UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
AMENDMENT NO. 1
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
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
--------------------
Securities registered pursuant to Section 12 (b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
COMMON STOCK, PAR VALUE $.01 PER SHARE NEW YORK STOCK EXCHANGE
9-1/4% SENIOR SUBORDINATED NOTES DUE 2004 NEW YORK STOCK EXCHANGE
Securities registered pursuant to Section 12 (g) of the Act:
NONE
--------------------
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. YES _X_ NO ___.
Indicate by check mark if disclosure of delinquent files pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]
The aggregate market value of the voting stock held by non-affiliates of
the Registrant at February 12, 1997, was approximately $117.5 million (based on
a value of $16.50 per share, the closing price of the Common Stock as quoted by
the New York Stock Exchange on such date). 27,801,500 shares of Common Stock,
par value $.01 per share, were outstanding on February 12, 1997.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 1997 Annual
Meeting of Shareholders, to be filed pursuant to Regulation 14A under the
Securities Exchange Act of 1934, are incorporated by reference into Part III.
LOUIS DREYFUS NATURAL GAS CORP.
FORM 10-K
TABLE OF CONTENTS
PAGE
----
PART I
Item 1 -- BUSINESS..................................................... 3
General............................................................. 4
Business Strategy................................................... 4
Forward-Looking Statements.......................................... 4
Recent Developments................................................. 5
Acquisitions........................................................ 5
Marketing........................................................... 6
Competition......................................................... 7
Regulation.......................................................... 7
Certain Operational Risks............................................ 10
Employees........................................................... 10
Relationship Between the Company and S.A. Louis Dreyfus et Cie...... 10
Potential Conflicts of Interest..................................... 11
Certain Definitions................................................. 11
Item 2 -- PROPERTIES................................................... 13
General............................................................. 13
Core Areas.......................................................... 13
Exploration Prospects............................................... 16
Reserves............................................................ 17
Costs Incurred and Drilling Results................................. 18
Acreage............................................................. 19
Productive Well Summary............................................. 19
Title to Properties................................................. 20
Item 3 -- LEGAL PROCEEDINGS............................................ 20
Item 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......... 20
PART II
Item 5 -- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.......................................... 21
Item 6 -- SELECTED FINANCIAL DATA...................................... 22
Item 7 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.......................... 23
Overview............................................................ 23
Results of Operations - Fiscal Year 1996 Compared
to Fiscal Year 1995................................................. 25
Results of Operations - Fiscal Year 1995 Compared
to Fiscal Year 1994................................................. 27
Capital Resources and Liquidity..................................... 28
Commitments and Capital Expenditures................................ 30
Fixed-Price Contracts............................................... 31
Sonora Gas Contract................................................. 35
Outlook for Fiscal Year 1997........................................ 35
Item 8 -- FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.................. 37
1
LOUIS DREYFUS NATURAL GAS CORP.
FORM 10-K
TABLE OF CONTENTS (CONTINUED)
PAGE
----
Item 9 -- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE......................... 37
PART III
Item 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......... 37
Item 11 -- EXECUTIVE COMPENSATION...................................... 37
Item 12 -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.................................................. 37
Item 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 37
PART IV
Item 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
ON FORM 8-K................................................. 38
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 reserve base is
primarily located in the Sonora area of West Texas, the Mid-Continent region,
the Permian Basin, and the Texas Gulf Coast. As of December 31, 1996, the
Company had proved reserves of 990 Bcfe with a Present Value (as hereinafter
defined) of $1.1 billion. The Company operates over 84% of its reserves, of
which 86% is natural gas and 83% is proved developed. The Company has a
long-lived asset base with a reserve life of 13.2 years at December 31, 1996.
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.
Subsequent thereto, S.A. Louis Dreyfus et Cie acquired or established other
subsidiaries or affiliates to conduct oil and gas activities which, through a
series of intercompany mergers in September 1993, were transferred to the
Company. In November 1993, the Company completed an initial public offering of
7.8 million shares of Common Stock with net proceeds of $129.9 million.
The Company has grown its production and reserves primarily through low
cost acquisitions and development drilling. Since 1990, the Company has
completed a significant number of reserve acquisitions including three
acquisitions ranging in size from $87 million to $180 million. Through its
acquisition and leasing programs, the Company has accumulated interests in 1.4
million gross acres with 1,200 potential drilling locations, of which 343 have
been assigned proved undeveloped reserves. The Company has exploited its
properties through an aggressive development drilling program, achieving a
drilling success rate of 96% since 1990. More recently, the Company has
emphasized exploratory drilling as an integral component of its operating
strategy. During 1996, the Company achieved success in this effort, as
evidenced by its completion of 18 of 25 exploratory wells.
The Company's balanced strategy of acquisitions and growth through drilling
has enabled the Company to replace 408% of its production since 1990 at an
average finding cost of $.71 per Mcfe. By increasing its production and
reserves, the Company has significantly grown its earnings per share and cash
flow as outlined in the table below:
PRODUCTION, PROVED RESERVES, EARNINGS
PER SHARE AND CASH FLOW GROWTH
COMPOUND
YEARS ENDED DECEMBER 31, ANNUAL
---------------------------------------------------------- GROWTH
1991 1992 1993 1994 1995 1996 RATE
------- ------- ------- ------- ------- -------- ----
Production (MMcfe).......... 19,985 28,650 43,179 54,321 61,434 75,004 30.3%
Proved reserves (MMcfe)..... 211,478 376,521 627,222 689,924 876,076 990,179 36.2
Earnings per share.......... $ .09 $ .09 $ .11 $ .39 $ .40 $ .76 53.2
Net cash provided by
operating activities (M$).. $16,514 $22,272 $52,666 $80,894 $89,515 $101,761 43.9
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.
3
BUSINESS STRATEGY
The Company's business strategy is to generate strong and consistent growth
in reserves, production, earnings and cash flow. The Company implements this
strategy through the following:
EXPANDED EXPLORATION PROGRAM. Stepped up exploration activity in the
Company's core regions exposes the Company to higher potential
production and reserve additions. The Company has a staff of 22
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. During
1996, the Company invested $15 million in connection with exploration
prospects, including drilling, seismic data collection and lease
acquisitions. Approximately $7 million of the 1996 exploration budget
was used for early stage lease acquisitions and seismic data
collection, which have created a foundation for an expanded
exploration program in 1997 and 1998. The Company has allocated $25
million, or 25%, of its current capital budget for additional
exploration activities in 1997.
GROWTH THROUGH DRILLING. In 1994, 1995 and 1996, the Company replaced
116%, 120% and 153%, respectively, of its production through the
drilling of 745 gross (450 net) wells, adding 251 Bcfe of proved
reserves (including revisions of previous estimates). The Company
conducts development drilling in areas where multiple productive oil
and gas bearing formations are likely to be encountered, thus reducing
dry hole risk.
STRATEGIC ACQUISITIONS. Since January 1, 1990, the Company has grown
rapidly by investing $629 million to acquire approximately 1 Tcfe of
proved reserves at an average acquisition cost of $0.66 per Mcfe. The
Company believes the cost of these acquisitions compares favorably to
industry averages. The acquisitions have been geographically
concentrated in the core regions where the Company possesses
considerable operating expertise and realizes economies of scale. The
Company principally targets acquisitions which have significant
development potential, are in close proximity to existing properties,
have a high degree of operatorship and can be integrated with minimal
incremental administrative cost.
PRICE RISK MANAGEMENT. The Company manages a portion of the risks
associated with decreases in prices of natural gas and crude oil
through long-term fixed-price physical delivery contracts and
financial contracts. Since 1990, the Company has generated $41
million in additional revenues through its price risk management
strategies. At December 31, 1996, 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 $190 million. These
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. Recently, a lesser portion of the Company's production has
been hedged due to the Company's reluctance to sell into a forward market
where prices trend down or are essentially flat over the next several
years. In 1996, 53% of the Company's production was sold pursuant to
fixed-price contracts, reduced from 83% in 1995.
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 (as
defined elsewhere herein) positions as of December 31, 1996, and other
information currently available to management. These statements assume,
among other things, (i) that no significant changes will occur in the
operating environment for the Company's oil and gas properties, and (ii) 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 risk, environmental risk,
drilling risk, reserve, operations and production risk, and counterparty
risk. Many 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 1997." Moreover, the Company may make
material acquisitions, 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
4
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.
RECENT DEVELOPMENTS
The following information discusses certain of the more significant
accomplishments of the Company during the year ended December 31, 1996.
ACQUISITIONS. During 1996, the Company acquired 76 Bcfe through a series
of proved reserve acquisitions for an aggregate $36.1 million, or $.48 per Mcfe.
The most significant 1996 acquisition was the purchase in April of certain
producing oil and gas properties located primarily in Oklahoma for a total
consideration of $32.3 million. The acquired oil and gas properties consisted
of 60 Bcfe of proved reserves.
1996 DRILLING PROGRAM. The Company's drilling program for 1996 resulted in
the drilling of 305 wells, of which, 289 wells were completed as commercial
producers, a drilling success rate of 95%. In connection with this program, the
Company added 115 Bcfe of proved reserves to its reserve base (including
revisions of previous estimates). See "Item 2 -- Properties -- Costs Incurred
and Drilling Results."
PROVED RESERVES. As of December 31, 1996, the Company's proved reserves
had grown 13% in relation to 1995 and was comprised of 23 MMBbls of oil and 849
Bcf of natural gas, or 990 Bcfe. This reserve growth represents a production
replacement ratio of more than 250%. The Company's estimated future net
revenues from reserves as of December 31, 1996 increased 58% to $2.4 billion.
The present value of such future net revenues discounted at 10% ("Present
Value") was $1.1 billion, an increase of 52% in relation to 1995. See "Item 2
- -- Properties -- Reserves" and Note 12 of the Notes to Consolidated Financial
Statements.
FINANCIAL RESULTS. The Company reported record earnings and cash flows
from operating activities for the year ended December 31, 1996, primarily as
the result of higher oil and gas production. Net income and cash flows from
operating activities were $21.1 million and $101.8 million, respectively.
See "Item 7 -- Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Results of Operations -- Fiscal Year 1996
Compared to Fiscal Year 1995."
ACQUISITIONS
The Company has completed a significant number of acquisitions during the
past five years, including three ranging in size from $87 million to $180
million. The following table summarizes the Company's acquisition activity for
the five years ending December 31, 1996:
SUMMARY ACQUISITION INFORMATION
YEARS ENDED DECEMBER 31,
----------------------------------------
1992 1993 1994 1995 1996 TOTAL
------ ------ ----- ------ ----- ------
Estimated proved reserves
acquired (Bcfe) (1)........... 163.8 296.8 56.1 190.5 75.5 782.7
Acquisition cost (MM$)......... $116.2 $188.9 $36.6 $118.7 $36.1 $496.5
Acquisition cost per Mcfe ($).. $ .71 $ .64 $ .65 $ .62 $ .48 $ .63
_____________
(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.
Senior 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 principally seeks
acquisitions in regions in which the Company believes that its prior experience
and existing operations will enable it to readily integrate the acquired
properties into its existing base of
5
operations.
The Company primarily seeks to acquire operated interests. 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 frequently seeks to acquire
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
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, basis swaps and option agreements (collectively
"Fixed-Price Contracts"). 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, 1996, these
contracts hedged 349 Bcf of natural gas and 362 MBbls of oil. 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 the past three years, a progressively smaller share
of the Company's production and reserve additions have been hedged due to a
reluctance to sell into a forward market where prices trend down or are
essentially flat over the next several years. Management believes that the
current relationship between cash flow protection and exposure to oil and gas
prices is an appropriate balance for the Company. However, the Company may
hedge a greater or smaller share of production in the future, depending on
market conditions, capital investment considerations and other factors.
DELIVERY CONTRACTS. The Company has entered into fixed-price natural gas
delivery contracts with independent power producers, natural gas pipeline
marketing affiliates, a municipality and other end users. Typically, these
contracts require the Company to deliver, and the purchaser to take,
specified quantities of natural gas at specified fixed prices, over the life
of the contracts. The Company meets its fixed-price delivery contract
requirements through purchases of natural gas in markets local to the
delivery point at the most attractive prices available. The contracts
generally permit the Company to deliver natural gas at its choice of several
pipeline or customary industry delivery points, permitting some market
flexibility to the Company in purchasing required natural gas supplies and
making deliveries and reducing transportation risks. Each contract is
individually negotiated based on the purchaser's specified needs.
ENERGY SWAPS. The Company enters into energy swaps as a fixed-price seller
in order to assure itself of fixed prices for the sale of its oil and gas
production. Less frequently, the Company enters into swaps as a fixed-price
purchaser to obtain a fixed-price supply to meet sale commitments at a
particular point in time. 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, counterbalance or 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.
6
COUNTERPARTIES. The following table summarizes certain information
concerning the Company's natural gas Fixed-Price Contracts and associated
counterparties at December 31, 1996:
NATURAL GAS FIXED-PRICE CONTRACT
VOLUMES BY COUNTERPARTY
VOLUMES COMMITTED (BBTU)
------------------------------------------------- PERCENTAGE
ENERGY SWAPS OF
DELIVERY ------------------ COMMITTED
CONTRACTS SALES PURCHASES COLLARS TOTAL VOLUME
--------- ------ --------- ------- ------- ----------
TYPE OF COUNTERPARTY:
Independent power producers.... 175,873 -- -- -- 175,873 50 %
Pipeline marketing affiliates.. 85,420 10,955 (1,825) -- 94,550 27
Financial institutions......... -- -- (20,675) 3,010 (17,665) (5)
Other.......................... 24,227 71,900 -- -- 96,127 28
------- ------ ------- ----- ------- ---
Total 285,520 82,855 (22,500) 3,010 348,885 100 %
------- ------ ------- ----- ------- ---
------- ------ ------- ----- ------- ---
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 from Company-operated properties is sold on a
market sensitive basis. During 1996, the Company had gas sales to three
unrelated purchasers which approximated 18%, 13% and 11% of total revenues.
In connection with a 1993 acquisition, the Company acquired the rights to
and obligations under a fixed-price, take-or-pay natural gas contract (the
"Sonora Gas Contract") with Lone Star Gas Company, then a division of ENSERCH
Corporation, ("Lone Star"). This contract covered a substantial portion of
the Company's production in the Sonora area and sales under such contract
accounted for 28% and 30% of the Company's total revenues during 1994 and
1995, respectively. The Sonora Gas Contract, which expired on December 31,
1995, provided a fixed price of $3.90 per Mcf during 1995. Subsequent to
December 31, 1995, the Company is selling the gas previously dedicated to the
Sonora Gas Contract to a third party at market prices which have been
significantly less than the fixed prices provided by the Sonora Gas Contract.
The loss of any wellhead purchaser is not anticipated to have a material
adverse effect on the Company because there are a substantial number of
alternative purchasers in the markets in which the Company sells its wellhead
production.
COMPETITION
The oil and gas industry is highly competitive. The Company competes 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 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
7
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 a non-operated working interest in an oil and gas lease
in the Gulf of Mexico, which was granted by the federal government and is
administered by the Minerals Management Service (the "MMS"), a federal
agency. This lease was issued through competitive bidding, contains
relatively standardized terms and requires compliance with detailed MMS
regulations and orders (which are subject to change by the MMS). For
offshore operations, lessees must obtain MMS approval for exploration,
development and production plans prior to the commencement of such
operations. In addition to permits required from other agencies (such as the
Coast Guard, the Army Corps of Engineers and the Environmental Protection
Agency), lessees must obtain a permit from the MMS prior to the commencement
of drilling. The MMS has promulgated regulations requiring offshore
production facilities located on the outer continental shelf to meet
stringent engineering and construction specifications. 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, other than damages caused by acts of war or the negligence of
third parties. 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
8
exploration and production wastes as "hazardous wastes" under RCRA which would
regulate such reclassified wastes and require government permits for
transportation, storage and disposal. If such legislation were to be
enacted, it could have a significant impact on the operating costs of the
Company, as well as the oil and gas industry in general. State initiatives
to further regulate oil and gas wastes could have a similar impact on the
Company.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "superfund" law, imposes liability, regardless
of fault or the legality of the original conduct, on certain classes of
persons that contributed to the release of a "hazardous substance" into the
environment. These persons include the current or previous owner and operator
of a site and companies that disposed, or arranged for the disposal, of the
hazardous substance found at a site. CERCLA also authorizes the EPA and, in
some cases, private parties to take actions in response to threats to the
public health or the environment and to seek recovery from such responsible
classes of persons of the costs of such action. In the course of operations,
the Company generates wastes that may fall within CERCLA's definition of
"hazardous substances." The Company may be responsible under CERCLA for all
or part of the costs to clean up sites at which such substances have been
disposed. The Company has not been named by the EPA or alleged by any third
party as being potentially responsible for costs and liabilities associated
with alleged releases of any "hazardous substance" at any superfund site, but
it is possible that it could be named in the future.
The Company's operations are subject to the requirements of the Federal
Occupational Safety and Health Act ("OSHA") and comparable state statutes.
The OSHA hazard communication standard, the EPA community right-to-know
regulations under Title III of the Federal Superfund Amendment and
Reauthorization Act and similar state statutes require that information be
organized and maintained about hazardous materials used or produced in its
operations. Certain of this information must be provided to employees, state
and local government authorities and citizens.
