UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934. For the fiscal year ended December 31, 1999
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934.
Commission File Number 1-12480
Louis Dreyfus Natural Gas Corp.
(Exact name of Registrant as specified in its charter)
Oklahoma 73-1098614
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
14000 Quail Springs Parkway, Suite 600
Oklahoma City, Oklahoma 73134
(Address of principal executive office) (Zip code)
Registrant's telephone number, including area code:
(405) 749-1300
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
- ------------------------------------------ ------------------------
Common Stock, par value $.01 per share New York Stock Exchange
9-1/4% Senior Subordinated Notes due 2004 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent files pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [X]
The aggregate market value of the voting stock held by non-affiliates of the
Registrant at March 1, 2000, was approximately $430.5 million (based on a value
of $22.44 per share, the closing price of the Common Stock as quoted by the New
York Stock Exchange on such date). 40,253,130 shares of Common Stock, par value
$.01 per share, were outstanding on March 1, 2000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 1999 Annual
Meeting of Shareholders, to be filed pursuant to Regulation 14A under the
Securities Exchange Act of 1934, are incorporated by reference into Part III.
LOUIS DREYFUS NATURAL GAS CORP.
Form 10-K
Table of Contents
Page
-----
PART I
Item 1 -- BUSINESS .................................................................. 3
General ................................................................... 3
Business Strategy ......................................................... 3
Forward-Looking Statements ................................................ 4
Recent Developments ....................................................... 5
Acquisitions .............................................................. 5
Marketing ................................................................. 6
Competition ............................................................... 7
Regulation ................................................................ 7
Certain Operational Risks ................................................. 9
Employees ................................................................. 9
Relationship Between the Company and S.A. Louis Dreyfus et Cie ............ 9
Potential Conflicts of Interest ........................................... 10
Certain Definitions ....................................................... 10
Item 2 -- PROPERTIES ................................................................ 12
General ................................................................... 12
Core Areas ................................................................ 13
Reserves .................................................................. 16
Costs Incurred and Drilling Results ....................................... 17
Acreage ................................................................... 18
Productive Well Summary ................................................... 18
Title to Properties ....................................................... 18
Item 3 -- LEGAL PROCEEDINGS ......................................................... 18
Item 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ....................... 19
PART II
Item 5 -- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS .................................................................. 19
Item 6 -- SELECTED FINANCIAL DATA ................................................... 19
Item 7 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS .................................................... 21
Overview .................................................................. 21
Results of Operations - Fiscal Year 1999 Compared to Fiscal Year 1998 ..... 23
Results of Operations - Fiscal Year 1998 Compared to Fiscal Year 1997 ..... 25
Capital Resources and Liquidity ........................................... 26
Commitments and Capital Expenditures ...................................... 28
Outlook for Fiscal Year 2000 .............................................. 28
Year 2000 Compliance ...................................................... 30
Item 7A -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ................ 30
General ................................................................... 30
Fixed-Price Contracts ..................................................... 30
Interest Rate Sensitivity ................................................. 34
Item 8 -- FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ............................... 35
Item 9 -- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE ................................................. 35
LOUIS DREYFUS NATURAL GAS CORP.
Form 10-K
Table of Contents (continued)
Page
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PART III
Item 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ........................ 36
Item 11 -- EXECUTIVE COMPENSATION .................................................... 36
Item 12 -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ............ 36
Item 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ............................ 36
PART IV
Item 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K............ 36
2
LOUIS DREYFUS NATURAL GAS CORP.
PART I
Item 1. Business
General
Louis Dreyfus Natural Gas Corp. (the "Company" or "Registrant") is one of the
largest independent natural gas companies in the United States engaged in the
acquisition, development, exploration, production and marketing of natural gas
and crude oil. The Company's acquisition, development and exploration
activities are primarily conducted in three geographically concentrated core
areas: the Permian Region of West Texas, Southeast New Mexico and the San Juan
Basin; the Mid-Continent Region of Oklahoma, Kansas, the Panhandle of Texas,
East Texas, Southwest Arkansas and North Louisiana; and the Gulf Coast Region,
which includes South Texas and Offshore Gulf of Mexico, (collectively "Core
Areas"). Approximately 95% of the Company's proved reserve value at December
31, 1999 is located within these Core Areas. Proved reserves as of December 31,
1999 totaled 1.5 Tcfe and had a Present Value (as hereinafter defined) of $1.0
billion. The Company's operated properties contain more than 80% of its total
proved reserves. Natural gas reserves comprised 88% of the Company's year-end
proved reserve position and 83% of its reserves were proved developed. The
Reserve Life of its proved reserves, as hereinafter defined, was 11.6 years.
The Company was acquired in 1990 by S.A. Louis Dreyfus et Cie to engage in
oil and gas acquisition, development, production and marketing activities. At
the time of acquisition, the Company's proved reserves totaled 61 Bcfe. Since
that date, the Company has experienced significant growth in its production and
reserves through both development and exploration drilling and proved reserve
acquisitions. The Company has accumulated interests in 2.5 million gross acres
with 1,575 identified drilling locations. Of these locations, 496 had been
assigned proved undeveloped reserves at December 31, 1999. The Company
aggressively exploits the value in its properties through an active development
drilling program. This program has resulted in the drilling of 1,493 wells with
a completion success rate of 92% over the five-year period ended December 31,
1999. In recent years, exploratory drilling has been increasingly emphasized as
an integral component of its business strategy and, consequently, the Company
has incurred substantial up-front costs, including significant acreage, seismic
and other geological and geophysical costs. During 1999, the Company invested
$29 million in connection with exploration activities, $15 million of which was
directed to acreage and seismic acquisition. The Company's exploration program
has had a cumulative drilling success rate of 71% since its inception in 1995.
The Company has replaced 281% of its production since 1994 at an average
Finding Cost, as hereinafter defined, of $1.01 per Mcfe, including the purchase
accounting impact of its acquisition of American Exploration Company in 1997
("American Acquisition"). Finding Costs excluding the effects of the American
Acquisition, which Management believes are more representative of the Company's
historical ability to replace reserves, were $.82 per Mcfe over this same five
year period. The following table reflects the Company's growth since 1994:
Production, Proved Reserves, Earnings
Per Share and Cash Flow Growth
Years Ended December 31, Five-Year
----------------------------------------------------------- Growth
1999 1998 1997 1996 1995 Rate
- --------------------------------------------------------------------------------------------------------------------------
Production (Bcfe) 125.8 121.6 84.3 75.0 61.4 18.3%
Proved reserves (Bcfe) 1,464.3 1,340.2 1,203.4 990.2 876.1 16.2
EBITDAX (MM$) (1) $ 213.0 $ 183.8 $ 164.9 $ 128.6 $ 111.6 17.8
Net cash provided by operating activities (MM$) $ 181.6 $ 147.4 $ 129.8 $ 101.8 $ 89.5 17.5
Net income (loss) (MM$) (2) $ 21.4 $ (43.3) $ (16.1) $ 21.1 $ 11.0 14.8
==========================================================================================================================
(1) See "--Certain Definitions."
(2) Earnings for 1998 were adversely affected by a $52.5 million non-cash
impairment charge and a significant decline in oil and gas prices.
Earnings for 1997 were adversely affected by a $75.2 million non-cash
impairment charge, substantially all of which was recognized in connection
with the American Acquisition. See "Item 7--Management's Discussion and
Analysis of Financial Condition and Results of Operations."
The address of the Company's principal executive offices is 14000 Quail Springs
Parkway, Suite 600, Oklahoma City, Oklahoma 73134, and its telephone number is
(405) 749-1300.
Business Strategy
The Company's business strategy is to generate strong and consistent growth in
reserves, production, operating cash flows and earnings. This strategy is
implemented through the following:
3
Natural Gas Focus. The Company emphasizes growth in natural gas reserves and
believes that the long-term supply and demand fundamentals for natural gas
are favorable for future natural gas price increases. Natural gas continues
to gain recognition as an efficient, clean and environmentally-friendly fuel
source alternative. This is particularly true for electricity generation
facilities, which are increasingly turning to natural gas for their power
consumption needs. About 88% of the Company's reserve base is comprised of
natural gas, making it substantially more leveraged to natural gas than the
industry average. Because of this focus, Louis Dreyfus Natural Gas now has
one of the largest domestic natural gas reserve bases in the industry.
Expanded Exploration Program. Increased exploration activity in the Company's
Core Areas exposes the Company to higher production and reserve growth
potential. The Company has a staff of 32 geoscientists and reservoir
engineers who have extensive experience in the use of advanced technologies,
including 3-D seismic analysis, computer aided mapping and reservoir
simulation modeling. These technologies are combined with a considerable
knowledge base gained through the Company's operating and development
drilling activities in these Core Areas. The combination results in a
disciplined approach to exploration growth. During 1999, $29 million was
invested in connection with exploration activities, including drilling,
seismic data collection and unproved leasehold acquisitions. Since the
inception of the program in 1995, the Company has drilled 119 gross (74 net)
exploratory wells with a completion success rate of 71%. The Company has
allocated approximately $60 million, or 29%, of its 2000 drilling budget to
exploration activities.
Development Drilling. The Company aggressively exploits the value in its oil
and gas property base through its active development drilling program. The
development drilling program has been an important source of low-risk
production growth and is conducted in areas where multiple productive oil and
gas bearing formations are likely to be encountered, thereby reducing dry
hole risk. The Company has drilled 1,374 gross (882 net) development wells
with a completion success rate of 94% over the five-year period ended
December 31, 1999. For 2000, the Company plans to continue its aggressive
development drilling program by investing approximately $150 million, or 71%
of its 2000 drilling budget.
Strategic Acquisitions. The Company has invested $545 million to acquire 548
Bcfe of proved reserves over the five-year period ended December 31, 1999,
representing an average acquisition cost of $.99 per Mcfe. The Company
believes that this aggregate average acquisition cost, which includes the
premium paid for the American Acquisition in 1997, compares favorably to
industry averages for independent exploration and production companies over
this same period of time. These acquisitions have been geographically
concentrated in its Core Areas where the Company possesses considerable
operating expertise and realizes economies of scale. The Company principally
targets acquisitions which have significant development potential, are in
close proximity to existing properties, have a high degree of operatorship
and can be integrated with minimal incremental administrative cost.
Large, Geographically-Concentrated Property Base. The Company owns interests
in approximately 9,400 wells located primarily in its Core Areas. As a result
of this large, geographically-concentrated property base, the opportunity to
generate positive results through the application of improved production
technologies and to achieve economies of scale is enhanced while the risk of
material adverse financial consequences from unexpected production
interruptions is minimized. The Company has five district offices in its Core
Areas and employs approximately 140 pumpers and other field personnel to
provide onsite management of its properties.
Forward-Looking Statements
All statements in this document other than purely historical information are
"Forward-Looking Statements" within the meaning of the federal securities laws.
These statements reflect the current expectations of management and are based on
the Company's historical operating trends, its proved reserve and Fixed-Price
Contract positions (as hereinafter defined) as of December 31, 1999, and other
information currently available to management. Forward-Looking Statements
include statements regarding the Company's future drilling plans and objectives,
and related exploration and development budgets, and number and location of
planned wells, and statements regarding the quality of the Company's properties
and potential reserve and production levels. These statements may be preceded or
followed by, or otherwise include the words "believes", "expects",
"anticipates", "intends", "plans", "estimates", "projects", or similar
expressions or statements that certain events "will" or "may" occur. These
statements assume, among other things, that no significant changes will occur in
the operating environment for the Company's oil and gas properties and that
there will be no material acquisitions or divestitures except as disclosed
herein.
The Company cautions that the Forward-Looking Statements are subject to all the
risks and uncertainties incident to the acquisition, exploration, development
and marketing of oil and gas reserves. These risks include, but are not limited
to, commodity price, counterparty, environmental, drilling, reserves, operations
and production risks. Certain of these risks are described elsewhere herein. See
"Item 7--Management's Discussion and Analysis of Financial Condition and Results
of Operations--Outlook for Fiscal Year 2000." Moreover, the Company may make
material acquisitions or divestitures, modify its Fixed-Price Contract positions
by entering into new contracts or terminating existing contracts, or enter into
4
financing transactions. None of these can be predicted with certainty and are
not taken into consideration in the Forward-Looking Statements made herein.
Statements concerning Fixed-Price Contract, interest rate swap and other
financial instrument fair values and their estimated contribution to future
results of operations are based upon market information as of a specific date.
This market information is often a function of significant judgment and
estimation. Further, market prices for oil and gas and market interest rates are
subject to significant volatility.
For all of these reasons, actual results may vary materially from the
Forward-Looking Statements and there is no assurance that the assumptions used
are necessarily the most likely. The Company expressly disclaims any obligation
or undertaking to release publicly any updates regarding any changes in the
Company's expectations with regard to the subject matter of any Forward-Looking
Statements or any changes in events, conditions or circumstances on which any
Forward-Looking Statements are based.
Recent Developments
The following information discusses certain of the more significant
accomplishments of the Company during the year ended December 31, 1999.
1999 Drilling Program. The Company's drilling program for 1999 was very
successful. The Company drilled 229 wells, of which 210 wells were completed as
commercial producers for a drilling success rate of 92%. This well count
included 16 exploratory wells, 88% of which were completed as producers, and 213
development wells, 92% of which were completed as producers. Through this
program, the Company added 208 Bcfe of proved reserves to its reserve base at an
all-in finding and development cost (total costs incurred to explore and develop
oil and gas properties divided by proved reserves added through extensions and
discoveries and revisions of previous estimates) of $.67 per Mcfe. The drilling
program replaced 165% of production through capital expenditures totaling $143.5
million, or 79% of cash flows from operating activities. The year ended December
31, 1999 marked the sixth consecutive year that the Company replaced its
production through its drilling activities. See "Item 2--Properties--Costs
Incurred and Drilling Results."
Proved Reserves. As of December 31, 1999, the Company's proved reserves
had grown 9% in relation to 1998 and was comprised of 28 MMBbls of oil and 1.3
Tcf of natural gas, or 1.5 Tcfe. This reserve growth represents a production
replacement ratio of nearly 200%. The Company's estimated future net revenues
from proved reserves was $2.1 billion as of December 31, 1999. The present
value of such future net revenues discounted at 10% ("Present Value") was $1.0
billion. See "Item 2--Properties--Reserves" and Note 14 of the Notes to
Consolidated Financial Statements appearing elsewhere herein.
Financial Results. The Company reported net income of $21.4 million, or
$.53 per share, on total revenue of $302.6 million for 1999, the highest net
income reported as a publicly-held company. This compares to a net loss of
$43.3 million, or $1.08 per share, on total revenue of $293.4 million for 1998.
The Company reported record cash flows from operating activities (before
working capital changes) of $171.8 million for the year ended December 31,
1999, which compares to $144.9 million for 1998, an increase of 19%. Cash flows
provided by operating activities after consideration for the change in working
capital was $181.6 million, which compares to $147.4 million for 1998. The 1999
increase in revenues and operating cash flows was achieved primarily through
growth in gas production and higher oil prices for the year. See "Item
7--Management's Discussion and Analysis of Financial Condition and Results of
Operations--Results of Operations--Fiscal Year 1999 Compared to Fiscal Year
1998." Record EBITDAX of $213.0 million and record oil and gas production of
126 Bcfe were also achieved in 1999.
Cost Reduction. The Company was highly successful in reducing costs for
1999. Each expense caption in the 1999 Statement of Operations, appearing
elsewhere herein, reflected improvement in relation to 1998, not only on a per
unit of production basis, but also in absolute amount. Cash operating costs
(production, overhead and interest costs) fell to $1.04 per Mcfe in 1999,
marking the sixth consecutive year that per unit cash costs have declined.
Fixed-Price Contract Monetization. The Company received proceeds totaling
$44.2 million in December 1999 pursuant to the termination of a fixed-price
natural gas physical delivery contract with an independent power producer. The
proceeds were used to pay down bank debt. See "Item 7A--Quantitative and
Qualitative Disclosures About Market Risk--Fixed-Price Contracts--Credit Risk."
Acquisitions
The Company has completed a significant number of proved reserve acquisitions
during the past five years, including three ranging in size from $87 million to
$340 million. In 1999, the Company completed a nominal amount of acquisitions
due to high relative prices being asked by sellers of proved properties in
relation to market prices for oil and gas, and to the generally lower cost at
which reserves could be added through the Company's drilling program. The
market for proved reserve acquisitions is uncertain and the Company cannot
predict the amount of capital ultimately to be invested in acquisitions during
2000. Although a significant number of oil and gas properties are predicted to
be placed on the market, higher oil
5
and gas commodity prices are expected to raise sellers' price expectations. The
following table summarizes the Company's acquisition activity for the five
years ended December 31, 1999:
Summary Acquisition Information
Years Ended December 31,
---------------------------------------------------------------
1999 1998 1997 1996 1995 Total
- ------------------------------------------------------------------------------------------------------------------------
Estimated proved reserves acquired
(Bcfe) (1) 41 7 234 76 190 548
Acquisition cost (MM$) $36.9 $4.1 $349.0 $36.1 $118.7 $544.8
Acquisition cost per Mcfe (2) $ .90 $.56 $ 1.49 $ .48 $ .62 $ .99
=========================================================================================================================
(1) Based on the first year-end reserve report prepared following the
acquisition date as adjusted for production between the acquisition date
and year-end.
(2) Results for 1997 include the purchase accounting impact of the American
Acquisition.
Management is actively involved in the screening of potential acquisitions and
the development and implementation of strategies for specific acquisitions. The
Company's staff of reservoir engineers, geologists, production engineers,
landmen and accountants have substantial experience in evaluating and acquiring
oil and gas reserves. The Company primarily seeks acquisitions in its Core
Areas in which the Company's experience and existing operations will enable it
to readily integrate the acquired properties. Acquisitions are targeted which
have significant further development and exploration potential and a high
degree of operatorship. The Company prefers to operate its properties whenever
possible in order to provide more control over the operation and development of
the properties and the marketing of production. The Company also pursues
additional interests in its operated properties from holders of non-operating
interests to increase its percentage ownership at attractive acquisition
prices.
Marketing
Fixed-Price Contracts
Description. The Company has entered into long-term physical delivery
contracts, energy swaps, collars, futures contracts and basis swaps
(collectively "Fixed-Price Contracts") to reduce its exposure to decreases in
oil and gas prices which are subject to significant and often volatile
fluctuation. 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, 1999, these contracts
hedge 52 Bcfe of future oil and gas production in 2000, and 133 Bcfe
thereafter, representing 13% of estimated proved reserves. The fixed prices in
such contracts generally escalate over the contract term. Fixed-Price Contract
volume and price information by year for the next five years and thereafter is
shown at "Item 7A--Quantitative and Qualitative Disclosures About Market
Risk--Fixed-Price Contracts." The Company has historically hedged a significant
portion of its natural gas and crude oil production. In recent years, a
progressively smaller share of the Company's production and reserve additions
have been hedged due to Management's belief that longer-term demand and supply
fundamentals for natural gas imply the potential for prices in excess of those
currently available in the long-term forward market. More recent hedging
activity has been for shorter periods of time, generally less than 12 months,
when market conditions have been viewed as favorable. The Company may decide to
hedge a greater or smaller share of production in the future depending on
market conditions, capital investment considerations and other factors.
Delivery Contracts. The Company has entered into fixed-price natural gas
delivery contracts with independent power producers, natural gas pipeline
marketing affiliates, a municipality and other end users. Typically, these
contracts require the Company to deliver, and the purchaser to take, specified
quantities of natural gas at specified fixed prices, over the life of the
contracts. Delivery contracts hedge 112 Bcf of future gas production as of
December 31, 1999, representing 9% of estimated proved natural gas reserves.
The contract term varies with each contract, ranging from a period of less than
four years to approximately 18 years. The Company meets its fixed-price
delivery contract requirements through purchases of natural gas in markets
local to the delivery point at the most attractive prices available. The
contracts generally permit the Company to deliver natural gas at its choice of
several pipeline or customary industry delivery points, permitting some market
flexibility to the Company in purchasing required natural gas supplies and
making deliveries and reducing transportation risks. Each contract is
individually negotiated based on the purchaser's specified needs.
Energy Swaps. The Company enters into energy swaps as a fixed-price seller
in order to assure itself of fixed prices for the sale of its oil and gas
production. At December 31, 1999, the Company was a party to six energy swaps,
which collectively hedge 57 Bcf of future gas production. The contract term
varies with each contact, ranging from a period of one year to approximately
eight years. The variables in an energy swap transaction are a fixed price, an
index price, a specified quantity and a period. One of the parties is
designated as the fixed-price purchaser ("FPP") and whenever the fixed price
exceeds
6
the index price for a given date or period, the FPP pays the other party, the
fixed-price seller ("FPS"), the difference between the fixed price and the
index price. Whenever the index price is in excess of the fixed price, the FPS
pays the difference between the index price and the fixed price to the FPP. In
this way the parties may, without physical delivery of oil or gas, hedge
against uncertainties and risk created by fluctuations in oil and gas prices in
connection with such party's actual physical supply, purchase or sale
commitments or requirements.
Counterparties. The following table summarizes certain information
concerning the Company's natural gas Fixed-Price Contracts and associated
counterparties at December 31, 1999:
Natural Gas Fixed-Price Contract
Volumes by Counterparty
Volumes Committed (BBtu)
-------------------------------------------------- Percentage
of
Delivery Energy Total
Contracts Swaps Collars (1) Total Volume
- ---------------------------------------------------------------------------------------------------
Type of Counterparty:
Pipeline marketing affiliates 54,357 22,453 -- 76,810 43%
Independent power producers 40,591 -- -- 40,591 23
Financial institutions -- 6,420 9,630 16,050 9
Other 17,549 27,900 -- 45,449 25
- ---------------------------------------------------------------------------------------------------
Total 112,497 56,773 9,630 178,900 100%
===================================================================================================
(1) Volumes as shown for fixed-price collars are the volumes in effect when the
market price for natural gas is at or below the floor price provided by
the collar. If the market price for natural gas exceeds the ceiling price,
then volumes under the collars are double those presented. See "Item
7A--Quantitative and Qualitative Disclosures About Market Risk
--Fixed-Price Contracts."
For additional information concerning the Company's Fixed-Price Contracts, see
"Item 7A--Quantitative and Qualitative Disclosures About Market
Risk--Fixed-Price Contracts."
Wellhead Marketing
The majority of the Company's wellhead gas production is sold to a variety of
purchasers on the spot market or dedicated to contracts with market-sensitive
pricing provisions. Substantially all of the undedicated natural gas produced
from Company-operated wells is marketed by the Company. Additionally, the
majority of the oil and condensate produced from Company-operated properties is
sold on a market price sensitive basis. During 1999, the Company had gas sales
to two unrelated purchasers which approximated 17% and 14% of total revenues,
respectively. See Note 9 of the Notes to Consolidated Financial Statements
appearing elsewhere herein. The loss of any wellhead purchaser is not
anticipated to have a material adverse effect on the Company because there are
a substantial number of alternative purchasers in the markets in which the
Company sells its wellhead production.
Competition
The oil and gas industry is highly competitive. The Company competes with major
oil and gas companies, other independent oil and gas concerns, gas marketing
companies and individual producers and operators for proved reserve and
undeveloped acreage acquisitions, the development, production and marketing of
oil and gas, and for contracting equipment and securing personnel. Many of
these competitors have financial and other resources which 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, and limited pipeline
capacity and access. Such circumstances could result in curtailment of
activities, increased costs, delays or losses in production or revenues or
cause interests in oil and gas leases to lapse. The Company believes that its
acquisition, development, production and marketing capabilities, financial
resources and the experience of its management and staff enable it to compete
effectively.
Regulation
The oil and gas industry is extensively regulated by federal, state and local
authorities. Legislation affecting the oil and gas industry is under constant
review for amendment or expansion. Numerous departments and agencies at the
federal, state and local level have issued rules and regulations affecting the
oil and gas industry, some of which carry substantial penalties for the failure
to comply. The regulatory burden on the oil and gas industry increases its cost
of doing business and, consequently, affects its profitability. Inasmuch as
such laws and regulations are frequently amended or reinterpreted, the Company
is unable to predict the future cost or impact of complying with such
regulations. The Company believes that its operations and facilities comply in
all material respects with applicable laws and regulations as currently in
effect and that the existence and enforcement of such laws and regulations have
no more restrictive effect on the Company's operations than on other similar
companies in the oil and gas industry.
7
Drilling and Production
The Company's operations are subject to various types of regulation at federal,
state and local levels. Such regulation includes requiring permits for the
drilling of wells, maintaining bonding requirements in order to drill or
operate wells and regulating the location of wells, the method of drilling and
casing wells, the surface use and restoration of properties upon which wells
are drilled and the plugging and abandoning of wells. The Company's operations
are also subject to various conservation requirements. These include the
regulation of the size and shape of drilling and spacing units or proration
units and the density of wells which may be drilled and the unitization or
pooling of oil and gas properties. In this regard, some states allow forced
pooling or integration of tracts to facilitate exploration while other states
rely on voluntary pooling of lands and leases. In addition, state conservation
laws establish maximum rates of production from oil and gas wells, generally
prohibit the venting or flaring of natural gas and impose certain requirements
regarding the ratability of production. These regulations may limit the amount
of oil and gas the Company can produce from its wells or limit the number of
wells or the locations at which the Company can drill.
The Company has operated and non-operated working interests in various oil
and gas leases in the Gulf of Mexico which were granted by the federal
government and are administered by the Minerals Management Service (the "MMS"),
a federal agency. These leases were issued through competitive bidding, contain
relatively standardized terms and require compliance with detailed MMS
regulations and orders, which are subject to change by the MMS. For offshore
operations, lessees must obtain MMS approval for exploration, development and
production plans prior to the commencement of such operations. In addition to
permits required from other agencies, such as the Coast Guard, the Army Corps
of Engineers and the Environmental Protection Agency, lessees must obtain a
permit from the MMS prior to the commencement of drilling. The MMS has
promulgated regulations requiring offshore production facilities located on the
outer continental shelf to meet stringent engineering and construction
specifications, and has established other regulations governing the plugging
and abandoning of wells located offshore and the removal of all production
facilities. With respect to any Company operations conducted on offshore
federal leases, liability may generally be imposed under the Outer Continental
Shelf Lands Act for costs of clean-up and damages caused by pollution resulting
from such operations. Under certain circumstances, including but not limited
to, conditions deemed to be a threat or harm to the environment, the MMS may
also require any Company operations on federal leases to be suspended or
terminated in the affected area.
Environmental
The Company's operations are subject to numerous federal and state laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of hazardous substances that can be
released into the environment in connection with drilling and production
activities, limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas, and impose substantial
liabilities for pollution resulting from the Company's operations. State laws
often impose requirements to remediate or restore property used for oil and gas
exploration and production activities, such as pit closure and plugging
abandoned wells. Although the Company believes that its operations and
facilities are in compliance in all material respects with applicable
environmental and health and safety laws and regulations, risks of substantial
costs and liabilities are inherent in oil and gas operations, and there can be
no assurance that substantial costs and liabilities will not be incurred in the
future. Moreover, the recent trend toward stricter standards in environmental
legislation, regulation and enforcement is likely to continue.
