<PAGE>

================================================================================

                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, 2000

                                       OR

[ ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934.

                         COMMISSION FILE NUMBER 1-12480
[GRAPHIC OMITTED]


                         LOUIS DREYFUS NATURAL GAS CORP.
             (Exact name of Registrant as specified in its charter)

               OKLAHOMA                                  73-1098614
  (State or other jurisdiction of                       (IRS Employer
  incorporation or organization)                        Identification No.)

   14000 QUAIL SPRINGS PARKWAY, SUITE 600
           OKLAHOMA CITY, OKLAHOMA                           73134
   (Address of principal executive office)                 (Zip code)

       Registrant's telephone number, including area code: (405) 749-1300

                      ------------------------------------


          Securities registered pursuant to Section 12(b) of the Act:

                                                        Name of each exchange
             Title of each class                         on which registered
             -------------------                         -------------------
  COMMON STOCK, PAR VALUE $.01 PER SHARE              NEW YORK STOCK EXCHANGE
 9 1/4% SENIOR SUBORDINATED NOTES DUE 2004            NEW YORK STOCK EXCHANGE

          Securities registered pursuant to Section 12(g) of the Act:

                                      NONE

                      ------------------------------------


    Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES X NO __.

    Indicate by check mark if disclosure of delinquent files pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]

    The aggregate market value of the voting stock held by non-affiliates of the
Registrant at February 22, 2001, was approximately $894 million (based on a
value of $36.75 per share, the closing price of the Common Stock as quoted by
the New York Stock Exchange on such date). 43,877,479 shares of Common Stock,
par value $.01 per share, were outstanding on February 22, 2001.

                       DOCUMENTS INCORPORATED BY REFERENCE

    Portions of the definitive proxy statement for the Registrant's 2001 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.

================================================================================

<PAGE>


                         LOUIS DREYFUS NATURAL GAS CORP.
                                    FORM 10-K
                                TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                                          PAGE
                                                                                          ----
                                     PART I
<S>                                                                                       <C>
Item 1 --  BUSINESS......................................................................  3
           General.......................................................................  3
           Business Strategy.............................................................  4
           Forward-Looking Statements....................................................  4
           Recent Developments...........................................................  5
           Acquisitions..................................................................  6
           Marketing.....................................................................  6
           Competition...................................................................  8
           Regulation....................................................................  8
           Certain Operational Risks..................................................... 10
           Employees..................................................................... 10
           Relationship Between the Company and S.A. Louis Dreyfus et Cie................ 10
           Potential Conflicts of Interest............................................... 11
           Recent Sales of Unregistered Securities....................................... 11
           Certain Definitions........................................................... 11

Item 2 --  PROPERTIES.................................................................... 13
           General....................................................................... 13
           Core Areas.................................................................... 14
           Reserves...................................................................... 17
           Costs Incurred and Drilling Results........................................... 18
           Acreage....................................................................... 19
           Productive Well Summary....................................................... 19
           Title to Properties........................................................... 19

Item 3 --  LEGAL PROCEEDINGS............................................................. 20

Item 4 --  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS........................... 20

                                     PART II

Item 5 --  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
               MATTERS................................................................... 20

Item 6 --  SELECTED FINANCIAL DATA....................................................... 21

Item 7 --  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
               RESULTS OF OPERATIONS..................................................... 22
           Overview...................................................................... 22
           Results of Operations - Fiscal Year 2000 Compared to Fiscal Year 1999......... 24
           Results of Operations - Fiscal Year 1999 Compared to Fiscal Year 1998......... 26
           Capital Resources and Liquidity............................................... 27
           Commitments and Capital Expenditures.......................................... 29
           Outlook for Fiscal Year 2001.................................................. 30

Item 7A -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.....................31
           General....................................................................... 31
           Fixed-Price Contracts......................................................... 31


                                             1
<PAGE>


                                LOUIS DREYFUS NATURAL GAS CORP.
                                           FORM 10-K
                               TABLE OF CONTENTS (CONTINUED)

                                                                                          PAGE
                                                                                          ----

           Interest Rate Sensitivity..................................................... 36

Item 8 --  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................................... 37

Item 9 --  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
               AND FINANCIAL DISCLOSURE.................................................. 37

                                    PART III

Item 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT............................ 37

Item 11 -- EXECUTIVE COMPENSATION........................................................ 37

Item 12 -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT................ 37

Item 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................................ 37

                                     PART IV

Item 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K............... 38
</TABLE>


                                             2


<PAGE>


                         LOUIS DREYFUS NATURAL GAS CORP.

                                     PART I

ITEM 1 -- BUSINESS

GENERAL

     Louis Dreyfus Natural Gas Corp. 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. Our
acquisition, development and exploration activities are primarily conducted in
three geographically concentrated core areas: the Permian Region which includes
west Texas, southeast New Mexico and the San Juan Basin; the Mid-Continent
Region which includes 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. Our proved reserves as of
December 31, 2000 totaled 1.8 Tcfe and future net revenues from these reserves
had a discounted present value of $3.7 billion. Properties that we operate
contain approximately 79% of our total proved reserves. Natural gas reserves
comprised 89% of our year-end proved reserve position and 82% of our reserves
were proved developed. The average reserve life of our proved reserves was 13.2
years. The definitions of certain technical terms can be found beginning at page
11.

     Louis Dreyfus Natural Gas Corp. originated with the acquisition of 61 Bcfe
by S.A. Louis Dreyfus et Cie in 1990. Since that date, we have experienced
significant growth in production and proved reserves through both development
and exploration drilling and proved reserve acquisitions. We have accumulated
interests in 2.8 million gross acres with 2,124 identified drilling locations as
of December 31, 2000. Of these locations, 770 had been assigned proved
undeveloped reserves at December 31, 2000. We aggressively exploit the value in
our properties through an active development drilling program. This program has
resulted in the drilling of 1,689 wells with a completion success rate of 92%
over the five-year period ended December 31, 2000. In recent years, exploratory
drilling has been increasingly emphasized as an integral component of our
business strategy and, consequently, we have incurred substantial up-front
costs, including significant acreage, seismic and other geological and
geophysical costs. During 2000, we invested $39 million in connection with
exploration activities, $22 million of which was directed to acreage and seismic
acquisition. Our exploration program has had a cumulative drilling success rate
of 70% over the five-year period ended December 31, 2000.

     We have replaced 282% of our production since 1995 at an average finding
cost of $1.01 per Mcfe, including the purchase accounting impact of acquiring
American Exploration Company in 1997. Finding costs excluding the effects of the
American Exploration acquisition, which we believe are more representative of
our historical ability to replace reserves, were $.85 per Mcfe over this same
five-year period. The following table reflects our growth since 1995:

     SELECTED GROWTH STATISTICS

<TABLE>
<CAPTION>

                                                     YEARS ENDED DECEMBER 31,                        FIVE-YEAR
                                        ---------------------------------------------------------     GROWTH
                                           2000        1999        1998        1997        1996        RATE
                                        ---------   ---------   ----------  ----------  ---------    ---------
     <S>                                <C>         <C>         <C>         <C>         <C>          <C>
     Production (Bcfe)................      137.0       125.8       121.6        84.3        75.0      17.4%
     Proved reserves (Bcfe)...........    1,808.0     1,464.3     1,340.2     1,203.4       990.2      15.6
     EBITDAX (MM$) (1)................  $   381.8   $   213.0   $   183.8   $   164.9   $   128.6      27.9
     Net cash provided by operating
       activities (MM$)...............  $   278.0   $   181.6   $   147.4   $   129.8   $   101.8      25.4
     Net income (loss) (MM$) (2)......  $    98.3   $    21.4   $   (43.3)  $   (16.1)  $    21.1      54.9
</TABLE>

     ------------------------------------

     (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 Exploration acquisition.
            Earnings for 2000 were positively influenced by higher oil and gas
            prices and higher gas production. See "Item 7 -- Management's
            Discussion and Analysis of Financial Condition and Results of
            Operations."


                                       3
<PAGE>


     The address of our principal executive offices is 14000 Quail Springs
Parkway, Suite 600, Oklahoma City, Oklahoma 73134, and our telephone number
is (405) 749-1300.

BUSINESS STRATEGY

     Our business strategy is to generate strong and consistent growth in
reserves, production, operating cash flows and earnings. This strategy is
implemented through the following:

     NATURAL GAS FOCUS. We emphasize growth in natural gas reserves and believe
     that the long-term supply and demand fundamentals for natural gas are
     favorable for continued strength in natural gas prices. 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 89% of our reserve
     base is comprised of natural gas, making us substantially more leveraged to
     natural gas than the industry average. Because of this focus, we now have
     one of the largest domestic natural gas reserve bases in the industry.

     EXPANDED EXPLORATION PROGRAM. Increased exploration activity in our core
     areas exposes us to higher production and reserve growth potential. We have
     a staff of 29 geoscientists and reservoir engineers who have extensive
     experience in the use of advanced technologies, including 3-D seismic
     analysis, computerized mapping and reservoir simulation modeling. These
     technologies are combined with a considerable knowledge base gained through
     our operating and development drilling activities in these core areas. The
     combination results in a disciplined approach to exploration growth. During
     2000, $39 million was invested in connection with exploration activities,
     including drilling, seismic data collection and unproved leasehold
     acquisitions. Over the five-year period ended December 31, 2000, we have
     drilled 125 gross (78 net) exploratory wells with a completion success rate
     of 70%. We have allocated approximately $64 million, or 22%, of our 2001
     drilling budget to exploration activities.

     DEVELOPMENT DRILLING. We aggressively exploit the value in our oil and gas
     property base through an 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. We have drilled 1,564 gross (1,045 net) development wells
     with a completion success rate of 94% over the five-year period ended
     December 31, 2000. For 2001, we plan to continue our aggressive development
     drilling program by investing approximately $226 million, or 78% of our
     2001 drilling budget.

     STRATEGIC ACQUISITIONS. We have invested $594 million to acquire 562 Bcfe
     of proved reserves over the five-year period ended December 31, 2000,
     representing an average acquisition cost of $1.06 per Mcfe. We believe that
     this aggregate average acquisition cost, which includes the purchase
     accounting impact of the American Exploration 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 our core areas where we possess considerable
     operating expertise and realize economies of scale. We principally target
     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. We own interests in
     approximately 10,000 wells located primarily in our 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. We have five district offices in our core areas
     and employ approximately 130 pumpers and other field personnel to provide
     onsite management of our 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 our current expectations and are based on our
historical


                                       4
<PAGE>


operating trends, our proved reserve and fixed-price contract positions as of
December 31, 2000, and other information currently available to us.
Forward-looking statements include statements regarding our future drilling
plans and objectives, and related exploration and development budgets, and
number and location of planned wells, and statements regarding the quality of
our 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 our oil and gas properties and that
there will be no material acquisitions or divestitures except as disclosed
herein.

     We caution 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 in this
document. See "Item 7 -- Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Outlook for Fiscal Year 2001." Moreover,
we may make material acquisitions or divestitures, modify our 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 in this document.

     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. We expressly disclaim any obligation or
undertaking to release publicly any updates regarding any changes in our
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 our more significant
accomplishments during the year ended December 31, 2000.

     2000 DRILLING PROGRAM. Our drilling program once again posted strong
results in 2000. We drilled 461 wells, of which 431 wells were completed as
commercial producers for a drilling success rate of 93%. This well count
included nine exploratory wells, 56% of which were completed as producers, and
452 development wells, 94% of which were completed as producers. Through this
program, 278 Bcfe of proved reserves were added to our reserve base at an all-in
finding and development cost (total costs incurred to explore and develop oil
and gas properties divided by proved reserves added through extensions and
discoveries and revisions of previous estimates) of $.86 per Mcfe. The drilling
program replaced 203% of production with drilling capital expenditures totaling
$238.9 million, or 86% of cash flows from operating activities. The year ended
December 31, 2000 marked the seventh consecutive year that reserves added
through our drilling program exceeded production. See "Item 2 -- Properties --
Costs Incurred and Drilling Results."

     PROVED RESERVE ACQUISITIONS. Proved reserve acquisitions in 2000 included
the purchase of substantially all of the oil and gas properties of Costilla
Energy, Inc. for approximately $122 million in cash. The acquired properties
were comprised of 135 Bcfe of net proved reserves included in 1,011 gross (607
net) producing wells at closing. The majority of the Costilla properties are
located within our three core operating areas. We also closed several smaller
acquisitions during the year. In total for 2000, we acquired 204 Bcfe of proved
reserves at an average finding cost of $.82 per Mcfe.

     PROVED RESERVES. Our proved reserves as of December 31, 2000 grew 23% in
relation to 1999 and were comprised of 33 MMBbls of oil and 1.6 Tcf of natural
gas, or 1.8 Tcfe. This reserve growth represents a production replacement ratio
of approximately 350%. Our estimated future net revenues from proved reserves
were $8.0 billion as of December 31, 2000. The present value of future net
revenues discounted at 10% was $3.7 billion. See "Item 2 -- Properties --
Reserves" and Note 13 of the Notes to Consolidated Financial Statements
appearing elsewhere in this document.


