other corporate purposes, could adversely affect the voting
power of holders of the Common Stock and could have the effect of making it more
difficult for a third-party to acquire, or of discouraging a third-party from
acquiring, control of the Company. The Company has no present plans to issue
Preferred Stock.
CERTAIN ANTI-TAKEOVER PROVISIONS
Stockholder Rights Plan. The Company expects that, at or immediately after
the time of the Spin Off, it will adopt a stockholder rights plan under which
rights will be issued to holders of the Common Stock that will provide that,
upon certain events related to an attempt to acquire control of the Company
without the approval of the Board of Directors, stockholders (other than those
involved in the change of control attempt) will have certain rights to acquire
additional shares of Common Stock (or capital stock of an acquiring entity) at a
substantial discount to the market price. The effect of the stockholder rights
plan will be to deter certain attempts at acquiring control of the Company
except as approved by the Board of Directors.
Classified Board of Directors. The Restated Certificate of Incorporation
and Bylaws provide that the Board of Directors is divided into three classes of
directors, with the classes to be as nearly equal in number as possible. As
currently comprised, Class I directors will serve until the Company's 1998
annual meeting of stockholders, Class II directors will serve until the 1999
annual meeting of stockholders, and Class III directors will serve until the
year 2000 annual meeting of stockholders. See "Management." Starting with the
1998 annual meeting of stockholders, one class of directors will be elected each
year for a three-year term. The classification of directors will have the effect
of making it more difficult for stockholders to change the composition of the
Board, in that at least two annual meetings of stockholders, instead of one,
will generally be
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required to effect a change in a majority of the Board. In addition, the
classification provisions could also have the effect of discouraging a third
party from initiating a proxy contest, making a tender offer or otherwise
attempting to obtain control of the Company, even though such an attempt might
be beneficial to the Company and its stockholders.
Removal of Directors. The Restated Certificate of Incorporation and Bylaws
provide that directors may be removed only for cause and only upon the
affirmative vote of holders of at least 80% of the voting power of all the then
outstanding shares of stock entitled to vote generally in the election of
directors ("Voting Stock"), voting together as a single class.
Stockholders Not Entitled to Call Special Meeting. The Restated Certificate
of Incorporation and Bylaws provide that special meetings of stockholders can be
called only upon a written request stating the purpose of such meeting delivered
to the Chairman of the Board, the President or the Secretary, signed by a
majority of the Board. Stockholders are not permitted to call a special meeting
or to require that the Board call a special meeting of stockholders. Moreover,
the business permitted to be conducted at any special meeting of stockholders is
limited to the business brought before the meeting pursuant to the notice of
meeting given by the Company.
Advance Notice of Stockholder Proposals and Nominations. The Bylaws
establish an advance notice procedure for stockholders to make nominations of
candidates for election as directors, or bring other business before an annual
meeting of stockholders of the Company (the "Stockholder Notice Procedure"). The
Stockholder Notice Procedure provides that only persons who are nominated by, or
at the direction of, the Board, or by a stockholder who has given timely written
notice to the Secretary of the Company prior to the meeting at which directors
are to be elected, will be eligible for election as directors of the Company.
The Stockholder Notice Procedure provides that at an annual meeting only such
business may be conducted as has been brought before the meeting by, or at the
direction of, the Chairman of the Board or by a stockholder who has given timely
written notice to the Secretary of the Company of such stockholder's intention
to bring such business before such meeting. Under the Stockholder Notice
Procedure, for notice of stockholder nominations to be made at an annual meeting
to be timely, such notice must be received by the Company not less than 70 days
nor more than 90 days prior to the first anniversary of the previous year's
annual meeting (or if the date of the annual meeting is advanced by more than 20
days, or delayed by more than 70 days, from such anniversary date, not earlier
than the 90th day prior to such meeting and not later than the later of (x) the
70th day prior to such meeting and (y) the 10th day after public announcement of
the date of such meeting is first made). Notwithstanding the foregoing, in the
event that the number of directors to be elected is increased and there is no
public announcement naming all of the nominees for director or specifying the
size of the increased Board made by the Company at least 80 days prior to the
first anniversary of the preceding year's annual meeting, a stockholder's notice
will be timely, but only with respect to nominees for any new positions created
by such increase, if it is received by the Company not later than the 10th day
after such public announcement is first made by the Company. Under the
Stockholder Notice Procedure, for notice of a stockholder nomination to be made
at a special meeting at which directors are to be elected to be timely, such
notice must be received by the Company not earlier than the 90th day before such
meeting and not later than the later of (x) the 70th day prior to such meeting
and (y) the 10th day after public announcement of the date of such meeting is
first made.
Under the Stockholder Notice Procedure, a stockholder's notice to the
Company proposing to nominate a person for election as a director must contain
certain information, including, without limitation, the identity and address of
the nominating stockholder, the class and number of shares of stock of the
Company which are owned by such stockholder, and all information regarding the
proposed nominee that would be required to be included in a proxy statement
soliciting proxies for the proposed nominee. Under the Stockholder Notice
Procedure, a stockholder's notice relating to the conduct of business other than
the nomination of directors must contain certain information about such business
and about the proposing stockholders, including, without limitation, a brief
description of the business the stockholder proposes to bring before the
meeting, the reasons for conducting such business at such meeting, the name and
address of such stockholder, the class and number of shares of stock of the
Company beneficially owned by such stockholder, and any material interest of
such stockholder in the business so proposed. If the Chairman of the Board or
other office presiding at a meeting
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determines that a person was not nominated, or other business was not brought
before the meeting, in accordance with the Stockholder Notice Procedure, such
person will not be eligible for election as a director, or such business will
not be conducted at such meeting, as the case may be.
The Stockholder Notice Procedure may have the effect of precluding a
contest for the election of directors or the consideration of stockholder
proposals if the proper procedures are not followed, and of discouraging or
deterring a third party from conducting a solicitation of proxies to elect its
own slate of directors or to approve its own proposal, without regard to whether
consideration of such nominees or proposals might be harmful or beneficial to
the Company and its stockholders.
Certain Amendments. The Restated Certificate of Incorporation provides that
the affirmative vote of the holders of at least 80% of the voting power of the
outstanding shares of Voting Stock, voting together as a single class, is
required to amend provisions of the Restated Certificate of Incorporation
relating to the number, election and term of the Company's directors, or the
removal of directors. The Restated Certificate of Incorporation further provides
that the Bylaws may be amended by the Board or by the affirmative vote of the
holders of at least a majority of the voting power of the outstanding shares of
Voting Stock, voting together as a single class, although any amendment by the
stockholders to the provisions of the Bylaws related to classification of the
Board and establishing the size of the Board requires the affirmative vote of
the holders of at least 80% of the outstanding Voting Stock.
The provisions summarized above may have anti-takeover effects and may
deter, delay or prevent a tender offer or other takeover attempt that a
stockholder might consider in such stockholder's best interest, including
takeover attempts that might result in a payment of a premium over market
prices.
Shareholder Action By Written Consent. The Restated Certificate of
Incorporation provides that, for so long as Ashland owns at least a majority of
the Voting Stock, any action otherwise required to be taken by the stockholders
of the Company at an annual or special meeting of stockholders may be taken
without a meeting, without notice and without a vote, if a written consent or
consents signed by the holders of not less than the minimum number of votes that
would be necessary to authorize or take such action at a meeting at which all
members entitled to vote thereon were present and voting, is delivered to the
Company in the manner set forth in the Restated Certificate of Incorporation.
The Restated Certificate of Incorporation provides that if Ashland ceases to own
at least a majority of the Voting Stock of the Company, then thereafter
shareholder action by written consent shall be prohibited.
Section 203 of the Delaware Law. The Company is subject to Section 203
("Section 203") of the Delaware General Corporation Law, as amended ("DGCL"),
which, subject to certain exceptions, prohibits a Delaware corporation from
engaging in any business combination with any interested stockholder for a
period of three years following the date that such stockholder became an
interested stockholder, unless (i) prior to such date, the board of directors of
the corporation approved either the business combination or the transaction that
resulted in the stockholder becoming an interested stockholder, (ii) upon
consummation of the transaction that resulted in the stockholder becoming an
interested stockholder, the interested stockholder owned at least 85% of the
voting stock of the corporation outstanding at the time the transaction
commenced excluding for purposes of determining the number of shares outstanding
those shares owned (x) by persons who are directors and also officers and (y) by
employee stock plans in which employee participants do not have the right to
determine confidentially whether shares held subject to the plan will be
tendered in a tender or exchange offer, or (iii) on or subsequent to such date,
the business combination is approved by the board of directors and authorized at
an annual or special meeting of stockholders, and not by written consent, by the
affirmative vote of at least 66 2/3% of the outstanding voting stock that is not
owned by the interested stockholder.
Section 203 defines business combinations to include (i) any merger or
consolidation involving the corporation and the interested stockholder, (ii) any
sale, transfer, pledge or other disposition of 10% or more of the assets of the
corporation involving the interested stockholder, (iii) subject to certain
exceptions, any transaction that results in the issuance or transfer by the
corporation of stock of the corporation to the interested stockholder, (iv) any
transaction involving the corporation that has the effect of increasing the
proportionate share of the stock of any class or series of the corporation
beneficially owned by the interested
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stockholder, or (iv) the receipt by the interested stockholder of the benefit of
any loans, advances, guarantees, pledges or other financial benefits provided by
or through the corporation. In general, Section 203 defines an interested
stockholder as any entity or person beneficially owning 15% or more or the
outstanding voting stock of the corporation and any entity or person affiliated
with or controlling or controlled by such entity.
LIMITATION OF LIABILITY OF DIRECTORS AND OFFICERS AND INDEMNIFICATION
The Restated Certificate of Incorporation of the Company limits the
liability of directors of the Company to the Company or its stockholders (in
their capacity as directors but not in their capacity as officers) to the
fullest extent permitted by the DGCL. Specifically, directors of the Company
will not be personally liable for monetary damages for breach of a director's
fiduciary duty as a director, except for liability (i) for any breach of the
director's duty of loyalty to the Company or its stockholders, (ii) for acts or
omissions not in good faith or which involve intentional misconduct or a knowing
violation of law, (iii) for unlawful payments of dividends or unlawful stock
repurchases or redemptions as provided in Section 174 or (iv) for any
transaction from which the director derived an improper personal benefit. The
Restated Certificate of Incorporation also provides that if the DGCL is amended
after the approval of the Restated Certificate of Incorporation to authorize
corporate action further eliminating or limiting the personal liability of
directors, then the liability of a director of the Company will be eliminated or
limited to the full extent permitted by the DGCL, as so amended.
In addition, the Restated Certificate of Incorporation requires the Company
to indemnify each person who is or was a director or officer of the Company to
the full extent permitted by the laws of the State of Delaware in the event he
is involved in legal proceedings by reason of the fact that he is or was a
director, officer, employee or agent of the Company, or is or was serving at the
Company's request as a director, officer, employee or agent of another
corporation, partnership or other enterprise. The Company is also required to
advance to such persons payments for their expenses incurred in defending a
proceeding to which indemnification might apply, provided, if the DGCL requires,
the recipient provides an undertaking agreeing to repay all amounts if it is
ultimately determined that he is not entitled to be indemnified. The right to
indemnification conferred on directors and officers of the Company under the
Restated Certificate of Incorporation is stated to be a contract right. In
addition, the Restated Certificate of Incorporation specifically provides that
the indemnification rights granted thereunder are non-exclusive.
The Company has entered into indemnification agreements with each of its
current directors providing specific procedures to better assure the directors'
right to indemnification, including procedures for directors to submit claims,
for determination of directors' entitlement to indemnification (including the
allocation of the burden of proof and selection of a reviewing party) and for
enforcement of directors' indemnification rights.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for the Common Stock is Harris Trust &
Savings Bank.
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SHARES ELIGIBLE FOR FUTURE SALE
Prior to the Offering, there has been no market for the Common Stock.
Future sales of substantial amounts of Common Stock in the public market could
adversely affect prevailing market prices. See "Risk Factors -- Shares Eligible
for Future Sale."
Upon completion of the Offering, the Company will have 17,500,000 shares of
Common Stock outstanding (17,965,000 shares if the Underwriters' over-allotment
option is exercised in full). Of these shares, the 3,100,000 shares sold in this
Offering will be freely transferable without restriction or registration under
the Securities Act, except for any shares purchased by an existing "affiliate"
of the Company, as that term is defined by the Securities Act (an "Affiliate"),
which shares will be subject to the resale limitations of Rule 144 adopted under
the Securities Act described below.
The remaining 14,400,000 shares of Common Stock (constituting 82.3% of the
shares to be outstanding on completion of the Offering) will be owned by
Ashland. Ashland has informed the Company that it expects to consummate the Spin
Off of such shares to its stockholders as soon as possible after obtaining a
favorable tax ruling on such transaction. Ashland has advised the Company that
it does not expect the Spin Off to occur prior to September 1997. No assurance
can be given that such Spin Off will occur. See "Risk Factors -- Intended Spin
Off by Ashland." If the Spin Off does not occur, Ashland will be entitled to
certain rights with respect to the registration of the sale of such shares under
the Securities Act. See "Relationship Between the Company and
Ashland -- Contractual Arrangements -- Registration Rights Agreement." Such a
sale of a significant amount of shares by Ashland could have a material adverse
effect on the market price of the Common Stock.
As of December 31, 1996, the Ashland LESOP held 8,401,243 shares of Ashland
common stock. Based upon the number of shares of Ashland outstanding at December
31, 1996, upon consummation of the Spin Off, the Ashland LESOP would own
approximately 1,855,000 shares of Common Stock of the Company, representing
10.6% of the outstanding shares of Common Stock at the time of the Spin Off
(10.4% if the Underwriters' over-allotment option is exercised), which would
make the Ashland LESOP the largest shareholder of the Company. The Company has
been advised that after the Spin Off, the Ashland LESOP intends to sell part or
all of the shares of Company Common Stock it receives in the Spin Off after
expiration of a 180 day post-Offering lockup agreement. Such sales may have an
adverse effect on the market price of the Common Stock.
The Company, Ashland, the Ashland LESOP and each officer and director of
the Company have agreed that they will not for a period of 180 days from the
date of this Prospectus, without the prior written consent of the
Representatives, directly or indirectly (i) offer, pledge, sell, contract to
sell, sell any option or contract to purchase, purchase any option or contract
to sell, grant any option, right or warrant for the sale of, or otherwise
dispose of or transfer (except by means of the Spin Off) any shares of the
Common Stock or any securities convertible into or exchangeable or exercisable
for Common Stock, or file any registration statement under the Securities Act
with respect to any of the foregoing or (ii) enter into any swap or any other
agreement or any transaction that transfers, in whole or in part, directly or
indirectly, the economic consequences of ownership of the Common Stock, whether
any such swap or transaction is to be settled by delivery of Common Stock or
other securities, in cash or otherwise.
The shares of Common Stock to be held by Ashland after the Offering will
constitute "restricted securities" within the meaning of Rule 144 and will be
eligible for sale by Ashland in the open market either in registered sales
effected pursuant to the Registration Rights Agreement, or pursuant to Rule 144.
In general, under Rule 144 as currently in effect, beginning 90 days after the
Offering, a person (or persons whose shares are aggregated) who owns shares that
were purchased from the Company (or any Affiliate) at least one year previously,
including a person who may be deemed an Affiliate of the Company, is entitled to
sell within any three-month period a number of shares that does not exceed the
greater of 1% of the then outstanding shares of the Company's Common Stock or
the average weekly trading volume of the Company's Common Stock in the over the
counter market during the four calendar weeks preceding the date on which notice
of the sale is filed with the Commission. Sales under Rule 144 are also subject
to certain manner of sale provisions, notice requirements and the availability
of current public information about the Company. Any person (or persons
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whose shares are aggregated) who is not deemed to have been an Affiliate of the
Company at any time during the 90 days preceding a sale, and who owns shares
within the definition of "restricted securities" under Rule 144 under the
Securities Act that were purchased from the Company (or any Affiliate) at least
two years previously, would be entitled to sell such shares under Rule 144(k)
without regard to the volume limitations, manner of sale provisions, public
information requirements or notice requirements.
Upon completion of the Offering, there will be 875,000 shares of Common
Stock issuable pursuant to outstanding options held by employees and directors,
all of which will be issued pursuant to a registration statement on Form S-8 and
will vest in increments and become freely tradeable, subject to certain
requirements of Rule 144, beginning one year after completion of the Offering.
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UNDERWRITING
Subject to the terms and conditions set forth in the Purchase Agreement
(the "Purchase Agreement") among the Company, Ashland and each of the
underwriters named below (the "Underwriters"), the Company has agreed to sell to
each of the Underwriters, and each of the Underwriters, for whom Merrill Lynch,
Pierce, Fenner & Smith Incorporated, Credit Suisse First Boston Corporation and
Goldman, Sachs & Co. are acting as representatives (the "Representatives"), has
severally agreed to purchase, the number of shares of Common Stock set forth
below opposite their respective names.
<TABLE>
<CAPTION>
NUMBER
UNDERWRITERS OF SHARES
------------ ---------
<S> <C>
Merrill Lynch, Pierce, Fenner & Smith
Incorporated...................................
Credit Suisse First Boston Corporation......................
Goldman, Sachs & Co. .......................................
---------
Total.......................................... 3,100,000
=========
</TABLE>
In the Purchase Agreement, the several Underwriters have agreed, subject to
the terms and conditions set forth therein, to purchase all of the shares of
Common Stock being sold pursuant to such Purchase Agreement if any of the shares
of Common Stock being sold pursuant to such Purchase Agreement are purchased.
Under certain circumstances, the commitments of non-defaulting Underwriters may
be increased as set forth in the Purchase Agreement.
The Representatives have advised the Company that the Underwriters propose
to offer the shares of Common Stock to the public initially at the public
offering price set forth on the cover page of this Prospectus, and to certain
dealers at such price less a concession not in excess of $ . per share. The
Underwriters may allow, and such dealers may reallow, a discount not in excess
of $ . per share on sales to certain other dealers. After the initial public
offering, the public offering price, concession and discount may be changed.
The Company has granted the Underwriters an option to purchase up to an
aggregate of 465,000 additional shares of Common Stock exercisable for 30 days
after the date of this Prospectus, to cover over-allotments, if any, at the
initial public offering price set forth on the cover page of this Prospectus
less the underwriting discount. To the extent that the Representatives exercise
such option, each of the Underwriters will have a firm commitment, subject to
certain conditions, to purchase approximately the same percentage of the option
shares that the number of shares to be purchased by it shown in the foregoing
table bears to the total number of shares initially offered by the Underwriters
hereby.
The Company and Ashland have jointly and severally agreed to indemnify the
Underwriters against certain liabilities, including liabilities under the
Securities Act, or to contribute to payments the Underwriters may be required to
make in respect thereof.
The Underwriters have informed the Company that they do not intend to sell
shares of the Common Stock offered hereby to any accounts over which they
exercise discretionary authority.
The Company, Ashland, the Ashland LESOP and each officer and director of
the Company have agreed that they will not for a period of 180 days from the
date of this Prospectus, without the prior written consent of the
Representatives, directly or indirectly (i) offer, pledge, sell, contract to
sell, sell any option or contract to purchase, purchase any option or contract
to sell, grant any option, right or warrant for the sale of, or otherwise
dispose of or transfer (except by means of the Spin Off) any shares of the
Common Stock or any securities convertible into or exchangeable or exercisable
for Common Stock, or file any registration statement under the Securities Act
with respect to any of the foregoing or (ii) enter into any swap or any other
agreement or any transaction that transfers, in whole or in part, directly or
indirectly, the economic consequences of ownership
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of the Common Stock, whether any such swap or transaction is to be settled by
delivery of Common Stock or other securities, in cash or otherwise.
Prior to the Offering, there has been no public market for the Common Stock
of the Company. The initial public offering price for the Common Stock will be
determined by negotiation between the Company and the Underwriters. Among the
factors that will be considered in determining the initial public offering price
are the Company's results of operations, the Company's current financial
condition, its future prospects, the experience of its management, the economics
of the industry in general, the general condition of the equity securities
market, the demand for similar securities of companies considered comparable to
the Company and other relevant factors. There can be no assurance that an active
trading market will develop for the Common Stock or that the Common Stock will
trade in the public market subsequent to the Offering at or above the initial
public offering price.
Application will be made to list the Common Stock for trading on the NYSE
under the symbol " ." In order to meet one of the requirements for listing the
Common Stock on the NYSE, the Underwriters have undertaken to sell lots of 100
or more shares to a minimum of 2,000 beneficial holders.
Credit Suisse First Boston Corporation has advised Ashland in connection
with the Spin Off and has performed and will continue to perform various
investment advisory and banking services for Ashland from time to time, for
which it receives customary fees.
The Representatives, on behalf of the Underwriters, may engage in
stabilizing transactions, syndicate covering transactions and penalty bids in
accordance with Rule 104 under the Exchange Act. Stabilizing transactions permit
bids to purchase the underlying security so long as the stabilizing bids do not
exceed a specified maximum. Syndicate covering transactions involve purchases of
shares of the Common Stock in the open market after the distribution has been
completed in order to cover syndicate short positions. Penalty bids permit the
Representatives to reclaim a selling concession from a syndicate member when the
shares of Common Stock originally sold by such syndicate member are purchased in
a syndicate covering transaction to cover syndicate short positions. Such
stabilizing transactions, syndicate covering transactions and penalty bids may
cause the price of the Common Stock to be higher than it would otherwise be in
the absence of such transactions.
LEGAL MATTERS
Certain legal matters in connection with the shares of Common Stock offered
hereby are being passed upon for the Company and Ashland by Vinson & Elkins
L.L.P., Houston, Texas, and for the Underwriters by Cravath, Swaine & Moore, New
York, New York. Cravath, Swaine & Moore serves as outside counsel to Ashland and
is currently representing Ashland in connection with several matters unrelated
to the Offering. Samuel C. Butler, a member of Cravath, Swaine & Moore, is a
director of Ashland.
EXPERTS
The consolidated financial statements of Blazer Energy Corp. at September
31, 1995 and 1996 and for each of the three years in the period ended September
31, 1996, appearing in this Prospectus and Registration Statement have been
audited by Ernst & Young LLP, independent auditors, as set forth in their report
thereon appearing elsewhere herein, and are included in reliance upon such
report given upon the authority of such firm as experts in accounting and
auditing. The estimated reserve evaluations and related calculations of
Netherland, Sewell & Associates, Inc. included in this Prospectus have been
included herein in reliance upon the authority of said firm as experts in
petroleum engineering.
AVAILABLE INFORMATION
The Company has not previously been subject to the reporting requirements
of the Exchange Act. The Company has filed with the Commission a Registration
Statement on Form S-1 (the "Registration Statement") under the Securities Act,
with respect to the offer and sale of Common Stock pursuant to this
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Prospectus. This Prospectus, which constitutes a part of the Registration
Statement, does not contain all of the information set forth in the Registration
Statement, certain items of which are contained in exhibits and schedules
thereto in accordance with the rules and regulations of the Commission. For
further information with respect to the Company and the Common Stock offered
hereby, reference is made to the Registration Statement, including the exhibits
and schedules thereto. Statements made in this Prospectus concerning the
contents of any contract, agreement or other document filed as an exhibit to the
Registration Statement are summaries of the terms of such contract, agreement or
document and are not necessarily complete; reference is made to each such
exhibit for a more complete description of the matters involved and each such
Statement is qualified in its entirety by such reference. The Registration
Statement and the exhibits and schedules thereto filed with the Commission may
be inspected, without charge, and copies may be obtained at prescribed rates, at
the public reference facilities maintained by the Commission at Judiciary Plaza,
450 Fifth Street, N.W., Washington, D.C. 20549 and at the regional offices of
the Commission located at 7 World Trade Center, Suite 1300, New York, New York
10048 and Citicorp Center, 500 West Madison Street, Suite 1400, Chicago,
Illinois 60661. The Commission maintains a site on the World Wide Web at http:
//www.sec.gov that contains reports, proxy and information statements and other
information regarding registrants that file electronically with the Commission.
For further information pertaining to the Common Stock offered by this
Prospectus and the Company, reference is made to the Registration Statement.
The Company intends to furnish holders of its Common Stock annual reports
containing audited consolidated financial statements.
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GLOSSARY OF OIL AND GAS TERMS
Unless otherwise indicated in this Prospectus, natural gas volumes are
stated at the legal pressure base of the state or area in which the reserves are
located and at 60 degrees Fahrenheit. Natural gas equivalents are determined
using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil, condensate or
natural gas liquids. As used herein, the following terms have specific meanings:
"Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means
billion cubic feet, "MBbl" means thousand barrels, "MMBbls" means million
barrels, "Mcfe" means thousand cubic feet equivalent, "MMcfe" means million
cubic feet equivalent, "Bcfe" means billion cubic feet equivalent and "MMBtu"
means million British Thermal Units.
With respect to information on the Company's working interest in wells,
drilling locations and acreage, "net" oil and gas wells, drilling locations or
acres are determined by multiplying "gross" oil and gas wells, drilling
locations or acres by the Company's working interest in such wells, drilling
locations or acres.
"Bbl" means barrel, a standard measure of liquid volume for oil, condensate
and natural gas liquids which equals 42 U.S. gallons.
"Capital expenditures" include: costs associated with exploratory and
development drilling (including dry holes); leasehold acquisitions; seismic data
acquisitions; geological, geophysical and land-related overhead expenditures;
delay rentals; producing property acquisitions; and other miscellaneous capital
expenditures.
"3-D seismic" means seismic data that is run, acquired, and processed to
yield a three-dimensional picture of the subsurface.
"Development well" means a well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive.
"Exploratory well" means a well drilled to find commercially productive
hydrocarbons in an unproved area, to find a new productive reservoir or to
extend significantly a known oil or natural gas reservoir.
"Proved developed reserves" are proved reserves that are expected to be
recovered from existing wells (including reserves behind pipe). Proved reserves
are considered developed only after the necessary equipment has been installed,
or when the costs to do so are relatively minor. Developed reserves may be
subcategorized as producing or nonproducing.
"Proved reserves" can be estimated with reasonable certainty to be
recoverable under current economic conditions. Current economic conditions
include prices and costs prevailing at the time of the estimate. Proved reserves
may be developed or undeveloped. In general, reserves are considered proved if
commercial producibility of the reservoir is supported by actual production or
formation tests. Proved reserves must have facilities to process and transport
those reserves to market that are operational at the time of the estimate, or
there is a commitment or reasonable expectation to install such facilities in
the future.
"Reserves" means estimated volumes of oil, condensate, natural gas, natural
gas liquids, and associated substances anticipated to be commercially
recoverable from known accumulations from a given date forward, under existing
economic conditions, by established operating practices, and under current
government regulations. Reserve estimates are based on interpretations of
available geographic geologic and/or engineering data. All reserve estimates
involve some degree of uncertainty, depending chiefly on the amount and
reliability of geologic and engineering data available at the time of the
estimate and the interpretation of these data. The relative degree of
uncertainty may be conveyed by placing reserves in one or two classifications,
either proved or unproved. Unproved reserves are less certain to be recovered
than proved reserves and may be subclassified as probable or possible to denote
progressively increasing uncertainty.
"Royalty" means an interest in an oil and gas lease that gives the owner of
the interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually carved from the leasehold interest
pursuant
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to an assignment to a third party reserved by an owner of the leasehold in
connection with a transfer of the leasehold to a subsequent owner.
"SEC Present Value" refers to a method of determining the present value of
proved reserves promulgated by the Commission. Under the Commission method, the
future net revenues before income taxes from proved reserves are estimated
assuming that oil and natural gas prices and production costs remain constant.
The resulting stream of revenues is then discounted at the rate of 10% per year
to obtain the present value. SEC Present Value does not give effect to
non-property expenses such as general and administrative expenses, debt service
and depreciation, depletion and amortization.
"Working interest" means an interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations. The share of production to which a working interest
owner is entitled will always be smaller than the share of costs that the
working interest owner is required to bear, with the balance of the production
accruing to the owners of royalties. For example, the owner of a 100% working
interest in a lease burdened only by a landowner's royalty of 12.5% would be
required to pay 100% of the costs of a well but would be entitled to retain
87.5% of the production.
92
<PAGE> 94
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
NUMBER
------
<S> <C>
BLAZER ENERGY CORP. AND SUBSIDIARIES
AUDITED ANNUAL CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Auditors............................ F-2
Consolidated Balance Sheets as of September 30, 1995 and
1996................................................... F-3
Statements of Consolidated Income for the Three Years
Ended September 30, 1996............................... F-4
Statements of Consolidated Stockholder's Equity for the
Three Years Ended September 30, 1996................... F-5
Statements of Consolidated Cash Flows for the Three Years
Ended September 30, 1996............................... F-6
Notes to Consolidated Financial Statements................ F-7
BLAZER ENERGY CORP. AND SUBSIDIARIES
UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets as of September 30, 1996 and
December 31, 1996...................................... F-23
Statements of Consolidated Income for the Three Months
Ended December 31, 1995
and 1996............................................... F-24
Statements of Consolidated Stockholder's Equity for the
Three Months Ended December 31, 1995 and 1996.......... F-25
Statements of Consolidated Cash Flows for the Three Months
Ended December 31, 1995 and 1996....................... F-26
Notes to Consolidated Financial Statements................ F-27
</TABLE>
F-1
<PAGE> 95
REPORT OF INDEPENDENT AUDITORS
Board of Directors and Stockholder
Blazer Energy Corp. and Subsidiaries
We have audited the accompanying consolidated balance sheets of Blazer
Energy Corp. (formerly Ashland Exploration, Inc.) and Subsidiaries as of
September 30, 1995 and 1996, and the related statements of consolidated income,
stockholder's equity and cash flows for each of the three years in the period
ended September 30, 1996. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements 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 consolidated financial position of Blazer Energy
Corp. and Subsidiaries at September 30, 1995 and 1996, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended September 30, 1996, in conformity with generally accepted
accounting principles.
As described in Note 1 to the consolidated financial statements, in fiscal
1995 the Company changed its method of accounting relative to impairments of
long-lived assets.
Houston, Texas
November 1, 1996
except for Note 12 as to which the date is
March 4, 1997
ERNST & YOUNG LLP
F-2
<PAGE> 96
BLAZER ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
SEPTEMBER 30,
------------------------
1995 1996
---------- ----------
(IN THOUSANDS)
<S> <C> <C>
Current assets:
Net obligations with affiliated companies (Note 9)........ $ 55,865 $ 90,552
Accounts receivable, less allowance for doubtful accounts
of $197 in 1995 and $249 in 1996....................... 17,544 45,303
Inventories............................................... 23,293 27,602
Prepaids and other current assets......................... 3,182 2,829
---------- ----------
Total current assets.............................. 99,884 166,286
Other assets................................................ 1,585 1,440
Property, plant and equipment, at cost (Note 1):
Oil and gas properties and equipment...................... 984,576 1,049,995
Unproved properties, net of accumulated amortization of
$6,403 in 1995 and $7,291 in 1996...................... 5,852 14,476
Other..................................................... 13,706 14,486
---------- ----------
1,004,134 1,078,957
Accumulated depreciation, depletion and amortization...... 621,825 651,532
---------- ----------
Property, plant and equipment, net.......................... 382,309 427,425
---------- ----------
Total assets...................................... $ 483,778 $ 595,151
========== ==========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Trade accounts payable.................................... $ 35,402 $ 68,026
Income taxes payable...................................... 9,355 9,282
Accrued liabilities....................................... 961 3,399
---------- ----------
Total current liabilities......................... 45,718 80,707
Noncurrent liabilities:
Deferred income (Note 3).................................. 33,022 29,228
Deferred income taxes (Note 2)............................ 32,804 37,242
Other (Note 4)............................................ 38,367 38,746
---------- ----------
Total noncurrent liabilities...................... 104,193 105,216
Commitments and contingencies (Note 5)
Stockholder's equity (Note 12):
Common stock -- $.01 par value, 100,000,000 shares
authorized; 14,400,000 shares issued and outstanding... 144 144
Additional paid-in capital................................ 24,255 24,255
Retained earnings......................................... 309,468 384,829
---------- ----------
Total stockholder's equity........................ 333,867 409,228
---------- ----------
Total liabilities and stockholder's equity........ $ 483,778 $ 595,151
========== ==========
</TABLE>
See accompanying notes.
F-3
<PAGE> 97
BLAZER ENERGY CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
YEAR ENDED SEPTEMBER 30,
--------------------------------
1994 1995 1996
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Revenues:
Sales and operating revenues:
Crude oil.............................................. $109,095 $117,854 $134,505
Natural gas............................................ 83,583 70,901 94,750
Columbia Gas settlement (Note 7).......................... -- -- 73,139
Other (Note 8)............................................ 3,622 1,538 1,677
-------- -------- --------
196,300 190,293 304,071
Cost and expenses:
Operating expenses, including foreign production taxes.... 106,524 106,223 148,077
NORM reclamation/litigation (Note 5)...................... -- -- 3,049
Depreciation, depletion and amortization (Note 1)......... 32,876 41,001 30,978
General and administrative expenses (Note 9).............. 15,048 10,083 16,317
Exploration costs, including dry holes.................... 14,219 38,837 11,649
-------- -------- --------
168,667 196,144 210,070
-------- -------- --------
Operating income (loss)..................................... 27,633 (5,851) 94,001
Interest expense............................................ 709 319 222
-------- -------- --------
Income (loss) before income taxes........................... 26,924 (6,170) 93,779
Income tax expense (benefit) (Note 2)....................... (7,438) (16,089) 18,418
-------- -------- --------
Net income.................................................. $ 34,362 $ 9,919 $ 75,361
======== ======== ========
</TABLE>
See accompanying notes.
F-4
<PAGE> 98
BLAZER ENERGY CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
ADDITIONAL
COMMON PAID-IN RETAINED
STOCK CAPITAL EARNINGS TOTAL
------ ---------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Balance at September 30, 1993........................ $144 $24,255 $265,187 $289,586
Net income......................................... -- -- 34,362 34,362
Deferred translation adjustment.................... -- -- (194) (194)
---- ------- -------- --------
Balance at September 30, 1994........................ 144 24,255 299,355 323,754
Net income......................................... -- -- 9,919 9,919
Deferred translation adjustment.................... -- -- 194 194
---- ------- -------- --------
Balance at September 30, 1995........................ 144 24,255 309,468 333,867
Net income......................................... -- -- 75,361 75,361
---- ------- -------- --------
Balance at September 30, 1996........................ $144 $24,255 $384,829 $409,228
==== ======= ======== ========
</TABLE>
See accompanying notes.
F-5
<PAGE> 99
BLAZER ENERGY CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED SEPTEMBER 30,
---------------------------------
1994 1995 1996
-------- --------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income................................................. $ 34,362 $ 9,919 $ 75,361
Adjustments to reconcile income to net cash provided by
operating activities:
Depreciation, depletion and amortization................. 32,876 41,001 30,978
Impairment of undeveloped leaseholds..................... 2,621 1,199 2,128
Deferred income.......................................... 8,651 13,490 (3,794)
Deferred income taxes.................................... 6,597 (1,525) 4,438
Changes in operating assets and liabilities:
Accounts receivable................................... (806) 14,748 (27,759)
Inventories........................................... 4,289 (3,507) (4,309)
Prepaids and other current assets..................... (5,819) 7,243 353
Trade accounts payable................................ 11,342 (6,558) 32,624
Income taxes payable.................................. (8,623) 8,529 (73)
Accrued liabilities................................... (855) (402) 2,438
Other................................................. 25,657 (25,108) 524
-------- --------- --------
Net cash provided by operating activities.................. 110,292 59,029 112,909
INVESTING ACTIVITIES
Property, plant and equipment:
Additions................................................ (41,102) (113,741) (80,371)
Property disposals....................................... 8,570 796 2,149
-------- --------- --------
Net cash used in investing activities...................... (32,532) (112,945) (78,222)
-------- --------- --------
Increase (decrease) in net obligations with affiliated
companies................................................ $ 77,760 $ (53,916) $ 34,687
======== ========= ========
</TABLE>
See accompanying notes.
F-6
<PAGE> 100
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1996
1. SIGNIFICANT ACCOUNTING POLICIES
Background
The consolidated financial statements of Blazer Energy Corp. (formerly
Ashland Exploration, Inc.) and subsidiaries (the "Company") include all
exploration and production operations of Ashland Inc. ("Ashland"). The Company
is engaged in the exploration for and the development, production, acquisition
and marketing of natural gas and oil in the United States and certain
international regions, primarily Nigeria.
Consolidation
The financial statements include the accounts of Blazer Energy Corp. and
subsidiaries. Significant intercompany accounts and transactions have been
eliminated in consolidation. Consistent with industry practice, the Company
utilizes pro rata consolidation to account for its investment in oil and gas
ventures.
Risk and Uncertainties
The preparation of the Company's consolidated financial statements in
conformity with generally accepted accounting principles requires the Company's
management to make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses and the disclosures of contingent
assets and liabilities. Significant items subject to such estimates and
assumptions include the carrying value of property, plant and equipment and
environmental reserves, among other items. Actual results could differ from the
estimates and assumptions used.
Inventories
Crude oil inventories are stated at current market value. Materials and
supplies inventories are stated at the lower of cost or market. Crude oil
inventories at September 30, 1995 and 1996 were $17,353,000 and $20,038,000,
respectively, and materials and supplies inventories at such dates were
$5,940,000 and $7,564,000, respectively.
Property, Plant and Equipment
The successful efforts method of accounting is followed for costs incurred
in oil and gas exploration and development activities. Property acquisition
costs and exploratory drilling costs for oil and gas properties are initially
capitalized. If and when exploratory wells are determined to be nonproductive,
the related costs are charged to expense. Other exploration costs, including
geological, geophysical and lease rentals, are charged to expense as incurred.
When a property is determined to contain proved reserves, property
acquisition costs and related exploratory drilling costs are transferred to
producing properties. Depreciation, depletion and amortization of producing
properties is computed separately on a field basis using the units-of-production
method.
Other fixed assets include office furniture and fixtures, vehicles and
miscellaneous equipment. These fixed assets are carried at cost and depreciated
using the straight-line method over their estimated useful lives.
Significant unproved properties are periodically evaluated and provision
made for impairment individually. Insignificant properties are amortized to
provide for estimated impairment.
Environmental Costs
Accruals for environmental costs are recognized when it is probable that a
liability has been incurred and the amount of that liability can be reasonably
estimated. Such costs are charged to expense if they are related
F-7
<PAGE> 101
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
to the remediation of conditions caused by past operations, or are not expected
to mitigate or prevent contamination from future operations. Accruals are
recorded at undiscounted amounts based on experience, assessments and current
technology and are regularly adjusted as environmental assessments and
remediation efforts proceed.
Natural Gas Revenues
Natural gas revenues generally are recorded using the sales method, whereby
the Company recognizes natural gas revenues based on the amount of gas sold to
purchasers on its behalf. As of September 30, 1996, the Company did not have any
material gas imbalances.
Crude Oil Revenues
Crude oil revenue is recognized as produced. A portion of such revenue from
international operations is deferred in anticipation of future transition
expenses, demobilization and abandonment costs.
Dismantlement, Removal and Restoration Costs
The estimated costs, net of salvage values, of dismantling and removing
major domestic facilities, including necessary site restoration, are accrued
using the units-of-production method. In the case of facilities where such costs
are not expected to be significant, the net cost is accrued when operations
cease. The Company has fully provided for its net share of estimated
international abandonment costs.
Income Taxes
The Company follows the provisions of Financial Accounting Standards Board
Statement No. 109, Accounting for Income Taxes.
Ashland and its subsidiaries file a consolidated U.S. income tax return to
the extent permitted by the Internal Revenue Code. The consolidated tax
liability or refund is generally allocated to companies in the consolidated
group on the basis of separate return computations. Tax benefits related to
operating losses and certain tax credits shown on Ashland's consolidated return
are allocated to companies in the consolidated group generating such items to
the extent that those tax benefits can be recognized by the consolidated group
for financial reporting purposes.
Ashland monitors its exposure to Internal Revenue Service audits on a
consolidated basis. Any adjustments to previously filed federal returns are
generally not passed to the subsidiaries.
Hedging Activities
The Company selectively uses futures contracts and swaps to reduce price
volatility and lock in favorable sales prices for future production of natural
gas and crude oil. Gains and losses on futures contracts and swaps are deferred
until the related gas or oil production has been produced or delivered. As a
result, gains and losses are generally offset by similar changes in the price of
natural gas and crude oil. Unrealized gains and losses are recorded as assets
and liabilities on the balance sheet at fair market value as of the balance
sheet date. While these instruments are intended to reduce the Company's
exposure to declines in the market price of natural gas and crude oil, they may
also limit the Company's gain from increases in the market price of natural gas
and crude oil. The fair value of these instruments reflects the estimated
amounts the Company would receive or pay to settle the contracts as of the end
of the period.
The futures contracts have settlement guaranteed by the New York Mercantile
Exchange ("NYMEX") and have nominal credit risk. The swap agreements are with
third parties and expose the Company to credit risk to the extent the third
parties are unable to meet their monthly settlement commitment to the Company.
F-8
<PAGE> 102
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company continually monitors the credit standing of the third parties and
anticipates they will be able to satisfy fully their contractual obligations.
At year-end 1994, the Company had 32 open futures contracts for its natural
gas production for November 1994 through April 1995. The Company had 120 open
crude oil futures contracts for November 1994 through November 1995. The
unrealized loss on the natural gas futures contracts and crude oil futures
contracts was not significant.
At year-end 1995, the Company had 172 open futures contracts for its
natural gas production for November 1995 through September 1996. There were no
open future contracts on crude oil or open swap agreements. The unrealized gain
on natural gas futures contracts was not significant.
At year-end 1996, the Company had 250 open futures contracts for its
natural gas production from November 1996 through September 1997. The Company
had 120 open crude oil futures contracts for November 1996 through November
1997. The Company had open swap agreements covering 1,528 contracts. The
unrealized gain on natural gas futures contracts and swap agreements was
$416,000 and $1,718,000, respectively. The unrealized loss on crude oil futures
contracts was not significant.
Concentration of Credit Risk
Substantially all of the Company's receivables are within the oil and gas
industry. Although diversified among several companies, collectibility is
dependent upon the general economic conditions of the industry. To date, this
concentration has not had a material effect on the financial position of the
Company.
Accounting for Stock-Based Compensation Plans
In October 1995 the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123 ("SFAS 123"), Accounting for
Stock-Based Compensation, which established financial accounting and reporting
standards for stock-based employee compensation plans. SFAS 123 encourages
companies to adopt a fair value based method of accounting for such plans but
continues to allow the use of the intrinsic value based method prescribed by
Accounting Principles Board Opinion No. 25 Accounting for Stock Issued to
Employees ("Opinion 25"). Companies electing to continue accounting in
accordance with Opinion 25 must make pro forma disclosures of net income and
earnings per share as if the fair value based method defined in SFAS 123 had
been applied. The Company will account for stock-based compensation in
accordance with Opinion 25 and will make pro forma disclosures in accordance
with the provisions of SFAS 123 in its financial statements.
Accounting Changes
Effective September 30, 1995, the Company adopted Statement of Financial
Accounting Standards Board No. 121 ("SFAS 121"), Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. As a result,
the Company recorded a charge of $4,385,000 (included in depreciation, depletion
and amortization) to write down certain assets to their fair values. Fair values
were based upon appraisals or estimates of discounted future cash flows on a
field basis for oil and gas properties. No provision was made in 1996.
F-9
<PAGE> 103
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
2. INCOME TAXES
A summary of the provision for income tax expense (benefit) follows:
<TABLE>
<CAPTION>
1994 1995 1996
-------- -------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
U.S. current........................................ $(13,918) $(14,373) $14,712
U.S. deferred....................................... 6,597 (1,525) 4,438
Australian current.................................. (117) (191) (732)
-------- -------- -------
$ (7,438) $(16,089) $18,418
======== ======== =======
</TABLE>
Income tax payments amounted to $14,415,000 in 1994, $2,772,000 in 1995 and
$33,840,000 in 1996.
Foreign production taxes for Nigeria are included in operating expenses.
Tax benefits related to operating losses and certain tax credits generated
by the Company have been allocated by Ashland to the Company to the extent that
those tax benefits could be realized by the consolidated group for financial
reporting. Income tax expense for the year ending September 30, 1996, would have
been unchanged on a separate return basis. Income tax benefits in earlier years
would have been reduced had the Company computed its tax provision on a separate
return basis. However, the Company believes that alternative methods were
available (such as the "monetization" of the Section 29 tax credits).
The difference between the United States statutory rate and the Company's
effective income tax rate is reconciled as follows:
<TABLE>
<CAPTION>
1994 1995 1996
------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Income tax (benefit) computed at statutory rates.... $ 9,423 $ (2,160) $ 32,823
Section 29 tax credits.............................. (9,700) (9,500) (10,503)
Net impact of foreign operations.................... (7,062) (3,348) (4,608)
Adjustment to prior year's tax...................... (172) (979) 531
State tax, net of federal tax....................... 64 (143) 137
Other............................................... 9 41 38
------- -------- --------
$(7,438) $(16,089) $ 18,418
======= ======== ========
</TABLE>
Deferred income taxes arise from temporary differences between the tax
basis of assets and liabilities and their reported amounts in the financial
statements. A summary of the components of deferred tax assets and liabilities
are as follows:
<TABLE>
<CAPTION>
1995 1996
------- -------
(IN THOUSANDS)
<S> <C> <C>
Deferred tax liabilities
Intangible drilling costs................................. $36,678 $42,253
Accelerated depreciation.................................. 6,346 7,389
------- -------
Total deferred tax liabilities.............................. 43,024 49,642
Deferred tax assets
Accrued postretirement benefits........................... 4,278 4,099
Basis differences, other than depreciation................ 4,313 4,868
Reserves and accrued liabilities.......................... 1,629 3,433
------- -------
Total deferred tax assets................................... 10,220 12,400
------- -------
Net deferred tax liabilities................................ $32,804 $37,242
======= =======
</TABLE>
F-10
<PAGE> 104
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
3. DEFERRED INCOME
The Company has deferred income from Nigerian operations on OPLs 98/118 to
provide for transitional operating expenses, demobilization and abandonment
costs associated with the support of its international producing activities and
to better match revenue with higher fixed costs associated with the later stages
of economic life of its major, international fields. Such deferred income is
recognized as production continues and costs are incurred. Deferred income is
adjusted prospectively over the remaining life of the producing properties as
the Company's assessment of such operations are periodically (at least annually)
revised. The Company has fully provided for its assessment of the impairment of
associated asset values.
A summary of the Company's producing assets and deferred income follows:
<TABLE>
<CAPTION>
1995 1996
------- -------
(IN THOUSANDS)
<S> <C> <C>
Oil and gas producting properties and equipment, net........ $ 9,119 $31,876
======= =======
Deferred income, net of production taxes.................... $33,022 $29,228
======= =======
</TABLE>
4. OTHER NONCURRENT LIABILITIES
<TABLE>
<CAPTION>
1995 1996
------- -------
(IN THOUSANDS)
<S> <C> <C>
Postretirement benefits..................................... $12,223 $11,711
Deferred foreign production taxes on crude oil inventory.... 14,706 17,014
Plugging and abandonment.................................... 8,512 7,909
State income tax............................................ 643 629
Other....................................................... 2,283 1,483
------- -------
$38,367 $38,746
======= =======
</TABLE>
Nigerian crude oil inventory balance was $17,306,000 in 1995 and
$20,016,000 in 1996.
5. COMMITMENTS AND CONTINGENCIES
The Company is subject to various federal, state and local environmental
laws and regulations which require remediation efforts at multiple locations,
including operating facilities and previously owned or operated facilities.
Environmental reserves are subject to considerable uncertainties which affect
the Company's ability to estimate its share of the ultimate costs of required
remediation efforts. Such uncertainties involve the nature and extent of
contamination at each site, the extent of required cleanup efforts under
existing environmental regulations, widely varying costs of alternate cleanup
methods, changes in environmental regulations, the potential effect of
continuing improvements in remediation technology and the number and financial
strength of other potentially responsible parties at multiparty sites. As a
result, charges to income for environmental liabilities could have a material
effect on results of operations in a particular quarter or fiscal year as
assessments and remediation efforts proceed, revised estimates are made based on
current information or as new remediation sites are identified.
During 1996, the U.S. Environmental Protection Agency and the state of
Kentucky approved the Company's plan of reclamation (including disposal off
site) of naturally occurring radioactive material ("NORM") from the Martha oil
field in Kentucky. The Company's independent contractor began implementing the
NORM reclamation work in September 1996. The Company estimates the total cost of
reclamation to be $4,500,000. At September 30 the Company had an undiscounted
liability of $1,750,000 and $3,550,000 in 1995 and 1996, respectively, for
environmental assessments and reclamation efforts.
F-11
<PAGE> 105
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The liability reflects the Company's most likely estimates of the remaining
costs which will be incurred to remediate the Martha field for which costs are
reasonably estimable. It is reasonably possible that changes in estimates will
occur in the near term. The Company believes it is probable that it will recover
30% of all environmental costs pursuant to settlements with Ashland's insurance
carriers.
In addition to environmental matters, the Company is party to numerous
claims and lawsuits. While these actions are being contested, the outcome of
individual matters is not predictable with assurance. Although any actual
liability is not determinable as of September 30, 1996, the Company believes
that any liability resulting from these matters, after taking into consideration
Ashland's insurance coverages should not have a material adverse effect on the
Company's consolidated financial position.
6. EMPLOYEES' PENSION AND RETIREMENT BENEFITS
Ashland sponsors pension plans which cover substantially all employees,
other than union employees covered by multiemployer pension plans under
collective bargaining agreements. Benefits under Ashland's plans generally are
based on employees' years of service and compensation during the years
immediately preceding their retirement. For certain plans, such benefits are
expected to come in part from one-half of employees' leveraged employee stock
ownership plan ("LESOP") accounts. Ashland determines the level of contributions
to the pension plans annually and contributes amounts within allowable
limitations imposed by Internal Revenue Service regulations. Ashland contributed
the maximum tax-deductible contributions to its pension plans during the last
three years. A discount rate of 8% and an assumed rate of salary increases of 5%
were used in determining the actuarial present value of projected benefit
obligations at September 30, 1996 (7.5% and 5% at September 30, 1995). The
Company's expense related to pension and the LESOP amounted to $1,560,000 in
1994, $1,488,000 in 1995 and $1,512,000 in 1996.
F-12
<PAGE> 106
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following tables detail Ashland's funded status of the plans and the
components of their pension expense.
<TABLE>
<CAPTION>
1995 1996
---------------------------------- ---------------------------------
PLANS WITH ASSETS PLANS WITH ABO PLANS WITH ASSETS PLANS WITH
IN EXCESS IN EXCESS IN EXCESS ABO IN EXCESS
OF ABO OF ASSETS OF ABO OF ASSETS
----------------- -------------- ----------------- -------------
(IN MILLIONS)
<S> <C> <C> <C> <C>
Plan assets at fair value (primarily
listed stocks and bonds)............ $14 $290 $360 $ --
Accumulated benefit obligations (ABO)
Vested.............................. 13 289 284 29
Nonvested........................... 1 69 35 36
--- ---- ------ ----
14 358 319 65
--- ---- ------ ----
Plan assets less than (in excess of)
ABO................................. -- 68(1) (41) 65(1)
Provisions for future salary
increases........................... 1 162 149 17
Deferred pension costs................ (3) (63) (10) (15)
--- ---- ------ ----
Net accrued (prepaid) pension
costs(2)............................ $(2) $167 $ 98 $ 67
=== ==== ====== ====
Components of deferred pension costs
Unrecognized transition gain
(loss)........................... $-- $ 9 $ 10 $ (4)
Unrecognized net loss............... (2) (93) (9) (34)
Unrecognized prior service costs.... (1) (9) (11) (1)
Recognition of minimum liability.... -- 30 -- 24
--- ---- ------ ----
$(3) $(63) $(10) $(15)
=== ==== ====== ====
</TABLE>
<TABLE>
<CAPTION>
1994 1995 1996
-------- -------- --------
<S> <C> <C> <C>
Components of pension expense
Service cost....................................... $ 24 $ 23 $ 32
Interest cost...................................... 29 34 40
Actual investment loss (gain) on plan assets....... 7 (51) (34)
Deferred investment gain (loss)(3)................. (27) 30 6
Other amortization and deferral.................... 4 1 3
Enhanced retirement program pension cost........... -- 15 --
---- ---- ----
$ 37 $ 52 $ 47
==== ==== ====
</TABLE>
- ---------------
(1) Includes unfunded ABO of $62 million in 1995 and $65 million in 1996 for
non-qualified supplemental pension plans.
(2) Amounts are recorded in various asset and liability accounts on Ashland's
consolidated balance sheets.
(3) The expected long-term rate of return on plan assets was 9%.
Ashland sponsors several unfunded benefits plans which provide health care
and life insurance benefits for eligible employees who retire from active
service or are disabled. The health care plans are contributory, with retiree
contributions adjusted periodically, and contain other cost-sharing features
such as deductibles and coinsurance. The life insurance plans are generally
noncontributory. Ashland funds the cost of these plans on a pay-as-you-go basis.
Effective October 1, 1992, Ashland amended nearly all of its retiree health
care plans to place a cap on the company's contributions and to adopt a
cost-sharing method based upon years of service. The cap limits Ashland's
contributions to the 1992 per capita health care costs, increasing thereafter by
up to 4.5% per year.
F-13
<PAGE> 107
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The amendments reduced the accumulated postretirement benefit obligation
("APBO") for retiree health care plans at that date by $197 million, which is
being amortized to income over approximately 12 years.
The APBO was determined using a discount rate of 7.5% at September 30,
1995, and 8% at September 30, 1996. Under the amended plan, the assumed annual
rate of increase in the per capita cost is 4.5%. The following tables detail the
status of Ashland's plans and the components of their postretirement benefit
expense.
<TABLE>
<CAPTION>
1994 1995 1996
------------- ------------- -------------
HEALTH LIFE HEALTH LIFE HEALTH LIFE
------ ---- ------ ---- ------ ----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Accumulated postretirement benefit
obligations (APBO)
Retired or disabled employees............. $146 $26 $130 $25
Fully eligible active plan participants... 33 4 33 5
Other active plan participants............ 123 5 127 5
---- --- ---- ---
302 35 290 35
Unrecognized net gain (loss)................ (2) (4) 28 (2)
Unrecognized plan amendment credit.......... 129 6 112 5
---- --- ---- ---
Accrued other postretirement benefit
costs..................................... $429 $37 $430 $38
==== === ==== ===
Components of other postretirement benefit
expense
Service cost.............................. $ 7 $ 1 $ 12 $ 1 $ 12 $ 1
Interest cost............................. 16 2 20 2 21 3
Amortization and deferral (principally
plan amendment credit)................. (15) (1) (15) (1) (16) (1)
---- --- ---- --- ---- ---
$ 8 $ 2 $ 17 $ 2 $ 17 $ 3
==== === ==== === ==== ===
</TABLE>
Ashland sponsors various savings plans to assist eligible employees in
providing for retirement or other future needs. Ashland matches employee
contributions up to 6% of their qualified earnings at a rate of 70% (20% for
LESOP participants prior to April 1, 1996). The increased company contributions
after March 31, 1996, are in the form of Ashland's common stock. Ashland's
contributions (including the value of common shares contributed to the plans)
amounted to $7 million in 1994, $9 million in 1995 and $15 million in 1996. The
Company's expense related to the plan and administrative fees amounted to
$115,000 in 1994, $125,000 in 1995 and $299,000 in 1996.
7. COLUMBIA GAS SETTLEMENT
During 1995, the Company entered into a settlement agreement with Columbia
Gas Transmission ("Columbia") to resolve claims involving natural gas sales
contracts that were abrogated by Columbia in 1991. The agreement provided for a
$78,500,000 payment to the Company, of which 5% was withheld by Columbia to be
used to potentially satisfy the claims of nonsettling producers. The Company
received the proceeds net of expenses under this agreement in 1996, which
resulted in operating income of $73,139,000. In the event that any portion of
the amount withheld by Columbia is not used to satisfy such nonsettling claims,
the Company and Ashland have agreed that such amount will be paid to Ashland.
8. OTHER REVENUES
The Company purchases third-party natural gas for resale and delivery into
major interstate pipelines. Revenue from these purchases and resales was
$490,000 in 1994, $419,000 in 1995 and $500,000 in 1996.
F-14
<PAGE> 108
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. RELATED PARTY TRANSACTIONS
The Company sells natural gas production to Ashland Petroleum Company and
crude oil production to Scurlock Permian Corp. These companies are wholly owned
subsidiaries of Ashland. Sales to Ashland Petroleum Company were $2,500,000,
$1,800,000 and $2,700,000 for the fiscal years ending 1994, 1995 and 1996,
respectively. Sales to Scurlock Permian Corp. were $1,500,000, $500,000 and
$200,000 for the fiscal years ending 1994, 1995, and 1996, respectively.
Ashland maintains a centralized cash function whereby excess cash is
invested to maximize the return to Ashland. Consequently, cash transactions are
completed by Ashland, with an offsetting intercompany payable or receivable
being recorded. In addition, noncash transactions between the Company and
affiliates are recorded through the utilization of intercompany accounts. This
intercompany balance is classified as current, as Ashland intends to make
payment for balances due within the next year.
Certain administrative services are provided to the Company by Ashland. For
these services, the Company receives an allocation of Ashland's general and
administrative expenses which amounted to $2,262,000 in 1994, $2,384,000 in 1995
and $2,326,000 in 1996. These services include, among others, insurance
administration and certain tax and legal administrative activities. It is
Ashland's policy to charge these expenses and all other central administrative
costs on the basis of direct usage when identifiable. Management of the Company
has determined that this method is reasonable.
10. ACQUISITIONS
In February 1995, the Company acquired certain properties from UMC
Petroleum Corp. for $24,917,000 in cash.
In March 1995, the Company acquired certain properties from Waco Oil & Gas
Co., Inc. for $43,796,000.
11. LEASES AND OTHER COMMITMENTS
The Company is a lessee in noncancelable leasing agreements for office
buildings, an offshore crude oil storage facility and other equipment and
properties which expire at various dates. Rental expense under operating leases
was $11,074,000 in 1994, $12,703,000 in 1995 and $13,614,000 in 1996. Future
minimum rental payments (which escalate over time) at September 30, 1996 follow
(in thousands):
<TABLE>
<S> <C>
1997........................................................ $8,717
1998........................................................ 6,405
1999........................................................ 944
2000........................................................ 1,072
2001........................................................ 1,048
Thereafter.................................................. 3,104
</TABLE>
12. SUBSEQUENT EVENTS
Subsequent to September 30, 1996, and based on actual reclamation work done
during the quarter ended December 31, 1996, the Company reevaluated the NORM
project and estimates the cost of remediation to be $12,000,000. The Company
believes that the remediation will be completed in calendar 1997. In January
1997 the Company made an offer of $10,750,000 to settle all outstanding
litigation related to NORM. The Company believes it is probable that it will
recover 30% of all reclamation and litigation costs pursuant to settlements with
Ashland's insurance carriers.
The Company intends to issue up to 3,565,000 shares of Common Stock in a
public offering in the third fiscal quarter of 1997. Effective March 4, 1997,
the Company effected a 1,440,000 for 1 stock split. The effect
F-15
<PAGE> 109
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
of the stock split has been reflected retroactively in the accompanying
financial statements. The Company's Certificate of Incorporation provides for
one class of Common Stock. This stock is $.01 par, 100,000,000 shares
authorized, 14,400,000 shares issued and outstanding.
The Company has entered into a letter agreement with The Chase Manhattan
Bank ("Chase"), under which prior to consummation of the public offering, the
Company will enter into a $200 million Credit Facility. The Credit Facility will
permit the Company to obtain unsecured revolving credit loans and the issuance
of letters of credit for a five-year period in an aggregate amount not to exceed
$200 million. Commitment availability will be governed by a Borrowing Base, as
defined in the Credit Facility.
The Company has entered into a letter of intent under which it will
monetize its Section 29 tax credits prior to consummation of the public offering
in a transaction under which it will receive (i) cash of approximately $6.5
million, (ii) the right to receive all of the cash flows from the Section 29 tax
credit properties, and (iii) quarterly payments measured by the Section 29 tax
credits generated by the Section 29 tax credit properties. The Company has
historically received credit from Ashland for the face amount of such tax
credits. Under the proposed transaction, the payments received for the value of
the Section 29 tax credits will be taxable as additional sales proceeds.
13. GEOGRAPHIC SEGMENT INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
U.S. INTERNATIONAL TOTAL
-------- ------------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
SEPTEMBER 30, 1994
Revenues.................................................. $ 91,272 $105,028 $196,300
Depreciation, depletion and amortization expense.......... 32,453 423 32,876
Operating income.......................................... 3,785 23,848 27,633
Identifiable assets....................................... 329,751 45,697 375,448
Capital additions......................................... 39,695 1,407 41,102
SEPTEMBER 30, 1995
Revenues.................................................. $ 75,843 $114,450 $190,293
Depreciation, depletion and amortization expense.......... 39,650 1,351 41,001
Operating income (loss)................................... (14,448) 8,597 (5,851)
Identifiable assets....................................... 392,074 35,839 427,913
Capital additions......................................... 104,715 9,026 113,741
SEPTEMBER 30, 1996
Revenues.................................................. $173,319* $130,752 $304,071*
Depreciation, depletion and amortization expense.......... 28,921 2,057 30,978
Operating income.......................................... 81,845* 12,156 94,001*
Identifiable assets....................................... 408,670 95,929 504,599
Capital additions......................................... 45,091 35,280 80,371
</TABLE>
- ---------------
* Includes $73,139 from the Columbia Gas settlement. See Note 7.
F-16
<PAGE> 110
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
QUARTER ENDED
-----------------------------------------
DECEMBER 31, MARCH 31,
------------------- ------------------
1994 1995 1995 1996
------- -------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Revenues........................................... $43,587 $127,183* $44,874 $63,757
Operating income (loss)............................ 11 79,091 (469) 10,410
Net income......................................... 3,401 55,202 1,678 10,452
</TABLE>
<TABLE>
<CAPTION>
QUARTER ENDED
-----------------------------------------
JUNE 30, SEPTEMBER 30,
------------------- ------------------
1995 1996 1995 1996
------- -------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Revenues........................................... $54,450 $ 49,229 $47,382 $63,902
Operating income (loss)............................ (279) 2,011 (5,114) 2,489
Net income......................................... 3,184 4,066 1,656 5,641
</TABLE>
- ---------------
* Includes $73,139 from the Columbia Gas settlement. See Note 7.
15. SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO OIL AND GAS
RESERVES
The following tables summarize discounted future net cash flows and changes
in such flows in accordance with Statement of Financial Accounting Standards
Board No. 69, ("SFAS 69"), Disclosures About Oil and Gas Producing Activities.
Under the guidelines of SFAS 69, estimated future cash flows are determined
based on current prices for crude oil and natural gas, estimated production of
proved crude oil and natural gas reserves, estimated future production and
development costs of those reserves based on current costs and economic
conditions and estimated future income and foreign production taxes based on
taxing arrangements in effect at year-end which include allocation of the full
tax benefit of Section 29 tax credits. Such cash flows are then discounted using
the prescribed 10% rate.
Many other assumptions could have been made which may have resulted in
significantly different estimates. The Company does not rely upon these
estimates in making investment and operating decisions. Furthermore, the Company
does not represent that such estimates are indicative of its expected future
cash flows or the current value of its reserves. Since gas prices utilized in
deriving these estimates are based on conditions that existed at September 30
and are usually different than prices that exist at December 31 due to seasonal
fluctuations in the natural gas market, the estimates may not be comparable to
those of other companies with different fiscal years. Prices can also vary
significantly at the same point in time from year to year due to a variety of
factors. The average gas price used in the discounted future net cash flows
calculations was based on $1.64 per MMBtu at Henry Hub, Louisiana for 1995 and
$1.85 per MMBtu for 1996.
F-17
<PAGE> 111
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Discounted Future Net Cash Flows
<TABLE>
<CAPTION>
U.S. INTERNATIONAL TOTAL
------ ------------- ------
(IN MILLIONS)
<S> <C> <C> <C>
SEPTEMBER 30, 1995
Future cash inflows......................................... $1,060 $ 228 $1,288
Future production (lifting) costs........................... (505) (159) (664)
Future development costs.................................... (58) (16) (74)
Future income and foreign production taxes.................. (33) (33) (66)
------ ----- ------
464 20 484
Annual 10% discount......................................... (212) (3) (215)
------ ----- ------
Standardized measure of discounted future net cash flows.... $ 252 $ 17 $ 269
====== ===== ======
SEPTEMBER 30, 1996
Future cash inflows......................................... $1,273 $ 669 $1,942
Future production (lifting) costs........................... (509) (388) (897)
Future development costs.................................... (55) (46) (101)
Future income and foreign production taxes.................. (116) (193) (309)
------ ----- ------
593 42 635
Annual 10% discount......................................... (304) (9) (313)
------ ----- ------
Standardized measure of discounted future net cash flows.... $ 289 $ 33 $ 322
====== ===== ======
</TABLE>
Changes in Discounted Future Net Cash Flows
<TABLE>
<CAPTION>
YEAR ENDED SEPTEMBER 30,
-------------------------------------------------------------------------------------------
1994 1995 1996
----------------------------- ---------------------------- ----------------------------
U.S. INTERNATIONAL TOTAL U.S. INTERNATIONAL TOTAL U.S. INTERNATIONAL TOTAL
----- ------------- ----- ---- ------------- ----- ---- ------------- -----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Net change due to extensions and
discoveries....................... $ 21 $ -- $ 21 $ 25 $ 6 $ 31 $ 27 $ 101 $ 128
Sales of oil and gas produced -- net
of production (lifting) costs..... (76) (9) (85) (61) (61) (122) (85) (63) (148)
Changes in prices................... (186) (3) (189) 24 24 48 60 20 80
Previously estimated development
costs incurred.................... 24 2 26 7 35 42 22 28 50
Net change due to revisions of
previous estimates of reserves.... (17) 34 17 7 46 53 4 106 110
Purchase (net of sales) of reserves
in place.......................... -- -- -- 40 -- 40 1 -- 1
Accretion of 10% discount........... 31 1 32 20 1 21 25 1 26
Other -- net(1)..................... 33 (11) 22 (9) (40) (49) 10 (54) (44)
Net change in income and foreign
production taxes.................. 59 (13) 46 2 (4) (2) (27) (123) (150)
----- ---- ----- ---- ---- ----- ---- ----- -----
(111) 1 (110) 55 7 62 37 16 53
Discounted future net cash flows at
beginning of year................. 308 9 317 197 10 207 252 17 269
----- ---- ----- ---- ---- ----- ---- ----- -----
Discounted future net cash flows at
end of year....................... $ 197 $ 10 $ 207 $252 $ 17 $ 269 $289 $ 33 $ 322
===== ==== ===== ==== ==== ===== ==== ===== =====
</TABLE>
- ---------------
(1) Includes changes in future production and development costs and changes in
the timing of future production.
F-18
<PAGE> 112
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CRUDE OIL AND NATURAL GAS RESERVES, REVENUES AND COSTS
The following tables summarize the Company's (1) crude oil and natural gas
reserves, (2) results of operations from oil and gas producing and marketing
activities, (3) costs incurred, both capitalized and expensed, in oil and gas
producing activities and (4) capitalized costs for oil and gas producing
activities, along with the related accumulated depreciation, depletion and
amortization. U.S. crude oil and natural gas reserves are reported net of
royalties and interests owned by others. International crude oil reserves relate
to reserves available to the Company, as producer, under a long-term contract
with the Nigerian National Petroleum Corporation ("NNPC").
Reserves reported in the table are estimated and are subject to future
revisions. Since October 1, 1995, no estimates of the Company's total proved net
oil or gas reserves have been filed or included in reports to any federal
authority or agency other than the Securities and Exchange Commission. Crude oil
reserves of 32.2 MMBbls at September 30, 1996 are as estimated by Netherland
Sewell. Such reserves are 10.7 MMBbls greater than the amount previously
reported as of such date in filings made with the Securities and Exchange
Commission (the "Commission") by Ashland, the amounts included in such filings
being derived from a Company-generated reserve report prior to the availability
of an estimate from Netherland Sewell.
Crude Oil and Natural Gas Reserves
<TABLE>
<CAPTION>
YEAR ENDED SEPTEMBER 30,
------------------------------------------------------------------------------------------
1994 1995 1996
---------------------------- ---------------------------- ----------------------------
U.S. INTERNATIONAL TOTAL U.S. INTERNATIONAL TOTAL U.S. INTERNATIONAL TOTAL
---- ------------- ----- ---- ------------- ----- ---- ------------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
CRUDE OIL RESERVES (MMBBLS)
Proved developed and undeveloped
reserves:
Beginning of year................. 1.4 7.7 9.1 0.9 7.6 8.5 1.3 14.4 15.7
Revisions of previous estimates... (0.1) 6.7 6.6 0.2 12.3 12.5 0.4 12.6 13.0
Extensions and discoveries........ -- -- -- -- 1.4 1.4 -- 10.0 10.0
Production........................ (0.1) (6.8) (6.9) (0.2) (6.9) (7.1) (0.2) (6.4) (6.6)
Net purchases (sales) of reserves
in place........................ (0.3) -- (0.3) 0.4 -- 0.4 0.1 -- 0.1
---- --- ---- ---- --- ---- ---- --- ----
End of year....................... 0.9 7.6 8.5 1.3 14.4 15.7 1.6 30.6 32.2
==== === ==== ==== === ==== ==== === ====
Proved developed reserves at
beginning of year................. 1.3 7.7 9.0 0.9 7.6 8.5 1.3 14.4 15.7
Proved developed reserves at end of
year.............................. 0.9 7.6 8.5 1.3 14.4 15.7 1.6 26.6 28.2
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED SEPTEMBER 30,
-------------------------
1994 1995 1996
----- ----- -----
<S> <C> <C> <C>
UNITED STATES -- NATURAL GAS RESERVES (BCF)
Proved developed and undeveloped reserves:
Beginning of year......................................... 455.5 349.2 507.4
Revisions of previous estimates........................... (98.2) 90.7 37.6
Extensions and discoveries................................ 25.9 21.2 70.0
Production................................................ (34.4) (37.5) (39.7)
Purchase (net of sales) of reserves in place.............. 0.4 83.8 1.6
----- ----- -----
End of year............................................... 349.2 507.4 576.9
===== ===== =====
Proved developed reserves at beginning of year.............. 352.0 320.5 427.3
Proved developed reserves at end of year.................... 320.5 427.3 477.0
</TABLE>
F-19
<PAGE> 113
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
YEAR ENDED SEPTEMBER 30,
---------------------------------------------------------------------------------------------
1994 1995 1996
---------------------------- ----------------------------- ------------------------------
U.S. INTERNATIONAL TOTAL U.S. INTERNATIONAL TOTAL U.S. INTERNATIONAL TOTAL
---- ------------- ----- ----- ------------- ----- ----- ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
RESULTS OF OPERATIONS
Revenues
Sales to third parties........ $ 96 $ 99 $ 195 $ 86 $110 $ 196 $ 112 $ 126 $ 238
Intersegment sales............ 4 -- 4 2 -- 2 3 -- 3
---- ---- ----- ----- ---- ----- ----- ----- ------
100 99 199 88 110 198 115 126 241
Costs and expenses
Production (lifting) costs.... (24) (90) (114) (27) (49) (76) (30) (64) (94)
Exploration expenses.......... (13) (1) (14) (11) (27) (38) (9) -- (9)
Depreciation, depletion,
amortization, and valuation
provisions.................. (34) (1) (35) (41) (1) (42) (34) (2) (36)
Other costs..................... (25) (2) (27) (24) (1) (25) 40 (1) 39
Income and foreign production
taxes......................... 7 19 26 16 (23) (7) (19) (46) (65)
---- ---- ----- ----- ---- ----- ----- ----- ------
$ 11 $ 24 $ 35 $ 1 $ 9 $ 10 $ 63 $ 13 $ 76
==== ==== ===== ===== ==== ===== ===== ===== ======
COSTS INCURRED
Property acquisition costs:
Proved...................... $ 1 $ -- $ 1 $ 69 $ -- $ 69 $ 2 $ -- $ 2
Unproved.................... 2 -- 2 2 -- 2 5 -- 5
Exploration costs............. 19 1 20 17 31 48 13 12 25
Development costs............. 32 2 34 30 10 40 35 28 63
CAPITALIZED COSTS
Proved properties............... $ 584 $400 $ 984 $ 624 $ 426 $1,050
Unproved properties............. 11 1 12 13 10 23
----- ---- ----- ----- ----- ------
595 401 996 637 436 1,073
Accumulated depreciation,
depletion and amortization.... (226) (392) (618) (254) (393) (647)
----- ---- ----- ----- ----- ------
$ 369 $ 9 $ 378 $ 383 $ 43 $ 426
===== ==== ===== ===== ===== ======
</TABLE>
NET OIL AND GAS PRODUCTION
The following table summarizes net oil and gas production (net after
royalty) for each of the three fiscal years ended September 30.
<TABLE>
<CAPTION>
1994 1995 1996
------ ------ ------
<S> <C> <C> <C>
Net natural gas production (MMcf per day):
United States.......................................... 94 103 109
Net crude oil production (Bbls per day):
United States.......................................... 822 609 564
International(1)....................................... 18,707 18,791 17,520
------ ------ ------
Total net crude oil production................. 19,529 19,400 18,084
====== ====== ======
</TABLE>
- ---------------
(1) Net production is before royalty.
F-20
<PAGE> 114
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
AVERAGE SALES PRICE AND PRODUCTION COST
The Company's average sales price per unit and production cost per unit for
crude oil and natural gas for each of the three fiscal years ended September 30
are set forth in the table below.
<TABLE>
<CAPTION>
1994 1995 1996
------ ------ ------
<S> <C> <C> <C>
Average sales prices -- natural gas (per Mcf):
United States.......................................... $ 2.42 $ 1.89 $ 2.39
Average sales prices -- crude oil (per Bbl):
United States.......................................... $14.29 $15.96 $18.22
International.......................................... 15.01 16.17 18.46
Average production cost(1):
United States (per Mcfe)............................... $ 0.48 $ 0.51 $ 0.47
International (per Bbl)................................ 4.83 5.02 5.63
</TABLE>
- ---------------
(1) Equivalents computed on a six Mcf to one Bbl ratio.
GROSS AND NET PRODUCTIVE WELLS
The following table sets forth the Company's gross and net productive
wells.
<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
------------------
GROSS NET
------ ------
<S> <C> <C>
Productive wells -- Gas:
United States............................................. 4,211 3,836
Productive wells -- Oil:
United States............................................. 36 22
International............................................. 36 36
----- -----
Total productive wells -- Oil..................... 72 58
===== =====
</TABLE>
These wells include 331 gross wells (317 domestic and 14 international) and
293 net wells (279 domestic and 14 international) at September 30, 1996, which
have multiple completions.
TOTAL GROSS AND NET OIL AND GAS PRODUCING AND UNDEVELOPED ACREAGE
The Company's major interests consist of producing and nonproducing working
interests located in the Appalachian and Gulf Coast areas, as well as royalty
interests located primarily in the Southwest and Midcontinent areas of the
United States. The Company has crude oil production in Nigeria from 103,000
acres onshore and 74,000 acres offshore held under a production-sharing contract
with the NNPC, the Nigerian state-owned petroleum company. In addition, the
Company is also conducting exploratory efforts on two additional offshore blocks
comprising a contract area of approximately 450,000 gross acres under another
production-sharing contract with NNPC. The following table sets forth the
Company's total gross and net oil and gas producing and undeveloped acreage:
<TABLE>
<CAPTION>
GROSS NET GROSS NET
PRODUCING PRODUCING UNDEVELOPED UNDEVELOPED
ACREAGE ACREAGE ACREAGE ACREAGE
--------- --------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Acreage:
United States....................... 1,263 936 748 410
International....................... 177 177 1,375 540
----- ----- ----- -----
Total....................... 1,440 1,113 2,123 950
===== ===== ===== =====
</TABLE>
F-21
<PAGE> 115
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Net Productive and Dry Wells Drilled
The Company's net productive and dry wells drilled during each of the three
fiscal years ended September 30 are set forth below.