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 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
9
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
$46 per barrel in current dollars. The credit available for coal seam
natural gas is adjusted for inflation and was approximately $1.01 per MMBtu
for 1995. 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
$8.5 million of Section 29 tax credits available for utilization in its
federal income tax returns for the years 1997 through 2002. Utilization of
such credits is subject to a number 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 January 31, 1997, the Company had approximately 314 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 ownership, development and management, manufacturing,
the marketing of electricity, natural gas and petroleum products and crude oil
refining.
S.A. Louis Dreyfus et Cie currently is the beneficial owner of
approximately 74.2% 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, development, capital, operating and acquisition expenditure plans.
There is no agreement between S.A. Louis Dreyfus et Cie and any other party,
including the Company, that would prevent S.A. Louis Dreyfus et Cie from
acquiring additional shares of the Common Stock.
The Company has an agreement ("Services Agreement") with S.A. Louis Dreyfus
et Cie pursuant to which S.A. Louis Dreyfus et Cie provides to the Company
various services (principally insurance-related services). Such services
historically have been supplied to the Company by S.A. Louis Dreyfus et Cie, and
the Services Agreement provides for the further delivery of such services, but
only to the extent requested by the Company. The Company reimburses S.A. Louis
Dreyfus et Cie for a portion of the salaries of employees performing requested
services based on the amount of
10
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.
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
11
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.
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 reserves by
production for the twelve-month period prior to the date of determination
(in gas equivalents).
TBTU. One trillion Btus.
TCFE. Trillion cubic fee of gas equivalent, determined using the ratio of
one Bbl of oil or condensate to six Mcf of natural gas.
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial
quantities of oil and gas regardless of whether such acreage contains
proved reserves.
WORKING INTEREST. The operating interest which gives the owner the right
to drill, produce and conduct operating activities on the property and a
share of production.
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ITEM 2 -- PROPERTIES
GENERAL
The Company's oil and gas acquisition, exploration and development
activities are conducted mainly in four core areas: the Sonora area of West
Texas, the Mid-Continent region, the Permian Basin and the Texas Gulf Coast. At
December 31, 1996, the Company had interests in approximately 7,300 producing
properties, 2,900 of which it operates. These operated properties comprised 84%
of the Company's total proved reserves at such date, which included 23 MMBbls of
oil and 849 Bcf of natural gas, aggregating 990 Bcfe. Net daily production
during 1996 was 5.1 MBbls of oil and 174.6 MMcf of natural gas, or an aggregate
204.9 MMcfe. During such period, the Company received an average price of
$19.56 per Bbl of oil and $2.34 per Mcf of gas, including the effects of the
Company's Fixed-Price Contracts. See "Item 7 -- Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Results of
Operations -- Fiscal Year 1996 Compared to Fiscal Year 1995 -- Oil and Gas
Prices." During 1996, the Company drilled 280 developmental oil and gas wells,
271 of which were completed as commercial producers, and 25 exploratory wells,
18 which were successfully completed.
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, 1996:
CORE AREAS
MID-
SONORA CONTINENT PERMIAN (1) GULF COAST TOTAL
-------- --------- ----------- ---------- ---------
PROPERTY STATISTICS (AS OF DECEMBER 31, 1996)
Proved reserves (Bcfe)........................... 494 325 97 74 990
Percent of total proved reserves................. 50% 33% 10% 7% 100%
Average net daily production (MMcfe) (2)......... 78.1 82.1 27.1 22.5 209.8
Gross producing wells............................ 1,526 2,730 2,773 283 7,312
Net producing wells.............................. 1,478 803 331 121 2,733
Gross acreage.................................... 335,000 587,000 335,000 143,000 1,400,000
Net acreage...................................... 263,000 247,000 203,000 43,000 756,000
Potential drill sites............................ 550 250 200 200 1,200
1996 RESULTS
Gross wells drilled.............................. 96 82 101 26 305
Gross successful wells........................... 93 78 97 21 289
Drilling success................................. 97% 95% 96% 81% 95%
Production (Bcfe)................................ 28.1 28.4 10.4 8.1 75.0
Lease operating expense per Mcfe................. $ .46 $ .41 $ .56 $ .54 $ .47
BUDGETED 1997 CAPITAL EXPENDITURES (MM$)
Development...................................... $ 34 $ 28 $ 11 $ 2 $ 75
Exploration...................................... 2 4 3 16 25
-------- ------- ------- ------- ---------
Total............................................ $ 36 $ 32 $ 14 $ 18 $ 100
-------- ------- ------- ------- ---------
-------- ------- ------- ------- ---------
- -------------------
(1) - Includes the Company's Levelland properties which were sold in January
1997.
(2) - Consists of average net daily production for December 1996.
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.
13
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 160 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. The Company recently acquired over 10,000
gross acres and plans to drill several 100% working interest wells to test
primarily the Strawn formation in the Buckhorn horst block, a localized
fault-bounded structural feature. The Company is also evaluating the
potential for drilling horizontal wells in the Strawn formation. The Company
is encouraged by recent horizontal activity conducted by other operators west
of the Company's acreage.
ELLENBURGER FORMATION. The Ellenburger formation, which lies approximately
500 feet below the Strawn formation, continues to be a play with interesting
potential in the Sonora area. This formation, which is productive on acreage in
close proximity to the Company's Sonora properties, is expected to produce from
dolomitic porosity in structurally defined traps. Recent drilling into this
formation has resulted in encouraging gas shows and helped define the structural
and reservoir complexity of the Ellenburger. The Company is continuing a
mapping program using 2-D seismic information in conjunction with sub-surface
data obtained in the development of the Canyon and Strawn formations, to
identify locations which are structurally suited for hydrocarbon accumulation in
the Ellenburger. The relatively modest cost to deepen wells to this horizon
make the potential economics of this play highly attractive. The Company
anticipates at least three Ellenburger tests during 1997.
Since 1993, the Company has continued an aggressive development program in
the Sonora area. Through December 31, 1996, the Company had drilled 306 Canyon
and Strawn wells with only 3 dry holes. For 1997, the Company plans to drill an
additional 100 wells in Sonora. A majority of the wells proposed to be drilled
in 1997 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 550 undrilled locations on the
Company's acreage of which 132 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 the infill potential, many of the Company's producing
wells in the Sonora Area have recompletion possibilities in existing wellbores
from Canyon sands not currently producing.
MID-CONTINENT REGION
The Company was actively involved in the Mid-Continent region when it was
acquired by S.A. Louis Dreyfus et Cie and has subsequently acquired 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 and in Southern Oklahoma. 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.
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. These formations have
potential for excellent production and reserves. 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
14
the last 15 years.
The Company has pursued an active low risk infill drilling program over
the past three years and plans to drill 80 development wells in the region
during 1997. In addition, the Company has recently commenced drilling an
initial horizontal well to begin evaluating its extensive acreage containing
the Mississippi Lime formation. This well is planned to have a 2,300 foot
lateral extension.
The Company has identified 250 undrilled locations in the Mid-Continent
region, of which 110 have been assigned proved undeveloped reserves.
PERMIAN REGION
The majority of the Company's interests in this region was acquired in
acquisitions in 1992, 1993 and 1994. The Company is actively involved in
drilling development and exploration wells in the Delaware basin of Southeast
New Mexico and the Val Verde basin and Spraberry trend of West Texas. The
primary drilling objectives in this region are the Delaware, Spraberry, Wolfcamp
and Morrow 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 two 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.
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 located in the Midland basin and 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.
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 the last two years, the Company has pursued an active
infill drilling program in the Spraberry trend which will continue in 1997.
WOLFCAMP. The Wolfcamp in the Southern Delaware and Val Verde basins are
deposited as submarine fan sequences that are 200 to 800 feet thick and range in
depth from 4,000 to 12,000 feet. During 1996, the Company drilled 5 gross wells
in the Brown Bassett area with a 100% success rate. The Company plans to
continue additional development in the field in 1997. Additionally, the Company
plans to drill a second test well in its Pecos Grande prospect, in which it
holds a 56% working interest in 11,000 gross acres in Pecos County, Texas. The
Company drilled a dry hole on this prospect in 1996, but the Company believes
that the prospect has not been adequately tested.
MORROW FORMATION. The Morrow formation consists of northwest to southeast
trending fluvial systems exhibiting excellent porosity and permeability at
depths between 10,500 to 11,500 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 6 Bcf for a single well.
The Company has identified 200 undrilled locations in the Permian region,
of which 69 have been assigned proved undeveloped reserves.
GULF COAST REGION
The Company's properties in the Gulf Coast Region consist of varying
interests in the A.W.P. (Olmos) Field and the North Tatum Field, as well as
in an offshore Gulf of Mexico platform, West Delta 152, which is its most
significant producing property in this region. At December 31, 1996, the
Company owned between a 20% and 39% non-operated working interest in the West
Delta 152 Field ("West Delta 152") which has 16 producing wells. The wells
produce from an eight-pile, 24-slot platform located in the Gulf of Mexico in
380 feet of water approximately 40 miles south-southwest of Venice,
Louisiana. The Company successfully completed seven of eight wells drilled in
1996. The Company anticipates that 3 wells will be drilled in West Delta 152
during 1997.
15
The Company has identified 200 undrilled locations in the Gulf Coast region
of which 32 have been assigned proved undeveloped reserves.
EXPLORATION PROSPECTS
In 1996, the Company began to place more emphasis on exploratory drilling
activities. The Company invested $15 million in 1996 for seismic and leasehold
acquisition and the drilling of 25 wells. The Company has currently budgeted
$25 million for exploration activities in 1997. The Company's exploration
prospects are located throughout its core regions.
YOAKUM GORGE. The Yoakum Gorge project is located within the Company's
Gulf Coast region in Lavaca County, Texas. The Company is currently
reviewing the 150 square miles of high-fold 3-D seismic data that was
obtained in 1996 and is evaluating drilling opportunities on its 60,000 gross
acres. 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 13,000 to 16,000 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 range potential of .5 to 3 Bcf per
well and are relatively easy to identify using 3-D seismic. The Company
successfully completed 9 shallow tests during 1996 and plans to drill up
to 40 additional wells during 1997. Initial 3-D seismic interpretation
indicates at least 70 shallow sand leads similar to those drilled in 1996.
During 1997, the Company also plans to drill 4 exploratory wells to test the
Lower Wilcox structures. 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 Company holds a 35% working interest in this
project.
SOUTHWEST SPEAKS. The Company has a 25% working interest in this Lower
Wilcox project which is also located in Lavaca County, Texas. The Lower Wilcox
sands are a series of deltaic sands trapped on a growth faulted structure formed
during the Wilcox time. This setting yields multiple zones with high per well
reserves and excellent flow rates. During 1996, the Company drilled and
completed the Pilgreen No. 1 well at a depth of 13,700 feet, with initial
production of 5,000 Mcf per day at 7,000 pounds flowing tubing pressure. This
well is believed to have additional productive zones behind pipe. During 1997,
the Company plans to drill at least one well in this prospect and up to three
additional wells, if the results of a planned seismic project are favorable.
COTTON VALLEY REEF TREND. The Company has a 15% working interest in 26,000
acres in the Cotton Valley Reef trend in Leon and Freestone 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 16,000
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 readily identifiable on high quality 3-D seismic data. They
are typically between 300 and 600 feet thick and can extend across 40 to 80
acres. Discoveries in the region by other operators have resulted in initial
production of up to 40 MMcf per day with single well reserves of as much as 80
Bcfe. The Company has identified 40 leads based on its 2-D seismic data. The
Company plans to begin a 3-D seismic project of 50 square miles in this area
during the first quarter of 1997 with initial drilling to begin by year-end, if
the results of the seismic project are favorable.
PITCHFORK RANCH. The Company has an option to explore on approximately
140,000 acres of the Pitchfork Ranch over the next three years. The
Pitchfork Ranch is located in the Permian region in King and Dickens
Counties, Texas. The Company will be the operator with at least a 77.5%
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 plans to
complete a 30 square mile 3-D seismic project by mid-1997 with initial
drilling to begin later in the year if the results of the seismic project are
favorable.
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
16
have very good rock properties that yield high flow rates. Using 3-D
seismic, the Company has successfully completed the second of two wells
drilled in this area at an initial flow rate of 5.3 MMcf per day. Seismic
interpretations indicate at least six leads that have seismic signatures
similar to those of the successful completion. The Company plans to commence
the next well in the first quarter of 1997.
RESERVES
The following table sets forth the estimated net quantities of the
Company's proved and proved developed reserves as of December 31, 1994, 1995
and 1996, and the estimated future net revenues and Present Values
attributable to total proved reserves at such dates.
PROVED RESERVES (1)
AS OF DECEMBER 31,
-------------------------------------
1994 1995 1996 (2)
---------- ---------- -----------
ESTIMATED PROVED RESERVES:
Natural gas (Bcf)................... 574.0 753.9 849.2
Oil (MMBbls)........................ 19.3 20.4 23.5
Total (Bcfe)........................ 689.9 876.1 990.2
Future net revenues (M$)............ $1,219,760 $1,531,501 $2,417,430
Present Value (M$) (3).............. $616,005 $737,512 $1,117,734
ESTIMATED PROVED DEVELOPED RESERVES:
Natural gas (Bcf)................... 433.3 630.6 709.7
Oil (MMBbls)........................ 13.1 14.8 17.9
Total (Bcfe)........................ 511.8 719.6 817.1
YEAR-END PRICES USED IN ESTIMATING
FUTURE NET REVENUES:
Natural gas (per Mcf)............... $2.61 $2.60 $3.55
Oil (per Bbl)....................... $16.08 $17.80 $24.66
-------------------
(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.
(2) - Includes 34 Bcfe of proved reserves (of which 24 Bcfe were proved
developed) attributable to the Company's Levelland properties which
were sold in January 1997 (the "Levelland Sale"). Future net revenues
and the Present Value attributable to the Levelland properties were
$68.5 million and $35.9 million, respectively, at December 31, 1996.
(3) - Increases in the Present Value for 1996 were due, in part, to a
significant increase in December 1996 natural gas and crude oil
prices. Holding the reserve quantities set forth in the December 31,
1996 reserve study (shown above) constant, the impact of using
average 1996 natural gas and oil prices of $2.63 per Mcf and $21.18
per Bbl and would have been to lower the Present Value to $834
million.
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, 1996 are
based upon studies prepared by the Company's staff of engineers and reviewed
by Ryder Scott Company, independent petroleum engineers. Estimated
recoverable proved reserves have been determined without regard to any
economic benefit that may be derived from the Company's Fixed-Price
Contracts. Such calculations were prepared using standard geological and
engineering methods generally accepted by the petroleum industry and in
accordance with Securities and Exchange Commission guidelines. The estimated
future net revenues and Present Value, as adjusted for Fixed-Price Contracts,
were based on the engineers' production volume estimates with price
adjustments based on the terms of the Company's Fixed-Price Contracts as of
December 31, 1996. 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.
17
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 $11 million
and $15 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 less than spot market prices at December 31, 1996. If such
Fixed-Price Contracts were not in effect and the Company used December 31,
1996 wellhead prices, the estimated future net revenues attributable to
proved reserves and the Present Value thereof would be $2.6 billion and $1.3
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 12 --
Supplemental Information -- Oil and Gas Reserves" in the Consolidated Financial
Statements of the Company 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
YEARS ENDED DECEMBER 31,
--------------------------------
1994 1995 1996
-------- -------- --------
(IN THOUSANDS)
Property acquisition costs:
Proved........................... $ 36,575 $118,652 $ 36,125
Unproved......................... 4,953 1,717 6,934
-------- -------- --------
41,528 120,369 43,059
Exploration costs................ -- 391 10,610
Development costs................ 67,764 64,498 80,553
-------- -------- --------
Total............................ $109,292 $185,258 $134,222
-------- -------- --------
-------- -------- --------
18
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,
--------------------------------------------
1994 1995 1996
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Development wells:
Gas.................... 144 131 134 115 179 130
Oil.................... 27 6 114 28 92 19
Dry.................... 4 2 14 5 9 5
--- --- --- --- --- ---
Total.................. 175 139 262 148 280 154
--- --- --- --- --- ---
--- --- --- --- --- ---
Exploratory wells:
Gas.................... -- -- 3 1 18 6
Oil.................... -- -- -- -- -- --
Dry.................... -- -- -- -- 7 2
--- --- --- --- --- ---
Total.................. -- -- 3 1 25 8
--- --- --- --- --- ---
--- --- --- --- --- ---
As of December 31, 1996, the Company was involved in the drilling, testing
or completing of 8 gross (4 net) development wells.
ACREAGE
The following table sets forth the Company's developed and undeveloped oil
and gas lease acreage as of December 31, 1996. 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
------- ------- ------- -------
Sonora area.................... 214,656 175,494 120,080 87,900
Mid-Continent region........... 539,448 216,176 47,390 30,750
Permian region................. 141,801 41,451 193,572 161,421
Gulf Coast region.............. 53,214 19,560 89,437 23,700
------- ------- ------- -------
Total.......................... 949,119 452,681 450,479 303,771
------- ------- ------- -------
------- ------- ------- -------
PRODUCTIVE WELL SUMMARY
The following table sets forth the Company's ownership in productive
wells at December 31, 1996. Gross oil and gas wells include 138 wells with
multiple completions. Wells with multiple completions are counted only once
for purposes of the following table.
PRODUCTIVE WELLS
PRODUCTIVE WELLS (1)
--------------------
GROSS NET
----- -----
Gas.................................. 3,486 2,248
Oil.................................. 3,826 485
----- -----
Total................................ 7,312 2,733
----- -----
----- -----
-------------------
(1) - Includes 837 gross (95 net) wells in the Company's Levelland
properties which were sold in January 1997.
19
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 30 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
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.