The Company's operations may generate wastes that are subject to the
Federal Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes. The Environmental Protection Agency (the "EPA") has limited the
disposal options for certain hazardous wastes and may adopt more stringent
disposal standards for nonhazardous wastes. Furthermore, legislation has been
proposed in Congress from time to time that would reclassify certain oil and
gas exploration and production wastes as "hazardous wastes" under RCRA which
would regulate such reclassified wastes and require government permits for
transportation, storage and disposal. If such legislation were to be enacted,
it could have a significant impact on the operating costs of the Company, as
well as the oil and gas industry in general. State initiatives to further
regulate oil and gas wastes could have a similar impact on the Company.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "superfund" law, imposes liability, regardless of
fault or the legality of the original conduct, on certain classes of persons
that contributed to the release of a "hazardous substance" into the
environment. These persons include the current or previous owner and operator
of a site and companies that disposed, or arranged for the disposal, of the
hazardous substance found at a site. CERCLA also authorizes the EPA and, in
some cases, private parties to take actions in response to threats to the
public health or the environment and to seek recovery from such responsible
classes of persons of the costs of such action. In the course of operations,
the Company generates wastes that may fall within CERCLA's definition of
"hazardous substances." The Company may be responsible under CERCLA for all or
part of the costs to clean up sites at which such substances have been
disposed. The Company has not been named by the EPA or alleged by any third
party as being potentially responsible for costs and liabilities associated
with alleged releases of any "hazardous substance" at any superfund site.
8
The Company's operations are subject to the requirements of the Federal
Occupational Safety and Health Act ("OSHA") and comparable state statutes. The
OSHA hazard communication standard, the EPA community right-to- know
regulations under Title III of the Federal Superfund Amendment and
Reauthorization Act and similar state statutes require that information be
organized and maintained about hazardous materials used or produced in its
operations. Certain of this information must be provided to employees, state
and local government authorities and citizens.
The Oil Pollution Act ("OPA") requires the lessee or permittee of an
offshore area in which a covered offshore facility is located to establish and
maintain evidence of financial responsibility in the amount of $35 million,
which may be increased to $150 million in certain circumstances to cover
liabilities related to an oil spill for which such person is statutorily
responsible. OPA also subjects responsible parties to strict, joint and several
and potentially unlimited liability for removal costs and certain other damages
caused by an oil spill covered by the statute.
Natural Gas Sales Transportation
In the past, there were various federal laws which regulated the price at which
natural gas could be sold. Since 1978, various federal laws have been enacted
which have resulted in the termination on January 1, 1993 of all price and
non-price controls for natural gas sold in "first sales." As a result, on and
after January 1, 1993, none of the Company's natural gas production is subject
to federal price controls.
The transportation and sale for resale of natural gas is subject to
regulation by the Federal Energy Regulatory Commission ("FERC") under the
Natural Gas Act of 1938 ("NGA") and the Natural Gas Policy Act of 1978
("NGPA"). Commencing in 1985, the FERC promulgated a series of orders and
regulations adopting changes that significantly affect the transportation and
marketing of natural gas. These changes have been intended to foster
competition in the natural gas industry by, among other things, inducing or
mandating that interstate pipeline companies provide nondiscriminatory
transportation services to producers, distributors and other shippers
(so-called "open access" requirements). The effect of the foregoing regulations
has been to create a more open access market for natural gas purchases and
sales and has enabled the Company, as a producer, buyer and seller of natural
gas, to enter into various contractual natural gas sale, purchase and
transportation arrangements on unregulated, privately negotiated terms.
The Company owns a 75-mile intrastate pipeline and associated compression
facilities in the Sonora area of West Texas. More than 98% of the gas
transported in this pipeline system during 1999 was owned by the Company. The
operation of this system is subject to regulation by the Texas Railroad
Commission.
Certain Operational Risks
The Company's operations are subject to the risks and uncertainties associated
with drilling, producing and transporting 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
will depend on its ability to replace current reserves through drilling,
acquisitions, or both. The Company's ability to market its oil and gas
production depends upon the availability and capacity of oil and gas gathering
systems and pipelines, among other factors, many of which are beyond the
Company's control.
The Company's operations are subject to the risks inherent in the oil and
gas industry, including the risks of fire, explosions, blow-outs, pipe failure,
abnormally pressured formations and environmental accidents such as oil spills,
gas leaks, salt water spills and leaks, ruptures or discharges of toxic gases,
the occurrence of any of which could result in substantial losses to the
Company due to injury or loss of life, severe damage to or destruction of
property, natural resources and equipment, pollution or other environmental
damage, clean-up responsibilities, regulatory investigation and penalties and
suspension of operations. The Company's operations may be materially curtailed,
delayed or canceled as a result of numerous factors, including the presence of
unanticipated pressure or irregularities in formations, accidents, title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery of equipment. In accordance with customary
industry practice, the Company maintains insurance against some, but not all,
of the risks described above. There can be no assurance that the levels of
insurance maintained by the Company will be adequate to cover any losses or
liabilities. The Company cannot predict the continued availability of insurance
or its availability at commercially acceptable premium levels.
Employees
As of March 1, 2000, the Company had approximately 400 employees. Management
believes that its relations with its employees are satisfactory. The Company's
employees are not covered by a collective bargaining agreement.
Relationship Between the Company and S.A. Louis Dreyfus et Cie
The Company was acquired by S.A. Louis Dreyfus et Cie in 1990 to engage in oil
and gas acquisition, development, production and marketing activities. S.A.
Louis Dreyfus et Cie's other principal activities include the international
merchandising and exporting of various commodities, ownership and management of
ocean vessels, real estate and crude oil refining.
9
S.A. Louis Dreyfus et Cie beneficially owns approximately 52% of the
Company's Common Stock. Through its effective ability to elect all directors of
the Company, S.A. Louis Dreyfus et Cie has the ability to control its business
and affairs, including decisions with respect to the acquisition or disposition
of Company assets and the future issuance of Common Stock or other securities.
S.A. Louis Dreyfus et Cie also has the ability to control the Company's
drilling, operating and acquisition expenditure plans. There is no agreement
that would prevent S.A. Louis Dreyfus et Cie from acquiring additional shares
of Common Stock. Approximately one-half of the shares owned by S.A. Louis
Dreyfus et Cie are required to be pledged to a judgment creditor of one of its
subsidiaries pending the outcome of an appeal of the judgment. This appeal is
not expected to be completed until after mid-year 2000. The judgment is
unrelated to the Company. The sale of all or a portion of these shares after
the completion of the appeal could result in a change in control of the
Company.
The Company has an agreement ("Services Agreement") with S.A. Louis
Dreyfus et Cie pursuant to which S.A. Louis Dreyfus et Cie provides to the
Company various services (principally insurance-related services). Such
services historically have been supplied to the Company by S.A. Louis Dreyfus
et Cie, and the Services Agreement provides for the further delivery of such
services, but only to the extent requested by the Company. The Company
reimburses S.A. Louis Dreyfus et Cie for a portion of the salaries of employees
performing requested services based on the amount of time expended ("Hourly
Charges"), all direct third party costs incurred by S.A. Louis Dreyfus et Cie
in rendering requested services and overhead costs equal to 40% of the Hourly
Charges. The Services Agreement will continue until terminated by either party
upon 60 days prior written notice to the other party in accordance with the
terms of the Services Agreement. In the event of termination of the Services
Agreement by S.A. Louis Dreyfus et Cie, the Company has an option to continue
the agreement for up to 180 days to enable it to arrange for alternative
services. Substantially all such services in 1999 relate to participation in
certain insurance programs of S.A. Louis Dreyfus et Cie.
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
intercompany transactions and agreements incident to their respective
businesses. Such transactions and agreements have related to, among other
things, the purchase and sale of natural gas and the provision of certain
corporate services. It is the intention of S.A. Louis Dreyfus et Cie and the
Company that the Company operate independently, other than receiving services
as contemplated by the Services Agreement, but S.A. Louis Dreyfus et Cie and
the Company may enter into 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 oil and gas acquisition, development or
exploration activities 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.
10
Development Well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive in an
attempt to recover proved undeveloped reserves.
Drilling Unit. An area specified by governmental regulations or orders or
by voluntary agreement for the drilling of a well to a specified formation or
formations which may combine several smaller tracts or subdivides a large
tract, and within which there is usually some right to share in production or
expense by agreement or by operation of law.
Dry Hole. A well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
EBITDAX. EBITDAX is defined herein as income (loss) before interest,
income taxes, depreciation, depletion and amortization, impairment, exploration
costs and change in derivative fair value. The Company believes that EBITDAX is
a financial measure commonly used in the oil and gas industry as an indicator
of a company's ability to service and incur debt. However, EBITDAX should not
be considered in isolation or as a substitute for net income, cash flows
provided by operating activities or other data prepared in accordance with
generally accepted accounting principles, or as a measure of a company's
profitability or liquidity. EBITDAX measures as presented may not be comparable
to other similarly titled measures of other companies.
Estimated Future Net Revenues. Revenues from production of oil and gas,
net of all production-related taxes, lease operating expenses, capital costs
and abandonment costs.
Exploratory Well. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
Finding Cost. Total costs incurred to acquire, explore and develop oil and
gas properties divided by the increase in proved reserves through acquisition
of proved properties, extensions and discoveries, improved recoveries and
revisions of previous estimates.
Gross Acre. An acre in which a working interest is owned.
Gross Well. A well in which a working interest is owned.
Infill Drilling. Drilling for the development and production of proved
undeveloped reserves that lie within an area bounded by producing wells.
Lease Operating Expense. All direct costs associated with and necessary to
operate a producing property.
MBbls. Thousand barrels.
MBtu. Thousand Btus.
Mcf. Thousand cubic feet.
Mcfe. Thousand cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf of natural gas.
MMBbls. Million barrels.
MMBtu. Million Btus.
MMcf. Million cubic feet.
MMcfe. Million cubic feet of natural gas equivalent, determined using the
ratio of one Bbl of oil or condensate to six Mcf of natural gas.
Natural Gas Liquids. Liquid hydrocarbons which have been extracted from
natural gas (e.g., ethane, propane, butane and natural gasoline).
Net Acres or Net Wells. The sum of the fractional working interests owned
in gross acres or gross wells.
Overriding Royalty Interest. An interest in an oil and gas property
entitling the owner to a share of oil and gas production free of well or
production costs.
Present Value. When used with respect to oil and gas reserves, present
value means the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production, future development
costs, and future abandonment costs, using prices and costs in effect as of the
date of the report or estimate, without giving effect to non-property related
expenses such as general and administrative expenses, debt service and future
income tax expense or to depreciation, depletion and amortization, discounted
using an annual discount rate of 10%. The prices used to estimate future net
revenues do not consider the effects of the Company's Fixed-Price Contracts.
11
Productive Well. A well that is producing oil or gas or that is capable of
production.
Proved Developed Reserves. Proved reserves that are expected to be
recovered through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of oil and gas which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions.
Proved Undeveloped Reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion.
Recompletion. The completion for production of an existing wellbore in
another formation from that in which the well has previously been completed.
Reserve Life. A measure of how long it will take to produce a quantity of
reserves, calculated by dividing estimated proved reserves by production for
the twelve-month period prior to the date of determination (in gas
equivalents).
Reserve Replacement Ratio. A measure of proved reserve growth determined
by dividing the net change in reserve quantities between two dates, excluding
production, by the quantity produced between the two dates.
TBtu. One trillion Btus.
Tcfe. Trillion cubic feet of gas equivalent, determined using the ratio of
one Bbl of oil or condensate to six Mcf of natural gas.
Undeveloped Acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.
Working Interest. The operating interest which gives the owner the right
to drill, produce and conduct operating activities on the property and a share
of production.
Item 2. Properties
General
The Company's oil and gas acquisition, exploration and development activities
are conducted mainly in its Core Areas: the Permian Region of West Texas,
Southeast New Mexico and the San Juan Basin; the Mid-Continent Region of
Oklahoma, Kansas, the Panhandle of Texas, East Texas, Southwest Arkansas and
North Louisiana; and the Gulf Coast Region which includes South Texas and
Offshore Gulf of Mexico. Proved reserves as of December 31, 1999 consisted of
28 MMBbls of oil and 1.3 Tcf of natural gas, totaling 1.5 Tcfe. At this date,
the Company had ownership interests in approximately 9,400 producing wells. The
Company operates approximately 3,400 of these wells which contain 83% of its
total proved reserves. Net daily production during 1999 was 8.1 MBbls of oil
and 295.8 MMcf of natural gas, or 344.6 MMcfe. The Company drilled 213
developmental oil and gas wells, of which 196 wells, or 92%, were completed as
commercial producers, and 16 exploratory wells, of which 14 wells, or 88%, were
successfully completed, during 1999.
The Company has allocated $210 million for its 2000 drilling program,
subject to revision based upon oil and gas prices, proved reserve acquisitions
and other factors. Approximately $60 million of this total, or 29%, has been
allocated to exploration activities and $150 million, or 71%, has been
allocated to development activities. It is expected that this drilling
expenditure will result in the drilling of about 350 wells, including 25
exploratory wells and 325 development wells. See "Item 7--Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Outlook for Fiscal Year 2000."
12
Core Areas
The following table sets forth certain information regarding the Company's
activities in each of its principal producing areas as of December 31, 1999:
Core Areas
Mid- Gulf
Permian Continent Coast Other Total
- ------------------------------------------------------------------------------------------------------------------
Property Statistics:
Proved reserves (Bcfe) 706 461 252 45 1,464
Percent of total proved reserves 48% 32% 17% 3% 100%
Gross producing wells 4,295 3,446 663 992 9,396
Net producing wells 1,959 1,089 198 163 3,409
Gross acreage 731,491 918,567 340,083 531,955 2,522,096
Net acreage 367,559 414,438 180,859 133,997 1,096,853
Potential drill sites 850 400 75 250 1,575
1999 Results:
Gross wells drilled 148 44 26 11 229
Gross successful wells 142 33 24 11 210
Drilling success 96% 75% 92% 100% 92%
Production (Bcfe) 39.9 39.3 43.8 2.8 125.8
Average net daily production (MMcfe) 109.4 107.6 119.9 7.7 344.6
Lease operating expense per Mcfe $ .46 $ .43 $ .33 $ .51 $ .41
2000 Drilling Budget (MM$):
Development $ 59 $ 38 $ 53 $ -- $ 150
Exploration 3 6 51 -- 60
- ------------------------------------------------------------------------------------------------------------------
Total $ 62 $ 44 $ 104 $ -- $ 210
==================================================================================================================
Permian Region
The Company is actively involved in development and exploration activities in
several areas within the Permian Region. These areas include the Sonora Area
and the Delaware Basin of Southeast New Mexico, among others. The Company's
properties in the Permian Region contain 706 Bcfe of proved reserves, nearly
one-half of the Company's total reserve base, in 4,295 wells. The Company
drilled 148 wells in the Permian Region in 1999 and daily production averaged
109 MMcfe per day. The Company has identified 850 undrilled locations in this
region of which 310 have been assigned proved undeveloped reserves. Plans for
this region in 2000 include the drilling of approximately 258 wells and a total
investment of $62 million, including acreage and seismic acquisition.
Sonora Area
The Sonora area is located in the West Texas counties of Schleicher, Crockett,
Sutton and Edwards. It is comprised of five fields: Sawyer, Shurley Ranch, MMW,
Aldwell Ranch and Whitehead, which are located on the northeast side of the Val
Verde Basin of West Central Texas. The Company has an average 88% working
interest in 1,785 wells, most of which are Company operated. Daily production
from the Sonora area during 1999 averaged 85 MMcfe per day. 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 7,000 to 9,000 feet.
Canyon Formation. Natural gas in the Canyon formation is stratigraphically
trapped in lenticular sandstone reservoirs and the typical Sonora Area well
encounters numerous such reservoirs over the formation's gross thickness of
approximately 1,500 feet. The Canyon reservoirs tend to be discontinuous and to
exhibit low porosity and permeability, characteristics which reduce the area
that can be effectively drained by a single well. These characteristics have
encouraged operators in the area to undertake Canyon infill drilling programs.
Initial wells were drilled on 640 acre drilling units, but well performance
characteristics have indicated that denser well spacing is necessary for
effective drainage. The Company continues to drill infill wells in these units
and, in some areas, fields are now developed on 40 acre spacing.
Strawn Formation. The Strawn formation, a shallow-marine, fossiliferous
limestone, produces natural gas from fractures and irregularly distributed
porosity trends draped across anticlinal features. Original field development
took place on 640 acre units, with subsequent infill programs downsizing some
areas to 80 acre density. Testing of the Strawn formation in Sonora wells, for
which the primary drilling objective was the Canyon formation, has been an
attractive play for the Company because the Strawn lies less than 1,000 feet
below the Canyon formation. Because of the closeness in depth, the incremental
cost
13
to evaluate the Strawn formation has been relatively minor. The Strawn
production is generally commingled with the Canyon production stream.
The Company has maintained an aggressive development drilling program in
the Sonora Area since 1993, having drilled 707 Canyon and Strawn wells with
only 23 dry holes. The 1999 drilling program resulted in the drilling of 127
wells, 124 of which were completed as commercial producers. The Company plans
to drill approximately 150 wells in Sonora during 2000, the majority of which
are relatively low risk locations. The Company has identified over 575
potential locations on its acreage, of which 266 have been assigned proved
undeveloped reserves. Subject to further study and drilling results, the
Company believes additional proved reserves will ultimately be attributed to
many of the other locations. In addition to infill drilling potential, many of
the Company's producing wells in the Sonora Area have recompletion
possibilities in existing wellbores.
Southeast New Mexico
The Company is also active in southeastern New Mexico in the Delaware Basin,
where the primary objectives are the Morrow and Wolfcamp carbonate. The Morrow
sands are deposited in fluvial channels which trend from northwest to
southeast. The Wolfcamp carbonate in the Company's area of interest is
deposited in deep water alluvial fans along a major reef complex and is
primarily oil production. These reservoirs exhibit excellent porosity and
permeability at depths between 10,000 and 15,000 feet. These objectives also
lend themselves to the use of modern technology and computer aided mapping. It
is anticipated that approximately 10 wells will be drilled for these objectives
in 2000.
Mid-Continent Region
The Company was actively involved in the Mid-Continent Region when it was
acquired by S.A. Louis Dreyfus et Cie and has subsequently acquired substantial
additional acreage and proved reserves in the area through multiple synergistic
acquisitions. The Company operates approximately 1,260 wells in the
Mid-Continent Region. The Company's properties are located in and along the
northern shelf of the Anadarko Basin in western Oklahoma, in the deeper
Anadarko Basin in the Texas Panhandle, and in Kansas. This region also includes
properties in the Smackover Trend in Southern Arkansas and the Oak Hill field
in East Texas. Development of the Company's Mid-Continent Region properties
began in the late 1970's. Production is predominately natural gas from
productive formations of Pennsylvanian and Pre-Pennsylvanian age rock.
Productive depths range from 3,000 to 17,000 feet. Pre-Pennsylvanian reservoirs
include the Chester, Mississippi and Hunton formations, with greater production
from these formations occurring in highly fractured carbonate intervals.
Pennsylvanian reservoirs include the Granite Wash, Red Fork, Atoka, Morrow and
Springer sandstones. The stratigraphic nature of these reservoirs frequently
provides for multiple targets in the same wellbores. Spacing in these
formations is generally on 640 acres with extensive increased density drilling
having occurred over the last 15 years. Two primary areas of focus in the Mid-
Continent are the Watonga-Chickasha Trend in central Oklahoma and the Texas
Panhandle.
The Company has pursued an active low-risk infill drilling program in the
Mid-Continent area over the past five years, including the drilling of 44 wells
in 1999. Average net daily production was 108 MMcfe per day for this region in
1999. The Company has ownership in 3,446 wells with proved reserves of 461
Bcfe. The Company has identified 400 undrilled locations in the Mid-Continent
Region, of which 148 have been assigned proved undeveloped reserves. The
Company plans to drill approximately 60 wells in this area during 2000, with
the primary development focus being the higher potential Morrow/Springer sand
subcrop in the Watonga-Chickasha Trend.
Watonga-Chickasha Trend
The Morrow/Springer sands located in central Oklahoma were deposited as bars
and channels along an ancient coast line more than 350 miles long. These sands
exhibit excellent porosity and permeability at depths of 10,000 to 13,000 feet.
Multiple objectives of up to a dozen sands have allowed increased drilling from
one well per 640 acres to as many as four wells per 640 acres. The majority of
the wells drilled in this trend are lower risk development wells. The Company
plans to drill four exploratory tests seeking to discover new bars or channels
and approximately 40 development wells during 2000.
Texas Panhandle
In the Texas Panhandle, the primary objective is the Morrow sand which was
deposited in fluvial channels. Previous experience has shown that 3D seismic
can help identify these sand channels. The Company completed a 40 square mile
3D seismic survey on the Munson Project in 1998, and in 1999, the Company
acquired access to 140 square miles of additional 3D seismic data. This data is
currently being processed and is expected to produce drilling locations for the
year 2000. The Company has an approximate 50% working interest in this 40,000
acre project.
Smackover Trend
The Company's operations in the Smackover Trend of Southwestern Arkansas are
focused primarily in the Midway field, which is operated by the Company. The
Midway field is located in Lafayette County, Arkansas and produces oil from the
Smackover formation at an average depth of 6,500 feet. The Company owns an
average of 79% working interest in this mature waterflood unit.
14
Gulf Coast Region
The Company has been active in the Gulf Coast Region since its initial entry
through an acquisition in 1991. Development drilling on these acquired
properties began in 1992 and continued into 1999. Presently, the Company is
actively involved in an exploration and development program in South Texas and
offshore in the Gulf of Mexico. The Company's properties in this region number
663 wells and include 252 Bcfe of proved reserves. The Company drilled 26 wells
in the Gulf Coast Region during 1999 and daily production averaged 120 MMcfe
per day. The Company has identified 75 undrilled locations in this region of
which 38 have been assigned proved undeveloped reserves. Plans for this region
in 2000 include the drilling of approximately 32 wells and a total investment
of $104 million, including acreage and seismic acquisition.
Lavaca County Area
The Company began its involvement in Lavaca County, Texas, in 1996 to explore
and drill primarily for the Lower Wilcox formation. Secondary targets include
the shallower Upper Wilcox, Miocene, Frio and Yegua targets. Working interests
in these projects, including the Yoakum Gorge and S.W. Speaks projects,
initially ranged from 25% to 35%. Subsequent acquisitions in 1997 and 1998 have
more than doubled the Company's interests in these projects. The Company has
additionally expanded its position in the Wilcox Trend further to the east to
include the Provident City field.
The Company now holds working interests ranging from 30% to 87.5% in
60,000 gross acres in Lavaca County. Since this project began, the Company has
participated in 50 Lower Wilcox wells, over 90% of which have successfully been
completed as producers. Approximately 200 square miles of high-fold 3D seismic
data was obtained in 1996 and 1997 which continues to be evaluated. An
additional 50 square miles of 3D seismic was shot on the South Borchers
prospect in late 1998 which is a southern extension to existing data. The
Company is currently participating in a 60 plus square mile 3D shoot to the
west of its current acreage holdings. The data will be available in the first
quarter of 2000. The target zones are the Lower Wilcox sands from 10,000 to
17,000 feet and the shallow Miocene, Frio, Yegua and Upper Wilcox sands ranging
in depth from 3,500 to 8,000 feet.
The Company's Lower Wilcox drilling program in 1999 resulted in the
successful completion of 17 wells, including four exploratory tests. The Lower
Wilcox sands are part of an ancient deltaic system deposited across an unstable
muddy continental shelf. The rapid subsidence of the underlying beds allowed
accumulation of massive Wilcox sand packages with a high degree of structural
complexity. These deep structures have significant potential, ranging up to 100
Bcf per field. Production rates for wells drilled in this program have ranged
as high as 30 MMcfe per day. Drilling plans for 2000 include approximately 20
Lower Wilcox wells in Lavaca County, of which five are expected to be
exploratory.
Wilcox Trend
As an extension to its Wilcox success in Lavaca County, the Company acquired
leasehold positions in Zapata, Goliad and Webb Counties during 1999. In the En
Seguido field located in Zapata County, the Company drilled the Laura Lopez #1
well, which was completed at a rate of 12 MMcf of natural gas per day with
8,900 pounds flowing tubing pressure. An offset development well is currently
being completed in this field. In addition to this En Seguido field activity,
the Company is drilling a Wilcox test on the W. Martinez prospect, also in
Zapata County, which is ten miles to the north of En Seguido. In total, the
Company owns approximately 4,800 gross acres in Zapata County with working
interests ranging from 38% to 100%. The Company plans to drill five wells in
2000 using its 100 square miles of 3D seismic.
In Goliad County, the Company acquired approximately 3,100 gross acres in
two prospects, the Cologne and Swickheimer prospects. The Company's working
interests in these prospects range from 37% to 54%. Exploratory tests for the
Lower Wilcox are planned for both of these projects in 2000.
Vicksburg Trend
In South Texas, the late Oligocene Vicksburg formation is a prolific producer
from shelf-edge delta sand reservoirs. The depositional environments
responsible for these sands include delta flanks and their associated shore
zones, strand plains and barrier systems. The extensively growth-faulted
Vicksburg deltas within the Rio Grande embayment contain numerous anticlinal
and fault closures and structural/stratigraphic combination trapping
situations. During 1999, the Company acquired approximately 7,900 gross acres
in the Tabasco prospect located in Hidalgo County with a net working interest
of 75% and in early 2000 acquired approximately 1,300 gross acres in the Lopez
Ranch prospect in Brooks County, with a net working interest of 50%.
Exploratory tests for the Vicksburg sand are planned for both of these projects
in 2000.
Offshore Area
The Company owns working interests in twelve operated and eight
outside-operated oil and gas production platforms and 148,000 acres, and owns
over three thousand square miles of 3D seismic data in the Gulf of Mexico.
Average net daily production from the Company's offshore properties was 51
MMcfe per day in 1999.
Texas State Waters. The Company owns an average 79% working interest in
more than 38,000 gross acres in the Texas State Waters area. In addition, the
Company has acquired 3,000 square miles of 3D seismic data in this offshore
area. High-quality 3D seismic information for the Texas State Waters previously
was unavailable due to the inability of vessels towing
15
seismic cables to operate in less than 60 feet of water without damaging the
seismic equipment. The advent of ocean-bottom cabling has made the acquisition
of high-quality 3D seismic information economically feasible. The Company
drilled one exploratory test in 1999, which appears productive on logs.
Completion operations are currently underway. The Company has identified
several exploration prospects in the shallow waters offshore in the Gulf of
Mexico which it plans to drill in 2000.
High Island 116. High Island Block 116 is located in shallow federal
waters, offshore Texas. The Company owns a 44% non-operated working interest in
this block which produces from the Lower Miocene sands at an approximate depth
of 10,000 feet. This block had average net daily production of 4 MMcfe during
1999. The Company is currently completing a new discovery drilled on this
platform in 1999.