<TABLE>
<CAPTION>
1994 1995 1996
---- ---- ----
<S> <C> <C> <C>
Net exploratory wells drilled -- United States:
Net productive wells...................................... 2 2 1
Net dry wells............................................. 4 5 1
--- --- ---
Total............................................. 6 7 2
=== === ===
Net exploratory wells drilled -- International:
Net productive wells...................................... 1 1 2
Net dry wells............................................. 1 2 --
--- --- ---
Total............................................. 2 3 2
=== === ===
Net development wells drilled:
Net productive wells:
United States.......................................... 59 88 79
International.......................................... -- -- 3
--- --- ---
Total............................................. 59 88 82
=== === ===
Net dry wells:
United States.......................................... 1 -- --
International.......................................... -- -- --
--- --- ---
Total............................................. 1 -- --
=== === ===
</TABLE>
F-22
<PAGE> 116
BLAZER ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1996 1996
------------- ------------
(IN THOUSANDS)
<S> <C> <C>
ASSETS
Current assets:
Net obligations with affiliated companies................. $ 90,552 $ 15,439
Accounts receivable, less allowance for doubtful accounts
of $249 in September and December...................... 45,303 44,577
Inventories............................................... 27,602 25,464
Prepaids and other current assets......................... 2,829 5,406
---------- ----------
Total current assets.............................. 166,286 90,886
Other assets................................................ 1,440 8,356
Property, plant and equipment, at cost:
Oil and gas properties and equipment...................... 1,049,995 1,062,136
Unproved properties, net of accumulated amortization of
$7,291 in September and $6,147 in December............. 14,476 16,426
Other..................................................... 14,486 14,802
---------- ----------
1,078,957 1,093,364
Accumulated depreciation, depletion and amortization...... 651,532 659,395
---------- ----------
Property, plant and equipment, net.......................... 427,425 433,969
---------- ----------
Total assets...................................... $ 595,151 $ 533,211
========== ==========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Trade accounts payable.................................... $ 68,026 $ 42,369
Income taxes payable...................................... 9,282 7,481
Accrued liabilities.................................... 3,399 3,228
---------- ----------
Total current liabilities......................... 80,707 53,078
Noncurrent liabilities:
Deferred income........................................ 29,228 31,715
Deferred income taxes.................................. 37,242 36,505
Other.................................................. 38,746 52,515
---------- ----------
Total noncurrent liabilities...................... 105,216 120,735
Commitments and contingencies
Stockholder's equity:
Common stock -- $.01 par value, 100,000,000 shares
authorized; 14,400,000 shares issued and
outstanding........................................... 144 144
Additional paid-in capital............................. 24,255 24,255
Retained earnings...................................... 384,829 334,999
---------- ----------
Total stockholder's equity........................ 409,228 359,398
---------- ----------
Total liabilities and stockholder's equity........ $ 595,151 $ 533,211
========== ==========
</TABLE>
F-23
<PAGE> 117
BLAZER ENERGY CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
DECEMBER 31,
--------------------
1995 1996
-------- -------
(IN THOUSANDS)
<S> <C> <C>
Revenues:
Sales and operating revenues:
Crude oil.............................................. $ 31,468 $41,452
Natural gas............................................ 21,971 31,173
Columbia Gas settlement................................... 73,139 --
Other..................................................... 605 649
-------- -------
127,183 73,274
Cost and expenses:
Operating expenses, net of foreign production taxes....... 34,208 35,120
NORM reclamation/litigation (Note 2)...................... -- 11,126
Depreciation, depletion and amortization.................. 7,983 7,933
General and administrative expenses....................... 4,571 4,098
Exploration costs, including dry holes.................... 1,330 10,356
-------- -------
48,092 68,633
-------- -------
Operating income............................................ 79,091 4,641
Interest expense............................................ 54 53
-------- -------
Income before income taxes.................................. 79,037 4,588
Income tax expense (benefit) (Note 3):...................... 23,835 (1,720)
-------- -------
Net income.................................................. $ 55,202 $ 6,308
======== =======
</TABLE>
F-24
<PAGE> 118
BLAZER ENERGY CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDER'S EQUITY
(UNAUDITED)
<TABLE>
<CAPTION>
ADDITIONAL
COMMON PAID-IN RETAINED
STOCK CAPITAL EARNINGS TOTAL
------ ---------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Beginning balance................................ $144 $24,255 $309,468 $333,867
Net income..................................... -- -- 55,202 55,202
---- ------- -------- --------
Balance at December 31, 1995..................... $144 $24,255 $364,670 $389,069
==== ======= ======== ========
Beginning balance................................ $144 $24,255 $384,829 $409,228
Net income.................................. -- -- 6,308 6,308
Intercompany dividend....................... -- (56,138) (56,138)
---- ------- -------- --------
Balance at December 31, 1996..................... $144 $24,255 $334,999 $359,398
==== ======= ======== ========
</TABLE>
F-25
<PAGE> 119
BLAZER ENERGY CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
DECEMBER 31,
--------------------
1995 1996
------- --------
(IN THOUSANDS)
<S> <C> <C>
OPERATING ACTIVITIES
Net income.................................................. $55,202 $ 6,308
Adjustments to reconcile income to net cash provided by
operating activities:
Depreciation, depletion and amortization.................. 7,983 7,933
Impairment expense........................................ 501 120
Deferred income........................................... 2,054 2,487
Deferred income taxes..................................... 514 (737)
Changes in operating assets and liabilities:
Accounts receivable.................................... (32,457) 726
Inventories............................................ (2,544) 2,138
Prepaids and other current assets...................... (19) (2,577)
Trade accounts payable................................. (7,035) (25,657)
Income taxes payable................................... (2,537) (1,801)
Accrued liabilities.................................... 2,388 (171)
Other.................................................. 4,976 6,853
------- --------
Net cash provided by (used for) operating activities........ 29,026 (4,378)
FINANCING ACTIVITIES
Intercompany dividends...................................... -- (56,138)
------- --------
Net cash used in financing activities....................... -- (56,138)
INVESTING ACTIVITIES
Property, plant and equipment:
Additions................................................. (8,097) (15,249)
Property disposals........................................ 166 652
------- --------
Net cash used in investing activities....................... (7,931) (14,597)
------- --------
Increase (decrease) in net obligations with affiliated
companies................................................. $21,095 $(75,113)
======= ========
</TABLE>
F-26
<PAGE> 120
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. SIGNIFICANT ACCOUNTING POLICIES
Background
The consolidated financial statements of Blazer Energy Corp. (formerly
Ashland Exploration, Inc.) and subsidiaries (the Company) include all
exploration and production operations of Ashland Inc. (Ashland). The Company is
engaged in the exploration for and the development, production acquisition and
marketing of natural gas and oil in the United States and certain international
regions, primarily Nigeria.
Consolidation
The financial statements include the accounts of Blazer Energy Corp. and
its subsidiaries. Significant intercompany accounts and transactions have been
eliminated in consolidation. Consistent with industry practice, the Company
utilizes pro rata consolidation to account for its investment in oil and gas
ventures.
Risk and Uncertainties
The preparation of the Company's consolidated financial statements in
conformity with generally accepted accounting principles requires the Company's
management to make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses and the disclosures of contingent
assets and liabilities. Significant items subject to such estimates and
assumptions include the carrying value of property, plant and equipment and
environmental reserves, among other items. Actual results could differ from the
estimates and assumptions used.
The unaudited financial statements of the Company, in the opinion of
management, present fairly the Company's financial position at December 31, 1996
and the Company's results of operations and cash flows for the three-month
periods ended December 31, 1995 and 1996. Interim period results are not
necessarily indicative of results of operations or cash flows for a full-year
period.
These financial statements and the notes thereto should be read in
conjunction with the Company's audited financial statements included elsewhere
in this prospectus.
Hedging Activities
The Company selectively uses futures contracts and swaps to reduce price
volatility and lock in favorable sales prices for future production of natural
gas and crude oil. Gains and losses on futures contracts and swaps are deferred
until the related gas or oil production has been produced or delivered. As a
result, gains and losses are generally offset by similar changes in the price of
natural gas and crude oil. Unrealized gains and losses are recorded as assets
and liabilities on the balance sheet at fair market value as of the balance
sheet date. While these instruments are intended to reduce the Company's
exposure to declines in the market price of natural gas and crude oil, they may
also limit the Company's gain from increases in the market price of natural gas
and crude oil. The fair value of these instruments reflects the estimated
amounts the Company would receive or pay to settle the contracts as of December
31.
The futures contracts have settlement guaranteed by the New York Mercantile
Exchange (NYMEX) and have nominal credit risk. The swap agreements are with
third parties and expose the Company to credit risk to the extent the third
parties are unable to meet their monthly settlement commitment to the Company.
The Company continually monitors the credit standing of the third parties and
anticipates they will be able to fully satisfy their contractual obligations.
At December 31, 1996, the Company had 2,358 open futures contracts for its
natural gas production for February 1997 through September 1997. The Company had
90 open crude oil futures contracts for
F-27
<PAGE> 121
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
February 1997 through November 1997. The unrealized loss on the natural gas
futures contracts and crude oil futures contracts was $534,000 and $251,000,
respectively.
2. NORM RECLAMATION AND RELATED LIABILITIES
Based on actual reclamation work done during the quarter ended December 31,
1996, the Company reevaluated the NORM project and estimates the cost of
remediation to be $12,000,000 and all remaining amounts to be expended based on
such estimates have been accrued. The Company believes that the remediation will
be completed in calendar 1997. In addition, in January 1997 the Company made an
offer of $10,750,000 to settle all outstanding litigation related to NORM. The
Company believes it is probable that it will recover 30% of all reclamation and
litigation costs pursuant to settlements with Ashland's insurance carriers.
3. INCOME TAX PROVISIONS
Income tax expenses have been computed on an interim based on estimated
effective rates for the entire year. Tax benefits of certain tax credits have
been allocated by Ashland to the Company to the extent that those tax credits
could be realized by the consolidated group for financial reporting. Income tax
expense for the period ended December 31, 1995 would have been unchanged if on a
separate return basis. Although other alternative tax planning strategies may
have been available to the Company, book income would not have been sufficient
to assure realization on a separate return basis for the period ended December
31, 1996.
The Company believes that the appropriate measure for its separate return
basis tax expense for such period, given the available tax planning strategies,
is to use the approximate pro forma effect of the anticipated monetization of
Section 29 tax credits. Such sale would have reduced net earnings by
approximately $1,295,000 to $5,013,000.
4. SUBSEQUENT EVENTS
Subsequent to September 30, 1996, and based on actual reclamation work done
during the quarter ended December 31, 1996, the Company reevaluated the NORM
project and estimates the cost of remediation to be $12,000,000. The Company
believes that the remediation will be completed in calendar 1997. In January
1997 the Company made an offer of $10,750,000 to settle all outstanding
litigation related to NORM. The Company believes it is probable that it will
recover 30% of all reclamation and litigation costs pursuant to settlements with
Ashland's insurance carriers.
The Company intends to issue up to 3,565,000 shares of Common Stock in a
public offering in the third fiscal quarter of 1997. Effective March 4, 1997,
the Company effected a 1,440,000 for 1 stock split. The effect of the stock
split has been reflected retroactively in the accompanying financial statements.
The Company's Certificate of Incorporation provides for one class of Common
Stock. This stock is $.01 par, 100,000,000 shares authorized, 14,400,000 shares
issued and outstanding.
The Company has entered into a letter agreement with The Chase Manhattan
Bank ("Chase"), under which prior to consummation of the public offering, the
Company will enter into a $200 million Credit Facility. The Credit Facility will
permit the Company to obtain unsecured revolving credit loans and the issuance
of letters of credit for a five-year period in an aggregate amount not to exceed
$200 million. Commitment availability will be governed by a Borrowing Base, as
defined in the Credit Facility.
F-28
<PAGE> 122
BLAZER ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
The Company has entered into a letter of intent under which it will
monetize its Section 29 tax credits prior to consummation of the public offering
in a transaction under which it will receive (i) cash of approximately $6.5
million, (ii) the right to receive all of the cash flows from the Section 29 tax
credit properties, and (iii) quarterly payments measured by the Section 29 tax
credits generated by the Section 29 tax credit properties. The Company has
historically received credit from Ashland for the face amount of such tax
credits. Under the proposed transaction, the payments received for the value of
the Section 29 tax credits will be taxable as additional sales proceeds.
F-29
<PAGE> 123
ANNEX A
[LETTERHEAD OF NETHERLAND, SEWELL & ASSOCIATES, INC.]
December 9, 1996
Mr. Larry J. Williams
Ashland Exploration, Inc.
14701 St. Mary's Lane, Suite 200
Houston, Texas 77079-2907
Dear Mr. Williams:
In accordance with your request, we have estimated the proved and
probable reserves and future revenue, as of October 1, 1996, to the Ashland
Exploration, Inc. (Ashland) interest in certain oil and gas properties located
in the United States as listed in the accompanying tabulations. This report
has been prepared using constant prices and costs. For the proved reserves,
this report conforms to the guidelines of the Securities and Exchange
Commission (SEC). However, inasmuch as the SEC does not recognize probable
reserves, the sections of this report dealing with such probable reserves
should not be used in filings with the SEC.
As presented in the accompanying summary projections, Tables I through
V, we estimate the net reserves and future net revenue to the Ashland interest,
as of October 1, 1996, to be:
<TABLE>
<CAPTION>
Net Reserves Future Net Revenue
------------------------------- ----------------------------------
Oil Gas Present Worth
Category (Barrels) (MCF) Total at 10%
- ----------------------- ----------- ------------ ------------ ---------------
<S> <C> <C> <C> <C>
Proved Developed
Producing 1,556,627 465,035,737 $560,995,900 $ 267,060,200
Non-Producing 53,319 11,922,803 16,990,700 9,951,200
Proved Undeveloped 27,344 99,926,308 130,211,600 39,942,500
----------- ----------- ------------ ---------------
Total Proved 1,637,290 576,884,848 $708,198,200 $ 316,953,900
Probable(1) 5,144 28,929,078 $37,454,100 $ 19,706,100
</TABLE>
(1) These reserves and future revenue are not risk weighted. Not included are
44,024,455 MCF of Eastern Region probable net gas reserves that are
uneconomic or marginal at current gas prices but become economic at
moderately higher gas prices.
The estimates shown in the previous table include no deductions for
federal income taxes and, as such, do not include the effect of the Section 29
nonconventional fuels federal income tax credit. However, many gas wells in
Ashland's Eastern Region qualify for the Section 29 tax credit based on
classification as either Devonian Shale gas producers or tight gas sand
producers. The
A-1
<PAGE> 124
Section 29 tax credit is currently $1.0055 per MMBTU for Devonian Shale gas
production and $0.5172 per MMBTU for tight gas sand production. Estimated
future net revenue for the Section 29 tax credit attributable to Eastern Region
gas wells is $48,425,200 for proved developed producing reserves and $501,100
for proved developed non-producing reserves. The present worth discounted at
10 percent of the Section 29 tax credit is estimated to be $37,106,500 for
proved developed producing reserves and $364,600 for proved developed
non-producing reserves. Wells qualifying for the Section 29 tax credit were
identified by Ashland and were not independently verified.
In view of the significant economic impact of the Section 29 tax
credit, this report also presents summary projections including the effect of
the Section 29 tax credit for estimated future gas production. Therefore, as
presented in the accompanying summary projections, Tables VI through X, we
estimate the net reserves and future net revenue to the Ashland interest, as of
October 1, 1996, including the effect of the Section 29 tax credit, to be:
<TABLE>
<CAPTION>
Net Reserves Future Net Revenue
-------------------------------------------------------------------------
Oil Gas Present Worth
Category (Barrels) (MCF) Total at 10%
- ----------------------- ----------- ------------- -------------- ---------------
<S> <C> <C> <C> <C>
Proved Developed
Producing 1,556,627 465,035,737 $609,421,100 $ 304,166,700
Non-Producing 53,319 11,922,803 17,491,800 10,315,800
Proved Undeveloped 27,344 99,926,308 130,211,600 39,942,500
----------- ------------ -------------- ---------------
Total Proved 1,637,290 576,884,848 $757,124,500 $ 354,425,000
Probable(1) 5,144 28,929,078 $37,454,100 $ 19,706,100
</TABLE>
(1) These reserves and future revenue are not risk weighted. Not included are
44,024,455 MCF of Eastern Region probable net gas reserves that are
uneconomic or marginal at current gas prices but become economic at
moderately higher gas prices.
The oil reserves shown include crude oil and condensate. Oil volumes
are expressed in barrels which are equivalent to 42 United States gallons. Gas
volumes are expressed in thousands of standard cubic feet (MCF) at the contract
temperature and pressure bases.
As shown in the Table of Contents, this report includes summary
projections of reserves and revenue by reserve category both excluding and
including the effect of the Section 29 tax credit. Summary projections of
reserves and revenue by reserve category are also included for each region and
for the Section 29 tax credit. One-line summaries of reserves and economics by
field are presented for each region. For the purposes of this report, the term
"lease" refers to a single economic projection.
The estimated reserves and future revenue shown in this report are for
proved developed producing, proved developed non-producing, proved undeveloped,
and probable reserves. Certain
A-2
<PAGE> 125
Eastern Region probable undeveloped locations evaluated were found to be
uneconomic or marginal at current gas prices but would become economic at
moderately higher gas prices. The net gas reserves from these currently
uneconomic locations, as of October 1, 1996, are estimated to be 21,696,871 MCF
for 84 wells in the Danville District, 17,606,324 MCF for 99 wells in the
Pikeville District, and 4,721,260 MCF for 23 wells in the Weston District.
Approximately 12,238,824 MCF of the aforementioned uneconomic reserves are
associated with 57 locations acquired from OXY USA Inc. Our estimates do not
include any value for possible reserves, although we have conducted a limited
study of the Eastern Region properties which indicates the existence of
numerous possible undeveloped locations. This report does not include any
value which could be attributed to interests in undeveloped acreage beyond
those tracts for which undeveloped reserves have been estimated. The table
following this letter sets forth our estimates of reserves and future net
revenue, by category, to the Ashland interest for each region.
Future gross revenue to the Ashland interest is prior to deducting
state production taxes and ad valorem taxes. Future net revenue is after
deducting these taxes, future capital costs, and operating expenses, but before
consideration of federal income taxes; future net revenue for the offshore
properties is also after deducting abandonment costs. As discussed in this
report, estimates are included for the effect of the Section 29 tax credit. In
accordance with SEC guidelines, the future net revenue has been discounted at
an annual rate of 10 percent to determine its "present worth." The present
worth is shown to indicate the effect of time on the value of money and should
not be construed as being the fair market value of the properties.
For the purposes of this report, a field inspection of the properties
has not been performed nor has the mechanical operation or condition of the
wells and their related facilities been examined. We have not investigated
possible environmental liability related to the properties; therefore, our
estimates do not include any costs which may be incurred due to such possible
liability. Our estimates of future revenue do not include any salvage value
for the lease and well equipment nor the cost of abandoning the onshore
properties. Future revenue estimates for offshore properties also do not
include any salvage value for the lease and well equipment, but do include
Ashland's estimate of the costs to abandon the wells, platforms, and production
facilities. Abandonment costs for offshore properties are included with other
capital investments.
Oil prices used in this report are based on a September 1996 West
Texas Intermediate posted price of $22.75 per barrel, adjusted by field for
gravity, transportation fees, and regional posted price differentials. Gas
prices used in this report are based on either the most current price available
for each lease or the contract price. Oil and gas prices are held constant in
accordance with SEC guidelines.
Lease and well operating costs are based on operating expense records
of Ashland. These costs include the per-well overhead expenses allowed under
joint operating agreements along with costs estimated to be incurred at and
below the district and field levels. Headquarters general and administrative
overhead expenses of Ashland are not included. For the Eastern Region, the
district level operating costs are aggregated and projected separately for each
district. Lease and well operating costs are held constant in accordance with
SEC guidelines. Capital costs are included as required for workovers, new
development wells, and production equipment.
A-3
<PAGE> 126
Ashland owns royalty interests in various properties which are
included in the Royalty Region section of this report. Estimates of reserves
and future net revenue for these properties are based on composite projections
of historical net oil and gas sales volumes by geographic region with major
value royalty properties evaluated individually.
We have made no investigation of potential gas volume and value
imbalances which may have resulted from overdelivery or underdelivery to the
Ashland interest. Therefore, our estimates of reserves and future revenue do
not include adjustments for the settlement of any such imbalances; our
projections are based on Ashland receiving its net revenue interest share of
estimated future gross gas production.
The reserves included in this report are estimates only and should not
be construed as exact quantities. They may or may not be actually recovered;
if recovered, the revenues therefrom and the costs related thereto could be
more or less than the estimated amounts. The sales rates, prices received for
the reserves, and costs incurred in recovering such reserves may vary from
assumptions included in this report due to governmental policies and
uncertainties of supply and demand. Also, estimates of reserves may increase
or decrease as a result of future operations.
In evaluating the information at our disposal concerning this report,
we have excluded from our consideration all matters as to which legal or
accounting, rather than engineering and geological, interpretation may be
controlling. As in all aspects of oil and gas evaluation, there are
uncertainties inherent in the interpretation of engineering and geological
data; therefore, our conclusions necessarily represent only informed
professional judgments.
The titles to the properties have not been examined by Netherland,
Sewell & Associates, Inc., nor has the actual degree or type of interest owned
been independently confirmed. The data used in our estimates were obtained
from Ashland Exploration, Inc., other interest owners, various operators of the
properties, and the nonconfidential files of Netherland, Sewell & Associates,
Inc. and were accepted as accurate. We are independent petroleum engineers,
geologists and geophysicists; we do not own an interest in these properties and
are not employed on a contingent basis. Basic geologic and field performance
data together with our engineering work sheets are maintained on file in our
office.
Very truly yours,
/s/ CLARENCE M. NETHERLAND
--------------------------
CLARENCE M. NETHERLAND
A-4
<PAGE> 127
[LETTERHEAD OF NETHERLAND, SEWELL & ASSOCIATES, INC.]
February 20, 1997
Mr. Larry J. Williams
Ashland Exploration, Inc.
14701 St. Mary's Lane, Suite 200
Houston, Texas 77079-2907
Dear Mr. Williams:
In accordance with your request, we have estimated the proved and
probable reserves and future revenue, as of October 1, 1996, to the Ashland Oil
(Nigeria) Company Unlimited (herein referred to as "Ashland") interest in 7 oil
fields in Oil Prospecting License (OPL) 98 and 2 oil fields in OPL 118 located
in the Niger Basin, Nigeria, as listed in the accompanying tabulations. This
report has been prepared using constant prices and costs. For the proved
reserves, this report conforms to the guidelines of the Securities and Exchange
Commission (SEC). However, inasmuch as the SEC does not recognize probable
reserves, the sections of this report dealing with such probable reserves
should not be used in filings with the SEC. All prices, costs, and revenue
estimates are expressed in United States dollars ($).
As presented in the accompanying summary projections, Tables I through
VIII, we estimate the gross reserves and future net revenue to the Ashland
interest in OPL 98 and OPL 118, as of October 1, 1996, to be:
<TABLE>
<CAPTION>
Gross Reserves Future Net Revenue ($)
--------------------------- ------------------------------------
Oil Gas Present Worth
Category (Barrels) (MCF) Total at 10%
- ------------------------ ------------- ------ -------------- --------------
<S> <C> <C> <C> <C>
Proved Developed
Producing 23,716,508 0 288,444,500 239,242,500
Non-Producing 2,921,604 0 46,409,500 31,873,500
Proved Undeveloped 4,005,853 0 36,672,400 22,292,700
Proved Govt. Take 0 0 (329,833,500) (259,880,300)
------------- ------ -------------- --------------
Total Proved 30,643,965 0 41,692,900 33,528,400
Probable(1) 13,700,741 0 205,031,000 138,299,500
Probable Govt. Take(1) 0 0 (181,507,600) (122,482,900)
------------- ------ -------------- --------------
Total Probable(1) 13,700,741 0 23,523,400 15,816,600
</TABLE>
(1) These reserves and future revenue are not risk weighted.
A-5
<PAGE> 128
The oil reserves shown include crude oil and condensate. Oil volumes
are expressed in barrels which are equivalent to 42 United States gallons.
There are no gas sales from the Ashland Nigerian concessions.
As shown in the Table of Contents, this report includes summary
projections of reserves and revenue by reserve category. Summary projections
of reserves and revenue by reserve category are also included for each OPL and
field. One-line summaries of reserves and economics are presented for each
field. Pertinent maps and exhibits are also included in the report. For the
purposes of this report, the term "lease" refers to a single economic
projection.
The estimated reserves and future revenue shown in this report are for
proved developed producing, proved developed non-producing, proved undeveloped,
and probable reserves. Our estimates do not include any value for possible
reserves although we have conducted a limited study of the properties which
indicates the existence of numerous possible undeveloped locations. This
report does not include any value which could be attributed to undrilled
prospect acreage beyond those tracts for which undeveloped reserves have been
estimated.
Future gross revenue to the Ashland interest is prior to deducting
royalty, Petroleum Profit Tax, Revised Government Tax, and the Nigerian
National Petroleum Company share of profit (Government Take). Future net
revenue is after deducting these items, future capital costs, and operating
expenses. In accordance with SEC guidelines, the future net revenue has been
discounted at an annual rate of 10 percent to determine its "present worth."
The present worth is shown to indicate the effect of time on the value of money
and should not be construed as being the fair market value of the properties.
For the purposes of this report, a field inspection of the properties
has not been performed nor has the mechanical operation or condition of the
wells and their related facilities been examined. We have not investigated
possible environmental liability related to the properties; therefore, our
estimates do not include any costs which may be incurred due to such possible
liability. Our estimates of future revenue do not include any salvage value
for the lease and well equipment nor the cost of abandoning the properties.
Oil prices used in this report are based on a September 1996
realisable price of $21.25 per barrel for OPL 98 and $22.64 per barrel for OPL
118, and are held constant in accordance with SEC guidelines.
Lease and well operating costs are based on operating expense records
of Ashland. These costs include Nigerian general and administrative costs,
Port Harcourt District office costs, Lagos Division office costs, and floating
production storage offloading costs along with costs estimated to be incurred
at and below the district level. Lease and well operating costs are held
constant in accordance with SEC guidelines. Capital costs are included as
required for workovers, new development wells, and production equipment.
The reserves included in this report are estimates only and should not
be construed as exact quantities. They may or may not be actually recovered;
if recovered, the revenues therefrom and
A-6
<PAGE> 129
the costs related thereto could be more or less than the estimated amounts.
The sales rates, prices received for the reserves, and costs incurred in
recovering such reserves may vary from assumptions included in this report due
to governmental policies and uncertainties of supply and demand. Also,
estimates of reserves may increase or decrease as a result of future
operations.
In evaluating the information at our disposal concerning this report,
we have excluded from our consideration all matters as to which political,
socioeconomic, legal or accounting, rather than engineering and geological,
interpretation may be controlling. As in all aspects of oil and gas
evaluation, there are uncertainties inherent in the interpretation of
engineering and geological data; therefore, our conclusions necessarily
represent only informed professional judgments.
The titles to the properties have not been examined by Netherland,
Sewell & Associates, Inc., nor has the actual degree or type of interest owned
been independently confirmed. The data used in our estimates were obtained
from Ashland Oil (Nigeria) Company Unlimited; Ashland Exploration, Inc.; and
the nonconfidential files of Netherland, Sewell & Associates, Inc. and were
accepted as accurate. We are independent petroleum engineers, geologists, and
geophysicists; we do not own an interest in these properties and are not
employed on a contingent basis. Basic geologic and field performance data
together with our engineering work sheets are maintained on file in our office.
Very truly yours,
/s/ CLARENCE M. NETHERLAND
--------------------------
CLARENCE M. NETHERLAND
A-7
<PAGE> 130
======================================================
NO DEALER, SALESPERSON OR OTHER INDIVIDUAL HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS IN
CONNECTION WITH THE OFFERING COVERED BY THIS PROSPECTUS. IF GIVEN OR MADE, SUCH
INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED
BY THE COMPANY OR THE UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER
TO SELL, OR A SOLICITATION OF AN OFFER TO BUY, THE COMMON STOCK IN ANY
JURISDICTION WHERE, OR TO ANY PERSON TO WHOM, IT IS UNLAWFUL TO MAKE SUCH OFFER
OR SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE AN IMPLICATION THAT THERE HAS
NOT BEEN ANY CHANGE IN THE FACTS SET FORTH IN THIS PROSPECTUS OR IN THE AFFAIRS
OF THE COMPANY SINCE THE DATE HEREOF.
---------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary.................... 3
Risk Factors.......................... 12
The Company........................... 22
Use of Proceeds....................... 22
Dividend Policy....................... 22
Capitalization........................ 23
Selected Historical and Pro Forma
Financial Information............... 24
Selected Operating Data............... 26
Pro Forma Consolidated Financial
Statements.......................... 27
Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................... 33
Business and Properties............... 45
Management............................ 68
Principal and Management Stock
Ownership........................... 77
Relationship Between the Company and
Ashland............................. 79
Description of Capital Stock.......... 82
Shares Eligible for Future Sale....... 86
Underwriting.......................... 88
Legal Matters......................... 89
Experts............................... 89
Available Information................. 89
Glossary of Oil and Gas Terms......... 91
Index to Financial Statements......... F-1
Reports of Independent Petroleum
Engineers........................... A-1
</TABLE>
---------------------
THROUGH AND INCLUDING , 1997 (THE 25TH DAY AFTER THE DATE OF
THIS PROSPECTUS), ALL DEALERS EFFECTING TRANSACTIONS IN THE COMMON STOCK,
WHETHER OR NOT PARTICIPATING IN THIS DISTRIBUTION, MAY BE REQUIRED TO DELIVER A
PROSPECTUS. THIS DELIVERY REQUIREMENT IS IN ADDITION TO THE OBLIGATION OF
DEALERS TO DELIVER A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO
THEIR UNSOLD ALLOTMENTS OR SUBSCRIPTIONS.
======================================================
======================================================
3,100,000 SHARES
[BLAZER ENERGY CORP. LOGO]
BLAZER ENERGY CORP.
COMMON STOCK
---------------------------
PROSPECTUS
---------------------------
MERRILL LYNCH & CO.
CREDIT SUISSE FIRST BOSTON
GOLDMAN, SACHS & CO.
, 1997
======================================================
<PAGE> 131
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
The following table sets forth the estimated costs and expenses of the
Registrant in connection with the Offering described in the Registration
Statement. All of the amounts shown are estimates except the SEC registration
fee and the NASD filing fee.
<TABLE>
<S> <C>
SEC Filing Fee.............................................. $ 25,758
NASD Filing Fee............................................. 9,000
NYSE Listing Fee............................................ *
Legal Fees and Expenses..................................... *
Accounting Fees and Expenses................................ *
Blue Sky Fees and Expenses.................................. *
Printing Expenses........................................... *
Miscellaneous Expenses...................................... *
--------
Total............................................. $ *
========
</TABLE>
- ---------------
* To be completed by amendment.
ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Under Delaware law, a corporation may include provisions in its certificate
of incorporation that will relieve its directors of monetary liability for
breaches of their fiduciary duty to the corporation, except under certain
circumstances, including a breach of the director's duty of loyalty, acts or
omissions of the director not in good faith or which involve intentional
misconduct or a knowing violation of law, the approval of an unlawful payment of
a dividend or an unlawful purchase by the corporation of stock or any
transaction from which the director derived an improper personal benefit. The
Company's Restated Certificate of Incorporation provides that the Company's
directors are not liable to the Company or its stockholders for monetary damages
for breach of their fiduciary duty, subject to the described exceptions
specified by Delaware law.
Section 145 of the Delaware General Corporation Law grants to the Company
the power to indemnify each officer and director of the Company against
liabilities and expenses incurred by reason of the fact that he is or was an
officer or director of the Company if he acted in good faith and in a manner he
reasonably believed to be in or not opposed to the best interests of the Company
and, with respect to any criminal action or proceeding, had no reasonable cause
to believe his conduct was unlawful. The Bylaws of the Company provide for
indemnification of each officer and director of the Company to the fullest
extent permitted by Delaware law.
Section 145 of the Delaware General Corporation Law also empowers the
Company to purchase and maintain insurance on behalf of any person who is or was
an officer or director of the Company against liability asserted against or
incurred by him in any such capacity, whether or not the Company would have the
power to indemnify such officer or director against such liability under the
provisions of Section 145. Directors' and officers' liability insurance is
provided under policies maintained by Ashland in the aggregate amount of
$100,000,000.
Reference is made to the Underwriting Agreement filed as Exhibit 1 to this
Registration Statement for a description of indemnification arrangements related
to this Offering.
ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.
During the past three years, the Company has not sold any of its
securities.
II-1
<PAGE> 132
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a) Exhibits:
<TABLE>
<S> <S>
1.1 -- Form of Underwriting Agreement
3.1* -- Amended and Restated Certificate of Incorporation
3.2* -- Amended and Restated Bylaws
4.1* -- Specimen of Common Stock certificate
5.1* -- Opinion of Vinson & Elkins L.L.P.
10.1* -- Tax Agreement
10.2* -- Indemnity Agreement
10.3* -- Services Agreement
10.4* -- Registration Rights Agreement
10.5 -- Production Sharing Contract between Nigerian National
Petroleum Corporation and Ashland Nigeria Exploration
Unltd.
10.6 -- Production Sharing Contract between Nigerian National
Petroleum Corporation and Ashland Oil (Nigeria) Company
Unltd.
10.7 -- Memorandum of Understanding on OPLs 98 and 118 between
The Federal Military Government of the Federal Republic
of Nigeria and Ashland Oil (Nigeria) Company
10.8 -- Memorandum of Understanding on OPLs 90 and 225 between
The Federal Military Government of the Federal Republic
of Nigeria and Ashland Nigeria Exploration Unltd.
10.9* -- 1997 Stock Incentive Plan
10.10* -- Form of Employment Agreement for W. Paul Tiefel, Robert
C. Bilger, Bradley W. Fischer, Jeffrey W. Lund and Mark
D. Pierce
10.11* -- Form of Director Indemnification Agreement
10.12 -- Commitment Letter entered into between The Chase
Manhattan Bank and Ashland Exploration, Inc., dated
February 25, 1997
10.13* -- Agreement regarding sale of Section 29 Tax Credit
Properties
21.1 -- Subsidiaries of the Registrant
23.1* -- Consent of Vinson & Elkins L.L.P. (included in Exhibit
5.1)
23.2 -- Consent of Ernst & Young LLP
23.3 -- Consent of Netherland, Sewell & Associates, Inc.
24.1 -- Powers of Attorney (included on signature page)
27.1 -- Financial Data Schedules
</TABLE>
- ---------------
* To be filed by amendment.
(b) Financial Statement Schedules:
None.
ITEM 17. UNDERTAKINGS.
(a) Insofar as indemnification for liabilities arising under the Securities
Act of 1933, as amended (the "Act") may be permitted to directors, officers and
controlling persons of the Registrant pursuant to the provisions referred to in
Item 14 of this Registration Statement, or otherwise, the Registrant has been
advised that in the opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed in the Act and is,
therefore, unenforceable. In the event that a claim for indemnification against
II-2
<PAGE> 133
such liabilities (other than the payment by the Registrant of expenses incurred
or paid by a director, officer or controlling person of the Registrant in the
successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities being
registered, the Registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against public
policy as expressed in the Act and will be governed by the final adjudication of
such issue.
(b) The Registrant hereby undertakes to provide the Underwriters at the
closing specified in the Underwriting Agreement certificates in such
denominations and registered in such names as required by the Underwriters to
permit prompt delivery to each purchaser.
(c) The undersigned Registrant hereby undertakes that:
(1) For purposes of determining liability under the Securities Act of
1933, the information omitted from the form of prospectus filed as part of
this Registration Statement filed pursuant to Rule 430A and contained in a
form of a prospectus filed by the registrant in reliance upon Rule
424(b)(1) or (4) or Rule 497(h) under the Act shall be deemed to be part of
this Registration Statement as of the time it was declared effective.
(2) For the purpose of determining liability under the Securities Act
of 1933, each post-effective amendment that contains a form of prospectus
shall be deemed to be a new registration statement relating to the
securities offered therein, and the offering of such securities at that
time shall be deemed to be the initial bona fide offering thereof.
II-3
<PAGE> 134
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the Registrant
has duly caused this Registration Statement to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Houston, State of Texas,
on the 4th day of March, 1997.
BLAZER ENERGY CORP.
By: /s/ W. PAUL TIEFEL
----------------------------------
W. Paul Tiefel
President and Chief Executive
Officer
Each person whose signature appears below hereby constitutes and appoints
W. Paul Tiefel and Robert C. Bilger, his true and lawful attorneys-in-fact and
agents, each acting alone, with full power of substitution and resubstitution,
for him and in his name, place and stead, in any and all capacities, to sign any
or all amendments (including, without limitation, post-effective amendments) to
this Registration Statement and any subsequent registration statement filed by
the Registrant pursuant to Rule 462(b) of the Securities Act of 1933, which
relates to this Registration Statement, and to file the same, with all exhibits
thereto, and all documents in connection herewith, with the Securities and
Exchange Commission, granting unto said attorneys-in-fact and agents, full power
and authority to do and perform each and every act and thing requisite and
necessary to be done in and about the premises, as fully to all intents and
purposes as he might or could do in person, hereby ratifying and confirming all
that said attorneys-in-fact and agents, each acting alone, or his or their
substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ W. PAUL TIEFEL President, Chief Executive Officer March 4, 1997
- ----------------------------------------------------- and Director (Principal
W. Paul Tiefel Executive Officer)
/s/ ROBERT C. BILGER Executive Vice President, Chief March 4, 1997
- ----------------------------------------------------- Financial Officer, Treasurer and
Robert C. Bilger Director (Principal Financial
Officer)
/s/ JOHN V. CONNOLLY Vice President and Controller March 4, 1997
- ----------------------------------------------------- (Principal Accounting Officer)
John V. Connolly
/s/ JAMES R. BOYD Chairman of the Board and Director March 4, 1997
- -----------------------------------------------------
James R. Boyd
/s/ THOMAS L. FEAZELL Director March 4, 1997
- -----------------------------------------------------
Thomas L. Feazell
/s/ PHILIP W. BLOCK Director March 4, 1997
- -----------------------------------------------------
Philip W. Block
/s/ DR. ROBERT B. STOBAUGH Director March 4, 1997
- -----------------------------------------------------
Dr. Robert B. Stobaugh
/s/ J.W. STEWART Director March 4, 1997
- -----------------------------------------------------
J.W. Stewart
</TABLE>
II-4
<PAGE> 135
EXHIBIT INDEX
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a) Exhibits:
<TABLE>
<S> <S>
1.1 -- Form of Underwriting Agreement
3.1* -- Amended and Restated Certificate of Incorporation
3.2* -- Amended and Restated Bylaws
4.1* -- Specimen of Common Stock certificate
5.1* -- Opinion of Vinson & Elkins L.L.P.
10.1* -- Tax Agreement
10.2* -- Indemnity Agreement
10.3* -- Services Agreement
10.4* -- Registration Rights Agreement
10.5 -- Production Sharing Contract between Nigerian National
Petroleum Corporation and Ashland Nigeria Exploration
Unltd.
10.6 -- Production Sharing Contract between Nigerian National
Petroleum Corporation and Ashland Oil (Nigeria) Company
Unltd.
10.7 -- Memorandum of Understanding on OPLs 98 and 118 between
The Federal Military Government of the Federal Republic
of Nigeria and Ashland Oil (Nigeria) Company
10.8 -- Memorandum of Understanding on OPLs 90 and 225 between
The Federal Military Government of the Federal Republic
of Nigeria and Ashland Nigeria Exploration Unltd.
10.9* -- 1997 Stock Incentive Plan
10.10* -- Form of Employment Agreement for W. Paul Tiefel, Robert
C. Bilger, Bradley W. Fischer, Jeffrey W. Lund and Mark
D. Pierce
10.11* -- Form of Director Indemnification Agreement
10.12 -- Commitment Letter entered into between The Chase
Manhattan Bank and Ashland Exploration, Inc., dated
February 25, 1997
10.13* -- Agreement regarding sale of Section 29 Tax Credit
Properties
21.1 -- Subsidiaries of the Registrant
23.1* -- Consent of Vinson & Elkins L.L.P. (included in Exhibit
5.1)
23.2 -- Consent of Ernst & Young LLP
23.3 -- Consent of Netherland, Sewell & Associates, Inc.
24.1 -- Powers of Attorney (included on signature page)
27.1 -- Financial Data Schedules
</TABLE>
- ---------------
* To be filed by amendment.
II-5
<PAGE> 1
================================================================================
[BLAZER ENERGY CORP.]
a Delaware corporation
[o] Shares of Common Stock
PURCHASE AGREEMENT
Dated: [o], 1997
================================================================================
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
<S> <C>
PURCHASE AGREEMENT..................................................... 1
SECTION 1. Representations and Warranties............................. 2
(a) Representations and Warranties by
the Company and Ashland............................ 2
(i) Compliance with Registration Requirements............ 2
(ii) Independent Accountants.............................. 3
(iii) Financial Statements................................. 3
(iv) No Material Adverse Change in Business............... 4
(v) Good Standing of the Company......................... 4
(vi) Good Standing of Subsidiaries........................ 4
(vii) Good Standing of Ashland............................. 5
(viii) Capitalization....................................... 5
(ix) Authorization of Agreements.......................... 5
(x) Authorization and Description of Securities......... 5
(xi) Absence of Defaults and Conflicts.................... 5
(xii) Absence of Labor Dispute............................. 6
(xiii) Absence of Proceedings............................... 6
(xiv) Accuracy of Exhibits................................. 7
(xv) Possession of Intellectual Property.................. 7
(xvi) Absence of Further Requirements...................... 7
(xvii) Possession of Licenses and Permits................... 7
(xviii) Title to Property.................................... 8
(xix) Compliance with Cuba Act............................. 8
(xx) Investment Company Act............................... 8
(xxi) Environmental Laws................................... 8
(xxii) Registration Rights.................................. 9
(xxiii) Independent Petroleum Engineers...................... 9
(b) Officer's Certificates................................... 9
SECTION 2. Sale and Delivery to Underwriters;
Closing....................................................... 9
(a) Initial Securities....................................... 9
(b) Option Securities........................................ 9
(c) Payment.................................................. 10
(d) Denominations; Registration.............................. 10
</TABLE>
<PAGE> 3
Contents, p.2
<TABLE>
<CAPTION>
Page
<S> <C>
SECTION 3. Covenants of the Company................................... 10
(a) Compliance with Securities Regulations and
Commission Requests.............................. 10
(b) Filing of Amendments..................................... 11
(c) Delivery of Registration Statements...................... 11
(d) Delivery of Prospectuses................................. 11
(e) Continued Compliance with Securities Laws................ 12
(f) Blue Sky Qualifications.................................. 12
(g) Rule 158................................................. 12
(h) Use of Proceeds.......................................... 12
(i) Listing ................................................. 13
(j) Restriction on Sale of Securities........................ 13
(k) Reporting Requirements................................... 13
(l) Compliance with Rule 463................................. 13
SECTION 4. Payment of Expenses........................................ 13
(a) Expenses................................................. 13
(b) Termination of Agreement................................. 14
SECTION 5. Conditions of Underwriters' Obligations.................... 14
(a) Effectiveness of Registration Statement.................. 14
(b) Opinion of Counsel for Company........................... 14
(c) Opinion of Counsel for Ashland........................... 14
(d) Opinion of Counsel for Underwriters...................... 15
(e) Officers' Certificate.................................... 15
(f) Accountants' Comfort Letter.............................. 15
(g) Bring-Down Comfort Letter................................ 15
(h) Petroleum Engineers' Letter.............................. 16
(i) Approval of Listing...................................... 16
(j) No Objection............................................. 16
(k) Lock-up Agreements....................................... 16
(l) Material Contracts....................................... 16
(m) Conditions to Purchase of Option Securities.............. 16
(n) Additional Documents..................................... 17
(o) Termination of Agreement................................. 17
SECTION 6. Indemnification ................................... 18
(a) Indemnification of Underwriters.......................... 18
(b) Indemnification of Company, Ashland, Directors and
Officers......................................... 18
(c) Actions against Parties; Notification.................... 19
(d) Settlement without Consent if Failure to Reimburse....... 19
SECTION 7. Contribution............................................... 19
SECTION 8. Representations, Warranties and Agreements
to Survive Delivery.......................................... 21
SECTION 9. Termination of Agreement................................... 21
</TABLE>
<PAGE> 4
Contents, p.3
<TABLE>
<CAPTION>
Page
<S> <C>
(a) Termination; General............................21
(b) Liabilities.....................................21
SECTION 10. Default by One or More of the
Underwriters.......................................21
SECTION 11. Notices...................................................22
SECTION 12. Parties...................................................22
SECTION 13. Governing Law and Time....................................23
SECTION 14. Effect of Headings........................................23
SCHEDULES
Schedule A--List of Underwriters.....................Sch A-1
Schedule B--Pricing Information......................Sch B-1
Schedule C--List of Persons Subject to Lock-up.......Sch C-1
EXHIBITS
Exhibit A--Form of Opinion of Company's
Counsel..........................................Exh A-1
Exhibit B--Form of Opinion of Ashland's
Counsel..........................................Exh B-1
Exhibit C--Form of Lock-up Letter....................Exh C-1
ANNEXES
Annex A--Form of Accountants' Comfort Letter.........Annex A
</TABLE>
<PAGE> 5
[Draft--2/25/97]
[BLAZER ENERGY CORP.]
(a Delaware corporation)
[o] Shares of Common Stock
(Par Value $.01 Per Share)
PURCHASE AGREEMENT
[o], 1997
MERRILL LYNCH & CO.
Merrill Lynch, Pierce, Fenner & Smith
Incorporated
Credit Suisse First Boston Corporation
Goldman, Sachs & Co.
as Representatives of the several Underwriters
c/o Merrill Lynch & Co.
Merrill Lynch, Pierce, Fenner & Smith
Incorporated
North Tower
World Financial Center
New York, New York 10281-1209
Ladies and Gentlemen:
[Blazer Energy Corp.], a Delaware corporation (the
"Company"), confirms its agreement with Merrill Lynch & Co., Merrill Lynch,
Pierce, Fenner & Smith Incorporated ("Merrill Lynch") and each of the other
Underwriters named in Schedule A hereto (collectively, the "Underwriters",
which term shall also include any underwriter substituted as hereinafter
provided in Section 10 hereof), for whom Merrill Lynch, Credit Suisse First
Boston Corporation and Goldman, Sachs & Co. are acting as representatives (in
such capacity, the "Representatives"), with respect to the issue and sale by
the Company and the purchase by the Underwriters, acting severally and not
jointly, of the respective numbers of shares of Common Stock, par value $.01
per share, of the Company ("Common Stock") set forth in said Schedule A, and
with respect to the grant by the Company to the Underwriters, acting severally
and not jointly, of the option described in Section 2(b) hereof to purchase all
or any part of [o] additional shares of Common Stock to cover over-allotments,
if any. The aforesaid [o] shares of Common Stock (the "Initial Securities") to
be purchased by the Underwriters and all or any part of the [o] shares of
Common Stock subject to the option described in Section 2(b) hereof (the
"Option Securities") are hereinafter called, collectively, the "Securities".
The Company is a wholly owned subsidiary of Ashland Inc., a
Kentucky corporation ("Ashland").
<PAGE> 6
2
The Company understands that the Underwriters propose to make
a public offering of the Securities as soon as the Representatives deem
advisable after this Agreement has been executed and delivered.
The Company has filed with the Securities and Exchange
Commission (the "Commission") a registration statement on Form S-1 (No. 333-o)
covering the registration of the Securities under the Securities Act of 1933,
as amended (the "1933 Act"), including the related preliminary prospectus or
prospectuses. Promptly after execution and delivery of this Agreement, the
Company will either (i) prepare and file a prospectus in accordance with the
provisions of Rule 430A ("Rule 430A") of the rules and regulations of the
Commission under the 1933 Act (the "1933 Act Regulations") and paragraph (b) of
Rule 424 ("Rule 424(b)") of the 1933 Act Regulations or (ii) if the Company has
elected to rely upon Rule 434 ("Rule 434") of the 1933 Act Regulations, prepare
and file a term sheet (a "Term Sheet") in accordance with the provisions of
Rule 434 and Rule 424(b). The information included in such prospectus or in
such Term Sheet, as the case may be, that was omitted from such registration
statement at the time it became effective but that is deemed to be part of such
registration statement at the time it became effective (a) pursuant to
paragraph (b) of Rule 430A is referred to as "Rule 430A Information" or (b)
pursuant to paragraph (d) of Rule 434 is referred to as "Rule 434 Information."
Each prospectus used before such registration statement became effective, and
any prospectus that omitted, as applicable, the Rule 430A Information or the
Rule 434 Information, that was used after such effectiveness and prior to the
execution and delivery of this Agreement, is herein called a "preliminary
prospectus." Such registration statement, including the exhibits thereto and
schedules thereto at the time it became effective and including the Rule 430A
Information and the Rule 434 Information, as applicable, is herein called the
"Registration Statement." Any registration statement filed pursuant to Rule
462(b) of the 1933 Act Regulations is herein referred to as the "Rule 462(b)
Registration Statement," and after such filing the term "Registration
Statement" shall include the Rule 462(b) Registration Statement. The final
prospectus in the form first furnished to the Underwriters for use in
connection with the offering of the Securities is herein called the
"Prospectus." If Rule 434 is relied on, the term "Prospectus" shall refer to
the preliminary prospectus dated [o], 1997, together with the Term Sheet and
all references in this Agreement to the date of the Prospectus shall mean the
date of the Term Sheet. For purposes of this Agreement, all references to the
Registration Statement, any preliminary prospectus, the Prospectus or any Term
Sheet or any amendment or supplement to any of the foregoing shall be deemed to
include the copy filed with the Commission pursuant to its Electronic Data
Gathering, Analysis and Retrieval system ("EDGAR").
1. Representations and Warranties. (a) Representations and
Warranties by the Company and Ashland. Each of the Company and Ashland, jointly
and severally, represents and warrants to each Underwriter as of the date
hereof, as of the Closing Time referred to in Section 2(c) hereof, and as of
each Date of Delivery (if any) referred to in Section 2(b) hereof, and agrees
with each Underwriter, as follows:
(i) Compliance with Registration Requirements. Each of the
Registration Statement and any Rule 462(b) Registration Statement has
become effective under the 1933 Act and no stop order suspending the
effectiveness of the Registration Statement or any Rule 462(b)
Registration Statement has been issued under the 1933 Act and no
proceedings for that purpose have been instituted or are pending or,
to the knowledge of the Company, are contemplated by the Commission,
and
<PAGE> 7
3
any request on the part of the Commission for additional information
has been complied with. At the respective times the Registration
Statement, any Rule 462(b) Registration Statement and any
post-effective amendments thereto became effective and at the Closing
Time (and, if any Option Securities are purchased, at the Date of
Delivery), the Registration Statement, the Rule 462(b) Registration
Statement and any amendments and supplements thereto complied and will
comply in all material respects with the requirements of the 1933 Act
and the 1933 Act Regulations and did not and will not contain an
untrue statement of a material fact or omit to state a material fact
required to be stated therein or necessary to make the statements
therein not misleading. Neither the Prospectus nor any amendments or
supplements thereto, at the time the Prospectus or any such amendment
or supplement was issued and at the Closing Time (and, if any Option
Securities are purchased, at the Date of Delivery), included or will
include an untrue statement of a material fact or omitted or will omit
to state a material fact necessary in order to make the statements
therein, in the light of the circumstances under which they were made,
not misleading. If Rule 434 is used, the Company will comply with the
requirements of Rule 434 and the Prospectus shall not be "materially
different", as such term is used in Rule 434, from the prospectus
included in the Registration Statement at the time it became
effective. The representations and warranties in this subsection shall
not apply to statements in or omissions from the Registration
Statement or Prospectus made in reliance upon and in conformity with
information furnished to the Company in writing by any Underwriter
through Merrill Lynch expressly for use in the Registration Statement
or Prospectus.
Each preliminary prospectus and the prospectus filed as part
of the Registration Statement as originally filed or as part of any
amendment thereto, or filed pursuant to Rule 424 under the 1933 Act,
complied when so filed in all material respects with the 1933 Act
Regulations and each preliminary prospectus and the Prospectus
delivered to the Underwriters for use in connection with this offering
was identical to the electronically transmitted copies thereof filed
with the Commission pursuant to EDGAR, except to the extent permitted
by Regulation S-T.
(ii) Independent Accountants. The accountants who certified
the financial statements and supporting schedules included in the
Registration Statement are independent public accountants as required
by the 1933 Act and the 1933 Act Regulations.
(iii) Financial Statements. The financial statements included
in the Registration Statement and the Prospectus, together with the
related schedules and notes, present fairly the financial position of
the Company and its consolidated subsidiaries at the dates indicated
and the statement of operations, stockholders' equity and cash flows
of the Company and its consolidated subsidiaries for the periods
specified; said financial statements have been prepared in conformity
with United States generally accepted accounting principles ("GAAP")
applied on a consistent basis throughout the periods involved. The
supporting schedules included in the Registration Statement present
fairly in accordance with GAAP the information required to be stated
therein. The selected financial data and the summary financial
information included in the Prospectus present fairly the information
shown therein and have been compiled on a basis consistent with that
<PAGE> 8
4
of the audited financial statements included in the Registration
Statement. The pro forma financial statements and the related notes
thereto included in the Registration Statement and the Prospectus
present fairly the information shown therein, have been prepared in
accordance with the Commission's rules and guidelines with respect to
pro forma financial statements and have been properly compiled on the
bases described therein, and the assumptions used in the preparation
thereof are reasonable and the adjustments used therein are
appropriate to give effect to the transactions and circumstances
referred to therein.
(iv) No Material Adverse Change in Business. Since the
respective dates as of which information is given in the Registration
Statement and the Prospectus, except as otherwise stated therein, (A)
there has been no material adverse change in the condition, financial
or otherwise, or in the earnings, business affairs or business
prospects of the Company and its subsidiaries considered as one
enterprise, whether or not arising in the ordinary course of business
(a "Material Adverse Effect"), (B) there have been no transactions
entered into by the Company or any of its subsidiaries, other than
those in the ordinary course of business, which are material with
respect to the Company and its subsidiaries considered as one
enterprise, and (C) there has been no dividend or distribution of any
kind declared, paid or made by the Company on any class of its capital
stock.
(v) Good Standing of the Company. The Company has been duly
organized and is validly existing as a corporation in good standing
under the laws of the State of Delaware and has corporate power and
authority to own, lease and operate its properties and to conduct its
business as described in the Prospectus and to enter into and perform
its obligations under this Agreement; and the Company is duly
qualified as a foreign corporation to transact business and is in good
standing in each other jurisdiction in which such qualification is
required, whether by reason of the ownership or leasing of property or
the conduct of business, except where the failure so to qualify or to
be in good standing would not result in a Material Adverse Effect.
(vi) Good Standing of Subsidiaries. Each "significant
subsidiary" of the Company (as such term is defined in Rule 1-02 of
Regulation S-X) and [Ashland Exploration Australia Pty, Ltd.] (each a
"Subsidiary" and, collectively, the "Subsidiaries") has been duly
organized and is validly existing as a corporation in good standing
under the laws of the jurisdiction of its incorporation, has corporate
power and authority to own, lease and operate its properties and to
conduct its business as described in the Prospectus and is duly
qualified as a foreign corporation to transact business and is in good
standing in each jurisdiction in which such qualification is required,
whether by reason of the ownership or leasing of property or the
conduct of business, except where the failure so to qualify or to be
in good standing would not result in a Material Adverse Effect; except
as otherwise disclosed in the Registration Statement, all of the
issued and outstanding capital stock of each such Subsidiary has been
duly authorized and validly issued, is fully paid and non-assessable
and is owned by the Company, directly or through subsidiaries, free
and clear of any security interest, mortgage, pledge, lien,
encumbrance, claim or equity; none of the outstanding shares of
capital stock of any Subsidiary was issued in violation of the
preemptive or similar rights of any securityholder of such Subsidiary.
The only subsidiaries of the Company are (a) the subsidiaries listed
on Exhibit 21 to the Registration
<PAGE> 9
5
Statement and (b) certain other subsidiaries which, considered in the
aggregate as a single Subsidiary, do not constitute a "significant
subsidiary" as defined in Rule 1-02 of Regulation S-X.
(vii) Good Standing of Ashland. Ashland has been duly
organized and is validly existing as a corporation in good standing
under the laws of the Commonwealth of Kentucky and has corporate power
and authority to own, lease and operate its properties and to conduct
its business as described in the Prospectus and to enter into and
perform its obligations under this Agreement.
(viii) Capitalization. The authorized, issued and outstanding
capital stock of the Company is as set forth in the Prospectus in the
column entitled "Actual" under the caption "Capitalization" (except
for subsequent issuances, if any, pursuant to this Agreement, pursuant
to reservations, agreements or employee benefit plans referred to in
the Prospectus or pursuant to the exercise of options referred to in
the Prospectus). The shares of issued and outstanding capital stock of
the Company have been duly authorized and validly issued and are fully
paid and non-assessable; none of the outstanding shares of capital
stock of the Company was issued in violation of the preemptive or
other similar rights of any securityholder of the Company.
(ix) Authorization of Agreements. This Agreement has been
duly authorized, executed and delivered by each of the Company and
Ashland. Each of the [Credit Facility, the Tax Agreement, the Services
Agreement, the Registration Rights Agreement and the Indemnification
Agreement] described in the Prospectus (collectively, the "Material
Contracts") is or when executed and delivered by the Company and
Ashland, as appropriate, will be, duly and validly authorized,
executed and delivered by the Company and Ashland, as appropriate, and
is or will be, when executed and delivered by the Company and Ashland,
as appropriate, a legally valid and binding obligation of the Company
and Ashland, as appropriate, enforceable against the Company and
Ashland, as appropriate, in accordance with its terms, except as such
enforcement may be subject to or limited by bankruptcy, insolvency and
general principles of equity.
(x) Authorization and Description of Securities. The
Securities have been duly authorized for issuance and sale to the
Underwriters pursuant to this Agreement and, when issued and delivered
by the Company pursuant to this Agreement against payment of the
consideration set forth herein, will be validly issued and fully paid
and non-assessable; the Common Stock conforms to all statements
relating thereto contained in the Prospectus and such description
conforms to the rights set forth in the instruments defining the same;
no holder of the Securities will be subject to personal liability by
reason of being such a holder; and the issuance of the Securities is
not subject to the preemptive or other similar rights of any
securityholder of the Company.
(xi) Absence of Defaults and Conflicts. Neither the Company,
Ashland nor any of their respective subsidiaries is in violation of
its charter or by-laws or in default in the performance or observance
of any obligation, agreement, covenant or condition contained in any
contract, indenture, mortgage, deed of trust, loan or credit
agreement, note, lease or other agreement or instrument to which it is
a party or by which it or any of them may be bound, or to which any of
the property
<PAGE> 10
6
or assets of the Company, Ashland or any of their respective
subsidiaries is subject (collectively, the "Agreements and
Instruments") except for such defaults that would not result in a
Material Adverse Effect; and the execution, delivery and performance
of this Agreement and the Material Contracts and the consummation of
the transactions contemplated herein, in the Material Contracts and in
the Registration Statement (including the issuance and sale of the
Securities, the use of the net proceeds from the sale of the
Securities as described in the Prospectus under the caption "Use of
Proceeds", the borrowing of approximately $[ ] million under the
Company's Credit Facility and the proposed distribution by Ashland of
its shares of the Company's Common Stock to Ashland's stockholders)
and compliance by each of the Company and Ashland with its obligations
hereunder and under the Material Contracts have been duly authorized
by all necessary corporate action and do not and will not, whether
with or without the giving of notice or passage of time or both,
conflict with or constitute a breach of, or default or Repayment Event
(as defined below) under, or result in the creation or imposition of
any lien, charge or encumbrance upon any property or assets of the
Company, Ashland or any of their respective subsidiaries pursuant to,
the Agreements and Instruments (except for such conflicts, breaches or
defaults or liens, charges or encumbrances that would not result in a
Material Adverse Effect), nor will such action result in any violation
of the provisions of the charter or by-laws of the Company, Ashland or
any of their respective subsidiaries or any applicable law, statute,
rule, regulation, judgment, order, writ or decree of any government,
government instrumentality or court, domestic or foreign, having
jurisdiction over the Company, Ashland or any of their respective
subsidiaries or any of their assets, properties or operations. As used
herein, a "Repayment Event" means any event or condition which gives
the holder of any note, debenture or other evidence of indebtedness
(or any person acting on such holder's behalf) the right to require
the repurchase, redemption or repayment of all or a portion of such
indebtedness by the Company, Ashland or any of their respective
subsidiaries.
(xii) Absence of Labor Dispute. No labor dispute with the
employees of the Company or any of its subsidiaries exists or, to the
knowledge of the Company or Ashland, is imminent, and neither the
Company nor Ashland is aware of any existing or imminent labor
disturbance by the employees of any of the Company's or any of its
subsidiaries' principal suppliers, manufacturers, customers or
contractors, which, in either case, may reasonably be expected to
result in a Material Adverse Effect.
(xiii) Absence of Proceedings. There is no action, suit,
proceeding, inquiry or investigation before or brought by any court or
governmental agency or body, domestic or foreign, now pending, or, to
the knowledge of the Company or Ashland, threatened, against or
affecting the Company or any of its subsidiaries, which is required to
be disclosed in the Registration Statement (other than as disclosed
therein), or which might reasonably be expected to result in a
Material Adverse Effect, or which might reasonably be expected to
materially and adversely affect the properties or assets of the
Company and its subsidiaries or the consummation of the transactions
contemplated in this Agreement, in the Material Contracts or in the
Registration Statement or the performance by the Company or Ashland of
its obligations hereunder or under the Material Contracts; the
aggregate of all pending legal or governmental proceedings to which
the Company or any of its subsidiaries is a party or of which any of
their respective property or
<PAGE> 11
7
assets is the subject which are not described in the Registration
Statement, including ordinary routine litigation incidental to the
business, could not reasonably be expected to result in a Material
Adverse Effect.
(xiv) Accuracy of Exhibits. There are no contracts or
documents which are required to be described in the Registration
Statement or the Prospectus or to be filed as exhibits thereto which
have not been so described and filed as required.
(xv) Possession of Intellectual Property. The Company and its
subsidiaries own or possess, or can acquire on reasonable terms,
adequate patents, patent rights, licenses, inventions, copyrights,
know-how (including trade secrets and other unpatented and/or
unpatentable proprietary or confidential information, systems or
procedures), trademarks, service marks, trade names or other
intellectual property (collectively, "Intellectual Property")
necessary to carry on the business now operated by them, and neither
the Company nor any of its subsidiaries has received any notice or is
otherwise aware of any infringement of or conflict with asserted
rights of others with respect to any Intellectual Property or of any
facts or circumstances which would render any Intellectual Property
invalid or inadequate to protect the interest of the Company or any of
its subsidiaries therein, and which infringement or conflict (if the
subject of any unfavorable decision, ruling or finding) or invalidity
or inadequacy, singly or in the aggregate, would result in a Material
Adverse Effect.
(xvi) Absence of Further Requirements. No filing with, or
authorization, approval, consent, license, order, registration,
qualification or decree of, any court or governmental authority or
agency is necessary or required for the performance by the Company or
Ashland of its obligations hereunder, in connection with the offering,
issuance or sale of the Securities hereunder or the consummation of
the transactions contemplated by this Agreement and the Material
Contracts except such as have been already obtained or as may be
required under the 1933 Act or the 1933 Act Regulations or state
securities laws.
(xvii) Possession of Licenses and Permits. The Company and
its subsidiaries possess such permits, licenses, approvals, consents
and other authorizations (collectively, "Governmental Licenses")
issued by the appropriate federal, state, local or foreign regulatory
agencies or bodies necessary to conduct the business now operated by
them; the Company and its subsidiaries are in compliance with the
terms and conditions of all such Governmental Licenses, except where
the failure so to comply would not, singly or in the aggregate, have a
Material Adverse Effect; all of the Governmental Licenses are valid
and in full force and effect, except when the invalidity of such
Governmental Licenses or the failure of such Governmental Licenses to
be in full force and effect would not have a Material Adverse Effect;
and neither the Company nor any of its subsidiaries has received any
notice of proceedings relating to the revocation or modification of
any such Governmental Licenses which, singly or in the aggregate, if
the subject of an unfavorable decision, ruling or finding, would
result in a Material Adverse Effect.
(xviii) Title to Property. The Company and its subsidiaries
have good and marketable title to all real property owned by the
Company and its subsidiaries and good title to all other properties
owned by them, in each case, free and clear of
<PAGE> 12
8
all mortgages, pledges, liens, security interests, claims,
restrictions, encumbrances or defects of any kind except such as (a)
are described in the Prospectus or (b) do not, singly or in the
aggregate, materially affect the value of such property and do not
interfere with the use made and proposed to be made of such property
by the Company or any of its subsidiaries; and all of the leases and
subleases material to the business of the Company and its
subsidiaries, considered as one enterprise, and under which the
Company or any of its subsidiaries holds properties described in the
Prospectus, are in full force and effect, and neither the Company nor
any subsidiary has any notice of any material claim of any sort that
has been asserted by anyone adverse to the rights of the Company or
any subsidiary under any of the leases or subleases mentioned above,
or affecting or questioning the rights of the Company or such
subsidiary to the continued possession of the leased or subleased
premises under any such lease or sublease.
(xix) Compliance with Cuba Act. Each of the Company and
Ashland and their respective affiliates has complied with, and is and
will be in compliance with, the provisions of that certain Florida act
relating to disclosure of doing business with Cuba, codified as
Section 517.075 of the Florida statutes, and the rules and regulations
thereunder (collectively, the "Cuba Act") or is exempt therefrom.
(xx) Investment Company Act. The Company is not, and upon the
issuance and sale of the Securities as herein contemplated and the
application of the net proceeds therefrom as described in the
Prospectus will not be, an "investment company" or an entity
"controlled" by an "investment company" as such terms are defined in
the Investment Company Act of 1940, as amended (the "1940 Act").
(xxi) Environmental Laws. Except as described in the
Registration Statement and except as would not, singly or in the
aggregate, result in a Material Adverse Effect, (A) neither the
Company nor any of its subsidiaries is in violation of any Federal,
state, local or foreign statute, law, rule, regulation, ordinance,
code, policy or rule of common law or any judicial or administrative
interpretation thereof, including any judicial or administrative
order, consent, decree or judgment, relating to pollution or
protection of human health, the environment (including, without
limitation, ambient air, surface water, groundwater, land surface or
subsurface strata) or wildlife, including, without limitation, laws
and regulations relating to the release or threatened release of
chemicals, pollutants, contaminants, wastes, toxic substances,
hazardous substances, petroleum or petroleum products (collectively,
"Hazardous Materials") or to the manufacture, processing,
distribution, use, treatment, storage, disposal, transport or handling
of Hazardous Materials (collectively, "Environmental Laws"), (B) the
Company and its subsidiaries have all permits, authorizations and
approvals required under any applicable Environmental Laws and are
each in compliance with their requirements, (C) there are no pending
or threatened administrative, regulatory or judicial actions, suits,
demands, demand letters, claims, liens, notices of noncompliance or
violation, investigation or proceedings relating to any Environmental
Law against the Company or any of its subsidiaries and (D) there are
no events or circumstances that might reasonably be expected to form
the basis of an order for clean-up or remediation, or an action, suit
or proceeding by any private party or governmental body or agency,
against or affecting the
<PAGE> 13
9
Company or any of its subsidiaries relating to Hazardous Materials or
any Environmental Laws.
(xxii) Registration Rights. There are no persons with
registration rights or other similar rights to have any securities
registered pursuant to the Registration Statement or otherwise
registered by the Company under the 1933 Act.
(xxiii) Independent Petroleum Engineers. Netherland, Sewell &
Associates, Inc. ("Netherland Sewell"), whose estimates are included
in the Prospectus, do not, nor do any of their employees, have any
interest in the Company, Ashland or any of their respective
subsidiaries; nor is their employment to review and report upon the
reserve estimates of the Company or their compensation for such work
contingent upon their estimates for the properties they reviewed.
(b) Officer's Certificates. Any certificate signed by any
officer of the Company or any of its subsidiaries or by Ashland delivered to
the Representatives or to counsel for the Underwriters shall be deemed a
representation and warranty by the Company or by Ashland, as the case may be,
to each Underwriter as to the matters covered thereby.
2. Sale and Delivery to Underwriters; Closing.
(a) Initial Securities. On the basis of the representations and warranties
herein contained and subject to the terms and conditions herein set forth, the
Company agrees to sell to each Underwriter, severally and not jointly, and each
Underwriter, severally and not jointly, agrees to purchase from the Company, at
the price per share set forth in Schedule B, the number of Initial Securities
set forth in Schedule A opposite the name of such Underwriter, plus any
additional number of Initial Securities which such Underwriter may become
obligated to purchase pursuant to the provisions of Section 10 hereof.
(b) Option Securities. In addition, on the basis of the
representations and warranties herein contained and subject to the terms and
conditions herein set forth, the Company hereby grants an option to the
Underwriters, severally and not jointly, to purchase up to an additional [o]
shares of Common Stock at the price per share set forth in Schedule B, less an
amount per share equal to any dividends or distributions declared by the
Company and payable on the Initial Securities but not payable on the Option
Securities. The option hereby granted will expire 30 days after the date hereof
and may be exercised in whole or in part from time to time only for the purpose
of covering over-allotments which may be made in connection with the offering
and distribution of the Initial Securities upon notice by the Representatives
to the Company setting forth the number of Option Securities as to which the
several Underwriters are then exercising the option and the time and date of
payment and delivery for such Option Securities. Any such time and date of
delivery (a "Date of Delivery") shall be determined by the Representatives, but
shall not be later than seven full business days after the exercise of said
option, nor in any event prior to the Closing Time, as hereinafter defined. If
the option is exercised as to all or any portion of the Option Securities, each
of the Underwriters, acting severally and not jointly, will purchase that
proportion of the total number of Option Securities then being purchased which
the number of Initial Securities set forth in Schedule A opposite the name of
such Underwriter bears to the total number of Initial Securities, subject in
each case to such adjustments as the Representatives in their discretion shall
make to eliminate any sales or purchases of fractional shares.
<PAGE> 14
10
(c) Payment. Payment of the purchase price for, and delivery
of certificates for, the Initial Securities shall be made at the offices of
Cravath, Swaine & Moore, Worldwide Plaza, 825 Eighth Avenue, New York, New York
10019, or at such other place as shall be agreed upon by the Representatives
and the Company, at 9:00 A.M. (Eastern time) on the third (fourth, if the
pricing occurs after 4:30 P.M. (Eastern time) on any given day) business day
after the date hereof (unless postponed in accordance with the provisions of
Section 10), or such other time not later than ten business days after such
date as shall be agreed upon by the Representatives and the Company (such time
and date of payment and delivery being herein called "Closing Time").
In addition, in the event that any or all of the Option
Securities are purchased by the Underwriters, payment of the purchase price
for, and delivery of certificates for, such Option Securities shall be made at
the above-mentioned offices, or at such other place as shall be agreed upon by
the Representatives and the Company, on each Date of Delivery as specified in
the notice from the Representatives to the Company.
Payment shall be made to the Company by wire transfer of
immediately available funds to a bank account designated by the Company,
against delivery to the Representatives for the respective accounts of the
Underwriters of certificates for the Securities to be purchased by them. It is
understood that each Underwriter has authorized the Representatives, for its
account, to accept delivery of, receipt for, and make payment of the purchase
price for, the Initial Securities and the Option Securities, if any, which it
has agreed to purchase. Merrill Lynch, individually and not as representative
of the Underwriters, may (but shall not be obligated to) make payment of the
purchase price for the Initial Securities or the Option Securities, if any, to
be purchased by any Underwriter whose funds have not been received by the
Closing Time or the relevant Date of Delivery, as the case may be, but such
payment shall not relieve such Underwriter from its obligations hereunder.
(d) Denominations; Registration. Certificates for the Initial
Securities and the Option Securities, if any, shall be in such denominations
and registered in such names as the Representatives may request in writing at
least two full business days before the Closing Time or the relevant Date of
Delivery, as the case may be. The certificates for the Initial Securities and
the Option Securities, if any, will be made available for examination and
packaging by the Representatives in The City of New York not later than 10:00
A.M. (Eastern time) on the business day prior to the Closing Time or the
relevant Date of Delivery, as the case may be.
3. Covenants of the Company. The Company covenants with
each Underwriter as follows:
(a) Compliance with Securities Regulations and Commission
Requests. The Company, subject to Section 3(b), will comply with the
requirements of Rule 430A or Rule 434, as applicable, and will notify
the Representatives immediately, and confirm the notice in writing,
(i) when any post-effective amendment to the Registration Statement
shall become effective, or any supplement to the Prospectus or any
amended Prospectus shall have been filed, (ii) of the receipt of any
comments from the Commission, (iii) of any request by the Commission
for any amendment to the Registration Statement or any amendment or
supplement to the Prospectus or for additional information, and
<PAGE> 15
11
(iv) of the issuance by the Commission of any stop order suspending
the effectiveness of the Registration Statement or of any order
preventing or suspending the use of any preliminary prospectus, or of
the suspension of the qualification of the Securities for offering or
sale in any jurisdiction, or of the initiation or threatening of any
proceedings for any of such purposes. The Company will promptly effect
the filings necessary pursuant to Rule 424(b) and will take such steps
as it deems necessary to ascertain promptly whether the form of
prospectus transmitted for filing under Rule 424(b) was received for
filing by the Commission and, in the event that it was not, it will
promptly file such prospectus. The Company will make every reasonable
effort to prevent the issuance of any stop order and, if any stop
order is issued, to obtain the lifting thereof at the earliest
possible moment.
(b) Filing of Amendments. The Company will give the
Representatives notice of its intention to file or prepare any
amendment to the Registration Statement (including any filing under
Rule 462(b)), any Term Sheet or any amendment, supplement or revision
to either the prospectus included in the Registration Statement at the
time it became effective or to the Prospectus will furnish the
Representatives with copies of any such documents a reasonable amount
of time prior to such proposed filing or use, as the case may be, and
will not file or use any such document to which the Representatives or
counsel for the Underwriters shall object.
(c) Delivery of Registration Statements. The Company has
furnished or will deliver to the Representatives and counsel for the
Underwriters, without charge, signed copies of the Registration
Statement as originally filed and of each amendment thereto (including
exhibits filed therewith or incorporated by reference therein) and
signed copies of all consents and certificates of experts, and will
also deliver to the Representatives, without charge, a conformed copy
of the Registration Statement as originally filed and of each
amendment thereto (without exhibits) for each of the Underwriters. The
copies of the Registration Statement and each amendment thereto
furnished to the Underwriters will be identical to the electronically
transmitted copies thereof filed with the Commission pursuant to
EDGAR, except to the extent permitted by Regulation S-T.
(d) Delivery of Prospectuses. The Company has delivered to
each Underwriter, without charge, as many copies of each preliminary
prospectus as such Underwriter reasonably requested, and the Company
hereby consents to the use of such copies for purposes permitted by
the 1933 Act. The Company will furnish to each Underwriter, without
charge, during the period when the Prospectus is required to be
delivered under the 1933 Act or the Securities Exchange Act of 1934,
as amended (the "1934 Act"), such number of copies of the Prospectus
(as amended or supplemented) as such Underwriter may reasonably
request. The Prospectus and any amendments or supplements thereto
furnished to the Underwriters will be identical to the electronically
transmitted copies thereof filed with the Commission pursuant to
EDGAR, except to the extent permitted by Regulation S-T.
(e) Continued Compliance with Securities Laws. The Company
will comply with the 1933 Act and the 1933 Act Regulations so as to
permit the completion of the distribution of the Securities as
contemplated in this Agreement
<PAGE> 16
12
and in the Prospectus. If at any time when a prospectus is required by
the 1933 Act to be delivered in connection with sales of the
Securities, any event shall occur or condition shall exist as a result
of which it is necessary, in the opinion of counsel for the
Underwriters or for the Company, to amend the Registration Statement
or amend or supplement the Prospectus in order that the Prospectus
will not include any untrue statements of a material fact or omit to
state a material fact necessary in order to make the statements
therein not misleading in the light of the circumstances existing at
the time it is delivered to a purchaser, or if it shall be necessary,
in the opinion of such counsel, at any such time to amend the
Registration Statement or amend or supplement the Prospectus in order
to comply with the requirements of the 1933 Act or the 1933 Act
Regulations, the Company will promptly prepare and file with the
Commission, subject to Section 3(b), such amendment or supplement as
may be necessary to correct such statement or omission or to make the
Registration Statement or the Prospectus comply with such
requirements, and the Company will furnish to the Underwriters such
number of copies of such amendment or supplement as the Underwriters
may reasonably request.
(f) Blue Sky Qualifications. The Company will use its best
efforts, in cooperation with the Underwriters, to qualify the
Securities for offering and sale under the applicable securities laws
of such states and other jurisdictions (domestic or foreign) as the
Representatives may designate and to maintain such qualifications in
effect for a period of not less than one year from the later of the
effective date of the Registration Statement and any Rule 462(b)
Registration Statement; provided, however, that the Company shall not
be obligated to file any general consent to service of process or to
qualify as a foreign corporation or as a dealer in securities in any
jurisdiction in which it is not so qualified or to subject itself to
taxation in respect of doing business in any jurisdiction in which it
is not otherwise so subject. In each jurisdiction in which the
Securities have been so qualified, the Company will file such
statements and reports as may be required by the laws of such
jurisdiction to continue such qualification in effect for a period of
not less than one year from the effective date of the Registration
Statement and any Rule 462(b) Registration Statement.
(g) Rule 158. The Company will timely file such reports
pursuant to the 1934 Act as are necessary in order to make generally
available to its securityholders as soon as practicable an earnings
statement for the purposes of, and to provide the benefits
contemplated by, the last paragraph of Section 11(a) of the 1933 Act.
(h) Use of Proceeds. The Company will use the net proceeds
received by it from the sale of the Securities in the manner specified
in the Prospectus under "Use of Proceeds".
(i) Listing. The Company will use its best efforts to effect
the listing of the Common Stock (including the Securities) on the New
York Stock Exchange.
(j) Restriction on Sale of Securities. During a period of 180
days from the date of the Prospectus, neither the Company nor Ashland
will, without the prior written consent of the Representatives, (i)
directly or indirectly, offer, pledge, sell, contract to sell, sell
any option or
<PAGE> 17
13
contract to purchase, purchase any option or contract to sell, grant
any option, right or warrant to purchase or otherwise transfer or
dispose of any share of Common Stock or any securities convertible
into or exercisable or exchangeable for Common Stock or file any
registration statement under the 1933 Act with respect to any of the
foregoing or (ii) enter into any swap or any other agreement or any
transaction that transfers, in whole or in part, directly or
indirectly, the economic consequence of ownership of the Common Stock,
whether any such swap or transaction described in clause (i) or (ii)
above is to be settled by delivery of Common Stock or such other
securities, in cash or otherwise. The foregoing sentence shall not
apply to (A) the Securities to be sold hereunder, (B) any shares of
Common Stock issued by the Company upon the exercise of an option or
warrant or the conversion of a security outstanding on the date hereof
and referred to in the Prospectus, (C) any shares of Common Stock
issued or options to purchase Common Stock granted pursuant to
existing employee benefit plans of the Company referred to in the
Prospectus or (D) any shares of Common Stock issued pursuant to any
non-employee director stock plan or dividend reinvestment plan of the
Company.
(k) Reporting Requirements. The Company, during the period
when the Prospectus is required to be delivered under the 1933 Act or
the 1934 Act, will file all documents required to be filed with the
Commission pursuant to the 1934 Act within the time periods required
by the 1934 Act and the rules and regulations of the Commission
thereunder.