The Company is not a defendant in any additional pending legal proceedings
other than routine litigation incidental to its business. While the ultimate
results of these proceedings cannot be predicted with certainty, the Company
does not believe that the outcome of these matters will have a material adverse
effect on the Company.
ITEM 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the quarter ended December 31, 1996, no matters were submitted by
the Company to a vote of its security holders.
20
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 February 12, 1997, the
Company estimates that there were approximately 1,000 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, 1995 and 1996, were
as follows:
COMMON STOCK MARKET PRICES
1995 1996
---------------- ----------------
HIGH LOW HIGH LOW
------ ------ ------ ------
QUARTER:
First.................... $14.38 $11.25 $15.13 $10.38
Second................... 16.50 13.88 15.13 10.75
Third.................... 15.00 12.00 15.75 13.25
Fourth................... 15.63 13.00 18.00 15.00
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 Company's bank credit facility and 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 will 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.
21
ITEM 6 -- SELECTED FINANCIAL DATA
The selected financial data presented below as of December 31, 1995 and
1996, and for each of the three years ended December 31, 1994, 1995 and 1996,
has been derived from, and is qualified by reference to, the Company's audited
Consolidated Financial Statements, including the notes thereto, attached as
pages F-1 to F-25. The selected financial data as of December 31, 1992, 1993
and 1994, and for the years ended December 31, 1992 and 1993, 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,
--------------------------------------------------------
1992 1993 1994 1995 1996
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
INCOME STATEMENT DATA:
Oil and gas sales............................. $ 59,821 $ 92,912 $138,584 $163,366 $185,558
Other income (loss)........................... 630 2,269 1,953 (418) 3,947
-------- -------- -------- -------- --------
Total revenues............................. 60,451 95,181 140,537 162,948 189,505
-------- -------- -------- -------- --------
Operating costs............................... 16,217 26,715 33,713 35,352 44,615
General and administrative.................... 6,448 11,822 15,309 16,631 16,325
Exploration costs............................. -- -- -- -- 4,965
Depreciation, depletion and amortization...... 25,148 38,649 53,321 57,796 65,278
Impairment of oil and gas properties (1)...... -- -- 5,300 15,694 --
Interest...................................... 9,939 14,364 16,856 21,736 26,822
-------- -------- -------- -------- --------
Total expenses............................. 57,752 91,550 124,499 147,209 158,005
-------- -------- -------- -------- --------
Income before income taxes.................... 2,699 3,631 16,038 15,739 31,500
Income taxes.................................. 820 1,371 5,292 4,722 10,398
-------- -------- -------- -------- --------
Net income.................................... $ 1,879 $ 2,260 $ 10,746 $ 11,017 $ 21,102
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Net income per share.......................... $ .09 $ .11 $ .39 $ .40 $ .76
Weighted average common shares outstanding.... 20,000 21,042 27,800 27,800 27,800
STATEMENT OF CASH FLOWS DATA:
Net cash provided by operating activities..... $ 22,272 $ 52,666 $ 80,894 $ 89,515 $101,761
Net cash used in investing activities......... 126,666 180,038 102,969 171,540 150,857
Net cash provided by financing activities..... 98,450 138,559 13,701 80,629 55,261
EBITDA (2).................................... 40,096 59,228 94,844 111,809 123,915
AS OF DECEMBER 31,
--------------------------------------------------------
1992 1993 1994 1995 1996
-------- -------- -------- -------- --------
(IN THOUSANDS)
BALANCE SHEET DATA:
Oil and gas properties, net................... $260,451 $432,842 $483,214 $584,900 $652,257
Total assets.................................. 290,354 481,488 528,261 634,937 733,613
Long-term debt, including current portion..... 191,631 203,955 215,010 314,760 343,907
Stockholders' equity.......................... 74,166 213,818 224,564 242,581 263,693
- -------------------
(1) - The impairment for 1994 was recorded in connection with the sale of
approximately one-half of the Company's ownership in an offshore property.
The 1995 impairment was recorded in connection with the adoption of SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-
Lived Assets to be Disposed Of." See "Item 7 -- Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Results
of Operations -- Fiscal Year 1995 Compared to Fiscal Year 1994 --
Impairment of Oil and Gas Properties."
(2) - EBITDA is defined herein as income (excluding gains and losses on
sales and retirements of assets and non-cash charges) before interest,
income taxes, and depreciation, depletion and amortization, but after
exploration costs ($5.0 million in 1996). EBITDA 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. The Company's bank credit facility
and the indenture agreement for the 9-1/4% Senior Subordinated Notes due
2004 include certain covenants based in part on EBITDA. However, EBITDA
should not be considered in isolation or as a substitute for net income,
cash flows provided by operating activities or other income or cash flow
data prepared in accordance with generally accepted accounting principles,
or as a measure of a company's profitability or liquidity. EBITDA
measures as presented may not be comparable to other similarly titled
measures of other companies. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Capital Resources and
Liquidity."
22
ITEM 7 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW
GENERAL. Since its acquisition by S.A. Louis Dreyfus et Cie in 1990, the
Company's oil and gas reserves and production have grown significantly as the
result of a number of proved reserve acquisitions and its active drilling
program. The Company's business strategy is to generate strong and consistent
growth in reserves, production, earnings and cash flow through a balanced
program of exploration and development drilling and strategic acquisitions of
oil and gas properties.
Over the three-year period ended December 31, 1996, the Company acquired an
aggregate 322 Bcfe for a total consideration of $191.4 million, or $.59 per
Mcfe. The Company intends to continue its strategy of acquiring producing
properties with significant development potential in its core regions.
The Company has maintained an active drilling program over the three-year
period ended December 31, 1996. The Company drilled 745 gross wells (450 net
wells), with an overall drilling success rate of 96%, adding 251 Bcfe of
reserves (including revisions of previous estimates) to its proved reserve base.
The year ended December 31, 1996 marked the third consecutive year that the
Company had 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 three-year period averaged $.75 per
Mcfe.
Recently, the Company has increasingly emphasized exploratory drilling as
an integral component of its operating strategy. During 1996, the Company
invested $15 million in connection with exploration prospects, including
drilling, seismic data collection and leasehold acquisition activities. The
Company has allocated $25 million, or 25%, of its current capital budget for
exploratory activities in 1997.
From 1990 through 1993, the Company's portfolio of Fixed-Price Contracts
hedged substantially all of its natural gas production. During that period, the
Company entered into several Fixed-Price Contracts which contained attractive
fixed natural gas prices relative to the acquisition cost of proved reserves.
Over the past few years, competition in Fixed-Price Contracts has increased and
the opportunities for attractive Fixed-Price Contracts have diminished, and spot
prices for natural gas have become significantly higher than nearby forward
market prices. In response to these changes, a progressively smaller share of
the Company's production and reserve growth has been hedged due to Management's
reluctance to sell into a forward market where prices trend down or are
essentially flat over the next several years. Management believes that the
current relationship between cash flow protection and exposure to oil and gas
prices is an appropriate balance for the Company. However, the Company may
decide to hedge a greater or smaller share of production in the future,
depending upon market conditions, capital investment considerations and other
factors. See "-- Fixed-Price Contracts".
23
SELECTED OPERATING DATA. The following table provides certain data
relating to the Company's operations.
SELECTED OPERATING DATA
YEARS ENDED DECEMBER 31,
--------------------------------------------------
1992 1993 1994 1995 1996
------- ------- -------- -------- --------
OIL AND GAS SALES: (M$)
Wellhead oil sales........................... $20,321 $34,542 $ 29,207 $ 28,973 $ 39,372
Effect of Fixed-Price Contracts (1).......... -- 1,516 5,064 1,077 (3,198)
------- ------- -------- -------- --------
Total oil sales.............................. $20,321 $36,058 $ 34,271 $ 30,050 $ 36,174
------- ------- -------- -------- --------
------- ------- -------- -------- --------
Wellhead natural gas sales:
Sales under Sonora Gas Contract (2)........ $ -- $ 4,108 $ 39,408 $ 49,500 $ --
Other sales................................ 37,878 56,803 55,945 60,573 148,244
------- ------- -------- -------- --------
Total...................................... 37,878 60,911 95,353 110,073 148,244
Effect of Fixed-Price Contracts (1).......... 1,622 (4,057) 8,960 23,243 1,140
------- ------- -------- -------- --------
Total natural gas sales...................... $39,500 $56,854 $104,313 $133,316 $149,384
------- ------- -------- -------- --------
------- ------- -------- -------- --------
PRODUCTION:
Oil production (MBbls)....................... 1,082 2,106 1,873 1,695 1,849
Natural gas production (MMcf):
Sold under Sonora Gas Contract (2)......... -- 1,076 10,247 12,692 --
Other production........................... 22,158 29,464 32,835 38,572 63,910
------- ------- -------- -------- --------
Total...................................... 22,158 30,540 43,082 51,264 63,910
------- ------- -------- -------- --------
------- ------- -------- -------- --------
Net equivalent production (MMcfe)............ 28,650 43,179 54,321 61,434 75,004
Oil production hedged by Fixed-Price
Contracts (MBbls)........................... -- 650 1,698 1,464 1,241
Gas production hedged by Fixed-Price
Contracts (BBtu)............................ 22,158 28,775 32,308 31,579 32,508
AVERAGE SALES PRICE:
Oil price (per Bbl):
Wellhead price............................. $ 18.78 $ 16.40 $ 15.59 $ 17.09 $ 21.29
Effect of Fixed-Price Contracts (1)........ -- .72 2.71 .64 (1.73)
------- ------- -------- -------- --------
Total...................................... $ 18.78 $ 17.12 $ 18.30 $ 17.73 $ 19.56
------- ------- -------- -------- --------
------- ------- -------- -------- --------
Average fixed price received under
Fixed-Price Contracts..................... $ -- $ 19.89 $ 20.15 $ 19.12 $ 19.53
Net effective cash realization (3)......... -- 94% 92% 93% 96%
Natural gas price (per Mcf):
Sales under Sonora Gas Contract (2)........ $ -- $ 3.82 $ 3.85 $ 3.90 $ --
Other wellhead sales....................... 1.71 1.93 1.70 1.57 2.32
------- ------- -------- -------- --------
Average price.............................. 1.71 1.99 2.21 2.15 2.32
Effect of Fixed-Price Contracts (1)........ .07 (.13) .21 .45 .02
------- ------- -------- -------- --------
Total...................................... $ 1.78 $ 1.86 $ 2.42 $ 2.60 $ 2.34
------- ------- -------- -------- --------
------- ------- -------- -------- --------
Average fixed price received under
Fixed-Price Contracts..................... $ 2.00 $ 2.17 $ 2.31 $ 2.40 $ 2.43
Net effective cash realization (3)......... 94% 87% 89% 97% 97%
Natural gas equivalent price (per Mcfe)...... $ 2.09 $ 2.15 $ 2.55 $ 2.66 $ 2.47
EXPENSES AND COSTS INCURRED: (per Mcfe)
Lease operating expenses..................... $ .45 $ .50 $ .51 $ .47 $ .47
Production taxes............................. .12 .12 .11 .11 .12
General and administrative................... .23 .27 .28 .27 .22
Depreciation, depletion and amortization -
oil and gas properties (4).................. .85 .85 .92 .88 .82
Finding cost (5)............................. .67 .71 .92 .70 .71
_____________
(1) - Effects of Fixed-Price Contracts represent the hedging results from
the Company's Fixed-Price Contracts. See "-- Fixed-Price Contracts."
(2) - The Sonora Gas Contract is a wellhead take or pay gas contract which
expired December 1995. See "-- Sonora Gas Contract."
(3) - 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. Natural gas results for 1996 do not include
the effects of a $4.3 million basis loss. See "-- Fixed-Price
Contracts -- Market Risk."
(4) - Does not include impairment losses of $5.3 million and $15.7 million
recorded for the years ended December 31, 1994 and 1995, respectively.
See "-- Results of Operations -- Fiscal Year 1995 Compared to Fiscal
Year 1994."
(5) - 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.
24
The following table presents certain information regarding the Company's
proved oil and gas reserves.
OIL AND GAS RESERVES DATA
AS OF DECEMBER 31,
------------------------------------------------------------
1992 1993 1994 1995 1996
-------- ---------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS)
ESTIMATED NET PROVED RESERVES (1)
Natural gas (MMcf)........................ 272,691 502,018 574,025 753,919 849,199
Oil (MBbls)............................... 17,305 20,867 19,317 20,360 23,497
Total (MMcfe)............................. 376,521 627,222 689,924 876,076 990,179
Reserve replacement ratio (2)............. 676% 714% 219% 430% 254%
Reserve life (in years) (3)............... 13.1 14.5 12.7 14.3 13.2
Estimated future net revenues including
Fixed-Price Contracts (1) (4)............ $757,650 $1,167,940 $1,219,760 $1,531,501 $2,417,430
Present Value including Fixed-Price
Contracts (1) (4)........................ 395,238 588,986 616,005 737,512 1,117,734
Present Value excluding Fixed-Price
Contracts (1) (4)........................ 294,441 455,362 358,766 524,354 1,303,709
_____________
(1) - Includes for 1996, data relating to the Company's Levelland
properties consisting of 34 Bcfe of proved reserves which were
sold in January 1997 for $27.1 million. Future net revenues and
the Present Value attributable to the Levelland properties were
$68.5 million and $35.9 million, respectively, at December 31,
1996.
(2) - 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.
(3) - The reserve life is calculated by dividing estimated net proved
reserves as of the date of determination by production for the
preceding twelve months.
(4) - 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 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. The Company experienced significant growth in total production
for the year ended December 31, 1996 in relation to 1995. 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. See "-- Sonora Gas Contract."
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
25
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. See "-- Fixed-Price Contracts."
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. See "-- Fixed-Price Contracts -- Market Risk."
OPERATING COSTS. Operating costs, which include lease operating expenses
and production taxes, 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 the periods presented 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. 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 incurred during 1996. No exploratory
dry holes were drilled and no exploratory geological and geophysical costs were
incurred during 1995.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense ("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. See "-- Impairment of Oil and Gas Properties" below.
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. See "-- Capital Resources and Liquidity."
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.
26
RESULTS OF OPERATIONS -- FISCAL YEAR 1995 COMPARED TO FISCAL YEAR 1994
NET INCOME AND CASH FLOWS FROM OPERATING ACTIVITIES. For the year ended
December 31, 1995, the Company reported net income of $11.0 million, or $.40 per
share, on total revenue of $162.9 million. This compares with net income of
$10.7 million, or $.39 per share, on total revenue of $140.5 million in 1994.
This improvement in earnings was achieved despite a $15.7 million pre-tax charge
recorded in the fourth quarter upon the adoption of SFAS 121. Cash flows from
operating activities (before working capital changes) for the year ended
December 31, 1995 reflected significant improvement, increasing 17% to $89.1
million from the $76.1 million reported for 1994. The improvements in earnings
and cash flows were primarily the result of a significant increase in gas
production and higher prices provided by the Company's Fixed-Price Contracts.
These items are discussed in greater detail below. Cash flows provided by
operating activities, inclusive of the net change in working capital, increased
to $89.5 million for 1995 compared to $80.9 million in 1994, principally for the
reasons discussed above.
PRODUCTION. The Company experienced growth in total oil and gas production
for the year ended December 31, 1995 in relation to 1994. On a natural gas
equivalent basis, the Company produced 61.4 Bcfe for 1995 compared to 54.3 Bcfe
for 1994, an increase of 13%. Natural gas production for 1995 was 51.3 Bcf, a
19% increase over the 43.1 Bcf produced in 1994. This significant increase was
primarily the result of proved reserve acquisitions made during 1995, the
largest of which was the July 1995 acquisition of oil and gas properties in the
Sonora field for $86.6 million, and the Company's drilling program. Oil
production for 1995 declined 10% to 1.7 MMBbls of oil compared to 1.9 MMBbls
produced in 1994.
OIL AND GAS PRICES. On a natural gas equivalent basis, the Company
realized an average price of $2.66 per Mcfe during 1995, an increase of 4%
compared to $2.55 per Mcfe for 1994. The Company's 1995 gas production yielded
an average price of $2.60 per Mcf, a 7% increase over the average price of $2.42
per Mcf for 1994. The Company's average gas price for 1995 was enhanced $.45
per Mcf as a result of the Company's Fixed-Price Contracts. The average gas
price for 1994 was enhanced $.21 per Mcf as a result of Fixed-Price Contracts in
effect for that period. The average oil price for 1995 decreased 3% to $17.73
per Bbl in relation to $18.30 per Bbl received in 1994. The average oil price
for 1995 was enhanced $.64 per Bbl as a result of Fixed-Price Contracts in
effect during the year. For 1994, the effect of Fixed-Price Contracts was to
increase the average oil price by $2.71 per Bbl.
The effect of higher gas production and higher gas prices in 1995 was to
increase gas sales by 28% to $133.3 million compared to $104.3 million for 1994.
The effect of lower oil production and lower oil prices in 1995 was to decrease
oil sales by 12% to $30.1 million compared to $34.3 million for 1994. The
aggregate impact of the Fixed-Priced Contracts hedging the Company's oil and gas
production was to increase oil and gas revenues by $24.3 million and $14.0
million for the years ended December 31, 1995 and 1994, respectively.
OTHER INCOME (LOSS). Other income (loss) for 1995 reflected a net loss of
$.4 million compared to income of $2.0 million reported for 1994. The major
components of the 1995 amount include a $4.3 million basis loss, a $1.3 million
gain resulting from the settlement of a legal claim and $1.1 million of well
services income. The 1994 amount was primarily comprised of well services
income. See "-- Fixed-Price Contracts -- Market Risk."