                                       5
<PAGE>


     FINANCIAL RESULTS. We reported net income of $98.3 million, or $2.29 per
share, on total revenue of $477.3 million for 2000, the highest net income
reported in our history. This compares to net income of $21.4 million, or $.53
per share, on total revenue of $302.6 million for 1999. We reported record
cash flows from operating activities before working capital changes of $337.4
million for the year ended December 31, 2000, which compares to $171.8
million for 1999, an increase of 96%. Cash flows provided by operating
activities after consideration for the change in working capital was $278.0
million, which compares to $181.6 million for 1999. The year 2000 increase in
earnings and operating cash flows was achieved primarily through significantly
higher oil and gas prices and growth in gas production. Record EBITDAX of
$381.8 million and record oil and gas production of 137 Bcfe were also
achieved in 2000. See "Item 7 -- Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Results of Operations -- Fiscal
Year 2000 Compared to Fiscal Year 1999."

ACQUISITIONS

     We have completed a significant number of proved reserve acquisitions
during the past five years, including two individually large acquisitions for
which we invested $122 million and $340 million, respectively. In 2000, we
acquired substantially all of the oil and gas properties of Costilla Energy,
Inc. for approximately $122 million in cash. The acquired properties were
comprised of 135 Bcfe of net proved reserves included in 1,011 gross (607 net)
producing wells at closing. The majority of the Costilla properties are located
within our three core operating areas. We also closed several smaller
acquisitions during the year. In total for 2000, we acquired 204 Bcfe of proved
reserves at an average finding cost of $.82 per Mcfe. The following table
summarizes our acquisition activity for the five years ended December 31, 2000:

     SUMMARY ACQUISITION INFORMATION

<TABLE>
<CAPTION>
                                                             YEARS ENDED DECEMBER 31,
                                           ------------------------------------------------------
                                              2000       1999       1998        1997       1996       TOTAL
                                           ----------  ---------  ---------  ----------  ---------  ----------
     <S>                                   <C>         <C>        <C>        <C>         <C>        <C>
     Estimated proved reserves acquired
       (Bcfe)............................        204         41          7         234         76         562
     Acquisition cost (MM$)..............  $   167.7   $   36.9   $    4.1   $   349.0   $   36.1   $   593.8
     Acquisition cost per Mcfe (1).......  $     .82   $    .90   $    .56   $    1.49   $    .48   $    1.06
</TABLE>


     ----------------------------------
     (1) - Results for 1997 include the purchase accounting impact of the
           American Exploration acquisition.

     We are actively involved in the screening of potential acquisitions and the
development and implementation of strategies for specific acquisitions. Our
staff of reservoir engineers, geologists, production engineers, landmen and
accountants have substantial experience in evaluating and acquiring oil and gas
reserves. We primarily seek acquisitions in our core areas in which our
experience and existing operations will enable us to readily integrate the
acquired properties. Acquisitions are targeted which emphasize natural gas, have
significant further development and exploration potential, and a high degree of
operatorship. We prefer to operate our properties whenever possible in order to
provide more control over the operation and development of the properties and
the marketing of production. We also pursue additional interests in our operated
properties from holders of non-operating interests to increase our percentage
ownership at attractive acquisition prices.

     The market for proved reserve acquisitions is uncertain and we cannot
predict the amount of capital ultimately to be invested in acquisitions during
2001. Although a significant number of oil and gas properties are predicted to
be placed on the market, higher oil and gas commodity prices are expected to
raise sellers' price expectations.

MARKETING

FIXED-PRICE CONTRACTS

     DESCRIPTION. We have entered into long-term physical delivery contracts,
energy swaps, collars and basis swaps, which we collectively refer to as
fixed-price contracts, to reduce exposure to decreases in oil and gas prices
which are subject to significant and often volatile fluctuation. These contracts
allow us to predict with greater certainty the effective oil and gas prices to
be received for our hedged production and benefit us when market prices are less
than the fixed prices provided in our fixed-price contracts. However, we will
not benefit from market prices that are higher than the fixed prices in such
contracts for our hedged production. At December 31, 2000, these contracts hedge
82 Bcf


                                       6
<PAGE>


of future gas production in 2001, and 120 Bcf thereafter, representing 11% of
estimated total proved reserves. The fixed prices in these 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." We have historically hedged a significant portion of
our natural gas and crude oil production. In recent years, a progressively
smaller share of our production and reserve additions have been hedged due to
our belief that longer-term demand and supply fundamentals for natural gas
imply the potential for continued strength in natural gas prices. More recent
hedging activity has been for shorter periods of time, generally less than 12
months, when market conditions have been viewed as favorable. We 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. We have entered into fixed-price natural gas delivery
contracts with natural gas pipeline marketing affiliates, a municipality, an
independent power producer and other end users. Typically, these contracts
require us 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 100 Bcf of future gas production as of December 31, 2000,
representing 6% of estimated proved natural gas reserves. The contract term
varies with each contract, ranging from a period of less than four years to
approximately 17 years. We meet our 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 us to deliver
natural gas at our choice of several pipeline or customary industry delivery
points, permitting some market flexibility to us 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 AND COLLARS. We enter into energy swaps and collars as a
fixed-price seller in order to reduce our exposure to falling market oil and gas
prices, assuring ourselves of fixed prices for the sale of our oil and gas
production. At December 31, 2000, we were a party to ten energy swaps, which
collectively hedge 62 Bcf of future gas production. The contract term varies
with each contact, ranging from a period of less than one year to approximately
seven 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 and whenever the fixed price exceeds the index
price for a given date or period, the fixed-price purchaser pays the other
party, the fixed-price seller, the difference between the fixed price and the
index price. Whenever the index price is in excess of the fixed price, the
fixed-price seller pays the difference between the index price and the fixed
price to the fixed-price purchaser. 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. 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 we receive the fixed price and pay 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. We were a party to seven fixed-price
collars at December 31, 2000 which hedged 39 Bcf of gas production in 2001.

     COUNTERPARTIES. The following table summarizes certain information
concerning our natural gas fixed-price contracts and associated counterparties
at December 31, 2000:

     NATURAL GAS FIXED-PRICE CONTRACT
               VOLUMES BY COUNTERPARTY

<TABLE>
<CAPTION>
                                                              VOLUMES COMMITTED (BBTU)
                                                    -------------------------------------------    PERCENTAGE
                                                     DELIVERY     ENERGY                            OF TOTAL
                                                    CONTRACTS     SWAPS     COLLARS      TOTAL       VOLUME
                                                    ---------     ------    -------     -------    ----------
     <S>                                            <C>           <C>       <C>         <C>        <C>
     TYPE OF COUNTERPARTY:
     Pipeline marketing affiliates................    50,238      23,420         --      73,658        36%
     Independent power producer...................    30,108          --         --      30,108        15
     Financial institutions.......................        --      17,150     39,100      56,250        28
     Other........................................    20,040      21,900         --      41,940        21
                                                    ---------     ------    -------     -------    ----------
     Total........................................   100,386      62,470     39,100     201,956       100%
                                                    =========     ======    =======     =======    ==========
</TABLE>

     For additional information concerning our fixed-price contracts, see "Item
7A -- Quantitative and Qualitative Disclosures About Market Risk -- Fixed-Price
Contracts."


                                       7
<PAGE>


WELLHEAD MARKETING

     The majority of our wellhead gas production is sold to a variety of
purchasers on the spot market or dedicated to contracts with market-sensitive
pricing provisions. We market substantially all of the undedicated natural gas
produced from our operated wells. Additionally, the majority of the oil and
condensate produced from our operated properties is sold on a market price
sensitive basis. During 2000, we had gas sales to three unrelated purchasers
which approximated 17%, 17% and 14% of total revenues, respectively. See Note
9 of the Notes to Consolidated Financial Statements appearing elsewhere in
this document. The loss of any wellhead purchaser is not anticipated to have
a material adverse effect on us because there are a substantial number of
alternative purchasers in the markets in which we sell our wellhead
production.

COMPETITION

     The oil and gas industry is highly competitive. We compete 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
us. Competition in the regions in which we own properties may result in
occasional shortages or unavailability of drilling rigs and other equipment used
in drilling activities, and limited pipeline capacity and access. These
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. We believe that our acquisition, development, production and marketing
capabilities, financial resources and the experience of our management and staff
enable us 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,
we are unable to predict the future cost or impact of complying with such
regulations. We believe that our 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 our operations than on other similarly situated companies
in the oil and gas industry.

DRILLING AND PRODUCTION

     Our operations are subject to various types of regulation at federal, state
and local levels. This 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. Our 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 we can produce from our wells or
limit the number of wells or the locations at which we can drill.

     We have 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, a federal agency commonly
referred to as the MMS. 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. For offshore operations,
lessees must obtain MMS approval for exploration, development and production
plans prior to commencement. 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.


                                       8

<PAGE>


With respect to any of our 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 of our operations on federal leases to be suspended or terminated
in the affected area.

ENVIRONMENTAL

     Our 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 our 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 we
believe that our 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.

     Our operations may generate wastes that are subject to the Federal Resource
Conservation and Recovery Act and comparable state statutes. The Environmental
Protection Agency, also referred to as 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 the Federal Resource Conservation
and Recovery Act 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 our operating costs,
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 us.

     The Comprehensive Environmental Response, Compensation and Liability Act,
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. The superfund law 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, we generate wastes that may
fall within this act's definition of "hazardous substances." We may be
responsible under the act for all or part of the costs to clean up sites at
which these substances have been disposed. We have 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.

     Our operations are subject to the requirements of the Federal Occupational
Safety and Health Act and comparable state statutes. The Federal Occupational
Safety and Health Act 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 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. The act 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


                                       9
<PAGE>


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 our 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, also referred to as the
FERC, under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978.
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 us, 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.

     We own a 75-mile intrastate pipeline and associated compression facilities
in the Sonora area of West Texas. Approximately 93% of the gas transported in
this pipeline system during 2000 was owned by us. The operation of this system
is subject to regulation by the Texas Railroad Commission.

CERTAIN OPERATIONAL RISKS

     Our operations are subject to the risks and uncertainties associated with
drilling, producing and transporting oil and gas. We 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. Our prospects for future growth will depend on our ability
to replace current reserves through drilling, acquisitions, or both. Our ability
to market our 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 our control.

     Our 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 us 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. Our 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, we
maintain insurance against some, but not all, of the risks described above.
There can be no assurance that the levels of insurance maintained by us will be
adequate to cover any losses or liabilities. We cannot predict the continued
availability of insurance or its availability at commercially acceptable premium
levels.

EMPLOYEES

     As of February 1, 2001, we had approximately 400 employees. We believe that
relations with our employees are satisfactory. Our employees are not covered by
a collective bargaining agreement.

RELATIONSHIP BETWEEN THE COMPANY AND S.A. LOUIS DREYFUS ET CIE

     S.A. Louis Dreyfus et Cie beneficially owns approximately 44% of our common
stock. Through their effective ability to elect all of our directors, S.A. Louis
Dreyfus et Cie has the ability to control our business and affairs, including
decisions with respect to the acquisition or disposition of assets and the
future issuance of common stock or other securities. S.A. Louis Dreyfus et Cie
also has the ability to control our 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 their subsidiaries pending the outcome of an appeal
of the judgment. This appeal is expected to be completed during 2001. The
judgment is unrelated to us. The sale of all or a portion of these shares after
the completion of the appeal could result in a change in control. 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.


                                      10
<PAGE>


     We have a services agreement with S.A. Louis Dreyfus et Cie pursuant to
which S.A. Louis Dreyfus et Cie provides various services (principally
insurance-related services). These services historically have been supplied to
us by S.A. Louis Dreyfus et Cie, and the services agreement provides for the
further delivery of these services, but only to the extent requested by us. We
reimburse S.A. Louis Dreyfus et Cie for a portion of the salaries of employees
performing requested services based on the amount of time expended, 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 allocated salary costs. The
services agreement will continue until terminated by either party upon 60 days
prior written notice to the other party. In the event of termination of the
services agreement by S.A. Louis Dreyfus et Cie, we have an option to continue
the agreement for up to 180 days to enable us to arrange for alternative
services. Substantially all the services provided under the agreement in 2000
relate to participation in certain insurance programs of S.A. Louis Dreyfus
et Cie.

POTENTIAL CONFLICTS OF INTEREST

     The nature of our business and that of S.A. Louis Dreyfus et Cie may give
rise to conflicts of interest between us. Conflicts could arise, for example,
with respect to intercompany transactions between us 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.

