UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[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)
Oklahoma 73-1098614
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
14000 Quail Springs Parkway, Suite 600
Oklahoma City, Oklahoma 73134
(Address of principal executive office) (Zip code)
Registrant's telephone number, including area code:
(405) 749-1300
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class 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
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.
LOUIS DREYFUS NATURAL GAS CORP.
Form 10-K
Table of Contents
Page
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PART I
Item 1 -- BUSINESS .................................................................. 3
General ................................................................... 3
Business Strategy ......................................................... 3
Forward-Looking Statements ................................................ 4
Recent Developments ....................................................... 5
Acquisitions .............................................................. 5
Marketing ................................................................. 6
Competition ............................................................... 7
Regulation ................................................................ 7
Certain Operational Risks ................................................. 9
Employees ................................................................. 9
Relationship Between the Company and S.A. Louis Dreyfus et Cie ............ 9
Potential Conflicts of Interest ........................................... 10
Certain Definitions ....................................................... 10
Item 2 -- PROPERTIES ................................................................ 12
General ................................................................... 12
Core Areas ................................................................ 13
Reserves .................................................................. 16
Costs Incurred and Drilling Results ....................................... 17
Acreage ................................................................... 18
Productive Well Summary ................................................... 19
Title to Properties ....................................................... 19
Item 3 -- LEGAL PROCEEDINGS ......................................................... 19
Item 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ....................... 20
PART II
Item 5 -- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS .................................................................. 20
Item 6 -- SELECTED FINANCIAL DATA ................................................... 20
Item 7 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS .................................................... 22
Overview .................................................................. 22
Results of Operations - Fiscal Year 1998 Compared to Fiscal Year 1997 ..... 24
Results of Operations - Fiscal Year 1997 Compared to Fiscal Year 1996 ..... 25
Capital Resources and Liquidity ........................................... 26
Commitments and Capital Expenditures ...................................... 28
Outlook for Fiscal Year 1999 .............................................. 28
Year 2000 Compliance ...................................................... 30
Item 7A-- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ................ 31
General ................................................................... 31
Fixed-Price Contracts ..................................................... 31
Interest Rate Sensitivity ................................................. 35
Item 8 -- FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ............................... 36
Item 9 -- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE ................................................. 36
LOUIS DREYFUS NATURAL GAS CORP.
Form 10-K
Table of Contents (continued)
Page
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PART III
Item 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ............. 37
Item 11 -- EXECUTIVE COMPENSATION ......................................... 37
Item 12 -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT . 37
Item 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ................. 37
PART IV
Item 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 37
2
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.
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 $.86 per Mcfe over this same five year period. The
following table reflects the Company's growth since 1993:
Production, Proved Reserves, Earnings
Per Share and Cash Flow Growth
Years Ended December 31, Five-Year
----------------------------------------------------------------- Growth
1998 1997 1996 1995 1994 Rate
- ---------------------------------------------------------------------------------------------------------------------------------
Production (Bcfe) 121.6 84.3 75.0 61.4 54.3 23.0%
Proved reserves (Bcfe) 1,340.2 1,203.4 990.2 876.1 689.9 16.4
EBITDAX (MM$) (1) $ 186.2 $ 164.9 $128.6 $111.6 $ 94.0 25.8
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) $ (1.31) $ (.53) $ .76 $ .40 $ .39 NM
- ---------------------------------------------------------------------------------------------------------------------------------
(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:
3
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 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 the cost of these acquisitions compares favorably to
industry averages. 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 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
4
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 14 of the Notes
to Consolidated Financial Statements appearing elsewhere herein.
Financial Results. The Company reported a net loss of $52.6 million, or
$1.31 per share, on total revenue of $278.5 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 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
$340 million. In 1998, the Company completed only a nominal amount of
acquisitions due to high relative prices being asked by sellers of proved
properties in relation to market prices for oil and gas. The market for proved
reserve acquisitions is expected to be more favorable to purchasers in 1999 as
some companies are forced to reduce leverage without having access to capital
markets. The following table summarizes the Company's acquisition activity for
the five years ended December 31, 1998:
5
Summary Acquisition Information
Years Ended December 31,
---------------------------------------------------------------
1998 1997 1996 1995 1994 Total
- -----------------------------------------------------------------------------------------------------------------------------
Estimated proved reserves acquired (Bcfe) (1) 7 234 76 190 56 563
Acquisition cost (MM$) $4.1 $349.0 $36.1 $118.7 $36.6 $544.5
Acquisition cost per Mcfe (2) $.56 $ 1.49 $ .48 $ .62 $ .65 $ .97
- -----------------------------------------------------------------------------------------------------------------------------
(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 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. The fixed prices in such
contracts generally escalate over the contract term. The Company has
traditionally hedged a significant portion of its 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. 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. 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:
6
Natural Gas Fixed-Price Contract
Volumes by Counterparty
Volumes Committed (BBtu)
------------------------------------------------------------- Percentage
Energy Swaps of
Delivery ----------------------- Committed
Contracts Sales Purchases Collars Total Volume
- ---------------------------------------------------------------------------------------------------------------
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%
- ---------------------------------------------------------------------------------------------------------------
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 two unrelated purchasers which approximated 21% and 10% of total revenues.
