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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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, 1997
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934.
COMMISSION FILE NUMBER 1-12480
[LOGO]
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
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Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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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
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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 6, 1998, was approximately $379.0 million (based on a value
of $19.81 per share, the closing price of the Common Stock as quoted by the New
York Stock Exchange on such date). 40,103,508 shares of Common Stock, par value
$.01 per share, were outstanding on March 6, 1998.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 1998 Annual
Meeting of Shareholders, to be filed pursuant to Regulation 14A under the
Securities Exchange Act of 1934, are incorporated by reference into Part III.
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LOUIS DREYFUS NATURAL GAS CORP.
FORM 10-K
TABLE OF CONTENTS
PAGE
-----
PART I
Item 1 -- BUSINESS........................................................................................ 3
General......................................................................................... 3
Business Strategy............................................................................... 4
Forward-Looking Statements...................................................................... 5
Recent Developments............................................................................. 6
Acquisitions.................................................................................... 7
Marketing....................................................................................... 7
Competition..................................................................................... 9
Regulation...................................................................................... 9
Certain Operational Risks....................................................................... 12
Employees....................................................................................... 12
Relationship Between the Company and S.A. Louis Dreyfus et Cie.................................. 12
Potential Conflicts of Interest................................................................. 13
Certain Definitions............................................................................. 13
Item 2 -- PROPERTIES...................................................................................... 16
General......................................................................................... 16
Core Areas...................................................................................... 16
Reserves........................................................................................ 21
Costs Incurred and Drilling Results............................................................. 22
Acreage......................................................................................... 23
Productive Well Summary......................................................................... 23
Title to Properties............................................................................. 24
Item 3 -- LEGAL PROCEEDINGS............................................................................... 24
Item 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............................................. 25
PART II
Item 5 -- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS........................... 25
Item 6 -- SELECTED FINANCIAL DATA......................................................................... 26
Item 7 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS........... 27
Overview........................................................................................ 27
Results of Operations--Fiscal Year 1997 Compared to Fiscal Year 1996............................ 29
Results of Operations--Fiscal Year 1996 Compared to Fiscal Year 1995............................ 31
Capital Resources and Liquidity................................................................. 32
Commitments and Capital Expenditures............................................................ 34
Fixed-Price Contracts........................................................................... 35
Outlook for Fiscal Year 1998.................................................................... 39
Item 7A -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK...................................... 41
Item 8 -- FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..................................................... 41
Item 9 -- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE............ 41
1
LOUIS DREYFUS NATURAL GAS CORP.
FORM 10-K
TABLE OF CONTENTS (CONTINUED)
PAGE
-----
PART III
Item 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.............................................. 41
Item 11 -- EXECUTIVE COMPENSATION.......................................................................... 41
Item 12 -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.................................. 42
Item 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.................................................. 42
PART IV
Item 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K................................. 42
2
LOUIS DREYFUS NATURAL GAS CORP.
PART I
ITEM 1--BUSINESS
GENERAL
Louis Dreyfus Natural Gas Corp. (the "Company" or "Registrant") is a large
independent energy company engaged in the acquisition, development and
exploration of natural gas and oil properties, and in the production and
marketing of natural gas and crude oil. The Company's acquisition, development
and exploration activities are primarily conducted in six core areas: the Sonora
area of West Texas; the Mid-Continent area of Oklahoma, Kansas and the Panhandle
of Texas; the Western area of West Texas and Southeast New Mexico; the Gulf
Coast area of South Texas; the Offshore area in the Gulf of Mexico; and the
Arklatex area of East Texas, Southwest Arkansas and Northern Louisiana
(collectively "Core Areas"). Approximately 98% of the Company's proved reserve
value at December 31, 1997 is geographically concentrated within these Core
Areas. Proved reserves as of December 31, 1997, totaled 1.2 Tcfe and had a
Present Value (as hereinafter defined) of $1.1 billion. More than 78% of its
proved reserves are operated by the Company. Natural gas reserves comprised 85%
of the Company's year-end reserve position and 87% of its reserves were proved
developed. The reserve life of its proved reserves was 10.7 years, based on pro
forma 1997 production for the American Acquisition, as hereinafter defined.
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. Through its proved reserve and undeveloped
acreage acquisitions, the Company has accumulated interests in 3.5 million gross
acres with 1,555 potential drilling locations, of which 459 have been assigned
proved undeveloped reserves. The Company aggressively exploits the value in its
properties through an active development drilling program. Over the five-year
period ended December 31, 1997, this program has resulted in the drilling of
1,083 wells with a completion success rate of 95%. In recent years, exploratory
drilling has been increasingly emphasized as an integral component of its
business strategy and in connection therewith, the Company has incurred
substantial up-front costs, including significant acreage positions, seismic
costs and other geological and geophysical costs. During 1997, the Company
invested $128 million in connection with exploration activities, including $98
million allocated to the unproved acreage position obtained in the American
Acquisition. This significant commitment has had the impact of increasing
finding costs in the near term, but is expected to result in future reserve
additions at more favorable rates. The Company's exploration program has
resulted in a cumulative 75% drilling success rate since its inception in 1995.
This balanced strategy has enabled the Company to replace 382% of its
production since 1992 at an average finding cost of $1.03 per Mcfe, including
the start-up costs associated with its exploration program. The year ended
December 31, 1997 marked the fourth consecutive year that the Company replaced
its production from both its acquisition and drilling programs. By increasing
its production and reserves, the Company has significantly grown its earnings
per share and operating cash flows as outlined in the table below:
3
PRODUCTION, PROVED RESERVES, EARNINGS
PER SHARE AND CASH FLOW GROWTH
YEARS ENDED DECEMBER 31,
----------------------------------------------------- FIVE-YEAR
1993 1994 1995 1996 1997 GROWTH RATE
--------- --------- --------- --------- --------- -----------
Production (Bcfe).................... 43.2 54.3 61.4 75.0 84.3 24.1%
Proved reserves (Bcfe)............... 627.2 689.9 876.1 990.2 1,203.4 26.2
Earnings per share--basic (1)........ $ .11 $ .39 $ .40 $ .76 $ 1.03 62.8
Net cash provided by operating
activities (MM$)................... $ 52.7 $ 80.9 $ 89.5 $ 101.8 $ 129.8 42.3
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(1) The 1997 amount excludes the effect of a $75.2 million non-cash impairment
charge ($47.1 million after tax), or $2.49 per share ($1.56 per share after
tax), 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--Results of Operations--Fiscal
Year 1997 Compared to Fiscal Year 1996--Net Income (Loss) and Cash Flows
from Operating Activities."
The address of the Company's principal executive offices is 14000 Quail
Springs Parkway, Suite 600, Oklahoma City, Oklahoma 73134, and its telephone
number is (405) 749-1300.
BUSINESS STRATEGY
The Company's business strategy is to generate strong and consistent growth
in reserves, production, operating cash flows and earnings. This strategy is
implemented through the following:
EXPANDED EXPLORATION PROGRAM. Increased exploration activity in the
Company's Core Areas exposes the Company to higher production and reserve
growth potential. The Company has a staff of 50 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 1997, $128 million was
invested in connection with exploration activities, including drilling,
seismic data collection and unproved lease acquisitions. Of this amount, $98
million represents the purchase price allocated to the unproved acreage
position obtained in the American Acquisition. Since the inception of the
program in 1995, the Company has drilled 76 gross (45 net) exploratory wells
with a completion success rate of 75%. The Company has allocated $78
million, or 39%, of its 1998 drilling budget to exploration activities.
DEVELOPMENT DRILLING. The Company historically has aggressively exploited
the value in its oil and gas property base through its development drilling
program. Over the five-year period ended December 31, 1997, the Company has
drilled 1,083 gross (676 net) development wells with a completion success
rate of 95%. 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. For 1998, the Company plans to expand its
development drilling program by investing $122 million, or 61% of its 1998
drilling budget. This is expected to result in the drilling of 340 wells.
STRATEGIC ACQUISITIONS. Over the five-year period ended December 31, 1997,
the Company has grown rapidly by investing $729 million to acquire
approximately 853 Bcfe of proved reserves at an average acquisition cost of
$.86 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
4
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 9,100 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 located central to its Core Areas and employs approximately 175
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, to a lesser extent, 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, 1997, Fixed-Price
Contracts have generated $29.5 million in additional revenues and operating
cash flows. At December 31, 1997, the pre-tax present value (discounted at
10%) of the estimated future net revenues for such contracts, based on the
difference between contract prices and forward market prices, was
approximately $187 million. This contract value is not reflected in the
Company's balance sheet. Fixed-Price Contracts provide a base of predictable
cash flows for a portion of the Company's gas and oil sales, thereby
enabling the Company to pursue its capital expenditures with a greater
degree of assurance. Since April 1996, the Company has not entered into
Fixed-Price Contracts with a term in excess of 12 months due to a reluctance
to sell into the prevailing forward market in which prices trend down or are
essentially flat over the next several years. In 1997, 56% of the Company's
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, 1997, and other information currently available to Management.
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, operations and production risks, and risks
attributable to the American Acquisition. Certain of these risks are described
elsewhere herein. See "Item 7--Management's Discussion and Analysis of Financial
Condition and Results of Operations--Outlook for Fiscal Year 1998." 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. 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.
5
RECENT DEVELOPMENTS
The following information discusses certain of the more significant
accomplishments of the Company during the year ended December 31, 1997.
AMERICAN ACQUISITION. On October 14, 1997, the Company completed the
acquisition of American Exploration Company ("American"), a Houston-based,
publicly-held independent energy company with exploration and development
activities focused primarily in South Texas, the Texas State Waters, the Cotton
Valley Reef Trend in East Texas and the Smackover Trend in Arkansas ("the
American Acquisition"). The acquisition consideration paid to the shareholders
of American consisted of 11.3 million shares of Company common stock and $47
million of cash. In addition, the Company assumed $116 million of long-term
debt, preferred stock having a liquidation value of $20 million and warrants and
options valued at $10 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.
Over the past two years, preceding the acquisition, the Company and American
worked together closely on certain projects. Through this association, each
company gained an appreciation for their complementary strengths. The Company's
strengths include a substantial, long-lived reserve base, a large inventory of
low-risk development drilling locations and strong oil and gas operating and
product marketing capabilities. American's strengths included a high quality,
although shorter-lived, reserve base, a substantial inventory of high potential
exploratory prospects and strong prospect generating and technical skills. The
American Acquisition combined the complementary strengths of each organization
and created a larger and more balanced independent exploration and production
company. The addition of American's proved reserves, which increased the
Company's proved reserves by 22%, improved the Company's property mix and
enhances operating cash flows available for reinvestment and debt service. As a
result of the American Acquisition, the Company has a stronger balance sheet,
higher operating cash flows and a more diversified property base, as well as
significant growth potential through a balance of low-risk development and
higher-risk exploration drilling.
1997 DRILLING PROGRAM. The Company's drilling program for 1997 resulted in
the drilling of 343 wells, of which 311 wells were completed as commercial
producers, a drilling success rate of 91%. This well count included 48
exploratory wells, 75% of which were completed as producers. Through this
program, the Company added 125 Bcfe of proved reserves to its reserve base. See
"Item 2--Properties--Costs Incurred and Drilling Results."
PROVED RESERVES. As of December 31, 1997, the Company's proved reserves had
grown 22% in relation to 1996 and was comprised of 29 MMBbls of oil and 1.0 Tcf
of natural gas, or 1.2 Tcfe. This reserve growth represents a production
replacement ratio of more than 350%. The Company's estimated future net revenues
from proved reserves as of December 31, 1997 was $2.2 billion. The present value
of such future net revenues discounted at 10% ("Present Value") was $1.1
billion. See "Item 2--Properties--Reserves" and Note 14 of the Notes to
Consolidated Financial Statements appearing elsewhere herein.
FINANCIAL RESULTS. Excluding the effects of a fourth-quarter impairment
charge, the Company reported net income of $31.1 million, or $1.03 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. 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. For the year ended December
31, 1997, the Company reported a net loss of $16.1 million, or $.53 per share,
after the effects of a $75.2 million non-cash impairment charge ($47.1 million
after tax),
6
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--Results of Operations--Fiscal Year 1997
Compared to Fiscal Year 1996."
ACQUISITIONS
The Company has completed a significant number of large proved reserve
acquisitions during the past five years, including four ranging in size from $87
million to $340 million. The following table summarizes the Company's
acquisition activity for the five years ended December 31, 1997:
SUMMARY ACQUISITION INFORMATION
YEARS ENDED DECEMBER 31,
-----------------------------------------------------
1993 1994 1995 1996 1997 TOTAL
--------- --------- --------- --------- --------- ---------
Estimated proved reserves acquired (Bcfe) (1)... 297 56 190 76 234 853
Acquisition cost (MM$).......................... $ 188.9 $ 36.6 $ 118.7 $ 36.1 $ 349.0 $ 729.3
Acquisition cost per Mcfe ($)................... $ .64 $ .65 $ .62 $ .48 $ 1.49 $ .86
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(1) Based on the first year-end reserve report prepared following the
acquisition date as adjusted for production between the acquisition date and
year-end.
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, 1997, these contracts
hedged 310 Bcf of future natural gas production and 79 MBbls of oil 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 a reluctance
to sell into the prevailing forward market where prices trend down or are
essentially flat over the next several years. 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.
7
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, 1997:
NATURAL GAS FIXED-PRICE CONTRACT
VOLUMES BY COUNTERPARTY
VOLUMES COMMITTED (BBTU)
-----------------------------------------------------------
ENERGY SWAPS PERCENTAGE OF
DELIVERY ---------------------- COMMITTED
CONTRACTS SALES PURCHASES COLLARS TOTAL VOLUME
----------- --------- ----------- ----------- --------- ---------------
TYPE OF COUNTERPARTY:
Independent power producers......... 158,257 -- -- -- 158,257 51%
Pipeline marketing affiliates....... 72,551 8,060 (1,825) -- 78,786 25
Financial institutions.............. -- -- (18,250) 1,350 (16,900) (5)
Other............................... 21,601 68,733 -- -- 90,334 29
----------- --------- ----------- ----- --------- ---
Total............................. 252,409 76,793 (20,075) 1,350 310,477 100%
----------- --------- ----------- ----- --------- ---
----------- --------- ----------- ----- --------- ---
For additional information concerning the Company's Fixed-Price Contracts,
see "Item 7--Management's Discussion and Analysis of Financial Condition and
Results of Operations--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 1997, the Company had gas sales
to three unrelated purchasers which approximated 22%, 15% 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.
8
COMPETITION
The oil and gas industry is highly competitive. The Company competes in the
areas of 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, with major oil and gas companies, other
independent oil and gas concerns, gas marketing companies and individual
producers and operators. 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 and
production capabilities, 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. The effect of these regulations is to limit the amount of oil and
gas the Company can produce from its wells and to limit the number of wells or
the locations at which the Company can drill.
The Company has operated and non-operated working interests in various oil
and gas leases in the Gulf of Mexico which were granted by the federal
government and are administered by the Minerals Management Service (the "MMS"),
a federal agency. These leases were issued through competitive bidding, contain
relatively standardized terms and require compliance with detailed MMS
regulations and orders (which are subject to change by the MMS). For offshore
operations, lessees must obtain MMS approval for exploration, development and
production plans prior to the commencement of such operations. In addition to
permits required from other agencies (such as the Coast Guard, the Army Corps of
Engineers and the Environmental Protection Agency), lessees must obtain a permit
from the MMS prior to the commencement of drilling. The MMS has promulgated
regulations requiring offshore production
9
facilities located on the outer continental shelf to meet stringent engineering
and construction specifications. Similarly, the MMS has promulgated 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
10
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. On March 25, 1997, the MMS proposed regulations to implement these
financial responsibility requirements under OPA. The Company cannot predict the
final form of any financial responsibility regulations that will be adopted by
the MMS, but the impact of any such regulations should not be any more adverse
to the Company than it will be to other similarly situated companies. OPA also
subjects responsible parties to strict, joint and several and potentially
unlimited liability for removal costs and certain other damages caused by an oil
spill covered by the statute.
NATURAL GAS SALES TRANSPORTATION
In the past, there were various federal laws which regulated the price at
which natural gas could be sold. Since 1978, various federal laws have been
enacted which have resulted in the termination on January 1, 1993 of all price
and non-price controls for natural gas sold in "first sales." As a result, on
and after January 1, 1993, none of the Company's natural gas production is
subject to federal price controls.
The transportation and sale for resale of natural gas is subject to
regulation by the Federal Energy Regulatory Commission ("FERC") under the
Natural Gas Act of 1938 ("NGA") and the Natural Gas Policy Act of 1978 ("NGPA").