     We and S.A. Louis Dreyfus et Cie have entered into intercompany
transactions and agreements incident to our respective businesses in the past.
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 both parties that we operate independently,
other than receiving services as contemplated by the services agreement, but we
may enter into material intercompany transactions. In any event, we intend that
the terms of any future transactions and agreements between us will be at least
as favorable to us as could be obtained from unaffiliated third parties.

     S.A. Louis Dreyfus et Cie does not currently engage in oil and gas
acquisition, development or exploration activities except through its beneficial
ownership of our 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, engage in
these activities directly or indirectly in the future. 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. We have not adopted any special procedures to address
potential conflicts of interest between us relating to such potential
competition. However, we do not currently anticipate that any potential
competition with S.A. Louis Dreyfus et Cie for fixed-price contracts would
adversely affect our ability to hedge our production.

RECENT SALES OF UNREGISTERED SECURITIES

     In December 2000, we issued a total of 363,541 shares of common stock to
four purchasers upon exercise of outstanding warrants. The warrants were
initially issued by American Exploration Company and were assumed by us in
connection with the acquisition of American Exploration Company in 1997. The
exercise price of the warrants was $17.69 per share of common stock, and the
exercise was paid by the warrant holders by the surrender of portions of the
warrants having a value at the time of surrender equal to the exercise price
paid as permitted by the terms of the warrants. The shares of common stock
issued upon exercise of the warrants were issued in reliance on the exemption
from registration afforded by Section 4(2) of the Securities Act of 1933, as
amended. Among the facts supporting our reliance on such exemption are that the
warrants were originally privately placed to, and continued to be held by, a
small group of institutional investors and that the investors acquired the
warrants and the underlying shares for their own accounts and without intention
of distributing or reselling the shares except in compliance with applicable
securities laws. We registered the resale of the shares by the holders in
accordance with the registration rights of the holders under the terms of the
warrants.

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.


                                      11
<PAGE>


     BBTU.  Billion Btus.

     DEVELOPED ACREAGE. The number of acres which are allocated or assignable to
producing wells or wells capable of production.

     DEVELOPMENT LOCATION.  A location on which a development well can be
drilled.

     DEVELOPMENT WELL. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive in an
attempt to recover proved undeveloped reserves.

     DRILLING UNIT. An area specified by governmental regulations or orders or
by voluntary agreement for the drilling of a well to a specified formation or
formations which may combine several smaller tracts or subdivides a large tract,
and within which there is usually some right to share in production or expense
by agreement or by operation of law.

     DRY HOLE. A well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.

     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. We believe 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 fixed-price contracts.

     PRODUCTIVE WELL. A well that is producing oil or gas or that is capable of
production.

     PROVED DEVELOPED RESERVES. Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.


                                      12
<PAGE>


     PROVED RESERVES. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, that is, prices and costs as
of the date the estimate is made.

     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 total 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

     Our oil and gas acquisition, exploration and development activities are
conducted mainly in our core areas: the Permian Region which includes west
Texas, southeast New Mexico and the San Juan Basin; the Mid-Continent Region
which includes 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, 2000
consisted of 33 MMBbls of oil and 1.6 Tcf of natural gas, totaling 1.8 Tcfe. We
have ownership interests in approximately 10,000 producing wells, and we operate
approximately 3,900 of these wells. Our operated wells contain 79% of our total
proved reserves. Net average daily production during 2000 was 7.8 MBbls of oil
and 327.5 MMcf of natural gas, or 374.4 MMcfe. We drilled 452 developmental oil
and gas wells, of which 426 wells, or 94%, were completed as commercial
producers, and nine exploratory wells, of which five wells, or 56%, were
successfully completed, during 2000.

     We have allocated $290 million for our 2001 drilling program, subject to
revision based upon oil and gas prices, proved reserve acquisitions and other
factors. Approximately $64 million of this total, or 22%, has been allocated to
exploration activities and $226 million, or 78%, has been allocated to
development activities. We expect that this drilling expenditure will result in
the drilling of about 590 wells, including 20 exploratory wells and 570
development wells. See "Item 7 -- Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Outlook for Fiscal Year 2001."


                                      13
<PAGE>


CORE AREAS

     The following table sets forth certain information regarding our activities
in each of our principal producing areas as of December 31, 2000:

     CORE AREAS

<TABLE>
<CAPTION>
                                                                            MID-         GULF
                                                             PERMIAN     CONTINENT       COAST       TOTAL
                                                            ----------   ----------   ----------   ----------
     <S>                                                    <C>          <C>          <C>          <C>
     PROPERTY STATISTICS:
     Proved reserves (Bcfe)...............................         906          577          325        1,808
     Percent of total proved reserves.....................          50%          32%          18%         100%
     Gross producing wells................................       5,668        3,368          927        9,963
     Net producing wells..................................       2,528        1,169          308        4,005
     Gross acreage........................................   1,349,200      952,484      452,935    2,754,619
     Net acreage..........................................     560,422      455,188      214,567    1,230,177
     Potential drill sites................................       1,205          745          174        2,124

     2000 RESULTS:
     Gross wells drilled..................................         354           61           46          461
     Gross successful wells...............................         343           53           35          431
     Drilling success.....................................          97%          87%          76%          93%
     Production (Bcfe)....................................        47.7         38.2         51.1        137.0
     Average net daily production (MMcfe).................       130.2        104.5        139.7        374.4
     Lease operating expense per Mcfe.....................  $      .45   $      .46   $      .34   $      .41

     2001 DRILLING BUDGET (MM$):
     Development..........................................  $      115   $       55   $       56   $      226
     Exploration..........................................           4           10           50           64
                                                            ----------   ----------   ----------   ----------
     Total................................................  $      119   $       65   $      106   $      290
                                                            ==========   ==========   ==========   ==========
</TABLE>


PERMIAN REGION

     We are actively involved in development and exploration activities in
several areas within the Permian Region. These areas include the Sonora area of
west Texas and the Delaware Basin of southeast New Mexico, among others. Our
properties in the Permian Region contain 906 Bcfe of proved reserves,
representing approximately one-half of our total reserve base, in 5,668 wells.
We drilled 354 wells in the Permian Region in 2000 and daily production averaged
130 MMcfe per day. We have identified 1,205 potential locations in this region
of which 478 have been assigned proved undeveloped reserves. Plans for this
region in 2001 include the drilling of approximately 430 wells and a total
investment of $119 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 primarily 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. We own an average
60% working interest in 3,497 wells and operate 2,038 of these wells. In our
operated wells, we own an average 98% working interest. Net daily production
from the Sonora area during 2000 averaged 95 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 Canyon infill drilling. Initial wells were drilled on 640 acre
drilling units, but well performance characteristics have shown that denser well
spacing is necessary for effective drainage. We continue to drill infill wells
in these units and, in some areas, the Canyon is 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


                                      14
<PAGE>


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 us. Because the Strawn formation lies less than 1,000
feet below the Canyon formation, the incremental cost to evaluate the Strawn
has been relatively minor. Strawn production is generally commingled with the
Canyon production stream.

     We have maintained an aggressive development drilling program in the Sonora
area since 1993, having drilled 917 Canyon and Strawn wells with only 29 dry
holes. The 2000 drilling program resulted in the drilling of 210 wells, 204 of
which were completed as commercial producers. We plan to drill approximately 300
wells in Sonora during 2001, the majority of which are relatively low risk
locations. We have identified over 1,000 potential locations on our acreage, of
which 407 have been assigned proved undeveloped reserves. Subject to further
study and drilling results, we believe additional proved reserves will
ultimately be attributed to many of the other locations. In addition to infill
drilling potential, a number of recompletion possibilities are present in
existing wellbores.

SOUTHEAST NEW MEXICO

     We are also active in southeastern New Mexico in the Delaware Basin, where
the primary objectives are the Morrow sand and the Wolfcamp carbonate. The
Morrow sands are deposited in fluvial channels which trend from northwest to
southeast. The Wolfcamp carbonate in our 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 3D
seismic technology and computerized mapping. It is anticipated that
approximately 55 wells will be drilled in this region in 2001.

MID-CONTINENT REGION

     We have been actively involved in the Mid-Continent Region since our
inception and over the past ten years have acquired substantial additional
acreage and proved reserves in the area through multiple synergistic
acquisitions. We operate approximately 1,370 wells in the Mid-Continent Region.
Our 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 properties in east Texas. Development of our 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. Our two primary areas of focus in the
Mid-Continent are the Watonga-Chickasha Trend in central Oklahoma and the Tuttle
field in southern Oklahoma.

     We have pursued an active low-risk infill drilling program in the
Mid-Continent area over the past five years, including the drilling of 61 wells
in 2000. Average net daily production during 2000 was 104 MMcfe per day for this
region. We have ownership in 3,368 wells with proved reserves of 577 Bcfe. We
have identified 745 potential locations in the Mid-Continent Region, of which
216 have been assigned proved undeveloped reserves. We plan to drill
approximately 115 wells in this area during 2001.

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. We plan to
drill at least two exploratory tests seeking to discover new bars or channels
and approximately 40 development wells during 2001.

TUTTLE FIELD

     The primary objectives in the Tuttle field are the Mississippi, Mayes,
Skinner and Hunton sands, with the total depth of wells drilled in this field
averaging 10,000 feet. We operate 131 gross wells in the field and own an
average 53%


                                      15
<PAGE>


working interest. During 2000, we successfully completed 12 wells and
significantly increased our ownership through an acquisition late in the
third quarter. Net daily production during 2000 averaged 9 MMcfe per day. We
plan to drill approximately 15 development wells in this field in 2001.

     SMACKOVER TREND. Our operations in the Smackover Trend of southwestern
Arkansas are focused primarily in the Midway field, which we operate. The Midway
field is located in Lafayette County, Arkansas and produces oil from the
Smackover formation at an average depth of 6,500 feet. We own an average 81%
working interest in this waterflood unit.

GULF COAST REGION

     We made our first acquisition in the Gulf Coast Region in 1991 and began
development drilling activities in this area in 1992. We are now actively
involved in an extensive exploration and development program in south Texas and,
to a lesser extent, offshore in the Gulf of Mexico. Our properties in this
region number 927 wells and include 325 Bcfe of proved reserves. We drilled 46
wells in the Gulf Coast Region during 2000 and daily production averaged 140
MMcfe per day. We have identified 174 potential locations in this region of
which 76 have been assigned proved undeveloped reserves. Plans for this region
in 2001 include the drilling of approximately 45 wells and a total investment of
$106 million, including acreage and seismic acquisition.

LAVACA COUNTY AREA

      We began our 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, 1998 and 2000 have more
than doubled our interests in these fields and have expanded our position in the
Wilcox Trend further to the east to include the Provident City field.

      We now hold working interests ranging from 30% to 100% in 65,000 gross
acres in Lavaca County. Since this project began, we have participated in 76
Lower Wilcox wells, over 80% of which have been successfully completed as
producers. Approximately 1,200 square miles of high-fold 3D seismic data has
been acquired since 1996 which continues to be evaluated. The target zones are
the Lower Wilcox sands from 11,000 to 17,000 feet and the shallow Miocene, Frio,
Yegua and Upper Wilcox sands ranging in depth from 3,500 to 8,000 feet.

     Our Lower Wilcox drilling program in 2000 resulted in the successful
completion of 26 wells, including five 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 200
Bcf per field. Production rates for wells drilled in this program have ranged as
high as 40 MMcfe per day. Drilling plans for 2001 include approximately 45 Lower
Wilcox wells in Lavaca County, of which 13 are expected to be exploratory.

WILCOX TREND

     As an extension to our Wilcox success in Lavaca County, we acquired
leasehold positions in Zapata, Goliad and Webb Counties during 1999. In the En
Seguido field located in Zapata County, we drilled the Laura Lopez #1 well,
which was completed at a rate of 16 MMcf of natural gas per day. An offset
development well was completed during 2000 at a rate of over 40 MMcf of natural
gas per day. Three additional development wells were completed in this field
during 2000 at a combined rate of 16 MMcf per day. Up to three additional En
Seguido wells are planned for 2001. In addition to this En Seguido field
activity, we completed two Wilcox tests on the W. Martinez prospect, also in
Zapata County, which is ten miles to the north of En Seguido. Initial production
for these two wells was a combined 12 MMcf per day. In total, we own
approximately 15,000 gross acres in Zapata County with working interests ranging
from 38% to 100%. We also own 500 square miles of 3D seismic information in
Zapata County and plan to drill a total of six development wells and three
exploratory wells in 2001.

     In Goliad County, we acquired approximately 3,100 gross acres in two
prospects, the Cologne and Swickheimer prospects. Our working interests in these
prospects range from 37% to 54%. Two exploratory tests for the Lower Wilcox were
completed in 2000 for a combined rate of 12 MMcf of natural gas per day. At
least one additional exploratory test is planned for 2001 in the Cologne
prospect.


                                      16

<PAGE>

OFFSHORE AREA

     We own working interests in seven operated and nine outside-operated oil
and gas production platforms and 200,000 acres in the Gulf of Mexico. Average
net daily production from our offshore properties was 34 MMcfe per day in
2000.