See Note 9 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 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.
7
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
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
8
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. Substantially all of the gas
transported in this pipeline system is owned by the Company. The operation of
this system is subject to regulation by the Texas Railroad Commission.
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.
9
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 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.
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.
10
EBITDAX. EBITDAX is defined herein as income (loss) before interest,
income taxes, depreciation, depletion and amortization, impairment and
exploration costs. 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.
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 deprecation, 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.
11
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.
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."
12
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
Mid- Gulf
Permian Continent Coast Other Total
- ------------------------------------------------------------------------------------------------------------------
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
- ------------------------------------------------------------------------------------------------------------------
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
13
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.
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 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.
14
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.
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
15
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 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
As of December 31,
------------------------------------------------------------------------
1998 1997 1996 1995 1994
- --------------------------------------------------------------------------------------------------------------------------
(dollars in millions, except price data)
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
16
As of December 31,
------------------------------------------------------------
1998 1997 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------
(dollars in millions, except price data)
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
- ---------------------------------------------------------------------------------------------------------
(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 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 14 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.
17
Costs Incurred
As of December 31,
----------------------------------------------------------------
1998 1997 1996 1995 1994
- ---------------------------------------------------------------------------------------------------
(in thousands)
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
===================================================================================================
(1) Proved and unproved property acquisition costs for 1997 include $339.9
million and $98.0 million, respectively, of allocated American Acquisition
purchase price.
The Company drilled or participated in the drilling of wells as set out in
the table below for the periods indicated.
Wells Drilled
Years Ended December 31,
----------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
- --------------------------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
- --------------------------------------------------------------------------------------------------------------
Development wells:
Gas 237 153 223 166 179 130 134 115 144 131
Oil 60 37 52 20 92 19 114 28 27 6
Dry 27 20 20 14 9 5 14 5 4 2
- --------------------------------------------------------------------------------------------------------------
Total 324 210 295 200 280 154 262 148 175 139
==============================================================================================================
Exploratory wells:
Gas 13 8 32 24 18 6 3 1 -- --
Oil 1 1 4 3 -- -- -- -- -- --
Dry 13 9 12 9 7 2 -- -- -- --
- --------------------------------------------------------------------------------------------------------------
Total 27 18 48 36 25 8 3 1 -- --
==============================================================================================================
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
Developed Undeveloped
------------------------ ------------------------
Gross Net Gross Net
- ---------------------------------------------------------------------
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
=====================================================================
18
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
Productive Wells
-----------------
Gross Net
- --------------------------------------------------------------------------------
Gas 5,537 2,801
Oil 3,665 611
- --------------------------------------------------------------------------------
Total 9,202 3,412
================================================================================
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 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.
19
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
1998 1997
------------------------- -------------------------
High Low High Low
- -----------------------------------------------------------------
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 10.88 24.88 17.63
=================================================================
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 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."
