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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
FORM 10-K/A
AMENDMENT NO. 1
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934. FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934.
COMMISSION FILE NUMBER 1-12480
------------------------
LOUIS DREYFUS NATURAL GAS CORP.
(Exact name of Registrant as specified in its charter)
<TABLE>
<S> <C>
OKLAHOMA 73-1098614
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
14000 QUAIL SPRINGS PARKWAY, SUITE 600 73134
OKLAHOMA CITY, OKLAHOMA (Zip code)
(Address of principal executive office)
</TABLE>
Registrant's telephone number, including area code:
(405) 749-1300
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<S> <C>
Title of each class Name of each exchange on which registered
COMMON STOCK, PAR VALUE $.01 PER SHARE NEW YORK STOCK EXCHANGE
9 1/4% SENIOR SUBORDINATED NOTES DUE 2004 NEW YORK STOCK EXCHANGE
</TABLE>
------------------------
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES /X/ NO / /
Indicate by check mark if disclosure of delinquent files pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. /X/
The aggregate market value of the voting stock held by non-affiliates of the
Registrant at March 12, 1999, was approximately $296.1 million (based on a value
of $15.50 per share, the closing price of the Common Stock as quoted by the New
York Stock Exchange on such date). 40,109,758 shares of Common Stock, par value
$.01 per share, were outstanding on March 12, 1999.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 1999 Annual
Meeting of Shareholders, to be filed pursuant to Regulation 14A under the
Securities Exchange Act of 1934, are incorporated by reference into Part III.
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<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
FORM 10-K/A
TABLE OF CONTENTS
<TABLE>
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PAGE
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<S> <C> <C>
PART I
Item 1 -- BUSINESS..................................................................................... 3
General...................................................................................... 3
Business Strategy............................................................................ 4
Forward-Looking Statements................................................................... 5
Recent Developments.......................................................................... 6
Acquisitions................................................................................. 7
Marketing.................................................................................... 7
Competition.................................................................................. 9
Regulation................................................................................... 9
Certain Operational Risks.................................................................... 12
Employees.................................................................................... 12
Relationship Between the Company and S.A. Louis Dreyfus et Cie............................... 12
Potential Conflicts of Interest.............................................................. 13
Certain Definitions.......................................................................... 13
Item 2 -- PROPERTIES................................................................................... 16
General...................................................................................... 16
Core Areas................................................................................... 16
Reserves..................................................................................... 21
Costs Incurred and Drilling Results.......................................................... 22
Acreage...................................................................................... 23
Productive Well Summary...................................................................... 23
Title to Properties.......................................................................... 24
Item 3 -- LEGAL PROCEEDINGS............................................................................ 24
Item 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......................................... 25
PART II
Item 5 -- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS........................ 25
Item 6 -- SELECTED FINANCIAL DATA...................................................................... 25
Item 7 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS........ 27
Overview..................................................................................... 27
Results of Operations--Fiscal Year 1998 Compared to Fiscal Year 1997......................... 30
Results of Operations--Fiscal Year 1997 Compared to Fiscal Year 1996......................... 33
Capital Resources and Liquidity.............................................................. 35
Commitments and Capital Expenditures......................................................... 37
Outlook for Fiscal Year 1999................................................................. 38
Year 2000 Compliance......................................................................... 40
</TABLE>
1
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LOUIS DREYFUS NATURAL GAS CORP.
FORM 10-K/A
TABLE OF CONTENTS
<TABLE>
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PAGE
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<S> <C> <C>
Item 7A -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK................................... 41
General...................................................................................... 41
Fixed-Price Contracts........................................................................ 41
Interest Rate Sensitivity.................................................................... 46
Item 8 -- FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.................................................. 49
Item 9 -- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE......... 49
PART III
Item 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT........................................... 49
Item 11 -- EXECUTIVE COMPENSATION....................................................................... 49
Item 12 -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT............................... 49
Item 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............................................... 49
PART IV
Item 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.............................. 49
</TABLE>
EXPLANATORY NOTE REGARDING THE REVIEW OF THE COMPANY'S PUBLIC FILINGS BY THE
SECURITIES AND EXCHANGE COMMISSION:
IN SEPTEMBER 1999, THE STAFF OF THE SECURITIES AND EXCHANGE COMMISSION
INFORMED THE COMPANY THAT THE DOCUMENTATION FOR ITS DERIVATIVE CONTRACTS AND
HEDGING ACTIVITIES WAS INSUFFICIENT AT THE OCTOBER 1, 1998 DATE OF ADOPTION OF
STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NO. 133, "ACCOUNTING FOR DERIVATIVE
INSTRUMENTS AND HEDGING ACTIVITIES" ("SFAS 133") TO QUALIFY FOR THE SPECIAL
HEDGE ACCOUNTING PROVISIONS OF THE STANDARD. THE COMPANY BELIEVED THAT IT
COMPLIED WITH THE SPIRIT AND INTENT OF THE PROVISIONS OF THE STANDARD WITH
RESPECT TO DOCUMENTATION; HOWEVER, THE STAFF OF THE SECURITIES AND EXCHANGE
COMMISSION CONCLUDED THAT THE COMPANY HAD NOT SPECIFICALLY COMPLIED WITH THE
PROVISIONS OF THE STANDARD REQUIRING ALL HEDGING RELATIONSHIPS BE DESIGNATED
ANEW (INCLUDING THE MEASUREMENT AND ASSESSMENT OF EFFECTIVENESS). ACCORDINGLY,
THE COMPANY HAS AMENDED ITS 1998 FORM 10-K TO RESTATE ITS ACCOUNTING FOR ITS
FIXED-PRICE CONTRACTS. THE COMPANY HAS CONTINUED TO REFER TO THESE FIXED-PRICE
CONTRACTS IN THIS FORM 10-K/A AS ECONOMIC HEDGES INASMUCH AS THIS WAS THE INTENT
WHEN SUCH CONTRACTS WERE EXECUTED, THE CHARACTERIZATION IS CONSISTENT WITH THE
ACTUAL ECONOMIC PERFORMANCE OF THE CONTRACTS, AND MANAGEMENT OF THE COMPANY
EXPECTS THE CONTRACTS TO SERVE IN THAT CAPACITY IN FUTURE PERIODS. SEE NOTE 2 OF
THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR A MORE DETAILED DISCUSSION OF
THE EFFECTS OF THE RESTATEMENT ON THE CONSOLIDATED FINANCIAL STATEMENTS INCLUDED
IN THIS AMENDMENT ON FORM 10-K/A.
2
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
PART I
ITEM 1. BUSINESS
GENERAL
Louis Dreyfus Natural Gas Corp. (the "Company" or "Registrant") is one of
the largest independent natural gas companies in the United States engaged in
the acquisition, development, exploration, production and marketing of natural
gas and crude oil. The Company's acquisition, development and exploration
activities are primarily conducted in three geographically concentrated core
areas: the Permian Region of West Texas, Southeast New Mexico and the San Juan
Basin; the Mid-Continent Region of Oklahoma, Kansas and the Panhandle of Texas;
and the Gulf Coast Region, which includes South Texas, Offshore Gulf of Mexico,
East Texas, Southwest Arkansas and North Louisiana (collectively "Core Areas").
Approximately 94% of the Company's proved reserve value at December 31, 1998 is
located within these Core Areas. Proved reserves as of December 31, 1998 totaled
1.3 Tcfe and had a Present Value (as hereinafter defined) of $979 million. The
Company's operated properties contain more than 80% of its total proved
reserves. Natural gas reserves comprised 89% of the Company's year-end proved
reserve position and 86% of its reserves were proved developed. The Reserve Life
of its proved reserves, as hereinafter defined, was 11.0 years.
The Company was acquired in 1990 by S.A. Louis Dreyfus et Cie to engage in
oil and gas acquisition, development, production and marketing activities. At
the time of acquisition, the Company's proved reserves totaled 61 Bcfe. Since
that date, the Company has experienced significant growth in its production and
reserves through a balanced strategy of proved reserve acquisitions and
development and exploration drilling. The Company has accumulated interests in
3.6 million gross acres with 1,575 identified drilling locations. Of these
locations, 394 had been assigned proved undeveloped reserves at December 31,
1998. The Company aggressively exploits the value in its properties through an
active development drilling program. This program has resulted in the drilling
of 1,439 wells with a completion success rate of 93% over the five-year period
ended December 31, 1998. In recent years, exploratory drilling has been
increasingly emphasized as an integral component of its business strategy and,
consequently, the Company has incurred substantial up-front costs, including
significant acreage, seismic and other geological and geophysical costs. During
1998, the Company invested $83 million in connection with exploration
activities, $23 million of which was directed to acreage and seismic
acquisition. The Company's exploration program has had a cumulative drilling
success rate of 69% since its inception in 1995.
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The Company's balanced growth strategy has enabled the Company to replace
296% of its production since 1993 at an average Finding Cost, as defined herein,
of $1.07 per Mcfe, including the purchase accounting impact of its acquisition
of American Exploration Company in 1997 ("American Acquisition"). Finding Costs
excluding the effects of the American Acquisition, which Management believes are
more representative of the Company's historical ability to replace reserves,
were $.86 per Mcfe over this same five year period. The following table reflects
the Company's growth since 1993:
PRODUCTION, PROVED RESERVES, EARNINGS
PER SHARE AND CASH FLOW GROWTH
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, FIVE-YEAR
----------------------------------------------------- GROWTH
1998 1997 1996 1995 1994 RATE
--------- --------- --------- --------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
Production (Bcfe)................................. 121.6 84.3 75.0 61.4 54.3 23.0%
Proved reserves (Bcfe)............................ 1,340.2 1,203.4 990.2 876.1 689.9 16.4
EBITDAX (MM$)(1).................................. $ 183.8 $ 164.9 $ 128.6 $ 111.6 $ 94.0 25.4
Net cash provided by operating activities (MM$)... $ 147.4 $ 129.8 $ 101.8 $ 89.5 $ 80.9 22.8
Net income (loss) per share--basic and
diluted(2)...................................... $ (1.08) $ (.53) $ .76 $ .40 $ .39 NM
</TABLE>
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(1) See "--Certain Definitions."
(2) Earnings for 1998 were adversely affected by a $52.5 million non-cash
impairment charge and a significant decline in oil and gas prices. Earnings
for 1997 were adversely affected by a $75.2 million non-cash impairment
charge, substantially all of which was recognized in connection with the
American Acquisition. See "Item 7--Management's Discussion and Analysis of
Financial Condition and Results of Operations."
The address of the Company's principal executive offices is 14000 Quail
Springs Parkway, Suite 600, Oklahoma City, Oklahoma 73134, and its telephone
number is (405) 749-1300.
BUSINESS STRATEGY
The Company's business strategy is to generate strong and consistent growth
in reserves, production, operating cash flows and earnings. This strategy is
implemented through the following:
EXPANDED EXPLORATION PROGRAM. Increased exploration activity in the
Company's Core Areas exposes the Company to higher production and reserve
growth potential. The Company has a staff of 30 geoscientists and reservoir
engineers who have extensive experience in the use of advanced technologies,
including 3-D seismic analysis, computer aided mapping and reservoir
simulation modeling. These technologies are combined with a considerable
knowledge base gained through the Company's operating and development
drilling activities in these Core Areas. The combination results in a
disciplined approach to exploration growth. During 1998, $83 million was
invested in connection with exploration activities, including drilling,
seismic data collection and unproved lease acquisitions. Since the inception
of the program in 1995, the Company has drilled 103 gross (63 net)
exploratory wells with a completion success rate of 69%. The Company has
allocated $61 million, or 36%, of its 1999 drilling budget to exploration
activities.
DEVELOPMENT DRILLING. The Company aggressively exploits the value in
its oil and gas property base through its active development drilling
program. The development drilling program has been an important source of
low-risk production growth and is conducted in areas where multiple
productive oil and gas bearing formations are likely to be encountered, thus
reducing dry hole risk. The Company has drilled 1,336 gross (851 net)
development wells with a completion success rate of 94% over the
4
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five-year period ended December 31, 1998. For 1999, the Company plans to
continue its aggressive development drilling program by investing $109
million, or 64% of its 1999 drilling budget.
STRATEGIC ACQUISITIONS. The Company has grown rapidly by investing $544
million to acquire 563 Bcfe of proved reserves over the five-year period
ended December 31, 1998, an average acquisition cost of $.97 per Mcfe. The
Company believes that this aggregate average acquisition cost, which
includes the 1997 American Acquisition for which the Company paid a premium,
compares favorably to industry averages for independent exploration and
production companies, which one published industry survey reports to be
$1.06 per Mcfe over this same period of time. These acquisitions have been
geographically concentrated in its Core Areas where the Company possesses
considerable operating expertise and realizes economies of scale. The
Company principally targets acquisitions which have significant development
potential, are in close proximity to existing properties, have a high degree
of operatorship and can be integrated with minimal incremental
administrative cost.
LARGE PROPERTY BASE. The Company owns interests in approximately 9,200
wells located primarily in its Core Areas. As a result of this large
property base, the opportunity to generate positive results through the
application of improved production technologies and to achieve economies of
scale is enhanced while the risk of material adverse financial consequences
from unexpected production problems is minimized. The Company has five
district offices in its Core Areas and employs approximately 140 pumpers and
other field personnel to provide onsite management of its properties.
PRICE RISK MANAGEMENT. The Company manages a portion of the risks
associated with decreases in prices of natural gas and crude oil through
long-term fixed-price physical delivery contracts, energy swaps, collars,
futures contracts and basis swaps (collectively "Fixed-Price Contracts").
Over the five-year period ended December 31, 1998, Fixed-Price Contracts
have generated $55.1 million in additional revenues and operating cash flows
and have resulted in additional cash proceeds of $76.8 million which have
been used to fund the Company's drilling activities. The estimated fair
value of the Company's Fixed-Price Contracts was $122.6 million at December
31, 1998, based on the difference between contract prices and forward market
prices, as adjusted for basis, contract performance risk and counterparty
credit risk. This contract value now resides on the Company's balance sheet
as a result of adopting Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133").
The estimated undiscounted, unrisked future net revenues associated with
these contracts was $226.4 million. Fixed-Price Contracts provide a base of
predictable cash flows for a portion of the Company's gas and oil sales,
enabling the Company to pursue its capital expenditures with a greater
degree of assurance. The Company has not entered into Fixed-Price Contracts
with a term in excess of 12 months since 1996 due to Management's belief
that demand and supply fundamentals for natural gas imply the potential for
prices in excess of those currently available in the long-term forward
market. Forty-four percent of the Company's 1998 production was hedged by
Fixed-Price Contracts.
FORWARD-LOOKING STATEMENTS
All statements in this document concerning the Company other than purely
historical information (collectively "Forward-Looking Statements") reflect the
current expectations of Management and are based on the Company's historical
operating trends, its proved reserve and Fixed-Price Contract positions as of
December 31, 1998, and other information currently available to Management. Such
Forward-Looking Statements include among others, statements regarding the
Company's future drilling plans and objectives, and related exploration and
development budgets, and number and location of planned wells, and statements
regarding the quality of the Company's properties and potential reserve and
production levels. These statements assume, among other things, that no
significant changes will occur in the operating environment for the Company's
oil and gas properties and that there will be no material
5
<PAGE>
acquisitions or divestitures except as disclosed herein. The Company cautions
that the Forward-Looking Statements are subject to all the risks and
uncertainties incident to the acquisition, development and marketing of, and
exploration for, oil and gas reserves. These risks include, but are not limited
to, commodity price risks, counterparty risks, environmental risks, drilling
risks, reserve risks, and operations
and production risks. Certain of these risks are described elsewhere herein. See
"Item 7--Management's Discussion and Analysis of Financial Condition and Results
of Operations--Outlook for Fiscal Year 1999." Moreover, the Company may make
material acquisitions or divestitures, modify its Fixed-Price Contract positions
by entering into new contracts or terminating existing contracts, or enter into
financing transactions. None of these can be predicted with certainty and,
accordingly, are not taken into consideration in the Forward-Looking Statements
made herein. Statements concerning Fixed-Price Contract, interest rate swap and
other financial instrument fair values and their estimated contribution to
future results of operations are based upon market information as of a specific
date. Such market information in certain cases is a function of significant
judgment and estimation. Further, market prices for oil and gas and market money
rates are subject to significant volatility. For all of the foregoing reasons,
actual results may vary materially from the Forward-Looking Statements and there
is no assurance that the assumptions used are necessarily the most likely. The
Company expressly disclaims any obligation or undertaking to release publicly
any updates regarding any changes in the Company's expectations with regard to
the subject matter of any Forward-Looking Statements or any changes in events,
conditions or circumstances on which any Forward-Looking Statements are based.
RECENT DEVELOPMENTS
The following information discusses certain of the more significant
accomplishments of the Company during the year ended December 31, 1998.
1998 DRILLING PROGRAM. The Company's drilling program for 1998 was the most
extensive and the most successful in the Company's history. The program resulted
in the drilling of 351 wells, of which 311 wells were completed as commercial
producers for a drilling success rate of 89%. This well count included 27
exploratory wells, 52% of which were completed as producers, and 324 development
wells, 92% of which were completed as producers. Through this program, the
Company added 258 Bcfe of proved reserves to its reserve base at an all-in
finding and development cost (total costs incurred to explore and develop oil
and gas properties divided by proved reserves added through extensions and
discoveries and revisions of previous estimates) of $.86 per Mcfe. 1998 marked
the fifth consecutive year that the Company replaced its production through its
drilling activities. See "Item 2--Properties--Costs Incurred and Drilling
Results."
PROVED RESERVES. As of December 31, 1998, the Company's proved reserves had
grown 11% in relation to 1997 and was comprised of 24 MMBbls of oil and 1.2 Tcf
of natural gas, or 1.3 Tcfe. This reserve growth represents a production
replacement ratio of more than 200%. The Company's estimated future net revenues
from proved reserves was $2.0 billion as of December 31, 1998. The present value
of such future net revenues discounted at 10% ("Present Value") was $1.0
billion. See "Item 2--Properties-- Reserves" and Note 15 of the Notes to
Consolidated Financial Statements appearing elsewhere herein.
FINANCIAL RESULTS. The Company reported a net loss of $43.3 million, or
$1.08 per share, on total revenue of $293.4 million for 1998. This compares to a
net loss of $16.1 million, or $.53 per share, on total revenue of $232.9 million
for 1997. The Company reported record cash flows from operating activities
(before working capital changes) of $144.9 million for the year ended December
31, 1998, which compares to $127.1 million for 1997, an increase of 14%. Cash
flows provided by operating activities after consideration for the change in
working capital was $147.4 million, which compares to $129.8 million for 1997.
The 1998 increase in revenues and operating cash flows was achieved primarily
through growth in oil and gas production which increased 44% to 121.6 Bcfe for
the year. See "Item 7--Management's
6
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Discussion and Analysis of Financial Condition and Results of
Operations--Results of Operations--Fiscal Year 1998 Compared to Fiscal Year
1997."
ACQUISITIONS
The Company has completed a significant number of proved reserve
acquisitions during the past five years, including three ranging in size from
$87 million to $340 million. In 1998, the Company completed only a nominal
amount of acquisitions due to high relative prices being asked by sellers of
proved properties in relation to market prices for oil and gas. The market for
proved reserve acquisitions is expected to be more favorable to purchasers in
1999 as some companies are forced to reduce leverage without having access to
capital markets. The following table summarizes the Company's acquisition
activity for the five years ended December 31, 1998:
SUMMARY ACQUISITION INFORMATION
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------------------------
1998 1997 1996 1995 1994 TOTAL
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Estimated proved reserves acquired (Bcfe)(1)............... 7 234 76 190 56 563
Acquisition cost (MM$)..................................... $ 4.1 $ 349.0 $ 36.1 $ 118.7 $ 36.6 $ 544.5
Acquisition cost per Mcfe(2)............................... $ .56 $ 1.49 $ .48 $ .62 $ .65 $ .97
</TABLE>
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(1) Based on the first year-end reserve report prepared following the
acquisition date as adjusted for production between the acquisition date and
year-end.
(2) Results for 1997 include the purchase accounting impact of the American
Acquisition.
Management is actively involved in the screening of potential acquisitions
and the development and implementation of strategies for specific acquisitions.
The Company's staff of reservoir engineers, geologists, production engineers,
landmen and accountants have substantial experience in evaluating and acquiring
oil and gas reserves. The Company primarily seeks acquisitions in its Core Areas
in which the Company's experience and existing operations will enable it to
readily integrate the acquired properties. Acquisitions are targeted which have
significant further development and exploration potential and a high degree of
operatorship. The Company prefers to operate its properties whenever possible in
order to provide more control over the operation and development of the
properties and the marketing of the production. The Company also pursues
additional interests in its operated properties from holders of non-operating
interests to increase its percentage ownership at attractive acquisition prices.
MARKETING
FIXED-PRICE CONTRACTS
DESCRIPTION. The Company has entered into Fixed-Price Contracts as economic
hedges to reduce its exposure to decreases in oil and gas prices which are
subject to significant and often volatile fluctuation. The Company's Fixed-Price
Contracts are comprised of long-term physical delivery contracts, energy swaps,
collars, futures contracts and basis swaps. These contracts allow the Company to
predict with greater certainty the effective oil and gas prices to be received
for its hedged production and benefit the Company when market prices are less
than the fixed prices provided in its Fixed-Price Contracts. However, the
Company will not benefit from market prices that are higher than the fixed
prices in such contracts for its hedged production. At December 31, 1998, these
contracts hedged 244 Bcf of future natural gas production, representing 20% of
estimated proved natural gas reserves. The fixed prices in such contracts
generally escalate over the contract term. Fixed-Price Contract volume and price
information by year for the next five years and thereafter is shown at "Item
7A--Quantitative and Qualitative Disclosures About Market Risk--Fixed-Price
Contracts." The Company has traditionally hedged a significant portion of its
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natural gas and crude oil production. In recent years, a progressively smaller
share of the Company's production and reserve additions have been hedged due to
Management's belief that longer-term demand and supply fundamentals for natural
gas imply the potential for prices in excess of those currently available in the
long-term forward market. More recent hedging activity has been for shorter
periods of time, generally less than 12 months, when market conditions have been
viewed as favorable. The Company may decide to hedge a greater or smaller share
of production in the future depending on market conditions, capital investment
considerations and other factors.
DELIVERY CONTRACTS. The Company has entered into fixed-price natural gas
delivery contracts with independent power producers, natural gas pipeline
marketing affiliates, a municipality and other end users. Typically, these
contracts require the Company to deliver, and the purchaser to take, specified
quantities of natural gas at specified fixed prices, over the life of the
contracts. Delivery contracts hedge 184.9 Bcf of future gas production as of
December 31, 1998, representing 15% of estimated proved natural gas reserves.
The contract term varies with each contract, ranging from a period of less than
one year to approximately 18 years. The Company meets its fixed-price delivery
contract requirements through purchases of natural gas in markets local to the
delivery point at the most attractive prices available. The contracts generally
permit the Company to deliver natural gas at its choice of several pipeline or
customary industry delivery points, permitting some market flexibility to the
Company in purchasing required natural gas supplies and making deliveries and
reducing transportation risks. Each contract is individually negotiated based on
the purchaser's specified needs.
ENERGY SWAPS. The Company enters into energy swaps as a fixed-price seller
in order to assure itself of fixed prices for the sale of its oil and gas
production. Less frequently, the Company enters into swaps as a fixed-price
purchaser to hedge the price of supply commitments. At December 31, 1998, the
Company was a party to six energy swaps, which collectively hedge 52.0 Bcf of
future gas production. The contract term varies with each contract, ranging from
a period of one year to approximately eight years. The variables in an energy
swap transaction are a fixed price, an index price, a specified quantity and a
period. One of the parties is designated as the fixed-price purchaser ("FPP")
and whenever the fixed price exceeds the index price for a given date or period,
the FPP pays the other party, the fixed-price seller ("FPS"), the difference
between the fixed price and the index price. Whenever the index price is in
excess of the fixed price, the FPS pays the difference between the index price
and the fixed price to the FPP. In this way the parties may, without physical
delivery of oil or gas, hedge against uncertainties and risk created by
fluctuations in oil and gas prices in connection with such party's actual
physical supply, purchase or sale commitments or requirements.
COUNTERPARTIES. The following table summarizes certain information
concerning the Company's natural gas Fixed-Price Contracts and associated
counterparties at December 31, 1998:
NATURAL GAS FIXED-PRICE CONTRACT
VOLUMES BY COUNTERPARTY
<TABLE>
<CAPTION>
VOLUMES COMMITED (BBTU)
----------------------------------------------------------- PERCENTAGE
ENERGY SWAPS OF
DELIVERY ---------------------- COMMITED
CONTRACTS SALES PURCHASES COLLARS TOTAL VOLUME
----------- --------- ----------- ----------- --------- -------------
<S> <C> <C> <C> <C> <C> <C>
TYPE OF COUNTERPARTY:
Independent power producers..................... 105,648 -- -- -- 105,648 43%
Pipeline marketing affiliates................... 59,682 23,068 (1,825) -- 80,925 33
Financial institutions.......................... -- -- (9,125) 7,300 (1,825) (1)
Other........................................... 19,575 39,900 -- -- 59,475 25
----------- --------- ----------- ----- --------- ---
Total........................................... 184,905 62,968 (10,950) 7,300 244,223 100%
----------- --------- ----------- ----- --------- ---
----------- --------- ----------- ----- --------- ---
</TABLE>
8
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For additional information concerning the Company's Fixed-Price Contracts,
see "Item 7A--Quantitative and Qualitative Disclosures About Market
Risk--Fixed-Price Contracts."
WELLHEAD MARKETING
The majority of the Company's wellhead gas production is sold to a variety
of purchasers on the spot market or dedicated to contracts with market-sensitive
pricing provisions. Substantially all of the undedicated natural gas produced
from Company-operated wells is marketed by the Company. Additionally, the
majority of the oil and condensate produced from Company-operated properties is
sold on a market price sensitive basis. During 1998, the Company had gas sales
to one unrelated purchaser which approximated 20% of total revenues. See Note 10
of the Notes to Consolidated Financial Statements appearing elsewhere herein.
The loss of any wellhead purchaser is not anticipated to have a material adverse
effect on the Company because there are a substantial number of alternative
purchasers in the markets in which the Company sells its wellhead production.
COMPETITION
The oil and gas industry is highly competitive. The Company competes with
major oil and gas companies, other independent oil and gas concerns, gas
marketing companies and individual producers and operators for proved reserve
and undeveloped acreage acquisitions and the development, production and
marketing of oil and gas, as well as contracting for equipment and securing
personnel. Many of these competitors have financial and other resources which
substantially exceed those available to the Company. Competition in the regions
in which the Company owns properties may result in occasional shortages or
unavailability of drilling rigs and other equipment used in drilling activities
as well as limited availability and access to pipelines. Such circumstances
could result in curtailment of activities, increased costs, delays or losses in
production or revenues or cause interests in oil and gas leases to lapse. The
Company believes that its acquisition, development, production and marketing
capabilities, financial resources and the experience of its Management and staff
enable it to compete effectively.
REGULATION
The oil and gas industry is extensively regulated by federal, state and
local authorities. Legislation affecting the oil and gas industry is under
constant review for amendment or expansion. Numerous departments and agencies at
the federal, state and local level have issued rules and regulations affecting
the oil and gas industry, some of which carry substantial penalties for the
failure to comply. The regulatory burden on the oil and gas industry increases
its cost of doing business and, consequently, affects its profitability.
Inasmuch as such laws and regulations are frequently amended or reinterpreted,
the Company is unable to predict the future cost or impact of complying with
such regulations. The Company believes that its operations and facilities comply
in all material respects with applicable laws and regulations as currently in
effect and that the existence and enforcement of such laws and regulations have
no more restrictive effect on the Company's operations than on other similar
companies in the oil and gas industry.
DRILLING AND PRODUCTION
The Company's operations are subject to various types of regulation at
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 abandoning of wells. The Company's operations are
also subject to various conservation requirements. These include the regulation
of the size and shape of drilling and spacing units or proration units and the
density of wells which may be drilled and the unitization or pooling of oil and
gas properties. In this regard, some states allow forced pooling or integration
of tracts to facilitate exploration while other states rely on voluntary
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pooling of lands and leases. In addition, state conservation laws establish
maximum rates of production from oil and gas wells, generally prohibit the
venting or flaring of natural gas and impose certain requirements regarding the
ratability of production. These regulations may limit the amount of oil and gas
the Company can produce from its wells or limit the number of wells or the
locations at which the Company can drill.
The Company has operated and non-operated working interests in various oil
and gas leases in the Gulf of Mexico which were granted by the federal
government and are administered by the Minerals Management Service (the "MMS"),
a federal agency. These leases were issued through competitive bidding, contain
relatively standardized terms and require compliance with detailed MMS
regulations and orders (which are subject to change by the MMS). For offshore
operations, lessees must obtain MMS approval for exploration, development and
production plans prior to the commencement of such operations. In addition to
permits required from other agencies (such as the Coast Guard, the Army Corps of
Engineers and the Environmental Protection Agency), 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 outer
continental shelf to meet stringent engineering and construction specifications,
and has established other regulations governing the plugging and abandoning of
wells located offshore and the removal of all production facilities. With
respect to any Company operations conducted on offshore federal leases,
liability may generally be imposed under the Outer Continental Shelf Lands Act
for costs of clean-up and damages caused by pollution resulting from such
operations. Under certain circumstances, including but not limited to,
conditions deemed to be a threat or harm to the environment, the MMS may also
require any Company operations on federal leases to be suspended or terminated
in the affected area.
ENVIRONMENTAL
The Company's operations are subject to numerous federal and state laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of hazardous 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. State laws often impose
requirements to remediate or restore property used for oil and gas exploration
and production activities, such as pit closure and plugging abandoned wells.
Although the Company believes that its operations and facilities are in
compliance in all material respects with applicable environmental and health and
safety laws and regulations, risks of substantial costs and liabilities are
inherent in oil and gas operations, and there can be no assurance that
substantial costs and liabilities will not be incurred in the future. Moreover,
the recent trend toward stricter standards in environmental legislation,
regulation and enforcement is likely to continue.
The Company's operations may generate wastes that are subject to the Federal
Resource Conservation and Recovery Act ("RCRA") and comparable state statutes.
The Environmental Protection Agency (the "EPA") has limited the disposal options
for certain hazardous wastes and may adopt more stringent disposal standards for
nonhazardous wastes. Furthermore, legislation has been proposed in Congress from
time to time that would reclassify certain oil and gas exploration and
production wastes as "hazardous wastes" under RCRA which would regulate such
reclassified wastes and require government permits for transportation, storage
and disposal. If such legislation were to be enacted, it could have a
significant impact on the operating costs of the Company, as well as the oil and
gas industry in general. State initiatives to further regulate oil and gas
wastes could have a similar impact on the Company.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "superfund" law, imposes liability, regardless of
fault or the legality of the original conduct, on certain classes of persons
that contributed to the release of a "hazardous substance" into the
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environment. These persons include the current or previous owner and operator of
a site and companies that disposed, or arranged for the disposal, of the
hazardous substance found at a site. CERCLA also authorizes the EPA and, in some
cases, private parties to take actions in response to threats to the public
health or the environment and to seek recovery from such responsible classes of
persons of the costs of such action. In the course of operations, the Company
generates wastes that may fall within CERCLA's definition of "hazardous
substances." The Company may be responsible under CERCLA for all or part of the
costs to clean up sites at which such substances have been disposed. The Company
has not been named by the EPA or alleged by any third party as being potentially
responsible for costs and liabilities associated with alleged releases of any
"hazardous substance" at any superfund site, but it is possible that it could be
named in the future.