     TEXAS STATE WATERS. We own an average 80% working interest in more than
50,000 gross acres in the Texas State Waters area. In addition, we have acquired
3,000 square miles of 3D seismic data in this offshore area. We have identified
several exploration prospects in the shallow waters offshore in the Gulf of
Mexico, at least two of which we plan to drill in 2001.

     HIGH ISLAND 45. High Island Block 45 is located in shallow federal waters,
offshore Texas. We are the operator and own 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
2000.

RESERVES

     The following table presents the estimated net quantities of our proved and
proved developed reserves, and the estimated future net revenues, and the
estimated present values attributable to total proved reserves for each of the
preceding five years.


<TABLE>
<CAPTION>

     PROVED RESERVES                                                       AS OF DECEMBER 31,
                                                         ----------------------------------------------------
                                                           2000       1999       1998       1997       1996
                                                         --------   --------   --------   --------   --------
                                                                (DOLLARS IN MILLIONS, EXCEPT PRICE DATA)
     <S>                                                 <C>        <C>        <C>        <C>        <C>
     ESTIMATED PROVED RESERVES:
     Natural gas (Bcf).................................   1,608.5    1,294.0    1,193.7    1,028.8      849.2
     Oil (MMBbls)......................................      33.3       28.4       24.4       29.1       23.5
     Total (Bcfe)......................................   1,808.0    1,464.3    1,340.2    1,203.4      990.2

     Estimated future net revenue......................  $8,018.9   $2,136.0   $1,676.8   $1,926.0   $2,643.8
     Present value discounted at 10%...................  $3,734.0   $1,049.7   $  811.1   $1,002.6   $1,303.7

     ESTIMATED PROVED DEVELOPED RESERVES:
     Natural gas (Bcf).................................   1,313.6    1,064.7    1,026.8      899.2      709.7
     Oil (MMBbls)......................................      27.9       23.9       20.7       24.3       17.9
     Total (Bcfe)......................................   1,481.0    1,208.4    1,151.2    1,045.1      817.1

     YEAR-END PRICES USED IN ESTIMATING FUTURE
        NET REVENUES:
     Natural gas (per Mcf).............................  $   6.07   $   2.19   $   2.07   $   2.49   $   3.82
     Oil (per Bbl).....................................  $  25.38   $  24.36   $   9.46   $  16.76   $  24.70

</TABLE>

     No estimates of our proved reserves comparable to those included herein
have been included in reports to any federal agency other than the Securities
and Exchange Commission.

     Our estimated proved reserves as of December 31, 2000 are based upon
studies prepared by our staff of engineers and reviewed by Ryder Scott Company,
independent petroleum engineers. Estimated recoverable proved reserves have been
determined without regard to any economic impact that may result from our
fixed-price contracts. These 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 values were based on the engineers'
production volume estimates as of each year-end. 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 significant increase in estimated future net revenues and present value
as of December 31, 2000 primarily resulted from a 177% increase in year-end
natural gas prices. We estimate 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 of future net revenues would change

                                      17

<PAGE>

the present value by $16 million and $67 million, respectively.

There are numerous uncertainties inherent in estimating quantities of proved
oil and natural gas reserves and their values, and in projecting future rates
of production and timing of development expenditures, including many factors
beyond our control. The reserve information shown is estimated. Reserve
engineering is a subjective process of estimating underground accumulations
of oil and gas that cannot be measured in an exact manner. The accuracy of
any reserve estimate is a function of the quality of available data, the
precision of the engineering and geological interpretation, and judgment. As
a result, estimates of different engineers often vary. The estimates of
reserves, future cash flows and present value are based on various
assumptions, including those prescribed by the Securities and Exchange
Commission, and are inherently imprecise. Actual future production, cash
flows, taxes, development expenditures, operating expenses and quantities of
recoverable oil and natural gas reserves may vary substantially from our
estimates. Also, the use of a 10% discount factor for reporting purposes may
not necessarily represent the most appropriate discount factor, given actual
interest rates and risks to which our business or the oil and natural gas
industry in general are subject.

     Quantities of proved reserves are estimated based on economic conditions,
including oil and natural gas prices in existence at the date of assessment. A
reduction in oil and gas prices not only would reduce the value of any proved
reserves, but also might reduce the amount of oil and gas that could be
economically produced, thereby reducing the quantity of reserves. Our reserves
and future cash flows may be subject to revisions, based upon changes in
economic conditions, including oil and natural gas prices, as well as due to
production results, results of future development, operating and development
costs, and other factors. Downward revisions of our reserves could have an
adverse affect on our financial condition and operating results.

     For further information on reserves, future net revenues and the
standardized measure of discounted future net cash flows, see Note 13 of the
Notes to Consolidated Financial Statements appearing elsewhere in this document.

COSTS INCURRED AND DRILLING RESULTS

     The following table presents certain information regarding the costs
incurred in our acquisition, exploration and development activities for each of
the preceding five years.


<TABLE>
<CAPTION>

     COSTS INCURRED                                                      AS OF DECEMBER 31,
                                                    ---------------------------------------------------------
                                                       2000        1999        1998        1997        1996
                                                    ---------   ---------   ---------   ---------   ---------
                                                                           (IN THOUSANDS)
     <S>                                            <C>         <C>         <C>         <C>         <C>
     Property acquisition costs: (1)
     Proved.......................................  $ 167,714   $  36,881   $   4,088   $ 349,037   $  36,125
     Unproved.....................................     18,375      10,766      11,815     109,648       6,934
                                                    ---------   ---------   ---------   ---------   ---------
                                                      186,089      47,647      15,903     458,685      43,059
     Exploration costs............................     23,729      19,409      74,123      21,514      10,610
     Development costs............................    196,741     116,597     136,462     122,402      80,553
                                                    ---------   ---------   ---------   ---------   ---------
     Total........................................  $ 406,559   $ 183,653   $ 226,488   $ 602,601   $ 134,222
                                                    =========   =========   =========   =========   =========

</TABLE>

     -------------------------------

     (1) - Proved and unproved property acquisition costs for 1997 include
           $339.9 million and $98.0 million, respectively, of allocated American
           Exploration acquisition purchase price.

     Proceeds from the sale of oil and gas properties for this same five-year
period were as follows: 2000: $11.2 million; 1999: $12.4 million; 1998: $14.3
million; 1997: $27.7 million; and 1996: $.7 million.

                                      18

<PAGE>

     We drilled or participated in the drilling of wells as set out in the table
below for the periods indicated.


<TABLE>
<CAPTION>

     WELLS DRILLED                                               YEARS ENDED DECEMBER 31,
                                    --------------------------------------------------------------------------
                                        2000           1999           1998            1997            1996
                                    ------------   ------------   -------------   ------------   -------------
                                    GROSS    NET   GROSS    NET   GROSS     NET   GROSS    NET   GROSS     NET
                                    -----    ---   -----    ---   -----     ---   -----    ---   -----     ---
     <S>                            <C>      <C>   <C>      <C>   <C>       <C>   <C>      <C>   <C>       <C>
     Development wells:
     Gas.........................     408    280    191     156     237     153    223     166     179     130
     Oil.........................      18     11      5       2      60      37     52      20      92      19
     Dry.........................      26     20     17      12      27      20     20      14       9       5
                                    -----    ---   -----    ---   -----     ---   -----    ---   -----     ---
     Total.......................     452    311    213     170     324     210    295     200     280     154
                                    =====    ===   =====    ===   =====     ===   =====    ===   =====     ===
     Exploratory wells:
     Gas.........................       5      2     13       8      13       8     32      24      18       6
     Oil.........................       -      -      1       1       1       1      4       3       -       -
     Dry.........................       4      3      2       2      13       9     12       9       7       2
                                    -----    ---   -----    ---   -----     ---   -----    ---   -----     ---
     Total.......................       9      5     16      11      27      18     48      36      25       8
                                    =====    ===   =====    ===   =====     ===   =====    ===   =====     ===

</TABLE>

     As of December 31, 2000 we were involved in the drilling, testing or
completing of 14 gross (8 net) development wells. No exploratory wells were in
progress at December 31, 2000.

ACREAGE

     The following table presents our developed and undeveloped oil and gas
lease and mineral acreage as of December 31, 2000. Excluded is acreage in which
our interest is limited to royalty, overriding royalty and other similar
interests.


<TABLE>
<CAPTION>

     ACREAGE                                                         DEVELOPED               UNDEVELOPED
                                                                ---------------------   ---------------------
                                                                   GROSS        NET        GROSS        NET
                                                                ---------     -------   ---------     -------
     <S>                                                        <C>           <C>       <C>           <C>
     Core Area:
     Permian..................................................    769,147     335,794     580,053     224,628
     Mid-Continent............................................    567,207     298,740     385,277     156,448
     Gulf Coast...............................................    234,499      85,453     218,436     129,114
                                                                ---------     -------   ---------     -------
     Total....................................................  1,570,853     719,987   1,183,766     510,190
                                                                =========     =======   =========     =======

</TABLE>

PRODUCTIVE WELL SUMMARY

     The following table presents our ownership in productive wells at December
31, 2000. Gross oil and gas wells include 172 wells with multiple completions.
Wells with multiple completions are counted only once for purposes of the
following table.


<TABLE>
<CAPTION>

     PRODUCTIVE WELLS                                                                        PRODUCTIVE WELLS
                                                                                            -----------------
                                                                                            GROSS        NET
                                                                                            -----       -----
     <S>                                                                                    <C>         <C>
     Gas..............................................................................      6,272       3,227
     Oil..............................................................................      3,691         778
                                                                                            -----       -----
     Total............................................................................      9,963       4,005
                                                                                            =====       =====

</TABLE>

TITLE TO PROPERTIES

     We believe that we have satisfactory title to our properties in accordance
with standards generally accepted in the oil and gas industry, subject to such
exceptions which, in our opinion, are not so material as to detract
substantially from the use or value of our properties. We perform extensive
title review in connection with acquisitions of proved reserves and have
obtained title opinions on substantially all of our 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.

     Our 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

                                      19

<PAGE>

information presented herein is presented net of such interests. Our
properties are also subject to liens for current taxes not yet due and other
encumbrances. We believe 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

     We are 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 an underground hydrocarbon plume
within the city of McAllen, Texas. The lawsuit alleges that gas wells and
related pipeline facilities owned and operated by us, and other facilities
operated by other defendants, caused the plume. In August 1999, the plaintiffs'
experts produced reports that suggested we might be considered a significant
contributor to the plume. Our investigation into this matter has not found any
leaks or discharges from our facilities. In addition, our investigation has
revealed the plume to be unrelated to our gas wells and facilities. Trial is not
anticipated to commence until the second half of 2001. We will vigorously defend
our interests in this case. We do not expect the ultimate outcome of the case to
have a material adverse impact on our financial position or results of
operations; however, results of litigation are inherently unpredictable and this
estimate may change in the future.

     We were a defendant in various other legal proceedings as of December 31,
2000 which are routine and incidental to our business. We will vigorously defend
our interests in these proceedings. While the ultimate results of all these
proceedings cannot be predicted with certainty, we do not believe that the
outcome of these matters will have a material adverse effect on our financial
position or results of operations.

ITEM 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     During the quarter ended December 31, 2000, no matters were submitted by us
to a vote of security holders.

                                    PART II

ITEM 5 -- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
          MATTERS

     Our common stock is listed on the New York Stock Exchange and traded under
the symbol "LD." As of February 22, 2001, we estimate there were approximately
11,000 beneficial owners of our common stock. The high and low sales prices for
our common stock during each quarter in the years ended December 31, 2000 and
1999, were as follows:


<TABLE>
<CAPTION>

     COMMON STOCK MARKET PRICES                                             2000                  1999
                                                                     ------------------   -------------------
                                                                       HIGH       LOW        HIGH        LOW
                                                                     -------    -------   --------   --------
     <S>                                                             <C>        <C>       <C>        <C>
     QUARTER:
     First........................................................   $ 34.00    $ 15.75   $  15.75   $  11.06
     Second.......................................................     35.00      24.00      22.00      14.25
     Third........................................................     40.13      25.19      23.31      18.88
     Fourth.......................................................     48.19      29.94      21.50      16.00

</TABLE>

     We have 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 our 9 1/4% Senior Subordinated Notes due 2004
restrict our 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 our 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 our earnings, capital needs and
general financial condition.