20
Selected Financial Data
Years Ended December 31,
-------------------------------------------------------------------
1998 1997 (2) 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------
(in thousands, except per share data)
Statement of Operations Data:
Oil and gas sales $ 271,575 $ 222,016 $ 185,558 $163,366 $ 138,584
Other income (loss) 6,916 10,901 3,947 (418) 1,953
- ----------------------------------------------------------------------------------------------------------------------
Total revenues 278,491 232,917 189,505 162,948 140,537
- ----------------------------------------------------------------------------------------------------------------------
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 40,908 28,737 26,822 21,736 16,856
- ----------------------------------------------------------------------------------------------------------------------
Total expenses 351,647 260,240 158,005 147,209 124,499
- ----------------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes and
cumulative effect of accounting change (73,156) (27,323) 31,500 15,739 16,038
Income taxes (19,605) (11,261) 10,398 4,722 5,292
- ----------------------------------------------------------------------------------------------------------------------
Net income (loss) before cumulative effect of
accounting change (53,551) (16,062) 21,102 11,017 10,746
Cumulative effect of accounting change, net of
tax of $591 964 -- -- -- --
- ----------------------------------------------------------------------------------------------------------------------
Net income (loss) $ (52,587) $ (16,062) $ 21,102 $ 11,017 $ 10,746
- ----------------------------------------------------------------------------------------------------------------------
Net income (loss) before cumulative effect of
accounting change per share $ (1.33) $ (.53) $ .76 $ .40 $ .39
Cumulative effect of accounting change per share .02 -- -- -- --
- ----------------------------------------------------------------------------------------------------------------------
Net income (loss) per share--basic and diluted $ (1.31) $ (.53) $ .76 $ .40 $ .39
======================================================================================================================
Weighted average diluted common shares 40,107 30,233 27,810 27,804 27,800
======================================================================================================================
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) 186,225 164,893 128,565 111,572 94,040
======================================================================================================================
As of December 31,
-------------------------------------------------------------------
1998 1997 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------
(in thousands)
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 596,103 563,344 343,907 314,760 215,010
Stockholders' equity 519,920 469,204 263,693 242,581 224,564
======================================================================================================================
(1) See "Item 1--Business--Certain Definitions."
(2) 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."
21
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 $52.6
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 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 $23 million of acreage and seismic information, and the drilling of 27
exploratory wells, of which 14 were completed as producers.
As of December 31, 1998, the Company's portfolio of Fixed-Price Contracts
hedge 244 Bcfe of future production at escalating fixed prices, representing
18% of its estimated proved reserves. These fixed prices are presently
significantly higher than the forward market prices for natural gas and oil.
Over the past few years, competition in Fixed-Price Contracts has increased,
opportunities for attractive Fixed-Price Contracts have diminished and
year-to-year price escalations in the forward market are considerably lower. In
response to these changes, a progressively smaller share of the Company's
production and reserve growth has been hedged due to Management's belief that
longer-term demand and supply fundamentals for natural gas imply the potential
for prices in excess of those currently available in the long-term forward
market. More recent hedging activity has been for shorter periods of time,
generally less than 12 months, when market conditions have been viewed as
favorable. The Company may decide to hedge a greater or smaller share of
production in the future depending upon market conditions, capital investment
considerations and other factors. See "Item 7A--Quantitative and Qualitative
Disclosures About Market Risk--Fixed-Price Contracts."
22
Selected Operating Data. The following table provides certain data
relating to the Company's operations.
Years Ended December 31,
Selected Operating Data -------------------------------------------------------------------
1998 1997 1996 1995 1994
- --------------------------------------------------------------------------------------------------------------------------
Oil and Gas Sales (M$):
Oil sales:
Wellhead $ 42,604 $ 40,680 $ 39,372 $ 28,973 $ 29,207
Effect of Fixed-Price Contracts (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 (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
Average Sales Price:
Oil price (per Bbl):
Wellhead price $ 12.42 $ 19.48 $ 21.29 $ 17.09 $ 15.59
Effect of Fixed-Price Contracts (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 (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
==========================================================================================================================
(1) Effect of Fixed-Price Contracts represents the hedging results from the
Company's Fixed-Price Contracts. See "Item 7A-- Quantitative and
Qualitative Disclosures About Market Risk--Fixed-Price Contracts."
(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.
23
The following table presents certain information regarding the Company's proved
oil and gas reserves.
As of December 31,
Oil and Gas Reserves --------------------------------------------------------------------
1998 1997 1996 1995 1994
- --------------------------------------------------------------------------------------------------------------------------
(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
==========================================================================================================================
(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 $52.6 million, or $1.31 per share, on total revenue of
$278.5 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.
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 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 Contracts 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 the Fixed-Price
Contracts hedging the Company's oil and gas production 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."
Other Income (Loss). The Company realized other income for 1998 of $6.9
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. The
1998 amount includes $2.5 million of gain attributable to derivative contract
ineffectiveness and the fair value of certain derivatives not qualifying as
cash flow hedges under SFAS 133.
24
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 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 recognized $52.5 million of impairment charges
during 1998, resulting primarily from a significant decline in oil and gas
prices. 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. See Note 1
and Note 3 of the Notes to the Consolidated Financial Statements appearing
elsewhere herein.