The Company's operations are subject to the requirements of the Federal
Occupational Safety and Health Act ("OSHA") and comparable state statutes. The
OSHA hazard communication standard, the EPA community right-to-know regulations
under Title III of the Federal Superfund Amendment and Reauthorization Act and
similar state statutes require that information be organized and maintained
about hazardous materials used or produced in its operations. Certain of this
information must be provided to employees, state and local government
authorities and citizens.
The Oil Pollution Act, as recently amended ("OPA"), requires the lessee or
permittee of the offshore area in which a covered offshore facility is located
to establish and maintain evidence of financial responsibility in the amount of
$35 million, which may be increased to $150 million in certain circumstances to
cover liabilities related to an oil spill for which such person is statutorily
responsible. In March 1997, the MMS proposed regulations to implement these
financial responsibility requirements under OPA. The Company cannot predict the
final form of any financial responsibility regulations that will be adopted by
the MMS, but the impact of any such regulations should not be any more adverse
to the Company than it will be to other similarly situated companies. OPA also
subjects responsible parties to strict, joint and several and potentially
unlimited liability for removal costs and certain other damages caused by an oil
spill covered by the statute.
NATURAL GAS SALES TRANSPORTATION
In the past, there were various federal laws which regulated the price at
which natural gas could be sold. Since 1978, various federal laws have been
enacted which have resulted in the termination on January 1, 1993 of all price
and non-price controls for natural gas sold in "first sales." As a result, on
and after January 1, 1993, none of the Company's natural gas production is
subject to federal price controls.
The transportation and sale for resale of natural gas is subject to
regulation by the Federal Energy Regulatory Commission ("FERC") under the
Natural Gas Act of 1938 ("NGA") and the Natural Gas Policy Act of 1978 ("NGPA").
Commencing in 1985, the FERC promulgated a series of orders and regulations
adopting changes that significantly affect the transportation and marketing of
natural gas. These changes have been intended to foster competition in the
natural gas industry by, among other things, inducing or mandating that
interstate pipeline companies provide nondiscriminatory transportation services
to producers, distributors and other shippers (so-called "open access"
requirements). The effect of the foregoing regulations has been to create a more
open access market for natural gas purchases and sales and has enabled the
Company, as a producer, buyer and seller of natural gas, to enter into various
contractual natural gas sale, purchase and transportation arrangements on
unregulated, privately negotiated terms.
The Company owns a 75-mile intrastate pipeline and associated compression
facilities in the Sonora area of West Texas. In excess of 98% of the gas
transported in this pipeline system during 1998 was owned by the Company. The
operation of this system is subject to regulation by the Texas Railroad
Commission.
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CERTAIN OPERATIONAL RISKS
The Company's operations are subject to the risks and uncertainties
associated with drilling for, and production and transportation of, oil and gas.
The Company must incur significant expenditures for the identification and
acquisition of properties and for the drilling and completion of wells. Drilling
activities are subject to numerous risks, including the risk that no
commercially productive oil or gas reservoirs will be encountered. The Company's
prospects for future growth and profitability will depend on its ability to
replace current reserves through drilling, acquisitions, or both. The Company's
ability to market its oil and gas production depends upon the availability and
capacity of oil and gas gathering systems and pipelines, among other factors,
many of which are beyond the Company's control.
The Company's operations are subject to the risks inherent in the oil and
gas industry, including the risks of fire, explosions, blow-outs, pipe failure,
abnormally pressured formations and environmental accidents such as oil spills,
gas leaks, salt water spills and leaks, ruptures or discharges of toxic gases,
the occurrence of any of which could result in substantial losses to the Company
due to injury or loss of life, severe damage to or destruction of property,
natural resources and equipment, pollution or other environmental damage,
clean-up responsibilities, regulatory investigation and penalties and suspension
of operations. The Company's operations may be materially curtailed, delayed or
canceled as a result of numerous factors, including the presence of
unanticipated pressure or irregularities in formations, accidents, title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery of equipment. In accordance with customary
industry practice, the Company maintains insurance against some, but not all, of
the risks described above. There can be no assurance that the levels of
insurance maintained by the Company will be adequate to cover any losses or
liabilities. The Company cannot predict the continued availability of insurance
or its availability at commercially acceptable premium levels.
EMPLOYEES
As of March 12, 1999, the Company had approximately 400 employees.
Management believes that its relations with its employees are satisfactory. The
Company's employees are not covered by a collective bargaining agreement.
RELATIONSHIP BETWEEN THE COMPANY AND S.A. LOUIS DREYFUS ET CIE
The Company was acquired by S.A. Louis Dreyfus et Cie in 1990 to engage in
oil and gas acquisition, development, production and marketing activities. S.A.
Louis Dreyfus et Cie's other principal activities include the international
merchandising and exporting of various commodities, ownership and management of
ocean vessels, real estate and crude oil refining.
S.A. Louis Dreyfus et Cie currently is the beneficial owner of approximately
52% of the Company's Common Stock. Through its ability to elect all directors of
the Company, S.A. Louis Dreyfus et Cie has the ability to control all matters
relating to the management of the Company, including any determination with
respect to the acquisition or disposition of Company assets and the future
issuance of Common Stock or other securities of the Company. S.A. Louis Dreyfus
et Cie also has the ability to control the Company's drilling, operating and
acquisition expenditure plans. There is no agreement between S.A. Louis Dreyfus
et Cie and any other party, including the Company, that would prevent S.A. Louis
Dreyfus et Cie from acquiring additional shares of the Common Stock.
The Company has an agreement ("Services Agreement") with S.A. Louis Dreyfus
et Cie pursuant to which S.A. Louis Dreyfus et Cie provides to the Company
various services (principally insurance-related services). Such services
historically have been supplied to the Company by S.A. Louis Dreyfus et Cie, and
the Services Agreement provides for the further delivery of such services, but
only to the extent requested by the Company. The Company reimburses S.A. Louis
Dreyfus et Cie for a portion of the salaries of employees performing requested
services based on the amount of time expended ("Hourly Charges"), all
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direct third party costs incurred by S.A. Louis Dreyfus et Cie in rendering
requested services and overhead costs equal to 40% of the Hourly Charges. The
Services Agreement will continue until terminated by either party upon 60 days
prior written notice to the other party in accordance with the terms of the
Services Agreement. In the event of termination of the Services Agreement by
S.A. Louis Dreyfus et Cie, the Company has an option to continue the agreement
for up to 180 days to enable it to arrange for alternative services.
POTENTIAL CONFLICTS OF INTEREST
The nature of the respective businesses of the Company and S.A. Louis
Dreyfus et Cie may give rise to conflicts of interest between such companies.
Conflicts could arise, for example, with respect to intercompany transactions
between the Company and S.A. Louis Dreyfus et Cie, competition in the marketing
of natural gas, the issuance of additional shares of voting securities, the
election of directors or the payment of dividends by the Company.
The Company and S.A. Louis Dreyfus et Cie have in the past entered into
significant intercompany transactions and agreements incident to their
respective businesses. Such transactions and agreements have related to, among
other things, the purchase and sale of natural gas and the provision of certain
corporate services. It is the intention of S.A. Louis Dreyfus et Cie and the
Company that the Company operate independently, other than receiving services as
contemplated by the Services Agreement, but S.A. Louis Dreyfus et Cie and the
Company may enter into other material intercompany transactions. In any event,
the Company intends that the terms of any future transactions and agreements
between the Company and S.A. Louis Dreyfus et Cie will be at least as favorable
to the Company as could be obtained from unaffiliated third parties.
S.A. Louis Dreyfus et Cie has advised the Company that it does not currently
intend to engage in the acquisition and development of, or exploration for, oil
and gas except through its beneficial ownership of Common Stock. However, as
part of S.A. Louis Dreyfus et Cie's business strategy, S.A. Louis Dreyfus et Cie
may, from time to time, acquire other businesses primarily engaged in other
activities, which may also include oil and gas acquisition, exploration and
development activities as part of such acquired businesses. S.A. Louis Dreyfus
et Cie is also actively engaged in the trading of oil and gas which includes the
use of fixed-price contracts. The Company has not adopted any special procedures
to address potential conflicts of interest between the Company and S.A. Louis
Dreyfus et Cie relating to such potential competition. However, the Company does
not currently anticipate that any potential competition with S.A. Louis Dreyfus
et Cie for fixed-price contracts would adversely affect its ability to hedge its
production.
CERTAIN DEFINITIONS
The terms defined in this section are used throughout this filing:
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to oil or other liquid hydrocarbons.
BCF. Billion cubic feet.
BCFE. Billion cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf of natural gas.
BTU. British thermal unit, which is the heat required to raise the
temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
BBTU. Billion Btus.
DEVELOPED ACREAGE. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
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DEVELOPMENT LOCATION. A location on which a development well can be
drilled.
DEVELOPMENT WELL. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive in an
attempt to recover proved undeveloped reserves.
DRILLING UNIT. An area specified by governmental regulations or orders or
by voluntary agreement for the drilling of a well to a specified formation or
formations which may combine several smaller tracts or subdivides a large tract,
and within which there is usually some right to share in production or expense
by agreement or by operation of law.
DRY HOLE. A well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
EBITDAX. EBITDAX is defined herein as income (loss) before interest, income
taxes, depreciation, depletion and amortization, impairment, exploration costs
and change in derivative fair value. The Company believes that EBITDAX is a
financial measure commonly used in the oil and gas industry as an indicator of a
company's ability to service and incur debt. However, EBITDAX should not be
considered in isolation or as a substitute for net income, cash flows provided
by operating activities or other data prepared in accordance with generally
accepted accounting principles, or as a measure of a company's profitability or
liquidity. EBITDAX measures as presented may not be comparable to other
similarly titled measures of other companies.
ESTIMATED FUTURE NET REVENUES. Revenues from production of oil and gas, net
of all production-related taxes, lease operating expenses, capital costs and
abandonment costs.
EXPLORATORY WELL. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
FINDING COST. Total costs incurred to acquire, explore and develop oil and
gas properties divided by the increase in proved reserves through acquisition of
proved properties, extensions and discoveries, improved recoveries and revisions
of previous estimates.
GROSS ACRE. An acre in which a working interest is owned.
GROSS WELL. A well in which a working interest is owned.
INFILL DRILLING. Drilling for the development and production of proved
undeveloped reserves that lie within an area bounded by producing wells.
LEASE OPERATING EXPENSE. All direct costs associated with and necessary to
operate a producing property.
MBBLS. Thousand barrels.
MBTU. Thousand Btus.
MCF. Thousand cubic feet.
MCFE. Thousand cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf of natural gas.
MMBBLS. Million barrels.
MMBTU. Million Btus.
MMCF. Million cubic feet.
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MMCFE. Million cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf of natural gas.
NATURAL GAS LIQUIDS. Liquid hydrocarbons which have been extracted from
natural gas (e.g., ethane, propane, butane and natural gasoline).
NET ACRES OR NET WELLS. The sum of the fractional working interests owned
in gross acres or gross wells.
OVERRIDING ROYALTY INTEREST. An interest in an oil and gas property
entitling the owner to a share of oil and gas production free of well or
production costs.
PRESENT VALUE. When used with respect to oil and gas reserves, present
value means the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production, future development
costs, and future abandonment costs, using prices and costs in effect as of the
date of the report or estimate, without giving effect to non-property related
expenses such as general and administrative expenses, debt service and future
income tax expense or to depreciation, depletion and amortization, discounted
using an annual discount rate of 10%. The prices used to estimate future net
revenues include the effects of the Company's Fixed-Price Contracts except where
otherwise specifically noted. Estimated quantities of proved reserves are
determined without regard to such contracts.
PRODUCTIVE WELL. A well that is producing oil or gas or that is capable of
production.
PROVED DEVELOPED RESERVES. Proved reserves that are expected to be
recovered through existing wells with existing equipment and operating methods.
PROVED RESERVES. The estimated quantities of oil and gas which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions.
PROVED UNDEVELOPED RESERVES. Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion.
RECOMPLETION. The completion for production of an existing wellbore in
another formation from that in which the well has previously been completed.
RESERVE LIFE. A measure of how long it will take to produce a quantity of
reserves, calculated by dividing estimated proved reserves by production for the
twelve-month period prior to the date of determination (in gas equivalents).
RESERVE REPLACEMENT RATIO. A measure of proved reserve growth determined by
dividing the net change in reserve quantities between two dates, excluding
production, by the quantity produced between the two dates.
TBTU. One trillion Btus.
TCFE. Trillion cubic feet of gas equivalent, determined using the ratio of
one Bbl of oil or condensate to six Mcf of natural gas.
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.
WORKING INTEREST. The operating interest which gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
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ITEM 2. PROPERTIES
GENERAL
The Company's oil and gas acquisition, exploration and development
activities are conducted mainly in its Core Areas: the Permian Region of West
Texas, Southeast New Mexico and the San Juan Basin; the Mid-Continent Region of
Oklahoma, Kansas and the Panhandle of Texas; and the Gulf Coast Region which
includes South Texas, Offshore Gulf of Mexico, East Texas, Southwest Arkansas
and North Louisiana. Proved reserves as of December 31, 1998 consisted of 24
MMBbls of oil and 1.2 Tcf of natural gas, totaling 1.3 Tcfe. At this date, the
Company had ownership interests in approximately 9,200 producing wells. The
Company operates 3,500 of these wells which contain 81% of its total proved
reserves. Net daily production during 1998 was 9.4 MBbls of oil and 276.9 MMcf
of natural gas, or 333.3 MMcfe. The Company drilled 324 developmental oil and
gas wells, 297 of which were completed as commercial producers, and 27
exploratory wells, 14 of which were successfully completed, during 1998.
The Company has allocated $170 million for its 1999 drilling program,
subject to revision based upon oil and gas prices, proved reserve acquisitions
and other factors. Approximately $61 million of this total, or 36%, has been
allocated to exploration activities and $109 million, or 64%, has been allocated
to development activities. It is expected that this drilling expenditure will
result in the drilling of about 220 wells, including 30 exploratory wells and
190 development wells. See "Item 7--Management's Discussion and Analysis of
Financial Condition and Results of Operations--Outlook for Fiscal Year 1999."
CORE AREAS
The following table sets forth certain information regarding the Company's
activities in each of its principal producing areas as of December 31, 1998:
CORE AREAS
<TABLE>
<CAPTION>
MID-
PERMIAN CONTINENT GULF COAST OTHER TOTAL
------------ ---------- ---------- ---------- ------------
<S> <C> <C> <C> <C> <C>
PROPERTY STATISTICS:
Proved reserves (Bcfe)........................... 635 406 250 49 1,340
Percent of total proved reserves................. 47% 30% 19% 4% 100%
Gross producing wells............................ 4,074 3,457 818 853 9,202
Net producing wells.............................. 1,934 1,056 287 135 3,412
Gross acreage.................................... 1,259,124 926,067 944,179 484,620 3,613,990
Net acreage...................................... 571,011 358,756 333,845 121,071 1,384,683
Potential drill sites............................ 850 400 75 250 1,575
1998 RESULTS:
Gross wells drilled.............................. 195 77 49 30 351
Gross successful wells........................... 179 65 41 26 311
Drilling success................................. 92% 84% 84% 87% 89%
Production (Bcfe)................................ 42.4 37.5 37.7 4.0 121.6
Average net daily production (MMcfe)............. 116.2 102.9 103.2 11.0 333.3
Lease operating expense per Mcfe................. $ .45 $ .43 $ .41 $ .54 $ .44
1999 DRILLING BUDGET (MM$):
Development...................................... $ 51 $ 36 $ 22 $ -- $ 109
Exploration...................................... 6 7 48 -- 61
------------ ---------- ---------- ---------- ------------
Total............................................ $ 57 $ 43 $ 70 $ -- $ 170
------------ ---------- ---------- ---------- ------------
------------ ---------- ---------- ---------- ------------
</TABLE>
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PERMIAN REGION
The Company is actively involved in development and exploration activities
in several areas within the Permian Region. These areas include the Sonora Area,
the Pitchfork Ranch and the Spraberry Trend of West Texas, and the Delaware
Basin of Southeast New Mexico, among others. The Company's properties in the
Permian Region contain 635 Bcfe of proved reserves, nearly one-half of the
Company's total reserve base, in about 4,100 wells. The Company drilled 195
wells in the Permian Region in 1998 and daily production averaged 116 MMcfe per
day. The Company has identified 850 undrilled locations in this region of which
202 have been assigned proved undeveloped reserves. Plans for this region in
1999 include the drilling of approximately 140 wells and a total investment of
$57 million, including acreage and seismic acquisition.
SONORA AREA
The Sonora area is located in the West Texas counties of Schleicher,
Crockett, Sutton and Edwards. It is comprised of five fields: Sawyer, Shurley
Ranch, MMW, Aldwell Ranch and Whitehead, which are located on the northeast side
of the Val Verde Basin of West Central Texas. The Company has an average 93%
working interest in 1,785 wells, most of which are Company operated. Production
is predominately from the Canyon formation at depths ranging from 2,500 to 6,500
feet and the Strawn formation at depths ranging from 5,000 to 9,000 feet. The
majority of the Company's interest in these properties was acquired in 1993 and
1995.
CANYON FORMATION. Natural gas in the Canyon formation is stratigraphically
trapped in lenticular sandstone reservoirs and the typical Sonora Area well
encounters numerous such reservoirs over the formation's gross thickness of
approximately 1,500 feet. The Canyon reservoirs tend to be discontinuous and to
exhibit low porosity and permeability, characteristics which reduce the area
that can be effectively drained by a single well. These characteristics have
encouraged operators in the area to undertake Canyon infill drilling programs.
Initial wells were drilled on 640 acre drilling units, but well performance
characteristics have indicated that denser well spacing is necessary for
effective drainage. The Company continues to drill infill wells in these units
and, in some areas, fields are now developed on 40 acre spacing.
STRAWN FORMATION. The Strawn formation, a shallow-marine, fossiliferous
limestone, produces natural gas from fractures and irregularly distributed
porosity trends draped across anticlinal features. Original field development
took place on 640 acre units, with subsequent infill programs downsizing some
areas to 80 acre density. Testing of the Strawn formation in Sonora wells, for
which the primary drilling objective was the Canyon formation, has been an
attractive play for the Company because the Strawn lies less than 1,000 feet
below the Canyon formation. Because of the closeness in depth, the incremental
cost to evaluate the Strawn formation has been relatively minor. The Strawn
production is generally commingled with the Canyon production stream. During
1998, the Company completed a 19 square mile 3D seismic survey on the Buckhorn
prospect, a northeast extension of Sonora. The 3D interpretation has identified
several Strawn reef prospects and an Atoka play.
The Company has maintained an aggressive development drilling program in the
Sonora Area since 1993, having drilled 580 Canyon and Strawn wells with only 20
dry holes. The 1998 drilling program resulted in the drilling of 126 wells which
contributed to record production from the Sonora Area. Net production from
Sonora reached the record rate of 93 MMcfe per day. The Company plans to drill
approximately 110 wells in Sonora during 1999, the majority of which are
relatively low risk locations. The Company has identified over 575 potential
locations on its acreage, of which 179 have been assigned proved undeveloped
reserves. Subject to further study and drilling results, the Company believes
additional proved reserves will ultimately be attributed to many of the other
locations. In addition to infill drilling potential, many of the Company's
producing wells in the Sonora Area have recompletion possibilities in existing
wellbores.
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The Company is currently drilling and evaluating a Lower Canyon play south
of the main producing area. More than 30,000 acres have been acquired along this
Lower Canyon trend and two Lower Canyon wells have been drilled. The first of
these two wells was dry, but the second well encountered potential Lower Canyon
sands and is waiting on completion.
PITCHFORK RANCH
The Pitchfork Ranch is located in King and Dickens Counties, Texas, and
covers approximately 140,000 acres. The Company is the operator and its
ownership ranges from 45% to 78% in certain leases within this ranch. Target
zones are the Tannehill sand at a depth of 4,500 feet and the Canyon/Strawn Reef
at 5,500 feet. The Tannehill sands were deposited as northeast to southwest
trending channel sands and extend over most of the acreage. Production is
generally found within point bars on structural highs or in stratigraphic traps.
Fields within this meandering channel system of the Tannehill can have potential
reserves of up to 2 MMBbls, with the opportunity for numerous fields to exist on
the ranch. The Canyon/ Strawn produces from reefs in the area, some of which
have produced more than 10 MMBbls. The first 30 square mile 3D seismic survey
conducted in 1997 resulted in the completion of six oil wells in the Tannehill
formation. In 1998, a second 3D seismic survey of 50 square miles was completed
and drilling of Tannehill and Canyon/Strawn targets is expected to commence in
the first quarter of 1999 based on this new seismic information.
SPRABERRY TREND
The Spraberry Trend is located in the West Texas counties of Martin,
Midland, Glasscock, Upton, Reagan and Irion. The fields in the Spraberry Trend
are characterized by the production of both oil and gas from productive zones
ranging from the Lower Clearfork formation at a depth of 4,500 feet, to the Dean
formation at a depth of 7,000 feet, with the majority of the production from the
Spraberry formation at a depth of 5,500 to 6,500 feet. The Spraberry formation
produces from fractured sandstones and siltstones and is characterized by low
porosity and permeability. These formation characteristics have encouraged
operators to develop the area on 80 acre spacing. Over the past few years, the
Company has pursued an active infill drilling program in the Spraberry trend
which will be pursued again when oil prices recover to provide more attractive
economics.
SOUTHEAST NEW MEXICO
The Company is also active in southeastern New Mexico in the Delaware Basin,
where the primary objectives are the Morrow sands and Devonian carbonates. The
Morrow sands are deposited in fluvial channels which trend from northwest to
southeast. The Devonian carbonates occur as reefs that are as much as 600 feet
thick. These reefs occur along a Devonian shelf edge that extends along a trend
that is more than 250 miles long. These reservoirs exhibit excellent porosity
and permeability at depths between 10,000 and 15,000 feet. These objectives also
lend themselves to the use of modern technology including 3D seismic and
computer aided mapping. In 1999 it is anticipated that approximately 10 wells
may be drilled for these objectives.
MID-CONTINENT REGION
The Company was actively involved in the Mid-Continent Region when it was
acquired by S.A. Louis Dreyfus et Cie and has subsequently acquired substantial
additional acreage and proved reserves in the area through multiple synergistic
acquisitions. The Company operates approximately 1,280 wells in the
Mid-Continent Region. The Company's properties are located in and along the
northern shelf of the Anadarko Basin in western Oklahoma, in the deeper Anadarko
Basin in the Texas Panhandle, and in Kansas. Development of the Company's
Mid-Continent Region properties began in the late 1970's. Production is
predominately natural gas from productive formations of Pennsylvanian and
Pre-Pennsylvanian age rock. Productive depths range from 3,000 to 17,000 feet.
Pre-Pennsylvanian
18
<PAGE>
reservoirs include the Chester, Mississippi and Hunton formations, with greater
production from these formations occurring in highly fractured carbonate
intervals. Pennsylvanian reservoirs include the Granite Wash, Red Fork, Atoka,
Morrow and Springer sandstones. The stratigraphic nature of these reservoirs
frequently provides for multiple targets in the same wellbores. Spacing in these
formations is generally on 640 acres with extensive increased density drilling
having occurred over the last 15 years. Two primary areas of focus in the
Mid-Continent are the Watonga-Chickasha Trend in central Oklahoma and the Texas
Panhandle.
The Company has pursued an active low-risk infill drilling program in the
Mid-Continent area over the past five years, including the drilling of 77 wells
in 1998. Average net daily production was 103 MMcfe per day for this region in
1998. The Company has ownership in about 3,500 wells with proved reserves of 406
Bcfe. The Company plans to drill approximately 60 wells in this area during
1999, with the primary development focus being the higher potential
Morrow/Springer sand subcrop in the Watonga-Chickasha Trend. The Company has
identified 400 undrilled locations in the Mid-Continent Region, of which 163
have been assigned proved undeveloped reserves.
WATONGA-CHICKASHA TREND
These Morrow/Springer sands, located in central Oklahoma, were deposited as
bars and channels along an ancient coast line more than 350 miles long. These
sands exhibit excellent porosity and permeability at depths of 10,000 to 13,000
feet. Multiple objectives of up to a dozen sands have allowed increased drilling
from one well per 640 acres to as many as four wells per 640 acres. The majority
of the wells drilled in this trend are lower risk development wells. During
1999, the Company plans to drill four exploratory tests seeking to discover new
bars or channels and approximately 40 development wells.
TEXAS PANHANDLE
In the Texas Panhandle, the primary objective is the Morrow sand which was
deposited in fluvial channels. Previous experience has shown that 3D seismic can
help identify these sand channels. In 1998, the Company completed a 40 square
mile 3D seismic survey on the Munson Project. This data is currently being
processed and is expected to produce drilling locations by the end of the first
quarter of 1999. The Company has approximately 50% working interest in this
40,000 acre project.
GULF COAST REGION
The Company has been active in the Gulf Coast Region since its initial entry
through an acquisition in 1991. Development drilling on these acquired
properties began in 1992 and continued into 1998. Presently, the Company is
actively involved in an exploration and development program in Lavaca County,
Texas and offshore in the Gulf of Mexico. The Company's properties in this
region number approximately 800 wells and include 250 Bcfe of proved reserves.
The Company drilled 49 wells in the Gulf Coast Region during 1998 and daily
production averaged 103 MMcfe per day. The Company has identified 75 undrilled
locations in this region of which 26 have been assigned proved undeveloped
reserves. Plans for this region in 1999 include the drilling of approximately 20
wells and a total investment of $70 million, including acreage and seismic
acquisition.
LAVACA COUNTY AREA
The Company began its involvement in Lavaca County joint venture projects in
1996 to explore and drill, primarily for the Lower Wilcox formation. Secondary
targets include the shallower Upper Wilcox, Miocene, Frio and Yegua targets.
Working interests in these projects, including the Yoakum Gorge and S.W. Speaks
projects, initially ranged from 25% to 35%. Subsequent acquisitions in 1997 and
1998 have more than doubled the Company's interests in these projects. The
Company has additionally expanded its position in the Wilcox trend further to
the east to include the Provident City field.
19
<PAGE>
The Company now holds working interests ranging from 30% to 87.5% in 60,000
gross acres in Lavaca County, Texas. Since this project began, the Company has
participated in 30 Lower Wilcox wells, over 90% of which have successfully been
completed as producers. Approximately 200 square miles of high-fold 3D seismic
data was obtained in 1996 and 1997 which continues to be evaluated. An
additional 50 square miles of 3D seismic was shot on the South Borchers prospect
in late 1998 which is a southern extension to existing data. This data is being
processed and interpreted with drilling expected to commence in mid-1999. The
target zones are the Lower Wilcox sands from 10,000 to 17,000 feet and the
shallow Miocene, Frio, Yegua and Upper Wilcox sands ranging in depth from 3,500
to 8,000 feet.
The Company's Lower Wilcox drilling program in 1998 resulted in the
successful completion of 20 wells, including eight exploratory tests. The Lower
Wilcox sands are part of an ancient deltaic system deposited across an unstable
muddy continental shelf. The rapid subsidence of the underlying beds allowed
accumulation of massive Wilcox sand packages with a high degree of structural
complexity. These deep structures present higher risk but have significant
potential, ranging up to 100 Bcf per field. The Company's Sibley #4 discovery in
the Frost field logged approximately 300 feet of pay and had initial production
of 10 MMcfe per day with 9,000 pounds of flowing tubing pressure from 60 feet of
interval. Drilling plans for 1999 include approximately 20 Lower Wilcox wells in
the Yoakum Gorge area, of which seven are expected to be exploratory.
ARKLATEX AREA
SMACKOVER TREND. The Company's operations in the Smackover Trend of
Southwestern Arkansas are focused primarily in the Midway field, which is
operated by the Company. The Midway field is located in Lafayette County,
Arkansas and produces oil from the Smackover formation at an average depth of
6,500 feet. The Company owns an average of 79% working interest in this mature
waterflood unit. Due to low oil prices, the Company does not plan to drill any
wells in these fields in 1999.
EAST TEXAS. The Company has varying working interests in over 100,000 acres
in the Oak Hill field and in the Cotton Valley Reef trend in Leon, Freestone,
Smith, Anderson and Cherokee Counties of East Texas. During 1998, the Company
drilled several successful wells targeting the Taylor sand formation and one in
the Cotton Valley Reef. The Company does not plan to drill any wells in the area
in 1999.
During 1998, the Company drilled 42 wells onshore in the Gulf Coast Region
and average net daily production was 56 MMcfe per day. The Company has
identified 60 undrilled onshore locations of which 22 have been assigned proved
undeveloped reserves.
OFFSHORE AREA
The Company owns working interests in twelve operated and eight
outside-operated oil and gas production platforms and 164,000 acres, and owns
over two thousand square miles of 3D seismic data in the Gulf of Mexico. Average
net daily production from the Company's offshore properties was 47 MMcfe per day
in 1998.
TEXAS STATE WATERS. The Company owns an average 79% working interest in
more than 38,000 gross acres in the Texas State Waters area. Two thousand square
miles of 3D seismic data has been collected in the area. High-quality 3D seismic
information for this offshore area previously was unavailable due to the
inability of vessels towing seismic cables to operate in less than 60 feet of
water without damaging the seismic equipment. The advent of ocean-bottom cabling
has made the acquisition of high-quality 3D seismic information economically
feasible. The Company drilled five exploratory tests offshore in 1998,
successfully completing two for a combined gross rate of 22 MMcfe per day. The
Company has identified several exploration prospects in the shallow waters
offshore in the Gulf of Mexico.
HIGH ISLAND 116. High Island Block 116 is located in shallow federal
waters, offshore Texas. The Company owns a 44% non-operated working interest in
this block which produces from the Lower
20
<PAGE>
Miocene sands at an approximate depth of 10,000 feet. This block had average net
daily production of 11 MMcfe during 1998.
EAST CAMERON BLOCK 328. East Cameron Block 328 is located in federal
waters, offshore Louisiana, in approximately 240 feet of water. The block is on
the flank of a large salt feature with multiple sands located in several fault
blocks. Production is from the Trim A, Trim S and the HB-1 sands. The platform
went on production in April 1998 and produced 16 MMcfe per day during 1998.
HIGH ISLAND 45. High Island Block 45 is located in shallow federal waters,
offshore Texas. The Company is the operator and owns a 25% working interest in
this block which produces from the Lower Miocene sands at an approximate depth
of 11,000 feet. This platform had average net daily production of 4 MMcfe during
1998.
RESERVES
The following table sets forth the estimated net quantities of the Company's
proved and proved developed reserves as of December 31 for each year presented
and the Estimated Future Net Revenues, as defined herein, and Present Values
attributable to total proved reserves at such dates.