                                      20

<PAGE>

ITEM 6 -- SELECTED FINANCIAL DATA

     The selected financial data presented below as of December 31, 2000 and
1999, and for each of the three years ended December 31, 2000, 1999 and 1998,
has been derived from, and is qualified by reference to, our audited
consolidated financial statements, including the notes thereto, contained in
this document beginning at page F-1. The selected financial data as of December
31, 1998, 1997 and 1996, and for the years ended December 31, 1997 and 1996, 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 our
consolidated financial statements, including the associated notes, and "Item 7
-- Management's Discussion and Analysis of Financial Condition and Results of
Operations."
<TABLE>
<CAPTION>
     SELECTED FINANCIAL DATA                                        YEARS ENDED DECEMBER 31,
                                                    ---------------------------------------------------------
                                                      2000(2)     1999        1998(3)     1997(4)      1996
                                                    ---------   ---------   ---------   ---------   ---------
                                                              (IN THOUSANDS, EXCEPT PER SHARE DATA)
     <S>                                            <C>         <C>         <C>         <C>         <C>
     STATEMENT OF OPERATIONS DATA:
     Oil and gas sales............................  $ 489,703   $ 290,878   $ 271,575   $ 222,016   $ 185,558
     Change in derivative fair value..............    (15,562)       (442)     17,346          --          --
     Other income.................................      3,144      12,170       4,462      10,901       3,947
                                                    ---------   ---------   ---------   ---------   ---------
       Total revenues.............................    477,285     302,606     293,383     232,917     189,505
                                                    ---------   ---------   ---------   ---------   ---------
     Operating costs..............................     86,915      66,039      66,295      49,169      44,615
     General and administrative...................     24,144      23,995      25,971      18,855      16,325
     Exploration costs............................     25,654      14,258      34,543       8,956       4,965
     Depreciation, depletion and amortization.....    129,323     117,080     131,408      79,325      65,278
     Impairment...................................     10,439       4,877      52,522      75,198          --
     Interest.....................................     41,431      40,667      40,849      28,737      26,822
                                                    ---------   ---------   ---------   ---------   ---------
       Total expenses.............................    317,906     266,916     351,588     260,240     158,005
                                                    ---------   ---------   ---------   ---------   ---------
     Income (loss) before income taxes and
       cumulative effect of accounting change.....    159,379      35,690     (58,205)    (27,323)     31,500
     Income tax provision (benefit)...............     61,119      14,276     (13,924)    (11,261)     10,398
                                                    ---------   ---------   ---------   ---------   ---------
     Net income (loss) before cumulative effect
       of accounting change.......................     98,260      21,414     (44,281)    (16,062)     21,102
     Cumulative effect of accounting change, net
       of tax.....................................         --          --         964          --          --
                                                    ---------   ---------   ---------   ---------   ---------
     Net income (loss)............................  $  98,260   $  21,414   $ (43,317)  $ (16,062)  $  21,102
                                                    =========   =========   =========   =========   =========
     Net income (loss) before cumulative effect
       of accounting change per share.............  $    2.29   $     .53   $   (1.10)  $    (.53)  $     .76
     Cumulative effect of accounting change per
       share......................................         --          --         .02          --          --
                                                    ---------   ---------   ---------   ---------   ---------
     Net income (loss) per share - diluted........  $    2.29   $     .53   $   (1.08)  $    (.53)  $     .76
                                                    =========   =========   =========   =========   =========

     Weighted average basic common shares.........     41,830      40,153      40,107      30,233      27,800
     Weighted average diluted common shares.......     42,836      40,389      40,107      30,233      27,810

     STATEMENT OF CASH FLOWS DATA:
     Net cash provided by operating activities....  $ 277,953   $ 181,556   $ 147,438   $ 129,846   $ 101,761
     Net cash used in investing activities........    399,581     167,662     215,274     216,603     150,857
     Net cash provided by (used in) financing
       activities.................................    114,767      (6,773)     64,837      84,546      55,261
     EBITDAX (1)..................................    381,788     213,014     183,771     164,893     128,565
<CAPTION>
                                                                        AS OF DECEMBER 31,
                                                   ----------------------------------------------------------
                                                      2000(2)     1999        1998(3)     1997(4)      1996
                                                   ----------  ----------  ----------  ----------  ----------
                                                                          (IN THOUSANDS)
     <S>                                           <C>         <C>         <C>         <C>         <C>
     BALANCE SHEET DATA:
     Oil and gas properties, net.................. $1,340,493  $1,104,804  $1,064,206  $1,077,091   $ 652,257
     Total assets.................................  1,501,965   1,227,087   1,283,808   1,210,954     733,613
     Long-term debt, including current portion....    606,909     555,222     596,844     563,344     343,907
     Stockholders' equity.........................    532,819     498,782     519,461     469,204     263,693
</TABLE>
     -------------------------------
     (1) -  See "Item 1 -- Business -- Certain Definitions."
     (2) -  We closed the acquisition of oil and gas properties from Costilla
            Energy Inc. in June 2000.
     (3) -  We adopted SFAS 133 in October 1998. See Note 1 of the Notes to
            Consolidated Financial Statements appearing elsewhere in this
            document.
     (4) -  We closed the acquisition of American Exploration in October 1997.

                                      21
<PAGE>


ITEM 7 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
          RESULTS OF OPERATIONS

OVERVIEW

     GENERAL. Our 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, 2000, this strategy
has resulted in a 106% increase in proved reserves to 1.8 Tcfe, a 123% increase
in oil and gas production to 137 Bcfe, 211% growth in cash flows from operating
activities to $278.0 million, and a 792% increase in net earnings to $98.3
million. All of these measures for 2000 represent record performance for us.
The growth achieved during 2000 was the result of a capital program that
included $238.9 million in drilling activities and $167.7 million in proved
reserve acquisitions.

     During the five-year period ended December 31, 2000, we drilled 1,689
gross (1,123 net wells), with an overall drilling success rate of 92%, adding
971 Bcfe of reserves (including revisions of previous estimates) to our proved
reserve base. The year ended December 31, 2000 marked the seventh consecutive
year that we replaced our production through our drilling activities. The 2000
drilling program added 278 Bcfe of proved reserves at an all-in finding and
development cost (total costs incurred to explore and develop oil and gas
properties divided by proved reserves added through extensions and discoveries
and revisions of previous estimates) of $.86 per Mcfe. This addition
represented 203% production replacement for 2000. We have increasingly
emphasized exploration as an integral component of our business strategy and in
that connection, have incurred substantial up-front costs, including
significant acreage positions, seismic costs and other geological and
geophysical costs. During 2000, we invested $39 million in connection with
exploration activities, resulting in the acquisition of $22 million of acreage
and seismic information, and the drilling of nine exploratory wells, of which
five were completed as producers.

     A substantial portion of our growth has been the result of proved reserve
acquisitions geographically concentrated in our core operating areas where we
have significant expertise and where we benefit from operational synergies.
During the five-year period ended December 31, 2000, we made proved reserve
acquisitions aggregating 562 Bcfe, purchased for a total consideration of $594
million, or $1.06 per Mcfe. Of particular significance was the acquisition of
oil and gas properties from Costilla Energy, Inc. in 2000, which added 135 Bcfe
of proved reserves, and the acquisition of American Exploration in October
1997, which added 217 Bcfe of proved reserves and an attractive unproved
acreage position.

     As of December 31, 2000, our portfolio of fixed-price contracts hedge 82
Bcf of future gas production in 2001, and 120 Bcf thereafter, at escalating
fixed prices. The average fixed prices in these contracts are lower than the
forward market prices for natural gas as of December 31, 2000. For the year
ending December 31, 2001, our fixed-price natural gas swaps hedge approximately
32 Bcf of gas production at an average fixed price of $4.90 per MMBtu. Our
fixed-price natural gas delivery contracts hedge approximately 18 Bcf of gas
production in 2001 at an average fixed price of $2.38 per MMBtu. Our
fixed-price natural gas collars hedge approximately 32 Bcf of gas production in
2001 at an average floor price of $4.57 per MMBtu and an average ceiling price
of $6.28 per MMBtu. Historically, we have been an active hedger of our
commodity price risk, hedging a portion of our future production out as far as
2017. Over the past few years, competition in fixed-price contracts has
increased, opportunities for attractive long-term fixed-price contracts have
diminished and prices in the forward market beyond one year are considerably
lower than the nearby year. In response to these changes, a progressively
smaller share of our production and reserve growth has been hedged due to our
belief that longer-term demand and supply fundamentals for natural gas imply
the potential for continued strength in natural gas prices. More recent hedging
activity has been for shorter periods of time, generally less than 12 months,
when market conditions have been viewed as favorable. We may decide to hedge a
greater or smaller share of production in the future depending upon market
conditions, capital investment considerations and other factors. See "Item 7A --
Quantitative and Qualitative Disclosures About Market Risk -- Fixed-Price
Contracts."


                                       22
<PAGE>


     SELECTED OPERATING DATA. The following table provides certain data relating
to our operations.

<TABLE>
<CAPTION>

     SELECTED OPERATING DATA                                        YEARS ENDED DECEMBER 31,
                                                    ----------------------------------------------------------
                                                       2000        1999        1998        1997        1996
                                                    ---------   ---------   ---------   ---------   ----------
     <S>                                            <C>         <C>         <C>         <C>         <C>
     OIL AND GAS SALES (M$):
     Oil sales:
       Wellhead...................................  $  82,916   $  51,361   $  42,604   $  40,680   $  39,372
       Effect of fixed-price contract
         settlements (1)..........................     (5,155)     (1,672)      2,159         803      (3,198)
                                                    ---------   ---------   ---------   ---------   ----------
       Total......................................  $  77,761   $  49,689   $  44,763   $  41,483   $  36,174
                                                    =========   =========   =========   =========   ==========
     Natural gas sales:
       Wellhead...................................  $ 469,046   $ 237,976   $ 205,822   $ 185,623   $ 148,244
       Effect of fixed-price contract
         settlements (1)..........................    (57,104)      3,213      20,990      (5,090)      1,140
                                                    ---------   ---------   ---------   ---------   ----------
       Total......................................  $ 411,942   $ 241,189   $ 226,812   $ 180,533   $ 149,384
                                                    =========   =========   =========   =========   ==========

     PRODUCTION:
     Oil production (MBbls).......................      2,860       2,965       3,430       2,088       1,849
     Natural gas production (MMcf)................    119,855     107,979     101,066      71,731      63,910
     Equivalent production (MMcfe)................    137,015     125,769     121,647      84,262      75,004

     Oil production hedged by fixed-price
       contracts (MBbls)..........................      1,156         569         539         686       1,241
     Gas production hedged by fixed-price
       contracts (BBtu)...........................     53,119      59,534      50,823      43,185      32,508

     AVERAGE SALES PRICE:
     Oil price (per Bbl):
       Wellhead price.............................  $   28.99   $   17.32   $   12.42   $   19.48   $   21.29
       Effect of fixed-price contract
         settlements (1)..........................      (1.80)       (.56)        .63         .38       (1.73)
                                                    ---------   ---------   ---------   ---------   ----------
       Total......................................  $   27.19   $   16.76   $   13.05   $   19.86   $   19.56
                                                    =========   =========   =========   =========   ==========
       Average fixed price provided by fixed-price
         contracts................................  $   24.36   $   21.64   $   17.37   $   21.81   $   19.53

     Natural gas price (per Mcf):
       Wellhead price.............................  $    3.91   $    2.20   $    2.03   $    2.59   $    2.32
       Effect of fixed-price contract
         settlements (1)..........................       (.47)        .03         .21        (.07)        .02
                                                    ---------   ---------   ---------   ---------   ----------
       Total......................................  $    3.44   $    2.23   $    2.24   $    2.52   $    2.34
                                                    =========   =========   =========   =========   ==========
       Average fixed price provided by fixed-price
         contracts................................  $    2.77   $    2.47   $    2.60   $    2.51   $    2.43

     Natural gas equivalent price (per Mcfe)......  $    3.57   $    2.31   $    2.23   $    2.63   $    2.47

     EXPENSES AND COSTS INCURRED (PER MCFE):
     Lease operating expenses.....................  $     .41   $     .41   $     .44   $     .45   $     .47
     Production taxes.............................        .22         .12         .11         .14         .12
     General and administrative...................        .18         .19         .21         .22         .22
     Depreciation, depletion and amortization -
       oil and gas properties (2).................        .91         .89        1.04         .88         .82
     Finding cost (3).............................        .84         .70         .85        1.81         .71
</TABLE>

     ------------------------------------

     (1)--"Effect of fixed-price contract settlements" represents the realized
          hedging results from our 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 2000, 1999
          and 1998.
     (2)--Does not include impairments. See "-- Results of Operations -- Fiscal
          Year 2000 Compared to Fiscal Year 1999" and "-- Results of Operations
          -- Fiscal Year 1999 Compared to Fiscal Year 1998."
     (3)--See "Item 1 -- Business -- Certain Definitions." Amounts for 1997
          include the allocated purchase price of the American Exploration
          acquisition pursuant to purchase accounting rules.



                                                      23
<PAGE>



     The following table presents certain information regarding our proved oil
and gas reserves.