(l) Compliance with Rule 463. The Company will file with the
Commission such reports on Form SR as may be required pursuant to Rule
463 of the 1933 Act Regulations.
4. Payment of Expenses. (a) Expenses. The Company will pay
all expenses incident to the performance of its obligations under this
Agreement, including (i) the preparation, printing and filing of the
Registration Statement (including financial statements and exhibits) as
originally filed and of each amendment thereto, (ii) the preparation, printing
and delivery to the Underwriters of this Agreement, any Agreement among
Underwriters and such other documents as may be required in connection with the
offering, purchase, sale, issuance or delivery of the Securities, (iii) the
preparation, issuance and delivery of the certificates for the Securities to
the Underwriters, including any stock or other transfer taxes and any stamp or
other duties payable upon the sale, issuance or delivery of the Securities to
the Underwriters, (iv) the fees and disbursements of the Company's counsel,
accountants and other advisors, (v) the qualification of the Securities under
securities laws in accordance with the provisions of Section 3(f) hereof,
including filing fees and the reasonable fees and disbursements of counsel for
the Underwriters in connection therewith and in connection with the preparation
of the Blue Sky Survey and any supplement thereto, (vi) the printing and
delivery to the Underwriters of copies of each preliminary prospectus, any Term
Sheets and of the Prospectus and any amendments or supplements thereto, (vii)
the preparation, printing and delivery to the Underwriters of copies of the
Blue Sky Survey and any supplement thereto, (viii) the fees and expenses of any
transfer agent or registrar for the Securities and (ix) the filing fees
incident to, and the reasonable fees and disbursements of counsel to the
Underwriters in connection with, the review by the National Association of
Securities Dealers, Inc. (the "NASD") of the terms of the sale of the
Securities and (x) the fees and expenses incurred in connection with the
listing of the Securities on the New York Stock Exchange.
<PAGE> 18
14
(b) Termination of Agreement. If this Agreement is terminated
by the Representatives in accordance with the provisions of Section 5 or
Section 9(a)(i) hereof, the Company shall reimburse the Underwriters for all of
their out-of-pocket expenses, including the reasonable fees and disbursements
of counsel for the Underwriters.
5. Conditions of Underwriters' Obligations. The obligations
of the several Underwriters hereunder are subject to the accuracy of the
representations and warranties of the Company and Ashland contained in Section
1 hereof or in certificates of any officer of the Company, Ashland or any of
their respective subsidiaries delivered pursuant to the provisions hereof, to
the performance by each of the Company and Ashland of its covenants and other
obligations hereunder, and to the following further conditions:
(a) Effectiveness of Registration Statement. The Registration
Statement, including any Rule 462(b) Registration Statement, has
become effective and at Closing Time no stop order suspending the
effectiveness of the Registration Statement shall have been issued
under the 1933 Act or proceedings therefor initiated or threatened by
the Commission, and any request on the part of the Commission for
additional information shall have been complied with to the reasonable
satisfaction of counsel to the Underwriters. A prospectus containing
the Rule 430A Information shall have been filed with the Commission in
accordance with Rule 424(b) (or a post-effective amendment providing
such information shall have been filed and declared effective in
accordance with the requirements of Rule 430A) or, if the Company has
elected to rely upon Rule 434, a Term Sheet shall have been filed with
the Commission in accordance with Rule 424(b).
(b) Opinion of Counsel for Company. At Closing Time, the
Representatives shall have received the favorable opinion, dated as of
Closing Time, of Vinson & Elkins L.L.P., counsel for the Company, in
form and substance satisfactory to counsel for the Underwriters,
together with signed or reproduced copies of such letter for each of
the other Underwriters to the effect set forth in Exhibit A hereto and
to such further effect as counsel to the Underwriters may reasonably
request.
(c) Opinion of Counsel for Ashland. At Closing Time, the
Representatives shall have received the favorable opinion, dated as of
Closing Time, of [Vinson & Elkins L.L.P.], counsel for Ashland, in
form and substance satisfactory to counsel for the Underwriters,
together with signed or reproduced copies of such letter for each of
the other Underwriters to the effect set forth in Exhibit B hereto and
to such further effect as counsel to the Underwriters may reasonably
request.
(d) Opinion of Counsel for Underwriters. At Closing Time, the
Representatives shall have received the favorable opinion, dated as of
Closing Time, of Cravath, Swaine & Moore, counsel for the
Underwriters, together with signed or reproduced copies of such letter
for each of the other Underwriters with respect to the issuance and
sale of the Securities, the Registration Statement and the Prospectus
(together with any further amendments and supplements thereto) as well
as such other related matters as the Representatives may reasonably
request, and such counsel shall have received such papers and
information as they may reasonably request to enable them to pass upon
such matters. In giving such
<PAGE> 19
15
opinion such counsel may rely, as to all matters governed by the laws
of jurisdictions other than the law of the State of New York, the
Federal law of the United States and the General Corporation Law of
the State of Delaware, upon the opinions of counsel satisfactory to
the Representatives. Such counsel may also state that, insofar as such
opinion involves factual matters, they have relied, to the extent they
deem proper, upon certificates of officers of the Company, Ashland and
the Company's subsidiaries and certificates of public officials.
(e) Officers' Certificate. At Closing Time, there shall not
have been, since the date hereof or since the respective dates as of
which information is given in the Prospectus, any material adverse
change in the condition, financial or otherwise, or in the earnings,
business affairs or business prospects of the Company and its
subsidiaries considered as one enterprise, whether or not arising in
the ordinary course of business, and the Representatives shall have
received certificates from each of the Company and Ashland, signed by
their respective Presidents or any Vice President and by their
respective chief financial or chief accounting officers, dated as of
Closing Time, to the effect that (i) there has been no such material
adverse change, (ii) the representations and warranties in Section
1(a) hereof are true and correct with the same force and effect as
though expressly made at and as of Closing Time, (iii) the Company has
complied with all agreements and satisfied all conditions on its part
to be performed or satisfied at or prior to Closing Time, and (iv) no
stop order suspending the effectiveness of the Registration Statement
has been issued and no proceedings for that purpose have been
instituted or are pending or are contemplated by the Commission.
(f) Accountants' Comfort Letter. At the time of the execution
of this Agreement, the Representatives shall have received from Ernst
& Young LLP a letter dated such date, in form and substance
satisfactory to the Representatives to the effect set forth in Annex A
and to such further effect as counsel to the Underwriters may
reasonably request, together with signed or reproduced copies of such
letter for each of the other Underwriters containing statements and
information of the type ordinarily included in accountants' "comfort
letters" to underwriters with respect to the financial statements and
certain financial information contained in the Registration Statement
and the Prospectus.
(g) Bring-down Comfort Letter. At Closing Time, the
Representatives shall have received from Ernst & Young LLP a letter,
dated as of Closing Time, to the effect that they reaffirm the
statements made in the letter furnished pursuant to subsection (f) of
this Section, except that the specified date referred to shall be a
date not more than three business days prior to Closing Time.
(h) Petroleum Engineers' Letter. At the time of the execution
of this Agreement, the Representatives shall have received from
Netherland Sewell a letter dated such date, in form and substance
satisfactory to the Representatives, together with signed or
reproduced copies of such letter for each of the other Underwriters,
to the effect that (other than changes in prices received by the
Company for the sale of its hydrocarbon production, which changes have
occurred since September 30, 1996), as of such date nothing has come
to the attention of Netherland Sewell which would cause it to change
any opinion expressed by it in its report dated as of October 1, 1996,
from which information included in the Registration Statement and the
Prospectus was extracted with respect to its
<PAGE> 20
16
estimates of proved developed and proved undeveloped oil and gas
reserves of the Company and its subsidiaries as a whole, and the
estimated future net cash flows from such reserves as described in the
Registration Statement and the Prospectus.
(i) Approval of Listing. At Closing Time, the Securities
shall have been approved for listing on the New York Stock Exchange,
subject only to official notice of issuance.
(j) No Objection. The NASD has confirmed that it has not
raised any objection with respect to the fairness and reasonableness
of the underwriting terms and arrangements.
(k) Lock-up Agreements. At the date of this Agreement, the
Representatives shall have received an agreement substantially in the
form of Exhibit C hereto signed by the persons listed on Schedule C
hereto.
(l) Material Agreements. Each of the Material Contracts shall
have been duly and validly authorized, executed and delivered by the
Company and Ashland, as appropriate, in the form filed as an exhibit
to the Registration Statement (with such changes as shall not, in your
reasonable judgment, be adverse in any material respects to
prospective purchasers of the Securities).
(m) Conditions to Purchase of Option Securities. In the event
that the Underwriters exercise their option provided in Section 2(b)
hereof to purchase all or any portion of the Option Securities, the
representations and warranties of the Company contained herein and the
statements in any certificates furnished by the Company or any
subsidiary of the Company hereunder shall be true and correct as of
each Date of Delivery and, at the relevant Date of Delivery, the
Representatives shall have received:
(i) Officers' Certificates. Certificates, dated such Date
of Delivery, of the President or a Vice President of the
Company and Ashland and of the chief financial or chief
accounting officer of the Company and Ashland confirming that
the certificates delivered at the Closing Time pursuant to
Section 5(e) hereof remains true and correct as of such Date
of Delivery.
(ii) Opinion of Counsel for Company. The favorable
opinion of Vinson & Elkins L.L.P., counsel for the Company,
in form and substance satisfactory to counsel for the
Underwriters, dated such Date of Delivery, relating to the
Option Securities to be purchased on such Date of Delivery
and otherwise to the same effect as the opinion required by
Section 5(b) hereof.
(iii) Opinion of Counsel for Ashland. The favorable
opinion of [Vinson & Elkins L.L.P.], counsel for Ashland, in
form and substance satisfactory to counsel for the
Underwriters, dated such Date of Delivery, relating to the
Option Securities to be purchased on such Date of Delivery
and otherwise to the same effect as the opinion required by
Section 5(c) hereof.
<PAGE> 21
17
(iv) Opinion of Counsel for Underwriters. The favorable
opinion of Cravath, Swaine & Moore, counsel for the
Underwriters, dated such Date of Delivery, relating to the
Option Securities to be purchased on such Date of Delivery
and otherwise to the same effect as the opinion required by
Section 5(d) hereof.
(v) Bring-down Comfort Letter. A letter from Ernst &
Young LLP, in form and substance satisfactory to the
Representatives and dated such Date of Delivery,
substantially in the same form and substance as the letter
furnished to the Representatives pursuant to Section 5(g)
hereof, except that the "specified date" in the letter
furnished pursuant to this paragraph shall be a date not more
than three days prior to such Date of Delivery.
(v) Bring-down Petroleum Engineers' Letter. A letter from
Netherland Sewell, in form and substance satisfactory to the
Representatives and dated such Date of Delivery,
substantially in the same form and substance as the letter
furnished to the Representatives pursuant to Section 5(h)
hereof.
(n) Additional Documents. At Closing Time and at each Date of
Delivery, counsel for the Underwriters shall have been furnished with
such documents and opinions as they may require for the purpose of
enabling them to pass upon the issuance and sale of the Securities as
herein contemplated, or in order to evidence the accuracy of any of
the representations or warranties, or the fulfillment of any of the
conditions, herein contained; and all proceedings taken by the Company
in connection with the issuance and sale of the Securities as herein
contemplated shall be satisfactory in form and substance to the
Representatives and counsel for the Underwriters.
(o) Termination of Agreement. If any condition specified in
this Section shall not have been fulfilled when and as required to be
fulfilled, this Agreement, or, in the case of any condition to the
purchase of Option Securities, on a Date of Delivery which is after
the Closing Time, the obligations of the several Underwriters to
purchase the relevant Option Securities, may be terminated by the
Representatives by notice to the Company at any time at or prior to
Closing Time or such Date of Delivery, as the case may be, and such
termination shall be without liability of any party to any other party
except as provided in Section 4 and except that Sections 1, 6, 7 and 8
shall survive any such termination and remain in full force and
effect.
6. Indemnification. (a) Indemnification of Underwriters.
Each of the Company and Ashland, jointly and severally, agrees to indemnify and
hold harmless each Underwriter and each person, if any, who controls any
Underwriter within the meaning of Section 15 of the 1933 Act or Section 20 of
the 1934 Act as follows:
(i) against any and all loss, liability, claim, damage and
expense whatsoever, as incurred, arising out of any untrue statement
or alleged untrue statement of a material fact contained in the
Registration Statement (or any amendment thereto), including the Rule
430A Information and the Rule 434 Information, if applicable, or the
omission or alleged omission therefrom of a material fact required to
be stated therein or necessary to make the statements therein not
misleading or arising out of any untrue statement or alleged untrue
<PAGE> 22
18
statement of a material fact included in any preliminary prospectus or
the Prospectus (or any amendment or supplement thereto), or the
omission or alleged omission therefrom of a material fact necessary in
order to make the statements therein, in the light of the
circumstances under which they were made, not misleading;
(ii) against any and all loss, liability, claim, damage and
expense whatsoever, as incurred, to the extent of the aggregate amount
paid in settlement of any litigation, or any investigation or
proceeding by any governmental agency or body, commenced or
threatened, or of any claim whatsoever based upon any such untrue
statement or omission, or any such alleged untrue statement or
omission; provided that (subject to Section 6(d) below) any such
settlement is effected with the written consent of the Company and
Ashland; and
(iii) against any and all expense whatsoever, as incurred
(including the fees and disbursements of counsel chosen by Merrill
Lynch), reasonably incurred in investigating, preparing or defending
against any litigation, or any investigation or proceeding by any
governmental agency or body, commenced or threatened, or any claim
whatsoever based upon any such untrue statement or omission, or any
such alleged untrue statement or omission, to the extent that any such
expense is not paid under (i) or (ii) above;
provided, however, that this indemnity agreement shall not apply to any loss,
liability, claim, damage or expense to the extent arising out of any untrue
statement or omission or alleged untrue statement or omission made in reliance
upon and in conformity with written information furnished to the Company by any
Underwriter through Merrill Lynch expressly for use in the Registration
Statement (or any amendment thereto), including the Rule 430A Information and
the Rule 434 Information, if applicable, or any preliminary prospectus or the
Prospectus (or any amendment or supplement thereto).
(b) Indemnification of Company, Ashland, Directors and
Officers. Each Underwriter severally agrees to indemnify and hold harmless the
Company, Ashland, their respective directors, each of the Company's officers
who signed the Registration Statement, and each person, if any, who controls
the Company or Ashland within the meaning of Section 15 of the 1933 Act or
Section 20 of the 1934 Act against any and all loss, liability, claim, damage
and expense described in the indemnity contained in subsection (a) of this
Section, as incurred, but only with respect to untrue statements or omissions,
or alleged untrue statements or omissions, made in the Registration Statement
(or any amendment thereto), including the Rule 430A Information and the Rule
434 Information, if applicable, or any preliminary prospectus or the Prospectus
(or any amendment or supplement thereto) in reliance upon and in conformity
with written information furnished to the Company by such Underwriter through
Merrill Lynch expressly for use in the Registration Statement (or any amendment
thereto) or such preliminary prospectus or the Prospectus (or any amendment or
supplement thereto).
(c) Actions against Parties; Notification. Each indemnified
party shall give notice as promptly as reasonably practicable to each
indemnifying party of any action commenced against it in respect of which
indemnity may be sought hereunder, but failure to so notify an indemnifying
party shall not relieve such indemnifying party from any liability hereunder to
the extent it is not materially prejudiced as a result thereof and in any event
shall not relieve it from any liability which it may have otherwise than on
<PAGE> 23
19
account of this indemnity agreement. In the case of parties indemnified
pursuant to Section 6(a) above, counsel to the indemnified parties shall be
selected by Merrill Lynch, and, in the case of parties indemnified pursuant to
Section 6(b) above, counsel to the indemnified parties shall be selected by the
Company. An indemnifying party may participate at its own expense in the
defense of any such action; provided, however, that counsel to the indemnifying
party shall not (except with the consent of the indemnified party) also be
counsel to the indemnified party. In no event shall the indemnifying parties be
liable for fees and expenses of more than one counsel (in addition to any local
counsel) separate from their own counsel for all indemnified parties in
connection with any one action or separate but similar or related actions in
the same jurisdiction arising out of the same general allegations or
circumstances. No indemnifying party shall, without the prior written consent
of the indemnified parties, settle or compromise or consent to the entry of any
judgment with respect to any litigation, or any investigation or proceeding by
any governmental agency or body, commenced or threatened, or any claim
whatsoever in respect of which indemnification or contribution could be sought
under this Section 6 or Section 7 hereof (whether or not the indemnified
parties are actual or potential parties thereto), unless such settlement,
compromise or consent (i) includes an unconditional release of each indemnified
party from all liability arising out of such litigation, investigation,
proceeding or claim and (ii) does not include a statement as to or an admission
of fault, culpability or a failure to act by or on behalf of any indemnified
party.
(d) Settlement without Consent if Failure to Reimburse. If at
any time an indemnified party shall have requested an indemnifying party to
reimburse the indemnified party for fees and expenses of counsel, such
indemnifying party agrees that it shall be liable for any settlement of the
nature contemplated by Section 6(a)(ii) effected without its written consent if
(i) such settlement is entered into more than 45 days after receipt by such
indemnifying party of the aforesaid request, (ii) such indemnifying party shall
have received notice of the terms of such settlement at least 30 days prior to
such settlement being entered into and (iii) such indemnifying party shall not
have reimbursed such indemnified party in accordance with such request prior to
the date of such settlement.
7. Contribution. If the indemnification provided for in
Section 6 hereof is for any reason unavailable to or insufficient to hold
harmless an indemnified party in respect of any losses, liabilities, claims,
damages or expenses referred to therein, then each indemnifying party shall
contribute to the aggregate amount of such losses, liabilities, claims, damages
and expenses incurred by such indemnified party, as incurred, (i) in such
proportion as is appropriate to reflect the relative benefits received by the
Company and Ashland on the one hand and the Underwriters on the other hand from
the offering of the Securities pursuant to this Agreement or (ii) if the
allocation provided by clause (i) is not permitted by applicable law, in such
proportion as is appropriate to reflect not only the relative benefits referred
to in clause (i) above but also the relative fault of the Company and Ashland
on the one hand and of the Underwriters on the other hand in connection with
the statements or omissions which resulted in such losses, liabilities, claims,
damages or expenses, as well as any other relevant equitable considerations.
The relative benefits received by the Company and Ashland on
the one hand and the Underwriters on the other hand in connection with the
offering of the Securities pursuant to this Agreement shall be deemed to be in
the same respective proportions as the total net proceeds from the offering of
the Securities pursuant to this
<PAGE> 24
20
Agreement (before deducting expenses) received by the Company (even though
ultimately distributed to Ashland) and the total underwriting discount received
by the Underwriters, in each case as set forth on the cover of the Prospectus,
or, if Rule 434 is used, the corresponding location on the Term Sheet, bear to
the aggregate initial public offering price of the Securities as set forth on
such cover.
The relative fault of the Company and Ashland on the one hand
and the Underwriters on the other hand shall be determined by reference to,
among other things, whether any such untrue or alleged untrue statement of a
material fact or omission or alleged omission to state a material fact relates
to information supplied by the Company or Ashland on the one hand or by the
Underwriters on the other hand and the parties' relative intent, knowledge,
access to information and opportunity to correct or prevent such statement or
omission.
The Company, Ashland and the Underwriters agree that it would
not be just and equitable if contribution pursuant to this Section 7 were
determined by pro rata allocation (even if the Underwriters were treated as one
entity for such purpose) or by any other method of allocation which does not
take account of the equitable considerations referred to above in this Section
7. The aggregate amount of losses, liabilities, claims, damages and expenses
incurred by an indemnified party and referred to above in this Section 7 shall
be deemed to include any legal or other expenses reasonably incurred by such
indemnified party in investigating, preparing or defending against any
litigation, or any investigation or proceeding by any governmental agency or
body, commenced or threatened, or any claim whatsoever based upon any such
untrue or alleged untrue statement or omission or alleged omission.
Notwithstanding the provisions of this Section 7, no
Underwriter shall be required to contribute any amount in excess of the amount
by which the total price at which the Securities underwritten by it and
distributed to the public were offered to the public exceeds the amount of any
damages which such Underwriter has otherwise been required to pay by reason of
any such untrue or alleged untrue statement or omission or alleged omission.
No person guilty of fraudulent misrepresentation (within the
meaning of Section 11(f) of the 1933 Act) shall be entitled to contribution
from any person who was not guilty of such fraudulent misrepresentation.
For purposes of this Section 7, each person, if any, who
controls an Underwriter within the meaning of Section 15 of the 1933 Act or
Section 20 of the 1934 Act shall have the same rights to contribution as such
Underwriter; each director of the Company, each officer of the Company who
signed the Registration Statement, and each person, if any, who controls the
Company within the meaning of Section 15 of the 1933 Act or Section 20 of the
1934 Act shall have the same rights to contribution as the Company; and each
director of Ashland and each person, if any, who controls Ashland within the
meaning of Section 15 of the 1933 Act or Section 20 of the 1934 Act shall have
the same rights to contribution as Ashland. The Underwriters' respective
obligations to contribute pursuant to this Section 7 are several in proportion
to the number of Initial Securities set forth opposite their respective names
in Schedule A hereto and not joint.
8. Representations, Warranties and Agreements to Survive
Delivery. All representations, warranties and agreements contained in this
Agreement or in certificates
<PAGE> 25
21
of officers of the Company or any of its subsidiaries or Ashland submitted
pursuant hereto, shall remain operative and in full force and effect,
regardless of any investigation made by or on behalf of any Underwriter or
controlling person, or by or on behalf of the Company or Ashland, and shall
survive delivery of the Securities to the Underwriters.
9. Termination of Agreement. (a) Termination; General. The
Representatives may terminate this Agreement, by notice to the Company and
Ashland, at any time at or prior to Closing Time (i) if there has been, since
the time of execution of this Agreement or since the respective dates as of
which information is given in the Prospectus, any material adverse change in
the condition, financial or otherwise, or in the earnings, business affairs or
business prospects of the Company and its subsidiaries considered as one
enterprise, whether or not arising in the ordinary course of business, or (ii)
if there has occurred any material adverse change in the financial markets in
the United States, any outbreak of hostilities or escalation thereof or other
calamity or crisis or any change or development involving a prospective change
in national or international political, financial or economic conditions, in
each case the effect of which is such as to make it, in the judgment of the
Representatives, impracticable to market the Securities or to enforce contracts
for the sale of the Securities, or (iii) if trading in any securities of
Ashland or the Company has been suspended or materially limited by the
Commission or the New York Stock Exchange, or if trading generally on the
American Stock Exchange or the New York Stock Exchange or in the Nasdaq
National Market has been suspended or materially limited, or minimum or maximum
prices for trading have been fixed, or maximum ranges for prices have been
required, by any of said exchanges or by such system or by order of the
Commission, the National Association of Securities Dealers, Inc. or any other
governmental authority, or (iv) if a banking moratorium has been declared by
either Federal or New York authorities.
(b) Liabilities. If this Agreement is terminated pursuant to
this Section, such termination shall be without liability of any party to any
other party except as provided in Section 4 hereof, and provided further that
Sections 1, 6, 7 and 8 shall survive such termination and remain in full force
and effect.
10. Default by One or More of the Underwriters. If one or
more of the Underwriters shall fail at Closing Time or a Date of Delivery to
purchase the Securities which it or they are obligated to purchase under this
Agreement (the "Defaulted Securities"), the Representatives shall have the
right, within 24 hours thereafter, to make arrangements for one or more of the
non-defaulting Underwriters, or any other underwriters, to purchase all, but
not less than all, of the Defaulted Securities in such amounts as may be agreed
upon and upon the terms herein set forth; if, however, the Representatives
shall not have completed such arrangements within such 24-hour period, then:
(i) if the number of Defaulted Securities does not exceed 10%
of the number of Securities to be purchased on such date, each of the
non-defaulting Underwriters shall be obligated, severally and not
jointly, to purchase the full amount thereof in the proportions that
their respective underwriting obligations hereunder bear to the
underwriting obligations of all non-defaulting Underwriters, or
(ii) if the number of Defaulted Securities exceeds 10% of the
number of Securities to be purchased on such date, this Agreement or,
with respect to any
<PAGE> 26
22
Date of Delivery which occurs after the Closing Time, the obligation
of the Underwriters to purchase and of the Company to sell the Option
Securities to be purchased and sold on such Date of Delivery shall
terminate without liability on the part of any non-defaulting
Underwriter.
No action taken pursuant to this Section shall relieve any
defaulting Underwriter from liability in respect of its default.
In the event of any such default which does not result in a
termination of this Agreement or, in the case of a Date of Delivery which is
after the Closing Time, which does not result in a termination of the
obligation of the Underwriters to purchase and the Company to sell the relevant
Option Securities, as the case may be, either the Representatives or the
Company shall have the right to postpone Closing Time or the relevant Date of
Delivery, as the case may be, for a period not exceeding seven days in order to
effect any required changes in the Registration Statement or Prospectus or in
any other documents or arrangements. As used herein, the term "Underwriter"
includes any person substituted for an Underwriter under this Section 10.
11. Notices. All notices and other communications hereunder
shall be in writing and shall be deemed to have been duly given if mailed or
transmitted by any standard form of telecommunication. Notices to the
Underwriters shall be directed to the Representatives at North Tower, World
Financial Center, New York, New York 10281-1201 attention of o; notices to the
Company shall be directed to it at 14701 St. Mary's Lane, Suite 200, Houston,
Texas 77079, attention of General Counsel; and notices to Ashland shall be
directed to it at 1000 Ashland Drive, Russell, Kentucky 41169, attention of
General Counsel.
12. Parties. This Agreement shall each inure to the benefit
of and be binding upon the Underwriters and the Company and their respective
successors. Nothing expressed or mentioned in this Agreement is intended or
shall be construed to give any person, firm or corporation, other than the
Underwriters, the Company and Ashland and their respective successors and the
controlling persons and officers and directors referred to in Sections 6 and 7
and their heirs and legal representatives, any legal or equitable right, remedy
or claim under or in respect of this Agreement or any provision herein
contained. This Agreement and all conditions and provisions hereof are intended
to be for the sole and exclusive benefit of the Underwriters, the Company and
Ashland and their respective successors, and said controlling persons and
officers and directors and their heirs and legal representatives, and for the
benefit of no other person, firm or corporation. No purchaser of Securities
from any Underwriter shall be deemed to be a successor by reason merely of such
purchase.
13. GOVERNING LAW AND TIME. THIS AGREEMENT SHALL BE GOVERNED
BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.
SPECIFIED TIMES OF DAY REFER TO NEW YORK CITY TIME.
14. Effect of Headings. The Article and Section headings
herein and the Table of Contents are for convenience only and shall not affect
the construction hereof.
<PAGE> 27
23
If the foregoing is in accordance with your understanding of
our agreement, please sign and return to the Company and Ashland a counterpart
hereof, whereupon this instrument, along with all counterparts, will become a
binding agreement between the Underwriters, the Company and Ashland in
accordance with its terms.
Very truly yours,
[BLAZER ENERGY CORP.],
by
-----------------------------------
Title:
ASHLAND INC.,
by
-----------------------------------
Title:
CONFIRMED AND ACCEPTED,
as of the date first
above written:
MERRILL LYNCH & CO.
MERRILL LYNCH, PIERCE,
FENNER & SMITH INCORPORATED
CREDIT SUISSE FIRST BOSTON
CORPORATION
GOLDMAN, SACHS & CO.
by MERRILL LYNCH, PIERCE,
FENNER & SMITH INCORPORATED
by
-------------------------------
Authorized Signatory
For themselves and as Representatives of the other
Underwriters named in Schedule A hereto.
<PAGE> 28
SCHEDULE A
<TABLE>
<CAPTION>
Number of
Name of Underwriter Initial Securities
- ------------------- ------------------
<S> <C>
Merrill Lynch, Pierce, Fenner & Smith
Incorporated................................................
Credit Suisse First Boston Corporation........................
Goldman, Sachs & Co...........................................
-------------
Total....................................................=============
</TABLE>
Sch. A-1
<PAGE> 29
SCHEDULE B
[BLAZER ENERGY CORP.]
[o] Shares of Common Stock
(Par Value $.01 Per Share)
1. The initial public offering price per share for the
Securities, determined as provided in said Section 2, shall be $o.
2. The purchase price per share for the Securities to be paid
by the several Underwriters shall be $o, being an amount equal to the initial
public offering price set forth above less $o per share; provided that the
purchase price per share for any Option Securities purchased upon the exercise
of the over-allotment option described in Section 2(b) shall be reduced by an
amount per share equal to any dividends or distributions declared by the
Company and payable on the Initial Securities but not payable on the Option
Securities.
Sch. B-1
<PAGE> 30
SCHEDULE C
James R. Boyd
W. Paul Teifel
Robert C. Bilger
Bradley W. Fischer
Mark D. Pierce
Jeffrey W. Lund
John V. Connolly
H. Roger Benedict
Judy C. Barnes
Thomas L. Feazell
Philip W. Block
Robert B. Stobaugh
Ashland Inc. Leveraged Employee Stock Ownership Plan
Sch. C-1
<PAGE> 31
Exhibit A
FORM OF OPINION OF COMPANY'S COUNSEL
TO BE DELIVERED PURSUANT TO
SECTION 5(b)
(i) The Company has been duly incorporated and is validly existing as
a corporation in good standing under the laws of the State of Delaware.
(ii) The Company has corporate power and authority to own, lease and
operate its properties and to conduct its business as described in the
Prospectus and to enter into and perform its obligations under the Purchase
Agreement and under [the Credit Facility, the Tax Agreement, the Services
Agreement, the Registration Rights Agreement and the Indemnification Agreement]
described in the Prospectus (the "Material Contracts").
(iii) The Company is duly qualified as a foreign corporation to
transact business and is in good standing in each jurisdiction in which such
qualification is required, whether by reason of the ownership or leasing of
property or the conduct of business, except where the failure so to qualify or
to be in good standing would not result in a Material Adverse Effect.
(iv) The authorized, issued and outstanding capital stock of the
Company is as set forth in the Prospectus in the column entitled "Actual" under
the caption "Capitalization" (except for subsequent issuances, if any, pursuant
to the Purchase Agreement or pursuant to reservations, agreements or employee
benefit plans referred to in the Prospectus or pursuant to the exercise of
options referred to in the Prospectus); the shares of issued and outstanding
capital stock of the Company have been duly authorized and validly issued and
are fully paid and non-assessable; and none of the outstanding shares of
capital stock of the Company was issued in violation of the preemptive or other
similar rights of any securityholder of the Company.
(v) The Securities have been duly authorized for issuance and sale to
the Underwriters pursuant to the Purchase Agreement and, when issued and
delivered by the Company pursuant to the Purchase Agreement against payment of
the consideration set forth in the Purchase Agreement, will be validly issued
and fully paid and non-assessable and no holder of the Securities is or will be
subject to personal liability by reason of being such a holder.
(vi) The issuance of the Securities is not subject to preemptive or
other similar rights of any securityholder of the Company.
(vii) Each Subsidiary has been duly incorporated and is validly
existing as a corporation in good standing under the laws of the jurisdiction
of its incorporation, has corporate power and authority to own, lease and
operate its properties and to conduct its business as described in the
Prospectus and is duly qualified as a foreign corporation to transact business
and is in good standing in each jurisdiction in which such qualification is
required, whether by reason of the ownership or leasing of property or the
conduct of business, except where the failure so to qualify or to be in good
standing would not result in a Material Adverse Effect; except as otherwise
disclosed in the Registration Statement, all of the issued and outstanding
capital stock of each Subsidiary has been duly authorized
Exh. A-1
<PAGE> 32
and validly issued, is fully paid and non-assessable and, to the best of our
knowledge, is owned by the Company, directly or through subsidiaries, free and
clear of any security interest, mortgage, pledge, lien, encumbrance, claim or
equity; none of the outstanding shares of capital stock of any Subsidiary was
issued in violation of the preemptive or similar rights of any securityholder
of such Subsidiary.
(viii) The Purchase Agreement has been duly authorized, executed and
delivered by the Company. Each of the Material Contracts is or will be, when
executed and delivered by the Company, duly and validly authorized, executed
and delivered by the Company and is or will be, when executed and delivered by
the Company, a legally valid and binding obligation of the Company enforceable
against the Company in accordance with its terms, except as such enforcement
may be subject to or limited by bankruptcy, insolvency and general principles
of equity.
(ix) The Registration Statement, including any Rule 462(b)
Registration Statement, has been declared effective under the 1933 Act; any
required filing of the Prospectus pursuant to Rule 424(b) has been made in the
manner and within the time period required by Rule 424(b); and, to the best of
our knowledge, no stop order suspending the effectiveness of the Registration
Statement or any Rule 462(b) Registration Statement has been issued under the
1933 Act and no proceedings for that purpose have been instituted or are
pending or threatened by the Commission.
(x) The Registration Statement, including any Rule 462(b) Registration
Statement, the Rule 430A Information and the Rule 434 Information, as
applicable, the Prospectus and each amendment or supplement to the Registration
Statement and Prospectus as of their respective effective or issue dates (other
than the financial statements and supporting schedules included therein or
omitted therefrom, as to which we need express no opinion) complied as to form
in all material respects with the requirements of the 1933 Act and the 1933 Act
Regulations.
(xi) If Rule 434 has been relied upon, the Prospectus was not
"materially different," as such term is used in Rule 434, from the prospectus
included in the Registration Statement at the time it became effective.
(xii) The form of certificate used to evidence the Common Stock
complies in all material respects with all applicable statutory requirements,
with any applicable requirements of the charter and by-laws of the Company and
the requirements of the New York Stock Exchange.
(xiii) To the best of our knowledge, there is not pending or
threatened any action, suit, proceeding, inquiry or investigation, to which the
Company or any subsidiary is a party, or to which the property of the Company
or any subsidiary is subject, before or brought by any court or governmental
agency or body, domestic or foreign, which might reasonably be expected to
result in a Material Adverse Effect, or which might reasonably be expected to
materially and adversely affect the properties or assets thereof or the
consummation of the transactions contemplated in the Purchase Agreement, the
Material Contracts and the Registration Statement or the performance by the
Company of its obligations thereunder.
(xiv) The information in the Prospectus under "Description of Capital
Stock", "Business and Properties--Government Regulation", "Business and
Properties--
Exh. A-2
<PAGE> 33
Environmental Matters", "Business and Properties--Litigation" and "Relationship
Between the Company and Ashland--Contractual Arrangements" and in the
Registration Statement under Item 14, to the extent that it constitutes matters
of law, summaries of legal matters, the Company's charter and by-laws or legal
proceedings, or legal conclusions, has been reviewed by us and is correct in
all material respects.
(xv) To the best of our knowledge, there are no statutes or
regulations that are required to be described in the Prospectus that are not
described as required.
(xvi) All descriptions in the Registration Statement of contracts and
other documents to which the Company or its subsidiaries are a party are
accurate in all material respects; to the best of our knowledge, there are no
franchises, contracts, indentures, mortgages, loan agreements, notes, leases or
other instruments required to be described or referred to in the Registration
Statement or to be filed as exhibits thereto other than those described or
referred to therein or filed or incorporated by reference as exhibits thereto,
and the descriptions thereof or references thereto are correct in all material
respects.
(xvii) To the best of our knowledge, neither the Company nor any
subsidiary is in violation of its charter or by-laws and no default by the
Company or any subsidiary exists in the due performance or observance of any
material obligation, agreement, covenant or condition contained in any
contract, indenture, mortgage, loan agreement, note, lease or other agreement
or instrument that is described or referred to in the Registration Statement or
the Prospectus or filed or incorporated by reference as an exhibit to the
Registration Statement.
(xviii) No filing with, or authorization, approval, consent, license,
order, registration, qualification or decree of, any court or governmental
authority or agency, domestic or foreign (other than under the 1933 Act and the
1933 Act Regulations, which have been obtained, or as may be required under the
securities or blue sky laws of the various states, as to which we need express
no opinion) is necessary or required in connection with the due authorization,
execution and delivery of the Purchase Agreement and the Material Contracts or
for the offering, issuance or sale of the Securities.
(xix) The execution, delivery and performance of the Purchase
Agreement and the Material Contracts and the consummation of the transactions
contemplated in the Purchase Agreement, the Material Contracts and in the
Registration Statement (including the issuance and sale of the Securities, the
use of the proceeds from the sale of the Securities as described in the
Prospectus under the caption "Use of Proceeds", the borrowing by the Company of
approximately $[ ] million under the Company's Credit Facility and the proposed
distribution by Ashland of its shares of the Company's Common Stock to
Ashland's stockholders) and compliance by the Company with its obligations
under the Purchase Agreement and the Material Contracts do not and will not,
whether with or without the giving of notice or lapse of time or both, conflict
with or constitute a breach of, or default or Repayment Event (as defined in
Section 1(a)(x) of the Purchase Agreement) under or result in the creation or
imposition of any lien, charge or encumbrance upon any property or assets of
the Company or any subsidiary pursuant to any contract, indenture, mortgage,
deed of trust, loan or credit agreement, note, lease or any other agreement or
instrument, known to us, to which the Company or any subsidiary is a party or
by which it or any of them may be bound, or to which any of the property or
assets of the Company or any subsidiary is subject (except for such conflicts,
breaches or
Exh. A-3
<PAGE> 34
defaults or liens, charges or encumbrances that would not have a Material
Adverse Effect), nor will such action result in any violation of the provisions
of the charter or by-laws of the Company or any subsidiary, or any applicable
law, statute, rule, regulation, judgment, order, writ or decree, known to us,
of any government, government instrumentality or court, domestic or foreign,
having jurisdiction over the Company or any subsidiary or any of their
respective properties, assets or operations.
(xx) To the best of our knowledge, there are no persons with
registration rights or other similar rights to have any securities registered
pursuant to the Registration Statement or otherwise registered by the Company
under the 1933 Act.
(xxi) The Company is not an "investment company" or an entity
"controlled" by an "investment company," as such terms are defined in the 1940
Act.
[(xxii) The Rights under the Company's Shareholder Rights Plan to
which holders of the Securities will be entitled have been duly authorized and
validly issued.]
Nothing has come to our attention that would lead us to believe
that the Registration Statement or any amendment thereto, including the Rule
430A Information and Rule 434 Information (if applicable), (except for
financial statements and schedules and other financial data included therein
or omitted therefrom, as to which we need make no statement), at the time such
Registration Statement or any such amendment became effective, contained an
untrue statement of a material fact or omitted to state a material fact
required to be stated therein or necessary to make the statements therein not
misleading or that the Prospectus or any amendment or supplement thereto
(except for financial statements and schedules and other financial data
included therein or omitted therefrom, as to which we need make no statement),
at the time the Prospectus was issued, at the time any such amended or
supplemented prospectus was issued or at the Closing Time, included or includes
an untrue statement of a material fact or omitted or omits to state a material
fact necessary in order to make the statements therein, in the light of the
circumstances under which they were made, not misleading.
In rendering such opinion, such counsel may rely, as to matters
of fact (but not as to legal conclusions), to the extent they deem proper, on
certificates of responsible officers of the Company and public officials. Such
opinion shall not state that it is to be governed or qualified by, or that it
is otherwise subject to, any treatise, written policy or other document
relating to legal opinions, including, without limitation, the Legal Opinion
Accord of the ABA Section of Business Law (1991).
Exh. A-4
<PAGE> 35
Exhibit B
FORM OF OPINION OF ASHLAND'S COUNSEL
TO BE DELIVERED PURSUANT TO
SECTION 5(c)
(i) Ashland has been duly incorporated and is validly existing as a
corporation in good standing under the laws of the Commonwealth of Kentucky.
(ii) Ashland has corporate power and authority to conduct its business
as described in the Prospectus and to enter into and perform its obligations
under the Purchase Agreement and under [the Tax Agreement, the Services
Agreement, the Registration Rights Agreement and the Indemnification Agreement]
described in the Prospectus (the "Material Contracts").
(iii) The Purchase Agreement has been duly authorized, executed and
delivered by Ashland. Each of the Material Contracts is or will be, when
executed and delivered by Ashland, duly and validly authorized, executed and
delivered by Ashland and is or will be, when executed and delivered by Ashland,
a legally valid and binding obligation of Ashland enforceable against Ashland
in accordance with its terms, except as such enforcement may be subject to or
limited by bankruptcy, insolvency and general principles of equity.
(iv) To the best of our knowledge, Ashland is not in violation of its
charter or by-laws.
(v) No filing with, or authorization, approval, consent, license,
order, registration, qualification or decree of, any court or governmental
authority or agency, domestic or foreign (other than under the 1933 Act and the
1933 Act Regulations, which have been obtained, or as may be required under the
securities or blue sky laws of the various states, as to which we need express
no opinion) is necessary or required in connection with the due authorization,
execution and delivery of the Purchase Agreement and the Material Contracts.
(vi) The execution, delivery and performance of the Purchase Agreement
and the Material Contracts and the consummation of the transactions
contemplated in the Purchase Agreement, the Material Contracts and in the
Registration Statement (including the issuance and sale of the Securities, the
use of the proceeds from the sale of the Securities as described in the
Prospectus under the caption "Use of Proceeds", the borrowing by the Company of
approximately $[ ] million under the Credit Facility and the proposed
distribution by Ashland of its shares of the Company's Common Stock to
Ashland's stockholders) and compliance by Ashland with its obligations under
the Purchase Agreement and the Material Contracts do not and will not, whether
with or without the giving of notice or lapse of time or both, conflict with or
constitute a breach of, or default or Repayment Event (as defined in Section
1(a)(x) of the Purchase Agreement) under or result in the creation or
imposition of any lien, charge or encumbrance upon any property or assets of
Ashland or any subsidiary pursuant to any contract, indenture, mortgage, deed
of trust, loan or credit agreement, note, lease or any other agreement or
instrument, known to us, to which Ashland or any subsidiary is a party or by
which it or any of them may be bound, or to which any of the property or assets
of Ashland or any subsidiary is subject (except for such conflicts, breaches or
defaults or
Exh. B-1
<PAGE> 36
liens, charges or encumbrances that would not have a Material Adverse Effect),
nor will such action result in any violation of the provisions of the charter
or by-laws of Ashland or any subsidiary, or any applicable law, statute, rule,
regulation, judgment, order, writ or decree, known to us, of any government,
government instrumentality or court, domestic or foreign, having jurisdiction
over Ashland or any subsidiary or any of their respective properties, assets or
operations.
Nothing has come to our attention that would lead us to believe
that the Registration Statement or any amendment thereto, including the Rule
430A Information and Rule 434 Information (if applicable), (except for
financial statements and schedules and other financial data6 included therein
or omitted therefrom, as to which we need make no statement), at the time such
Registration Statement or any such amendment became effective, contained an
untrue statement of a material fact or omitted to state a material fact
required to be stated therein or necessary to make the statements therein not
misleading or that the Prospectus or any amendment or supplement thereto
(except for financial statements and schedules and other financial data
included therein or omitted therefrom, as to which we need make no statement),
at the time the Prospectus was issued, at the time any such amended or
supplemented prospectus was issued or at the Closing Time, included or includes
an untrue statement of a material fact or omitted or omits to state a material
fact necessary in order to make the statements therein, in the light of the
circumstances under which they were made, not misleading.
In rendering such opinion, such counsel may rely, as to matters
of fact (but not as to legal conclusions), to the extent they deem proper, on
certificates of responsible officers of the Company and Ashland and public
officials. Such opinion shall not state that it is to be governed or qualified
by, or that it is otherwise subject to, any treatise, written policy or other
document relating to legal opinions, including, without limitation, the Legal
Opinion Accord of the ABA Section of Business Law (1991).
Exh. B-2
<PAGE> 37
Exhibit C
FORM OF LOCK-UP FROM DIRECTORS AND OFFICERS
PURSUANT TO SECTION 5(k)
[o], 1997
MERRILL LYNCH & CO.
Merrill Lynch, Pierce, Fenner & Smith
Incorporated,
Credit Suisse First Boston Corporation
Goldman, Sachs & Co.,
as Representatives of the several
Underwriters to be named in the
within-mentioned Purchase Agreement
c/o Merrill Lynch & Co.
Merrill Lynch, Pierce, Fenner & Smith
Incorporated
North Tower
World Financial Center
New York, New York 10281-1209
Re: Proposed Public Offering by [Blazer Energy Corp.]
Dear Sirs:
The undersigned, a stockholder [or optionholder] [and an
officer and/or director] of [Blazer Energy Corp.], a Delaware corporation (the
"Company"), understands that Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner
& Smith Incorporated ("Merrill Lynch"), Credit Suisse First Boston Corporation
and Goldman, Sachs & Co. propose to enter into a Purchase Agreement (the
"Purchase Agreement") with the Company and Ashland providing for the public
offering of shares (the "Securities") of the Company's common stock, par value
$.01 per share (the "Common Stock"). In recognition of the benefit that such an
offering will confer upon the undersigned as a stockholder [or optionholder]
[and an officer and/or director] of the Company, and for other good and
valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the undersigned agrees with each underwriter to be named in the
Purchase Agreement that, during a period of 180 days from the date of the
Purchase Agreement, the undersigned will not, without the prior written consent
of the Representatives, directly or indirectly, (i) offer, pledge, sell,
contract to sell, sell any option or contract to purchase, purchase any option
or contract to sell, grant any option, right or warrant for the sale of, or
otherwise dispose of or transfer any shares of the Company's Common Stock or
any securities convertible into or exchangeable or exercisable for Common
Stock, whether now owned or hereafter acquired by the undersigned or with
respect to which the undersigned has or hereafter acquires the power of
disposition, or file any registration statement under the
Exh. C-1
<PAGE> 38
Securities Act of 1933, as amended, with respect to any of the foregoing or
(ii) enter into any swap or any other agreement or any transaction that
transfers, in whole or in part, directly or indirectly, the economic
consequence of ownership of the Common Stock, whether any such swap or
transaction is to be settled by delivery of Common Stock or other securities,
in cash or otherwise.
Very truly yours,
Signature:
Print Name:
Exh. C-2
<PAGE> 39
Annex A
FORM OF ACCOUNTANTS' COMFORT LETTER PURSUANT TO
SECTION 5(f)
We are independent public accountants with respect to the
Company within the meaning of the 1933 Act and the applicable published 1933
Act Regulations
(i) in our opinion, the audited financial statements [and the
related financial statement schedules] included in the Registration
Statement and the Prospectus comply as to form in all material
respects with the applicable accounting requirements of the 1933 Act
and the published rules and regulations thereunder;
(ii) on the basis of procedures (but not an examination in
accordance with generally accepted auditing standards) consisting of a
reading of the unaudited interim consolidated financial statements of
the Company for the three month periods ended December 31, 1995 and
December 31, 1996 and the three and six month periods ended March 31,
1996 and March 31, 1997, included in the Registration Statement and
the Prospectus (collectively, the "Quarterly Financials"), a reading
of the minutes of all meetings (including any Committee meetings) of
the stockholders and directors of the Company and its subsidiaries and
all meetings of the directors of Ashland and the Compensation and
Audit Committees of Ashland's Board of Directors since October 1,
1996, inquiries of certain officials of Ashland, the Company and its
subsidiaries responsible for financial and accounting matters, a
review of interim financial information in accordance with standards
established by the American Institute of Certified Public Accountants
in Statement on Auditing Standards No. 71, Interim Financial
Information ("SAS 71"), with respect to the six month periods ended
March 31, 1996 and March 31, 1997 and such other inquiries and
procedures as may be specified in such letter, nothing came to our
attention that caused us to believe that:
(A) the Quarterly Financials included in the
Registration Statement and the Prospectus do not comply as to
form in all material respects with the applicable accounting
requirements of the 1933 Act and the 1933 Act Regulations or
any material modifications should be made to the unaudited
consolidated financial statements included in the
Registration Statement and the Prospectus for them to be in
conformity with generally accepted accounting principles;
(B) at a specified date not more than three days
prior to the date of this Agreement, there was any change in
the consolidated capital stock (other than issuances of
capital stock upon exercise of options, in each case which
were outstanding on the date of the latest financial
statement included in the Registration Statement) of the
Company or any decrease in the consolidated net current
assets or stockholders' equity of the Company or any increase
in the consolidated long-term debt of the Company, in each
case as compared with amounts shown in the latest balance
sheet included in the Registration Statement, except in each
case for changes, decreases
Annex A-1
<PAGE> 40
or increases that the Registration Statement discloses have
occurred or may occur; or
(C) for the period from March 31, 1997 to a
specified date not more than three days prior to the date of
this Agreement, there was any decrease in consolidated net
revenues, consolidated operating income, the total or per
share amounts of consolidated income before extraordinary
items or consolidated net income, in each case as compared
with the comparable period in the preceding year, except in
each case for any decreases that the Registration Statement
discloses have occurred or may occur;
(iii) based upon the procedures set forth in clause (ii)
above and a reading of the historical data included in the Selected
Historical and Pro Forma Financial Information included in the
Registration Statement and a reading of the financial statements from
which such data were derived, nothing came to our attention that
caused us to believe that the historical data included in the Selected
Historical and Pro Forma Financial Information included in the
Registration Statement do not comply as to form in all material
respects with the disclosure requirements of Item 301 of Regulation
S-K of the 1933 Act, that the amounts included in the historical data
included in the Selected Historical and Pro Forma Financial
Information are not in agreement with the corresponding amounts in the
audited consolidated financial statements for the respective periods
or that the financial statements not included in the Registration
Statement from which certain of such data were derived are not in
conformity with generally accepted accounting principles;
(iv) we have compared the information in the Registration
Statement under selected captions with the disclosure requirements of
Regulation S-K of the 1933 Act and on the basis of limited procedures
specified herein nothing came to our attention that caused us to
believe that this information does not comply as to form in all
material respects with the disclosure requirements of Items 302, 402
and [503(d)], respectively, of Regulation S-K;
(v) we are unable to and do not express any opinion on the
[Pro Forma Combining Statement of Operations] (the "Pro Forma
Statement") included in the Registration Statement or on the pro forma
adjustments applied to the historical amounts included in the Pro
Forma Statement; however, for purposes of this letter we have:
(A) read the Pro Forma Statement;
(B) performed an audit of the financial statements
as of and for the year ended September 30, 1996, and a review
in accordance with SAS 71 of the financial statements as of
and for the six month period ended March 31, 1997, to which
the pro forma adjustments were applied;
(C) made inquiries of certain officials of the
Company who have responsibility for financial and accounting
matters about the basis for their determination of the pro
forma adjustments and whether the Pro Forma Statement
complies as to form in all material respects with the
applicable accounting requirements of Rule 11-02 of
Regulation S-X; and
Annex A-2
<PAGE> 41
(D) proved the arithmetic accuracy of the
application of the pro forma adjustments to the historical
amounts in the Pro Forma Statement; and on the basis of such
procedures and such other inquiries and procedures as
specified herein, nothing came to our attention that caused
us to believe that the Pro Forma Statement included in the
Registration Statement does not comply as to form in all
material respects with the applicable requirements of Rule
11-02 of Regulation S-X or that the pro forma adjustments
have not been properly applied to the historical amounts in
the compilation of those statements; and
(vi) in addition to the procedures referred to in clause (ii)
above, we have performed other procedures, not constituting an audit,
with respect to certain amounts, percentages, numerical data and
financial information appearing in the Registration Statement, which
are specified herein, and have compared certain of such items with,
and have found such items to be in agreement with, the accounting and
financial records of the Company.
Annex A-3
<PAGE> 1
EXHIBIT 10.5
PRODUCTION SHARING CONTRACT
BETWEEN
NIGERIAN NATIONAL PETROLEUM CORPORATION
AND
ASHLAND NIGERIA EXPLORATION UNLIMITED
<PAGE> 2
C O N T E N T S
<TABLE>
<CAPTION>
Page
----
<S> <C>
Recital/Preamble . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
CLAUSES
- -------
CLAUSE 1 DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . 2
CLAUSE 2 BONUSES . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
CLAUSE 3 SCOPE . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
CLAUSE 4 TERM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
CLAUSE 5 EXCLUSION OF AREAS . . . . . . . . . . . . . . . . . . . . . . 8
CLAUSE 6 WORK PROGRAMME AND EXPENDITURES . . . . . . . . . . . . . . . 8
CLAUSE 7 MANAGEMENT COMMITTEE . . . . . . . . . . . . . . . . . . . . . 10
CLAUSE 8 RIGHTS AND OBLIGATIONS OF THE PARTIES . . . . . . . . . . . . 17
CLAUSE 9 RECOVERY OF OPERATING COSTS AND CRUDE OIL ALLOCATION . . . . 21
CLAUSE 10 VALUATION OF AVAILABLE CRUDE OIL . . . . . . . . . . . . . . . 23
CLAUSE 11 SOLE RISK OPERATIONS . . . . . . . . . . . . . . . . . . . . . 25
CLAUSE 12 PAYMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
CLAUSE 13 TITLE TO EQUIPMENT . . . . . . . . . . . . . . . . . . . . . . 31
CLAUSE 14 EMPLOYMENT AND TRAINING OF NIGERIAN PERSONNEL . . . . . . . . 32
CLAUSE 15 BOOKS AND ACCOUNTS, AUDITS AND OVERHEAD CHARGES . . . . . . . 33
CLAUSE 16 TAXES, ROYALTY, RATES AND DUTIES . . . . . . . . . . . . . . . 34
CLAUSE 17 INSURANCE . . . . . . . . . . . . . . . . . . . . . . . . . . 35
CLAUSE 18 CONFIDENTIALITY AND PUBLIC ANNOUNCEMENTS . . . . . . . . . . . 36
CLAUSE 19 FORCE MAJEURE . . . . . . . . . . . . . . . . . . . . . . . . 38
</TABLE>
-1-
<PAGE> 3
<TABLE>
<S> <C> <C>
CLAUSE 20 LAWS AND REGULATIONS . . . . . . . . . . . . . . . . . . . . . 38
CLAUSE 21 UTILISATION OF NATURAL GAS . . . . . . . . . . . . . . . . . . 39
CLAUSE 22 CONSULTATION AND ARBITRATION . . . . . . . . . . . . . . . . . 40
CLAUSE 23 EFFECTIVENESS . . . . . . . . . . . . . . . . . . . . . . . . 41
CLAUSE 24 OTHER PROVISIONS . . . . . . . . . . . . . . . . . . . . . . . 41
CLAUSE 25 NOTICES . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
ANNEXES
- -------
Annex A - Contract Area
Annex B - Accounting Procedure
Annex C - Allocation Procedure
Annex D - Nomination, Ship Scheduling, and Lifting Procedure
Annex E - Procurement and Project Implementation Procedures
</TABLE>
-2-
<PAGE> 4
THIS PRODUCTION SHARING CONTRACT (this "Contract") is made and entered into
this 25th day of March, 1992 ("Effective Date") BETWEEN the Nigerian National
Petroleum Corporation (hereinafter called "NNPC" which expression shall, where
the context so admits, include its successors and assigns) of the one part, AND
Ashland Nigeria Exploration Unlimited, an unlimited company incorporated in
Nigeria under the Companies and Allied Matters Act 1990 (hereinafter called
"Company" which expression shall, where the context so admits, include its
successors and assigns) of the other part.
WHEREAS, by virtue of Section 1 of the Petroleum Act 1969 and its amendments,
the Federal Republic of Nigeria ("Nigeria") is vested with the entire ownership
and control of all petroleum in, under or upon any land which is in Nigeria or
under the territorial waters of Nigeria or forms part of the continental shelf
of Nigeria; and
WHEREAS, NNPC is the holder of the Oil Prospecting Licenses ("OPLs") 90 and 225
described in Annex A hereto; and
WHEREAS by virtue of the Nigerian National Petroleum Corporation Act 1977, NNPC
has the right, power and authority to enter into this Contract; and
WHEREAS, NNPC and an Affiliate of Company (Ashland Oil (Nigeria) Company)
entered into a Letter of Understanding dated 16th August, 1991 ("LOU") which
set forth terms and conditions under which Petroleum Operations would be
conducted in OPLs 90 and 225 with the intent that such terms and conditions
would be incorporated into a definitive production sharing contract which is
this Contract; and
WHEREAS, Company represents that it has assumed all the rights and obligations
of its said Affiliate under the said LOU and represents that it has the
technical competence to conduct Petroleum Operations and has the funds both
local and foreign and has agreed to conduct the said Operations.
-1-
<PAGE> 5
NOW, THEREFORE, in consideration of the premises and the mutual covenants
herein contained, it is hereby agreed as follows:
CLAUSE 1
DEFINITIONS
As used in this Contract, unless otherwise specified, the following terms shall
have the respective meaning here ascribed to them:
(a) "ACCOUNTING PROCEDURE" means the rules and procedures set forth in Annex
B and attached to and forming part of this Contract;
(b) "AFFILIATE" means a company or other entity that controls or is
controlled by a Party to this Contract, or a company or other entity
which controls or is controlled by a company or other entity which
controls a Party to this Contract, it being understood that control
shall mean ownership by one company or entity of at least 50% of:
(i) the voting stock, if the other company is a corporation issuing
stock or;
(ii) the controlling rights or interests, if the other entity is not a
corporation.
(c) "AVAILABLE CRUDE OIL" means the Crude Oil won and saved from the
Contract Area after deducting amounts used in Petroleum Operations.
(d) "BARREL" means a quantity or unit of Crude Oil, equal to forty-two (42)
United States gallons at the temperature of sixty degrees (60degrees)
Fahrenheit.
(e) "BUDGET" means the cost estimate of items included in a Work Programme.
(f) "COMMERCIAL QUANTITY" means the capability to produce at least 10,000
Barrels per day of Crude Oil from the Contract Area.
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(g) "CONCESSION RENTALS" means the rents payable on the OPLs or OMLs under
the Petroleum Act 1969 and the Petroleum (Drilling and Production)
Regulations 1969.
(h) "CONTRACT AREA" means the Nigerian OPLs 90 and 225 as known to the
Parties hereto and which OPLs are shown and particularly described in
documents attached to and forming part of this Contract as Annex A,
and/or any subsequent Oil Mining Lease(s) ("OMLs") derived therefrom.
(i) "COST OIL" means the quantum of Available Crude Oil allocated to Company
to enable it to generate the Proceeds to recover all Operating Costs as
specified in the Accounting Procedure.
(j) "CRUDE OIL" means liquid petroleum which has been treated but not
refined and includes condensates but excludes water and sediments.
(k) "EFFECTIVE DATE" means the date first above written.
(1) "FOREIGN CURRENCY" means currency other than that of Nigeria but
acceptable to Government, to NNPC and to Company.
(m) "GOVERNMENT" means the government of the Federal Republic of Nigeria.
(n) "LIFTING PROCEDURE" means the rules and procedures set forth in Annex D
and attached to and forming part of this Contract.
(o) "NATURAL GAS" means all gaseous hydrocarbons produced in association
with Crude Oil or from reservoirs which produce mainly gaseous
hydrocarbons.
(p) "OIL MINING LEASE" ("OML") means a lease granted by the Minister of
Petroleum and Mineral Resources under the Petroleum Act 1969, to a
lessee to search for, win, work, carry away and dispose of Petroleum.
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(q) "OIL PROSPECTING LICENSE" ("OPL") means a license granted by the
Minister of Petroleum and Mineral Resources under the Petroleum Act
1969, to a licensee to prospect for Petroleum.
(r) "OPERATING COSTS" means expenditures made and obligations incurred in
carrying out Petroleum Operations as determined in accordance with the
Accounting Procedure.
(s) "PARTIES" means NNPC and Company.
(t) "PETROLEUM OPERATIONS" means the same as defined in the PPT Act 1959, as
amended.
(u) "PETROLEUM PROFITS TAX" OR "PPT" means the taxes pursuant to the
Petroleum Profits Tax Act 1959, as amended.
(v) "PROCEEDS" means the amount in U.S. Dollars determined by multiplying
the Realisable Price by the number of Barrels of Available Crude Oil
lifted by either Party.
(w) "PROFIT OIL" means the balance of Available Crude Oil after the
allocation of Royalty Oil, Tax Oil, and Cost Oil.
(x) "REALISABLE PRICE" means the price in U.S. Dollars per Barrel determined
pursuant to Clause 10.
(y) "ROYALTY" means the amount payable pursuant to the Petroleum Act 1969
and Petroleum (Drilling and Production) Regulations 1969.
(z) "ROYALTY OIL" means the quantum of available Crude Oil allocated to NNPC
which will generate an amount of Proceeds equal to the actual payment of
Royalty and Concession Rentals.
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(aa) "TAX OIL" means the quantum of Available Crude Oil allocated to NNPC
which will generate an amount of Proceeds equal to the actual payment of
PPT.
(ab) "WORK PROGRAMME" means for the applicable period a statement itemizing
the Petroleum Operations to be carried out in the Contract Area.
(ac) "YEAR" means a period of twelve (12) months commencing with January 1
and ending the following December 31, according to the Gregorian
Calendar.
CLAUSE 2
BONUSES
2.1 SIGNATURE BONUS
Company shall pay to NNPC a Signature Bonus in the sum of two million
U.S. Dollars ($2,000,000) within thirty (30) days after the Effective
Date of this Contract which NNPC shall pay to the Government.
2.2 PRODUCTION BONUSES
Company shall pay NNPC the following Production Bonuses:
(a) the sum of two million U.S. Dollars ($2,000,000) within 30 days
after the cumulative production from the Contract Area reaches 20
million Barrels;
(b) the sum of two million U.S. Dollars ($2,000,000) within 30 days
after the cumulative production from the Contract Area reaches 30
million Barrels; and
(c) the sum of two million U.S. Dollars ($2,000,000) within 30 days
after the cumulative production from the Contract Area reaches 50
million Barrels.
2.3 The Signature Bonus and Production Bonuses provided for in this Clause 2
shall not be recoverable as Cost Oil.
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2.4 Except as provided in this Clause 2 or elsewhere in this Contract, there
shall be no other bonuses, fees, or premiums payable by Company.
CLAUSE 3
SCOPE
3.1 This Contract is a production sharing contract governed in accordance
with the terms and provisions hereof. Petroleum Operations and
provision of financing and technical requirements by Company in
accordance with the terms of this Contract shall be in consultation and
cooperation with NNPC. NNPC, as holder of all rights in and to the
Contract Area, hereby appoints and constitutes Company the exclusive
company to conduct Petroleum Operations in the Contract Area.
3.2 During the Term of this Contract the total Available Crude Oil shall be
allocated to the Parties in accordance with the provisions of Clause 9,
the Accounting Procedure (Annex B) and the Allocation Procedure (Annex
C).
3.3 Company shall carry the risk of Operating Costs required to carry out
Petroleum Operations and shall therefore have an economic interest in
development of Crude Oil deposits in the Contract Area.
3.4 Company is engaged in Petroleum Operations pursuant to the Petroleum
Profits Tax Act 1959 and its subsequent amendments ("PPT Act") and
accordingly the Companies Income Tax Act 1979, as amended, shall have no
application.
CLAUSE 4
TERM
4.1 The Term of this Contract, subject to paragraphs 4.2 and 4.3, shall be
twenty-five (25) years certain (including the exploration period) from
the Effective Date.
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4.2 This Contract may be terminated in its entirety at any time by:
(a) NNPC giving to Company not less than ninety (90) days prior
written notice of termination if Company has committed a material
breach of its obligations hereunder including the Work Programme
approved for any given period under the Contract and Company
fails to remedy such breach within (6) six months of the original
notification of such breach; or
(b) NNPC giving to Company not less than ninety (90) days written
notice of termination if Company is declared bankrupt and is
forced to make restitution to its creditors, or becomes
insolvent, or is found by a court having competent jurisdiction
to have willfully violated any Nigerian laws and regulations
governing Petroleum Operations, financial transactions and/or
commercial operations during the Term of the Contract; or
(c) Company giving to NNPC not less than ninety (90) days prior
written notice to that effect subject to the conditions in Clause
6.2.
4.3 If Crude Oil is not discovered in quantities which can be produced
commercially within the Contract Area within five (5) years from the
Effective Date, this Contract shall automatically terminate in its
entirety.
4.4 If Crude Oil is discovered in any portion of the Contract Area within
five (5) years from the Effective Date, which in the judgment of NNPC
and Company can be produced commercially based on consideration of all
pertinent operating and financial data, then as to that particular
portion of the Contract Area development will commence. In other
portions of the Contract Area which have not been excluded pursuant to
Clause 5, exploration may continue.
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CLAUSE 5
EXCLUSION OF AREAS
Not later than the end of three (3) years from the Effective Date twenty-five
percent (25%) of the acreage in the original Contract Area shall be excluded
from the Contract Area and not later than the end of five (5) years from the
Effective Date an additional twenty-five percent (25%) of the acreage in the
original Contract Area shall be excluded from the Contract Area. Such acreage
to be excluded from the Contract Area shall be agreed by both Parties and shall
not include any parts of the Contract Area corresponding to the surface areas
of any reservoir capable of producing Crude Oil.
CLAUSE 6
WORK PROGRAMME AND EXPENDITURES
6.1 Company shall within six (6) months after the Effective Date, unless
mutually extended by the Parties, commence seismic investigations in the
Contract Area and thereafter shall commence drilling operations in
accordance with sound international petroleum practices. Geologic
conditions warranting, drilling operations will be commenced not later
than eighteen (18) months after the Effective Date unless mutually
extended by the Parties.
6.2 Company shall conduct Petroleum Operations during the first five (5)
years following the Effective Date in accordance with the minimum Work
Programme provided in this Clause 6.2 which shall be conducted in two
phases as follows:
(a) For the first phase, during the initial three (3) year period
following the Effective Date, the minimum Work Programme shall
consist of 2,000 km of 2-D seismic, 200 sq km of 3-D seismic and
the drilling of three (3) wells; provided however, that Company
shall have no obligation to expend more than twenty million U.S.
Dollars ($20,000,000) for Petroleum Operations during such period
with respect to this first phase even if the said minimum Work
Programme has not been accomplished. The minimum Work Programme
hereunder and the cost therefor shall include such work, if any,
incurred by the Company prior to the Effective Date pursuant to
Clause 15 of
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the Letter of Understanding between NNPC and an Affiliate of
Company dated 16th August, 1991.
(b) For the second phase, during the subsequent two (2) year period
the minimum Work Programme shall consist of three (3) additional
wells; provided however, that Company shall have no obligation to
expend more than ten million U.S. Dollars ($10,000,000) for
Petroleum Operations during such two (2) year period with respect
to this second phase even if the said minimum Work Programme has
not been accomplished.
If at any time within the initial three (3) year period (the first phase
above) Company should terminate this Contract pursuant to Clause 4 prior
to fulfilling the minimum Work Programme outlined in Clause 6.2(a) then
Company shall pay to NNPC the difference between twenty million U.S.
Dollars ($20,000,000) and the actual amount expended. Should Company
terminate this Contract pursuant to Clause 4 within the subsequent two
(2) year period (the second phase above) prior to fulfilling the minimum
Work Programme outlined in Clause 6.2(b) then Company shall pay to NNPC
the difference between ten million U.S. Dollars ($10,000,000) and the
actual amount expended. Provided however, should the actual amount
expended with respect to the first phase exceed twenty million U.S.
Dollars ($20,000,000), such excess shall be applied against the
expenditure for the second phase, such that Company shall have no
obligation to expend in the aggregate more than thirty million U.S.
Dollars ($30,000,000) for Petroleum Operations during the first five (5)
year period from the Effective Date.
6.3 Within two (2) months after the Effective Date and thereafter at least
three (3) months prior to the beginning of each Year, Company shall
prepare and submit for review and approval by the Management Committee,
pursuant to Clause 7, a Work Programme and Budget for the Contract Area
setting forth the Petroleum Operations which Company proposes to carry
out during the ensuing Year, or in the case of the first Work Programme
and Budget, during the remainder of the current Year. The Management
Committee shall review and approve such Work Programme and Budget in
accordance with Clause 7.4.
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CLAUSE 7
MANAGEMENT COMMITTEE
7.1 A Management Committee shall be established within thirty (30) days from
the date of execution of the Contract for the purpose of providing
orderly direction or all matters pertaining to the Petroleum Operations
and Work Programmes pursuant to Clause 6.3 of the Contract. The powers
and duties of the Management Committee shall include but not be limited
to the following:
(a) the review, revision, and approval of all proposed Work
Programmes and Budgets in accordance with Clause 7.3(e);
(b) the review, revision, and approval of any proposed
recommendations made by either Party or by any Sub-Committee,
pursuant to Clause 7.6 with respect to Petroleum Operations;
(c) ensuring that the Company carries out the decisions of the
Management Committee and conducts Petroleum Operations pursuant
to this Contract;
(d) the consideration and decision on matters relating to the
exclusion of areas in the Contract Area pursuant to Clause 5;
(e) settlement of claims and litigation in excess of three hundred
thousand Naira (N300,000) or the equivalent thereof in Foreign
Currency, or such other amount as may be approved by the
Management Committee insofar as such claims are not covered by
policies of insurance maintained under this Contract;
(f) consideration and approval of the sale or disposal of any items
or property relating to Petroleum Operations in accordance with
the provisions of the Contract except for items/properties of
historic costs less than one hundred thousand Naira (N100,000);
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(g) settlement of unresolved audit exceptions arising from audits as
provided for in Clause 15.2 of this Contract;
(h) ensuring that the Company implements the provisions of the
Accounting Procedure (Annex B), the Lifting Procedure (Annex D),
and the Procurement and Project Implementation Procedures (Annex
E) and all amendments and revisions thereto as agreed by the
Parties;
(i) any other matters relating to Petroleum Operations except:
(i) those matters under the sole discretion and control of the
Company in carrying out its duties and functions,
(ii) those matters elsewhere provided for in this Contract, or
(iii) those matters reserved to the Parties in their respective
rights pursuant to Clause 8;
(j) consideration and approval of the sale or disposal and exchange
of information to third parties other than routine exchange of
seismic data and other such data commonly exchanged within the
industry;
(k) consideration and determination of any other matter relating to
the Petroleum Operations which may be referred to it by any Party
(other than any proposal to amend this Contract) or which is
otherwise designated under this Contract for reference to it; and
(l) the consideration and determination of matters relating to Sole
Risk Operations except for those matters under the sole
discretion and control of the Sole Risk Party as provided for in
Clause 11 of this Contract.
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7.2 (a) The Management Committee shall consist of ten (10) persons
appointed by the Parties as follows:
NNPC - 5
Company - 5
(b) Each Party shall designate by notice in writing to the other
Party, the names of its representatives to serve as members of
the Management Committee as provided in Clause 7.2(a) hereof and
their respective alternates, which members or alternates shall be
authorized to represent that Party with respect to the decisions
of the Management Committee. Such notice shall give the names,
titles and addresses of the designated members and alternates.
Each member may nominate any other member or alternate to
represent such member at meetings of the Management Committee.
(c) At least fourteen (14) business days prior to each scheduled
Management Committee meeting, the Company shall provide an agenda
of matters, with briefs, to be considered during such meeting.
Any Party desiring to have other matters placed on the agenda
shall give notice to the other Party not less than seven (7)
business days prior to the scheduled meeting. No other matter
may be introduced into the agenda at the meeting for deliberation
unless mutually agreed by the Parties. No agenda shall be
required in the event of an emergency meeting called pursuant to
Clause 7.5(b).
(d) Either Party may change any of its respective members or
alternates as described in Clause 7.2 (b) from time to time by
notifying the other Party in writing not less than ten (10) days
in advance of the effective date of such change.
(e) NNPC shall appoint the Chairman of the Management Committee and
the Company shall appoint the Secretary. The Secretary shall not
be a member of the Management Committee but shall keep minutes of
all meetings and records of all decisions of the Management
Committee. Within fourteen (14) days after each meeting, the
Secretary
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shall forward drafts of the minutes to the Parties. Within
fourteen days thereafter each Party shall return the minutes with
its comments to the Secretary who shall within fourteen (14) days
thereafter forward the final draft to the other Party. The
minutes of each meeting shall be approved by the Management
Committee at the next meeting and copies thereof shall be
supplied to the Parties. In addition, the Secretary shall at
each meeting, prepare a written summary of any decisions made by
the Management Committee for approval and signature by the
Parties prior to adjournment.
7.3 (a) Not later than the 28th day of February of each Year, the
Chairman shall prepare and forward to the Parties, a calendar of
meetings as agreed by the Management Committee for that Year.
(b) Unless otherwise agreed by the Parties, the Management Committee
shall meet at the head office or the Company once every four (4)
calendar months, or at such other intervals or venue as may be
agreed by the Management Committee and, in addition, whenever
requested by either Party by giving at least twenty-one (21) days
notice in writing to other Party which notice shall specify the
matter or matters to be considered at the meeting; or, when
summoned by the Chairman or by the Company as an emergency
meeting for which no specified notice period shall be required.
(c) The quorum for any meeting of the Management Committee shall
consist of a minimum of three (3) representatives of NNPC and
three (3) representatives of the Company. The Chairman or his
alternate and the Company's Managing Director or his alternate
must be present at every Management Committee meeting for a
quorum to be formed. If no such quorum is present, the Chairman
shall call another meeting of the Management Committee giving at
least fourteen (14) days written notice of such meeting.
(d) The Secretary shall convene all meetings of the Management
Committee other than the emergency meetings.
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(e) Within eight (8) weeks after the submission of a Work Programme
and Budget by Company pursuant to Clause 6.3, the Management
Committee shall meet to consider and approve such submission.
Should NNPC wish to propose a revision as to certain specific
features of the said Work Programme and Budget, it shall within
six (6) weeks after receipt thereof so notify Company in writing
specifying in reasonable detail the changes requested and its
reasons therefor. The Management Committee will endeavor to
resolve the request for revisions proposed by NNPC. If NNPC has
not proposed any revisions in writing within six (6) weeks, then
the said Work Programme and Budget as submitted shall be approved
by resolution of the Management Committee. Any portion of a Work
Programme about which NNPC has not proposed a revision shall
insofar as possible be carried out as prescribed therein.
7.4 (a) Except as may be expressly provided for in this Contract, the
Management Committee shall determine and adopt rules to govern
its procedures.
(b) Members attending a meeting of the Management Committee may be
accompanied by advisers and experts to the extent reasonably
necessary to assist with the conduct of such meeting. Such
advisers and experts shall not vote or in any way participate in
decisions, but may contribute in a non-binding way to discussions
or debates of the Management Committee.
(c) At any Management Committee meeting where there is a quorum, the
Chairman or his alternate shall exercise the voting rights of
NNPC and the Managing Director of the Company or his alternate
shall exercise the voting rights of Company.
(d) Except as otherwise expressly provided in this Contract all
decisions of the Management Committee shall be made by the
unanimous vote of the Parties. If unanimity is not obtained on
any matter (including any matter pertaining to a Work Programme
or Budget proposed by Company) proposed to the Management
Committee, then the Management Committee shall meet again to
attempt to resolve
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such matter not later than fourteen (14) days after the meeting
in which the proposed matter was rejected by a negative vote.
Any portion of such proposal that is not rejected shall insofar
as possible be carried out. At least seven (7) days prior to
such second meeting, the Party casting the dissenting vote shall
provide to the other Party in writing in reasonable detail the
reasons for such dissenting vote. If such written reasons are
not provided at least (7) days prior to such second meeting, then
the proposal shall be deemed approved. In such second meeting
the agenda shall be comprised of such written reasons as provided
by the dissenting Party. If unanimity is not obtained in the
second meeting, then the Management Committee shall meet a third
time within fourteen (14) days after the second meeting. If
unanimity is not obtained in the third meeting then the
appropriate provisions of Clause 11 or 22 shall apply.
(e) Nothing in this Clause 7 shall be construed so as to give the
Management Committee the right to increase the minimum Work
Programme pursuant to Clauses 6.1 and 6.2.
(f) The Parties shall be bound by, and abide by, each decision of the
Management Committee duly made in accordance with the provisions
of this Contract.
7.5 Any matter which is within the powers and duties of the Management
Committee may be determined by the Management Committee without a
Management Committee meeting if such matter is submitted by either Party
to the other Party with due notice and with sufficient information
regarding the matter to be determined so as to enable the Parties to
make an informed decision with respect to such matter.
(a) Except for urgent matters referred to in Clause 7.5(b), each
Party shall cast its vote with respect to such matter within
twenty-one (21) days of receipt of such notice and such manner of
determination shall be followed unless a Party objects, within
fourteen (14) days of receipt of such notice, to having the
matter determined in such manner. If any Party fails to vote by
the expiry of the twenty-one (21) day period for voting, it shall
be deemed to have voted in the affirmative. The Secretary shall
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promptly advise the Parties of the results of such vote and the
Secretary shall draft a resolution to be signed as soon as
possible by the Parties.
(b) Each Party shall nominate one of its officers as its
representative from whom the other Party may seek binding
decisions on urgent matters, including, but not limited to
ongoing drilling operations, by telephone, telex or in person and
they shall advise each other in writing of the persons so
nominated and any changes therefor.
(c) In the event of an emergency requiring immediate operational
action, either Party may take all actions it deems proper or
advisable to protect its interests and those of its respective
employees and any costs so incurred shall be included in the
Operating Costs. Prompt notification of any such action taken by
a Party and the estimated cost shall be given to the other Party
within forty-eight (48) hours of the commencement of the event.
(d) The decisions made pursuant to this Clause 7.5 shall be recorded
in the minutes of the next scheduled meeting of the Management
Committee, and shall be binding upon the Parties to the same
extent as if the matter had been determined at a meeting of the
Management Committee.
7.6 The Management Committee shall establish Exploration and Technical
Sub-Committees and any other advisory Sub-Committees as it considers
necessary from time to time such as Finance and Budget, and
Legal/Services Sub-Committees:
(a) Each Sub-committee established pursuant to this Clause 7.6 shall
be given terms of reference and shall be subject to such
direction and procedures as the Management Committee may give or
determine.
(b) The Management Committee shall appoint the members of the
Sub-Committees which shall be comprised of equal representation
from the Parties. The chairmen of the Sub-Committees shall be
designated by Company.
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(c) The deliberations and recommendations of any Sub-Committee shall
be advisory only and shall become binding and effective upon
acceptance by the Management Committee.