Commencing in 1985, the FERC promulgated a series of orders and regulations
adopting changes that significantly affect the transportation and marketing of
natural gas. These changes have been intended to foster competition in the
natural gas industry by, among other things, inducing or mandating that
interstate pipeline companies provide nondiscriminatory transportation services
to producers, distributors and other shippers (so-called "open access"
requirements). The FERC has also sought to expedite the certification process
for new services, facilities and operations of those pipeline companies
providing "open access" services. The FERC's actions in these areas have been
subject to extensive judicial review and have generated significant industry
comment and proposals for modifications to existing regulations. The Company
cannot predict whether and to what extent judicial review will affect these
matters.
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.
SECTION 29 TAX CREDITS
Federal tax law provides an income tax credit for production of certain
fuels produced from nonconventional sources (including both coal seam natural
gas and natural gas produced from tight formations), subject to a number of
limitations. Fuels qualifying for the credit must be produced from a well
drilled or a facility placed-in-service before January 1, 1993 and be sold
before January 1, 2003.
The basic credit, which is approximately $.52 per MMBtu of natural gas, is
computed by reference to the price of oil and is phased out as the price of oil
exceeds $23.50 in 1980 dollars (adjusted for inflation) with complete phaseout
if such price exceeds $29.50 in 1980 dollars (similarly adjusted). Under this
formula, the commencement of the phaseout would be triggered if the average
price for oil rose above $47
11
per barrel in current dollars. The credit available for coal seam natural gas is
adjusted for inflation and was approximately $1.03 per MMBtu for 1996. A portion
of the natural gas production from wells drilled on the Company's leases in
several of its significant producing areas qualify for Section 29 tax credits.
The Company estimates that it will have an aggregate $6.3 million of Section 29
tax credits available for utilization in its federal income tax returns for the
years 1998 through 2002. Utilization of such credits is subject to a number of
factors, many of which are not within the Company's ability to control or
predict.
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, among other factors,
the availability and capacity of oil and gas gathering systems and pipelines,
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 6, 1998, 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, petroleum products marketing 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
12
Cie and any other party, including the Company, that would prevent S.A. Louis
Dreyfus et Cie from acquiring additional shares of the Common Stock.
The Company has an agreement ("Services Agreement") with S.A. Louis Dreyfus
et Cie pursuant to which S.A. Louis Dreyfus et Cie provides to the Company
various services (principally insurance-related services). Such services
historically have been supplied to the Company by S.A. Louis Dreyfus et Cie, and
the Services Agreement provides for the further delivery of such services, but
only to the extent requested by the Company. The Company reimburses S.A. Louis
Dreyfus et Cie for a portion of the salaries of employees performing requested
services based on the amount of time expended ("Hourly Charges"), all 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, the financing of
acquisition, development and marketing activities of the Company 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.
13
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.
ESTIMATED FUTURE NET REVENUES. Revenues from production of oil and gas, net
of all production-related taxes, lease operating expenses and capital 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.
MBBL. 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.
MMBBL. Million barrels.
MMBTU. Million Btus.
14
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 and future
development 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.
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.
15
ITEM 2--PROPERTIES
GENERAL
The Company's oil and gas acquisition, exploration and development
activities are conducted mainly in its Core Areas: the Sonora area of West
Texas; the Mid-Continent area of Oklahoma, Kansas and the Panhandle of Texas;
the Western area of West Texas and Southeast New Mexico; the Gulf Coast area of
South Texas; the Offshore area in the Gulf of Mexico; and the Arklatex area of
East Texas, Southwest Arkansas and Northern Louisiana. At December 31, 1997, the
Company had interests in approximately 9,100 producing properties, 3,300 of
which it operates. Proved reserves as of December 31, 1997, consisted of 29
MMBbls of oil and 1.0 Tcf of natural gas, or 1.2 Tcfe. Properties operated by
the Company represented 78% of total proved reserves. Net daily production
during 1997 was 5.7 MBbls of oil and 196.5 MMcf of natural gas, or 230.9 MMcfe,
which includes the impact of production from the American Acquisition from
October 14, 1997 through December 31, 1997. During 1997, the Company drilled 295
developmental oil and gas wells, 275 of which were completed as commercial
producers, and 48 exploratory wells, 36 of which were successfully completed.
For 1998, the Company has allocated $200 million for its 1998 drilling
program. Of this amount $78 million, or 39%, has been allocated to exploration
activities and $122 million, or 61%, has been allocated to development
activities. It is expected that the 1998 program will result in the drilling of
400 wells, of which 60 will be exploratory wells and 340 will be development
wells.
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, 1997:
CORE AREAS
MID- GULF
SONORA CONTINENT WESTERN COAST ARKLATEX OFFSHORE TOTAL
--------- ----------- ---------- --------- --------- --------- ----------
PROPERTY STATISTICS:
Proved reserves (Bcfe).......... 480 420 110 91 53 49 1,203
Percent of total proved
reserves...................... 40% 35% 9% 8% 4% 4% 100%
Average net daily production
(MMcfe)(1).................... 86.2 104.7 32.3 31.3 13.9 51.9 320.3
Gross producing wells........... 1,649 3,602 2,981 617 182 60 9,091
Net producing wells............. 1,535 1,071 430 195 101 16 3,348
Gross acreage................... 403,112 890,721 1,222,788 301,887 460,519 174,229 3,453,256
Net acreage..................... 291,410 333,498 359,497 132,927 101,115 73,094 1,291,541
Potential drill sites........... 575 300 500 100 30 50 1,555
1997 RESULTS:
Gross wells drilled............. 149 84 69 35 3 3 343
Gross successful wells.......... 138 81 61 26 3 2 311
Drilling success................ 93% 96% 88% 74% 100% 67% 91%
Production (Bcfe)............... 29.7 31.4 9.2 6.8 1.2 6.0 84.3
Lease operating expense per
Mcfe.......................... $ .43 $ .43 $ .47 $ .55 $ .65 $ .39 $ .45
1998 DRILLING BUDGET (MM$):
Development..................... $ 46 $ 31 $ 14 $ 16 $ 8 $ 7 $ 122
Exploration..................... 4 9 9 27 11 18 78
--------- ----------- ---------- --------- --------- --------- ----------
Total......................... $ 50 $ 40 $ 23 $ 43 $ 19 $ 25 $ 200
--------- ----------- ---------- --------- --------- --------- ----------
--------- ----------- ---------- --------- --------- --------- ----------
- ------------------------
(1) Average net daily production for December 1997.
16
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. Development of the Company's
Sonora properties was initiated in the 1970's. 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 accumulated through acquisitions 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 Canyon 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
over the years. 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 downsize these units, and the
fields currently are developed in some areas 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 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 cost to evaluate the Strawn
formation while drilling for the Canyon formation is relatively minor. The
Strawn production is generally commingled with the Canyon production stream. In
1996, the Company acquired over 10,000 gross acres in the Buckhorn horst block,
a localized fault-bounded structural feature, which extends the Canyon and
Strawn to the northeast. Pinnacle reef structures are targeted in this Strawn
extension which are expected to have higher average reserves and initial daily
production of up to 5 MMcf of natural gas.
Since 1993, the Company has continued an aggressive development program in
the Sonora area. Through December 31, 1997, the Company had drilled 455 Canyon
and Strawn wells with only 14 dry holes. The 1997 drilling program resulted in
the drilling of 149 wells which in turn increased net daily production by 10% to
86 MMcfe at December 1997. For 1998, the Company plans to drill an additional
123 wells in Sonora. A majority of the wells proposed to be drilled are on
relatively low risk locations which have not been assigned proved reserves.
Since only a portion of the Company's Sonora acreage is developed on 40 acre
density, the Company has identified over 575 undrilled locations on the
Company's acreage of which 110 have been assigned proved undeveloped reserves.
The Company believes that, subject to further study and drilling results,
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.
MID-CONTINENT AREA
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 additional
interests in the area through multiple acquisitions that have increased reserves
with minimal additional administrative costs. The Company's properties in the
Mid-Continent region are located in and along the northern shelf of the Anadarko
basin in Western Oklahoma and 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 numerous formations of
Pennsylvanian and Pre-Pennsylvanian age rock. Productive depths range from 3,000
to 17,000 feet.
17
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.
SON OF BEVO. The Company is the operator and holds a 35% working interest
in this project in Lipscomb County of the Texas Panhandle. The prolific Upper
Morrow, at a depth of 10,000 feet, was deposited in a meandering river channel
environment with gas stratigraphically trapped in point bars. These point bars
can be up to 50 feet thick and have very good rock properties that yield high
flow rates. Using 3-D seismic, the Company has successfully completed six of
eight wells drilled in this area at initial flow rates ranging up to 5 MMcf per
day. Three wells are planned for 1998.
BRADSHAW FIELD. The Bradshaw field encompasses approximately 250 square
miles and is located approximately ten miles northwest of the Hugoton Field in
Hamilton County, Kansas. The field produces gas from the Winfield, Fort Riley
and Towanda sands of the Chase Group at depths ranging from 2,600 feet to 2,900
feet. The Company operates 137 wells in this field and owns an average working
interest of 94%. Twelve wells are planned for 1998.
The Company has pursued an active low-risk infill drilling program in the
Mid-Continent area over the past four years, including the drilling of 84 wells
in 1997. Average net daily production improved 28% to 105 MMcfe as of December
1997 due to drilling and acquisition activity during the year. The Company plans
to drill 110 wells in this area during 1998, with the primary development focus
being the higher potential Morrow/Springer sand subcrop in the Watonga-Chickasha
Trend. The Company has identified 300 undrilled locations in the Mid-Continent
area, of which 109 have been assigned proved undeveloped reserves.
WESTERN AREA
The Company is actively involved in drilling development and exploration
wells in the Delaware basin of Southeast New Mexico and the Spraberry trend of
West Texas. The primary drilling objectives in this region are the Delaware,
Morrow, Spraberry, Wolfcamp and Tannehill sands.
DELAWARE FORMATION. The Delaware formation was deposited in broad, braided
channel systems over most of the Delaware basin. The sands range in depth from
3,000 to 5,000 feet with multiple objectives in the Bell Canyon and Cherry
Canyon. Over the past three years, the Company has pursued an active development
program in the Happy Valley field in Eddy County of Southeast New Mexico to
exploit the Delaware formation. Production is predominately oil with reserves
ranging from 75,000 to 150,000 Bbls per well.
MORROW FORMATION. The Morrow formation consists of northwest to southeast
trending fluvial systems exhibiting excellent porosity and permeability at
depths between 10,000 to 12,500 feet. The Company continues to drill and
participate in Morrow wells in the Artesia area which is situated along the
northwest shelf of the Delaware basin. Morrow formation gas reserves can range
up to six Bcf for a single well.
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, primarily an oil reservoir, 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
18
the last three years, the Company has pursued an active infill drilling program
in the Spraberry trend which will continue in 1998.
WOLFCAMP FORMATION. The Wolfcamp in the southern Delaware basin is
deposited as a submarine fan sequence that is 200 to 800 feet thick and ranges
in depth from 4,000 to 12,000 feet. The Wolfcamp is the primary target in the
Company's development activities in the Brown Bassett area.
PITCHFORK RANCH. The Company has an option to explore on approximately
140,000 acres of the Pitchfork Ranch over the next two years. The Pitchfork
Ranch is located in King and Dickens Counties, Texas. The Company is the
operator with a 78% working interest. Target zones are the Tannehill sand at a
depth of 4,500 feet and the Strawn Lime 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 Company completed a
30 square mile 3-D seismic project and successfully completed 4 of 7 Tannehill
tests during 1997. Four additional exploratory tests are planned for 1998 in the
initial seismic area. To the northeast of the initial shoot, the Company plans
to conduct a 50 square mile 3-D seismic project during the second quarter of
1998.
During 1997, the Company drilled 69 wells in the Western area, resulting in
a 19% increase in average daily production to 32.3 MMcfe as of December 1997.
The Company has identified 500 undrilled locations in this region of which 201
have been assigned proved undeveloped reserves. Plans for 1998 include the
drilling of 77 wells in this region.
GULF COAST AREA
YOAKUM GORGE AREA. The Company holds working interests ranging from 30% to
87.5% in 60,000 gross acres in this project located in Lavaca County, Texas.
Approximately 200 square miles of high-fold 3-D seismic data was obtained in
1996 and 1997 which continues to be evaluated. The target zones are the shallow
Miocene, Frio, Yegua and Upper Wilcox sands, ranging in depth from 3,500 to
8,000 feet and the deeper Lower Wilcox sands from 10,000 to 17,000 feet. The
shallow sands were deposited in a fluvial environment and are often point bar
sands with high porosity and permeability. These sands have a reserve potential
ranging from .5 to 20 Bcf per well and are relatively easy to identify using 3-D
seismic. The Company successfully completed 17 of 21 shallow tests during 1997
and plans to drill up to 15 additional wells during 1998.
In 1997, the Company accelerated its Lower Wilcox drilling program with the
drilling of eight wells, which included three 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 deeper structures present higher risk but have greater
potential, ranging up to 100 Bcf per field. The Jacobs Ranch #1 discovery in the
Cranz field logged approximately 180 feet of pay and had initial production of 7
MMcfe per day from 40 feet of perforations. In addition, five wells were
completed in the S.W. Speaks field which have increased gross production in this
field to approximately 23 MMcf per day, 5 MMcf net to the Company's ownership.
Drilling plans for 1998 include the drilling of 20 Lower Wilcox wells in the
Yoakum Gorge area, including six additional wells in the S.W. Speaks field.
During 1997, 35 wells were drilled by the Company in the Gulf Coast area and
average net daily production as of December 1997 was 31 MMcfe. The Company has
identified 100 undrilled locations in the Gulf Coast region of which 27 have
been assigned proved undeveloped reserves. For 1998, 50 wells are planned to be
drilled.
19
ARKLATEX AREA
SMACKOVER TREND. The Company's operations in the Smackover Trend of
Southwestern Arkansas are focused primarily in the Midway and Buckner fields,
both of which are 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 79% working interest in
this field. Midway is a mature waterflood unit that has produced approximately
80 million barrels of oil since 1942, or approximately 50% of the estimated
original oil in place. Horizontal drilling technology is being utilized to
significantly increase production levels and enhance oil recoveries. The Buckner
field is located approximately 11 miles southeast of the Midway field in
Lafayette County, Arkansas, and has produced approximately 12 million barrels of
oil, or approximately 20% of the estimated original oil in place. In 1997, the
Buckner field was unitized and a horizontal drilling program and waterflood
project were initiated. Ten horizontal wells are planned for 1998.
COTTON VALLEY REEF TREND. The Company has varying working interests in
100,000 acres in the Cotton Valley Reef trend in Leon, Freestone, Smith,
Anderson and Cherokee Counties of East Texas, an area that has attracted many of
the largest independent producers. The targets are pinnacle reef build-ups at
depths ranging from 13,000 to 17,000 feet that formed on the shelf slope in a
shallow water environment during the Jurassic age. These reefs display a dimout
on the Cotton Valley seismic event and therefore are identifiable on high
quality 3-D seismic data. They are typically between 200 and 400 feet thick and
can extend across 40 to 80 acres. Discoveries in the region by other operators
have resulted in initial production rates ranging between 10 and 30 MMcf per
day. In 1997, the Company's first Cotton Valley Reef test resulted in a
discovery, the McMahon #4, which is presently producing at 10 MMcf per day.
Three additional Cotton Valley Reef tests are planned for 1998.
OFFSHORE AREA
The Company owns working interests in ten operated and eight
outside-operated oil and gas production platforms and 174,000 acres in the Gulf
of Mexico. The more significant of these properties are described as follows.
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 3-D seismic data has been collected in this area and the Company is
commencing a five prospect drilling program in 1998. High-quality 3-D 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 3-D seismic information economically
feasible. The Company has identified 16 exploration prospects in the shallow
waters offshore in the Gulf of Mexico and plans to drill at least 5 prospects in
1998.
HIGH ISLAND BLOCK 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. At December 31, 1997 this block had average net daily production
of 14.9 MMcfe.
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. On April 1,
1997, a blowout and fire occurred during the drilling of a horizontal
development well at East Cameron Block 328. No personnel were injured in the
accident. The upper structure of the platform, however, was severely damaged.
The well was successfully capped and the four remaining wells on the platform
were secured. The production deck was removed and dismantled and certain
production equipment has been salvaged. The Company is rebuilding the production
deck and expects to restore production from the
20
platform in the second quarter of 1998. The platform was producing at
approximately 11.4 MMcfe per day prior to the blowout. An additional well has
been drilled and completed, with production awaiting the completion of the
platform.