Interest Expense. Interest expense for 1998 was $40.9 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 swaps in effect during
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 $19.6
million on a pre-tax loss of $73.2 million, an effective rate of 27%. This
compares to a tax benefit of $11.3 million, or 41%, on pre-tax 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
25
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.
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.
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. See Note 1 and Note 3 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 pre-tax loss of $27.3 million, an effective rate of 41%. This
compares to a tax provision of $10.4 million, or 33%, on pre-tax 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
26
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."
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 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 $186.2 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 and exploration costs.
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.
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
27
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 $596.1 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.
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 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
28
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 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 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.
29
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 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 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.
30
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.
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 to hedge 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. 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. Under energy swap purchase contracts, the
Company pays a fixed price for the commodity and receives a floating market
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.
31
The following table summarizes the estimated volumes, fixed prices,
fixed-price sales, fixed-price purchases and future net revenues (as defined
below) attributable to the Company's Fixed-Price Contracts as of December 31,
1998.
Years Ending December 31, Balance
--------------------------------------------------------- through
1999 2000 2001 2002 2003 2017 Total
- -------------------------------------------------------------------------------------------------------------------
(dollars in thousands, except price data)
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
===================================================================================================================
(1) The Company expects the prices to be realized for its hedged production
will vary from the prices shown due to location, quality and other factors
which create a differential between wellhead prices and the floating
prices under its Fixed-Price Contracts. See "-- Market Risk."
(2) 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." Future net revenues as presented herein are undiscounted and have
not been adjusted for contract performance risk or counterparty credit
risk. See Note 12 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.
32
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.
The estimated fair value of the Company's Fixed-Price Contracts and the
associated carrying value as of December 31, 1998 are provided below.
Estimated Carrying
Fair Value Value
- ---------------------------------------------------------------------------
(in thousands)
Fixed-Price Contracts as of December 31, 1998:
Natural Gas Swaps:
Sales Contracts $ 25,574 $ 25,574
Purchase Contracts 905 905
Natural Gas Physical Delivery Contracts 96,423 96,423
Natural Gas Collars 3,367 3,367
Natural Gas Basis Swaps (3,660) (3,660)
- ---------------------------------------------------------------------------
Total $122,609 $122,609
===========================================================================
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 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.
Substantially all of the Company's Fixed-Price Contracts and interest rate
swaps are designated as cash flow hedges. 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.
All of the Company's Fixed-Price Contracts have been executed in
connection with its natural gas and crude oil hedging program and not for
trading purposes. Further, all Fixed-Price Contracts have performed according
to Management expectations in reducing the Company's exposure to adverse
movements in commodity prices. However, SFAS 133 has very specific guidelines
for measuring hedge effectiveness. Certain of the Company's contracts did not
meet this criteria although they continue to perform as anticipated. 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.
33
If a Fixed-Price Contract which qualified for hedge accounting is
liquidated or sold prior to maturity, the gain or loss is deferred and
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 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. Other income for the year ended December 31,
1998 included $2.5 million of gain attributable to contract hedge
ineffectiveness and the change in fair value of contracts not qualifying as
cash flow hedges.
Credit Risk. The terms of the Company's Fixed-Price Contracts generally
provide for monthly settlements and energy swap contracts provide for the
netting of payments. 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.
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.
34
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 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. If an interest rate swap is liquidated or
sold prior to maturity, the gain or loss is recorded in accumulated other
comprehensive income and amortized as interest expense over the original
contract term. For the years ended December 31, 1998, 1997 and 1996, interest
rate swaps 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 pursuant to SFAS 133, was designated as a
fair value hedge of 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 fair value of the Subordinated Notes. This interest rate
swap was terminated in the fourth quarter of 1998.
35
The following table provides information about the Company's interest rate
swaps and certain other financial instruments as of December 31, 1998.
Years Ending December 31, Balance
-------------------------------------------------------------- through
1999 2000 2001 2002 2003 2017 Total
- ---------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands, except price data)
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%
=================================================================================================================================
(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.
Estimated Carrying
Fair Value Value
- ----------------------------------------------------------
(in thousands)
As of December 31, 1998:
Bank debt $ (297,200) $ (297,200)
Senior Notes (187,704) (198,912)
Subordinated Notes (102,897) (99,991)
Interest rate swaps 389 389
- ----------------------------------------------------------
Total $ (587,412) $ (595,714)
==========================================================
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.
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-25 inclusive, found at the end of this report.