CLAUSE 8
RIGHTS AND OBLIGATIONS OF THE PARTIES
8.1 In accordance with this Contract, Company shall:
(a) Provide all necessary funds for payment of Operating Costs
including, but not limited to, funds required to provide all
materials, equipment, supplies, and technical requirements
(including personnel) purchased, paid for or leased in Foreign
Currency;
(b) Furnish such other funds for the performance of Work Programmes
that require payment in Foreign Currency, including payments to
third parties who perform services as subcontractors;
(c) Prepare Work Programmes and Budgets and carry out approved Work
Programmes in a good and workmanlike manner and in accordance
with internationally acceptable petroleum industry practices and
standards with the object of avoiding waste and obtaining maximum
ultimate recovery of Crude Oil at minimum costs;
(d) Ensure that all leased property paid for in Foreign Currency and
brought into Nigeria for Petroleum Operations is treated in
accordance with the terms of the applicable leases;
(e) Have the right to sell, assign, transfer, convey or otherwise
dispose of any part of its rights and interests under this
Contract to other parties including Affiliates without any fee or
other costs with the prior written consent of NNPC which consent
shall not be unreasonably withheld;
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(f) Have the right of ingress to and egress from the Contract Area
and to and from facilities therein located at all times during
the Term of this Contract;
(g) Submit to NNPC for permanent custody copies of all geological,
geophysical, drilling, well production, operating and other data
and reports as it may compile during the Term hereof and at the
end of the Contract surrender all original data and reports to
NNPC;
(h) Prepare estimated and final PPT returns and submit same to NNPC
on a timely basis in accordance with the PPT Act;
(i) Prepare and carry out plans and programmes for industrial
training and education of Nigerians for all job classifications
with respect to Petroleum Operations in accordance with the
Petroleum Act 1969;
(j) Have the right to lift in accordance with Annex D and freely
export and to retain abroad the receipts from the sale of
Available Crude Oil allocated to it hereunder:
(k) Employ only such personnel as are reasonably necessary to conduct
the Petroleum Operations and employ qualified Nigerian Nationals
to the maximum extent possible and in this respect:
(i) Company shall determine the qualifications and number of
positions required to conduct Petroleum Operations in a
prudent and cost effective manner.
(ii) Qualified Nigerians shall be employed in all non-
specialized positions.
(iii) Qualified Nigerians shall also be employed in specialized
positions such as those in exploration, drilling,
engineering, production, and finance. Company shall have
the right, subject to applicable laws, rules and
regulations, to employ non-Nigerians in such specialized
positions where qualified
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Nigerians are not available provided that Company shall
recruit and train Nigerians for such specialized positions
such that the number of non-Nigerian staff shall be kept
to a minimum.
(iv) Officials of NNPC shall be assigned to work with Company
from time to time by mutual consent of the Parties and
such officials and Company officials shall not be treated
differently with regard to salaries and other benefits
from other similar petroleum companies and their officials
engaged directly in similar Petroleum Operations in
Nigeria;
(l) Give preference to such goods which are available in Nigeria or
services rendered by Nigerian nationals, provided such goods meet
the industry standards and such services are of good quality and
are offered at competitive prices and are timely available;
(m) In respect of payment of customs duties and other like charges,
Company and its subcontractors shall not be treated differently
from any other companies and their subcontractors engaged
directly in similar Petroleum Operations in Nigeria;
(n) Indemnify and hold harmless NNPC from and against losses
(including legal fees and expenses) of whatever kind and nature
resulting from Company's negligence or willful misconduct in
carrying out Petroleum Operations and as a consequence of any
final decision given by Nigerian Court, except where such Losses
are shown to result from any action or failure to act on the part
or NNPC, provided however, that under no circumstances shall
Company be liable to NNPC for reservoir damage or pollution or
any consequential losses or damages whatsoever or howsoever
occurring including, but not limited to, lost production or lost
profits;
(o) Have the right to finance Petroleum Operations from external
sources under terms and conditions approved by NNPC; and
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(p) Not exercise all or any rights or authority over the Contract
Area in derogation of the rights of NNPC.
8.2 In accordance with this Contract, NNPC shall:
(a) Pay to the Government in a timely manner, all Bonuses, Royalties,
Concession Rentals and PPT accruing out of Petroleum Operations;
(b) With its professional staff assigned pursuant to Clause
8.1(k)(iv), work jointly with Company's professional staff in
Company's Exploration, Petroleum Engineering,
Facilities/Materials and Finance Departments;
(c) Otherwise assist and expedite Company's execution of Petroleum
Operations and Work Programmes including, but not limited to,
assistance in supplying or otherwise making available all
necessary visas, work permits, rights of way and easements as may
be requested by Company (Expenses incurred by NNPC at Company's
request in providing such assistance shall be reimbursed to NNPC
by Company in accordance with Clause 12.1. Company shall include
such reimbursements in the Operating Costs. Such reimbursements
will be made against NNPC's invoice and shall be in U.S. Dollars
computed at the rate of exchange published by the Central Bank of
Nigeria and/or the Federal Ministry of Finance);
(d) Have title to all original data resulting from the Petroleum
Operations including but not limited to geological, geophysical,
engineering, well logs, completion, production, operations,
status reports and any other data as Company may compile during
the Term hereof, provided however, Company shall retain and use
such original data during the Term of this Contract and NNPC
shall have access to such original data during the Term of this
Contract;
(e) Not exercise all or any of its right or authority over the
Contract Area in derogation of the rights of Company;
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(f) Take such action as may be required to convert OPLs 90 and 225 to
OMLs if a commercial discovery is made; and
(g) Have obtained any and all approvals from Government which are
necessary for the execution of this Contract.
CLAUSE 9
RECOVERY OF OPERATING COSTS AND CRUDE OIL ALLOCATION
9.1 The allocation of Available Crude Oil shall be in accordance with the
Accounting Procedure (Annex B), the Allocation Procedure (Annex C) and
this Clause 9 as follows:
(a) Royalty Oil shall be allocated to NNPC in the quantum which will
generate an amount of Proceeds to pay the actual Royalty payable
during each month and the Concession Rental payable annually;
(b) Tax Oil shall be allocated to NNPC in the quantum which will
generate an amount of Proceeds to pay the actual PPT liability
payable during each month;
(c) Cost Oil shall be allocated to Company in the quantum which will
generate an amount of Proceeds for recovery of Operating Costs;
and
(d) Profit Oil, being the balance of available Crude Oil after
deducting Royalty Oil, Tax Oil, and Cost Oil, shall be allocated
to each Party pursuant to Schedule B-2 of the Accounting
Procedure (Annex B) as follows:
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<TABLE>
<CAPTION>
Monthly Average Profit Oil
MBOPD From Contract Area Percentages
---------------------------------------- ---------------------
NNPC Company
---- -------
<S> <C> <C>
0 to 40 30 70
Greater than 40 but less than 75 40 60
Greater than 75 but less than 100 45 55
100 and above 60 40
</TABLE>
9.2 The quantum of Available Crude Oil to be allocated to each Party under
this Contract shall be determined at the fiscalisation point.
9.3 Each Party shall take in kind, lift and dispose of its allocation of
Available Crude Oil in accordance with the Lifting Procedure (Annex D).
9.4 Allocation of Royalty Oil and Tax Oil to NNPC shall be applied towards
the liabilities of Company and NNPC for Royalty, Concession Rentals, and
PPT and the Proceeds therefrom shall be paid to the Government by NNPC
on behalf of both Parties.
9.5 Should either Party lift the other Party's allocation of Available Crude
Oil pursuant to Clause 10, the purchasers of such Crude Oil shall be
instructed to pay the receipts from such Available Crude Oil sales
directly into the lifting Party's account and the lifting Party shall
within seven (7) days transfer to the account designated by the
non-lifting Party, the receipt of such portion of the Proceeds to which
the non-lifting Party is so entitled.
9.6 If NNPC agrees, Company may purchase any portion of NNPC's allocation of
Available Crude Oil from the Contract Area under NNPC's terms and
conditions including valuation and pricing of the Crude Oil as
applicable to other third party buyers of NNPC's Crude Oil.
9.7 Both Parties shall meet on a monthly/quarterly basis to reconcile all
Crude Oil allocated and lifted during the period as per Article III 7 of
Annex D.
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CLAUSE 10
VALUATION OF AVAILABLE CRUDE OIL
10.1 Available Crude Oil allocated to each Party shall be valued in
accordance with the following procedures:
(a) On the attainment of commercial production, the Parties shall
engage the services of at least two independent laboratories to
determine the assay of the new Crude Oil.
(b) When a new Crude Oil stream is produced, a trial marketing period
shall be designated which shall extend for the first six (6)
month period during which such new stream is lifted or for the
period of time required for the first ten (10) liftings,
whichever is longer. During the trial marketing period the
Parties shall:
(i) Collect samples of the new Crude Oil upon which the assays
shall be performed as provided in Clause 10.l(a) above;
(ii) Determine the approximate quality of the new Crude Oil by
estimating the yield values from refinery modelling;
(iii) Share in the marketing such that each Party markets
approximately an equal amount of the new Crude Oil and to
the extent that one Party lifts the other Party's
allocation of Available Crude Oil, payments therefor shall
be made in accordance with Clause 9.5;
(iv) Exchange information regarding the marketing of the new
Crude Oil including documents which verify the sales price
and terms of each lifting;
(v) Apply the actual f.o.b. sales price to determine the value
for each lifting which f.o.b. sales pricing for each
lifting shall continue after the trial marketing period
until the Parties agree to a valuation of the new Crude
Oil
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but in no event longer than ninety (90) days after
conclusion of the trial marketing period.
(c) As soon as practicable but in no event not later than sixty (60)
days after the end of the trial marketing period, the Parties
shall meet to review the assay, yield, and actual sales data.
Each Party may present a proposal for the valuation of the new
Crude Oil. A valuation method shall be established for
determining the price for each lifting of Available Crude Oil.
Such valuation method shall be in accordance with the Realisable
Price provisions set forth in the Memorandum of Understanding
pursuant to Clause 16.6 of this Contract. It is the intent of
the Parties that such prices shall reflect the true market value
of the new Crude Oil. The valuation method determined hereunder
(including the product yield values) shall be mutually agreed
within thirty (30) days from the aforementioned meeting failing
which, determination of such valuation shall be referred to the
Management Committee for resolution pursuant to Clause 7.
(d) Upon the conclusion of the trial marketing period, the Parties
shall be entitled to lift their allocation of Available Crude Oil
pursuant to Clause 9 and the Lifting Procedure.
10.2 If in the opinion of either Party an agreed price valuation method fails
to reflect the market value of a Crude Oil produced in the Contract
Area, then such Party may propose to the other Party modifications to
such valuation method once in every six (6) months but in no event more
than twice in any year. The Parties shall then meet within thirty (30)
days of such proposal and mutually agree on any modifications to such
valuation within thirty (30) days from such meeting failing which,
determination of such valuation shall be referred to the Management
Committee for resolution pursuant to Clause 7.
10.3 Segregation of Crude Oils for different quality and/or grade shall be by
agreement of the Parties taking into consideration, among other things,
the operational practicality of
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segregation and the cost benefit analysis thereof. If the Parties agree
on such segregation the following provisions shall apply:
(a) Any and all provisions of the Contract concerning valuation of
Crude Oil shall separately apply to each segregated Crude Oil
produced;
(b) Each grade or quality of Crude Oil produced and segregated in a
given Year shall contribute its proportionate share to the total
quantity designated in such Year as Royalty Oil, Tax Oil, Cost
Oil and Profit Oil.
CLAUSE 11
SOLE RISK OPERATIONS
11.1 For the purpose of this Clause 11:
(a) "Common Cost" means overhead expenses in respect of operating and
maintenance charges and depreciation on common user assets which
are shared by Sole Risk Operations and Petroleum Operations.
(b) "Exploratory Well" means:
(i) a well drilled in the Contract Area in an area lying
outside the interpreted closure of any structural or
stratigraphic trap on which closure a well has been
drilled which is capable of producing Crude Oil, or
(ii) a well in the Contract area in any area lying inside the
interpreted closure of any structural or stratigraphic
trap, to the extent such well is deepened or plugged back
to a stratigraphic level different from that to which it
had previously been drilled and found capable of producing
Crude Oil; or
(iii) any well that has been agreed by the Parties to be an
Exploratory Well.
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(c) "Non-Sole Risk Party" means a Party who does not join in the
proposal for, nor participate in a Sole Risk Operation;
(d) "Production Facilities" means drilling and/or production
platforms and/or Crude Oil storage and transportation facilities
required to produce and deliver any Crude Oil that may be
discovered from an Exploratory Well;
(e) "Sole Risk Exploratory Well" means an Exploratory Well drilled by
a Sole Risk Party pursuant to this Clause 11;
(f) "Sole Risk Notice" - means a notice given pursuant to Clause 11.4
herein of a Party's intention to conduct a Sole Risk Operation;
(g) "Sole Risk Operation" - means an operation conducted for only one
of the Parties in the Contract Area in accordance with the
provisions of this Clause 11.
(h) "Sole Risk Party" - means the Party who proposes and/or
undertakes a Sole Risk Operation pursuant to this Clause 11.
11.2 Subject to Clause 11.3, Sole Risk Operations shall only include and be
undertaken in the Contract Area in respect of any one or more of the
following activities:
(a) the deepening, sidetracking or plugging back of an Exploratory
Well;
(b) the drilling of an Exploratory Well including testing and coring
programmes;
(c) the drilling of appraisal and development wells and the
installation of Production Facilities to develop a discovery made
by a Sole Risk Exploratory Well;
(d) any other activity or project agreed by the Parties to be
undertaken as a Sole Risk Operation.
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11.3 (a) No Sole Risk Operation may be conducted if it would adversely
affect any other Petroleum Operations or conflict with all or any
part of any current Work Programme.
(b) No Sole Risk Operation shall be undertaken until:
(i) The Sole Risk Operation shall first have been proposed in
writing to the Management Committee which proposal shall
specify appropriate details of the said operations such as
location of proposed well, scope of geological and
geophysical programmes, proposed depth, itemized estimate
of the costs thereof, economic analysis, expected dates of
commencement and completion; and
(ii) The Management Committee shall have disapproved or be
deemed to have disapproved the proposal.
(c) A Sole Risk Operation for the deepening or sidetracking of an
Exploratory Well which is in the course of drilling may be
proposed only if such well has not encountered a discovery and
the Parties have decided to abandon the well following their
receipt of all drilling and test results. The Parties shall make
any decision relating to the abandonment of such well as
expeditiously as possible.
11.4 Within 12 months after the Management Committee rejects a proposal for
any of the Petroleum Operations described in Clause 11.2 or, in the case
of Clause 11.3 (c), within 48 hours after a decision of the Parties to
abandon an Exploratory Well, either Party may give to the other Party a
Sole Risk Notice in writing. The Non-Sole Risk Party shall have sixty
(60) days after the receipt of the Sole Risk Notice within which to
notify the Sole Risk Party that said Non-Sole Risk Party elects to
participate in the costs of such Sole Risk Operation, ("Participation
Notice"); provided, however, that in the case of a Sole Risk activity
pursuant to Clause 11.3 (c) the period in which the Participation Notice
may be given shall be forty-eight (48) hours.
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11.5 If the Non-Sole Risk Party elects to participate in a proposed Sole Risk
Operation within the applicable period specified in Clause 11.4, such
Sole Risk Operation shall be carried out by the Company as a Petroleum
Operation and the current Work Programme shall be deemed to be amended
accordingly.
11.6 In the event the Non-Sole Risk Party does not elect, within the
applicable period specified in Clause 11.4 to participate in a proposed
Sole Risk Operation, the Sole Risk Party shall be entitled to carry out
the Sole Risk Operation at its sole risk, cost and expenditure. Costs
and expenses of the Sole Risk Operation incurred by the Sole Risk Party
shall be computed in accordance with the principles set out in the
Accounting Procedure.
11.7 (a) Notwithstanding that the Company may not be the Sole Risk Party,
the Sole Risk Operation shall, subject to Clauses 11.7(e) and
11.8, be carried out promptly and diligently by the Company for
the sole account and benefit of the Sole Risk Party.
(b) Any Sole Risk Operation shall be carried out at the sole risk,
and under the overall supervision and control of the Sole Risk
Party but otherwise pursuant to this Contract.
(c) The cost and expense of any Sole Risk Operation shall be entirely
for the account of the Sole Risk Party and shall not be
chargeable as Operating Costs under this Contract nor shall in
any way alter the Cost Oil and/or Profit Oil which may be due to
the Non-Sole Risk Party from other Petroleum Operations conducted
hereunder. However, such cost and expense shall be deductible
for PPT purposes pursuant to the Accounting Procedure and any
benefit from such deductions shall accrue entirely to the Sole
Risk Party.
(d) The Company shall keep and maintain separate books, records, and
accounts (including bank accounts) with respect to the Sole Risk
Operations, including the Sole Risk portion of all Common Costs
in connection therewith, which shall be subject to the right of
examination and audit by the Sole Risk Party.
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<PAGE> 32
(e) The Sole Risk Party shall be obligated to advance the estimated
expenditure for the Sole Risk Operation to the Company within
fifteen (15) days after receipt of the Company's request
therefor. The Company, if not the Sole Risk Party, shall not
use, or be required to use, its own funds for the purpose of
paying the costs and expenses of the Sole Risk Operation.
11.8 It is hereby understood and agreed that the Sole Risk Party shall do all
things necessary to enable the Company on its behalf to commence the
Sole Risk Operation within one hundred and eighty (180) days after
expiry of the period specified in Clause 11.4 for giving a Participation
Notice in the case of a Sole Risk Operation under Clause 11.2; or within
48 hours after expiry of the period specified in Clause 11.4 for giving
a Participation Notice in case of projects under Clause 11.3(c). If the
Sole Risk Operation specified in the Sole Risk Notice is not commenced
within the period specified in this Clause 11.8 for reasons attributable
to the Sole Risk Party, then the right of the Sole Risk Party to carry
out the Sole Risk Operation shall lapse.
11.9 The Company shall, in relation to the Sole Risk Operation, furnish to
NNPC all information and data which the Company is obligated to give
NNPC under the Terms of this Contract.
11.10 The Non-Sole Risk Party may at any time, elect to participate in a Sole
Risk Operation by paying to the Sole Risk Party an amount equal to two
hundred percent (200%) of the cumulative cost and expenditure of the
Sole Risk Operation incurred as of the date of such election, being
hereinafter referred to as the "Re-entry Penalty". The whole or any
part of the Re-entry Penalty shall be paid in cash in the currency in
which the Sole Risk costs have been incurred or in kind or both as may
be mutually agreed by the Parties. Following an election and payment as
aforesaid, such operations shall be carried out as Petroleum Operations.
11.11 The Sole Risk Party shall be entitled to use property purchased for the
Petroleum Operation and personnel of the Company for Sole Risk Operation
upon terms and conditions agreed by the Parties; provided however, that
it is understood that at all times the Petroleum Operations
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shall take precedence over the Sole Risk Operation in such use of
Petroleum Operation property and Company personnel.
11.12 The Sole Risk Party shall indemnify and hold harmless the Non-Sole Risk
Party from all suits, claims, liens, liabilities, damages, costs, losses
and expenses whatsoever directly or indirectly caused to third parties
or incurred by the Non-Sole Risk Party as a result of anything done or
omitted to be done in the course of carrying out the Sole Risk
Operation.
11.13 (a) Subject to Clause 11.10, all property acquired through a Sole
Risk Operation, including data and information shall be wholly
owned by the Sole Risk Party.
(b) In case of a Sole Risk Operation under Clause 11.2 (c) the
relevant Production Facilities as well as any Crude Oil produced
therefrom, shall be owned by the Sole Risk Party until such time
as the Non-Sole Risk Party has elected to participate in further
work under the Sole Risk Operation pursuant to Clause 11.10 and
paid the Re-entry Penalty.
(c) Notwithstanding the election of the Non-Sole Risk Party to
participate in a Sole Risk Operation involving production of
Crude Oil discovered as the result of a Sole Risk Exploratory
Well, and the payment by the Non-Sole Risk Party of the Re-entry
Penalty pursuant to Clause 11.10, the Non-Sole Risk Party shall
not be entitled to receive any payment in kind or cash or credit
for any Crude Oil which was produced as a result of a discovery
from such Exploratory Well prior to the date of such election and
payment. Upon such election and payment however the Non-Sole
Risk Party shall be entitled to its Profit Oil Share of Crude Oil
produced as a result of a discovery from such Exploratory Well
following such election and payment.
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CLAUSE 12
PAYMENTS
12.1 The method of payment of any sum due from Company to NNPC and vice versa
shall be in accordance with the prevailing guidelines of the Federal
Ministry of Finance of Nigeria, the Central Bank of Nigeria and in
accordance with the Accounting Procedure, Annex B.
12.2 Unless otherwise provided herein, any payments which NNPC is required to
make to Company or which Company is required to make to NNPC pursuant to
this Contract shall be made within thirty (30) days following the end of
the month in which the obligation to make such payments occurs. Overdue
payments shall bear interest at the annual rate of one (1) month LIBOR
plus 2%
12.3 Each Party shall have the right to set off against sums due and payable
to the other Party under this Contract agreed sums past due under this
Clause.
CLAUSE 13
TITLE TO EQUIPMENT
13.1 Company shall finance the cost of purchasing all equipment to be used in
Petroleum Operations in the Contract Area pursuant to the Work
Programmes and such equipment shall become the property of NNPC on
arrival in Nigeria. Company and NNPC shall have the right to use such
equipment exclusively for Petroleum Operations in the Contract Area
during the Term of this Contract. Should NNPC desire to use such
equipment outside the Contract Area, such use shall be subject to terms
and conditions agreed by the Parties provided that it is understood
Petroleum Operations hereunder shall take precedence over such use by
NNPC.
13.2 Company's right to use such purchased equipment shall cease with the
termination or expiration (whichever is earlier) of this Contract.
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13.3 The provisions of Clause 13.1 with respect to the title of property
passing to NNPC shall not apply to leased equipment belonging to foreign
third parties, and such equipment may be freely exported from Nigeria in
accordance with the terms of the applicable lease.
13.4 Title to all lands purchased or otherwise acquired by Company for the
purposes of Petroleum Operations and all movable property utilised in
the Contract Area and incorporated permanently in any premises,
locations and structures for the purposes of Petroleum Operations
hereunder shall be in the name of NNPC and Company. Upon termination
of this Contract pursuant to Clause 4, NNPC shall take possession of
such lands and property and Company shall hand over such lands and
property within a reasonable period of time.
13.5 Subject to Clause 13.3 hereof, all fixed assets purchased or otherwise
acquired by Company for the purposes of Petroleum Operations hereunder
shall become the property of NNPC. Upon termination of this Contract
pursuant to Clause 4, Company shall hand over possession of such fixed
assets to NNPC.
13.6 During the Term of this Contract, any agreed sale of equipment, lands,
fixed assets, materials and machinery acquired for the purpose of the
Petroleum Operations hereunder shall be conducted by Company on the
basis of the highest price obtainable and the proceeds of such sale
shall be credited to the Petroleum Operations.
CLAUSE 14
EMPLOYMENT AND TRAINING OF NIGERIAN PERSONNEL
14.1 Each Year, Company shall submit a detailed programme for recruitment
and training for the following Year in respect of its Nigerian personnel
in accordance with the Petroleum Act 1969 and its amendment.
14.2 Costs and expenses incurred in the recruitment and training of Nigerian
personnel shall be included in Operating Costs.
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CLAUSE 15
BOOKS AND ACCOUNTS, AUDITS
AND OVERHEAD CHARGES
15.1 BOOKS AND ACCOUNTS
Company shall be responsible for keeping complete books of accounts
consistent with modern petroleum industry and accounting practices and
procedures. The statutory books and accounts shall be kept in Naira.
All other books of accounts shall be made up both in Nigerian currency
and U.S. Dollars. Officials of NNPC and Company shall have access to
such books and accounts and officials of NNPC assigned to Company
pursuant to Clause 8.1(k)(iv) shall participate in the preparation of
same.
15.2 AUDITS
NNPC shall have the right to inspect and audit the books and accounts
relating to this Contract for any Year by giving thirty (30) days
written notice to Company and Company shall facilitate the work of such
inspection and auditing; provided however, that the costs of such
inspection and auditing shall be met by NNPC, and provided also that if
such inspection and auditing have not been so carried out within one (1)
Year following the end of the Year in question, the books and accounts
relating to such Year shall be deemed to be accepted by the Parties as
satisfactory. Any exception must be made in writing ninety (90) days
following the end of such audit and failure to give such written notice
within such time shall establish the correctness of the books and
accounts.
15.3 OVERHEAD CHARGES
Company shall include as Operating Cost overhead charges equal to two
and one-half percent (2-1/2%) of the aggregate amount of expenditures
for geologic and geophysical studies/surveys, exploration and appraisal
drilling, intangible drilling costs and Capital Cost (as defined in the
Accounting Procedure) including development drilling costs.
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CLAUSE 16
TAXES, ROYALTY, RATES AND DUTIES
16.1 In accordance with applicable laws and regulations all sums the
liability for which was incurred by the Company to the Federal
Government of Nigeria by way of Custom or Excise duty or other like
charges levied in respect of plant, storage tanks, pipelines, tools,
machinery and equipment essential for use in the Company's Petroleum
Operations shall be charged to Operating Cost.
16.2 All sums the liability for which was incurred by the Company to the
Federal Government of Nigeria or to any State or Local Government
Council in Nigeria by way of duty (other than customs and excise duties
under 16.1 above) rates, stamp duty, penalties on gas flared, bank
commissions levied by the Central Bank of Nigeria, fees and charges
shall be charged to Operating Cost.
16.3 NNPC shall pay all Royalty, Concession Rentals and PPT on behalf of
itself and Company out of Available Crude Oil allocated to it under
Clause 9.1 of this Contract.
16.4 The PPT rate shall be in accordance with the PPT Act and shall be 65.75%
for the first five (5) years of production from each field developed in
the Contract Area commencing from the first day of the month of first
sale therefrom and 85% thereafter, provided that if other rates are
offered to other producing companies in Nigeria, the same shall apply to
this Contract.
16.5 Within a reasonable period of time following the Effective Date of this
Contract, the Government shall establish and execute a Memorandum of
Understanding on Incentives for Encouraging Investments in Exploration
and Development Activities and Enhancing Crude Oil Exports (hereinafter
called the Memorandum of Understanding) with NNPC and Company which
shall be applied when determining the Royalty and PPT payable pursuant
to the Petroleum Operations hereunder. The Memorandum of Understanding
shall provide to the Parties the incentives extended to other oil
companies producing in Nigeria under
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those certain Memorandum of Understanding agreements between the
Government and such other companies effective 1st January, 1991
including any amendments or successor documents. The Memorandum of
Understanding shall include those provisions set forth in Article III
Paragraph 3 of the Accounting Procedure.
16.6 The Memorandum of Understanding shall include provisions to establish
the Realisable Price for the purpose or determining the payments of
Royalty and PPT in respect of Crude Oil produced and lifted pursuant to
this Contract. Such provisions shall be in accordance with the
Realisable Price provisions contained in those certain Memorandum of
Understanding agreements effective 1st January, 1991 between the
Government and the other oil companies producing in Nigeria. The
parameters for new Crude Oil streams produced from the Contract Area
shall be determined in accordance with provisions of Clause 10 of the
Contract.
16.7 NNPC shall make available to Company copies of receipts bearing the
names of both Parties for the payments made for PPT, Royalty and
Concession Rentals.
CLAUSE 17
INSURANCE
17.1 All property obtained under the provisions of this Contract shall be
adequately insured by Company in consultation with NNPC, in its name and
that of NNPC with limits of liability not less than those required by
Nigerian laws and regulations. The premia for such policies shall be
included in operating Costs. All policies shall name NNPC as a
co-insured with a waiver of subrogation rights in favor of NNPC.
17.2 In case of loss of or damage to property, indemnifications paid by the
insurance companies shall be entirely received by Company for Petroleum
Operations. Company shall determine whether the lost or damaged
property should be repaired, replaced or abandoned. If the decision is
to repair or replace, Company will immediately replace or repair such
lost or damaged property. Any excess cost of repair or replacement
above the amount reimbursed
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by the insurance companies shall be regarded as Operating Costs. If the
decision is to neither repair nor replace then the proceeds of any
coverage shall be credited to Operating Costs.
17.3 Company shall take out and maintain an insurance policy covering any and
all damages caused to third parties as a direct or indirect result of
Company's Petroleum Operations. Company shall defend and hold NNPC
harmless from damages and losses caused to third parties in consequence
of Company's gross negligence or willful misconduct in the performance
of this Contract.
17.4 All insurance policies under this Clause 17 shall be based on good
international petroleum industry practice, and shall be taken out in the
Nigerian insurance market except for those concerning risks for which
Company cannot obtain coverage in Nigeria which shall be taken out
abroad through the Nigerian Reinsurance Corporation, to the extent
required by law.
17.5 Company shall not be exempted from obligations arising from this Clause
17 even when the obligations of this Contract are performed by Company's
agents.
17.6 Company shall maintain other insurance policies required under Nigerian
law.
CLAUSE 18
CONFIDENTIALITY AND PUBLIC ANNOUNCEMENTS
18.1 Company shall keep information furnished to it by NNPC and all plans,
maps, drawings, designs, data, scientific, technical and financial
reports and other data and information of any kind or nature relating to
Petroleum Operations including any discovery of Petroleum as strictly
confidential, for all times, and shall ensure that their entire or
partial contents shall under no circumstances be disclosed by Company in
any announcement to the public or to any third party without the prior
written consent of NNPC.
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The provisions of this Clause 18 shall not apply to disclosure to:
(a) Subcontractors, affiliates, assignees, auditors, legal advisers,
provided that such disclosures are required for the effective
performance of the aforementioned recipients' duties related to
Petroleum Operations;
(b) Financial institutions involved in the funding of Petroleum
Operations hereunder, provided, in all cases, that the recipients
of such data and information agree in writing to keep such data
and information strictly confidential; and
(c) Comply with statutory obligation or the requirements of any
governmental agency in which event Company will notify NNPC of
any information so disclosed.
18.2 Company shall take necessary measures in order to make its employees,
agents, representatives, proxies and subcontractors comply with the same
obligation of confidentiality provided for in this Clause 18.
18.3 The provisions of this Clause 18 shall not be voided by the expiry or
termination of this Contract on any grounds whatsoever and these
provisions constitute a continuing obligation, and accordingly the
restrictions arising therefrom shall be in force at all times.
18.4 Company shall use its best endeavors to ensure that Company's servants,
employees, agents and subcontractors shall not make any reference in
public or publish any notes in newspapers, periodicals or books nor
divulge, by any other means whatsoever, any information on the
activities under Company's responsibility, or any reports, data or any
facts and documents that may come to their knowledge by virtue of this
Contract, without the prior written consent of NNPC.
18.5 Company shall submit to NNPC all statutory reports and information for
submission to Government and other statutory bodies.
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CLAUSE 19
FORCE MAJEURE
19.1 Any failure or delay on the part of either Party in the performance of
its obligations or duties under this Contract shall be excused to the
extent attributable to force majeure. A force majeure situation
includes delays, defaults or inability to perform under this Contract
due to any event beyond the reasonable control of either Party. Such
event may be, but is not limited to, any act, event, happening, or
occurrence due to natural causes; and acts or perils of navigation,
fire, hostilities, war (declared or undeclared), blockade, labour
disturbances, strikes, riots, insurrection, civil commotion, quarantine
restrictions, epidemics, storms, floods, earthquakes, accidents,
blowouts, lightning, and acts of or orders of Government.
19.2 If operations are delayed, curtailed or prevented by force majeure, then
the time for carrying out the obligation and duties thereby affected,
and obligations hereunder, shall be extended for a period equal to the
period thus involved.
19.3 The Party whose ability to perform its obligations is so affected shall
promptly notify the other Party thereof not later than twenty-four (24)
hours after the establishment of the start of force majeure stating the
cause, and both Parties shall do all that is reasonably within their
powers to remove such cause.
19.4 Company's failure or inability to find Crude Oil in Commercial Quantity
for reasons other than as specified in Clause 19.1 hereof shall not be
deemed force majeure.
CLAUSE 20
LAWS AND REGULATIONS
20.1 This Contract shall be governed by and construed in accordance with the
Laws of the Federation of Nigeria, and any dispute arising therefrom
shall be determined in accordance with such laws.
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20.2 No Term or provision of this Contract including the agreement of the
Parties to submit to arbitration hereunder, shall prevent or limit the
Government from exercising its sovereign rights.
20.3 In the event that any enactment of or change in the laws or regulations
of Nigeria or any rules, procedures, guidelines, instructions,
directives, or policies, pertaining to the Contract introduced by any
Government department or Government parastatals or agencies occurs
subsequent to the Effective Date of this Contract which materially and
adversely affects the rights and obligations or the economic benefits of
Company, the Parties shall use their best efforts to agree to such
modifications to this Contract as will compensate for the effect of such
changes. If the Parties fail to agree on such modifications within a
period of ninety days (90) following the date on which the change in
question took effect, the matter shall thereafter be referred at the
option of either Party to arbitration under Article 22 hereof.
Following arbitrator's determination, this Contract shall be deemed
forthwith modified in accordance with that determination.
20.4 All affairs related to this Contract shall be conducted in the language
in which this Contract was drawn up.
CLAUSE 21
UTILISATION OF NATURAL GAS
21.1 All Natural Gas discovered in the Contract Area shall be the sole
property of Government.
21.2 If Company discovers a commercially viable non-associated gas field,
NNPC shall require Company to investigate and submit proposals for the
commercial development of the gas field for NNPC's consideration
provided that any cost in respect of such proposals or investigation
shall be included in Operating Cost. For the commercial development of
the non-associated natural gas field, the funding arrangements and
participation by the Company in the project shall be the subject of
another agreement and Company shall have the right to participate in
such development project.
-39-
<PAGE> 43
21.3 Notwithstanding the provisions of Clause 21 hereof, Company shall have
the right to use, at no cost to Company, the associated Natural Gas
produced with Crude Oil as fuel for production operations; gas
recycling, secondary recovery by gas injection, gas lift, or any other
economical secondary recovery schemes, stimulation of wells or
artificial lifts necessary in the commercial field discovered and
developed by the Company but only with the prior written consent of
NNPC, which consent shall not be unreasonably withheld. The objective
of maximum technical and economic recovery of Crude Oil shall always be
paramount. However, not later than five (5) years after the
commencement of production of Crude Oil from the Contract Area, the
Company shall submit to the Minister, a programme for the utilisation of
any Natural Gas whether associated with Crude Oil or not which has been
discovered from the Contract Area.
CLAUSE 22
CONSULTATION AND ARBITRATION
If a difference or dispute arises between NNPC and Company, concerning the
interpretation or performance of this Contract, and if the parties hereto fail
to settle such difference or dispute by amicable agreement, then either Party
may serve on the other a demand for arbitration. Within thirty (30) days of
such demand being served, each Party shall appoint an arbitrator and the two
arbitrators thus appointed shall within a further thirty (30) days appoint a
third arbitrator and if the arbitrators do not agree on the appointment of such
third arbitrator, or if either Party fails to appoint the arbitrator to be
appointed by it, such arbitrator shall be appointed by a High Court of Nigeria
in accordance with the provisions of the Arbitration and Conciliation Act, Cap
19, Laws of the Federation of Nigeria 1990 (notice of the intention to apply to
the Court having been duly given in writing by the applicant Party to the other
Party) and when appointed the third arbitrator shall convene meetings and act
as chairman thereat. If an arbitrator fails or is unable to act, a successor
shall be appointed by the respective Party or by the arbitrators in the event
the chairman must be succeeded. The arbitration award shall be binding upon
the Parties and the expenses of the arbitration shall be borne by the Parties
in such proportion and manner as may be provided in the award. The Nigerian
Arbitration and Conciliation Act, Cap 19, Laws of the Federation of Nigeria
1990 shall apply. The venue of the arbitration shall be anywhere in Nigeria as
agreed by the Parties.
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<PAGE> 44
CLAUSE 23
EFFECTIVENESS
23.1 This Contract shall come into force and effect on the Effective Date.
23.2 This Contract shall not be amended or modified in any respect except by
mutual consent, in writing, of the Parties hereto.
CLAUSE 24
OTHER PROVISIONS
Should the Government grant fiscal terms to NNPC in respect of other oil
companies' production sharing contracts or NNPC grant contract terms to other
oil companies operating production sharing contracts in Nigeria more favorable
than the terms provided herein, the Parties shall meet and mutually agree on
revisions to this Contract which will give to Company the economic benefit of
such more favorable terms.
CLAUSE 25
NOTICES
25.1 Any notices required to be given by either Party to the other shall be
in writing and shall be deemed to have been duly given if sent and
received by mail or telegram or cable (confirmed by mail) or registered
post to, or hand delivered at the following registered offices:
NNPC: THE GROUP EXECUTIVE DIRECTOR, NAPIMS
NIGERIAN NATIONAL PETROLEUM CORPORATION
7, KOFO ABAYOMI STREET
VICTORIA ISLAND,
LAGOS.
CABLE: NAPETCOR
TELEX: 21126 NG
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<PAGE> 45
COMPANY: THE MANAGING DIRECTOR
ASHLAND NIGERIA EXPLORATION UNLIMITED
10, BISHOP ABOYADE-COLE ST.
VICTORIA ISLAND
LAGOS
TELEX: 961-211023 ASHOIL NG
25.2 Either Party shall notify the other promptly of any change in the above
address.
SIGNED AND DELIVERED FOR AND ON BEHALF OF
NIGERIAN NATIONAL PETROLEUM CORPORATION
BY: /s/ OWELLE G. P. O. CHIKELU
-----------------------------------
Name: OWELLE G. P. O. CHIKELU
Designation: CHAIRMAN, NNPC BOARD OF DIRECTORS
IN THE PRESENCE OF:
Name: DR. T. M. JOHN
-----------------------------------
Signature: /s/ Dr. T. M. JOHN
Designation: GROUP MANAGING DIRECTOR
Address: NNPC HQ, LAGOS.
SIGNED AND DELIVERED FOR AND ON BEHALF OF
ASHLAND NIGERIA EXPLORATION UNLIMITED
BY: /s/ MR. B. W. FISCHER
-----------------------------------
Name: MR. B. W. FISCHER
Designation: GENERAL MANAGER AND MANAGING DIRECTOR
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<PAGE> 46
IN THE PRESENCE OF:
Name: Joseph I. Obi
-----------------------------------
Signature: /s/ Joseph I. Obi
-----------------------------------
Designation: Secretary
-----------------------------------
Address: 10 Bishop Aboyade Cole Street
-----------------------------------
Victoria Island, Lagos
-----------------------------------
-43-
<PAGE> 47
ANNEX A
TO THAT CERTAIN PRODUCTION SHARING
CONTRACT BETWEEN NNPC AND COMPANY
DATED 25TH MARCH 1992
[Map of Nigerian Mid Belt Coordinates]
-44-
<PAGE> 48
ANNEX B
TO THAT CERTAIN PRODUCTION SHARING CONTRACT
BETWEEN NNPC AND COMPANY DATED 25 MARCH 1992
ACCOUNTING PROCEDURE
ARTICLE I
GENERAL PROVISIONS
1. DEFINITIONS
This Accounting Procedure attached to and forming a part of the Contract
is to be followed and observed in the performance of either Party's
obligations thereunder. The defined terms appearing herein shall have
the same meaning as is ascribed to them in the Contract.
2. ACCOUNTS AND STATEMENTS
Company's accounting records and books shall be kept as provided under
Clause 15.1 of the Contract in accordance with generally accepted and
recognized accounting standards, consistent with modern petroleum
industry practices and procedures. All original books of accounts
together with original supporting documentation shall be kept and
maintained in Nigeria in compliance with all Nigerian laws and
regulations.
3. OTHER
In the event of a conflict of the terms of this Procedure and the
Contract the terms of the Contract shall apply.
ARTICLE II
OPERATING COSTS
Operating Costs shall be defined as all costs, expenses and obligations
incurred by Company in carrying out Petroleum Operations and shall consist of
(1) Non-Capital Costs, and (2) Capital Costs.
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<PAGE> 49
1. NON-CAPITAL COSTS
Non-Capital Costs mean those Operating Costs incurred that are
chargeable to the current Year's operations. Non-Capital Costs
include, but are not limited to the following:
(a) General office expense - office, services and general
administration services pertaining to Petroleum Operations
including but not limited to, services of legal, financial,
purchasing, insurance, accounting, computer, and personnel
departments; transportation, rental of specialized equipment,
scholarships, charitable contributions and educational awards.
(b) Labour and related costs - salaries and wages, including bonuses,
of employees of Company who are directly engaged in the conduct
of Petroleum Operations, whether temporarily or permanently
assigned, irrespective of the location of such employees
including, but not limited to, the costs of employee benefits,
customary allowances and personal expenses incurred under
Company's practice and policy, and amounts imposed by applicable
Governmental authorities which are applicable to such employees.
These costs and expenses shall include:
(i) Cost of established plans for employee group life
insurance, hospitalization, pension, retirement, savings
and other benefits plan;
(ii) Cost of holidays, vacations, sickness and disability
benefits;
(iii) Cost of living, housing and other customary allowances;
(iv) Reasonable personal expenses which are reimbursable under
Company's standard personnel policies;
(v) Obligations imposed by Governmental authorities:
-46-
<PAGE> 50
(vi) Cost of transportation of employees, other than as
provided in paragraph (c) below, as required in the
conduct of Petroleum Operations; and
(vii) Charges in respect of employees temporarily engaged in
Petroleum Operations shall be calculated to reflect the
actual costs thereto during the period or periods of such
engagement.
(c) Employee relocation costs - costs for relocation, transportation
and transfer of employees of Company engaged in Petroleum
Operations pursuant to Clause 8.1(k) of this Contract including,
but not limited to the cost of freight and passenger service of
such employees' families and their personal and household effects
together with meals, hotel and other expenditures related to such
transfer incurred with respect to:
(i) employees of the Company within Nigeria, including
expatriate employees, engaged in Petroleum Operation;
(ii) transfers to Nigeria for engagement in Petroleum
Operations;
(iii) final repatriation or transfer of Company's expatriate
employees and families in the case of such employees'
retirement, relocation/reassignment or separation from the
Company; and
(iv) Nigerian employees on training assignments outside the
Contract Area.
(d) Services provided by third parties - cost of professional,
technical, consultation, utilities and other services procured
from third party sources pursuant to any contract or other
arrangements between such third parties and Company for the
purpose of Petroleum Operations.
(e) Legal expenses - All costs or expenses of handling,
investigating, asserting, defending, and settling litigation or
claims arising out of or relating to Petroleum
-47-
<PAGE> 51
Operations or necessary to protect or recover property used in
Petroleum Operations including, but not limited to, legal fees,
court costs, arbitration costs, cost of investigation or
procuring evidence and amounts paid in settlement or satisfaction
of any such litigation, arbitration or claims in accordance with
the provisions of this Contract.
(f) Services provided by Affiliates of Company - professional,
administrative, scientific and technical services for the direct
benefit of Petroleum Operations including, but not limited to,
services provided by the exploration, production, legal,
financial, purchasing, insurance, accounting and computer
services departments of such Affiliates. Charges for providing
these services shall reflect the actual cost only of providing
such services and shall not include any element of profit.
(g) Head Office overhead charge - parent company overhead in the
amount specified in Clause 15.3 of the Contract.
(h) A charge equal to four percent (4%) of the f.o.b. value of
materials for which Company or its Affiliates has arranged to
purchase and coordinate the forwarding and expediting effort.
(i) Interest - interest on loans used to finance Petroleum Operations
provided the terms of such loans were approved by NNPC.
(j) Insurance premiums and settlements - premium paid for insurance
normally required to be carried for the Petroleum Operations
together with all expenditures incurred and paid in settlement of
any and all losses, claims, damages, judgments, and other
expenses, including fees and deductibles relating to Company's
performance under the Contract.
(k) Duties and taxes - all duties and taxes, fees and any Government
assessments, including but not limited to, gas flare charges,
license fees, customs duties, and any
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<PAGE> 52
other payments to the Government other than Royalties, PPT and
Concession Rentals.
(1) Operating expenses - labour, materials and services used in day
to day oil well operations, oil field production facilities
operations, secondary recovery operations; storage,
transportation, delivery and marketing operations; and other
operating activities, including repairs, well workovers,
maintenance and related leasing or rental of all materials,
equipment and supplies.
(m) Geologic and geophysical surveys - labour, materials and services
used in aerial, geological, topographical, geophysical and
seismic surveys incurred in connection with exploration excluding
however the purchase of data from NNPC prior to 1st January,
1991.
(n) Intangible drilling costs - expenditures for labour, fuel,
repairs, maintenance, hauling, and supplies and materials (not
including, casing or other well fixtures) which are for or
incidental to drilling, cleaning, deepening or completing wells
or the preparation thereof incurred in respect of:
(i) determination of well locations, geological, geophysical,
topographical and geographical surveys for site evaluation
preparatory to drilling including the determination of
near surface and near sea bed hazards,
(ii) cleaning, draining and leveling land, road-building and
the laying of foundations,
(iii) drilling, shooting, testing and cleaning wells,
(iv) erection of rigs and tankage assembly and installation of
pipelines and other plant and equipment required in the
preparation or drilling of wells producing Crude Oil.
-49-
<PAGE> 53
(o) Exploration and appraisal drilling - all expenditures incurred in
connection with exploration drilling, and the drilling of the
first two appraisal wells in a particular field, and the drilling
of development wells which are dry, including costs incurred in
respect of casing, well cement and well fixtures.
(p) Abandonment - all expenditures incurred in connection with the
plugging of wells; the removal and disposal of equipment and
facilities including wellheads, processing and storage
facilities, platforms, pipelines, transport and export
facilities, roads, buildings, wharves, plants, machinery,
fixtures; the restoration of sites and structures including the
payment of damages to property lessors.
2. CAPITAL COSTS
Capital Costs means, without limitation, expenditures which are subject
to a Capital Allowance under the PPT Act. Such expenditures normally
have a useful life beyond the year incurred and include but are not
limited to the following:
(a) Plant expenditures - expenditures in connection with the design,
construction, and installation of plant facilities (including
machinery, fixtures, and appurtenances) associated with the
production, treating, and processing of Crude Oil (except such
costs properly allocable to intangible drilling costs) including
offshore platforms, secondary or enhanced recovery systems, gas
injection, water disposal; expenditures for equipment, machinery,
and fixtures purchased to conduct Petroleum Operations such as
office furniture and fixtures, office equipment, barges, floating
craft, automotive equipment, aircraft, construction equipment,
miscellaneous equipment, and furniture and fixtures related to
employee housing and recreational facilities.
(b) Pipeline and storage expenditures - expenditures in connection
with the design, installation, and construction of pipeline,
transportation, storage, and terminal facilities associated with
Petroleum Operations including tanks, metering, and export lines.
-50-
<PAGE> 54
(c) Building expenditure - expenditures incurred in connection with
the construction of buildings, structures or works of a permanent
nature including workshops, warehouses, offices, roads, wharves,
employee housing and recreational facilities and other tangible
property incidental to construction.
(d) Drilling expenditures - expenditures for tangible goods in
connection with drilling wells such as casing, tubing, surface
and sub-surface production equipment, flow lines, instruments;
costs incurred in connection with the acquisition of rights over
the Contract Area pursuant to paragraph l(d)i of the Second
Schedule of the PPT Act except any bonuses paid under Clause 2 of
the Contract.
(e) Pre-Production expenditures - all costs (including those
otherwise falling within Non-Capital Costs described in paragraph
2 of this Article II) incurred before the first PPT accounting
period.
(f) Material inventory - cost of materials purchased and maintained
as inventory items solely for Petroleum Operations subject to the
following provisions:
(i) Company shall supply or purchase any materials required
for the Petroleum Operations, including those required in
the foreseeable future. Inventory stock levels shall take
account of the time necessary to provide the replacement,
emergency needs and similar considerations.
(ii) Materials purchased by Company for use in the Petroleum
Operations shall be valued so as to include invoice price
(less prepayment discounts, cash discounts, and other
discounts if any) plus freight and forwarding charges
between point of supply and point of destination but not
included in the invoice price, inspection costs,
insurance, customs fees and taxes, on imported materials
required for this Contract.
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<PAGE> 55
(iii) Materials not available in Nigeria supplied by Company or
from its Affiliate's stocks shall be valued at the current
competitive cost in the international market.
(iv) Company shall maintain physical and accounting controls of
materials in stock in accordance with general practice in
the international petroleum industry. Company shall make
a total inventory at least once a year to be observed by
NNPC and its external auditors. NNPC may however carry
out partial or total inventories at its own expense,
whenever it considers necessary, provided such exercise
does not disrupt Petroleum Operations.
ARTICLE III
COMPUTATION OF ROYALTY, CONCESSION RENTALS AND PPT
1. Company shall compute the amount of Royalty and Concession Rentals
payable by NNPC pursuant to Clause 8.2 of the Contract. Such amounts
shall be computed as provided under the Petroleum Act 1969 and the
prevailing fiscal laws and regulations. For purposes of Article IV
hereof, Company shall compute the Royalty payment for remittance in a
given month based on the prevailing fiscal value of the Crude Oil
produced during the second preceding month. Annual Concession Rental
payments shall be taken into account when such payments are remitted.
NNPC shall remit all required payments of Royalty and Concession Rentals
to the Government.
2. Company shall compute the PPT payable by NNPC pursuant to Clause 8.2(a)
of the Contract in accordance with the provisions of the PPT Act and the
Memorandum of Understanding including, but not limited to, such
provisions pertaining to deductions, capital allowance, and any credits
which offset PPT liability. The applicable PPT rate shall be in
accordance with the PPT Act and shall be 65.75% for the first five years
of production from each field developed in the Contract Area commencing
for each field from the first day of the month of first sale therefrom.
Specifically, and not by way of limitation, the Reserve Addition Bonus,
if any, described under paragraph 3 of this Article III shall be applied
in computing
-52-
<PAGE> 56
the PPT payable. NNPC shall make all required PPT payments to the
Federal Inland Revenue Department. Company shall prepare all returns
required under the PPT Act and timely file them with NNPC. The monthly
PPT payable will be determined from such PPT returns.
3. The Memorandum Of Understanding shall be applied when calculating the
PPT. This shall include the application of the Guaranteed Notional
Margin, Revised Government Take, Reserve Addition Bonus, and the tax
offset for Capital Investment Costs. The Reserve Addition Bonus in
respect of reserves found prior to the first year of production shall be
the lesser of the annual average amount expended on Work Programmes
prior to such first year or the amount determined in accordance with the
following:
<TABLE>
<CAPTION>
Reserves Found Prior Reserve Addition Bonus
to First Year of Rate Applied To The
Production Respective Tranche
Million Barrels ($/BBL)
-------------------- ----------------------
<S> <C>
Less than 40 nil
40-60 $0.25
60-90 $0.30
Greater than 90 $0.50
</TABLE>
4. In the event that there is more than one field producing in the Contract
Area and different PPT rates (i.e. either 65.75% or 85%) apply to such
fields, the Chargeable Profit (as defined under the PPT Act) shall be
allocated to each field in the proportion that the fiscal values from
each field during the accounting Year bear to the total fiscal values
from the Contract Area during the accounting Year. The applicable PPT
rate will then be applied to the appropriate Chargeable Profit allocated
to each field.
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<PAGE> 57
ARTICLE IV
ACCOUNTING ANALYSES
1. A monthly accounting analysis in the form of Schedule B-1 attached to
this Accounting Procedure shall be prepared by Company and furnished to
NNPC within sixty (60) days of the end of the period covered by such
analysis.
2. The Realisable Price and the quantities actually lifted by the Parties
shall be used to compute the Proceeds as reflected in Section A of each
Schedule B-l and the allocation of such Proceeds in the categories
described under Clause 9.1 of the Contract shall be reflected in Section
B thereof.
3. The allocation of the quantity of Available Crude Oil to each Party
pursuant to Clause 9 of the Contract shall be according to and governed
by provisions of the Allocation Procedure.
4. The priority of allocation of the total Proceeds for each Period shall
be as follows:
(a) Royalty Oil,
(b) Tax Oil,
(c) Cost Oil, and
(d) Profit Oil.
5. The amount chargeable to and recoverable from Royalty Oil, Tax Oil and
Cost Oil to be entered in Section B of Schedule B-l shall be determined
as follows:
(a) Royalty Oil - The sum of royalties payable during such month,
and, where applicable, the annual amount of Concession Rentals as
provided under Article III 1 for purposes of Royalty Oil.
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<PAGE> 58
(b) Tax Oil - The sum of the PPT payable for such month as provided
under Article III 2, 3, and 4 for purposes of Tax Oil.
(c) Cost Oil - The Operating Costs applicable to such month for
purposes of Cost Oil as follows:
(i) Non-Capital Costs shall be the amount recorded in the
books and accounts of Company for such month in accordance
with this Accounting Procedure.
(ii) Capital Costs recorded in the books and accounts of
Company shall be recoverable in full and chargeable in
equal installments over a five (5) year period or the
remaining life of the Contract, whichever is less.
Amortization of such costs shall be in accordance with the
method prescribed under the Second Schedule of the PPT
Act, or over the remaining life of the contract, whichever
is less.
(d) Any carryover from previous months as provided under paragraph 6
of this Article.
6. Any amounts chargeable and recoverable in excess of the allocation of
Proceeds for the month to Royalty Oil, Tax Oil and Cost Oil shall be
carried forward to subsequent months. Carryovers shall be determined as
follows:
(a) A Royalty Oil value carryover results when the Proceeds for such
month are insufficient for recovery of the Royalty Oil due for
the month.
(b) A Tax Oil value carryover results when the Proceeds remaining
after allocating a portion of the Proceeds to Royalty Oil are
insufficient for recovery of the Tax Oil due for the month.
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<PAGE> 59
(c) A Cost Oil value carryover results when the Proceeds remaining
after allocating a portion of the Proceeds to Royalty Oil and Tax
Oil are insufficient for recovery of Cost Oil due for the month.
7. Profit Oil results where Proceeds remain after allocations to Royalty
Oil, Tax Oil and Cost Oil pursuant to paragraph 5 of this Article IV.
Profit Oil shall be allocated to the Parties according to the following
percentages:
<TABLE>
<CAPTION>
Monthly Average Profit Oil
MBOPD From Contract Area Percentages
---------------------------------------- ----------------------
NNPC COMPANY
---- -------
<S> <C> <C>
0 to 40 30 70
Greater than 40 but less than 75 40 60
Greater than 75 but less than 100 45 55
100 and above 60 40
</TABLE>
A computation of Profit Oil shares in the form of Schedule B-2 attached
to this Accounting Procedure shall be submitted monthly in conjunction
with Schedule B-1.
ARTICLE V
OTHER PROVISIONS
1. Company shall open and keep bank accounts in Nigeria in Naira where all
funds remitted from abroad shall be deposited for the purpose of meeting
local expenditures. For purposes of keeping the books of accounts, any
Foreign Currency remitted by Company into Nigeria shall be converted
into Naira at the monthly exchange rates advised by the Central Bank of
Nigeria.
2. Company shall prepare financial accounting and budget statements in
accordance with NNPC's prescribed reporting format.
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<PAGE> 60
3. Financial accounting and budget statements, in accordance with NNPC's
prescribed reporting format, shall be prepared quarterly, by Company, in
respect of Sole Risk Operations.
4. With respect to any agreed sum arising out of this Contract owing
between the Parties that is past due, any set-off pursuant to Clause
12.3 shall be exercised by giving the other Party written notice thereof
accompanied by sufficient descriptions of the offsetting sums to allow
the Parties to properly account therefor.
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<PAGE> 61
SCHEDULE B-1
MONTHLY ACCOUNTING ANALYSIS
MONTHLY OF _____________, ____________
SECTION A - LIFTING SUMMARY
<TABLE>
<CAPTION>
============================================================================================================
Proceeds Received By:
--------------------------
Lifting Date Crude Type RP Volume Proceeds NNPC ANEU
US$/Bbl Bbls US$
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
============================================================================================================
Totals
========================================================================
</TABLE>
SECTION B - ALLOCATION OF PROCEEDS - EXPRESSED IN U.S. DOLLARS
<TABLE>
<CAPTION>
==============================================================================================================
ALLOCATION OF
PRIOR CURRENT RECOVERABLE PROCEEDS:
MONTH MONTH THIS ---------------
CATEGORY CARRYOVER CHARGES MONTH NNPC ANEU CARRY-OVER
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Royalty Oil
- --------------------------------------------------------------------------------------------------------------
Tax Oil
- --------------------------------------------------------------------------------------------------------------
Cost Oil
- --------------------------------------------------------------------------------------------------------------
NNPC Profit Oil
- --------------------------------------------------------------------------------------------------------------
ANEU Profit Oil
==============================================================================================================
Totals
==============================================================================================================
</TABLE>
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<PAGE> 62
SCHEDULE B-2
PROFIT OIL SHARES
MONTH OF _________, ______
SECTION A - TOTAL PRODUCTION FOR THE MONTH
<TABLE>
<CAPTION>
==============================================================
Field Total Net Barrels
- --------------------------------------------------------------
<S> <C>
- --------------------------------------------------------------
- --------------------------------------------------------------
- --------------------------------------------------------------
==============================================================
==============================================================
</TABLE>
SECTION B - TOTAL PROFIT OIL FOR THE MONTH
<TABLE>
<CAPTION>
==============================================================
Category US$
- --------------------------------------------------------------
<S> <C>
Proceeds
- --------------------------------------------------------------
Royalty Oil
- --------------------------------------------------------------
Tax Oil
- --------------------------------------------------------------
Cost Oil
- --------------------------------------------------------------
Profit Oil
==============================================================
</TABLE>
SECTION C - CALCULATION OF PROFIT OIL SHARES
<TABLE>
<CAPTION>
========================================================================================================================
Monthly % Of Total Monthly Profit NNPC Profit NNPC's ANEU's
Barrels/Day Produced Production Monthly By Tranch, US $ Share By Profit, Profit,
For The Month By Tranch, Barrels Production Tranch US $ US $
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
First 40,000 Bbls/Day 0.30
- ------------------------------------------------------------------------------------------------------------------------
Next 35,000 Bbls/Day 0.40
- ------------------------------------------------------------------------------------------------------------------------
Next 25,000 Bbls/Day 0.45
- ------------------------------------------------------------------------------------------------------------------------
Over 100,000 Bbls, Day 0.60
- ------------------------------------------------------------------------------------------------------------------------
Total Monthly
Production
========================================================================================================================
</TABLE>
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<PAGE> 63
ANNEX C
TO THAT CERTAIN PRODUCTION SHARING CONTRACT
BETWEEN NNPC AND THE COMPANY DATED 25 MARCH 1992
ALLOCATION PROCEDURE
ARTICLE I
APPLICATION
1. This Allocation Procedure ("this Procedure") sets out the methods for
the allocation of Available Crude Oil from the Contract Area and the
Parties shall allocate all liftings of Available Crude Oil in accordance
with this Procedure and the Contract.
2. In the event that the production of Available Crude Oil is segregated
into two or more types of grades, the provisions of this Procedure shall
apply separately to each such type or grade. To the extent that
distribution on such a basis is impracticable, a separate method for the
allocation of such Available Crude Oil shall be agreed upon by the
Parties.
3. In the event of a conflict between the terms of this Procedure and the
Contract, the terms of the Contract shall prevail.
4. The procedures set forth herein may be amended from time to time by
mutual agreement of the Parties.
ARTICLE II
DEFINITIONS
1. The words and expressions defined in the Contract when used herein,
shall have the meaning ascribed to them in the Contract. In addition,
the following words shall have the meanings set forth below:
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<PAGE> 64
(a) "CURRENT QUARTER" means the calendar quarter within which the
relevant Schedules are prepared and submitted;
(b) "FORECAST QUARTER" means the first calendar quarter succeeding
the Current Quarter;
(c) "LIFTING ALLOCATION" means the quantity of Available Crude Oil
which each Party has the right to take in kind, lift and dispose
of in accordance with Clause 9 of the Contract;
(d) "PRIMARY NOMINATION" means written statement issued by each
Party to the other at least twenty-five (25) days prior to the
commencement of each quarter declaring the volume by grade of its
estimated Lifting Allocation which the Party desires to lift
during the Forecast Quarter;
(e) "PROCEEDS" means the amount in U.S. Dollars determined by
multiplying the Realisable Price by the number of Barrels of
Available Crude Oil lifted by either Party; and
(f) "PROCEEDS IMBALANCE" means the difference between each Party's
Proceeds to which it is entitled and the Proceeds which each
Party has actually received, as reflected in each quarter's
Schedule C-2 of this Procedure.
ARTICLE III
LIFTING ALLOCATION
1. On or before September 30 of every year, Company shall advise the
Parties of its forecast of the Available Crude Oil to be produced by
grades during each month of the first six (6) months of the next ensuing
Year.
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<PAGE> 65
2. On or before March 31 of every year, Company shall advise NNPC of its
forecast of Available Crude Oil to be produced by grades during each
month of the six (6) months commencing July 1, of the Year.
3. Thirty-five (35) days before commencement of production from the
Contract Area and thereafter thirty-five (35) days prior to the
beginning of the Forecast Quarter, Company shall notify NNPC of the
estimated Lifting Allocation which can be produced and made available
for disposal during the Forecast Quarter. Such estimated Lifting
Allocation shall take into account any Proceeds Imbalance for the
quarter first preceding the Current Quarter and any estimated Proceeds
Imbalance for the Current Quarter computed in accordance with paragraph
3 of Article IV. Such notice shall be in the form of Schedule C-l
attached hereto indicating the estimated quantities of Royalty Oil, Tax
Oil, Cost Oil and Profit Oil, each Party's estimated Lifting Allocation
and the estimated Realisable Price used to prepare such estimated
Lifting Allocations.
4. Twenty-five (25) days before the commencement of production from the
Contract Area and thereafter not later than twenty-five (25) days before
the beginning of Forecast Quarter, each Party shall notify the other of
its Primary Nomination of Available Crude Oil which it intend(s) to lift
during the Forecast Quarter which shall not exceed its estimated Lifting
Allocation. Such notice shall include the information described in
Article V, paragraph 1 of Annex D - Nomination, Ship Scheduling and
Lifting Procedure.
5. The estimated Realisable Price to be used by Company to prepare Schedule
C-l (Estimated Quarterly Lifting Allocation) shall be the Realisable
Price of the first month of the Current Quarter.
6. Each Party shall be obligated to lift its own Lifting Allocation in
accordance with the Nomination, Ship Scheduling and Lifting Procedure
(Annex D). In the event that one Party lifts the other Party's Lifting
Allocation, the lifting Party shall pay to the non-Lifting Party the
applicable Proceeds pursuant to Clause 9.5 of the Contract. In such
case, the non-lifting
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Party shall be treated for all other purposes under this Contract as
though it had made such lifting itself.
ARTICLE IV
ADJUSTMENTS OF LIFTING ALLOCATION
1. On or before thirty-five (35) days prior to the last day of the Current
Quarter, the Lifting Allocation for the first preceding quarter thereto
shall be computed and the Proceeds Imbalance determined and notified to
NNPC in the form of Schedule C-2 attached hereto. Section A of such
Schedule C-2 shall be based on the actual liftings made by the Parties
and the Proceeds therefrom. Section B of such Schedule C-2 shall be
prepared from the Schedule B-l's (of the Accounting Procedure) for the
months in the quarter.
2. On or before thirty-five (35) days prior to the last day of the Current
Quarter, the Proceeds Imbalance for the Current Quarter shall be
estimated, taking into account the actual Proceeds Imbalance computed
for the first preceding quarter under paragraph 1 of this Article IV.
3. The Proceeds Imbalance for the first preceding quarter computed under
paragraph 1 above and the estimated Proceeds Imbalance for the Current
Quarter computed under paragraph 2 above shall be taken into account by
the Parties by debiting or crediting such Proceeds Imbalances to each
Party's share of the estimated Lifting Allocation reflected in Schedule
C-1 for the Forecast Quarter filed in accordance with paragraph 3 of
Article III.
4. Notwithstanding the reports required to be kept by Company pursuant to
Article IV in Annex D, Company shall keep complete records of all
liftings. At the end of each quarter, the Parties will meet to
reconcile the Lifting Allocations and the actual liftings with a view to
making adjustments as appropriate. If any disagreement arises with
respect to such reconciliation, the area of disagreement shall be
mutually resolved by the Parties.
5. All Lifting Allocations and actual liftings shall be audited at the end
of each calendar year by a mutually acceptable independent auditor.
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SCHEDULE C-1
ESTIMATED QUARTERLY LIFTING ALLOCATION
_____ QUARTER (_____-_____), ______
SECTION A - ESTIMATED TOTAL PROCEEDS
<TABLE>
<CAPTION>
================================================================================
Estimated Estimated Estimated
Crude Lifting RP Proceeds
Type Volume Bbls US$/Bbl US$
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
================================================================================
Totals
================================================================================
</TABLE>
SECTION B - ALLOCATION OF ESTIMATED PROCEEDS - EXPRESSED IN U.S. DOLLARS
<TABLE>
<CAPTION>
=============================================================================================================
Allocation of Estimated
Prior Estimated Recoverable Proceeds To:
Month Quarter This ----------------------
Category Carryover Charges Quarter NNPC ANEU
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Royalty Oil
- -------------------------------------------------------------------------------------------------------------
Tax Oil
- -------------------------------------------------------------------------------------------------------------
Cost Oil
- -------------------------------------------------------------------------------------------------------------
NNPC Profit Oil
- -------------------------------------------------------------------------------------------------------------
ANEU Profit Oil
=============================================================================================================
Totals
=============================================================================================================
Prior Quarter's Proceeds Imbalance
(Over) /Under
---------------------------------------------------------------------------
Current Quarter's Estimated Proceeds Imbalance
(Over) / Under
---------------------------------------------------------------------------
Estimated Proceeds Allocation For Quarter
===========================================================================
</TABLE>
SECTION C - ESTIMATED LIFTING ALLOCATION
<TABLE>
<CAPTION>
=========================================================================================================
NNPC Allocation ANEU Allocation
Crude --------------------------------------------------------------------------------
Type Proceeds Bbls Proceeds Bbls
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
=========================================================================================================
</TABLE>
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SCHEDULE C-2
ACTUAL QUARTERLY LIFTING ALLOCATION
________ QUARTER (_____-_____), _______
SECTION A - LIFTING SUMMARY
<TABLE>
<CAPTION>
=========================================================================================================
Proceeds Received By:
Crude Volume Proceeds RP --------------------------
Type Bbls US$ US$/Bbl NNPC ANEU
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
=========================================================================================================
Totals
=========================================================================================================
</TABLE>
SECTION B - ALLOCATION OF PROCEEDS - EXPRESSED IN U.S. DOLLARS
<TABLE>
<CAPTION>
==============================================================================================================
NNPC: ANEU:
---------------------------------------------------------
Category Sum of Allocation Lifting Allocation Lifting
Monthly of Proceeds of Proceeds
Allocation Proceeds Received Proceeds Received
==============================================================================================================
<S> <C> <C> <C> <C> <C>
Royalty Oil
- --------------------------------------------------------------------------------------------------------------
Tax Oil
- --------------------------------------------------------------------------------------------------------------
Cost Oil
- --------------------------------------------------------------------------------------------------------------
NNPC Profit Oil
- --------------------------------------------------------------------------------------------------------------
ANEU Profit Oil
==============================================================================================================
Totals
==============================================================================================================
Quarter (Over)/Under
----------------------------------------------------------------------------------------
Prior Quarter (Over)/Under
Proceeds ----------------------------------------------------------------------------------------
Imbalance Total (Over)/Under
==============================================================================================================
</TABLE>
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ANNEX D
UNIFORM NOMINATION, SHIP SCHEDULING AND LIFTING PROCEDURE
PREAMBLE
This Annex D attached to and forming part of the Production Sharing Contract
made between NIGERIAN NATIONAL PETROLEUM CORPORATION AND ASHLAND NIGERIA
EXPLORATION UNLIMITED dated the 25th day of March, 1992 (CONTRACT).
ARTICLE I
APPLICATION
1. This Annex D sets out the procedure for the nomination, ship scheduling
and lifting of Available Crude Oil from the Contract Area.
2. Pursuant to Clause 9 of the Contract NNPC and Company have the rights to
nominate, lift and separately dispose of their agreed allocation of
Available Crude Oil produced and saved from the Contract Area.
3. The procedures set herein may be amended from time to time by the mutual
agreement of the parties.
4. In the event of a conflict between the terms of this Annex D and the
Contract, the terms of the Contract shall apply.
ARTICLE II
DEFINITION AND TERMINOLOGY
1. Words and expressions in this Annex shall have the meaning ascribed to
them in the Contract. In addition, the following words shall have the
following meanings:
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(a) "AVAILABLE PRODUCTION" means the quantity of Petroleum which can
be efficiently and economically produced and saved from the
producing wells subject to any limitations imposed by government
authority or other technical limitations resulting from
Operations.
(b) "TECHNICAL ALLOWABLE PRODUCTION" means the quantity of petroleum
from time to time determined by the Department of Petroleum
Resources as being the quantity that may be produced from the
Contract Area on a well by well basis for a particular period.
(c) "COMMERCIAL PRODUCTION QUOTA" means the quantity of petroleum
from time to time fixed or advised by National Petroleum
Investment Management Services (NAPIMS) on behalf of the
Honorable Minister of Petroleum Resources as the permissible
quantity that may be produced from the Contract Area on a crude
stream basis for a particular month/quarter.
(d) "ACTUAL PRODUCTION" means the quantity of petroleum which is
produced from the Contract Area on a monthly/quarterly basis.
(e) "AVAILABLE MONTHLY SCHEDULING QUANTITY" means each Party's
allocation of the Available Production for the calendar month
plus Opening Stock.
(f) "COMBINED LIFTING SCHEDULE" means the lifting programmes of the
Parties for a given calendar month/quarter as prepared by the
Company and agreed to by the Parties.
(g) "OPENING STOCK" means the quantity of crude oil that each Party
may carry forward to the succeeding month, recognizing the
difficulty in lifting precisely the Available Monthly Scheduling
Quantity. This quantity which excludes unpumpable dead stock,
should not be such as to cause a production shut-in through
reaching maximum stock
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levels where of course the provisions of Article V will apply.
The quantity also includes credits/debits accruing after
reconciliation with Available crude.
(h) "PRIMARY NOMINATION" means a written statement issued by each
Party to the Contractor at least twenty-five (25) days prior to
the commencement of each calendar month of its production
nominations based on its allocation of the Commercial Production
Quota Crude Oil by grade, which it desires to take during the
particular calendar month plus Opening Stock.
ARTICLE III
PRODUCTION/NOTICE OF AVAILABILITY
1. Company shall endeavor to produce the aggregate volume of oil nominated
by the Parties as provided in this Contract.
2. In the event that Available Crude Oil is segregated into two or more
grades the provisions of this Annex D shall apply separately to each
such grade. To the extent that distribution on such a basis is
impracticable, separate arrangement for sharing of such Available Crude
Oil shall be agreed upon by the Parties.
3. On or before September 30 of every year, Company shall advise the
Parties of its forecast of the Available Production to be produced by
grades during each month of the first six (6) months of the next ensuing
year.
4. On or before March 31 of every year, Company shall advise NNPC of its
forecast of the Available Production to be produced by grades during
each month of six months commencing July 1, of the year.
5. Where for operational reasons the Company cannot exactly produce at the
anticipated Commercial Production Quota, the company shall notify NNPC
promptly of any required changes exceeding 2% of the quantities
originally notified. In any event, when actual
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production for the month/quarter is known each Party's allocation will
be re-calculated and the differences between Actual Production and
Commercial Production Quota will be credited/debited to each Party, and
shall form the Party's entitlement for the following month or quarter
except in the case of production shut-ins where the provisions of
Section 6 will apply.
6. Twenty-Five (25) days before the commencement of Production from the
Contract Area and thereafter not later than twenty-five (25) days before
the beginning of each month, each Party shall notify the company of its
Primary Nomination of Available Crude Oil which it intend(s) to lift
during the ensuing month, which shall not exceed its monthly allocation
of Commercial Production Quota plus Opening Stock.
7. At the end of each month/quarter, Parties will meet to reconcile
Available Monthly Scheduling Quantities with actual Available Crude
lifted and adjustments made where necessary. All entitlements shall be
audited at the end of each calendar year by mutually acceptable
independent auditor.
8. Company shall keep complete records of all liftings and advise the NNPC
in accordance with Article III & IV of this Annex D.
ARTICLE IV
COMPANY'S REPORTS
1. The Company shall, not more than fifteen (15) working days after the end
of each calendar month, and quarter, prepare and furnish to NNPC written
statement showing in respect of the month and quarter respectively:
(a) Production Quota: each party's allocation of Commercial
Production Quota;
(b) Lifting against Available Crude Oil;.
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(c) Each Party's allocations of Available Crude Oil;
(d) Quantity of Crude Oil in Stock for each Party at the end of the
said calendar month or quarter; and
(e) Any production losses attributable to crude oil used in Petroleum
Operations.
2. In the event NNPC disagrees with any of the Company's reports, the area
of disagreement shall be mutually resolved by the Company and NNPC.
Company shall thereafter prepare a revised report to reflect the changes
agreed.
3. Company must also endeavor to send consistent statistical data to the
different reporting bodies and should adhere to agreed formats of
reporting.
ARTICLE V
SCHEDULING DETAILS
1. SCHEDULING NOTIFICATION - At least twenty-five (25) days prior to the
beginning of a calendar month, NNPC shall notify the Company of its
proposed tanker schedule for that calendar month specifying the
following:
(a) A loading date range of ten (10) days for each tanker lifting;
(b) The desired parcel size for each lifting in Barrels, subject
always to change within a range of plus or minus five percent
(5%) by the Party so nominating;
(c) The tanker's name or To Be Named (TBN) for each tanker lifting.
Tanker nominations made as TBN shall be replaced at least five
(5) working days prior to the accepted date range, unless a
shorter time is acceptable to the Company; and
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(d) Documentation instructions shall be given for each lifting not
later than four (4) days prior to the first day of the accepted
date range for the tanker in question.
2. TANKER SUBSTITUTION - Either Party may substitute another tanker to lift
its nominated volume of Crude Oil, provided such substituted tanker has
the same arrival date range as the originally scheduled tanker and all
other provisions of this Annex D are complied with.
3. OVERLAPPING DATE RANGES - In the event the Combined Lifting Schedule
contains overlapping accepted date ranges, the tanker which gives its
Notice of Readiness (NOR) and has provided all documentation and
obtained clearances first within such accepted date ranges shall be
loaded first, unless urgent operational requirements dictate otherwise
in which case, demurrage shall be borne by Petroleum Operations and
charged to Operating cost.
4. CONFIRMATION OF LIFTING SCHEDULES - At least fifteen (15) days prior to
the beginning of a calendar month, the Company shall either confirm the
feasibility of the proposed monthly lifting schedules or, alternatively,
advise necessary modifications to such schedules. Such confirmation
which shall be in the form of combined lifting schedule, should include
a loading date range of three (3) days for each lifting, the first day
being the earliest date of arrival and the 3rd day being the latest date
of arrival.
5. OPERATIONAL DELAYS - The Parties recognize that occasionally environment
and technical problem in the Contract Area may cause delays and/or
disruptions in the Combined Lifting Schedule. The Company shall
promptly notify NNPC of such delays and/or disruptions, and the
projected termination of each of such delays and/or disruptions and
advise NNPC of the revised Combined Lifting Schedule. In the event such
notification does not allow for a revised Combined Lifting Schedule on
the part of NNPC, then any resultant costs will be charged to Operating
Cost.
6. ESTIMATED DELAYED ARRIVAL OF A TANKER - Whenever it becomes apparent
that a tanker will not be available as scheduled or will be delayed, the
party utilising such tanker shall notify
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the other Party of the circumstances and expected duration of the
delays. Upon assessing the impact that the delay will have upon the
Combined Lifting Schedule and Production during the current and/or next
month, the Company shall make appropriate revision(s) to the Combined
Lifting Schedule to avoid disruption in production. In the event that
any Party fails to lift its Nominated Share of Production in any
month/quarter due to circumstances beyond the Party's Control or
difficulties in maintaining the lifting schedule, that party shall have
the right during the following quarter/month to lift the unlifted
quantities.
7. TANKER STANDARDS - All Tankers nominated for lifting by any Party
pursuant to this Annex D shall conform to the international regulations
and standards concerning size, equipment, safety, maintenance and the
like adopted by the Company for the Terminal in question and by the
appropriate government authority. Failure of a tanker to meet such
standards shall not excuse the nominating Party from the applicable
consequences provided in the Contract. Company shall keep NNPC advised
as to the current Regulations and standards in use at the terminals
operated by the Company.
ARTICLE VI
PRODUCTION DECREASES/INCREASES SUBSEQUENT TO NOMINATION
1. Production decreases occurring after lifting nominations have been
scheduled and not resulting from the fault of either Party shall be
shared by the Parties in proportion to their respective nominations.
2. Production increases occurring after lifting nominations have been
confirmed by the Company shall be shared by the Parties, in proportion
to their respective agreed allocation.
3. To the extent that field operations permit, a Party shall have the right
to adjust its nomination during a month following confirmation of
lifting schedule provided that the nominations, entitlement and lifting
of the other Party are not affected thereby without their express
written consent. Adjusted nomination shall always be within the limits
of the Party's allocated portion of the Commercial Production Quota,
plus Opening Stock.
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4. Any production decrease caused by or resulting directly from the actions
of one Party shall not affect the availability or entitlement of the
other Party. Company will, to the greatest extent possible, endeavor
not to affect the lifting of the other Party.
5. For the avoidance of doubt each Party's agreed allocations shall be
based on Actual Production.