WEST DELTA 152. The Company owns between a 20% and a 39% non-operated
working interest in West Delta 152 which has 17 producing wells. The wells
produce from an eight-pile, 24-slot platform located in 380 feet of water
approximately 40 miles southwest of Venice, Louisiana. West Delta 152 had
average net daily production of 8.3 MMcfe in December 1997.
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 and Present Values attributable to total
proved reserves at such dates.
PROVED RESERVES
AS OF DECEMBER 31,
-----------------------------------------------------
1993 1994 1995 1996 1997
--------- --------- --------- --------- ---------
(DOLLARS IN MILLIONS, EXCEPT PRICE DATA)
ESTIMATED PROVED RESERVES:
Natural gas (Bcf)............................. 502.0 574.0 753.9 849.2 1,028.8
Oil (MMBbls).................................. 20.9 19.3 20.4 23.5 29.1
Total (Bcfe)................................ 627.2 689.9 876.1 990.2 1,203.4
Future net revenues........................... $ 1,167.9 $ 1,219.8 $ 1,531.5 $ 2,417.4 $ 2,169.9
Present Value including Fixed-Price
Contracts................................... $ 589.0 $ 616.0 $ 737.5 $ 1,117.7 $ 1,136.0
Present Value excluding Fixed-Price
Contracts................................... $ 455.4 $ 358.8 $ 524.4 $ 1,303.7 $ 1,002.6
ESTIMATED PROVED DEVELOPED RESERVES:
Natural gas (Bcf)............................. 378.0 433.3 630.6 709.7 899.2
Oil (MMBbls).................................. 14.8 13.1 14.8 17.9 24.3
Total (Bcfe)................................ 467.0 511.8 719.6 817.1 1,045.1
YEAR-END PRICES USED IN ESTIMATING FUTURE NET
REVENUES (1):
Natural gas (per Mcf)......................... $ 2.88 $ 2.61 $ 2.60 $ 3.55 $ 2.73
Oil (per Bbl)................................. $ 13.91 $ 16.08 $ 17.80 $ 24.66 $ 16.77
- ------------------------
(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, 1997 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
21
December 31, 1997. 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 $16 million
and $29 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, 1997. If such Fixed-Price Contracts were
not in effect and the Company used December 31, 1997 wellhead prices, the
estimated future net revenues attributable to proved reserves and the Present
Value thereof would be $1.9 billion and $1.0 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 data set forth herein represent only estimates. 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.
COSTS INCURRED
AS OF DECEMBER 31,
----------------------------------------------------------
1993 1994 1995 1996 1997
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
Property acquisition costs: (1)
Proved..................................... $ 188,940 $ 36,575 $ 118,652 $ 36,125 $ 349,037
Unproved................................... 464 4,953 1,717 6,934 109,648
---------- ---------- ---------- ---------- ----------
189,404 41,528 120,369 43,059 458,685
Exploration costs.......................... -- -- 391 10,610 21,514
Development costs.......................... 29,959 67,764 64,498 80,553 122,402
---------- ---------- ---------- ---------- ----------
Total.................................... $ 219,363 $ 109,292 $ 185,258 $ 134,222 $ 602,601
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
- ------------------------
(1) Proved and unproved property acquisition costs for 1997 include $339.9
million and $98.0 million, respectively, of allocated American Acquisition
purchase price. See "Recent Developments--American Exploration."
22
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,
-----------------------------------------------------------------------------
1993 1994 1995 1996 1997
------------- ------------- ------------- ------------- -------------
GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Development wells:
Gas............................................... 51 21 144 131 134 115 179 130 223 166
Oil............................................... 13 11 27 6 114 28 92 19 52 20
Dry............................................... 7 3 4 2 14 5 9 5 20 14
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total........................................... 71 35 175 139 262 148 280 154 295 200
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Exploratory wells:
Gas............................................... -- -- -- -- 3 1 18 6 32 24
Oil............................................... -- -- -- -- -- -- -- -- 4 3
Dry............................................... -- -- -- -- -- -- 7 2 12 9
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total........................................... -- -- -- -- 3 1 25 8 48 36
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
As of December 31, 1997, the Company was involved in the drilling, testing
or completing of 16 gross (7 net) development wells.
ACREAGE
The following table sets forth the Company's developed and undeveloped oil
and gas lease and mineral acreage as of December 31, 1997. 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:
Sonora.................................................. 252,809 194,710 150,303 96,700
Mid-Continent........................................... 637,771 257,904 252,950 75,594
Western................................................. 580,966 107,280 641,822 252,217
Gulf Coast.............................................. 131,903 37,550 169,984 95,377
Offshore................................................ 67,444 18,385 106,785 54,709
Arklatex................................................ 63,937 10,102 396,582 91,013
---------- --------- ---------- ---------
Total................................................. 1,734,830 625,931 1,718,426 665,610
---------- --------- ---------- ---------
---------- --------- ---------- ---------
PRODUCTIVE WELL SUMMARY
The following table sets forth the Company's ownership in productive wells
at December 31, 1997. Gross oil and gas wells include 171 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.................................................................................... 6,061 2,746
Oil.................................................................................... 3,030 602
--------- ---------
Total................................................................................ 9,091 3,348
--------- ---------
--------- ---------
23
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 27 Bcfe of the Company's oil and gas properties are
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. The judgment amount was in addition to a $1.3 million deposit
previously paid by Midcon to the Company. 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. 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. On
January 24, 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. The
Company considers the allegations of Midcon to be without merit and will
vigorously defend against this action.
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 also requested
declaratory judgment that it has a right to relief from the contract price due
to regulatory changes, which it alleges renders the contract commercially
impracticable, and that Federal Energy Regulatory Commission Order No. 636 is a
condition subsequent which excuses performance under the contract. In April
1995, American filed counterclaims against KNGSS relating to the failure of
KNGSS to take and pay for certain minimum volumes of gas, among other
contractual matters. American has dismissed all of its counterclaims, and KNGSS
has dismissed its commercially impracticable and condition subsequent claims.
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.
No appeal to the ruling has been filed by KNGSS as of March 6, 1998. Although
the Company cannot predict the ultimate outcome of this
24
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.
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 $3.2
million plus interest. In addition, American had received preliminary and final
royalty underpayment determinations from the MMS 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
On October 14, 1997, at a special meeting of the stockholders of the
Company, the stockholders approved the merger of American with and into the
Company pursuant to the Agreement and Plan of Reorganization, dated as of June
24, 1997, as amended between American and the Company. There were 25,049,811
shares voted in favor of the merger, 3,800 shares voted against or withheld and
2,772,689 shares were abstentions or broker non-votes.
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 6, 1998, the Company estimates
there were approximately 13,500 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, 1996 and 1997, were as follows:
COMMON STOCK MARKET PRICES
1996 1997
-------------------- --------------------
HIGH LOW HIGH LOW
--------- --------- --------- ---------
Quarter:
First............................................................ $ 15.13 $ 10.38 $ 19.50 $ 14.50
Second........................................................... 15.13 10.75 18.38 13.38
Third............................................................ 15.75 13.25 22.50 15.38
Fourth........................................................... 18.00 15.00 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.
25
ITEM 6--SELECTED FINANCIAL DATA
The selected financial data presented below as of December 31, 1996 and
1997, and for each of the three years ended December 31, 1995, 1996 and 1997,
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, 1993, 1994
and 1995, and for the years ended December 31, 1993 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."
SELECTED FINANCIAL DATA
YEARS ENDED DECEMBER 31,
-------------------------------------------------------
1993 1994 1995 1996 1997
--------- --------- --------- --------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Oil and gas sales..................................... $ 92,912 $ 138,584 $ 163,366 $ 185,558 $ 222,016
Other income (loss)................................... 2,269 1,953 (418) 3,947 10,901
--------- --------- --------- --------- -----------
Total revenues...................................... 95,181 140,537 162,948 189,505 232,917
--------- --------- --------- --------- -----------
Operating costs....................................... 26,715 33,713 35,352 44,615 49,169
General and administrative............................ 11,822 15,309 16,631 16,325 18,855
Exploration costs..................................... -- -- -- 4,965 8,956
Depreciation, depletion and amortization.............. 38,649 53,321 57,796 65,278 79,325
Impairment............................................ -- 5,300 15,694 -- 75,198
Interest.............................................. 14,364 16,856 21,736 26,822 28,737
--------- --------- --------- --------- -----------
Total expenses...................................... 91,550 124,499 147,209 158,005 260,240
--------- --------- --------- --------- -----------
Income (loss) before income taxes..................... 3,631 16,038 15,739 31,500 (27,323)
Income taxes.......................................... 1,371 5,292 4,722 10,398 (11,261)
--------- --------- --------- --------- -----------
Net income (loss)..................................... $ 2,260 $ 10,746 $ 11,017 $ 21,102 $ (16,062)
--------- --------- --------- --------- -----------
--------- --------- --------- --------- -----------
Net income (loss) per share--basic and diluted........ $ .11 $ .39 $ .40 $ .76 $ (.53)
Weighted average diluted common shares outstanding.... 21,042 27,800 27,804 27,810 30,233
STATEMENT OF CASH FLOWS DATA:
Net cash provided by operating activities............. $ 52,666 $ 80,894 $ 89,515 $ 101,761 $ 129,846
Net cash used in investing activities................. 180,038 102,969 171,540 150,857 216,603
Net cash provided by financing activities............. 138,559 13,701 80,629 55,261 84,546
EBITDAX (1)........................................... 59,169 94,040 111,572 128,565 164,893
AS OF DECEMBER 31,
-------------------------------------------------------
1993 1994 1995 1996 1997
--------- --------- --------- --------- -----------
(IN THOUSANDS)
BALANCE SHEET DATA:
Oil and gas properties, net........................... $ 432,842 $ 483,214 $ 584,900 $ 652,257 $ 1,077,091
Total assets.......................................... 481,488 528,261 634,937 733,613 1,210,954
Long-term debt, including current portion............. 203,955 215,010 314,760 343,907 563,344
Stockholders' equity.................................. 213,818 224,564 242,581 263,693 469,204
- --------------------------
(1) 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.
26
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, 1997, this strategy has resulted in a 220% increase in proved reserves to
1.2 Tcfe. In addition, production levels increased 194% to 84 Bcfe and cash
flows from operating activities increased 483% to $129.8 million. Excluding a
one-time impairment charge recognized in connection with the American
Acquisition, the Company also realized record results of operations for 1997.
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 this five-year period, the Company made proved reserve acquisitions
aggregating 853 Bcfe, purchased for a total consideration of $729.3 million, or
$.86 per Mcfe. Of particular significance was the American Acquisition which was
completed on October 14, 1997. See related discussion under "--Commitments and
Capital Expenditures."
The Company's drilling program over this five-year period resulted in the
drilling of 1,159 gross (721 net wells), with an overall drilling success rate
of 94%, adding 362 Bcfe of reserves (including revisions of previous estimates)
to its proved reserve base. The year ended December 31, 1997 marked the fourth
consecutive year that the Company replaced its production by both its
acquisition and drilling programs. Total finding costs (total costs incurred to
acquire, explore and develop oil and gas properties divided by the increase in
proved reserves through acquisitions of proved properties, extensions and
discoveries, and revisions of previous estimates) over this five-year period
averaged $1.03 per Mcfe. 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 1997, the
Company invested $128 million in connection with exploration activities,
including $98 million allocated to the unproved acreage position obtained in the
American Acquisition. This significant commitment has had the impact of
increasing finding costs in the near term, but is expected to result in future
reserve additions at more favorable rates.
As of December 31, 1997, the Company's portfolio of Fixed-Price Contracts
hedge 311 Bcfe of future production at escalating fixed prices, representing 26%
of its estimated proved reserves. These fixed prices are presently significantly
higher than the forward market prices for natural gas and oil. Over the past few
years, competition in Fixed-Price Contracts has increased, opportunities for
attractive Fixed-Price Contracts have diminished and spot prices for natural gas
are higher than nearby forward market prices. In response to these changes, a
progressively smaller share of the Company's production and reserve growth has
been hedged due to a reluctance to sell into the prevailing forward market where
prices trend down or are essentially flat over the next several years. More
recent hedging activity has been for shorter periods of time, generally less
than 12 months, when market conditions have been viewed as favorable. The
Company may decide to hedge a greater or smaller share of production in the
future depending upon market conditions, capital investment considerations and
other factors. See "--Fixed-Price Contracts".
SELECTED OPERATING DATA. The following table provides certain data relating
to the Company's operations.
27
SELECTED OPERATING DATA
YEARS ENDED DECEMBER 31,
-----------------------------------------------------
1993 1994 1995 1996 1997
--------- --------- --------- --------- ---------
OIL AND GAS SALES (M$):
Oil sales:
Wellhead................................................ $ 34,542 $ 29,207 $ 28,973 $ 39,372 $ 40,680
Effect of Fixed-Price Contracts (1)..................... 1,516 5,064 1,077 (3,198) 803
--------- --------- --------- --------- ---------
Total................................................... $ 36,058 $ 34,271 $ 30,050 $ 36,174 $ 41,483
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Natural gas sales:
Wellhead................................................ $ 60,911 $ 95,353 $ 110,073 $ 148,244 $ 185,623
Effect of Fixed-Price Contracts (1)..................... (4,057) 8,960 23,243 1,140 (5,090)
--------- --------- --------- --------- ---------
Total................................................... $ 56,854 $ 104,313 $ 133,316 $ 149,384 $ 180,533
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
PRODUCTION:
Oil production (MBbls).................................... 2,106 1,873 1,695 1,849 2,088
Natural gas production (MMcf)............................. 30,540 43,082 51,264 63,910 71,731
Equivalent production (MMcfe)............................. 43,179 54,321 61,434 75,004 84,262
Oil production hedged by Fixed-Price Contracts
(MBbls)............................................... 650 1,698 1,464 1,241 686
Gas production hedged by Fixed-Price Contracts (BBtu)... 28,775 32,308 31,579 32,508 43,185
AVERAGE SALES PRICE:
Oil price (per Bbl):
Wellhead price.......................................... $ 16.40 $ 15.59 $ 17.09 $ 21.29 $ 19.48
Effect of Fixed-Price Contracts (1)..................... .72 2.71 .64 (1.73) .38
--------- --------- --------- --------- ---------
Total................................................... $ 17.12 $ 18.30 $ 17.73 $ 19.56 $ 19.86
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Average fixed price provided by Fixed-Price Contracts... $ 19.89 $ 20.15 $ 19.12 $ 19.53 $ 21.81
Net effective cash realization (2)...................... 94% 92% 93% 96% 96%
Natural gas price (per Mcf):
Wellhead price.......................................... $ 1.99 $ 2.21 $ 2.15 $ 2.32 $ 2.59
Effect of Fixed-Price Contracts (1)..................... (.13) .21 .45 .02 (.07)
--------- --------- --------- --------- ---------
Total................................................... $ 1.86 $ 2.42 $ 2.60 $ 2.34 $ 2.52
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Average fixed price provided by Fixed-Price Contracts... $ 2.17 $ 2.31 $ 2.40 $ 2.43 $ 2.51
Net effective cash realization (2)...................... 87% 89% 97% 97% 99%
Natural gas equivalent price (per Mcfe)................... $ 2.15 $ 2.55 $ 2.66 $ 2.47 $ 2.63
EXPENSES AND COSTS INCURRED (PER MCFE):
Lease operating expenses................................ $ .50 $ .51 $ .47 $ .47 $ .45
Production taxes........................................ .12 .11 .11 .12 .14
General and administrative.............................. .27 .28 .27 .22 .22
Depreciation, depletion and amortization--oil and gas
properties (3)........................................ .85 .92 .88 .82 .88
Finding cost (4)........................................ .71 .92 .70 .71 1.81
- --------------------------
(1) Effect of Fixed-Price Contracts represents the hedging results from the
Company's Fixed-Price Contracts. See "--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 "--Fixed-Price Contracts--Market Risk."
(3) Does not include impairments. See "--Results of Operations--Fiscal Year 1997
Compared to Fiscal Year 1996" and "--Results of Operations--Fiscal Year 1996
Compared to Fiscal Year 1995."
(4) Total costs incurred to acquire, explore and develop oil and gas properties
divided by the increase in proved reserves through acquisitions of proved
properties, extensions and discoveries, and revisions of previous estimates.
Amounts for 1997 include the allocated purchase price of the American
Acquisition.
28
The following table presents certain information regarding the Company's
proved oil and gas reserves.