East Cameron Block 328. East Cameron Block 328 is located in federal
waters, offshore Louisiana, in approximately 240 feet of water. The block is on
the flank of a large salt feature with multiple sands located in several fault
blocks. Production is from the Trim A, Trim S and the HB-1 sands. The platform
produced 9 MMcfe per day during 1999.
High Island 45. High Island Block 45 is located in shallow federal waters,
offshore Texas. The Company is the operator and owns an 83% working interest in
this block which produces from the Lower Miocene sands at an approximate depth
of 11,000 feet. This platform averaged net daily production of 11 MMcfe during
1999. The Company acquired additional interest in this block during 1999.
Reserves
The following table presents the estimated net quantities of the Company's
proved and proved developed reserves, the Estimated Future Net Revenues, and
the Present Values, as defined herein, attributable to total proved reserves
for each of the five years in the period ended December 31, 1999.
Proved Reserves
As of December 31,
------------------------------------------------------------------------
1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------------
(dollars in millions, except price data)
Estimated Proved Reserves:
Natural gas (Bcf) 1,294.0 1,193.7 1,028.8 849.2 753.9
Oil (MMBbls) 28.4 24.4 29.1 23.5 20.4
Total (Bcfe) 1,464.3 1,340.2 1,203.4 990.2 876.1
Estimated Future Net Revenue $ 2,136.0 $ 1,676.8 $ 1,926.0 $ 2,643.8 $ 1,092.4
Present Value $ 1,049.7 $ 811.1 $ 1,002.6 $ 1,303.7 $ 524.4
Estimated Proved Developed Reserves:
Natural gas (Bcf) 1,064.7 1,026.8 899.2 709.7 630.6
Oil (MMBbls) 23.9 20.7 24.3 17.9 14.8
Total (Bcfe) 1,208.4 1,151.2 1,045.1 817.1 719.6
Year-end Prices used in Estimating Future
Net Revenues:
Natural gas (per Mcf) $ 2.19 $ 2.07 $ 2.49 $ 3.82 $ 2.02
Oil (per Bbl) $ 24.36 $ 9.46 $ 16.76 $ 24.70 $ 17.82
=====================================================================================================================
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, 1999 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 were
based on the engineers' production volume estimates as of December 31, 1999.
The amounts shown do not give effect to indirect expenses such as general and
administrative expenses, debt service and future income tax expense or to
depletion, depreciation and amortization.
The Company estimates that if all other factors (including the estimated
quantities of economically recoverable reserves) were held constant, a $1.00
per Bbl change in oil prices and a $.10 per Mcf change in gas prices from those
used in calculating the Present Value would change such Present Value by $14
million and $57 million, respectively.
16
The prices used in calculating the Estimated Future Net Revenues
attributable to proved reserves do not consider the Company's Fixed-Price
Contracts for the corresponding volumes and production periods. These contract
prices are on average higher than spot market prices at December 31, 1999. If
Fixed-Price Contract pricing was used at December 31, 1999, the Estimated
Future Net Revenues and the Present Value attributable to proved reserves would
be $2.2 billion and $1.1 billion, respectively.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of the
Company. The reserve information shown herein is estimated. Reserve engineering
is a subjective process of estimating underground accumulations of oil and gas
that cannot be measured in an exact manner, and the accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. As a result, estimates of different
engineers often vary. In addition, results of drilling, testing and production
subsequent to the date of an estimate may justify revision of such estimate.
Accordingly, reserve estimates often differ from the quantities of oil and gas
that are ultimately recovered. The meaningfulness of such estimates is highly
dependent upon the accuracy of the assumptions upon which they were based.
For further information on reserves, future net revenues and the
standardized measure of discounted future net cash flows, see Note 14 of the
Notes to Consolidated Financial Statements appearing elsewhere herein.
Costs Incurred and Drilling Results
The following table presents certain information regarding the costs incurred
by the Company in its acquisition, exploration and development activities for
each of the five years in the period ended December 31, 1999.
Costs Incurred
As of December 31,
-----------------------------------------------------------------
1999 1998 1997 1996 1995
- ----------------------------------------------------------------------------------------------------
(in thousands)
Property acquisition costs: (1)
Proved $ 36,881 $ 4,088 $349,037 $ 36,125 $118,652
Unproved 10,766 11,815 109,648 6,934 1,717
- ----------------------------------------------------------------------------------------------------
47,647 15,903 458,685 43,059 120,369
Exploration costs 19,409 74,123 21,514 10,610 391
Development costs 116,597 136,462 122,402 80,553 64,498
- ----------------------------------------------------------------------------------------------------
Total $183,653 $226,488 $602,601 $134,222 $185,258
====================================================================================================
(1) Proved and unproved property acquisition costs for 1997 include $339.9
million and $98.0 million, respectively, of allocated American Acquisition
purchase price.
Proceeds from the sale of oil and gas properties for this same five-year
period were as follows: 1999: $12.4 million; 1998: $14.3 million; 1997: $27.7
million; 1996: $.7 million; and 1995: $14.9 million.
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,
----------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
- --------------------------------------------------------------------------------------------------------------
Development wells:
Gas 191 156 237 153 223 166 179 130 134 115
Oil 5 2 60 37 52 20 92 19 114 28
Dry 17 12 27 20 20 14 9 5 14 5
- --------------------------------------------------------------------------------------------------------------
Total 213 170 324 210 295 200 280 154 262 148
==============================================================================================================
Exploratory wells:
Gas 13 8 13 8 32 24 18 6 3 1
Oil 1 1 1 1 4 3 -- -- -- --
Dry 2 2 13 9 12 9 7 2 -- --
- --------------------------------------------------------------------------------------------------------------
Total 16 11 27 18 48 36 25 8 3 1
==============================================================================================================
As of December 31, 1999 the Company was involved in the drilling, testing or
completing of 10 gross (6 net) development wells and 1 gross (1 net)
exploratory well.
17
Acreage
The following table presents the Company's developed and undeveloped oil and
gas lease and mineral acreage as of December 31, 1999. Excluded is acreage in
which the Company's interest is limited to royalty, overriding royalty and
other similar interests.
Acreage
Developed Undeveloped
------------------------ -------------------------
Gross Net Gross Net
- ----------------------------------------------------------------------
Core Area:
Permian 414,588 241,641 316,903 125,918
Mid-Continent 530,284 271,251 388,283 143,187
Gulf Coast 157,154 67,540 182,929 113,319
Other 278,266 43,778 253,689 90,219
- ----------------------------------------------------------------------
Total 1,380,292 624,210 1,141,804 472,643
======================================================================
Productive Well Summary
The following table presents the Company's ownership in productive wells at
December 31, 1999. Gross oil and gas wells include 160 wells with multiple
completions. Wells with multiple completions are counted only once for purposes
of the following table.
Productive Wells
Productive Wells
------------------
Gross Net
- ----------------------------------------------------------------------
Gas 5,833 2,816
Oil 3,563 593
- ----------------------------------------------------------------------
Total 9,396 3,409
======================================================================
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.
Item 3. Legal Proceedings
In December 1995, the United States District Court for the Western District of
Oklahoma entered a $10.8 million judgment in favor of the Company against
Midcon Offshore, Inc. ("Midcon") in connection with non-performance by Midcon
under an agreement to purchase a certain offshore oil and gas property. In
January 1996, Midcon delivered a $10.8 million promissory note to the Company
secured by liens on assets of Midcon in settlement of disputes in connection
with this litigation. Midcon paid $3.0 million to the Company prior to its
filing for bankruptcy in December 1996. In July 1999, an agreement was reached
between the Company and the Trustee to the Midcon bankruptcy case which
provided for the payment of $8.6 million to the Company in satisfaction of its
claims against the estate. The settlement was approved by the bankruptcy court
and payment was made to the Company in August 1999. Receipt of the settlement
proceeds has been reflected in earnings and operating cash flows for the year
ended December 31, 1999.
In February 1995, a lawsuit was filed in the United States District Court
in Denver, Colorado, by KN Gas Supply Services, Inc. ("KNGSS"), requesting
declaratory judgment that KNGSS had the right to reduce the contract price for
gas produced from the Bowdoin Field, a property obtained in the American
Acquisition, to market levels from October 1, 1993 forward. KNGSS alleged that
it was entitled to a refund of approximately $7.7 million for the period through
September 1996. KNGSS had not updated its refund claim beyond this date. A
motion for summary judgment was filed in July 1996 by the Company, and in
February 1998, the Court ruled in favor of the Company and against KNGSS. KNGSS
subsequently filed an appeal which has been
18
denied by the 10th Circuit Court of Appeals. No further appeal has been filed
by KNGSS and the filing deadline available for making a subsequent appeal has
expired.
The Company is one of numerous defendants in several lawsuits originally filed
in 1995, subsequently consolidated with related litigation, and now pending in
the Texas 93rd Judicial District Court in Hildago County, Texas. The lawsuit
alleges that the plaintiffs, a group of local landowners and businesses, have
suffered damages including, but not limited to, property damage and lost profits
of approximately $60 million as the result of hydrocarbon contamination of the
groundwater within the city of McAllen, Texas. The lawsuit alleges that gas
wells and related pipeline facilities owned and operated by the Company, and
other facilities operated by other defendants, caused the contamination. In
August 1999, the plaintiffs' experts produced reports that suggested the Company
might be considered a significant contributor to the contamination. The
Company's investigation into this matter has not found any leaks or discharges
from its facilities and believes the contamination to be unrelated to the
Company's gas wells and facilities. Trial is scheduled for May 2000. The Company
will vigorously defend its interests in this case and does not expect the
ultimate outcome of the case to have a material adverse impact on its financial
position or results of operations.
The Company is a defendant in additional pending legal proceedings which
are routine and incidental to its business. The largest of such legal claims
was for an alleged underpayment of royalty of $2.8 million plus interest. While
the ultimate results of all these proceedings and determinations cannot be
predicted with certainty, the Company will vigorously defend its interests and
does not believe that the outcome of these matters will have a material adverse
effect on the Company.
Item 4. Submission of Matters to a Vote of Security Holders
During the quarter ended December 31, 1999, no matters were submitted by the
Company to a vote of its security holders.
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
The Company's Common Stock is listed on the New York Stock Exchange ("NYSE")
and traded under the symbol "LD." As of March 1, 2000, the Company estimates
there were approximately 10,000 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, 1999 and 1998, were as follows:
Common Stock Market Prices
1999 1998
------------------------- -------------------------
High Low High Low
- -----------------------------------------------------------------
Quarter:
First $ 15.75 $ 11.06 $ 20.13 $ 16.50
Second 22.00 14.25 20.63 15.50
Third 23.31 18.88 19.00 10.50
Fourth 21.50 16.00 16.44 12.00
=================================================================
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 indenture agreement for the Company's 9-1/4% Senior
Subordinated Notes due 2004 restrict the Company's ability to declare or pay
cash dividends unless certain financial ratios are maintained. Although it is
not currently anticipated that any cash dividends will be paid on the Common
Stock in the foreseeable future, the Board of Directors may review the
Company's dividend policy from time to time. In determining whether to declare
dividends and the amount of dividends to be declared, the Board will consider
relevant factors, including the Company's earnings, its capital needs and its
general financial condition.
Item 6. Selected Financial Data
The selected financial data presented below as of December 31, 1999 and 1998,
and for each of the three years ended December 31, 1999, 1998 and 1997, has
been derived from, and is qualified by reference to, the Company's audited
Consolidated Financial Statements, including the notes thereto, contained
herein beginning at page F-1. The selected financial data as of December 31,
1997, 1996 and 1995, and for the years ended December 31, 1996 and 1995, 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."
19
Selected Financial Data
Years Ended December 31,
--------------------------------------------------------------------
1999 1998 (2) 1997 (3) 1996 1995
- -----------------------------------------------------------------------------------------------------------------------
(in thousands, except per share data)
Statement of Operations Data:
Oil and gas sales $ 290,878 $ 271,575 $ 222,016 $ 185,558 $163,366
Change in derivative fair value (442) 17,346 -- -- --
Other income (loss) 12,170 4,462 10,901 3,947 (418)
- -----------------------------------------------------------------------------------------------------------------------
Total revenues 302,606 293,383 232,917 189,505 162,948
- -----------------------------------------------------------------------------------------------------------------------
Operating costs 66,039 66,295 49,169 44,615 35,352
General and administrative 23,995 25,971 18,855 16,325 16,631
Exploration costs 14,258 34,543 8,956 4,965 --
Depreciation, depletion and amortization 117,080 131,408 79,325 65,278 57,796
Impairment 4,877 52,522 75,198 -- 15,694
Interest 40,667 40,849 28,737 26,822 21,736
- -----------------------------------------------------------------------------------------------------------------------
Total expenses 266,916 351,588 260,240 158,005 147,209
- -----------------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes and
cumulative effect of accounting change 35,690 (58,205) (27,323) 31,500 15,739
Income tax provision (benefit) 14,276 (13,924) (11,261) 10,398 4,722
- -----------------------------------------------------------------------------------------------------------------------
Net income (loss) before cumulative effect of
accounting change 21,414 (44,281) (16,062) 21,102 11,017
Cumulative effect of accounting change, net of
tax -- 964 -- -- --
- -----------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 21,414 $ (43,317) $ (16,062) $ 21,102 $ 11,017
=======================================================================================================================
Net income (loss) before cumulative effect of
accounting change per share $ .53 $ (1.10) $ (.53) $ .76 $ .40
Cumulative effect of accounting change per share -- .02 -- -- --
- -----------------------------------------------------------------------------------------------------------------------
Net income (loss) per share--basic and diluted $ .53 $ (1.08) $ (.53) $ .76 $ .40
=======================================================================================================================
Weighted average basic common shares 40,153 40,107 30,233 27,800 27,800
Weighted average diluted common shares 40,389 40,107 30,233 27,810 27,804
=======================================================================================================================
Statement of Cash Flows Data:
Net cash provided by operating activities $ 181,556 $ 147,438 $ 129,846 $ 101,761 $ 89,515
Net cash used in investing activities 167,662 215,274 216,603 150,857 171,540
Net cash provided by (used in) financing
activities (6,773) 64,837 84,546 55,261 80,629
EBITDAX (1) 213,014 183,771 164,893 128,565 111,572
=======================================================================================================================
As of December 31,
---------------------------------------------------------------------
1999 1998 (2) 1997 (3) 1996 1995
- ------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance Sheet Data:
Oil and gas properties, net $1,104,804 $1,064,206 $1,077,091 $ 652,257 $584,900
Total assets 1,227,087 1,283,808 1,210,954 733,613 634,937
Long-term debt, including current portion 555,222 596,844 563,344 343,907 314,760
Stockholders' equity 498,782 519,461 469,204 263,693 242,581
========================================================================================================================
(1) See "Item 1--Business--Certain Definitions."
(2) In October 1998, the Company adopted SFAS 133. See Note 1 of the Notes to
Consolidated Financial Statements appearing elsewhere herein.
(3) In October 1997, the Company closed the American Acquisition. See "Item
7--Management's Discussion and Analysis of Financial Condition and Results
of Operations--Results of Operations--Fiscal Year 1998 Compared to Fiscal
Year 1997."
20
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Overview
General. The Company's business strategy is to generate strong and consistent
growth in reserves, production, operating cash flows and earnings through a
program of exploration and development drilling and strategic acquisitions of
oil and gas properties. Over the five-year period ended December 31, 1999, this
strategy has resulted in a 112% increase in proved reserves to 1.5 Tcfe, a 132%
increase in oil and gas production to 126 Bcfe, 124% growth in cash flows from
operating activities to $181.6 million, and a 99% increase in net earnings to
$21.4 million. All of these measures represented record performance for the
Company. The growth achieved during 1999 was the result of a net capital
program funded solely through operating cash flows.
During the five-year period ended December 31, 1999, the Company drilled
1,493 gross (956 net wells), with an overall drilling success rate of 92%,
adding 767 Bcfe of reserves (including revisions of previous estimates) to its
proved reserve base. The year ended December 31, 1999 marked the sixth
consecutive year that the Company replaced its production through its drilling
activities. Through its 1999 drilling program, the Company added 208 Bcfe of
proved reserves at an all-in finding and development cost (total costs incurred
to explore and develop oil and gas properties divided by proved reserves added
through extensions and discoveries and revisions of previous estimates) of $.67
per Mcfe. These additions represent 175% production replacement for 1999. The
Company has increasingly emphasized exploration as an integral component of its
business strategy and in connection therewith, has incurred substantial up-
front costs, including significant acreage positions, seismic costs and other
geological and geophysical costs. During 1999, the Company invested $29 million
in connection with exploration activities, resulting in the acquisition of $15
million of acreage and seismic information, and the drilling of 16 exploratory
wells, of which 14 were completed as producers (a completion success rate of
88%).
A substantial portion of the Company's growth has been the result of
proved reserve acquisitions geographically concentrated in its Core Areas where
the Company has significant expertise and where the Company benefits from
operational synergies. During the five-year period ended December 31, 1999, the
Company made proved reserve acquisitions aggregating 548 Bcfe, purchased for a
total consideration of $544.8 million, or $.99 per Mcfe. Of particular
significance was the American Acquisition in October 1997 which added 217 Bcfe
to the Company's proved reserve base and an attractive unproved acreage
position.
As of December 31, 1999, the Company's portfolio of Fixed-Price Contracts
hedge 52 Bcfe of future oil and gas production in 2000, and 133 Bcfe
thereafter, at escalating fixed prices. The average fixed prices in these
contracts are higher than the forward market prices for natural gas and oil as
of December 31, 1999. Historically, the Company has been an active hedger of
its commodity price risk, hedging future production out as far as 2017. This
hedging activity has resulted in net realized cash gains in excess of $160
million since the Company's inception in 1990. Over the past few years,
competition in Fixed-Price Contracts has increased, opportunities for
attractive Fixed-Price Contracts have diminished and year-to-year price
escalations in the forward market are considerably lower. In response to these
changes, a progressively smaller share of the Company's production and reserve
growth has been hedged due to Management's belief that longer-term demand and
supply fundamentals for natural gas imply the potential for prices in excess of
those currently available in the long-term forward market. More recent hedging
activity has been for shorter periods of time, generally less than 12 months,
when market conditions have been viewed as favorable. The Company may decide to
hedge a greater or smaller share of production in the future depending upon
market conditions, capital investment considerations and other factors. See
"Item 7A--Quantitative and Qualitative Disclosures About Market
Risk--Fixed-Price Contracts."
21
Selected Operating Data. The following table provides certain data
relating to the Company's operations.
Years Ended December 31,
Selected Operating Data ------------------------------------------------------------------
1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------
Oil and Gas Sales (M$):
Oil sales:
Wellhead $ 51,361 $ 42,604 $ 40,680 $ 39,372 $ 28,973
Effect of Fixed-Price Contract settlements (1) (1,672) 2,159 803 (3,198) 1,077
- ---------------------------------------------------------------------------------------------------------------------------
Total $ 49,689 $ 44,763 $ 41,483 $ 36,174 $ 30,050
===========================================================================================================================
Natural gas sales:
Wellhead $237,976 $ 205,822 $185,623 $148,244 $ 110,073
Effect of Fixed-Price Contracts settlements (1) 3,213 20,990 (5,090) 1,140 23,243
- ---------------------------------------------------------------------------------------------------------------------------
Total $241,189 $ 226,812 $180,533 $149,384 $ 133,316
===========================================================================================================================
Production:
Oil production (MBbls) 2,965 3,430 2,088 1,849 1,695
Natural gas production (MMcf) 107,979 101,066 71,731 63,910 51,264
Equivalent production (MMcfe) 125,769 121,647 84,262 75,004 61,434
Oil production hedged by Fixed-Price Contracts (MBbls) 569 539 686 1,241 1,464
Gas production hedged by Fixed-Price Contracts (BBtu) 59,534 50,823 43,185 32,508 31,579
Average Sales Price:
Oil price (per Bbl):
Wellhead price $ 17.32 $ 12.42 $ 19.48 $ 21.29 $ 17.09
Effect of Fixed-Price Contracts settlements (1) ( .56) .63 .38 ( 1.73) .64
- ---------------------------------------------------------------------------------------------------------------------------
Total $ 16.76 $ 13.05 $ 19.86 $ 19.56 $ 17.73
===========================================================================================================================
Average fixed price provided by Fixed-Price
Contracts $ 21.64 $ 17.37 $ 21.81 $ 19.53 $ 19.12
Natural gas price (per Mcf):
Wellhead price $ 2.20 $ 2.03 $ 2.59 $ 2.32 $ 2.15
Effect of Fixed-Price Contracts settlements (1) .03 .21 ( .07) .02 .45
- ---------------------------------------------------------------------------------------------------------------------------
Total $ 2.23 $ 2.24 $ 2.52 $ 2.34 $ 2.60
===========================================================================================================================
Average fixed price provided by Fixed-Price
Contracts $ 2.47 $ 2.60 $ 2.51 $ 2.43 $ 2.40
Natural gas equivalent price (per Mcfe) $ 2.31 $ 2.23 $ 2.63 $ 2.47 $ 2.66
Expenses and Costs Incurred (per Mcfe):
Lease operating expenses $ .41 $ .44 $ .45 $ .47 $ .47
Production taxes .12 .11 .14 .12 .11
General and administrative .19 .21 .22 .22 .27
Depreciation, depletion and amortization--oil and
gas properties (2) .89 1.04 .88 .82 .88
Finding Cost (3) .70 .85 1.81 .71 .70
===========================================================================================================================
(1) "Effect of Fixed-Price Contracts settlements" represents the realized
hedging results from the Company's Fixed-Price Contracts. See "Item
7A--Quantitative and Qualitative Disclosures About Market
Risk--Fixed-Price Contracts." These amounts do not include the change in
derivative fair value reported in results of operations for 1999 and 1998.
(2) Does not include impairments. See "--Results of Operations--Fiscal Year
1999 Compared to Fiscal Year 1998" and "--Results of Operations--Fiscal
Year 1998 Compared to Fiscal Year 1997."
(3) See "Item 1--Business--Certain Definitions." Amounts for 1997 include the
allocated purchase price of the American Acquisition pursuant to purchase
accounting rules.
22
The following table presents certain information regarding the Company's proved
oil and gas reserves.
As of December 31,
Oil and Gas Reserves ----------------------------------------------------------------------
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
(dollars in millions)
Estimated Net Proved Reserves:
Natural gas (MMcf) 1,294,029 1,193,666 1,028,752 849,199 753,919
Oil (MBbls) 28,372 24,416 29,109 23,497 20,360
Total (MMcfe) 1,464,258 1,340,161 1,203,405 990,179 876,076
Reserve Replacement Ratio (1) 207% 219% 396% 254% 430%
Reserve Life (in years) (1) (2) 11.6 11.0 10.7 13.2 14.3
Estimated Future Net Revenues (1) (3) $ 2,136.0 $ 1,676.8 $ 1,926.0 $ 2,643.8 $ 1,092.4
Present Value (1) (3) $ 1,049.7 $ 811.1 $ 1,002.6 $ 1,303.7 $ 524.4
==============================================================================================================
(1) See "Item 1--Business--Certain Definitions."
(2) For 1997, pro forma production for the American Acquisition of 113.0 Bcfe
was used in the reserve life determination.
(3) Estimated Future Net Revenues and the Present Value give no effect to the
Company's portfolio of Fixed-Price Contracts or federal or state income
taxes attributable to estimated future net revenues. See "Item
2--Properties--Reserves."
Results of Operations--Fiscal Year 1999 Compared to Fiscal Year 1998
Net Income (Loss) and Cash Flows from Operating Activities. The Company
reported net income of $21.4 million, or $.53 per share, on total revenue of
$302.6 million for the year ended December 31, 1999. This compares to a net
loss of $43.3 million, or $1.08 per share, on total revenue of $293.4 million
for 1998. Cash flows from operating activities (before working capital changes)
for 1999 grew 19% to $171.8 million compared to $144.9 million for 1998. Cash
flows provided by operating activities after consideration for the change in
working capital was $181.6 million, which compares to $147.4 million for 1998.
The significant increase in earnings and cash flows between the two periods was
principally the result of cost improvements realized during 1999, higher oil
and gas sales resulting from gas production growth and higher oil prices, and a
nonrecurring pretax gain of $8.6 million recognized upon the settlement of
certain litigation. Earnings for 1998 were adversely affected by non-cash
impairment charges totaling $52.5 million ($34.1 million after tax or $.85 per
share), resulting primarily from significantly lower oil and gas prices.
Production. Total production for the year ended December 31, 1999 grew 3%,
to 125.8 Bcfe, compared to 121.6 Bcfe produced during 1998. Natural gas
production for 1999 was 108.0 Bcf, a 7% increase over the 101.1 Bcf produced in
1998. Oil production in 1999 decreased 14% to 3.0 MMBbls compared to 3.4 MMBbls
produced in 1998. The increase in total production is primarily attributable to
the results of the Company's 1999 net capital expenditure program which was
funded solely through cash flows from operating activities.
Oil and Gas Prices. On a natural gas equivalent basis, the Company
realized an average price of $2.31 per Mcfe for 1999, a 4% increase compared to
the $2.23 per Mcfe received in 1998. The Company's 1999 gas production yielded
an average price of $2.23 per Mcf, slightly lower than 1998's average price of
$2.24 per Mcf. The Company's average gas price was enhanced $.03 per Mcf in
1999 and $.21 per Mcf in 1998 as a result of the Company's hedging activities.
The average oil price received during 1999 increased 28% to $16.76 per Bbl
compared to $13.05 per Bbl for 1998. Fixed-Price Contract settlements decreased
the average oil price in 1999 by $.56 per Bbl and increased the average oil
price in 1998 by $.63 per Bbl.
The combination of higher gas production and lower average price for 1999
increased gas sales by 6% to $241.2 million compared to $226.8 million reported
for 1998. The combined effect of higher oil prices and lower oil production was
an 11% increase in oil sales to $49.7 million compared to $44.8 million for the
prior-year period. The aggregate impact of Fixed-Price Contract settlements
during each period was an increase in oil and gas revenues of $1.5 million in
1999 and an increase in oil and gas revenues of $23.1 million in 1998. See
"Item 7A--Quantitative and Qualitative Disclosures About Market
Risk--Fixed-Price Contracts."
Change in Derivative Fair Value. The Company was an early adopter of SFAS
133, effective October 1, 1998. Pursuant to the provisions of the standard, all
hedging designations and the methodology for determining hedge ineffectiveness
must be documented at the inception of the hedge, and, upon the initial
adoption of the standard, hedging relationships must be designated anew. The
documentation must also indicate the risk management intent for entering into
the hedging arrangement. The Company believed that it complied with the spirit
and intent of the provisions of the standard with respect to documentation.