PROVED RESERVES
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------------------------------------
1998 1997 1996 1995 1994
--------- --------- --------- --------- ---------
(DOLLARS IN MILLIONS, EXCEPT PRICE DATA)
<S> <C> <C> <C> <C> <C>
ESTIMATED PROVED RESERVES:
Natural gas (Bcf)....................................... 1,193.7 1,028.8 849.2 753.9 574.0
Oil (MMBbls)............................................ 24.4 29.1 23.5 20.4 19.3
Total (Bcfe)............................................ 1,340.2 1,203.4 990.2 876.1 689.9
Estimated Future Net Revenues including
Fixed-Price Contracts................................. $ 1,955.6 $ 2,169.9 $ 2,417.4 $ 1,531.5 $ 1,219.8
Estimated Future Net Revenues excluding
Fixed-Price Contracts................................. $ 1,676.8 $ 1,926.0 $ 2,643.8 $ 1,092.4 $ 683.4
Present Value including Fixed-Price Contracts........... $ 978.9 $ 1,136.0 $ 1,117.7 $ 737.5 $ 616.0
Present Value excluding Fixed-Price Contracts........... $ 811.1 $ 1,002.6 $ 1,303.7 $ 524.4 $ 358.8
ESTIMATED PROVED DEVELOPED RESERVES:
Natural gas (Bcf)....................................... 1,026.8 899.2 709.7 630.6 433.3
Oil (MMBbls)............................................ 20.7 24.3 17.9 14.8 13.1
Total (Bcfe)............................................ 1,151.2 1,045.1 817.1 719.6 511.8
YEAR-END PRICES USED IN ESTIMATING FUTURE
NET REVENUES(1):
Natural gas (per Mcf)................................... $ 2.30 $ 2.73 $ 3.55 $ 2.60 $ 2.61
Oil (per Bbl)........................................... $ 9.46 $ 16.77 $ 24.66 $ 17.80 $ 16.08
</TABLE>
- ------------------------
(1) The year-end prices used to estimate future net revenues include the effects
of the Company's Fixed-Price Contracts which have escalating fixed prices.
Estimated proved reserve quantities have been determined without regard to
such contracts.
No estimates of the Company's proved reserves comparable to those included
herein have been included in reports to any federal agency other than the
Securities and Exchange Commission.
The Company's estimated proved reserves as of December 31, 1998 are based
upon studies prepared by the Company's staff of engineers and reviewed by Ryder
Scott Company, independent petroleum engineers. Estimated recoverable proved
reserves have been determined without regard to any economic
21
<PAGE>
benefit that may be derived from the Company's Fixed-Price Contracts. Such
calculations were prepared using standard geological and engineering methods
generally accepted by the petroleum industry and in accordance with Securities
and Exchange Commission guidelines. The Estimated Future Net Revenues and
Present Value, as adjusted for Fixed-Price Contracts, were based on the
engineers' production volume estimates with price adjustments based on the terms
of the Company's Fixed-Price Contracts as of December 31, 1998. The amounts
shown do not give effect to indirect expenses such as general and administrative
expenses, debt service and future income tax expense or to depletion,
depreciation and amortization.
The Company estimates that if all other factors (including the estimated
quantities of economically recoverable reserves) were held constant, a $1.00 per
Bbl change in oil prices and a $.10 per Mcf change in gas prices from those used
in calculating the Present Value would change such Present Value by $14 million
and $39 million, respectively.
The prices used in calculating the Estimated Future Net Revenues
attributable to proved reserves are determined using the Company's Fixed-Price
Contracts for the corresponding volumes and production periods adjusted for
estimated location and quality differentials. These prices are on average higher
than spot market prices at December 31, 1998. If such Fixed-Price Contracts were
not in effect and the Company used December 31, 1998 wellhead prices, the
Estimated Future Net Revenues attributable to proved reserves and the Present
Value thereof would be $1.7 billion and $.8 billion, respectively.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the Company. The
reserve information shown herein is estimated. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact manner, and the accuracy of any reserve estimate
is a function of the quality of available data and of engineering and geological
interpretation and judgment. 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 oil and gas that are ultimately
recovered. The meaningfulness of such estimates is highly dependent upon the
accuracy of the assumptions upon which they were based.
For further information on reserves, future net revenues and the
standardized measure of discounted future net cash flows, see Note 15 of the
Notes to Consolidated Financial Statements appearing elsewhere herein.
COSTS INCURRED AND DRILLING RESULTS
The following table sets forth certain information regarding the costs
incurred by the Company in its acquisition, exploration and development
activities during the periods indicated.
COSTS INCURRED
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
----------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
PROPERTY ACQUISITION COSTS:(1)
Proved............................................... $ 4,088 $ 349,037 $ 36,125 $ 118,652 $ 36,575
Unproved............................................. 11,815 109,648 6,934 1,717 4,953
---------- ---------- ---------- ---------- ----------
15,903 458,685 43,059 120,369 41,528
Exploration costs.................................... 74,123 21,514 10,610 391 --
Development costs.................................... 136,462 122,402 80,553 64,498 67,764
---------- ---------- ---------- ---------- ----------
Total................................................ $ 226,488 $ 602,601 $ 134,222 $ 185,258 $ 109,292
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
</TABLE>
- ------------------------
(1) Proved and unproved property acquisition costs for 1997 include $339.9
million and $98.0 million, respectively, of allocated American Acquisition
purchase price.
22
<PAGE>
The Company drilled or participated in the drilling of wells as set out in
the table below for the periods indicated.
WELLS DRILLED
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------
1998 1997 1996
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
DEVELOPMENT WELLS:
Gas..................................... 237 153 223 166 179 130
Oil..................................... 60 37 52 20 92 19
Dry..................................... 27 20 20 14 9 5
----- ---- ----- ---- ----- ----
Total................................... 324 210 295 200 280 154
----- ---- ----- ---- ----- ----
----- ---- ----- ---- ----- ----
EXPLORATORY WELLS:
Gas..................................... 13 8 32 24 18 6
Oil..................................... 1 1 4 3 -- --
Dry..................................... 13 9 12 9 7 2
----- ---- ----- ---- ----- ----
Total................................... 27 18 48 36 25 8
----- ---- ----- ---- ----- ----
----- ---- ----- ---- ----- ----
<CAPTION>
1995 1994
------------ ------------
GROSS NET GROSS NET
----- ---- ----- ----
<S> <C> <C> <C> <C>
DEVELOPMENT WELLS:
Gas..................................... 134 115 144 131
Oil..................................... 114 28 27 6
Dry..................................... 14 5 4 2
----- ---- ----- ----
Total................................... 262 148 175 139
----- ---- ----- ----
----- ---- ----- ----
EXPLORATORY WELLS:
Gas..................................... 3 1 -- --
Oil..................................... -- -- -- --
Dry..................................... -- -- -- --
----- ---- ----- ----
Total................................... 3 1 -- --
----- ---- ----- ----
----- ---- ----- ----
</TABLE>
As of December 31, 1998, the Company was involved in the drilling, testing
or completing of six gross (five net) development wells and two gross (one net)
exploratory wells.
ACREAGE
The following table sets forth the Company's developed and undeveloped oil
and gas lease and mineral acreage as of December 31, 1998. Excluded is acreage
in which the Company's interest is limited to royalty, overriding royalty and
other similar interests.
ACREAGE
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
--------------------- ---------------------
GROSS NET GROSS NET
---------- --------- ---------- ---------
<S> <C> <C> <C> <C>
CORE AREA:
Permian........................................................... 541,269 251,336 717,855 319,675
Mid-Continent..................................................... 641,737 274,344 284,330 84,412
Gulf Coast........................................................ 270,431 73,646 673,748 260,199
Other............................................................. 268,956 46,013 215,664 75,058
---------- --------- ---------- ---------
Total............................................................. 1,722,393 645,339 1,891,597 739,344
---------- --------- ---------- ---------
---------- --------- ---------- ---------
</TABLE>
PRODUCTIVE WELL SUMMARY
The following table sets forth the Company's ownership in productive wells
at December 31, 1998. Gross oil and gas wells include 176 wells with multiple
completions. Wells with multiple completions are counted only once for purposes
of the following table.
PRODUCTIVE WELLS
<TABLE>
<CAPTION>
PRODUCTIVE WELLS
--------------------
GROSS NET
--------- ---------
<S> <C> <C>
Gas....................................................................... 5,537 2,801
Oil....................................................................... 3,665 611
--------- ---------
Total..................................................................... 9,202 3,412
--------- ---------
--------- ---------
</TABLE>
23
<PAGE>
TITLE TO PROPERTIES
The Company believes that it has satisfactory title to its properties in
accordance with standards generally accepted in the oil and gas industry,
subject to such exceptions which, in the opinion of the Company, are not so
material as to detract substantially from the use or value of its properties.
The Company performs extensive title review in connection with acquisitions of
proved reserves and has obtained title opinions on substantially all of its
material producing properties. As is customary in the oil and gas industry, only
a perfunctory title examination is performed in connection with acquisition of
leases covering undeveloped properties. Generally, prior to drilling a well, a
more thorough title examination of the drill site tract is conducted and
curative work is performed with respect to significant title defects, if any,
before proceeding with operations.
The Company's oil and gas properties are subject to royalty, overriding
royalty, carried, net profits, working and other similar interests and
contractual arrangements customary in the oil and gas industry. Except as
otherwise indicated, all information presented herein is presented net of such
interests. The Company's properties are also subject to liens for current taxes
not yet due and other encumbrances. The Company believes that such burdens do
not materially detract from the value of such properties or from the respective
interests therein or materially interfere with their use in the operation of the
business. Approximately 29 Bcfe of the Company's oil and gas properties is
mortgaged to a Fixed-Price Contract counterparty, securing the Company's
performance under such contract.
ITEM 3. LEGAL PROCEEDINGS
MIDCON. On December 22, 1995, the United States District Court for the
Western District of Oklahoma entered a $10.8 million judgment in favor of the
Company against Midcon Offshore, Inc. ("Midcon") in connection with
non-performance by Midcon under an agreement to purchase a certain offshore oil
and gas property. In January 1996, Midcon delivered a $10.8 million promissory
note to the Company secured by first and second liens on assets of Midcon,
payable in full on or before December 15, 1996 in settlement of disputes in
connection with this litigation. During 1996, the Company received principal and
interest payments on the promissory note totaling $1.7 million which have been
reflected in the accompanying financial statements as other income. On December
16, 1996, Midcon filed for protection from its creditors under Chapter 11 of the
United States Bankruptcy Code in the United States Bankruptcy Court, Southern
District of Texas, Corpus Christi Division. In January 1997, Midcon filed an
action in the bankruptcy court alleging that Midcon's action in connection with
the settlement constituted fraudulent transfers or avoidable preferences, and
seeking a return of amounts paid and a release of the liens securing the payment
obligation under the note. The complaint filed in the action also alleged
certain affirmative claims against the Company including injury to reputation
and loss of business opportunity. The complaint also seeks subordination of the
Company's claim. The Court denied the Company's motion to dismiss the complaint.
The Company considers the allegations of the complaint to be without merit and
will vigorously defend against this action. Collection of unpaid interest and
principal on the Midcon note is uncertain and no amounts have been recorded with
respect thereto in the accompanying financial statements as of December 31,
1998. The Company will recognize income as any payments are received.
KNGSS. In February 1995, a lawsuit was filed in the United States District
Court in Denver, Colorado, by KN Gas Supply Services, Inc. ("KNGSS"), requesting
declaratory judgment that KNGSS had the right to reduce the contract price for
gas produced from the Bowdoin Field, a property obtained in the American
Acquisition, to market levels from October 1, 1993 forward. KNGSS alleges that
it has overpaid American and seeks a refund of approximately $7.7 million for
the period through September 1996. KNGSS has not updated its refund claim
through the present date. A motion for summary judgment was filed by American in
July 1996 and was argued before the court in February 1997. The Company assumed
responsibility for this lawsuit in connection with the American Acquisition. In
February 1998, the court ruled in favor of the Company's motion. KNGSS
subsequently filed an appeal which has not been heard. Although the Company
cannot predict the ultimate outcome of this proceeding, it will continue to
24
<PAGE>
vigorously defend its interests in this case and does not expect the outcome of
the case to have a material adverse impact on its financial position or results
of operations.
OTHER. American was a defendant in various other legal proceedings for
which the Company also assumed responsibility in the American Acquisition. The
largest of such legal claims was for an alleged underpayment of royalty of $5.5
million plus interest. In addition, American had received preliminary and final
royalty underpayment determinations from the Minerals Management Service
aggregating approximately $2.8 million plus interest in connection with certain
gas contract settlements made in prior years. The Company is a defendant in
additional pending legal proceedings which are routine and incidental to its
business. While the ultimate results of all these proceedings and determinations
cannot be predicted with certainty, the Company will vigorously defend its
interests and does not believe that the outcome of these matters will have a
material adverse effect on the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the quarter ended December 31, 1998, no matters were submitted by the
Company to a vote of its security holders.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock is listed on the New York Stock Exchange ("NYSE")
and traded under the symbol "LD." As of March 12, 1999, the Company estimates
there were approximately 10,500 beneficial owners of its Common Stock. The high
and low sales prices for the Company's Common Stock during each quarter in the
years ended December 31, 1998 and 1997, were as follows:
COMMON STOCK MARKET PRICES
<TABLE>
<CAPTION>
1998 1997
-------------------- --------------------
HIGH LOW HIGH LOW
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
QUARTER:
First................................................................... $ 20.13 $ 16.50 $ 19.50 $ 14.50
Second.................................................................. 20.63 15.50 18.38 13.38
Third................................................................... 19.00 10.50 22.50 15.38
Fourth.................................................................. 16.44 12.00 24.88 17.63
</TABLE>
The Company has paid no dividends, cash or otherwise, subsequent to the date
of the initial public offering of the Common Stock in November 1993. Certain
provisions of the indenture agreement for the Company's 9 1/4% Senior
Subordinated Notes due 2004 restrict the Company's ability to declare or pay
cash dividends unless certain financial ratios are maintained. Although it is
not currently anticipated that any cash dividends will be paid on the Common
Stock in the foreseeable future, the Board of Directors may review the Company's
dividend policy from time to time. In determining whether to declare dividends
and the amount of dividends to be declared, the Board will consider relevant
factors, including the Company's earnings, its capital needs and its general
financial condition.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data presented below as of December 31, 1998 and
1997, and for each of the three years ended December 31, 1998, 1997 and 1996,
has been derived from, and is qualified by reference to, the Company's audited
Consolidated Financial Statements, including the notes thereto, contained herein
beginning at page F-1. The selected financial data as of December 31, 1996, 1995
and 1994, and for the years ended December 31, 1995 and 1994, has been derived
from audited consolidated financial
25
<PAGE>
statements previously filed with the Securities and Exchange Commission but not
contained or incorporated herein. The selected financial data should be read in
conjunction with the Consolidated Financial Statements of the Company, including
the notes thereto, and "Item 7--Management's Discussion and Analysis of
Financial Condition and Results of Operations."
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
1998(2) 1997(3) 1996 1995 1994
------------ ------------ ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Oil and gas sales................................ $ 271,575 $ 222,016 $ 185,558 $ 163,366 $ 138,584
Change in derivative fair value.................. 17,346 -- -- -- --
Other income (loss).............................. 4,462 10,901 3,947 (418) 1,953
------------ ------------ ---------- ---------- ----------
Total revenues................................. 293,383 232,917 189,505 162,948 140,537
------------ ------------ ---------- ---------- ----------
Operating costs.................................. 66,295 49,169 44,615 35,352 33,713
General and administrative....................... 25,971 18,855 16,325 16,631 15,309
Exploration costs................................ 34,543 8,956 4,965 -- --
Depreciation, depletion and amortization......... 131,408 79,325 65,278 57,796 53,321
Impairment....................................... 52,522 75,198 -- 15,694 5,300
Interest......................................... 40,849 28,737 26,822 21,736 16,856
------------ ------------ ---------- ---------- ----------
Total expenses................................. 351,588 260,240 158,005 147,209 124,499
------------ ------------ ---------- ---------- ----------
Income (loss) before income taxes and cumulative
effect of accounting change.................... (58,205) (27,323) 31,500 15,739 16,038
Income taxes..................................... (13,924) (11,261) 10,398 4,722 5,292
------------ ------------ ---------- ---------- ----------
Net income (loss) before cumulative effect of
accounting change.............................. (44,281) (16,062) 21,102 11,017 10,746
Cumulative effect of accounting change, net of
tax of $591.................................... 964 -- -- -- --
------------ ------------ ---------- ---------- ----------
Net income (loss)................................ $ (43,317) $ (16,062) $ 21,102 $ 11,017 $ 10,746
------------ ------------ ---------- ---------- ----------
------------ ------------ ---------- ---------- ----------
Net income (loss) before cumulative effect of
accounting change per share.................... $ (1.10) $ (.53) $ .76 $ .40 $ .39
Cumulative effect of accounting change per
share.......................................... .02 -- -- -- --
------------ ------------ ---------- ---------- ----------
Net income (loss) per share--basic and diluted... $ (1.08) $ (.53) $ .76 $ .40 $ .39
------------ ------------ ---------- ---------- ----------
------------ ------------ ---------- ---------- ----------
Weighted average diluted common shares........... 40,107 30,233 27,810 27,804 27,800
</TABLE>
26
<PAGE>
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
1998(2) 1997(3) 1996 1995 1994
------------ ------------ ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
STATEMENT OF CASH FLOWS DATA:
Net cash provided by operating activities........ $ 147,438 $ 129,846 $ 101,761 $ 89,515 $ 80,894
Net cash used in investing activities............ 215,274 216,603 150,857 171,540 102,969
Net cash provided by financing activities........ 64,837 84,546 55,261 80,629 13,701
EBITDAX(1)....................................... 183,771 164,893 128,565 111,572 94,040
<CAPTION>
AS OF DECEMBER 31,
--------------------------------------------------------------
1998(2) 1997(3) 1996 1995 1994
------------ ------------ ---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Oil and gas properties, net...................... $ 1,064,206 $ 1,077,091 $ 652,257 $ 584,900 $ 483,214
Total assets..................................... 1,283,808 1,210,954 733,613 634,937 528,261
Long-term debt, including current portion........ 596,844 563,344 343,907 314,760 215,010
Stockholders' equity............................. 519,461 469,204 263,693 242,581 224,564
</TABLE>
- ------------------------
(1) See "Item 1--Business--Certain Definitions."
(2) Restated. See Note 2 of the Notes to Consolidated Financial Statements
appearing elsewhere herein.
(3) In October 1997, the Company closed the American Acquisition. See "Item
7--Management's Discussion and Analysis of Financial Condition and Results
of Operations--Results of Operations-- Fiscal Year 1998 Compared to Fiscal
Year 1997" and "-- Fiscal Year 1997 Compared to Fiscal Year 1996."
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
GENERAL. The Company's business strategy is to generate strong and
consistent growth in reserves, production, operating cash flows and earnings
through a balanced program of exploration and development drilling and strategic
acquisitions of oil and gas properties. Over the five-year period ended December
31, 1998, this strategy has resulted in a 114% increase in proved reserves to
1.3 Tcfe, a 182% increase in oil and gas production to 122 Bcfe, and 180% growth
in cash flows from operating activities to $147.4 million. Earnings for the year
ended December 31, 1998 were adversely affected by a significant downturn in oil
and gas prices, resulting in a net loss of $43.3 million.
The majority of the Company's growth has been the result of proved reserve
acquisitions geographically concentrated in its Core Areas where the Company has
significant expertise and where the Company benefits from operational synergies.
During the five-year period ended December 31, 1998, the Company made proved
reserve acquisitions aggregating 563 Bcfe, purchased for a total consideration
of $544.5 million, or $.97 per Mcfe. Of particular significance was the American
Acquisition which closed October 1997.
The Company's drilling program has played an increasingly important role in
its growth strategy. During the five-year period ended December 31, 1998, the
Company drilled 1,439 gross (914 net wells), with an overall drilling success
rate of 93%, adding 610 Bcfe of reserves (including revisions of previous
estimates) to its proved reserve base. The year ended December 31, 1998 marked
the fifth consecutive year that the Company replaced its production through its
drilling activities with 1998 representing the most successful year to date.
Through its 1998 drilling program, the Company added 258 Bcfe of proved reserves
at an all-in finding and development cost (total costs incurred to explore and
develop oil and gas properties divided by proved reserves added through
extensions and discoveries and revisions of previous estimates) of $.86 per
Mcfe. These additions represent 212% production replacement for 1998. The
Company has
27
<PAGE>
increasingly emphasized exploration as an integral component of its business
strategy and in connection therewith, has incurred substantial up-front costs,
including significant acreage positions, seismic costs and other geological and
geophysical costs. During 1998, the Company invested $83 million in connection
with exploration activities, resulting in the acquisition of $23 million of
acreage and seismic information, and the drilling of 27 exploratory wells, of
which 14 were completed as producers.
As of December 31, 1998, the Company's portfolio of Fixed-Price Contracts
are economic hedges of 244 Bcfe of future production at escalating fixed prices,
representing 18% of its estimated proved reserves. These fixed prices are
presently significantly higher than the forward market prices for natural gas
and oil. Over the past few years, competition in Fixed-Price Contracts has
increased, opportunities for attractive Fixed-Price Contracts have diminished
and year-to-year price escalations in the forward market are considerably lower.
In response to these changes, a progressively smaller share of the Company's
production and reserve growth has been hedged due to Management's belief that
longer-term demand and supply fundamentals for natural gas imply the potential
for prices in excess of those currently available in the long-term forward
market. More recent hedging activity has been for shorter periods of time,
generally less than 12 months, when market conditions have been viewed as
favorable. The Company may decide to hedge a greater or smaller share of
production in the future depending upon market conditions, capital investment
considerations and other factors. See "Item 7A--Quantitative and Qualitative
Disclosures About Market Risk--Fixed-Price Contracts" and Note 2 of the Notes to
Consolidated Financial Statements appearing elsewhere herein.
SELECTED OPERATING DATA. The following table provides certain data relating
to the Company's operations.
SELECTED OPERATING DATA
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
OIL AND GAS SALES (M$):
Oil sales:
Wellhead........................................... $ 42,604 $ 40,680 $ 39,372 $ 28,973 $ 29,207
Effect of Fixed-Price Contracts settlements(1)..... 2,159 803 (3,198) 1,077 5,064
---------- ---------- ---------- ---------- ----------
Total.............................................. $ 44,763 $ 41,483 $ 36,174 $ 30,050 $ 34,271
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Natural gas sales:
Wellhead........................................... $ 205,822 $ 185,623 $ 148,244 $ 110,073 $ 95,353
Effect of Fixed-Price Contracts settlements(1)..... 20,990 (5,090) 1,140 23,243 8,960
---------- ---------- ---------- ---------- ----------
Total.............................................. $ 226,812 $ 180,533 $ 149,384 $ 133,316 $ 104,313
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
PRODUCTION:
Oil production (MBbls)............................... 3,430 2,088 1,849 1,695 1,873
Natural gas production (MMcf)........................ 101,066 71,731 63,910 51,264 43,082
Equivalent production (MMcfe)........................ 121,647 84,262 75,004 61,434 54,321
Oil production hedged by Fixed-Price Contracts
(MBbls)............................................ 539 686 1,241 1,464 1,698
Gas production hedged by Fixed-Price Contracts
(BBtu)............................................. 50,823 43,185 32,508 31,579 32,308
</TABLE>
28
<PAGE>
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
AVERAGE SALES PRICE:
Oil price (per Bbl):
Wellhead price..................................... $ 12.42 $ 19.48 $ 21.29 $ 17.09 $ 15.59
Effect of Fixed-Price Contracts settlements(1)..... .63 .38 (1.73) .64 2.71
---------- ---------- ---------- ---------- ----------
Total.............................................. $ 13.05 $ 19.86 $ 19.56 $ 17.73 $ 18.30
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Average fixed price provided by Fixed-Price
Contracts........................................ $ 17.37 $ 21.81 $ 19.53 $ 19.12 $ 20.15
Net effective cash realization(2).................. 90% 96% 96% 93% 92%
Natural gas price (per Mcf):
Wellhead price..................................... $ 2.03 $ 2.59 $ 2.32 $ 2.15 $ 2.21
Effect of Fixed-Price Contracts settlements(1)..... .21 (.07) .02 .45 .21
---------- ---------- ---------- ---------- ----------
Total.............................................. $ 2.24 $ 2.52 $ 2.34 $ 2.60 $ 2.42
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Average fixed price provided by Fixed-Price
Contracts........................................ $ 2.60 $ 2.51 $ 2.43 $ 2.40 $ 2.31
Net effective cash realization(2).................. 94% 99% 97% 97% 89%
Natural gas equivalent price (per Mcfe)............ $ 2.23 $ 2.63 $ 2.47 $ 2.66 $ 2.55
EXPENSES AND COSTS INCURRED (PER MCFE):
Lease operating expenses............................. $ .44 $ .45 $ .47 $ .47 $ .51
Production taxes..................................... .11 .14 .12 .11 .11
General and administrative........................... .21 .22 .22 .27 .28
Depreciation, depletion and amortization--oil and gas
properties(3)...................................... 1.04 .88 .82 .88 .92
Finding Cost(4)...................................... .85 1.81 .71 .70 .92
</TABLE>
- ------------------------
(1) "Effect of Fixed-Price Contracts settlements" represents the hedging results
from the Company's Fixed-Price Contracts. See "Item 7A--Quantitative and
Qualitative Disclosures About Market Risk-- Fixed-Price Contracts." These
amounts do not include any change in derivative fair value reported in
results of operations for 1998.
(2) Represents the net effective cash price realized for the Company's hedged
production as a percentage of the fixed prices in the Company's Fixed-Price
Contracts. See "Item 7A--Quantitative and Qualitative Disclosures About
Market Risk--Fixed-Price Contracts--Market Risk."
(3) Does not include impairments. See "--Results of Operations--Fiscal Year 1998
Compared to Fiscal Year 1997" and "--Results of Operations--Fiscal Year 1997
Compared to Fiscal Year 1996."
(4) See "Item 1--Business--Certain Definitions." Amounts for 1997 include the
allocated purchase price of the American Acquisition.
The following table presents certain information regarding the Company's
proved oil and gas reserves.
29
<PAGE>
OIL AND GAS RESERVES
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------------------------------------------
1998 1997 1996 1995 1994
------------ ------------ --------- --------- ---------
<S> <C> <C> <C> <C> <C>
(DOLLARS IN MILLIONS)
ESTIMATED NET PROVED RESERVES:
Natural gas (MMcf)................................. 1,193,666 1,028,752 849,199 753,919 574,025
Oil (MBbls)........................................ 24,416 29,109 23,497 20,360 19,317
Total (MMcfe)...................................... 1,340,161 1,203,405 990,179 876,076 689,924
Reserve Replacement Ratio(1)....................... 219% 396% 254% 430% 219%
Reserve Life (in years)(1)(2)...................... 11.0 10.7 13.2 14.3 12.7
Estimated Future Net Revenues including Fixed-Price
Contracts(1)(3).................................. $ 1,955.6 $ 2,169.9 $ 2,417.4 $ 1,531.5 $ 1,219.8
Estimated Future Net Revenues excluding Fixed-Price
Contracts(1)(3).................................. $ 1,676.8 $ 1,926.0 $ 2,643.8 $ 1,092.4 $ 683.4
Present Value including Fixed-Price
Contracts(1)(3).................................. $ 978.9 $ 1,136.0 $ 1,117.7 $ 737.5 $ 616.0
Present Value excluding Fixed-Price
Contracts(1)(3).................................. $ 811.1 $ 1,002.6 $ 1,303.7 $ 524.4 $ 358.8
</TABLE>
- ------------------------
(1) See "Item 1--Business--Certain Definitions."
(2) For 1997, pro forma production for the American Acquisition of 113.0 Bcfe
was used in the reserve life determination.
(3) Estimated Future Net Revenues and the Present Value give no effect to
federal or state income taxes attributable to estimated future net revenues.
See "Item 2--Properties--Reserves."
RESULTS OF OPERATIONS--FISCAL YEAR 1998 COMPARED TO FISCAL YEAR 1997
NET INCOME (LOSS) AND CASH FLOWS FROM OPERATING ACTIVITIES. The Company
reported a net loss of $43.3 million, or $1.08 per share, on total revenue of
$293.4 million for 1998. This compares to a net loss of $16.1 million, or $.53
per share, on total revenue of $232.9 million for 1997. The significant downturn
in oil and gas prices during 1998 was the principal contributor to the decline
in earnings between the two periods. Cash flows from operating activities
(before working capital changes) for the year ended December 31, 1998 grew 14%
to $144.9 million compared to $127.1 million for 1997. Cash flows provided by
operating activities after consideration for the change in working capital was
$147.4 million, which compares to $129.8 million for 1997. Significant
production growth was the principal driver behind the increase in operating cash
flows for 1998, more than offsetting the effects of lower oil and gas prices.
Earnings for both years were adversely affected by non-cash impairment charges.
For 1998, the Company recognized impairment charges totaling $52.5 million
($34.1 million after tax or $.85 per share), resulting primarily from
significantly lower oil and gas prices. In 1997, a $75.2 million ($47.1 million
after tax, or $1.56 per share) impairment charge was recorded in connection with
the acquisition of American Exploration Company. See "--Change in Derivative
Fair Value."
PRODUCTION. Total production for the year ended December 31, 1998 grew 44%,
to 121.6 Bcfe, compared to 84.3 Bcfe produced during 1997. Natural gas
production for 1998 was 101.1 Bcf, a 41% increase over the 71.7 Bcf produced in
1997. Oil production in 1998 increased 64% to 3.4 MMBbls compared to 2.1 MMBbls
produced in 1997. These increases are primarily attributable to the American
Acquisition and the results of the Company's exploration and development
drilling activities.
OIL AND GAS PRICES. On a natural gas equivalent basis, the Company realized
an average price of $2.23 per Mcfe for 1998, a 15% decrease compared to the
$2.63 per Mcfe received in 1997. The Company's
30
<PAGE>
1998 gas production yielded an average price of $2.24 per Mcf, an 11% decrease
compared to 1997's average price of $2.52 per Mcf. The Company's average gas
price for 1998 was enhanced $.21 per Mcf as a result of the Company's hedging
activities. The average gas price for 1997 decreased $.07 per Mcf as a result of
Fixed-Price Contracts in effect for that period. The average oil price received
during 1998 decreased 34% to $13.05 per Bbl compared to $19.86 per Bbl for 1997.
Fixed-Price Contract settlements increased the average oil price in 1998 by $.63
per Bbl and increased the average oil price in 1997 by $.38 per Bbl.
The combination of higher gas production and lower average price for 1998
increased gas sales by 26% to $226.8 million compared to $180.5 million reported
for 1997. The combined effect of lower oil prices and higher oil production was
an 8% increase in oil sales to $44.8 million compared to $41.5 million for the
prior-year period. The aggregate impact of Fixed-Price Contract settlements
during each period was an increase in oil and gas revenues of $23.1 million in
1998 and a decrease in oil and gas revenues of $4.3 million 1997. See "Item
7A--Quantitative and Qualitative Disclosures About Market Risk--Fixed-Price
Contracts."
CHANGE IN DERIVATIVE FAIR VALUE. Pursuant to the provisions of SFAS 133,
all hedging designations and the methodology for determining hedge
ineffectiveness must be documented at the inception of the hedge, and upon the
initial adoption of the standard, hedging relationships must be designated anew.
The documentation must also indicate the risk management intent for entering
into the hedging arrangement. The Company believed that it complied with the
spirit and intent of the provisions of the standard with respect to
documentation. However, in connection with a review of the Company's public
filings by the Staff of the Securities and Exchange Commission in September
1999, the Company's documentation was found to be insufficient as of the October
1, 1998 date of adoption of SFAS 133. Therefore, the Company is precluded from
being able to utilize the special provisions of hedge accounting for the fourth
quarter of 1998, and the period from January 1, 1999 to January 13, 1999, the
date the Company's documentation was sufficient in relation to the formal
documentation requirements of the standard. As a result, the changes in the fair
value of all of the Company's derivatives during the fourth quarter were
required to be reported in results of operations, rather than in other
comprehensive income. The accompanying fincancial statements as of December 31,
1998, and for the year then ended, have been restated to reflect this change in
accounting. The effect of the restatement was to increase reported results of
operations by $15.0 million ($9.3 million after tax, or $.23 per share) for the
year ended December 31, 1998.