<TABLE>
<CAPTION>
                                                                       AS OF DECEMBER 31,
     OIL AND GAS RESERVES DATA                      ---------------------------------------------------------
                                                       2000        1999        1998        1997        1996
                                                    ---------   ---------   ---------   ---------     -------
                                                                      (DOLLARS IN MILLIONS)
     <S>                                            <C>         <C>         <C>         <C>           <C>
     ESTIMATED NET PROVED RESERVES:
     Natural gas (MMcf)...........................  1,608,469   1,294,029   1,193,666   1,028,752     849,199
     Oil (MBbls)..................................     33,258      28,372      24,416      29,109      23,497
     Total (MMcfe)................................  1,808,018   1,464,258   1,340,161   1,203,405     990,179

     Reserve replacement ratio (1)................        352%        207%        219%        396%        254%
     Reserve life (in years) (1) (2)..............       13.2        11.6        11.0        10.7        13.2

     Estimated future net revenues (1) (3)........  $ 8,018.9   $ 2,136.0   $ 1,676.8   $ 1,926.0   $ 2,643.8
     Present value (1) (3)........................  $ 3,734.0   $ 1,049.7   $   811.1   $ 1,002.6   $ 1,303.7
</TABLE>

     ------------------------------------

     (1)--See "Item 1 -- Business -- Certain Definitions."
     (2)--For 1997, pro forma production for the American Exploration
          acquisition of 113.0 Bcfe was used in the reserve life determination.
     (3)--Estimated future net revenues and present values give no effect to our
          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 2000 COMPARED TO FISCAL YEAR 1999

     NET INCOME AND CASH FLOWS FROM OPERATING ACTIVITIES. We reported net
income of $98.3 million, or $2.29 per share, on total revenue of $477.3 million
for the year ended December 31, 2000. This compares to net income of $21.4
million, or $.53 per share, on total revenue of $302.6 million for 1999. Net
income excluding the non-cash impact of SFAS 133 derivative accounting and
nonrecurring impairment charges was $114.3 million, or $2.67 per share, for the
year ended December 31, 2000 and $24.6 million, or $.61 per share, for 1999.
Cash flows from operating activities before working capital changes for 2000
grew 96% to $337.4 million compared to $171.8 million for 1999. Cash flows
provided by operating activities after consideration for the change in working
capital were $278.0 million, which compares to $181.6 million for 1999. The
significant increase in earnings and operating cash flows between the two
periods was principally the result of higher oil and gas prices and higher gas
production.

     PRODUCTION. Total production for the year ended December 31, 2000 grew 9%,
to 137.0 Bcfe, compared to 125.8 Bcfe produced during 1999. Natural gas
production for 2000 was 119.9 Bcf, an 11% increase over the 108.0 Bcf produced
in 1999. Oil production in 2000 decreased 4% to 2.9 MMBbls compared to 3.0
MMBbls produced in 1999. The increase in total production is primarily
attributable to the results of our 2000 exploration and development drilling
program and proved reserve acquisitions made throughout the year.

     OIL AND GAS PRICES. Our 2000 gas production yielded an average price of
$3.44 per Mcf, 54% higher than 1999's average price of $2.23 per Mcf. Our
average gas price was reduced $.47 per Mcf in 2000 and increased $.03 per Mcf
in 1999 as a result of our hedging activities. The average oil price realized
during 2000 increased 62% to $27.19 per Bbl compared to $16.76 per Bbl for
1999. Fixed-price contract settlements decreased the average oil price in 2000
by $1.80 per Bbl and decreased the average oil price in 1999 by $.56 per Bbl.
On a natural gas equivalent basis, we realized an average price of $3.57 per
Mcfe for 2000, a 55% increase compared to the $2.31 per Mcfe received in 1999.

     The combination of higher gas production and higher average gas price for
2000 increased natural gas sales by 71% to $411.9 million, compared to $241.2
million reported for 1999. The net effect of higher oil prices and lower oil
production resulted in a 56% increase in oil sales to $77.8 million, compared
to $49.7 million for the prior-year period. The aggregate impact of fixed-price
contract settlements during each period was a decrease in oil and gas revenues
of $62.3 million in 2000 and an increase in oil and gas revenues of $1.5
million in 1999. See "Item 7A -- Quantitative and Qualitative Disclosures About
Market Risk -- Fixed-Price Contracts."

     CHANGE IN DERIVATIVE FAIR VALUE. We recognized losses in change in
derivative fair value of $15.6 million and $.4 million for the years ended
December 31, 2000 and 1999, respectively. Amounts recorded in this caption
represent non-cash gains and losses created by temporary valuation swings in
derivatives or portions of derivatives which are not entitled to receive hedge
accounting treatment. All amounts recorded in this caption are ultimately
reversed in this caption over the respective contract term. See "Item 7A
--Quantitative and Qualitative Disclosures About Market Risk


                                       24
<PAGE>


-- Fixed-Price Contracts -- Accounting" for a discussion of the components
recorded in this caption.

     OTHER INCOME. We realized other income for 2000 of $3.1 million compared
to $12.2 million for 1999. The amount for 1999 included a nonrecurring pretax
gain of $8.6 million recognized upon the settlement of certain litigation.

     OPERATING COSTS. Operating costs for 2000 were comprised of $56.3 million
of lease operating expenses and $30.6 million of production taxes. This
compares to $51.2 million of lease operating expenses and $14.8 million of
production taxes for 1999. The increase in lease operating expenses is
principally attributable to the costs associated with acquired properties, in
particular the Costilla properties, and wells drilled during the year. On a
natural gas equivalent unit of production basis, lease operating expenses
remained constant in 2000 at $.41 per Mcfe in relation to 1999. The increase in
production taxes in 2000 is attributable to higher oil and gas prices and
higher gas production.

     GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense, or
G&A, for 2000 increased modestly to $24.1 million compared to $24.0 million for
1999. This limited increase is primarily the result of increases in overhead
recoveries associated with a more active drilling program, which largely offset
cost increases during the year. As a result, G&A per natural gas equivalent
unit of production improved to $.18 per Mcfe for 2000 compared to $.19 per Mcfe
for 1999.

     EXPLORATION COSTS. Exploration costs, comprised of geological and
geophysical costs, or G&G costs, exploratory dry hole costs, and leasehold
impairment costs, were $25.7 million for the year ended December 31, 2000
compared to $14.3 million for the year ended December 31, 1999. The 2000 amount
consisted of $5.8 million of seismic acquisition and other G&G costs, $11.0
million of dry hole costs and $8.9 million of leasehold impairments. The 1999
amount consisted of $5.0 million of G&G costs, $1.2 million of dry hole costs
and $8.1 million of leasehold impairments.

     DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense, or DD&A, for the year ended December 31, 2000 was $129.3
million compared to $117.1 million for 1999. This increase is due to an
increase in the oil and gas DD&A rate for 2000 and an increase in gas
production. The oil and gas DD&A rate per equivalent unit of production was
$.91 per Mcfe for 2000 compared to $.89 per Mcfe in 1999. The DD&A rate
increased primarily as a result of production increases in certain higher cost
fields and the cost of the Costilla acquisition.

     IMPAIRMENT. We recorded total impairment charges of $10.4 million during
2000 primarily as a result of downward reserve revisions for two single-well
offshore fields. Overall for 2000, we realized net upward reserve revisions of
approximately 2 Bcfe. In 1999, we recognized impairment charges totaling $4.9
million, also primarily the result of downward reserve revisions for certain
offshore fields. For 1999, we reported net upward reserve revisions of
approximately 12 Bcfe.

     For purposes of determining whether oil and gas properties have been
impaired, we utilize forward market price quotations as of the date of
determination in estimating the future cash flows from our oil and gas
properties. This forward market price information is consistent with that
generally used by us 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 the year-end reserve report are assumed.

     INTEREST EXPENSE. Interest expense for 2000 was $41.4 million which
compares to $40.7 million for 1999. The 2000 increase is primarily due to
higher average debt balances outstanding during the year, principally the
result of the Costilla acquisition. The net impact of interest rate swap
settlements for the year ended December 31, 2000 decreased interest expense by
$1.9 million. The impact of interest rate swap settlements in 1999 was not
material. See "-- Item 7A - Quantitative and Qualitative Disclosures About
Market Risk -- Interest Rate Sensitivity."

     INCOME TAXES. For 2000, we recorded a tax provision of $61.1 million on
pretax income of $159.4 million, an effective rate of 38%. This compares to a
tax provision of $14.3 million, or 40%, on pretax income of $35.7 million for
1999. The effective rate for 1999 varied from the statutory rate due to
permanent differences related to the tax bases


                                       25
<PAGE>


of certain acquired oil and gas properties.

RESULTS OF OPERATIONS -- FISCAL YEAR 1999 COMPARED TO FISCAL YEAR 1998

     NET INCOME (LOSS) AND CASH FLOWS FROM OPERATING ACTIVITIES. We 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 operating 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 our 1999 net capital expenditure program which was funded solely
through cash flows from operating activities.

     OIL AND GAS PRICES. Our 1999 gas production yielded an average price of
$2.23 per Mcf, slightly lower than 1998's average price of $2.24 per Mcf. Our
average gas price was enhanced $.03 per Mcf in 1999 and $.21 per Mcf in 1998 as
a result of our 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. On a
natural gas equivalent basis, we 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 combination of higher gas production and lower average gas 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. We recognized a loss in change in
derivative fair value of $.4 million in 1999 and a gain of $17.3 million in
1998. Amounts recorded in this caption represent non-cash gains and losses
created by temporary valuation swings in derivatives or portions of derivatives
which are not entitled to receive hedge accounting treatment. All amounts
recorded in this caption are ultimately reversed in this caption over the
respective contract term. See "Item 7A -- Quantitative and Qualitative
Disclosures About Market Risk -- Fixed-Price Contracts -- Accounting" for a
discussion of the components recorded in this caption.

     OTHER INCOME (LOSS). We realized other income for 1999 of $12.2 million
compared to $4.5 million for 1998. The 1999 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.


                                       26
<PAGE>


     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 us 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 G&G costs, exploratory
dry hole costs 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 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. 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. We recorded total impairment charges of $4.9 million during
1999 primarily as a result of downward reserve revisions for certain offshore
fields. Overall for 1999, we reported net upward reserve revisions of
approximately 12 Bcfe. In 1998, we 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 oil and gas properties have been
impaired, we utilize forward market price quotations as of the date of
determination in estimating the future cash flows from our oil and gas
properties. This forward market price information is consistent with that
generally used by us 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 the 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, we 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, we
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 in
this document.

CAPITAL RESOURCES AND LIQUIDITY

     CASH FLOWS. Our business of acquiring, exploring and developing oil and
gas properties is capital intensive. Our ability to grow our reserve base is
contingent, in part, upon our ability to generate cash flows from operating
activities and to access outside sources of capital to fund investing
activities. For the three years ended December 31, 2000, 1999 and 1998, our
cash flows related to investing activities included net investments of $395.1
million, $165.9 million and $212.6 million, respectively, in oil and gas
property acquisition, exploration and development activities. We currently
anticipate spending approximately $290 million in exploration and development
activities in 2001. 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 drilling investments include expenditures

                                       27
<PAGE>


which under successful efforts accounting are expensed as incurred or if
unsuccessful in discovering new reserves. Investing activities for the years
ended December 31, 2000, 1999 and 1998, include $17.8 million, $6.6 million
and $30.5 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
$278.0 million, $181.6 million and $147.4 million, representing 70%, 109% and
69%, 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 2000
Compared to Fiscal Year 1999" and "-- Results of Operations -- Fiscal Year
1999 Compared to Fiscal Year 1998."

     Cash flows from financing activities were a significant source of funding
for our investing activities in 2000 and 1998. Historically, we have relied
upon availability under various revolving bank credit facilities and proceeds
from the issuance of senior and subordinated notes to fund our investing
activities. For the year ended December 31, 1999, we reduced our borrowings
under such facilities by $41.6 million. For the two years ended December 31,
2000 and 1998, net amounts borrowed under such facilities were $58.2 million
and $31.7 million, or 15% and 15%, respectively, of the net cash oil and gas
investments made for each year. Our debt facilities are discussed in greater
detail below. In addition, we received $44.2 and $40.1 million from the
termination of two fixed-price contracts in 1999 and 1998, respectively.

     In June 2000, we sold 2.4 million shares of common stock at $31.00 per
share ($29.53 per share net of underwriting discount) in a public offering.
Proceeds from the offering of $70.9 million received in July 2000 were applied
to reduce a majority of the indebtedness incurred in connection with the
acquisition of properties from Costilla Energy, Inc. In addition, an indirect
wholly-owned subsidiary of S.A. Louis Dreyfus et Cie sold 1.6 million shares of
our common stock in the offering. Subsequent to the offering, S.A. Louis
Dreyfus et Cie through its subsidiaries owned 19.2 million common shares, or
approximately 44% of the total issued and outstanding common shares.