However, in connection with a review of the Company's public filings by the
Staff of the Securities and Exchange Commission in September 1999, the
Company's documentation was determined to be insufficient as of the October 1,
1998 date of adoption of SFAS 133. Therefore, the Company was precluded from
being able to utilize the special provisions of
23
hedge accounting for the fourth quarter of 1998, and the period from January 1,
1999 to January 13, 1999, the date the Company's documentation was sufficient
in relation to the formal documentation requirements of the standard. As a
result, the changes in the fair value of all of the Company's derivatives
during the fourth quarter were required to be reported in results of
operations, rather than in other comprehensive income. The Company reported a
net gain of $17.3 million in "change in derivative fair value" for 1998,
primarily as a consequence of this required accounting treatment. In 1999, the
Company reported a net loss of $.4 million, the largest component of which
relates to the unwinding of the gains previously recognized in 1998 and early
1999 as cash settlements under the contracts are realized.
Other Income (Loss). The Company realized other income for 1999 of $12.2
million compared to $4.5 million for 1998. This increase was primarily the
result of a nonrecurring pretax gain of $8.6 million recognized upon the
settlement of certain litigation.
Operating Costs. Operating costs for 1999 were comprised of $51.2 million
of lease operating expenses and $14.8 million of production taxes. This
compares to $53.2 million of lease operating expenses and $13.1 million of
production taxes for 1998. The decrease in lease operating expenses is
principally attributable to improved operating efficiencies in the field and to
a reduction in costs for services and materials. On a natural gas equivalent
unit of production basis, lease operating expenses improved to $.41 per Mcfe
compared to $.44 for 1998. The increase in production taxes in 1999 is
attributable to higher production and higher oil prices.
General and Administrative Expense. General and administrative expense
("G&A") for 1999 was $24.0 million compared to $26.0 million for 1998. This
decrease is primarily attributable to cost reduction measures implemented by
the Company in the first quarter of 1999. As a result, G&A per natural gas
equivalent unit of production improved to $.19 per Mcfe for 1999 compared to
$.21 per Mcfe for 1998.
Exploration Costs. Exploration costs, comprised of geological and
geophysical, exploratory dry hole and leasehold impairment costs, were $14.3
million for the year ended December 31, 1999 compared to $34.5 million for the
year ended December 31, 1998. The 1999 amount consisted of $5.0 million of
seismic acquisition and other geological and geophysical costs (collectively
"G&G Costs"), $1.2 million of dry hole costs and $8.1 million of leasehold
impairments. The 1998 amount consisted of $12.8 million of G&G costs, $16.5
million of dry hole costs and $5.2 million of leasehold impairments.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense ("DD&A") for the year ended December 31, 1999 was $117.1
million compared to $131.4 million for 1998. This decrease is due to a decrease
in the oil and gas DD&A rate for 1999. The oil and gas DD&A rate per equivalent
unit of production was $.89 per Mcfe for 1999 compared to $1.04 per Mcfe in
1998. The DD&A rate improved primarily as a result of 1999 proved reserve
additions added at a Finding Cost of $.70 per Mcfe, and the impairment charge
recorded in the fourth quarter of 1998.
Impairment. The Company recorded total impairment charges of $4.9 million
during 1999 primarily as a result of downward reserve revisions for certain
offshore fields. In total, the Company reported net upward reserve revisions of
approximately 12 Bcfe. In 1998, the Company recognized impairment charges
totaling $52.5 million, primarily as a result of a significant decline in oil
and gas prices in the fourth quarter of 1998. For purposes of determining
whether its oil and gas properties have been impaired, the Company utilizes
forward market price quotations as of the date of determination in estimating
the future cash flows from its oil and gas properties. This forward market
price information is consistent with that generally used by the Company in
making drilling and acquisition plans and decisions. In the impairment
calculation, these market prices for future periods are used to price the
estimated production from proved reserves for the corresponding periods in
arriving at future cash flows. No changes in production from the profile
included in its year-end reserve report are assumed.
Interest Expense. Interest expense for 1999 was $40.7 million which
compares to $40.8 million for 1998. The net impact of interest rate swap
settlements for the years ended December 31, 1999 and 1998 was immaterial. See
"--Item 7A--Quantitative and Qualitative Disclosures About Market Risk--
Interest Rate Sensitivity."
Income Taxes. For 1999, the Company recorded a tax provision of $14.3
million on pretax income of $35.7 million, an effective rate of 40%. This
compares to a tax benefit of $13.9 million, or 24%, on a pretax loss of $58.2
million for 1998. The effective rates for both 1999 and 1998 varied from the
statutory rate due to permanent differences related to the tax bases of certain
acquired oil and gas properties. The effective tax rate for 1998 includes the
effect of an adjustment to the net operating loss carryforward valuation
allowance.
Cumulative Effect of Accounting Change. In the fourth quarter of 1998, the
Company adopted the provisions of SFAS 133 which established new accounting and
reporting guidelines for derivative instruments and hedging activities. This
caption includes the cumulative adjustments to results of operations related to
adopting this standard of $1.6 million, shown net of tax of $.6 million. See
Note 1 of the Notes to Consolidated Financial Statements appearing elsewhere
herein.
24
Results of Operations--Fiscal Year 1998 Compared to Fiscal Year 1997
Net Income (Loss) and Cash Flows from Operating Activities. The Company
reported a net loss of $43.3 million, or $1.08 per share, on total revenue of
$293.4 million for 1998. This compares to a net loss of $16.1 million, or $.53
per share, on total revenue of $232.9 million for 1997. The significant
downturn in oil and gas prices during 1998 was the principal contributor to the
decline in earnings between the two periods. Cash flows from operating
activities (before working capital changes) for the year ended December 31,
1998 grew 14% to $144.9 million compared to $127.1 million for 1997. Cash flows
provided by operating activities after consideration for the change in working
capital was $147.4 million, which compares to $129.8 million for 1997.
Significant production growth was the principal driver behind the increase in
operating cash flows for 1998, more than offsetting the effects of lower oil
and gas prices. Earnings for both years were adversely affected by non-cash
impairment charges. For 1998, the Company recognized impairment charges
totaling $52.5 million ($34.1 million after tax or $.85 per share), resulting
primarily from significantly lower oil and gas prices. In 1997, a $75.2 million
($47.1 million after tax, or $1.56 per share) impairment charge was recorded in
connection with the acquisition of American Exploration Company. See "--Change
in Derivative Fair Value."
Production. Total production for the year ended December 31, 1998 grew
44%, to 121.6 Bcfe, compared to 84.3 Bcfe produced during 1997. Natural gas
production for 1998 was 101.1 Bcf, a 41% increase over the 71.7 Bcf produced in
1997. Oil production in 1998 increased 64% to 3.4 MMBbls compared to 2.1 MMBbls
produced in 1997. These increases are primarily attributable to the American
Acquisition and the results of the Company's exploration and development
drilling activities.
Oil and Gas Prices. On a natural gas equivalent basis, the Company
realized an average price of $2.23 per Mcfe for 1998, a 15% decrease compared
to the $2.63 per Mcfe received in 1997. The Company's 1998 gas production
yielded an average price of $2.24 per Mcf, an 11% decrease compared to 1997's
average price of $2.52 per Mcf. The Company's average gas price was enhanced
$.21 per Mcf in 1998 and decreased $.07 per Mcf in 1997 as a result of the
Company's hedging activities. The average oil price received during 1998
decreased 34% to $13.05 per Bbl compared to $19.86 per Bbl for 1997.
Fixed-Price Contract settlements increased the average oil price in 1998 by
$.63 per Bbl and increased the average oil price in 1997 by $.38 per Bbl.
The combination of higher gas production and lower average price for 1998
increased gas sales by 26% to $226.8 million compared to $180.5 million
reported for 1997. The combined effect of lower oil prices and higher oil
production was an 8% increase in oil sales to $44.8 million compared to $41.5
million for the prior-year period. The aggregate impact of Fixed-Price Contract
settlements during each period was an increase in oil and gas revenues of $23.1
million in 1998 and a decrease in oil and gas revenues of $4.3 million in 1997.
See "Item 7A--Quantitative and Qualitative Disclosures About Market Risk--
Fixed-Price Contracts."
Change in Derivative Fair Value. The Company was an early adopter of SFAS
133, effective October 1, 1998. For the fourth quarter of 1998, the Company was
precluded from being able to utilize the special hedge accounting provisions of
the standard. As a result, the changes in the fair value of all of the
Company's derivatives during the fourth quarter were reported in results of
operations, rather than in other comprehensive income. The Company reported a
net gain of $17.3 million in "change in derivative fair value" for 1998,
primarily as a consequence of this required accounting treatment. See
"--Results of Operations--Fiscal Year 1999 Compared to Fiscal Year 1998--Change
in Derivative Fair Value."
Other Income (Loss). The Company realized other income for 1998 of $4.5
million compared to $10.9 million for 1997. The 1997 amount includes a net gain
of $8.5 million realized upon the sale of a non-core waterflood property.
Operating Costs. Operating costs for 1998 were comprised of $53.2 million
of lease operating expenses and $13.1 million of production taxes. This
compares to $37.7 million of lease operating expenses and $11.5 million of
production taxes for 1997. This increase is principally attributable to
producing properties acquired and wells drilled during 1998 and 1997. On a
natural gas equivalent unit of production basis, lease operating expenses
improved to $.44 per Mcfe compared to $.45 for 1997.
General and Administrative Expense. G&A for 1998 was $26.0 million
compared to $18.9 million for 1997. This increase is primarily attributable to
increases in personnel and related costs associated with the American
Acquisition. G&A per natural gas equivalent unit of production improved to $.21
per Mcfe for 1998 compared to $.22 per Mcfe for 1997.
Exploration Costs. Exploration costs, comprised of G&G costs, exploratory
dry hole and leasehold impairment costs, were $34.5 million for the year ended
December 31, 1998 compared to $9.0 million for the year ended December 31,
1997. This increase is consistent with the increase in exploration activity
conducted by the Company during 1998 compared to 1997. The 1998 amount
consisted of $12.8 million of G&G costs, $16.5 million of dry hole costs and
$5.2 million of leasehold impairments. The 1997 amount consisted of $2.5
million of G&G costs, $5.0 million of dry hole costs and $1.5 million of
leasehold impairments.
25
Depreciation, Depletion and Amortization. DD&A for the year ended December
31, 1998 was $131.4 million compared to $79.3 million for 1997. This increase
is due primarily to higher production levels and an increase in the oil and gas
DD&A rate for 1998. The oil and gas DD&A rate per equivalent unit of production
was $1.04 per Mcfe for 1998 compared to $.88 per Mcfe in 1997. This increase
was due primarily to the American Acquisition purchase price allocated to
proved reserves pursuant to purchase accounting rules. The DD&A rate for the
fourth quarter of 1998 improved to $.94 per Mcfe primarily as a result of 1998
reserve additions added at a Finding Cost of $.85 per Mcfe. Such rate
improvement was realized without consideration for the effect of the impairment
charge recorded in the fourth quarter of 1998.
Impairment. The Company recorded total impairment charges of $52.5 million
during 1998. As a result of a significant decline in oil and gas prices in the
fourth quarter of 1998, the Company performed a review for possible impairment
which resulted in $42.7 million of impairment recognition. Of this total, $38.7
million related to certain oil properties which were adversely affected by the
decline in crude oil prices. For purposes of determining whether its oil and
gas properties have been impaired, the Company utilizes forward market price
quotations as of the date of determination in estimating the future cash flows
from its oil and gas properties. This forward market price information is
consistent with that generally used by the Company in making drilling and
acquisition plans and decisions. In the impairment calculation, these market
prices for future periods are used to price the estimated production from
proved reserves for the corresponding periods in arriving at future cash flows.
The weighted average forward market crude oil price as of December 31, 1998
used in the impairment calculation was approximately $18 per Bbl, which equates
to an average field price of approximately $16 per Bbl. The majority of the
recorded impairment was recognized for properties in the Company's Permian and
Gulf Coast Regions, which were affected by crude oil price declines due, in
part, to their relatively short production lives and higher annual production
declines. Certain other oil properties in these regions either have a high
carrying value in relation to their estimated future net revenues or relatively
high operating costs which could result in future impairments in the event of
further price declines or change in the estimated quantities of proved
reserves.
In 1997, the Company recognized a $75.2 million impairment charge,
substantially all of which was associated with the allocation of the American
Acquisition purchase price to the oil and gas properties acquired. The purchase
price, as determined under purchase accounting rules, exceeded the estimated
fair value of the tangible assets of American. Factors which contributed to the
Company's decision to acquire American, in addition to the value of its oil and
gas properties, include (1) an accelerated diversification into exploration
activity, (2) the expected improvement in certain financial measures on a per
share basis, (3) the expected improvement in stock liquidity and (4) the
expected improvement in total market capitalization, among other reasons. See
Note 1 and Note 3 of the Notes to the Consolidated Financial Statements
appearing elsewhere herein.
Interest Expense. Interest expense for 1998 was $40.8 million compared to
$28.7 million for 1997. This increase is primarily attributable to higher
average long-term debt balances outstanding during 1998 as the result of the
American Acquisition. The net impact of interest rate swap settlements for the
years ended December 31, 1998 and 1997 was immaterial. See "Item
7A--Quantitative and Qualitative Disclosures About Market Risk--Interest Rate
Sensitivity."
Income Taxes. For 1998, the Company recorded a tax benefit of $13.9
million on a pretax loss of $58.2 million, an effective rate of 24%. This
compares to a tax benefit of $11.3 million, or 41%, on pretax loss of $27.3
million for 1997. The effective rates for both 1998 and 1997 varied from the
statutory rate due to the availability of Section 29 credits. In addition, the
effective tax rate for 1998 includes the effect of an adjustment to the net
operating loss carryforward valuation allowance and permanent differences
related to the tax bases of certain acquired oil and gas properties.
Cumulative Effect of Accounting Change. In the fourth quarter of 1998, the
Company adopted the provisions of SFAS 133 which establishes new accounting and
reporting guidelines for derivative instruments and hedging activities. This
caption includes the cumulative adjustments to results of operations related to
adopting this standard of $1.6 million, shown net of tax of $.6 million. See
Note 1 of the Notes to Consolidated Financial Statements appearing elsewhere
herein.
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, 1999, 1998 and
1997, the Company's cash flows related to investing activities included net
investments of $165.9 million, $212.6 million and $208.2 million, respectively,
in oil and gas property acquisition, exploration and development activities.
The Company currently anticipates spending approximately $210 million in
exploration and development activities in 2000. The expenditure amounts for
1997 do not include non-cash acquisition costs aggregating an additional $366.8
million which were funded primarily through the issuance of Common Stock,
Preferred Stock, warrants and options, and the assumption of debt. Variations
in capital expenditure levels over the three-year period are primarily tied to
the amount of proved property acquisitions made in each year. See
"--Commitments and Capital Expenditures." Certain of these investments include
expenditures which under successful efforts accounting are expensed as incurred
or if unsuccessful in discovering new reserves.
26
Investing activities for the years ended December 31, 1999, 1998 and 1997,
include $6.6 million, $30.5 million and $6.7 million, respectively, of costs
which have been expensed as exploration costs in the statement of operations
for the corresponding periods. For the three-year period, cash flows from
operating activities were $181.6 million, $147.4 million and $129.8 million,
representing 109%, 69% and 62%, respectively, of the net cash oil and gas
property investments made in each year. Substantially all of the cash flows
from operating activities are generated from oil and gas sales which are highly
dependent upon oil and gas prices. Significant decreases in the market prices
of oil or gas could result in reductions of cash flows from operating
activities, which in turn could impact the amount of capital investment. A
portion of this price risk and cash flow volatility has been hedged by
Fixed-Price Contracts. See "Item 7A--Quantitative and Qualitative Disclosures
About Market Risk--Fixed-Price Contracts." The growth achieved in cash flows
from operating activities over this period is discussed under "--Results of
Operations--Fiscal Year 1999 Compared to Fiscal Year 1998" and "--Results of
Operations--Fiscal Year 1998 Compared to Fiscal Year 1997."
Cash flows from financing activities were a significant source of funding
for the Company's investing activities in 1998 and 1997. Historically, the
Company has relied upon availability under various revolving bank credit
facilities and proceeds from the issuance of senior and subordinated notes to
fund its investing activities. For the year ended December 31, 1999, the
Company reduced its borrowings under such facilities by $41.6 million. For the
two years ended December 31, 1998 and 1997, net amounts borrowed under such
facilities were $31.7 million and $95.7 million, or 15% and 46%, respectively,
of the net cash oil and gas investments made for each year. The Company's debt
facilities are discussed in greater detail below. In addition, the Company
received $44.2 and $40.1 million from the termination of two Fixed-Price
Contracts in 1999 and 1998, respectively.
The Company's EBITDAX increased to $213.0 million in 1999 from $183.8
million in 1998 and $164.9 million in 1997. EBITDAX is defined herein as income
(loss) before interest, income taxes, DD&A, impairment, exploration costs and
change in derivative fair value. Increases in EBITDAX have occurred primarily
as a result of increases in the Company's oil and gas sales. The Company
believes that EBITDAX is a financial measure commonly used in the oil and gas
industry as an indicator of a company's ability to service and incur debt.
However, EBITDAX should not be considered in isolation or as a substitute for
net income, cash flows provided by operating activities or other data prepared
in accordance with generally accepted accounting principles, or as a measure of
a company's profitability or liquidity. EBITDAX measures as presented herein
may not be comparable to other similarly titled measures of other companies.
$450 Million Revolving Credit Facility. The Company has a revolving credit
facility (the "Credit Facility") with a syndicate of banks which provides up to
$450 million in borrowings (the "Commitment"). Letters of credit under the
Credit Facility are limited to $75 million of such availability. The Credit
Facility allows the Company to draw on the full $450 million credit line
without restrictions tied to periodic revaluations of its oil and gas reserves
provided the Company continues to maintain an investment grade credit rating
from either Standard & Poor's Ratings Service or Moody's Investors Service. A
borrowing base can be required only upon the vote by a majority in interest of
the lenders after the loss of an investment grade credit rating. No principal
payments are required under the Credit Facility prior to maturity on October
14, 2002. The Company has relied upon the Credit Facility to provide funds for
acquisitions and to provide letters of credit to meet the Company's margin
requirements under Fixed-Price Contracts. See "Item 7A--Quantitative and
Qualitative Disclosures About Market Risk--Fixed-Price Contracts." As of
December 31, 1999, the Company had $255.6 million of principal and $2.8 million
of letters of credit outstanding under the Credit Facility.
The Company has the option of borrowing at a LIBOR-based interest rate or
the Base Rate (approximating the prime rate). The LIBOR interest rate margin
and the facility fee payable under the Credit Facility are subject to a sliding
scale based on the Company's senior debt credit rating. At December 31, 1999
the applicable interest rate was LIBOR plus 30 basis points. The Credit
Facility also requires the payment of a facility fee equal to 15 basis points
of the Commitment. At December 31, 1999, the average interest rate for
borrowings under the Credit Facility was 6.5%. The effective interest rate
including the effect of interest rate swaps was 5.9%.
The Credit Facility contains various affirmative and restrictive covenants
which, among other things, limit total indebtedness to $700 million ($625
million of senior indebtedness) and require the Company to meet certain
financial tests. Borrowings under the Credit Facility are unsecured.
Other Lines of Credit. The Company has certain other unsecured lines of
credit available to it, which aggregated $30.1 million as of December 31, 1999.
Such short-term lines of credit are primarily used to meet margin requirements
under Fixed-Price Contracts and for working capital purposes. At December 31,
1999, the Company had no indebtedness and $.1 million of letters of credit
outstanding under these credit lines.
6-7/8% Senior Notes due 2007. In December 1997, the Company issued $200
million principal amount, $198.8 million net of discount, of 6-7/8% Senior Notes
due 2007 (the "Senior Notes"). Interest is payable semi-annually on June 1 and
December 1.
27
The associated indenture agreement contains restrictive covenants which place
limitations on the amount of liens and the Company's ability to enter into sale
and leaseback transactions.
9-1/4% Senior Subordinated Notes due 2004. In June 1994, the Company issued
$100 million principal amount, $98.5 million net of discount, of 9-1/4% Senior
Subordinated Notes due 2004 (the "Subordinated Notes"). Interest is payable
semi-annually on June 15 and December 15. The associated indenture agreement
contains restrictive covenants which limit, among other things, the prepayment
of the Subordinated Notes, the incurrence of additional indebtedness, the
payment of dividends and the disposition of assets.
At December 31, 1999, the Company had working capital of $1.8 million and
a current ratio of 1.0 to 1. Total long-term debt outstanding at December 31,
1999 was $555.2 million. The Company's long-term debt as a percentage of its
total capitalization was 53%. The amount of required principal payments for the
next five years and thereafter as of December 31, 1999 is as follows: 2000--$0;
2001--$0; 2002--$255.6 million; 2003--$0; 2004--$100 million; thereafter--$200
million. The Company believes that the borrowing capacity under its existing
credit facilities, combined with the Company's internal cash flows, will be
adequate to finance the capital expenditure program budgeted for 2000 and to
meet the Company's margin requirements under its Fixed-Price Contracts. See
"--Commitments and Capital Expenditures" and "Item 7A--Quantitative and
Qualitative Disclosures About Market Risk--Fixed-Price Contracts--Margin."
See "Item 7A--Quantitative and Qualitative Disclosures About Market
Risk--Interest Rate Sensitivity" for a discussion of the interest rate swaps
hedging the interest rate exposure associated with borrowings under the Credit
Facility.
Commitments and Capital Expenditures
The Company's business strategy is to generate strong and consistent growth in
reserves, production, operating cash flows and earnings through a program of
exploration and development drilling and strategic acquisitions of oil and gas
properties. For the year ended December 31, 1999, the Company invested $114.9
million in development activities, $28.6 million in exploration activities and
$34.8 million in proved reserve acquisitions in connection with this strategy.
In addition, the Company received $12.4 million in connection with sales of
certain oil and gas properties. The Company's 1999 drilling program resulted in
the drilling of 229 gross (181 net) wells, including 16 gross (11 net)
exploratory wells and 213 gross (170 net) development wells. The Company's
drilling activities added 208 Bcfe to its proved reserve base. Reserves added
through 1999 acquisitions aggregated 41 Bcfe. Property sales for 1999 resulted
in the divestiture of 11 Bcfe.
The Company's approved drilling budget for 2000 provides for approximately
$210 million in oil and gas exploration and development activities. Of these
expenditures, approximately $150 million is targeted for development activities
and $60 million is directed to exploration activities to be conducted in its
Core Areas. Actual levels of exploration and development expenditures may vary
due to many factors, including drilling results, new drilling opportunities,
drilling rig availability, oil and natural gas prices and acquisition
opportunities. See "--Outlook for 2000." The Company continues to actively
search for attractive oil and gas property acquisitions, but is not able to
predict the timing or amount of capital expenditure which may ultimately be
employed in acquisitions during 2000.
In the ordinary course of its business, the Company may contract for
drilling or other services for extended periods of time, but generally less
than 12 months, or may enter into agreements for oil and gas lease acreage
which require a certain level of drilling activity to maintain its lease
position. Such arrangements are common to the Company's industry.
Outlook for Fiscal Year 2000
General. The discussion of the Company's fiscal year 2000 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, 1999, and other information currently available to
management. Forward-Looking Statements include statements regarding the
Company's future drilling plans and objectives, and related exploration and
development budgets, and number and location of planned wells, and statements
regarding the quality of the Company's properties and potential reserve and
production levels. These statements may be preceded or followed by, or
otherwise include the words "believes", "expects", "anticipates", "intends",
"plans", "estimates", "projects", or similar expressions or statements that
certain events "will" or "may" occur. These statements assume, among other
things, that no significant changes will occur in the operating environment for
the Company's oil and gas properties and that there will be no material
acquisitions or divestitures except as disclosed herein. The Company cautions
that the Forward-Looking Statements are subject to all the risks and
uncertainties incident to the acquisition, exploration, development and
marketing of oil and gas reserves. These risks include, but are not limited to,
commodity price, counterparty, environmental, drilling, reserves, operations
and production risks. Certain of these risks are described elsewhere herein.
Moreover, the Company may make material acquisitions or divestitures, modify
its Fixed-Price Contract positions by entering into new contracts or
terminating existing contracts, or enter into financing transactions. None of
these can be predicted with certainty and are not taken into consideration in
the Forward-Looking Statements made herein. Statements concerning Fixed-Price
Contract, interest rate swap and other financial instrument fair values and
their estimated con-
28
tribution to future results of operations are based upon market information as
of a specific date. This market information is often a function of significant
judgment and estimation. Further, market prices for oil and gas and market
interest rates are subject to significant volatility. For all of these reasons,
actual results may vary materially from the Forward-Looking Statements and
there is no assurance that the assumptions used are necessarily the most
likely. The Company expressly disclaims any obligation or undertaking to
release publicly any updates regarding any changes in the Company's
expectations with regard to the subject matter of any Forward-Looking
Statements or any changes in events, conditions or circumstances on which any
Forward-Looking Statements are based.
Production. The Company's drilling budget approved by the Board of
Directors for 2000 is $210 million. Based on this expenditure level, the
inventory of drilling opportunities identified for 2000, internal production
forecasts for developed and undeveloped properties and historical Finding Cost
results, the Company expects continued growth in total oil and gas production
for 2000, although there can be no assurance. The amount of drilling
expenditures actually committed during 2000 is subject to revision. An extended
low price environment for oil and gas may result in lower drilling expenditures
to prevent leverage from increasing. This, in turn, would be expected to result
in less oil and gas production for the year.
Oil and Gas Prices. The Company's Fixed-Price Contracts in 2000 are
expected to provide average fixed prices of $2.40 per Mcf for its hedged
natural gas and $23.40 per Bbl for its hedged crude oil before consideration of
basis. Oil and gas sales will also include $13.3 million of gains from the
amortization of deferred gains from price-risk management activities recorded
net of tax in accumulated other comprehensive income. See "Item
7A--Quantitative and Qualitative Disclosures About Market Risk--Fixed-Price
Contracts." As of December 31, 1999, the Company's Fixed-Price Contracts hedge
52 Bcfe of oil and gas production in 2000 (considering fixed-price collar
volumes at the floor price). No plans currently exist to increase or decrease
the amount of hedged production volumes for 2000; 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 2000. For 1999, average monthly wellhead prices
for its natural gas ranged from $1.59 per Mcf to $2.93 per Mcf and oil prices
varied from $10.07 per Bbl to $24.81 per Bbl. Because less than 50% of the
Company's estimated 2000 production is hedged by Fixed-Price Contracts, the
Company's 2000 oil and gas revenues are highly sensitive to commodity price
changes.
Change in Derivative Fair Value. Amounts recorded in this caption include
(1) the ineffective portion of any of the Company's cash flow hedges as
measured on a quarterly basis, (2) the change in fair value for any derivative
that does not meet the specific cash flow hedge criteria of SFAS 133 and (3)
the reversal of amounts previously recorded as gains or losses in this caption
as actual cash settlements are realized under its contracts. The Company
expects to reverse approximately $8.4 million of previously recognized net
gains during 2000. Other amounts that may be included in this caption cannot be
predicted.