OIL AND GAS RESERVES DATA
AS OF DECEMBER 31,
---------------------------------------------------------------
1993 1994 1995 1996 1997
----------- ----------- ----------- ----------- -----------
(DOLLARS IN THOUSANDS)
ESTIMATED NET PROVED RESERVES:
Natural gas (MMcf)............................... 502,018 574,025 753,919 849,199 1,028,752
Oil (MBbls)...................................... 20,867 19,317 20,360 23,497 29,109
Total (MMcfe).................................... 627,222 689,924 876,076 990,179 1,203,405
Reserve replacement ratio (1).................... 714% 219% 430% 254% 396%
Reserve life (in years) (2)...................... 14.5 12.7 14.3 13.2 10.7
Estimated future net revenues including Fixed-
Price Contracts (3)............................ $ 1,167,940 $ 1,219,760 $ 1,531,501 $ 2,417,430 $ 2,169,917
Present Value including Fixed-Price Contracts
(3)............................................ 588,986 616,005 737,512 1,117,734 1,135,970
Present Value excluding Fixed-Price Contracts
(3)............................................ 455,362 358,766 524,354 1,303,709 1,002,649
- --------------------------
(1) The reserve replacement ratio is a percentage determined by dividing the
estimated proved reserves added during a year from exploration and
development activities, acquisitions of proved reserves and revisions of
previous estimates by the oil and gas volumes produced during that year.
(2) The reserve life is calculated by dividing estimated net proved reserves as
of the date of determination by production for the preceding twelve months.
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 "Business and Properties--Reserves."
RESULTS OF OPERATIONS--FISCAL YEAR 1997 COMPARED TO FISCAL YEAR 1996
NET INCOME (LOSS) AND CASH FLOWS FROM OPERATING ACTIVITIES. Excluding the
effects of a fourth-quarter impairment charge, the Company reported net income
of $31.1 million, or $1.03 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. 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. For the year ended December 31, 1997, the Company
reported a net loss of $16.1 million, or $.53 per share, after the effects of a
$75.2 million non-cash impairment charge ($47.1 million after tax),
substantially all of which was recognized in connection with the American
Acquisition.
PRODUCTION. Total production for the year ended December 31, 1997 grew 12%,
to 84.3 Bcfe, compared to 75.0 Bcfe produced during 1996. Natural gas production
for 1997 was 71.7 Bcf, a 12% increase over the 63.9 Bcf produced in 1996. Oil
production in 1997 increased 13% to 2.1 MMBbls compared to 1.8 MMBbls produced
in 1996. These increases are primarily attributable to the American Acquisition
and the results of the Company's exploration and development drilling
activities.
OIL AND GAS PRICES. On a natural gas equivalent basis, the Company realized
an average price of $2.63 per Mcfe for 1997, a 6% increase compared to the $2.47
per Mcfe received in 1996. The Company's 1997 gas production yielded an average
price of $2.52 per Mcf, an 8% increase compared to 1996's average price of $2.34
per Mcf. The Company's average gas price for 1997 decreased $.07 per Mcf as a
result of the Company's hedging activities. The average gas price for 1996 was
enhanced $.02 per Mcf as a result of Fixed-Price Contracts in effect for that
period. The average oil price received during 1997 improved 2% to $19.86 per Bbl
compared to $19.56 per Bbl for 1996. Fixed-
29
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
was to increase gas sales by 21% to $180.5 million in relation 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 "--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, which include lease operating expenses
and production taxes, increased to $49.2 million for 1997 compared to $44.6
million 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. 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 for 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. Depreciation, depletion and
amortization expense ("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
incurred 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.
30
RESULTS OF OPERATIONS--FISCAL YEAR 1996 COMPARED TO FISCAL YEAR 1995
NET INCOME AND CASH FLOWS FROM OPERATING ACTIVITIES. For the year ended
December 31, 1996, the Company reported net income of $21.1 million, or $.76 per
share, on total revenue of $189.5 million. This compares with net income of
$11.0 million, or $.40 per share, on total revenue of $162.9 million for the
year ended December 31, 1995. Cash flows from operating activities (before
working capital changes) for 1996 also reflected significant improvement,
increasing 13% to $101.0 million from the $89.1 million reported for 1995. The
improvement in earnings and cash flows was achieved primarily through growth in
oil and gas production. In addition, earnings for the year ended December 31,
1995 were reduced by a $15.7 million pre-tax impairment recorded in connection
with the adoption of SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"). These items
are discussed in greater detail below. Cash flows provided by operating
activities, inclusive of the net change in working capital, increased to $101.8
million in 1996 compared to $89.5 million for 1995, also due principally to the
1996 increase in production.
PRODUCTION. On a natural gas equivalent basis, the Company produced 75.0
Bcfe, an increase of 22% compared to 61.4 Bcfe produced during 1995. Natural gas
production for 1996 was 63.9 Bcf, a 25% increase over the 51.3 Bcf produced in
1995. Oil production in 1996 increased 9% to 1.8 MMBbls, compared to 1.7 MMBbls
produced in 1995. These increases are attributable to the results of the
Company's exploration and development drilling activities and to acquisitions of
proved reserves.
OIL AND GAS PRICES. On a natural gas equivalent basis, the Company realized
an average price of $2.47 for 1996, a 7% decrease from the $2.66 received in
1995. The Company's 1996 gas production yielded an average price of $2.34 per
Mcf, a 10% decrease compared to 1995's average price of $2.60 per Mcf. This
decrease is primarily attributable to the expiration in December 1995 of a
contract which paid $3.90 per Mcf for approximately 25% of the Company's total
gas production in 1995. The impact of Fixed-Price Contracts in effect for the
years ended December 31, 1996 and 1995 was to increase the average gas price by
$.02 per Mcf and $.45 per Mcf, respectively. The average oil price received
during 1996 improved 10% to $19.56 per Bbl compared to $17.73 per Bbl for 1995.
Fixed-Price Contracts decreased the average oil price in 1996 by $1.73 per Bbl
and increased the average oil price in 1995 by $.64 per Bbl.
The net effect of higher gas production and lower gas prices for 1996 was to
increase gas sales by 12% to $149.4 million in relation to $133.3 million
reported for 1995. The effect of higher oil prices and higher oil production was
to increase oil sales for 1996 to $36.2 million, a 20% increase from 1995. The
aggregate impact of the Fixed-Price Contracts hedging the Company's oil and gas
production was to decrease oil and gas revenue by $2.1 million in 1996 and to
increase oil and gas revenue by $24.3 million in 1995.
OTHER INCOME (LOSS). The Company realized other income for 1996 of $3.9
million compared to a net loss of $.4 million for 1995. Other income (loss) for
1996 and 1995 included $1.7 million and $1.3 million, respectively, of proceeds
received pursuant to the settlement of a legal claim. The net loss for 1995 was
primarily the result of a $4.3 million basis loss recorded in the fourth quarter
of 1995.
OPERATING COSTS. Operating costs increased to $44.6 million for 1996
compared to $35.4 million for 1995. This increase is principally attributable to
producing properties acquired and wells drilled during 1996 and 1995 and to
higher production taxes associated with the 1996 increase in oil and gas
revenue. On a natural gas equivalent unit of production basis, lease operating
expenses were $.47 per Mcfe for both 1996 and 1995.
GENERAL AND ADMINISTRATIVE EXPENSE. G&A for 1996 was $16.3 million compared
to $16.6 million for 1995. This decrease is primarily attributable to an
increase in overhead and cost recoveries from third parties which exceeded
increases in personnel and related costs. G&A per natural gas equivalent unit of
production was $.22 per Mcfe for 1996 compared to $.27 per Mcfe for 1995. This
improvement is attributable to a significant increase in production for 1996
which did not entail a proportionate increase in personnel and related costs.
EXPLORATION COSTS. Exploration costs, comprised of exploratory geological
and geophysical costs, exploratory dry holes and leasehold impairment costs,
were $5.0 million for the year ended December 31, 1996. This amount includes
$2.5 million of seismic acquisition costs, $1.9 million of dry hole costs and
$.6 million of leasehold impairment. No exploratory dry holes were drilled and
no exploratory geological and geophysical costs were incurred during 1995.
31
DEPRECIATION, DEPLETION AND AMORTIZATION. DD&A for the year ended December
31, 1996 was $65.3 million compared to $57.8 million for 1995. This increase is
mainly due to higher production levels for 1996 compared to 1995. The oil and
gas DD&A rate per equivalent unit of production was $.82 per Mcfe for 1996
compared to $.88 per Mcfe in 1995. The improved DD&A rate for 1996 was
principally due to favorable reserve finding cost results for the periods
presented and to an impairment charge taken in the fourth quarter of 1995 upon
the adoption of SFAS 121.
IMPAIRMENT OF OIL AND GAS PROPERTIES. In the fourth quarter of 1995, the
Company adopted the provisions of SFAS 121, pursuant to which the Company's oil
and gas properties are reviewed on a field-by-field basis for indications of
impairment. See Note 1 of the Notes to Consolidated Financial Statements
appearing elsewhere herein. The implementation of SFAS 121 resulted in a pre-tax
impairment charge of $15.7 million for the year ended December 31, 1995,
affecting approximately 5% of the Company's 327 fields. No impairment was
incurred for the year ended December 31, 1996.
INTEREST EXPENSE. Interest expense for 1996 was $26.8 million compared to
$21.7 million for 1995. This increase is primarily attributable to higher
average long-term debt balances outstanding during 1996. The net impact of
interest rate swaps in effect during the years ended December 31, 1996 and 1995
was to increase interest expense by $.9 million in 1996 and to decrease interest
expense by $.3 million in 1995.
INCOME TAXES. For 1996, the Company recorded a tax provision of $10.4
million on pre-tax income of $31.5 million, an effective rate of 33%. This
compares to a provision of $4.7 million, or 30% on pre-tax income of $15.7
million for 1995. The effective rate for both years was lower than the statutory
rate primarily 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, 1995, 1996 and
1997, the Company expended cash flows from investing activities of $185.3
million, $134.2 million and $235.8 million, respectively, in oil and gas
property acquisition, exploration and development activities and currently
anticipates spending approximately $200 million in exploration and development
activities in 1998. 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 $89.5 million, $101.8 million and $129.8
million, representing 48%, 76% and 55%, 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
significant portion of the price risk and cash flow volatility has been hedged
by Fixed-Price Contracts. See "--Fixed-Price Contracts." The growth achieved in
cash flows from operating activities over this period is discussed under
"--Results of Operations--Fiscal Year 1997 Compared to Fiscal Year 1996" and
"--Results of Operations--Fiscal Year 1996 Compared to Fiscal Year 1995."
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, 1997. 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,
1995, 1996 and 1997, net amounts borrowed under such facilities were $99.6
million, $29.0 million and $95.7 million, or 54%, 22% and 41%, 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, for the year
ended December 31, 1996, the Company received $26.2 million of deferred hedging
gains, the majority of which was received in connection with the amendment of a
certain Fixed-Price Contract.
The Company's EBITDAX increased from $111.6 million in 1995 to $128.6
million in 1996 and $164.9 million in 1997. EBITDAX is defined herein as income
(loss) before interest, income taxes, DD&A, impairment and exploration
32
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. On October 14, 1997, in connection
with the American Acquisition, the Company replaced its $300 million borrowing
base credit facility with a new $550 million revolving credit facility (the
"Credit Facility"). Upon the issuance of senior notes in December 1997, the
Company reduced the aggregate commitment under the Credit Facility to $450
million (the "Commitment"). 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. Letters of credit are limited to $75 million of
such availability. No principal payments are required under the Credit Facility
prior to termination on October 14, 2002. The Company has relied upon the Credit
Facility and the predecessor bank facility to provide funds for acquisitions and
to provide letters of credit to meet the Company's margin requirements under
Fixed-Price Contracts. As of December 31, 1997, the Company had $261.0 million
of principal and $5.0 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, 1997,
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, 1997, the effective interest rate for borrowings
under the Credit Facility was 6.3%, including the effect of interest rate swaps.
The Credit Facility contains various affirmative and restrictive covenants
which generally provide greater flexibility than those contained in the prior
facility. These covenants, 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. In
connection with the termination of the $300 million borrowing base credit
facility, the Company recognized a charge of approximately $1.7 million
representing the unamortized loan origination fees associated with the facility.
OTHER LINES OF CREDIT. The Company has certain other unsecured lines of
credit available to it, which aggregated $42.8 million as of December 31, 1997.
Such short-term lines of credit are primarily used to meet margining
requirements under Fixed-Price Contracts and for working capital purposes. At
December 31, 1997, the Company had $4.5 million of indebtedness and $15.3
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. In October 1997, the Company entered
into financial swaps which effectively fixed the price of the underlying
treasury bond used to price the Senior Notes. The settlement of these hedges
ultimately resulted in a deferred hedging loss of $3.6 million which is being
amortized into interest expense over the life of the Senior Notes.
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, 1997, the Company had working capital of $3.2 million and a
current ratio of 1.0 to 1. Total long-term debt outstanding at December 31, 1997
was $563.3 million. The Company's long-term debt as a percentage of its total
capitalization was 55%. The amount of required principal payments for the next
five years and thereafter as of
33
December 31, 1997 are as follows: 1998--$0; 1999--$0; 2000--$0; 2001--$0;
2002--$265.5 million; 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 1998 and to meet the Company's margin
requirements under its Fixed-Price Contracts. See "--Commitments and Capital
Expenditures" and "--Fixed-Price Contracts--Margining."
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, 1997, the Company had fixed the interest rate on
average notional amounts of $99 million and $33 million for the years ended
December 31, 1998 and 1999, respectively. Under the interest rate swaps, the
Company receives the LIBOR three-month rate (5.8% at December 31, 1997) and pays
an average rate of 6.3% for 1998 and 6.5% for 1999. The notional amounts are
less than the maximum amount anticipated to be available under the Credit
Facility in such years. The Company has an additional interest rate swap under
which the Company pays the LIBOR three-month rate and receives 7.1% on a
notional amount of $25 million. This interest rate swap matures June 2004.
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 deferred and amortized as interest
expense over the original contract term. At December 31, 1996 and 1997, the
amount of such deferrals was not material.
A reconciliation of the notional amounts of the Company's interest rate
swaps for each of the three years ended December 31, 1995, 1996 and 1997, is as
follows:
INTEREST RATE SWAPS--NOTIONAL AMOUNTS
YEARS ENDED DECEMBER 31,
-----------------------------------
1995 1996 1997
---------- ---------- -----------
(IN THOUSANDS)
Notional amount of fixed interest rate swaps, beginning of year... $ 86,000 $ 203,000 $ 186,000
Interest rate swaps added....................................... 155,000 -- 150,000
Interest rate swap settlements.................................. (38,000) (17,000) (44,000)
Interest rate swaps canceled.................................... -- -- (150,000)
---------- ---------- -----------
Notional amount of fixed interest rate swaps, end of year......... $ 203,000 $ 186,000 $ 142,000
---------- ---------- -----------
---------- ---------- -----------
Notional amount of floating interest rate swaps, beginning of
year............................................................ $ -- $ -- $ 25,000
Interest rate swap added........................................ -- 25,000 --
---------- ---------- -----------
Notional amount of floating interest rate swaps, end of year...... $ -- $ 25,000 $ 25,000
---------- ---------- -----------
---------- ---------- -----------
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, 1997, the Company
expended $349.0 million on proved reserve acquisitions, $109.7 million on
unproved oil and gas property acquisitions, $21.5 million on exploration
activities and $122.4 million on development activities in connection with this
strategy. The most significant 1997 acquisition occurred in October with the
purchase of American. The American Acquisition consideration, including the
non-cash consideration issued and assumed, resulted in a purchase price
allocation to the acquired oil and gas properties of $437.9 million, including
$98.0 million to unproved properties. See "--Capital Resources and Liquidity"
and Note 11 of the Notes to Consolidated Financial Statements appearing
elsewhere herein. The American oil and gas properties 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. Additionally, the Company made other acquisitions of proved oil and gas
reserves during 1997 which aggregated 17 Bcfe for a combined purchase price of
$9.1 million. The results of operations relating to all these acquisitions have
been included in the Company's financial results for the periods subsequent to
the closing of each transaction. The Company's 1997 drilling program
34
resulted in the drilling of 343 gross (236 net) wells, including 48 gross (36
net) exploratory wells and 295 gross (200 net) development wells. The Company's
drilling activities added 125 Bcfe to its proved reserve base.
The Company's approved drilling budget for 1998 provides for approximately
$200 million in oil and gas exploration and development activities. Of these
expenditures, approximately $122 million is targeted for development activities
and $78 million for 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. 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 1998.
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.
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, 1995, 1996 and 1997, Fixed-Price Contracts hedged 84%, 51%
and 60%, respectively, of the Company's gas production and 86%, 67% and 33%,
respectively, of its oil production. As of December 31, 1997, Fixed-Price
Contracts are in place to hedge 310 Bcf of the Company's estimated future gas
production and 79 MBbls of its 1998 oil 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.
35
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,
1997.