OTHER INCOME (LOSS). The Company realized other income for 1998 of $4.5
million compared to $10.9 million for 1997. The 1997 amount includes a net gain
of $8.5 million realized upon the sale of a non-core waterflood property.
OPERATING COSTS. Operating costs for 1998 were comprised of $53.2 million
of lease operating expenses and $13.1 million of production taxes. This compares
to $37.7 million of lease operating expenses and $11.5 million of production
taxes for 1997. This increase is principally attributable to producing
properties acquired and wells drilled during 1998 and 1997. On a natural gas
equivalent unit of production basis, lease operating expenses improved to $.44
per Mcfe compared to $.45 for 1997.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense
("G&A") for 1998 was $26.0 million compared to $18.9 million for 1997. This
increase is primarily attributable to increases in personnel and related costs
as the result of the American Acquisition. G&A per natural gas equivalent unit
of production improved to $.21 per Mcfe for 1998 compared to $.22 per Mcfe for
1997.
EXPLORATION COSTS. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs, were
$34.5 million for the year ended December 31, 1998 compared to $9.0 million for
the year ended December 31, 1997. This increase is consistent with the increase
in exploration activity conducted by the Company during 1998 compared to 1997.
The 1998 amount consisted of $12.8 million of seismic acquisition and other
geological and geophysical costs, $16.5 million of dry hole
31
<PAGE>
costs and $5.2 million of leasehold impairment. The 1997 amount consisted of
$2.5 million of seismic acquisition and other geological and geophysical costs,
$5.0 million of dry hole costs and $1.5 million of leasehold impairment.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense ("DD&A") for the year ended December 31, 1998 was $131.4
million compared to $79.3 million for 1997. This increase is due primarily to
higher production levels and an increase in the oil and gas DD&A rate for 1998.
The oil and gas DD&A rate per equivalent unit of production was $1.04 per Mcfe
for 1998 compared to $.88 per Mcfe in 1997. This increase was due primarily to
the American Acquisition purchase price allocated to proved reserves. The DD&A
rate for the fourth quarter of 1998 improved to $.94 per Mcfe primarily as a
result of 1998 reserve additions included in the Company's year-end reserve
report added at a Finding Cost of $.85 per Mcfe. Such rate improvement was
realized without consideration for the effect of the impairment charge recorded
in the fourth quarter of 1998.
IMPAIRMENT. The Company recorded total impairment charges of $52.5 million
during 1998. As a result of a significant decline in oil and gas prices in the
fourth quarter of 1998, the Company performed a review for possible impairment
in which $42.7 million of impairments were recognized. Of this total, $38.7
million related to certain oil properties which were adversely affected by the
decline in crude oil prices. For purposes of determining whether its oil and gas
properties have been impaired, the Company utilizes forward market price
quotations as of the date of determination in estimating the future cash flows
from its oil and gas properties. This forward market price information is
consistent with that generally used by the Company in making drilling and
acquisition plans and decisions. In the impairment calculation, these market
prices for future periods are used to price the estimated production from proved
reserves for the corresponding periods in arriving at future cash flows. The
weighted average forward market crude oil price as of December 31, 1998 used in
the impairment calculation was approximately $18 per Bbl, which equates to an
average field price of approximately $16 per Bbl. The impairment calculation was
based on proved reserves, as probable and possible reserves attributable to the
properties impaired were insignificant. No changes in production from the
profile included in its year-end reserve report were assumed. The majority of
the recorded impairment was recognized for properties in the Company's Permian
and Gulf Coast Regions, which were impacted by crude oil price declines due in
part to their relatively short production lives and higher annual production
declines. Certain other of the Company's oil properties in these regions either
have a high carrying value in relation to their estimated future net revenues or
relatively high operating costs which could result in future impairments in the
event of further price declines or changes in the estimated quantities of proved
reserves.
In 1997, the Company recognized a $75.2 million impairment charge,
substantially all of which was associated with the allocation of the American
Acquisition purchase price to the oil and gas properties acquired. The purchase
price, as determined under purchase accounting rules, exceeded the estimated
fair value of the tangible assets of American. Factors which contributed to the
Company's decision to acquire American, in addition to the value of its oil and
gas properties, include (1) an accelerated diversification into exploration
activity, (2) the expected improvement in certain financial measures on a per
share basis, (3) the expected improvement in stock liquidity and (4) the
expected improvements in total market capitalization, among other reasons. See
Note 1 and Note 4 of the Notes to the Consolidated Financial Statements
appearing elsewhere herein.
INTEREST EXPENSE. Interest expense for 1998 was $40.8 million compared to
$28.7 million for 1997. This increase is primarily attributable to higher
average long-term debt balances outstanding during 1998 as the result of the
American Acquisition. The net impact of interest rate swap settlements for the
years ended December 31, 1998 and 1997 was to increase interest expense by $.3
million and $.2 million, respectively. See "--Capital Resources and Liquidity."
INCOME TAXES. For 1998, the Company recorded a tax benefit of $13.9 million
on a pretax loss of $58.2 million, an effective rate of 24%. This compares to a
tax benefit of $11.3 million, or 41%, on pretax
32
<PAGE>
loss of $27.3 million for 1997. The effective rates for both 1998 and 1997
varied from the statutory rate due to the availability of Section 29 credits. In
addition, the effective tax rate for 1998 includes the effect of an adjustment
to the net operating loss carryforward valuation allowance and permanent
differences related to the tax basis of certain acquired oil and gas properties.
CUMULATIVE EFFECT OF ACCOUNTING CHANGE. In the fourth quarter, the Company
adopted the provisions of SFAS 133 which establishes new accounting and
reporting guidelines for derivative instruments and hedging activities. This
caption includes the cumulative adjustments to results of operations related to
adopting this standard of $1.6 million, shown net of tax of $.6 million. See
Note 1 of the Notes to Consolidated Financial Statements appearing elsewhere
herein.
RESULTS OF OPERATIONS--FISCAL YEAR 1997 COMPARED TO FISCAL YEAR 1996
NET INCOME (LOSS) AND CASH FLOWS FROM OPERATING ACTIVITIES. For the year
ended December 31, 1997, the Company reported a net loss of $16.1 million, or
$.53 per share, on total revenue of $232.9 million for 1997. This compares with
net income of $21.1 million, or $.76 per share, on total revenue of $189.5
million for 1996. Results of operations for 1997 were adversely affected by the
recognition of a $75.2 million non-cash impairment charge ($47.1 million after
tax), recorded in connection with the American Acquisition. The Company reported
record cash flows from operating activities (before working capital changes) for
the year ended December 31, 1997 of $127.1 million, which compares to $101.0
million for 1996, an increase of 26%. Cash flows provided by operating
activities after consideration for the change in working capital was $129.8
million, which compares to $101.8 million for 1996. The 1997 increase in
revenues and operating cash flows was achieved primarily through growth in oil
and gas production and higher oil and gas prices.
PRODUCTION. Total production for the year ended December 31, 1997 grew 12%,
to 84.3 Bcfe, compared to 75.0 Bcfe produced during 1996. Natural gas production
for 1997 was 71.7 Bcf, a 12% increase over the 63.9 Bcf produced in 1996. Oil
production in 1997 increased 13% to 2.1 MMBbls compared to 1.8 MMBbls produced
in 1996. These increases are primarily attributable to the American Acquisition
and the results of the Company's exploration and development drilling
activities.
OIL AND GAS PRICES. On a natural gas equivalent basis, the Company realized
an average price of $2.63 per Mcfe for 1997, a 6% increase compared to the $2.47
per Mcfe received in 1996. The Company's 1997 gas production yielded an average
price of $2.52 per Mcf, an 8% increase compared to 1996's average price of $2.34
per Mcf. The Company's average gas price for 1997 decreased $.07 per Mcf as a
result of the Company's hedging activities. The average gas price for 1996 was
enhanced $.02 per Mcf as a result of Fixed-Price Contracts in effect for that
period. The average oil price received during 1997 improved 2% to $19.86 per Bbl
compared to $19.56 per Bbl for 1996. Fixed-Price Contracts increased the average
oil price in 1997 by $.38 per Bbl and decreased the average oil price in 1996 by
$1.73 per Bbl.
The combination of higher gas production and higher average price for 1997
increased gas sales by 21% to $180.5 million compared to $149.4 million reported
for 1996. The effect of higher oil prices and higher oil production was to
increase oil sales by 15% to $41.5 million compared to $36.2 million for the
prior-year period. The aggregate impact of the Fixed-Price Contracts hedging the
Company's oil and gas production was to decrease oil and gas revenues by $4.3
million and $2.1 million in 1997 and 1996, respectively. See "Item
7A--Quantitative and Qualitative Disclosures About Market Risk--Fixed-Price
Contracts."
OTHER INCOME (LOSS). The Company realized other income for 1997 of $10.9
million compared to $3.9 million for 1996. The 1997 amount includes a net gain
of $8.5 million realized upon the sale of a non-core waterflood property. The
1996 amount includes $1.7 million of proceeds pursuant to the settlement of a
legal claim.
33
<PAGE>
OPERATING COSTS. Operating costs for 1997 were comprised of $37.7 million
of lease operating expenses and $11.5 million of production taxes. This compares
to $35.0 million of lease operating expenses and $9.6 million of production
taxes for 1996. This increase is principally attributable to producing
properties acquired and wells drilled during 1997 and 1996 and to higher
production taxes associated with the 1997 increase in oil and gas revenue. On a
natural gas equivalent unit of production basis, lease operating expenses
improved to $.45 per Mcfe compared to $.47 for 1996, due in part to the sale of
a high-cost, non-core waterflood property.
GENERAL AND ADMINISTRATIVE EXPENSE. G&A for 1997 was $18.9 million compared
to $16.3 million for 1996. This increase is primarily attributable to increases
in personnel and related costs as the result of the American Acquisition. G&A
per natural gas equivalent unit of production was $.22 per Mcfe for both 1997
and 1996.
EXPLORATION COSTS. Exploration costs, comprised of geological and
geophysical costs, exploratory dry holes and leasehold impairment costs, were
$9.0 million for the year ended December 31, 1997 compared to $5.0 million for
the year ended December 31, 1996. This increase is consistent with the increase
in exploration activity conducted by the Company during 1997 compared to 1996.
The 1997 amount consists of $2.5 million of seismic acquisition and other
geological and geophysical costs, $5.0 million of dry hole costs and $1.5
million of leasehold impairment. The 1996 amount consists of $2.5 million of
seismic acquisition costs, $1.9 million of dry hole costs and $.6 million of
leasehold impairment.
34
<PAGE>
DEPRECIATION, DEPLETION AND AMORTIZATION. DD&A for the year ended December
31, 1997 was $79.3 million compared to $65.3 million for 1996. This increase is
due primarily to higher production levels and an increase in the oil and gas
DD&A rate for 1997. The oil and gas DD&A rate per equivalent unit of production
was $.88 per Mcfe for 1997 compared to $.82 per Mcfe in 1996. This increase was
due primarily to the American Acquisition purchase price allocated to proved
reserves.
IMPAIRMENT. In the fourth quarter of 1997, the Company recognized a $75.2
million impairment charge, substantially all of which was recognized in
connection with the allocation of the American Acquisition purchase price to the
oil and gas properties acquired. The purchase price, as determined under
purchase accounting rules, exceeded the estimated fair value of the tangible
assets of American. Factors which contributed to the Company's decision to
acquire American, in addition to the value of its oil and gas properties,
include (1) an accelerated diversification into exploration activity, (2) the
expected improvement in certain financial measures on a per share basis, (3) the
expected improvement in stock liquidity and (4) the expected improvement in
total market capitalization, among other reasons. See Note 1 and Note 4 of the
Notes to the Consolidated Financial Statements appearing elsewhere herein. No
impairment was recognized for the year ended December 31, 1996.
INTEREST EXPENSE. Interest expense for 1997 was $28.7 million compared to
$26.8 million for 1996. This increase is primarily attributable to higher
average long-term debt balances outstanding during 1997 as the result of the
American Acquisition. The net impact of interest rate swaps in effect during the
years ended December 31, 1997 and 1996 was to increase interest expense by $.2
million and $.9 million, respectively. See "--Capital Resources and Liquidity."
INCOME TAXES. For 1997, the Company recorded a tax benefit of $11.3 million
on a pretax loss of $27.3 million, an effective rate of 41%. This compares to a
tax provision of $10.4 million, or 33%, on pretax income of $31.5 million for
1996. The effective rates for both 1997 and 1996 varied from the statutory rate
due to the availability of Section 29 credits.
CAPITAL RESOURCES AND LIQUIDITY
CASH FLOWS. The Company's business of acquiring, exploring and developing
oil and gas properties is capital intensive. The Company's ability to grow its
reserve base is contingent, in part, upon its ability to generate cash flows
from operating activities and to access outside sources of capital to fund its
investing activities. For the three years ended December 31, 1998, 1997 and
1996, the Company's cash flows from investing activities included investments of
$226.9 million, $235.8 million and $134.2 million, respectively, in oil and gas
property acquisition, exploration and development activities and currently
anticipates spending approximately $170 million in exploration and development
activities in 1999. Such investments comprised substantially all of the total
cash flow invested by the Company during the three-year period. The expenditure
amounts for 1997 do not include non-cash acquisition costs aggregating an
additional $366.8 million which were funded primarily through the issuance of
Common Stock, Preferred Stock, warrants and options, and the assumption of debt.
Variations in capital expenditure levels over the three-year period are
primarily tied to the amount of proved property acquisitions made in each year.
See "--Commitments and Capital Expenditures." Certain of these investments
include expenditures which under successful efforts accounting are expensed as
incurred or if unsuccessful in discovering new reserves. Investing activities
for the years ended December 31, 1998, 1997 and 1996, include $30.5 million,
$6.7 million and $4.4 million, respectively, of costs which have been expensed
as exploration costs in the statement of operations for the corresponding
periods. For the three-year period, cash flows from operating activities were
$147.4 million, $129.8 million and $101.8 million, representing 65%, 55% and
76%, respectively, of the oil and gas property investments made for cash in each
year. Substantially all of the cash flows from operating activities are
generated from oil and gas sales which are highly dependent upon oil and gas
prices. Significant decreases in the market prices of oil or gas could result in
reductions of cash flows from operating activities, which in turn could impact
the amount of capital investment. A
35
<PAGE>
portion of this price risk and cash flow volatility has been hedged by
Fixed-Price Contracts. See "Item 7A--Quantitative and Qualitative Disclosures
About Market Risk--Fixed-Price Contracts." The growth achieved in cash flows
from operating activities over this period is discussed under "--Results of
Operations--Fiscal Year 1998 Compared to Fiscal Year 1997" and "--Results of
Operations--Fiscal Year 1997 Compared to Fiscal Year 1996."
Cash flows from financing activities were a significant source of funding
for the Company's investing activities over the three-year period ended December
31, 1998. The Company has relied upon availability under various revolving bank
credit facilities and proceeds from the issuance of senior and subordinated
notes to fund its investing activities. For the three years ended December 31,
1998, 1997 and 1996, net amounts borrowed under such facilities were $31.7
million, $95.7 million and $29.0 million, or 14%, 41% and 22%, respectively, of
the cash oil and gas investments made for each year. The Company's debt
facilities are discussed in greater detail below. In addition, the Company
received $40.1 million from the termination of a Fixed-Price Contract in 1998
and $26.2 million from the amendment of certain Fixed-Price Contracts in 1996.
The Company's EBITDAX increased to $183.8 million in 1998 from $164.9
million in 1997 and $128.6 million in 1996. EBITDAX is defined herein as income
(loss) before interest, income taxes, DD&A, impairment, exploration costs and
change in derivative fair value. Increases in EBITDAX have occurred primarily as
a result of increases in the Company's oil and gas sales. The Company believes
that EBITDAX is a financial measure commonly used in the oil and gas industry as
an indicator of a company's ability to service and incur debt. However, EBITDAX
should not be considered in isolation or as a substitute for net income, cash
flows provided by operating activities or other data prepared in accordance with
generally accepted accounting principles, or as a measure of a company's
profitability or liquidity. EBITDAX measures as presented herein may not be
comparable to other similarly titled measures of other companies.
$450 MILLION REVOLVING CREDIT FACILITY. The Company has a revolving credit
facility (the "Credit Facility") with a syndicate of banks which provides up to
$450 million in borrowings (the "Commitment"). Letters of credit under the
Credit Facility are limited to $75 million of such availability. The Credit
Facility allows the Company to draw on the full $450 million credit line without
restrictions tied to periodic revaluations of its oil and gas reserves provided
the Company continues to maintain an investment grade credit rating from either
Standard & Poor's Ratings Service or Moody's Investors Service. A borrowing base
can be required only upon the vote by a majority in interest of the lenders
after the loss of an investment grade credit rating. No principal payments are
required under the Credit Facility prior to maturity on October 14, 2002. The
Company has relied upon the Credit Facility to provide funds for acquisitions
and to provide letters of credit to meet the Company's margin requirements under
Fixed-Price Contracts. See "Item 7A--Quantitative and Qualitative Disclosures
About Market Risk--Fixed-Price Contracts." As of December 31, 1998, the Company
had $295.0 million of principal and $17.8 million of letters of credit
outstanding under the Credit Facility.
The Company has the option of borrowing at a LIBOR-based interest rate or
the Base Rate (approximating the prime rate). The LIBOR interest rate margin and
the facility fee payable under the Credit Facility are subject to a sliding
scale based on the Company's senior debt credit rating. At December 31, 1998,
the applicable interest rate was LIBOR plus 30 basis points. The Credit Facility
also requires the payment of a facility fee equal to 15 basis points of the
Commitment. At December 31, 1998, the effective interest rate for borrowings
under the Credit Facility was 5.9%, including the effect of interest rate swaps.
The Credit Facility contains various affirmative and restrictive covenants
which, among other things, limit total indebtedness to $700 million ($625
million of senior indebtedness) and require the Company to meet certain
financial tests. Borrowings under the Credit Facility are unsecured.
36
<PAGE>
OTHER LINES OF CREDIT. The Company has certain other unsecured lines of
credit available to it, which aggregated $45.0 million as of December 31, 1998.
Such short-term lines of credit are primarily used to meet margin requirements
under Fixed-Price Contracts and for working capital purposes. At December 31,
1998, the Company had $2.2 million of indebtedness and $.1 million of letters of
credit outstanding under these credit lines. Repayment of indebtedness
thereunder is expected to be made through Credit Facility availability.
6 7/8% SENIOR NOTES DUE 2007. In December 1997, the Company issued $200
million principal amount, $198.8 million net of discount, of 6 7/8% Senior Notes
due 2007 (the "Senior Notes"). Interest is payable semi-annually on June 1 and
December 1. The associated indenture agreement contains restrictive covenants
which place limitations on the amount of liens and the Company's ability to
enter into sale and leaseback transactions.
9 1/4% SENIOR SUBORDINATED NOTES DUE 2004. In June 1994, the Company issued
$100 million principal amount, $98.5 million net of discount, of 9 1/4% Senior
Subordinated Notes due 2004 (the "Subordinated Notes"). Interest is payable
semi-annually on June 15 and December 15. The associated indenture agreement
contains restrictive covenants which limit, among other things, the prepayment
of the Subordinated Notes, the incurrence of additional indebtedness, the
payment of dividends and the disposition of assets.
At December 31, 1998, the Company had working capital of $24.6 million and a
current ratio of 1.4 to 1. Total long-term debt outstanding at December 31, 1998
was $596.8 million. The Company's long-term debt as a percentage of its total
capitalization was 53%. The amount of required principal payments for the next
five years and thereafter as of December 31, 1998 are as follows: 1999--$0;
2000--$0; 2001--$0; 2002--$297.2 million; 2003--$0; thereafter--$300 million.
The Company believes that the borrowing capacity under its existing credit
facilities, combined with the Company's internal cash flows, will be adequate to
finance the capital expenditure program budgeted for 1999 and to meet the
Company's margin requirements under its Fixed-Price Contracts. See
"--Commitments and Capital Expenditures" and "Item 7A--Quantitative and
Qualitative Disclosures About Market Risk--Fixed-Price Contracts-- Margin."
See "Item 7A--Quantitative and Qualitative Disclosures About Market
Risk--Interest Rate Sensitivity" for a discussion of the interest rate swaps
hedging the interest rate exposure associated with borrowings under the Credit
Facility. Also see Note 2 of the Notes to Consolidated Financial Statements
appearing elsewhere herein.
COMMITMENTS AND CAPITAL EXPENDITURES
The Company's business strategy is to generate strong and consistent growth
in reserves, production, operating cash flows and earnings through a balanced
program of exploration and development drilling and strategic acquisitions of
oil and gas properties. For the year ended December 31, 1998, the Company
expended $139.5 million on development activities, $82.9 million on exploration
activities and $4.1 million on proved reserve acquisitions in connection with
this strategy. The Company's 1998 drilling program resulted in the drilling of
351 gross (228 net) wells, including 27 gross (18 net) exploratory wells and 324
gross (210 net) development wells. The Company's drilling activities added 258
Bcfe to its proved reserve base. Reserves added through 1998 acquisitions
aggregated 7 Bcfe.
The Company's approved drilling budget for 1999 provides for approximately
$170 million in oil and gas exploration and development activities. Of these
expenditures, approximately $109 million is targeted for development activities
and $61 million is directed to exploration activities to be conducted in its
Core Areas. Actual levels of exploration and development expenditures may vary
due to many factors, including drilling results, new drilling opportunities,
drilling rig availability, oil and natural gas prices and acquisition
opportunities. See "-- Outlook for 1999." The Company continues to actively
search for attractive oil and
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<PAGE>
gas property acquisitions, but is not able to predict the timing or amount of
capital expenditure which may ultimately be employed in acquisitions during
1999.
In the ordinary course of its business, the Company may contract for
drilling or other services for extended periods of time, but generally less than
12 months, or may enter into agreements for oil and gas lease acreage which
require a certain level of drilling activity to maintain its lease position.
Such arrangements are common to the Company's industry.
OUTLOOK FOR FISCAL YEAR 1999
GENERAL. The discussion of the Company's fiscal year 1999 outlook provided
under this caption and other Forward-Looking Statements in this document reflect
the current expectations of Management and are based on the Company's historical
operating trends, its proved reserve and Fixed-Price Contract positions as of
December 31, 1998 and other information currently available to Management. Such
Forward-Looking Statements include among others, statements regarding the
Company's future drilling plans and objectives and related exploration and
development budgets and number and location of planned wells, and statements
regarding the quality of the Company's properties and potential reserve and
production levels. These statements assume, among other things, that no
significant changes will occur in the operating environment for the Company's
oil and gas properties and that there will be no material acquisitions or
divestitures except as disclosed herein. THE COMPANY CAUTIONS THAT THE
FORWARD-LOOKING STATEMENTS ARE SUBJECT TO ALL THE RISKS AND UNCERTAINTIES
INCIDENT TO THE ACQUISITION, EXPLORATION, DEVELOPMENT AND MARKETING OF OIL AND
GAS RESERVES. THESE RISKS INCLUDE, BUT ARE NOT LIMITED TO, COMMODITY PRICE
RISKS, COUNTERPARTY RISKS, ENVIRONMENTAL RISKS, DRILLING RISKS, RESERVES RISKS,
AND OPERATIONS AND PRODUCTION RISKS. CERTAIN OF THESE RISKS ARE DESCRIBED
ELSEWHERE HEREIN. MOREOVER, THE COMPANY MAY MAKE MATERIAL ACQUISITIONS OR
DIVESTITURES, MODIFY ITS FIXED-PRICE CONTRACT POSITION BY ENTERING INTO NEW
CONTRACTS OR TERMINATING EXISTING CONTRACTS, OR ENTER INTO FINANCING
TRANSACTIONS. NONE OF THESE CAN BE PREDICTED WITH CERTAINTY AND, ACCORDINGLY,
ARE NOT TAKEN INTO CONSIDERATION IN THE FORWARD-LOOKING STATEMENTS MADE HEREIN.
STATEMENTS CONCERNING FIXED-PRICE CONTRACT, INTEREST RATE SWAP AND OTHER
FINANCIAL INSTRUMENT FAIR VALUES AND THEIR ESTIMATED CONTRIBUTION TO FUTURE
RESULTS OF OPERATIONS ARE BASED UPON MARKET INFORMATION AS OF A SPECIFIC DATE.
SUCH MARKET INFORMATION IN CERTAIN CASES IS A FUNCTION OF SIGNIFICANT JUDGMENT
AND ESTIMATION. FURTHER, MARKET PRICES FOR OIL AND GAS AND MARKET MONEY RATES
ARE SUBJECT TO SIGNIFICANT VOLATILITY. FOR ALL OF THE FOREGOING REASONS, ACTUAL
RESULTS MAY DIFFER MATERIALLY FROM THE FORWARD-LOOKING STATEMENTS AND THERE IS
NO ASSURANCE THAT THE ASSUMPTIONS USED ARE NECESSARILY THE MOST LIKELY. THE
COMPANY EXPRESSLY DISCLAIMS ANY OBLIGATIONS OR UNDERTAKINGS TO RELEASE PUBLICLY
ANY UPDATES REGARDING ANY CHANGES IN THE COMPANY'S EXPECTATIONS WITH REGARD TO
THE SUBJECT MATTER OF ANY FORWARD-LOOKING STATEMENTS OR ANY CHANGES IN EVENTS,
CONDITIONS OR CIRCUMSTANCES ON WHICH ANY FORWARD-LOOKING STATEMENTS ARE BASED.
PRODUCTION. The Company's drilling budget approved by the Board of
Directors for 1999 is $170 million. Based on this expenditure level, the
inventory of drilling opportunities identified for 1999, internal production
forecasts for developed and undeveloped properties and historical Finding Cost
results, the Company expects continued growth in total oil and gas production
for 1999, although there can be no assurance. The amount of drilling
expenditures actually committed during 1999 is subject to revision. A continued
low price environment for oil and gas may result in lower drilling expenditures
to prevent leverage from increasing. This, in turn, would be expected to result
in less oil and gas production for the year.
OIL AND GAS PRICES. The Company's Fixed-Price Contracts in 1999 are
expected to provide average fixed prices of $2.73 per Mcf for its hedged natural
gas before consideration of basis. Based on February 1999 quotations for
regional natural gas prices for the balance of 1999 and giving effect to the
Company's portfolio of basis swaps, the Company anticipates price realization
percentages comparable to historical averages. See "Item 7A--Quantitative and
Qualitative Disclosures About Market Risk--Fixed-Price Contracts--Market Risk."
As of December 31, 1998, the Company's Fixed-Price Contracts hedge
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<PAGE>
36 Bcf of natural gas production in 1999 and since year-end, the Company has
entered into a number of fixed-price collars for various periods of 1999 which
hedge an additional 14 Bcf of gas production at an average floor price of $1.83
per Mcfe and 31 Bcf at an average ceiling price of $2.09 per Mcfe. In addition,
the Company entered into a 1999 fixed-price swap which hedges 3 Bcf at $1.94. No
plans currently exist to increase or decrease the amount of hedged production
volumes for 1999; however, the Company may decide to hedge a greater or smaller
share of production in the future.
The fair value of the Company's Fixed-Price Contracts will fluctuate due to
changes in market prices for oil and gas changes in basis. All such changes in
fair value will be reflected in results of operations for the period from
January 1, 1999 through January 13, 1999. Thereafter, the fair value changes for
those contracts which qualify as hedges under SFAS 133 will be reflected in
other comprehensive income. See "--Results of Operations--Fiscal 1998 Compared
to Fiscal 1997--Change in Derivative Fair Value."
The Company is unable to predict the market prices that will be received for
its unhedged production in 1999. For 1998, average monthly wellhead prices for
its natural gas ranged from $1.78 per Mcf to $2.26 per Mcf and oil prices varied
from $9.84 per Bbl to $15.24 per Bbl. Because less than 50% of the Company's
estimated 1999 production is hedged by Fixed-Price Contracts, the Company's 1999
oil and gas revenues are highly sensitive to commodity price changes.
OTHER INCOME. The Company presently has no plans to dispose of any
significant oil and gas property. Other sources of miscellaneous income are
expected to be comparable to prior year results. See "Item 3--Legal
Proceedings--Midcon" regarding the potential favorable resolution of a legal
claim.
OPERATING COSTS. On an equivalent unit of production basis, lifting costs
are anticipated to decrease slightly in relation to historical results for 1998
and 1997. This performance is somewhat dependent upon the growth in production
discussed above. Production taxes are expected to be incurred at an average rate
of 5% to 6% of wellhead oil and gas sales.
GENERAL AND ADMINISTRATIVE EXPENSE. Estimated G&A costs for 1999 are
expected to approximate 1998's results in the aggregate.
EXPLORATION COSTS. The Company expects to commit approximately $61 million
of its 1999 capital expenditure budget to exploration drilling, leasehold,
seismic and other geological and geophysical costs. Under the successful efforts
method of accounting, the costs associated with unsuccessful exploration wells
are expensed. All exploratory geological and geophysical costs (budgeted at $7
million for 1999) are expensed as incurred, regardless of ultimate success in
the discovery of new reserves. Remaining exploration costs to be expensed in
1999 will depend on the Company's exploratory drilling results. The amount of
actual exploration expenditures committed during 1999 is subject to revision
based, in part, on changes in expected 1999 operating cash flows and desired
leverage levels. See "Production" above.
DEPRECIATION, DEPLETION AND AMORTIZATION. The Company expects the DD&A rate
for 1999 to reflect improvement in relation to 1998's results. The Company's
fourth quarter rate was $.94 per Mcfe based upon the year-end reserve study.
This rate will show additional improvement as a result of the impairment charge
recorded in the fourth quarter. The Company will be subject to fluctuation in
its DD&A rate as production from certain significant properties varies in
relation to total production.
IMPAIRMENT. Impairment recognition is subject to many factors, including
oil and gas prices, revisions to reserve estimates and the cost of future
reserve additions. Many of these factors are beyond the Company's ability to
control or predict; consequently, the timing and amount of future impairments,
if any, is unknown. Further weakening of oil and gas prices could result in
future impairment recognition.
INTEREST EXPENSE. The Company plans for its capital expenditure levels in
1999 to approximate its operating cash flows for the year. Consequently, average
outstanding indebtedness is expected to remain relatively constant with 1998's
year-end debt balance. Interest expense is anticipated to reflect a modest
39
<PAGE>
increase over the prior year. This estimate makes no assumption with respect to
future material acquisitions, divestitures or financings, changes in capital
expenditures or operating cash flows, or increases in stockholders' equity. See
"--Capital Resources and Liquidity" for interest rate information for the
Company's indebtedness.
INCOME TAXES. The Company expects, based on its estimated tax attributes at
December 31, 1998, that its income tax provision for 1999 will result in an
effective rate approximating statutory rates. However, declines in oil and gas
prices could impact the Company's ability to utilize its net operating loss
carryforwards, which would have an adverse effect on the tax provision for 1999.
The Company anticipates utilization of $10.0 million of net operating loss
carryforwards in 1999.