Other Income. The Company is unaware of any material amounts expected to
affect this caption in 2000. Other sources of miscellaneous income are expected
to be comparable to prior year results.
Operating Costs. On an equivalent unit of production basis, lifting costs
are anticipated to approximate with the historical results for 1999. This
performance is somewhat dependent upon the growth in production discussed
above. Production taxes are expected to be incurred at an average rate of 5% to
6% of wellhead oil and gas sales.
General and Administrative Expense. Estimated G&A costs for 2000 are
expected to approximate 1999's results on an equivalent unit of production
basis.
Exploration Costs. The Company expects to commit approximately $60 million
of its 2000 capital expenditure budget to exploration drilling, leasehold, and
G&G costs. Under the successful efforts method of accounting, the costs
associated with unsuccessful exploration wells are expensed. All G&G costs
(budgeted at $9 million for 2000) are expensed as incurred, regardless of
ultimate success in the discovery of new reserves. Remaining exploration costs
to be expensed in 2000 will depend on the Company's exploratory drilling
results. The amount of actual exploration expenditures committed during 2000 is
subject to revision based, in part, on changes in expected 2000 operating cash
flows. See "Production" above.
Depreciation, Depletion and Amortization. The Company expects the DD&A
rate for 2000 to approximate the 1999 rate. The Company's fourth quarter rate
was $.90 per Mcfe based upon the Company's year-end reserve position. The
Company will be subject to fluctuation in its DD&A rate as production from
certain significant properties varies in relation to total production.
Impairment. Impairment recognition is subject to many factors, including
oil and gas prices, revisions to reserve estimates and the cost of future
reserve additions. Many of these factors are beyond the Company's ability to
control or predict; consequently, the timing and amount of future impairments,
if any, is unknown. Weakening of oil and gas prices could result in future
impairment recognition.
29
Interest Expense. The Company plans for its capital expenditure levels in
2000 to approximate its operating cash flows for the year. Consequently,
average outstanding indebtedness is expected to remain relatively constant with
1999's year-end debt balance and interest expense is anticipated to approximate
1999's results. See "Item 7A--Quantitative and Qualitative Disclosures About
Market Risk--Interest Rate Sensitivity" for interest rate information for the
Company's indebtedness.
Income Taxes. The Company expects, based on its estimated tax attributes
at December 31, 1999, that its income tax provision for 2000 will result in an
effective rate approximating statutory rates. However, declines in oil and gas
prices could impact the Company's ability to utilize its net operating loss
carryforwards, which would have an adverse effect on the tax provision for
2000. The Company anticipates utilization of $10.0 million of net operating
loss carryforwards in 2000.
Year 2000 Compliance
The Company experienced no significant consequence of any kind related to
internal or external year 2000 computer and business system compliance issues.
All systems requiring remediation were appropriately addressed in 1999. The
cost of such remediation was immaterial.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
General
The Company's results of operations and operating cash flows are impacted by
changes in market prices for oil and gas and changes in market interest rates.
To mitigate a portion of its exposure to adverse market changes, the Company
has entered into Fixed-Price Contracts and interest rate swaps. All of the
Company's Fixed-Price Contracts and interest rate swaps have been entered into
as hedges of oil and gas price risk or interest rate risk and not for trading
purposes. Information regarding the Company's market exposures, Fixed-Price
Contracts, interest rate swaps and certain other financial instruments is
provided below. All information is presented in U.S. Dollars.
Fixed-Price Contracts
Description of Contracts. The Company has entered into Fixed-Price Contracts to
reduce its exposure to unfavorable changes in oil and gas prices which are
subject to significant and often volatile fluctuation. The Company's
Fixed-Price Contracts are comprised of long-term physical delivery contracts,
energy swaps, collars and basis swaps. These contracts allow the Company to
predict with greater certainty the effective oil and gas prices to be received
for its hedged production and benefit the Company when market prices are less
than the fixed prices provided in its Fixed-Price Contracts. However, the
Company will not benefit from market prices that are higher than the fixed
prices in such contracts for its hedged production. For the years ended
December 31, 1999, 1998 and 1997, Fixed-Price Contracts hedged 55%, 50% and
60%, respectively, of the Company's gas production and 19%, 16% and 33%,
respectively, of its oil production. As of December 31, 1999, Fixed-Price
Contracts are in place to hedge 52 Bcfe of future oil and gas production in
2000, and 133 Bcfe thereafter.
For energy swap 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. The fixed-price payment and the floating-price payment are
netted, resulting in a net amount due to or from the counterparty. For physical
delivery contracts, the Company purchases gas in the spot market at floating
market prices and delivers such gas to the contract counterparty at a fixed
price. The Company's natural gas collars contain a fixed floor price (put) and
ceiling price (call). If the market price of natural gas exceeds the call
strike price or falls below the put strike price, then the Company receives the
fixed price and pays the market price. If the market price of natural gas is
between the call and the put strike price, then no payments are due from either
party. Under the Company's basis swaps, the Company receives the floating
market price for NYMEX futures and pays the floating market price plus a fixed
differential for a specified regional spot market index.
30
The following table summarizes the estimated volumes, fixed prices,
fixed-price sales and future net revenues attributable to the Company's
Fixed-Price Contracts as of December 31, 1999. The Company expects the prices
to be realized for its hedged production to vary from the prices shown in the
following table due to basis, which is the differential between the floating
price paid under each energy swap contract, or the cost of gas to supply
physical delivery contracts, and the price received at the wellhead for the
Company's production. Basis differentials are caused by differences in
location, quality, contract terms, timing and other variables. Future net
revenues for any period are determined as the differential between the fixed
prices provided by Fixed-Price Contracts and forward market prices as of
December 31, 1999, as adjusted for basis. Future net revenues change with
changes in market prices and basis. See "--Market Risk."
Years Ending December 31, Balance
--------------------------------------------------------- through
2000 2001 2002 2003 2004 2017 Total
- -----------------------------------------------------------------------------------------------------------------------
(dollars in thousands, except price data)
Natural Gas Swaps:
Contract volumes (BBtu) 19,460 7,475 6,405 5,650 5,650 12,133 56,773
Weighted-average fixed price
per MMBtu (1) $ 2.46 $ 2.47 $ 2.67 $ 2.92 $ 3.12 $ 3.36 $ 2.79
Future fixed-price sales $ 47,950 $18,446 $17,098 $16,492 $17,608 $ 40,821 $158,415
Future net revenues (2) $ 1,699 $ (117) $ 1,053 $ 2,194 $ 3,111 $ 8,686 $ 16,626
Natural Gas Physical Delivery
Contracts:
Contract volumes (BBtu) 16,633 17,211 17,086 14,216 6,030 41,321 112,497
Weighted-average fixed price
per MMBtu (1) $ 2.29 $ 2.36 $ 2.43 $ 2.50 $ 2.45 $ 2.93 $ 2.59
Future fixed-price sales $ 38,081 $40,628 $41,568 $35,477 $14,788 $121,209 $291,751
Future net revenues (2) $ (492) $ (576) $ 326 $ 725 $ (368) $ 6,023 $ 5,638
Natural Gas Collars:
Contract volumes (BBtu):
Floor 9,630 -- -- -- -- -- 9,630
Ceiling 19,260 -- -- -- -- -- 19,260
Weighted-average fixed-price
per MMBtu (1):
Floor $ 2.48 $ -- $ -- $ -- $ -- $ -- $ 2.48
Ceiling $ 2.80 $ -- $ -- $ -- $ -- $ -- $ 2.80
Future fixed-price sales (at floor) $ 23,882 $ -- $ -- $ -- $ -- $ -- $ 23,882
Future net revenues (2) $ 1,323 $ -- $ -- $ -- $ -- $ -- $ 1,323
Total Natural Gas Contracts (3):
Contract volumes (BBtu) 45,723 24,686 23,491 19,866 11,680 53,454 178,900
Weighted-average fixed price
per MMBtu (1) $ 2.40 $ 2.39 $ 2.50 $ 2.62 $ 2.77 $ 3.03 $ 2.65
Future fixed-price sales $109,913 $59,074 $58,666 $51,969 $32,396 $162,030 $474,048
Future net revenues (2) $ 2,530 $ (693) $ 1,379 $ 2,919 $ 2,743 $ 14,709 $ 23,587
Crude Oil Swaps:
Contract volumes (MBbls) 1,001 -- -- -- -- -- 1,001
Weighted-average fixed price
per Bbl (1) $ 23.40 $ -- $ -- $ -- $ -- $ -- $ 23.40
Future fixed-price sales $ 23,423 $ -- $ -- $ -- $ -- $ -- $ 23,423
Future net revenues (2) $ 377 $ -- $ -- $ -- $ -- $ -- $ 377
=======================================================================================================================
(1) The Company expects the prices to be realized for its hedged production to
vary from the prices shown due to basis. See "--Market Risk."
(2) Future net revenues as presented above are undiscounted and have not been
adjusted for contract performance risk or counterparty credit risk.
(3) Does not include basis swaps with notional volumes by year, as follows:
2000-21.3 TBtu; 2001-9.4 TBtu; and 2002-5.5 TBtu.
31
The estimates of future net revenues from the Company's Fixed-Price
Contracts are computed based on the difference between the prices provided by
the Fixed-Price Contracts and forward market prices as of the specified date.
The market for natural gas beyond a five year horizon is illiquid and published
market quotations are not available. The Company has relied upon near-term
market quotations, longer-term over-the-counter market quotations and other
market information to determine its future net revenue estimates. Forward
market prices for natural gas are dependent upon supply and demand factors in
such forward market and are subject to significant volatility. The future net
revenue estimates shown above are subject to change as forward market prices
change.
The estimated fair value and carrying value of the Company's Fixed-Price
Contracts as of December 31, 1999 and 1998 are provided below.
December 31, 1999 December 31, 1998
------------------------- --------------------------
Estimated Carrying Estimated Carrying
Fair Value Value Fair Value Value
- --------------------------------------------------------------------------------------------------------------
(in thousands)
Derivative assets:
Fixed-price natural gas swaps:
Sales contracts $ 16,433 $ 16,433 $ 26,125 $ 26,125
Purchase contracts -- -- 905 905
Fixed-price natural gas collars 1,323 1,323 3,367 3,367
Fixed-price natural gas physical delivery contracts 7,921 7,921 99,342 99,342
Natural gas basis swaps -- -- 74 74
Fixed-price crude oil swaps 360 360 -- --
Derivative liabilities:
Fixed-price natural gas swaps--sales contracts (4,329) (4,329) (551) (551)
Fixed-price natural gas physical delivery contracts (9,081) (9,081) (2,920) (2,920)
Natural gas basis swaps (3,271) (3,271) (3,734) (3,734)
- --------------------------------------------------------------------------------------------------------------
Total $ 9,356 $ 9,356 $122,608 $122,608
==============================================================================================================
The fair value of Fixed-Price Contracts as of December 31, 1999 and 1998
was estimated based on market prices of natural gas and crude oil for the
periods covered by the contracts. The net differential between the prices in
each contract and market prices for future periods, as adjusted for estimated
basis, has been applied to the volumes stipulated in each contract to arrive at
an estimated future value. This estimated future value was discounted on a
contract-by-contract basis at rates commensurate with the Company's estimation
of contract performance risk and counterparty credit risk. The terms and
conditions of the Company's fixed-price physical delivery contracts and certain
financial swaps are uniquely tailored to the Company's circumstances. In
addition, the determination of market prices for natural gas beyond a five year
horizon is subject to significant judgment and estimation. As a result, the
Fixed-Price Contract fair value as reflected in the balance sheet as of
December 31, 1999 and 1998 does not necessarily represent the value a third
party would pay to assume the Company's positions.
Accounting. In October 1998, the Company adopted SFAS 133 which
establishes new accounting and reporting guidelines for derivative instruments
and hedging activities. It requires that all derivative instruments be
recognized as assets or liabilities in the statement of financial position,
measured at fair value. The accounting for changes in the fair value of a
derivative depends on the intended use of the derivative and the resulting
designation. Designation is established at the inception of a derivative, but
redesignation is permitted. For derivatives designated as cash flow hedges,
changes in fair value are recognized in other comprehensive income until the
hedged item is recognized in earnings. Hedge effectiveness is to be measured at
least quarterly based on the relative changes in fair value between the
derivative contract and the hedged item over time. Any change in fair value
resulting from ineffectiveness, as defined by SFAS 133, is recognized
immediately in earnings. Changes in fair value for contracts which do not meet
the SFAS 133 cash flow hedge definition are also recognized in earnings.
Substantially all of the Company's Fixed-Price Contracts and interest rate
swaps are designated as cash flow hedges. For the period from October 1, 1998
to January 13, 1999, the change in fair value of all derivative contracts was
recognized in results of operations. See "Item 7--Management's Discussion and
Analysis of Financial Condition and Results of Operations--Results of
Operations--Fiscal Year 1999 Compared to Fiscal Year 1998--Change in Derivative
Fair Value."
All of the Company's Fixed-Price Contracts have been executed in
connection with its natural gas and crude oil hedging program. For these
contracts 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. The fair value of all of its Fixed-Price Contracts are recorded as
assets or liabilities in the Company's balance sheet.
32
If a Fixed-Price Contract which qualified for cash flow hedge accounting
is liquidated or sold prior to maturity, the gain or loss at the time of
termination remains in accumulated other comprehensive income to be amortized
into oil and gas sales over the original term of the contract. The Company had
pretax unamortized deferred gains of $99.7 million and $61.3 million as of
December 31, 1999 and 1998, respectively, related to terminated contracts which
were recorded net of deferred tax effects in accumulated other comprehensive
income. Prepayments received under Fixed-Price Contracts with continuing
performance obligations are recorded as deferred revenue and amortized into oil
and gas sales over the term of the underlying contract.
For the years ended December 31, 1999, 1998 and 1997, oil and gas sales
included $1.5 million of net gains, $23.1 million of net gains and $4.3 million
of net losses, respectively, associated with realized gains and losses under
its Fixed-Price Contracts.
Credit Risk. Fixed-Price Contract terms generally provide for monthly
settlements and energy swaps provide for a net settlement due to or from the
respective party, as discussed previously. The counterparties to the contracts
are comprised of independent power producers, pipeline marketing affiliates,
financial institutions, a municipality and S.A. Louis Dreyfus et Cie, among
others. In some cases, the Company requires letters of credit or corporate
guarantees to secure the performance obligations of the contract counterparty.
Should a counterparty to a contract default on a contract, there can be no
assurance that the Company would be able to enter into a new contract with a
third party on terms comparable to the original contract. The Company has not
experienced non-performance by any counterparty.
Cancellation or termination of a Fixed-Price contract subjects a greater
portion of the Company's gas production to market prices, which, in a low price
environment, could have an adverse effect on the Company's future operating
results. In addition, the associated carrying value of the contract would be
removed from the Company's balance sheet.
The Company was a party to two Fixed-Price Contracts, both long-term
physical delivery contracts, with independent power producers ("IPPs") which
sold electrical power under firm, fixed-price contracts to Niagara Mohawk
Corporation ("NIMO"), a New York state utility ("NIMO Contracts"). The ability
of these IPPs to perform their obligations to the Company was dependent on the
continued performance by NIMO of its power purchase obligations to the
counterparties. NIMO had taken aggressive regulatory, judicial and contractual
actions in recent years seeking to curtail power purchase obligations,
including its obligations to the NIMO Contract counterparties, and had further
stated that its future financial prospects were dependent on its ability to
resolve these obligations, along with other matters. In July 1997, NIMO entered
into a Master Restructuring Agreement (the "MRA") with 16 IPPs, including the
NIMO Contract counterparties. Subsequently, one of the NIMO Contract
counterparties withdrew from the MRA. The power purchase agreement between NIMO
and the other counterparty was terminated. In connection therewith, the Company
agreed in June 1998 to terminate its Fixed-Price Contract to the counterparty
in exchange for $40.1 million. The associated realized gain has been recorded
in accumulated other comprehensive income, net of tax effect. In settlement of
litigation initiated by NIMO against the remaining NIMO counterparty, an
agreement was reached in late October 1999 between the respective parties to
terminate the power contract in exchange for a cash payment from NIMO. In
connection with this agreement, the Company agreed to the termination of its
contract with the IPP in exchange for a cash payment to the Company of $44.2
million. The associated realized gain has been recorded in accumulated other
comprehensive income, net of tax.
Market Risk. 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, 1999, 1998 and 1997, the Company received on an Mcf
basis approximately 6%, 6% and 1% less than the prices specified in its natural
gas Fixed-Price Contracts, respectively, due to basis. For its oil production
hedged by crude oil Fixed-Price Contracts, the Company realized approximately
7%, 10% 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 2000 represents a $1.1
million change in gas sales. A 1% move in price realization for hedged oil
production in 2000 represents a $.2 million 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.
Except for the effect of basis movements, the Company expects that any
changes in Fixed-Price Contract fair value attributable to changes in market
prices for natural gas will be offset by changes in the value of its natural
gas reserves. This change in natural gas reserve value, however, is not
reflected in the Company's balance sheet. Further, changes in future gains and
losses to be realized in oil and gas sales upon cash settlements of Fixed-Price
Contracts resulting from changes in market prices for oil and natural gas are
expected to be offset by changes in the price received for the Company's hedged
oil and natural gas production. Because the majority of the Company's future
estimated oil and gas production is unhedged, declining oil and gas prices
could have a material adverse effect on the Company's future results of
operations and operating cash flows.
33
Margin. The Company is required to post margin in the form of bank letters
of credit or treasury bills under certain of its Fixed-Price Contracts. In some
cases, the amount of such margin is fixed; in others, the amount changes as the
market value of the respective contract changes, or if certain financial tests
are not met. For the years ended December 31, 1999, 1998 and 1997, the maximum
aggregate amount of margin posted by the Company was $23.5 million, $23.7
million and $28.7 million, respectively. In connection with the termination of
the NIMO Contract in December 1999, $15 million of margin and 29 Bcfe of
mortgaged reserves were permanently released by the counterparty. See "--Credit
Risk." 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, 1999, the Company had issued margin in the form of letters of credit
totaling $2.0 million.
Interest Rate Sensitivity
The Company has entered into interest rate swaps to hedge the interest rate
exposure associated with borrowings under the Credit Facility. As of December
31, 1999, the Company had fixed the interest rate on average notional amounts
of $125 million, $125 million and $94 million for the years ended December 31,
2000, 2001 and 2002, respectively. Under the interest rate swaps, the Company
receives the LIBOR three-month rate (6.0% at December 31, 1999) and pays an
average rate of 5.0% for each period covered by the swaps. The notional amounts
are less than the maximum amount anticipated to be available under the Credit
Facility in such years.
For each interest rate swap, the differential between the fixed rate and
the floating rate multiplied by the notional amount is the swap gain or loss.
Such gain or loss is included in interest expense in the period for which the
interest rate exposure was hedged. Pursuant to SFAS 133, if an interest rate
swap qualifying as a cash flow hedge is liquidated or sold prior to maturity,
the gain or loss on the interest rate swap at the time of termination remains
in accumulated other comprehensive income, to be recognized as an adjustment to
interest expense over the original contract term. For the years ended December
31, 1999, 1998 and 1997, interest rate swaps increased interest expense by $.1
million, $.3 million and $.2 million, respectively.
The following table provides information about the Company's interest rate
swaps and certain other financial instruments as of December 31, 1999.
Years Ending December 31, Balance
-------------------------------------------------------------- through
2000 2001 2002 2003 2004 2007 Total
- -------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands)
Expected Maturities of Long-
Term Debt:
Bank debt $ -- $ -- $ 255,600 $ -- $ -- $ -- $ 255,600
Average interest rate (1) 6.8% 7.1% 7.2% -- -- -- 7.0%
Senior Notes $ -- $ -- $ -- $ -- $ -- $ 200,000 $ 200,000
Fixed interest rate 6.9% 6.9% 6.9% 6.9% 6.9% 6.9% 6.9%
Subordinated Notes $ -- $ -- $ -- $ -- $100,000 $ -- $ 100,000
Fixed interest rate 9.3% 9.3% 9.3% 9.3% 9.3% -- 9.3%
Interest Rate Swaps:
Average notional amount by year $125,000 $125,000 $ 94,000 $ -- $ -- $ -- $ 344,000
Average pay rate--fixed 5.0% 5.0% 5.0% -- -- -- 5.0%
Average receive rate--variable (2) 6.5% 6.8% 6.9% -- -- -- 6.7%
===============================================================================================================================
(1) Based on market quotations for interest rates as of December 31, 1999 plus
the appropriate credit spread for the indicated debt instrument. Does not
include commitment fees. See "Item 7--Management's Discussion and Analysis
of Financial Condition and Results of Operations--Capital Resources and
Liquidity."
(2) Based on market quotations for interest rates as of December 31, 1999.
34
The estimated fair value of the Company's interest rate swaps and certain
other financial instruments and the associated carrying value as of December
31, 1999 and 1998 are provided below.
December 31, 1999 December 31, 1998
------------------------------- -------------------------------
Estimated Carrying Estimated Carrying
Fair Value Value Fair Value Value
- -----------------------------------------------------------------------------------------
(in thousands)
Bank debt $ (255,600) $ (255,600) $ (297,200) $ (297,200)
Senior Notes (177,012) (199,034) (187,704) (198,912)
Subordinated Notes (99,591) (100,588) (102,897) (100,732)
Interest rate swaps 5,660 5,660 389 389
- -----------------------------------------------------------------------------------------
Total $ (526,543) $ (549,562) $ (587,412) $ (596,455)
=========================================================================================
The Company's bank debt bears interest at rates which move with market
interest rates. Accordingly, the fair value of such debt at December 31, 1999
and 1998 was estimated to approximate the carrying amount. The fair values of
the 6-7/8% Senior Notes due 2007 and the 9-1/4% Senior Subordinated Notes due
2004 were determined based on market quotations for such securities. The fair
value of the Company's interest rate swaps was based on market interest rates
as of each respective date.
The Company expects that changes in realized interest rate swap gains and
losses attributable to future changes in market interest rates will be offset
by changes in the interest payments hedged by such interest rate swaps. The
fair value of such swaps until settlement will be subject to change as market
interest rates change. Increases in market interest rates would have an adverse
effect on the Company's results of operations since the majority of its bank
debt interest rate exposure is unhedged.
Item 8. Financial Statements and Supplementary Data
The Consolidated Financial Statements and supplementary data of the Company are
set forth on pages F-1 through F-25 inclusive, found at the end of this report.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
35
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 2000 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,
1999.
Item 11. Executive Compensation
The information required under Item 11 will be contained in the Proxy Statement
under the heading "Executive Compensation and Other Information" and is
incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required under Item 12 will be contained in the Proxy Statement
under the heading "Security Ownership of Certain Beneficial Owners and
Management" and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions
The information required under Item 13 will be contained in the Proxy Statement
under the headings "Certain Transactions" and "Executive Compensation and Other
Information--Compensation Committee Interlocks and Insider Participation" and
is incorporated herein by reference.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
(a) The following documents are filed as part of this report:
1. Financial Statements: See Index to Consolidated Financial Statements and
Financial Statement Schedule immediately following the signature page of
this report.
2. Financial Statement Schedule: See Index to Consolidated Financial
Statements and Schedule immediately following the signature page of this
report.
3. Exhibits: The following documents are filed as exhibits to this report,
all of which have been previously filed or incorporated by reference
except as otherwise indicated below.
Exhibit No. Description of Exhibit
- --------------------------------------------------------------------------------
2.1 Agreement and Plan of Reorganization dated as of June 24, 1997, as
amended, between Louis Dreyfus Natural Gas Corp. and American Exploration
Company (incorporated herein by reference to Annex A to Louis Dreyfus
Natural Gas Corp.'s Joint Proxy Statement/Prospectus filed with the
Securities and Exchange Commission on September 12, 1997 pursuant to Rule
424(b)(3) relating to Louis Dreyfus Natural Gas Corp.'s Registration
Statement on Form S-4, Registration No. 333-34849).
3.1 Amended and Restated Certificate of Incorporation of the Registrant
(incorporated by reference to Exhibit 3.1 of the Registrant's
Registration Statement on Form S-1, Registration No. 33-69102).
3.2 Certificate of Merger of the Registrant dated September 9, 1993
(incorporated by reference to Exhibit 3.2 of the Registrant's
Registration Statement on Form S-1, Registration No. 33-69102).
3.3 Amended and Restated Bylaws of the Registrant (incorporated by reference
to Exhibit 3.3 of the Registrant's Registration Statement on Form S-1,
Registration No. 33-69102).
3.4 Certificate of Merger of the Registrant dated November 1, 1993
(incorporated by reference to Exhibit 3.4 of the Registrant's
Registration Statement on Form S-1, Registration No. 33-69102).
4.1 Indenture agreement dated as of June 15, 1994 for $100,000,000 of 9 1/4%
Senior Subordinated Notes due 2004 between Louis Dreyfus Natural Gas
Corp., as Issuer, and Bank of Montreal Trust Company, as Trustee
(incorporated by reference to Exhibit 10.2 of the Registrant's Form 10-Q
for the quarter ended September 30, 1994).
4.2 Indenture agreement dated as of December 11, 1997 for $200,000,000 of
6-7/8% Senior Notes due 2007 between Louis Dreyfus Natural Gas Corp. and
LaSalle National Bank as Trustee (incorporated by reference to Exhibit
4.1 of the Registrant's Registration Statement on Form S-4, Registration
No. 333-45773).
*10.1 Stock Option Plan of Louis Dreyfus Natural Gas Corp. as amended and
restated effective December 1998 (incorporated by reference to Exhibit
10.1 of the Registrant's Form 10-K for the year ended December 31, 1998).
36
Exhibit No. Description of Exhibit
- --------------------------------------------------------------------
10.2 Form of Indemnification Agreement with directors of the Registrant
(incorporated by reference to Exhibit 10.2 of the Registrant's
Registration Statement on Form S-1, Registration No. 33-69102).
10.3 Registration Rights Agreement between the Registrant and Louis Dreyfus
Natural Gas Holdings Corp. (incorporated by reference to Exhibit 10.3 of
the Registrant's Registration Statement on Form S-1, Registration No.
33-76828).
10.4 Amendment dated December 22, 1993 to Registration Rights Agreement
between the Registrant, Louis Dreyfus Natural Gas Holdings Corp. and S.A.
Louis Dreyfus et Cie (incorporated by reference to Exhibit 10.4 of the
Registrant's Registration Statement on Form S-1, Registration No.
33-76828).
10.5 Services Agreement between the Registrant and Louis Dreyfus Holding
Company, Inc. (incorporated by reference to Exhibit 10.5 of the
Registrant's Registration Statement Form S-1, Registration No. 33-76828).
10.6 Credit Agreement dated as of October 14, 1997, among Louis Dreyfus
Natural Gas Corp., as Borrower, Bank of Montreal, as Administrative
Agent, Chase Manhattan Bank, as Syndication Agent, NationsBank of Texas,
N.A., as Documentation Agent, and certain other lenders signatory thereto
(incorporated by reference to Exhibit 10.1 of the Registrant's Form 8-K
dated October 14, 1997).