ARTICLE VII
DELIVERY TERMS AND CONDITIONS
1. TANKER NOTIFICATION - The Parties shall report, or cause the tankers
nominated for lifting pursuant to this Annex D to report, by radio/telex
to Company of each tanker's Schedule arrival date and hour as follows:
(a) Seven (7) days before estimated arrival, or upon clearing at last
port if there is less than seven (7) days steaming time before
estimated arrival;
(b) Seventy-two (72) hours before estimated arrival;
(c) Forty-Eight (48) hours before estimated arrival;
(d) Twenty-four (24) hours before estimated arrival; and
(e) At any other time(s) between the seventy-two (72) hours notice,
forty-eight (48) hours notice and twenty-four (24) hours notice
when estimated arrival is to be revised by more than twelve (12)
hours from that most recently notified or after that revised by
more than one-half hour.
Parties shall also cause such tanker so nominated, or their agent, to
report by radio/telex to the Nigerian Government Port Head Official at
the port at least seventy-two (72) hours before each tanker's scheduled
arrival date giving the tanker's name, call sign, ETA at the
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port(s), cargo tonnage to be loaded, number of crew health status,
whether or not a doctor is on board and a request for "Free Pratique."
2. NOTICE OF READINESS - Upon arrival at the designated safe anchorage at
the Port or upon the time of boarding of the Mooring master, whichever
is earlier, the Master of the tanker shall give the Company a Notice Of
Readiness (NOR) by radio or by letter, as appropriate, confirming that
the tanker is ready to load cargo, berth or no berth. Laytime, as
herein provided, shall commence upon the expiration of six (6) running
hours after receipt by the Loading Terminal of such notice, upon the
tanker's completion of mooring at the sea loading terminal, whichever
first occurs. However, where delay is caused to the tanker getting into
berth after giving NOR for any reason over which neither Company nor the
loading Terminal has control, such delay shall not count as used
laytime. In addition time used by tanker while proceeding to berth or
awaiting entry and Free Pratique by customs after the expiration of six
(6) running hours free time, shall not count as used laytime.
3. EARLY TANKER ARRIVAL - Notwithstanding the provisions of Article VII 2
above, if the tanker arrives and tenders NOR to load prior to its agreed
date range, Company shall endeavor to load tanker on arrival or as soon
thereafter as possible and laytime shall only commence when loading
commences. If, however, Company is unable to accept tanker for loading
prior to the agreed date range, laytime shall commence at 0600 hours,
local time on the first day of the agreed date range or when loading
commences, whichever occurs first.
4. LATE TANKER ARRIVAL - If tanker arrives and tenders NOR to load after
its accepted date range and other tankers (having arrived during their
accepted date-range), are either loading or waiting to load the loading
tanker shall be governed by the earliest availability of crude and
loading slot, and laytime shall commence only when loading commences.
5. LAYTIME - Company shall be allowed laytime in running hours equal to one
half of the voyage laytime permitted under Worldscale, or such other
freight scale that is issued in replacement thereof, for loading a full
cargo and pro rata thereof for a part cargo, with a minimum of eighteen
(18) hours, Sundays and Holidays included, any delay due to the fault
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of the tanker or its facilities to load cargo within the time allowed
shall not count as used laytime. If rules of the Owner of the vessel or
Regulations of Government or appropriate Government Agencies prohibit
loading of the cargo at any time, the time so lost shall not count as
used laytime. Time consumed loading or discharging ballast or
discharging slops shall not count as used laytime. Laytime shall
continue until hoses have disconnected.
Laytime allowed for loading a full cargo is "36 Running Hours" with a
provision for pro-rating the laytime in the case of vessels loading part
cargo. When a vessel is loading one parcel only and operations commence
ahead of the acceptance date there is no demurrage involved unless the
vessel completes cargo after the permissible laytime, commencing 0001
hours on the agreed acceptance date. In cases where a vessel loads more
than one parcel and more than one acceptance date is awarded, then
demurrage will not count unless the total loading is completed after the
expiry of the permissible laytime for the last parcel, counting 0001
hours on the last acceptance date.
6. DEMURRAGE - If the Company is unable to load within the time allowed,
the Company shall apply demurrage per running hour (pro rata for a part
thereof) for laytime exceeding the allowed laytime as specified herein.
The rate of demurrage will be calculated by multiplying the time by the
Average Freight Rate Assessment (AFRA) as determined by the London
Tanker Brokers Panel. In the event such determination is no longer
available, a freight rate assessment shall be mutually agreed by the
Parties; which rate shall be appropriate in relation to the size of the
tanker and in demurrage rate according to tanker size as specified in
the Worldwide Tanker Nominal Freight Scale or such other freight scale
that is issued in replacement thereof. If however, demurrage shall be
incurred by reason of fire, storm, explosion, or by strike, picketing,
lockout, stoppage or restraint or labour difficulties, or disturbances
or by breakdown of machinery or equipment in or about the Loading
Terminal, the rate of demurrage as calculated in accordance with the
above shall be governed by Force Majeure and shall not attract any
demurrage. Demurrage claims must be notified within ninety (90) days
from Bill of Lading date.
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7. CHANGE OF BERTH - Company shall have the right to shift any vessel from
one berth to another. Charges of running lines on arrival at and leaving
the berth, wharfage and dockage charges at that berth, and any other
extra port charges or port expenses incurred by reason of such shifting
at the Company's request shall be borne by the Company and shall count
as used laytime. If, however, it is necessary to shift the vessel from
the berth because of breakdown machinery of other deficiency of the
vessel or its crew, the resulting expenses shall be borne by the Party
whose Crude Oil is being lifted. The time consumed in such
circumstances, shall not count as used laytime. However, the vessel
shall lose its regular turn in berth. When the vessel is ready to
recommence loading, it shall so advise Company and await its turn for
reberthing and such time after notice is given shall not count as used
laytime.
8. TANKER DEPARTURE - Tanker shall vacate the berth as soon as loading is
complete. The Party that scheduled such tanker shall indemnify Company
for any direct loss or damage incurred as a result of tanker's failure
to vacate the berth promptly including such loss or damage as may be
incurred due to resulting delay in the docking of the tanker awaiting
the next turn to load at such berth.
9. LOADING HOSES - Hoses for loading shall be furnished by the Company and
shall be connected and disconnected by the tanker's crew under the
supervision of a suitable qualified Ship's Officer acting on the advise
of the Operator's Mooring Master.
10. PARTIAL CARGO - Should Company supply less than full cargo, for any
reasons the tanker shall not be required to proceed to sea until all of
her tanks are filled with a combination of cargo and ballast as will
place her in a seaworthy condition.
ARTICLE VIII
CRUDE OIL QUANTITY AND MEASUREMENT
1. CERTIFICATION - The quantity and origin of each shipment of Crude Oil
shall be determined by the appropriate Government authority at the
loading Terminal and set forth in standard
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Certificates of Quantity, Quality and Origin. Each Party shall have the
right to designate a representative at its own expenses, who shall have
the right to witness the determination of Quantity, Quality and Origin.
All reasonable facilities shall be supplied by the Company as necessary,
to such Party's representatives at the Port to enable such
representatives to witness the measurements taken at the Loading
Terminal and the taking of the sample to be used supplied to the
Representative of the Party.
2. ACCEPTANCE OF CERTIFICATE - If the Party in question does not appoint a
representative, or if such representative appointed as aforesaid agrees
with the Certificate of Quantity, Quality and Origin of a shipment of
Crude Oil (in which event he shall so indicate by signing the
Certificate of Quantity, Quality and Origin), such determinations shall
be final and binding on the Parties.
3. REFUSAL OF CERTIFICATE - If the determination of Quantity, Quality and
Origin by Company have not been approved by such a representative in
accordance with Article VIII 2 above and dispute arises concerning the
Quantity, Quality and Origin of Crude Oil, recourse shall be had to an
independent expert to resolve the dispute on the basis of his expertise.
Claims about Quantity and Quality of Crude Oil delivered shall be
notified within forty-five (45) days from Bill of Lading date. The
expert shall be selected on the basis of his special knowledge of the
subject matter in this regard and shall be appointed by mutual agreement
of the Parties provided however, that the documentation shall
nevertheless be prepared in accordance with the Company's
determinations. Such expert shall file his conclusions within thirty
(30) days after his date of appointment. Any conclusions of such expert
shall be binding upon Parties. Pending the determination of the
dispute, the tanker may sail, unless the Parties agree otherwise.
4. QUANTITY DETERMINATION - The quantity of Crude Oil lifted shall be
determined at the time of loading on the basis of gauging the terminal
tanks before and after the lifting of such Crude Oil, or otherwise by
meter readings installed on the loading line from the tanks, if approved
by appropriate Government Authority. The quantity in Barrels of Crude
Oil determined pursuant to the foregoing procedure shall be corrected to
a temperature of sixty
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degrees Fahrenheit (60 degrees F) in accordance with the most currently
published ASTM-IP Petroleum Measurement Tables. A copy of the
concession calculation, if any, shall be submitted to the Lifting Party
through its representative. In addition, the Basic Sediment and Water
("BS&W") content, determined in accordance with Article VII 5 hereof,
shall be deducted from the quantity loaded, for purposes of preparing
the Bill of Lading for such shipment and for purposes of substantiating
claims about Quantity and Quality. Any substantiated loss of Crude Oil
occurring in transit between the point of such determination and
delivery point shall be borne by the Parties as cost of operation
provided such losses do not result due to differences in method of
determining BS&W between the loading and discharge terminals. For
differences occurring where same method of determination at both points
are used, provisions of Article VIII 3 above shall apply. The retained
sample shall be used in determining such loss claims.
5. QUALITY DETERMINATION - The determination of API Gravity and BS&W
content shall be made of each shipment of Crude Oil. BS&W content and
API Gravity shall be determined according to standard international
practices acceptable to the relevant Government authorities.
6. SAMPLES - A sample of each shipment of Crude Oil shall be taken. The
sample shall be sealed and retained by Company for a maximum of ninety
(90) days. The lifting party or its representative shall have the right
to receive one (1) gallon sealed sample of the Crude Oil loaded which
shall be placed on board the tanker, if so requested.
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ANNEX E
TO THAT CERTAIN PRODUCTION SHARING CONTRACT
BETWEEN NNPC AND COMPANY DATED 25 MARCH, 1992
PROCUREMENT AND PROJECT IMPLEMENTATION PROCEDURES
ARTICLE I
APPLICATION
1.1 These Procurement and Project Implementation Procedures ("Procedures")
shall be followed and observed in the performance of either Party's
obligations under the Contract. Words and expressions defined under the
Contract, when used herein, shall have the meanings ascribed to them in
the Contract. In the event of a conflict between the terms of these
Procedures and the Contract, the terms of the Contract shall prevail.
1.2 These Procedures shall be applicable to all contracts and purchase
orders which values exceed the respective limits set forth in Article
1.3 and which, pursuant thereto, require the prior concurrence of NNPC.
These Procedures may be amended from time to time by the Parties.
1.3 The Company shall have the authority, subject to any limitations or
restrictions established by the Management Committee, to enter into any
contract or place any purchase order in its own name for the performance
of services or the procurement of facilities, equipment, materials or
supplies, provided that:
(a) Prior approval of NNPC will be obtained for all foreign contracts
and foreign purchase orders awarded to third parties where the
cost exceeds one hundred thousand U.S. Dollars ($100,000);
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(b) Prior approval of NNPC will be obtained for all local contracts
and purchase orders where the cost exceeds one million Naira
(N1,000,000);
(c) The amounts set forth in Article 1.3 (a), (b), and (h) will be
reviewed by the Management Committee whenever it becomes apparent
to either Party that such limits create unreasonable constraints
on the Petroleum Operations. In the event of a significant
change in the exchange rate of Naira to U.S. Dollar compared to
that which existed on the Effective Date, the Management
Committee shall review the limits set forth in Article 1.3 (a),
(b) and (h);
(d) Such contracts shall be entered into, and such purchase orders
shall be placed with third parties, which in Company's opinion
are technically and financially able to properly perform their
obligations;
(e) Procedures customary in the oil industry for securing competitive
prices shall prevail unless compelling reasons to the contrary
exist;
(f) Company shall give preference to contractors that are companies
organized under the laws of Nigeria to the maximum extent
possible, provided there is no significant difference in price,
quality, or availability between such contractor and other
contractors;
(g) Company shall give preference to such goods which are
manufactured or produced in Nigeria or services rendered by
Nigerians, provided such goods and services are of required
quality, are offered at competitive prices, and are timely
available; and
(h) The above limits and these Procedures shall not apply to
purchases made for warehouses replenishment stock not exceeding
one hundred thousand U.S. Dollars ($100,000) or one million Naira
(N1,000,000) nor shall they apply to the purchase of tubulars of
less than two hundred thousand U.S. Dollars ($200,000) or two
million Naira (N2,000,000) made in furtherance of planned
drilling programmes. Where
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there are Naira and U.S. Dollar components of such purchases, the
total shall not exceed two hundred thousand U.S. Dollars
($200,000) or the equivalent of two million Naira (N2,000,000.)
ARTICLE II
PROJECT IMPLEMENTATION PROCEDURE
2.1 Company realizing the need for a project or contract to which these
Procedures apply pursuant to Article 1.3 herein above, shall introduce
it as part of the proposed Work Programmes and Budgets to be developed
and submitted by the Company to the Management Committee pursuant to
Clause 6.3 of this Contract.
(a) Company shall provide adequate information with respect to the
project including, without limitation, the following:
(i) A clear definition of the necessity and objectives of the
project;
(ii) Scope of the project; and
(iii) Cost estimate thereof.
(b) Company shall transmit the project proposal along with all
related documentation to NNPC for consideration.
(c) NNPC may make recommendations in writing to the Company regarding
the selection, scope and timing of the project. The Management
Committee shall consider the proposal and the recommendations of
NNPC and shall determine the matter in accordance with Clause 7
of the Contract. Any disputed issues shall be resolved by the
Management Committee pursuant to Clause 7.4(d) of the Contract.
If NNPC does not submit any recommendations in writing to Company
within fifteen (15) working days of the submittal of the project,
the project as proposed by
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Company shall be deemed approved by the Management Committee and
shall be so noted in the minutes of the next meeting.
2.2 The project as approved pursuant to Article 2.1 above shall form part of
the Work Programme and Budget of the Petroleum Operations. Such
approval shall also constitute authorizations by the Management
Committee to the Company to initiate contracts and purchases relevant to
the project proposal, subject to the provisions of Article 1.3.
2.3 The resources for the project design, supervision, and management shall
first be drawn from the Company's available in-house expertise. If the
Management Committee approves, such may be performed by the Company's
Affiliate under the approved budget for the project. Competent Nigerian
Engineering/Design companies may also be considered by the Management
Committee for such projects. NNPC staff who shall be seconded pursuant
to Clause 8.2 (b) of the Contract shall be fully involved in the project
design, supervision and management.
2.4 After approval of the project/budget, Company shall prepare and transmit
to NNPC complete details of the project including, without limitation,
the following:
(a) Project definition;
(b) Project specification;
(c) Flow diagrams;
(d) Projects implementation schedule showing all phases of the
project including, without limitation, engineering design,
material/equipment procurement, inspection, transportation,
fabrication/construction, installation, testing and commissioning;
(e) Major equipment specifications;
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(f) Cost estimate of the project;
(g) An activity status report; and
(h) Copies of all approved Company's AFEs.
ARTICLE III
CONTRACT TENDER PROCEDURE
3.1 The following tender procedure shall apply to work/service/supply not
directly undertaken by the Company or by the Company's Affiliate:
(a) Company shall maintain a list of approved contractors for the
purposes of contracts for the Petroleum Operations, (the
"Approved Contractors' List"). NNPC shall have the right to
propose contractors to be included/deleted in the list. Company
shall be responsible for prequalifying any contractor to be
included in the Approved Contractors' List.
(b) Contractors included in the Approved Contractors' List shall be
both local and/or overseas contractors or entities. Where
regulations require, they shall be registered with the Petroleum
Resources Department of the Ministry of Petroleum and Mineral
Resources.
(c) When a contract is to be bid, Company shall present a list of
proposed bidders to NNPC for concurrence not less than fifteen
(15) working days before the issuance of invitations to bid to
prospective contractors. NNPC may propose additional names to be
included in the list of proposed bidders or the deletion of any
one thereof. Contract specifications shall be in English and in
a recognized format used in the international petroleum industry.
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(d) If NNPC has not responded within fifteen (15) working days from
the date of the official receipt following the presentation of
the list of proposed bidders as aforesaid, the list shall be
deemed to have been approved.
3.2 Company shall establish a Tender Committee who shall be responsible for
pre-qualifying bidders, sending out bid invitations, receiving and
evaluating bids and determining successful bidders to whom contracts
shall be awarded.
3.3 Analyses and recommendations of bids received and opened by the Tender
Committee shall be sent by Company to NNPC for concurrence before a
contract is signed with the selected contractor. NNPC shall respond
within fifteen (15) working days from the date of official receipt.
Approval of Company's recommendations shall be deemed to have been given
if NNPC has not responded within the said period.
3.4 Prospective vendors/contractors for work estimated in excess of one
hundred thousand U.S. Dollars ($100,000) shall submit the commercial
summary of their bids to Company in two properly sealed envelopes, one
addressed to Company and one addressed to NNPC. Company shall retain
one and send one to NNPC, properly enveloped, sealed and addressed to
NNPC.
3.5. In all cases in which an offshore contractor or its Nigerian Affiliate
is invited to bid, Company shall make full disclosure to NNPC of its
relationship, if any, with such contractors.
3.6 These Procedures may be waived and Company may negotiate directly with
the contractor and promptly inform NNPC of the outcome of such
negotiations in the following cases:
(a) emergency situations; and
(b) in work requiring specialized skills, or when special
circumstances warrant, upon the approval of NNPC.
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ARTICLE IV
GENERAL CONDITIONS OF CONTRACTS
4.1 The payment terms shall provide, without limitation, that:
(a) A minimum of 10% of contract price shall be held as a retention
payment until after the end of a guarantee period agreed with the
contractor which shall vary between six months and twelve months,
depending on the project, with the exception of drilling and
seismic data acquisition, well surveys and other such services;
provided that, a contractor may be given the option to provide
other guarantee equivalent to the 10% retention such as Letter of
Credit or Performance Bond; and
(b) Provisions shall be made for appropriate withholding tax as may
be applicable.
4.2 The language of all contracts shall be English.
4.3 (a) The governing law of all agreements signed with contractors shall
be Nigerian law for work to be conducted in Nigeria and to the
extent feasible, for work outside Nigeria.
(b) Nigerian law shall apply to contractors performing in Nigeria
and, as far as practicable, they shall use indigenous human and
material resources.
(c) All contracts shall include a provision whereby the contractor
shall hold Company harmless and indemnify Company from and
against all liabilities, losses, damages and claims resulting
from claims and suits by third parties.
4.4. Each contract shall provide for early termination upon notice and
Company shall use all reasonable endeavors to obtain a termination
provision with minimal penalty.
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4.5 Contracts shall provide, in the case of a foreign contractor, that the
local part of the work, where practicable, shall be performed by
contractor's local subsidiary.
ARTICLE V
MATERIALS AND EQUIPMENT PROCUREMENT
5.1. Company may, through own in-house or parent company procure materials
and equipment subject to conditions set forth in this Article 5.
5.2 The provisions of this Article 5 shall not apply to lump sum or turnkey
contracts/projects.
5.3 In ordering the equipment/materials, Company shall obtain from
vendors/manufacturers such rebates/discounts and such
warranties/guarantees that such vendors/manufacturers normally offer,
and all rebates, discounts, guarantees and all other grants and
responsibilities shall be for the benefit of the Petroleum Operations.
5.4 Company shall:
(a) By means of established policies and procedures ensure that its
procurement efforts provide the best total value, with proper
consideration of quality, service, price, delivery and Operating
Costs to the benefit of the Petroleum Operations;
(b) Maintain appropriate records, which shall be kept up to date,
clearly documenting procurement activities;
(c) Provide quarterly and annual inventory of materials in stock.
(d) Provide a quarterly listing of excess materials in its stock list
to NNPC; and
(e) Check the excess material listings from other companies, to
identify materials available in the country prior to initiating
any foreign purchase order.
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5.5 Company shall initiate and maintain policies and practices which provide
a competitive environment/climate amongst local and/or overseas
suppliers. Competitive quotation processes shall be employed for all
local procurement where the estimated value exceeds the equivalent of
thirty thousand U.S. Dollars ($30,000.)
(a) Fabrication, wherever practicable shall be done locally provided
standards are not jeopardized. To this effect, the Petroleum
Operations recognize and shall accommodate local offers at a
premium not exceeding 3%.
(b) Subject to Article 3.1 (a), Company shall give preference to
Nigerian indigenous contractors in the award of contracts
provided such companies possess the requisite skills and offer
competitive terms. Contracts within the agreed financial limit
of the Company shall be awarded to only competent Nigerian
indigenous contractors provided such contractors meet the
required quality, offer competitive prices and deliver on a
timely basis. Where there are no Nigerian indigenous contractors
possessing the required skill/capability for the execution of
such contracts, the Company shall notify NNPC accordingly.
5.6 Analyses and recommendations of competitive quotations of a value
exceeding the limits established in Article 1.3 shall be transmitted to
NNPC for approval before a purchase order is issued to the selected
vendor/manufacturer. Approval shall be deemed to have been given if a
response has not been received from NNPC within fifteen (15) working
days of receipt by NNPC of the said analyses and recommendations.
5.7 Pre-inspection of rig, equipment/stock materials of reasonable value
shall be jointly carried out at factory site and quay before shipment at
the request of either Party.
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ARTICLE VI
PROJECT MONITORING
6.1 Company shall provide a project report monthly to NNPC.
6.2 For major projects exceeding two hundred thousand U.S. Dollars
($200,000) or equivalent, Company shall provide to NNPC a detailed
quarterly report which shall include:
(a) Approved budget total for each project;
(b) Expenditure on each project;
(c) Variances and explanations;
(d) Number and value of construction change orders;
(e) Bar chart of schedule showing work in progress and work already
completed and schedule of mile-stones and significant events; and
(f) Summary of progress during the reporting period, summary of
existing problems, if any, and proposed remedial action,
anticipated problems, and percentage of completion.
6.3 In the case of an increase in cost in excess of 10% on the project,
Company shall promptly notify NNPC and obtain necessary budget approval.
6.4 Not later than six (6) months following the physical completion of any
major project whose cost exceeds two hundred thousand U.S. Dollars
($200,000) or equivalent, Company shall prepare and deliver to NNPC a
project completion report which shall include the following:
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(a) Cost performance of the project in accordance with the work
breakdown at the commencement of the project;
(b) Significant variations in any item or sub-items;
(c) Summary of problems and unexpected events encountered during the
project; and
(d) List of excess project materials.
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EXHIBIT 10.6
ASHLAND OIL (NIG) COMPANY UNLIMITED
PRODUCTION SHARING CONTRACT
BETWEEN
NIGERIAN NATIONAL PETROLEUM CORPORATION
(THE CORPORATION)
AND
ASHLAND OIL (NIGERIA) COMPANY UNLIMITED
(THE CONTRACTOR)
March 17, 1994 - Original
ASHLAND
<PAGE> 2
C O N T E N T S
<TABLE>
<CAPTION>
Page
----
<S> <C>
Recital/Preamble . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
CLAUSES
- -------
1 DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
2 SCOPE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
3 TERM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
4 EXCLUSION OF AREAS . . . . . . . . . . . . . . . . . . . . . . . . . 7
5 WORK PROGRAMME AND EXPENDITURE . . . . . . . . . . . . . . . . . . . 8
6 MANAGEMENT COMMITTEE . . . . . . . . . . . . . . . . . . . . . . . . 9
7 RIGHTS AND OBLIGATIONS OF THE PARTIES . . . . . . . . . . . . . . . . 14
8 RECOVERY OF OPERATING COSTS AND CRUDE OIL ALLOCATION . . . . . . . . 17
9 VALUATION OF AVAILABLE CRUDE OIL . . . . . . . . . . . . . . . . . . 19
10 PAYMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
11 TITLE TO EQUIPMENT . . . . . . . . . . . . . . . . . . . . . . . . . 22
12 EMPLOYMENT AND TRAINING OF NIGERIAN PERSONNEL . . . . . . . . . . . . 23
13 BOOKS AND ACCOUNTS, AUDIT AND OVERHEAD CHARGES . . . . . . . . . . . 24
14 BONUSES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
15 ROYALTY AND TAXES . . . . . . . . . . . . . . . . . . . . . . . . . . 26
16 INSURANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
17 CONFIDENTIALITY AND PUBLIC ANNOUNCEMENTS . . . . . . . . . . . . . . 28
18 FORCE MAJEURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
</TABLE>
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<TABLE>
<S> <C> <C>
19 LAWS AND REGULATIONS . . . . . . . . . . . . . . . . . . . . . . . . 31
20 UTILIZATION OF NATURAL GAS . . . . . . . . . . . . . . . . . . . . . 32
21 CONSULTATION AND ARBITRATION . . . . . . . . . . . . . . . . . . . . 33
22 EFFECTIVENESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
23 NOTICES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
</TABLE>
ANNEXES
Annex A - Contract Area
Annex B - Accounting Procedure
Annex C - Allocation Procedure
Annex D - Nomination, Ship Scheduling, and Lifting Procedure
Annex E - Procurement and Project Implementation Procedures
Annex F - Revised Memorandum of Understanding
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<PAGE> 4
THIS CONTRACT is made and entered into this 24th day of May, 1994 BETWEEN the
NIGERIAN NATIONAL PETROLEUM CORPORATION, a corporation established under the
Laws of the Federal Republic of Nigeria, with its Head Office at No. 7 Kofo
Abayomi Street, Victoria Island, Lagos (hereinafter referred to as "the
CORPORATION" which expression shall, where the context so admits, include its
successors and assigns) of the one part, AND ASHLAND OIL (NIGERIA) COMPANY
UNLIMITED, a company incorporated under the laws of Nigeria and having its
registered office at, 10 Bishop Aboyade Cole Street, Victoria Island, LAGOS
(hereinafter called "the CONTRACTOR" which expression shall, where the context
so admits, include its successors and assigns) of the other part.
WHEREAS, by virtue of Section 1 of the Petroleum Act 1969 Cap 350 Laws of the
Federation of Nigeria 1990 as amended, the Federal Republic of Nigeria
(Nigeria) is vested with the entire ownership and control of all petroleum in,
under or upon any land which is in Nigeria or under the territorial waters of
Nigeria or forms part of the continental shelf of Nigeria or within the
Exclusive Economic Zone of Nigeria; and
WHEREAS, the CORPORATION is the holder or is entitled to hold the Oil
Prospecting Licences (OPLs) Nos 98 and 118 and any subsequent Oil Mining
Lease(s) (OML(S)) derived therefrom; and
WHEREAS, the said area of the OPLs 98 and 118 and any subsequent OML(s) shall
constitute the Contract Area; and
WHEREAS, Contractor is conducting Petroleum Operations on OPLs 98 and 118 under
a Production Sharing Contract dated 12 June, 1973, as amended by agreements
dated 1 April, 1977 and 13 November, 1986, (hereinafter collectively referred
to as "the 1973 PSC"); and
WHEREAS, a five year extension in principle effective June 13, 1993 of the said
1973 PSC was by a letter dated the 5th day of November, 1992 granted to the
Contractor; and
WHEREAS, in order to provide an economic incentive for Contractor to undertake
further exploration obligations in the Contract Area, CORPORATION and
CONTRACTOR agree that the 1973 PSC should be further amended by replacing it
with a new Production Sharing Contract; and
WHEREAS, by virtue of the Nigerian National Petroleum Corporation Act 1977 Cap
320 Laws of the Federation of Nigeria 1990, CORPORATION has the right, power
and authority to enter into this contract; and
WHEREAS, the CONTRACTOR represents that it has technical competence and
professional skills necessary to conduct petroleum operations and has the funds
both local and foreign for carrying on the said operations and has agreed to
conduct the said operations;
NOW, THEREFORE, in consideration of the premises and the mutual covenants
herein reserved and contained, it is hereby agreed as follows:
<PAGE> 5
CLAUSE 1
DEFINITIONS
As used in this Contract, unless otherwise specified, the following terms shall
have the respective meaning herein ascribed to them:
(a) "Accounting Procedure" means the rules and procedures as set forth in
Annex B and attached to and forming part of this Contract;
(b) "Affiliate" means a company or other entity that controls or is
controlled by a party to this Contract, or a company or other entity
which controls a party to this Contract, it being understood that
control shall mean ownership by one company or entity of at least 50%
of:
(i) the voting stock, if the other company is a corporation issuing
stock or;
(ii) the controlling rights or interests, if the other entity is not a
corporation.
(c) "Available Crude Oil" means the Crude Oil won and saved from the
Contract Area after deducting amounts used in Petroleum Operations.
(d) "Barrel" means a quantity or unit of Crude Oil, equal to forty-two (42)
United States gallons at the temperature of sixty degrees (60degrees)
Fahrenheit at normal atmospheric pressure.
(e) "Budget" means the cost estimate of items included in a Work Programme.
(f) "Calendar Year" means a period of twelve (12) months commencing from
January 1 and ending the following December 31, according to the
Gregorian Calendar.
(g) "Commercial Quantity" shall have the same meaning as defined in the
Petroleum Act 1969 as amended.
(h) "Concession Rentals" means the rents payable on the OPLs or OMLs under
the Petroleum Act 1969 and the Petroleum (Drilling and Production)
Regulations 1969 Cap 350 Laws of the Federation of Nigeria, as amended.
(i) "Contract Area" means the area of the OPLs 98 and 118 and any OML(s)
derived therefrom.
(j) "Contract Year" means a period of twelve (12) consecutive months
according to the Gregorian Calendar, from the Effective Date of this
Contract or from the anniversary of the Effective Date.
(k) "Cost Oil" means the quantum of Available Crude Oil allocated to
CONTRACTOR to enable it to generate the Proceeds to recover all
Operating Costs as specified in the Accounting Procedure.
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(l) "Crude Oil" means liquid petroleum which has been treated but not
refined and includes condensates but excludes water and sediments.
(m) "Effective Date" means 13 June, 1993.
(n) "Foreign Currency" means currency other than that of Nigeria agreed upon
by the parties and acceptable to the Federal Government of Nigeria.
(o) "Government" means the government of the Federal Republic of Nigeria.
(p) "Lifting Procedure" means the rules and procedures set forth in Annex D
and attached to and forming part of this Contract.
(q) "Minister" means Minister or Secretary charged with the responsibility
for Petroleum Resources.
(r) "Ministry" means the ministry charged with the responsibility for
Petroleum Resources.
(s) "Natural Gas" means all gaseous hydrocarbons produced in association
with Crude Oil or from reservoirs which produce mainly gaseous
hydrocarbons.
(t) "Oil Mining Lease" ("OML") means a lease granted by the Minister under
the Petroleum Act Cap 350, Laws of the Federation of Nigeria 1990 as
amended, to a lessee to search for, win, work, carry away and dispose of
Petroleum.
(u) "Oil Prospecting Licence" ("OPL") means a licence granted by the
Minister under the Petroleum Act 1969 Cap 350, Laws of the Federation of
Nigeria as amended, to a licensee to prospect for Petroleum; "OPLs", as
used herein, means Oil Prospecting Licenses 98 and 118.
(v) "Operating Costs" means expenditures made and obligations incurred in
carrying out Petroleum Operations as determined in accordance with the
Accounting Procedure.
(w) "Parties" means the CORPORATION and the CONTRACTOR.
(x) "Petroleum Operations" means the same as defined in the Petroleum
Profits Tax (PPT) Act 1959 Cap 354 Laws of the Federation of Nigeria
1990 as amended.
(y) "Petroleum Profits Tax" or "PPT" means the tax pursuant to the Petroleum
Profits Tax Act Cap 354 Laws of the Federation of Nigeria 1990 as
amended.
(z) "Proceeds" means the amount in U.S. Dollars determined by multiplying
the Realizable Price by the number of Barrels of Available Crude Oil
lifted by either Party.
(aa) "Profit Oil" means the balance of Available Crude Oil after the
allocation of Royalty Oil, Tax Oil, and Cost Oil.
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<PAGE> 7
(ab) "Realizable Price" means the price in U.S. Dollars per Barrel determined
pursuant to Clause 9.
(ac) "Royalty" means the amount payable pursuant to the Petroleum Act 1969
and Petroleum (Drilling and Production) Regulations 1969 Cap 350 Laws of
the Federation of Nigeria 1990, as amended.
(ad) "Royalty Oil" means the quantum of Available Crude Oil allocated to the
CORPORATION which will generate an amount of Proceeds equal to the
actual payment of Royalty and Concession Rentals.
(ae) "Tax Oil" means the quantum of Available Crude Oil allocated to the
CORPORATION will generate an amount of Proceeds equal to the actual
payment of PPT.
(af) "Work Programme" means for the applicable period a statement itemizing
the Petroleum Operations to be carried out in the Contract Area as
defined in Clause 5.
(ag) "Year" means a period of twelve (12) consecutive months according to
the Gregorian Calendar.
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<PAGE> 8
CLAUSE 2
SCOPE
2.1 This Contract is a Production Sharing Contract governed in accordance
with the terms and provisions hereof. Petroleum Operations and
provision of financial and technical requirements by the CONTRACTOR in
accordance with the terms of this Contract shall be in consultation with
the CORPORATION. The CORPORATION, as holder of all rights in and to the
Contract Area, hereby appoints and constitutes the CONTRACTOR the
exclusive company to conduct Petroleum Operations in the Contract Area.
As of the Effective Date, for all purposes this Contract will supersede
and replace the 1973 PSC.
2.2 During the term of this Contract the total Available Crude Oil shall be
allocated to the Parties in accordance with the provisions of Clause 8,
the Accounting Procedure (Annex B) and the Allocation Procedure (Annex
C).
2.3 The CONTRACTOR shall provide funds and bear the risk of Operating Costs
required to carry out Petroleum Operations and shall therefore have an
economic interest in development of Crude Oil deposits in the Contract
Area.
2.4 The CONTRACTOR is engaged in Petroleum Operations pursuant to the
Petroleum Profits Tax Act 1959 Cap 354 Laws of the Federation of Nigeria
1990 ("PPT Act") as amended and accordingly the Companies Income Tax Act
1979 Cap 60 Laws of the Federation of Nigeria 1990, as amended, shall
have no application.
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<PAGE> 9
CLAUSE 3
TERM
3.1 The term of this Contract, subject to paragraphs 3.2 and 3.3 shall be
twenty (20) years from the Effective Date.
3.2 This Contract may be terminated at any time by:
(a) The CORPORATION giving to the CONTRACTOR not less than ninety
(90) days prior written notice of termination if the CONTRACTOR
has committed a material breach of its obligations hereunder
including the Work Programme approved for any given period under
the Contract and the CONTRACTOR fails to remedy such breach
within six (6) months of the original notification of such
breach; provided such breach is not a subject of Arbitration
pursuant to clause 21,
(b) The CORPORATION giving to the CONTRACTOR not less than ninety
(90) days written notice of termination if the CONTRACTOR is
declared bankrupt and is forced to make restitution to its
creditors, or becomes insolvent, or is found by a court having
competent and final jurisdiction to have willfully violated any
Nigerian laws and regulations governing Petroleum Operations,
financial transactions and/or commercial operations during the
term of the Contract; and such violations adversely affect the
CORPORATION's interest under this Contract in a substantial
manner and the CONTRACTOR has failed to remedy same within a
reasonable period following the court finding; or
(c) The CONTRACTOR giving to the CORPORATION not less than ninety
(90) days prior written notice to that effect.
3.3 If at the end of the fifth year from the Effective Date the agreed
Exploration Work Programme in Clause 5 up till that time has not been
substantially executed, this Contract shall terminate forthwith.
3.4 This Contract shall terminate if no new Crude Oil production is found in
the Contract Area as a result of the agreed Exploration Work Programme
in Clause 5 after five (5) years from the Effective Date.
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CLAUSE 4
EXCLUSION OF AREAS
4.1 Not later than five (5) years from the Effective Date fifty per cent
(50%) of the Contract Area shall be excluded.
4.2 Any excluded area shall revert to the Government.
4.3 The fifty per cent (50%) of the Contract Area to be excluded shall be
agreed by both Parties and shall not include any part of the Contract
Area corresponding to surface areas of any field in which Petroleum has
been discovered in Commercial Quantity.
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<PAGE> 11
CLAUSE 5
WORK PROGRAMME AND EXPENDITURE
5.1 Within two (2) months after the Effective Date and thereafter at least
three (3) months prior to the beginning of each Year, the CONTRACTOR
shall prepare and submit for review and approval by the Management
Committee, pursuant to Clause 6, a Work Programme and Budget for the
Contract Area setting forth the Petroleum Operations which CONTRACTOR
proposes to carry out during the ensuing Year, or in case of first Work
Programme and Budget, during the remainder of the current Year. The
Management Committee shall review and approve such Work Programme and
Budget in accordance with Clause 6.3(e) prior to submission of the Work
Programme and Budget to the Ministry.
5.2 The minimum Exploration Work Programme during the exploration period
shall consist of the drilling of two (2) wells; provided, however, that
Contractor shall have no obligation to expend more than twelve million
U.S. Dollars ($12,000,000) in the drilling of said wells even if the
minimum Exploration Work Programme has not been accomplished. Within
eighteen (18) months of the Effective Date, Contractor shall commence
drilling of the first of such wells.
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<PAGE> 12
CLAUSE 6
MANAGEMENT COMMITTEE
6.1 A Management Committee shall be established within thirty (30) days from
the date of execution of this Contract for the purpose of providing
orderly direction of all matters pertaining to the Petroleum Operations
and Work Programme. The powers and duties of the Management Committee
shall include but not be limited to the following:
(a) the review, revision, and approval of all proposed Work
Programmes and Budgets in accordance with Clauses 5 and 6.3(e);
(b) the review, revision, and approval of any proposed
recommendations made by either Party or by any subcommittee,
pursuant to Clause 6.6 with respect to Petroleum Operations;
(c) ensuring that the CONTRACTOR carries out the decisions of the
Management Committee and conducts Petroleum Operations pursuant
to this Contract;
(d) the consideration and decision on matters relating to the
exclusion of areas in the Contract Area pursuant to Clause 4; and
in accordance with the Petroleum laws;
(e) settlement of claims and litigation in excess of five hundred
thousand Naira (N500,000) or the equivalent thereof in Foreign
Currency, or such other amount as may be approved by the
Management Committee insofar as such claims are not covered by
policies of insurance maintained under this Contract;
(f) consideration and approval of the sale or disposal of any items
or movable property relating to Petroleum Operations in
accordance with the provisions of this Contract except for
items/properties of historic costs less than one million Naira
(N1,000,000); and any sale or disposal of fixed asset shall be
referred to the CORPORATION;
(g) settlement of unresolved audit exceptions arising from audits as
provided for in Clause 13.2 of this Contract;
(h) ensuring that the CONTRACTOR implements the provisions of the
Accounting Procedure (Annex B), the Lifting Procedure (Annex D),
and the Procurement and Project Implementation Procedures (Annex
E) and all amendments and revisions thereto as agreed by the
Parties;
(i) any other matters relating to Petroleum Operations except:
(i) those matters under the sole discretion and control of the
CONTRACTOR in carrying out its duties and functions,
(ii) those matters elsewhere provided for in this Contract, or
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<PAGE> 13
(iii) those matters reserved to the Parties in their respective
rights pursuant to Clause 7;
(j) consideration and approval of the sale or disposal and exchange
of information to third parties other than routine exchange of
seismic data and other such data commonly exchanged within the
industry; and
(k) consideration and determination of any other matter relating to
the Petroleum Operations which may be referred to it by any Party
(other than any proposal to amend this Contract) or which is
otherwise designated under this Contract for reference to it.
6.2 (a) The Management Committee shall consist of ten (10) persons
appointed by the Parties as follows:
The CORPORATION - 5
The CONTRACTOR - 5
(b) Each Party shall designate by notice in writing to the other
Party, the names of its representatives to serve as members of
the Management Committee as provided in Clause 6.2(a) hereof and
their respective alternates, which members or alternates shall be
authorized to represent that Party with respect to the decisions
of the Management Committee. Such notice shall give the names,
titles and addresses of the designated members and alternates.
Each member may nominate any other member or alternate to
represent such member at meetings of the Management Committee.
(c) At least fourteen (14) business days prior to each scheduled
Management Committee meeting, the Secretary shall provide an
agenda of matters, with briefs, to be considered during such
meeting. Any Party desiring to have other matters placed on the
agenda shall give notice to the other Party not less than seven
(7) business days prior to the scheduled meeting. No other
matter may be introduced into the agenda thereafter for
deliberation at the meeting unless mutually agreed by the
Parties. No agenda shall be required in the event of an
emergency meeting called pursuant to Clause 6.3(b).
(d) Either Party may change any of its respective members or
alternates as described in Clause 6.2(b) from time to time by
notifying the other Party in writing not less than ten (10) days
in advance of the effective date of such change.
(e) The CORPORATION shall appoint the Chairman of the Management
Committee and the CONTRACTOR shall appoint the Secretary. The
Secretary shall not be a member of the Management Committee but
shall keep minutes of all meetings and records of all decisions
of the Management Committee. Within fourteen (14) days after
each meeting, the Secretary shall forward drafts of the minutes
to the Parties. Within fourteen (14) days thereafter each Party
shall return the minutes with its
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<PAGE> 14
comments to the Secretary who shall within fourteen (14) days
thereafter forward the final draft to the other Party. The
minutes of each meeting shall be approved by the Management
Committee at the next meeting and copies thereof shall be
supplied to the Parties. In addition, the Secretary shall at
each meeting, prepare a written summary of any decision made by
the Management Committee for approval and signature by the
Parties to adjournment.
6.3 (a) Not later than the twenty-eighth (28th) day of February of each
Year, the Chairman shall prepare and forward to the Parties, a
calendar of meetings as agreed by the Management Committee for
that Year.
(b) Unless otherwise agreed by the Parties, the Management Committee
shall meet at the head office of the CONTRACTOR once every four
(4) calendar months, or at such other intervals or venue as may
be agreed by the Management Committee and, in addition, whenever
requested by either Party by giving at least twenty-one (21) days
notice in writing to the other Party which notice shall specify
the matter or matters to be considered at the meeting; or, when
summoned by the Chairman or by the CONTRACTOR as an emergency
meeting for which no specified notice period shall be required.
(c) The quorum for any meeting of the Management Committee shall
consist of a minimum of three (3) representatives of the
CORPORATION and three (3) representatives of the CONTRACTOR. The
Chairman or his alternate and the CONTRACTOR's Managing Director
or his alternate must be present at every Management Committee
meeting for a quorum to be formed. If no such quorum is present,
the Chairman shall call another meeting of the Management
Committee giving at least fourteen (14) days written notice of
such meeting.
(d) The Secretary shall in consultation with the Chairman convene all
meetings of the Management Committee other than the emergency
meetings.
(e) Within eight (8) weeks after the submission of a Work Programme
and Budget by the CONTRACTOR the Management Committee shall meet
to consider and approve such submission. Should the CORPORATION
wish to propose a revision as to certain specific features of the
said Work Programme and Budget, it shall within six (6) weeks
after receipt thereof so notify the CONTRACTOR in writing
specifying in reasonable detail the changes requested and its
reasons therefor. The Management Committee will endeavor to
resolve the request for revisions proposed by the CORPORATION.
If the CORPORATION has not proposed any revisions in writing
within six (6) weeks, then the said Work Programme and Budget as
submitted shall be approved by resolution of the Management
Committee. Any portion of a Work Programme about which the
CORPORATION has not proposed a revision shall insofar as possible
be carried out as prescribed therein.
6.4 (a) Except as may be expressly provided for in this Contract, the
Management Committee shall determine and adopt rules to govern
its procedures.
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<PAGE> 15
(b) Members attending a meeting of the Management Committee may be
accompanied by advisers and experts to the extent reasonably
necessary to assist with the conduct of such meeting. Such
advisers and experts shall not vote or in any way participate in
decisions, but may contribute in a non-binding way to discussions
or debates of the Management Committee.
(c) At any Management Committee meeting where there is a quorum, the
Chairman or his alternate shall exercise the voting rights of the
CORPORATION and the Managing Director of the CONTRACTOR or his
alternate shall exercise the voting rights of the CONTRACTOR.
(d) Except as otherwise expressly provided in this Contract all
decisions of the Management Committee shall be made by the
unanimous vote of the Parties. If unanimity is not obtained on
any matter (including any matter pertaining to a Work Programme
or Budget proposed by the CONTRACTOR) proposed to the Management
Committee, then the Management Committee shall meet again to
attempt to resolve such matter not later than fourteen (14) days
after the meeting in which the proposed matter was rejected by a
negative vote. Any portion of such proposal that is not rejected
shall insofar as possible be carried out. At least seven (7)
days prior to such second meeting, the Party casting the
dissenting vote shall provide to the other Party in writing in
reasonable detail the reasons for such dissenting vote. If such
written reasons are not provided at least seven (7) days prior to
such second meeting, then the proposal shall be deemed approved.
In such second meeting the agenda shall be comprised of such
written reasons as provided by the dissenting Party. If
unanimity is not obtained in the second meeting, then the
Management Committee shall meet a third time within fourteen (14)
days after the second meeting. If unanimity is not obtained in
the third meeting then the CORPORATION and the CONTRACTOR may
agree to appoint an independent qualified expert to advise on the
matter, which advice shall be binding on the Parties. In the
event of failure of the Parties to agree to the appointment of
the said expert the provisions of Clause 21 shall apply.
(e) The Parties shall be bound by, and abide by, each decision of the
Management Committee duly made in accordance with the provisions
of this Contract.
6.5 Any matter which is within the powers and duties of the Management
Committee may be determined by the Management Committee without a
Management Committee meeting if such matter is submitted by either Party
to the other Party with due notice and with sufficient information
regarding the matter to be determined so as to enable the Parties to
make an informed decision with respect to such matter.
(a) Except for urgent matters referred to in Clause 6.5(b), each
party shall cast its vote with respect to such matter within
twenty-one (21) days of receipt of such notice and such manner of
determination shall be followed unless a Party objects, within
fourteen (14) days of receipt of such notice, to having the
matter determined in such manner. If any Party fails to vote by
the expiry of the twenty-one (21) days period
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<PAGE> 16
for voting, it shall be deemed to have voted in the affirmative.
The Secretary shall promptly advise the Parties of the results of
such vote and the Secretary shall draft a resolution to be signed
as soon as possible by the Parties.
(b) Each Party shall nominate one of its officers as its
representative from whom the other Party may seek binding
decisions on urgent matters, including, but not limited to
ongoing drilling operations, by telephone, letter, facsimile
transmission, telex or in person and they shall advise each other
in writing of the persons so nominated and any changes thereof.
(c) In the event of an emergency requiring immediate operational
action, either Party may take all actions it deems proper or
advisable to protect its interests and those of its respective
employees and any costs so incurred shall be included in the
Operating Costs. Prompt notification of any such action taken by
a Party and the estimated cost shall be given to the other Party
within forty-eight (48) hours of the commencement of the event.
(d) The decisions made pursuant to this Clause 6.5 shall be recorded
in the minutes of the next scheduled meeting of the Management
Committee, and shall be binding upon the Parties to the same
extent as if the matter had been determined at a meeting of the
Management Committee.
6.6 The Management Committee shall establish exploration and technical
sub-committees and any other advisory sub-committees as it considers
necessary from time to time such as finance and budget, and
legal/services sub-committees:
(a) Each sub-committee established pursuant to this Clause 6.6 shall
be given terms of reference and shall be subject to such
direction and procedures as the Management Committee may give or
determine.
(b) The Management Committee shall appoint the members of the
sub-committees which shall be comprised of equal representation
from the Parties. The chairmen and the secretaries of the
sub-committees shall be appointed by the Management Committee.
(c) The deliberations and recommendations of any sub-committee shall
be advisory only and shall become binding and effective upon
acceptance by the Management Committee.
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<PAGE> 17
CLAUSE 7
RIGHTS AND OBLIGATIONS OF THE PARTIES
7.1 In accordance with this Contract, the CONTRACTOR shall:
(a) Provide all necessary funds for payment of Operating Costs
including, but not limited to, funds required to provide all
materials, equipment, supplies, and technical requirements
(including personnel) purchased, paid for or leased in Foreign
Currency;
(b) Furnish such other funds for the performance of Work Programmes
that require payment in Foreign Currency, including payments to
third parties who perform services as subcontractors;
(c) Prepare Work Programmes and Budgets and carry out approved Work
Programmes in a good and workmanlike manner and in accordance
with internationally acceptable petroleum industry practices and
standards with the object of avoiding waste and obtaining maximum
ultimate recovery of Crude Oil at minimum costs;
(d) Ensure that all lease equipment paid for in Foreign Currency and
brought into Nigeria for Petroleum Operations is treated in
accordance with the terms of the applicable leases;
(e) Have the right to dispose of, assign, transfer, convey or
otherwise dispose of any part of its rights and interests under
this Contract to other parties including Affiliates with the
prior written consent of the CORPORATION which consent shall not
be unreasonably withheld;
(f) Have the right of ingress to and egress from the Contract Area
and to and from facilities therein located at all times during
the term of this Contract;
(g) Submit to the CORPORATION for permanent custody copies of all
geological, geophysical, drilling, well production, operating and
other data and reports as it may compile during the term hereof
and at the end of the Contract surrender all original data and
reports to the CORPORATION;
(h) Prepare estimated and final PPT returns and submit same to the
CORPORATION on a timely basis in accordance with the PPT Act;
(i) Have the right to lift in accordance with Annex D and freely
export and to retain abroad the receipts from the sale of
Available Crude Oil allocated to it hereunder;
(j) Prepare and carry out plans and programmes for industrial
training and education of Nigerians for all job classifications
with respect to Petroleum Operations in
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<PAGE> 18
accordance with the Petroleum Act Cap 350 Laws of the Federation
of Nigeria 1990, as amended;
(k) Employ only such personnel as are reasonably necessary to conduct
the Petroleum Operations in a prudent and cost effective manner;
(l) Give preference to such goods which are available in Nigeria or
services rendered by Nigerian nationals, provided they meet the
specifications and the standards of the goods and services;
(m) In respect of payment of customs duties and other like charges,
the CONTRACTOR and its subcontractors shall not be treated
differently from any other companies and their subcontractors
engaged directly in similar Petroleum Operations in Nigeria;
(n) Indemnify and hold harmless the CORPORATION from and against
losses (including legal fees and expenses) of whatever kind and
nature resulting from the CONTRACTOR's negligence or wilful
misconduct in carrying out Petroleum Operations and as a
consequence of any final decision given by a Nigerian Court,
except where such losses are shown to result from any action or
failure to act on the part of the CORPORATION, provided however,
that under no circumstances shall the CONTRACTOR be liable to the
CORPORATION for reservoir damage or pollution or any
consequential losses or damages occurring including, but not
limited to, lost production or lost profits;
(o) Have the right to finance Petroleum Operations from external
sources under terms and conditions approved by the CORPORATION;
and
(p) Not exercise all or any rights or authority over the Contract
Area in derogation of the rights of the CORPORATION.
7.2 In accordance with this Contract, the CORPORATION shall:
(a) Pay to the Government in a timely manner, all Bonuses, Royalties,
Concession Rentals and PPT accruing out of Petroleum Operations;
(b) With its professional staff attached pursuant to Clause 12.4,
work jointly with the CONTRACTOR's professional staff in the
CONTRACTOR'S Exploration, Petroleum Engineering,
Facilities/Materials and Finance Departments;
(c) Otherwise assist and expedite the CONTRACTOR's execution of
Petroleum Operations and Work Programmes including, but not
limited to, assistance in supplying or otherwise making available
all necessary visas, work permits, rights of way and easements as
may be requested by the CONTRACTOR (Expenses incurred by the
CORPORATION at the CONTRACTOR's request in providing such
assistance shall be reimbursed to the CORPORATION by the
CONTRACTOR in accordance with Clause 11.1. The CONTRACTOR shall
include such
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<PAGE> 19
reimbursements in the Operating Costs. Such reimbursements will
be made against the CORPORATION's invoice and shall be in U.S.
Dollars computed at the ruling rate of exchange published by the
Central Bank of Nigeria on the date the expense was incurred);
(d) Have title to all original data resulting from the Petroleum
Operations including but not limited to geological, geophysical,
engineering, well logs, completion, production, operations,
status reports and any other data as the CONTRACTOR may compile
during the term hereof, provided however, that the CONTRACTOR
shall keep and use such original data during the term of this
Contract and the CORPORATION shall have access to such original
data during the Term of this Contract;
(e) Not exercise all or any of its right or authority over the
Contract Area in derogation of the rights of the CONTRACTOR; and
(f) The CORPORATION shall apply for conversion of the OPL to OML and
shall exercise all the rights and comply with all the obligations
of a Licensee or Lessee under the Petroleum Act 1969 and its
amendments.
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<PAGE> 20
CLAUSE 8
RECOVERY OF OPERATING COSTS AND CRUDE OIL ALLOCATION
8.1 The allocation of Available Crude Oil shall be in accordance with the
Accounting Procedure (Annex B), the Allocation Procedure (Annex C) and
this Clause 8 as follows:
(a) Royalty Oil shall be allocated to the CORPORATION in such quantum
as will generate an amount of Proceeds equal to the actual
Royalty payable during each month and the Concession Rental
payable annually;
(b) Cost Oil shall be allocated to the CONTRACTOR in such quantum as
will generate an amount of Proceeds sufficient for recovery of
Operating Costs in OPLs 98 and 118 and any OMLs derived
therefrom. All Operating Costs expended in U.S. Dollars will be
recovered in U.S. Dollars through Cost Oil allocations;
(c) Tax Oil shall be allocated to the CORPORATION in such quantum as
will generate an amount of Proceeds equal to actual PPT liability
payable during each month;
(d) All Operating Costs incurred on OPLs 98 and 118 prior to the
Effective Date which remain unrecovered on the Effective Date
shall be recoverable as Operating Cost by CONTRACTOR from Cost
Oil under this Contract;
(e) The CONTRACTOR shall for PPT purposes be entitled to consolidate
OPLs 98 and 118 and any OMLs derived therefrom.
(f) Profit Oil, being the balance of Available Crude Oil after
deducting Royalty Oil, Tax Oil, and Cost Oil, shall be allocated
to each Party pursuant to Schedule B-2 of the Accounting
Procedure (Annex B) as follows:
<TABLE>
<CAPTION>
PROFIT OIL
MONTHLY AVERAGE MBOPD PERCENTAGES
FROM CONTRACT AREA CORPORATION CONTRACTOR
----------------------------------- ------------- ------------
<S> <C> <C>
0 to 40 20 80
Greater than 40 but less than 75 35 65
Greater than 75 but less than 100 45 55
100 and above 50 50
</TABLE>
8.2 The quantum of Available Crude Oil to be allocated to each Party under
this Contract shall be determined at the fiscalisation point.
8.3 Each Party shall take in kind, lift and dispose of its allocation of
Available Crude Oil in accordance with the Lifting Procedure (Annex D).
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<PAGE> 21
8.4 Allocation of Royalty Oil and Tax Oil to the CORPORATION shall be
applied towards the liabilities of the CONTRACTOR and the CORPORATION
for Royalty, Concession Rentals, and PPT and the Proceeds therefrom
shall be paid to the Government by the CORPORATION on behalf of both
Parties.
8.5 Either Party may at the request of the other, lift the other Party's
Available Crude Oil pursuant to Clause 9.1 and the lifting Party shall
within sixty (60) days transfer to the account of the non-lifting Party
the proceeds of the sale to which the non-lifting Party is entitled.
Overdue payments shall bear interest at the rate of one (1) month LIBOR
plus two percent (2%).
8.6 The CONTRACTOR may purchase any portion of the CORPORATION's allocation
of Available Crude Oil from the Contract Area under the CORPORATION's
terms and conditions including valuation and pricing of the Crude Oil as
applicable to other third party buyers of the CORPORATION's Crude Oil.
8.7 Both Parties shall meet on a monthly or quarterly basis as may be agreed
to reconcile all Crude Oil allocated and lifted during the period as per
Article III 7 of Annex D.
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<PAGE> 22
CLAUSE 9
VALUATION OF AVAILABLE CRUDE OIL
9.1 Available Crude Oil allocated to each Party shall be valued in
accordance with the following procedures:
(a) On the attainment of commercial production, each Party shall
engage the services of an independent laboratory of good repute
to determine the assay of the new Crude Oil.
(b) When a new Crude Oil stream is produced, a trial marketing period
shall be designated which shall extend for the first six (6)
month period during which such new stream is lifted or for the
period of time required for the first ten (10) liftings,
whichever is longer. During the trial marketing period the
Parties shall:
(i) Collect samples of the new Crude Oil upon which the assays
shall be performed as provided in Clause 9.1 (a) above;
(ii) Determine the approximate quality of the new Crude Oil by
estimating the yield values from refinery modeling;
(iii) Share in the marketing such that each Party markets
approximately an equal amount of the new Crude Oil and to
the extent that one Party lifts the other Party's
allocation of Available Crude Oil, payments therefor shall
be made in accordance with Clause 8.5;
(iv) Exchange information regarding the marketing of the new
Crude Oil including documents which verify the sales price
and terms of each lifting;
(v) Apply the actual f.o.b. sales price to determine the value
for each lifting which f.o.b. sales pricing for each
lifting shall continue after the trial marketing period
until the Parties agree to a valuation of the new Crude
Oil but in no event longer than ninety (90) days after
conclusion of the trial marketing period.
(c) As soon as practicable but in any event not later than sixty (60)
days after the end of the trial marketing period, the Parties
shall meet to review the assay, yield, and actual sales data.
Each Party may present a proposal for the valuation of the new
Crude Oil. A valuation method shall be established for
determining the price for each lifting of Available Crude Oil.
Such valuation method shall be in accordance with the Realizable
Price provisions set forth in the Revised Memorandum of
Understanding attached to this Contract as Annex F. It is the
intent of the Parties that such prices shall reflect the true
market value of the new Crude Oil. The valuation method
determined hereunder (including the product yield values) shall
be mutually agreed within thirty (30) days from the
aforementioned meeting failing which, determination of such
valuation shall be referred to the Ministry.
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<PAGE> 23
(d) Upon the conclusion of the trial marketing period, the Parties
shall be entitled to lift their allocation of Available Crude Oil
pursuant to Clause 8 and the Lifting Procedure.
(e) When a new Crude Oil stream is produced from the Contract Area
and is commingled with an existing Crude Oil produced in Nigeria
which has an established Realizable Price basis then such basis
shall be applied to the extent practicable for determining the
Realizable Price of the new Crude Oil. The Parties shall meet
and mutually agree on any appropriate modifications to such
established valuation basis which may be required to reflect any
change in the market value of the Crude Oils as a result of
commingling.
(f) The valuation method for determining the price for each lifting
of Available Crude Oil from fields other than those discovered
after the Effective Date, shall continue to be in accordance with
the Realizable Price provisions set forth in the Revised
Memorandum of Understanding.
9.2 If in the opinion of either Party an agreed price valuation method fails
to reflect the market value of a Crude Oil produced in the Contract
Area, then such Party may propose to the other Party modifications to
such valuation method once in every six (6) months but in no event more
than twice in any year. The Parties shall then meet within thirty (30)
days of such proposal and mutually agree on any modifications to such
valuation within thirty (30) days from such meeting failing which,
determination of such valuation shall be referred to the Ministry.
9.3 Segregation of Crude Oils of different quality and/or grade shall be by
agreement of the Parties taking into consideration, among other things,
the operational practicality of segregation and the cost benefit
analysis thereof. If the Parties agree on such segregation the
following provisions shall apply:
(a) Any and all provisions of the Contract concerning valuation of
Crude Oil shall separately apply to each segregated Crude Oil
produced;
(b) Each grade or quality of Crude Oil produced and segregated in a
given Year shall contribute its proportionate share to the total
quantity designated in such Year as Royalty Oil, Tax Oil, Cost
Oil and Profit Oil.
CLAUSE 10
PAYMENT
10.1 The method of payment of any sum due from the CONTRACTOR to the
CORPORATION and vice versa shall be in accordance with the prevailing
guidelines of the Federal Ministry of Finance of Nigeria, the Central
Bank of Nigeria and in accordance with the Accounting Procedure, Annex
B.
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10.2 Unless otherwise provided herein, any payments which the CORPORATION is
required to make to the CONTRACTOR or which the CONTRACTOR is required
to make to the CORPORATION pursuant to this Contract shall be made
within (30) days following the end of the month in which the obligation
to make such payments occurs. Overdue payments shall bear interest at
the annual rate of one (1) month LIBOR plus 2%.
10.3 Each Party shall have the right of set off against the other Party for
sums due and payable to the other Party under this Contract agreed sums
past due under this Clause.
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<PAGE> 25
CLAUSE 11
TITLE TO EQUIPMENT
11.1 The CONTRACTOR shall finance the cost of purchasing all equipment to be
used in Petroleum Operations in the Contract Area pursuant to the Work
Programmes and such equipment shall become the property of the
CORPORATION on arrival in Nigeria. The CONTRACTOR and the CORPORATION
shall have the right to use such equipment exclusively for Petroleum
Operations in the Contract Area during the Term of this Contract.
Should the CORPORATION desire to use such equipment outside the Contract
Area, such use shall be subject to terms and conditions agreed by the
parties provided that it is understood Petroleum Operations hereunder
shall take precedence over such use by the CORPORATION.
11.2 The CONTRACTOR's right to use such purchased equipment shall cease with
the termination or expiration (whichever is earlier) of this Contract.
11.3 The provisions of Clause 11.1 with respect to the title of property
passing to the CORPORATION shall not apply to leased equipment belonging
to local or foreign third parties, and such equipment may be freely
exported from Nigeria in accordance with the terms of the applicable
lease.
11.4 Title to all lands purchased or otherwise acquired by the CONTRACTOR for
the purposes of Petroleum Operations and all movable property utilized
in the Contract Area and incorporated permanently in any premises,
locations and structures for the purposes of Petroleum Operations
hereunder shall be in the name of the CORPORATION and the CONTRACTOR.
Upon termination of this Contract pursuant to Clause 3, the CORPORATION
shall take possession of such lands and property and the CONTRACTOR
shall hand over such lands and property within thirty (30) days.
11.5 Subject to Clause 11.2 hereof, all fixed assets purchased or otherwise
acquired by the CONTRACTOR for the purposes of Petroleum Operations
hereunder shall become the property of the CORPORATION. Upon
termination of this Contract pursuant to Clause 3, the CONTRACTOR shall
hand over possession of such fixed assets to the CORPORATION.
11.6 During the term of this Contract, any agreed sale of equipment, lands
fixed assets, materials and machinery acquired for the purpose of the
Petroleum Operations hereunder shall be conducted by the CONTRACTOR on
the basis of the highest price obtainable and the proceeds of such sale
shall be credited to the Petroleum Operations.
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CLAUSE 12
EMPLOYMENT AND TRAINING OF NIGERIAN PERSONNEL
12.1 Each Year, the CONTRACTOR shall submit a detailed programme for
recruitment and training for the following Year in respect of its
Nigerian personnel in accordance with the Petroleum Act 1969 and its
amendments.
12.2 Qualified Nigerians shall be employed in all nonspecialized positions.
12.3 Qualified Nigerians shall also be employed in specialized positions such
as those in exploration, drilling, engineering, production, and finance.
The CONTRACTOR shall have the right, subject to applicable laws, rules
and regulations, to employ non-Nigerians in such specialized positions
where qualified Nigerians are not available provided that the CONTRACTOR
shall recruit and train Nigerians for such specialized positions such
that the number of non-Nigerian staff shall be kept to a minimum.
12.4 Competent professionals of the CORPORATION shall be attached to work
with the CONTRACTOR from time to time and such officials and the
CONTRACTOR's officials shall not be treated differently with regard to
salaries and other benefits.
12.5 Costs and expenses incurred in the recruitment and training of Nigerian
personnel shall be included in Operating Costs.
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<PAGE> 27
CLAUSE 13
BOOKS AND ACCOUNTS, AUDIT
AND OVERHEAD CHARGES
13.1 Books and Accounts
The CONTRACTOR shall be responsible for keeping complete books of
accounts consistent with modern petroleum industry and accounting
practices and procedures. The statutory books and accounts of this PSC
shall be kept in Naira and U.S. dollars. All other books of accounts as
the operator may consider necessary shall be kept in columnar form in
both Naira and U.S. Dollars. Officials of the CORPORATION and the
CONTRACTOR shall have access to such books and accounts and officials of
the CORPORATION attached to the CONTRACTOR pursuant to Clause 12.4 shall
participate in the preparation of same.
13.2 Audits
The CORPORATION and its external auditors shall have the right to
inspect and audit the books and accounts relating to this Contract for
any year by giving thirty (30) days written notice to the CONTRACTOR and
the CONTRACTOR shall facilitate the work of such inspection and
auditing; provided however, that the costs of such inspection and
auditing shall be met by the CORPORATION, and provided also that if such
inspection and auditing have not been so carried out within two (2)
Years following the end of the Year in question, the books and accounts
relating to such Year shall be deemed to be accepted by the parties as
satisfactory. Any exception must be made in writing ninety (90) days
following the end of such audit and failure to give such written notice
within such time shall establish the correctness of the books and
accounts.
13.3 Home Office Overhead Charges
The CONTRACTOR shall include the following percentages on total annual
capital expenditure as overhead charges in calculating total Operating
Costs:
- First $200 million 1.00% of Capex
- Next $200 million 0.75% of Capex
- Next $100 million 0.50% of Capex
- Above $500 million 0%
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<PAGE> 28
CLAUSE 14
BONUSES
Production Bonus
14.1 The CONTRACTOR shall pay the CORPORATION the following Bonuses:
(a) a sum in US Dollars equivalent to zero point two percent (0.2%)
of cumulative production of 50 million barrels of Crude Oil
attained in the Contract Area from fields discovered after the
Effective Date at the price on the due date.
(b) a sum in US Dollars equivalent to zero point one percent (0.1%)
of cumulative production of 100 million barrels of Crude Oil
attained in the Contract Area from fields discovered after the
Effective Date at the price on the due date.
14.2 The Production Bonuses provided for in this Clause 14 shall not be
recoverable as Cost Oil and shall be payable within 30 days of such
production level being first attained.
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<PAGE> 29
CLAUSE 15
ROYALTY AND TAXES
15.1 Royalty
Royalty rates will be as provided in the Petroleum Act 1969, as amended,
and the prevailing fiscal laws and regulations.
15.2 Petroleum Profit Tax (PPT)
(a) The PPT shall be in accordance with the PPT Act 1959 as amended.
(b) The PPT rate applicable to the Contract Area shall be 65.75% for
the first five (5) years of production from each field developed
in the Contract Area commencing from the first day of the month
of the first sale therefrom and 85% thereafter.
15.3 The CORPORATION shall pay all Royalty, Concession Rentals and PPT on
behalf of itself and the CONTRACTOR out of Available Crude Oil allocated
to it under Clause 8.1 of this Contract.
15.4 The Realizable Price established under the terms of the Revised
Memorandum of Understanding in accordance with Clause 9 of this Contract
shall be used in determining the amount payable on Royalty and PPT in
respect of Crude Oil produced and lifted pursuant to this Contract. The
parameters for new Crude Oil streams produced from the Contract Area
shall also be determined in accordance with provisions of Clause 9 of
this Contract.
15.5 The CORPORATION shall make available to the CONTRACTOR copies of
receipts issued by the Federal Board of Inland Revenue for the payment
made for PPT.
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CLAUSE 16
INSURANCE
16.1 All property acquired under the provisions of this Contract shall be
adequately insured in an insurance company of good repute by the
CONTRACTOR in consultation with the CORPORATION, in its name and that of
the CORPORATION with limits of liability not less than those required by
Nigerian laws and regulations. The premia for such policies shall be
included in Operating Costs. All policies shall name the CORPORATION as
a co-insured with a waiver of subrogation rights in favor of the
CORPORATION.
16.2 In case of loss of or damage to property, indemnifications paid by the
insurance companies shall be entirely received by the CONTRACTOR for
Petroleum Operations. The CONTRACTOR shall determine whether the lost
or damaged property should be repaired, replaced or abandoned. If the
decision is to repair or replace, the CONTRACTOR shall immediately
replace or repair such lost or damaged property. Any excess cost of
repair or replacement above the amount reimbursed by the insurance
companies shall be regarded as Operating Costs. If the decision is to
neither repair nor replace then the proceeds of any coverage shall be
credited to Operating Costs. In the event that the loss or damage is
attributable to the CONTRACTOR's wilful misconduct the excess cost of
replacement or repair shall not be reimbursed as Operating Cost.
16.3 The CONTRACTOR shall take out and maintain an insurance policy covering
any and all damages caused to third parties as a direct or indirect
result of the CONTRACTOR's Petroleum Operations. The CONTRACTOR shall
defend and hold the CORPORATION harmless from damages and losses caused
to third parties in consequence of the CONTRACTOR's wilful misconduct in
the performance of this Contract.
16.4 All insurance policies under this Clause 16 shall be based on good
international petroleum industry practice, and shall be taken out in the
Nigerian market except for those concerning risks for which the
CONTRACTOR cannot obtain coverage in Nigeria which shall be taken out
abroad, to the extent allowed by law.
16.5 In entering into contracts with any sub-contractor for the performance
of Petroleum Operations, the CONTRACTOR shall require such
sub-contractor to take adequate insurance in accordance with Clauses
16.1 and 16.3 above and to properly indemnify the CORPORATION and the
CONTRACTOR for any damage done and to properly indemnify and hold the
CORPORATION and the CONTRACTOR harmless against claims from third
parties.
16.6 The CONTRACTOR shall maintain other insurance policies required under
Nigerian law.
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CLAUSE 17
CONFIDENTIALITY AND PUBLIC ANNOUNCEMENTS
17.1 The CONTRACTOR shall keep information furnished to it by the CORPORATION
and all plans, maps, drawings, designs, data, scientific, technical and
financial reports and other data and information of any kind or nature
relating to Petroleum Operations including any discovery of Petroleum as
strictly confidential, for all times, and shall ensure that their entire
or partial contents shall under no circumstances be disclosed by the
CONTRACTOR in any announcement to the public or to any third party
without the prior written consent of the CORPORATION.
The provisions of this Clause 17 shall not apply to disclosure to:
(a) Subcontractors, affiliates, assignees, auditors, legal advisers,
provided that such disclosures are required for the effective
performance of the aforementioned recipients' duties related to
Petroleum Operations;
(b) Comply with statutory obligation or the requirements of any
governmental agency in which case the CONTRACTOR will notify the
CORPORATION of any information so disclosed.
(c) Financial institutions involved in the provision of finance for
the operations hereunder provided, in all such cases, that the
recipients of such data and information agree in writing to keep
such data and information strictly confidential.
(d) A third party for the purpose of negotiating an assignment of
interest hereunder provided such third party executes an
undertaking to keep the information disclosed confidential.
17.2 The CONTRACTOR shall take necessary measures in order to make its
employees, agents, representatives, proxies and subcontractors comply
with the same obligation of confidentiality provided for in this Clause
17.
17.3 The provisions of this Clause 17 shall not be voided by the expiry or
termination of this Contract on any grounds whatsoever and these
provisions constitute a continuing obligation, and accordingly the
restrictions arising therefrom shall be in force at all times.
17.4 The CONTRACTOR shall use its best endeavors to ensure that the
CONTRACTOR's servants, employees, agents and subcontractors shall not
make any reference in public or publish any notes in newspapers,
periodicals or books nor divulge, by any other means whatsoever, any
information on the activities under the CONTRACTOR's responsibility, or
any reports, data or any facts and documents that may come to their
knowledge by virtue of this Contract, without the prior written consent
of the CORPORATION.
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17.5 The CONTRACTOR shall submit to the CORPORATION all statutory reports and
information for submission to Government and other statutory bodies.
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CLAUSE 18
FORCE MAJEURE
18.1 Any failure or delay on the part of either Party in the performance of
its obligations or duties under this Contract shall be excused to the
extent attributable to force majeure. A force majeure situation
includes delays, defaults or inability to perform under this Contract
due to any event beyond the reasonable control of either Party. Such
event may be, but is not limited to, any act, event, happening, or
occurrence due to natural causes; and acts or perils of navigation,
fire, hostilities, war (declared or undeclared), blockade, labor
disturbances, strikes, riots, insurrection, civil commotion, quarantine
restrictions, epidemics, storms, floods, earthquakes, accidents,
blowouts, lightning, and acts of or orders of Government.
18.2 If operations are delayed, curtailed or prevented by force majeure, then
the time for carrying out the obligation and duties thereby affected,
and rights and obligations hereunder, shall be extended for a period
equal to the period thus involved.
18.3 The Party whose ability to perform its obligations is so affected shall
promptly notify the other Party thereof not later than forty-eight (48)
hours after the establishment of the start of force majeure stating the
cause, and both Parties shall do all that is reasonably within their
powers to remove such cause.
18.4 The CONTRACTOR's failure or inability to find Crude Oil in Commercial
Quantity for reasons other than as specified in Clause 18.1 hereof shall
not be deemed force majeure.
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CLAUSE 19
LAWS AND REGULATIONS
19.1 This Contract shall be governed by and construed in accordance with the
Laws of the Federation of Nigeria, and any dispute arising therefrom
shall be determined in accordance with such laws.
19.2 In the event that any enactment of or change in the laws or regulations
of Nigeria or any rules, procedures, guidelines, instructions,
directives, or policies, pertaining to the Contract introduced by any
Government department or Government parastatals or agencies occurs
subsequent to the Effective Date of this Contract which materially and
adversely affects the rights and obligations or the economic benefits of
the CONTRACTOR, the Parties shall use their best efforts to agree to
such modifications to this Contract as will compensate for the effect of
such changes. If the Parties fail to agree on such modifications within
a period of ninety (90) days following the date on which the change in
question took effect, the matter shall thereafter be referred at the
option of either Party to arbitration under Article 21 hereof.
Following arbitrator's determination, this Contract shall be deemed
forthwith modified in accordance with that determination.
19.3 All affairs related to this Contract shall be conducted in the language
in which this Contract was drawn up.
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CLAUSE 20
UTILIZATION OF NATURAL GAS
20.1 If the CONTRACTOR discovers a commercially viable quantity of Natural
Gas, the CORPORATION shall require the CONTRACTOR to investigate and
submit proposals for the commercial development of the Natural Gas for
the CORPORATION's consideration provided that any cost in respect of
such proposals or investigation shall be included in Operating Cost.
For the commercial development of natural gas field, the funding
arrangements and participation by the CONTRACTOR in the project shall be
the subject of another agreement and the CONTRACTOR shall have the right
to participate in such development project.
20.2 Notwithstanding the provisions of Clause 20 hereof, the CONTRACTOR may
utilize, at no cost the associated Natural Gas produced with Crude Oil
as fuel for production operations; gas recycling, secondary recovery by
gas injection, gas lift, or any other economical secondary recovery
schemes, stimulation of wells or artificial lifts necessary in the
commercial field discovered and developed by the CONTRACTOR but only
with the prior written consent of the CORPORATION, which consent shall
not be unreasonably withheld. The objective of maximum technical and
economic recovery of Crude Oil shall always be paramount. However, not
later than two (2) years after the commencement of production of Crude
Oil from the Contract Area, the CONTRACTOR shall submit to the Minister,
a programme for the utilization of any Natural Gas whether associated
with Crude Oil or not which has been discovered from the Contract Area.
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CLAUSE 21
CONSULTATION AND ARBITRATION
If a difference or dispute arises between the CORPORATION and the CONTRACTOR,
concerning the interpretation or performance of this Contract, and if the
parties fail to settle such difference or dispute by amicable agreement, then
either party may serve on the other a demand for arbitration. Within thirty
(30) days of such demand being served, each party shall appoint an arbitrator
and the two arbitrators thus appointed shall with a further thirty (30) days
appoint a third arbitrator and if the arbitrators do not agree on the
appointment of such third arbitrator, or if either Party fails to appoint the
arbitrator to be appointed by it, such an arbitrator or third arbitrator shall
be appointed by the President of the Court of Arbitration of the International
Chamber of Commerce (ICC) in Paris on the application of the other Party
(notice of the intention to apply having duly given in writing by the applicant
party to the other party) and when appointed the third arbitrator shall convene
meeting and act as chairman thereat. If an arbitrator fails or is unable to
act, a successor shall be appointed by the respective party or by the
arbitrators in the event the chairman must be succeeded. The arbitration award
shall be binding upon the parties and the expenses shall be borne by the
parties in such proportion and manner as may be provided in the award. The
Nigerian Arbitration and Conciliation Act Cap 19, Laws of the Federation of
Nigeria, 1990 shall apply to this contract. The venue of the arbitration shall
be any where in Nigeria as agreed by the parties.
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CLAUSE 22
EFFECTIVENESS
22.1 This Contract shall come into force and effect on the Effective Date.
22.2 This Contract shall not be amended or modified in any respect except by
mutual consent, in writing of the Parties hereto.
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CLAUSE 23
NOTICES
23.1 Any notices required to be given by either Party to the other shall be
in writing and shall be deemed to have been duly given and received if
sent by fax, telegram or cable (confirmed by mail) or registered post
to, or hand delivered at the following registered offices:
THE CORPORATION:
THE GROUP MANAGING DIRECTOR
NIGERIAN NATIONAL PETROLEUM CORPORATION
7, KOFO ABAYOMI STREET
VICTORIA ISLAND
LAGOS.
CABLE: NAPETCOR
TELEX: 21126 NG
FAX
THE CONTRACTOR:
THE MANAGING DIRECTOR
Ashland Oil (Nigeria) Company Unlimited
10, Bishop Aboyade-Cole Street
Victoria Island
Lagos
CABLE:
TELEX: 961-211023 ASHOIL NG
FAX: 234-1616816
23.2 Either Party shall notify the other promptly of any change in the above
address.