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
None.
36
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.
Exhibit No. Description of Exhibit
- --------------------------------------------------------------------------------
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.
37
Exhibit No. Description of Exhibit
- -------------------------------------------------------------------------------
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).
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).
*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.
38
Exhibit No. Description of Exhibit
- --------------------------------------------------------------------------------
*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.
- ---------
* Constitutes a management contract or compensatory plan or arrangement
required to be filed as an exhibit to this report.
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.
39
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.
LOUIS DREYFUS NATURAL GAS CORP.
Date: March 12, 1999 By: /s/ JEFFREY A. BONNEY
-------------------------------------
Jeffrey A. Bonney
Executive Vice President and Chief
Financial Officer
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.
Signatures Title Date
MARK E. MONROE* President, Chief Executive Officer and Director March 12, 1999
- ----------------------- (principal executive officer)
Mark E. Monroe
RICHARD E. BROSS* Executive Vice President and Director March 12, 1999
- -----------------------
Richard E. Bross*
/s/ JEFFREY A. BONNEY Executive Vice President and Chief Financial Officer March 12, 1999
- ----------------------- (principal financial and accounting officer)
Jeffrey A. Bonney
SIMON B. RICH, JR.* Chairman of the Board of Directors March 12, 1999
- -----------------------
Simon B. Rich, Jr.
MARK ANDREWS* Vice Chairman of the Board of Directors March 12, 1999
- -----------------------
Mark Andrews
GERARD LOUIS-DREYFUS* Director March 12, 1999
- -----------------------
Gerard Louis-Dreyfus
E. WILLIAM BARNETT* Director March 12, 1999
- -----------------------
E. William Barnett
DANIEL R. FINN, JR.* Director March 12, 1999
- -----------------------
Daniel R. Finn, Jr.
PETER G. GERRY* Director March 12, 1999
- -----------------------
Peter G. Gerry
JOHN H. MOORE* Director March 12, 1999
- -----------------------
John H. Moore
JAMES R. PAUL* Director March 12, 1999
- -----------------------
James R. Paul
*By: /s/ JEFFREY A. BONNEY
---------------------
Jeffrey A. Bonney
Attorney-in-fact
40
LOUIS DREYFUS NATURAL GAS CORP.
Index to Consolidated Financial Statements and Financial Statement Schedule
Consolidated Financial Statements Page
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-25
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
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."
ERNST & YOUNG LLP
Oklahoma City, Oklahoma
February 4, 1999
F-2
LOUIS DREYFUS NATURAL GAS CORP.
Consolidated Balance Sheets
(dollars in thousands)
A S S E T S
December 31,
-------------------------------
1998 1997
- ----------------------------------------------------------------------------------------------------------
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
==========================================================================================================
L I A B I L I T I E S A N D S T O C K H O L D E R S ' E Q U I T Y
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 596,103 563,344
- ----------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred revenue 15,551 17,387
Deferred gains from price-risk management activities -- 23,453
Deferred income taxes 65,398 21,896
Other 24,686 16,104
- ----------------------------------------------------------------------------------------------------------
105,635 78,840
- ----------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes 7 and 13)
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 (deficit) (2,535) 50,052
Accumulated other comprehensive income 102,979 --
- ----------------------------------------------------------------------------------------------------------
519,920 469,204
- ----------------------------------------------------------------------------------------------------------
$1,283,808 $1,210,954
==========================================================================================================
See accompanying notes to consolidated financial statements.
F-3
LOUIS DREYFUS NATURAL GAS CORP.
Consolidated Statements of Operations
(in thousands, except per share data)
Years Ended December 31,
-------------------------------------------
1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------
Revenues
Oil and gas sales $ 271,575 $ 222,016 $ 185,558
Other income 6,916 10,901 3,947
- ---------------------------------------------------------------------------------------------------------------
278,491 232,917 189,505
- ---------------------------------------------------------------------------------------------------------------
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 40,908 28,737 26,822
- ---------------------------------------------------------------------------------------------------------------
351,647 260,240 158,005
- ---------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes and cumulative effect of
accounting change (73,156) (27,323) 31,500
Income taxes (19,605) (11,261) 10,398
- ---------------------------------------------------------------------------------------------------------------
Net income (loss) before cumulative effect of accounting change (53,551) (16,062) 21,102
Cumulative effect of accounting change, net of tax of $591 964 -- --
- ---------------------------------------------------------------------------------------------------------------
Net Income (loss) $ (52,587) $ (16,062) $ 21,102
===============================================================================================================
Per Share
Net income (loss) before cumulative effect of accounting change $ (1.33) $ (.53) $ .76
Cumulative effect of accounting change .02 -- --
- ---------------------------------------------------------------------------------------------------------------
Net income (loss)--basic and diluted $ (1.31) $ (.53) $ .76
===============================================================================================================
Weighted average diluted common shares 40,107 30,233 27,810
===============================================================================================================
See accompanying notes to consolidated financial statements.