10.7 Swap Agreement dated November 1, 1993 between the Registrant and Louis
Dreyfus Energy Corp. (incorporated by reference to Exhibit 10.17 of the
Registrant's Registration Statement on Form S-1, Registration No.
33-69102).
*10.8 Amendment to Option Agreement of Simon B. Rich, Jr. (incorporated by
reference to Exhibit 10.14 of the Registrant's Form 10-K for the fiscal
year ended December 31, 1996).
*10.9 Form of Amendment to Outstanding Option Agreements of Employees
(incorporated by reference to Exhibit 10.15 of the Registrant's Form 10-K
for the fiscal year ended December 31, 1996).
*10.10 Form of Amendment to Outstanding Option Agreements of Non-Employee
Directors (incorporated by reference to Exhibit 10.16 of the Registrant's
Form 10-K for the fiscal year ended December 31, 1996).
*10.11 Employment Agreement, dated as of June 24, 1997, between Louis Dreyfus
Natural Gas Corp. and Mark Andrews (incorporated by reference to Exhibit
10.3 to Form 8-K dated June 24, 1997, of American Exploration Company).
*10.12 Form of Change in Control Agreements between Registrant and Messrs. Mark
E. Monroe, Jeffrey A. Bonney, Richard E. Bross, Ronnie K. Irani and Kevin
R. White (incorporated by reference to Exhibit 10.1 of the Registrant's
Form 10-Q for the quarter ended March 31, 1998).
*10.13 Louis Dreyfus Natural Gas Corp. Deferred Stock Trust Agreement dated
April 14, 1998 (incorporated by reference to Exhibit 10.2 of the
Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.14 Deferred Stock Award Agreement dated March 31, 1998 between Registrant
and Mark E. Monroe (incorporated by reference to Exhibit 10.3 of the
Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.15 Deferred Stock Award Agreement dated March 31, 1998 between Registrant
and Richard E. Bross (incorporated by reference to Exhibit 10.4 of the
Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.16 Deferred Stock Award Agreement dated March 31, 1998 between Registrant
and Ronnie K. Irani (incorporated by reference to Exhibit 10.5 of the
Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.17 Deferred Stock Award Agreement dated March 31, 1998 between Registrant
and Kevin R. White (incorporated by reference to Exhibit 10.6 of the
Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.18 Louis Dreyfus Natural Gas Corp. Non-employee Director Deferred Stock
Trust Agreement dated December 1, 1998.
*10.19 Amendment No. 1 to Louis Dreyfus Natural Gas Corp. Deferred Stock Trust
Agreement dated September 30, 1998.
*10.20 Louis Dreyfus Natural Gas Corp. Non-Employee Director Deferred Stock
Compensation Program as adopted effective July 23, 1998.
21.1 List of subsidiaries of the Registrant.
23.1 Consent of Independent Auditors.
37
24.1 Powers of Attorney.
27.1 Financial Data Schedule.
- ---------
* Constitutes a management contract or compensatory plan or arrangement
required to be filed as an exhibit to this report.
Certain of the exhibits to this filing contain schedules which have been
omitted in accordance with applicable regulations. The Registrant
undertakes to furnish supplementally a copy of any omitted schedule to
the Securities and Exchange Commission upon request.
(b) Reports on Form 8-K.
None.
38
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 6, 2000
By: /s/ JEFFREY A. BONNEY
-------------------------------------
Jeffrey A. Bonney
Executive Vice President and Chief
Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signatures Title Date
MARK E. MONROE* President, Chief Executive Officer and Director March 6, 2000
- ----------------------- (principal executive officer)
Mark E. Monroe
RICHARD E. BROSS* Executive Vice President and Director March 6, 2000
- -----------------------
Richard E. Bross
/s/ JEFFREY A. BONNEY Executive Vice President and Chief Financial Officer March 6, 2000
- ----------------------- (principal financial and accounting officer)
Jeffrey A. Bonney
SIMON B. RICH, JR.* Chairman of the Board of Directors March 6, 2000
- -----------------------
Simon B. Rich, Jr.
MARK ANDREWS* Vice Chairman of the Board of Directors March 6, 2000
- -----------------------
Mark Andrews
GERARD LOUIS-DREYFUS* Director March 6, 2000
- -----------------------
Gerard Louis-Dreyfus
E. WILLIAM BARNETT* Director March 6, 2000
- -----------------------
E. William Barnett
DANIEL R. FINN, JR.* Director March 6, 2000
- -----------------------
Daniel R. Finn, Jr.
PETER G. GERRY* Director March 6, 2000
- -----------------------
Peter G. Gerry
JOHN H. MOORE* Director March 6, 2000
- -----------------------
John H. Moore
JAMES R. PAUL* Director March 6, 2000
- -----------------------
James R. Paul
NANCY K. QUINN* Director March 6, 2000
- -----------------------
Nancy K. Quinn
ERNEST F. STEINER* Director March 6, 2000
- -----------------------
Ernest F. Steiner
*By: /s/ JEFFREY A. BONNEY
--------------------
Jeffrey A. Bonney
Attorney-in-fact
39
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, 1999 and 1998 ........................................ F-3
Consolidated Statements of Operations:
Years ended December 31, 1999, 1998 and 1997 ...................... F-4
Consolidated Statements of Stockholders' Equity:
Years ended December 31, 1999, 1998 and 1997 ...................... F-5
Consolidated Statements of Cash Flows:
Years ended December 31, 1999, 1998 and 1997 ...................... F-6
Notes to Consolidated Financial Statements ......................... F-7
Consolidated Financial Statement Schedule
Schedule II--Consolidated Valuation and Qualifying Accounts ......... F-25
All other schedules for which provision is made in the applicable
accounting regulations of the Securities and Exchange Commission are not
required under the related instructions or are inapplicable and therefore have
been omitted.
F-1
Report of Independent Auditors
The Board of Directors and Stockholders
Louis Dreyfus Natural Gas Corp.
We have audited the accompanying consolidated balance sheets of Louis Dreyfus
Natural Gas Corp. (the "Company") as of December 31, 1999 and 1998, and the
related consolidated statements of operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1999. 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 auditing standards generally
accepted in the United States. 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, 1999 and 1998, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended December 31,
1999 in conformity with accounting principles generally accepted in the United
States. 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 Consolidated Financial Statements,
effective October 1, 1998, the Company adopted Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and
Hedging Activities."
ERNST & YOUNG LLP
Oklahoma City, Oklahoma
February 7, 2000
F-2
LOUIS DREYFUS NATURAL GAS CORP.
Consolidated Balance Sheets
(dollars in thousands)
A S S E T S
December 31,
-------------------------------
1999 1998
- -----------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents $ 9,660 $ 2,539
Receivables:
Oil and gas sales 43,782 37,381
Joint interest and other, net 8,923 11,725
Costs reimbursable by insurance -- 7,200
Fixed-price contracts and other derivatives 7,204 23,338
Prepaids and other 4,928 4,572
- -----------------------------------------------------------------------------------------------------------
Total current assets 74,497 86,755
- -----------------------------------------------------------------------------------------------------------
Property and Equipment, at cost, based on successful efforts accounting 1,636,854 1,519,296
Less accumulated depreciation, depletion and amortization (513,715) (434,693)
- -----------------------------------------------------------------------------------------------------------
1,123,139 1,084,603
---------- ----------
Other Assets
Fixed-price contracts and other derivatives 24,493 107,302
Other, net 4,958 5,148
- -----------------------------------------------------------------------------------------------------------
29,451 112,450
- -----------------------------------------------------------------------------------------------------------
$1,227,087 $1,283,808
===========================================================================================================
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 $ 41,216 $ 38,222
Accrued liabilities 12,413 10,696
Revenues payable 14,413 10,940
Fixed-price contracts and other derivatives 4,673 2,292
- -----------------------------------------------------------------------------------------------------------
Total current liabilities 72,715 62,150
- -----------------------------------------------------------------------------------------------------------
Long-Term Debt 555,222 596,844
- -----------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred revenue 13,524 15,551
Fixed-price contracts and other derivatives 12,008 5,350
Deferred income taxes 52,341 65,116
Other 22,495 19,336
- -----------------------------------------------------------------------------------------------------------
100,368 105,353
- -----------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes 7 and 13)
Stockholders' Equity
Preferred stock, par value $.01; 10 million shares authorized; no shares
outstanding -- --
Common stock, par value $.01; 100 million shares authorized; issued and
outstanding, 40,230,880 and 40,109,758 shares, respectively 402 401
Paid-in capital 420,859 419,075
Retained earnings 28,149 6,735
Accumulated other comprehensive income 49,981 93,250
Treasury stock, at cost, 32,139 common shares (609) --
- -----------------------------------------------------------------------------------------------------------
498,782 519,461
- -----------------------------------------------------------------------------------------------------------
$1,227,087 $1,283,808
===========================================================================================================
See accompanying notes to consolidated financial statements.
F-3
LOUIS DREYFUS NATURAL GAS CORP.
Consolidated Statements of Operations
(in thousands, except per share data)
Years Ended December 31,
-------------------------------------------
1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------
Revenues
Oil and gas sales $290,878 $ 271,575 $ 222,016
Change in derivative fair value (442) 17,346 --
Other income 12,170 4,462 10,901
- ---------------------------------------------------------------------------------------------------------------
302,606 293,383 232,917
- ---------------------------------------------------------------------------------------------------------------
Expenses
Operating costs 66,039 66,295 49,169
General and administrative 23,995 25,971 18,855
Exploration costs 14,258 34,543 8,956
Depreciation, depletion and amortization 117,080 131,408 79,325
Impairment 4,877 52,522 75,198
Interest 40,667 40,849 28,737
- ---------------------------------------------------------------------------------------------------------------
266,916 351,588 260,240
- ---------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes and cumulative effect of
accounting change 35,690 (58,205) (27,323)
Income tax provision (benefit) 14,276 (13,924) (11,261)
- ---------------------------------------------------------------------------------------------------------------
Net income (loss) before cumulative effect of accounting change 21,414 (44,281) (16,062)
Cumulative effect of accounting change, net of tax -- 964 --
- ---------------------------------------------------------------------------------------------------------------
Net Income (loss) $ 21,414 $ (43,317) $ (16,062)
===============================================================================================================
Per Share
Net income (loss) before cumulative effect of accounting change $ .53 $ (1.10) $ (.53)
Cumulative effect of accounting change -- .02 --
- ---------------------------------------------------------------------------------------------------------------
Net income (loss)--basic and diluted $ .53 $ (1.08) $ (.53)
- ---------------------------------------------------------------------------------------------------------------
Weighted average number of common shares:
Basic 40,153 40,107 30,233
Diluted 40,389 40,107 30,233
- ---------------------------------------------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
F-4
LOUIS DREYFUS NATURAL GAS CORP.
Consolidated Statements of Stockholders' Equity
(in thousands)
Additional
Preferred Common Paid-In
Stock Stock Capital
- -----------------------------------------------------------------------------
Balance at December 31, 1996 $ -- $278 $197,301
Preferred stock issued in American
Acquisition 21,080 -- --
Preferred stock converted (20,655) 10 16,726
Preferred stock redeemed (425) -- --
Common stock issued in
American Acquisition -- 113 193,964
Exercise of stock options -- -- 497
Warrants and options issued in
American Acquisition -- -- 10,263
Net loss -- -- --
- -----------------------------------------------------------------------------
Balance at December 31, 1997 -- 401 418,751
Comprehensive income:
Net loss -- -- --
Other comprehensive income, net of tax:
Cumulative effect of accounting change -- -- --
Reclassification adjustments--
contract settlements -- -- --
Total comprehensive income -- -- --
Exercise of stock options -- -- 324
- -----------------------------------------------------------------------------
Balance at December 31, 1998 -- 401 419,075
Comprehensive income:
Net income -- -- --
Other comprehensive loss, net of tax:
Change in fixed-price contract and other
derivative fair value -- -- --
Reclassification adjustments--
contract settlements -- -- --
Total comprehensive loss -- -- --
Exercise of stock options -- 1 1,784
Treasury shares purchased -- -- --
- -----------------------------------------------------------------------------
Balance at December 31, 1999 $ -- $402 $420,859
=============================================================================
Accumulated
Other Total
Retained Comprehensive Treasury Stockholders'
Earnings Income Stock Equity
- -------------------------------------------------------------------------------------------------
Balance at December 31, 1996 $ 66,114 $ -- $ -- $ 263,693
Preferred stock issued in American
Acquisition -- -- -- 21,080
Preferred stock converted -- -- -- (3,919)
Preferred stock redeemed -- -- -- (425)
Common stock issued in
American Acquisition -- -- -- 194,077
Exercise of stock options -- -- -- 497
Warrants and options issued in
American Acquisition -- -- -- 10,263
Net loss (16,062) -- -- (16,062)
- -------------------------------------------------------------------------------------------------
Balance at December 31, 1997 50,052 -- -- 469,204
Comprehensive income:
Net loss (43,317) -- -- (43,317)
Other comprehensive income, net of tax:
Cumulative effect of accounting change -- 97,681 -- 97,681
Reclassification adjustments--
contract settlements -- (4,431) -- (4,431)
---------
Total comprehensive income -- -- -- 49,933
Exercise of stock options -- -- -- 324
- -------------------------------------------------------------------------------------------------
Balance at December 31, 1998 6,735 93,250 -- 519,461
Comprehensive income:
Net income 21,414 -- -- 21,414
Other comprehensive loss, net of tax:
Change in fixed-price contract and other
derivative fair value -- (38,881) -- (38,881)
Reclassification adjustments--
contract settlements -- (4,388) -- (4,388)
---------
Total comprehensive loss -- -- -- (21,855)
Exercise of stock options -- -- -- 1,785
Treasury shares purchased -- -- (609) (609)
- -------------------------------------------------------------------------------------------------
Balance at December 31, 1999 $ 28,149 $ 49,981 $ (609) $ 498,782
=================================================================================================
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,
---------------------------------------------
1999 1998 1997
- -------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net income (loss) $ 21,414 $ (43,317) $ (16,062)
Items not affecting cash flows:
Depreciation, depletion and amortization 117,080 131,408 79,325
Impairment 4,877 52,522 75,198
Deferred income taxes 13,745 (14,524) (12,296)
Exploration costs 14,258 34,543 8,956
Change in derivative fair value 442 (17,346) --
Gain on sale of property (398) (166) (8,745)
Other 413 1,799 698
Net change in operating assets and liabilities,
exclusive of amounts acquired:
Accounts receivable 2,897 27,529 (5,598)
Prepaids and other (356) 8,093 (2,059)
Accounts payable 2,994 (23,179) 10,162
Accrued liabilities 717 (6,646) 75
Revenues payable 3,473 (3,278) 192
- -------------------------------------------------------------------------------------------------------
181,556 147,438 129,846
- -------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Exploration and development expenditures (143,521) (222,400) (154,396)
Acquisition of oil and gas properties (34,784) (4,500) (9,118)
Purchase of American Exploration Company -- -- (72,323)
Additions to other property and equipment (1,560) (2,615) (2,650)
Proceeds from sale of property and equipment 12,659 14,413 27,887
Change in other assets (456) (172) (6,003)
- -------------------------------------------------------------------------------------------------------
(167,662) (215,274) (216,603)
- -------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Proceeds from bank borrowings 368,169 475,362 868,037
Repayments of bank borrowings (409,769) (443,662) (928,537)
Proceeds from issuance of senior notes -- -- 198,784
Repayments of subordinated notes -- -- (42,621)
Proceeds from contract termination 44,153 40,136 --
Proceeds from stock options exercised 1,710 324 497
Purchase of treasury shares (609) -- --
Redemption of preferred stock -- -- (4,344)
Change in deferred revenue (2,027) (1,836) (1,662)
Change in gains from price-risk management activities (5,762) (2,321) (2,773)
Change in other long-term liabilities (2,638) (3,166) (2,835)
- -------------------------------------------------------------------------------------------------------
(6,773) 64,837 84,546
- -------------------------------------------------------------------------------------------------------
Change in cash and cash equivalents 7,121 (2,999) (2,211)
Cash and cash equivalents, beginning of year 2,539 5,538 7,749
- -------------------------------------------------------------------------------------------------------
Cash and cash equivalents, end of year $ 9,660 $ 2,539 $ 5,538
=======================================================================================================
See accompanying notes to consolidated financial statements.
F-6
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements
Note 1. Significant Accounting Policies
General. Louis Dreyfus Natural Gas Corp. ("LDNG" or the "Company") is one of
the largest independent natural gas companies in the United States engaged in
the acquisition, development, exploration, production and marketing of natural
gas and crude oil. At December 31, 1999, approximately 52% of the Company's
Common Stock was owned by various subsidiaries of Societe Anonyme Louis Dreyfus
& Cie (collectively "S.A. Louis Dreyfus et Cie"). See Note 6--Transactions with
Related Parties. The accounting policies of LDNG reflect industry practices and
conform to accounting principles generally accepted in the United States. The
more significant of such policies are briefly described below.
Principles of Consolidation and Basis of Presentation. The accompanying
consolidated financial statements include the accounts of LDNG and its
wholly-owned subsidiaries after elimination of all material intercompany
accounts and transactions. Certain reclassifications have been made in the
financial statements for the years ended December 31, 1998 and 1997 to conform
to the financial statement presentation for the year ended December 31, 1999.
Use of Estimates. The preparation of the financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the amounts reported in the
financial statements and accompanying notes. Actual results could differ from
those estimates.
Cash and Cash Equivalents. Cash and cash equivalents consist of all demand
deposits and funds invested in short- term investments with original maturities
of three months or less.
Concentration of Credit Risk. The Company sells oil and natural gas to
various customers, participates with other parties in the drilling, completion
and operation of oil and natural gas wells and enters into long-term energy
swaps and physical delivery contracts. The majority of the Company's accounts
receivable are due from purchasers of oil and natural gas and from fixed-price
contract counterparties. Certain of these receivables are subject to collateral
or margin requirements. The Company has established procedures to monitor
credit risk and has not experienced significant credit losses in prior years.
See Note 13--Derivatives--Credit Risk. As of December 31, 1999 and 1998, the
Company's joint interest and other receivables are shown net of allowance for
doubtful accounts of $1.1 million and $1.2 million, respectively.
Property and Equipment. The Company utilizes the successful efforts method
of accounting for oil and natural gas producing activities. Costs incurred in
connection with the drilling and equipping of exploratory wells are capitalized
as incurred. If proved reserves are not found, such costs are charged to
expense. Other exploration costs, including delay rentals and seismic costs,
are charged to expense as incurred. Development costs, which include the costs
of drilling and equipping development wells, whether successful or
unsuccessful, are capitalized as incurred. All general and administrative costs
are expensed as incurred. Depreciation, depletion and amortization of
capitalized costs of proved oil and gas properties is computed by the
unit-of-production method on a field-by-field basis. The costs of unproved oil
and gas properties are assessed quarterly on a property-by-property basis. If
unproved properties are determined to be productive, the related costs are
transferred to proved oil and gas properties. If unproved properties are
determined not to be productive, or if the value of such properties has been
otherwise impaired, the excess carrying value is charged to expense.
Expenditures made in connection with the Company's drilling program are
presented in the accompanying statement of cash flows as investing activities.
As indicated above, certain of these amounts are expensed as incurred or if
unsuccessful in discovering new reserves. Investing activities for the years
ended December 31, 1999, 1998 and 1997, include $6.6 million, $30.5 million and
$6.7 million, respectively, of costs which have been expensed as exploration
costs in the statement of operations for the corresponding periods.
The Company's oil and gas properties are reviewed on a field-by-field
basis for indications of impairment whenever events or circumstances indicate
that the carrying value of its oil and gas properties may not be recoverable.
In order to determine whether an impairment has occurred, the Company estimates
the expected future net cash flows from its oil and gas properties as of the
date of determination, and compares such future cash flows to the respective
carrying amounts. Such estimated future cash flows are based on proved reserves
and forward market prices for oil and gas that existed as of the date of
determination. Those oil and gas properties which have carrying amounts in
excess of estimated future cash flows are deemed impaired. The carrying value
of impaired properties is adjusted to an estimated fair value by discounting
the estimated expected future cash flows attributable to such properties at a
discount rate estimated to be representative of the market for such properties.
The excess is charged to expense and may not be reinstated. In 1999, the
Company recognized impairment charges aggregating $4.9 million, primarily as
the result of downward revisions to estimated future recoverable reserves from
certain offshore properties identified in the preparation of the year-end
reserve study. Overall, the Company experienced net upward reserve revisions of
approximately 12 Bcfe for 1999. For 1998, the Company recognized impairment
charges aggregating $52.5 million. The associated impairment reviews were
conducted as the result of declining oil and gas prices during
F-7
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
the year which adversely affected the estimated future cash flows from the
Company's oil and gas properties. In 1997, the Company recognized a $75.2
million impairment charge, substantially all of which was recorded in connection
with the acquisition of American Exploration Company, a Houston-based
exploration and production company ("American") in October 1997 (the "American
Acquisition"). The allocation of the American Acquisition purchase price, based
on the relative fair values of the acquired properties, was reviewed for
indications of impairment, resulting in an impairment charge. See Note
3--Acquisitions. Lower oil and gas prices or future downward revisions of
reserve estimates could result in future impairment recognition.
The Company provides for the estimated cost, at current prices, of
dismantling and removing oil and gas production facilities. Such estimated
costs are recorded at discounted values based on the estimated productive lives
of the associated oil and gas property and amortized by the unit-of-production
method. As of December 31, 1999 and 1998, estimated total future dismantling
and restoration costs of $12.1 million and $6.3 million, respectively, were
included in other liabilities in the accompanying balance sheets.
Depreciation of other property and equipment is provided by using the
straight-line method over estimated useful lives of three to 20 years.
Debt Issuance Costs. Debt issuance costs are amortized over the term of
the associated debt instrument using the straight-line method. The unamortized
balance of such costs included in other assets as of December 31, 1999 and
1998, was $3.1 million and $3.7 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 receivable or a liability is recorded to the extent that the
Company's underproduced or overproduced position in a reservoir cannot be
recouped through the production of remaining reserves. At December 31, 1999 and
1998, the Company had recorded imbalance liabilities of $4.0 million and
imbalance receivables of $1.4 million.
Income Taxes. The Company files a consolidated United States income tax
return which includes the taxable income or loss of its subsidiaries. Deferred
federal and state income taxes are provided on all significant temporary
differences between the financial statement carrying amounts of assets and
liabilities and their respective tax bases.
Hedging. The Company reduces its exposure to unfavorable changes in oil
and natural gas prices by utilizing fixed- price physical delivery contracts,
energy swaps, collars, futures contracts, basis swaps and options (collectively
"Fixed- Price Contracts"). The Company also enters into interest rate swap
contracts to reduce its exposure to adverse interest rate fluctuations. In
October 1998, the Company adopted Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS
133") which established new accounting and reporting guidelines for derivative
instruments and hedging activities. It requires that all derivative instruments
be recognized as assets or liabilities in the statement of financial position,
measured at fair value. The accounting for changes in the fair value of a
derivative depends on the intended use of the derivative and the resulting
designation. Designation is established at the inception of a derivative, but
redesignation is permitted. For derivatives designated as cash flow hedges,
changes in fair value are recognized in other comprehensive income until the
hedged item is recognized in earnings. Hedge effectiveness is measured at least
quarterly based on the relative changes in fair value between the derivative
contract and the hedged item over time. Any change in fair value resulting from
ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings.
Substantially all of the Company's Fixed-Price Contracts and interest rate
swaps are designated as cash flow hedges. Changes in the fair value of
derivative instruments which are not designated as cash flow hedges or do not
meet the effectiveness guidelines of SFAS 133 are recorded in earnings as the
changes occur. Fixed-Price Contracts monetized prior to their maturity are
classified as financing activities in the accompanying statements of cash
flows. As indicated below, the change in fair value of all derivative contracts
for the period from October 1, 1998 to January 13, 1999 was recognized in
results of operations.
Adoption of SFAS 133 in October 1998 resulted in the reclassification of
$62.2 million of deferred gains from price-risk management activities and $3.3
million of deferred hedging losses related to terminated contracts to
accumulated other comprehensive income, recorded net of deferred income tax
effects. In addition, adoption resulted in the recognition of $130.6 million of
derivative assets and $7.6 million of derivative liabilities in the Company's
balance sheet as of December 31, 1998. SFAS 133 precludes the consideration of
future cash flows from derivative instruments in asset impairment
determinations irrespective of any risk management intent for entering into
such instruments. Adoption of the standard resulted in an additional impairment
charge of $12.4 million which was included in earnings as a cumulative effect
of an accounting change. Also included in earnings for 1998 as a cumulative
effect of an accounting change are the following: $8.6 million of Fixed--
F-8
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
Price Contract gains associated with the incremental impairment charge, $2.8
million of Fixed-Price Contract gains relating to contracts not qualifying as
cash flow hedges, $1.5 million of Fixed-Price Contract gains relating to
Fixed-Price Contract hedge ineffectiveness, and $1.1 million of net gain
associated with a fair value hedge which hedged a portion of the Company's
subordinated debt. See Note 10--Capital Stock and Stockholders' Equity
Information, Note 12--Financial Instruments and Note 13--Derivatives. The
Company does not hold or issue financial instruments with leveraged features.
Pursuant to the provisions of SFAS 133, all hedging designations and the
methodology for determining hedge ineffectiveness must be documented at the
inception of the hedge, and, upon the initial adoption of the standard, hedging
relationships must be designated anew. The documentation must also indicate the
risk management intent for entering into the hedging arrangement. The Company
believed that it complied with the spirit and intent of the provisions of the
standard with respect to documentation. However, in connection with the review
of the Company's public filings by the Staff of the Securities and Exchange
Commission in September 1999, the Company's documentation was determined to be
insufficient as of the October 1, 1998 date of adoption of SFAS 133. Therefore,
the Company was precluded from utilizing the special provisions of hedge
accounting for the fourth quarter of 1998, and the period from January 1, 1999
to January 13, 1999, the date the Company's documentation was sufficient in
relation to the formal documentation requirements of the standard. As a result,
the changes in fair value of all of the Company's derivatives during this
period were required to be reported in results of operations, rather than in
other comprehensive income.
Although certain of the Company's Fixed-Price Contracts may not qualify as
cash flow hedges under the specific guidelines of SFAS 133, the Company has
continued to refer to these contracts in this document as hedges inasmuch as
this was the intent when such contracts were executed, the characterization is
consistent with the actual economic performance of the contracts, and
management expects the contracts to continue to mitigate its commodity price
risk in the future. The accounting for such contracts, however, is consistent
with the requirements of SFAS 133.
Earnings per Share. The Company follows Statement of Financial Accounting
Standards No. 128, "Earnings per Share", to compute earnings per share. The
increase in potential shares used to determine diluted earnings per share for
the year ended December 31, 1999 is attributable to dilutive stock options.