SIGNED AND DELIVERED for and on behalf of
NIGERIAN NATIONAL PETROLEUM CORPORATION
By: /s/ C. O. Oyibo
----------------------------------------
Name: C. O. Oyibo
Designation: Group Managing Director
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<PAGE> 39
IN THE PRESENCE OF:
Name: M. A. Olorunfemi
Signature: /s/ M. A. Olorunfemi
----------------------------------------------
Designation:
Address:
SIGNED AND DELIVERED for and on behalf of
ASHLAND OIL (NIGERIA) COMPANY UNLIMITED
By: /s/ H. R. Benedict
-----------------------------------------------------
Name: H. R. Benedict
Designation: GENERAL MANAGER AND MANAGING DIRECTOR
IN THE PRESENCE OF:
Name: J. I. Obi
Signature: /s/ J. I. Obi
----------------------------------------------
Designation: COMPANY SECRETARY
APPROVED BY THE HON. MINISTER
This 25th day of May, 1994
Signature: /s/ Don Etiebet
----------------------------------------------
Name: Don Etiebet
DESIGNATION: HON. MINISTER OF PETROLEUM AND MINERAL RESOURCES.
IN THE PRESENCE OF
Name: Abdullah Hashim
Signature: /s/ Abdullah Hashim
----------------------------------------------
Designation: Director - General (Petroleum)
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<PAGE> 40
ANNEX A
[Map of Field]
-37-
<PAGE> 41
ANNEX B
TO THE PRODUCTION SHARING CONTRACT BETWEEN
CORPORATION and CONTRACTOR dated this day 199
ACCOUNTING PROCEDURE
Article I
General Provisions
1. Definitions
This Accounting Procedure attached to and forming a part of the Contract
is to be followed and observed in the performance of either Party's
obligations thereunder. The defined terms appearing herein shall have
the same meaning as is ascribed to them in the Contract.
2. Accounts and Statements
CONTRACTOR's accounting records and books shall be kept as provided
under Clause 13.1 of the Contract in accordance with generally accepted
and recognized accounting standards, consistent with modern petroleum
industry practices and procedures. All original books of accounts
together with original supporting documentation shall be kept and
maintained in Nigeria in compliance with all Nigerian laws and
regulations.
3. Other
In the event of a conflict of the terms of this Procedure and the
Contract the terms of the Contract shall apply.
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Article II
Operating Costs
Operating Costs shall be defined as all costs, expenses paid and obligations
incurred by the CONTRACTOR in carrying out Petroleum Operations and shall
consist of (1) Non-Capital Costs, and (2) Capital Costs.
1. Non-capital Costs
Non-capital Costs mean those Operating Costs incurred that are
chargeable to the current year's operations. Non-capital Costs include,
but are not limited to the following:
(a) General office expenses - office, services and general
administration services pertaining to Petroleum Operations
including but not limited to, services of legal, financial,
purchasing, insurance, accounting, computer, and personnel
department; communications, transportation, rental of specialized
equipment, scholarships, charitable contributions and educational
awards.
(b) Labour and related costs - salaries and wages, including bonuses,
of employees of the CONTRACTOR who are directly engaged in the
conduct of Petroleum Operations, whether temporarily or
permanently assigned, irrespective of the location of such
employee including but not limited to, the costs of employee
benefits, customary allowances and personal expenses incurred
under the CONTRACTOR's practice and policy, and amounts imposed
by applicable Governmental authorities which are applicable to
such employees. These costs and expenses shall include:
(i) Cost of established plans for employee group life
insurance, hospitalization, pension, retirement, savings
and other benefit plan;
(ii) Cost of holidays, vacations, sickness and disability
benefits;
(iii) Cost of living, housing and other customary allowances;
(iv) Reasonable personal expenses which are reimbursable under
the CONTRACTOR's standard personnel policies;
(v) Obligations imposed by Governmental authorities;
(vi) Cost of transportation of employees, other than as
provided in paragraph (c) below, as required in the
conduct of Petroleum Operations; and
(vii) Charges in respect of employees temporarily engaged in
Petroleum Operations which shall be calculated to reflect
the actual costs thereto during the period or periods of
such engagement.
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(c) Employee relocation costs - costs for relocation, transportation
and transfer of employees of CONTRACTOR engaged in Petroleum
Operations pursuant to Clause 7.1(k) of this Contract including,
but not limited to the cost of freight and passenger service of
such employees' families and their personal and household effects
together with meals, hotel and other expenditures related to such
transfer incurred with respect to:
(i) employees of the CONTRACTOR within Nigeria, including
expatriate employees, engaged in Petroleum Operation;
(ii) transfer to Nigeria for engagement in Petroleum
Operations;
(iii) relocation costs and other expenses incurred in the final
repatriation or transfer of the CONTRACTOR's expatriate
employees and families in the case of such employees'
retirement, or separation from the CONTRACTOR, or in case
of such employees' relocation to the CONTRACTOR's Head
Office.
Provided that relocation costs incurred in moving an
expatriate employee and his family beyond his point of
origin, established at the time of his transfer to
Nigeria, will not be recoverable as Operating Cost and
provided that no charge shall be made to the Petroleum
Operation with respect to the expenses incurred in the
final repatriation or transfer of the expatriate employees
and families to other areas outside of the Contract Area.
(iv) Nigerian employees on training assignments outside the
Contract Area.
(d) Services provided by third parties - cost of professional,
technical, consultation, utilities and other services procured
from third party sources pursuant to any contract or other
arrangements between such third parties and the CONTRACTOR for
the purpose of Petroleum Operations.
(e) Legal expenses - All costs or expenses of handling,
investigating, asserting, defending, and settling litigation or
claims arising out of or relating to Petroleum Operations or
necessary to protect or recover property used in Petroleum
Operations including, but not limited to, legal fees, court
costs, arbitration costs, cost of investigation or procuring
evidence and amounts paid in settlement or satisfaction of any
such litigation, arbitration or claims in accordance with the
provisions of this Contract.
(f) Services provided by Affiliates of the CONTRACTOR, professional,
administrative, scientific and technical services for the direct
benefit of Petroleum Operations including, but not limited to,
services provided by the exploration, production, legal,
financial, purchasing, insurance, accounting and computer
services departments of such Affiliates. Charges for providing
these services shall reflect the actual cost only
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<PAGE> 44
and must be consistent with international market prices and shall
not include any element of profit.
(g) Head Office overhead charge - parent company overhead in the
amount specified in Clause 13.3 of the Contract.
(h) Interest - interest on loans used to finance Petroleum Operations
provided the terms of such loans were with the prior approval of
CORPORATION, and not higher than the prevailing commercial rates.
(i) Insurance premiums and settlements - premiums paid for insurance
normally required to be carried for the Petroleum Operations
together with all expenditures incurred and paid in settlement of
any and all losses, claims, damages, judgements, and other
expenses, including fees and deductibles relating to the
CONTRACTOR's performance under the Contract.
(j) Duties and taxes - all duties and taxes, fees and any Government
assessments, including but not limited to, gas flare charges,
license fees, customs duties, and any other payments to the
Government other than Royalties, PPT and Concession Rental.
(k) Intangible drilling costs - expenditures for labor, fuel,
repairs, maintenance, hauling, and supplies and materials (not
including, casing and other well fixtures) which are for or
incidental to drilling, cleaning, deepening or completing wells
or the preparation thereof incurred in respect of:
(i) determination of well locations, geological, geophysical,
topographical and geographical surveys for site evaluation
preparatory to drilling including the determination of
near surface and near sea bed hazards,
(ii) cleaning, draining and leveling land, road-building and
the laying of foundations,
(iii) drilling, shooting, testing and cleaning wells,
(iv) erection of rigs and tankage assembly and installation of
pipelines and other plan and equipment required in the
preparation or drilling of wells producing Crude Oil.
(l) Geological and geophysical surveys - labor, materials and
services used in aerial, geological, topographical, geophysical
and seismic surveys incurred in connection with exploration
excluding however the purchase of data from CORPORATION.
(m) Operating expenses - labor, materials and services used in day to
day oil well operations, oil field production facilities
operations, secondary recovery operations; storage,
transportation, delivery and marketing operations; and other
operating
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<PAGE> 45
activities, including repairs, well workovers, maintenance and
related leasing or rental of all materials, equipment and
supplies.
(n) Exploration and appraisal drilling - all expenditures incurred in
connection with exploration drilling, and the drilling of the
first two appraisal wells in a particular field, and drilling of
development wells which are dry, including costs incurred in
respect of casing, well cement and well fixtures.
(o) Abandonment - a provision for all expenditures incurred in
connection with the plugging of wells; the removal and disposal
of equipment and facilities including well heads, processing and
storage facilities, platforms, pipelines, transport and export
facilities, roads, buildings, wharves, plants, machinery,
fixtures, the restoration of sites and structures including the
payment of damages to property lessors.
2. Capital Costs
Capital Costs means, without limitations, expenditures which are subject
to a Capital Allowance under the PPT Act. Such expenditures normally
have a useful life beyond the year incurred and include but are not
limited to the following:
(a) Plant expenditures - expenditures in connection with the design,
construction, and installation of plant facilities (including
machinery, fixtures, and appurtenances) associated with the
production, treating, and processing of Crude Oil (except such
costs properly allocable to intangible drilling costs) including
offshore platforms, secondary or enhanced recovery systems, gas
injection, water disposal, expenditures for equipment, machinery
and fixtures purchased to conduct Petroleum Operations such as
office furniture and fixtures, office equipment, barges, floating
crafts, automotive equipment, Petroleum Operational aircraft,
construction equipment, miscellaneous equipment.
(b) Pipeline and storage expenditures - expenditures in connection
with the design, installation, construction of pipeline,
transportation, storage, and terminal facilities associated with
Petroleum Operations including tanks, metering, and export lines.
(c) Building expenditure - expenditures incurred in connection with
the construction of building, structures or works of a permanent
nature including workshops, warehouses, offices, roads, wharves,
furniture and fixtures related to employee housing and
recreational facilities and other tangible property incidental to
construction.
(d) Drilling expenditures - expenditures for tangible goods in
connection with drilling wells such as casing, tubing, surface
and sub-surface production equipment, flow lines, instruments;
costs incurred in connection with the acquisition of rights over
the Contract Area pursuant to paragraph l(d)i of the Second
Schedule of the PPT Act except any bonuses paid under Clause 14
of this Contract.
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(e) Pre-Production expenditures - all costs (including those
otherwise falling within Non-Capital Costs described in paragraph
1 of this Article II) incurred before the first PPT accounting
period.
(f) Material inventory - cost of materials purchased and maintained
as inventory items solely for Petroleum Operations subject to the
following provisions:
(i) The CONTRACTOR shall supply or purchase any materials
required for the Petroleum Operations, including those
required in the foreseeable future. Inventory stock
levels shall take account of the time necessary to provide
the replacement, emergency needs and similar
considerations.
(ii) Materials purchased by the CONTRACTOR for use in the
Petroleum Operations shall be valued so as to include
invoice price (less prepayment discounts, cash discounts,
and other discounts if any) plus freight and forwarding
charges between point of supply and point of destination
but not included in the invoice price, inspection costs,
insurance, customs fees and taxes, on imported materials
required for this Contract.
(iii) Materials not available in Nigeria supplied by the
CONTRACTOR or from its Affiliates' stocks shall be valued
at the current competitive cost in the international
market.
(iv) The CONTRACTOR shall maintain physical and accounting
controls of materials in stock in accordance with general
practice in the international petroleum industry. The
CONTRACTOR shall make a total inventory at least once a
year to be observed by the CORPORATION and its external
auditors. The CORPORATION may however carry out partial
or total inventories at its own expenses, whenever it
considers necessary, provided such exercise does not
unreasonably disrupt Petroleum Operations.
Article III
Computation of Royalty, Concession Rentals and PPT
1. The CONTRACTOR shall compute the amount of Royalty and Concession
Rentals payable by the CORPORATION pursuant to Clause 8.1 of this
Contract. Such amounts shall be computed as provided under the
Petroleum Act 1969 as amended and the PPTA 1959 as amended and the
provisions of this Contract. For purposes of Article IV hereof, the
CONTRACTOR shall compute the Royalty payment for remittance to
Government in a given month based on the prevailing fiscal value of the
Crude Oil produced during the second preceding month. Annual Concession
Rental payments shall be taken into account when such payments are
remitted. The CORPORATION shall remit all required payments of Royalty
and Concession Rentals to the Government. The Royalty shall be computed
as follows:
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ROYALTY
Royalty rates will be as provided in the Petroleum Act 1969, as amended,
and the prevailing fiscal laws and regulations.
2.(a) The CONTRACTOR shall compute the PPT payable by CORPORATION pursuant to
Clause 8.1 of this Contract in accordance with the provisions of the PPT
Act and the Revised Memorandum of Understanding, as well as any
prevailing Government fiscal incentives including, but not limited to,
any credit which offsets PPT liability.
(b) The PPT shall be in accordance with the PPT Act 1959, as amended.
(c) The PPT rate applicable to the Contract Area shall be in accordance with
the PPT Act and shall be 65.75% for the first five years of production
from each field developed in the Contract Area commencing for each field
from the first day of the month of first sale therefrom and 85%
thereafter.
(d) The CORPORATION shall make all required PPT payments to Federal Board of
Inland Revenue. The CONTRACTOR shall prepare all returns required under
the PPT Act and timely submit them to the CORPORATION for onward filing
with the Federal Board of Inland Revenue. The monthly PPT payable shall
be determined from such PPT returns.
3. The Revised Memorandum of Understanding shall be applied when
calculating the PPT. This shall include the application of the
Guaranteed Notional Margin, Revised Government Take, Reserve Addition
Bonus, and the tax offset for Capital Investment Costs.
4. In the event that there is more than one field producing in the Contract
Area and different PPT rates (i.e., either 65.75% or 85%) apply to such
fields, the Chargeable Profit (as defined under the PPT Act) shall be
allocated to each field in the proportion that the fiscal values from
each field during the accounting Year bear to the total fiscal values
from the Contract Area during the accounting Year. The applicable PPT
rate will then be applied to the appropriate Chargeable Profit allocated
to each field.
Article IV
Accounting Analyses
1. A monthly accounting analysis in the form of Schedule B-1 attached to
this Accounting Procedure shall be prepared by the CONTRACTOR and
furnished to CORPORATION within sixty (60) days of the end of the period
covered by such analysis, for consideration and approval.
2. The Realizable Price and the quantities actually lifted by the Parties
shall be used to compute the Proceeds as reflected in Section A of each
Schedule B-1 and the allocation of such
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<PAGE> 48
Proceeds in the categories described under Clause 8.1 of the Contract
shall be reflected in Section B thereof.
3. The allocation of the quantity of Available Crude Oil to each Party
pursuant to Clause 8 of the Contract shall be according to and governed
by provisions of the Allocation Procedure.
4. The priority of allocation of the total proceeds for each Period shall
be as follows:
(a) Royalty Oil,
(b) Cost Oil,
(c) Tax Oil,
(d) Profit Oil.
5. The amount chargeable to and recoverable from Royalty Oil, Tax Oil and
Cost Oil to be entered in Section B of Schedule B-1 shall be determined
as follows:
(a) Royalty Oil - The sum of royalties payable during such month,
and, where applicable, the annual amount of Concession Rentals as
provided under Article III 1 for purposes of Royalty Oil.
(b) Cost Oil - The Operating Costs applicable to such month for
purposes of Cost Oil as follows:
(i) Non-Capital Costs shall be the amount recorded in the
books and accounts of the CONTRACTOR for such month in
accordance with this Accounting Procedure.
(ii) Capital Costs recorded in the books and accounts of the
CONTRACTOR shall be recoverable in full and chargeable in
equal installments over a five (5) year period or the
remaining life of the Contract, whichever is less.
Amortization of such costs shall be in accordance with the
method prescribed under the Second Schedule of the PPT
Act, or over the remaining life of the contract, whichever
is less.
(iii) Qualifying Pre-Production Costs for the Contract Area
shall be in accordance with the PPT Act 1959 as amended.
(c) Tax Oil - The sum of the PPT payable for such month as provided
under Article III 2, 3 and 4, for purposes of Tax Oil.
(d) Any carryover from previous months as provided under paragraph 6
of this Article.
6. Any amounts chargeable and recoverable in excess of the allocation of
Proceeds for the month to Royalty Oil, Tax Oil and Cost Oil shall be
carried forward to subsequent months. Carryovers shall be determined as
follows:
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(a) A Royalty Oil value carryover results when the Proceeds for such
month are insufficient for recovery of the Royalty Oil due for
the month.
(b) A Cost Oil value carryover results when the Proceeds remaining
after allocating a portion of the Proceeds to Royalty Oil is
insufficient for recovery of Cost Oil due for the month,
including the costs described in Clause 8.1(d) of the Contract.
(c) A Tax Oil value carryover results when the proceeds remaining
after allocating a portion of the Proceeds to Royalty Oil and
Cost Oil are insufficient for recovery of the Tax Oil due for the
month.
7. Profit Oil results where proceeds remain after allocations to Royalty
Oil, and Cost Oil, and Tax Oil pursuant to paragraph 5 of this Article
IV. Profit Oil shall be allocated to the Parties according to the
following percentages:
<TABLE>
<CAPTION>
Profit Oil
Monthly Average MBOPD Percentages
from Contract Area CORPORATION CONTRACTOR
- ---------------------------- ----------- ----------
<S> <C> <C>
0 to 40 20 30
Greater than 40 but less than 75 35 65
Greater than 75 but less than 100 45 55
100 and above 50 50
</TABLE>
A computation of Profit Oil shares in the form of Schedule B-2 attached
to this Account Procedure shall be submitted monthly in conjunction with
Schedule B-l.
Article V
Other Provisions
1. The CONTRACTOR shall open and keep bank accounts in Nigeria in Naira and
U.S. Dollars where all funds remitted from abroad shall be deposited for
the purpose of meeting local expenditures. For purposes of keeping the
books of accounts, any Foreign Currency remitted by the CONTRACTOR into
Nigeria shall be converted into Naira at the monthly exchange rates
advised by the Central Bank of Nigeria.
2. The CONTRACTOR shall prepare financial accounting and budget statements
in accordance with the CORPORATION's prescribed reporting format.
3. With respect to any agreed sum arising out of this Contract owing
between the Parties that is past due, any set-off pursuant to Clause
10.3 shall be exercised by giving the other Party written notice thereof
accompanied by sufficient description of the offsetting sums to allow
the Parties to properly account therefor.
-46-
<PAGE> 50
The CONTRACTOR shall report on the cumulative production in the
Production Area in the Form on Schedule B-3 attached.
-47-
<PAGE> 51
SCHEDULE B-1
MONTHLY ACCOUNTING ANALYSIS
MONTH OF ___________, ___________
SECTION A - LIFTING SUMMARY
<TABLE>
<CAPTION>
==============================================================================================================
RP Proceeds Received By:
Lifting Crude US$/ Volume Proceeds
Date Type Bbl Bbls US$ CORPORATION CONTRACTOR
==============================================================================================================
<S> <C> <C> <C> <C> <C> <C>
- --------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------
Totals
==============================================================================================================
</TABLE>
SECTION B - ALLOCATION OF PROCEEDS - EXPRESSED IN U.S. DOLLARS
<TABLE>
<CAPTION>
==============================================================================================================
PRIOR CURRENT RECOVERABLE ALLOCATION
MONTH MONTH THIS OF CARRYOVER
CATEGORY CARRYOVER CHARGES MONTH PROCEEDS:
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
CORP CONTR
- --------------------------------------------------------------------------------------------------------------
Royalty Oil
- --------------------------------------------------------------------------------------------------------------
Cost Oil
- --------------------------------------------------------------------------------------------------------------
Tax Oil
- --------------------------------------------------------------------------------------------------------------
Corp Profit Oil
- --------------------------------------------------------------------------------------------------------------
Contr Profit Oil
- --------------------------------------------------------------------------------------------------------------
Totals
==============================================================================================================
</TABLE>
-48-
<PAGE> 52
Schedule B-2
Profit Oil Shares
Month of ____________, _____
<TABLE>
<CAPTION>
Section A - Total Production Section B - Total Profit Oil
For the Month For the Month
=========================================== ==========================================
Field Total Net Barrels Category US$
- ------------------------------------------- ------------------------------------------
<S> <C> <C>
Proceeds
- ------------------------------------------- ------------------------------------------
Royalty Oil
- ------------------------------------------- ------------------------------------------
Cost Oil
- ------------------------------------------- ------------------------------------------
Tax Oil
=========================================== ==========================================
Profit Oil
=========================================== ==========================================
</TABLE>
Section C - Cumulative Production To Date (Schedule B-3, Section B)
- -------------------------
Section D - Calculation of Profit Oil Shares
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
Monthly
Barrels/Day Monthly Profit Corp/Contr
Produced Production % of Total By Profit Corp's Contr's
For the Month By Tranch, Monthly Tranch, Share by Profit, Profit,
Barrels Production US$ Tranch US$ US$
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
First 40,000 0.20/0.80
Bbls/Day
- -----------------------------------------------------------------------------------------------------------------
Next 35,000 0.35/0.65
Bbls/Day
- -----------------------------------------------------------------------------------------------------------------
Next 25,000 0.45/0.55
Bbls/Day
- -----------------------------------------------------------------------------------------------------------------
Over 100,000 0.50/0.50
Bbls/Day
- -----------------------------------------------------------------------------------------------------------------
Total
Monthly
Production
- -----------------------------------------------------------------------------------------------------------------
</TABLE>
-49-
<PAGE> 53
Schedule B-3
Cumulative Production Analysis
SECTION A - MONTHLY PRODUCTION
<TABLE>
<CAPTION>
================================================================================================================
Planned Planned Actual Actual
Crude Production Cumulative Production Cumulative
Type for Month for Quarter for Month for Quarter
Bbls Bbls Bbls Bbls
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
- ----------------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------
Totals
================================================================================================================
</TABLE>
SECTION B - CUMULATIVE PRODUCTION
<TABLE>
<CAPTION>
=================================================================================================================
Cumulative Previous Quarter Cumulative
Production Cumulative Production
Crude Type for Quarter Production B/F To Date
Bbls Bbls Bbls
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
- -----------------------------------------------------------------------------------------------------------------
Totals
=================================================================================================================
</TABLE>
SECTION C - CUMULATIVE PRODUCTION/LIFTINGS/STORAGES
<TABLE>
<CAPTION>
==============================================================================================================
Crude Cumulative Cumulative In
Type Production Liftings Storage
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
- --------------------------------------------------------------------------------------------------------------
Totals
==============================================================================================================
</TABLE>
-50-
<PAGE> 54
ANNEX C
To The Production Sharing Contract
Between the CORPORATION and the CONTRACTOR Dated................
ALLOCATION PROCEDURE
Article I
Application
1. This Allocation Procedure ("this Procedure") sets out the methods for
the allocation of Available Crude Oil from the Contract Area and the
Parties shall allocate all liftings of Available Crude Oil in accordance
with this Procedure and the Contract.
2. In the event that the production of Available Crude Oil is segregated
into two or more types or grades, the provisions of this Procedure shall
apply separately to each such type or grade. To the extent that
distribution on such a basis is impracticable, a separate method for the
allocation of such Available Crude Oil shall be agreed upon by the
Parties.
3. In the event of a conflict between the terms of this Procedure and the
Contract, the terms of the Contract shall prevail.
4. The procedures set forth herein may be amended from time to time by
mutual agreement of the Parties.
-51-
<PAGE> 55
Article II
Definitions
1. The words and expressions defined in the Contract when used herein,
shall have the meaning ascribed to them in the Contract. In addition,
the following words shall have the meanings set forth below:
(a) "Current Quarter" means the calendar quarter within which the
relevant Schedules are prepared and submitted;
(b) "Forecast Quarter" means the first calendar quarter succeeding
the Current Quarter;
(c) "Lifting Allocation" means the quantity of Available Crude Oil
which each Party has the right to take in kind, lift and dispose
of in accordance with Clause 9 of the Contract;
(d) "Primary Nomination" means written statement issued by each Party
to the other at least twenty-five (25) days prior to the
commencement cf each quarter declaring the volume by grade of its
estimated Lifting Allocation which the Party desires to lift
during the Forecast Quarter;
(e) "Proceeds" means the amount in U.S. Dollars determined by
multiplying the Realizable Price by the number of barrels of
Available Crude Oil lifted by either Party; and
(f) "Proceeds Imbalance" means the difference between each Party's
Proceeds to which it is entitled and the Proceeds which each
Party has actually received, as reflected in each quarter's
Schedule C-2 of this Procedure.
-52-
<PAGE> 56
Article III
Lifting Allocation
1. On or before September 30 of every year, the CONTRACTOR shall advise the
Parties of its forecast of the Available Crude Oil to be produced by
grades during each month of the first six (6) months of the next ensuing
Year.
2. On or before March 31 of every year, the CONTRACTOR shall advise the
CORPORATION of its forecast of Available Crude Oil to be produced by
grades during each month of the six (6) months commencing July 1, of the
Year.
3. Thirty-five (35) days before commencement of production from the
Contract Area and thereafter thirty-five (35) days prior to the
beginning of the Forecast Quarter, the CONTRACTOR shall notify the
CORPORATION of the estimated Lifting Allocation which can be produced
and made available for disposal during the Forecast Quarter. Such
estimated Lifting Allocation shall take into account any Proceeds
Imbalance for the quarter first preceding the Current Quarter and any
estimated Proceeds Imbalance for the Current Quarter computed in
accordance with paragraph 3 of Article IV. Such notice shall be in the
form of Schedule C-l attached hereto indicating the estimated quantities
of Royalty Oil, Tax Oil, Cost Oil and Profit Oil, each Party's estimated
Lifting Allocation and the estimated Realizable Price used to prepare
such estimated Lifting Allocations.
4. Twenty-five (25) days before the commencement of production from the
Contract Area and thereafter not later than twenty-five (25) days before
the beginning of Forecast Quarter, each Party shall notify the other of
its Primary Nomination of Available Crude Oil which it intends to lift
during the Forecast Quarter which shall not exceed its estimated Lifting
Allocation. Such notice shall include the information described in
Article V, paragraph 1 of Annex D - Nomination, Ship Scheduling and
Lifting Procedure.
5. The estimated Realizable Price to be used by the CONTRACTOR to prepare
Schedule C-l (Estimated Quarterly Lifting Allocation) shall be the
Realizable Price of the first month of the Current Quarter.
6. Each Party shall be obligated to lift its own Lifting Allocation in
accordance with the Nomination, Ship Scheduling and Lifting Procedure
(Annex D). In the event that one Party lifts the other Party's Lifting
Allocation, pursuant to Clause 9.1 of the Contract the lifting Party
shall pay to the non-lifting Party the applicable Proceeds pursuant to
Clause 8.5 of the Contract. In such case, the non-lifting Party shall
be treated for all other purposes under this Contract as though it had
made such lifting itself.
-53-
<PAGE> 57
Article IV
Adjustments of Lifting Allocations
1. On or before thirty-five (35) days prior to the last day of the Current
Quarter, the Lifting Allocation for the first preceding quarter thereto
shall be computed and the Proceeds Imbalance determined and agreed to by
the CORPORATION in the form of Schedule C-2 attached hereto. Section A
of such Schedule C-2 shall be based on the actual liftings made by the
Parties and the Proceeds therefrom. Section B of such Schedule C-2
shall be prepared from the Schedule B-l (of the Accounting Procedure)
for the months in the quarter.
2. On or before thirty-five (35) days prior to the last day of the Current
Quarter, the Proceeds Imbalance for the Current Quarter shall be
estimated, taking into account the actual Proceeds Imbalance computed
for the first preceding quarter under paragraph 1 of this Article IV.
3. The Proceeds Imbalance for the first preceding quarter computed under
paragraph 1 above and the estimated Proceeds Imbalance for the Current
Quarter computed under paragraph 2 above shall be taken into account by
the Parties by debiting or crediting such Proceeds Imbalances to each
Party's share of the estimated Lifting Allocation reflected in Schedule
C-l for the Forecast Quarter filed by dividing the respective Proceeds
Imbalance by the Realizable Price applicable for the period in question.
4. Notwithstanding the reports required to be kept by the CONTRACTOR
pursuant to Article IV in Annex D, the CONTRACTOR shall keep complete
records of all liftings. At the end of each quarter, the Parties will
meet to reconcile the Lifting Allocations and the actual lifting with a
view to making adjustments as appropriate. If any disagreement arises
with respect to such reconciliation, the area of disagreement shall be
mutually resolved by the Parties, in accordance with the official
records of the Ministry.
5. All Lifting Allocations and actual liftings shall be audited at the end
of each calendar year by a mutually acceptable independent auditor.
-54-
<PAGE> 58
SCHEDULE C-1
ESTIMATED QUARTERLY LIFTING ALLOCATION
_____QUARTER (_____-_____), _______
SECTION A - ESTIMATED TOTAL PROCEEDS
<TABLE>
<CAPTION>
================================================================================================
Estimated Estimated Estimated
Crude Lifting RP Proceeds
Type Volume Bbls US$/Bbl US$
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
================================================================================================
Totals
================================================================================================
</TABLE>
SECTION B - ALLOCATION OF ESTIMATED PROCEEDS - EXPRESSED IN U.S. DOLLARS
<TABLE>
<CAPTION>
=================================================================================================================
Allocation of Estimated
Prior Estimated Recoverable Proceeds To:
Category Month Quarter This --------------------------
Carryover Charges Quarter CORP CONTR
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
- -----------------------------------------------------------------------------------------------------------------
Royalty Oil
- -----------------------------------------------------------------------------------------------------------------
Cost Oil
- -----------------------------------------------------------------------------------------------------------------
Tax Oil
- -----------------------------------------------------------------------------------------------------------------
CORP Profit Oil
- -----------------------------------------------------------------------------------------------------------------
CONTR Profit Oil
=================================================================================================================
Totals
=================================================================================================================
Prior Quarter's Proceeds Imbalance
(Over)/Under
=======================================================================================
Current Quarter's Estimated Proceeds
Imbalance (Over)/Under
=======================================================================================
Estimated Proceeds Allocation For Quarter
=======================================================================================
</TABLE>
SECTION C - ESTIMATED LIFTING ALLOCATION
<TABLE>
<CAPTION>
==============================================================================================================
Crude CORP Allocation CONTR Allocation
Type Proceeds Bbls Proceeds Bbls
==============================================================================================================
<S> <C> <C> <C> <C>
==============================================================================================================
</TABLE>
-55-
<PAGE> 59
SCHEDULE C-2
ACTUAL QUARTERLY LIFTING ALLOCATION
_______ QUARTER (______-______), ________
SECTION A - LIFTING SUMMARY
<TABLE>
<CAPTION>
==============================================================================================================
Crude Volume Proceeds RP Proceeds Received By
Type Bbls US$ US$/Bbl -----------------------------------
CORPORATION CONTRACTOR
==============================================================================================================
<S> <C> <C> <C> <C> <C>
- --------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------
==============================================================================================================
Totals
==============================================================================================================
</TABLE>
SECTION B - ALLOCATION OF PROCEEDS - EXPRESSED IN U.S. DOLLARS
<TABLE>
<CAPTION>
============================================================================
CORPORATION CONTRACTOR
----------------------------------------------------------------------------
Category Sum of Allocation Lifting Allocation Lifting
Monthly of Proceeds of Proceeds
Allocation Proceeds Received Proceeds Received
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Royalty Oil
- --------------------------------------------------------------------------------------------------------------------
Cost Oil
- --------------------------------------------------------------------------------------------------------------------
Tax Oil
- --------------------------------------------------------------------------------------------------------------------
CORPORATION Profit Oil
- --------------------------------------------------------------------------------------------------------------------
CONTRACTOR Profit Oil
====================================================================================================================
Totals
====================================================================================================================
====================================================================================================================
Quarter (Over)/Under
---------------------------------------------------------------------------------------------
Prior Quarter (Over)/Under
Proceeds ---------------------------------------------------------------------------------------------
Imbalance Total (Over)/Underr)/Under
====================================================================================================================
</TABLE>
-56-
<PAGE> 60
ANNEX D
To The Production Sharing Contract
Between CORPORATION and the CONTRACTOR Dated ..............
UNIFORM NOMINATION, SHIP SCHEDULING AND LIFTING PROCEDURE
Article I
Application
1. This Annex D sets out the procedure for the nomination, ship scheduling
and lifting of Available Crude Oil from the Contract Area.
2. Pursuant to Clause 8.3 of the Contract the CORPORATION and the
CONTRACTOR have the right to nominate, lift and separately dispose of
their agreed allocation of Available Crude Oil produced and saved from
the Contract Area.
3. The procedures set herein may be amended from time to time by the mutual
agreement of the Parties.
4. In the event of a conflict between the terms of this Annex D and the
Contract, the terms of the Contract shall apply.
-57-
<PAGE> 61
ARTICLE II
Definition and Terminology
1. Words and expressions - this Annex shall have the meanings ascribed to
them in the Contract. In addition, the following words shall have the
following meanings:
(a) "Available Production" means the quantity of Petroleum which can
be efficiently and economically produced and saved from the
producing wells subject to any limitations imposed by government
authority or other technical limitations resulting from
Operations.
(b) "Technical Allowable Production" means the quantity of Petroleum
from time to time determined by the Ministry as being the
quantity that may be produced from the Contract Area on a well by
well basis for a particular period.
(c) "Commercial Production Quota" means the quantity of Petroleum
from time to time fixed or advised by the Ministry as the
permissible quantity that may be produced from the Contract Area
on a crude stream basis for a particular month/quarter.
(d) "Actual Production" means the quantity of Petroleum which is
produced from the Contract Area on a monthly/quarterly basis.
(e) "Available Monthly Scheduling Quantity" means each Party's
allocation of the Available Production for the calendar month
plus Opening Stock.
(f) "Combined Lifting Schedule" means the lifting programmes of the
Parties for a given calendar month/quarter as prepared by the
CONTRACTOR and agreed to by the Parties.
(g) "Opening Stock" means the quantity of Crude Oil that each Party
may carry forward to the succeeding month, recognizing the
difficulty - lifting precisely the Available
-58-
<PAGE> 62
Monthly Scheduling Quantity which excludes unpumpable dead stock,
should not be such as to cause a production shut-in through
reaching maximum stock levels where of course the provisions of
Article V will apply. The Quantity also includes credits/debits
accruing after reconciliation with Available Crude Oil.
(h) "Primary Nomination" means a written statement issued by one
Party to the other at least twenty-five (25) days prior to the
commencement of each calendar month of its production nominations
based on its allocation of the Commercial Production Quota Crude
Oil by grade, which it desires to take during the particular
calendar month plus Opening Stock.
-59-
<PAGE> 63
Article III
Production/Notice of Availability
1. The CONTRACTOR shall endeavour to produce the aggregate volume of oil
nominated by the Parties as provided in this Contract.
2. In the event that Available Crude Oil is segregated into two or more
grades the provisions of this Annex D shall apply separately to each
such grade. To the extent that distribution on such a basis is
impracticable, separate arrangement for sharing of such Available Crude
Oil shall be agreed upon by the Parties.
3. On or before September 30 of every year, the CONTRACTOR shall advise the
Parties of its forecast of the Available Production to be produced by
grades during each month of the first six (6) months of the next ensuing
year.
4. On or before March 31 of every year, the CONTRACTOR shall advise
CORPORATION of its forecast of the Available Production to be produced
by grades during each month of six months commencing July 1, of the
year.
5. Where for operational reasons the CONTRACTOR cannot exactly produce at
the anticipated Commercial Production Quota, the CONTRACTOR shall notify
the CORPORATION promptly of any required changes exceeding 2% of the
quantities originally notified. In any event, when actual production
for the month/quarter is known each Party's allocation will be
recalculated and the differences between Actual Production and
Commercial Production Quota will be credited/debited to each Party, and
shall form the Party's entitlement for the following month or quarter
except in the case of production shut-ins where the provisions of
Section 6 will apply.
6. Twenty-Five (25) days before the commencement of production from the
Contract Area and thereafter not later than twenty-five (25) days before
the beginning of each month, each Party shall notify the other of its
Primary Nomination of Available Crude Oil which it intend(s) to
-60-
<PAGE> 64
lift during the ensuing month, which shall not exceed its monthly
allocation of Commercial Production Quota plus Opening Stock.
7. At the end of each month or quarter, as may be agreed, Parties will meet
to reconcile Available Monthly Scheduling Quantities with actual
Available Crude lifted and adjustments made where necessary. All
entitlements shall be audited at the end of each calendar year by a
mutually acceptable independent auditor.
8. The CONTRACTOR shall keep complete records of all lifting and provide
same to the CORPORATION in accordance with Articles III & IV of this
Annex D.
-61-
<PAGE> 65
Article IV
The CONTRACTOR's Reports
1. The CONTRACTOR shall, not more than fifteen (15) working days after the
end of each calendar month, and quarter, prepare and furnish to the
CORPORATION a written statement showing in respect of the month and
quarter respectively:
(a) Production Quota: each Party's allocation of Commercial
Production Quota;
(b) Lifting against Available Crude Oil;
(c) Each Party's allocation of Available Crude Oil;
(d) Quantity of Crude Oil in Stock for each Party at the end of the
said calendar month or quarter; and
(e) Any production losses attributable to Crude Oil used in Petroleum
Operations.
(f) Cumulative production.
2. In the event the CORPORATION disagrees with any of the CONTRACTOR's
reports, the area of disagreement shall be mutually resolved by the
CONTRACTOR and the CORPORATION to the satisfaction of the Ministry. The
CONTRACTOR shall thereafter prepare a revised report to reflect the
changes agreed.
3. The CONTRACTOR must also endeavour to send consistent statistical data
to the different reporting bodies and should adhere to agreed formats of
reporting.
-62-
<PAGE> 66
Article V
Scheduling Details
1. Scheduling Notification - At least twenty-five (25) days prior to the
beginning of a calendar month, the CORPORATION shall notify the
CONTRACTOR of its proposed tanker schedule for that calendar month
specifying the following:
(a) A loading date range of ten (10) days for each tanker lifting;
(b) The desired parcel size for each lifting in Barrels, subject
always to change within a range of plus or minus rive percent
(5%) by the Party so nominating;
(c) The tanker's name or To Be Named (TBN) for each tanker lifting.
Tanker nominations made as TBN shall be replaced at least five
(5) working days prior to the accepted date range, unless a
shorter time is acceptable to the CONTRACTOR; and
(d) Documentation instructions shall be given for each lifting not
later than four (4) days prior to the first day of the accepted
date range for the tanker in question.
2. Tanker Substitution - Either Party may substitute another tanker to lift
its nominated volume of Crude Oil, provided such substituted tanker has
the same arrival date range as the originally scheduled tanker and all
other provisions of this Annex D are complied with.
3. Overlapping Date Ranges - In the event the Combined Lifting Schedule
contains overlapping accepted date ranges, the tanker which gives its
Notice of Readiness (NOR) and has provided all documentation and
obtained clearances first within such accepted date ranges shall be
loaded first, unless urgent operational requirements dictate otherwise
in which case, demurrage shall be borne by Petroleum Operations and
charged to Operating Costs.
4. Confirmation of Lifting Schedules - At least fifteen (15) days prior to
the beginning of a calendar month, the CONTRACTOR shall either confirm
the feasibility of the proposed
-63-
<PAGE> 67
monthly lifting schedules or, alternatively, advise necessary
modifications to such schedules. Such confirmation which shall be in
the form of combined lifting schedule, should include a loading date
range of three (3) days for each lifting, the first day being the
earliest date of arrival and the third day being the latest date of
arrival.
5. Operation Delays - The Parties recognize that occasionally environmental
and technical problems in the Contract Area may cause delays and/or
disruptions in the combined lifting schedule. The CONTRACTOR shall
promptly notify the CORPORATION of such delays and/or disruptions, and
the projected termination of each of such delays and/or disruptions and
advise the CORPORATION of the revised combined lifting schedule. In the
event such notification does not allow for a revised combined lifting
schedule on the part of the CORPORATION, then any resultant costs will
be charged to Operating Costs.
6. Estimated Delayed Arrival of a Tanker - Whenever it becomes apparent
that a tanker will not be available as scheduled or will be delayed, the
Party utilizing such tanker shall notify the other Party of the
circumstances and expected duration of the delays. Upon assessing the
impact that the delay will have upon the Combined Lifting Schedule and
Production during the current and/or next month, the CONTRACTOR shall
make appropriate revision(s) to the Combined Lifting Schedule to avoid
disruption in production. In the event that any Party fails to lift its
Nominated Share of Production in any month/quarter due to circumstances
beyond the Party's control or difficulties in maintaining the lifting
schedule, that Party shall have the right during the following
quarter/month to lift the unlifted quantities.
7. Tanker Standards - All tankers nominated for lifting by any Party
pursuant to this Annex D shall conform to the International regulations
and standards concerning size, equipment, safety, maintenance and the
like adopted by the CONTRACTOR for the Terminal in question and by the
appropriate government authority. Failure of a tanker to meet such
standards shall not excuse the nominating Party from the applicable
consequences provided in the Contract. The CONTRACTOR shall keep the
CORPORATION advised as to the current Regulations and standards in use
at the terminals operated by the CONTRACTOR.
-64-
<PAGE> 68
8. Destination of Crude Oil - The CONTRACTOR shall at all times disclose
the destination of the Crude Oil lifted under this Contract.
-65-
<PAGE> 69
Article VI
Production Decreases/Increases Subsequent to Nomination
1. Production decreases occurring after lifting nominations have been
scheduled and not resulting from the fault of either Party shall be
shared by the Parties in proportion to their respective nominations.
2. Production increases occurring after lifting nominations have been
confirmed by the CONTRACTOR shall be shared by the Parties, in
proportion to their respective agreed allocation.
3. To the extent that field operations permit, a Party shall have the right
to adjust its nomination during a monthly following confirmation of
lifting schedule provided that the nominations, entitlements and lifting
of the other Party are not affected thereby without their express
written consent. Adjusted nomination shall always be within the limits
of the Party's allocated portion of the Commercial Production Quota,
plus Opening Stock.
4. Any production decrease caused by or resulting directly from the actions
of one Party shall not affect the availability or entitlement of the
other Party. The CONTRACTOR will, to the greatest extent possible,
endeavour not to affect the lifting of the other Party.
5. For the avoidance of doubt each Party's agreed allocations shall be
based on Actual Production.
-66-
<PAGE> 70
Article VII
Delivery Terms and Conditions
1. Tanker Notification - The Parties shall report, or cause the tankers
nominated for lifting pursuant to this Annex D to report, by radio/telex
to the CONTRACTOR of each tanker's Schedule arrival date and hour as
follows:
(a) Seven (7) days before estimated arrival, or upon clearing at last
port if there is less than seven (7) days steaming time before
estimated arrival;
(b) Seventy-Two (72) hours before estimated arrival;
(c) Forty-eight (48) hours before estimated arrival;
(d) Twenty-four (24) hours before estimated arrival; and
(e) At any other time(s) between the seventy-two (72) hours notice,
forty-eight (48) hours notice and twenty-four (24) hours notice
when estimated arrival is to be revised by more than twelve (12)
hours from that most recently notified or after that revised by
more than one-half hour.
Parties shall also cause such tanker so nominated, or their agent, to
report by radio/telex to the Nigerian Government Port Head Official at
the port at least seventy-two (72) hours before each tanker's scheduled
arrival date giving the tanker's name, call sign, ETA at the port(s),
cargo tonnage to be loaded, number of crew, health status, whether or
not a doctor is on board and a request for "Free Pratique".
2. Notice of Readiness - Upon arrival at the designated safe anchorage at
the Port or upon the time of boarding of the Mooring master, whichever
is earlier, the Master of the tanker shall give the CONTRACTOR a Notice
of Readiness (NOR) by radio or by letter, as appropriate, confirming
that the tanker is ready to load cargo, berth or no berth. Laytime, as
herein
-67-
<PAGE> 71
provided, shall commence upon the expiration of six (6) running hours
after receipt by the Loading Terminal of such notice, or upon the
tanker's completion of mooring at the sea loading terminal, whichever
first occurs. However, where delay is caused to the tanker getting into
berth after giving NOR for any reason over which neither the CONTRACTOR
nor the loading Terminal has control, such delay shall not count as used
laytime. In addition time used by tanker while proceeding to berth or
awaiting entry and Free Pratique by customs after the expiration of six
(6) running hours free time, shall not count as used laytime.
3. Early Tanker Arrival - Notwithstanding the provisions of Article VII2
above, if the tanker arrives and tender NOR to load prior to its agreed
date range, the CONTRACTOR shall endeavor to load tanker on arrival or
as soon thereafter as possible and laytime shall only commence when
loading commences. If, however, the CONTRACTOR is unable to accept
tanker for loading prior to the agreed date range, laytime shall
commence at 0600 hours, local time on the first day of the agreed date
range or when loading commences, whichever occurs first.
4. Late Tanker Arrival - if tanker arrives and tender NOR to load after its
accepted date range and other tankers (having arrived during their
accepted date-range), are either loading or waiting to load the loading
tanker shall be governed by the earliest availability of crude and
loading slot, and laytime shall commence only when loading commences.
5. Laytime - The CONTRACTOR shall be allowed laytime in running hours equal
to one-half of the voyage laytime permitted under Worldscale, or such
other freight scale that is issued in replacement thereof, for loading a
full cargo and pro rata thereof for a part cargo, with a minimum of
eighteen (18) hours. Sundays and Holidays included, any delay due to
the fault of the tanker or its facilities to load cargo within the time
allowed shall not count as used laytime. If rules of the Owner of the
vessel or Regulations of Government or appropriate Government Agencies
prohibit loading of the cargo at any time, the time so lost shall not
count as used lay time. Time consumed loading or discharging ballast or
discharging slops shall not count as used laytime. Laytime shall
continue until hoses have disconnected.
-68-
<PAGE> 72
Laytime allowed for loading a full cargo is "36 Running Hours" with a
provision for pro-rating the laytime in the case of vessels loading part
cargo. When a vessel is loading one parcel only and operations commence
ahead of the acceptance date there is no demurrage involved unless the
vessel completes cargo after the permissible laytime, commencing 0001
hours more than one parcel and more than one acceptance date is awarded,
then demurrage will not count unless the total loading is completed
after the expiry of the permissible laytime for the last parcel,
counting 0001 hours on the last acceptance date.
6. Demurrage - If the CONTRACTOR is unable to load within the time allowed,
the CONTRACTOR shall apply demurrage per running hour (pro rata for a
part thereof) for laytime exceeding the allowed laytime as specified
herein. The rate of demurrage will be calculated by multiplying the
time by the Average Freight Rate Assessment (AFRA) as determined by the
London Tanker Brokers Panel. In the event such determination is no
longer available, a freight rate assessment shall be mutually agreed by
the Parties; which rate shall be appropriate in relation to the size of
the tanker and in demurrage rate according to tanker size as specified
in the Worldwide Tanker Nominal Freight Scale or such other foreign
scale that is issued in replacement thereof. If however, demurrage
shall be incurred by reason of fire, storm, explosion, or by strike,
picketing, lockout, stoppage or restraint or labor difficulties, or
disturbances or by breakdown of machinery or equipment in or about the
Loading Terminal, the rate of demurrage as calculated in accordance with
the above shall be governed by Force Majeure and shall not attract any
demurrage. Demurrage claims must be notified with ninety (90) days from
Bill of Lading date.
7. Changes of Berth - The CONTRACTOR shall have the right to shift any
vessel from one berth to another. Charges of running lines on arrival
at and leaving and berth; wharfage and dockage charges at that berth,
and any other extra port charges or port expenses incurred by reason of
such shifting at the CONTRACTOR's request shall be borne by the
CONTRACTOR and shall count as used laytime. If, however, it is
necessary to shift the vessel from the berth because of breakdown
machinery or other deficiency of the vessel or its crew, the resulting
expenses shall be borne by the Party whose Crude Oil is being lifted.
The time consumed in such circumstances, shall not count as used lay
time. However, the
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vessel shall lose its regular turn in berth. When the vessel is ready
to recommence loading, it shall so advise the CONTRACTOR and await its
turn for reberthing and such time after notice is given shall not count
as used laytime.
8. Tanker Departure - Tanker shall vacate the berth as soon as loading is
complete. The Party that schedule such tanker shall indemnify the
CONTRACTOR for any direct loss or damage incurred as a result of
tanker's failure to vacate the berth promptly including such loss or
damage as may be incurred due to resulting delay in the docking of the
tanker awaiting the next turn to load at such berth.
9. Loading Hoses - Hoses for loading shall be furnished by the CONTRACTOR
and shall be connected and disconnected by the tanker's crew under the
supervision of a suitable qualified Ship's Officer acting on the advise
of the Operator's Mooring Master.
10. Partial Cargo - Should the CONTRACTOR supply less than full cargo, for
any reasons the tanker shall not be required to proceed to sea until all
of her tanks are filled with a combination of cargo and ballast as will
place her in a seaworthy condition.
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Article VIII
Crude Oil Quantity And Measurement
1. Certification - The quantity and origin of each shipment of Crude Oil
shall be determined by the appropriate Government authority at the
loading Terminal and set forth in standard Certificates of Quantity,
Quality and Origin. Each Party shall have the right to designate a
representative at its own expenses, who shall have the right to witness
the determination of Quantity, Quality and Origin. All reasonable
facilities shall be supplied by the CONTRACTOR as necessary, to such
Party's representatives at the Port to enable such representatives to
witness the measurements taken at the Loading Terminal and the taking of
the sample to be used supplied to the Representative of the Party.
2. Acceptance of Certificate - If the Party in question does not appoint a
representative, or if such representative appointed as aforesaid agrees
with the Certificate of Quantity, Quality and Origin of a shipment of
Crude Oil (in which event he shall so indicate by signing the
Certificate of Quantity, Quality and Origin), such determinations shall
be final and binding on the Parties.
3. Refusal of Certificate - If the determination of Quantity, Quality and
Origin by the appropriate Government authority has not been approved by
such a representative in accordance with Article VIII 2 above and
dispute arises concerning the Quantity, Quality and Origin of Crude Oil,
recourse shall be had to a mutually agreed independent expert to resolve
the dispute on the basis of his expertise. Claims about Quantity and
Quality of Crude Oil delivered shall be notified within forty-five (45)
days from Bill of Lading date. The expert shall be selected on the
basis of his special knowledge of the subject matter in this regard and
shall be appointed by mutual agreement of the Parties. Such expert
shall file his conclusions within thirty (30) days after his date of
appointment. Any conclusions of such expert shall be binding upon
Parties. Pending the determination of the dispute, the tanker may sail,
unless the Parties agree otherwise.
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4. Quantity Determination - The quantity of Crude Oil lifted shall be
determined at the time of loading on the basis of gauging the terminal
tanks before and after the lifting of such Crude Oil, or otherwise by
meter reading installed on the loading line from the tanks, as approved
by appropriate Government Authority. The quantity in Barrels of Crude
Oil determined pursuant to the foregoing procedure shall be corrected to
a temperature of sixty degree Fahrenheit (60'F) in accordance with the
most currently published ASTM-IP Petroleum Measurement Tables. A copy
of the concession calculation, if any, shall be submitted to the Lifting
Party through it's representative. In addition, the Basic Sediment and
Water ("BS&W") content, determined in accordance with Article VII 5
hereof, shall be deducted from the quantity loaded, for purposes of
preparing the Bill or Lading for such shipment and for purposes of
substantiating claims about Quantity and Quality. Any substantiated
loss of Crude Oil occurring in transit between the point of such
determination and delivery shall be borne by the Party lifting provided
such losses do not result due to differences in method of determining
BS&W between the loading and discharge terminals. For differences
occurring where same method of determination at both points are used,
provisions of Article VIII 3 above shall apply. The retained sample
shall be used in determining such loss claims.
5. Quality Determination - The determination of API Gravity and BS&W
content shall be made of each shipment of Crude Oil. BS&W content and
API Gravity shall be determined according to standard international
practices acceptable to the relevant Government authorities.
6. Samples - A sample of each shipment of Crude Oil shall be taken. The
sample shall be sealed and retained by the CONTRACTOR for a maximum of
ninety (90) days. The lifting party or its representative shall have
the right to receive one (1) gallon sealed sample of the Crude Oil
loaded which shall be placed on board the tanker, if so requested.
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ANNEX E
To The Production Sharing Contract
Between CORPORATION and the CONTRACTOR Dated . . . . .
PROCUREMENT AND PROJECT IMPLEMENTATION PROCEDURES
Article I
Application
1.1 These Procurement and Project Implementation Procedures ("Procedures")
shall be followed and observed in the performance of either Party's
obligations under the Contract. Words and expressions defined under the
Contract, when used herein; shall have the meanings ascribed to them in
the Contract. In the event of a conflict between the terms of these
Procedures and the Contract, the terms of the Contract shall prevail.
1.2 These Procedures shall be applicable to all contracts and purchase
orders whose values exceed the respective limits set forth in Article
1.3 and which, pursuant thereto, require the prior concurrence of the
CORPORATION. These Procedures may be amended from time to time by the
Parties.
1.3 The CONTRACTOR shall have the authority, subject to any limitations or
restrictions established by the Management Committee, to enter into any
contract or place any purchase order in its own name for the performance
of services or the procurement of facilities, equipment, materials or
supplies, provided that:
(a) Prior approval of the CORPORATION shall be obtained for all
foreign contracts and foreign purchase orders awarded to third
parties where the cost exceeds two hundred and fifty thousand
U.S. Dollars ($250,000);
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(b) Prior approval of the CORPORATION shall be obtained for all local
contracts and purchase orders where the cost exceeds one million
Naira (Nl,000,000);
(c) The amounts set forth in Article 1.3(a), (b) and (h) will be
reviewed by the Management Committee whenever it becomes apparent
to either Party that such limits create unreasonable constraints
on the Petroleum Operations. In the event of a significant
change in the exchange rate of Naira to U.S. Dollar compared to
that which existed on the Effective Date, the Management
Committee shall review the limits set forth in Article 1.3(a),
(b) and (h);
(d) Such contracts shall be entered into, and such purchase orders
shall be placed with third parties, which in the CONTRACTOR's
opinion are technically and financially able to properly perform
their obligations;
(e) Procedures customary in the oil industry for securing competitive
prices shall prevail.
(f) The CONTRACTOR shall give preference to contractors that are
companies organized under the laws of Nigeria to the maximum
extent possible provided they meet the required standards.
(g) The CONTRACTOR shall give preference to such goods which are
manufactured or produced in Nigeria or services rendered by
Nigerians provided they meet specifications and standards.
(h) The above limits and these procedures shall not apply to
purchases made for warehouse replenishment stock not exceeding
two hundred and fifty thousand U.S. Dollars ($250,000) or one
million Naira (Nl,000,000) nor shall they apply to the purchase
of tubulars of less than five hundred thousand U.S. Dollars
($500,000) or two million Naira (N2,000,000) made in furtherance
of planned drilling programmes. Where there are Naira and U.S.
Dollar components of such purchases, the total shall not exceed
five hundred thousand U.S. Dollars ($500,000) or two million
Naira (N2,000,000).
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Article II
Project Implementation Procedure
2.1 The CONTRACTOR realizing the need for a project or contract to which
these Procedures apply pursuant to Article 1.3 above, shall introduce it
as part of the proposed Work Programme and Budgets to be developed and
submitted by the CONTRACTOR to the Management Committee pursuant to
Clause 6 of this Contract.
(a) The CONTRACTOR shall provide adequate information with respect to
the project including, without limitation, the following:
(i) A clear definition of the necessity and objectives of the
project;
(ii) Scope of the project; and
(iii) Cost estimate thereof.
(b) The CONTRACTOR shall transmit the project proposal along with all
related documentation to the CORPORATION for consideration.
(c) The CORPORATION may make recommendations in writing to the
CONTRACTOR regarding the selection, scope and timing of the
project. The Management Committee shall consider the proposal
and the recommendations of the CORPORATION and shall determine
the matter in accordance with Clause 6 of the Contract. Any
disputed issues shall be resolved by the Management Committee
pursuant to Clause 6.4(d) of the Contract. If the CORPORATION
does not submit any recommendations in writing to the CONTRACTOR
within thirty (30) working days of the submittal of the project,
the project as proposed by the CONTRACTOR shall be deemed
approved by the Management Committee and shall be so noted in the
minutes of the next meeting.
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<PAGE> 79
2.2 The project as approved pursuant to Article 2.1 above shall form part of
the Work Programme and Budget of the Petroleum Operations. Such
approval shall also constitute authorizations by the Management
Committee to the CONTRACTOR to initiate contracts and purchases relevant
to the project proposal, subject to the provisions of Article 1.3.
2.3 The resources for the project design, supervision, and management shall
first be drawn from the CONTRACTOR's available in-house expertise. If
the Management Committee approves, such may be performed by the
CONTRACTOR's Affiliate under the approved budget for the project.
Competent Nigerian Engineering/Design companies shall be given priority
over others by the Management Committee for such projects. The
CORPORATION staff who shall be seconded pursuant to Clause 12.4 of this
Contract shall be fully involved in the project design, supervision and
management.
2.4 After approval of the project/budget, the CONTRACTOR shall prepare and
transmit to the CORPORATION complete details of the project including,
without limitation, the following:
(a) Project definition;
(b) Project specification;
(c) Flow diagrams;
(d) Projects implementation schedule showing all phases of the
project including, without limitation, engineering design,
material/equipment procurement, inspection, transportation,
fabrication/construction, installation, testing and
commissioning;
(e) Major equipment specifications;
(f) Cost estimate of the project;
(g) An activity status report; and
(h) Copies of all approved CONTRACTOR's Authority for Expenditure
(AFEs).
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<PAGE> 80
Article III
Contract Tender Procedure
3.1 The following tender procedure shall apply to work/services/supply not
directly undertaken by the CONTRACTOR or by the CONTRACTOR's Affiliate:
(a) The CONTRACTOR shall maintain a list of approved contractors for
the purposes of contracts for the Petroleum Operations, (the
"Approved Contractors' List"). The CORPORATION shall have the
right to nominate contractors to be included/deleted in the list.
The CORPORATION and the CONTRACTOR shall be responsible for
pre-qualifying any contractor to be included in the Approved
Contractors' List.
(b) Contractors included in the Approved Contractors' List shall be
both local and/or overseas contractors or entities. Where
regulations require, they shall be registered with the Petroleum
Resources Department of the Ministry of Petroleum and Mineral
Resources.
(c) When a contract is to be bid, the CONTRACTOR shall present a list
of proposed bidders to the CORPORATION for concurrence not less
than fifteen (15) working days before the issuance of invitations
to bid to prospective contractors. The CORPORATION may propose
additional names to be included in the list of proposed bidders
or the deletion of any one thereof. Contract specifications
shall be in English and in a recognized format used in the
international petroleum industry.
(d) If the CORPORATION has not responded within fifteen (15) working
days from the date of the official receipt following the
presentation of the list of proposed bidders as aforesaid, the
list shall be deemed to have been approved.
3.2 The CONTRACTOR shall within its limits in Article 1.3(a), (b) and (h)
establish a Tender Committee who shall be responsible for pre-qualifying
bidders, sending out bid invitations,
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receiving and evaluating bids and determining successful bidders to whom
contracts shall be awarded.
3.3 Analyses and recommendations of bids received and opened by the Tender
Committee shall be sent by the CONTRACTOR to the CORPORATION for
approval before a contract is signed with the selected contractor. The
CORPORATION shall respond within fifteen (15) working days from the date
of official receipt. Approval of the CONTRACTOR's recommendations shall
be deemed to have been given if the CORPORATION has not responded within
the said period.
3.4 Prospective vendors/contractors for work estimated in excess of two
hundred and fifty thousand U.S. Dollars ($250,800) shall submit the
commercial summary of their bids to the CONTRACTOR in two properly
sealed envelope, one addressed to the CONTRACTOR and one addressed to
the CORPORATION. The CONTRACTOR shall retain one and send one to the
CORPORATION, properly enveloped, sealed and addressed to CORPORATION.
3.5 In all cases in which an offshore contractor or its Nigerian Affiliate
is invited to bid, the CONTRACTOR shall make full disclosure to the
CORPORATION of its relationship, if any, with such contractors.
3.6 These Procedures may be waived and the CONTRACTOR may negotiate directly
with the contractor and promptly inform the CORPORATION of the outcome
of such negotiations in the following cases:
(a) emergency situations; and
(b) in work requiring specialized skills, or when special
circumstances warrant, upon the approval of the CORPORATION.
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Article IV
General Conditions of Contracts
4.1 The payment terms shall provide, without limitation, that:
(a) A minimum of 10% of contract price shall be held as a retention
fee until after the end of a guarantee period agreed with the
contractor which shall vary between six months and twelve months,
depending on the project, with the exception of drilling and
seismic data acquisition, well surveys and other such services;
provided that, a contractor may be given the option to provide
other guarantee equivalent to the 10% retention such as Letter of
Credit or Performance Bond; and
(b) Provisions shall be made for appropriate withholding tax as may
be applicable.
4.2 The language of all contracts shall be English.
4.3 (a) The governing law of all agreements signed with contractors shall
be Nigerian law for work to be conducted in Nigeria and to the
extent feasible, for work outside Nigeria.
(b) Nigerian law shall apply to contractors performing in Nigeria
and, as far as practicable, they shall use Nigerian resources
both human and material.
(c) All contracts shall include a provision whereby the contractor
shall hold the CONTRACTOR harmless and indemnify the CONTRACTOR
from and against all liabilities, losses, damages and claims
resulting from claims and suits by third parties.
4.4 Each contract shall provide for early termination upon notice and the
CONTRACTOR shall use all reasonable endeavours to obtain a termination
provision with minimal penalty.
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<PAGE> 83
4.5 Contractors shall provide, in the case of a foreign contractor, that the
local part of the work, in all cases, shall be performed by contractor's
local subsidiary.
Article V
Materials and Equipment Procurement
5.1 The CONTRACTOR may, through own in-house or parent company procure
materials and equipment subject to conditions set forth in this Article
5.
5.2 The provisions of this Article 5 shall not apply to lump sum or turnkey
contracts/projects.
5.3 In ordering the equipment/materials, the CONTRACTOR shall obtain from
vendors/manufacturers such rebates/discounts and such
warranties/guarantees that such vendors/manufacturers normally offer,
and all rebates, discounts, guarantees and all other grants and
responsibilities shall be for the benefit of the Petroleum Operations.
5.4 The CONTRACTOR shall:
(a) By means of established policies and procedures ensure that its
procurement efforts provide the best total value, with proper
consideration of quality, service, price, delivery and Operating
Costs to the benefit of the Petroleum Operations;
(b) Maintain appropriate records, which shall be kept up to date,
clearly documenting procurement activities;
(c) Provide quarterly and annual inventory of materials in stock;
(d) Provide a quarterly listing of excess materials in its stock list
to the CORPORATION; and
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<PAGE> 84
(e) Check the excess materials listings from other companies, to
identify materials available in the country prior to initiating
any foreign purchase order.
5.5 The CONTRACTOR shall initiate and maintain policies and practices which
provide a competitive environment/climate amongst local and/or overseas
suppliers. Competitive quotation processes shall be employed for all
local procurement where the estimated value exceeds the equivalent of
one hundred thousand U.S. Dollars ($100,000).
(a) Fabrication, wherever practicable shall be done locally. To this
effect, the Petroleum Operations recognize and shall accommodate
local offers at a premium not exceeding 10%
(b) Subject to Article 3.1(a), the CONTRACTOR shall give preference
to Nigerian indigenous contractors in the award of contracts.
Contracts within the agreed financial limit of the CONTRACTOR
shall be awarded to only competent Nigerian indigenous
contractors. Where there are no Nigerian indigenous contractors
possessing the required skill/capability for the execution of
such contracts, the CONTRACTOR shall notify the CORPORATION
accordingly.
5.6 Analyses and recommendations of competitive quotations of a value
exceeding the limits established in Article 1.3 shall be transmitted to
the CORPORATION for approval before a purchase order is issued to the
selected vendor/manufacturer. Approval shall be deemed to have been
given if a response has not been received from the CORPORATION within
fifteen (15) working days of receipt by the CORPORATION of the said
analyses and recommendations.
5.7 Pre-inspection of rig, equipment/stock materials of reasonable value
shall be jointly carried out at factory site and quay before shipment at
the request of either Party.
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<PAGE> 85
Article VI
Project Monitoring
6.1 The CONTRACTOR shall provide a project report monthly to the
CORPORATION.
6.2 For major projects exceeding two hundred and fifty thousand U.S. Dollars
($250,000) or equivalent, the CONTRACTOR shall provide to the
CORPORATION a detailed quarterly report which shall include:
(a) Approved budget total for each project;
(b) Expenditure on each project;
(c) Variances and explanations;
(d) Number and value of construction change orders;
(e) Bar chart of schedule showing work in progress and work already
completed and schedule of mile-stones and significant events; and
(f) Summary of progress during the reporting period, summary of
existing problems, if any, and proposed remedial action,
anticipated problems, and percentage of completion.
Provided that the CORPORATION shall have the right to send its own
representatives to assess the project based on the report.
6.3 In the case of an increase in cost in excess of 10% on the project, the
CONTRACTOR shall promptly notify the CORPORATION and obtain necessary
budget approval.
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6.4 Not later than six (6) months following the physical completion of any
major project whose cost exceeds two hundred and fifty thousand U.S.
Dollars ($250,000) or equivalent, the CONTRACTOR shall prepare and
deliver to the CORPORATION a project completion report which shall
include the following:
(a) Cost performance of the project in accordance with the work
breakdown at the commencement of the project;
(b) Significant variations in any item or sub-items;
(c) Summary of problems and unexpected events encountered during the
project; and
(d) List of excess project materials.
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ANNEX F
MEMORANDUM OF UNDERSTANDING
ON OPLS 98 AND 118
BETWEEN
THE FEDERAL MILITARY GOVERNMENT OF THE FEDERAL
REPUBLIC OF NIGERIA
AND
ASHLAND OIL (NIGERIA) COMPANY
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<PAGE> 88
MEMORANDUM OF UNDERSTANDING
ON INCENTIVES FOR ENCOURAGING INVESTMENTS INI EXPLORATION AND
DEVELOPMENT ACTIVITIES AND ENHANCING CRUDE OIL EXPORTS
THIS MEMORANDUM OF UNDERSTANDING is made the ___ day of ______, 1991, BETWEEN
THE FEDERAL MILITARY GOVERNMENT OF THE FEDERAL REPUBLIC OF NIGERIA,
("Government"), represented by the Honorable Secretary of Petroleum Resources
and Ashland Oil (Nigeria) Company, a company incorporated under the laws of
Nigeria whose registered office is at 10 Bishop Aboyade Cole St., Victoria
Island, Lagos ("Ashland").
WHEREAS:
(i) Government and Ashland entered into a MEMORANDUM OF UNDERSTANDING
ON INCENTIVES FOR ENHANCING CRUDE OIL EXPORTS AND ENCOURAGING
INVESTMENTS IN EXPLORATION AND DEVELOPMENT ACTIVITIES (the
"Memorandum of Understanding") effective 1st January, 1986.
(ii) Some matters in the Memorandum of Understanding were more
particularly detailed in the Side Letter dated 17th of January,
1986, which also formed part of the Memorandum of Understanding.
(iii) Government and Ashland reviewed the Memorandum of Understanding
and the Side Letter and agreed to a "First Amendment" effective
1st October, 1986.
(iv) Government and Ashland further reviewed the Memorandum of
Understanding and the Side Letter and agreed to a "Second
Amendment" effective 1st July, 1987.
(v) Some Platt's product price quotations used in determining Price
were updated in letters (dated l9th October 1988 and 27th July
1990) from the Nigerian National Petroleum Corporation ("NNPC").
(vi) Government and Ashland have further reviewed the Memorandum of
Understanding and the aforementioned Side Letters and amendments
and have mutually agreed to consolidate them into this
Memorandum.
(vii) Ashland is conducting Petroleum Operations under the Production
Sharing Contract between NNPC and Ashland dated 12th June 1973,
as amended to date ("PSC").
(viii) Ashland has thoroughly explored all of the acreage within the
area (OPLs 98 and 118) covered by the PSC and has fully developed
all commercial oil fields discovered as a result thereof.
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NOW THEREFORE, the parties hereby agree as follows:
1.1 The said Memorandum of Understanding dated 17th January, 1986
together with the Side Letter and the amendments referred to in
the above recitals hereto are hereby terminated and are replace
and superseded in their entirety by this Memorandum of
Understanding ("this Memorandum").
1.2 The fiscal regime currently applicable to the oil industry is
modified to ensure that the industry realizes not less than the
profit margin established pursuant to Clauses 2.4, 2.5 and 2.6
herein.
l.3 The terms and conditions set forth in Clauses 2 to 5 of this
Memorandum shall form part of the new fiscal regime.
2. Incentives
2.1 Prior to the instruction of the incentives described in this
Memorandum, the fiscal regime existing at 31st December 1985,
provided for computations of Royalty on Posted Price and
Petroleum Profit Tax ("PPT") on the higher of actual proceeds
(Section 9) or Posted Prices (Section 17A), of the Petroleum
Profits Tax Act 1959 and its amendments ("PPT Act").
2.2 Except as otherwise specified in Clause 2.6, it is intended by
the incentives described in this Memorandum to accord a minimum
Guaranteed Notional Margin of $2.30/bbl, aL.ter payment of the
PPT and Royalty as provided under the PSC. However, this minimum
Guaranteed Notional Margin shall be premised on the fact that the
technical cost of operations does not exceed the Notional Fiscal
Technical Cost which, at present, is $2.50/bbl.
2.3 It is further intended that when in any one calendar year
Ashland's actual expenditure on Capital Investment Costs defined
as T2 in Appendix l is equal to or exceeds $1.50/bbl on average
then the minimum Guaranteed Notional Margin specified in Clause
2.2 shall be increased to $2.50/bbl. Furthermore in this
circumstance, the Notional Fiscal Technical Cost shall be
increased to $3.50/bbl.
2.4 For the purpose oL. this Memorandum, Government Take (Royalty and
PPT) relating to the PSC for any fiscal accounting year shall be
the lower oL. Government Take according to the 31/12/1985 Royalty
and PPT regulations calculated by substitution of Official
Selling Price ("OSP") for Posted Price and the Revised Government
'Take ("RGT") calculated per the of offset pricing formula below:
RGT = OP-(TR x TC) -OT
Where:
RGT = Revised Government Take
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<PAGE> 90
OP = Offset Price = B x RP
RP = Realizable Price Calculated in accordance with
Clauses 2.12, 2.13, and 2.14 hereof to
determine/mirror the crude oil market values of
Nigerian export grades.
B = K [(1-Roy) x TR +Roy)
K = Factor of 1.0042 when the minimum Guaranteed
Notional Margin is $2.30/bbl.
Factor of O.9869 when the minimum Guaranteed
Notional Margin is $2.50/bbl.
Roy = Royalty Rate
TR = Applicable Tax Rate
TC = Deductions under Sections 10, 14 and 15 (excluding
royalty) of the PPT Act.
TO = Offsets under Section 17 of the PPT Act.
2.5 For Realisable Prices below $23/bbl, the K-Factors specified
under Clause 2.4 shall be substituted by the undernoted
self-adjusting mechanism for the determination of the K-Factor
which shall be applied to restore the desired Guaranteed Notional
Margin:
K = 1.1364 (1 - M + 0.15 FC )
-----------
RP
Where:
M = Guaranteed Notional Margin
FC = Notional Fiscal Technical Cost
Therefore when M is $2.30/bbl:
K = 1.1364 (1 - $2.30 + 0.15 [$2.50] )
--------------------
RP
and, when M is $2.50/bbl
K = 1.1364 (1 - $2.50 + 0.15 [$3.50] )
--------------------
RP
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2.6 The following mechanism shall be applied for establishing the
Guaranteed Notional Margin for Realisable Prices less than
$12.50/bbl:
M = (1 - FC ) (RP(1) a(1) + RP(2) a(2) + RP(3) a(3))
--
RP
Where:
M = Guaranteed Notional margin (presently $2.30/bbl
subject to Clause 2.3)
RP = Realisable Price
FC = Notional Fiscal Technical Cost (presently $2.50/bbl
subject to Clause 2.3)
a = Ashland's Percentage share of field profit.
For:
<TABLE>
<CAPTION>
Realisable Price Ashland Share Applicable
in the Range to Price Range
---------------- -------------------------
<S> <C>
0 less than RP(1) less than a(1) = 0.30 = 0.365
or equal to $5/bbl
$5/bbl less than RP(2) less a(2) = 0.22 = 0.263
than or equal to $10/bbl
$10/bbl less than RP(3) less a(3) = 0.11 = 0.131
than or equal to $12.50/bbl
</TABLE>
For worked examples refer to Appendix 2.
2.7 The K-Factors specified under Clauses 2.4 and 2.5 shall remain in
force until amended by the Minister of Petroleum Resources. It
is intended that such amendment shall only be necessary when
Realisable Price exceeds $30/bbl for at least 45 days
continuously. If the Realisable Price returns below $30/bbl, the
K-Factors will return automatically to the levels specified in
Clauses 2.4 and 2.5 as appropriate.
2.8 The Parties agree that, since Ashland has thoroughly explored all
of the said areas covered by the PSC and has fully developed all
oil fields which are commercial under the terms of the PSC,
further investment in such areas for exploration and/or
development is not viable for Ashland and, therefore, the
incentives known as the Capital Investment Cost Tax Offset and
the Reserves Addition Bonus, which were provided to the oil
industry under the Memorandum of Understanding agreements signed
in 1991 shall not be applicable to Ashland under this Memorandum;
provided however, that if circumstances change (such as the PSC
is extended beyond 12 June 1993) and Ashland undertakes further
investment, as approved by NNPC, under the PSC, then this
Memorandum shall be amended to provide that the aforementioned
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incentives stated in this Clause 2.8 shall be extended to
Ashland, and in addition, the values of M = $2.50/bbl and FC =
$3.50/bbl shall apply to Ashland when T2 is equal to or greater
than $1.50/bbl.
2.9 To the extent that in any one calendar year the actual technical
cost of operations exceeds $3.50/bbl on average and such excess
arises due to Capital Investment Costs (T2 as defined below)
equaling or exceeding $1.50/bbl, Ashland shall be entitled to a
tax offset against its PPT liability for that year. This offset
shall be:
10% x (LIBOR + 1%) x (0.80 x T(2))
Where
LIBOR = The average Financial Times London Inter
Bank Fixing Offer Rate for 3 month US
Dollars as quoted in the London Financial
Times on 1 January, 1 April, 1 July and 1
October or the next succeeding quotation
day.
T(2) = Deductions under Sections 10, 14 and 15
(excluding Royalty and Production Operating
Expenses) of the PPT Act.
2.10 To the extent that in any one year that additions to oil and
condensate Ultimate Recovery ("UR") exceed the production for
that year, then Ashland shall be entitled to a "Reserves Addition
Bonus" in the form of an offset against its PPT liability for the
year. For the purpose of estimating the "Reserves Addition
Bonus", UR shall be the sum of proven and probable crude oil and
condensate Ultimate Recovery. UR shall be determined in a manner
acceptable to the Department of Petroleum Resources and such UR
shall be as confirmed by Honourable Minister of Petroleum
Resources. The "Reserves Addition Bonus" shall be calculated for
each year in tranches determined by reference to the
addition/production ratio ("R");
R = ([UR at end year] - [UR at start of year])
----------------------------------------
Annual Production
For:
<TABLE>
<CAPTION>
Incremental Addition/ Bonus Rate Per
R in the Range Production Ratio Incremental Barrel
------------------------------------------- ------------------------------- --------------------
<S> <C> <C>
1.0 less than R less than or equal to 1.25 Ra(1) = R - 1.00 X(1) = $.10/bbl
1.25 less than R less than or equal to 1.50 Ra(1) = 0.25 and X(2) = $0.25/bbl
Ra(2) = R - 1.25
1.50 less than R less than or equal to 1.75 Ra(1) = Ra(2) = 0.25 X(3) = $0.40/bbl
and Ra(3) = R - 1.50
R greater than 1.75 Ra(1) = Ra(2) = Ra3 = 0.25 X(4) = $0.50/bbl
and Ra(4) = R - 1.75
</TABLE>
For purposes of calculating Reserves Addition Bonus
herein, the formula below shall apply:
-89-
<PAGE> 93
Bonus = [Ra(1) X(1) + Ra(2) X(2) Ra(3) X(3) + Ra(4) X(4)]P
Where:
P = Annual Production
X = Bonus rates for various values of R
UR = Ultimate Recovery which is defined as the total
volume of crude oil and condensate recovered and to
be recovered over the life time of the field
For worked examples see Appendix 2.
In the event that in any one calendar year there is a downward
revision to the total oil and condensate Ultimate Recovery, to
the extent that the downward revision represents an adjustment to
Ultimate Recovery on which Ashland had received "Reserves
Additions Bonus" in previous years, Government shall have the
right to require Ashland to recalculate the "Reserves Additions
Bonus" in respect of those years. Ashland shall immediately pay
to Government any additional PPT liability arising from the
recomputation of the "Reserves Additions Bonus" and the related
tax offsets.
2.11 RGT will be calculated in Naira each month (under the terms
outlined in this Memorandum) and compared for the same volume of
exports with Government Take for the same month under the terms
of the present (31/12/85) Royalty and PPR regulations. Identical
rates of exchange will be used to convert U.S. Dollar prices to
Naira in both Government Take and RGT calculations. The amount
by which RGT is less than Government Take each month will be
accumulated and at the end of the fiscal accounting year will be
applied as the annual tax credit to be offset against PPT due for
that fiscal accounting period.
2.12 For the purpose of the RGT formula, the terms and conditions of
Appendix A (attached to and forming part of this Memorandum)
including yield percentages of the three crude streams (Bonny
Light, Forcados, Bonny Medium), weighted for each of the primary
market areas as defined in Clause 2.13, shall be mutually agreed
for a 6 month period determined 3 months in advance. Thus the
terms and conditions of Appendix A applicable to the respective
market for the period 1st October through 31st March, will be
determined on or before the preceding 1st July, and for the
period 1st April through 30th September, on or before the
preceding 1st January. If there is no mutual agreement, the
terms and conditions of Appendix A applicable to the preceding
year and for the same 6 month period will prevail.