     Our EBITDAX increased to $381.8 million in 2000 from $213.0 million in
1999 and $183.8 million in 1998. 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 our oil and gas sales. We believe 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. We have a revolving credit
facility with a syndicate of banks which provides up to $450 million in
borrowings. Letters of credit under the credit facility are limited to $75
million of this total availability. The credit facility allows us to draw on
the full $450 million credit line without restrictions tied to periodic
revaluations of our oil and gas reserves provided we continue to maintain an
investment grade credit rating from either Standard & Poor's Ratings Service or
Moody's Investors Service. We currently have senior unsecured credit ratings of
BBB and Baa3 from Standard & Poor's and Moody's, respectively. 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. We
have relied upon the credit facility to provide funds for acquisitions and to
provide letters of credit to meet our margin requirements under fixed-price
contracts. See "Item 7A -- Quantitative and Qualitative Disclosures About
Market Risk -- Fixed-Price Contracts." As of December 31, 2000, we had $300.6
million of principal and $71.6 million of letters of credit outstanding under
the credit facility.

     We have 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 our senior debt credit rating. At December 31, 2000 the applicable
interest rate was LIBOR plus 23 basis points.


                                       28
<PAGE>


The credit facility also requires the payment of a facility fee equal to 12
basis points of the total commitment. The average interest rate for borrowings
under the credit facility was 6.9% at December 31, 2000. The effective interest
rate including the effect of interest rate swaps was 6.2%.

     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 us to meet certain financial tests.
Borrowings under the credit facility are unsecured.

     OTHER LINES OF CREDIT. We have certain other unsecured lines of credit
available to use, which aggregated $50.1 million as of December 31, 2000. These
short-term lines of credit are primarily used for working capital purposes.
Borrowings under these credit lines totaled $13.2 million as of December 31,
2000. Outstanding letters of credit were immaterial. Repayment of indebtedness
under these credit lines is expected to be made through the revolving bank
credit facility availability.

     6 7/8% SENIOR NOTES DUE 2007. In December 1997, we issued $200 million
principal amount, $198.8 million net of discount, of 6 7/8% Senior Notes due
2007. 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 our ability to enter into sale and
leaseback transactions.

     9 1/4% SENIOR SUBORDINATED NOTES DUE 2004. In June 1994, we issued $100
million principal amount, $98.5 million net of discount, of 9 1/4% Senior
Subordinated Notes due 2004. 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. We purchased $6.3 million principal amount of these
notes in the open market during 2000, leaving an outstanding unpaid principal
balance of $93.7 million as of December 31, 2000.

     At December 31, 2000, we had a working capital deficit of $70.8 million
and a current ratio of .7 to 1. This working capital deficit is the result of
recording the fair value of fixed-price contract settlements scheduled to occur
over the next twelve-month period based on market prices for oil and gas as of
the balance sheet date, and option valuations. The offsetting increase in value
of the hedged future production has not been accrued in the accompanying
balance sheet, creating the appearance of a working capital deficit from the
contracts. These settlement amounts are not due and payable until the monthly
period that the related underlying hedged transaction occurs. In some cases,
the recorded liability for certain contracts significantly exceeds the total
settlement amounts that would be paid to a counterparty based on prices in
effect at the balance sheet date due to option time value. Since we expect to
hold these collars to maturity, this time value component has no direct
relationship to actual future contract settlements and consequently does not
represent a liability which will be settled in cash or realized in any way.
Short-term liquidity has actually improved as a result of the increase in oil
and gas prices. Excluding the current portion of fixed-price contracts from
current assets and liabilities, working capital was $54.4 million and the
current ratio was 1.7 to 1. Total long-term debt outstanding at December 31,
2000 was $606.9 million. Our long-term debt as a percentage of total
capitalization was 53%. Debt to capitalization excluding the unrealized
non-cash effects of SFAS 133 in accumulated other comprehensive income in
stockholders' equity was 49%. The amount of required principal payments for the
next five years and thereafter as of December 31, 2000 is as follows: 2001 -
$0; 2002 - $313.8 million; 2003 - $0; 2004 - $93.7 million; 2005 - $0;
thereafter - $200 million. We believe that the borrowing capacity under our
existing credit facilities, combined with our internal cash flows, will be
adequate to finance the capital expenditure program budgeted for 2001 and to
meet our margin requirements under 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 bank
credit facility.

COMMITMENTS AND CAPITAL EXPENDITURES

     Our 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.


                                       29
<PAGE>


For the year ended December 31, 2000, we invested $199.8 million in development
activities, $39.1 million in exploration activities and $167.4 million in
proved reserve acquisitions in connection with this strategy. In addition, we
received $11.2 million in connection with sales of certain oil and gas
properties. Our 2000 drilling program resulted in the drilling of 461 gross
(316 net) wells, including nine gross (five net) exploratory wells and 452
gross (311 net) development wells. Our drilling activities added 278 Bcfe to
our proved reserve base. Reserves added through 2000 acquisitions totaled 204
Bcfe.

     Our approved drilling budget for 2001 provides for approximately $290
million in oil and gas exploration and development activities. Of these
expenditures, approximately $226 million is targeted for development activities
and $64 million is directed to exploration activities to be conducted in our
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 2001." We continue to actively search for
attractive oil and gas property acquisitions, but are not able to predict the
timing or amount of capital expenditure which may ultimately be employed in
acquisitions during 2001.

     In the ordinary course of our business, we 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 our industry.

OUTLOOK FOR FISCAL YEAR 2001

     GENERAL. The discussion of our fiscal year 2001 outlook provided under
this caption and other forward-looking statements in this document reflect the
current expectations of management and are based on our historical operating
trends, our proved reserve and fixed-price contract positions as of December
31, 2000, and other information currently available to us. Forward-looking
statements include statements regarding our future drilling plans and
objectives, and related exploration and development budgets, and number and
location of planned wells, and statements regarding the quality of our
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 our oil and gas properties and that there will
be no material acquisitions or divestitures except as disclosed in this
document.

     We caution 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
in this document. Moreover, we may make material acquisitions or divestitures,
modify 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.

     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. We expressly disclaim any obligation or
undertaking to release publicly any updates regarding any changes in our
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.

     There is no assumption for proved reserve acquisitions which may be made
during 2001 in the estimates provided below. Acquisitions could, depending on
size, materially impact these estimates.

     REVENUES. Our drilling budget approved by the Board of Directors for 2001
is $290 million. Based on this


                                       30
<PAGE>


expenditure level, the inventory of drilling opportunities identified for 2001,
internal production forecasts for developed and undeveloped properties and
historical finding cost results, we expect 2001 production to range from 147
Bcfe to 161 Bcfe. Gas production is expected to range from 132 Bcf to 144 Bcf.
Oil production is expected to approximate 2.7 MMBbls. We expect that natural
gas prices at the wellhead will average $.08 to $.12 per Mcf less than the
average of the last three trading days for the NYMEX Henry Hub index (NYMEX
L3D). The NYMEX L3D price for January 2001 was $9.79 per MMBtu and for February
2001 was $6.94 per MMBtu. Crude oil prices are expected to average $1.50 to
$1.75 per Bbl less than the average NYMEX West Texas Intermediate price (WTI).

     Approximately 50 Bcf of natural gas in 2001 is hedged by swaps and
physical delivery contracts. The weighted average contract price is expected to
be approximately $4.29 per Mcf before the impact of basis, including the
amortization of deferred gains. Additionally, approximately 32 Bcf of gas is
subject to collars with average floor prices of $4.57 per Mcf and average
ceiling prices of $6.28 per Mcf. The impact of contract basis is expected to
range from being neutral to having the effect of increasing the average
contract price by $.03 per Mcf for hedged production. The amount of change in
derivative fair value to be reported in revenues for 2001 cannot be predicted
due to contract valuations and effectiveness testing which are performed at the
end of each quarter throughout the year.

     EXPENSES. Lease operating expenses for 2001 are expected to range from
$.42 to $.44 per Mcfe. Production taxes are expected to range from 5.5% to 6.0%
of wellhead sales. DD&A for 2001 is expected to range from $.95 to $.97 per
Mcfe.

     General and administrative costs are expected to range from $29 million to
$30 million in 2001. Exploration costs could range between $25 million and $60
million, depending upon the level of investment in seismic, other geological
and geophysical costs and success experienced with exploration drilling. We do
not expect to recognize impairment charges in 2001; however, impairments cannot
be predicted with any certainty. Interest expense is expected to range from $30
million to $33 million, but is highly dependent upon oil and gas prices and
level of capital expenditures.

     We expect that the effective income tax rate for 2001 will approximate
38%. The current tax provision in 2001, which is particularly susceptible to
change with fluctuating commodity prices, is expected to represent between 50%
and 65% of the total tax provision primarily as a result of the deduction of
intangible drilling costs and utilization of acquired tax carryforwards.

ITEM 7A  -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

GENERAL

     Our 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 this exposure to adverse market changes, we have entered
into fixed-price contracts and interest rate swaps. All of our 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 our 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. We utilize fixed-price contracts to reduce
exposure to unfavorable changes in oil and gas prices which are subject to
significant and often volatile fluctuation. Our fixed-price contracts are
comprised of long-term physical delivery contracts, energy swaps, collars and
basis swaps. These contracts allow us to predict with greater certainty the
effective oil and gas prices to be received for our hedged production and
benefit operating cash flows and earnings when market prices are less than the
fixed prices provided in the contracts. However, we will not benefit from
market prices that are higher than the fixed prices in the contracts for hedged
production. For the years ended December 31, 2000, 1999 and 1998, fixed-price
contracts hedged 44%, 55% and 50%, respectively, of our gas production and 40%,
19% and 16%, respectively, of our oil production. As of December 31, 2000,
fixed-price contracts are in place to hedge 82 Bcf of future gas production in
2001, and 120 Bcf thereafter.

     For energy swap contracts, we receive a fixed price for the respective
commodity and pay a floating market price, as defined in each contract
(generally NYMEX future prices or a regional spot market index), to the
counterparty. The


                                       31
<PAGE>


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, we
purchase gas in the spot market at floating market prices and deliver gas to
the contract counterparty at a fixed price. 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 we
receive the fixed price and pay 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 basis swaps, we receive the floating market
price for NYMEX futures and pay 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 fixed-price
contracts as of December 31, 2000. We expect the prices to be realized for
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 our hedged 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, 2000, as adjusted for basis.
Future net revenues change with changes in market prices and basis. See "--
Market Risk."

<TABLE>
<CAPTION>

                                               YEARS ENDING DECEMBER 31,                    BALANCE
                                   ----------------------------------------------------     THROUGH
                                     2001        2002       2003       2004       2005        2017       TOTAL
                                   --------    --------   --------   --------   --------   ---------   ---------
                                                   (DOLLARS IN THOUSANDS, EXCEPT PRICE DATA)
    <S>                            <C>         <C>        <C>        <C>        <C>        <C>         <C>
    NATURAL GAS SWAPS:
    Contract volumes (BBtu).....      32,340      6,697      5,650      5,650      5,650       6,483      62,470
    Weighted-average fixed price
      per MMBtu (1).............   $    4.90   $   2.65   $   2.92   $   3.12   $   3.32   $    3.41   $    4.02
    Future fixed-price sales....   $ 158,579   $ 17,766   $ 16,492   $ 17,608   $ 18,740   $  22,082   $ 251,267
    Future net revenues (2).....   $ (36,849)  $(11,542)  $ (5,028)  $ (3,276)  $ (2,089)  $  (1,901)  $ (60,685)

    NATURAL GAS PHYSICAL
      DELIVERY CONTRACTS:
    Contract volumes (BBtu).....      17,814     17,689     14,819      6,634      5,314      38,116     100,386
    Weighted-average fixed price
      per MMBtu (1).............   $    2.38   $   2.46   $   2.53   $   2.53   $   2.63   $    3.01   $    2.68
    Future fixed-price sales....   $  42,464   $ 43,461   $ 37,428   $ 16,802   $ 13,978   $ 114,760   $ 268,893
    Future net revenues (2).....   $ (71,426)  $(32,751)  $(18,105)  $ (7,569)  $ (5,519)  $ (31,932)  $(167,302)

    NATURAL GAS COLLARS:
    Contract volumes (BBtu):
      Floor.....................      31,800      7,300         --         --         --          --      39,100
      Ceiling...................      31,800      7,300         --         --         --          --      39,100
    Weighted-average fixed-price
      per MMBtu (1):
      Floor.....................   $    4.57   $   2.84   $     --   $     --   $     --   $      --   $    4.25
      Ceiling...................   $    6.28   $   3.94   $     --   $     --   $     --   $      --   $    5.84
    Future fixed-price sales (4)   $ 145,447   $ 20,732   $     --   $     --   $     --   $      --   $ 166,179
    Future net revenues (2).....   $ (16,201)  $ (3,902)  $     --   $     --   $     --   $      --   $ (20,103)

    TOTAL NATURAL GAS CONTRACTS (3):
    Contract volumes (BBtu).....      81,954     31,686     20,469     12,284     10,964      44,599     201,956
    Weighted-average fixed price
      per MMBtu (1).............   $    4.23   $   2.59   $   2.63   $   2.80   $   2.98   $    3.07   $    3.40
    Future fixed-price sales (4)   $ 346,490   $ 81,959   $ 53,920   $ 34,410   $ 32,718   $ 136,842   $ 686,339
    Future net revenues (2).....   $(124,476)  $(48,195)  $(23,133)  $(10,845)  $ (7,608)  $ (33,833)  $(248,090)
</TABLE>

    ------------------------------------

    (1) - We expect the prices to be realized for hedged production to vary from
          the prices shown due to basis. See "-- Market Risk."
    (2) - Future net revenue amounts as presented above are undiscounted and
          have not been adjusted for contract performance risk or counterparty
          credit risk. Bracketed amounts represent decreases to future natural
          gas sales.
    (3) - Does not include basis swaps with notional volumes by year, as
          follows: 2001 - 9.4 TBtu; and 2002 - 5.5 TBtu.
    (4) - Assumes floor prices for natural gas collar volumes.