YEAR 2000 COMPLIANCE
GENERAL. The Company continues to address the business issues surrounding
the ability of computer software and hardware and other business systems to
appropriately consider periods and dates after December 31, 1999, both in its
offices and field locations ("Year 2000 Issue"). Non-compliant information
technology ("IT") systems and non-IT systems could result in system failures or
miscalculations causing disruptions of business operations or a temporary
inability to engage in normal business activities. Both IT and non-IT systems
may contain embedded technology, which complicates the Company's efforts to
identify, assess and remediate the Year 2000 Issue.
The Company has formed a task force to develop and implement a comprehensive
plan to resolve the Year 2000 Issue and to oversee the assessment, remediation,
testing and implementation phases of the plan. The plan encompasses a study of
significant operational exposures that would be reasonably likely to result from
the failure by the Company or significant third parties to be Year 2000
compliant on a timely basis. These exposures include the ability of the Company
to produce its oil and gas reserves, to maintain environmental compliance and to
meet contractual obligations. It also includes the ability of the Company's
purchasers, transporters, outside operators and other customers to buy, take
delivery of, transport and pay for natural gas and crude oil produced. Other
risks relate to continued performance of suppliers, vendors and service
companies that the Company relies upon to conduct its operations, as well as the
financial institutions utilized in connection with the Company's borrowing and
cash management activities. The mandate of the task force includes monitoring
the progress of third parties as deemed appropriate, to the extent information
can be obtained.
STATUS. IT Systems. The Company has completed the assessment phase of all
significant IT systems, including its accounting, land, production and
engineering software and its computer hardware. The remediation phase for the
Company's material systems has been completed. Upgrades of certain PC-based
systems will continue throughout 1999 but non-compliance in these systems does
not represent a material exposure. As of March 12, 1999, the testing phase was
estimated to be 80% complete, and was expected to be fully complete in April
1999. The implementation phase was estimated to be 75% complete as of March 12,
1999, with upgraded significant IT systems expected to be fully operational in
April 1999.
Non-IT Systems. The Company has completed the assessment phase of all
significant non-IT systems, which includes operating equipment with embedded
chips or software. The Company believes that the remediation, testing and
implementation phases are complete. The existence of embedded technology is by
nature more difficult to identify. While the Company believes that all
significant non-IT systems are Year 2000 compliant, the task force will continue
to search for previously unidentified exposures.
Third Parties. The Company estimates that it is 90% complete with the
assessment phase of its exposure to Year 2000 compliance by material third
parties (identified above). The assessment phase is expected to be completed in
May 1999. The responses received to date from third parties have not identified
a material non-compliance issue that would require action by the Company. The
Company will continue to monitor its exposure to material third parties to the
extent information is available. The
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<PAGE>
Company has a limited number of systems which interface directly with third
parties. Such systems, although believed to be compliant, are not significant to
the Company's business operations.
The Company cannot be assured that the various phases of its Year 2000 plan
will successfully identify and mitigate all material exposures to the Year 2000
Issue. See Risk Factors below.
COSTS. The Company has used, and will continue to use, primarily internal
resources to reprogram, or replace, test and implement the software, hardware
and operating equipment for Year 2000 modifications. Because the majority of the
software employed by the Company was purchased from third parties subject to
ongoing maintenance agreements, Year 2000 upgrades did not result in significant
cash outlays. Total costs incurred to date in connection with Year 2000
compliance has been immaterial. The estimated cost attributable to remaining
compliance issues in the aggregate is expected to be less than $250,000
including hardware, software, internal and external labor costs, which will be
funded through operating cash flows.
RISK FACTORS. Management believes it has an effective program in place to
resolve the Year 2000 Issue in a timely manner and does not expect to incur
significant operational problems due to Year 2000 non-compliance. As noted
above, the Company has not yet completed all necessary phases of its Year 2000
plan. Further, no assurance can be given that all material issues will be
identified, or that all material third parties will be compliant by the year
2000. If all significant Year 2000 issues are not properly and timely
identified, assessed, remediated, tested and implemented, there can be no
assurance that the Company's results of operations will not be materially
affected. Additionally, there can be no assurance that non-compliance by third
parties will not have a material adverse effect on the Company's systems or
results of operations.
The Company has not identified a "worst case scenario" that is reasonably
likely as of this date. Accordingly, the Company currently does not have a
contingency plan in place to address Year 2000 non-compliance. The Company plans
to evaluate the status of its Year 2000 plan in April 1999 and will determine at
that date whether such a plan is necessary.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
GENERAL
The Company's results of operations and operating cash flows are impacted by
changes in market prices for oil and gas and changes in market interest rates.
To mitigate a portion of its exposure to adverse market changes, the Company has
entered into Fixed-Price Contracts and interest rate swaps. All of the Company's
Fixed-Price Contracts and interest rate swaps have been entered into as hedges
of oil and gas price risk or interest rate risk and not for trading purposes.
Information regarding the Company's market exposures, Fixed-Price Contracts,
interest rate swaps and certain other financial instruments is provided below.
All information is presented in U.S. Dollars. See Note 2 of the Notes to
Consolidated Financial Statements appearing elsewhere herein.
FIXED-PRICE CONTRACTS
DESCRIPTION OF CONTRACTS. The Company has entered into Fixed-Price
Contracts to reduce its exposure to unfavorable changes in oil and gas prices
which are subject to significant and often volatile fluctuation. The Company's
Fixed-Price Contracts are comprised of long-term physical delivery contracts,
energy swaps, collars, futures contracts and basis swaps. These contracts allow
the Company to predict with greater certainty the effective oil and gas prices
to be received for its hedged production and benefit the Company when market
prices are less than the fixed prices provided in its Fixed-Price Contracts.
However, the Company will not benefit from market prices that are higher than
the fixed prices in such contracts for its hedged production. For the years
ended December 31, 1998, 1997 and 1996, Fixed-Price Contracts hedged 50%, 60%
and 51%, respectively, of the Company's gas production and 16%, 33% and 67%,
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<PAGE>
respectively, of its oil production. As of December 31, 1998, Fixed-Price
Contracts are in place as economic hedges of 244 Bcf of the Company's estimated
future gas production.
For energy swap sales contracts, the Company receives a fixed price for the
respective commodity and pays a floating market price, as defined in each
contract (generally NYMEX futures prices or a regional spot market index), to
the counterparty. Under energy swap purchase contracts, the Company pays a fixed
price for the commodity and receives a floating market price. In both types of
energy swaps, the fixed-price payment and the floating-price payment are netted,
resulting in a net amount due to or from the counterparty. For physical delivery
contracts, the Company purchases gas in the spot market at floating market
prices and delivers such gas to the contract counterparty at a fixed price. The
Company's natural gas collars contain a fixed floor price (put) and ceiling
price (call). If the market price of natural gas exceeds the call strike price
or falls below the put strike price, then the Company receives the fixed price
and pays the market price. If the market price of natural gas is between the
call and the put strike price, then no payments are due from either party. Under
the Company's basis swaps, the Company receives the floating market price for
NYMEX futures and pays the floating market price plus a fixed differential for a
specified regional spot market index.
The following table summarizes the estimated volumes, fixed prices,
fixed-price sales, fixed-price purchases and future net revenues attributable to
the Company's Fixed-Price Contracts as of December 31, 1998. The Company expects
the prices to be realized for its hedged production to vary from the prices
shown in the following table due to basis, which is the differential between the
floating price paid under each energy swap contract, or the cost of gas to
supply physical delivery contracts, and the price received at the wellhead for
the Company's production. Basis differentials are caused by differences in
location, quality, contract terms, timing and other variables. Future net
revenues for any period are determined as the differential between the fixed
prices provided by Fixed-Price Contracts and forward market prices as of
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December 31, 1998, as adjusted for basis. Future net revenues change with
changes in market prices and basis. See "--Market Risk."
<TABLE>
<CAPTION>
YEARS ENDING DECEMBER 31, BALANCE
----------------------------------------------------- THROUGH
1999 2000 2001 2002 2003 2017 TOTAL
--------- --------- --------- --------- --------- --------- ---------
(DOLLARS IN THOUSANDS, EXCEPT PRICE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
NATURAL GAS SWAPS:
SALES CONTRACTS
Contract volumes (BBtu)........................... 15,825 9,830 7,475 6,405 5,650 17,783 62,968
Weighted-average fixed price per MMBtu(1)......... $ 2.44 $ 2.46 $ 2.47 $ 2.67 $ 2.92 $ 3.29 $ 2.75
Future fixed-price sales.......................... $ 38,629 $ 24,164 $ 18,446 $ 17,098 $ 16,492 $ 58,429 $ 173,258
Future net revenues(2)............................ $ 7,251 $ 2,441 $ 1,792 $ 2,648 $ 3,534 $ 15,576 $ 33,242
PURCHASE CONTRACTS
Contract volumes (BBtu)........................... (10,950) -- -- -- -- -- (10,950)
Weighted-average fixed price per MMBtu(1)......... $ 2.18 $ -- $ -- $ -- $ -- $ -- $ 2.18
Future fixed-price purchases...................... $ (23,880) $ -- $ -- $ -- $ -- $ -- $ (23,880)
Future net revenues(2)............................ $ 939 $ -- $ -- $ -- $ -- $ -- $ 939
NATURAL GAS PHYSICAL DELIVERY CONTRACTS:
Contract volumes (BBtu)........................... 24,144 22,678 23,240 23,115 20,245 71,483 184,905
Weighted-average fixed price per MMBtu(1)......... $ 2.76 $ 2.94 $ 3.06 $ 3.21 $ 3.47 $ 4.32 $ 3.56
Future fixed-price sales.......................... $ 66,682 $ 66,675 $ 71,109 $ 74,150 $ 70,292 $ 308,529 $ 657,437
Future net revenues(2)............................ $ 13,574 $ 14,495 $ 17,246 $ 19,770 $ 21,076 $ 102,688 $ 188,849
NATURAL GAS COLLARS:
Contract volumes (BBtu):
Floor............................................. 7,300 -- -- -- -- -- 7,300
Ceiling........................................... 14,600 -- -- -- -- -- 14,600
Weighted-average fixed-price per MMBtu(1):
Floor............................................. $ 2.41 $ -- $ -- $ -- $ -- $ -- $ 2.41
Ceiling........................................... $ 2.78 $ -- $ -- $ -- $ -- $ -- $ 2.78
Future fixed-price sales.......................... $ 17,599 $ -- $ -- $ -- $ -- $ -- $ 17,599
Future net revenues(2)............................ $ 3,367 $ -- $ -- $ -- $ -- $ -- $ 3,367
TOTAL NATURAL GAS CONTRACTS(3):
Contract volumes (BBtu)........................... 36,319 32,508 30,715 29,520 25,895 89,266 244,223
Weighted-average fixed price per MMBtu(1)......... $ 2.73 $ 2.79 $ 2.92 $ 3.09 $ 3.35 $ 4.11 $ 3.38
Future fixed-price sales.......................... $ 99,030 $ 90,839 $ 89,555 $ 91,248 $ 86,784 $ 366,958 $ 824,414
Future net revenues(2)............................ $ 25,131 $ 16,936 $ 19,038 $ 22,418 $ 24,610 $ 118,264 $ 226,397
</TABLE>
- ------------------------
(1) The Company expects the prices to be realized for its hedged production to
vary from the prices shown due to basis. See "--Market Risk."
(2) Future net revenues as presented above are undiscounted and have not been
adjusted for contract performance risk or counterparty credit risk. See Note
13 of the Notes to Consolidated Financial Statements appearing elsewhere
herein.
(3) Does not include basis swaps with notional volumes by year, as follows:
1999--19.0 TBtu; 2000-- 21.3 TBtu; 2001--9.4 TBtu; and 2002--5.5 TBtu.
The estimates of future net revenues from the Company's Fixed-Price
Contracts are computed based on the difference between the prices provided by
the Fixed-Price Contracts and forward market prices as of the specified date.
The market for natural gas beyond a five year horizon is illiquid and published
market quotations are not available. The Company has relied upon near-term
market quotations, longer-term over-the-counter market quotations and other
market information to determine its future net revenue estimates. Forward market
prices for natural gas are dependent upon supply and demand factors in such
forward market and are subject to significant volatility. The future net revenue
estimates shown above are subject to change as forward market prices change.
43
<PAGE>
The estimated fair value of the Company's Fixed-Price Contracts and the
associated carrying value as of December 31, 1998 are provided below.
<TABLE>
<CAPTION>
ESTIMATED CARRYING
FAIR VALUE VALUE
---------- ----------
(IN THOUSANDS)
<S> <C> <C>
Derivative assets:
Fixed-price natural gas swaps:
Sales contracts....................................................................... $ 26,125 $ 26,125
Purchase contracts.................................................................... 905 905
Fixed-price natural gas collars......................................................... 3,367 3,367
Fixed-price natural gas delivery contracts.............................................. 99,342 99,342
Natural gas basis swaps................................................................. 74 74
Derivative liabilities:
Fixed-price natural gas swaps--sales contracts.......................................... (551) (551)
Fixed-price natural gas delivery contracts.............................................. (2,920) (2,920)
Natural gas basis swaps................................................................. (3,734) (3,734)
---------- ----------
$ 122,608 $ 122,608
---------- ----------
---------- ----------
</TABLE>
The fair value of Fixed-Price Contracts as of December 31, 1998 was
estimated based on market prices of natural gas and crude oil for the periods
covered by the contracts. The net differential between the prices in each
contract and market prices for future periods, as adjusted for estimated basis,
has been applied to the volumes stipulated in each contract to arrive at an
estimated future value. In connection with the adoption of SFAS 133, this
estimated future value was discounted on a contract-by-contract basis at rates
commensurate with the Company's estimation of contract performance risk and
counterparty credit risk. The terms and conditions of the Company's fixed-price
physical delivery contracts and certain financial swaps are uniquely tailored to
the Company's circumstances. In addition, the determination of market prices for
natural gas beyond a five year horizon is subject to significant judgment and
estimation. As a result, the Fixed-Price Contract fair value as reflected in the
balance sheet as of December 31, 1998 does not necessarily represent the value a
third party would pay to assume the Company's positions.
ACCOUNTING. In October 1998, the Company adopted SFAS 133 which establishes
new accounting and reporting guidelines for derivative instruments and hedging
activities. It requires that all derivative instruments be recognized as assets
or liabilities in the statement of financial position, measured at fair value.
The accounting for changes in the fair value of a derivative depends on the
intended use of the derivative and the resulting designation. Designation is
established at the inception of a derivative, but redesignation is permitted.
For derivatives designated as cash flow hedges, changes in fair value are
recognized in other comprehensive income until the hedged item is recognized in
earnings. Hedge effectiveness is to be measured at least quarterly based on the
relative changes in fair value between the derivative contract and the hedged
item over time. Any change in fair value resulting from ineffectiveness, as
defined by SFAS 133, is recognized immediately in earnings. Effective January
13, 1999, substantially all of the Company's Fixed-Price Contracts and interest
rate swaps are designated as cash flow hedges. For the period from October 1,
1998 to January 13, 1999, the change in fair value of all derivative contracts
was recognized in results of operations. See Note 2 of the Notes to Consolidated
Financial Statements appearing elsewhere herein and "Item 7--Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Results of Operations--Fiscal Year 1998 Compared to Fiscal Year
1997-- Change in Derivative Fair Value."
All of the Company's Fixed-Price Contracts have been executed in connection
with its natural gas and crude oil hedging program. For Fixed-Price Contracts
qualifying as hedges pursuant to SFAS 133, the differential between the fixed
price and the floating price for each contract settlement period multiplied by
the associated contract volumes is the contract profit or loss. The realized
contract profit or loss is included in oil and gas sales in the period for which
the underlying commodity was hedged. For those contracts not
44
<PAGE>
qualifying as hedges, the associated fair value, as well as future changes in
market value, are recognized in earnings. The fair value of all of its
Fixed-Price Contracts are recorded as assets or liabilities in the Company's
balance sheet.
If a Fixed-Price Contract which qualified for hedge accounting is liquidated
or sold prior to maturity, the gain or loss at the time of termination remains
in accumulated other comprehensive income to be amortized into oil and gas sales
over the original term of the contract. At December 31, 1998, the Company had
pretax unamortized deferred gains of $61.3 million related to terminated
contracts which were recorded net of deferred tax effects in accumulated other
comprehensive income. Prior to the adoption of SFAS 133, the Company recorded
gains and losses from contract terminations as deferred liabilities and assets,
respectively. At December 31, 1997, the balance of deferred gains from
price-risk management activities was $23.5 million. Prepayments received under
Fixed-Price Contracts with continuing performance obligations are recorded as
deferred revenue and amortized into oil and gas sales over the term of the
underlying contract.
For the years ended December 31, 1998, 1997 and 1996, oil and gas sales
included $23.1 million of net gains, $4.3 million of net losses and $2.1 million
of net losses, respectively, associated with realized gains and losses under its
Fixed-Price Contracts.
CREDIT RISK. Fixed-Price Contract terms generally provide for monthly
settlements and energy swaps provide for a net settlement due to or from the
respective party, as discussed previously. The counterparties to the contracts
are comprised of independent power producers, pipeline marketing affiliates,
financial institutions, a municipality and S.A. Louis Dreyfus et Cie, among
others. In some cases, the Company requires letters of credit or corporate
guarantees to secure the performance obligations of the contract counterparty.
Should a counterparty to a contract default on a contract, there can be no
assurance that the Company would be able to enter into a new contract with a
third party on terms comparable to the original contract. The Company has not
experienced non-performance by any counterparty.
The Company was a party to two Fixed-Price Contracts, both long-term
physical delivery contracts, with independent power producers ("IPPs") which
sold electrical power under firm, fixed-price contracts to Niagara Mohawk
Corporation ("NIMO"), a New York state utility ("NIMO Contracts"). The ability
of these IPPs to perform their obligations to the Company was dependent on the
continued performance by NIMO of its power purchase obligations to the
counterparties. NIMO has taken aggressive regulatory, judicial and contractual
actions in recent years seeking to curtail power purchase obligations, including
its obligations to the NIMO Contract counterparties, and had further stated that
its future financial prospects were dependent on its ability to resolve these
obligations, along with other matters. In July 1997, NIMO entered into a Master
Restructuring Agreement (the "MRA") with 16 IPPs, including the NIMO Contract
counterparties. Subsequently, one of the NIMO Contract counterparties withdrew
from the MRA. The power purchase agreement between NIMO and the other
counterparty was terminated. In connection therewith, the Company agreed to
terminate its fixed-price contract to the counterparty in exchange for $40.1
million, the receipt of which has been recorded in accumulated other
comprehensive income, net of tax effect. The remaining NIMO Contract which
hedges 54 Bcf of natural gas as of December 31, 1998 remains in force and is
reflected in the Company's balance sheet at a fair value of $72 million. The
Company continues to deliver natural gas pursuant to the terms of this contract
which expires in 2007. NIMO has continued to seek relief from its contractual
obligations under this contract in the court system. Although there can be no
assurance, Management does not expect that NIMO will ultimately succeed in these
efforts.
Cancellation or termination of a Fixed-Price contract would subject a
greater portion of the Company's gas production to market prices, which, in a
low price environment, could have an adverse effect on the Company's future
operating results. In addition, the associated carrying value of the contract
would be removed from the Company's balance sheet. Any associated proceeds would
be reflected in accumulated other comprehensive income, net of income tax
effects, and amortized into earnings over the original contract term.
45
<PAGE>
MARKET RISK. The Company's natural gas Fixed-Price Contracts at December
31, 1998 hedge 244 Bcf of proved natural gas reserves at fixed prices,
representing 20% of its estimated proved natural gas reserves. If the Company's
proved natural gas reserves are produced at rates less than anticipated, Fixed-
Price Contract volumes could exceed production volumes. In such case, the
Company would be required to satisfy its contractual commitments for any excess
volumes at market prices in effect for each settlement period, which may be
above the contract price, without a corresponding offset in wellhead revenue.
The Company expects future production volumes to be equal to or greater than the
volumes provided in its contracts.
The differential between the floating price paid under each energy swap
contract, or the cost of gas to supply physical delivery contracts, and the
price received at the wellhead for the Company's production is termed "basis"
and is the result of differences in location, quality, contract terms, timing
and other variables. The effective price realizations which result from the
Company's Fixed-Price Contracts are affected by movements in basis. For the
years ended December 31, 1998, 1997 and 1996, the Company received on an Mcf
basis approximately 6%, 1% and 3% less than the prices specified in its natural
gas Fixed-Price Contracts, respectively, due to basis. For its oil production
hedged by crude oil Fixed-Price Contracts, the Company realized approximately
10%, 4% and 4% less than the specified contract prices for such years,
respectively. Basis movements can result from a number of variables, including
regional supply and demand factors, changes in the Company's portfolio of
Fixed-Price Contracts and the composition of the Company's producing property
base. Basis movements are generally considerably less than the price movements
affecting the underlying commodity, but their effect can be significant. A 1%
move in price realization for hedged natural gas in 1999 represents a $1.0
million change in gas sales. The Company actively manages its exposure to basis
movements and from time to time will enter into contracts designed to reduce
such exposure.
Except for the effect of basis movements, the Company expects that any
changes in Fixed-Price Contract fair value attributable to changes in market
prices for natural gas will be offset by changes in the value of its natural gas
reserves. This change in natural gas reserve value, however, is not reflected in
the Company's balance sheet. Further, changes in future gains and losses to be
realized in oil and gas sales upon future settlements of Fixed-Price Contracts
resulting from changes in market prices for natural gas are expected to be
offset by changes in the price received for the Company's hedged natural gas
production. Because the majority of the Company's future estimated oil and gas
production is unhedged, declining oil and gas prices could have a material
adverse effect on the Company's future results of operations and operating cash
flows.
MARGIN. The Company is required to post margin in the form of bank letters
of credit or treasury bills under certain of its Fixed-Price Contracts. In some
cases, the amount of such margin is fixed; in others, the amount changes as the
market value of the respective contract changes, or if certain financial tests
are not met. For the years ended December 31, 1998, 1997 and 1996, the maximum
aggregate amount of margin posted by the Company was $23.7 million, $28.7
million and $28.4 million, respectively. If natural gas prices were to rise, or
if the Company fails to meet the financial tests contained in certain of its
Fixed-Price Contracts, margin requirements could increase significantly. The
Company believes that it will be able to meet such requirements through the
Credit Facility and such other credit lines that it has or may obtain in the
future. If the Company is unable to meet its margin requirements, a contract
could be terminated and the Company could be required to pay damages to the
counterparty which generally approximate the cost to the counterparty of
replacing the contract. At December 31, 1998, the Company had issued margin in
the form of letters of credit and treasury bills totaling $17.0 million and $1.5
million, respectively. In addition, approximately 29 Bcf of the Company's proved
gas reserves are mortgaged to a Fixed-Price Contract counterparty, securing the
Company's performance under the associated contract.
INTEREST RATE SENSITIVITY
The Company has entered into interest rate swaps to hedge the interest rate
exposure associated with borrowings under the Credit Facility. As of December
31, 1998, the Company had fixed the interest rate on
46
<PAGE>
average notional amounts of $158 million, $125 million, $125 million and $94
million for the years ended December 31, 1999, 2000, 2001 and 2002,
respectively. Under the interest rate swaps, the Company receives the LIBOR
three-month rate (5.1% at December 31, 1998) and pays an average rate of 5.3%,
5.0%, 5.0% and 5.0% for 1999, 2000, 2001 and 2002, respectively. The notional
amounts are less than the maximum amount anticipated to be available under the
Credit Facility in such years.
For each interest rate swap qualifying as a hedge following the adoption of
SFAS 133, the periodic swap settlement (the differential between the fixed rate
and the floating rate multiplied by the notional amount) is recognized in
interest expense, while the remainder of the swap's change in fair value is
recorded in accumulated other comprehensive income. See Note 2 of the Notes to
Consolidated Financial Statements appearing elsewhere herein. Prior to the
adoption of SFAS 133, only the periodic swap settlement is recorded, included in
interest expense in the period for which the interest rate exposure was hedged.
For the years ended December 31, 1998, 1997 and 1996, interest rate swap
settlements increased interest expense by $.3 million, $.2 million and $.9
million, respectively. Following the adoption of SFAS 133, if an interest rate
swap qualifying as a hedge is liquidated or sold prior to maturity, the gain or
loss on the interest rate swap at the time of termination remains in accumulated
other comprehensive income, to be recognized as an adjustment to interest
expense over the original contract term.
As of October 1, 1998, the Company had one interest rate swap with a
notional amount of $25 million, which under SFAS 133 guidelines, was a fair
value hedge for a portion of the Subordinated Notes. As a result, cumulative
effect of an accounting change in the statement of operations for the year ended
December 31, 1998 included a gain of $2.7 million associated with the fair value
of this interest rate swap and a loss of $1.6 million attributable to the change
in fair value of the Subordinated Notes. This interest rate swap was terminated
in the fourth quarter of 1998.
47
<PAGE>
The following table provides information about the Company's interest rate
swaps and certain other financial instruments as of December 31, 1998.
<TABLE>
<CAPTION>
YEARS ENDING DECEMBER 31, BALANCE
--------------------------------------------------------- THROUGH
1999 2000 2001 2002 2003 2017 TOTAL
---------- ---------- ---------- ---------- --------- ---------- ----------
(DOLLARS IN THOUSANDS, EXCEPT PRICE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
EXPECTED MATURITIES OF LONG-TERM
DEBT:
Bank debt........................ $ -- $ -- $ -- $ 297,200 $ -- $ -- $ 297,200
Average interest rate(1)....... 5.4% 5.4% 5.5% 5.5% -- -- 5.4%
Senior Notes..................... $ -- $ -- $ -- $ -- $ -- $ 200,000 $ 200,000
Fixed interest rate............ 6.9% 6.9% 6.9% 6.9% 6.9% 6.9% 6.9%
Subordinated Notes............... $ -- $ -- $ -- $ -- $ -- $ 100,000 $ 100,000
Fixed interest rate............ 9.3% 9.3% 9.3% 9.3% 9.3% 9.3% 9.3%
INTEREST RATE SWAPS:
Average notional amount by
year........................... $ 158,000 $ 125,000 $ 125,000 $ 94,000 $ -- $ -- $ 502,000
Average pay rate--fixed........ 5.3% 5.0% 5.0% 5.0% -- -- 5.1%
Average receive rate--
variable(2).................. 5.1% 5.1% 5.2% 5.2% -- -- 5.1%
</TABLE>
- ------------------------
(1) Based on market quotations for interest rates as of December 31, 1998 plus
the appropriate credit spread for the respective debt instrument. Does not
include commitment fees. See "Item 7-- Management's Discussion and Analysis
of Financial Condition and Results of Operations--Capital Resources and
Liquidity."
(2) Based on market quotations for interest rates as of December 31, 1998.
The estimated fair value of the Company's interest rate swaps and certain
other financial instruments and the associated carrying value as of December 31,
1998 are provided below.
<TABLE>
<CAPTION>
ESTIMATED CARRYING
FAIR VALUE VALUE
----------- -----------
(IN THOUSANDS)
<S> <C> <C>
AS OF DECEMBER 31, 1998:
Bank debt............................................................................... $ (297,200) $ (297,200)
Senior Notes............................................................................ (187,704) (198,912)
Subordinated Notes...................................................................... (102,897) (100,732)
Interest rate swaps..................................................................... 389 389
----------- -----------
Total................................................................................... $ (587,412) $ (596,455)
----------- -----------
----------- -----------
</TABLE>
The Company's bank debt bears interest at rates which move with market
interest rates. Accordingly, the fair value of such debt at December 31, 1998
was estimated to approximate the carrying amount. The fair values of the 6 7/8%
Senior Notes due 2007 and the 9 1/4% Senior Subordinated Notes due 2004 were
determined based on market quotations for such securities. The fair value of the
Company's interest rate swaps was based on market interest rates as of such
date.
The Company expects that changes in realized interest rate swap gains and
losses attributable to future changes in market interest rates will be offset by
changes in the interest payments hedged by such interest rate swaps. The fair
value of such swaps until settlement will be subject to change as market
interest rates change. Increases in market interest rates would have an adverse
effect on the Company's results of operations since the majority of its bank
debt interest rate exposure is unhedged.
48
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements and supplementary data of the Company
are set forth on pages F-1 through F-34 inclusive, found at the end of this
report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required under Item 10 will be contained in the definitive
Proxy Statement of the Company for its 1999 Annual Meeting of Shareholders (the
"Proxy Statement") under the headings "Election of Directors" and "Executive
Compensation and Other Information" and is incorporated herein by reference. The
Proxy Statement will be filed pursuant to Regulation 14A with the Securities and
Exchange Commission not later than 120 days after December 31, 1998.
ITEM 11. EXECUTIVE COMPENSATION
The information required under Item 11 will be contained in the Proxy
Statement under the heading "Executive Compensation and Other Information" and
is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required under Item 12 will be contained in the Proxy
Statement under the heading "Security Ownership of Certain Beneficial Owners and
Management" and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required under Item 13 will be contained in the Proxy
Statement under the headings "Certain Transactions" and "Executive Compensation
and Other Information--Compensation Committee Interlocks and Insider
Participation" and is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements: See Index to Consolidated Financial Statements and
Financial Statement Schedule immediately following the signature page of
this report.
2. Financial Statement Schedule: See Index to Consolidated Financial
Statements and Schedule immediately following the signature page of this
report.
3. Exhibits: The following documents are filed as exhibits to this report,
all of which have been previously filed or incorporated by reference
except as otherwise indicated below.
49
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
- --------- ---------------------------------------------------------------------------------------------------------
<C> <S>
2.1 Agreement and Plan of Reorganization dated as of June 24, 1997, as amended, between Louis Dreyfus Natural
Gas Corp. and American Exploration Company (incorporated herein by reference to Annex A to Louis Dreyfus
Natural Gas Corp.'s Joint Proxy Statement/Prospectus filed with the Securities and Exchange Commission on
September 12, 1997 pursuant to Rule 424(b)(3) relating to Louis Dreyfus Natural Gas Corp.'s Registration
Statement on Form S-4, Registration No. 333-34849).
3.1 Amended and Restated Certificate of Incorporation of the Registrant (incorporated by reference to Exhibit
3.1 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
3.2 Certificate of Merger of the Registrant dated September 9, 1993 (incorporated by reference to Exhibit 3.2
of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
3.3 Amended and Restated Bylaws of the Registrant (incorporated by reference to Exhibit 3.3 of the
Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
3.4 Certificate of Merger of the Registrant dated November 1, 1993 (incorporated by reference to Exhibit 3.4
of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
4.1 Indenture agreement dated as of June 15, 1994 for $100,000,000 of 9 1/4% Senior Subordinated Notes due
2004 between Louis Dreyfus Natural Gas Corp., as Issuer, and Bank of Montreal Trust Company, as Trustee
(incorporated by reference to Exhibit 10.2 of the Registrant's Form 10-Q for the quarter ended September
30, 1994).
4.2 Indenture agreement dated as of December 11, 1997 for $200,000,000 of 6 7/8% Senior Notes due 2007
between Louis Dreyfus Natural Gas Corp. and LaSalle National Bank as Trustee (incorporated by reference
to Exhibit 4.1 of the Registrant's Registration Statement on Form S-4, Registration No. 333-45773).
*10.1 Stock Option Plan of Louis Dreyfus Natural Gas Corp. as amended and restated effective December 1998.