YEARS ENDING DECEMBER 31, BALANCE
------------------------------------------------ THROUGH
1998 1999 2000 2001 2002 2017 TOTAL
-------- -------- -------- -------- -------- -------- ----------
(DOLLARS IN THOUSANDS, EXCEPT PRICE DATA)
NATURAL GAS SWAPS:
SALES CONTRACTS
Contract volumes (BBtu)................................... 13,825 15,825 9,830 7,475 6,405 23,433 76,793
Weighted-average fixed price per MMBtu (1)................ $ 2.33 $ 2.44 $ 2.46 $ 2.47 $ 2.67 $ 3.20 $ 2.68
Future fixed-price sales.................................. $ 32,243 $ 38,629 $ 24,164 $ 18,446 $ 17,098 $ 74,922 $ 205,502
Future net revenues (2)................................... $ 999 $ 2,865 $ 2,145 $ 1,665 $ 2,654 $ 19,997 $ 30,325
PURCHASE CONTRACTS
Contract volumes (BBtu)................................... (9,125) (10,950) -- -- -- -- (20,075)
Weighted-average fixed price per MMBtu (1)................ $ 2.09 $ 2.18 $ -- $ -- $ -- $ -- $ 2.14
Future fixed-price purchases.............................. $(19,108) $(23,880) $ -- $ -- $ -- $ -- $ (42,988)
Future net revenues (2)................................... $ 1,515 $ 867 $ -- $ -- $ -- $ -- $ 2,382
NATURAL GAS PHYSICAL DELIVERY CONTRACTS:
Contract volumes (BBtu)................................... 36,060 28,204 26,749 27,300 27,175 106,921 252,409
Weighted-average fixed price per MMBtu (1)................ $ 2.64 $ 2.84 $ 3.04 $ 3.19 $ 3.35 $ 4.30 $ 3.55
Future fixed-price sales.................................. $ 95,130 $ 80,125 $ 81,403 $ 86,963 $ 91,170 $460,285 $ 895,076
Future net revenues (2)................................... $ 13,550 $ 16,120 $ 20,856 $ 25,152 $ 29,271 $181,507 $ 286,456
TOTAL NATURAL GAS CONTRACTS (3)(4):
Contract volumes (BBtu)................................... 40,760 33,079 36,579 34,775 33,580 130,354 309,127
Weighted-average fixed price per MMBtu (1)................ $ 2.66 $ 2.87 $ 2.89 $ 3.03 $ 3.22 $ 4.11 $ 3.42
Future fixed-price sales.................................. $108,265 $ 94,874 $105,567 $105,409 $108,268 $535,207 $1,057,590
Future net revenues (2)................................... $ 16,064 $ 19,852 $ 23,001 $ 26,817 $ 31,925 $201,504 $ 319,163
CRUDE OIL SWAPS:
Contract volumes (MBbls).................................. 79 -- -- -- -- -- 79
Weighted-average fixed price per Bbl (1).................. $ 22.20 $ -- $ -- $ -- $ -- $ -- $ 22.20
Future fixed-price sales.................................. $ 1,754 $ -- $ -- $ -- $ -- $ -- $ 1,754
Future net revenues (2)................................... $ 345 $ -- $ -- $ -- $ -- $ -- $ 345
- ------------------------------
(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, 1997, as adjusted for basis. Future net
revenues change as market prices and basis fluctuate. See "--Market Risk."
(3) Does not include basis swaps with notional volumes by year, as follows:
1998--24.5 TBtu; 1999--19.0 TBtu; 2000--21.3 TBtu; 2001--9.4 TBtu; and
2002--5.5 TBtu.
(4) Does not include 1.4 TBtu of natural gas hedged by fixed-price collars for
1998 with a weighted-average floor price of $2.34 per MMBtu and a
weighted-average ceiling price of $2.55 per MMBtu.
The estimates of the future net revenues of 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.
Such estimates do not necessarily represent the fair market value of the
Company's Fixed-Price Contracts or the actual future net revenues that will be
received. The forward market prices for natural gas and oil are highly volatile,
are dependent upon supply and demand factors in such forward market and may not
correspond to the actual market prices at the settlement dates of the Company's
Fixed-Price Contracts. Such forward market prices are available in a limited
over-the-counter market and are obtained from sources the Company believes to be
reliable.
36
A reconciliation of the future amounts to be received (or paid) under the
Company's Fixed-Price Contracts for the three years ended December 31, 1995,
1996 and 1997, is as follows:
FIXED-PRICE CONTRACTS--FUTURE FIXED-PRICE SALES
AND PURCHASES
YEARS ENDED DECEMBER 31,
--------------------------------------
1995 1996 1997
------------ ------------ ----------
(IN THOUSANDS)
NATURAL GAS SWAPS:
SALES CONTRACTS
Future fixed-price sales, beginning of year..................... $ 225,901 $ 194,580 $ 219,289
Contract additions, net....................................... 4,958 78,770 4,538
Contract settlements and revisions............................ (29,664) (10,544) (18,325)
Contract cancellations (1).................................... (6,615) (43,517) --
------------ ------------ ----------
Future fixed-price sales, end of year (2)(3).................... $ 194,580 $ 219,289 $ 205,502
------------ ------------ ----------
------------ ------------ ----------
PURCHASE CONTRACTS
Future fixed-price purchases, beginning of year................. $ (9,334) $ (46,656) $ (47,961)
Contract additions............................................ (46,656) (1,994) (587)
Contract settlements and revisions............................ 9,334 689 5,560
------------ ------------ ----------
Future fixed-price purchases, end of year....................... $ (46,656) $ (47,961) $ (42,988)
------------ ------------ ----------
------------ ------------ ----------
NATURAL GAS PHYSICAL DELIVERY CONTRACTS:
Future fixed-price sales, beginning of year..................... $ 963,356 $ 1,078,779 $ 977,518
Contract additions............................................ 173,274 1,787 --
Contract settlements and revisions............................ (57,851) (103,048) (82,442)
------------ ------------ ----------
Future fixed-price sales, end of year (3)....................... $ 1,078,779 $ 977,518 $ 895,076
------------ ------------ ----------
------------ ------------ ----------
CRUDE OIL SWAPS:
Future fixed-price sales, beginning of year..................... $ 39,438 $ 15,400 $ 8,080
Contract additions............................................ 4,321 16,913 8,311
Contract settlements and revisions............................ (28,359) (24,233) (14,637)
------------ ------------ ----------
Future fixed-price sales, end of year........................... $ 15,400 $ 8,080 $ 1,754
------------ ------------ ----------
------------ ------------ ----------
- ------------------------
(1) 1996 amounts are attributable to a contract with S.A. Louis Dreyfus et Cie
which was canceled in January 1996.
(2) Does not include any future receipts or payments attributable to fixed-price
collars added in 1996 and 1997 hedging 3.0 TBtu and 3.8 TBtu of natural gas,
respectively.
(3) Does not include any future receipts or payments attributable to the
Company's portfolio of basis swaps.
ACCOUNTING. 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. 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. Consequently, no amounts are reflected in the Company's
balance sheets or income statements related to changes in market value of the
contracts. If a Fixed-Price Contract 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, 1996 and 1997, the Company had
deferred gains from price-risk management activities of $26.2 million and $23.5
million, respectively.
37
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.
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 is a party to two Fixed-Price Contracts, both long-term physical
delivery contracts, with independent power producers ("IPPs") which sell
electrical power under firm, fixed-price contracts to Niagara Mohawk Corporation
("NIMO"), a New York state utility. The Company's Fixed-Price Contracts with
such IPPs hedged an aggregate 96 Bcf of natural gas as of December 31, 1997. At
December 31, 1997, the net present value of the differential between the fixed
prices provided by these contracts and forward market prices, as adjusted for
basis and discounted at 10%, was $138 million, or 73% of such net present value
attributable to all of the Company's Fixed-Price Contracts. This premium in the
fixed prices is not reflected in the Company's financial statements until
realized. For the years ended December 31, 1995, 1996 and 1997, these contracts
contributed $9.6 million, $.9 million and $1.8 million, respectively, to natural
gas sales. The ability of these IPPs to perform their obligations to the Company
is 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 IPPs that are
counterparties to the Company's Fixed-Price Contracts described above, and has
further stated that its future financial prospects are 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 Company's counterparties. Pursuant to the MRA, the
power purchase agreements between NIMO and the IPPs would be terminated,
restated or amended, in exchange for an aggregate of $3.6 billion in cash, $50
million in notes or cash, 46 million shares of NIMO common stock and certain
fixed-price swap contracts. The allocation of the consideration among the IPPs
has not been disclosed. The closing of the MRA is conditioned upon, among other
things, NIMO and the IPPs negotiating their individual restated and amended
contracts, the receipt of all regulatory approvals, the IPPs entering into new
third party arrangements which will enable each IPP to restructure its projects
on a reasonably satisfactory economic basis, NIMO having completed all necessary
financing arrangements and NIMO and the IPPs having received all necessary
approvals from their respective boards of directors, shareholders and partners.
At this time, the Company cannot predict whether the conditions precedent to
the closing of the MRA will ultimately be satisfied. Any proceeds received by
the Company in consideration for termination of a Fixed-Price Contract would be
used to repay indebtedness outstanding under the Bank Credit Facility and would
be reflected under current accounting rules in the Company's balance sheet as
deferred hedging gains to be amortized into oil and gas revenues over the
original life of the underlying contracts. However, the amount of any proceeds
to be received by the Company is subject to negotiation with the Company's
counterparties and contingent upon the counterparties participating in the
closing of the MRA. Negotiations with the Company's counterparties are governed
by confidentiality agreements. Cancellation of the contracts would subject a
greater portion of the Company's gas production to market prices, which in a low
gas price environment could adversely affect the carrying value of the Company's
oil and gas properties and could otherwise have an adverse effect on the
Company.
38
MARKET RISK. The Company's natural gas Fixed-Price Contracts at December
31, 1997 hedge 310 Bcf of proved natural gas reserves at fixed prices. These
contract quantities represent 30% of the Company's estimated proved natural gas
reserves as of December 31, 1997. 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, 1995, 1996 and 1997, the Company received on an Mcf
basis approximately 3%, 3% and 1% less than the prices specified in its natural
gas Fixed-Price Contracts, respectively, due to basis. Such results exclude the
impact of a temporary loss of correlation which occurred in the first quarter of
1996. For its oil production hedged by crude oil Fixed-Price Contracts, the
Company realized approximately 7%, 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 1998 represents a $1.1 million change in gas sales. A 1% change in price
realization for hedged oil production in 1998 would be less than $.1 million.
The Company actively manages its exposure to basis movements and from time to
time will enter into contracts designed to reduce such exposure.
MARGINING. 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, 1995, 1996 and 1997, the
maximum aggregate amount of margin posted by the Company was $23.4 million,
$28.4 million and $28.7 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, 1997, the Company had issued margin in
the form of letters of credit and treasury bills totaling $19.2 million and $4.5
million, respectively. In addition, approximately 27 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.
OUTLOOK FOR FISCAL YEAR 1998
GENERAL. The discussion of the Company's fiscal year 1998 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, 1997 and other information currently available to Management. 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
39
GAS RESERVES. THESE RISKS INCLUDE, BUT ARE NOT LIMITED TO, COMMODITY PRICE
RISKS, COUNTERPARTY RISKS, ENVIRONMENTAL RISKS, DRILLING RISKS, RESERVES RISKS,
AND OPERATIONS AND PRODUCTION RISKS. CERTAIN OF THESE RISKS ARE DESCRIBED
ELSEWHERE HEREIN. MOREOVER, THE COMPANY MAY MAKE MATERIAL ACQUISITIONS OR
DIVESTITURES, MODIFY ITS FIXED-PRICE CONTRACT POSITION BY ENTERING INTO NEW
CONTRACTS OR TERMINATING EXISTING CONTRACTS, OR ENTER INTO FINANCING
TRANSACTIONS. NONE OF THESE CAN BE PREDICTED WITH CERTAINTY AND, ACCORDINGLY,
ARE NOT TAKEN INTO CONSIDERATION IN THE FORWARD-LOOKING STATEMENTS MADE HEREIN.
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 plans to commit a record amount of capital to its
1998 exploration and development drilling program. In addition, the Company will
have a full year of production results from the American Acquisition which was
closed in October 1997. These factors should result in a significant increase in
oil and gas production for 1998 in relation to 1997. See "--Commitments and
Capital Expenditures."
OIL AND GAS PRICES. The Company's Fixed-Price Contracts in 1998 are
expected to provide average fixed prices of $2.66 per Mcf and $22.20 per Bbl for
its hedged natural gas and crude oil, respectively, before consideration of
basis. Based on February 1998 quotations for regional natural gas prices for the
balance of 1998 and giving effect to the Company's portfolio of basis swaps, the
Company anticipates price realization percentages comparable to historical
averages. See "--Fixed-Price Contracts--Market Risk." As of December 31, 1997,
the Company's Fixed-Price Contracts hedge 42 Bcf of natural gas production
(including 1 Bcf of fixed-price collars) and 79 MBbls of oil production in 1998.
No plans currently exist to increase or decrease the amount of hedged production
volumes for 1998; however, the Company may decide to hedge a greater or smaller
share of production in the future. In addition, negotiations with IPPs covering
two Fixed-Price Contracts may lead to the termination of such contracts. See
"--Fixed-Price Contracts--Credit Risk."
The Company is unable to predict the market prices that will be received for
its unhedged production in 1998. For 1997, average monthly wellhead prices for
its natural gas ranged from $1.85 per Mcf to $4.11 per Mcf and its oil prices
varied from $17.94 per Bbl to $24.94 per Bbl. Because less than 50% of the
Company's estimated 1998 production is hedged by Fixed-Price Contracts, the
Company's 1998 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 miscellaneous sources of 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. The Company will experience a significant increase in
lifting costs and production taxes as the result of the American Acquisition
properties and associated revenues. On an equivalent unit of production basis,
lifting costs are not anticipated to increase significantly in relation to
historical results for 1996 and 1997. 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. The Company anticipates a significant
increase in its G&A costs for 1998 as a result of the American Acquisition. On
an equivalent unit of production basis, G&A costs are not expected to increase
in relation to historical results for 1997.
EXPLORATION COSTS. The Company expects to commit approximately $78 million
of its 1998 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
40
are expensed. All exploratory geological and geophysical costs (budgeted at $11
million for 1998) are expensed as incurred, regardless of ultimate success in
the discovery of new reserves. Remaining exploration costs to be expensed in
1998 will depend on the Company's exploratory drilling results.
DEPRECIATION, DEPLETION AND AMORTIZATION. The Company expects its DD&A to
increase significantly in the aggregate and on a per unit of production basis as
a result of the American Acquisition. The allocation of the associated purchase
price to the proved oil and gas properties of American will cause the overall
blended DD&A rate per Mcfe to increase. Additionally, 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. Due to the American Acquisition purchase price allocation,
the associated oil and gas properties generally have a higher cost basis than
the properties of LDNG owned prior to the acquisition. As a result, these
properties will be more susceptible to future impairments.
INTEREST EXPENSE. As a result of the American Acquisition, the Company
expects to have higher average outstanding indebtedness during 1998 in relation
to the prior year. Additionally, the average interest rate is expected to
increase due to the issuance of the Senior Notes in December 1997. Consequently,
interest expense is anticipated to increase in relation to 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, 1997, that its income tax provision for 1998 will result in an
effective rate approximating statutory rates.
ITEM 7A--QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not applicable.
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-27 inclusive, found at the end of this
report.
ITEM 9--CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10--DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required under Item 10 will be contained in the definitive
Proxy Statement of the Company for its 1998 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, 1997.
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.
41
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).
42
*10.1 Stock Option Plan of Louis Dreyfus Natural Gas Corp. as amended and restated effective February
1997 (incorporated by reference to Exhibit 10.1 of the Registrant's Form 10-K for the fiscal year
ended December 31, 1996).
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 Louis Dreyfus Deferred Compensation Stock Equivalent Plan (incorporated by reference to Exhibit
10.18 of the Registrant's Form 10-K for the fiscal year ended December 31, 1994).
10.10 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).
*10.11 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).
*10.12 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).
*10.13 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).
*10.14 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).
21.1 List of subsidiaries of the Registrant.
23.1 Consent of Independent Auditors.
24.1 Powers of Attorney.
43
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.
A current report on Form 8-K dated October 14, 1997 was filed by the
Registrant reporting the closing of the merger with American Exploration
Company and a new senior bank credit facility. Financial statements of
American Exploration Company and related pro forma financial information
were incorporated by reference 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.
44
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 9, 1998 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.