Stock options were not considered in the diluted earnings per share
calculations for 1998 and 1997 as the effect would be antidilutive. See Note
8--Employee Benefit Plans and Note 10--Capital Stock and Stockholders' Equity
Information for a description of potentially dilutive securities of the
Company.
Stock Options. The Company accounts for employee stock-based compensation
using the intrinsic value method prescribed by Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees", and related
interpretations. No compensation expense is recorded with respect to stock
options granted at prices equal to the market value of the Company's Common
Stock at the date of grant. Upon exercise, the excess of the proceeds over the
par value of the shares issued is credited to additional paid-in capital. See
Note 8--Employee Benefit Plans.
Note 2. Property and Equipment
Capitalized Costs. The Company's oil and gas acquisition, exploration and
development activities are conducted primarily in Texas, Oklahoma, New Mexico
and offshore in the Gulf of Mexico. The following table summarizes the
capitalized costs associated with these activities:
December 31,
-----------------------------
1999 1998
- --------------------------------------------------------------------------------------
(in thousands)
Oil and gas properties:
Proved $1,562,581 $1,434,066
Unproved 39,572 51,304
Accumulated depreciation, depletion and amortization (497,349) (421,164)
- --------------------------------------------------------------------------------------
1,104,804 1,064,206
- --------------------------------------------------------------------------------------
Other property and equipment 34,701 33,926
Accumulated depreciation (16,366) (13,529)
- --------------------------------------------------------------------------------------
18,335 20,397
- --------------------------------------------------------------------------------------
$1,123,139 $1,084,603
======================================================================================
F-9
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
Depreciation, depletion and amortization expense of oil and gas properties
per Mcfe was $.89, $1.04 and $.88 for the years ended December 31, 1999, 1998
and 1997, respectively. Such amounts do not include impairment charges recorded
in each year. See Note 1--Significant Accounting Policies. For the years ended
December 31, 1999, 1998 and 1997, the Company capitalized interest of $2.0
million, $3.3 million and $1.0 million, respectively, in connection with its
exploration and development activities. Depreciation of other property and
equipment was $3.5 million, $4.1 million and $3.2 million for the years ended
December 31, 1999, 1998 and 1997, respectively.
Unproved properties at December 31, 1999 consist primarily of acreage
positions obtained in the American Acquisition. The Company will evaluate such
properties over their respective lease terms or as drilling results are
determined.
Costs Incurred. The following table summarizes the costs incurred in the
Company's acquisition, exploration and development activities for the years
ended December 31, 1999, 1998 and 1997, respectively.
Years Ended December 31,
--------------------------------------
1999 1998 1997
- ---------------------------------------------------------------------
(in thousands)
Property acquisition costs:
Proved $ 36,881 $ 4,088 $349,037
Unproved 10,766 11,815 109,648
- ---------------------------------------------------------------------
47,647 15,903 458,685
Exploration costs 19,409 74,123 21,514
Development costs 116,597 136,462 122,402
- ---------------------------------------------------------------------
$183,653 $226,488 $602,601
=====================================================================
Note 3. Acquisitions
In October 1997, the Company acquired 100% of the outstanding common stock of
American for approximately 11.3 million shares of LDNG Common Stock valued at
$17.15 per share and $47.2 million of cash. In addition, LDNG assumed $116
million of American long-term debt, $20 million liquidation value of American
preferred stock and warrants and options valued at $10.3 million. The
acquisition consisted of 217 Bcfe of proved reserves, approximately 3,500
producing wells, 1.0 million gross acres of developed leasehold, 2.0 million
gross acres of undeveloped leasehold and other assets and liabilities. The
purchase method was used to account for this acquisition.
The following unaudited pro forma results of operations data gives effect
to the American Acquisition as if the transaction had occurred on January 1,
1997. 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 this acquisition closed on this date, or of future
results of operations. The historic information has been adjusted for (1) oil
and gas sales and related operating costs, (2) amortization of oil and gas
properties based on the purchase price, (3) incremental general and
administrative expenses associated with ownership of the properties, and (4)
incremental interest expense resulting from borrowings made under the Credit
Facility, as hereinafter defined, in connection with this acquisition.
Year Ended
December 31,
----------------------
1997
- -------------------------------------------------------------------------
(in thousands, except
per share data)
Unaudited pro forma information:
Revenues $303,719
Net income 16,752
Net income per common share--basic and diluted .43
=========================================================================
The pro forma information for 1997 does not include a $73.1 million
impairment charge incurred as a result of recording the cost of the American
Acquisition, which was in excess of the underlying tangible assets, nor does it
consider the effects of certain cost reduction plans, financing plans or the
effects of certain purchase accounting adjustments.
During 1999, 1998 and 1997, the Company made numerous other acquisitions
of proved oil and gas properties, the net purchase price of which aggregated
$34.8 million, $4.1 million and $9.1 million, respectively. The results of
operations related to such acquisitions have been included in the accompanying
statements of operations and cash flows for the periods subsequent to the
closing of each transaction.
F-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,
-------------------------
1999 1998
- -----------------------------------------------------------------------
(in thousands)
Bank Debt:
$450 Million Revolving Credit Facility $255,600 $295,000
Other Lines of Credit -- 2,200
- -----------------------------------------------------------------------
255,600 297,200
6-7/8% Senior Notes due 2007 199,034 198,912
9-1/4% Senior Subordinated Notes due 2004 100,588 100,732
- -----------------------------------------------------------------------
$555,222 $596,844
=======================================================================
$450 Million Revolving Credit Facility. The Company has a revolving credit
facility (the "Credit Facility") with a syndicate of banks which provides up to
$450 million in borrowings (the "Commitment"). Letters of credit under the
Credit Facility are limited to $75 million of such availability. The Credit
Facility allows the Company to draw on the full $450 million credit line
without restrictions tied to periodic revaluations of its oil and gas reserves
provided the Company continues to maintain an investment grade credit rating
from either Standard & Poor's Ratings Service or Moody's Investors Service. A
borrowing base can be required only upon the vote by a majority in interest of
the lenders after the loss of an investment grade credit rating. No principal
payments are required under the Credit Facility prior to maturity on October
14, 2002. The Company has relied upon the Credit Facility to provide funds for
acquisitions and to provide letters of credit to meet the Company's margin
requirements under Fixed-Price Contracts. See Note 13--Derivatives. As of
December 31, 1999, the Company had $255.6 million of principal and $2.8 million
of letters of credit outstanding under the Credit Facility.
The Company has the option of borrowing at a LIBOR-based interest rate or
the Base Rate (approximating the prime rate). The LIBOR interest rate margin
and the facility fee payable under the Credit Facility are subject to a sliding
scale based on the Company's senior debt credit rating. At December 31, 1999,
the applicable interest rate was LIBOR plus 30 basis points. The Credit
Facility also requires the payment of a facility fee equal to 15 basis points
of the Commitment. The average interest rate for borrowings under the Credit
Facility was 6.5% as of December 31, 1999. Including the effect of interest
rate swaps which hedge a portion of the interest rate exposure attributable to
this facility, the effective interest rate was 5.9%.
The Credit Facility contains various affirmative and restrictive covenants
which, among other things, limit total indebtedness to $700 million ($625
million of senior indebtedness) and require the Company to meet certain
financial tests. Borrowings under the Credit Facility are unsecured.
Other Lines of Credit. The Company has certain other unsecured lines of
credit available to it, which aggregated $30.1 million as of December 31, 1999.
Such short-term lines of credit are primarily used to meet margin requirements
under Fixed-Price Contracts and for working capital purposes. At December 31,
1999, three letters of credit totaling $.1 million were outstanding under these
credit lines.
6-7/8% Senior Notes due 2007. In December 1997, the Company issued $200
million principal amount, $198.8 million net of discount, of 6-7/8% Senior Notes
due 2007 (the "Senior Notes"). Interest is payable semi-annually on June 1 and
December 1. The associated indenture agreement contains restrictive covenants
which place limitations on the amount of liens and the Company's ability to
enter into sale and leaseback transactions.
9-1/4% Senior Subordinated Notes due 2004. In June 1994, the Company issued
$100 million principal amount, $98.5 million net of discount, of 9-1/4% Senior
Subordinated Notes due 2004 (the "Subordinated Notes"). Interest is payable
semi-annually on June 15 and December 15. The associated indenture agreement
contains restrictive covenants which limit, among other things, the prepayment
of the Subordinated Notes, the incurrence of additional indebtedness, the
payment of dividends and the disposition of assets.
The amount of required principal payments for the next five years and
thereafter as of December 31, 1999 are as follows: 2000--$0; 2001--$0;
2002--$255.6 million; 2003--$0; 2004--$100 million; thereafter--$200 million.
See Note 13--Derivatives for a description of the interest rate swaps hedging a
portion of the Credit Facility's outstanding debt.
F-11
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
Note 5. Income Taxes
The significant components of income tax expense (benefit) before cumulative
effect of accounting change for the years ended December 31, 1999, 1998 and
1997 are as follows:
Years Ended December 31,
---------------------------------------
1999 1998 1997
- -----------------------------------------------------------------------------------------------------------
(in thousands)
Current tax expense:
Federal $ 497 $ 527 $ 885
State 34 73 150
- -----------------------------------------------------------------------------------------------------------
531 600 1,035
- -----------------------------------------------------------------------------------------------------------
Deferred tax expense (benefit):
Federal 12,054 (12,766) (11,407)
State 1,691 (1,758) (889)
- -----------------------------------------------------------------------------------------------------------
13,745 (14,524) (12,296)
- -----------------------------------------------------------------------------------------------------------
$14,276 $ (13,924) $ (11,261)
===========================================================================================================
The provision for income taxes before cumulative effect of accounting
change differed from the computed "expected" income tax provision using
statutory rates on income before income taxes for the following reasons:
Years Ended December 31,
-----------------------------------------
1999 1998 1997
- -------------------------------------------------------------------------------------------------------------
(in thousands)
Computed "expected" income tax $12,492 $ (20,372) $ (9,563)
Increases (reductions) in taxes resulting from:
State income taxes, net of federal benefit 1,121 (1,095) (481)
Permanent differences (principally related to basis differences
in oil and gas properties) 588 6,133 935
Change in valuation allowance (194) 2,667 --
Section 29 credits (394) (851) (1,748)
Other 663 (406) (404)
- -------------------------------------------------------------------------------------------------------------
$14,276 $ (13,924) $ (11,261)
- -------------------------------------------------------------------------------------------------------------
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,
---------------------------
1999 1998
- -------------------------------------------------------------------------------------------------------------
(in thousands)
Deferred tax liabilities:
Capitalized costs and related depreciation, depletion and amortization $ 93,414 $ 69,116
Fixed-Price Contracts and other derivatives 12,045 49,643
Other 102 39
- -------------------------------------------------------------------------------------------------------------
105,561 118,798
- -------------------------------------------------------------------------------------------------------------
Deferred tax assets:
Deferred revenue 5,139 5,909
Fixed-Price Contracts and other derivatives 6,339 2,904
Alternative minimum tax credits 6,136 5,855
Net operating loss carryforwards 85,074 93,086
Other 735 846
- -------------------------------------------------------------------------------------------------------------
103,423 108,600
Valuation allowance for net operating loss carryforwards (50,203) (54,918)
- -------------------------------------------------------------------------------------------------------------
53,220 53,682
- -------------------------------------------------------------------------------------------------------------
Net deferred tax liability $ 52,341 $ 65,116
=============================================================================================================
F-12
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
At December 31, 1999, the Company had U.S. Federal net operating loss
carryforwards of $240.1 million that expire beginning in 2000 and alternative
minimum tax credit carryforwards of $6.1 million that can be carried forward
indefinitely but which can be used only to reduce regular tax liabilities in
excess of alternative minimum tax liabilities. Net operating loss carryforwards
of $143.4 million are expected to expire without utilization due to the change
of control provisions of Section 382 of the Internal Revenue Code. Such
expirations have been fully reserved through the valuation allowance.
Note 6. Transactions with Related Parties
Fixed-Price Contract Activity. In 1993, the Company entered into a fixed-price
sales contract with S.A. Louis Dreyfus et Cie hedging 33 Bcf of natural gas
over a five-year period beginning in 1996, at a weighted-average fixed price of
$2.49 per Mcf. For the years ended December 31, 1999 and 1998, the Company
realized hedging gains of $3.4 million and $2.9 million, respectively, in
results of operations related to this contract. For 1997, the contract resulted
in the recognition of a $.6 million hedging loss.
The Company uses the commodity trading resources of S.A. Louis Dreyfus et
Cie when purchasing natural gas futures contracts on the New York Mercantile
Exchange ("NYMEX"). In that regard, the Company reimburses S.A. Louis Dreyfus
et Cie for margin posted on behalf of the Company. At December 31, 1998, margin
of $1.5 million had been posted on the Company's behalf by S.A. Louis Dreyfus
et Cie under this arrangement.
General and Administrative Expense. The Company is a party to a services
agreement with S.A. Louis Dreyfus et Cie pursuant to which the Company is
billed for certain administrative and support services (principally insurance
costs and services) provided by S.A. Louis Dreyfus et Cie at amounts
approximating cost. General and administrative expenses for the years ended
December 31, 1999, 1998 and 1997 include $.5 million, $1.4 million and $.9
million, respectively, for such services.
Note 7. Commitments and Contingencies
Litigation. In December 1995, the United States District Court for the Western
District of Oklahoma entered a $10.8 million judgment in favor of the Company
against Midcon Offshore, Inc. ("Midcon") in connection with non- performance by
Midcon under an agreement to purchase a certain offshore oil and gas property.
In January 1996, Midcon delivered a $10.8 million promissory note to the
Company secured by liens on assets of Midcon in settlement of disputes in
connection with this litigation. Midcon paid $3.0 million to the Company prior
to its filing for bankruptcy in December 1996. In July 1999, an agreement was
reached between the Company and the Trustee to the Midcon bankruptcy case,
which provided for the payment of $8.6 million to the Company in satisfaction
of its claims against the estate. The settlement was approved by the bankruptcy
court and payment was made to the Company in August 1999. Receipt of the
settlement proceeds has been reflected in earnings and operating cash flows for
the year ended December 31, 1999.
In February 1995, a lawsuit was filed in the United States District Court
in Denver, Colorado, by KN Gas Supply Services, Inc. ("KNGSS"), requesting
declaratory judgment that KNGSS had the right to reduce the contract price for
gas produced from the Bowdoin Field, a property acquired by the Company, to
market levels from October 1, 1993 forward. KNGSS alleged that it was entitled
to a refund of approximately $7.7 million for the period through September 1996.
KNGSS had not updated its refund claim beyond this date. A motion for summary
judgment was filed in July 1996 by the Company, and in February 1998, the Court
ruled in favor of the Company and against KNGSS. KNGSS subsequently filed an
appeal which has been denied by the 10th Circuit Court of Appeals. No further
appeal has been filed by KNGSS and the filing deadline available for making a
subsequent appeal has expired.
The Company is one of numerous defendants in several lawsuits originally filed
in 1995, subsequently consolidated with related litigation, and now pending in
the Texas 93rd Judicial District Court in Hildago County, Texas. The lawsuit
alleges that the plaintiffs, a group of local landowners and businesses, have
suffered damages including, but not limited to, property damage and lost profits
of approximately $60 million as the result of hydrocarbon contamination of the
groundwater within the city of McAllen, Texas. The lawsuit alleges that gas
wells and related pipeline facilities owned and operated by the Company, and
other facilities operated by other defendants, caused the contamination. In
August 1999, the plaintiffs' experts produced reports that suggested the Company
might be considered a significant contributor to the contamination. The
Company's investigation into this matter has not found any leaks or discharges
from its facilities and believes the contamination to be unrelated to the
Company's gas wells and facilities. Trial is scheduled for May 2000. The Company
will vigorously defend its interests in this case and does not expect the
ultimate outcome of the case to have a material adverse impact on its financial
position or results of operations.
The Company was a defendant in various other legal proceedings as of
December 31, 1999, which are routine and incidental to its business. The
largest of such legal claims was for an alleged underpayment of royalty of $2.8
million, plus interest. While the ultimate results of these proceedings and
determinations cannot be predicted with certainty, the Company will
F-13
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
vigorously defend its interests and does not believe that the outcome of these
matters will have a material adverse effect on the Company.
Rental Commitments. Minimum annual rental commitments as of December 31,
1999 under noncancellable office space leases are as follows: 2000--$3.1
million; 2001--$2.2 million; 2002--$1.1 million; 2003 and thereafter--$1.0
million. Approximately $2.2 million of such rental commitments is included in
other long-term liabilities as of December 31, 1999. Rent expense included in
results of operations for the three years ended December 31, 1999, 1998 and
1997 was $1.5 million, $2.1 million and $1.1 million, respectively.
Note 8. Employee Benefit Plans
401(k) Plan. The Company's employees who have completed a specified term of
service are eligible for participation in the Louis Dreyfus Natural Gas Profit
Sharing and 401(k) Plan and Trust Agreement (the "401(k) Plan"). Pursuant to
the plan provisions, employee contributions can be made up to 17% of
compensation. Company contributions are discretionary. Employees vest in
Company contributions at 20% per year of service. For the years ended December
31, 1999, 1998 and 1997, the Company contributed $1.3 million, $1.2 million and
$.9 million, respectively, to the 401(k) Plan.
Stock Compensation Plans. Certain executive officers of the Company were
participants in the Louis Dreyfus Deferred Compensation Stock Equivalent Plan
sponsored by S.A. Louis Dreyfus et Cie ("Stock Equivalent Plan"). Under this
plan, participants were awarded stock equivalent rights ("SERs") expressed as a
number of stock equivalent units. At December 31, 1997, SERs totaling 83,500
stock equivalent units were outstanding. Recorded compensation expense
attributable to the SERs was approximately $.4 million for the year ended
December 31, 1997. In 1998, the Stock Equivalent Plan was terminated and
replaced with the Louis Dreyfus Natural Gas Corp. Deferred Stock Trust Agreement
("Trust Agreement"). The Trust Agreement establishes a trust which serves as a
depositary for restricted stock awards granted pursuant to the Trust Agreement.
An aggregate of 55,000 shares previously earned under the Stock Equivalent Plan
was purchased by the Company and contributed to the trust for distribution upon
termination of employment or other specified events, thus eliminating the
Company's obligations under the Stock Equivalent Plan. Also during 1998, a
separate deferred stock trust agreement was established to create a compensation
program for the services of non- employee directors of the Company. In
connection therewith, the Company purchased and contributed 8,000 shares of
restricted stock during 1998.
Officers, directors and certain key employees have been granted options to
purchase the Company's Common Stock under its 1993 Stock Option Plan (the
"Option Plan"). Under the Option Plan, the Company may grant both incentive
stock options intended to qualify under Section 422 of the Internal Revenue
Code and options which are not qualified as incentive stock options. The
maximum number of shares of Common Stock issuable under the Option Plan is 3
million shares, subject to appropriate equitable adjustment in the event of a
reorganization, stock split, stock dividend, reclassification or other change
affecting the Company's Common Stock. As of December 31, 1999 and 1998, options
to purchase 631,183 shares and 875,420 shares of Common Stock, respectively,
were available for grant under the Option Plan. Options granted under the
Option Plan vest over a period of time based on the nature of the grants and as
defined in the individual grant agreements, but generally over a four year
period. The exercise price of each option (with the exception of 53,330 options
issued in connection with the American Acquisition) equals the market price of
the Company's stock on the date of grant and an option's expiration date is ten
years from the date of issuance.
The following pro forma information, as required by Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS
123"), presents net income and earnings per share information as if the Company
had accounted for stock options issued after December 31, 1994 using the fair
value method prescribed by that statement. The fair value of issued stock
options was estimated at the date of grant using a Black-Scholes option pricing
model. Valuation assumptions for option grants in 1999, 1998 and 1997 included
the following: risk-free interest rates of 5.8%, 4.9% and 5.7%, respectively; no
dividends over the option term; stock price volatility factors of .37, .36 and
.32, respectively, and a weighted average expected option life of five years.
The estimated fair value as determined by the model is amortized to expense over
the respective vesting period. The SFAS 123 pro forma information presented
below is not necessarily indicative of the pro forma effects to be presented in
future periods. Additionally, option grants made prior to 1995 have been
excluded.
F-14
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
The SFAS 123 pro forma information is as follows:
Years Ended December 31,
------------------------------------------
1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
(in thousands, except per share data)
Net income (loss) $18,988 $ (45,194) $ (16,981)
Net income (loss) per share .47 (1.13) (.56)
================================================================================================================================
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions, including expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in
the subjective input assumptions can materially affect the fair value estimate,
in management's opinion, the existing models do not necessarily provide a
reliable single measure of fair value of its stock options.
Stock option transactions for 1999, 1998 and 1997 are summarized as
follows:
Years Ended December 31,
----------------------------------------------------------------------------------------
1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
Weighted- Weighted- Weighted-
Average Average Average
Shares Exercise Price Shares Exercise Price Shares Exercise Price
- --------------------------------------------------------------------------------------------------------------------------------
Outstanding at beginning of year 2,124,580 $ 16.85 1,708,330 $ 19.03 993,250 $ 15.98
Granted 426,000 19.16 1,054,750 15.51 806,080 22.46
Exercised (159,513) 15.45 (22,500) 15.05 (30,500) 16.18
Canceled (22,250) 14.44 (616,000) 20.68 (60,500) 16.02
- --------------------------------------------------------------------------------------------------------------------------------
Outstanding at end of year 2,368,817 17.38 2,124,580 16.85 1,708,330 19.03
================================================================================================================================
Exercisable at end of year 1,148,317 17.21 909,830 17.27 722,330 16.91
================================================================================================================================
Weighted-average fair value of options
granted during year (1) $ 8.05 $ 6.17 $ 8.79
================================================================================================================================
(1) Excludes for 1997 the fair value of options to purchase 53,330 shares
issued in connection with the American Acquisition and recorded as part of
the corresponding purchase price. See Note 3--Acquisitions.
Outstanding options to acquire 1.3 million shares of stock at December 31, 1999
had exercise prices ranging from $18.00 to $23.16 per share and had a
weighted-average remaining contractual life of 7.2 years. The balance of
options outstanding at December 31, 1999 had exercise prices ranging from
$12.47 to $16.69 per share and a weighted-average remaining contractual life of
7.9 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, 1999 gas sales to Enron
Corp. and PG&E Corp. approximated 17% and 14% of total revenues, respectively.
For the year ended December 31, 1998, gas sales to PG&E Corp. approximated 20%
of total revenues. For the year ended December 31, 1997, gas sales to PG&E
Corp., Enron and GPM Gas Corporation approximated 22%, 15% and 10% of total
revenues, respectively. The Company believes that alternative purchasers are
available, if necessary, to purchase its production at prices substantially
similar to those received from these significant purchasers in 1999.
F-15
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
Note 10. Capital Stock and Stockholders' Equity Information
Common Stock. The following table sets forth the Company's Common Stock
activity for the periods presented:
Years Ended December 31,
---------------------------------
1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------
(in thousands)
Common Stock Activity:
Balance, beginning of year 40,110 40,088 27,801
Exercise of stock options 121 22 30
Treasury shares purchased (32) -- --
Shares issued in the American Acquisition -- -- 11,316
Shares issued on conversion of Preferred Stock -- -- 941
- ----------------------------------------------------------------------------------------------------------------
Balance, end of year 40,199 40,110 40,088
================================================================================================================
Preferred Stock. In October 1997, in connection with the American
Acquisition, the Company issued 800,000 depositary shares representing a 1/200
interest in a share of $450 Cumulative Convertible Preferred Stock ("Preferred
Stock") to the holders of American preferred stock. In December 1997, in
connection with the Company's redemption offer for the Preferred Stock at
$26.35 per depositary share, holders of 783,675 depositary shares elected to
convert into 940,649 shares of Common Stock and $3.9 million of cash. The
remaining depositary shares were redeemed on December 31, 1997 for an aggregate
cash payment of $.4 million.
Warrants. At December 31, 1999, the Company had outstanding warrants to
purchase 1.2 million shares of Common Stock, all of which are currently
exercisable, issued in connection with the American Acquisition for the
outstanding warrants of American. The warrants have an exercise price of $17.47
per share and expire in December 2004. Additional warrants to purchase 356,489
shares expired unexercised in April 1999.
Other Comprehensive Income. The components of other comprehensive income
and related tax effects for the years ended December 31, 1999 and 1998 are
shown as follows:
Tax Net of
Gross Effect Tax
- ----------------------------------------------------------------------------------------------------------------
Year ended December 31, 1999:
Change in Fixed-Price Contract and other derivative fair value $ (62,711) $ (23,830) $ (38,881)
Reclassification adjustments--contract settlements (7,078) (2,690) (4,388)
- ----------------------------------------------------------------------------------------------------------------
$ (69,789) $ (26,520) $ (43,269)
================================================================================================================
Year ended December 31, 1998:
Cumulative effect of accounting change $ 157,550 $ 59,869 $ 97,681
Reclassification adjustments--contract settlements (7,147) (2,716) (4,431)
- ----------------------------------------------------------------------------------------------------------------
$ 150,403 $ 57,153 $ 93,250
==============================================================================================================
Note 11. Supplemental Statement of Cash Flows Information
In October 1997, LDNG issued Common Stock, Preferred Stock, warrants, options
and cash in connection with the American Acquisition. The accompanying
financial statements include the following amounts attributable to the acquired
assets and liabilities of American:
American
Acquisition
- ----------------------------------------------------------------------------------------------------------------
(in thousands)
Value allocated to the oil and gas properties of American $ 437,920
Other non-cash assets acquired 3,176
Working capital acquired 3,874
Long-term debt assumed (123,621)
Other liabilities assumed (23,606)
Common Stock issued (194,077)
Preferred Stock issued (21,080)
Warrants and options issued (10,263)
- ----------------------------------------------------------------------------------------------------------------
Cash paid, including cash overdrafts assumed $ 72,323
================================================================================================================
F-16
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
For the years ended December 31, 1999, 1998 and 1997, the Company paid
interest of $39.7 million, $38.3 million and $25.8 million, respectively, net
of capitalized interest, and paid income taxes of $.9 million, $.3 million and
$1.0 million, respectively.
Note 12. Financial Instruments
The following information is provided regarding the estimated fair value of the
financial instruments, including derivative assets and liabilities as defined
by SFAS 133, employed by the Company as of December 31, 1999 and 1998, and the
methods and assumptions used to estimate the fair value of such financial
instruments:
December 31, 1999 December 31, 1998
--------------------------- ---------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- ----------------------------------------------------------------------------------------------------------------
(in thousands)
Derivative assets:
Fixed-price natural gas swaps:
Sales contracts $ 16,433 $ 16,433 $ 26,125 $ 26,125
Purchase contracts -- -- 905 905
Fixed-price natural gas collars 1,323 1,323 3,367 3,367
Fixed-price natural gas physical delivery contracts 7,921 7,921 99,342 99,342
Natural gas basis swaps -- -- 74 74
Fixed-price crude oil swaps 360 360 n/a n/a
Interest rate swaps 5,660 5,660 827 827
Derivative liabilities:
Fixed-price natural gas swaps--sales contracts (4,329) (4,329) (551) (551)
Fixed-price natural gas physical delivery contracts (9,081) (9,081) (2,920) (2,920)
Natural gas basis swaps (3,271) (3,271) (3,734) (3,734)
Interest rate swaps -- -- (437) (437)
Bank debt (1) (255,600) (255,600) (297,200) (297,200)
6-7/8% Senior Notes due 2007 (1) (199,034) (177,012) (198,912) (187,704)
9-1/4% Senior Subordinated Notes due 2004 (1) (100,588) (99,591) (100,732) (102,897)
================================================================================================================
(1) Carrying amounts do not include capitalized debt issuance costs. See Note
1--Significant Accounting Policies-- Debt Issuance Costs.