F-4
LOUIS DREYFUS NATURAL GAS CORP.
Consolidated Statements of Stockholders' Equity
(in thousands)
Accumulated
Additional Other Total
Preferred Common Paid-In Retained Comprehensive Stockholders'
Stock Stock Capital Earnings Income Equity
- ------------------------------------------------------------------------------------------------------------------------
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 -- -- -- (52,587) -- (52,587)
Other comprehensive income, net of tax:
Cumulative effect of accounting change -- -- -- -- 97,681 97,681
Reclassification adjustments -- -- -- -- (4,431) (4,431)
Change in fixed-price contract and other
derivative effectiveness -- -- -- -- 471 471
Change in fixed-price contract and other
derivative fair value -- -- -- -- 9,258 9,258
--------
Total comprehensive income 50,392
- ------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 $ -- $401 $419,075 $ (2,535) $102,979 $519,920
========================================================================================================================
See accompanying notes to consolidated financial statements.
F-5
LOUIS DREYFUS NATURAL GAS CORP.
Consolidated Statements of Cash Flows
(in thousands)
Years Ended December 31,
--------------------------------------------
1998 1997 1996
- ------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net income (loss) $ (52,587) $ (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 (20,205) (12,296) 9,065
Exploration costs 34,543 8,956 4,965
Gain on sale of property (166) (8,745) (68)
Other (596) 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
======================================================================================================
See accompanying notes to consolidated financial statements.
F-6
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 6--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 13--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.
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. 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
3--Acquisitions.
F-7
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
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, 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 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.
Substantially all of the Company's Fixed-Price Contracts and interest rate
swaps are designated as cash flow hedges. 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.
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 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 4--Long-Term
Debt, Note 10--Capital Stock and Stockholders' Equity Information, Note
12--Financial Instruments and Note 13--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
F-8
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
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 8--Employee Benefit Plans and
Note 10--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 8--Employee Benefit Plans.
Note 2. 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:
December 31,
-----------------------------
1998 1997
- -------------------------------------------------------------------------------------
(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
=====================================================================================
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.
Years Ended December 31,
--------------------------------------
1998 1997 1996
- ---------------------------------------------------------------------
(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
=====================================================================
F-9
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
Note 3. 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.
Years Ended December 31,
-------------------------
1997 1996
- ---------------------------------------------------------------------------
(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
===========================================================================
The pro forma information presented for 1997 and 1996 does not include a
$73.1 million impairment charge recorded in connection with the American
Acquisition, nor does it consider the effects of certain cost reduction plans,
financing plans or the effects of certain purchase accounting adjustments
(collectively "Pro Forma Adjustments"). The estimated combined financial impact
of the Pro Forma Adjustments would be an increase in pro forma net income of
$9.0 million, or $.23 per share, and $11.7 million, or $.30 per share, for the
years ended December 31, 1997 and 1996, respectively.
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.
Note 4. Long-Term Debt
Long-term debt consists of the following:
December 31,
-------------------------
1998 1997
- -----------------------------------------------------------------------
(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 99,991 99,053
- -----------------------------------------------------------------------
$596,103 $563,344
=======================================================================
$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.
F-10
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
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 13--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.
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.
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 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
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. If an interest rate swap is liquidated or
sold prior to maturity, the gain or loss is recorded in accumulated other
comprehensive income and amortized as interest expense over the original
contract term. For the years ended December 31, 1998, 1997 and 1996, interest
rate swaps 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 pursuant to SFAS 133, was designated as a
fair value hedge of 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 fair value of the Subordinated Notes. This interest rate
swap was terminated in the fourth quarter of 1998.