NAME TITLE DATE
- ------------------------------ -------------------------- -------------------
MARK E. MONROE* President, Chief Executive March 9, 1998
- ------------------------------ Officer and Director
Mark E. Monroe (principal executive
officer)
RICHARD E. BROSS* Executive Vice President March 9, 1998
- ------------------------------ and Director
Richard E. Bross
/s/ JEFFREY A. BONNEY Executive Vice President March 9, 1998
- ------------------------------ and Chief Financial
Jeffrey A. Bonney Officer (principal
financial and accounting
officer)
SIMON B. RICH, JR.* Chairman of the Board of March 9, 1998
- ------------------------------ Directors
Simon B. Rich, Jr.
MARK ANDREWS* Vice Chairman of the Board March 9, 1998
- ------------------------------ of Directors
Mark Andrews
GERARD LOUIS-DREYFUS* Director March 9, 1998
- ------------------------------
Gerard Louis-Dreyfus
DANIEL R. FINN, JR.* Director March 9, 1998
- ------------------------------
Daniel R. Finn, Jr.
PETER G. GERRY* Director March 9, 1998
- ------------------------------
Peter G. Gerry
JOHN H. MOORE* Director March 9, 1998
- ------------------------------
John H. Moore
JAMES R. PAUL* Director March 9, 1998
- ------------------------------
James R. Paul
*By: /s/ JEFFREY A. BONNEY
-------------------------
Jeffrey A. Bonney
ATTORNEY-IN-FACT
45
LOUIS DREYFUS NATURAL GAS CORP.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
PAGE
---------
CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Auditors............................................................................. F-2
Consolidated Balance Sheets:
December 31, 1996 and 1997............................................................................... F-3
Consolidated Statements of Operations:
Years ended December 31, 1995, 1996 and 1997............................................................. F-4
Consolidated Statements of Stockholders' Equity:
Years ended December 31, 1995, 1996 and 1997............................................................. F-5
Consolidated Statements of Cash Flows:
Years ended December 31, 1995, 1996 and 1997............................................................. F-6
Notes to Consolidated Financial Statements................................................................. F-7
CONSOLIDATED FINANCIAL STATEMENT SCHEDULE
Schedule II--Consolidated Valuation and Qualifying Accounts................................................ F-30
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, 1996 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, 1997. 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, 1996 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, 1997
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.
ERNST & YOUNG LLP
Oklahoma City, Oklahoma
February 2, 1998
F-2
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
ASSETS
DECEMBER 31,
---------------------
1996 1997
--------- ----------
CURRENT ASSETS
Cash and cash equivalents........................................................................... $ 7,749 $ 5,538
Receivables:
Oil and gas sales................................................................................. 33,579 46,192
Costs reimbursable by insurance................................................................... -- 22,406
Joint interest and other, net..................................................................... 5,358 14,311
Deposits............................................................................................ 5,592 4,467
Inventory and other................................................................................. 3,147 9,883
--------- ----------
Total current assets.............................................................................. 55,425 102,797
--------- ----------
PROPERTY AND EQUIPMENT, at cost, based on successful efforts accounting............................. 907,027 1,404,784
Less accumulated depreciation, depletion and amortization........................................... (235,162) (305,769)
--------- ----------
671,865 1,099,015
--------- ----------
OTHER ASSETS, net................................................................................... 6,323 9,142
--------- ----------
$ 733,613 $1,210,954
--------- ----------
--------- ----------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable.................................................................................... $ 36,415 $ 61,197
Accrued liabilities................................................................................. 7,251 22,258
Revenues payable.................................................................................... 7,419 16,111
--------- ----------
Total current liabilities....................................................................... 51,085 99,566
--------- ----------
LONG-TERM DEBT...................................................................................... 343,907 563,344
--------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred revenue.................................................................................... 19,049 17,387
Deferred gains from price-risk management activities................................................ 26,226 23,453
Deferred income taxes............................................................................... 22,692 21,896
Other............................................................................................... 6,961 16,104
--------- ----------
74,928 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, 27,800,750 and
40,088,258 shares, respectively................................................................... 278 401
Additional paid-in capital.......................................................................... 197,301 418,751
Retained earnings................................................................................... 66,114 50,052
--------- ----------
263,693 469,204
--------- ----------
$ 733,613 $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,
----------------------------------
1995 1996 1997
---------- ---------- ----------
REVENUES
Oil and gas sales............................................................ $ 163,366 $ 185,558 $ 222,016
Other income (loss).......................................................... (418) 3,947 10,901
---------- ---------- ----------
162,948 189,505 232,917
---------- ---------- ----------
EXPENSES
Operating costs.............................................................. 35,352 44,615 49,169
General and administrative................................................... 16,631 16,325 18,855
Exploration costs............................................................ -- 4,965 8,956
Depreciation, depletion and amortization..................................... 57,796 65,278 79,325
Impairment................................................................... 15,694 -- 75,198
Interest..................................................................... 21,736 26,822 28,737
---------- ---------- ----------
147,209 158,005 260,240
---------- ---------- ----------
Income (loss) before income taxes............................................ 15,739 31,500 (27,323)
Income taxes................................................................. 4,722 10,398 (11,261)
---------- ---------- ----------
NET INCOME (LOSS) $ 11,017 $ 21,102 $ (16,062)
---------- ---------- ----------
---------- ---------- ----------
Net income (loss) per share--basic and diluted............................... $ .40 $ .76 $ (.53)
---------- ---------- ----------
---------- ---------- ----------
Weighted average diluted common shares outstanding........................... 27,804 27,810 30,233
---------- ---------- ----------
---------- ---------- ----------
See accompanying notes to consolidated financial statements.
F-4
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
ADDITIONAL TOTAL
PREFERRED COMMON PAID-IN RETAINED STOCKHOLDERS'
STOCK STOCK CAPITAL EARNINGS EQUITY
---------- ----------- ---------- ---------- ------------
BALANCE AT DECEMBER 31, 1994........................ $ -- $ 278 $ 190,291 $ 33,995 $ 224,564
Contribution by affiliate........................... -- -- 7,000 -- 7,000
Net income.......................................... -- -- -- 11,017 11,017
---------- ----- ---------- ---------- ------------
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
---------- ----- ---------- ---------- ------------
---------- ----- ---------- ---------- ------------
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,
----------------------------------
1995 1996 1997
---------- ---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)........................................................... $ 11,017 $ 21,102 $ (16,062)
Items not affecting cash flows:
Depreciation, depletion and amortization.................................. 58,403 65,278 79,325
Impairment................................................................ 15,694 -- 75,198
Deferred income taxes..................................................... 3,348 9,065 (12,296)
Exploration costs......................................................... -- 4,965 8,956
Gain on sale of property.................................................. (204) (68) (8,745)
Other..................................................................... 844 639 698
Net change in operating assets and liabilities, exclusive of amounts
acquired:
Accounts receivable....................................................... (8,578) (10,194) (5,598)
Deposits.................................................................. (679) (1,692) 1,125
Inventory and other....................................................... (1,074) (52) (3,184)
Accounts payable.......................................................... 5,982 14,957 10,162
Accrued liabilities....................................................... 40 (661) 75
Revenues payable.......................................................... 412 2,732 192
Deferred revenue.......................................................... 4,310 (4,310) --
---------- ---------- ----------
89,515 101,761 129,846
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development expenditures.................................... (66,606) (98,097) (154,396)
Acquisition of oil and gas properties....................................... (118,652) (36,125) (9,118)
Purchase of American Exploration Company.................................... -- -- (72,323)
Additions to other property and equipment................................... (1,528) (17,660) (2,650)
Proceeds from sale of property and equipment................................ 15,125 1,101 27,887
Change in other assets...................................................... 121 (76) (6,003)
---------- ---------- ----------
(171,540) (150,857) (216,603)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from bank borrowings............................................... 240,350 241,240 868,037
Repayments of bank borrowings............................................... (140,747) (212,240) (928,537)
Proceeds from issuance of senior notes...................................... -- -- 198,784
Repayments of subordinated notes............................................ -- -- (42,621)
Proceeds from stock options exercised....................................... -- 10 497
Redemption of preferred stock............................................... -- -- (4,344)
Change in deferred revenue.................................................. (18,590) (2,268) (1,662)
Change in deferred hedging gains............................................ -- 26,226 (2,773)
Change in other long-term liabilities....................................... (384) 2,293 (2,835)
---------- ---------- ----------
80,629 55,261 84,546
---------- ---------- ----------
Change in cash and cash equivalents......................................... (1,396) 6,165 (2,211)
Cash and cash equivalents, beginning of year................................ 2,980 1,584 7,749
---------- ---------- ----------
Cash and cash equivalents, end of year...................................... $ 1,584 $ 7,749 $ 5,538
---------- ---------- ----------
---------- ---------- ----------
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. (the "Company") is an independent
energy company primarily engaged in the acquisition, development, exploration,
production and marketing of natural gas and crude oil. At December 31, 1997,
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, 1995 and 1996 to conform
to the financial statement presentation for the year ended December 31, 1997.
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, 1996 and 1997, the
Company's joint interest and other receivables are shown net of allowance for
doubtful accounts of $1.1 million.
INVENTORY. Inventory consists primarily of tubular goods and is carried at
the lower of cost or market.
PROPERTY AND EQUIPMENT. The Company utilizes the successful efforts method
of accounting for oil and natural gas producing activities. Costs incurred in
connection with the drilling and equipping of exploratory wells are capitalized
as incurred. If proved reserves are not found, such costs are charged to
expense. Other exploration costs, including delay rentals and seismic costs, are
charged to expense as incurred. Development costs, which include the costs of
drilling and equipping development wells, whether successful or unsuccessful,
are capitalized as incurred. All general and administrative costs are expensed
as incurred. Depreciation, depletion and amortization of capitalized costs of
proved oil and gas properties is computed by the unit-of-production method on a
field-by-field basis. The costs of unproved oil and gas properties are assessed
quarterly on a property-by-property basis. If unproved properties are determined
to be productive, the related costs are transferred to proved oil and gas
properties. If unproved properties are determined not to be productive, or if
the value of such properties has been otherwise impaired, the excess carrying
value is charged to expense.
F-7
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1--SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
In 1995, the Company adopted the provisions of Statement of Financial
Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"). Pursuant to
SFAS 121, 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. The adoption of SFAS 121, in
conjunction with the completion of the Company's proved reserve estimates as of
December 31, 1995, led to a review of the Company's oil and gas properties on a
field-by-field basis for indications of impairment. Such review resulted in the
recognition of an impairment charge of $15.7 million for the year ended December
31, 1995. 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.
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, 1996 and 1997, estimated total future dismantling and
restoration costs of $1.9 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, 1996 and 1997,
was $4.2 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, 1996 and 1997, the Company had recorded imbalance
liabilities of $1.6 million and $3.2 million, respectively. The Company's
remaining net underproduced imbalance position at December 31, 1996 and 1997 was
not material.
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.
F-8
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1--SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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 has also entered into interest rate swap
contracts to reduce its exposure to interest rate fluctuations. Gains and losses
from hedging transactions are recognized in income and are reflected as cash
flows from operating activities in the periods for which the underlying
commodity or interest rate was hedged. If the necessary correlation (generally a
correlation coefficient of 80% or greater) to the commodity or interest rate
being hedged ceases to exist, the differential between the market value and the
carrying value of the affected contracts is recognized as a gain or loss in the
period that the permanent loss of correlation is identified, with future changes
in market value recognized as a gain or loss in the period of change. When a
temporary loss of correlation has occurred, the anomalous basis differential
attributable to the affected contracts is recognized as a gain or loss in the
period in which the loss of effectiveness is identified. See Note 4--Long-Term
Debt, 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. In December 1997, the Company adopted Statement of
Financial Accounting Standards No. 128, "Earnings per Share" ("SFAS 128"), which
changes the method used to compute earnings per share and requires the
restatement of all prior periods to conform with the new calculation method. The
calculation of basic earnings per share for the years ended December 31, 1995
and 1996 pursuant to SFAS 128 did not result in a revision to amounts previously
reported. The calculation of diluted earnings per share was the same as basic
earnings per share for all periods presented. Weighted average common shares
outstanding used in the calculation of basic earnings per share for the years
ended December 31, 1995, 1996, and 1997 (in thousands) were 27,800, 27,800 and
30,233, respectively. Dilutive potential common shares used in the calculation
of diluted earnings per share for the years ended December 31, 1995, 1996 and
1997 (in thousands) were 27,804, 27,810 and 30,233, respectively. The increase
in number of shares for 1995 and 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 AND EQUIVALENT RIGHTS. The Company accounts for employee
stock-based compensation using the intrinsic value method prescribed by
Accounting Principles Board (APB) 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. For stock equivalent rights, the value to be paid upon exercise
is charged to earnings over the respective vesting period or as the price of the
Company's Common Stock changes after such rights have become fully vested. See
Note 8--Employee Benefit Plans.
F-9
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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,
------------------------
1996 1997
---------- ------------
(IN THOUSANDS)
Oil and gas properties:
Proved........................................................................ $ 873,546 $ 1,298,046
Unproved...................................................................... 6,657 74,893
Accumulated depreciation, depletion and amortization.......................... (227,946) (295,848)
---------- ------------
652,257 1,077,091
---------- ------------
Other property and equipment.................................................. 26,824 31,845
Accumulated depreciation...................................................... (7,216) (9,921)
---------- ------------
19,608 21,924
---------- ------------
$ 671,865 $ 1,099,015
---------- ------------
---------- ------------
Depreciation, depletion and amortization expense of oil and gas properties
per Mcfe was $.88, $.82 and $.88 for the years ended December 31, 1995, 1996 and
1997, respectively. Such amounts do not include impairment charges recorded in
1995 and 1997. See Note 1--Significant Accounting Policies. For the years ended
December 31, 1995, 1996 and 1997, the Company capitalized $.3 million, $.4
million and $1.0 million of interest, respectively, in connection with its
exploration and development activities. Depreciation of other property and
equipment was $2.1 million, $2.6 million and $3.2 million for the years ended
December 31, 1995, 1996 and 1997, respectively.
Unproved properties at December 31, 1997 consist primarily of allocated
American Acquisition costs recorded net of impairment. 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, 1995, 1996 and 1997, respectively.
YEARS ENDED DECEMBER 31,
----------------------------------
1995 1996 1997
---------- ---------- ----------
(IN THOUSANDS)
Property acquisition costs:
Proved............................................................. $ 118,652 $ 36,125 $ 349,037
Unproved........................................................... 1,717 6,934 109,648
---------- ---------- ----------
120,369 43,059 458,685
Exploration costs.................................................. 391 10,610 21,514
Development costs.................................................. 64,498 80,553 122,402
---------- ---------- ----------
$ 185,258 $ 134,222 $ 602,601
---------- ---------- ----------
---------- ---------- ----------
F-10
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.
In July 1995, the Company purchased certain producing oil and gas properties
in Sonora for $86.6 million (the "Sonora Acquisition"). The acquired oil and gas
properties consisted of approximately 700 producing wells, 100,000 gross acres
and an estimated 139 Bcfe of proved reserves. 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
and gives effect to the Sonora Acquisition as if the transaction had occurred on
January 1, 1995. 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,
----------------------------------
1995 1996 1997
---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE
DATA)
Unaudited pro forma information:
Revenues........................................................... $ 176,933 $ 266,703 $ 303,719
Net income......................................................... 12,158 3,440 16,752
Net income per common share--basic and diluted..................... .44 .09 .43
The pro forma information presented for 1996 and 1997 does not include a
one-time impairment charge of $73.1 million 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
$11.7 million, or $.30 per share, and $9.0 million, or $.23 per share, for the
years ended December 31, 1996 and 1997, respectively.
During 1995, 1996 and 1997, the Company made numerous other acquisitions of
proved oil and gas properties, the net purchase price of which aggregated $32.1
million, $36.1 million and $9.1 million, respectively. The results of operations
related to such acquisitions have been included in the accompanying statements
of operations and cash flows for the periods subsequent to the closing of each
transaction.
F-11
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 4--LONG-TERM DEBT
Long-term debt consists of the following:
DECEMBER 31,
------------------------
1996 1997
---------- ------------
(IN THOUSANDS)
Bank Debt:
$450 Million Revolving Credit Facility........................................ $ -- $ 261,000
$300 Million Borrowing Base Credit Facility................................... 235,000 --
Other Lines of Credit......................................................... 10,000 4,500
---------- ------------
245,000 265,500
6 7/8% Senior Notes due 2007.................................................. -- 198,791
9 1/4% Senior Subordinated Notes due 2004..................................... 98,907 99,053
---------- ------------
$ 343,907 $ 563,344
---------- ------------
---------- ------------
$450 MILLION REVOLVING CREDIT FACILITY. On October 14, 1997, in connection
with the American Acquisition, the Company replaced its $300 million borrowing
base credit facility with a new $550 million revolving credit facility (the
"Credit Facility"). Upon the issuance of senior notes in December 1997, the
Company reduced the aggregate commitment under the Credit Facility to $450
million (the "Commitment"). 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. Letters of credit are limited to $75 million of
such availability. No principal payments are required under the Credit Facility
prior to termination on October 14, 2002. The Company has relied upon the Credit
Facility and the predecessor bank 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,
1997, the Company had $261.0 million of principal and $5.0 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, 1997,
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, 1997, the effective interest rate for borrowings
under the Credit Facility was 6.3%, including the effect of interest rate swaps.