2.13 Appendix A shows the basis for determining the Realizable Price
f.o.b. Nigeria ("RP"). The c.i.f. value for each of the crude
streams shall be calculated monthly by utilizing the agreed
product yield and the average of mid-range product prices quoted
each quotation day for the period 1st to 20th day of the month of
lifting in Platt's
-90-
<PAGE> 94
Oilgram Price Report published by McGraw-Hill Inc. ("Platt's")
for each of the following markets viz: cargoes c.i.f. North-West
Europe basis ARA, cargoes c.i.f. Mediterranean basis Genoa/Lavera
(or if not quoted cargoes f.o.b. basis Italy) and US Gulf Coast
waterborne. In the USGC, L.P.G. will be priced at Platt's
quotation for Mont Belvieu Gas Liquids. Specific adjustments for
freight, ocean loss, insurance, and processing cost applicable to
each primary market shall be deducted in the calculation of the
Net Back Value ("NBV") Portion of the RP. The final NBV Portion
of the RP shall be determined by comparing the NBV so calculated
with the average of the appropriate crude oil quotations as
published in Platt's effective for each quotation day for the
period 1st to 20th (inclusive) of the same month. The NBV shall
be limited to a range of plus or minus 40 (forty) US cents per US
barrel around the prices of BBQ, Forcado Blend and Bonny Medium
through the following mechanism, where:
A: Initial NBV
B: Average Crude Oil Price (Bonny Light = Platt's BBQ;
Forcados = Platt's Forcados; and Bonny Medium = Platt's
BBQ - $1.20/bbl)
The Final NBV is equal to F2 as follows:
F1: The greater of (B-40c./bbl) and A
F2: The lesser of (B+40c./bbl) and F1
2.14 The Final NBV resulting from Clause 2.13 will be averaged with
crude oil price quotations to determine RP for each crude stream
as follow. Such RP for any month shall be deemed as the RP for
that month's lifting.
Bonny Light: The Final NBV for any month, calculated on the
basis of Appendix A, plus the average of mid range quotations for
BBQ crude oil in Platt's for each quotation day for the period
1st to 20th of the same month less $0.25/bbl, the whole divided
by two.
Bonny Medium: The Final NBV for any month, calculated on the
basis of Appendix A, plus the average of mid-range quotations for
BBQ crude oil in Platt's for each quotation day for the period
1st to 20th of the same month less $1.45/bbl the whole divided by
two.
Forcados: The Final NBV for any month, calculated on the basis
of Appendix A, plus the average of mid-range quotations for
Forcados crude oil in Platt's for each quotation day for the
period 1st to 20th of the same month less $0.25/bbl, the whole
divided by two.
3. Conditions
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<PAGE> 95
In consideration of the incentives granted herein by the Government,
Ashland undertakes to market all NNPC's Lifting Allocations (as defined
in the PSC) subject to NNPC's right to revoke such authority as provided
under Clause 5 of the PSC.
4. Non-Performance
4.1 Where, however, Ashland is unable to lift all or part of NNPC's
Lifting Allocation as defined and provided under the PSC, Ashland
agrees to pay to NNPC 2% of the average RP (for the quarter of
default) for each barrel not lifted. This payment will be made
in U.S. dollars or as may be directed by the Government and shall
not be considered as Operating Cost or be taken into account in
respect of year-end adjustment of cost or treated as a cost
allowance for the calculation of PPT.
4.2 In the event of force majeure, as defined in Clause 6, the
provision of Clause 4.1 shall not apply. If any restriction is
placed on the importation of crude oil including tariff barriers
or other relevant restrictions on trade which to the knowledge of
both parties affect Ashland's ability to dispose of Nigerian
Crude Oil, the parties agree to meet to discuss an equitable
solution.
5. Agreement of Government Agencies
Government confirms that the terms of this Memorandum have been agreed
by the appropriate Government Ministries in Nigeria including the
Ministry of Finance, the Federal Inland Revenue Department, and the
Central Bank of Nigeria. In consequence, Government guarantees to
Ashland that no penalties, fines or other imposts including costs of
litigation and/or defense of the fiscal and foreign exchange
arrangements included in this Memorandum shall be imposed upon Ashland
by reason of compliance with this Memorandum.
6. Force Majeure
No failure or omission to carry out or to observe any of the terms,
provisions or conditions of this Memorandum shall, except as is herein
expressly provided to the contrary, give rise to any claim by one party
hereto against the other or be deemed to be a breach of this Memorandum,
if such failure or omission arises from any cause reasonably beyond the
control of either party. Such cause may be but is not limited to, any
act, event, happening, or occurrence due to natural causes, breakdown of
vessels or machinery and equipment, civil unrest, strikes, lock-outs or
labor disputes, war, battle and commotion, or action of any relevant de
facto government. The rights of both parties shall be adjusted and to
the extent of their performance up to the time of the relevant event as
is reasonable in normal commercial practice and practicable in the
particular circumstances. As soon as practicable after the supervening
circumstances, the obligations under this Memorandum shall be resumed by
both parties as if there had been no interruption. Either party
claiming to be affected by such event shall give immediate notice in
writing of such claims to the other party giving full particulars
thereof and furthermore shall give immediate notice in writing of the
cessation of any such event.
-92-
<PAGE> 96
7. Effective Date
This Memorandum shall become effective from the 1st day of January 1991.
Ashland may terminate this Memorandum having given one year's prior
notice to NNPC to withdraw.
8. Appendices
Appendices 1, 2(a & b), 3 and A (including Attachment 1) attached hereto
form part of this Memorandum.
-93-
<PAGE> 97
AS WITNESS the hands of the duly authorized representatives of the Parties the
day and year first above written.
THE FEDERAL MILITARY GOVERNMENT
OF THE FEDERAL REPUBLIC OF NIGERIA
By: /s/ CHIEF P. C. ASIODU
-----------------------------------------------------------------------------
Name: CHIEF P. C. ASIODU
Designation: Honorable Secretary of Petroleum & Mineral Resources
IN the presence of:
Name:
---------------------------------------------------------------------------
Signature:
----------------------------------------------------------------------
Designation:
--------------------------------------------------------------------
Address:
------------------------------------------------------------------------
-------------------------------------------------------------------------
SIGNED for an on behalf of
ASHLAND OIL (NIGERIA) COMPANY
By: /s/ BRADLEY W. FISCHER
-----------------------------------------------------------------------------
Name: BRADLEY W. FISCHER
---------------------------------------------------------------------------
Designation: Managing Director
IN the presence of
Name: Mrs. Dorothy O. Atake
---------------------------------------------------------------------------
Signature: /s/ Dorothy O. Atake
----------------------------------------------------------------------
Designation: Senior Liaison Officer
--------------------------------------------------------------------
Address: Ashland Oil (Nigeria) Company Unlimited
------------------------------------------------------------------------
10, Bishop Aboyade, Cole Street, Victoria Island, Lagos
-------------------------------------------------------------------------
-94-
<PAGE> 98
APPENDIX 1
PROCEDURE ON THE CALCULATION OF TECHNICAL COST PER BARREL
WITH REFERENCE TO THE MEMORANDUM OF UNDERSTANDING ON
INCENTIVES BETWEEN THE FEDERAL MILITARY GOVERNMENT
OF THE FEDERAL REPUBLIC OF NIGERIA
AND COMPANY - CLAUSE 2.3
The following expenses and costs reported by Company for the purposes of cost
recovery pursuant to the PSC during the period January/December of the year of
lifting shall be included in calculating the actual production cost per barrel
for the purpose of this Memorandum of Understanding.
(a) Production Operating Expenses: T(1)
(i) Direct Reproduction Expenses as per items 400 and 401 of Report
No. 002 of Account Reporting Manual.
(ii) Portion of Administrative and General Expenses allocated to
Production - refer item 402 of Report No. 002 of Accounts
Reporting Manual.
(iii) Custom Duties and Gross Rentals allocated to Production - refer
items 4043 and 4045 of Report No. 002 of the Accounts Reporting
Manual.
(iv) Extra Ordinary/Prior Year Expenses/Incomes - refer item 405 of
Report No. 002 Accounts Reporting Manual.
(b) Capital Investment Costs which qualify for expensing for PPT calculation
and chargeable to Production Costs: T(2)
(i) Exploration Drilling Costs.
(ii) Appraisal Drilling Cost (1st and 2nd Wells).
(iii) Intangible Drilling and Development Costs.
(iv) Capital Allowances - shall be restricted to the capital
allowances applicable direct to production and a share of the
capital allowances on overhead assets allocated to production.
Such Capital Allowance should be reconciled with the Allowances
claimed for the year under Section 15 of the PPTA.
(c) It is expected that the Production Operating Expenses and Capital
Investment Costs above will be reconciled by Company with Report Nos.
002 and 001 of the Accounts Reporting Manual respectively.
-95-
<PAGE> 99
(d) The recommended basis for allocation of Expenses and Costs in a(ii),
a(iii) and a(iv) above to production shall be:
P
---------
E + P + X
Where:
P = The additions to the Capital costs during the year and the
Operating expenses for the year reported by Ashland for
the purposes of cost recovery pursuant to the PSC which
are directly related to the production function.
E = The additions to the Capital costs during the year and the
Operating expenses for the year reported by Ashland for
the purposes of cost recovery pursuant to the PSC which
are directly related to the exploration function.
X = Any other expenditures other than Production and
Exploration functions which are reported by Ashland for
the purposes of cost recovery pursuant to the PSC.
(a) (i) to (iv) + (b) (i) to (iv)
(e) Production Cost Per Barrel = ----------------------------------
Annual Production (Barrels)
(f) The advice on cost per barrel forwarded to NNPC should be supported with
a working paper.
-96-
<PAGE> 100
APPENDIX 2 (a)
WORKED EXAMPLES FOR ESTABLISHING THE GUARANTEED NOTIONAL
MARGIN FOR R.P. LESS THAN $12.5/bbl - CLAUSE 2.6
WHERE FC = $2.50/BBL
1.) If RP = $4
RP(1) = $4
a(1) = 0.30
and FC = $2.5
Margin M = (1 - 2.5) x (4 x 0.30)
---
4
= 0.375 x 1.2
M = $0.45
===================
2.) If RP = $9
RP(1) = $5
a(1) = 0.30
RP(2) = $4
a(2) = 0.22
M = (1 - 2.5) x (5 x 0.30 + 4 x 0.22)
---
9
= 0.722 x 2.38
M = $1.719
====================
3.) If RP = $11
RP(1) = $5
a(1) = 0.30
-97-
<PAGE> 101
RP(2) = $5
a(2) = 0.22
RP(3) = $1
a(3) = 0.11
and M = (1 - 2.5) x (5 x 0.30 + 5 x 0.22 + 1 x 0.11)
---
11
= 0.7727 x 2.71
M = $2.094
====================
4.) If RP = $12.50
RP(1) = $5
a(1) = 0.30
RP(2) = $5
a(2) = 0.22
RP(3) = $2.50
a(3) = 0.11
and M = (1 - 2.5) x (5 x 0.30 + 5 x 0.22 + 2.5 x 0.11)
-----
12.50
= 0.80 x 2.875
M = $2.30
===================
-98-
<PAGE> 102
APPENDIX 2(b)
WORKED EXAMPLES FOR ESTABLISHING THE GUARANTEED
NOTIONAL MARGIN R.P. LESS THAN $12.5/bbl - CLAUSE 2.6
WHERE FC = $3.50/BBL
1.) If RP = $4
RP(1) = $4
a(1) = 0.365
and FC = $3.5
Margin M = (1 - 3.50) x (4 x 0.365)
----
4
= 0.125 x 1.46
M = $0.1825
2.) If RP = $9
RP(1) = $5
a(1) = 0.365
RP(2) = $4
a(2) = 0.263
M = (1 - 3.50) x (5 x 0.365 + 4 x 0.263)
----
9
= 0.611 x 2.877
M = $1.758
3.) If RP = $11
RP(1) = $5
a(1) = 0.365
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<PAGE> 103
RP(2) = $5
a(2) = 0.263
RP(3) = $1
a(3) = 0.131
and M = (1 - 3.50) x (5 x 0.365 + 5 x 0.263 + 1 x 0.131)
----
11
= 0.6818 x 3.271
M = $2.23
====================
4.) If RP = $12.50
RP(1) = $5
a(1) = 0.365
RP(2) = $5
a(2) = 0.263
RP(3) = $2.50
a(3) = 0.131
and M = (1 - 3.50) x (5 x 0.365 + 5 x 0.263 + 2.5 x 0.131)
-----
12.50
= 0.72 x 3.4675
M = $2.50
===================
-100-
<PAGE> 104
APPENDIX 3
WORKED EXAMPLES ON COMPUTATION OF RESERVES
ADDITION BONUS
1.) Take UR End Year = 640 million barrels
UR Begin Year = 400 million barrels
Annual Production = 200 million barrels
R = 640 - 400
-----------------
200
= 1.2
Ra(1) = 0.2
X(1) = $0.10/bbl
.'. Bonus = [Ra(1) X(1)] P
= [(0.2) (0.10)] x 200
= US$4.0 million
==============
2.) Take UR End Year = 700 million barrels
UR Begin Year = 400 million barrels
Annual Production = 200 million barrels
R = 700 - 400
-----------------
200
= 1.5
Ra(1) = 0.25
Ra(2) = 0.25
X(1) = $0.10/bbl
X(2) = $0.25/bbl
-101-
<PAGE> 105
.'. Bonus = [(Ra(1) X(1)) + (Ra(2) X(2))] P
= [(0.25) (0.10) + (0.25) (0.25)] x 200
= US$17.5 million
===============
3.) Take UR End Year = 740 million barrels
UR Begin Year = 400 million barrels
Annual Production = 200 million barrels
R = 740 - 400
-----------------
200
= 1.7
Ra(1) = 0.25
Ra(2) = 0.25
Ra(3) = 0.20
X(1) = $0.10/bbl
X(2) = $0.25/bbl
X(3) = $0.40/bbl
.'. Bonus = [Ra(1) X1(1) + Ra(2) X(2) + Ra(3) X(3) ] P
= [(.25) (.10) + (.25) (.25) + (.20) (.40)] x 200
= US$33.5 million
===============
4.) Take UR End Year = 900 million barrels
UR Begin Year = 400 million barrels
Annual Production = 200 million barrels
R = 900 - 400
-----------------
200
-102-
<PAGE> 106
= 2.5
Ra(1) = 0.25
Ra(2) = 0.25
Ra(3) = 0.25
Ra(4) = 0.75
X(1) = $0.10/bbl
X(2) = $0.25/bbl
X(3) = $0.40/bbl
X(4) = $0.50/bbl
.'. Bonus = [Ra(1) X(1) + Ra(2) X(2) + Ra(3) X(3) + Ra(4) X(4)]P
= [(.25) (.10) + (.25) (.25) +
(.25) (.40) + (.75) (.50)] x 200
= US$112.5 million
================
-103-
<PAGE> 107
APPENDIX A
CALCULATION OF REALIZABLE PRICE
The market weighted FOB Nigeria Net Back Value ("NBV") for the purpose
of calculating Realizable Price under this Memorandum shall be calculated from
the data given below and in accordance with the worked example shown in
Attachment 1 to this Appendix A.
1. Delivery Each export grade of crude oil will be deemed delivered to:
U.S. Gulf Coast (USGC) 60 per cent
North West Europe (NWE) 20 per cent
Mediterranean (MED) 20 per cent
2. Grades The export grades of crude oil are:
Bonny Light of standard export gravity 37 degrees API
Forcados Blend of standard export gravity 31 degrees "
Bonny Medium of standard export gravity 26 degrees "
Qua Iboe Light of standard export gravity 37 degrees "
Escravos Light of standard export gravity 36 degrees "
Brass Blend of standard export gravity 43 degrees "
Pennington Light of standard export gravity 36 degrees "
Commingled Antan of standard export gravity 32 degrees "
3. Conversion Factors
Bonny Light 7.5060 barrels per metric tonne
Forcados Blend 7.2390 " " " "
Bonny Medium 7.0160 " " " "
Qua Iboe Light 7.5060 " " " "
Escravos Light 7.4625 " " " "
Brass Blend 7.7741 " " " "
Pennington Light 7.2396 " " " "
Commingled Antan 7.2844 " " " "
4. Yields The following refinery yields will be applied to each
geographical area unless amended under the terms of Clause 2.12
of this Memorandum
U.S. Gulf Coast (expressed as Volume %)
(Same yields apply Summer and Winter)
-104-
<PAGE> 108
<TABLE>
<CAPTION>
BONNY LIGHT FORCADOS BLEND BONNY MEDIUM
----------- -------------- ------------
% Vol. % Vol. % Vol.
<S> <C> <C> <C>
LPG Propane 2.30 2.40 2.50
LPG Normal Butane 2.30 2.40 2.50
Gasoline Regular 17.80 16.42 14.25
Gasoline Unleaded 17.80 16.43 14.25
Naptha 12.30 8.30 5.20
Jet Kero 12.80 10.50 8.50
No. 2 Oil 22.40 29.55 36.70
Max 1% S Fuel Oil 12.30 14.00 16.10
Refy Fuel Loss - - -
TOTAL 100.00 100.00 100.00
</TABLE>
NORTH WEST EUROPE (NWE) AND MEDITERRANEAN (MED)
(Expressed as Weight %)
<TABLE>
<CAPTION>
Summer Winter
% wt. % wt.
---------- -------------
<S> <C> <C> <C>
BONNY LIGHT
-----------
Gasoline
Premium 24.50 20.00
Regular 8.60 8.50
Jet Kerosene 10.00 8.50
Gasoil 23.10 34.50
Fuel Oil 1% 28.80 23.50
Refy Fuel/Loss 5.00 5.00
TOTAL 100.00 100.00
FORCADOS BLEND
--------------
Gasoline
Premium 19.00 15.40
Regular 7.50 5.80
Jet Kerosene 8.80 8.80
Gasoil 29.00 36.30
Fuel Oil 1% 30.70 28.70
Refy Fuel/Loss 5.00 5.00
TOTAL 100.00 100.00
BONNY MEDIUM
------------
Gasoline
Premium 8.70 7.00
Regular 3.60 3.00
Jet Kerosene 8.00 6.00
Gasoil 27.60 30.50
Fuel Oil 1% 47.50 48.90
Refy Fuel/Loss 4.60 4.60
TOTAL 100.00 100.00
</TABLE>
-105-
<PAGE> 109
Summer yields are to be used for the calculation of all prices for the
months of April, May, June, July, August and September.
The Winter yields will apply for the months of October, November,
December, January, February and March.
5. Processing Fees
U.S. Gulf - $1.90 per barrel
NWE - $1.40 " "
MED - $1.30 " "
6. Valuation of Refined Products:
Reference to Platt's quotations outlined in Attachment 1a to Appendix A
will be made to value the refinery yields in accordance with Clause 2.12
of this Memorandum. In each case the average of the mid-range product
prices for each quotation day for the period 1st to 20th (inclusive) of
the month in question will be used.
7. Freight
US Gulf Coast - LR 2 for Bonny Light and Forcados, one port
loading and one port discharge.
- LR 1 for Bonny Medium one port loading and
one port discharge.
NEW and MED - 25% VLCC plus 75% LR 2 for Bonny Light and
Forcados, one port loading and one port
discharge.
- LR 1 for Bonny Medium, one port loading and
one port discharge.
Freight rates for the various ship sizes will be based on monthly
assessments obtained from the London Tanker Brokers Panel.
8. Insurance and Outturn Loss
The following will be allowable deductions in the calculation of the
realizable price.
Insurance $0.03 per barrel
Outturn Loss $0.05 per barrel
9. Method used in Calculating NBV
See Attachment 1 to this Appendix.
-106-
<PAGE> 110
10. Price Differentials Between Bonny Light Final Realizable Price and Other
Nigerian Light Crude Oil Grades Bonny Light will be used as the
reference crude for all other Nigerian crude oils except Forcados and
Bonny Medium. Forcados crude is separately quoted in Platt's while
Bonny Medium will be taken as BBQ less $1.20 per barrel. The
differential between Bonny Light and other Nigerian Light grades shall
be as follows:
<TABLE>
<Capation>
0 less than RP less $20/bbl/ less than RP
Price Range than or equal to $20/bbl less than or equal to $25/bbl $25/bbl less than RP
- -------------- ------------------------ ------------------------------ ----------------------
<S> <C> <C> <C>
Brass - - -
Qua Iboe 5 cents 7.5 cents 10 cents
Escravos 10 cents 12.5 cents 15 cents
Pennington 5 cents 7.5 cents 10 cents
</TABLE>
11. Formula for Realizable Price
<TABLE>
<S> <C> <C>
Bonny Light (BL) = BBQ - $0.25/bbl + NBV
-------------------------
2
Forcados Blend (FB) = FB - $0.25/bbl + NBV
------------------------
2
Bonny Medium (BM) = BBQ - $1.45/bbl + NBV
-------------------------
2
</TABLE>
with NBV limited to a $0.40 per barrel tunnel around BBQ, Forcados and
Bonny Medium.
-107-
<PAGE> 111
Appendix A - Attachment 1a
QUOTATIONS USED IN REALIZABLE PRICE CALCULATIONS
<TABLE>
<S> <C> <C> <C>
Market Product Quotation Source
------ ------- --------- ------
USGC LPG Propane Propane Gas Liquids - Mont Belvieu
LPG Normal Butane Normal Buttane Gas Liquids - Mont Belvieu
Gasoline Regular Unl. 87 US Gulf Coast - Waterborne
Gasoline Unleaded Unl. 87 US Gulf Coast - Waterborne
Naphtha Naphtha US Gulf Coast - Waterborne
Jet Kero. Jet Kerosene US Gulf Coast - Waterborne
No. 2 Oil No. 2 Oil US Gulf Coast - Waterborne
Max. 1.0%S Fuel Oil No. 6 1.0%S US Gulf Coast - Waterborne
NWE Gasoline Premium Prem. 0.15% Cargoes CIF NWE Basis ARA
Gasoline Regular Reg Unlx0.925 Cargoes CIF NWE Basis ARA
Jet Kerosene Jet Kerosene Cargoes CIF NWE Basis ARA
Gasoil Gasoil 0.2 x 0.85 / Gasoil 0.3 x 0.15 Cargoes CIF NWE Basis ARA
Fuel Oil 1.0% 1% Fuel Oil Cargoes CIF NWE Basis ARA
MED Gasoline Premium Prem 0.25% until 31/5/91 Cargoes CIF Med Basis
Genoa/Lavera
Prem 0.15% x 0.98 after 31/5/91 Cargoes CIF Med Basis
Genoa/Lavera
Gasoline Regular Prem 0.25% x 0.921 until 31/5/91 Cargoes CIF Med Basis
Genoa/Lavera
Prem 0.15% x 0.903 after 31/5/91 Cargoes CIF Med Basis
Genoa/Lavera
Jet Kerosene Jet Kerosene Cargoes CIF Med Basis
Genoa/Lavera
Gasoil Gasoil Cargoes CIF Med Basis
Genoa/Lavera
Fuel Oil 1.0% 1% Fuel Oil Cargoes CIF Med Basis
Genoa/Lavera
</TABLE>
For Mediterranean, when cargoes CIF are not quoted, use FOB quotation.
-108-
<PAGE> 112
APPENDIX A - ATTACHMENT 1
WORKED EXAMPLE OF NETBACK CALCULATION TO DETERMINE
REALIZABLE PRICE FOR BONNY LIGHT CRUDE
Note:
All figures calculated are rounded to 4 decimal places, that is rounding down
if the 5th decimal place is 4 or less, otherwise rounding up.
Realizable Prices are based on the standard export gravities as per Paragraph 2
of this Appendix. The final calculated Realizable Prices will be adjusted to
take account of API variations as follows:
For each 0.1 deg. API difference above or below the reference gravity,
an adjustment of $0.003 per barrel will be added to or subtracted from
the calculated Realizable Price.
Section 1 - Calculation of NBV per Market
(A) U.S. Gulf Coast (USGC)
<TABLE>
<CAPTION>
Yields
Cents/Gallon $/bbl % Vol. $/bbl
------------ ----- ------ -----
<S> <C> <C> <<C> <C>
LPG Propane 29.8846 x .42 = 12.5515 x 2.30 = 0.2887
LPG Normal Butane 43.0962 x .42 = 18.1004 x 2.30 = 0.4163
Gasoline Regular 60.1827 x .42 = 25.2767 x 17.80 = 4.4993
Gasoline Unleaded 60.1827 x .42 = 25.8876 x 17.80 = 4.4993
Naphtha 60.8173 x .42 = 25.5433 x 12.30 = 3.1418
Jet Kerosene 66.7019 x .42 = 28.0148 x 12.80 = 3.5859
N. 2 H.O. 66.4135 x .42 = 27.8937 x 22.40 = 6.2482
Max 1.0% S F.O. ($/bbl) = 11.5962 x 12.30 = 1.4263
------
Gross Product Worth (GPW) 24.1058
Conversion Factor 7.506
From the above, following deductions to apply:
Processing Fee 1.9000
Freight Flat Rate LR2 Conversion
($/MT) x (WS Points) Factor
----------- ----------- -----------
10.62 125.8% / 7.506 = 1.7999
Outturn Loss 0.0500
Insurance 0.0300
---------
(a) Netback - USGC ($/bbl) 20.3459
</TABLE>
-109-
<PAGE> 113
(B) North West Europe (NWE)
<TABLE>
<CAPTION>
Yields
$/MT % wt. $/MT
---------- ------------ -----------
<S> <C> <C> <C>
Gasoline Premium = 242.6923 x 20.00 = 48.5385
Gasoline Regular = 210.3664 x 8.50 = 17.8811
Jet Kerosene = 308.6538 x 8.50 = 26.2356
Gasoil = 287.6346 x 34.50 = 99.2339
Fuel Oil 1% = 93.0000 x 23.50 = 21.8550
Refinery Fuel and Loss = 5.00 = -
Gross Product Worth (GPW) - ($/MT) = 213.7441
Conversion Factor 7.506
Gross Product Worth (GPW) - ($/bbl) = 28.4764
</TABLE>
From the above, following deductions to apply:
<TABLE>
<CAPTION>
Processing Fee 1.4000
Freight Flat Rate Vessel Class Conversion
($/MT) (WS Points) Factor
--------- ------------ -----------
<S> <C> <C> <C> <C>
LR2 - 75% 8.79 x 130.4%/ 7.506 = 1.1453
VLCC - 25% 8.79 x 90.0%/ 7.506 = 0.2635
Outturn Loss 0.0500
Insurance 0.0300
--------
(b) Netback - NWE ($/bbl) 25.5876
</TABLE>
(C) Mediterranean (MED)
-------------------
<TABLE>
<CAPTION>
Yields
$/MT % wt. $/MT
--------- ----------- -----------
<S> <C> <C> <C>
Gasoline Premium = 238.0000 x 20.00 = 47.6000
Gasoline Regular = 219.1980 x 8.50 = 18.6318
Jet Kerosene = 307.5385 x 8.50 = 26.1408
Gasoil = 294.3846 x 34.50 = 101.5627
Fuel Oil 1 = 98.3077 x 23.50 = 23.1023
Refinery Fuel and Loss = 5.00 = -
---------
Gross Product Worth (GPW) - ($/MT) = 217.0376
Conversion Factor 7.506
Gross Product Worth (GPW) - ($/bbl) = 28.9152
</TABLE>
-110-
<PAGE> 114
From the above, following deductions to apply:
<TABLE>
<CAPTION>
Processing Fee 1.3000
Freight Flat Rate Vessel Class Conversion
($/MT) (WS Points) Factor
---------- -------------- -------------
<S> <C> <C> <C> <C>
LR2 - 75% 8.16 x 131.0%/ 7.506 = 1.0681
VLCC - 25% 8.16 x 85.0%/ 7.506 = 0.2310
Outturn Loss 0.0500
Insurance 0.0300
--------
(c) Netback - MED ($/bbl) 26.2361
</TABLE>
Section 2 - Calculation of NBV
- ------------------------------
<TABLE>
<CAPTION>
Market Weighting Netback Contribution
------ --------- ------- ------------
<S> <C> <C> <C>
(a) USGC 60% x 20.3459 = 12.2075
(b) NWE 20% x 25.5876 = 5.1175
(c) MED 20% x 26.2361 = 5.2472
------
(d) Initial NBV ($/bbl) = 22.5722
</TABLE>
Section 3 - Calculation of Final NBV
- ------------------------------------
<TABLE>
<S> <C>
A. Initial NBV 22.5722
B. BBQ Average 20.8712
F1. Greater of (B-40c.) and A 22.5722
F2. Lesser of (B+40c.) and F1 21.2712
(e) Final NBV ($/bbl) 21.2712
</TABLE>
NOTE:
- -----
NBV shall be adjusted only if its value is greater/lower than BBQ by
more than 40 cents per barrel.
Section 4 - Calculation of Realizable Price
- -------------------------------------------
<TABLE>
<S> <C>
Crude Element BBQ 20.8712
Less 25c./bbl differential 0.2500
--------
(i) 20.6212
Produce Element Final NBV (ii) 21.2712
Average of (i) and (ii) 20.9462
Reliable Price for Bonny Light ($/bbl) = 20.9462
</TABLE>
-111-
<PAGE> 1
EXHIBIT 10.7
[Ashland logo goes here]
ASHLAND OIL (NIGERIA) COMPANY
MEMORANDUM OF UNDERSTANDING
ON OPLS 98 AND 118
BETWEEN
THE FEDERAL MILITARY GOVERNMENT OF THE FEDERAL
REPUBLIC OF NIGERIA
AND
ASHLAND OIL (NIGERIA) COMPANY
LAGOS
<PAGE> 2
MEMORANDUM OF UNDERSTANDING
ON INCENTIVES FOR ENCOURAGING INVESTMENTS IN EXPLORATION AND
DEVELOPMENT ACTIVITIES AND ENHANCING CRUDE OIL EXPORTS
THIS MEMORANDUM OF UNDERSTANDING is made the 10th day of August, 1993, BETWEEN
THE FEDERAL MILITARY GOVERNMENT OF THE FEDERAL REPUBLIC OF NIGERIA
("Government"), represented by the Honourable Secretary of Petroleum Resources
and Ashland Oil (Nigeria) Company, a company incorporated under the laws of
Nigeria whose registered office is at 10 Bishop Aboyade Cole St., Victoria
Island, Lagos ("Ashland").
WHEREAS:
(i) Government and Ashland entered into a MEMORANDUM OF
UNDERSTANDING ON INCENTIVES FOR ENHANCING CRUDE OIL EXPORTS
AND ENCOURAGING INVESTMENTS IN EXPLORATION AND DEVELOPMENT
ACTIVITIES (the "Memorandum of Understanding")
effective 1st January, 1986.
(ii) Some matters in the Memorandum of Understanding were more
particularly detailed in the Side Letter dated 17th of
January, 1986, which also formed part of the Memorandum of
Understanding.
(iii) Government and Ashland reviewed the Memorandum of
Understanding and the Side Letter and agreed to a "First
Amendment" effective 1st October, 1986.
(iv) Government and Ashland further reviewed the Memorandum of
Understanding and the Side Letter and agreed to a "Second
Amendment" effective 1st July, 1987.
(v) Some Platt's product price quotations used in determining
Price were updated in letters (dated 19th October 1988 and
27th July 1990) from the Nigerian National Petroleum
Corporation ("NNPC").
(vi) Government and Ashland have further reviewed the Memorandum of
Understanding and the aforementioned Side Letters and
amendments and have mutually agreed to consolidate them into
this Memorandum.
(vii) Ashland is conducting Petroleum Operations under the
Production Sharing Contract between NNPC and Ashland dated
12th June 1973, as amended to date ("PSC").
(viii) Ashland has thoroughly explored all of the acreage within the
area (OPLs 98 and 118) covered by the PSC and has fully
developed all commercial oil fields discovered as a result
thereof.
<PAGE> 3
NOW THEREFORE, the parties hereby agree as follows:
1.1 The said Memorandum of Understanding dated 17th January, 1986
together with the Side Letter and the amendments referred to
in the above recitals hereto are hereby terminated and are
replaced and superseded in their entirety by this Memorandum
of Understanding ("this Memorandum").
1.2 The fiscal regime currently applicable to the oil industry is
modified to ensure that the industry realizes not less than
the profit margin established pursuant to Clauses 2.4, 2.5 and
2.6 herein.
1.3 The terms and conditions set forth in Clauses 2 to 5 of this
Memorandum shall form part of the new fiscal regime.
2. Incentives
2.1 Prior to the introduction of the incentives described in this
Memorandum, the fiscal regime existing at 31st December 1985,
provided for the computations of Royalty on Posted Price and
Petroleum Profit Tax ("PPT") on the higher of actual proceeds
(Section 9) or Posted Prices (Section 17A), of the Petroleum
Profits Tax Act 1959 and its amendments ("PPT Act").
2.2 Except as otherwise specified in Clause 2.6, it is intended by
the incentives described in this Memorandum to accord a
minimum Guaranteed Notional Margin of $2.30/bbl, after payment
of the PPT and Royalty as provided under the PSC. However,
this minimum Guaranteed Notional Margin shall be premised on
the fact that the technical cost of operations does not exceed
the Notional Fiscal Technical Cost which, at present, is
$2.50/bbl.
2.3 It is further intended that when in any one calendar year
Ashland's actual expenditure on Capital Investment Costs
defined as T(2) in Appendix 1 is equal to or exceeds $1.50/bbl
on average than then the minimum Guaranteed Notional Margin
specified in Clause 2.2 shall be increased to $2.50/bbl.
Furthermore in this circumstance, the Notional Fiscal
Technical Cost shall be increased to $3.50/bbl.
2.4 For the purpose of this Memorandum, Government Take (Royalty
and PPT) relating to the PSC for any fiscal accounting year
shall be the lower of Government Take according to the
31/12/1985 Royalty and PPT regulations calculated by
substitution of Official Selling Price ("OSP") for Posted
Price and the Revised Government Take ("RGT") calculated per
the offset pricing formula below:
RGT = OP-(TR x TC)-OT
-2-
<PAGE> 4
Where:
RGT = Revised Government Take
OP = Offset Price = B x RP
RP = Realisable Price Calculated in accordance
with Clauses 2.12, 2.13, and 2.14 hereof to
determine/mirror the crude oil market values
of Nigerian export grades.
B = K [(1-Roy) x TR + Roy]
K = Factor of 1.0042 when the minimum Guaranteed
Notional Margin is $2.30/bbl. Factor of
0.9869 when the minimum Guaranteed Notional
Margin is $2.50/bbl.
Roy = Royalty Rate
TR = Applicable Tax Rate
TC = Deductions under Sections 10, 14 and 15
(excluding Royalty) of the PPT Act.
OT = Offsets under Section 17 of the PPT Act.
2.5 For Realisable Prices below $23/bbl, the K-Factors specified
under Clause 2.4 shall be substituted by the undernoted
self-adjusting mechanism for the determination of the K-Factor
which shall be applied to restore the desired Guaranteed
Notional Margin:
M+0.15FC
K = 1.1364 (1 - --------)
RP
Where:
M = Guaranteed Notional Margin
FC = Notional Fiscal Technical Cost
Therefore when M is $2.30/bbl:
$2.30+0.15[$2.50]
K = 1.1364 (1 - -----------------)
RP
-3-
<PAGE> 5
and, when M is $2.50/bbl
$2.50+0.15[$3.50]
K = 1.1364 (1 - -----------------)
RP
2.6 The following mechanism shall be applied for establishing the
Guaranteed Notional Margin for Realisable Prices less than
$12.50/bbl:
FC
M = (1 - --) (RP(1) a(1) + RP(2) a(2) + RP(3) a(3)
RP
Where:
M = Guaranteed Notional Margin (presently
$2.30/bbl subject to Clause 2.3)
RP = Realisable Price
FC = Notional Fiscal Technical Cost (presently
$2.50/bbl subject to Clause 2.3)
a = Ashland's Percentage share of field profit.
For:
<TABLE>
<CAPTION>
Realisable Price Ashland Share Applicable
---------------- ------------------------
in the Range to Price Range
------------ --------------
<S> <C> <C>
(FC = $2.50) (FC = $3.50)
------------ ------------
0 less than RP(1) less than or equal to $5/bbl a(1) = 0.30 = 0.365
$5/bbl less than RP(2) less than or equal to $10/bbl a(2) = 0.22 = 0.263
$10/bbl less than RP(3) less than or equal to $12.50/bbl a(3) = 0.11 = 0.131
</TABLE>
For worked examples refer to Appendix 2.
2.7 The K-Factors specified under Clauses 2.4 and 2.5 shall remain
in force until amended by the Minister of Petroleum Resources.
It is intended that such amendment shall only be necessary
when Realisable Price exceeds $30/bbl for at least 45 days
continuously. If the Realisable Price returns below $30/bbl,
the K-Factors will return automatically to the levels
specified in Clauses 2.4 and 2.5 as appropriate.
2.8 The Parties agree that, since Ashland has thoroughly explored
all of the said areas covered by the PSC and has fully
developed all oil fields which are commercial under the terms
of the PSC, further investment in such areas for exploration
and/or
-4-
<PAGE> 6
development is not viable for Ashland and, therefore, the
incentives known as the Capital Investment Cost Tax Offset and
the Reserves Addition Bonus, which were provided to the oil
industry under the Memorandum of Understanding agreements
signed in 1991 shall not be applicable to Ashland under this
Memorandum; provided however, that if circumstances change
(such as the PSC is extended beyond 12 June 1993) and Ashland
undertakes further investment, as approved by NNPC, under the
PSC, then this Memorandum shall be amended to provide that the
aforementioned incentives stated in this Clause 2.8 shall be
extended to Ashland, and in addition, the values of M =
$2.50/bbl and FC = $3.50/bbl shall apply to Ashland when T2 is
equal to or greater than $1.50/bbl.
2.9 To the extent that in any one calendar year the actual
technical cost of operations exceeds $3.50/bbl on average and
such excess arises due to Capital Investment Costs (T(2) as
defined below) equalling or exceeding $1.50/bbl, Ashland shall
be entitled to a tax offset against its PPT liability for that
year. This offset shall be:
10% x (LIBOR + 1%) x (0.80 x T(2))
Where
LIBOR = The average Financial Times London Inter Bank Fixing
Offer Rate for 3 month US Dollars as quoted in the
London Financial Times on 1 January, 1 April, 1 July
and 1 October or the next succeeding quotation day.
T(2) = Deductions under Sections 10, 14 and 15 (excluding
Royalty and Production Operating Expenses) of the
PPT Act.
2.10 To the extent that in any one year the additions to oil and
condensate Ultimate Recovery ("UR") exceed the production for
that year, then Ashland shall be entitled to a "Reserves
Addition Bonus" in the form of an offset against its PPT
liability for the year. For the purpose of estimating the
"Reserves Addition Bonus", UR shall be the sum of proven and
probable crude oil and condensate Ultimate Recovery. UR shall
be determined in a manner acceptable to the Department of
Petroleum Resources and such UR shall be as confirmed by
Honourable Minister of Petroleum Resources. The "Reserves
Addition Bonus" shall be calculated for each year in tranches
determined by reference to the addition/production ration
("R"):
R = ([UR at end year]-[UR at start of year])
----------------------------------------
Annual Production
For:
-5-
<PAGE> 7
<TABLE>
<CAPTION>
Incremental Addition/ Bonus Rate Per
R in the Range Production Ratio Incremental Barrel
-------------- ----------------- ------------------
<S> <C> <C>
1.0 less than R less than or equal to 1.25 Ra(1) = R - 1.00 X(1) = $0.10/bbl
1.25 less than R less than or equal to 1.50 Ra(1) = 0.25 and X(2) = $0.25/bbl
Ra(2) = R - 1.25
1.50 less than R less than or equal to 1.75 Ra(1) = Ra(2) = 0.25 X(3) = $0.40/bbl
and Ra(3) = R - 1.50
R greater than 1.75 Ra(1) = Ra(2) = Ra(3) = 0.25 X(4) = $0.50/bbl
and R(4) = R - 1.75
</TABLE>
For purposes of calculating Reserves Addition Bonus herein, the formula below
shall apply:
Bonus = [Ra(1) X(1) + Ra(2) X(2) + Ra(3) X(3) + Ra(4)
X(4)] P
Where:
P = Annual Production
X = Bonus rates for various values of R
UR = Ultimate Recovery which is defined as the
total volume of crude oil and condensate
recovered and to be recovered over the life
time of the field
For worked examples see Appendix 3.
In the event that in any one calendar year there is a downward
revision to the total oil and condensate Ultimate Recovery, to
the extent that the downward revision represents an adjustment
to Ultimate Recovery on which Ashland had received "Reserves
Additions Bonus" in previous years, Government shall have the
right to require Ashland to recalculate the "Reserves Additions
Bonus" in respect of those years. Ashland shall immediately
pay to Government any additional PPT liability arising from the
recomputation of the "Reserves Additions Bonus" and the related
tax offsets.
2.11 RGT will be calculated in Naira each month (under the terms
outlined in this Memorandum) and compared for the same volume
of exports with Government Take for the same month under the
terms of the present (31/12/85) Royalty and PPT regulations.
Identical rates of exchange will be used to convert U.S. Dollar
prices to
-6-
<PAGE> 8
Naira in both Government Take and RGT calculations. The amount
by which RGT is less than Government Take each month will be
accumulated and at the end of the fiscal accounting year will
be applied as the annual tax credit to be offset against PPT
due for that fiscal accounting period.
2.12 For the purpose of the RGT formula, the terms and conditions of
Appendix A (attached to and forming part of this Memorandum)
including yield percentages of the three crude streams (Bonny
Light, Forcados, Bonny Medium), weighted for each of the
primary market areas as defined in Clause 2.13, shall be
mutually agreed for a 6 month period determined 3 months in
advance. Thus the terms and conditions of Appendix A
applicable to the respective market for the period 1st October
through 31st March, will be determined on or before the
preceding 1st July, and for the period 1st April through 30th
September, on or before the preceding 1st January. If there is
no mutual agreement, the terms and conditions of Appendix A
applicable to the preceding year and for the same 6 month
period will prevail.
2.13 Appendix A shows the basis for determining the Realisable Price
f.o.b. Nigeria ("RP"). The c.i.f. value for each of the crude
streams shall be calculated monthly by utilising the agreed
product yield and the average of mid-range product prices
quoted each quotation day for the period 1st to 20th day of the
month of lifting in Platt's Oilgram Price Report published by
McGraw-Hill Inc. ("Platt's") for each of the following markets
viz: cargoes c.i.f. North-West Europe basis ARA, cargoes
c.i.f. Mediterranean basis Genoa/Lavera (or if not quoted
cargoes f.o.b. basis Italy) and US Gulf Coast waterborne. In
the USGC, L.P.G. will be priced at Platt's quotation for Mont
Belvieu Gas Liquids. Specific adjustments for freight, ocean
loss, insurance, and processing cost applicable to each primary
market shall be deducted in the calculation of the Net Back
Value ("NBV") Portion of the RP. The final NBV Portion of the
RP shall be determined by comparing the NBV so calculated with
the average of the appropriate crude oil quotations as
published in Platt's effective for each quotation day for the
period 1st to 20th (inclusive) of the same month. The NBV
shall be limited to a range of plus or minus 40 (forty) US
cents per US barrel around the prices of BBQ, Forcados Blend
and Bonny Medium through the following mechanism, where:
A: Initial NBV
B: Average Crude Oil Price (Bonny Light = Platt's BBQ;
Forcados = Platt's Forcados; and Bonny Medium = Platt's
BBQ - $1.20/bbl)
The final NBV is equal to F2 as follows:
F1: The greater of (B-40c./bbl) and A
F2: The lesser of (B+40c./bbl) and F1
-7-
<PAGE> 9
2.14 The Final NBV resulting from Clause 2.13 will be averaged with
crude oil price quotations to determine RP for each crude
stream as follows. Such RP for any month shall be deemed as
the RP for that month's liftings.
Bonny Light: The Final NBV for any month, calculated on the
basis of Appendix A, plus the average of mid-range quotations
for BBQ crude oil in Platt's for each quotation day for the
period 1st to 20th of the same month less $0.25/bbl, the whole
divided by two.
Bonny Medium: The Final NBV for any month, calculated on the
basis of Appendix A, plus the average of mid-range quotations
for BBQ crude oil in Platt's for each quotation day for the
period 1st to 20th of the same month less $1.45/bbl the whole
divided by two.
Forcados: The Final NBV for any month, calculated on the basis
of Appendix A, plus the average of mid- range quotations for
Forcados crude oil in Platt's for each quotation day for the
period 1st to 20th of the same month less $0.25/bbl, the whole
divided by two.
3. Conditions
In consideration of the incentives granted herein by the Government,
Ashland undertakes to market all NNPC's Lifting Allocations (as defined
in the PSC) subject to NNPC's right to revoke such authority as provided
under Clause 5 of the PSC.
4. Non-Performance
4.1 Where, however, Ashland is unable to lift all or part of
NNCPC's Lifting Allocation as defined and provided under the
PSC, Ashland agrees to pay to NNPC 2% of the average RP (for
the quarter of default) for each barrel not lifted. This
payment will be made in U.S. dollars or as may be directed by
the Government and shall not be considered as Operating Cost or
be taken into account in respect of year-end adjustment of cost
or treated as a cost allowance for the calculation of PPT.
4.2 In the event of force majeure, as defined in Clause 6, the
provision of Clause 4.1 shall not apply. If any restriction is
placed on the importation of crude oil including tariff
barriers or other relevant restrictions on trade which to the
knowledge of both parties affect Ashland's ability to dispose
of Nigerian Crude Oil, the parties agree to meet to discuss an
equitable solution.
5. Agreement of Government Agencies
Government confirms that the terms of this Memorandum have been agreed
by the appropriate Government Ministries in Nigeria including the
Ministry of Finance, the Federal Inland Revenue Department, and the
Central Bank of Nigeria. In consequence, Government
-8-
<PAGE> 10
guarantees to Ashland that no penalties, fines or other imposts
including costs of litigation and/or defence of the fiscal and foreign
exchange arrangements included in this Memorandum shall be imposed upon
Ashland by reason of compliance with this Memorandum.
6. Force Majeure
No failure or omission to carry out or to observe any of the terms,
provisions or conditions of this Memorandum shall, except as is herein
expressly provided to the contrary, give rise to any claim by one party
hereto against the other or be deemed to be a breach of this Memorandum,
if such failure or omission arises from any cause reasonably beyond the
control of either party. Such cause may be but is not limited to, any
act, event, happening, or occurrence due to natural causes, breakdown of
vessels or of machinery and equipment, civil unrest, strikes, lock-outs
or labour disputes, war, battle and commotion, or action of any relevant
de facto government. The rights of both parties shall be adjusted and
to the extent of their performance up to the time of the relevant event
as is reasonable in normal commercial practice and practicable in the
particular circumstances. As soon as practicable after the supervening
circumstances, the obligations under this Memorandum shall be resumed by
both parties as if there had been no interruption. Either party
claiming to be affected by such event shall give immediate notice in
writing of such claims to the other party giving full particulars
thereof and furthermore shall give immediate notice in writing of the
cessation of any such event.
7. Effective Date
This Memorandum shall become effective from the 1st day of January 1991.
Ashland may terminate this Memorandum having given one year's prior
notice to NNPC to withdraw.
8. Appendices
Appendices 1, 2(a & b), 3 and A (including Attachment 1) attached hereto
form part of this Memorandum.
-9-
<PAGE> 11
AS WITNESS the hands of the duly authorized representatives of the Parties the
day and year first above written.
THE FEDERAL MILITARY GOVERNMENT
OF THE FEDERAL REPUBLIC OF NIGERIA
By: /S/ Chief P.C. Asiodu
-------------------------------------------------------------------------
Name: CHIEF P.C. ASIODU
-----------------------------------------------------------------------
Designation: HONOURABLE SECRETARY OF PETROLEUM & MINERAL RESOURCES
----------------------------------------------------------------
IN the presence of:-
Name: Dr. G.A. Soyoye
-----------------------------------------------------------------------
Signature: /S/ Dr. G.A. Soyoye
------------------------------------------------------------------
Designation: Special Advisor
----------------------------------------------------------------
Address:
--------------------------------------------------------------------
--------------------------------------------------------------------
SIGNED for and on behalf of
ASHLAND OIL (NIGERIA) COMPANY
By: Bradley W. Fischer
-------------------------------------------------------------------------
Name: /S/ Bradley W. Fischer
-----------------------------------------------------------------------
Designation: Managing Director
----------------------------------------------------------------
IN the presence of:-
Name: Mrs. Dorothy O. Atake
-----------------------------------------------------------------------
Signature: /S/ Dorothy O. Atake
------------------------------------------------------------------
Designation: Senior Liaison Officer
----------------------------------------------------------------
Address: Ashland Oil (Nigeria) Company Unlimited,
--------------------------------------------------------------------
10 Bishop Aboyade, Cole Street, Victoria Island, Lagos
--------------------------------------------------------------------
-10-
<PAGE> 12
APPENDIX 1
PROCEDURE ON THE CALCULATION OF TECHNICAL COST PER BARREL
WITH REFERENCE TO THE MEMORANDUM OF UNDERSTANDING ON
INCENTIVES BETWEEN THE FEDERAL MILIARY GOVERNMENT
OF THE FEDERAL REPUBLIC OF NIGERIA
AND COMPANY - CLAUSE 2.3
The following expenses and costs reported by Company for the purposes of cost
recovery pursuant to the PSC during the period January/December of the year of
lifting shall be included in calculating the actual production cost per barrel
for the purpose of this Memorandum of Understanding.
(a) Production Operating Expenses: T(1)
(i) Direct Production Expenses as per items 400 and 401 of Report
No. 002 of Account Reporting Manual.
(ii) Portion of Administrative and General Expenses allocated to
Production - refer item 402 of Report No. 002 of Accounts
Reporting Manual.
(iii) Custom Duties and Gross Rentals allocated to Production - refer
items 4043 and 4045 of Report No. 002 of the Accounts Reporting
Manual.
(iv) Extra Ordinary/Prior Year Expenses/Incomes - refer item 405 of
Report No. 002 Accounts Reporting Manual.
(b) Capital Investment Costs which qualify for expensing for PPT calculation
and chargeable to Production Costs: T(2)
(i) Exploration Drilling Costs.
(ii) Appraisal Drilling Cost (1st and 2nd Wells).
(iii) Intangible Drilling and Development Costs.
(iv) Capital Allowances - shall be restricted to the capital
allowances applicable direct to production and a share of the
capital allowances on overhead assets allocated to production.
Such Capital Allowance should be reconciled with the Allowances
claimed for the year under Section 15 of the PPTA.
(c) It is expected that the Production Operating Expenses and Capital
Investment Costs above will be reconciled by Company with Report Nos.
002 and 001 of the Accounts Reporting Manual respectively.
-11-
<PAGE> 13
(d) The recommended basis for allocation of Expenses and Costs in a(ii),
a(iii) and a(iv) above to production shall be:
P
---------
E + P + X
Where:
P = The additions to the Capital costs during the year and
the Operating expenses for the year reported by Ashland
for the purposes of cost recovery pursuant to the PSC
which are directly related to the production function.
E = The additions to the Capital costs during the year and
the Operating expenses for the year reported by Ashland
for the purposes of cost recovery pursuant to the PSC
which are directly related to the exploration function.
X = Any other expenditures other than Production and
Exploration functions which are reported by Ashland for
the purposes of cost recovery pursuant to the PSC.
(a) (i) to (iv) + (b) (i) to (iv)
(e) Production Cost Per Barrel = ------------------------------------
Annual Production (Barrels)
(f) The advice on cost per barrel forwarded to NNPC should be supported with
a working paper.
-12-
<PAGE> 14
APPENDIX 2 (A)
WORKED EXAMPLES FOR ESTABLISHING THE GUARANTEED
NOTIONAL MARGIN FOR R.P. LESS THAN $12.5/BBL - CLAUSE 2.6
WHERE FC = $2.50/BBL
1.) If RP = $4
RP(1) = $4
a(1) = 0.30
and FC = $2.5
Margin M = (1 - 2.5) x (4 x 0.30)
---
4
= 0.375 x 1.2
M = $0.45
=======================
2.) If RP = $9
RP(1) = $5
a(1) = 0.30
RP(2) = $4
a(2) = 0.22
M = (1 - 2.5) x (5 x 0.30 + 4 x 0.22)
---
9
= 0.722 x 2.38
M = $1.719
=======================
3.) If RP = $11
RP(1) = $5
a(1) = 0.30
-13-
<PAGE> 15
RP(2) = $5
a(2) = 0.22
RP(3) = $1
a(3) = 0.11
and M = (1 - 2.5) x (5 x 0.30 + 5 x 0.22 + 1 x 0.11)
---
11
= 0.7727 x 2.71
M = $2.094
=======================
4.) If RP = $12.50
RP(1) = $5
a(1) = 0.30
RP(2) = $5
a(2) = 0.22
RP(3) = $2.50
a(3) = 0.11
and M = (1 - 2.5) x (5 x 0.30 + 5 x 0.22 + 2.5 x 0.11)
---
12.50
= 0.80 x 2.875
M = $2.30
=======================
-14-
<PAGE> 16
APPENDIX 2(b)
WORKED EXAMPLES FOR ESTABLISHING THE GUARANTEED
NOTIONAL MARGIN FOR R.P. LESS THAN $12.50/BBL - CLAUSE 2.6
WHERE FC = $3.50/BBL
1.) If RP = $4
RP(1) = $4
a(1) = 0.365
and FC = $3.5
Margin M = (1 - 3.50) x (4 x 0.365)
----
4
= 0.125 x 1.46
M = $0.1825
=======================
2.) If RP = $9
RP(1) = $5
a(1) = 0.365
RP(2) = $4
a(2) = 0.263
M = (1 - 3.50) x (5 x 0.365 + 4 x 0.263)
----
9
= 0.611 x 2.877
M = $1.758
=======================
3.) If RP = $11
RP(1) = $5
a(1) = 0.365
-15-
<PAGE> 17
RP(2) = $5
a(2) = 0.263
RP(3) = $1
a(3) = 0.131
and M = (1-3.50) x (5 x 0.365 + 5 x 0.263 + 1 x 0.131)
----
11
= 0.6818 x 3.271
M = $2.23
=======================
4.) If RP = $12.50
RP(1) = $5
a(1) = 0.365
RP(2) = $5
a(2) = 0.263
RP(3) = $2.50
a(3) = 0.131
and M = (1-3.50)x(5 x 0.365 + 5 x 0.263 + 2.5 x 0.131)
----
12.50
= 0.72 x 3.4675
M = $2.50
=======================
-16-
<PAGE> 18
APPENDIX 3
WORKED EXAMPLES ON COMPUTATION OF RESERVES
ADDITION BONUS
1.) Take UR End Year = 640 million barrels
UR Begin Year = 400 million barrels
Annual Production = 200 million barrels
R = 640 - 400
---------------
200
= 1.2
Ra(1) = 0.2
X(1) = $0.10/bbl
.' . Bonus = [Ra(1) X(1)] P
= [(0.2) (0.10)] x 200
= US$4.0 million
==============
2.) Take UR End Year = 700 million barrels
UR Begin Year = 400 million barrels
Annual Production = 200 million barrels
R = 700 - 400
---------------
200
= 1.5
Ra(1) = 0.25
Ra(2) = 0.25
X(1) = $0.10/bbl
X(2) = $0.25/bbl
. ' . Bonus = [(Ra(1) X(1)) + (Ra(2) X(2))]P
-17-
<PAGE> 19
= [(0.25)(0.10) + (0.25)(0.25)]
x 200
= US$17.5 million
===============
3.) Take UR End Year = 740 million barrels
UR Begin Year = 400 million barrels
Annual Production = 200 million barrels
R = 740 - 400
---------------
200
= 1.7
Ra(1) = 0.25
Ra(2) = 0.25
Ra(3) = 0.20
X(1) = $0.10/bbl
X(2) = $0.25/bbl
X(3) = $0.40/bbl
. ' . Bonus = [Ra(1) X(1) + Ra(2) X(2) +
Ra(3) X(3)] P
= [ (.25) (.10)+(.25) (.25)+
(.20) (.40)] x 200
= US$33.5 million
===============
4.) Take UR End Year = 900 million barrels
UR Begin Year = 400 million barrels
Annual Production = 200 million barrels
R = 900 - 400
---------------
200
= 2.5
-18-
<PAGE> 20
Ra(1) = 0.25
Ra(2) = 0.25
Ra(3) = 0.25
Ra(4) = 0.75
X(1) = $0.10/bbl
X(2) = $0.25/bbl
X(3) = $0.40/bbl
X(4) = $0.50/bbl
. ' . Bonus = [Ra(1) X(1) + Ra(2) X(2) +
Ra(3) X(3) + Ra(4) X(4)] P
= [(.25)(.10) + (.25)(.25) +
(.25)(.40) + (.75)(.50)] x
200
= US$112.5 million
-19-
<PAGE> 21
APPENDIX A
CALCULATION OF REALISABLE PRICE
The market weighted FOB Nigeria Net Back Value ("NBV") for the purpose
of calculating Realisable Price under this Memorandum shall be calculated from
the data given below and in accordance with the worked example shown in
Attachment 1 to this Appendix A.
<TABLE>
<S> <C> <C>
1. Delivery Each export grade of crude oil will be deemed
-------- delivered to:
U.S. Gulf Coast (USGC) 60 per cent
North West Europe (NWE) 20 per cent
Mediterranean (MED) 20 per cent
2. Grades The export grades of crude oil are:
------
Bonny Light of standard export gravity 37 degrees API
Forcados Blend of standard export gravity 31 degrees "
Bonny Medium of standard export gravity 26 degrees "
Qua Iboe Light of standard export gravity 37 degrees "
Escravos Light of standard export gravity 36 degrees "
Brass Blend of standard export gravity 43 degrees "
Pennington Light of standard export gravity 36 degrees "
Commingled Antan of standard export gravity 32 degrees "
3. Conversion Factors
------------------
Bonny Light 7.5060 barrels per metric tonne
Forcados Blend 7.2390 " " " "
Bonny Medium 7.0160 " " " "
Qua Iboe Light 7.5060 " " " "
Escravos Light 7.4625 " " " "
Brass Blend 7.7741 " " " "
Pennington Light 7.2396 " " " "
Commingled Antan 7.2844 " " " "
</TABLE>
-20-
<PAGE> 22
4. Yields The following refinery yields will be applied to each
geographical area unless amended under the terms of Clause
2.12 of this Memorandum
U.S. Gulf Coast (expressed as Volume %)
(Same yields apply Summer and Winter)
<TABLE>
<CAPTION>
BONNY LIGHT FORCADOS BLEND BONNY MEDIUM
----------- -------------- ------------
% Vol. % Vol. % Vol.
<S> <C> <C> <C>
LPG Propane 2.30 2.40 2.50
LPG Normal Butane 2.30 2.40 2.50
Gasoline Regular 17.80 16.42 14.25
Gasoline Unleaded 17.80 16.43 14.25
Naphtha 12.30 8.30 5.20
Jet Kero 12.80 10.50 8.50
No. 2 Oil 22.40 29.55 36.70
Max 1% S Fuel Oil 12.30 14.00 16.10
Refy Fuel Loss -- -- --
TOTAL 100.00 100.00 100.00
</TABLE>
NORTH WEST EUROPE (NWE) AND MEDITERRANEAN (MED)
(Expressed as Weight %)
<TABLE>
<CAPTION>
Summer Winter
% wt. % wt.
--------- -------
BONNY LIGHT
-----------
<S> <C> <C>
Gasoline
Premium 24.50 20.00
Regular 8.60 8.50
Jet Kerosene 10.00 8.50
Gasoil 23.10 34.50
Fuel Oil 1% 28.80 23.50
Refy Fuel/Loss 5.00 5.00
TOTAL 100.00 100.00
</TABLE>
-21-
<PAGE> 23
FORCADOS BLEND
<TABLE>
<CAPTION>
<S> <C> <C> <C>
Gasoline
Premium 19.00 15.40
Regular 7.50 5.80
Jet Kerosene 8.80 8.80
Gasoil 29.00 36.30
Fuel Oil 1% 30.70 28.70
Refy Fuel/Loss 5.00 5.00
TOTAL 100.00 100.00
BONNY MEDIUM
------------
Gasoline
Premium 8.70 7.00
Regular 3.60 3.00
Jet Kerosene 8.00 6.00
Gasoil 27.60 30.50
Fuel Oil 1% 47.50 48.90
Refy Fuel/Loss 4.60 4.60
TOTAL 100.00 100.00
</TABLE>
Summer yields are to be used for the calculation of all prices for the
months of April, May, June, July, August and September.
The Winter yields will apply for the months of October, November,
December, January, February and March.
5. Processing Fees
U.S. Gulf - $1.90 per barrel
NWE - $1.40 " "
MED - $1.30 " "
6. Valuation of Refined Products:
Reference to Platt's quotations outlined in Attachment 1a to Appendix
A will be made to value the refinery yields in accordance with Clause
2.12 of this Memorandum. In each case the average of the mid-range
product prices for each quotation day for the period 1st to 20th
(inclusive) of the month in question will be used.
-22-
<PAGE> 24
7. Freight
US Gulf Coast - LR 2 for Bonny Light and Forcados, one port
loading and one port discharge.
- LR 1 for Bonny Medium one port loading and one
port discharge.
NWE and MED - 25% VLCC plus 75% LR 2 for Bonny Light and
Forcados, one port loading and one port
discharge.
- LR 1 for Bonny Medium, one port loading and
one port discharge.
Freight rates for the various ship sizes will be based on monthly
assessments obtained from the London Tanker Brokers Panel.
8. Insurance and Outturn Loss
The following will be allowable deductions in the calculation of the
realisable price.
Insurance $0.03 per barrel
Outturn Loss $0.05 per barrel
9. Method used in Calculating NBV
See Attachment 1 to this Appendix.
10. Price Differentials Between Bonny Light Final Realisable Price and
Other Nigerian Light Crude Oil Grades Bonny Light will be used as the
reference crude for all other Nigerian crude oils except Forcados and
Bonny Medium. Forcados crude is separately quoted in Platt's while
Bonny Medium will be taken as BBQ less $1.20 per barrel. The
differential between Bonny Light and other Nigerian Light grades shall
be as follows:
<TABLE>
<CAPTION>
0 less than RP $20/bbl less than RP
less than or equal less than or equal
Price Range to $20/bbl to $25/bbl $25/bbl less than RP
------------------ -------------------- --------------------
<S> <C> <C> <C>
Brass - - -
Qua Iboe 5 cents 7.5 cents 10 cents
Escravos 10 cents 12.5 cents 15 cents
Pennington 5 cents 7.5 cents 10 cents
</TABLE>
-23-
<PAGE> 25
11. Formula for Realisable Price
Bonny Light (BL) = BBQ - $0.25/bbl + NBV
---------------------
2
Forcados Blend (FB) = FB - $0.25/bbl + NBV
---------------------
2
Bonny Medium (BM) = BBQ - $1.45/bbl + NBV
---------------------
2
with NBV limited to a $0.40 per barrel tunnel around BBQ, Forcados and
Bonny Medium.
-24-
<PAGE> 26
APPENDIX A - ATTACHMENT 1A
QUOTATIONS USED IN REALISABLE PRICE CALCULATIONS
<TABLE>
<CAPTION>
Market Product Quotation Source
------ ------- --------- ------
<S> <C> <C> <C>
USGC LPG Propane Propane Gas Liquids - Mont Belvieu
LPG Normal Butane Normal Butane Gas Liquids - Mont Belvieu
Gasoline Regular Unl. 87 US Gulf Coast - Waterborne
Gasoline Unleaded Unl. 87 US Gulf Coast - Waterborne
Naphtha Naphtha US Gulf Coast - Waterborne
Jet Kero. Jet Kerosene US Gulf Coast - Waterborne
No. 2 Oil No. 2 Oil US Gulf Coast - Waterborne
Max. 1.0%S Fuel Oil No. 6 1.0%S US Gulf Coast - Waterborne
NWE Gasoline Premium Prem. 0.15% Cargoes CIF NWE Basis ARA
Gasoline Regular Reg Unlx0.925 Cargoes CIF NWE Basis ARA
Jet Kerosene Jet Kerosene Cargoes CIF NWE Basis ARA
Gasoil Gasoil 0.2 x 0.85 + Gasoil 0.3 x 0.15 Cargoes CIF NWE Basis ARA
Fuel Oil 1.0% 1% Fuel Oil Cargoes CIF NWE Basis ARA
MED Gasoline Premium Prem 0.25% until 31/5/91 Cargoes CIF Med Basis Genoa/Lavera
Prem 0.15% x 0.98 after 31/5/91 Cargoes CIF Med Basis Genoa/Lavera
Gasoline Regular Prem 0.25% x 0.921 until 31/5/91 Cargoes CIF Med Basis Genoa/Lavera
Prem 0.15% x 0.903 after 31/5/91 Cargoes CIF Med Basis Genoa/Lavera
Jet Kerosene Jet Kerosene Cargoes CIF Med Basis Genoa/Lavera
Gasoil Gasoil Cargoes CIF Med Basis Genoa/Lavera
Fuel Oil 1.0% 1% Fuel Oil Cargoes CIF Med Basis Genoa/Lavera
</TABLE>
For Mediterranean, when cargoes CIF are not quoted, use FOB
quotation.
-25-
<PAGE> 27
APPENDIX A - ATTACHMENT 1
WORKED EXAMPLE OF NETBACK CALCULATION TO DETERMINE
REALISABLE PRICE FOR BONNY LIGHT CRUDE
Note:
All figures calculated are rounded to 4 decimal places, that is rounding down
if the 5th decimal place is 4 or less, otherwise rounding up.
Realisable Prices are based on the standard export gravities as per Paragraph 2
of this Appendix. The final calculated Realisable Prices will be adjusted to
take account of API variations as follows:
For each 0.1 deg. API difference above or below the reference gravity,
an adjustment of $0.003 per barrel will be added to or subtracted from
the calculated Realisable Price.
Section 1 - Calculation of NBV per Market
<TABLE>
<CAPTION>
(A) U.S. Gulf Coast (USGC)
Yields
Cents/Gallon $/bbl % Vol. $/bbl
------------ -------- ------- -------
<S> <C>
LPG Propane 29.8846 x .42 = 12.5515 x 2.30 = 0.2887
LPG Normal Butane 43.0962 x .42 = 18.1004 x 2.30 = 0.4163
Gasoline Regular 60.1827 x .42 = 25.2767 x 17.80 = 4.4993
Gasoline Unleaded 60.1827 x .42 = 25.8876 x 17.80 = 4.4993
Naphtha 60.8173 x .42 = 25.5433 x 12.30 = 3.1418
Jet Kerosene 66.7019 x .42 = 28.0148 x 12.80 = 3.5859
No. 2 H.O. 66.4135 x .42 = 27.8937 x 22.40 = 6.2482
Max 1.0% S F.O. ($/bbl) = 11.5962 x 12.30 = 1.4263
------
Gross Product Worth (GPW) 24.1058
Conversion Factor 7.506
</TABLE>
From the above, following deductions to apply:
<TABLE>
<CAPTION>
Processing Fee 1.9000
Freight Flat Rate LR 2 Conversion
($/MT) (WS Points) Factor
--------- ----------- --------------
<S> <C> <C> <C> <C>
10.62 x 125.8% / 7.506 = 1.7799
Outturn Loss 0.0500
Insurance 0.0300
-----------
(a) Netback - USGC ($/bbl) 20.3459
</TABLE>
-26-
<PAGE> 28
<TABLE>
<CAPTION>
(B) North West Europe (NWE)
Yields
$/MT % wt. $/MT
--------- ------- -------
<S> <C> <C> <C> <C> <C>
Gasoline Premium = 242.6923 x 20.00 = 48.5385
Gasoline Regular = 210.3664 x 8.50 = 17.8811
Jet Kerosene = 308.6538 x 8.50 = 26.2356
Gasoil = 287.6346 x 34.50 = 99.2339
Fuel Oil 1% = 93.0000 x 23.50 = 21.8550
Refinery Fuel and Loss = 5.00 = -
--------
Gross Product Worth (GPW) - ($/MT) = 213.7441
Conversion Factor 7.506
Gross Product Worth (GPW) - ($/bbl) = 28.4764
</TABLE>
From the above, following deductions to apply:
<TABLE>
<CAPTION>
Processing Fee 1.4000
Freight Flat Rate Vessel Class Conversion
($/MT) (WS points) Factor
--------- ------------ --------------
<S> <C> <C> <C> <C> <C>
LR2 - 75% 8.79 x 130.4%/ 7.506 = 1.1453
VLCC - 25% 8.79 x 90.0%/ 7.506 = 0.2635
Outturn Loss 0.0500
Insurance 0.0300
------
(b) netback - NWE ($/bbl) 25.5876
</TABLE>
<TABLE>
<CAPTION>
(C) Mediterranean (MED)
Yields
$/MT % wt. $/MT
--------- ------- -------
<S> <C> <C> <C> <C>
Gasoline Premium = 238.0000 x 20.00 = 47.6000
Gasoline Regular = 219.1980 x 8.50 = 18.6318
Jet Kerosene = 307.5385 x 8.50 = 26.1408
Gasoil = 294.3846 x 34.50 = 101.5627
Fuel Oil 1 = 98.3077 x 23.50 = 23.1023
Refinery Fuel and Loss = 5.00 = -
--------------
Gross Product Worth (GPW) - ($/MT) = 217.0376
Conversion Factor 7.506
Gross Product Worth (GPW) - ($/bbl) = 28.9152
</TABLE>
From the above, following deductions to apply:
-27-
<PAGE> 29
<TABLE>
<CAPTION>
Processing Fee 1.3000
Freight Flat Rate Vessel Class Conversion
($/MT) (WS points) Factor
--------- ------------ --------------
<S> <C> <C> <C> <C> <C> <C>
LR2 - 75% 8.16 x 131.0%/ 7.506 = 1.0681
VLCC - 25% 8.16 x 85.0%/ 7.506 = 0.2310
Outturn Loss 0.0500
Insurance 0.0300
-------
26.2361
(c) Netback - MED ($/bbl)
</TABLE>
Section 2 - Calculation of NBV
<TABLE>
<CAPTION>
Market Weighting Netback Contribution
------ --------- ------- ------------
<S> <C> <C> <C> <C> <C>
(a) USGC 60% x 20.3459 = 12.2075
(b) NWE 20% x 25.5876 = 5.1175
(c) MED 20% x 26.2361 = 5.2472
--------
(d) Initial NBV ($/bbl) = 22.5722
</TABLE>
Section 3 - Calculation of Final NBV
<TABLE>
<S> <C> <C>
A. Initial NBV 22.5722
B. BBQ Average 20.8712
F1. Greater of (B-$.40) and A 22.5722
F2. Lesser of (B+$.40) and F1 21.2712
(e) Final NBV ($/bbl) 21.2712
</TABLE>
NOTE:
NBV shall be adjusted only if its value is greater/lower than BBQ by
more than 40 cents per barrel.
Section 4 - Calculation of Realisable Price
<TABLE>
<S> <C> <C>
Crude Element BBQ 20.8712
Less $.25/bbl differential 0.2500
-------
(i) 20.6212
Product Element Final NBV (ii) 21.2712
Average of (i) and (ii) 20.9462
Realisable Price for Bonny Light ($/bbl) = 20.9462
</TABLE>
-28-
<PAGE> 1
EXHIBIT 10.8
ASHLAND NIGERIA EXPLORATION UNLIMITED
NPPC/ANEU
MEMORANDUM OF UNDERSTANDING
OPLS90 AND 225
FEBRUARY 1994
[Ashland logo goes here]
<PAGE> 2
MEMORANDUM OF UNDERSTANDING
ON INCENTIVES FOR ENCOURAGING INVESTMENTS IN EXPLORATION
AND DEVELOPMENT ACTIVITIES AND ENHANCING CRUDE OIL EXPORTS
THIS MEMORANDUM OF UNDERSTANDING made this 24th day of May, 1994, BETWEEN THE
FEDERAL MILITARY GOVERNMENT OF THE FEDERAL REPUBLIC OF NIGERIA ("Government")
represented by the Honourable Minister of Petroleum And Mineral Resources; and
Ashland Nigeria Exploration, Ultd., a company incorporated under the laws of
Nigeria whose registered office is at 10 Bishop Aboyade Cole St., Victoria
Island, Lagos ("Company"), establishes the understanding of each of the above
named parties in respect of the incentives for encouraging investments in
exploration and development activities and enhancing crude oil exports.
NOW THEREFORE, the parties hereby agree as follows:
1.1 The fiscal regime currently applicable to the oil industry is
modified to ensure that the industry realizes not less than
the profit margin established pursuant to Clauses 2.4, 2.5
and 2.6 herein.
1.2 The terms and conditions set forth in Clauses 2 to 5 of this
Memorandum of Understanding ("this Memorandum") shall form
part of the new fiscal regime.
1.3 The operations covered by this Memorandum are those conducted
between Nigerian National Petroleum Corporation ("NNPC") and
Company under that certain Production Sharing Contract dated
March 25, 1992 ("PSC") and the computation of the incentives
hereunder shall be applied to the Petroleum Operations under
the PSC.
2. Incentives
2.1 Prior to the introduction of the incentives described in this
Memorandum, the fiscal regime existing at 31st December 1985,
provided for computations of Royalty on Posted Price and
Petroleum Profit Tax ("PPT") on the higher of actual proceeds
(Section 9) or Posted Prices (Section 17A), of the Petroleum
Profits Tax Act 1959 and its amendments ("PPT Act").
2.2 Except as otherwise specified in Clause 2.6, it is intended
by the incentives described in this Memorandum to accord a
minimum Guaranteed Notional Margin of $2.30/bbl, after
payment of the PPT and Royalty as provided under the PSC.
However, this minimum Guaranteed Notional Margin shall be
premised on the fact that the technical cost of operations
under the PSC does not exceed the Notional Fiscal Technical
Cost which, at present, is $2.50/bbl.
2.3 It is further intended that when in any one calendar year
actual expenditures on Capital Investment Costs relating to
the PSC defined as T2 in Appendix 1 is equal to or exceeds
$1.50/bbl on average then the minimum Guaranteed Notional
Margin specified in Clause 2.2 shall be increased to
$2.50/bbl. Furthermore in this circumstance, the Notional
Fiscal Technical Cost shall be increased to $3.50/bbl.
<PAGE> 3
2.4 For the purpose of this Memorandum, Government Take (Royalty
and PPT) relating to the PSC for any fiscal accounting year
shall be the lower of Government Take according to the
31/12/1985 Royalty and PPT regulations calculated by
substitution of OSP for Posted Price and the Revised
Government Take ("RGT") calculated per the offset pricing
formula below:
RGT = OP-(TR x TC)-OT
Where:
RGT = Revised Government Take
OP = Offset Price = B x RP
RP = Realisable Price Calculated in accordance
with Clauses 2.12, 2.13, and 2.14 hereof to
determine/mirror the crude oil market
values of Nigerian export grades.
B = K [(1-Roy) x TR + Roy]
K = Factor of 1.0042 when the Guaranteed
Notional Margin is $2.30/bbl.
= Factor of 0.9869 when the Guaranteed
Notional Margin is $2.50/bbl.
Roy = Royalty Rate
TR = Applicable Tax Rate
TC = Deductions under Sections 10, 14 and 15
(excluding Royalty) of the PPT Act.
OT = Offsets under Section 17 of the PPT Act.
2.5 For Realisable Prices below $23/bbl, the K-Factor specified
under Clause 2.4 shall be substituted by the undernoted
self-adjusting mechanism for the determination of the
K-Factor which shall be applied to restore the desired
Guaranteed Notional Margin:
M+0.15FC
K = 1.1364(1 - --------)
RP
Where:
M = Guaranteed Notional Margin
FC = Notional Fiscal Technical Cost
-2-
<PAGE> 4
Therefore when M is $2.30/bbl:
$2.30 + 0.15 [$2.50]
K = 1.1364(1 - --------------------)
RP
and, when M is $2.50/bbl:
$2.50 + 0.15 [$3.50]
K = 1.1364(1 - --------------------)
RP
2.6 The following mechanism shall be applied for establishing the
Guaranteed Notional Margin for RPs less than $12.50/bbl:
FC
M = (1 - -- )(RP(1) a(1)+RP(2) a(2)+RP(3) a(3))
RP
Where:
M = Guaranteed Notional Margin (presently
$2.30/bbl subject to Clause 2.3)
RP = Realisable Price
FC = Notional Fiscal Technical Cost (presently
$2.50/bbl subject to Clause 2.3)
a = Percentage share of field profit.
For:
<TABLE>
<CAPTION>
Realisable Price Ashland Share Applicable
in the Range to Price Range
------------ --------------
(FC = $2.50) (FC = $3.50)
------------ ------------
<S> <C> <C>
0 Less than RP(1) Less than or equal to $5/bbl a(1) = 0.30 = 0.365
$5/bbl Less than RP(2) Less than or equal to $10/bbl a(2) = 0.22 = 0.263
$10/bbl Less than RP(3) Less than or equal to $12.50/bbl a(3) = 0.11 = 0.131
</TABLE>
For worked examples refer to Appendices 2(a) and 2(b)
2.7 The K-Factors specified under Clauses 2.4 and 2.5 shall
remain in force until amended by the Honourable Minister of
Petroleum and Mineral Resources. It is intended that such
amendment shall only be necessary when RPs exceeds $30/bbl
for at least 45 days continuously. If the RP returns below
$30/bbl the K-Factors will return automatically to the levels
specified in Clauses 2.4 and 2.5 as appropriate.
2.8 To the extent that in any one calendar year the actual
technical cost of operations exceeds $3.50/bbl on average and
such excess arises due to Capital Investment Costs
-3-
<PAGE> 5
(T(2)as defined below) equalling or exceeding $1.50/bbl, a tax
offset shall be applied against PPT liability for that year
relating to the PSC. This offset shall be:
10% x (LIBOR + 1%) x (0.80 x T(2))
Where
LIBOR = The average Financial Times
London Inter Bank Fixing Offer Rate
for 3 month US Dollars as quoted in
the London Financial Times on 1
January, 1 April, 1 July and 1
October or the next succeeding
quotation day.
T(2) = Deductions under Sections 10, 14
and 15 (excluding Royalty and
Production Operating Expenses) of
the PPT Act.