F-11
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
Note 5. 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:
Years Ended December 31,
---------------------------------------
1998 1997 1996
- --------------------------------------------------------------------------
(in thousands)
Current tax expense:
Federal $ 527 $ 885 $ 1,159
State 73 150 174
- --------------------------------------------------------------------------
600 1,035 1,333
- --------------------------------------------------------------------------
Deferred tax expense (benefit):
Federal (17,999) (11,407) 8,271
State (2,206) (889) 794
- --------------------------------------------------------------------------
(20,205) (12,296) 9,065
- --------------------------------------------------------------------------
$ (19,605) $ (11,261) $10,398
==========================================================================
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:
Years Ended December 31,
-----------------------------------------
1998 1997 1996
- -------------------------------------------------------------------------------------------------
(in thousands)
Computed "expected" income tax $ (25,605) $ (9,563) $ 11,025
Increases (reductions) in taxes resulting from:
State income taxes, net of federal benefit (1,386) (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 (563) (404) 507
- -------------------------------------------------------------------------------------------------
$ (19,605) $ (11,261) $ 10,398
=================================================================================================
F-12
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (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:
December 31,
---------------------------
1998 1997
- -----------------------------------------------------------------------------------------------------
(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 564 1,185
- -----------------------------------------------------------------------------------------------------
86,923 109,851
Valuation allowance for net operating loss carryforwards (33,523) (43,489)
- -----------------------------------------------------------------------------------------------------
53,400 66,362
- -----------------------------------------------------------------------------------------------------
Net deferred tax liability $ 65,398 $ 21,896
=====================================================================================================
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 6. 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
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.
F-13
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
Note 7. 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 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 8. 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
F-14
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
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.
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:
Years Ended December 31,
----------------------------------------
1998 1997 1996
- ------------------------------------------------------------------------
(in thousands, except per share data)
Net income (loss) $ (55,232) $ (16,981) $20,698
Net income (loss) per share (1.38) (.56) .74
========================================================================
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-15
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
Stock option transactions for 1998, 1997 and 1996 are summarized as follows:
Years Ended December 31,
----------------------------------------------------------------------------------------------
1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------------------------
Weighted- Weighted- Weighted-
Average Average Average
Shares Exercise Price Shares Exercise Price Shares Exercise Price
- ---------------------------------------------------------------------------------------------------------------------------------
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
=================================================================================================================================
(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 3--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 9. 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. and Enron Capital and Trade Resources
approximated 21% and 10% of total revenues, respectively. 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.
Note 10. Capital Stock and Stockholders' Equity Information
Common Stock. The following table sets forth the Company's Common Stock
activity for the periods presented:
Years Ended December 31,
-------------------------------
1998 1997 1996
- ----------------------------------------------------------------------------------
(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
=================================================================================
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
F-16
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
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:
Tax Net of
Gross Effect Tax
- -------------------------------------------------------------------------------------------------------------
Cumulative effect of accounting change $157,550 $ 59,869 $ 97,681
Reclassification adjustments (7,147) (2,716) (4,431)
Change in fixed-price contract and other derivative effectiveness 759 288 471
Change in fixed-price contract and other derivative fair value 14,933 5,675 9,258
- -------------------------------------------------------------------------------------------------------------
$166,095 $ 63,116 $102,979
=============================================================================================================
Note 11. 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:
American
Acquisition
- ------------------------------------------------------------------------------
(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
==============================================================================
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.
Note 12. 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 December 31, 1998 and 1997, and the
methods and assumptions used to estimate the fair value of such financial
instruments:
December 31, 1998 December 31, 1997
--------------------------- ---------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- ------------------------------------------------------------------------------------------------------------
(in thousands)
Fixed-price natural gas swaps (1):
Sales contracts $ 25,574 $ 25,574 $ 76 $ 18,000
Purchase contracts 905 905 -- 2,000
Fixed-price natural gas collars 3,367 3,367 -- --
Fixed-price natural gas physical delivery contracts 96,423 96,423 1,138 166,000
Natural gas basis swaps (3,660) (3,660) -- 1,000
Fixed-price crude oil swaps n/a n/a -- --
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) (99,991) (102,897) (99,053) (108,235)
Interest rate swaps--fixed 389 389 -- (1,000)
Interest rate swaps--floating n/a n/a -- 1,000
============================================================================================================
F-17
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
(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%, the discount factor prescribed by the Securities and
Exchange Commission for discounting future net cash flows from its oil and gas
properties. See Note 14--Supplemental Information--Oil and Gas Reserves. 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, 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.
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
based on market interest rates as of such dates.
Note 13. 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 to hedge 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. 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. Under energy swap purchase contracts, the
Company pays a fixed price for the commodity and receives a floating market
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 (as defined
below) attributable to the Company's Fixed-Price Contracts as of December 31,
1998.