The Credit Facility contains various affirmative and restrictive covenants
which generally provide greater flexibility than those contained in the prior
facility. These covenants, 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. In
connection with the termination of the $300 million borrowing base credit
facility, the Company recognized a charge of approximately $1.7 million
representing the unamortized loan origination fees associated with the facility.
OTHER LINES OF CREDIT. The Company has certain other unsecured lines of
credit available to it, which aggregated $42.8 million as of December 31, 1997.
Such short-term lines of credit are primarily used to
F-12
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 4--LONG-TERM DEBT (CONTINUED)
meet margining requirements under Fixed-Price Contracts and for working capital
purposes. At December 31, 1997, the Company had $4.5 million of indebtedness and
$15.3 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. In October 1997, the Company entered
into financial swaps which effectively fixed the price of the underlying
treasury bond used to price the Senior Notes. The settlement of these hedges
ultimately resulted in a deferred hedging loss of $3.6 million which is being
amortized into interest expense over the life of the Senior Notes.
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, 1997 are as follows: 1998--$0; 1999--$0; 2000--$0;
2001--$0; 2002--$265.5 million; 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, 1997, the Company had fixed the interest rate on
average notional amounts of $99 million and $33 million for the years ended
December 31, 1998 and 1999, respectively. Under the interest rate swaps, the
Company receives the LIBOR three-month rate (5.8% at December 31, 1997) and pays
an average rate of 6.3% for 1998 and 6.5% for 1999. The notional amounts are
less than the maximum amount anticipated to be available under the Credit
Facility in such years. The Company has an additional interest rate swap under
which the Company pays the LIBOR three-month rate and receives 7.1% on a
notional amount of $25 million. This interest rate swap matures June 2004.
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 deferred and amortized as interest
expense over the original contract term. At December 31, 1996 and 1997, the
amount of such deferrals was not material.
F-13
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 5--INCOME TAXES
The significant components of income tax expense (benefit) for the years
ended December 31, 1995, 1996 and 1997 are as follows:
YEARS ENDED DECEMBER 31,
--------------------------------
1995 1996 1997
--------- --------- ----------
(IN THOUSANDS)
Current tax expense:
Federal............................................................... $ 1,195 $ 1,159 $ 885
State................................................................. 179 174 150
--------- --------- ----------
1,374 1,333 1,035
--------- --------- ----------
Deferred tax expense (benefit):
Federal............................................................... 3,033 8,271 (11,407)
State................................................................. 315 794 (889)
--------- --------- ----------
3,348 9,065 (12,296)
--------- --------- ----------
$ 4,722 $ 10,398 $ (11,261)
--------- --------- ----------
--------- --------- ----------
The provision for income taxes differed from the computed "expected" income
tax provision using statutory rates on income before income taxes for the
following reasons:
YEARS ENDED DECEMBER 31,
--------------------------------
1995 1996 1997
--------- --------- ----------
(IN THOUSANDS)
Computed "expected" income tax........................................ $ 5,509 $ 11,025 $ (9,563)
Increases (reductions) in taxes resulting from:
State income taxes, net of federal benefit.......................... 321 629 (481)
Permanent differences (principally related to basis differences in
oil and gas properties)........................................... 861 265 935
Section 29 credits.................................................. (2,090) (2,028) (1,748)
Other............................................................... 121 507 (404)
--------- --------- ----------
$ 4,722 $ 10,398 $ (11,261)
--------- --------- ----------
--------- --------- ----------
F-14
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 5--INCOME TAXES (CONTINUED)
Deferred tax assets and liabilities, resulting from differences between the
financial statement carrying amounts and the tax bases of assets and
liabilities, consist of the following:
DECEMBER 31,
---------------------
1996 1997
--------- ----------
(IN THOUSANDS)
Deferred tax liabilities:
Capitalized costs and related depreciation, depletion and amortization........... $ 43,416 $ 87,406
Other............................................................................ 825 852
--------- ----------
44,241 88,258
--------- ----------
Deferred tax assets:
Deferred revenue and hedging gains............................................... 17,251 15,519
Alternative minimum tax credits.................................................. 4,298 5,332
Net operating loss carryforwards from American Acquisition....................... -- 87,815
Other............................................................................ -- 1,185
--------- ----------
21,549 109,851
Valuation allowance for net operating loss carryforwards......................... -- (43,489)
--------- ----------
21,549 66,362
--------- ----------
Net deferred tax liability....................................................... $ 22,692 $ 21,896
--------- ----------
--------- ----------
At December 31, 1997, the Company had U.S. Federal net operating loss
carryforwards of $231.1 million that expire beginning in 1998, statutory
depletion carryforwards totaling $.7 million that can be carried forward
indefinitely and alternative minimum tax credit carryforwards of $5.3 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 $114.4 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 covering 33 Bcf of
natural gas over a five-year period beginning in 1996, at a weighted-average
fixed price of $2.49 per Mcf.
The Company uses the commodity trading resources of S.A. Louis Dreyfus et
Cie when purchasing natural gas futures contracts on the NYMEX. In that regard,
the Company reimburses S.A. Louis Dreyfus et Cie for margin posted by the
affiliate on behalf of the Company. At December 31, 1996 and 1997, margin of
$5.6 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 from certain wells
in the Sonora area, 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
F-15
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 6--TRANSACTIONS WITH RELATED PARTIES (CONTINUED)
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 provided by S.A. Louis Dreyfus
et Cie at amounts approximating cost. General and administrative expenses for
the years ended December 31, 1995, 1996 and 1997 include $.8 million, $.9
million and $.9 million, respectively, for such services (principally insurance
costs and services).
OTHER. At December 31, 1996 and 1997, the Company owed S.A. Louis Dreyfus
et Cie approximately $2.3 million and $.7 million, respectively, principally for
posted margin and miscellaneous general and administrative expenses. Such
amounts are included in accounts payable in the accompanying balance sheets.
NOTE 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. The judgment amount was in addition to a $1.3 million deposit
previously paid by Midcon to the Company. As a result of the judgment, the
Company recognized the $1.3 million deposit paid by Midcon as other income in
1995. 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. On January 24, 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. The Company considers the allegations of Midcon to be
without merit and will vigorously defend against this action. Collection of the
remaining 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, 1997. 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 also requested
declaratory judgment that it has a right to relief from the contract price due
to regulatory changes, which it alleges renders the contract commercially
impracticable, and that Federal Energy Regulatory Commission Order No. 636 is a
condition subsequent which excuses performance under the contract. In April
1995, American filed counterclaims against KNGSS relating to the failure of
KNGSS to take and pay for certain minimum volumes of gas, among other
contractual matters. American has dismissed all of its counterclaims, and KNGSS
has dismissed its commercially impracticable and condition subsequent claims.
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
F-16
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 7--COMMITMENTS AND CONTINGENCIES (CONTINUED)
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. 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 $3.2 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.
INSURANCE RECOVERY. On April 1, 1997, a blowout and fire occurred during
the drilling of a horizontal development well at East Cameron Block 328 located
in federal waters offshore Louisiana (acquired in the American Acquisition). No
personnel were injured in the accident. The upper structure of the platform,
however, was severely damaged. In addition, the drilling rig operated by a third
party contractor and various other subcontractors' equipment were damaged or
destroyed. The well was successfully capped and the four remaining wells on the
platform were secured. The production deck was removed and dismantled and
certain production equipment has been salvaged. The Company is rebuilding the
production deck and expects to restore production from the platform in the
second quarter of 1998.
The Company carries various types of insurance relating to the blowout and
estimates that total costs to control the blowout and return to production will
aggregate approximately $44 million. As of December 31, 1997, the Company has
recognized a liability of approximately $2.1 million for certain estimated costs
that may not be recoverable through insurance. At this stage of the Company's
insurance claim, it is not possible to quantify what other amounts, if any, will
not be recoverable from insurance or legally responsible third parties. If the
Company is unable to recover a significant portion of its costs from insurance
or other third parties, the additional costs to be incurred could result in the
recognition of an impairment charge. The MMS, which has jurisdiction over
operations in federal waters, is required by regulation to investigate this type
of incident and to make a public report. To date, the MMS has not issued any
report regarding the blowout.
As of December 31, 1997, costs incurred for the recovery effort at East
Cameron Block 328 totaled approximately $38.9 million, approximately $16.5
million of which has been reimbursed by insurance companies. The balance of
$22.4 million is reflected as a receivable in the accompanying consolidated
balance sheet.
RENTAL COMMITMENTS. Minimum annual rental commitments as of December 31,
1997 under noncancelable office space leases are as follows: 1998--$3.6 million;
1999--$1.9 million; 2000--$1.9 million; 2001 and thereafter--$1.1 million.
Approximately $4.1 million of such rental commitments is included in other
long-term liabilities as of December 31, 1997, presented net of estimated future
rental income of $.9 million to be received during 1998.
F-17
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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, 1995, 1996 and
1997, the Company contributed $.8 million, $.9 million and $.9 million,
respectively, to the 401(k) Plan.
STOCK COMPENSATION PLANS. Certain executive officers of the Company are
participants in the Louis Dreyfus Deferred Compensation Stock Equivalent Plan
sponsored by S.A. Louis Dreyfus et Cie. Under this plan, participants were
awarded stock equivalent rights ("SERs") expressed as a number of stock
equivalent units. SERs are paid in cash following the termination of employment
with the S.A. Louis Dreyfus et Cie group, based on the average trading prices of
the Company's Common Stock during the month of December in the year of, or
preceding, termination of employment. At December 31, 1995, 1996 and 1997, SERs
totaling 85,000, 85,000 and 83,500 stock equivalent units, respectively, were
outstanding. Recorded compensation expense attributable the SERs was
approximately $.4 million for each of the years ended December 31, 1995, 1996
and 1997, respectively. The SERs were fully vested as of December 31, 1997.
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 2.0 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, 1996 and 1997, options
to purchase 6,750 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.
Generally, the exercise price of each option 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 in 1995, 1996 and 1997 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 with the following assumptions for 1995, 1996 and 1997: risk-free interest
rates of 6.0%, 6.6% and 5.7%, respectively; no dividends over the option term;
stock price volatility factors of .32, .31 and .32, 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.
F-18
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 8--EMPLOYEE BENEFIT PLANS (CONTINUED)
The SFAS 123 pro forma information is as follows:
YEARS ENDED DECEMBER 31,
--------------------------------
1995 1996 1997
--------- --------- ----------
(IN THOUSANDS, EXCEPT PER SHARE
DATA)
Net income (loss)................................................. $ 10,847 $ 20,698 $ (16,981)
Net income (loss) per share....................................... .39 .74 (.56)
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.
Stock option transactions for 1995, 1996 and 1997 are summarized as follows:
YEARS ENDED DECEMBER 31,
-----------------------------------------------------------------------------
1995 1996 1997
------------------------ ------------------------ -------------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- ------------- --------- ------------- ---------- -------------
Outstanding at beginning of
year........................... 515,000 $ 18.06 792,000 $ 16.42 993,250 $ 15.98
Granted.......................... 294,000 13.64 212,000 14.39 806,080 22.46
Exercised........................ -- -- (750) 13.69 (30,500) 16.18
Canceled......................... (17,000) 18.00 (10,000) 16.71 (60,500) 16.02
--------- --------- ----------
Outstanding at end of year....... 792,000 16.42 993,250 15.98 1,708,330 19.03
--------- --------- ----------
--------- --------- ----------
Exercisable at end of year....... 275,250 17.60 469,000 17.08 722,330 16.91
--------- --------- ----------
--------- --------- ----------
Weighted-average fair value of
options granted during year
(1)............................ $ 5.27 $ 5.71 $ 8.79
--------- --------- ----------
--------- --------- ----------
- ------------------------
(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 1.2 million shares of stock at December 31,
1997 had exercise prices ranging from $18.00 to $23.16 per share and had a
weighted-average remaining contractual life of 8.3 years. The balance of options
outstanding at December 31, 1997 had exercise prices ranging from $12.63 to
$17.71 per share and a weighted-average remaining contractual life of 8.4 years.
F-19
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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, 1995, gas sales to Lone
Star Gas Company represented 30% of total revenues for that year. 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. 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. 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 1997.
NOTE 10--CAPITAL STOCK
COMMON STOCK. The following table sets forth the Company's Common Stock
activity for the periods presented:
YEARS ENDED DECEMBER 31,
-------------------------------
1995 1996 1997
--------- --------- ---------
(IN THOUSANDS)
Common Stock Activity:
Balance, beginning of year............................................. 27,800 27,800 27,801
Exercise of stock options.............................................. -- 1 30
Shares issued in the American Acquisition.............................. -- -- 11,316
Shares issued on conversion of Preferred Stock......................... -- -- 941
--------- --------- ---------
Balance, end of year................................................... 27,800 27,801 40,088
--------- --------- ---------
--------- --------- ---------
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, 1997, the Company had outstanding warrants to
purchase 1.6 million shares of Common Stock, all of which are currently
exercisable, issued in connection with the American Acquisition for the
outstanding warrants of American. The associated exercise prices range from
$17.47 to $23.06 per share.
F-20
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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, 1995, 1996 and 1997, the Company paid
interest of $18.9 million, $25.3 million and $25.8 million, respectively, net of
capitalized interest, and paid income taxes of $3.5 million, $1.4 million and
$1.0 million, respectively.
NOTE 12--FINANCIAL INSTRUMENTS
The following information is provided regarding the estimated fair value of
certain on- and off-balance sheet financial instruments employed by the Company
as of December 31, 1996 and 1997, and the methods and assumptions used to
estimate the fair value of such financial instruments:
DECEMBER 31, 1996 DECEMBER 31, 1997
------------------------ ------------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
----------- ----------- ----------- -----------
(IN THOUSANDS)
Fixed-price natural gas energy swaps:
Sales contracts.................................. $ 76 $ 19,000 $ 76 $ 18,000
Purchase contracts............................... -- 1,000 -- 2,000
Fixed-price natural gas collars.................... -- 1,000 -- --
Fixed-price natural gas physical delivery contracts
(1).............................................. 1,864 168,000 1,138 166,000
Natural gas basis swaps............................ -- 1,000 -- 1,000
Fixed-price crude oil energy swaps................. -- -- -- --
Bank debt (2)...................................... (245,000) (245,000) (265,500) (265,500)
6 7/8% Senior Notes due 2007 (2)(3)................ n/a n/a (198,791) (199,714)
9 1/4% Senior Subordinated Notes due 2004 (2)...... (98,907) (106,000) (99,053) (108,235)
Interest rate swaps--fixed......................... -- (1,000) -- (1,000)
Interest rate swaps--floating...................... -- 1,000 -- 1,000
- ------------------------
(1) The Company's fixed-price delivery contracts, which are not financial
instruments pursuant to Statement of Financial Accounting Standards No. 107,
are presented for informational purposes only. See Note 13--Fixed-Price
Contracts.
F-21
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 12--FINANCIAL INSTRUMENTS (CONTINUED)
(2) Carrying amounts do not include capitalized debt issuance costs. See Note
1--Significant Accounting Policies.
(3) Carrying amount does not include associated deferred hedging loss. See Note
4--Long-Term Debt.
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 the Company's Fixed-Price Contracts as of December 31,
1996 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 covered by each contract to
arrive at an estimated future value. This future value was then discounted at
10% per year. Due to the characteristics of the Company's contracts, an
established market does not exist to determine a true fair value. Many factors,
such as performance, basis and credit risks, have not been considered in the
foregoing calculation. See Note 13-- Fixed-Price Contracts. This calculation
measures the amount by which such contracts are in- or out-of-the money in
relation to market prices at each respective year-end. Since Fixed-Price
Contracts are used to hedge natural gas and crude oil prices, any change in
contract value is expected to be offset by an opposite change in the value of
the Company's reserves hedged by the contracts.
The fair value of bank debt at December 31, 1996 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 by
applying an estimated credit spread to quoted yields for treasury notes with
comparable maturities to the respective debt instrument. The fair value of the
Company's interest rate swaps for each of the years presented is based on market
quotations 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, 1995, 1996 and 1997, Fixed-Price Contracts hedged 84%, 51%
and 60%, respectively, of the Company's gas production and 86%, 67% and 33%,
respectively, of its oil production. As of December 31, 1997, Fixed-Price
Contracts are in place to hedge 310 Bcf of the Company's estimated future gas
production and 79 MBbls of its 1998 oil 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.