2.9 To the extent that in any one year the additions to oil and
condensate Ultimate Recovery ("UR") exceed the production for
that year, then the Company shall be entitled to a "Reserves
Addition Bonus" in the form of an offset against PPT
liability for that year relating to the PSC. For the purpose
of estimating the "Reserves Addition Bonus", UR shall be the
sum of proven and probable crude oil and condensate ultimate
recovery. UR shall be determined in a manner acceptable to
the Department of Petroleum Resources and such UR shall be as
confirmed by The Honourable Minister of Petroleum Resources.
The Reserves Addition Bonus shall be calculated for each year
in tranches determined by reference to the
addition/production ratio ("R"):
([UR at end year]-[UR at start of year])
R = ----------------------------------------
Annual Production
For:
<TABLE>
<CAPTION>
Incremental Addition/ Bonus Rate Per
R in the Range Production Ratio Incremental Barrel
-------------- ---------------- ------------------
<S> <C> <C>
1.0 Less than R Less than or equal to 1.25 Ra(1) = R - 1.00 X(1) = $0.10/bbl
1.25 Less than R Less than or equal to 1.50 Ra(1) = 0.25 and X(2) = $0.25/bbl
Ra(2) = R - 1.25
1.50 Less than R Less than or equal to 1.75 Ra(1) = Ra(2) = 0.25 X(3) = $0.40/bbl
and Ra(3) = R - 1.50
R greater than 1.75 Ra1 = Ra(2) = Ra(3) = 0.25 X(4) = $0.50/bbl
and R(4) = R - 1.75
</TABLE>
-4-
<PAGE> 6
For purposes of calculating Reserves Addition Bonus herein,
the formula below shall apply:
Bonus = [Ra(l)X(1)+Ra(2)X(2)+Ra(3)X(3)+Ra(4)X(4)] P
Where:
P = Annual Production
X = Bonus rates for various values of R
UR = Ultimate Recovery which is defined as the
total volume of crude oil and condensate
recovered and to be recovered over the life
time of the field
For worked examples see Appendix 3.
In the event that in any one calendar year there is a
downward revision to the UR, to the extent that the downward
revision represents an adjustment to UR on "Reserves
Additions Bonus" applicable to the PSC in previous years,
Government shall have the right to require a recalculation of
the "Reserves Additions Bonus" in respect of those years. Any
additional PPT liability arising from the recomputation of
the "Reserves Additions Bonus" and the related tax offsets
shall be adjusted under terms of the PSC.
Notwithstanding the foregoing provisions to the contrary, the
Reserves Addition Bonus to be offset against PPT in respect
of reserves found prior to the first year of production shall
be the lesser of the annual average amount expended on Work
Programmes (as that term is defined under the PSC) prior to
such first year or the amount determined in accordance with
the following:
<TABLE>
<CAPTION>
Reserve Addition Rate
Reserves Found Prior Applied to the
to First Year of Production Respective Tranche
(Million Barrels) ($/BBL)
--------------------------- ---------------------
<S> <C>
Less than 40 nil
40 - 60 $0.25
60 - 90 $0.30
Greater than 90 $0.50
</TABLE>
2.10 RGT will be calculated in Naira each month (under the terms
outlined in this Memorandum) and compared for the same volume
of exports with Government Take for the same month under the
terms of the present (31/12/85) Royalty and PPT provisions.
Identical rates of exchange will be used to convert U.S.
Dollar prices to
-5-
<PAGE> 7
Naira in both Government Take and RGT calculations. The
amount by which RGT is less than Government Take each month
will be accumulated and at the end of the fiscal accounting
year will be applied as the annual tax credit to be offset
against PPT due for that fiscal accounting period.
2.11 For the purpose of the RGT formula, the terms and conditions
of Appendix A (attached to and forming part of this
Memorandum) including yield percentages of the three crude
streams (Bonny Light, Forcados, Bonny Medium), weighted for
each of the primary market areas as defined in Clause 2.12,
shall be mutually agreed for a 6 month period determined 3
months in advance. Thus the terms and conditions of Appendix
A applicable to the respective market for the period 1st
October through 31st March, will be determined on or before
the preceding 1st July, and for the period 1st April through
30th September, on or before the preceding 1st January. If
there is no mutual agreement, the terms and conditions of
Appendix A applicable to the preceding year and for the same
6 month period will prevail.
2.12 Appendix A shows the basis for determining the RP f.o.b.
Nigeria. The c.i.f. value for each of the crude streams shall
be calculated monthly by utilising the agreed product yield
and the average of mid-range product prices quoted each
quotation day for the period 1st to 20th day of the month of
lifting in Platt's Oilgram Price Report published by
McGraw-Hill Inc. ("Platt's") for each of the following
markets viz: cargoes c.i.f. North-West Europe basis ARA,
cargoes c.i.f. Mediterranean basis Genoa/Lavera (or if not
quoted cargoes f.o.b. basis Italy) and U.S. Gulf Coast
waterborne. In the USGC, L.P.G. will be priced at Platt's
quotation for Mont Belvieu Gas Liquids. Specific adjustments
for freight, ocean loss, insurance, and processing cost
applicable to each primary market shall be deducted in the
calculation of the Net Back Value ("NBV") Portion of the RP.
The final NBV Portion of the RP shall be determined by
comparing the NBV so calculated with the average of the
appropriate crude oil quotations as published in Platt's
effective for each quotation day for the period 1st to 20th
(inclusive) of the same month. The NBV shall be limited to a
range of plus or minus 40 (forty) US cents per US barrel
around the prices of BQ, Forcados Blend and Bonny Medium
through the following mechanism, where:
A: Initial NBV
B: Average Crude Oil Price (Bonny Light = Platt's BQ;
Forcados = Platt's Forcados; and Bonny Medium =
Platt's BQ - $1.20/bbl)
The Final NBV is equal to F2 as follows:
Fl: The greater of (B-40(cent)/bbl) and A
F2: The lesser of (B+40(cent)/bbl) and F1
-6-
<PAGE> 8
2.13 The Final NBV resulting from Clause 2.12 will be averaged
with crude oil price quotations to determine RP for each
crude stream as follows. Such RP for any month shall be
deemed as the RP for that month's liftings.
Bonny Light: The Final NBV for any month, calculated on the
basis of Appendix A, plus the average of mid range quotations
for BQ crude oil in Platt's for each quotation day for the
period 1st to 20th of the same month less $0.25/bbl, the
whole divided by two.
Bonny Medium: The Final NBV for any month, calculated on the
basis of Appendix A, plus the average of mid-range quotations
for BQ crude oil in Platt's for each quotation day for the
period 1st to 20th of the same month less $1.45/bbl the whole
divided by two.
Forcados: The Final NBV for any month, calculated on the
basis of Appendix A, plus the average of mid-range quotations
for Forcados crude oil in Platt's for each quotation day for
the period 1st to 20th of the same month less $0.25/bbl, the
whole divided by two.
2.14 The valuation basis for determining the RP for any new Crude
Oil stream produced from the Contract Area of the PSC shall
be established by mutual agreement of the Parties. It is the
intent of the Parties that such RP's shall reflect the true
market value of the Crude Oil obtainable through arms-length
transactions with independent third parties and that neither
Party should gain or lose on the pricing thereof relative to
its value in the market place. Such valuation basis shall be
established as follows:
(a) When a new segregated Crude Oil stream is produced,
a trial marketing period shall be designated which
shall extend for the first six (6) month period
during which such new stream is lifted or for the
period of time required for the first ten (10)
liftings whichever is longer. During the trial
marketing period the Parties shall:
(i) Collect samples of the new Crude Oil upon
which assays shall be performed;
(ii) Determine the approximate quality of the
new Crude Oil by estimating the yield
values from refinery modelling;
(iii) Share in the marketing such that each Party
markets approximately an equal amount of
the new Crude Oil;
(iv) Exchange information regarding the
marketing of the new Crude Oil including
documents which verify the sales price and
terms of each lifting;
-7-
<PAGE> 9
(v) Apply the actual f.o.b. sales price to
determine the NRP for each lifting; and
(vi) Arrange for payment by the purchaser of the
proceeds in accordance with Clause 9.5 of
the PSC.
(b) As soon as practical but in no event no later than
60 days later the end of the trial marketing period,
the Parties shall meet to review the assay, yield,
and actual sales data. Each Party may present a
proposal for the valuation of the new Crude Oil and
the Parties shall establish a mutually agreeable
valuation basis which implements the intent
expressed above. Upon the conclusion of the trial
marketing period, the Parties shall be entitled to
lift their allocation of Available Crude Oil
pursuant to the PSC. Until such time as the Parties
agree on a valuation method, the parties shall
continue to apply the actual f.o.b. sales price to
determine the RP for such liftings.
(c) When a new Crude Oil stream is produced from the
Contract Area and is commingled with an existing
Crude Oil produced in Nigeria which has an
established RP basis then such basis shall be
applied to the extent practical for determining the
RP of the new Crude Oil. The Parties shall meet and
mutually agree on any appropriate modifications to
such established valuation basis which may be
required to reflect any change in the market value
of the Crude Oils as a result of commingling.
(d) If in the opinion of either Party an agree RP
valuation fails to reflect the market value of a
Crude Oil produced in the Contract Area, then such
Party may propose to the other Party modifications
to the RP method. The Parties shall then meet within
thirty (30) days of such proposal and mutually agree
on any modifications to the NRP method necessary to
reflect the intent of the Parties as expressed in
10.1 of the PSC.
3. Conditions
In consideration for the granting of incentives, Company undertakes to
carry out the work programme attached hereto as Appendix B which is
identical to the minimum Work Programme provided under the PSC and
shall be governed under the terms thereof.
3.1 If Company does not substantially comply with the provision
of Appendix B for a relevant phase as specified in the work
programme, a notice thereof shall be served by NNPC on the
Company. If within three (3) months of the date of service
the Company fails to remedy the conditions which created the
notice the incentives described herein shall cease to apply
and the Conditions of Clause 2.1 shall be reinstated from
that date. The notice shall be communicated to the Federal
Inland Revenue Department at the end of the notice period.
After that date reinstatement of OSP for Posted Price, the
offset pricing formula and other terms and conditions of this
Memorandum shall apply only when such non-compliance shall
have been
-8-
<PAGE> 10
remedied. No notice shall be served by NNPC on the Company in
the case of force majeure or when there is a mutual agreement
by NNPC and Company or when a work programme is reduced by
mutual agreement.
4. Agreement of Government Agencies
Government confirms that the terms of this Memorandum have been agreed
by the appropriate Government Ministries in Nigeria including the
Ministry of Finance, the Federal Inland Revenue Department, and the
Central Bank of Nigeria. In consequence, Government guarantees that no
penalties, fines or other imposts including costs of litigation and/or
defence of the fiscal and foreign exchange arrangements included in
this Memorandum shall be imposed upon the operations related to the
PSC by reason of compliance with this Memorandum.
5. Force Majeure
No failure or omission to carry out or to observe any of the terms,
provisions or conditions of this Memorandum shall, except as is herein
expressly provided to the contrary, give rise to any claim by one
party hereto against the others or be deemed to be a breach of this
Memorandum, if such failure or omission arises from any cause
reasonably beyond the control of either party. Such cause may be but
is not limited to, acts of God, breakdown of vessels or of machinery
and equipment, civil unrest, strikes, lock-outs or labour disputes,
war, battle and commotion, or action of any relevant de facto
government. The rights of all parties shall be adjusted and to the
extent of their performance up to the time of the relevant event as is
reasonable in normal commercial practice and practicable in the
particular circumstances. As soon as practicable after the supervening
circumstances, the obligations under this Memorandum shall be resumed
by all parties as if there had been no interruption. Any party
claiming to be affected by such event shall give immediate notice in
writing of such claims to the other parties giving full particulars
thereof and furthermore shall give immediate notice in writing of the
cessation of any such event.
6. Effective Date
This Memorandum shall become effective from the 25th day of March
1992. Ashland may terminate this Memorandum having given one year's
prior notice to NNPC to withdraw.
7. Appendices
Appendices 1, 2(a & b), 3, A (including Attachment la), and B attached
hereto form part of this Memorandum.
-9-
<PAGE> 11
AS WITNESS the hands of the duly authorised representatives of the Parties the
day and year first above written.
SIGNED for and on behalf of
THE FEDERAL MILITARY GOVERNMENT
OF THE FEDERAL REPUBLIC OF NIGERIA
By: /s/ Chief D.O. Etiebet
-----------------------------
Name: CHIEF D.O. ETIEBET
Designation: HONOURABLE MINISTER OF PETROLEUM AND MINERAL RESOURCES
IN the presence of :
Name: Abdullahi Hashim
--------------------------------------------------------------------------
Signature: /s/ Abdullahi Hashim
---------------------------------------------------------------------
Designation: DG(P)
-------------------------------------------------------------------
Address: Ministry of Petroleum and Mineral Resources
-----------------------------------------------------------------------
- -------------------------------------------------------------------------------
-10-
<PAGE> 12
SIGNED for and on behalf of ASHLAND NIGERIA EXPLORATION, ULTD.
By: /s/ H.R. Benedict
----------------------------------------------------------------------------
Name: H.R. Benedict
--------------------------------------------------------------------------
Designation: Managing Director
IN the presence of :
Name: E.E.A. Skinn
--------------------------------------------------------------------------
Signature: /s/ E.E.A. Skinn
---------------------------------------------------------------------
Designation: Head, Joint Venture
-------------------------------------------------------------------
Address: Ashland Oil (Nig) Company ULTD
-----------------------------------------------------------------------
10 Bishop Aboyade, Cole Street, V/I, Lagos
-----------------------------------------------------------------------
-11-
<PAGE> 13
APPENDIX 1
PROCEDURE ON THE CALCULATION OF TECHNICAL COST PER BARREL WITH
REFERENCE TO THE MEMORANDUM OF UNDERSTANDING ON
INCENTIVES BETWEEN THE FEDERAL MILITARY GOVERNMENT
OF THE FEDERAL REPUBLIC OF NIGERIA
AND COMPANY - CLAUSE 2.3
The following expenses and costs reported by Company for the purposes of cost
recovery pursuant to the PSC during the period January/December of the year of
lifting shall be included in calculating the actual production cost per barrel
for the purpose of this Memorandum of Understanding.
(a) Production Operating Expenses: T(1)
(i) Direct Production Expenses as per items 400 and 401 of Report
No. 002 of Account Reporting Manual.
(ii) Portion of Administrative and General Expenses allocated to
Production - refer item 402 of Report No. 002 of Accounts
Reporting Manual.
(iii) Custom Duties and Gross Rentals allocated to Production -
refer items 4043 and 4045 of Report No. 002 of the Accounts
Reporting Manual.
(iv) Extra Ordinary/Prior Year Expenses/Incomes - refer item 405
of Report No. 002 Accounts Reporting Manual.
(b) Capital Investment Costs which qualify for expensing for PPT
calculation and chargeable to Production Costs: T(2)
(i) Exploration Drilling Costs.
(ii) Appraisal Drilling Cost (lst and 2nd Wells).
(iii) Intangible Drilling and Development Costs.
(iv) Capital Allowances - shall be restricted to the capital
allowances applicable direct to production and a share of the
capital allowances on overhead assets allocated to
production. Such Capital Allowance should be reconciled with
the Allowances claimed for the year under Section 15 of the
PPTA.
(c) It is expected that the Production Operating Expenses and Capital
Investment Costs above will be reconciled by Company with Report Nos.
002 and 001 of the Accounts Reporting Manual respectively.
-12-
<PAGE> 14
(d) The recommended basis for allocation of Expenses and Costs in a(ii),
a(iii) and a(iv) above to production shall be:
P
---------
E + P + X
Where:
P = The additions to the Capital costs during
the year and the Operating expenses for the
year reported by Ashland for the purposes
of cost recovery pursuant to the PSC which
are directly related to the production
function.
E = The addition to the Capital costs during
the year and the Operating expenses for the
year reported by Ashland for the purposes
of cost recovery pursuant to the PSC which
are directly related to the exploration
function.
X = Any other expenditures other than
Production and Exploration functions which
are reported by Ashland for the purposes of
cost recovery pursuant to the PSC.
(e) Production Cost Per Barrel = (a)(i) to (iv) + (b)(i) to ( iv )
---------------------------------
Annual Production (Barrels)
(f) The advice on cost per barrel forwarded to NNPC should be supported
with a working paper.
-13-
<PAGE> 15
APPENDIX 2 (a)
WORKED EXAMPLES FOR ESTABLISHING THE GUARANTEED
NOTIONAL MARGIN FOR R.P. LESS THAN $12.5/BBL - CLAUSE 2.6
WHERE FC = $2.50/BBL
1.) If RP = $4
RP(1) = $4
a(1) = 0.30
and FC = $2.5
Margin M = (1 - 2.5) x (4 x 0.30)
---
4
= 0.375 x 1.2
M = $0.45
=======================
2.) If RP = $9
RP(1) = $5
a(1) = 0.30
RP(2) = $4
a(2) = 0.22
M = (1 - 2.5) x (5 x 0.30 + 4 x 0.22)
---
9
= 0.722 x 2.38
M = $1.719
========================
3.) If RP = $11
RP(1) = $5
a(1) = 0.30
-14-
<PAGE> 16
RP(2) = $5
a(2) = 0.22
RP(3) = $1
a(3) = 0.11
and M = (1 - 2.5) x (5 x 0.30+5 x 0.22+1 x 0.11)
----
11
= 0.7727 x 2.71
M = $2.094
========================
4.) If RP = $12.50
a(1) = 0.30
RP(1) = $5
a(2) = 0.22
RP(2) = $5
a(3) = 0.11
RP(3) = $2.50
and M = (1 - 2.5) x (5 x 0.30+5 x 0.22+2.5 x 0.11)
-----
12.50
= 0.80 x 2.875
M = $2.30
=======================
-15-
<PAGE> 17
APPENDIX 2(B)
WORKED EXAMPLES FOR ESTABLISHING THE GUARANTEED
NOTIONAL MARGIN FOR R.P. LESS THAN $12.5/BBL - CLAUSE 2.6
WHERE FC = $3.50/BBL
1.) If RP = $4
RP(l) = $4
a(l) = 0.365
and FC = $3.5
Margin M = (1 - 3.5) x (4 x 0.365)
---
4
= 0.125 x 1.46
M = $0.1825
=========================
2.) If RP = $9
RP(1) = $5
a(1) = 0.365
RP(2) = $4
a(2) = 0.263
M = (1 - 3.5) x (5 x 0.365 + 4 x 0.263)
---
9
= 0.611 x 2.877
M = $1.758
========================
3.) If RP = $11
RP(l) = $5
a(l) = 0.365
-16-
<PAGE> 18
RP(2) = $5
a(2) = 0.263
RP(3) = $1
a(3) = 0.131
and M = (1-3.5) x (5 x 0.365+5 x 0.263+1 x 0.131)
----
11
= 0.6818 x 3.271
M = $2.23
=======================
4.) If RP = $12.50
a(l) = 0.365
RP(l) = $5
a(2) = 0.263
RP(2) = $5
a(3) = 0.131
RP(3) = $2.50
and M = (1-3.50) x (5 x 0.365+5 x 0.263+2.5 x 0.131)
----
12
= 0.72 x 3.4675
M = $2.50
==================
-17-
<PAGE> 19
APPENDIX 3
WORKED EXAMPLES ON COMPUTATION OF RESERVES
ADDITION BONUS
1.) Take UR End Year = 640 million barrels
UR Begin Year = 400 million barrels
Annual Production = 200 million barrels
R = 640 - 400
---------------
200
= 1.2
Ra(1) = 0.2
X(1) = $0.10/bbl
.' . Bonus = ][Ra(1) X(1)] P
= [(0.2) (0.10)] x 200
= US$4.0 million
==============
2.) Take UR End Year = 700 million barrels
UR Begin Year = 400 million barrels
Annual Production = 200 million barrels
R = 700 - 400
---------------
200
= 1.5
Ra1 = 0.25
Ra2 = 0.25
X1 = $0.10/bbl
X2 = $0.25/bbl
. ' . Bonus = [(Ra(1)X(1)) + (Ra(2)X(2))] P
-18-
<PAGE> 20
<TABLE>
<S> <C>
= [(0.25)(0.10)+(0.25)(0.25)] x 200
= US$17.5 million
3.) Take UR End Year = 740 million barrels
UR Begin Year = 400 million barrels
Annual Production = 200 million barrels
R = 740 - 400
---------------
200
= 1.7
Ra(1) = 0.25
Ra(2) = 0.25
Ra(3) = 0.20
X(1) = $0.10/bbl
X(2) = $0.25/bbl
X3 = $0.40/bbl
. ' . Bonus = [Ra(1)X(1) + Ra(2)X(2) + Ra(3)X(3)] P
= [(.25)(.10)+(.25)(.25)+(.20)(.40)]x200
= US$33.5 million
4.) Take UR End Year = 900 million barrels
UR Begin Year = 400 million barrels
Annual Production = 200 million barrels
R = 900 - 400
---------------
200
= 2.5
Ra(1) = 0.25
</TABLE>
-19-
<PAGE> 21
<TABLE>
<S> <C>
Ra(2) = 0.25
Ra(3) = 0.25
Ra(4) = 0.75
X(1) = $0.10/bbl
X(2) = $0.25/bbl
X(3) = $0.40/bbl
X(4) = $0.50/bbl
. ' . Bonus = [Ra(1) X(1)+ Ra(2) X(2)+ Ra(3) X(3) + Ra(4) X(4)] P
= [(.25)(.10) + (.25) (.25) + (.25) (.40)
+ (.75) (.50)] x 200
= US$112.5 million
================
</TABLE>
-20-
<PAGE> 22
APPENDIX A
CALCULATION OF REALISABLE PRICE
The market weighted FOB Nigeria Net Back Value ("NBV") for the purpose
of calculating Realisable Price under this Memorandum shall be calculated from
the data given below and in accordance with the worked example shown in
Attachment 1 to this Appendix A.
<TABLE>
<S> <C> <C>
1. Delivery Each export grade of crude oil will be deemed delivered to:
U.S. Gulf Coast (USGC) 60 per cent
North West Europe (NWE) 20 per cent
Mediterranean (MED) 20 per cent
2. Grades The export grades of crude oil are:
Bonny Light of standard export gravity 37 degrees API
Forcados Blend of standard export gravity 31 degrees "
Bonny Medium of standard export gravity 26 degrees "
Qua Iboe Light of standard export gravity 37 degrees "
Escravos Light of standard export gravity 36 degrees "
Brass Blend of standard export gravity 43 degrees "
Pennington Light of standard export gravity 36 degrees "
Commingled Antan of standard export gravity 32 degrees "
3. Conversion Factors
Bonny Light 7.5060 barrels per metric tonne
Forcados Blend 7.2390 " " " "
Bonny Medium 7.0160 " " " "
Qua Iboe Light 7.5060 " " " "
Escravos Light 7.4625 " " " "
Brass Blend 7.7741 " " " "
Pennington Light 7.2396 " " " "
Commingled Antan 7.2844 " " " "
</TABLE>
-21-
<PAGE> 23
4. Yields The following refinery yields will be applied to each
geographical area unless amended under the terms of Clause
2.12 of this Memorandum
U.S. Gulf Coast (expressed as Volume %)
(Same yields apply Summer and Winter)
<TABLE>
<CAPTION>
BONNY LIGHT FORCADOS BLEND BONNY MEDIUM
----------- -------------- ------------
% Vol. % Vol. % Vol.
<S> <C> <C> <C>
LPG Propane 2.30 2.40 2.50
LPG Normal 2.30 2.40 2.50
Butane
Gasoline Regular 17.80 16.42 14.25
Gasoline 17.80 16.43 14.25
Unleaded
Naphtha 12.30 8.30 5.20
Jet Kero 12.80 10.50 8.50
No. 2 Oil 22.40 29.55 36.70
Max 1% S Fuel 12.30 14.00 16.10
Oil
Refy Fuel Loss -- -- --
TOTAL 100.00 100.00 100.00
</TABLE>
NORTH WEST EUROPE (NWE) AND MEDITERRANEAN (MED)
(Expressed as Weight %)
<TABLE>
<CAPTION>
Summer Winter
% wt. % wt.
------ ------
<S> <C> <C>
BONNY LIGHT
Gasoline
Premium 24.50 20.00
Regular 8.60 8.50
Jet Kerosene 10.00 8.50
Gasoil 23.10 34.50
Fuel Oil 1% 28.80 23.50
Refy Fuel/Loss 5.00 5.00
TOTAL 100.00 100.00
</TABLE>
-22-
<PAGE> 24
FORCADOS BLEND
<TABLE>
<S> <C> <C>
Gasoline
Premium 19.00 15.40
Regular 7.50 5.80
Jet Kerosene 8.80 8.80
Gasoil 29.00 36.30
Fuel Oil 1% 30.70 28.70
Refy Fuel/Loss 5.00 5.00
TOTAL 100.00 100.00
</TABLE>
BONNY MEDIUM
<TABLE>
<S> <C> <C>
Gasoline
Premium 8.70 7.00
Regular 3.60 3.00
Jet Kerosene 8.00 6.00
Gasoil 27.60 30.50
Fuel Oil 1% 47.50 48.90
Refy Fuel/Loss 4.60 4.60
TOTAL 100.00 100.00
</TABLE>
Summer yields are to be used for the calculation of all prices for the
months of April, May, June, July, August and September.
The Winter yields will apply for the months of October, November,
December, January, February and March.
5. Processing Fees
U.S. Gulf - $1.90 per barrel
NWE - $1.40 " "
MED - $1.30 " "
6. Valuation of Refined Products:
Reference to Platt's quotations outlined in Attachment 1a to Appendix
A will be made to value the refinery yields in accordance with Clause
2.12 of this Memorandum. In each case the average of the mid-range
product prices for each quotation day for the period 1st to 20th
(inclusive) of the month in question will be used.
-23-
<PAGE> 25
7. Freight
US Gulf Coast - LR 2 for Bonny Light and Forcados,
one port loading and one port
discharge.
- LR 1 for Bonny Medium one port
loading and one port discharge.
NWE and MED - 25% VLCC plus 75% LR 2 for Bonny
Light and Forcados, one port
loading and one port discharge.
- LR 1 for Bonny Medium, one port
loading and one port discharge.
Freight rates for the various ship sizes will be based on monthly
assessments obtained from the London Tanker Brokers Panel.
8. Insurance and Outturn Loss
The following will be allowable deductions in the calculation of the
realisable price.
Insurance $0.03 per barrel
Outturn Loss $0.05 per barrel
9. Method used in Calculating NBV
See Attachment 1 to this Appendix.
10. Price Differentials Between Bonny Light Final Realisable Price and
Other Nigerian Light Crude Oil Grades
Bonny Light will be used as the reference crude for all other Nigerian
crude oils except Forcados and Bonny Medium. Forcados crude is
separately quoted in Platt's while Bonny Medium will be taken as BBQ
less $1.20 per barrel. The differential between Bonny Light and other
Nigerian Light grades shall be as follows:
<TABLE>
<CAPTION>
0 Less than $20/bbl Less than
Price Range RP Less than or equal to $20/bbl RP Less than or equal to $25/bbl $25/bbl Less than RP
-------------------------------- -------------------------------- --------------------
<S> <C> <C> <C>
Brass - - -
Qua Iboe 5 cents 7.5 cents 10 cents
Escravos 10 cents 12.5 cents 15 cents
Pennington 5 cents 7.5 cents 10 cents
</TABLE>
-24-
<PAGE> 26
11. Formula for Realisable Price
Bonny Light (BL) = BBQ - $0.25/bbl + NBV
---------------------
2
Forcados Blend (FB) = FB - $0.25/bbl + NBV
--------------------
2
Bonny Medium (BM) = BBQ - $1.45/bbl + NBV
---------------------
2
with NBV limited to a $0.40 per barrel tunnel around BBQ, Forcados and
Bonny Medium.
-25-
<PAGE> 27
APPENDIX A - ATTACHMENT 1A
QUOTATIONS USED IN REALISABLE PRICE CALCULATIONS
<TABLE>
<CAPTION>
Market Product Quotation Source
- ------ ------- --------- ------
<S> <C> <C> <C>
USGC LPG Propane Propane Gas Liquids - Mont Belvieu
LPG Normal Butane Normal Butane Gas Liquids - Mont Belvieu
Gasoline Regular Unl. 87 US Gulf Coast - Waterborne
Gasoline Unleaded Unl. 87 US Gulf Coast - Waterborne
Naphtha Naphtha US Gulf Coast - Waterborne
Jet Kero. Jet Kerosene US Gulf Coast - Waterborne
No. 2 Oil No. 2 Oil US Gulf Coast - Waterborne
Max. 1.0%S Fuel Oil No. 6 1.0%S US Gulf Coast - Waterborne
NWE Gasoline Premium Prem. 0.15% Cargoes CIF NWE Basis ARA
Gasoline Regular Reg Unlx0.925 Cargoes CIF NWE Basis ARA
Jet Kerosene Jet Kerosene Cargoes CIF NWE Basis ARA
Gasoil Gasoil 0.2 x 0.85 + Gasoil 0.3 x 0.15 Cargoes CIF NWE Basis ARA
Fuel Oil 1.0% 1% Fuel Oil Cargoes CIF NWE Basis ARA
MED Gasoline Premium Prem 0.25% until 31/5/91 Cargoes CIF Med Basis Genoa/Lavera
Prem 0.15% x 0.98 after 31/5/91 Cargoes CIF Med Basis Genoa/Lavera
Gasoline Regular Prem 0.25% x 0.921 until 31/5/91 Cargoes CIF Med Basis Genoa/Lavera
Prem 0.15% x 0.903 after 31/5/91 Cargoes CIF Med Basis Genoa/Lavera
Jet Kerosene Jet Kerosene Cargoes CIF Med Basis Genoa/Lavera
Gasoil Gasoil Cargoes CIF Med Basis Genoa/Lavera
Fuel Oil 1.0% 1% Fuel Oil Cargoes CIF Med Basis Genoa/Lavera
</TABLE>
For Mediterranean, when cargoes CIF are not quoted, use FOB quotation.
-26-
<PAGE> 28
APPENDIX A - ATTACHMENT 1
WORKED EXAMPLE OF NETBACK CALCULATION TO DETERMINE
REALISABLE PRICE FOR BONNY LIGHT CRUDE
Note:
All figures calculated are rounded to 4 decimal places, that is rounding down
if the 5th decimal place is 4 or less, otherwise rounding up.
Realisable Prices are based on the standard export gravities as per Paragraph 2
of this Appendix. The final calculated Realisable Prices will be adjusted to
take account of API variations as follows:
For each 0.1 deg. API difference above or below the reference gravity,
an adjustment of $0.003 per barrel will be added to or subtracted from
the calculated Realisable Price.
Section 1 - Calculation of NBV per Market
(A) U.S. Gulf Coast (USGC)
<TABLE>
<CAPTION>
Yields
Cents/Gallon $/bbl % Vol. $/bbl
------------ ----- ------ -----
<S> <C> <C> <C> <C>
LPG Propane 29.8846 x .42 = 12.5515 x 2.30 = 0.2887
LPG Normal Butane 43.0962 x .42 = 18.1004 x 2.30 = 0.4163
Gasoline Regular 60.1827 x .42 = 25.2767 x 17.80 = 4.4993
Gasoline Unleaded 60.1827 x .42 = 25.8876 x 17.80 = 4.4993
Naphtha 60.8173 x .42 = 25.5433 x 12.30 = 3.1418
Jet Kerosene 66.7019 x .42 = 28.0148 x 12.80 = 3.5859
No. 2 H.O. 66.4135 x .42 = 27.8937 x 22.40 = 6.2482
Max 1.0% S F.O. ($/bbl) = 11.5962 x 12.30 = 1.4263
-------
Gross Product Worth (GPW) 24.1058
Conversion Factor 7.506
</TABLE>
From the above, following deductions to apply:
<TABLE>
<S> <C> <C> <C> <C>
Processing Fee 1.9000
Freight Flat Rate LR 2 Conversion
($/MT) (WS Points) Factor
--------- ----------- ----------
10.62 x 125.8% / 7.506 = 1.7799
Outturn Loss 0.0500
Insurance 0.0300
(a) Netback - USGC ($/bbl) 20.3459
</TABLE>
-27-
<PAGE> 29
(B) North West Europe (NWE)
<TABLE>
<CAPTION>
Yields
$/MT % wt. $/MT
---- ------ ----
<S> <C> <C> <C>
Gasoline Premium = 242.6923 x 20.00 = 48.5385
Gasoline Regular = 210.3664 x 8.50 = 17.8811
Jet Kerosene = 308.6538 x 8.50 = 26.2356
Gasoil = 287.6346 x 34.50 = 99.2339
Fuel Oil 1% = 93.0000 x 23.50 = 21.8550
Refinery Fuel and Loss = 5.00 = -
--------
Gross Product Worth (GPW) - ($/MT) = 213.7441
Conversion Factor 7.506
Gross Product Worth (GPW) - ($/bbl) = 28.4764
From the above, following deductions to apply:
</TABLE>
<TABLE>
<CAPTION>
Processing Fee 1.4000
Freight Flat Rate Vessel Class Conversion
($/MT) (WS points) Factor
--------- ------------ ----------
<S> <C> <C> <C> <C>
LR2 - 75% 8.79 x 130.4%/ 7.506 = 1.1453
VLCC - 25% 8.79 x 90.0%/ 7.506 = 0.2635
Outturn Loss 0.0500
Insurance 0.0300
(b) netback - NWE ($/bbl) 25.5876
</TABLE>
(C) Mediterranean (MED)
<TABLE>
<CAPTION>
Yields
$/MT % wt. $/MT
---- ------ ----
<S> <C> <C> <C>
Gasoline Premium = 238.0000 x 20.00 = 47.6000
Gasoline Regular = 219.1980 x 8.50 = 18.6318
Jet Kerosene = 307.5385 x 8.50 = 26.1408
Gasoil = 294.3846 x 34.50 = 101.5627
Fuel Oil 1 = 98.3077 x 23.50 = 23.1023
Refinery Fuel and Loss = 5.00 = -
--------
Gross Product Worth (GPW) - ($/MT) = 217.0376
Conversion Factor 7.506
Gross Product Worth (GPW) - ($/bbl) = 28.9152
</TABLE>
From the above, following deductions to apply:
-28-
ASH_MEM.WPD
<PAGE> 30
<TABLE>
<CAPTION>
Processing Fee 1.3000
Freight Flat Rate Vessel Class Conversion
($/MT) (WS points) Factor
--------- ------------ ----------
<S> <C> <C> <C> <C>
LR2 - 75% 8.16 x 131.0%/ 7.506 = 1.0681
VLCC - 25% 8.16 x 85.0%/ 7.506 = 0.2310
Outturn Loss 0.0500
Insurance 0.0300
(c) Netback - MED ($/bbl) 26.2361
</TABLE>
Section 2 - Calculation of NBV
<TABLE>
<CAPTION>
Market Weighting Netback Contribution
------ --------- ------- ------------
<S> <C> <C> <C> <C>
(a) USGC 60% x 20.3459 = 12.2075
(b) NWE 20% x 25.5876 = 5.1175
(c) MED 20% x 26.2361 = 5.2472
--------
(d) Initial NBV ($/bbl) = 22.5722
</TABLE>
Section 3 - Calculation of Final NBV
<TABLE>
<S> <C>
A. Initial NBV 22.5722
B. BBQ Average 20.8712
F1. Greater of (B-$.40) and A 22.5722
F2. Lesser of (B+$.40) and F1 21.2712
(e) Final NBV ($/bbl) 21.2712
</TABLE>
NOTE:
NBV shall be adjusted only if its value is greater/lower than BBQ by
more than 40 cents per barrel.
Section 4 - Calculation of Realisable Price
<TABLE>
<S> <C> <C>
Crude Element BBQ 20.8712
Less $.25/bbl differential 0.2500
--------
(i) 20.6212
Product Element Final NBV (ii) 21.2712
Average of (i) and (ii) 20.9462
Realisable Price for Bonny Light ($/bbl) = 20.9462
</TABLE>
-29-
<PAGE> 31
APPENDIX B
WORK PROGRAMME AND EXPENDITURES PROVIDED
UNDER THAT CERTAIN PRODUCTION SHARING CONTRACT (PSC)
DATED MARCH 25, 1992
CLAUSE 6
WORK PROGRAMME AND EXPENDITURES
6.1 Company shall within six (6) months after the Effective Date, unless
mutually extended by the Parties, commence seismic investigations in
the Contract Area and thereafter shall commence drilling operations in
accordance with sound international petroleum practices. Geologic
conditions warranting, drilling operations will be commenced not later
than eighteen (18) months after the Effective Date unless mutually
extended by the Parties.
6.2 Company shall conduct Petroleum Operations during the first five (5)
years following the Effective Date in accordance with the minimum Work
Programme provided in this Clause 6.2 which shall be conducted in two
phases as follows:
(a) For the first phase, during the initial three (3) year period
following the Effective Date, the minimum Work Programme
shall consist of 2,000 km of 2-D seismic, 200 sq km of 3-D
seismic and the drilling of three (3) wells; provided
however, that Company shall have no obligation to expend more
than twenty million U.S. Dollars ($20,000,000) for Petroleum
Operations during such period with respect to this first
phase even if the said minimum Work Programme has not been
accomplished. The minimum Work Programme hereunder and the
cost therefor shall include such work, if any, incurred by
the Company prior to the Effective Date pursuant to Clause 15
of the Letter of Understanding between NNPC and an Affiliate
of Company dated 16th August, 1991.
(b) For the second phase, during the subsequent two (2) year
period the minimum Work Programme shall consist of three (3)
additional wells; provided however, that Company shall have
no obligation to expend more than ten million U.S. Dollars
($10,000,000) for Petroleum Operations during such two (2)
year period with respect to this second phase even if the
said minimum Work Programme has not been accomplished.
If at any time within the initial three (3) year period (the first
phase above) Company should terminate this Contract pursuant to Clause
4 prior to fulfilling the minimum Work Programme outlined in Clause o
6.2(a) then Company shall pay to NNPC the difference between twenty
million U.S. Dollars ($20,000,000) and the actual amount expended.
Should Company terminate this Contract pursuant to Clause 4 within the
subsequent two (2) year period (the second phase above) prior to
fulfilling the minimum Work Programme outlined in Clause 6.2(b) then
Company shall pay to NNPC the difference between ten million U.S.
Dollars ($10,000,000) and the actual amount expended. Provided
however, should the actual
-30-
<PAGE> 32
amount expended with respect to the first phase exceed twenty million
U.S. Dollars ($20,000,000), such excess shall be applied against the
expenditure for the second phase, such that Company shall have no
obligation to expend in the aggregate more than thirty million U.S.
Dollars ($30,000,000) for Petroleum Operations during the first five
(5) year period from the Effective Date.
6.3 Within two (2) months after the Effective Date and thereafter at least
three (3) months prior to the beginning of each Year, Company shall
prepare and submit for review and approval by the Management
Committee, pursuant to Clause 7, a Work Programme and Budget for the
Contract Area setting forth the Petroleum Operations which Company
proposes to carry out during the ensuing Year, or in the case of the
first Work Programme and Budget, during the remainder of the current
Year. The Management Committee shall review and approve such Work
Programme and Budget in accordance with Clause 7.4.
-31-
<PAGE> 1
Ashland Exploration, Inc.
Senior Credit Facility
Commitment Letter
February 25, 1997
Ashland Exploration, Inc.
14701 St. Mary's Lane, Suite 200
Houston, TX 77079
Attention: Mr. Robert C. Bilger
Ladies and Gentlemen:
You have advised The Chase Manhattan Bank ("Chase") and Chase
Securities Inc. ("CSI") that Ashland, Inc. plans a public offering of up to
19.9% of the common stock of its existing wholly-owned subsidiary Ashland
Exploration, Inc. (the "Borrower" or "you"). In that connection, you have
requested that CSI agree to structure, arrange and syndicate for you a senior
credit facility in an aggregate amount of up to $200 million (the "Facility")
and that Chase commit to provide the entire principal amount of the Facility
and to serve as administrative agent for the Facility.
CSI is pleased to advise you that it is willing to act as
exclusive advisor and arranger for the Facility.
Furthermore, Chase is pleased to advise you of (a) its
commitment to provide the entire amount of the Facility, and (b) its agreement
to use commercially reasonable efforts to assemble a syndicate of financial
institutions identified by CSI and Chase in consultation with you, to join
Chase in providing commitments for the Facility, in each case upon the terms
and subject to the conditions set forth or referred to in this commitment
letter (this "Commitment Letter") and in the Summary of Terms and Conditions
attached hereto as Exhibit A (the "Term Sheet").
<PAGE> 2
It is agreed that Chase will act as the sole and exclusive
Administrative Agent, and that CSI will act as the sole and exclusive advisor
and arranger, and that J.P. Morgan will be offered the title of Documentation
Agent, and that National Westminster Bank PLC will be offered the title of
Syndication Agent for the Facility, and each will, in such capacities, perform
the duties and exercise the authority customarily performed and exercised by it
in such roles. You agree that no other agents, co-agents or arrangers will be
appointed, no other titles will be awarded and no compensation (other than that
expressly contemplated by the Term Sheet and the Fee Letter referred to below)
will be paid in connection with the Facility unless you and we shall so agree.
Notwithstanding that the Facility is fully underwritten by
Chase, CSI intends to syndicate the Facility to a group of financial
institutions (together with Chase, the "Lenders") identified by us in
consultation with you. CSI intends to commence syndication efforts promptly
upon the execution of this Commitment Letter, and you agree actively to assist
CSI in completing a syndication satisfactory to it. Such assistance shall
include (a) your using commercially reasonable efforts to ensure that the
syndication efforts benefit materially from your existing lender relationships,
(b) direct contact between senior management and advisors of the Borrower and
the proposed Lenders, (c) assistance in the preparation of a Confidential
Information Memorandum and other marketing materials to be used in connection
with the syndication and (d) the hosting, with CSI, of one or more meetings of
prospective Lenders.
CSI, in consultation with you, will manage all aspects of the
syndication, including decisions as to the selection of institutions to be
approached and when they will be approached, when their commitments will be
accepted, which institutions will participate, the allocations of the
commitments among the Lenders and the amount and distribution of fees among the
Lenders. To assist CSI in its syndication efforts, you agree, to the extent
permitted by law, promptly to prepare and provide to CSI and Chase all
information with respect to the Borrower, including all financial information
and projections (the "Projections"), as we may reasonably request in connection
with the arrangement and syndication of the Facility. You hereby represent and
covenant that (a) all information other than the Projections (the
"Information") that has been or will be made available to Chase or CSI by you
or any of your representatives is or will be, when furnished, complete and
correct in all material respects and does not or will not, when furnished,
contain any untrue statement of a material fact or omit to state a material
fact necessary in order to make the statements contained therein not materially
misleading in light of the circumstances under which such statements are made
and (b) the Projections that have been or will be made available to Chase or
CSI by you or any of your representatives have been or will be prepared in good
faith based upon reasonable assumptions. You understand that in arranging and
syndicating the Facility we may use and rely on the Information and Projections
without independent verification thereof. You hereby acknowledge and consent
that CSI may share the Confidential Information Memorandum, the Information and
any other information or matters relating to the Borrower or the transaction
contemplated hereby with affiliates of CSI, including The Chase Manhattan Bank,
and Chase, and that such affiliates may likewise share information relating to
the Borrower or such transactions with CSI.
-2-
<PAGE> 3
Ashland Exploration, Inc.
Commitment Letter
February 25, 1997
As consideration for Chase's commitment hereunder and CSI's
agreement to perform the services described herein, you agree to pay to Chase
the nonrefundable fees set forth in Schedule I to the Term Sheet and in the Fee
Letter dated the date hereof and delivered herewith (the "Fee Letter").
Chase's commitment hereunder and CSI's agreement to perform
the services described herein are subject to (a) there not occurring or
becoming known to us any material adverse condition or material adverse change
in or affecting the business, operations, property, condition (financial or
otherwise) or prospects of the Borrower and its subsidiaries, taken as a whole,
(b) our completion of and satisfaction in all respects with a due diligence
investigation of the Borrower, (c) our not becoming aware after the date hereof
of any information or other matter affecting the Borrower or the transactions
contemplated hereby which is inconsistent in a material and adverse manner with
any such information or other matter disclosed to us prior to the date hereof,
(d) there not having occurred a material disruption of or material adverse
change in financial, banking or capital market conditions that, in our
judgment, could materially impair the syndication of the Facility, (e) our
satisfaction that prior to and during the syndication of the Facility there
shall be no competing offering, placement or arrangement of any debt securities
or bank financing by or on behalf of the Borrower or any affiliate thereof, (f)
the negotiation, execution and delivery on or before April 30, 1997 of
definitive documentation with respect to the Facility satisfactory to Chase and
its counsel and (g) the other conditions set forth or referred to in the Term
Sheet. The terms and conditions of Chase's commitment hereunder and of the
Facility are not limited to those set forth herein and in the Term Sheet.
Those matters that are not covered by the provisions hereof and of the Term
Sheet are subject to the approval and agreement of Chase, CSI and the Borrower.
-3-
<PAGE> 4
Ashland Exploration, Inc.
Commitment Letter
February 25, 1997
You agree to indemnify and hold harmless Chase, CSI, their
affiliates and their respective officers, directors, employees, advisors, and
agents (each, an "Indemnified Person") from and against any and all losses,
claims, damages and liabilities (the "Losses") to which any such Indemnified
Person may become subject arising out of or in connection with this Commitment
Letter, the Facility, the use of the proceeds thereof, or any related
transaction or any claim, litigation, investigation or proceeding relating to
any of the foregoing, regardless of whether any Indemnified Person is a party
thereto, and to reimburse each Indemnified Person upon demand for any legal or
other expenses incurred in connection with investigating or defending any of
the foregoing, provided that the foregoing indemnity will not, as to any
Indemnified Person, apply to Losses or related expenses to the extent they
arise from the willful misconduct or gross negligence of such Indemnified
Person. YOU AGREE THAT THE INDEMNITY CONTAINED IN THE PRECEDING SENTENCE
EXTENDS TO AND IS INTENDED TO COVER LOSSES AND RELATED EXPENSES ARISING OUT OF
THE ORDINARY, SOLE OR CONTRIBUTORY NEGLIGENCE OF AN INDEMNIFIED PERSON. In
addition, you agree to reimburse Chase, CSI and their affiliates on demand for
all out-of-pocket expenses (including due diligence expenses, syndication
expenses, travel expenses, and reasonable fees, charges and disbursements of
counsel) incurred in connection with the Facility and any related documentation
(including this Commitment Letter, the Term Sheet, the Fee Letter and the
definitive financing documentation) or the administration, amendment,
modification or waiver thereof. No Indemnified Person shall be liable for any
indirect or consequential damages in connection with its activities related to
the Facility.
This Commitment Letter shall not be assignable by you without
the prior written consent of Chase and CSI (and any purported assignment
without such consent shall be null and void), is intended to be solely for the
benefit of the parties hereto and is not intended to confer any benefits upon,
or create any rights in favor of, any person other than the parties hereto.
This Commitment Letter may not be amended or waived except by an instrument in
writing signed by you, Chase and CSI. This Commitment Letter may be executed
in any number of counterparts, each of which shall be an original, and all of
which, when taken together, shall constitute one agreement. Delivery of an
executed signature page of this Commitment Letter by facsimile transmission
shall be effective as delivery of a manually executed counterpart hereof. This
Commitment Letter (together with the Term Sheet) and the Fee Letter are the
only agreements that have been entered into among us with respect to the
Facility and set forth the entire understanding of the parties with respect
thereto. THIS COMMITMENT LETTER SHALL BE GOVERNED BY, AND CONSTRUED IN
ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.
-4-
<PAGE> 5
Ashland Exploration, Inc.
Commitment Letter
February 25, 1997
This Commitment Letter is delivered to you on the
understanding that neither this Commitment Letter, the Term Sheet or the Fee
Letter nor any of their terms or substance shall be disclosed, directly or
indirectly, to any other person except (a) to your officers, agents and
advisors who are directly involved in the consideration of this matter, (b) as
may be compelled in a judicial or administrative proceeding or as otherwise
required by law (in which case you agree to inform us promptly thereof) or (c)
as necessary or advisable in connection with a public offering or other
distribution of the Borrower's equity securities.
Chase and CSI each agree that we will use our best efforts not
to disclose without your prior written consent (other than to our employees,
auditors or counsel) the Projections or any other information with respect to
you or your assets which is furnished pursuant to this Commitment or the
Facility and which is designated by you in writing as confidential, provided
that Chase and/or CSI may disclose any such information (a) as has become
generally available to the public, (b) as may be required or appropriate in any
report, statement or testimony submitted to any municipal, state or Federal
regulatory body having or claiming to have jurisdiction over either of us or to
the Federal Reserve Board or Federal Deposit Insurance Corporation or similar
organizations (whether in the United States or elsewhere) or their successors,
(c) as may be required or appropriate in response to any summons or subpoena or
in connection with any litigation or in connection with the exercise of any
remedies under the Facility and (d) to the prospective Lenders, provided that
each such prospective Lender executes an agreement with you containing
provisions substantially identical to those contained in this paragraph.
-5-
<PAGE> 6
Ashland Exploration, Inc.
Commitment Letter
February 25, 1997
The reimbursement, indemnification and confidentiality
provisions contained herein and in the Fee Letter shall remain in full force
and effect regardless of whether definitive financing documentation shall be
executed and delivered and notwithstanding the termination of this Commitment
Letter or Chase's commitment hereunder.
THIS COMMITMENT LETTER, THE ATTACHED TERM SHEET, THE FEE
LETTER AND ALL EXHIBITS, SCHEDULES AND OTHER ATTACHMENTS HERETO AND THERETO
CONSTITUTE A "LOAN AGREEMENT" AND REPRESENT THE FINAL AGREEMENT BETWEEN THE
PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OR PRIOR, CONTEMPORANEOUS OR
SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL
AGREEMENTS BETWEEN THE PARTIES.
If the foregoing correctly sets forth our agreement, please
indicate your acceptance of the terms hereof and of the Term Sheet and the Fee
Letter by returning to us executed counterparts hereof and of the Fee Letter
not later than 5:00 p.m., Houston, Texas time, on February 28, 1997. Chase's
commitment and CSI's agreements herein will expire at such time in the event
Chase has not received such executed counterparts in accordance with the
immediately preceding sentence.
-6-
<PAGE> 7
Ashland Exploration, Inc.
Commitment Letter
February 25, 1997
Chase and CSI are pleased to have been given the opportunity
to assist you in connection with this important financing.
Very truly yours,
THE CHASE MANHATTAN BANK
By: /s/ MARY JO WOODFORD
Name: Title:
CHASE SECURITIES INC.
By: /s/ GEORGE M. SERICE
Name: Title:
Accepted and agreed to as of
ASHLAND EXPLORATION, INC.
By: /s/ ROBERT C. BILGER
Name: Robert C. Bilger
Title: Senior Vice President
-7-
<PAGE> 8
Ashland Exploration, Inc.
Senior Credit Facility
Fee Letter
February 25, 1997
Ashland Exploration, Inc.
14701 St. Mary's Lane, Suite 200
Houston, TX 77079
Attention: Mr. Robert C. Bilger
Ladies and Gentlemen:
Reference is made to the Commitment Letter
dated the date hereof (including the attached Term
Sheet, the "Commitment Letter") between us and you
regarding the Facility described therein. Capitalized
terms used but not defined herein are used with the
meanings assigned to them in the Commitment Letter.
This letter agreement is the Fee Letter referred to in
the Commitment Letter.
As consideration for CSI's agreement to
arrange the Facility and Chase's commitment under the
Commitment Letter, you agree to pay the following fees:
A. An arrangement fee in a total amount equal to
$175,000, which fee will be payable to CSI
on the date on which the documentation
evidencing the Facility is executed (the
"Closing Date").
A. (i) If syndication of the Facility reduces
Chase's commitment to $40 million or less
(a "Successful Syndication") prior to the
Closing Date, you agree to pay all upfront
fees to the Lenders during syndication
(estimated to be 5.0 to 10.0 basis points
on the Facility Amount); or
(ii) If a Successful Syndication is not
completed prior to the Closing Date, the
Borrower shall pay an underwriting fee of
$275,000 on the Closing Date.
A. An annual non-refundable administration fee in
an amount equal to $35,000 payable on the
Closing Date and annually in advance
thereafter.
In addition, Chase and the other Lenders shall be paid
the other fees specified in the Commitment Letter.
<PAGE> 9
Ashland Exploration, Inc.
Fee Letter
February 25, 1997
You agree that, once paid, the fees or
any part thereof payable hereunder and under the
Commitment Letter shall not be refundable under any
circumstances, regardless of whether the transactions or
borrowings contemplated by the Commitment Letter are
consummated. All fees payable hereunder and under the
Commitment Letter shall be paid in immediately available
funds and shall be in addition to reimbursement of Chase's
and CSI's out-of-pocket expenses. You agree that
Chase and CSI may, in their sole discretion, share all or
a portion of any of the fees payable pursuant to this Fee
Letter with any of the other Lenders.
It is understood and agreed that this
Fee Letter shall not constitute or give rise to any
obligation to provide any financing; such an obligation
will arise only to the extent provided in the Commitment
Letter if accepted in accordance with its terms. This
Fee Letter may not be amended or waived except by an
instrument in writing signed by Chase, CSI and you.
THIS FEE LETTER SHALL BE GOVERNED BY, AND CONSTRUED IN
ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK. This
Fee Letter may be executed in any number of counterparts,
each of which shall be an original, and all of which,
when taken together, shall constitute one agreement.
Delivery of an executed signature page of this Fee
Letter by facsimile transmission shall be effective as
delivery of a manually executed counterpart hereof.
You agree that this Fee Letter and its
contents are subject to the confidentiality provisions of
the Commitment Letter.
-2-
<PAGE> 10
Ashland Exploration, Inc.
Fee Letter
February 25, 1997
Please confirm that the foregoing is
our mutual understanding by signing and returning to
us an executed counterpart of this Fee Letter.
Very truly yours,
THE CHASE MANHATTAN BANK
By: /s/ MARY JO WOODFORD
--------------------------
Name: Mary Jo Woodford
Title: Vice President
CHASE SECURITIES INC.
By: /s/ GEORGE M. SERICE
--------------------------
Name: George M. Serice
Title: Vice President
Accepted and agreed to as of
the date first above written:
ASHLAND EXPLORATION, INC.
By: /s/ ROBERT C. BILGER
---------------------------
Name: Robert C. Bilger
Title: Senior Vice President
-3-
<PAGE> 11
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
ASHLAND EXPLORATION, INC.
Exhibit A - Summary of Terms and Conditions
February 25, 1997
BORROWERS: Ashland Exploration, Inc. ("AEI") and certain
of its subsidiaries, including subsidiaries
which either (i) are U.S. holding companies
for entities owning the Nigerian assets or
(ii) are established and operating in Nigeria
and directly own the Nigerian assets. All
subsidiary borrowers under this Credit
Facility are the "Subsidiaries".
GUARANTORS: AEI will guarantee all obligations of the
Subsidiaries. The Subsidiaries and other
material subsidiaries of AEI, if any, will
also guarantee the obligations, subject to
solvency considerations.
LENDERS: The Chase Manhattan Bank ("Chase"), which
commits to the entire amount of this
facility, and other financial institutions
(collectively, the "Lenders") which shall be
chosen by CSI in consultation with AEI.
Commitments several and not joint.
ADMINISTRATIVE AGENT
AND L/C ISSUING BANK: Chase (the "Agent").
DOCUMENTATION AGENT: J.P. Morgan.
SYNDICATION AGENT: National Westminster Bank PLC.
ARRANGER FOR THE
CREDIT FACILITY: Chase Securities Inc. ("CSI").
CREDIT FACILITY: Five-year Revolving Senior Credit Facility
(the "Credit Facility") in an amount of up to
$200,000,000, with a Letter of Credit ("L/C")
sublimit of $50,000,000 (the loans and L/C
liabilities thereunder, the "Loans" and "L/C
Liabilities", respectively; provided that no
Loans shall be made nor L/Cs issued to the
extent such Loans and outstanding L/C
Liabilities would exceed the lesser of the
Credit Facility amount or the Borrowing Base.
_______________________________________________________________________________
1 CHASE SECURITIES INC.
<PAGE> 12
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
OUTSTANDINGS: "Outstandings" at any time shall mean the
aggregate principal amount of the Loans and
the L/C Liabilities outstanding at such time.
CLOSING DATE: To be determined.
TERMINATION DATE: Five years from the Closing Date.
AVAILABILITY: The Credit Facility shall be available on a
revolving basis during the period commencing
on the Closing Date and ending on the
Termination Date, subject to satisfaction of
Conditions Precedent.
INITIAL BORROWING BASE: $250,000,000.
MATURITY DATE: The Termination Date, subject to acceleration
and prepayment provisions.
USE OF PROCEEDS: Proceeds from the Credit Facility will be
used for general corporate purposes and not
for purposes which would violate any law,
rule or regulation; provided, however, that
until the term note evidencing indebtedness
of up to $180 million from AEI to Ashland
Inc. (the "Ashland Note") is repaid, proceeds
from the Credit Facility will be used to
repay the Ashland Note.
INTEREST RATE: A Borrower may elect that all or a portion of
the Loans to it bear interest at a per annum
rate equal on any day to:
(a) The higher of (i) the rate of interest
established by Chase as its prime rate in
effect on such day at its principal office in
New York City and (ii) the Federal Funds
Effective Rate in effect on such day plus 1/2
of 1% (such higher rate, the "ABR"; Loans
bearing interest based upon such rate, "ABR
Loans"). The ABR is not the lowest rate
charged by Chase to its borrowers; or
(b) The rate at which eurodollar deposits for
one, two, three or six months, or such other
period as the Lenders may agree (as selected
by such Borrower) are offered by Chase in the
interbank eurodollar market in the
approximate amount of the requested borrowing
(the "Eurodollar Rate"); Loans bearing
interest based upon such rate, "Eurodollar
Loans") in each case plus the Applicable
Eurodollar Margin.
_______________________________________________________________________________
2 CHASE SECURITIES INC.
<PAGE> 13
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
APPLICABLE MARGIN: See Schedule I.
FEES: See Schedule I.
INTEREST PAYMENT DATES: In the case of ABR Loans, the last day of
each calendar quarter.
In the case of Eurodollar Loans, on the last
day of each relevant interest period and, in
the case of any interest period longer than
three months, on each successive date three
months after the first day of such interest
period.
DEFAULT RATE: Any overdue principal, interest or other
amounts will bear interest at a rate per
annum equal to the ABR plus 2%.
AMORTIZATION: All Outstandings and other amounts then
unpaid shall be due in full on the
Termination Date, but subject to Mandatory
Prepayments. Also, any amounts drawn under
L/C's ("L/C Advances") must be immediately
repaid either in cash or through available
Loans.
INTEREST RATE BASIS: 360 days (365/366 days in the case of ABR
Loans based on the prime rate) for actual
days elapsed.
OPTIONAL PREPAYMENTS: Loan prepayments will be permitted at any
time without penalty (except for breakage and
related costs associated with prepayments of
Eurodollar Loans).
_______________________________________________________________________________
3 CHASE SECURITIES INC.
<PAGE> 14
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
MANDATORY PREPAYMENTS: If on any date the aggregate Outstandings
exceed the Borrowing Base then applicable,
the Borrower shall be required by each of 90
and 180 days after such date to either (a)
make a mandatory prepayment to the Lenders or
(b) take such steps as may be approved by the
Agent to reduce such excess by at least 50%
or the remainder of such excess,
respectively.
YIELD PROTECTION: The financing agreements will contain the
Agent's customary provisions relating to
increased costs, capital adequacy protection,
withholding and other taxes and illegality.
BORROWING BASE: Outstandings under the Credit Facility will
be permitted up to the lesser of (i) the
Credit Facility Amount, or (ii) the Borrowing
Base then in effect.
The Initial Borrowing Base is $250 million
and the next Scheduled Determination is in
1998. The Borrowing Base will determined by
the Agent in its sole discretion in
accordance with its customary practices and
approved by those Lenders holding at least
66 2/3% of the Commitment (the "Required
Banks"). After the Closing Date, the Agent
will determine a Borrowing Base on an annual
basis; however, each of AEI and the Required
Banks will have the right to call for one
additional determination (an "Unscheduled
Determination") of the Borrowing Base between
Scheduled Determinations.
To assist the Agent in setting the Borrowing
Base, AEI will furnish a report (the
"Independent Engineering Report") prepared by
an Approved Petroleum Engineer (such as
Netherland, Sewell and Associates) to the
Agent no later than February 28 of each year
reflecting data as of December 31 of the
prior year and, upon the request of the Agent
or Required Banks, furnish an AEI-prepared
Company Report requested in connection with
an Unscheduled Determination within 30 days
of such request. The Agent will determine
the Borrowing Base within 30 days of the
receipt of the Reports, communicate the
determination to AEI and then to the Lenders.
Required Banks will have 14 days to approve
or disapprove the Borrowing Base.
BORROWING BASE ALLOCATION: AEI shall allocate the Borrowing Base amount
at the end of each fiscal quarter between two
tranches. Availability under Tranche A may
be utilized by AEI and availability under
Tranche B may be utilized by the
Subsidiaries. The amount allocated to
Tranche B will be no greater than the lesser
of (i) $125 million or (ii) the Borrowing
Base then in effect.
_______________________________________________________________________________
4 CHASE SECURITIES INC.
<PAGE> 15
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
SWING LINE: Chase or any other Lender, in the aggregate,
may provide a $20,000,000 Swing Line Facility
to AEI, which will be cross-defaulted to the
Facility. At all times, sufficient
availability under the Credit Facility must
be in place to take out outstandings under
the Swing Line Facility. The Swing Line will
be used to support cash management activity.
COLLATERAL: Unsecured.
_______________________________________________________________________________
5 CHASE SECURITIES INC.
<PAGE> 16
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
CONDITIONS PRECEDENT
TO CLOSING: The Credit Agreement shall contain such
conditions precedent to Closing usual and
customary for transactions of this type,
including, but not limited to, the following:
a) Corporate action, authority and status:
receipt of organizational documents
for each Borrower.
b) Incumbency for each Borrower.
c) Duly executed and delivered credit
documents.
d) Opinions of counsel to AEI and the
Subsidiaries.
e) Agent's satisfaction with title and
environmental issues.
f) Receipt of counterparts from the Lenders.
g) Any necessary third-party consents or
approvals.
h) Other documents as the Agent may reasonably
request.
REPRESENTATIONS AND
WARRANTIES: The Credit Agreement shall contain such
representations and warranties usual and
customary for transactions of this type,
including, but not limited to:
1) Corporate existence, authority and status
of each Borrower.
2) Information:
_______________________________________________________________________________
6 CHASE SECURITIES INC.
<PAGE> 17
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
Financial statements.
o No undisclosed material contingent
liabilities or long term commitments.
o No Material Adverse Change ("MAC")
3. No litigation, which if adversely determined,
could cause a MAC.
4. No breach of law or other agreements or
documents.
5. All necessary corporate power and authority.
6. All approvals and consents obtained.
7. Regulations G, T, U and X.
8. ERISA.
9. Payment of taxes.
10. Environmental compliance; absence of material
environmental claims.
11. Good and defensible title.
12. Investment Company Act, PUHCA.
13. Solvency of each Borrower and Guarantor.
_______________________________________________________________________________
7 CHASE SECURITIES INC.
<PAGE> 18
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
AFFIRMATIVE COVENANTS: The Credit Agreement shall contain affirmative
covenants usual and customary for transactions of
this type, including, but not limited to:
1. Financial statements and certificates:
o Quarterly and yearly AEI consolidated
financials with certificates.
o Notification of Default, any event or
condition which would cause a MAC, litigation
of $1 million or more, regulatory proceedings
which would cause a MAC.
o ERISA notices and information.
2. Annual independent engineering report and, if
requested by Required Banks, semi-annual
AEI-prepared update covering domestic and
foreign reserves.
3. Right to inspection of properties, books and
records.
4. Environmental compliance.
5. Payment of taxes.
6. Maintenance of insurance.
7. ERISA.
FINANCIAL COVENANTS: The Credit Agreement shall contain the following
financial covenants, which shall be measured at the
end of each fiscal quarter using AEI consolidated
financial statements:
a. Minimum Consolidated Net Worth of $[80% of CNW
at the Closing Date] million plus 50% of
positive net income plus 75% of the gross
proceeds of any equity issue (subsequent to the
IPO).
b. Four quarter rolling EBITDA to Interest
Coverage of at least 2.75 to 1.0.
_______________________________________________________________________________
8 CHASE SECURITIES INC.
<PAGE> 19
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
NEGATIVE COVENANTS: The Credit Agreement shall contain negative covenants
usual and customary for transactions of this type,
including, but not limited to:
1. No additional Indebtedness other than:
o Funded Indebtedness (short or long-term) other
than the Credit Facility or the Swing Line
Facility not to exceed $10,000,000; provided,
however, that the Ashland Note is allowed and
will not subtract from this dollar allowance.
o Capital Leases assumed between Borrowing Base
determinations up to 10% of consolidated net
worth; provided, however, that the two planned
Floating Production System Capital Leases are
pre-approved, are factored into the initial
Borrowing Base determination and will not
subtract from the Capital Lease allowance.
o Liabilities incurred under interest rate or
commodity swap transactions which are not
speculative in nature.
o Other customary exceptions to be negotiated.
2. No Liens, with customary exceptions to include (1)
Liens in the ordinary course of business, not for
borrowed money or the deferred purchase price of
goods or services, securing obligations not yet
due which do not in the aggregate materially
detract from the value of the property subject
thereto or impair the use thereof; (2) existing
Liens (to be scheduled); (3) Liens securing
permitted Indebtedness.
3. No asset sales (other than the sale of oil and gas
production in the normal course of business)
between Borrowing Base determinations beyond
$15,000,000; provided, however, that the planned
sale of AEI tax credits which is expected to gross
approximately $40 million and be completed by
[date] is pre-approved, factored into the initial
Borrowing Base determination and will not subtract
from the asset sale allowance. AEI may request
approval of additional asset sales from the
Required Banks, which will trigger the right of
the Agent or Required Banks to call for an
additional, immediate Borrowing Base
determination.
4. No Investments other than standard Permitted
Investments, intercompany transfers between and
among AEI and those subsidiaries which are
Borrowers or Guarantors under this Credit
Facility, and a basket for Other Investments.
_______________________________________________________________________________
9 CHASE SECURITIES, INC.
<PAGE> 20
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
5. Dividends limited to 50% of rolling four quarter
positive net income.
6. Transactions with affiliates must be
"arms-length".
7. Limitations on mergers and sale of substantially
all assets.
8. No sale and leaseback transactions.
EVENTS OF DEFAULT: The Credit Agreement shall contain events of default
usual and customary for transactions of this type,
including, but not limited to:
1. Nonpayment of principal when due.
2. Nonpayment of interest, fees or other amounts
within applicable grace periods.
3. Cross default.
4. Adverse judgment, in the aggregate, in excess of
$10,000,000.
5. Material inaccuracy of representations and
warranties.
6. Failure to make any mandatory prepayment.
7. Bankruptcy, insolvency, etc.
8. Change of Control: no acquisition by a single
Person or Persons acting as a Group of over 30%
of total equity of AEI and no change of a
majority of the Directors of AEI in any 12 month
period after Ashland Inc. (the current parent of
AEI) ceases to own the majority of the common
stock of AEI.
9. Violation of covenants (subject to 30 day grace
in the case of certain affirmative covenants).
10. Material ERISA non-compliance.
11. Material Environmental liabilities.
ASSIGNMENTS AND
PARTICIPATIONS: Each Lender will have the right to assign to
one or more eligible assignees all or a portion of
its rights and obligations under the Loan Documents,
with the consent, not to be unreasonably withheld, of
the Agent and AEI. Minimum aggregate assignment
level of $10,000,000. The assignee shall pay to the
Agent an administrative fee of $2,500.
_______________________________________________________________________________
10 CHASE SECURITIES INC.
<PAGE> 21
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
Each Lender will also have the right, without the
consent of any Borrower, to assign, as security, all
or part of its rights under the Loan Documents to any
Federal Reserve Bank.
Each Lender will have the right, without the consent
of any Borrower, to sell participations in its rights
and obligations under the Loan Documents, subject to
customary restrictions on the participants' voting
rights. Participants will have the same benefits as
the Lenders with respect to yield protection and
increased cost provisions.
The Agent agrees to hold a minimum of 10% of the $200
million Commitment through the life of the Credit
Facility.
COUNSEL TO THE AGENT: Liddell, Sapp, Zivley, Hill & LaBoon, L.L.P.
GOVERNING LAW/
JURISDICTION: State of New York, submission to New York
jurisdiction, appointment of process agent in
New York City and waiver of jury trial.
TAXES AND INCREASED
COSTS: All amounts payable under the Credit Facility
are to be paid in full without deduction in respect of
withholding or any other present or future taxes
and/or duties. Payments will be required to be
grossed-up for any withholding or other tax which may
be imposed. The Borrowers will reimburse the Lenders
for any increased costs arising in the future due to
the imposition of reserve requirements or other
measures imposed by regulatory bodies, excluding costs
or implementation of existing BIS capital adequacy
requirements, which costs shall be presented, in
reasonable detail, to AEI for payment within 180 days
of the payment of such costs by the Lender. The
Lenders will use reasonable efforts at all times to
mitigate the effects of such events. In any event,
AEI will have the option of prepaying advances and/or
canceling the commitments without penalty with the
exception of breakage costs. AEI will also have the
right to replace any Lender claiming Increased Costs.
_______________________________________________________________________________
11 CHASE SECURITIES INC.
<PAGE> 22
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
EXPENSES: THE COSTS AND EXPENSES (INCLUDING, WITHOUT
LIMITATION, THE FEES AND EXPENSES OF COUNSEL TO THE
AGENT AND THE AGENT'S OUT-OF-POCKET EXPENSES) ARISING
IN CONNECTION WITH THE PREPARATION, EXECUTION AND
DELIVERY OF THE DOCUMENTATION RELATING TO THE CREDIT
FACILITY SHALL BE FOR THE ACCOUNT OF AEI. IN
ADDITION, AEI WILL INDEMNIFY, PAY AND HOLD HARMLESS
THE AGENT AND THE LENDERS (AND THEIR RESPECTIVE
DIRECTORS, OFFICERS, EMPLOYEES AND AGENTS) AGAINST ANY
LOSS, LIABILITY, COST OR EXPENSE INCURRED IN RESPECT
OF THE FINANCING CONTEMPLATED HEREBY OR THE USE OR THE
PROPOSED USE OF PROCEEDS THEREOF.
_______________________________________________________________________________
12 CHASE SECURITIES INC.
<PAGE> 23
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
SCHEDULE I
APPLICABLE MARGIN/
COMMITMENT FEE/
LETTER OF CREDIT FEE
PAYABLE TO THE AGENT AND
LENDERS:
Tranche A and Tranche B will, in the
aggregate, be charged margins and fees no
less than as determined by the grid (the
"Pricing Grid") below:
<TABLE>
<CAPTION>
BORROWING BASE UTILIZATION
LEVEL I LEVEL II LEVEL III LEVEL IV LEVEL V
greater than 30% greater than 55% greater than 70%
less than or less than or less than or less than or greater than
equal to 30% equal to 55% equal to 70% equal to 85% 85%
<S> <C> <C> <C> <C> <C>
Eurodollar Margin 50.0 bps 62.5 bps 75.0 bps 100.0 bps 125.0 bps
ABR Margin 0.0 bps 0.0 bps 0.0 bps 0.0 bps 0.0 bps
Commitment Fee 20.0 bps 20.0 bps 25.0 bps 30.0 bps 35.0 bps
L/C Fee (p.a.) 50.0 bps 62.5 bps 75.0 bps 100.0 bps 125.0 bps
</TABLE>
"Borrowing Base Utilization" means, on each
day, the ratio of (a) Tranche A and Tranche B
Outstandings on such day divided by (b) the
Borrowing Base then in effect.
The margins and fees due (the "Aggregate
Fees") will reflect the Margins and Fees
applicable to the aggregate of Tranche A and
B Outstandings as determined by the Pricing
Grid. Billing will be split between (i) the
Subsidiary Borrowers, who will be billed at
an assumed 62.5 bps on their share of the
Tranche B Outstandings and (ii) AEI, which
will be billed the positive difference
between the Aggregate Fees and the aggregate
of the Subsidiary billings; provided,
however, that if the Subsidiary billings
exceed the Aggregate Fees, neither the Agent
or Lenders will be obligated to refund any
amount billed to the Subsidiaries.
_______________________________________________________________________________
13 CHASE SECURITIES INC.
<PAGE> 24
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
The Letter of Credit Fee will correspond with the applicable Letter of Credit
Fee in the above pricing grid, subject
to a minimum fee of $500 per L/C per annum.
No L/C may have a maturity which exceeds the
Credit Facility Termination Date.
In addition to the L/C Fee, the Borrower will pay Chase a 1/8 of 1% per annum
Fronting Fee as consideration for capital
costs incurred for retaining the full
amount of the Letter of Credit on its books.
The Commitment Fee will be payable on the daily difference between (a) the
lesser of (i) the Credit Facility Amount,
or (ii) the Borrowing Base minus (b) the
Outstandings, and will be due at the end
of such calendar quarter.
_______________________________________________________________________________
14 CHASE SECURITIES INC.
<PAGE> 25
CONFIDENTIAL ASHLAND EXPLORATION, INC.
_______________________________________________________________________________
SCHEDULE I (CONT'D)
ARRANGEMENT FEE PAYABLE
TO CSI: $175,000, due on the date definitive
documentation regarding the Credit Facility
is executed (the "Closing Date").
UNDERWRITING FEE PAYABLE
TO CHASE: If syndication of the Credit Facility
reducing Chase's commitment to $40 million or
less (a "Successful Syndication") is not
completed prior to the Closing Date, the
Borrower shall pay an Underwriting Fee of
$275,000 on the Closing Date.
PARTICIPATION FEES PAYABLE
TO CHASE AND LENDERS: Only if a Successful Syndication is completed
prior to the Closing Date (and, hence, the
Underwriting Fee is not due and payable),
shall AEI be responsible for all upfront fees
paid to the Lenders during syndication
(estimated to be 5.0 to 10.0 basis points on
the Credit Facility Amount).
ADMINISTRATIVE FEE PAYABLE
TO CHASE: $35,000, which is a non-refundable fee
payable on the Closing Date and annually in
advance thereafter.
_______________________________________________________________________________
15 CHASE SECURITIES INC.
<PAGE> 1
EXHIBIT 21.1
LIST OF DIRECT AND INDIRECT SUBSIDIARIES AND STATE
OR JURISDICTION OF INCORPORATION OR ORGANIZATION
- -- Ashland Overseas Investments Co. (Delaware)
- -- Ashland Crude Marketing, Inc. (Delaware)
- -- Ashland Exploration Australia Pty., Ltd. (Australia)
- -- Ashland Oil (Nigeria) Company Unltd. (Nigeria)
- -- Ashland Nigerian Development Co. (Delaware)
- -- Ashland of Nigeria Ltd. (Delaware)
- -- Ashland Exploration Nigeria, Inc. (Delaware)
- -- Ashland Nigeria Exploration Unltd. (Nigeria)
<PAGE> 1
EXHIBIT 23.2
CONSENT OF INDEPENDENT AUDITORS
We consent to the reference to our firm under the caption "Experts" and to the
use of our reports dated November 1, 1996, except for Note 12 as to which the
date is March 4, 1997, in the Registration Statement (Form S-1) and related
Prospectus of Blazer Energy Corp., for the registration of 3,565,000 shares of
its common stock.
ERNST & YOUNG LLP
Houston, Texas
March 4, 1997
<PAGE> 1
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
As independent petroleum engineers and geologists, Netherland, Sewell
& Associates, Inc. hereby consents to (i) the reference to our firm as experts,
(ii) the summarization of our reports for fiscal years ending September 30,
1991, 1994, 1995, and 1996 of Blazer Energy Corp., and (iii) the inclusion of
our reports dated December 9, 1996 and February 20, 1997 as Annex A in Blazer
Energy Corp.'s Registration Statement on Form S-1 to be filed with the
Securities and Exchange Commission.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ CLARENCE M. NETHERLAND
----------------------------
CLARENCE M. NETHERLAND
CHAIRMAN
Dallas, Texas
February 28, 1997
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM BAZER
ENERGY CORP S-1.
</LEGEND>
<CIK> 0001035009
<NAME> BLAZER ENERGY CORP.
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> YEAR 3-MOS
<FISCAL-YEAR-END> SEP-30-1996 DEC-31-1996
<PERIOD-START> OCT-1-1995 OCT-1-1996
<PERIOD-END> SEP-30-1996 DEC-31-1996
<CASH> 0 0
<SECURITIES> 0 0
<RECEIVABLES> 135,855 60,016
<ALLOWANCES> 249 249
<INVENTORY> 27,602 25,464
<CURRENT-ASSETS> 166,286 90,886
<PP&E> 1,078,957 1,093,364
<DEPRECIATION> 651,532 659,395
<TOTAL-ASSETS> 595,151 533,211
<CURRENT-LIABILITIES> 81,192 53,078
<BONDS> 0 0
0 0
0 0
<COMMON> 144 144
<OTHER-SE> 24,255 24,255
<TOTAL-LIABILITY-AND-EQUITY> 595,151 533,211
<SALES> 229,255 72,625
<TOTAL-REVENUES> 304,071 73,274
<CGS> 148,077 35,120
<TOTAL-COSTS> 193,753 64,535
<OTHER-EXPENSES> 16,317 4,098
<LOSS-PROVISION> 52 0
<INTEREST-EXPENSE> 222 53
<INCOME-PRETAX> 93,779 4,588
<INCOME-TAX> 18,418 (1,720)
<INCOME-CONTINUING> 75,361 6,308
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 0
<CHANGES> 0 0
<NET-INCOME> 75,361 6,308
<EPS-PRIMARY> 5.23 .44
<EPS-DILUTED> 5.23 .44
</TABLE>