F-18
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
Years Ending December 31, Balance
--------------------------------------------------------- through
1999 2000 2001 2002 2003 2017 Total
- --------------------------------------------------------------------------------------------------------------------
(dollars in thousands, except price data)
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
====================================================================================================================
(1) The Company expects the prices to be realized for its hedged production
will vary from the prices shown due to location, quality and other factors
which create a differential between wellhead prices and the floating prices
under its Fixed-Price Contracts. See "Market Risk."
(2) 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."
Future net revenues as presented herein are undiscounted and have not been
adjusted for contract performance risk or counterparty credit risk. See
Note 12--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.
F-19
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
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 12--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 and not for
trading purposes. Further, all Fixed-Price Contracts have performed according
to Management expectations in reducing the Company's exposure to adverse
movements in commodity prices. However, SFAS 133 has very specific guidelines
for measuring hedge effectiveness. Certain of the Company's contracts did not
meet this criteria although they continue to perform as anticipated. 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.
If a Fixed-Price Contract which qualified for hedge accounting is
liquidated or sold prior to maturity, the gain or loss is deferred and
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 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. 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. Other income for the year ended December 31,
1998 included $2.5 million of gain attributable to contract hedge
ineffectiveness and the change in fair value of contracts not qualifying as
cash flow hedges.
Credit Risk. The terms of the Company's Fixed-Price Contracts generally
provide for monthly settlements and energy swap contracts provide for the
netting of payments. 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
F-20
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
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.
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 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.
Note 14. 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
F-21
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
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:
1998 1997 1996
--------------------------- -------------------------- --------------------------
Oil Gas Oil Gas Oil Gas
(MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MMcf)
- -----------------------------------------------------------------------------------------------------------------------------
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
=============================================================================================================================
(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.
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 on the basis of prices received at December 31, 1998, 1997 and
1996, as adjusted for the effects of the Company's existing Fixed- Price
Contracts, 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.
F-22
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
December 31,
------------------------------------------------
1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------
(in thousands)
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
==================================================================================================================
SEC PV10% including Fixed-Price Contracts (3) $978,914 $1,135,970 $1,117,734
==================================================================================================================
SEC PV10% excluding Fixed-Price Contracts (3) $811,073 $1,002,649 $1,303,709
==================================================================================================================
(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 12--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.
(3) The SEC PV10% amounts give no effect to federal or state income taxes
attributable to estimated future net revenues.
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. Neither the standardized measure
calculation, prepared pursuant to the provisions of Statement of Financial
Accounting Standards No. 69, nor the SEC PV10% amounts, 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.
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:
Years Ended December 31,
---------------------------------------------
1998 1997 1996
- -------------------------------------------------------------------------------------------------------------
(in thousands)
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
=============================================================================================================
F-23
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
Note 15. Quarterly Results (unaudited)
1998 1997
------------------------------------------------- ------------------------------------------------
First Second Third Fourth First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands, except per share data)
Revenues (1) $ 69,596 $ 70,351 $ 68,834 $ 69,710 $61,062 $ 44,940 $ 46,793 $ 80,122
Operating profit (loss) (2) 12,609 358 7,904 (28,605) 23,739 17,193 17,757 (44,545)
Net income (loss) before
cumulative effect of
accounting change (3) (2,043) (10,391) (5,439) (35,678) 14,035 4,205 4,402 (38,704)
Net income (loss) before
cumulative effect of
accounting change per
share--basic and diluted (0.05) (0.26) (0.14) (0.89) .50 0.15 0.16 (1.03)
Net income (loss) (3) (2,043) (10,391) (5,439) (34,714) 14,035 4,205 4,402 (38,704)
Net income (loss) per share--
basic and diluted (0.05) (0.26) (0.14) (0.87) .50 0.15 0.16 (1.03)
=================================================================================================================================
(1) The revenue increase in the fourth quarter of 1997 is largely attributable
to the American Acquisition. Revenue increases in the first 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-24
LOUIS DREYFUS NATURAL GAS CORP.
Schedule II--Consolidated Valuation and Qualifying Accounts
(in thousands)
Balance at Balance at
Beginning of End of
Period Additions (1) Deductions (2) Period
- -------------------------------------------------------------------------------------------------------------------------
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
=========================================================================================================================
(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-25
INDEX TO EXHIBITS
Exhibit
No. Description of Exhibit
--- ----------------------
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).
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).
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.