OPERATING COSTS. Operating costs, which include lease operating expenses
and production taxes, increased to $35.4 million for 1995, compared to $33.7
million for 1994. This increase is principally due to the operating costs of
the Sonora oil and gas properties acquired in July 1995. On a natural gas
equivalent unit of production basis, lease operating expenses for 1995 were $.47
per Mcfe compared to $.51 per Mcfe in 1994. This improvement is attributable to
operational efficiencies achieved in certain of the Company's major operating
areas, a reduction in remedial work performed on properties acquired in prior
periods and a reduction in lease operating expenses associated with the West
Delta 152 working interest sold in January 1995.
GENERAL AND ADMINISTRATIVE EXPENSE. G&A for 1995 was $16.6 million
compared to $15.3 million for 1994. This increase is principally the result
of an increase in personnel to accommodate the growth experienced by the
Company. On a natural gas equivalent unit of production basis, G&A costs were
$.27 per Mcfe for 1995 compared to $.28 per Mcfe for 1994. This favorable
change is primarily attributable to production from the July 1995 acquisition
of Sonora oil and gas properties which did not require a proportionate
increase in G&A.
DEPRECIATION, DEPLETION AND AMORTIZATION. DD&A for the year ended December
31, 1995 was $57.8 million
27
compared to $53.3 million for 1994. This increase is attributable to the
1995 increase in production discussed previously. On a natural gas
equivalent unit of production basis, the 1995 oil and gas DD&A rate was $.88
per Mcfe compared to $.92 per Mcfe for 1994. This improvement in 1995 was
primarily the result of proved reserves acquired during the year at a lower
cost per Mcfe.
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.
In January 1995, the Company completed the sale of approximately 50% of its
ownership in West Delta 152, a Company-operated offshore property, to an
unrelated third party for a sale price of $12 million. The buyer assumed
operations in February 1995. For the year ended December 31, 1994, in
connection with an earlier sale transaction involving West Delta 152 which was
not ultimately consummated, the Company recorded a $5.3 million impairment
charge. Such charge approximated the book loss incurred upon the ultimate sale
of the property interest.
INTEREST EXPENSE. Interest expense for 1995 was $21.7 million compared to
$16.9 million for 1994. This increase is principally attributable to higher
average outstanding indebtedness incurred in conjunction with 1995 acquisitions.
The net impact of interest rate swaps in effect during the years ended December
31, 1995 and 1994 was to decrease interest expense by $.3 million in 1995 and to
increase interest expense by $1.7 million in 1994.
INCOME TAXES. For 1995, the Company recorded a tax provision of $4.7
million on pre-tax income of $15.7 million, an effective rate of 30%. This
compares to a provision of $5.3 million on pre-tax income of $16.0 million for
1994, an effective rate of 33%. In the fourth quarter of 1995, the Company
recorded a $7.0 million capital contribution and a corresponding reduction in
deferred taxes payable in connection with the utilization of certain tax
attributes in its federal income tax return which were generated prior to the
initial public offering. Because these attributes were not deducted in the
consolidated federal income tax return of S.A. Louis Dreyfus et Cie, they became
available to the Company.
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, 1994, 1995 and 1996, the Company expended $103.8 million, $185.3
million and $134.2 million, respectively, in oil and gas property
acquisition, exploration and development activities and currently anticipates
spending $100 million in exploration and development activities in 1997. See
"--Commitments and Capital Expenditures." Such investments comprised
substantially all of the total cash flow invested by the Company during the
three-year period. Variations in capital expenditure levels over the
three-year period are primarily tied to the amount of proved property
acquisitions made in each year. For the three-year period, cash flows from
operating activities were $80.9 million, $89.5 million and $101.8 million,
representing 78%, 48% and 76%, respectively, of the oil and gas property
investments made for 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 both cash flows from
operating activities and the amount available for borrowing under the bank
credit facility. This, in turn, could impact the amount of capital
investment. See "--Fixed-Price Contracts" and "--Credit Facility." The
growth achieved in cash flows from operating activities over this period is
discussed under "--Results of Operations--Fiscal Year 1996 Compared to Fiscal
Year 1995" and "--Results of Operations--Fiscal Year 1995 Compared to Fiscal
Year 1994."
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, 1996. The Company has relied upon availability under
various revolving bank credit facilities and proceeds from the issuance of
subordinated notes to fund its investing activities. For the three years
ended December 31, 1994, 1995 and 1996, net amounts borrowed under such
arrangements were $15.5 million, $99.6 million and $29.0 million, or 15%, 54%
and 22%, respectively, of the oil and gas investments made for each year.
The Company's bank credit facilities, the availability thereunder, and the
subordinated notes are discussed in greater detail below. In addition, for
the year ended December 31, 1996, the Company received $26.2
28
million of deferred hedging gains, the majority of which was received in
connection with the amendment of a certain Fixed-Price Contract. See
"--Fixed-Price Contracts--Accounting."
The Company's EBITDA increased from $94.8 million in 1994 to $111.8
million in 1995 and $123.9 million in 1996. EBITDA is defined herein as
income (excluding gains and losses on sales and retirements of assets and
non-cash charges) before interest, income taxes and DD&A, but after
exploration costs ($5.0 million in 1996). Increases in EBITDA have occurred
primarily as a result of increases in the Company's oil and gas sales.
EBITDA 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. The Company's
bank credit facility and the indenture agreement for the 9-1/4% Senior
Subordinated Notes due 2004 include certain covenants based in part on
EBITDA. However, EBITDA should not be considered in isolation or as a
substitute for net income, cash flows provided by operating activities or
other income or cash flows data prepared in accordance with generally
accepted accounting principles, or as a measure of a company's profitability
or liquidity. EBITDA measures as presented may not be comparable to other
similarly titled measures of other companies.
CREDIT FACILITY. The Company has a revolving credit facility with a
syndicate of banks, as most recently amended July 31, 1996 to reduce the
pricing and extend the maturity (the "Credit Facility"), which provides up to
$300 million in borrowings and letters of credit (the "Commitment"), with
letters of credit limited to $75 million of such availability. The Commitment
reduces at the rate of $18.75 million per quarter commencing October 31, 1999
through July 31, 2003. Borrowings and letters of credit under the Credit
Facility are limited to the lesser of the Commitment or the Oil and Gas
Reserves Loan Value. The Oil and Gas Reserves Loan Value is a borrowing base
calculation determined by a periodic valuation of the Company's oil and gas
reserves and Fixed-Price Contracts. The Oil and Gas Reserves Loan Value was
most recently reset in December 1996 at $330 million. The Company has relied
upon the Credit Facility to provide funds for acquisitions and to provide
letters of credit to meet the Company's margin requirements under Fixed-Price
Contracts. See "-- Fixed-Price Contracts -- Margining." As of December 31,
1996, the Company had $235.0 million of principal and $3.3 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 agreement also provides
for a competitive bid option for borrowings under the facility. The LIBOR
interest rate margin and the commitment fee payable under the Credit Facility
are subject to a sliding scale based on the relationship of outstanding
indebtedness to the Present Value of the Company's oil and gas reserves and
Fixed-Price Contracts. The LIBOR interest rate margin varies from .25% to
.55% per annum. At December 31, 1996, the applicable interest rate was LIBOR
plus .30%. The Credit Facility also requires the payment of a facility fee
equal to .20% of the Commitment.
The Credit Facility contains various affirmative and restrictive
covenants. These covenants, among other things, limit additional
indebtedness, the extent to which volumes under Fixed-Price Contracts can
exceed proved reserves in any year and in the aggregate, the sale of assets
and the payment of dividends, and require the Company to meet certain
financial tests. Borrowings under the Credit Facility are unsecured.
The Company has entered into interest rate swaps to hedge the interest rate
exposure associated with the Credit Facility. As of December 31, 1996, the
Company had fixed the interest rate on average notional amounts of $153 million,
$99 million and $33 million for the years ended December 31, 1997, 1998, and
1999, respectively. Under the interest rate swaps, the Company receives the
LIBOR three-month rate (5.6% at December 31, 1996) and pays an average rate of
6.1% for 1997, 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. As of December 31, 1996, the effective interest rate for borrowings
under the Credit Facility was 6.3%. In June 1996, the Company entered into 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, 1995 and
1996, the amount of such deferrals was not material.
29
A reconciliation of the notional amounts of the Company's interest rate
swaps for each of the three years ended December 31, 1994, 1995 and 1996, is
as follows:
INTEREST RATE SWAPS - NOTIONAL AMOUNTS
YEARS ENDED DECEMBER 31,
------------------------------
1994 1995 1996
-------- -------- --------
(IN THOUSANDS)
Notional amount of fixed interest rate
swaps, beginning of year................ $170,000 $ 86,000 $203,000
Interest rate swaps added.............. 9,000 155,000 --
Interest rate swap settlements......... (38,000) (38,000) (17,000)
Interest rate swaps canceled........... (55,000) -- --
-------- -------- --------
Notional amount of fixed interest rate
swaps, end of year...................... $ 86,000 $203,000 $186,000
-------- -------- --------
-------- -------- --------
Notional amount of floating interest
rate swaps, beginning of year........... $ -- $ -- $ --
Interest rate swap added............... -- -- 25,000
-------- -------- --------
Notional amount of floating interest
rate swaps, end of year................. $ -- $ -- $ 25,000
-------- -------- --------
-------- -------- --------
SUBORDINATED NOTES. In June 1994, the Company completed the sale of $100
million of 9-1/4% Senior Subordinated Notes due 2004 (the "Notes") in a public
offering. The Notes were sold at 98.534% of face value to yield 9.48% to
maturity. Interest is payable semi-annually on June 15 and December 15. The
associated indenture agreement contains certain restrictive covenants which
limit, among other things, the prepayment of the Notes, the incurrence of
additional indebtedness, the payment of dividends and the disposition of
assets.
OTHER. The Company has certain other unsecured lines of credit
available to it which aggregated $53 million as of December 31, 1996. Such
short-term lines of credit are primarily used to meet margining requirements
under Fixed-Price Contracts and for working capital purposes. As of December
31, 1996, the Company had $10 million of indebtedness and $17.9 million of
letters of credit outstanding under such credit lines. Repayment of
indebtedness thereunder is expected to be made through Credit Facility
availability.
The Company believes that the borrowing capacity currently available and
to be made available upon future Oil and Gas Reserves Loan Value
redeterminations under the Credit Facility, combined with the Company's
internal cash flows, will be adequate to finance the capital expenditure
program budgeted for 1997 and to meet the Company's margin requirements under
its Fixed-Price Contracts. See "-- Commitments and Capital Expenditures" and
"-- Fixed-Price Contracts -- Margining." At December 31, 1996, the Company
had working capital of $4.3 million and a current ratio of 1.1 to 1. Total
long-term debt outstanding at December 31, 1996 was $343.9 million. The
Company's long-term debt as a percentage of its total capitalization was 57%.
The amount of required principal payments for the next five years and
thereafter as of December 31, 1996 are as follows: 1997 - $0; 1998 - $0;
1999 -$0; 2000 - $42.1 million; 2001 -$75.0 million; 2002 and thereafter -
$227.9 million.
In February 1997, the Company and S.A. Louis Dreyfus et Cie announced a
proposed combined primary and secondary offering of 5,500,000 shares of Common
Stock, 2,750,000 shares to be issued by each company. If the offering is
consummated, the Company intends to initially use its share of the net
offering proceeds to reduce outstanding indebtedness under the Credit Facility
and, subsequently, to fund acquisition, exploration and development
opportunities not considered in the Company's current 1997 capital budget, and
for other corporate purposes.
COMMITMENTS AND CAPITAL EXPENDITURES
The Company's primary business strategy has been to increase production
and reserves through exploration and development drilling activities and
through the acquisition of proved oil and gas properties. For the year ended
December 31, 1996, the Company expended $134.2 million in connection with this
strategy, funded principally through internally generated cash flows and bank
borrowings. The most significant 1996 acquisition occurred in April with the
purchase of certain producing oil and gas properties located primarily in
Oklahoma for a total consideration of $32.3 million. The acquired oil and gas
properties consisted of 60 Bcfe of proved reserves. Additionally, the Company
made numerous other acquisitions of proved oil and gas reserves during 1996
which aggregated 16 Bcfe for a combined
30
purchase price of $3.8 million. The results of operations relating to these
acquisitions have been included in the Company's financial results for the
periods subsequent to the closing of each transaction. In connection with
its 1996 drilling program, the Company expended $98.1 million, drilling 305
gross (162 net) wells, including 25 gross (8 net) exploratory wells and 280
gross (154 net) development wells. The Company's drilling activities added
115 Bcfe to its proved reserve base (including revisions to previous
estimates).
In November 1996, the Company purchased a 75-mile pipeline located in
the Sonora area for $15.2 million, including the associated compression
facilities and transportation contracts.
The Company's approved capital budget for 1997 provides for approximately
$100 million in exploration and development drilling activities. Of these
expenditures, $75 million is targeted for development activities and $25 million
for exploration activities to be conducted in its core operating areas of the
Gulf Coast, the Mid-Continent, Sonora and the Permian Basin. Actual levels of
exploration and development expenditures may vary due to many factors, including
drilling results, new drilling opportunities, oil and natural gas prices and
acquisition opportunities. The Company continues to actively search for
attractive proved reserve acquisitions, but is not able to predict the timing or
amount of capital expenditure which may ultimately be employed in acquisitions
during 1997.
In January 1997, the Company completed the Levelland Sale to an unrelated
third party. The Company received total sales proceeds of $27.1 million,
subject to closing costs and adjustments. The sale resulted in an estimated
pre-tax gain, after sales commission, of $8.5 million, to be recorded in the
first quarter of 1997. The proceeds were applied to outstanding indebtedness
under the Credit Facility.
See "Fixed-Price Contracts" for a discussion of the Company's commitments
under its Fixed-Price Contracts.
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, basis swaps and option
agreements. 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. In 1994, Fixed-Price Contracts hedged
98% of the Company's gas production not otherwise subject to fixed prices and
91% of its oil production. In 1995, Fixed-Price Contracts hedged 84% of the
Company's gas production and 86% of its oil production. For the year ended
December 31, 1996, Fixed-Price Contracts hedged 51% of the Company's gas
production and 67% of its oil production. As of December 31, 1996,
Fixed-Price Contracts are in place to hedge 349 Bcf of the Company's
estimated future production from proved gas reserves and 362 MBbls of its
estimated 1997 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.
31
The following table summarizes the estimated volumes, fixed prices,
fixed-price sales, fixed-price purchases and future net revenues (as defined
below) attributable to the Company's Fixed-Price Contracts as of December 31,
1996.
FIXED-PRICE CONTRACTS
YEARS ENDING DECEMBER 31, BALANCE
-------------------------------------------------- THROUGH
1997 1998 1999 2000 2001 2017 TOTAL
------- -------- -------- -------- ------- -------- --------
NATURAL GAS SWAPS, OPTIONS
AND FUTURES
SALES CONTRACTS
Contract volumes (BBtu)........... 6,068 13,825 15,825 9,830 7,475 29,832 82,855
Weighted-average fixed price
per MMBtu (1)................... $ 2.27 $ 2.33 $ 2.44 $ 2.46 $ 2.47 $ 3.08 $ 2.65
Future fixed-price sales (M$)..... $13,802 $ 32,243 $ 38,629 $ 24,164 $ 18,446 $ 92,005 $ 219,289
Future net revenues (M$) (2)...... $ 362 $ 2,381 $ 3,973 $ 2,489 $ 1,852 $ 22,866 $ 33,923
PURCHASE CONTRACTS
Contract volumes (BBtu)........... (2,425) (9,125) (10,950) -- -- -- (22,500)
Weighted-average fixed price
per MMBtu (1)................... $ 2.05 $ 2.09 $ 2.18 $ -- $ -- $ -- $ 2.13
Future fixed-price purchases (M$). $(4,973) $(19,108) $(23,880) $ -- $ -- $ -- $ (47,961)
Future net revenues (M$) (2)...... $ 399 $ 602 $ 100 $ -- $ -- $ -- $ 1,101
NATURAL GAS PHYSICAL
DELIVERY CONTRACTS
Contract volumes (BBtu)........... 33,111 36,060 28,204 26,749 27,300 134,096 285,520
Weighted-average fixed price
per MMBtu (1)................... $ 2.49 $ 2.64 $ 2.84 $ 3.04 $ 3.19 $ 4.11 $ 3.42
Future fixed-price sales (M$)..... $82,442 $ 95,130 $ 80,125 $ 81,403 $ 86,963 $551,455 $ 977,518
Future net revenues (M$) (2)...... $ 8,902 $ 17,782 $ 18,748 $ 22,486 $ 26,568 $210,070 $ 304,556
TOTAL NATURAL GAS
CONTRACTS (3) (4)
Contract volumes (BBtu)........... 36,754 40,760 33,079 36,579 34,775 163,928 345,875
Weighted-average fixed price
per MMBtu (1)................... $ 2.48 $ 2.66 $ 2.87 $ 2.89 $ 3.03 $ 3.93 $ 3.32
Future fixed-price sales (M$)..... $91,271 $108,265 $ 94,874 $105,567 $105,409 $643,460 $1,148,846
Future net revenues (M$) (2)...... $ 9,663 $ 20,765 $ 22,821 $ 24,975 $ 28,420 $232,936 $ 339,580
CRUDE OIL SWAPS AND FUTURES
Contract volumes (MBbls).......... 362 -- -- -- -- -- 362
Weighted-average fixed price
per Bbl (1)..................... $ 22.32 $ -- $ -- $ -- $ -- $ -- $ 22.32
Future fixed-price sales (M$)..... $ 8,080 $ -- $ -- $ -- $ -- $ -- $ 8,080
Future net revenues (M$) (2)...... $ (172) $ -- $ -- $ -- $ -- $ -- $ (172)
- -------------------
(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, 1996, 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:
1997 - 21.0 TBtu; 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 3.0 TBtu of natural gas hedged by fixed-price collars for
January through September 1997 with a weighted-average floor price of
$2.30 per MMBtu and a weighted-average ceiling price of $2.84 per MMBtu.