F-22
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 13--FIXED-PRICE CONTRACTS (CONTINUED)
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,
1997.
YEARS ENDING DECEMBER 31, BALANCE
------------------------------------------------ THROUGH
1998 1999 2000 2001 2002 2017 TOTAL
-------- -------- -------- -------- -------- -------- ----------
(DOLLARS IN THOUSANDS, EXCEPT PRICE DATA)
NATURAL GAS SWAPS:
SALES CONTRACTS
Contract volumes (BBtu)................................... 13,825 15,825 9,830 7,475 6,405 23,433 76,793
Weighted-average fixed price per MMBtu (1)................ $ 2.33 $ 2.44 $ 2.46 $ 2.47 $ 2.67 $ 3.20 $ 2.68
Future fixed-price sales.................................. $ 32,243 $ 38,629 $ 24,164 $ 18,446 $ 17,098 $ 74,922 $ 205,502
Future net revenues (2)................................... $ 999 $ 2,865 $ 2,145 $ 1,665 $ 2,654 $ 19,997 $ 30,325
PURCHASE CONTRACTS
Contract volumes (BBtu)................................... (9,125) (10,950) -- -- -- -- (20,075)
Weighted-average fixed price per MMBtu (1)................ $ 2.09 $ 2.18 $ -- $ -- $ -- $ -- $ 2.14
Future fixed-price purchases.............................. $(19,108) $(23,880) $ -- $ -- $ -- $ -- $ (42,988)
Future net revenues (2)................................... $ 1,515 $ 867 $ -- $ -- $ -- $ -- $ 2,382
NATURAL GAS PHYSICAL DELIVERY CONTRACTS:
Contract volumes (BBtu)................................... 36,060 28,204 26,749 27,300 27,175 106,921 252,409
Weighted-average fixed price per MMBtu (1)................ $ 2.64 $ 2.84 $ 3.04 $ 3.19 $ 3.35 $ 4.30 $ 3.55
Future fixed-price sales.................................. $ 95,130 $ 80,125 $ 81,403 $ 86,963 $ 91,170 $460,285 $ 895,076
Future net revenues (2)................................... $ 13,550 $ 16,120 $ 20,856 $ 25,152 $ 29,271 $181,507 $ 286,456
TOTAL NATURAL GAS CONTRACTS (3)(4):
Contract volumes (BBtu)................................... 40,760 33,079 36,579 34,775 33,580 130,354 309,127
Weighted-average fixed price per MMBtu (1)................ $ 2.66 $ 2.87 $ 2.89 $ 3.03 $ 3.22 $ 4.11 $ 3.42
Future fixed-price sales.................................. $108,265 $ 94,874 $105,567 $105,409 $108,268 $535,207 $1,057,590
Future net revenues (2)................................... $ 16,064 $ 19,852 $ 23,001 $ 26,817 $ 31,925 $201,504 $ 319,163
CRUDE OIL SWAPS:
Contract volumes (MBbls).................................. 79 -- -- -- -- -- 79
Weighted-average fixed price per Bbl (1).................. $ 22.20 $ -- $ -- $ -- $ -- $ -- $ 22.20
Future fixed-price sales.................................. $ 1,754 $ -- $ -- $ -- $ -- $ -- $ 1,754
Future net revenues (2)................................... $ 345 $ -- $ -- $ -- $ -- $ -- $ 345
- ------------------------
(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, 1997, as adjusted for basis. Future net
revenues change as market prices and basis fluctuate. See "Market Risk."
(3) Does not include basis swaps with notional volumes by year, as follows:
1998--24.5 TBtu; 1999--19.0 TBtu; 2000--21.3 TBtu; 2001--9.4 TBtu; and
2002--5.5 TBtu.
(4) Does not include 1.4 TBtu of natural gas hedged by fixed-price collars for
1998 with a weighted-average floor price of $2.34 per MMBtu and a
weighted-average ceiling price of $2.55 per MMBtu.
F-23
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 13--FIXED-PRICE CONTRACTS (CONTINUED)
The estimates of the future net revenues of 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.
Such estimates do not necessarily represent the fair market value of the
Company's Fixed-Price Contracts or the actual future net revenues that will be
received. The forward market prices for natural gas and oil are highly volatile,
are dependent upon supply and demand factors in such forward market and may not
correspond to the actual market prices at the settlement dates of the Company's
Fixed-Price Contracts. Such forward market prices are available in a limited
over-the-counter market and are obtained from sources the Company believes to be
reliable.
ACCOUNTING. 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. 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. Consequently, no amounts are reflected in the Company's
balance sheets or income statements related to changes in market value of the
contracts. If a Fixed-Price Contract 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, 1996 and 1997, the Company had
deferred gains from price-risk management activities of $26.2 million and $23.5
million, respectively. 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.
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 is a party to two Fixed-Price Contracts, both long-term physical
delivery contracts, with independent power producers ("IPPs") which sell
electrical power under firm, fixed-price contracts to Niagara Mohawk Corporation
("NIMO"), a New York state utility. The Company's Fixed-Price Contracts with
such IPPs hedged an aggregate 96 Bcf of natural gas as of December 31, 1997. At
December 31, 1997, the net present value of the differential between the fixed
prices provided by these contracts and forward market prices, as adjusted for
basis and discounted at 10%, was $138 million, or 73% of such net present value
attributable to all of the Company's Fixed-Price Contracts. This premium in the
fixed prices is not reflected in the Company's financial statements until
realized. For the years ended December 31, 1995, 1996 and 1997, these contracts
contributed $9.6 million, $.9 million and $1.8 million, respectively, to natural
gas sales. The ability of these IPPs to perform their obligations to the Company
is 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 IPPs that are
counterparties to the Company's Fixed-Price Contracts described above, and has
further stated that its future financial prospects are dependent on its ability
to resolve these obligations, along with other matters.
F-24
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 13--FIXED-PRICE CONTRACTS (CONTINUED)
In July 1997, NIMO entered into a Master Restructuring Agreement (the "MRA")
with 16 IPPs, including the Company's counterparties. Pursuant to the MRA, the
power purchase agreements between NIMO and the IPPs would be terminated,
restated or amended, in exchange for an aggregate of $3.6 billion in cash, $50
million in notes or cash, 46 million shares of NIMO common stock and certain
fixed-price swap contracts. The allocation of the consideration among the IPPs
has not been disclosed. The closing of the MRA is conditioned upon, among other
things, NIMO and the IPPs negotiating their individual restated and amended
contracts, the receipt of all regulatory approvals, the IPPs entering into new
third party arrangements which will enable each IPP to restructure its projects
on a reasonably satisfactory economic basis, NIMO having completed all necessary
financing arrangements and NIMO and the IPPs having received all necessary
approvals from their respective boards of directors, shareholders and partners.
At this time, the Company cannot predict whether the conditions precedent to
the closing of the MRA will ultimately be satisfied. Any proceeds received by
the Company in consideration for termination of a Fixed-Price Contract would be
used to repay indebtedness outstanding under the Bank Credit Facility and would
be reflected under current accounting rules in the Company's balance sheet as
deferred hedging gains to be amortized into oil and gas revenues over the
original life of the underlying contracts. However, the amount of any proceeds
to be received by the Company is subject to negotiation with the Company's
counterparties and contingent upon the counterparties participating in the
closing of the MRA. Negotiations with the Company's counterparties are governed
by confidentiality agreements. Cancellation of the contracts would subject a
greater portion of the Company's gas production to market prices, which in a low
gas price environment could adversely affect the carrying value of the Company's
oil and gas properties and could otherwise have an adverse effect on the
Company.
MARKET RISK. The Company's natural gas Fixed-Price Contracts at December
31, 1997 hedge 310 Bcf of proved natural gas reserves at fixed prices. These
contract quantities represent 30% of the Company's estimated proved natural gas
reserves as of December 31, 1997. 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, 1995, 1996 and 1997, the Company received on an Mcf
basis approximately 3%, 3% and 1% less than the prices specified in its natural
gas Fixed-Price Contracts, respectively, due to basis. Such results exclude the
impact of a temporary loss of correlation which occurred in the first quarter of
1996. For its oil production hedged by crude oil Fixed-Price Contracts, the
Company realized approximately 7%, 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%
F-25
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 13--FIXED-PRICE CONTRACTS (CONTINUED)
move in price realization for hedged natural gas in 1998 represents a $1.1
million change in gas sales. A 1% change in price realization for hedged oil
production in 1998 would be less than $.1 million. The Company actively manages
its exposure to basis movements and from time to time will enter into contracts
designed to reduce such exposure.
MARGINING. 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, 1995, 1996 and 1997, the
maximum aggregate amount of margin posted by the Company was $23.4 million,
$28.4 million and $28.7 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, 1997, the Company had issued margin in
the form of letters of credit and treasury bills totaling $19.2 million and $4.5
million, respectively. In addition, approximately 27 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, 1995, 1996 and 1997. Reserve estimates for these years have
been prepared by the Company's petroleum engineers and reviewed by an
independent engineering firm. All studies have been prepared in accordance with
regulations prescribed by the Securities and Exchange Commission. Future net
revenue is estimated by such engineers using oil and gas prices in effect as of
the end of each respective year with price escalations permitted only for those
properties which have wellhead contracts allowing specific increases. Future
operating costs estimated in each study are based on historical operating costs
incurred. Reserve quantity estimates are calculated without regard to prices in
the Company's Fixed-Price Contracts.
The reliability of any reserve estimate is a function of the quality of
available information and of engineering interpretation and judgment. Such
estimates are susceptible to revision in light of subsequent drilling and
production history or as a result of changes in economic conditions.
F-26
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 14--SUPPLEMENTAL INFORMATION--OIL AND GAS RESERVES (UNAUDITED) (CONTINUED)
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, 1995, 1996 and
1997:
1995 1996 1997
---------------------- ---------------------- -----------------------
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
----------- --------- ----------- --------- ----------- ----------
PROVED RESERVES:
Beginning of year..................... 19,317 574,025 20,360 753,919 23,497 849,199
Acquisition of proved reserves........ 1,439 181,867 2,173 62,497 11,679 163,651
Extensions and discoveries............ 949 66,382 2,643 76,873 1,271 116,919
Revisions of previous
estimates (1)....................... 1,544 (7,738) 335 19,939 263 (26,345)
Sales of reserves in place............ (1,194) (9,353) (165) (119) (5,512) (2,941)
Production............................ (1,695) (51,264) (1,849) (63,910) (2,089) (71,731)
----------- --------- ----------- --------- ----------- ----------
End of year........................... 20,360 753,919 23,497 849,199 29,109 1,028,752
----------- --------- ----------- --------- ----------- ----------
----------- --------- ----------- --------- ----------- ----------
PROVED DEVELOPED RESERVES:
Beginning of year..................... 13,089 433,306 14,839 630,604 17,894 709,712
----------- --------- ----------- --------- ----------- ----------
----------- --------- ----------- --------- ----------- ----------
End of year........................... 14,839 630,604 17,894 709,712 24,321 899,196
----------- --------- ----------- --------- ----------- ----------
----------- --------- ----------- --------- ----------- ----------
- ------------------------
(1) Revisions for 1996 and 1997 are primarily the result of significant
movements in year-end natural gas prices between the periods presented.
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, 1995, 1996 and
1997, as adjusted for the effects of the Company's existing Fixed-Price
Contracts, as follows: 1995--$17.80 per Bbl, $2.60 per Mcf; 1996--$24.66 per
Bbl, $3.55 per Mcf; and 1997--$16.77 per Bbl, $2.73 per Mcf.
(3) The resulting future gross revenue streams were reduced by estimated future
costs to develop and to produce the proved reserves, 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.
F-27
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 14--SUPPLEMENTAL INFORMATION--OIL AND GAS RESERVES (UNAUDITED) (CONTINUED)
(5) The resulting future net revenue streams were reduced to present value
amounts by applying a 10% discount factor.
DECEMBER 31,
-----------------------------------------
1995 1996 1997
------------ ------------- ------------
(IN THOUSANDS)
Future cash inflows................................ $ 2,325,573 $ 3,596,493 $ 3,291,773
Future production costs............................ (686,476) (1,053,989) (985,639)
Future development costs........................... (107,596) (125,074) (136,217)
Future income taxes................................ (377,771) (704,818) (438,183)
------------ ------------- ------------
1,153,730 1,712,612 1,731,734
Discount at 10% per year........................... (590,433) (909,168) (774,993)
------------ ------------- ------------
Standardized measure of discounted future net cash
flows (1)........................................ $ 563,297 $ 803,444 $ 956,741
------------ ------------- ------------
------------ ------------- ------------
SEC PV10% including Fixed-Price
Contracts (2).................................... $ 737,512 $ 1,117,734 $ 1,135,970
------------ ------------- ------------
------------ ------------- ------------
SEC PV10% excluding Fixed-Price
Contracts (2).................................... $ 524,354 $ 1,303,709 $ 1,002,649
------------ ------------- ------------
------------ ------------- ------------
- ------------------------
(1) The standardized measure of discounted future net cash flows excluding the
effect of the Company's Fixed-Price Contracts was $431.0 million, $922.6
million and $873.5 million as of December 31, 1995, 1996 and 1997,
respectively.
(2) 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.
F-28
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 14--SUPPLEMENTAL INFORMATION--OIL AND GAS RESERVES (UNAUDITED) (CONTINUED)
CHANGES RELATING TO THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS (UNAUDITED). The principal changes in the standardized measure of
discounted future net cash flows attributable to the Company's oil and gas
reserves for the years ended December 31, 1995, 1996 and 1997, were as follows:
YEARS ENDED DECEMBER 31,
-------------------------------------
1995 1996 1997
----------- ----------- -----------
(IN THOUSANDS)
Balance, beginning of year....................................... $ 476,821 $ 563,297 $ 803,444
Acquisitions of proved reserves.................................. 116,229 116,263 212,428
Extensions and discoveries, net of future development costs...... 52,823 147,817 118,849
Revisions of previous quantity estimates......................... 1,623 26,431 (22,766)
Oil and gas sales, net of production costs....................... (128,014) (140,943) (172,847)
Sales of reserves in place....................................... (7,953) (614) (35,896)
Net changes in sales prices and production costs................. 48,242 140,205 (177,843)
Development costs incurred and changes in estimated future
development costs.............................................. 30,279 13,099 27,804
Net change in income taxes....................................... (35,031) (140,076) 135,061
Accretion of discount............................................ 61,600 73,751 111,773
Changes in timing of production and other........................ (53,322) 4,214 (43,266)
----------- ----------- -----------
Balance, end of year............................................. $ 563,297 $ 803,444 $ 956,741
----------- ----------- -----------
----------- ----------- -----------
NOTE 15--QUARTERLY RESULTS (UNAUDITED)
1996 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)................... $ 39,850 $ 45,816 $ 48,988 $ 54,851 $ 61,062 $ 44,940 $ 46,793 $ 80,122
Operating profit (loss) (2).... 14,570 17,376 20,395 22,392 23,739 17,193 17,757 (44,545)
Net income (loss) (2).......... 2,252 4,534 6,510 7,806 14,035 4,205 4,402 (38,704)
Net income (loss) per share
--basic and diluted (3)...... .08 .16 .23 .28 .50 .15 .16 (1.03)
- ------------------------
(1) Revenue increases in the second quarter of 1996 and the fourth quarter of
1997 are largely attributable to acquisitions of proved properties. Revenue
increases in the fourth quarter of 1996, the first quarter of 1997 and the
fourth quarter of 1997 were also favorably impacted by higher oil and gas
prices.
(2) The operating loss and the net loss in the fourth quarter of 1997 were
attributable to a $75.2 million impairment charge. See Note 1--Significant
Accounting Policies.
(3) In December 1997, the Company adopted SFAS 128; such adoption did not result
in a revision to earnings per share amounts previously reported.
F-29
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, 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
------ --- --- -----------
------ --- --- -----------
December 31, 1995:
Allowance for doubtful accounts--Joint interest and other
receivables............................................. $ 1,022 $ 100 $ 36 $ 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-30
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 February
1997 (incorporated by reference to Exhibit 10.1 of the Registrant's Form 10-K for the fiscal year
ended December 31, 1996).
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 Louis Dreyfus Deferred Compensation Stock Equivalent Plan (incorporated by reference to Exhibit
10.18 of the Registrant's Form 10-K for the fiscal year ended December 31, 1994).
10.10 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).
10.11 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).
10.12 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).
10.13 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).
10.14 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).
21.1 List of subsidiaries of the Registrant.
23.1 Consent of Independent Auditors.
24.1 Powers of Attorney.
27.1 Financial Data Schedule.