10.2 Form of Indemnification Agreement with directors of the Registrant (incorporated by reference to Exhibit
10.2 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
10.3 Registration Rights Agreement between the Registrant and Louis Dreyfus Natural Gas Holdings Corp.
(incorporated by reference to Exhibit 10.3 of the Registrant's Registration Statement on Form S-1,
Registration No. 33-76828).
10.4 Amendment dated December 22, 1993 to Registration Rights Agreement between the Registrant, Louis Dreyfus
Natural Gas Holdings Corp. and S.A. Louis Dreyfus et Cie (incorporated by reference to Exhibit 10.4 of
the Registrant's Registration Statement on Form S-1, Registration No. 33-76828).
10.5 Services Agreement between the Registrant and Louis Dreyfus Holding Company, Inc. (incorporated by
reference to Exhibit 10.5 of the Registrant's Registration Statement Form S-1, Registration No.
33-76828).
</TABLE>
50
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
- --------- ---------------------------------------------------------------------------------------------------------
<C> <S>
10.6 Credit Agreement dated as of October 14, 1997, among Louis Dreyfus Natural Gas Corp., as Borrower, Bank
of Montreal, as Administrative Agent, Chase Manhattan Bank, as Syndication Agent, NationsBank of Texas,
N.A., as Documentation Agent, and certain other lenders signatory thereto (incorporated by reference to
Exhibit 10.1 of the Registrant's Form 8-K dated October 14, 1997).
10.7 Swap Agreement dated November 1, 1993 between the Registrant and Louis Dreyfus Energy Corp. (incorporated
by reference to Exhibit 10.17 of the Registrant's Registration Statement on Form S-1, Registration No.
33-69102).
10.8 Memorandum of Agreement for a natural gas swap dated September 16, 1994, between Louis Dreyfus Natural
Gas Corp. and Louis Dreyfus Energy Corp. (incorporated by reference to Exhibit 10.3 of the Registrant's
Form 10-Q for the quarter ended September 30, 1994).
10.9 Memorandum of Agreement, effective January 10, 1996, for the cancellation of a natural gas swap between
the Registrant and Louis Dreyfus Energy Corp. (incorporated by reference to Exhibit 10.16 of the
Registrant's Form 10-K for the fiscal year ended December 31, 1995).
*10.10 Amendment to Option Agreement of Simon B. Rich, Jr. (incorporated by reference to Exhibit 10.14 of the
Registrant's Form 10-K for the fiscal year ended December 31, 1996).
*10.11 Form of Amendment to Outstanding Option Agreements of Employees (incorporated by reference to Exhibit
10.15 of the Registrant's Form 10-K for the fiscal year ended December 31, 1996).
*10.12 Form of Amendment to Outstanding Option Agreements of Non-Employee Directors (incorporated by reference
to Exhibit 10.16 of the Registrant's Form 10-K for the fiscal year ended December 31, 1996).
*10.13 Employment Agreement, dated as of June 24, 1997, between Louis Dreyfus Natural Gas Corp. and Mark Andrews
(incorporated by reference to Exhibit 10.3 to Form 8-K dated June 24, 1997, of American Exploration
Company).
*10.14 Form of Change in Control Agreements between Registrant and Messrs. Mark E. Monroe, Jeffrey A. Bonney,
Richard E. Bross, Ronnie K. Irani and Kevin R. White (incorporated by reference to Exhibit 10.1 of the
Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.15 Louis Dreyfus Natural Gas Corp. Deferred Stock Trust Agreement dated April 14, 1998 (incorporated by
reference to Exhibit 10.2 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.16 Deferred Stock Award Agreement dated March 31, 1998 between Registrant and Mark E. Monroe (incorporated
by reference to Exhibit 10.3 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.17 Deferred Stock Award Agreement dated March 31, 1998 between Registrant and Richard E. Bross (incorporated
by reference to Exhibit 10.4 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.18 Deferred Stock Award Agreement dated March 31, 1998 between Registrant and Ronnie K. Irani (incorporated
by reference to Exhibit 10.5 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
</TABLE>
51
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
- --------- ---------------------------------------------------------------------------------------------------------
<C> <S>
*10.19 Deferred Stock Award Agreement dated March 31, 1998 between Registrant and Kevin R. White (incorporated
by reference to Exhibit 10.6 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.20 Louis Dreyfus Natural Gas Corp. Non-employee Director Deferred Stock Trust Agreement dated December 1,
1998.
*10.21 Amendment No. 1 to Louis Dreyfus Natural Gas Corp. Deferred Stock Trust Agreement dated September 30,
1998.
*10.22 Louis Dreyfus Natural Gas Corp. Non-Employee Director Deferred Stock Compensation Program as adopted
effective July 23, 1998.
21.1 List of subsidiaries of the Registrant.
**23.1 Consent of Independent Auditors.
24.1 Powers of Attorney.
**27.1 Financial Data Schedule.
</TABLE>
- ------------------------
* Constitutes a management contract or compensatory plan or arrangement
required to be filed as an exhibit to this report.
** Filed herewith.
Certain of the exhibits to this filing contain schedules which have been
omitted in accordance with applicable regulations. The Registrant undertakes
to furnish supplementally a copy of any omitted schedule to the Securities
and Exchange Commission upon request.
(b) Reports on Form 8-K.
None.
52
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
<TABLE>
<S> <C> <C>
LOUIS DREYFUS NATURAL GAS CORP.
Date: October 7, 1999 By: /s/ JEFFREY A. BONNEY
-----------------------------------------
Jeffrey A. Bonney
EXECUTIVE VICE PRESIDENT AND CHIEF
FINANCIAL OFFICER
</TABLE>
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURES TITLE DATE
- ------------------------------ -------------------------- -------------------
<C> <S> <C>
President, Chief Executive
MARK E. MONROE* Officer and Director
- ------------------------------ (principal executive October 7, 1999
Mark E. Monroe officer)
RICHARD E. BROSS*
- ------------------------------ Executive Vice President October 7, 1999
Richard E. Bross* and Director
Executive Vice President
/s/ JEFFREY A. BONNEY and Chief Financial
- ------------------------------ Officer October 7, 1999
Jeffrey A. Bonney (principal financial and
accounting officer)
SIMON B. RICH, JR.*
- ------------------------------ Chairman of the Board of October 7, 1999
Simon B. Rich, Jr.* Directors
MARK ANDREWS*
- ------------------------------ Vice Chairman of the Board October 7, 1999
Mark Andrews* of Directors
GERARD LOUIS-DREYFUS*
- ------------------------------ Director October 7, 1999
Gerard Louis-Dreyfus*
E. WILLIAM BARNETT*
- ------------------------------ Director October 7, 1999
E. William Barnett*
DANIEL R. FINN, JR.*
- ------------------------------ Director October 7, 1999
Daniel R. Finn, Jr.*
PETER G. GERRY*
- ------------------------------ Director October 7, 1999
Peter G. Gerry*
JOHN H. MOORE*
- ------------------------------ Director October 7, 1999
John H. Moore*
JAMES R. PAUL*
- ------------------------------ Director October 7, 1999
James R. Paul*
</TABLE>
<TABLE>
<S> <C> <C> <C>
*By: /s/ JEFFREY A. BONNEY
--------------------------------------
Jeffrey A. Bonney
ATTORNEY-IN-FACT
</TABLE>
53
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
<TABLE>
<CAPTION>
PAGE
---------
<S> <C>
CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Auditors............................................................................. F-2
Consolidated Balance Sheets:
December 31, 1998 and 1997............................................................................... F-3
Consolidated Statements of Operations:
Years ended December 31, 1998, 1997 and 1996............................................................. F-4
Consolidated Statements of Stockholders' Equity:
Years ended December 31, 1998, 1997 and 1996............................................................. F-5
Consolidated Statements of Cash Flows:
Years ended December 31, 1998, 1997 and 1996............................................................. F-6
Notes to Consolidated Financial Statements................................................................. F-7
CONSOLIDATED FINANCIAL STATEMENT SCHEDULE
Schedule II--Consolidated Valuation and Qualifying Accounts................................................ F-35
</TABLE>
All other schedules for which provision is made in the applicable accounting
regulations of the Securities and Exchange Commission are not required under the
related instructions or are inapplicable and therefore have been omitted.
F-1
<PAGE>
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders
Louis Dreyfus Natural Gas Corp.
We have audited the accompanying consolidated balance sheets of Louis Dreyfus
Natural Gas Corp. (the "Company") as of December 31, 1998 and 1997, and the
related consolidated statements of operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1998. Our
audits also included the financial statement schedule listed in the Index to
Item 14(a). These financial statements and the schedule are the responsibility
of the Company's management. Our responsibility is to express an opinion on
these financial statements and the schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of the Company at
December 31, 1998 and 1997, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended December 31, 1998
in conformity with generally accepted accounting principles. Also, in our
opinion, the related financial statement schedule, when considered in relation
to the basic financial statements taken as a whole, presents fairly in all
material respects, the information set forth therein.
As discussed in Note 1 of the notes to the consolidated financial statements,
effective October 1, 1998, the Company adopted Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities."
As described in Note 2, the consolidated financial statements as of and for the
year ended December 31, 1998 have been restated.
ERNST & YOUNG LLP
Oklahoma City, Oklahoma
February 4, 1999
except for Note 2, as to which the date is
October 4, 1999
F-2
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1998 1997
----------- ------------
(RESTATED)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents.............................................................. $ 2,539 $ 5,538
Receivables:
Oil and gas sales.................................................................... 37,381 46,192
Joint interest and other, net........................................................ 11,725 14,311
Costs reimbursable by insurance...................................................... 7,200 22,406
Fixed-price contracts and other derivatives............................................ 23,338 --
Deposits............................................................................... 1,490 4,467
Inventory and other.................................................................... 3,082 9,883
----------- ------------
Total current assets................................................................... 86,755 102,797
----------- ------------
PROPERTY AND EQUIPMENT, at cost, based on successful efforts accounting................ 1,519,296 1,404,784
Less accumulated depreciation, depletion and amortization.............................. (434,693) (305,769)
----------- ------------
1,084,603 1,099,015
----------- ------------
OTHER ASSETS
Fixed price contracts and other derivatives............................................ 107,302 --
Other, net............................................................................. 5,148 9,142
----------- ------------
112,450 9,142
----------- ------------
$ 1,283,808 $ 1,210,954
----------- ------------
----------- ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable....................................................................... $ 38,222 $ 61,197
Accrued liabilities.................................................................... 12,988 22,258
Revenues payable....................................................................... 10,940 16,111
----------- ------------
Total current liabilities............................................................ 62,150 99,566
----------- ------------
LONG-TERM DEBT......................................................................... 596,844 563,344
----------- ------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred revenue....................................................................... 15,551 17,387
Deferred gains from price-risk management activities................................... -- 23,453
Deferred income taxes.................................................................. 65,116 21,896
Other.................................................................................. 24,686 16,104
----------- ------------
105,353 78,840
----------- ------------
COMMITMENTS AND CONTINGENCIES (Notes 8 and 14)
STOCKHOLDERS' EQUITY
Preferred stock, par value $.01; 10 million shares authorized; no shares outstanding... -- --
Common stock, par value $.01; 100 million shares authorized; issued and outstanding,
40,109,758 and 40,088,258 shares, respectively....................................... 401 401
Additional paid-in capital............................................................. 419,075 418,751
Retained earnings...................................................................... 6,735 50,052
Accumulated other comprehensive income................................................. 93,250 --
----------- ------------
519,461 469,204
----------- ------------
$ 1,283,808 $ 1,210,954
----------- ------------
----------- ------------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-3
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------
1998 1997 1996
---------- ---------- ----------
(RESTATED)
<S> <C> <C> <C>
REVENUES
Oil and gas sales............................................................ $ 271,575 $ 222,016 $ 185,558
Change in derivative fair value.............................................. 17,346 -- --
Other income................................................................. 4,462 10,901 3,947
---------- ---------- ----------
293,383 232,917 189,505
---------- ---------- ----------
EXPENSES
Operating costs.............................................................. 66,295 49,169 44,615
General and administrative................................................... 25,971 18,855 16,325
Exploration costs............................................................ 34,543 8,956 4,965
Depreciation, depletion and amortization..................................... 131,408 79,325 65,278
Impairment................................................................... 52,522 75,198 --
Interest..................................................................... 40,849 28,737 26,822
---------- ---------- ----------
351,588 260,240 158,005
---------- ---------- ----------
Income (loss) before income taxes and cumulative effect of accounting
change..................................................................... (58,205) (27,323) 31,500
Income tax provision (benefit)............................................... (13,924) (11,261) 10,398
---------- ---------- ----------
Net income (loss) before cumulative effect of accounting change.............. (44,281) (16,062) 21,102
Cumulative effect of accounting change, net of tax of $591................... 964 -- --
---------- ---------- ----------
NET INCOME (LOSS)............................................................ $ (43,317) $ (16,062) $ 21,102
---------- ---------- ----------
---------- ---------- ----------
PER SHARE
Net income (loss) before cumulative effect of accounting change.............. $ (1.10) $ (.53) $ .76
Cumulative effect of accounting change....................................... .02 -- --
---------- ---------- ----------
Net income (loss)--basic and diluted......................................... $ (1.08) $ (.53) $ .76
---------- ---------- ----------
---------- ---------- ----------
Weighted average diluted common shares....................................... 40,107 30,233 27,810
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-4
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
ACCUMULATED
ADDITIONAL OTHER TOTAL
PREFERRED COMMON PAID-IN RETAINED COMPREHENSIVE STOCKHOLDERS'
STOCK STOCK CAPITAL EARNINGS INCOME EQUITY
---------- ----------- ---------- ---------- -------------- ------------
<S> <C> <C> <C> <C> <C> <C>
BALANCE AT DECEMBER 31, 1995........ $ -- $ 278 $ 197,291 $ 45,012 $ -- $ 242,581
Exercise of stock options........... -- -- 10 -- -- 10
Net income.......................... -- -- -- 21,102 -- 21,102
---------- ----- ---------- ---------- -------------- ------------
BALANCE AT DECEMBER 31, 1996........ -- 278 197,301 66,114 -- 263,693
Preferred stock issued in American
Acquisition....................... 21,080 -- -- -- -- 21,080
Preferred stock converted........... (20,655) 10 16,726 -- -- (3,919)
Preferred stock redeemed............ (425) -- -- -- -- (425)
Common stock issued in American
Acquisition....................... -- 113 193,964 -- -- 194,077
Exercise of stock options........... -- -- 497 -- -- 497
Warrants and options issued in
American Acquisition.............. -- -- 10,263 -- -- 10,263
Net loss............................ -- -- -- (16,062) -- (16,062)
---------- ----- ---------- ---------- -------------- ------------
BALANCE AT DECEMBER 31, 1997........ -- 401 418,751 50,052 -- 469,204
Exercise of stock options........... -- -- 324 -- -- 324
------------
Sub-total......................... -- -- -- -- -- 469,528
------------
Comprehensive income:
Net loss............................ -- -- -- (43,317) -- (43,317)
Other comprehensive income, net of
tax:
Cumulative effect of accounting
change.......................... -- -- -- -- 97,681 97,681
Reclassification adjustments--
contract settlements............ -- -- -- -- (4,431) (4,431)
------------
Total comprehensive income
(restated)........................ -- -- -- -- -- 49,933
---------- ----- ---------- ---------- -------------- ------------
BALANCE AT DECEMBER 31, 1998
(RESTATED)........................ $ -- $ 401 $ 419,075 $ 6,735 $ 93,250 $ 519,461
---------- ----- ---------- ---------- -------------- ------------
---------- ----- ---------- ---------- -------------- ------------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-5
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------
1998 1997 1996
---------- --------- ---------
(RESTATED)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)................................................... $ (43,317) $ (16,062) $ 21,102
Items not affecting cash flows:
Depreciation, depletion and amortization.......................... 131,408 79,325 65,278
Impairment........................................................ 52,522 75,198 --
Deferred income taxes............................................. (14,524) (12,296) 9,065
Exploration costs................................................. 34,543 8,956 4,965
Change in derivative fair value................................... (17,346) -- --
Gain on sale of property.......................................... (166) (8,745) (68)
Other............................................................. 1,799 698 639
Net change in operating assets and liabilities, exclusive of amounts
acquired:
Accounts receivable............................................... 27,529 (5,598) (10,194)
Deposits.......................................................... 2,977 1,125 (1,692)
Inventory and other............................................... 5,116 (3,184) (52)
Accounts payable.................................................. (23,179) 10,162 14,957
Accrued liabilities............................................... (6,646) 75 (661)
Revenues payable.................................................. (3,278) 192 2,732
Deferred revenue.................................................. -- -- (4,310)
---------- --------- ---------
147,438 129,846 101,761
---------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development expenditures............................ (222,400) (154,396) (98,097)
Acquisition of oil and gas properties............................... (4,500) (9,118) (36,125)
Purchase of American Exploration Company............................ -- (72,323) --
Additions to other property and equipment........................... (2,615) (2,650) (17,660)
Proceeds from sale of property and equipment........................ 14,413 27,887 1,101
Change in other assets.............................................. (172) (6,003) (76)
---------- --------- ---------
(215,274) (216,603) (150,857)
---------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from bank borrowings....................................... 475,362 868,037 241,240
Repayments of bank borrowings....................................... (443,662) (928,537) (212,240)
Proceeds from issuance of senior notes.............................. -- 198,784 --
Repayments of subordinated notes.................................... -- (42,621) --
Proceeds from contract termination.................................. 40,136 -- 25,000
Proceeds from stock options exercised............................... 324 497 10
Redemption of preferred stock....................................... -- (4,344) --
Change in deferred revenue.......................................... (1,836) (1,662) (2,268)
Change in gains from price-risk management activities............... (2,321) (2,773) 1,226
Change in other long-term liabilities............................... (3,166) (2,835) 2,293
---------- --------- ---------
64,837 84,546 55,261
---------- --------- ---------
Change in cash and cash equivalents................................. (2,999) (2,211) 6,165
Cash and cash equivalents, beginning of year........................ 5,538 7,749 1,584
---------- --------- ---------
Cash and cash equivalents, end of year.............................. $ 2,539 $ 5,538 $ 7,749
---------- --------- ---------
---------- --------- ---------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-6
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
GENERAL. Louis Dreyfus Natural Gas Corp. ("LDNG" or the "Company") is one of
the largest independent natural gas companies in the United States engaged in
the acquisition, development, exploration, production and marketing of natural
gas and crude oil. At December 31, 1998, approximately 52% of the Company's
Common Stock was owned by various subsidiaries of Societe Anonyme Louis Dreyfus
& Cie (collectively "S.A. Louis Dreyfus et Cie"). See Note 7--Transactions with
Related Parties. The accounting policies of LDNG reflect industry practices and
conform to generally accepted accounting principles. The more significant of
such policies are briefly described below.
PRINCIPLES OF CONSOLIDATION AND BASIS OF PRESENTATION. The accompanying
consolidated financial statements include the accounts of LDNG and its
wholly-owned subsidiaries after elimination of all material intercompany
accounts and transactions. Certain reclassifications have been made in the
financial statements for the years ended December 31, 1997 and 1996 to conform
to the financial statement presentation for the year ended December 31, 1998.
USE OF ESTIMATES. The preparation of the financial statements in conformity
with generally accepted accounting principles requires Management to make
estimates and assumptions that affect the amounts reported in the financial
statements and accompanying notes. Actual results could differ from those
estimates.
CASH AND CASH EQUIVALENTS. Cash and cash equivalents consist of all demand
deposits and funds invested in short-term investments with original maturities
of three months or less.
CONCENTRATION OF CREDIT RISK. The Company sells oil and natural gas to
various customers, participates with other parties in the drilling, completion
and operation of oil and natural gas wells and enters into long-term energy
swaps and physical delivery contracts. The majority of the Company's accounts
receivable are due from purchasers of oil and natural gas and from fixed-price
contract counterparties. Certain of these receivables are subject to collateral
or margin requirements. The Company has established procedures to monitor credit
risk and has not experienced significant credit losses in prior years. See Note
14--Fixed-Price Contracts--Credit Risk. As of December 31, 1998 and 1997, the
Company's joint interest and other receivables are shown net of allowance for
doubtful accounts of $1.2 million and $1.1 million, respectively.
INVENTORY. Inventory consists primarily of tubular goods and is carried at
the lower of cost or market.
PROPERTY AND EQUIPMENT. The Company utilizes the successful efforts method
of accounting for oil and natural gas producing activities. Costs incurred in
connection with the drilling and equipping of exploratory wells are capitalized
as incurred. If proved reserves are not found, such costs are charged to
expense. Other exploration costs, including delay rentals and seismic costs, are
charged to expense as incurred. Development costs, which include the costs of
drilling and equipping development wells, whether successful or unsuccessful,
are capitalized as incurred. All general and administrative costs are expensed
as incurred. Depreciation, depletion and amortization of capitalized costs of
proved oil and gas properties is computed by the unit-of-production method on a
field-by-field basis. The costs of unproved oil and gas properties are assessed
quarterly on a property-by-property basis. If unproved properties are determined
to be productive, the related costs are transferred to proved oil and gas
properties. If unproved properties are determined not to be productive, or if
the value of such properties has been otherwise impaired, the excess carrying
value is charged to expense.
F-7
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Expenditures made in connection with the Company's drilling program are
presented in the accompanying statement of cash flows as investing activities.
As indicated above, certain of these amounts are expensed as incurred or if
unsuccessful in discovering new reserves. Investing activities for the years
ended December 31, 1998, 1997 and 1996, include $30.5 million, $6.7 million and
$4.4 million, respectively, of costs which have been expensed as exploration
costs in the statement of operations for the corresponding periods.
The Company's oil and gas properties are reviewed on a field-by-field basis
for indications of impairment whenever events or circumstances indicate that the
carrying value of its oil and gas properties may not be recoverable. In order to
determine whether an impairment has occurred, the Company estimates the expected
future net cash flows from its oil and gas properties as of the date of
determination, and compares such future cash flows to the respective carrying
amounts. Such estimated future cash flows are based on proved reserves and
forward market prices for oil and gas that existed as of the date of
determination. Those oil and gas properties which have carrying amounts in
excess of estimated future cash flows are deemed impaired. The carrying value of
impaired properties is adjusted to an estimated fair value by discounting the
estimated expected future cash flows attributable to such properties at a
discount rate estimated to be representative of the market for such properties.
The excess is charged to expense and may not be reinstated. For 1998, the
Company recognized impairment charges aggregating $52.5 million. The associated
impairment reviews were conducted as the result of declining oil and gas prices
during the year which adversely affected the estimated future cash flows from
the Company's oil and gas properties. Further weakening of oil and gas prices
could result in future impairment recognition. In 1997, the Company recognized a
$75.2 million impairment charge, substantially all of which was recorded in
connection with the acquisition of American Exploration Company, a Houston-based
exploration and production company ("American") in October 1997 (the "American
Acquisition"). The allocation of the American Acquisition purchase price, based
on the relative fair values of the acquired properties, was reviewed for
indications of impairment. Such review resulted in the impairment charge
recognition. See Note 4--Acquisitions.
The Company provides for the estimated cost, at current prices, of
dismantling and removing oil and gas production facilities. Such estimated costs
are recorded at discounted values based on the estimated productive lives of the
associated oil and gas property and amortized by the unit-of-production method.
As of December 31, 1998 and 1997, estimated total future dismantling and
restoration costs of $6.3 million and $5.8 million, respectively, were included
in other liabilities in the accompanying balance sheets.
Depreciation of other property and equipment is provided by using the
straight-line method over estimated useful lives of three to 20 years.
DEBT ISSUANCE COSTS. Debt issuance costs are amortized over the term of the
associated debt instrument using the straight-line method. The unamortized
balance of such costs included in other assets as of December 31, 1998 and 1997,
was $3.7 million and $4.1 million, respectively.
OIL AND GAS SALES AND GAS IMBALANCES. Oil and gas revenues are recognized
as oil and gas is produced and sold. The Company uses the sales method of
accounting for gas imbalances in those circumstances where the Company has
underproduced or overproduced its ownership percentage in a property. Under this
method, a liability is recorded to the extent that the Company's overproduced
position in a reservoir cannot be recouped through the production of remaining
reserves. At December 31,
F-8
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
1998 and 1997, the Company had recorded imbalance liabilities of $4.0 million
and $3.2 million, respectively. Additionally, at December 31, 1998, the Company
had imbalance receivables of $1.4 million.
INCOME TAXES. The Company files a consolidated United States income tax
return which includes the taxable income or loss of its subsidiaries. Deferred
federal and state income taxes are provided on all significant temporary
differences between the financial statement carrying amounts of assets and
liabilities and their respective tax bases.
HEDGING. The Company reduces its exposure to unfavorable changes in oil and
natural gas prices by utilizing fixed-price physical delivery contracts, energy
swaps, collars, futures contracts, basis swaps and options (collectively
"Fixed-Price Contracts"). The Company also enters into interest rate swap
contracts to reduce its exposure to adverse interest rate fluctuations. In
October 1998, the Company adopted Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS
133") which establishes new accounting and reporting guidelines for derivative
instruments and hedging activities. It requires that all derivative instruments
be recognized as assets or liabilities in the statement of financial position,
measured at fair value. The accounting for changes in the fair value of a
derivative depends on the intended use of the derivative and the resulting
designation. Designation is established at the inception of a derivative, but
redesignation is permitted. For derivatives designated as cash flow hedges,
changes in fair value are recognized in other comprehensive income until the
hedged item is recognized in earnings. Hedge effectiveness is to be measured at
least quarterly based on the relative changes in fair value between the
derivative contract and the hedged item over time. Any change in fair value
resulting from ineffectiveness, as defined by SFAS 133, is recognized
immediately in earnings. Effective January 13, 1999, substantially all of the
Company's Fixed-Price Contracts and interest rate swaps are designated as cash
flow hedges. For the period from October 1, 1998 to January 13, 1999, the change
in fair value of all derivative contracts was recognized in results of
operations. See Note 2-- Restatement of 1998 Financial Statements. Changes in
the fair value of derivative instruments which are not designated as hedges or
are defined by SFAS 133 as being "fair value hedges" are recorded in earnings as
the changes occur. Fixed-Price contracts monotized prior to their maturity are
classified as financing activities in the accompanying statements of cash flows.
Adoption of the standard resulted in the reclassification of $62.2 million
of deferred gains from price-risk management activities and $3.3 million of
deferred hedging losses related to terminated contracts to accumulated other
comprehensive income, recorded net of deferred income tax effects. In addition,
adoption resulted in the recognition of $130.6 million of derivative assets and
$7.6 million of derivative liabilities in the Company's balance sheet as of
December 31, 1998. SFAS 133 precludes the consideration of future cash flows
from derivative instruments in asset impairment determinations irrespective of
any risk management intent for entering into such instruments. Adoption of the
standard resulted in an additional impairment charge of $12.4 million which has
been included in earnings as a cumulative effect of an accounting change. Also
included in earnings as a cumulative effect of an accounting change are the
following: $8.6 million of Fixed-Price Contract gains associated with the
incremental impairment charge, $2.8 million of Fixed-Price Contract gains
relating to contracts not qualifying as cash flow hedges, $1.5 million of
Fixed-Price Contract gains relating to Fixed-Price Contract hedge
ineffectiveness, and $1.1 million of net gain associated with a fair value hedge
which hedged a portion of the Company's subordinated debt. See Note
2--Restatement of 1998 Financial Statements, Note 5--Long-Term Debt, Note
11--Capital Stock and Stockholders' Equity Information, Note 13--Financial
Instruments and
F-9
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Note 14--Fixed-Price Contracts. The Company does not hold or issue financial
instruments with leveraged features.
EARNINGS PER SHARE. The Company follows Statement of Financial Accounting
Standards No. 128, "Earnings per Share" ("SFAS 128"), to compute earnings per
share. Weighted average common shares outstanding used in the calculation of
basic earnings per share for the years ended December 31, 1998, 1997, and 1996
(in thousands) were 40,107, 30,233 and 27,800, respectively. Dilutive potential
common shares used in the calculation of diluted earnings per share for the
years ended December 31, 1998, 1997 and 1996 (in thousands) were 40,107, 30,233
and 27,810, respectively. The increase in dilutive potential shares for 1996 is
attributable to dilutive stock options. See Note 9--Employee Benefit Plans and
Note 11--Capital Stock for a description of potentially dilutive securities of
the Company.
STOCK OPTIONS. The Company accounts for employee stock-based compensation
using the intrinsic value method prescribed by Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees" and related
interpretations. No compensation expense is recorded with respect to stock
options granted at prices equal to the market value of the Company's Common
Stock at the date of grant. Upon exercise, the excess of the proceeds over the
par value of the shares issued is credited to additional paid-in capital. See
Note 9--Employee Benefit Plans.
NOTE 2. RESTATEMENT OF 1998 FINANCIAL STATEMENTS
Pursuant to the provisions of SFAS 133, all hedging designations and the
methodology for determining hedge ineffectiveness must be documented at the
inception of the hedge, and, upon the initial adoption of the standard, hedging
relationships must be designated anew. The documentation must also indicate the
risk management intent for entering into the hedging arrangement. The Company
believed that it complied with the spirit and intent of the provisions of the
standard with respect to documentation. However, in connection with the review
of the Company's public filings by the Staff of the Securities and Exchange
Commission in September 1999, the Company's documentation was found to be
insufficient as of the October 1, 1998 date of adoption of SFAS 133. Therefore,
the Company is precluded from being able to utilize the special provisions of
hedge accounting for the fourth quarter of 1998, and the period from January 1,
1999 to January 13, 1999, the date the Company's documentation was sufficient in
relation to the formal documentation requirements of the standard. As a result,
the changes in fair value of all of the Company's derivatives during the fourth
quarter were required to be reported in results of operations, rather than in
other comprehensive income. The accompanying financial statements as of December
31,
F-10
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 2. RESTATEMENT OF 1998 FINANCIAL STATEMENTS (CONTINUED)
1998, and for the year then ended, have been amended to reflect this change in
accounting. The effect of the restatement is provided below.
<TABLE>
<CAPTION>
AS
AS PREVIOUSLY
RESTATED REPORTED
------------ ------------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
<S> <C> <C>
STATEMENT OF OPERATIONS DATA FOR THE YEAR ENDED DECEMBER 31, 1998:
Change in derivative fair value....................................................... $ 17,346 $ --
Other income.......................................................................... 4,462 6,916
Total revenues........................................................................ 293,383 278,491
Interest expense...................................................................... 40,849 40,908
Total expenses........................................................................ 351,588 351,647
Loss before income taxes and cumulative effect of accounting change................... (58,205) (73,156)
Income taxes (benefit)................................................................ (13,924) (19,605)
Net loss before cumulative effect of accounting change................................ (44,281) (53,551)
Net loss.............................................................................. (43,317) (52,587)
Net loss before cumulative effect of accounting changes per share..................... (1.10) (1.33)
Net loss per share - basic and diluted................................................ (1.08) (1.31)
BALANCE SHEET DATA AS OF DECEMBER 31, 1998:
Long-term debt........................................................................ 596,844 596,103
Deferred income taxes................................................................. 65,116 65,398
Total deferred credit and other liabilities........................................... 105,353 105,635
Retained earnings (deficit)........................................................... 6,735 (2,535)
Accumulated other comprehensive income................................................ 93,250 102,979
Total stockholders' equity............................................................ 519,461 519,920
</TABLE>
The Company has continued to refer to its Fixed-Price Contracts as economic
hedges in the notes to the consolidated financial statements inasmuch as this
was the intent when such contracts were executed, the characterization is
consistent with the actual economic performance of the contracts, and management
expects the contracts to serve in that capacity in future periods.