The estimates of the future net revenues and present value of the
Company's Fixed-Price Contracts contained herein 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
32
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.
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, 1994,
1995 and 1996, is as follows:
FIXED-PRICE CONTRACTS -- FUTURE FIXED-PRICE SALES AND PURCHASES
YEARS ENDED DECEMBER 31,
---------------------------------------
1994 1995 1996
---------- ---------- ----------
(IN THOUSANDS)
NATURAL GAS SWAPS - SALES CONTRACTS
Future fixed-price sales, beginning of year..... $ 232,797 $ 225,901 $ 194,580
Contract additions, net....................... 43,520 4,958 78,770
Contract settlements and revisions............ (50,416) (29,664) (10,544)
Contract cancellations (1).................... -- (6,615) (43,517)
---------- ---------- ----------
Future fixed-price sales, end of year (2) (3)... $ 225,901 $ 194,580 $ 219,289
---------- ---------- ----------
---------- ---------- ----------
NATURAL GAS SWAPS - PURCHASE CONTRACTS
Future fixed-price purchases, beginning of year. $ (29,689) $ (9,334) $ (46,656)
Contract additions............................ (9,334) (46,656) (1,994)
Contract settlements and revisions............ 22,006 9,334 689
Contract cancellations........................ 7,683 -- --
---------- ---------- ----------
Future fixed-price purchases, end of year....... $ (9,334) $ (46,656) $ (47,961)
---------- ---------- ----------
---------- ---------- ----------
NATURAL GAS PHYSICAL DELIVERY CONTRACTS
Future fixed-price sales, beginning of year..... $1,027,686 $ 963,356 $1,078,779
Contract additions............................ 34,933 173,274 1,787
Contract settlements and revisions............ (99,263) (57,851) (103,048)
---------- ---------- ----------
Future fixed-price sales, end of year (3)....... $ 963,356 $1,078,779 $ 977,518
---------- ---------- ----------
---------- ---------- ----------
CRUDE OIL SWAPS
Future fixed-price sales, beginning of year..... $ 74,096 $ 39,438 $ 15,400
Contract additions.............................. -- 4,321 16,913
Contract settlements and revisions.............. (34,658) (28,359) (24,233)
---------- ---------- ----------
Future fixed-price sales, end of year........... $ 39,438 $ 15,400 $ 8,080
---------- ---------- ----------
---------- ---------- ----------
-------------------
(1) - 1996 amounts are attributable to a contract with S.A. Louis Dreyfus
et Cie which was canceled in January 1996. See "-- Market Risk."
(2) - Does not include any future receipts or payments attributable to
fixed-price collars added in 1996 hedging 3.0 TBtu
of natural gas.
(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. 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.
In June 1996, the Company and an unaffiliated counterparty to one of its
fixed-price contracts amended the terms
33
of a fixed-priced natural gas contract to monetize the premium in the fixed
prices provided by the contract. Pursuant to the amendment, the Company
received a non-refundable payment in the amount of $25.0 million. As
consideration for this payment, the weighted-average fixed price over the
remaining 17 years of the contract was reduced from $3.20 per MMBtu to $2.37
per MMBtu, approximating the forward market prices for natural gas at the
time. The payment has been reflected in the Company's balance sheet as a
deferred hedging gain and is being amortized into earnings over the life of
the original 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 loss of a contract would subject
a greater portion of the Company's oil and gas production to market prices and
could adversely affect the carrying value of the Company's oil and gas
properties and the amount of borrowing capacity available under the Credit
Facility. The Company has not experienced non-performance by any Counterparty.
Two Fixed-Price Contracts which hedge an aggregate 106 Bcf of natural
gas as of December 31, 1996 are with independent power producers ("IPPs")
which sell electrical power under firm fixed-price contracts to Niagara
Mohawk Corporation ("NIMO"), a New York state utility. At December 31, 1996,
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 $135 million, or 71% 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, 1994, 1995 and 1996, these
contracts contributed $5.1 million, $9.6 million and $.9 million,
respectively, to natural gas sales. The ability of these IPPs to perform
their obligations to the Company is largely 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 the obligations, along with
a number of other matters. On March 10, 1997, NIMO announced that an
agreement in principle had been reached with 19 IPPs, including those who are
counterparties to the Company's contracts, to restructure or terminate
numerous power purchase contracts. This agreement in principle is subject to
negotiation of final agreements, regulatory and shareholder approvals and
other conditions, and the specific terms of the proposed agreements with the
Company's counterparties have not been disclosed to the Company. The Company
is unable to determine the effect of these proposed agreements on the
Company. However, to the extent NIMO is successful in reducing its obligations
to purchase power from the Company's counterparties, the ability of such
counterparties to continue to purchase natural gas from the Company under
existing Fixed-Price Contracts may be adversely affected, which may in turn
have an adverse effect on the Company.
MARKET RISK. The Company's Fixed-Price Contracts at December 31, 1996
hedge 349 Bcf of proved natural gas reserves, substantially all of which are
proved developed reserves, and 362 MBbls of oil, at fixed prices. These
contract quantities represent 41% and 2% of the Company's estimated proved
natural gas and crude oil reserves, respectively, at December 31, 1996. If
the Company's proved reserves are produced at rates less than anticipated,
the volumes specified under the Fixed-Price Contracts may exceed production
volumes. In such case, the Company would be required to satisfy its
contractual commitments at market prices in effect for each settlement
period, which may be above the contract price, without a corresponding offset
in wellhead revenue for any excess volumes. 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, 1994, 1995 and 1996, the Company received on an Mcf
basis approximately 11%, 3% and 3% less than the prices specified in its
natural gas Fixed-Price Contracts, respectively, due to basis. Such results
do not include a $4.3
34
million basis loss recognized in the fourth quarter of 1995, discussed below.
For its oil production hedged by crude oil Fixed-Price Contracts, the
Company realized approximately 8%, 7% 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 1997 represents a $913,000 change in
gas sales. A 1% change in price realization for hedged oil production in
1997 represents an $81,000 change in oil sales. The Company actively manages
its exposure to basis movements and from time to time will enter into
contracts designed to reduce such exposure.
In the first quarter of 1996, the Company experienced a significant
widening of basis for certain of its Fixed-Price Contracts. These particular
contracts have floating indices tied to the NYMEX natural gas contract or
involve the purchase of gas in the spot market priced at or near the Henry Hub
delivery point in Louisiana. Due to a significant increase in demand for
natural gas in the Northeast region of the United States, NYMEX prices for
natural gas rose disproportionately in relation to the regional market prices
received for the Company's natural gas. This temporary loss of correlation
resulted in a $4.3 million charge in the fourth quarter of 1995 (when the
anomaly was identified) to reflect the estimated basis loss incurred. To reduce
exposure to Henry Hub basis volatility, the Company canceled a 20-Bcf contract
with S.A. Louis Dreyfus et Cie in January 1996, receiving $1.6 million in
proceeds. These proceeds are being amortized into oil and gas sales over the
original 19-month contract term which commenced January 1996. The Company has
also entered into several basis swaps with unaffiliated parties which are
designed to substantially reduce exposure to basis volatility over the next six
years.
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, 1994,
1995 and 1996, the maximum aggregate amount of margin posted by the Company
was $41.0 million, $23.4 million and $25.9 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, 1996,
the Company had issued margin in the form of letters of credit and treasury
bills totaling $20.3 million and $5.6 million, respectively. In addition,
approximately 30 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.
SONORA GAS CONTRACT
During 1995, certain gas production from the Sonora area was dedicated
to a wellhead contract with Lone Star that provided a fixed sales price of
$3.90 per Mcf (the Sonora Gas Contract). The Sonora Gas Contract obligated
Lone Star to take or pay for at least 55% of the contracted wells' combined
deliverability. Lone Star was entitled to recoup payments made for gas not
taken in prior years by taking gas in excess of the 55% requirement without
payment and crediting the value of such excess gas against the amount
previously paid. For the years ended December 31, 1994 and 1995, such
recoupment was $16.6 million and $18.0 million, respectively. For the years
ended December 31, 1994 and 1995, sales to Lone Star under the Sonora Gas
Contract were $39.4 million and $49.5 million, respectively, or 28% and 30%
of total oil and gas sales, respectively. This contract expired on December
31, 1995. The production previously dedicated to this contract is being
sold, beginning January 1, 1996, to a third party under a contract with
market sensitive pricing provisions.
OUTLOOK FOR FISCAL YEAR 1997
GENERAL. The discussion of the Company's fiscal year 1997 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, 1996 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. The Forward-Looking Statements also assume that there
will be no material acquisitions or divestitures except as disclosed herein.
THE
35
COMPANY CAUTIONS THAT THE FORWARD-LOOKING STATEMENTS PROVIDED HEREIN ARE
SUBJECT TO ALL THE RISKS AND UNCERTAINTIES INCIDENT TO THE ACQUISITION,
EXPLORATION, DEVELOPMENT AND MARKETING OF OIL AND GAS RESERVES. THESE RISKS
INCLUDE, BUT ARE NOT LIMITED TO, COMMODITY PRICE RISK, ENVIRONMENTAL RISK,
DRILLING RISK, RESERVE RISK, OPERATIONS AND PRODUCTION RISK, AND COUNTERPARTY
RISK. MANY OF THESE RISKS ARE DESCRIBED ELSEWHERE HEREIN. MOREOVER, THE
COMPANY MAY MAKE MATERIAL ACQUISITIONS, 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.
PRODUCTION. Based on budgeted drilling expenditures and internal reserve
estimates for 1997, the Company expects continued growth in total oil and gas
production for 1997. See "-- Commitments and Capital Expenditures."
OIL AND GAS PRICES. The Company's Fixed-Price Contracts in 1997 provide
average fixed prices of $2.48 per Mcf and $22.32 per Bbl for its hedged natural
gas and crude oil, respectively, before consideration of basis. Based on
January 1997 quotations for regional natural gas prices for the balance of 1997
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, 1996, the
Company's Fixed-Price Contracts hedge 37 Bcf of natural gas production
(excluding 3 Bcf of fixed-price collars) and 362 MBbls of oil production in
1997. No plans currently exist to increase or decrease the amount of hedged
production volumes for 1997; however, the Company may decide to hedge a greater
or smaller share of production in the future.
The Company is unable to predict the market prices that will be received
for its unhedged production in 1997. For 1996, average monthly wellhead
prices for its natural gas ranged from $1.90 per Mcf to $3.91 per Mcf and its
oil prices varied from $17.29 per Bbl to $24.65 per Bbl. Because less than
one-half of the Company's estimated 1997 production is hedged by Fixed-Price
Contracts, the Company's 1997 oil and gas revenues are highly sensitive to
commodity price changes.
OTHER INCOME. The Company estimates that it will recognize a net
pre-tax gain of $8.5 million in connection with the Levelland Sale in January
1997 and that its well services income will remain relatively constant with
the prior year's results. Other miscellaneous sources of income, such as
gains or losses on other property dispositions, cannot be estimated. In
January 1996, the Company received a $10.8 million promissory note from
Midcon Offshore, Inc. in connection with the settlement of certain
litigation. On December 16, 1996, Midcon filed for protection from its
creditors under Chapter 11 of the United States Bankruptcy Code. 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
Company's financial statements. The Company will recognize income as any
payments are received. See Note 7 of the Notes to Consolidated Financial
Statements appearing elsewhere herein.
OPERATING COSTS. Lifting costs on an equivalent unit of production
basis are anticipated to remain relatively constant with the prior year as
the result of new production from wells to be drilled in 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 relatively
modest increase in its G&A costs for 1997. Planned increases in personnel and
personnel costs are expected to be largely offset by increases in overhead
recoveries from third parties.
EXPLORATION COSTS. The Company expects to commit approximately $25 million
of its 1997 capital expenditure budget to exploration drilling, leasehold,
seismic and other geological and geophysical costs. Under the successful
efforts method of accounting, the costs associated with unsuccessful exploration
wells are expensed. All exploratory geological and geophysical costs (budgeted
at $3.5 million for 1997) are expensed as incurred, regardless of ultimate
success in the discovery of new reserves. Remaining exploration costs to be
expensed in 1997 will depend on the Company's exploratory drilling results.
DEPRECIATION, DEPLETION AND AMORTIZATION. Based on the Company's proved
reserve position at December 31, 1996 and assuming 1997 finding cost results
comparable to 1996, the Company's DD&A per equivalent unit of production
36
is expected to decline modestly in 1997, subject to future revisions in the
Company's proved reserve position.
IMPAIRMENT OF OIL AND GAS PROPERTIES. Revisions to prices, reserves or
other factors which would result in a material change in the estimated future
net cash flows for the Company's oil and gas fields during 1997 are not
anticipated. Consequently, while no material impairment charge is expected, no
assurance can be given.
INTEREST EXPENSE. Based on budgeted capital expenditure levels,
estimated proceeds from the Levelland Sale, estimated proceeds from the
proposed Common Stock offering and estimated cash flows from operating
activities, a reduction in average outstanding indebtedness is anticipated
for 1997. Consequently, interest expense is anticipated to decrease in
relation to the prior year. However, the Company continues to actively
search for attractive proved reserve acquisitions and the Company may expand
its exploration and development activities over budgeted levels, which could
cause average outstanding indebtedness to increase. See "--Capital Resources
and Liquidity" for a discussion of interest rate information for borrowings
under the Credit Facility.
INCOME TAXES. The Company expects that the utilization of Section 29
credits in its tax provision for 1996 will result in an overall effective tax
rate of 34% to 36%.
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 1997 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, 1996.
ITEM 11 -- EXECUTIVE COMPENSATION
The information required under Item 11 will be contained in the Proxy
Statement under the heading "Executive Compensation and Other Information" and
is incorporated herein by reference.
ITEM 12 -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required under Item 12 will be contained in the Proxy
Statement under the heading "Security Ownership of Certain Beneficial Owners and
Management" and is incorporated herein by reference.
ITEM 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required under Item 13 will be contained in the Proxy
Statement under the headings "Certain Transactions" and "Executive Compensation
and Other Information -- Compensation Committee Interlocks and Insider
Participation" and is incorporated herein by reference.
37
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
------- ----------------------
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).
*10.1 Stock Option Plan of Louis Dreyfus Natural Gas Corp. as amended
and restated effective February 1997 (previously filed).
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 Loan Agreement dated as of October 6, 1994, among Louis Dreyfus
Natural Gas Corp., as Borrower, Banque Paribas (New York Branch),
as Administrative Agent, Banque Paribas (New York Branch), Bank
of Montreal and Citibank, N.A., as Co-Agents (Incorporated by
reference to Exhibit 10.1 of the Registrant's Form 10-Q for the
quarter ended September 30, 1994).
38
10.7 Amendment to Loan Agreement dated as of July 31, 1996
(Incorporated by reference to Exhibit 10.1 of the Registrant's
Form 10-Q for the quarter ended June 30, 1996).
10.8 Gas Purchase Contract, as amended, dated December 21, 1972
between Lone Star Gas Company and the Registrant (successor by
assignment) (Incorporated by reference to Exhibit 10.15 of the
Registrant's Registration Statement on Form S-l, Registration No.
33-69102).
10.9 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).
10.10 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).
*10.11 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).
10.12 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).
10.13 Notice of Execution for a natural gas swap transaction between
Louis Dreyfus Natural Gas Corp. and Duke/Louis Dreyfus L.L.C.
dated April 1, 1996. (Incorporated by reference to Exhibit 10.1
of the Registrant's Form 10-Q for the quarter ended March 31,
1996).
*10.14 Amendment to Option Agreement of Simon B. Rich, Jr. (previously
filed).
*10.15 Form of Amendment to Outstanding Option Agreements of Employees
(previously filed).
*10.16 Form of Amendment to Outstanding Option Agreements of
Non-Employee Directors (previously filed).
21.1 List of subsidiaries of the Registrant.
23.1 Consent of Independent Auditors.
24.1 Powers of Attorney (previously filed).
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. The Company filed no report on Form 8-K during the
quarter ended December 31, 1996.
39
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
LOUIS DREYFUS NATURAL GAS CORP.
Date: March 18, 1997 By: /s/ JEFFREY A. BONNEY
-------------------------------
Jeffrey A. Bonney
Vice President and Chief
Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
SIGNATURES TITLE DATE
---------- ----- ----
SIMON B. RICH, JR.* Chairman of the Board of March 18, 1997
- --------------------------- Directors
Simon B. Rich, Jr.
MARK E. MONROE* President, Chief Executive March 18, 1997
- --------------------------- Officer and Director
Mark E. Monroe (Principal Executive Officer)
RICHARD E. BROSS* Executive Vice President and March 18, 1997
- --------------------------- Director
Richard E. Bross
PETER B. FRITZINGER* Chief Financial Officer March 18, 1997
- --------------------------- and Treasurer (Principal
Peter B. Fritzinger Financial Officer)
/s/ JEFFREY A. BONNEY Vice President and March 18, 1997
- --------------------------- Chief Accounting Officer
Jeffrey A. Bonney (Principal Accounting Officer)
GERARD LOUIS-DREYFUS* Director March 18, 1997
- ---------------------------
Gerard Louis-Dreyfus
DANIEL R. FINN, JR.* Director March 18, 1997
- ---------------------------
Daniel R. Finn, Jr.