Cash and cash equivalents, accounts receivable, deposits, accounts
payable, revenues payable and accrued liabilities were each estimated to have a
fair value approximating the carrying amount due to the short maturity of those
instruments or to the criteria used to determine carrying value in the
financial statements.
The fair value of Fixed-Price Contracts as of December 31, 1999 and 1998
was estimated based on market prices of natural gas and crude oil for the
periods covered by the contracts. The net differential between the prices in
each contract and market prices for future periods, as adjusted for estimated
basis, has been applied to the volumes stipulated in each contract to arrive at
an estimated future value. This estimated future value was discounted on a
contract-by-contract basis at rates commensurate with the Company's estimation
of contract performance risk and counterparty credit risk. The terms and
conditions of the Company's fixed-price physical delivery contracts and certain
financial swaps are uniquely tailored to the Company's circumstances. In
addition, certain of the Company's contracts hedge gas production for periods
beyond five years into the future. The market for natural gas beyond the five
year horizon is illiquid and published market quotations are not available. The
Company has relied upon near-term market quotations, longer-term
over-the-counter market quotations and other market information to determine
its fair value estimates. The Fixed-Price Contract fair value as reflected in
the balance sheet as of December 31, 1999 and 1998 does not necessarily
represent the value a third party would pay to assume the Company's positions.
The short-term and long-term derivative assets are presented in the
accompanying balance sheet under the caption "Fixed-price contracts and other
derivatives" in Current Assets and Other Assets, respectively. Short-term and
long-term derivative liabilities are presented in the balance sheet as
"Fixed-price contracts and other derivatives" in Current Liabilities and in
Deferred Credits and Other Liabilities, respectively.
The Company's bank debt bears interest at rates which move with market
interest rates. Accordingly, the fair value of such debt at December 31, 1999
and 1998 was estimated to approximate the carrying amount. The fair values of
the 6-7/8% Senior Notes due 2007 and the 9-1/4% Senior Subordinated Notes due
2004 were determined based on market quotations
F-17
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
for such securities. The fair value of the Company's interest rate swaps for
each of the years presented was determined by using a third-party interest rate
swap valuation model or by reliance upon third-party quotations. Such
valuations are based on market interest rates as of the determination date.
Note 13. Derivatives
Description of Contracts. The Company has entered into Fixed-Price Contracts to
reduce its exposure to unfavorable changes in oil and gas prices which are
subject to significant and often volatile fluctuation. The Company's
Fixed-Price Contracts are comprised of long-term physical delivery contracts,
energy swaps, collars, futures contracts and basis swaps. These contracts allow
the Company to predict with greater certainty the effective oil and gas prices
to be received for its hedged production and benefit the Company when market
prices are less than the fixed prices provided in its Fixed-Price Contracts.
However, the Company will not benefit from market prices that are higher than
the fixed prices in such contracts for its hedged production. For the years
ended December 31, 1999, 1998 and 1997, Fixed-Price Contracts hedged 55%, 50%
and 60%, respectively, of the Company's gas production and 19%, 16% and 33%,
respectively, of its oil production. Fixed-Price Contracts as of December 31,
1999, hedge 52 Bcfe of future oil and gas production in 2000, and 133 Bcfe
thereafter.
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. The fixed-price payment and the floating-price payment are
netted, resulting in a net amount due to or from the counterparty. For physical
delivery contracts, the Company purchases gas in the spot market at floating
market prices and delivers such gas to the contract counterparty at a fixed
price. The Company's natural gas collars contain a fixed floor price (put) and
ceiling price (call). If the market price of natural gas exceeds the call
strike price or falls below the put strike price, then the Company receives the
fixed price and pays the market price. If the market price of natural gas is
between the call and the put strike price, then no payments are due from either
party. Under the Company's basis swaps, the Company receives the floating
market price for NYMEX futures and pays the floating market price plus a fixed
differential for a specified regional spot market index.
The following table summarizes the estimated volumes, fixed prices,
fixed-price sales and future net revenues attributable to the Company's
Fixed-Price Contracts as of December 31, 1999. The Company expects the prices
to be realized for its hedged production to vary from the prices shown in the
following table due to basis, which is the differential between the floating
price paid under each energy swap contract, or the cost of gas to supply
physical delivery contracts, and the price received at the wellhead for the
Company's production. Basis differentials are caused by differences in
location, quality, contract terms, timing and other variables. Future net
revenues for any period are determined as the differential between the fixed
prices provided by Fixed-Price Contracts and forward market prices as of
December 31, 1999, as adjusted for basis. Future net revenues change with
changes in market prices and basis. See "--Market Risk."
F-18
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
Years Ending December 31, Balance
--------------------------------------------------------- through
2000 2001 2002 2003 2004 2017 Total
- -----------------------------------------------------------------------------------------------------------------------
(dollars in thousands, except price data)
Natural Gas Swaps:
Contract volumes (BBtu) 19,460 7,475 6,405 5,650 5,650 12,133 56,773
Weighted-average fixed price
per MMBtu (1) $ 2.46 $ 2.47 $ 2.67 $ 2.92 $ 3.12 $ 3.36 $ 2.79
Future fixed-price sales $ 47,950 $18,446 $17,098 $16,492 $17,608 $ 40,821 $158,415
Future net revenues (2) $ 1,699 $ (117) $ 1,053 $ 2,194 $ 3,111 $ 8,686 $ 16,626
Natural Gas Physical Delivery
Contracts:
Contract volumes (BBtu) 16,633 17,211 17,086 14,216 6,030 41,321 112,497
Weighted-average fixed price
per MMBtu (1) $ 2.29 $ 2.36 $ 2.43 $ 2.50 $ 2.45 $ 2.93 $ 2.59
Future fixed-price sales $ 38,081 $40,628 $41,568 $35,477 $14,788 $121,209 $291,751
Future net revenues (2) $ (492) $ (576) $ 326 $ 725 $ (368) $ 6,023 $ 5,638
Natural Gas Collars:
Contract volumes (BBtu):
Floor 9,630 -- -- -- -- -- 9,630
Ceiling 19,260 -- -- -- -- -- 19,260
Weighted-average fixed-price
per MMBtu (1):
Floor $ 2.48 $ -- $ -- $ -- $ -- $ -- $ 2.48
Ceiling $ 2.80 $ -- $ -- $ -- $ -- $ -- $ 2.80
Future fixed-price sales (at floor) $ 23,882 $ -- $ -- $ -- $ -- $ -- $ 23,882
Future net revenues (2) $ 1,323 $ -- $ -- $ -- $ -- $ -- $ 1,323
Total Natural Gas Contracts (3):
Contract volumes (BBtu) 45,723 24,686 23,491 19,866 11,680 53,454 178,900
Weighted-average fixed price
per MMBtu (1) $ 2.40 $ 2.39 $ 2.50 $ 2.62 $ 2.77 $ 3.03 $ 2.65
Future fixed-price sales $109,913 $59,074 $58,666 $51,969 $32,396 $162,030 $474,048
Future net revenues (2) $ 2,530 $ (693) $ 1,379 $ 2,919 $ 2,743 $ 14,709 $ 23,587
Crude Oil Swaps:
Contract volumes (MBbls) 1,001 -- -- -- -- -- 1,001
Weighted-average fixed price
per Bbl (1) $ 23.40 $ -- $ -- $ -- $ -- $ -- $ 23.40
Future fixed-price sales $ 23,423 $ -- $ -- $ -- $ -- $ -- $ 23,423
Future net revenues (2) $ 377 $ -- $ -- $ -- $ -- $ -- $ 377
=======================================================================================================================
(1) The Company expects the prices to be realized for its hedged production to
vary from the prices shown due to basis. See "Market Risk."
(2) Future net revenues as presented above are undiscounted and have not been
adjusted for contract performance risk or counterparty credit risk. See
Note 12--Financial Instruments.
(3) Does not include basis swaps with notional volumes by year, as follows:
2000-21.3 TBtu; 2001-9.4 TBtu; and 2002-5.5 TBtu.
The estimates of future net revenues from the Company's Fixed-Price
Contracts are computed based on the difference between the prices provided by
the Fixed-Price Contracts and forward market prices as of the specified date.
The market for natural gas beyond a five year horizon is illiquid and published
market quotations are not available. The Company has relied upon near-term
market quotations, longer-term over-the-counter market quotations and other
market information to
F-19
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
determine its future net revenue estimates. Forward market prices for natural
gas are dependent upon supply and demand factors in such forward market and are
subject to significant volatility. The future net revenue estimates shown above
are subject to change as forward market prices change. See Note 12--Financial
Instruments for estimated fair value information.
Accounting. All of the Company's Fixed-Price Contracts have been executed
in connection with its natural gas and crude oil hedging program. For
Fixed-Price Contracts qualifying as cash flow hedges pursuant to SFAS 133, the
differential between the fixed price and the floating price for each contract
settlement period multiplied by the associated contract volumes is the contract
profit or loss. The realized contract profit or loss is included in oil and gas
sales in the period for which the underlying commodity was hedged. Changes in
market value for these contracts for volumes not yet settled are not reflected
in the Company's income statements, but rather are shown as adjustments to
other comprehensive income. For those contracts not qualifying as cash flow
hedges, the associated fair value, as well as future changes in market value,
are recognized in earnings. The fair value of all of its Fixed-Price Contracts
are recorded as assets or liabilities in the Company's balance sheet.
If a Fixed-Price Contract which qualified for cash flow hedge accounting
is liquidated or sold prior to maturity, the gain or loss at the time of
termination remains in accumulated other comprehensive income to be amortized
into oil and gas sales over the original term of the contract. The Company had
pretax unamortized deferred gains of $99.7 million and $61.3 million as of
December 31, 1999 and 1998, respectively, related to terminated contracts which
were recorded net of deferred tax effects in accumulated other comprehensive
income. Prepayments received under Fixed-Price Contracts with continuing
performance obligations are recorded as deferred revenue and amortized into oil
and gas sales over the term of the underlying contract. See Note 1--Significant
Accounting Policies--Hedging.
For the years ended December 31, 1999, 1998 and 1997, oil and gas sales
included $1.5 million of net gains, $23.1 million of net gains and $4.3 million
of net losses, respectively, associated with realized gains and losses under
its Fixed-Price Contracts. Change in derivative fair value for the years ended
December 31, 1999 and 1998 was comprised of: (1) gains totaling $6.2 million
and $15.7 million, respectively, representing the change in fair value for all
of the Company's derivatives for the period from October 1, 1998 to January 13,
1999, recognized in earnings for documentation issues (see Note 1--Significant
Accounting Policies--Hedging); and (2) gains totaling $5.4 million and $1.6
million, respectively, attributable to the change in fair value of derivative
contracts not designated as cash flow hedges. In addition, the caption for 1999
includes a net loss of $1.9 million attributable to a loss of effectiveness for
certain derivatives designated as cash flow hedges, a net gain of $1.8 million
representing the ineffective portion of the Company's cash flow hedges, and a
loss of $11.9 million representing the reversal of net gains previously
recorded in this caption as actual cash settlements were realized under the
respective contracts.
In addition to the future net settlements identified in the table under
"--Description of Contracts", the Company expects the following adjustments in
2000: (1) oil and gas sales will include $13.3 million in gains from the
amortization of deferred gains from price-risk management activities recorded
net of tax in accumulated other comprehensive income, (2) interest expense will
include $.4 million of loss from the amortization of deferred interest rate
hedging losses recorded net of tax in accumulated other comprehensive income,
and (3) change in derivative fair value in the statement of operations will
include a loss of $8.4 million relating to the unwinding of previously
recognized net gains in this caption as actual cash settlements are realized
for the respective derivative contracts.
Credit Risk. Fixed-Price Contracts terms generally provide for monthly
settlements and energy swaps provide for a net settlement due to or from the
respective party as discussed previously. The counterparties to the contracts
are comprised of independent power producers, pipeline marketing affiliates,
financial institutions, a municipality and S.A. Louis Dreyfus et Cie, among
others. In some cases, the Company requires letters of credit or corporate
guarantees to secure the performance obligations of the contract counterparty.
Should a counterparty to a contract default on a contract, there can be no
assurance that the Company would be able to enter into a new contract with a
third party on terms comparable to the original contract. The Company has not
experienced non-performance by any counterparty.
Cancellation or termination of a Fixed-Price Contract would subject a
greater portion of the Company's gas production to market prices, which, in a
low price environment, could have an adverse effect on the Company's future
operating results. In addition, the associated carrying value of the contract
would be removed from the Company's balance sheet.
The Company was a party to two Fixed-Price Contracts, both long-term
physical delivery contracts, with independent power producers ("IPPs") which
sold electrical power under firm, fixed-price contracts to Niagara Mohawk
Corporation ("NIMO"), a New York state utility ("NIMO Contracts"). The ability
of these IPPs to perform their obligations to the Company was dependent on the
continued performance by NIMO of its power purchase obligations to the
counterparties. NIMO
F-20
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
had taken aggressive regulatory, judicial and contractual actions in recent
years seeking to curtail power purchase obligations, including its obligations
to the NIMO Contract counterparties, and had further stated that its future
financial prospects were dependent on its ability to resolve these obligations,
along with other matters. In July 1997, NIMO entered into a Master
Restructuring Agreement (the "MRA") with 16 IPPs, including the NIMO Contract
counterparties. Subsequently, one of the NIMO Contract counterparties withdrew
from the MRA. The power purchase agreement between NIMO and the other
counterparty was terminated. In connection therewith, the Company agreed in
June 1998 to terminate its fixed-price contract to the counterparty in exchange
for $40.1 million. The associated realized gain has been recorded in
accumulated other comprehensive income, net of tax effect. In settlement of
litigation initiated by NIMO against the remaining NIMO contract counterparty,
an agreement was reached in late October 1999 between the respective parties to
terminate the power contract in exchange for a cash payment from NIMO. In
connection with this agreement, the Company agreed to the termination of its
contract with the IPP in exchange for a cash payment to the Company of $44.2
million. The associated realized gain has been recorded in accumulated other
comprehensive income, net of tax.
Market Risk. 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, 1999, 1998 and 1997, the Company received on an Mcf
basis approximately 6%, 6% and 1% less than the prices specified in its natural
gas Fixed-Price Contracts, respectively, due to basis. For its oil production
hedged by crude oil Fixed-Price Contracts, the Company realized approximately
7%, 10% 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 2000 represents a $1.1
million change in gas sales. A 1% move in price realization for hedged oil in
2000 represents a $.2 million 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.
Except for the effect of basis movements, the Company expects that any
changes in Fixed-Price Contract fair value attributable to changes in market
prices for oil and natural gas will be offset by changes in the value of its
oil and natural gas reserves. This change in reserve value, however, is not
reflected in the Company's balance sheet. Further, changes in future gains and
losses to be realized in oil and gas sales upon cash settlements of Fixed-Price
Contracts as a result of changes in market prices for oil and natural gas are
expected to be offset by changes in the price received for the Company's hedged
oil and natural gas production. Because the majority of the Company's future
estimated oil and gas production is unhedged, declining oil and gas prices
could have a material adverse effect on the Company's future results of
operations and operating cash flows.
Margin. The Company is required to post margin in the form of bank letters
of credit or treasury bills under certain of its Fixed-Price Contracts. In some
cases, the amount of such margin is fixed; in others, the amount changes as the
market value of the respective contract changes, or if certain financial tests
are not met. For the years ended December 31, 1999, 1998 and 1997, the maximum
aggregate amount of margin posted by the Company was $23.5 million, $23.7
million and $28.7 million, respectively. In connection with the termination of
the NIMO Contract in December 1999, $15 million of margin and 29 Bcf of
mortgaged reserves were permanently released by the counterparty. 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, 1999, the Company had
issued margin in the form of letters of credit totaling $2.0 million.
Interest Rate Swaps. The Company has entered into interest rate swaps to
hedge the interest rate exposure associated with borrowings under the Credit
Facility. As of December 31, 1999, the Company had fixed the interest rate on
average notional amounts of $125 million, $125 million and $94 million for the
years ended December 31, 2000, 2001 and 2002, respectively. Under the interest
rate swaps, the Company receives the LIBOR three-month rate (6.0% at December
31, 1999) and pays an average rate of 5.0% for each period covered by the
swaps. The notional amounts are less than the maximum amount anticipated to be
available under the Credit Facility in such years.
F-21
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
For each interest rate swap, the differential between the fixed rate and
the floating rate multiplied by the notional amount is the swap gain or loss.
Such gain or loss is included in interest expense in the period for which the
interest rate exposure was hedged. Pursuant to SFAS 133, if an interest rate
swap qualifying as a cash flow hedge is liquidated or sold prior to maturity,
the gain or loss on the interest rate swap at the time of termination remains
in accumulated other comprehensive income, to be recognized as an adjustment to
interest expense over the original contract term. At December 31, 1999 and
1998, the Company had deferred termination losses of $2.8 million and $3.2
million, respectively, recorded net of tax in accumulated other comprehensive
income. For the years ended December 31, 1999, 1998 and 1997, interest rate
swaps increased interest expense by $.1 million, $.3 million and $.2 million,
respectively.
Note 14. Supplemental Information--Oil and Gas Reserves (unaudited)
The following information summarizes the Company's net proved reserves of crude
oil and natural gas and the present values thereof for the three years ended
December 31, 1999, 1998 and 1997. Reserve estimates for these years have been
prepared by the Company's petroleum engineers and reviewed by an independent
engineering firm. All studies have been prepared in accordance with regulations
prescribed by the Securities and Exchange Commission. Future net revenue is
estimated by such engineers using oil and gas prices in effect as of the end of
each respective year with price escalations permitted only for those properties
which have wellhead contracts allowing specific increases. Future operating
costs estimated in each study are based on historical operating costs incurred.
Reserve quantity estimates are calculated without regard to prices in the
Company's Fixed-Price Contracts.
The reliability of any reserve estimate is a function of the quality of
available information and of engineering interpretation and judgment. Such
estimates are susceptible to revision in light of subsequent drilling and
production history or as a result of changes in economic conditions.
Estimated Quantities of Oil and Gas Reserves (unaudited). The following
table presents the Company's estimated proved reserves, all of which are
located in the United States, for the years ended December 31, 1999, 1998 and
1997. Proved reserves are the estimated quantities of oil and gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that are
expected to be recovered through existing wells with existing equipment and
operating methods.
1999 1998 1997
--------------------------- --------------------------- --------------------------
Oil Gas Oil Gas Oil Gas
(MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MMcf)
- ------------------------------------------------------------------------------------------------------------------------------
Proved Reserves:
Beginning of year 24,416 1,193,666 29,109 1,028,752 23,497 849,199
Acquisition of proved reserves 436 38,352 166 6,270 11,679 163,651
Extensions and discoveries 1,328 199,687 1,943 246,382 1,271 116,919
Revisions of previous estimates (1) 5,736 (22,506) (3,165) 19,974 263 (26,345)
Sales of reserves in place (579) (7,191) (207) (6,646) (5,512) (2,941)
Production (2,965) (107,979) (3,430) (101,066) (2,089) (71,731)
- ------------------------------------------------------------------------------------------------------------------------------
End of year 28,372 1,294,029 24,416 1,193,666 29,109 1,028,752
==============================================================================================================================
Proved Developed Reserves:
Beginning of year 20,722 1,026,834 24,321 899,196 17,894 709,712
==============================================================================================================================
End of year 23,943 1,064,739 20,722 1,026,834 24,321 899,196
==============================================================================================================================
(1) The crude oil volume revision for 1998 was primarily the result of a
significant reduction in year-end 1998 crude oil prices compared to the
prior year-end. The crude oil volume revision for 1999 was primarily the
result of a significant increase in year-end 1999 crude oil prices
compared to the prior year-end.
Standardized Measure of Discounted Future Net Cash Flows (unaudited). The
following table reflects the standardized measure of discounted future net cash
flows relating to the Company's interests in proved oil and gas reserves. The
future net cash inflows were developed as follows:
(1) Estimates were made of quantities of proved reserves and the future periods
in which they are expected to be produced based on year-end economic
conditions.
F-22
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
(2) The estimated cash flows from future production of proved reserves were
prepared using year-end prices for each respective year, as follows:
1999--$24.36 per Bbl, $2.19 per Mcf; 1998--$9.46 per Bbl, $2.07 per Mcf;
and 1997--$16.76 per Bbl, $2.49 per Mcf. These prices do not include the
effect of the Company's Fixed-Price Contracts.
(3) The resulting future gross revenue streams were reduced by estimated future
costs to develop and to produce the proved reserves and estimated
abandonment costs, based on year-end estimates.
(4) Future income taxes were computed by applying the appropriate statutory tax
rates to the future pretax net cash flows less the current tax bases 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,
-----------------------------------------------
1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------
(in thousands)
Future cash inflows (1) $ 3,521,914 $2,695,864 $3,047,840
Future production costs (1,169,263) (870,420) (985,639)
Future development costs (216,211) (148,595) (136,217)
Future income taxes (460,504) (278,363) (345,552)
- --------------------------------------------------------------------------------------------------------------------
1,675,936 1,398,486 1,580,432
Discount at 10% per year (813,818) (678,780) (706,932)
- --------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows (1) (2) $ 862,118 $ 719,706 $ 873,500
====================================================================================================================
(1) Future cash inflows and the standardized measure of discounted future net
cash flows do not include the expected cash flow contribution of the
Company's Fixed-Price Contracts based on year-end oil and gas prices.
(2) The standardized measure of discounted future net cash flows including the
effect of the Company's Fixed-Price Contracts was $896.7 million, $838.7
million and $956.7 million as of December 31, 1999, 1998 and 1997,
respectively.
The standardized measure information in the preceding table was derived
from estimates of the Company's proved oil and gas reserves contained in
studies prepared by petroleum engineers. The standardized measure calculation,
prepared pursuant to the provisions of Statement of Financial Accounting
Standards No. 69, does not purport to represent the fair market value of the
Company's oil and gas reserves. The foregoing information is presented for
comparative purposes as of the Company's year-end and is not intended to
reflect any changes in value which may result from future price fluctuations.
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, 1999, 1998 and 1997, were as follows:
Years Ended December 31,
---------------------------------------------
1999 1998 1997
- -------------------------------------------------------------------------------------------------------------
(in thousands)
Balance, beginning of year $ 719,706 $ 873,500 $ 922,611
Acquisitions of proved reserves 39,877 4,236 212,428
Extensions and discoveries, net of future development costs 194,059 183,231 118,849
Revisions of previous quantity estimates 9,118 676 (20,755)
Oil and gas sales, net of production costs (223,298) (182,131) (177,134)
Sales of reserves in place (8,236) (7,769) (35,896)
Net changes in sales prices and production costs 153,701 (234,815) (513,461)
Development costs incurred and changes in estimated future
development costs (14,138) 41,121 27,804
Net change in income taxes (96,236) 37,783 251,949
Accretion of discount 81,107 100,265 130,371
Changes in timing of production and other 6,458 (96,391) (43,266)
- -------------------------------------------------------------------------------------------------------------
Balance, end of year $ 862,118 $ 719,706 $ 873,500
=============================================================================================================
F-23
LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)
Note 15. Quarterly Results (unaudited)
1999
-------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
- --------------------------------------------------------------------------------
(in thousands, except per share data)
Revenues (1) $ 57,123 $62,422 $ 89,946 $ 93,115
Operating profit (loss) (2) 12,023 24,438 27,012 30,022
Net income (loss) before
cumulative effect of
accounting change (3) (3,821) (454) 13,048 12,641
Net income (loss) before
cumulative effect of
accounting change per
share--basic and diluted (0.10) (0.01) 0.32 0.31
Net income (loss) (3) (3,821) (454) 13,048 12,641
Net income (loss) per share--
basic and diluted (0.10) (0.01) 0.32 0.31
================================================================================
1998
-------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
- --------------------------------------------------------------------------------
(in thousands, except per share data)
Revenues (1) $ 69,596 $ 70,351 $ 68,834 $ 84,602
Operating profit (loss) (2) 12,609 358 7,904 (28,605)
Net income (loss) before
cumulative effect of
accounting change (3) (2,043) (10,391) (5,439) (26,408)
Net income (loss) before
cumulative effect of
accounting change per
share--basic and diluted (0.05) (0.26) (0.14) (0.66)
Net income (loss) (3) (2,043) (10,391) (5,439) (25,444)
Net income (loss) per share--
basic and diluted (0.05) (0.26) (0.14) (0.63)
================================================================================
(1) The revenue decrease in the first quarter of 1999 is primarily attributable
to low oil and gas prices; the decrease in the second quarter of 1999 is
attributable to change in derivative fair value. The revenue increases in
the third and fourth quarters of 1999 were favorably impacted by higher
oil and gas prices and changes in derivative fair value. The revenue
increase in the fourth quarter of 1998 is largely attributable to change
in derivative fair value.
(2) The increases in operating profits for the third and fourth quarters of
1999 are attributable to higher oil and gas prices. The decrease in
operating profit in the second quarter of 1998 is attributable to a $9.9
million impairment charge. The operating loss in the fourth quarter of
1998 was attributable to an impairment charge of $42.6 million. See Note 1
--Significant Accounting Policies.
(3) Net losses in the first and second quarters of 1999 resulted from lower oil
and gas prices and changes in derivative fair value previously discussed.
Net income in the third and fourth quarters of 1999 resulted primarily
from higher oil and gas prices. Net losses in 1998 resulted from lower oil
and gas prices and impairment charges previously discussed.
F-24
LOUIS DREYFUS NATURAL GAS CORP.
Schedule II--Consolidated Valuation and Qualifying Accounts
(in thousands)
Balance at Balance at
Beginning of End of
Period Additions (1) Deductions (2) Period
- ------------------------------------------------------------------------------------------------------------------------
Description:
December 31, 1999:
Allowance for doubtful accounts--Joint interest and
other receivables $1,198 $ 12 $ 96 $1,114
========================================================================================================================
December 31, 1998:
Allowance for doubtful accounts--Joint interest and
other receivables $1,135 $176 $113 $1,198
========================================================================================================================
December 31, 1997:
Allowance for doubtful accounts--Joint interest and
other receivables $1,086 $ 49 $ -- $1,135
========================================================================================================================
(1) Additions relate to provisions for doubtful accounts.
(2) Deductions relate to the write-off of accounts receivable deemed
uncollectible.
F-25