F-11
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 3. PROPERTY AND EQUIPMENT
CAPITALIZED COSTS. The Company's oil and gas acquisition, exploration and
development activities are conducted primarily in Texas, Oklahoma, New Mexico
and offshore in the Gulf of Mexico. The following table summarizes the
capitalized costs associated with these activities:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1998 1997
------------ ------------
<S> <C> <C>
(IN THOUSANDS)
OIL AND GAS PROPERTIES:
Proved................................................................................ $ 1,434,066 $ 1,298,046
Unproved.............................................................................. 51,304 74,893
Accumulated depreciation, depletion and amortization.................................. (421,164) (295,848)
------------ ------------
1,064,206 1,077,091
------------ ------------
Other property and equipment.......................................................... 33,926 31,845
Accumulated depreciation.............................................................. (13,529) (9,921)
------------ ------------
20,397 21,924
------------ ------------
$ 1,084,603 $ 1,099,015
------------ ------------
------------ ------------
</TABLE>
Depreciation, depletion and amortization expense of oil and gas properties
per Mcfe was $1.04, $.88 and $.82 for the years ended December 31, 1998, 1997
and 1996, respectively. Such amounts do not include impairment charges recorded
in 1998 and 1997. See Note 1--Significant Accounting Policies. For the years
ended December 31, 1998, 1997 and 1996, the Company capitalized $3.3 million,
$1.0 million and $.4 million of interest, respectively, in connection with its
exploration and development activities. Depreciation of other property and
equipment was $4.1 million, $3.2 million and $2.6 million for the years ended
December 31, 1998, 1997 and 1996, respectively.
Unproved properties at December 31, 1998 consist primarily of acreage
positions obtained in the American Acquisition. The Company will evaluate such
properties over their respective lease terms or as drilling results are
determined.
COSTS INCURRED. The following table summarizes the costs incurred in the
Company's acquisition, exploration and development activities for the years
ended December 31, 1998, 1997 and 1996, respectively.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------
1998 1997 1996
---------- ---------- ----------
<S> <C> <C> <C>
(IN THOUSANDS)
PROPERTY ACQUISITION COSTS:
Proved....................................................................... $ 4,088 $ 349,037 $ 36,125
Unproved..................................................................... 11,815 109,648 6,934
---------- ---------- ----------
15,903 458,685 43,059
Exploration costs............................................................ 74,123 21,514 10,610
Development costs............................................................ 136,462 122,402 80,553
---------- ---------- ----------
$ 226,488 $ 602,601 $ 134,222
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
F-12
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 4. ACQUISITIONS
In October 1997, the Company acquired 100% of the outstanding common stock
of American for approximately 11.3 million shares of LDNG Common Stock valued at
$17.15 per share and $47.2 million of cash. In addition, LDNG assumed $116
million of American long-term debt, $20 million liquidation value of American
preferred stock and warrants and options valued at $10.3 million. The
acquisition consisted of 217 Bcfe of proved reserves, approximately 3,500
producing wells, 1.0 million gross acres of developed leasehold, 2.0 million
gross acres of undeveloped leasehold and other assets and liabilities. The
purchase method was used to account for this acquisition.
The following unaudited pro forma results of operations data gives effect to
the American Acquisition as if the transaction had occurred on January 1, 1996.
The unaudited pro forma information is presented for illustrative purposes only
and is not necessarily indicative of the actual results that would have occurred
had these acquisitions closed on these respective dates or of future results of
operations. The historic information has been adjusted for (1) oil and gas sales
and related operating costs, (2) amortization of the oil and gas properties
based on the purchase price, (3) incremental general and administrative expenses
associated with the ownership of the properties, and (4) incremental interest
expense resulting from the borrowings made under the Credit Facility, as
hereinafter defined, in connection with each acquisition.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER
31,
----------------------
1997 1996
---------- ----------
<S> <C> <C>
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
UNAUDITED PRO FORMA INFORMATION:
Revenues.................................................................................. $ 303,719 $ 266,703
Net income................................................................................ 16,752 3,440
Net income per common share--basic and diluted............................................ .43 .09
</TABLE>
The pro forma information for 1997 and 1996 does not include a $73.1 million
impairment charge incurred as a result of recording the cost of the American
Acquisition, which was in excess of the underlying tangible assets, nor does it
consider the effects of certain cost reduction plans, financing plans or the
effects of certain purchase accounting adjustments.
During 1998, 1997 and 1996, the Company made numerous other acquisitions of
proved oil and gas properties, the net purchase price of which aggregated $4.1
million, $9.1 million and $36.1 million, respectively. The results of operations
related to such acquisitions have been included in the accompanying statements
of operations and cash flows for the periods subsequent to the closing of each
transaction.
F-13
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 5. LONG-TERM DEBT
Long-term debt consists of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------
1998 1997
---------- ----------
<S> <C> <C>
(IN THOUSANDS)
BANK DEBT:
$450 Million Revolving Credit Facility.................................................... $ 295,000 $ 261,000
Other Lines of Credit..................................................................... 2,200 4,500
---------- ----------
297,200 265,500
6 7/8% Senior Notes due 2007.............................................................. 198,912 198,791
9 1/4% Senior Subordinated Notes due 2004................................................. 100,732 99,053
---------- ----------
$ 596,844 $ 563,344
---------- ----------
---------- ----------
</TABLE>
$450 MILLION REVOLVING CREDIT FACILITY. The Company has a revolving credit
facility (the "Credit Facility") with a syndicate of banks which provides up to
$450 million in borrowings (the "Commitment"). Letters of credit under the
Credit Facility are limited to $75 million of such availability. The Credit
Facility allows the Company to draw on the full $450 million credit line without
restrictions tied to periodic revaluations of its oil and gas reserves provided
the Company continues to maintain an investment grade credit rating from either
Standard & Poor's Ratings Service or Moody's Investors Service. A borrowing base
can be required only upon the vote by a majority in interest of the lenders
after the loss of an investment grade credit rating. No principal payments are
required under the Credit Facility prior to maturity on October 14, 2002. The
Company has relied upon the Credit Facility to provide funds for acquisitions
and to provide letters of credit to meet the Company's margin requirements under
Fixed-Price Contracts. See Note 14--Fixed-Price Contracts. As of December 31,
1998, the Company had $295.0 million of principal and $17.8 million of letters
of credit outstanding under the Credit Facility.
The Company has the option of borrowing at a LIBOR-based interest rate or
the Base Rate (approximating the prime rate). The LIBOR interest rate margin and
the facility fee payable under the Credit Facility are subject to a sliding
scale based on the Company's senior debt credit rating. At December 31, 1998,
the applicable interest rate was LIBOR plus 30 basis points. The Credit Facility
also requires the payment of a facility fee equal to 15 basis points of the
Commitment. The average interest rate for borrowings under the Credit Facility
was 5.6% as of December 31, 1998. Including the effect of interest rate swaps
which hedge a portion of the interest rate exposure attributable to this
facility, the effective interest rate was 5.9%.
The Credit Facility contains various affirmative and restrictive covenants
which, among other things, limit total indebtedness to $700 million ($625
million of senior indebtedness) and require the Company to meet certain
financial tests. Borrowings under the Credit Facility are unsecured.
OTHER LINES OF CREDIT. The Company has certain other unsecured lines of
credit available to it, which aggregated $45.0 million as of December 31, 1998.
Such short-term lines of credit are primarily used to meet margin requirements
under Fixed-Price Contracts and for working capital purposes. At December 31,
1998, the Company had $2.2 million of indebtedness and $.1 million of letters of
credit outstanding under these credit lines. Repayment of indebtedness
thereunder is expected to be made through Credit Facility availability.
F-14
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 5. LONG-TERM DEBT (CONTINUED)
6 7/8% SENIOR NOTES DUE 2007. In December 1997, the Company issued $200
million principal amount, $198.8 million net of discount, of 6-7/8% Senior Notes
due 2007 (the "Senior Notes"). Interest is payable semi-annually on June 1 and
December 1. The associated indenture agreement contains restrictive covenants
which place limitations on the amount of liens and the Company's ability to
enter into sale and leaseback transactions.
9 1/4% SENIOR SUBORDINATED NOTES DUE 2004. In June 1994, the Company issued
$100 million principal amount, $98.5 million net of discount, of 9-1/4% Senior
Subordinated Notes due 2004 (the "Subordinated Notes"). Interest is payable
semi-annually on June 15 and December 15. The associated indenture agreement
contains restrictive covenants which limit, among other things, the prepayment
of the Subordinated Notes, the incurrence of additional indebtedness, the
payment of dividends and the disposition of assets.
The amount of required principal payments for the next five years and
thereafter as of December 31, 1998 are as follows: 1999--$0; 2000--$0; 2001--$0;
2002--$297.2 million; 2003--$0; thereafter-- $300 million.
INTEREST RATE SWAPS. The Company has entered into interest rate swaps as
economic hedges of the interest rate exposure associated with borrowings under
the Credit Facility. As of December 31, 1998, the Company had fixed the interest
rate on average notional amounts of $158 million, $125 million, $125 million and
$94 million for the years ended December 31, 1999, 2000, 2001 and 2002,
respectively. Under the interest rate swaps, the Company receives the LIBOR
three-month rate (5.1% at December 31, 1998) and pays an average rate of 5.3%,
5.0%, 5.0% and 5.0% for 1999, 2000, 2001 and 2002, respectively. The notional
amounts are less than the maximum amount anticipated to be available under the
Credit Facility in such years.
For each interest rate swap, the differential between the fixed rate and the
floating rate multiplied by the notional amount is the swap gain or loss. Such
gain or loss is included in interest expense in the period for which the
interest rate exposure was hedged. Pursuant to SFAS 133, if an interest rate
swap is liquidated or sold prior to maturity, the gain or loss on the interest
rate swap at the time of termination remains in accumulated other comprehensive
income, to be recognized as an adjustment to interest expense over the original
contract term. See Note 2--Restatement of 1998 Financial Statements. Prior to
the adoption of SFAS 133, the gain or loss attributable to terminated contracts
was accounted for as a deferred asset or liability. For the years ended December
31, 1998, 1997 and 1996, interest rate swap settlements increased interest
expense by $.3 million, $.2 million and $.9 million, respectively.
As of October 1, 1998, the Company had one interest rate swap with a
notional amount of $25 million, which under SFAS 133 guidelines, was a fair
value hedge for a portion of the Subordinated Notes. As a result, cumulative
effect of an accounting change in the statement of operations for the year ended
December 31, 1998 included a gain of $2.7 million associated with the fair value
of this interest rate swap and a loss of $1.6 million attributable to the change
in fair value of the Subordinated Notes. This interest rate swap was terminated
in the fourth quarter of 1998.
F-15
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 6. INCOME TAXES
The significant components of income tax expense (benefit) before cumulative
effect of accounting change for the years ended December 31, 1998, 1997 and 1996
are as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
---------- ---------- ---------
<S> <C> <C> <C>
(IN THOUSANDS)
CURRENT TAX EXPENSE:
Federal........................................................................ $ 527 $ 885 $ 1,159
State.......................................................................... 73 150 174
---------- ---------- ---------
600 1,035 1,333
---------- ---------- ---------
DEFERRED TAX EXPENSE (BENEFIT):
Federal........................................................................ (12,766) (11,407) 8,271
State.......................................................................... (1,758) (889) 794
---------- ---------- ---------
(14,524) (12,296) 9,065
---------- ---------- ---------
$ (13,924) $ (11,261) $ 10,398
---------- ---------- ---------
---------- ---------- ---------
</TABLE>
The provision for income taxes before cumulative effect of accounting change
differed from the computed "expected" income tax provision using statutory rates
on income before income taxes for the following reasons:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
---------- ---------- ---------
<S> <C> <C> <C>
(IN THOUSANDS)
Computed "expected" income tax................................................. $ (20,372) $ (9,563) $ 11,025
Increases (reductions) in taxes resulting from:
State income taxes, net of federal benefit................................... (1,095) (481) 629
Permanent differences (principally related to basis differences in oil and
gas properties)............................................................ 6,133 935 265
Change in valuation allowance................................................ 2,667 -- --
Section 29 credits........................................................... (851) (1,748) (2,028)
Other........................................................................ (406) (404) 507
---------- ---------- ---------
$ (13,924) $ (11,261) $ 10,398
---------- ---------- ---------
---------- ---------- ---------
</TABLE>
F-16
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 6. INCOME TAXES (CONTINUED)
Deferred tax assets and liabilities, resulting from differences between the
financial statement carrying amounts and the tax bases of assets and
liabilities, consist of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------
1998 1997
---------- ----------
<S> <C> <C>
(IN THOUSANDS)
DEFERRED TAX LIABILITIES:
Capitalized costs and related depreciation, depletion and amortization.................... $ 69,116 $ 87,406
Fixed-Price Contracts and other derivatives............................................... 49,643 --
Other..................................................................................... 39 852
---------- ----------
118,798 88,258
DEFERRED TAX ASSETS:
Deferred revenue and hedging gains........................................................ 5,909 15,519
Fixed-Price Contracts and other derivatives............................................... 2,904 --
Alternative minimum tax credits........................................................... 5,855 5,332
Net operating loss carryforwards.......................................................... 71,691 87,815
Other..................................................................................... 846 1,185
---------- ----------
87,205 109,851
Valuation allowance for net operating loss carryforwards.................................. (33,523) (43,489)
---------- ----------
53,682 66,362
---------- ----------
Net deferred tax liability................................................................ $ 65,116 $ 21,896
---------- ----------
---------- ----------
</TABLE>
At December 31, 1998, the Company had U.S. Federal net operating loss
carryforwards of $202.5 million that expire beginning in 1999 and alternative
minimum tax credit carryforwards of $5.9 million that can be carried forward
indefinitely but which can be used only to reduce regular tax liabilities in
excess of alternative minimum tax liabilities. Net operating loss carryforwards
of $95.8 million are expected to expire without utilization due to the change of
control provisions of Section 382 of the Internal Revenue Code. Such expirations
have been fully reserved through the valuation allowance.
NOTE 7. TRANSACTIONS WITH RELATED PARTIES
FIXED-PRICE CONTRACT ACTIVITY. In 1993, the Company entered into a fixed-price
sales contract with S.A. Louis Dreyfus et Cie hedging 33 Bcf of natural gas over
a five-year period beginning in 1996, at a weighted-average fixed price of $2.49
per Mcf. For the years ended December 31, 1998 and 1996, the Company realized
hedging gains of $2.9 million and $.8 million, respectively, in results of
operations related to this contract. For 1997, the contract resulted in the
recognition of a $.6 million hedging loss.
The Company uses the commodity trading resources of S.A. Louis Dreyfus et
Cie when purchasing natural gas futures contracts on the New York Mercantile
Exchange ("NYMEX"). In that regard, the Company reimburses S.A. Louis Dreyfus et
Cie for margin posted on behalf of the Company. At December 31, 1998 and 1997,
margin of $1.5 million and $4.5 million, respectively, had been posted on the
Company's behalf by S.A. Louis Dreyfus et Cie under this arrangement.
In 1994, the Company entered into a Fixed-Price Contract with S.A. Louis
Dreyfus et Cie which hedged 20 Bcf of natural gas production commencing January
1, 1996. This natural gas swap provided a weighted-average fixed price of
approximately $2.18 per Mcf. In January 1996, the Company canceled this
F-17
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 7. TRANSACTIONS WITH RELATED PARTIES (CONTINUED)
contract and received $1.6 million upon termination. The proceeds were deferred
and amortized into oil and gas sales over the original 19-month term of the
contract.
GENERAL AND ADMINISTRATIVE EXPENSE. The Company is a party to a services
agreement with S.A. Louis Dreyfus et Cie pursuant to which the Company is billed
for certain administrative and support services (principally insurance costs and
services) provided by S.A. Louis Dreyfus et Cie at amounts approximating cost.
General and administrative expenses for the years ended December 31, 1998, 1997
and 1996 include $1.4 million, $.9 million and $.9 million, respectively, for
such services.
OTHER. At December 31, 1998 and 1997, the Company owed S.A. Louis Dreyfus
et Cie approximately $.1 million and $.7 million, respectively, principally for
posted margin and miscellaneous general and administrative expenses. Such
amounts are included in accounts payable in the accompanying balance sheets.
NOTE 8. COMMITMENTS AND CONTINGENCIES
LITIGATION. On December 22, 1995, the United States District Court for the
Western District of Oklahoma entered a $10.8 million judgment in favor of the
Company against Midcon Offshore, Inc. ("Midcon") in connection with
non-performance by Midcon under an agreement to purchase a certain offshore oil
and gas property. In January 1996, Midcon delivered a $10.8 million promissory
note to the Company secured by first and second liens on assets of Midcon,
payable in full on or before December 15, 1996 in settlement of disputes in
connection with this litigation. During 1996, the Company received principal and
interest payments on the promissory note totaling $1.7 million which have been
reflected in the accompanying financial statements as other income. On December
16, 1996, Midcon filed for protection from its creditors under Chapter 11 of the
United States Bankruptcy Code in the United States Bankruptcy Court, Southern
District of Texas, Corpus Christi Division. In January 1997, Midcon filed an
action in the bankruptcy court alleging that Midcon's action in connection with
the settlement constituted fraudulent transfers or avoidable preferences, and
seeking a return of amounts paid and a release of the liens securing the payment
obligation under the note. The complaint filed in the action also alleged
certain affirmative claims against the Company including injury to reputation
and loss of business opportunity. The complaint also seeks subordination of the
Company's claim. The Court denied the Company's motion to dismiss the complaint.
The Company considers the allegations of the complaint to be without merit and
will vigorously defend against this action. Collection of unpaid interest and
principal on the Midcon note is uncertain and no amounts have been recorded with
respect thereto in the accompanying financial statements as of December 31,
1998. The Company will recognize income as any payments are received.
In February 1995, a lawsuit was filed in the United States District Court in
Denver, Colorado, by KN Gas Supply Services, Inc. ("KNGSS"), requesting
declaratory judgment that KNGSS had the right to reduce the contract price for
gas produced from the Bowdoin Field, a property obtained in the American
Acquisition, to market levels from October 1, 1993 forward. KNGSS alleges that
it has overpaid American and seeks a refund of approximately $7.7 million for
the period through September 1996. KNGSS has not updated its refund claim
through the present date. A motion for summary judgment was filed by American in
July 1996 and was argued before the court in February 1997. The Company assumed
responsibility for this lawsuit in connection with the American Acquisition. In
February 1998, the court ruled in favor of the Company's motion. KNGSS
subsequently filed an appeal which has not been heard. Although the Company
cannot predict the ultimate outcome of this proceeding, it will continue to
vigorously defend its
F-18
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 8. COMMITMENTS AND CONTINGENCIES (CONTINUED)
interests in this case and does not expect the outcome of the case to have a
material adverse impact on its financial position or results of operations.
American was a defendant in various other legal proceedings for which the
Company also assumed responsibility in the American Acquisition. The largest of
such legal claims was for an alleged underpayment of royalty of $5.5 million
plus interest. In addition, American had received preliminary and final royalty
underpayment determinations from the Minerals Management Service aggregating
approximately $2.8 million plus interest in connection with certain gas contract
settlements made in prior years. The Company is a defendant in additional
pending legal proceedings which are routine and incidental to its business.
While the ultimate results of all these proceedings and determinations cannot be
predicted with certainty, the Company will vigorously defend its interests and
does not believe that the outcome of these matters will have a material adverse
effect on the Company.
RENTAL COMMITMENTS. Minimum annual rental commitments as of December 31,
1998 under noncancelable office space leases are as follows: 1999--$3.1 million;
2000--$3.0 million; 2001--$2.2 million; 2002 and thereafter--$2.2 million.
Approximately $3.8 million of such rental commitments is included in other
long-term liabilities as of December 31, 1998, presented net of estimated future
rental income to be received of $1.0 million. Rent expense included in results
of operations for the three years ended December 31, 1998, 1997 and 1996 was
$2.1 million, $1.1 million and $.9 million, respectively.
NOTE 9. EMPLOYEE BENEFIT PLANS
401(K) PLAN. The Company's employees who have completed a specified term of
service are eligible for participation in the Louis Dreyfus Natural Gas Profit
Sharing and 401(k) Plan and Trust Agreement (the "401(k) Plan"). Pursuant to the
plan provisions, employee contributions can be made up to 17% of compensation.
Company contributions are discretionary. Employees vest in Company contributions
at 20% per year of service. For the years ended December 31, 1998, 1997 and
1996, the Company contributed $1.2 million, $.9 million and $.9 million,
respectively, to the 401(k) Plan.
STOCK COMPENSATION PLANS. Certain executive officers of the Company were
participants in the Louis Dreyfus Deferred Compensation Stock Equivalent Plan
sponsored by S.A. Louis Dreyfus et Cie ("Stock Equivalent Plan"). Under this
plan, participants were awarded stock equivalent rights ("SERs") expressed as a
number of stock equivalent units. At December 31, 1997 and 1996, SERs totaling
83,500 and 85,000 stock equivalent units, respectively, were outstanding.
Recorded compensation expense attributable to the SERs was approximately $.4
million for each of the years ended December 31, 1997 and 1996. In 1998, the
Stock Equivalent Plan was terminated and replaced with the Louis Dreyfus Natural
Gas Corp. Deferred Stock Trust Agreement ("Trust Agreement"). The Trust
Agreement establishes a trust which serves as a depositary for restricted stock
awards granted pursuant to the Trust Agreement. An aggregate of 55,000 shares
previously earned under the Stock Equivalent Plan were purchased by the Company
and contributed to the trust for distribution upon termination of employment or
other specified events, thus eliminating the Company's obligations under the
Stock Equivalent Plan. These transactions resulted in a net reduction to
compensation expense of $.6 million after consideration for amounts previously
recorded in connection with the Stock Equivalent Plan. Also during 1998, a
separate deferred stock trust agreement was established to create a compensation
program for the services of non-employee directors of the Company. In connection
therewith, the Company purchased and contributed 8,000 shares of restricted
stock during 1998.
F-19
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 9. EMPLOYEE BENEFIT PLANS (CONTINUED)
Officers, directors and certain key employees have been granted options to
purchase the Company's Common Stock under its 1993 Stock Option Plan (the
"Option Plan"). Under the Option Plan, the Company may grant both incentive
stock options intended to qualify under Section 422 of the Internal Revenue Code
and options which are not qualified as incentive stock options. The maximum
number of shares of Common Stock issuable under the Option Plan is 3.0 million
shares, subject to appropriate equitable adjustment in the event of a
reorganization, stock split, stock dividend, reclassification or other change
affecting the Company's Common Stock. As of December 31, 1998 and 1997, options
to purchase 875,420 shares and 291,670 shares of Common Stock, respectively,
were available for grant under the Option Plan. Options granted under the Option
Plan vest over a period of time based on the nature of the grants and as defined
in the individual grant agreements, but generally over a four to five-year
period. The exercise price of each option, with certain exceptions, equals the
market price of the Company's stock on the date of grant and an option's
expiration date is ten years from the date of issuance.
The following pro forma information, as required by Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS
123"), presents net income and earnings per share information as if the Company
had accounted for stock options issued after December 31, 1994 using the fair
value method prescribed by that statement. The fair value of issued stock
options was estimated at the date of grant using a Black-Scholes option pricing
model. Valuation assumptions for option grants in 1998, 1997 and 1996 included
the following: risk-free interest rates of 4.9%, 5.7% and 6.6%, respectively; no
dividends over the option term; stock price volatility factors of .36, .32 and
.31, respectively, and a weighted average expected option life of five years.
The estimated fair value as determined by the model is amortized to expense over
the respective vesting period. The SFAS 123 pro forma information presented
below is not necessarily indicative of the pro forma effects to be presented in
future periods. Additionally, option awards made prior to 1995 have been
excluded.
The SFAS 123 pro forma information is as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
---------- ---------- ---------
<S> <C> <C> <C>
(IN THOUSANDS, EXCEPT PER SHARE
DATA)
Net income (loss)........................................................... $ (45,962) $ (16,981) $ 20,698
Net income (loss) per share................................................. (1.15) (.56) .74
</TABLE>
The Black-Scholes option valuation model was developed for use in estimating
the fair value of traded options which have no vesting restrictions and are
fully transferable. In addition, option valuation models require the input of
highly subjective assumptions including the expected stock price volatility.
Because the Company's employee stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in Management's
opinion, the existing models do not necessarily provide a reliable single
measure of fair value of its stock options.
F-20
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 9. EMPLOYEE BENEFIT PLANS (CONTINUED)
Stock option transactions for 1998, 1997 and 1996 are summarized as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------------------------------------------------------
1998 1997 1996
--------------------------- --------------------------- -------------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
------------ ------------- ------------ ------------- ---------- -------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year... 1,708,330 $ 19.03 993,250 $ 15.98 792,000 $ 16.42
Granted............................ 1,054,750 15.51 806,080 22.46 212,000 14.39
Exercised.......................... (22,500) 15.05 (30,500) 16.18 (750) 13.69
Canceled........................... (616,000) 20.68 (60,500) 16.02 (10,000) 16.71
------------ ------------ ----------
Outstanding at end of year......... 2,124,580 17.27 1,708,330 19.03 993,250 15.98
------------ ------------ ----------
------------ ------------ ----------
Exercisable at end of year......... 909,830 17.27 722,330 16.91 469,000 17.08
------------ ------------ ----------
------------ ------------ ----------
Weighted-average fair value of
options granted during year(1)... $ 6.17 $ 8.79 $ 5.71
------------ ------------ ----------
------------ ------------ ----------
</TABLE>
- ------------------------
(1) Excludes for 1997 the fair value of options to purchase 53,330 shares issued
in connection with the American Acquisition and recorded as part of the
corresponding purchase price. See Note 4-- Acquisitions.
Outstanding options to acquire .9 million shares of stock at December 31,
1998 had exercise prices ranging from $18.00 to $23.16 per share and had a
weighted-average remaining contractual life of 6.9 years. The balance of options
outstanding at December 31, 1998 had exercise prices ranging from $12.63 to
$17.71 per share and a weighted-average remaining contractual life of 8.8 years.
NOTE 10. SIGNIFICANT CUSTOMERS
The Company's oil and gas sales at the wellhead are sold under contracts
with various purchasers. For the year ended December 31, 1998, gas sales to PG&E
Texas Industrial Energy, L.P. approximated 20% of total revenues. For the year
ended December 31, 1997, gas sales to PG&E Texas Industrial Energy, L.P., Enron
Capital and Trade Resources and GPM Gas Corporation approximated 22%, 15% and
10% of total revenues, respectively. For the year ended December 31, 1996, gas
sales to Valero Industrial Gas, L.P., HPL Resources Corp. and GPM Gas
Corporation approximated 18%, 13% and 11% of total revenues, respectively. The
Company believes that alternative purchasers are available, if necessary, to
purchase its production at prices substantially similar to those received from
these significant purchasers in 1998.
F-21
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 11. CAPITAL STOCK AND STOCKHOLDERS' EQUITY INFORMATION
COMMON STOCK. The following table sets forth the Company's Common Stock
activity for the periods presented:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
(IN THOUSANDS)
COMMON STOCK ACTIVITY:
Balance, beginning of year........................................................... 40,088 27,801 27,800
Exercise of stock options............................................................ 22 30 1
Shares issued in the American Acquisition............................................ -- 11,316 --
Shares issued on conversion of Preferred Stock....................................... -- 941 --
--------- --------- ---------
Balance, end of year................................................................. 40,110 40,088 27,801
--------- --------- ---------
--------- --------- ---------
</TABLE>
PREFERRED STOCK. In October 1997, in connection with the American
Acquisition, the Company issued 800,000 depositary shares representing a 1/200
interest in a share of $450 Cumulative Convertible Preferred Stock ("Preferred
Stock") to the holders of American preferred stock. In December 1997, in
connection with the Company's redemption offer for the Preferred Stock at $26.35
per depositary share, holders of 783,675 depositary shares elected to convert
into 940,649 shares of Common Stock and $3.9 million of cash. The remaining
depositary shares were redeemed on December 31, 1997 for an aggregate cash
payment of $.4 million.
WARRANTS. At December 31, 1998, the Company had outstanding warrants to
purchase 1.6 million shares of Common Stock, all of which are currently
exercisable, issued in connection with the American Acquisition for the
outstanding warrants of American. The associated exercise prices range from
$17.47 to $23.06 per share. Warrants to purchase .4 million shares expire April
1999; the balance expire December 2004.
OTHER COMPREHENSIVE INCOME. The components of other comprehensive income
and related tax effects for the year ended December 31, 1998 are shown as
follows:
<TABLE>
<CAPTION>
TAX NET OF
GROSS EFFECT TAX
---------- --------- ---------
<S> <C> <C> <C>
Cumulative effect of accounting change.......................................... $ 157,550 $ 59,869 $ 97,681
Reclassification adjustments--contract settlements.............................. (7,147) (2,716) (4,431)
---------- --------- ---------
$ 150,403 $ 57,153 $ 93,250
---------- --------- ---------
---------- --------- ---------
</TABLE>
F-22
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 12. SUPPLEMENTAL STATEMENT OF CASH FLOWS INFORMATION
In October 1997, LDNG issued Common Stock, Preferred Stock, warrants and
options and cash in connection with the American Acquisition. The accompanying
financial statements include the following amounts attributable to the acquired
assets and liabilities of American:
<TABLE>
<CAPTION>
AMERICAN
ACQUISITION
-------------
<S> <C>
(IN
THOUSANDS)
Value allocated to the oil and gas properties of American...................... $ 437,920
Other non-cash assets acquired................................................. 3,176
Working capital acquired....................................................... 3,874
Long-term debt assumed......................................................... (123,621)
Other liabilities assumed...................................................... (23,606)
Common Stock issued............................................................ (194,077)
Preferred Stock issued......................................................... (21,080)
Warrants and options issued.................................................... (10,263)
-------------
Cash paid, including cash overdrafts assumed................................... $ 72,323
-------------
-------------
</TABLE>
For the years ended December 31, 1998, 1997 and 1996, the Company paid
interest of $38.3 million, $25.8 million and $25.3 million, respectively, net of
capitalized interest, and paid income taxes of $.3 million, $1.0 million and
$1.4 million, respectively.
See Note 1--Significant Accounting Policies--Property and Equipment.
NOTE 13. FINANCIAL INSTRUMENTS
The following information is provided regarding the estimated fair value of
the financial instruments, including derivative assets and liabilities as
defined by SFAS 133, employed by the Company as of
F-23
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 13. FINANCIAL INSTRUMENTS (CONTINUED)
December 31, 1998 and 1997, and the methods and assumptions used to estimate the
fair value of such financial instruments:
<TABLE>
<CAPTION>
DECEMBER 31, 1998 DECEMBER 31, 1997
------------------------ ------------------------
CARRYING FAIR CARRYING FAIR
AMOUNT(1) VALUE AMOUNT VALUE
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
(IN THOUSANDS)
DERIVATIVE ASSETS:
Fixed-price natural gas swaps:
Sales contracts.......................................... $ 26,125 $ 26,125 $ 76 $ 20,000
Purchase contracts....................................... 905 905 -- 2,000
Fixed-price natural gas collars............................ 3,367 3,367 -- --
Fixed-price natural gas physical delivery contracts........ 99,342 99,342 1,138 166,000
Natural gas basis swaps.................................... 74 74 -- 1,500
Fixed-price crude oil swaps................................ N/A N/A -- --
Interest rate swaps--fixed................................. 827 827 -- --
Interest rate swaps--floating.............................. N/A N/A -- 1,000
DERIVATIVE LIABILITIES:
Fixed-price natural gas swaps--sales contracts............. (551) (551) -- (2,000)
Fixed-price natural gas physical delivery contracts........ (2,920) (2,920) -- --
Natural gas basis swaps.................................... (3,734) (3,734) -- (500)
Interest rate swaps--fixed................................. (437) (437) -- (1,000)
Bank debt(2)................................................. (297,200) (297,200) (265,500) (265,500)
6 7/8% Senior Notes due 2007(2).............................. (198,912) (187,704) (198,791) (199,714)
9 1/4% Senior Subordinated Notes due 2004(2)................. (100,732) (102,897) (99,053) (108,235)
</TABLE>
- ------------------------
(1) The Company adopted the provisions of SFAS 133 as of October 1, 1998
pursuant to which the fair value of the Company's derivative instruments are
recorded as assets and liabilities in the balance sheet. See Note
1--Significant Accounting Policies--Hedging.