JOHN J. HOGAN, JR.* Director March 18, 1997
- ---------------------------
John J. Hogan, Jr.
JAMES T. RODGERS, III* Director March 18, 1997
- ---------------------------
James T. Rodgers, III
*By: /s/ JEFFREY A. BONNEY
--------------------------------
Jeffrey A. Bonney
ATTORNEY-IN-FACT
40
LOUIS DREYFUS NATURAL GAS CORP.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
- -------------------------------------------------------------------------------
CONSOLIDATED FINANCIAL STATEMENTS PAGE
----
Report of Independent Auditors........................................... F-2
Consolidated Balance Sheets:
December 31, 1995 and 1996............................................. F-3
Consolidated Statements of Income:
Years ended December 31, 1994, 1995 and 1996........................... F-4
Consolidated Statements of Stockholders' Equity:
Years ended December 31, 1994, 1995 and 1996........................... F-5
Consolidated Statements of Cash Flows:
Years ended December 31, 1994, 1995 and 1996........................... F-6
Notes to Consolidated Financial Statements............................... F-7
CONSOLIDATED FINANCIAL STATEMENT SCHEDULE
Schedule II - Consolidated Valuation and Qualifying Accounts............. F-27
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, 1995 and 1996, and
the related consolidated statements of income, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1996. 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, 1995 and 1996, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended December 31, 1996
in conformity with generally accepted accounting principles. Also, in our
opinion, the related financial statement schedule, when considered in relation
to the basic financial statements taken as a whole, presents fairly in all
material respects, the information set forth therein.
As discussed in Note 1 of the notes to the consolidated financial
statements, effective October 1, 1995, the Company adopted Statement of
Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of."
ERNST & YOUNG LLP
Oklahoma City, Oklahoma
January 31, 1997,
except for the second paragraph of Note 13, as to which the date is
March 10, 1997
F-2
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
A S S E T S
DECEMBER 31,
----------------------
1995 1996
--------- ---------
CURRENT ASSETS
Cash and cash equivalents......................... $ 1,584 $ 7,749
Receivables:
Oil and gas sales............................... 23,443 33,579
Joint interest and other, net................... 5,300 5,358
Deposits.......................................... 3,900 5,592
Inventory and other............................... 3,095 3,147
--------- ---------
Total current assets......................... 37,322 55,425
--------- ---------
PROPERTY AND EQUIPMENT, at cost, based on
successful efforts accounting.................... 762,654 907,027
Less accumulated depreciation, depletion and
amortization..................................... (172,801) (235,162)
--------- ---------
589,853 671,865
--------- ---------
OTHER ASSETS, net................................. 7,762 6,323
--------- ---------
$ 634,937 $ 733,613
--------- ---------
--------- ---------
L I A B I L I T I E S A N D S T O C K H O L D E R S ' E Q U I T Y
CURRENT LIABILITIES
Accounts payable.................................. $ 21,458 $ 36,415
Accrued liabilities............................... 7,912 7,251
Revenues payable.................................. 4,687 7,419
--------- ---------
Total current liabilities.................... 34,057 51,085
BANK DEBT......................................... 216,000 245,000
SUBORDINATED DEBT................................. 98,760 98,907
DEFERRED REVENUE.................................. 25,627 19,049
DEFERRED HEDGING GAINS............................ -- 26,226
OTHER LONG-TERM LIABILITIES....................... 4,285 6,961
DEFERRED INCOME TAXES............................. 13,627 22,692
--------- ---------
392,356 469,920
--------- ---------
COMMITMENTS AND CONTINGENCIES (Notes 7 and 11)
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,
27,800,000 and 27,800,750 shares, respectively.. 278 278
Additional paid-in capital........................ 197,291 197,301
Retained earnings................................. 45,012 66,114
--------- ---------
242,581 263,693
--------- ---------
$ 634,937 $ 733,613
--------- ---------
--------- ---------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-3
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)
YEARS ENDED DECEMBER 31,
-----------------------------------
1994 1995 1996
-------- -------- --------
REVENUES
Oil and gas sales.................... $138,584 $163,366 $185,558
Other income (loss).................. 1,953 (418) 3,947
-------- -------- --------
140,537 162,948 189,505
-------- -------- --------
EXPENSES
Operating costs...................... 33,713 35,352 44,615
General and administrative........... 15,309 16,631 16,325
Exploration costs.................... -- -- 4,965
Depreciation, depletion, and
amortization....................... 53,321 57,796 65,278
Impairment of oil and gas properties. 5,300 15,694 --
Interest............................. 16,856 21,736 26,822
-------- -------- --------
124,499 147,209 158,005
-------- -------- --------
Income before income taxes........... 16,038 15,739 31,500
Income taxes......................... 5,292 4,722 10,398
-------- -------- --------
NET INCOME........................... $ 10,746 $ 11,017 $ 21,102
-------- -------- --------
-------- -------- --------
Net income per share................. $ .39 $ .40 $ .76
-------- -------- --------
-------- -------- --------
Weighted average common shares
outstanding........................ 27,800 27,800 27,800
-------- -------- --------
-------- -------- --------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-4
LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
COMMON STOCK
--------------- ADDITIONAL TOTAL
PAR PAID-IN RETAINED STOCKHOLDERS'
SHARES VALUE CAPITAL EARNINGS EQUITY
------ ----- ---------- -------- -------------
BALANCE AT DECEMBER 31, 1993.. 27,800 $278 $190,291 $23,249 $213,818
Net income.................... -- -- -- 10,746 10,746
------- ---- -------- ------- --------
BALANCE AT DECEMBER 31, 1994.. 27,800 278 190,291 33,995 224,564
Contribution by affiliate..... -- -- 7,000 -- 7,000
Net income.................... -- -- -- 11,017 11,017
------- ---- -------- ------- --------
BALANCE AT DECEMBER 31, 1995.. 27,800 278 197,291 45,012 242,581
Exercise of stock options..... 1 -- 10 -- 10
Net income.................... -- -- -- 21,102 21,102
------ ---- -------- ------- --------
BALANCE AT DECEMBER 31, 1996.. 27,801 $278 $197,301 $66,114 $263,693
------ ---- -------- ------- --------
------ ---- -------- ------- --------
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,
---------------------------------------
1994 1995 1996
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income............................................... $ 10,746 $ 11,017 $ 21,102
Items not affecting cash flows:
Depreciation, depletion, amortization and impairment... 61,146 74,097 65,278
Deferred income taxes.................................. 3,183 3,348 9,065
Exploration costs...................................... -- -- 4,965
Other.................................................. 1,064 640 571
Net change in operating assets and liabilities:
Accounts receivable.................................... (4,441) (8,578) (10,194)
Deposits............................................... (1,265) (679) (1,692)
Inventory and other.................................... (113) (1,074) (52)
Accounts payable....................................... 5,939 5,982 14,957
Accrued liabilities.................................... 4,267 40 (661)
Revenues payable....................................... 368 412 2,732
Deferred revenue....................................... -- 4,310 (4,310)
--------- --------- ---------
80,894 89,515 101,761
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Oil and gas property expenditures........................ (103,796) (185,258) (134,222)
Additions to other property and equipment................ (1,738) (1,528) (17,660)
Proceeds from sale of property and equipment............. 3,947 15,125 1,101
Change in other assets................................... (1,382) 121 (76)
--------- --------- ---------
(102,969) (171,540) (150,857)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term bank borrowings.................. 50,928 240,350 241,240
Repayments of long-term bank borrowings.................. (131,750) (140,747) (212,240)
Net proceeds from issuance of subordinated debt.......... 96,317 -- --
Repayments to affiliate.................................. (6,736) -- --
Proceeds from stock options exercised.................... -- -- 10
Proceeds from issuance of fixed-price contract........... 22,028 -- --
Change in deferred revenue............................... (16,727) (18,590) (2,268)
Change in deferred hedging gains......................... -- -- 26,226
Change in other long-term liabilities.................... (359) (384) 2,293
--------- --------- ---------
13,701 80,629 55,261
--------- --------- ---------
Change in cash and cash equivalents...................... (8,374) (1,396) 6,165
Cash and cash equivalents, beginning of year............. 11,354 2,980 1,584
--------- --------- ---------
Cash and cash equivalents, end of year................... $ 2,980 $ 1,584 $ 7,749
--------- --------- ---------
--------- --------- ---------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW
INFORMATION
Interest paid, net of capitalized interest............... $ 16,983 $ 18,851 $ 25,254
Income taxes paid........................................ 225 3,533 1,387
--------- --------- ---------
$ 17,208 $ 22,384 $ 26,641
--------- --------- ---------
--------- --------- ---------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-6
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- SIGNIFICANT ACCOUNTING POLICIES
The accounting policies of Louis Dreyfus Natural Gas Corp. ("LDNG" or the
"Company") reflect industry practices and conform to generally accepted
accounting principles. The more significant of such policies are briefly
described below.
GENERAL. LDNG is an independent energy company primarily engaged in the
acquisition, development, exploration, production and marketing of natural gas
and crude oil. At December 31, 1996, approximately 74% 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 and Note 8 -- Employee Benefit Plans.
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, 1994 and 1995 to conform
to the financial statement presentation for the year ended December 31, 1996.
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 11 -- Fixed-Price Contracts -- Credit Risk. As of December 31, 1995
and 1996, 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, 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.
Depletion of acquired properties is computed by the unit-of-production method on
a field basis using proved reserves. Depreciation, depletion and amortization
of capitalized development costs, which include the costs of unsuccessful
development drilling, is computed by the unit-of-production method on a field
basis using proved developed reserves.
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
F-7
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
future cash flows are deemed impaired. The carrying value of these
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. Prior to the adoption
of SFAS 121, the net capitalized costs of total proved properties were
compared to total undiscounted estimated future net cash flows (including
income tax considerations) from total proved reserves. Any excess was
charged to expense in the period in which the excess occurred.
The Company provides for the estimated cost, at current prices, of
dismantling and removing oil and gas production facilities. Such estimated
costs are capitalized and amortized over the life of the related oil and gas
property. As of December 31, 1995 and 1996, the Company had accrued estimated
total future dismantling and restoration costs of $1.9 million.
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, 1995 and 1996,
was $5.3 million and $4.2 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. The Company's net underproduced imbalance position at
December 31, 1995 and 1996 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.
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 10 -- Financial Instruments and Note 11 -- Fixed-Price
Contracts. The Company does not hold or issue financial instruments with
leveraged features.
EARNINGS PER SHARE. Primary and fully diluted earnings per common share
are based on the weighted average number of shares of Common Stock outstanding.
The effects of common equivalent shares were immaterial or were not dilutive for
each of the periods presented. Accordingly, primary and fully diluted earnings
per share are the same for all periods presented.
F-8
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
STOCK OPTIONS AND EQUIVALENT RIGHTS. No accounting is made with respect
to stock options until they are exercised, as all options have been granted
at a price 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.
NOTE 2 -- PROPERTY AND EQUIPMENT
CAPITALIZED COSTS. The Company's oil and gas acquisition, exploration and
development activities are conducted primarily in Texas, Oklahoma and New
Mexico. The following table summarizes the capitalized costs associated with
these activities:
DECEMBER 31,
-------------------------
1995 1996
---------- ----------
(IN THOUSANDS)
Oil and gas properties:
Proved...................................... $ 749,584 $ 873,546
Unproved.................................... 2,280 6,657
Accumulated depreciation, depletion and
amortization.............................. (166,964) (227,946)
---------- ----------
584,900 652,257
---------- ----------
Other property and equipment................ 10,790 26,824
Accumulated depreciation.................... (5,837) (7,216)
---------- ----------
4,953 19,608
---------- ----------
$ 589,853 $ 671,865
---------- ----------
---------- ----------
Depreciation, depletion and amortization expense ("DD&A") of oil and gas
properties per Mcfe was $.92, $.88 and $.82 for the years ended December 31,
1994, 1995 and 1996, respectively. Such amounts do not include a $5.3 million
impairment recorded in connection with the sale of an offshore property in 1994
or a $15.7 million impairment recorded in conjunction with the adoption of SFAS
121 in 1995. See Note 1 -- Significant Accounting Policies. For the years
ended December 31, 1995 and 1996, the Company capitalized $266,000 and $431,000
of interest, respectively, in connection with its exploration and development
activities. No interest was capitalized for the year ended December 31, 1994.
Unproved properties at December 31, 1996 consist primarily of lease
acquisition costs incurred during 1996. The Company will evaluate such
properties over their respective lease terms.
COSTS INCURRED. The following table summarizes the costs incurred in the
Company's acquisition, exploration and development activities for the years
ended December 31, 1994, 1995 and 1996, respectively.
YEARS ENDED DECEMBER 31,
--------------------------------
1994 1995 1996
-------- -------- --------
(IN THOUSANDS)
Property acquisition costs:
Proved........................... $ 36,575 $118,652 $ 36,125
Unproved......................... 4,953 1,717 6,934
-------- -------- --------
41,528 120,369 43,059
Exploration costs................ -- 391 10,610
Development costs................ 67,764 64,498 80,553
-------- -------- --------
$109,292 $185,258 $134,222
-------- -------- --------
-------- -------- --------
F-9
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 3 -- PROPERTY ACQUISITIONS
OIL AND GAS PROPERTIES. In November 1993, the Company acquired certain
producing oil and gas properties in the Sonora area of West Texas ("Sonora").
The associated purchase price included the assumption of a deferred recoupment
liability owed to a purchaser of certain gas production from the acquired
properties. For the years ended December 31, 1994 and 1995, the purchaser
recouped $16.6 million and $18.0 million, respectively, by taking gas in excess
of contractually required volumes without payment therefor and crediting the
value of such gas against the deferred recoupment liability. The amounts
recouped by the purchaser have been reflected as gas sales and as cash flows
from operating activities for 1994 and 1995; the corresponding reduction in the
deferred recoupment liability, which was fully recouped as of December 31, 1995,
has been presented as cash flows used in financing activities.
In July 1995, the Company purchased certain additional producing oil and
gas properties in Sonora for $86.6 million. 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 acquisition was accounted for as a
purchase; accordingly, the results of operations relating to this acquisition
are included in the Company's financial results for the periods subsequent to
closing. The following unaudited pro forma results of operations data gives
effect to the acquisition as if the transaction had been consummated as of
January 1, 1994 and 1995, respectively. 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 the acquisition been consummated
as of January 1, 1994 or 1995, respectively, or of future results of operations.
The 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, to fund the acquisition.
YEARS ENDED DECEMBER 31,
------------------------
1994 1995
-------- --------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
Unaudited pro forma information:
Revenues................................. $162,816 $176,933
Net income............................... 12,163 12,158
Net income per share..................... .44 .44
During 1994, 1995 and 1996, the Company made numerous other acquisitions of
proved oil and gas properties, the net purchase price of which aggregated $36.6
million, $32.1 million and $36.1 million, respectively. The results of
operations related to such acquisitions have been included in the accompanying
statements of income and cash flows for the periods subsequent to the closing of
each transaction.
OTHER. In November 1996, the Company purchased a 75-mile pipeline located
in Sonora for $15.2 million, including the associated compression facilities and
transportation contracts. Amortization of the purchase price is computed by the
unit-of-production method using proved reserves.
F-10
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,
------------------------
1995 1996
-------- --------
(IN THOUSANDS)
BANK DEBT
Revolving bank credit facility (A)....... $209,000 $235,000
Other lines of credit (B)................ 7,000 10,000
-------- --------
216,000 245,000
SUBORDINATED DEBT (C).................... 98,760 98,907
-------- --------
$314,760 $343,907
-------- --------
-------- --------
(A) The Company has a revolving credit facility with a syndicate of banks,
as most recently amended July 31, 1996 to reduce the pricing and extend the
maturity (the "Credit Facility"), which provides up to $300 million in
borrowings and letters of credit (the "Commitment"), with letters of credit
limited to $75 million of such availability. The Commitment reduces at the
rate of $18.75 million per quarter commencing October 31, 1999 through July
31, 2003. Borrowings and letters of credit under the Credit Facility are
limited to the lesser of the Commitment or the Oil and Gas Reserves Loan
Value. The Oil and Gas Reserves Loan Value is a borrowing base calculation
determined by a periodic valuation of the Company's oil and gas reserves and
Fixed-Price Contracts. The Oil and Gas Reserves Loan Value was most recently
reset in December 1996 at $330 million. The Company has relied upon the
Credit Facility to provide funds for acquisitions and to provide letters of
credit to meet the Company's margin requirements under Fixed-Price
Contracts. See Note 11 -- Fixed-Price Contracts. As of December 31, 1996,
the Company had $235.0 million of principal and $3.3 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 agreement also
provides for a competitive bid option for borrowings under the facility.
The LIBOR interest rate margin and the commitment fee payable under the
Credit Facility are subject to a sliding scale based on the relationship
of outstanding indebtedness to the discounted present value of the
Company's oil and gas reserves and Fixed-Price Contracts. The LIBOR
interest rate margin varies from .25% to .55% per annum. At December 31,
1996, the applicable interest rate was LIBOR plus .30%. The Credit
Facility also requires the payment of a facility fee equal to .20% of the
Commitment.