(2) Carrying amounts do not include capitalized debt issuance costs. See Note
1--Significant Accounting Policies--Debt Issuance Costs.
Cash and cash equivalents, accounts receivable, deposits, accounts payable,
revenues payable and accrued liabilities were each estimated to have a fair
value approximating the carrying amount due to the short maturity of those
instruments or to the criteria used to determine carrying value in the financial
statements.
The fair value of Fixed-Price Contracts as of December 31, 1998 and 1997 was
estimated based on market prices of natural gas and crude oil for the periods
covered by the contracts. The net differential between the prices in each
contract and market prices for future periods, as adjusted for estimated basis,
has been applied to the volumes stipulated in each contract to arrive at an
estimated future value. As of December 31, 1998, in connection with the adoption
of SFAS 133, this estimated future value was discounted on a
contract-by-contract basis at rates commensurate with the Company's estimation
of contract performance risk and counterparty credit risk. For December 31, 1997
(prior to the adoption of SFAS 133), the Company discounted the future value at
a rate of 10%, which the Company believed to be a reasonable estimate of fair
value at that date. The terms and conditions of the Company's fixed-price
F-24
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 13. FINANCIAL INSTRUMENTS (CONTINUED)
physical delivery contracts and certain financial swaps are uniquely tailored to
the Company's circumstances. In addition, certain of the Company's contracts
hedge gas production for periods beyond five years into the future. The market
for natural gas beyond the five year horizon is illiquid and published market
quotations are not available. The Company has relied upon near-term market
quotations, longer-term over-the-counter market quotations and other market
information to determine its fair value estimates. The Fixed-Price Contract fair
value as reflected in the balance sheet as of December 31, 1998 does not
necessarily represent the value a third party would pay to assume the Company's
positions. For 1998, short-term and long-term derivative assets are presented in
the accompanying balance sheet under the caption "Fixed-price contracts and
other derivatives" in Current Assets and Other Assets, respectively. Short-term
and long-term derivative liabilities are presented in the 1998 balance sheet as
"Accrued liabilities" in Current Liabilities and as "Other" in Deferred Credits
and Other Liabilities, respectively. Derivative assets and liabilities prior to
1998 were not reflected in the Company's balance sheet.
The Company's bank debt bears interest at rates which move with market
interest rates. Accordingly, the fair value of such debt at December 31, 1998
and 1997 was estimated to approximate the carrying amount. The fair values of
the 6 7/8% Senior Notes due 2007 and the 9 1/4% Senior Subordinated Notes due
2004 were determined based on market quotations for such securities. The fair
value of the Company's interest rate swaps for each of the years presented was
determined by using a third-party interest rate swap valuation model or by
reliance upon third-party quotations. Such valuations are based on market
interest rates as of the determination date.
NOTE 14. FIXED-PRICE CONTRACTS
DESCRIPTION OF CONTRACTS. The Company has entered into Fixed-Price
Contracts to reduce its exposure to unfavorable changes in oil and gas prices
which are subject to significant and often volatile fluctuation. The Company's
Fixed-Price Contracts are comprised of long-term physical delivery contracts,
energy swaps, collars, futures contracts and basis swaps. These contracts allow
the Company to predict with greater certainty the effective oil and gas prices
to be received for its hedged production and benefit the Company when market
prices are less than the fixed prices provided in its Fixed-Price Contracts.
However, the Company will not benefit from market prices that are higher than
the fixed prices in such contracts for its hedged production. For the years
ended December 31, 1998, 1997 and 1996, Fixed-Price Contracts hedged 50%, 60%
and 51%, respectively, of the Company's gas production and 16%, 33% and 67%,
respectively, of its oil production. As of December 31, 1998, Fixed-Price
Contracts are in place as economic hedges of 244 Bcf of the Company's estimated
future gas production. See Note 2--Restatement of 1998 Financial Statements.
For energy swap sales contracts, the Company receives a fixed price for the
respective commodity and pays a floating market price, as defined in each
contract (generally NYMEX futures prices or a regional spot market index), to
the counterparty. Under energy swap purchase contracts, the Company pays a fixed
price for the commodity and receives a floating market price. In both types of
energy swaps, the fixed-price payment and the floating-price payment are netted,
resulting in a net amount due to or from the counterparty. For physical delivery
contracts, the Company purchases gas in the spot market at floating market
prices and delivers such gas to the contract counterparty at a fixed price. The
Company's natural gas collars contain a fixed floor price (put) and ceiling
price (call). If the market price of natural gas exceeds the call strike price
or falls below the put strike price, then the Company receives the fixed price
and pays the market price. If the market price of natural gas is between the
call and the put strike price,
F-25
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 14. FIXED-PRICE CONTRACTS (CONTINUED)
then no payments are due from either party. Under the Company's basis swaps, the
Company receives the floating market price for NYMEX futures and pays the
floating market price plus a fixed differential for a specified regional spot
market index.
The following table summarizes the estimated volumes, fixed prices,
fixed-price sales, fixed-price purchases and future net revenues attributable to
the Company's Fixed-Price Contracts as of December 31, 1998. The Company expects
the prices to be realized for its hedged production to vary from the prices
shown in the following table due to basis, which is the differential between the
floating price paid under each energy swap contract, or the cost of gas to
supply physical delivery contracts, and the price received at the wellhead for
the Company's production. Basis differentials are caused by differences in
location, quality, contract terms, timing and other variables. Future net
revenues for any period are determined as the differential between the fixed
prices provided by Fixed-Price Contracts and forward market prices as of
December 31, 1998, as adjusted for basis. Future net revenues change with
changes in market prices and basis. See "--Market Risk."
<TABLE>
<CAPTION>
YEARS ENDING DECEMBER 31, BALANCE
-------------------------------------------- THROUGH
1999 2000 2001 2002 2003 2017 TOTAL
-------- ------- ------- ------- ------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
NATURAL GAS SWAPS:
SALES CONTRACTS
Contract volumes (BBtu)................................ 15,825 9,830 7,475 6,405 5,650 17,783 62,968
Weighted-average fixed price per MMBtu(1).............. $ 2.44 $ 2.46 $ 2.47 $ 2.67 $ 2.92 $ 3.29 $ 2.75
Future fixed-price sales............................... $ 38,629 $24,164 $18,446 $17,098 $16,492 $ 58,429 $173,258
Future net revenues(2)................................. $ 7,251 $ 2,441 $ 1,792 $ 2,648 $ 3,534 $ 15,576 $ 33,242
PURCHASE CONTRACTS
Contract volumes (BBtu)................................ (10,950) -- -- -- -- -- (10,950)
Weighted-average fixed price per MMBtu(1).............. $ 2.18 $ -- $ -- $ -- $ -- $ -- $ 2.18
Future fixed-price purchases........................... $(23,880) $ -- $ -- $ -- $ -- $ -- $(23,880)
Future net revenues(2)................................. $ 939 $ -- $ -- $ -- $ -- $ -- $ 939
NATURAL GAS PHYSICAL DELIVERY CONTRACTS:
Contract volumes (BBtu)................................ 24,144 22,678 23,240 23,115 20,245 71,483 184,905
Weighted-average fixed price per MMBtu(1).............. $ 2.76 $ 2.94 $ 3.06 $ 3.21 $ 3.47 $ 4.32 $ 3.56
Future fixed-price sales............................... $ 66,682 $66,675 $71,109 $74,150 $70,292 $308,529 $657,437
Future net revenues(2)................................. $ 13,574 $14,495 $17,246 $19,770 $21,076 $102,688 $188,849
NATURAL GAS COLLARS:
Contract volumes (BBtu):
Floor................................................ 7,300 -- -- -- -- -- 7,300
Ceiling.............................................. 14,600 -- -- -- -- -- 14,600
Weighted-average fixed-price per MMBtu(1):
Floor................................................ $ 2.41 $ -- $ -- $ -- $ -- $ -- $ 2.41
Ceiling.............................................. $ 2.78 $ -- $ -- $ -- $ -- $ -- $ 2.78
</TABLE>
F-26
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 14. FIXED-PRICE CONTRACTS (CONTINUED)
<TABLE>
<CAPTION>
YEARS ENDING DECEMBER 31, BALANCE
-------------------------------------------- THROUGH
1999 2000 2001 2002 2003 2017 TOTAL
-------- ------- ------- ------- ------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
Future fixed-price sales............................... $ 17,599 $ -- $ -- $ -- $ -- $ -- $ 17,599
Future net revenues(2)................................. $ 3,367 $ -- $ -- $ -- $ -- $ -- $ 3,367
TOTAL NATURAL GAS CONTRACTS(3):
Contract volumes (BBtu)................................ 36,319 32,508 30,715 29,520 25,895 89,266 244,223
Weighted-average fixed price per MMBtu(1).............. $ 2.73 $ 2.79 $ 2.92 $ 3.09 $ 3.35 $ 4.11 $ 3.38
Future fixed-price sales............................... $ 99,030 $90,839 $89,555 $91,248 $86,784 $366,958 $824,414
Future net revenues(2)................................. $ 25,131 $16,936 $19,038 $22,418 $24,610 $118,264 $226,397
</TABLE>
- --------------------------
(1) The Company expects the prices to be realized for its hedged production to
vary from the prices shown due to basis. See "Market Risk."
(2) Future net revenues as presented above are undiscounted and have not been
adjusted for contract performance risk or counterparty credit risk. See Note
13--Financial Instruments.
(3) Does not include basis swaps with notional volumes by year, as follows:
1999--19.0 TBtu; 2000--21.3 TBtu; 2001--9.4 TBtu; and 2002--5.5 TBtu.
The estimates of future net revenues from the Company's Fixed-Price
Contracts are computed based on the difference between the prices provided by
the Fixed-Price Contracts and forward market prices as of the specified date.
The market for natural gas beyond a five year horizon is illiquid and published
market quotations are not available. The Company has relied upon near-term
market quotations, longer-term over-the-counter market quotations and other
market information to determine its future net revenue estimates. Forward market
prices for natural gas are dependent upon supply and demand factors in such
forward market and are subject to significant volatility. The future net revenue
estimates shown above are subject to change as forward market prices change. See
Note 13--Financial Instruments for estimated fair value information.
ACCOUNTING. All of the Company's Fixed-Price Contracts have been executed
in connection with its natural gas and crude oil hedging program. For
Fixed-Price Contracts qualifying as hedges pursuant to SFAS 133, the
differential between the fixed price and the floating price for each contract
settlement period multiplied by the associated contract volumes is the contract
profit or loss. The realized contract profit or loss is included in oil and gas
sales in the period for which the underlying commodity was hedged. Changes in
market value for these contracts for volumes not yet settled are not reflected
in the Company's income statements, but rather are shown as adjustments to other
comprehensive income. For those contracts not qualifying as hedges, the
associated fair value, as well as future changes in market value, are recognized
in earnings. The fair value of all of its Fixed-Price Contracts are recorded as
assets or liabilities in the Company's balance sheet. See Note 2--Restatement of
1998 Financial Statements.
If a Fixed-Price Contract which qualified for hedge accounting is liquidated
or sold prior to maturity, the gain or loss at the time of termination remains
in accumulated other comprehensive income to be amortized into oil and gas sales
over the original term of the contract. At December 31, 1998, the Company had
pretax unamortized deferred gains of $61.3 million related to terminated
contracts which were recorded net of deferred tax effects in accumulated other
comprehensive income. Prior to the adoption of SFAS 133, the Company recorded
gains and losses from contract terminations as deferred liabilities and assets,
respectively. At December 31, 1997, the balance of deferred gains from
price-risk
F-27
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 14. FIXED-PRICE CONTRACTS (CONTINUED)
management activities was $23.5 million. Prepayments received under Fixed-Price
Contracts with continuing performance obligations are recorded as deferred
revenue and amortized into oil and gas sales over the term of the underlying
contract. See Note 1--Significant Accounting Policies--Hedging.
For the years ended December 31, 1998, 1997 and 1996, oil and gas sales
included $23.1 million of net gains, $4.3 million of net losses and $2.1 million
of net losses, respectively, associated with realized gains and losses under its
Fixed-Price Contracts.
CREDIT RISK. Fixed-Price Contract terms generally provide for monthly
settlements and energy swaps provide for a net settlement due to or from the
respective party as discussed previously. The counterparties to the contracts
are comprised of independent power producers, pipeline marketing affiliates,
financial institutions, a municipality and S.A. Louis Dreyfus et Cie, among
others. In some cases, the Company requires letters of credit or corporate
guarantees to secure the performance obligations of the contract counterparty.
Should a counterparty to a contract default on a contract, there can be no
assurance that the Company would be able to enter into a new contract with a
third party on terms comparable to the original contract. The Company has not
experienced non-performance by any counterparty.
The Company was a party to two Fixed-Price Contracts, both long-term
physical delivery contracts, with independent power producers ("IPPs") which
sold electrical power under firm, fixed-price contracts to Niagara Mohawk
Corporation ("NIMO"), a New York state utility ("NIMO Contracts"). The ability
of these IPPs to perform their obligations to the Company was dependent on the
continued performance by NIMO of its power purchase obligations to the
counterparties. NIMO has taken aggressive regulatory, judicial and contractual
actions in recent years seeking to curtail power purchase obligations, including
its obligations to the NIMO Contract counterparties, and had further stated that
its future financial prospects were dependent on its ability to resolve these
obligations, along with other matters. In July 1997, NIMO entered into a Master
Restructuring Agreement (the "MRA") with 16 IPPs, including the NIMO Contract
counterparties. Subsequently, one of the NIMO Contract counterparties withdrew
from the MRA. The power purchase agreement between NIMO and the other
counterparty was terminated. In connection therewith, the Company agreed to
terminate its fixed-price contract to the counterparty in exchange for $40.1
million, the receipt of which has been recorded in accumulated other
comprehensive income, net of tax effect. The remaining NIMO Contract which
hedges 54 Bcf of natural gas as of December 31, 1998 remains in force and is
reflected in the Company's balance sheet at a fair value of $72 million. The
Company continues to deliver natural gas pursuant to the terms of this contract
which expires in 2007. NIMO has continued to seek relief from its contractual
obligations under this contract in the court system. Although there can be no
assurance, Management does not expect that NIMO will ultimately succeed in these
efforts.
Cancellation or termination of a Fixed-Price contract would subject a
greater portion of the Company's gas production to market prices, which, in a
low price environment, could have an adverse effect on the Company's future
operating results. In addition, the associated carrying value of the contract
would be removed from the Company's balance sheet. Any associated proceeds from
a Fixed-Price Contract which qualified for hedge accounting would be reflected
in accumulated other comprehensive income, net of income tax effects, and
amortized into earnings over the original contract term.
MARKET RISK. The Company's natural gas Fixed-Price Contracts at December
31, 1998 hedge 244 Bcf of proved natural gas reserves at fixed prices,
representing 20% of its estimated proved natural gas reserves. If the Company's
proved natural gas reserves are produced at rates less than anticipated, Fixed-
F-28
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 14. FIXED-PRICE CONTRACTS (CONTINUED)
Price Contract volumes could exceed production volumes. In such case, the
Company would be required to satisfy its contractual commitments for any excess
volumes at market prices in effect for each settlement period, which may be
above the contract price, without a corresponding offset in wellhead revenue.
The Company expects future production volumes to be equal to or greater than the
volumes provided in its contracts.
The differential between the floating price paid under each energy swap
contract, or the cost of gas to supply physical delivery contracts, and the
price received at the wellhead for the Company's production is termed "basis"
and is the result of differences in location, quality, contract terms, timing
and other variables. The effective price realizations which result from the
Company's Fixed-Price Contracts are affected by movements in basis. For the
years ended December 31, 1998, 1997 and 1996, the Company received on an Mcf
basis approximately 6%, 1% and 3% less than the prices specified in its natural
gas Fixed-Price Contracts, respectively, due to basis. For its oil production
hedged by crude oil Fixed-Price Contracts, the Company realized approximately
10%, 4% and 4% less than the specified contract prices for such years,
respectively. Basis movements can result from a number of variables, including
regional supply and demand factors, changes in the Company's portfolio of
Fixed-Price Contracts and the composition of the Company's producing property
base. Basis movements are generally considerably less than the price movements
affecting the underlying commodity, but their effect can be significant. A 1%
move in price realization for hedged natural gas in 1999 represents a $1.0
million change in gas sales. The Company actively manages its exposure to basis
movements and from time to time will enter into contracts designed to reduce
such exposure.
Except for the effect of basis movements, the Company expects that any
changes in Fixed-Price Contract fair value attributable to changes in market
prices for natural gas will be offset by changes in the value of its natural gas
reserves. This change in natural gas reserve value, however, is not reflected in
the Company's balance sheet. Further, changes in future gains and losses to be
realized in oil and gas sales upon future settlements of Fixed-Price Contracts
as a result of changes in market prices for natural gas are expected to be
offset by changes in the price received for the Company's hedged natural gas
production.
MARGIN. The Company is required to post margin in the form of bank letters
of credit or treasury bills under certain of its Fixed-Price Contracts. In some
cases, the amount of such margin is fixed; in others, the amount changes as the
market value of the respective contract changes, or if certain financial tests
are not met. For the years ended December 31, 1998, 1997 and 1996, the maximum
aggregate amount of margin posted by the Company was $23.7 million, $28.7
million and $28.4 million, respectively. If natural gas prices were to rise, or
if the Company fails to meet the financial tests contained in certain of its
Fixed-Price Contracts, margin requirements could increase significantly. The
Company believes that it will be able to meet such requirements through the
Credit Facility and such other credit lines that it has or may obtain in the
future. If the Company is unable to meet its margin requirements, a contract
could be terminated and the Company could be required to pay damages to the
counterparty which generally approximate the cost to the counterparty of
replacing the contract. At December 31, 1998, the Company had issued margin in
the form of letters of credit and treasury bills totaling $17.0 million and $1.5
million, respectively. In addition, approximately 29 Bcf of the Company's proved
gas reserves are mortgaged to a Fixed-Price Contract counterparty, securing the
Company's performance under the associated contract.
F-29
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 15. SUPPLEMENTAL INFORMATION--OIL AND GAS RESERVES (UNAUDITED)
The following information summarizes the Company's net proved reserves of
crude oil and natural gas and the present values thereof for the three years
ended December 31, 1998, 1997 and 1996. Reserve estimates for these years have
been prepared by the Company's petroleum engineers and reviewed by an
independent engineering firm. All studies have been prepared in accordance with
regulations prescribed by the Securities and Exchange Commission. Future net
revenue is estimated by such engineers using oil and gas prices in effect as of
the end of each respective year with price escalations permitted only for those
properties which have wellhead contracts allowing specific increases. Future
operating costs estimated in each study are based on historical operating costs
incurred. Reserve quantity estimates are calculated without regard to prices in
the Company's Fixed-Price Contracts.
The reliability of any reserve estimate is a function of the quality of
available information and of engineering interpretation and judgment. Such
estimates are susceptible to revision in light of subsequent drilling and
production history or as a result of changes in economic conditions.
ESTIMATED QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED). The following
table sets forth the Company's estimated proved reserves, all of which are
located in the United States, for the years ended December 31, 1998, 1997 and
1996. Proved reserves are the estimated quantities of oil and gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that are
expected to be recovered through existing wells with existing equipment and
operating methods.
<TABLE>
<CAPTION>
1998 1997 1996
----------------------- ----------------------- ----------------------
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
----------- ---------- ----------- ---------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C>
PROVED RESERVES:
Beginning of year.............................. 29,109 1,028,752 23,497 849,199 20,360 753,919
Acquisition of proved reserves................. 166 6,270 11,679 163,651 2,173 62,497
Extensions and discoveries..................... 1,943 246,382 1,271 116,919 2,643 76,873
Revisions of previous estimates(1)............. (3,165) 19,974 263 (26,345) 335 19,939
Sales of reserves in place..................... (207) (6,646) (5,512) (2,941) (165) (119)
Production..................................... (3,430) (101,066) (2,089) (71,731) (1,849) (63,910)
----------- ---------- ----------- ---------- ----------- ---------
End of year.................................... 24,416 1,193,666 29,109 1,028,752 23,497 849,199
----------- ---------- ----------- ---------- ----------- ---------
----------- ---------- ----------- ---------- ----------- ---------
PROVED DEVELOPED RESERVES:
Beginning of year.............................. 24,321 899,196 17,894 709,712 14,839 630,604
----------- ---------- ----------- ---------- ----------- ---------
----------- ---------- ----------- ---------- ----------- ---------
End of year.................................... 20,722 1,026,834 24,321 899,196 17,894 709,712
----------- ---------- ----------- ---------- ----------- ---------
----------- ---------- ----------- ---------- ----------- ---------
</TABLE>
- ------------------------
(1) The crude oil volume revision for 1998 was primarily the result of a
significant reduction in year-end 1998 crude oil prices compared to the
prior year-end.
F-30
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 15. SUPPLEMENTAL INFORMATION--OIL AND GAS RESERVES (UNAUDITED) (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED). The
following table reflects the standardized measure of discounted future net cash
flows relating to the Company's interests in proved oil and gas reserves. The
future net cash inflows were developed as follows:
(1) Estimates were made of quantities of proved reserves and the future periods
in which they are expected to be produced based on year-end economic
conditions.
(2) The estimated cash flows from future production of proved reserves were
prepared using year-end prices for each respective year, as adjusted for the
Company's Fixed-Price Contracts in effect at each respective year-end, as
follows: 1998--$9.46 per Bbl, $2.30 per Mcf; 1997--$16.77 per Bbl, $2.73 per
Mcf; and 1996--$24.66 per Bbl, $3.55 per Mcf.
(3) The resulting future gross revenue streams were reduced by estimated future
costs to develop and to produce the proved reserves and estimated
abandonment costs for offshore properties, based on year-end estimates.
(4) Future income taxes were computed by applying the appropriate statutory tax
rates to the future pretax net cash flows less the current tax basis of the
properties involved and related carryforwards, giving effect to permanent
differences and tax credits.
(5) The resulting future net revenue streams were reduced to present value
amounts by applying a 10% discount factor.
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------------
1998 1997 1996
------------ ------------ -------------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows(1)................................................. $ 2,974,575 $ 3,291,773 $ 3,596,493
Future production costs................................................ (870,420) (985,639) (1,053,989)
Future development costs............................................... (148,595) (136,217) (125,074)
Future income taxes.................................................... (371,076) (438,183) (704,818)
------------ ------------ -------------
1,584,484 1,731,734 1,712,612
Discount at 10% per year............................................... (745,828) (774,993) (909,168)
------------ ------------ -------------
Standardized measure of discounted future net cash flows(1)(2)......... $ 838,656 $ 956,741 $ 803,444
------------ ------------ -------------
------------ ------------ -------------
</TABLE>
- ------------------------
(1) Future cash inflows and the standardized measure of discounted future net
cash flows include the expected cash flow contribution of the Company's
Fixed-Price Contracts based on year-end oil and gas prices. Such future cash
inflows have not been adjusted for contract performance risk or counterparty
credit risk. See Note 13--Financial Instruments.
(2) The standardized measure of discounted future net cash flows excluding the
effect of the Company's Fixed-Price Contracts was $719.7 million, $873.5
million and $922.6 million as of December 31, 1998, 1997 and 1996,
respectively.
The standardized measure information in the preceding table was derived from
estimates of the Company's proved oil and gas reserves contained in studies
prepared by petroleum engineers. The standardized measure calculation, prepared
pursuant to the provisions of Statement of Financial Accounting Standards No.
69, does not purport to represent the fair market value of the Company's oil and
gas reserves. The foregoing information is presented for comparative purposes as
of the Company's year-end and is not intended to reflect any changes in value
which may result from future price fluctuations.
F-31
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 15. SUPPLEMENTAL INFORMATION--OIL AND GAS RESERVES (UNAUDITED) (CONTINUED)
CHANGES RELATING TO THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS (UNAUDITED). The principal changes in the standardized measure of
discounted future net cash flows attributable to the Company's oil and gas
reserves for the years ended December 31, 1998, 1997 and 1996, were as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------
1998 1997 1996
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Balance, beginning of year................................................. $ 956,741 $ 803,444 $ 563,297
Acquisitions of proved reserves............................................ 4,236 212,428 116,263
Extensions and discoveries, net of future development costs................ 183,231 118,849 147,817
Revisions of previous quantity estimates................................... 813 (22,766) 26,431
Oil and gas sales, net of production costs................................. (205,280) (172,847) (140,943)
Sales of reserves in place................................................. (7,769) (35,896) (614)
Net changes in sales prices and production costs........................... (190,614) (177,843) 140,205
Development costs incurred and changes in estimated future development
costs.................................................................... 41,121 27,804 13,099
Net change in income taxes................................................. 38,971 135,061 (140,076)
Accretion of discount...................................................... 113,597 111,773 73,751
Changes in timing of production and other.................................. (96,391) (43,266) 4,214
----------- ----------- -----------
Balance, end of year....................................................... $ 838,656 $ 956,741 $ 803,444
----------- ----------- -----------
----------- ----------- -----------
</TABLE>
NOTE 16. QUARTERLY RESULTS (UNAUDITED)
<TABLE>
<CAPTION>
1998 1997
------------------------------------------------ -------------------------------------
FIRST SECOND THIRD FOURTH FIRST SECOND THIRD
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
----------- ---------- ----------- ---------- ----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues(1)..................... $ 69,596 $ 70,351 $ 68,834 $ 84,602 $ 61,062 $ 44,940 $ 46,793
Operating profit (loss)(2)...... 12,609 358 7,904 (28,605) 23,739 17,193 17,757
Net income (loss) before
cumulative effect of
accounting change(3).......... (2,043) (10,391) (5,439) (26,408) 14,035 4,205 4,402
Net income (loss) before
cumulative effect of
accounting change per
share--basic and diluted...... (0.05) (0.26) (0.14) (0.66) .50 0.15 0.16
Net income (loss)(3)............ (2,043) (10,391) (5,439) (25,444) 14,035 4,205 4,402
Net income (loss) per
share--basic and diluted...... (0.05) (0.26) (0.14) (0.63) .50 0.15 0.16
<CAPTION>
FOURTH
QUARTER
----------
<S> <C>
Revenues(1)..................... $ 80,122
Operating profit (loss)(2)...... (44,545)
Net income (loss) before
cumulative effect of
accounting change(3).......... (38,704)
Net income (loss) before
cumulative effect of
accounting change per
share--basic and diluted...... (1.03)
Net income (loss)(3)............ (38,704)
Net income (loss) per
share--basic and diluted...... (1.03)
</TABLE>
- ------------------------
(1) The revenue increase in the fourth quarter of 1998 is largely attributable
to change in derivative fair value. See Note 2--Restatement of 1998
Financial Statements. The revenue increase in the fourth quarter of 1997 is
largely attributable to the American Acquisition. Revenue increases in the
first
F-32
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 16. QUARTERLY RESULTS (UNAUDITED) (CONTINUED)
quarter of 1997 and the fourth quarter of 1997 were also favorably impacted
by higher oil and gas prices.
(2) The decrease in operating profit in the second quarter of 1998 is
attributable to a $9.9 million impairment charge. Also, operating losses in
the fourth quarters of 1998 and 1997 were attributable to impairment charges
of $42.6 million and $75.2 million, respectively. See Note 1--Significant
Accounting Policies.
(3) Net losses in 1998 resulted from lower oil and gas prices and impairment
charges previously discussed.
F-33
<PAGE>
LOUIS DREYFUS NATURAL GAS CORP.
SCHEDULE II--CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
<TABLE>
<CAPTION>
BALANCE AT BALANCE AT
BEGINNING OF END OF
PERIOD ADDITIONS(1) DEDUCTIONS(2) PERIOD
--------------- ---------------- ----------------- ------------
<S> <C> <C> <C> <C>
DESCRIPTION:
December 31, 1998:
Allowance for doubtful accounts--Joint interest and
other receivables.................................... $ 1,135 $ 176 $ 113 $ 1,198
--------------- ---------------- ----------------- ------------
--------------- ---------------- ----------------- ------------
December 31, 1997:
Allowance for doubtful accounts--Joint interest and
other receivables.................................... $ 1,086 $ 49 $ -- $ 1,135
--------------- ---------------- ----------------- ------------
--------------- ---------------- ----------------- ------------
December 31, 1996:
Allowance for doubtful accounts--Joint interest and
other receivables.................................... $ 1,086 $ 25 $ 25 $ 1,086
--------------- ---------------- ----------------- ------------
--------------- ---------------- ----------------- ------------
</TABLE>
- ------------------------
(1) Additions relate to provisions for doubtful accounts charged to general and
administrative expense.
(2) Deductions relate to the write-off of accounts receivable deemed
uncollectible.
F-34
<PAGE>
EXHIBIT 23.1
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in the Registration Statements
(Form S-8, No. 33-92724, No. 333-29907 and No. 333-82057) pertaining to the
Louis Dreyfus Natural Gas Corp. Stock Option Plan and the Registration Statement
(Form S-8, No. 333-77185) pertaining to the Non-Employee Director Deferred
Compensation Program of Louis Dreyfus Natural Gas Corp. of our report dated
February 4, 1999, except for Note 2, as to which the date is October 4, 1999,
with respect to the consolidated financial statements and schedule of Louis
Dreyfus Natural Gas Corp., as amended, included in the Annual Report on Form
10-K/A for the year ended December 31, 1998.
ERNST & YOUNG LLP
Oklahoma City, Oklahoma
October 4, 1999
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE AUDITED
CONSOLIDATED BALANCE SHEET AT DECEMBER 31, 1998 AND THE AUDITED CONSOLIDATED
STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1998 AND IS QUALIFIED IN ITS
ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 2,539
<SECURITIES> 0
<RECEIVABLES> 57,504
<ALLOWANCES> (1,198)
<INVENTORY> 434
<CURRENT-ASSETS> 86,755
<PP&E> 1,519,296
<DEPRECIATION> (434,693)
<TOTAL-ASSETS> 1,283,808
<CURRENT-LIABILITIES> 62,150
<BONDS> 596,844
0
0
<COMMON> 401
<OTHER-SE> 519,060
<TOTAL-LIABILITY-AND-EQUITY> 1,283,808
<SALES> 271,575
<TOTAL-REVENUES> 293,383
<CGS> 66,295
<TOTAL-COSTS> 351,588
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 40,849
<INCOME-PRETAX> (58,205)
<INCOME-TAX> (13,924)
<INCOME-CONTINUING> (44,281)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 964
<NET-INCOME> (43,317)
<EPS-BASIC> (1.08)
<EPS-DILUTED> (1.08)
</TABLE>