The Credit Facility contains various affirmative and restrictive
covenants. These covenants, among other things, limit additional
indebtedness, the extent to which volumes under Fixed-Price Contracts can
exceed proved reserves in any year and in the aggregate, the sale of
assets and the payment of dividends, and require the Company to meet
certain financial tests. Borrowings under the Credit Facility are
unsecured.
The Company has entered into interest rate swaps to hedge the interest
rate exposure associated with the Credit Facility. As of December 31,
1996, the Company had fixed the interest rate on average notional amounts
of $153 million, $99 million and $33 million for the years ended December
31, 1997, 1998, and 1999, respectively. Under the interest rate swaps,
the Company receives the LIBOR three-month rate (5.6% at December 31,
1996) and pays an average rate of 6.1% for 1997, 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. As
of December 31, 1996, the effective interest rate for borrowings under
the Credit Facility was 6.3%. In June 1996, the Company entered into 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
F-11
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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, 1995
and 1996, the amount of such deferrals was not material.
(B) The Company has certain other unsecured lines of credit available to it,
which aggregated $53 million as of December 31, 1996. 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,
1996, the Company had $10 million of indebtedness and $17.9 million of
letters of credit outstanding under these credit lines. Repayment of
indebtedness thereunder is expected to be made through Credit Facility
availability.
(C) In June 1994, the Company completed the sale of $100 million of 9-1/4%
Senior Subordinated Notes due 2004 (the "Notes") in a public offering.
The Notes were sold at 98.534% of face value to yield 9.48% to maturity.
Interest is payable semi-annually on June 15 and December 15. The
associated indenture agreement contains certain restrictive covenants
which limit, among other things, the prepayment of the 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, 1996 are as follows: 1997 - $0; 1998 - $0;
1999 - $0; 2000 - $42.1 million; 2001 - $75.0 million; 2002 and thereafter -
$227.9 million.
NOTE 5 -- INCOME TAXES
The significant components of income tax expense for the years ended
December 31, 1994, 1995 and 1996 are as follows:
YEARS ENDED DECEMBER 31,
---------------------------
1994 1995 1996
------ ------ -------
(IN THOUSANDS)
Current tax expense:
Federal............................. $1,716 $1,195 $ 1,159
State............................... 393 179 174
------ ------ -------
2,109 1,374 1,333
------ ------ -------
Deferred tax expense:
Federal............................. 3,056 3,033 8,271
State............................... 127 315 794
------ ------ -------
3,183 3,348 9,065
------ ------ -------
$5,292 $4,722 $10,398
------ ------ -------
------ ------ -------
F-12
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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,
----------------------------
1994 1995 1996
------- ------- -------
(IN THOUSANDS)
Computed "expected" income tax......... $ 5,613 $ 5,509 $11,025
Increases (reductions) in taxes
resulting from:
State income taxes, net of
federal benefit................. 338 321 629
Permanent differences (principally
related to basis differences in
oil and gas properties)......... 298 861 265
Section 29 credits................ (2,269) (2,090) (2,028)
Other............................. 1,312 121 507
------- ------- -------
$ 5,292 $ 4,722 $10,398
------- ------- -------
------- ------- -------
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,
------------------
1995 1996
------- -------
(IN THOUSANDS)
Deferred tax liabilities:
Capitalized costs and related
depreciation, depletion,
amortization and impairment................... $25,653 $43,416
Other........................................... 817 825
------- -------
26,470 44,241
------- -------
Deferred tax assets:
Deferred revenue and hedging gains.............. 9,738 17,251
Alternative minimum tax credits................. 3,105 4,298
------- -------
12,843 21,549
------- -------
Net deferred tax liability...................... $13,627 $22,692
------- -------
------- -------
In 1995, the Company recorded a $7.0 million capital contribution and a
corresponding reduction in deferred taxes payable in connection with the
utilization of certain tax attributes in its federal income tax return. Such
attributes were generated prior to the Company's initial public offering but
were not deducted in the consolidated federal income tax return of the Company's
U.S. parent.
NOTE 6 -- TRANSACTIONS WITH RELATED PARTIES
FIXED-PRICE CONTRACT ACTIVITY. In 1991, one long-term sales contract
was assigned to the Company at S.A. Louis Dreyfus et Cie's net carrying value
of $9.7 million. Amortization of this contract approximated $2.5 million and
$607,000 for the years ended December 31, 1994 and 1995, respectively, and
has been reflected in the accompanying statements of income as a reduction of
oil and gas sales. This contract expired in March 1995.
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. In
conjunction with the execution of a 75-Bcf physical delivery contract with a
third party in July 1995, the Company canceled 3 Bcf of fixed-price sales
under this contract. The Company received approximately $760,000 as
consideration for this partial cancellation. Such consideration was deferred
and subsequently amortized into earnings during 1996 (the period covered by
the term of the canceled contract volumes).
F-13
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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, 1995 and 1996,
margin of $3.9 million and $5.6 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 two Fixed-Price Contracts with S.A.
Louis Dreyfus et Cie. The first of these was a fixed-price sale 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 proceeds are being amortized into earnings over the
original 19-month term of the contract. The second contract, also a natural
gas swap, provided for the purchase by the Company of 1.8 Bcf of natural gas
during the first quarter of 1995, at a fixed price of $1.81 per Mcf.
Also during 1994, in connection with the monthly purchase of natural gas
to supply certain of the Company's fixed-price delivery contracts, the
Company purchased 318 MMcf from S.A. Louis Dreyfus et Cie at an average price
of $2.21 per Mcf and sold 45 MMcf to S.A. Louis Dreyfus et Cie at an average
price of $2.30 per Mcf.
In 1996, the Company entered into a ten-year, 20-Bcf fixed-price sale
with Duke/Louis Dreyfus L.L.C., an affiliate, which commences June 1997. The
fixed prices in this contract range from $2.05 to $2.51 per MMBtu.
GENERAL AND ADMINISTRATIVE EXPENSE. In September 1993, the Company
entered into 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. Amounts
paid to S.A. Louis Dreyfus et Cie under this agreement (principally for
insurance costs) aggregated $605,000, $756,000 and $907,000 for the years
ended December 31, 1994, 1995 and 1996, respectively.
INTEREST. In October 1992, S.A. Louis Dreyfus et Cie assigned a third
party interest rate swap contract to the Company with a declining notional
amount of approximately $94 million pursuant to which the Company paid an
annual fixed interest rate of 5.9%. This contract matured in 1995.
OTHER. At December 31, 1995 and 1996, the Company owed S.A. Louis
Dreyfus et Cie approximately $.5 million and $2.3 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
F-14
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Midcon note is uncertain and no amounts have been recorded with respect
thereto in the accompanying financial statements as of December 31, 1996.
The Company will recognize income as any payments are received.
The Company is not a defendant in any additional pending legal
proceedings other than routine litigation incidental to its business. While
the ultimate results of these proceedings cannot be predicted with certainty,
the Company does not believe that the outcome of these matters will have a
material adverse effect on the Company.
RENTAL COMMITMENTS. Minimum annual rental commitments as of December
31, 1996 under noncancelable office space leases are as follows: 1997 - $1.8
million; 1998 - $1.7 million; 1999 and thereafter - $0. Approximately $1.8
million of such rental commitments is included in other long-term liabilities
as of December 31, 1996, presented net of estimated future rental income of
$1.0 million to be received over the next two years.
NOTE 8 -- EMPLOYEE BENEFIT PLANS
401(K) AND PENSION PLANS. Through June 30, 1994, the employees of the
Company were eligible for pensions under a defined benefit plan sponsored by
S.A. Louis Dreyfus et Cie. Benefits under the plan were based on years of
service and compensation levels. The Company's net periodic pension costs,
which were an allocation of S.A. Louis Dreyfus et Cie's net pension costs of
the plan attributable to the employees of the Company, totaled $405,000 for
the year ended December 31, 1994, including termination costs. At June 30,
1994, the Company's participation in S.A. Louis Dreyfus et Cie's pension plan
was discontinued.
S.A. Louis Dreyfus et Cie also sponsored a plan to provide retirement
benefits under Section 401(k) of the Internal Revenue Code for all employees,
including those of the Company, who have completed a specified term of
service. Employee contributions, up to 6% of compensation, were matched 50%
by the Company. The Company's contributions vested over a five-year period
and totaled $276,000 for the year ended December 31, 1994. The Company's
participation in this plan was terminated on December 31, 1994.
In December 1994, the Board of Directors adopted the Louis Dreyfus
Natural Gas Profit Sharing and 401(k) Plan and Trust Agreement (the "401(k)
Plan"). Effective January 1, 1995, the Company's employees who have completed
a specified term of service are eligible for participation in the 401(k)
Plan. Employee contributions can be made up to 6% of compensation. Employer
contributions are discretionary. Employees vest in Company contributions at
20% per year of service. For the years ended December 31, 1995 and 1996, the
Company contributed $788,000 and $878,000, respectively, to the 401(k) Plan.
STOCK COMPENSATION PLANS. Certain 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, 1994,
1995 and 1996, SERs totaling 85,000 stock equivalent units were outstanding.
Recorded compensation expense attributable the SERs was $523,000, $441,000
and $383,000 for the years ended December 31, 1994, 1995 and 1996,
respectively. The SERs become fully vested on December 31, 1997.
In October 1993, the Board of Directors approved, and the Company's sole
stockholder adopted, the Company's 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 1,000,000
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. All officers and directors of the
Company, and other key employees who hold positions of significant
responsibility, are eligible to receive awards under the Option
F-15
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Plan. Options granted become exercisable at the rate of 25% per year
commencing one year after the date of grant, with the exception of those
granted to non-employee directors which vest and become fully exercisable on
the date of grant. 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 Company accounts for the issuance of stock options in accordance
with Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued
to Employees" ("APB 25"). Under APB 25, no compensation expense is
recognized in the financial statements for options granted with an exercise
price equal to the market price of the underlying stock on the date of grant.
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 and 1996 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 and 1996: risk-free
interest rates of 6.0% and 6.6%, respectively; no dividends over the option
term; stock price volatility factors of .32 and .31, respectively, and a
weighted average expected option life of five years for both 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 due to the future impact of nonvested awards granted in
1995 and 1996. Additionally, option awards made prior to 1995 have been
excluded.
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.
The SFAS 123 pro forma information is as follows:
YEARS ENDED DECEMBER 31,
------------------------
1995 1996
---- ----
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
Net income..................... $10,847 $20,698
Net income per share........... .39 .74
F-16
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Stock option transactions for 1994, 1995 and 1996 are summarized as
follows:
YEARS ENDED DECEMBER 31,
----------------------------------------------------------
1994 1995 1996
------------------ ------------------- ------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
------- --------- ------- --------- ------- ---------
Outstanding at beginning of
year...................... 500,000 $18.00 515,000 $18.06 792,000 $16.42
Granted..................... 15,000 19.88 294,000 13.64 212,000 14.39
Exercised................... -- -- -- -- (750) 13.69
Canceled.................... -- -- (17,000) 18.00 (10,000) 16.71
------- ------ ------- ------ ------- ------
Outstanding at end of year.. 515,000 18.06 792,000 16.42 993,250 15.98
------- ------ ------- ------ ------- ------
------- ------ ------- ------ ------- ------
Exercisable at end of year.. 125,000 18.00 275,250 17.60 469,000 17.08
------- ------ ------- ------ ------- ------
------- ------ ------- ------ ------- ------
Weighted-average fair value
of options granted during
year...................... $ 8.41 $ 5.27 $ 5.71
------- ------- -------
------- ------- -------
Outstanding options to acquire 491,000 shares of stock at December 31,
1996 had exercise prices ranging from $18.00 to $19.88 per share and had a
weighted-average remaining contractual life of 6.9 years. The balance of
options outstanding at December 31, 1996 had exercise prices ranging from
$12.63 to $14.44 per share and a weighted-average remaining contractual life
of 9.1 years.
NOTE 9 -- SIGNIFICANT CUSTOMERS
The Company's oil and gas sales at the wellhead are sold under contracts
with various purchasers. For the year ended December 31, 1994, gas sales to
Lone Star Gas Company and GPM Gas Corporation approximated 28% and 10% of
total revenues, respectively. Sales to Lone Star Gas Company in 1995
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. 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 1996.
F-17
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 10 -- 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, 1995 and 1996, and the methods and assumptions
used to estimate the fair value of such financial instruments:
DECEMBER 31, 1995 DECEMBER 31, 1996
----------------------- -----------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
--------- ---------- --------- ----------
(IN THOUSANDS)
Fixed-price natural gas energy swaps:
Sales contracts..................... $ (760) $ 29,500 $ -- $ 19,000
Purchase contracts.................. -- (4,000) -- 1,000
Fixed-price natural gas collars.......... n/a n/a -- 1,000
Fixed-price natural gas physical
delivery contracts (1)................. 2,186 209,000 1,940 168,000
Natural gas basis swaps.................. n/a n/a -- 1,000
Fixed-price crude oil energy swaps....... -- 1,000 -- --
Bank debt (2)............................ (216,000) (216,000) (245,000) (245,000)
Subordinated debt (2).................... (98,760) (108,695) (98,907) (106,000)
Interest rate swaps - fixed.............. 152 (3,319) -- (1,000)
Interest rate swaps - floating........... n/a n/a -- 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 11 -- Fixed-Price Contracts.
(2) - Carrying amounts do not include capitalized debt issuance
costs. See Note 1 -- Significant Accounting Policies.
Cash and cash equivalents, accounts receivable, short-term investments,
deposits, accounts payable, revenues payable and accrued restoration
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, 1995 and 1996, was estimated based on market prices of natural gas and
crude oil for the periods covered by the contracts. The net differential
between the fixed (or floating) 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%. 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 11
- -- Fixed-Price Contracts and Note 13--Subsequent Events. 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
the value associated with such contracts is expected to be offset by an
opposite change in the value of the Company's reserves.
The fair value of bank debt at December 31, 1995 and 1996 was
estimated to approximate the carrying amount. The fair value of subordinated
debt as of such dates is determined by applying an estimated credit spread to
quoted yields for treasury notes with comparable maturities to such debt.
The fair value of the Company's interest rate swaps for each of the years
presented is based on quoted market prices as of such dates.
F-18
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 11 -- 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, basis swaps and option
agreements. 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. In 1994, Fixed-Price Contracts hedged
98% of the Company's gas production not otherwise subject to fixed prices and
91% of its oil production. In 1995, Fixed-Price Contracts hedged 84% of the
Company's gas production and 86% of its oil production. For the year ended
December 31, 1996, Fixed-Price Contracts hedged 51% of the Company's gas
production and 67% of its oil production. As of December 31, 1996,
Fixed-Price Contracts are in place to hedge 349 Bcf of the Company's
estimated future production from proved gas reserves and 362 MBbls of its
estimated 1997 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.
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,
1996.
F-19
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDING DECEMBER 31, BALANCE
------------------------------------------------------------- THROUGH
1997 1998 1999 2000 2001 2017 TOTAL
--------- --------- --------- --------- --------- --------- ----------
NATURAL GAS SWAPS,
OPTIONS AND FUTURES
SALES CONTRACTS
Contract volumes (BBtu)......... 6,068 13,825 15,825 9,830 7,475 29,832 82,855
Weighted-average fixed price
per MMBtu (1).............. $ 2.27 $ 2.33 $ 2.44 $ 2.46 $ 2.47 $ 3.08 $ 2.65
Future fixed-price sales (M$)... $ 13,802 $ 32,243 $ 38,629 $ 24,164 $ 18,446 $ 92,005 $ 219,289
Future net revenues (M$) (2).... $ 362 $ 2,381 $ 3,973 $ 2,489 $ 1,852 $ 22,866 $ 33,923
PURCHASE CONTRACTS
Contract volumes (BBtu)......... (2,425) (9,125) (10,950) -- -- -- (22,500)
Weighted-average fixed price
per MMBtu (1).............. $ 2.05 $ 2.09 $ 2.18 $ -- $ -- $ -- $ 2.13
Future fixed-price
purchases (M$)............. $ (4,973) $ (19,108) $ (23,880) $ -- $ -- $ -- $ (47,961)
Future net revenues (M$) (2).... $ 399 $ 602 $ 100 $ -- $ -- $ -- $ 1,101
NATURAL GAS PHYSICAL
DELIVERY CONTRACTS
Contract volumes (BBtu)......... 33,111 36,060 28,204 26,749 27,300 134,096 285,520
Weighted-average fixed price
per MMBtu (1).............. $ 2.49 $ 2.64 $ 2.84 $ 3.04 $ 3.19 $ 4.11 $ 3.42
Future fixed-price sales (M$)... $ 82,442 $ 95,130 $ 80,125 $ 81,403 $ 86,963 $ 551,455 $ 977,518
Future net revenues (M$)(2)..... $ 8,902 $ 17,782 $ 18,748 $ 22,486 $ 26,568 $ 210,070 $ 304,556
TOTAL NATURAL GAS
CONTRACTS (3) (4)
Contract volumes (BBtu)......... 36,754 40,760 33,079 36,579 34,775 163,928 345,875
Weighted-average fixed price
per MMBtu (1).............. $ 2.48 $ 2.66 $ 2.87 $ 2.89 $ 3.03 $ 3.93 $ 3.32
Future fixed-price sales (M$)... $ 91,271 $ 108,265 $ 94,874 $105,567 $ 105,409 $ 643,460 $1,148,846
Future net revenues (M$) (2).... $ 9,663 $ 20,765 $ 22,821 $ 24,975 $ 28,420 $ 232,936 $ 339,580
CRUDE OIL SWAPS AND
FUTURES
Contract volumes (MBbls)........ 362 -- -- -- -- -- 362
Weighted-average fixed price
per Bbl (1)................ $ 22.32 $ -- $ -- $ -- $ -- $ -- $ 22.32
Future fixed-price sales (M$)... $ 8,080 $ -- $ -- $ -- $ -- $ -- $ 8,080
Future net revenues (M$) (2).... $ (172) $ -- $ -- $ -- $ -- $ -- $ (172)
- -------------------------
(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, 1996, 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:
1997 - 21.0 TBtu; 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 3.0 TBtu of natural gas hedged by fixed-price collars for
January through September 1997 with a weighted-average floor price of
$2.30 per MMBtu and a weighted-average ceiling price of $2.84 per MMBtu.
The estimates of the future net revenues and present value of the
Company's Fixed-Price Contracts contained herein 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.
F-20
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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. 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. Also see Note 1 -- Significant Accounting
Policies -- Hedging.
In June 1996, the Company and an unaffiliated counterparty to one of its
fixed-price contracts amended the terms of a fixed-priced natural gas contract
to monetize the premium in the fixed prices provided by the contract. Pursuant
to the amendment, the Company received a non-refundable payment in the amount of
$25.0 million. As consideration for this payment, the weighted-average fixed
price over the remaining 17 years of the contract was reduced from an average of
$3.20 per MMBtu to an average of $2.37 per MMBtu, approximating the forward
market prices for natural gas at the time. The payment has been reflected in
the Company's balance sheet as a deferred hedging gain and is being amortized
into earnings over the life of the original 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 loss of a contract would subject
a greater portion of the Company's oil and gas production to market prices and
could adversely affect the carrying value of the Company's oil and gas
properties and the amount of borrowing capacity available under the Credit
Facility. The Company has not experienced non-performance by any counterparty.
Two Fixed-Price Contracts which hedge an aggregate 106 Bcf of natural
gas as of December 31, 1996 are with independent power producers ("IPPs")
which sell electrical power under firm fixed-price contracts to Niagara
Mohawk Corporation ("NIMO"), a New York state utility. As of December 31,
1996, 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 $135 million, or 71% 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, 1994, 1995 and 1996, these
contracts contributed $5.1 million, $9.6 million and $.9 million,
respectively, to natural gas sales. The ability of these IPPs to perform
their obligations to the Company is largely 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. As of December 31, 1996, NIMO had not been successful in
these actions. On August 1, 1996, NIMO announced an offer to terminate 44
independent power contracts, including those to the Company's counterparties,
in exchange for a combination of cash and debt securities from a newly
restructured NIMO. As of December 31, 1996, the terms of the offer had not
been made public. See Note 13 -- Subsequent Events.
F-21
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
MARKET RISK. The Company's Fixed-Price Contracts at December 31, 1996
hedge 349 Bcf of proved natural gas reserves, substantially all of which are
proved developed reserves, and 362 MBbls of oil, at fixed prices. These
contract quantities represent 41% and 2% of the Company's estimated proved
natural gas and crude oil reserves, respectively, as of December 31, 1996.
If the Company's proved reserves are produced at rates less than anticipated,
the volumes specified under the Fixed-Price Contracts may exceed production
volumes. In such case, the Company would be required to satisfy its
contractual commitments at market prices in effect for each settlement
period, which may be above the contract price, without a corresponding offset
in wellhead revenue for any excess volumes. 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, 1994, 1995 and 1996, the Company received on an Mcf
basis approximately 11%, 3% and 3% less than the prices specified in its
natural gas Fixed-Price Contracts, respectively, due to basis. Such results
do not include a $4.3 million basis loss recognized in the fourth quarter of
1995, discussed below. For its oil production hedged by crude oil
Fixed-Price Contracts, the Company realized approximately 8%, 7% 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 1997 represents a
$913,000 change in gas sales. A 1% change in price realization for hedged
oil production in 1997 represents an $81,000 change in oil sales. The
Company actively manages its exposure to basis movements and from time to
time will enter into contracts designed to reduce such exposure.
In the first quarter of 1996, the Company experienced a significant
widening of basis for certain of its Fixed-Price Contracts. These particular
contracts have floating indices tied to the NYMEX natural gas contract or
involve the purchase of gas in the spot market priced at or near the Henry Hub
delivery point in Louisiana. Due to a significant increase in demand for
natural gas in the Northeastern region of the United States, NYMEX prices for
natural gas rose disproportionately in relation to the regional market prices
received for the Company's natural gas. This temporary loss of correlation
resulted in a $4.3 million charge in the fourth quarter of 1995 (when the
anomaly was identified) to reflect the estimated basis loss incurred. To reduce
exposure to Henry Hub basis volatility, the Company canceled a 20-Bcf contract
with S.A. Louis Dreyfus et Cie in January 1996, receiving $1.6 million in
proceeds. These proceeds are being amortized into oil and gas sales over the
original 19-month contract term which commenced January 1996. The Company has
also entered into several basis swaps with unaffiliated parties which are
designed to substantially reduce exposure to basis volatility over the next six
years.
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, 1994,
1995 and 1996, the maximum aggregate amount of margin posted by the Company
was $41.0 million, $23.4 million and $25.9 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, 1996,
the Company had issued margin in the form of letters of credit and treasury
bills totaling $20.3 million and $5.6 million, respectively. In addition,
approximately 30 Bcf of the Company's proved gas reserves are mortgaged to a
Fixed-Price Contract counterparty, securing the Company's performance under
the associated contract.
F-22
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 12 -- 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, 1994, 1995 and 1996. Reserve estimates for these
years have been prepared by the Company's petroleum engineers and reviewed by
an independent engineering firm. All studies have been prepared in
accordance with regulations prescribed by the Securities and Exchange
Commission. Future net revenue is estimated by such engineers using oil and
gas prices in effect as of the end of each respective year with price
escalations permitted only for those properties which have wellhead contracts
allowing specific increases. Future operating costs estimated in each study
are based on historical operating costs incurred. Reserve quantity estimates
are calculated without regard to prices in the Company's Fixed-Price Contracts.
The reliability of any reserve estimate is a function of the quality of
available information and of engineering interpretation and judgment. Such
estimates are susceptible to revision in light of subsequent drilling and
production history or as a result of changes in economic conditions.
ESTIMATED QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED). The following
table sets forth the Company's estimated proved reserves, all of which are
located in the United States, for the years ended December 31, 1994, 1995 and
1996:
1994 1995 1996
----------------------- ----------------------- -----------------------
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
------- -------- ------- -------- ------- --------
PROVED RESERVES
Beginning of year................ 20,867 502,018 19,317 574,025 20,360 753,919
Acquisition of proved reserves... 1,569 46,649 1,439 181,867 2,173 62,497
Extensions and discoveries....... 210 54,439 949 66,382 2,643 76,873
Revisions of previous estimates.. (1,344) 15,219 1,544 (7,738) 335 19,939
Sales of reserves in place....... (112) (1,218) (1,194) (9,353) (165) (119)
Production....................... (1,873) (43,082) (1,695) (51,264) (1,849) (63,910)
------ ------- ------ ------- ------ -------
End of year (1).................. 19,317 574,025 20,360 753,919 23,497 849,199
------ ------- ------ ------- ------ -------
------ ------- ------ ------- ------ -------
PROVED DEVELOPED RESERVES
Beginning of year................ 14,839 378,000 13,089 433,306 14,839 630,604
------ ------- ------ ------- ------ -------
------ ------- ------ ------- ------ -------
End of year (1).................. 13,089 433,306 14,839 630,604 17,894 709,712
------ ------- ------ ------- ------ -------
------ ------- ------ ------- ------ -------
(1) - Totals for 1996 includes 5.5 MMBbls of proved oil reserves and 1.5 Bcf of
proved natural gas reserves attributable to the Company's Levelland
properties which were sold in January 1997. See Note 13 -- Subsequent
Events.
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, 1994, 1995 and 1996, as adjusted for the effects of
the Company's existing Fixed- Price Contracts, as follows: 1994
- $16.08 per Bbl, $2.61 per Mcf; 1995 - $17.80 per Bbl, $2.60 per
Mcf; and 1996 - $24.66 per Bbl, $3.55 per Mcf.
(3) - The resulting future gross revenue streams were reduced by
estimated future costs to develop and to produce the proved
reserves, based on year-end estimates.
F-23
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) - Future income taxes were computed by applying the appropriate
statutory tax rates to the future pretax net cash flows less the
current tax basis of the properties involved and related
carryforwards, giving effect to permanent differences and tax
credits.
(5) - The resulting future net revenue streams were reduced to present
value amounts by applying a 10% discount factor.
DECEMBER 31,
------------------------------------------
1994 1995 1996
----------- ----------- ------------
(IN THOUSANDS)
Future cash inflows.............. $ 1,806,890 $ 2,325,573 $ 3,596,493
Future production costs.......... (467,704) (686,476) (1,053,989)
Future development costs......... (119,426) (107,596) (125,074)
Discount at 10% per year......... (603,755) (793,989) (1,299,696)
----------- ----------- ------------
Net present value of future
net revenues................ 616,005 737,512 1,117,734
Discounted future income taxes... (139,184) (174,215) (314,290)
----------- ---------- -----------
Standardized measure of
discounted future net cash
flows (1) (2)................... $ 476,821 $ 563,297 $ 803,444
----------- ---------- -----------
----------- ---------- -----------
- -------------
(1) - The standardized measure of discounted future net cash flows excluding the
effect of the Company's Fixed-Price Contracts was $316.8 million, $431.0
million and $922.6 million as of December 31, 1994, 1995 and 1996,
respectively.
(2) - The standardized measure of discounted future net cash flows as of
December 31, 1996 includes $25.8 million attributable to the Company's
Levelland properties which were sold in January 1997. See Note 13 --
Subsequent Events.
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. These studies calculate the
discounted present value of future net revenues from the Company's proved oil
and gas reserves, determined without regard for the Company's Fixed-Price
Contracts or consideration for future income tax consequences, at $359
million, $524 million and $1.304 billion as of December 31, 1994, 1995 and
1996, respectively. The standardized measure calculation, prepared pursuant
to the provisions of Statement of Financial Accounting Standards No. 69, does
not purport to represent the fair market value of the Company's oil and gas
reserves. The foregoing information is presented for comparative purposes as
of the Company's year-end and is not intended to reflect any changes in value
which may result from future price fluctuations.
Increases in the standardized measure and the net present value of
future net revenues, including the effects of Fixed-Price Contracts, for 1996
were due, in part, to a significant increase in December 1996 natural gas and
crude oil prices. Holding the reserve quantities set forth in the December
31, 1996 reserve study constant, the impact of using average 1996 natural gas
and oil prices of $2.63 per Mcf and $21.18 per Bbl would have been to lower
the standardized measure and present value calculations to $632 million and
$834 million, respectively.
F-24
LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (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, 1994, 1995 and 1996, were as
follows:
YEARS ENDED DECEMBER 31,
-------------------------------------------
1994 1995 1996
---- ---- ----
(IN THOUSANDS)
Balance, beginning of year................................. $ 457,579 $ 476,821 $ 563,297
Acquisitions of proved reserves............................ 32,105 116,229 116,263
Extensions and discoveries, net of future development
costs.................................................... 28,731 52,823 147,817
Revisions of previous quantity estimates................... 7,493 1,623 26,431
Oil and gas sales, net of production costs................. (104,871) (128,014) (140,943)
Sales of reserves in place................................. (1,935) (7,953) (614)
Net changes in sales prices and production costs........... 13,303 48,242 140,205
Development costs incurred and changes in estimated
future development costs................................. 3,188 30,279 13,099
Net change in income taxes................................. (7,776) (35,031) (140,076)
Accretion of discount...................................... 58,899 61,600 73,751
Changes in timing of production and other (1).............. (9,895) (53,322) 4,214
---------- ---------- ----------
Balance, end of year....................................... $ 476,821 $ 563,297 $ 803,444
---------- ---------- ----------
---------- ---------- ----------
- -------------
(1) - The decrease in this caption for 1995 reflects the impact of a higher
average discount rate resulting from a change in the timing of future
cash flows.
NOTE 13 -- SUBSEQUENT EVENTS
PROPERTY SALE. In January 1997, the Company completed the sale of its
West Texas Levelland properties to an unrelated third party. The Company
received total sales proceeds of $27.1 million, subject to closing costs and
adjustments. The sale will result in an estimated pre-tax gain, after sales
commission, of $8.5 million, to be recorded in the first quarter of 1997. At
December 31, 1996, the Levelland properties had 5.5 MMBbls of proved oil
reserves and 1.5 Bcf of proved natural gas reserves, net to the Company's
interest. The proceeds were applied to outstanding indebtedness under the
Credit Facility.
NIMO. On March 10, 1997, NIMO announced that an agreement in principle
had been reached with 19 IPPs, including those who are counterparties to the
Company's contracts, to restructure or terminate numerous power purchase
contracts. This agreement in principle is subject to negotiation of final
agreements, regulatory and shareholder approvals and other conditions, and
the specific terms of the proposed agreements with the Company's
counterparties have not been disclosed to the Company. The Company is unable
to determine the effect of these proposed agreements on the Company. However,
to the extent NIMO is successful in reducing its obligations to purchase power
from the Company's counterparties, the ability of such counterparties to
continue to purchase natural gas from the Company under existing Fixed-Price
Contracts may be adversely affected, which may in turn have an adverse effect
on the Company. See Note 11 -- Fixed Price Contracts.
F-25
NOTE 14 -- QUARTERLY RESULTS (UNAUDITED)
1995 1996
-------------------------------------------- ----------------------------------------------
FIRST SECOND THIRD FOURTH FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
------- ------- ------- ------- ------- ------ ------- -------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Revenues (1).................. $39,410 $38,173 $43,554 $41,811 $39,850 $45,816 $48,988 $54,851
Operating profit (loss) (2)... 17,526 17,594 18,596 (50) 14,570 17,376 20,395 22,392
Net income (loss) (2)......... 5,804 5,732 5,591 (6,110) 2,252 4,534 6,510 7,806
Net income (loss) per share... .21 .21 .20 (.22) .08 .16 .23 .28
- -------------
(1) - Increases in revenues are largely attributable to development activities
during 1995 and 1996 and the acquisition of proved reserves in the third
quarter of 1995 and the second quarter of 1996. See Note 3 -- Property
Acquisitions.
(2) - The operating loss and the net loss in the fourth quarter of 1995 were
primarily due to a $15.7 million impairment charge recorded in connection
with the adoption of SFAS 121 and the recognition of a $4.3 million basis
loss. See Note 1 -- Significant Accounting Policies and Note 11 --
Fixed-Price Contracts.
F-26
LOUIS DREYFUS NATURAL GAS CORP.
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
BALANCE AT ADDITIONS BALANCE AT
BEGINNING OF CHARGED TO END OF
PERIOD EXPENSE OTHER PERIOD
------------ ---------- ----- ----------
DESCRIPTION:
December 31, 1996 (1)
Allowance for doubtful accounts -
Joint interest and other receivables.... $1,086 $ 25 $(25) $1,086
------ ---- ---- ------
------ ---- ---- ------
December 31, 1995 (1)
Allowance for doubtful accounts -
Joint interest and other receivables.... $1,022 $100 $(36) $1,086
------ ---- ---- ------
------ ---- ---- ------
December 31, 1994 (1)
Allowance for doubtful accounts -
Joint interest and other receivables.... $ 760 $262 $ -- $1,022
------ ---- ---- ------
------ ---- ---- ------
- -------------------
(1) - Increases during 1994, 1995 and 1996 relate to provisions for doubtful
accounts charged to general and administrative expense.
F-27
INDEX TO EXHIBITS
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
- ------- ----------------------
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).
10.1 Stock Option Plan of Louis Dreyfus Natural Gas Corp. as amended and
restated effective February 1997 (previously filed).
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 Loan Agreement dated as of October 6, 1994, among Louis Dreyfus
Natural Gas Corp., as Borrower, Banque Paribas (New York Branch), as
Administrative Agent, Banque Paribas (New York Branch), Bank of
Montreal and Citibank, N.A., as Co-Agents (Incorporated by reference
to Exhibit 10.1 of the Registrant's Form 10-Q for the quarter ended
September 30, 1994).
10.7 Amendment to Loan Agreement dated as of July 31, 1996 (Incorporated
by reference to Exhibit 10.1 of the Registrant's Form 10-Q for the
quarter ended June 30, 1996).
10.8 Gas Purchase Contract, as amended, dated December 21, 1972 between
Lone Star Gas Company and the Registrant (successor by assignment)
(Incorporated by reference to Exhibit 10.15 of the Registrant's
Registration Statement on Form S-l, Registration No. 33-69102).
10.9 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).
10.10 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).
10.11 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).
10.12 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).
10.13 Notice of Execution for a natural gas swap transaction between Louis
Dreyfus Natural Gas Corp. and Duke/Louis Dreyfus L.L.C. dated April
1, 1996. (Incorporated by reference to Exhibit 10.1 of the
Registrant's Form 10-Q for the quarter ended March 31, 1996).
10.14 Amendment to Option Agreement of Simon B. Rich, Jr. (previously filed).
10.15 Form of Amendment to Outstanding Option Agreements of Employees
(previously filed).
10.16 Form of Amendment to Outstanding Option Agreements of Non-Employee
Directors (previously filed).
21.1 List of subsidiaries of the Registrant (previously filed).
23.1 Consent of Independent Auditors.
24.1 Powers of Attorney (previously filed).
27.1 Financial Data Schedule.