                                       32
<PAGE>

     The estimates of future net revenues from fixed-price contracts are
computed based on the difference between the prices provided by the 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. We have relied upon near-term market quotations, longer-term
over-the-counter market quotations and other market information to determine
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 our fixed-price contracts as
of December 31, 2000 and 1999 are provided below.

<TABLE>
<CAPTION>
                                                                DECEMBER 31, 2000       DECEMBER 31, 1999
                                                            ------------------------  ------------------------
                                                              CARRYING     ESTIMATED   CARRYING      ESTIMATED
                                                                VALUE     FAIR VALUE     VALUE      FAIR VALUE
                                                            -----------  -----------  -----------  -----------
                                                                              (IN THOUSANDS)
     <S>                                                    <C>          <C>          <C>          <C>
     DERIVATIVE ASSETS:
     Fixed-price natural gas swaps........................  $       --   $       --   $   16,433   $   16,433
     Fixed-price natural gas collars......................          --           --        1,323        1,323
     Fixed-price natural gas delivery contracts...........          --           --        7,921        7,921
     Fixed-price crude oil swaps..........................          --           --          360          360

     DERIVATIVE LIABILITIES:
     Fixed-price natural gas swaps........................     (55,923)     (55,923)      (4,329)      (4,329)
     Fixed-price natural gas collars......................     (26,054)     (26,054)          --           --
     Fixed-price natural gas delivery contracts...........    (146,234)    (146,234)      (9,081)      (9,081)
     Natural gas basis swaps..............................      (1,491)      (1,491)      (3,271)      (3,271)
                                                            -----------  -----------  -----------  -----------
     Total................................................  $ (229,702)  $ (229,702)  $    9,356   $     9,356
                                                            ===========  ===========  ===========  ===========
</TABLE>

     The fair value of fixed-price contracts as of December 31, 2000 and 1999
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 our estimation of
contract performance risk and counterparty credit risk. The fair value of
derivative instruments which contain options (e.g. collar structures) has been
estimated based on remaining term, volatility and other factors. The terms and
conditions of our fixed-price physical delivery contracts and certain financial
swaps are uniquely tailored to our circumstances. In addition, certain of the
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. We have relied upon near-term
market quotations, longer-term over-the-counter market quotations and other
market information to determine fair value estimates.

     The change in carrying value of fixed-price contracts and interest rate
swaps in the December 31, 2000 balance sheet compared to the December 31, 1999
balance sheet resulted from a significant increase in market prices for natural
gas and an increase in interest rates. Derivative liabilities reflected as
current in the December 31, 2000 balance sheet include the estimated fair value
of fixed-price contract settlements scheduled to occur over the subsequent
twelve-month period based on market prices for oil and gas as of the balance
sheet date, and option time value. The offsetting increase in value of the
hedged future production has not been accrued in the accompanying balance
sheet, creating the appearance of a working capital deficit from these
contracts. These contract settlement amounts are not due and payable until the
monthly period that the related underlying hedged production occurs. In some
cases the recorded liability for certain contracts significantly exceeds the
total settlement amounts that would be paid to a counterparty based on prices
in effect at the balance sheet date due to option time value. Since we expect
to hold these contracts to maturity, this time value component has no direct
relationship to actual future contract settlements and consequently does not
represent a liability which will be settled in cash or realized in any way.

     The vast majority of all fixed-price contract fair value changes are
reflected in accumulated other comprehensive income on the face of the balance
sheet, shown net of deferred tax effect. At December 31, 2000, this accounting
treatment resulted in a cumulative unrealized reduction in stockholders' equity
of $99.0 million, giving the appearance that a loss in net enterprise value was
experienced as a result of increases in market oil and gas prices. Except for
the effect of basis movements, we expect 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 our oil and natural gas
reserves. Because only 13% of the future production from our natural gas
reserves is hedged, higher oil and gas prices actually increase our net
enterprise value, as is apparent in the standardized measure calculation.


                                       33
<PAGE>


This change in reserve value, however, is not reflected in our balance sheet.
See Note 13 -- Supplemental Information - Oil and Gas Reserves appearing
elsewhere in this document.

     ACCOUNTING. In October 1998, the Company adopted 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 and
meeting the effectiveness guidelines of SFAS 133, 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, or the time value of options 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 our fixed-price contracts and interest rate swaps are designated as cash
flow hedges. 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. Based on the interpretations of
these guidelines by the Staff of the Securities and Exchange Commission in
September 1999, the changes in fair value of all of our derivatives during the
period from October 1, 1998 to January 13, 1999 were required to be reported in
results of operations, rather than in other comprehensive income.

     All of the fixed-price contracts have been executed in connection with our
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 production was hedged. For fixed-price
contracts qualifying as cash flow hedges pursuant to SFAS 133, changes in fair
value for volumes not yet settled are shown as adjustments to other
comprehensive income. The fair value of all fixed-price contracts are recorded
as assets or liabilities in the 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. Included in
accumulated other comprehensive income at December 31, 2000 and 1999, were
pretax unamortized deferred gains of $86.4 million and $99.7 million,
respectively, related to terminated contracts. These deferred gains were
recorded net of deferred tax effect. 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, 2000, 1999 and 1998, oil and gas sales
included $62.3 million of net losses, $1.5 million of net gains and $23.1
million of net gains, respectively, associated with realized gains and losses
under fixed-price contracts.

     Change in derivative fair value for the years ended December 31, 2000,
1999 and 1998 was comprised of the following:

<TABLE>
<CAPTION>

                                                                                     YEARS ENDED DECEMBER 31,
                                                                              ------------------------------------
                                                                                  2000        1999         1998
                                                                              -----------  ----------   ----------
                                                                                         (IN THOUSANDS)
     <S>                                                                      <C>          <C>          <C>
     CHANGE IN DERIVATIVE FAIR VALUE
     Change in fair value for derivatives not qualifying for hedge
         accounting.........................................................  $   (2,632)  $    9,740   $   17,346
     Amortization of derivative fair value gains and losses recognized in
         earnings prior to actual cash settlement...........................      (6,501)      (2,943)          --
     Ineffective portion of derivatives qualifying for hedge accounting,
         including the time value component of collars......................      (6,429)      (7,239)          --
                                                                              ----------   ----------   ----------
                                                                              $  (15,562)  $     (442)  $   17,346
                                                                              ==========   ==========   ==========

</TABLE>

     Amounts recorded in change in derivative fair value do not represent cash
gains or losses. Rather, these


                                       34
<PAGE>


amounts are temporary valuation swings in contracts or portions of contracts
that are not entitled to receive hedge accounting treatment. All amounts
initially recorded in this caption are ultimately reversed within this same
caption over the respective contract terms. Despite certain fixed-price
contracts failing the effectiveness guidelines of SFAS 133 from time to time,
fixed-price contracts continue to be effective in achieving the risk management
objectives for which they were intended.

     In addition to the future net settlements identified in the table under
"--Description of Contracts", we expect the following adjustments in 2001: (1)
oil and gas sales will include $13.9 million of gains from the amortization of
deferred gains from price-risk management activities, (2) interest expense will
include $.4 million of loss from the amortization of deferred interest rate
hedging losses, and (3) change in derivative fair value in the statement of
operations will include a loss of $4.7 million relating to the unwinding of
previously recognized net gains in this caption as actual contract cash
settlements are realized and the time value component of options reverse.

     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 pipeline marketing affiliates, financial institutions, an independent power
producer, a municipality and other end users. In some cases, we require 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 we would be able to enter into a new
contract with a third party on terms comparable to the original contract. We
have not experienced non-performance by any counterparty.

     Cancellation or termination of a fixed-price contract would subject a
greater portion of our gas production to market prices, which, in a low price
environment, could have an adverse effect on our future operating results. In
addition, the associated carrying value of the contract would be removed from
the balance sheet.

      In October 1999 and June 1998, we agreed to the termination of two
long-term fixed-price natural gas delivery contracts. These terminations
resulted in the receipt of cash in the amount of $44.2 million and $40.1
million, respectively. The associated realized gains have 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 our 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
fixed-price contracts are affected by movements in basis. For the years ended
December 31, 2000, 1999 and 1998, we received on an Mcf basis approximately 2%,
6% and 6% less than the prices specified in natural gas fixed-price contracts,
respectively, due to basis. For oil production hedged by crude oil fixed-price
contracts, we realized approximately 6%, 7% and 10% 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
our portfolio of fixed-price contracts and the composition of our 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 2001
represents a $3.5 million change in gas sales. We actively manage exposure to
basis movements and from time to time will enter into contracts designed to
reduce such exposure.

     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 our hedged oil and natural gas production. Because the
majority of our future estimated oil and gas production is unhedged, declining
oil and gas prices could have a material adverse effect on future results of
operations and operating cash flows. Conversely, increases in market prices of
oil and gas would benefit future results of operations and operating cash flows.

     MARGIN. We are required to post margin in the form of bank letters of
credit or treasury bills under certain of our 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


                                       35
<PAGE>

December 31, 2000, 1999 and 1998, the maximum aggregate amount of margin
posted was $70.8 million, $23.5 million and $23.7 million, respectively. If
natural gas prices rise as they did in 2000, or if we fail to meet the
financial tests contained in certain of fixed-price contracts, margin
requirements increase significantly. We believe that margin requirements will
be adequately met through bank credit facility availability, other existing
lines of credit, or credit lines that may be obtained in the future. If we
are unable to meet margin requirements, a contract could be terminated and we
could be required to pay damages to the counterparty which generally
approximate the cost to the counterparty of replacing the contract. At
December 31, 2000, margin had been issued in the form of letters of credit
totaling $70.8 million. Subsequent to December 31, 2000, margin requirements
under fixed-price contracts to two counterparties were reduced, resulting in
a $44 million reduction in posted margin.

INTEREST RATE SENSITIVITY

     We have interest rate swaps designed to hedge the interest rate exposure
associated with borrowings under the credit facility. As of December 31, 2000,
we had fixed the interest rate on average notional amounts of $125 million and
$94 million for the years ended December 31, 2001 and 2002, respectively. Under
the interest rate swaps, we receive the LIBOR three-month rate (6.4% at December
31, 2000) and pay 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 bank credit facility for the respective 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.
This 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 year ended December
31, 2000, interest rate swaps decreased interest expense by $1.9 million. The
impact of interest rate swap settlements in 1999 and 1998 was not material.

     The following table provides information about our interest rate swaps and
certain other financial instruments as of December 31, 2000.

<TABLE>
<CAPTION>
                                                        YEARS ENDING DECEMBER 31,                BALANCE
                                          ----------------------------------------------------   THROUGH
                                            2001       2002       2003       2004       2005       2007         TOTAL
                                          --------   --------   --------   --------   --------   ---------    ---------
    <S>                                   <C>        <C>        <C>        <C>        <C>        <C>          <C>
                                                                (DOLLARS IN THOUSANDS)
    EXPECTED MATURITIES OF LONG-
      TERM DEBT:
    Bank debt...........................  $     --   $313,800   $     --   $     --   $     --   $      --    $ 313,800
      Average interest rate (1).........      6.2%       5.3%         --         --         --          --         5.8%
    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..................  $     --   $     --   $     --   $ 93,700   $     --   $      --    $  93,700
      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   $ 94,000   $     --   $     --   $     --   $      --    $ 219,000
      Average pay rate - fixed..........      5.0%       5.0%         --         --         --          --         5.0%
      Average receive rate - variable
        (2).............................      6.0%       5.1%         --         --         --          --         5.5%
</TABLE>

    ------------------------------------

    (1) - Based on market quotations for interest rates as of December 31, 2000
          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, 2000.

    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,
2000 and 1999 are provided below.


                                       36
<PAGE>

<TABLE>
<CAPTION>
                                                          DECEMBER 31, 2000               DECEMBER 31, 1999
                                                    ---------------------------     ---------------------------
                                                     CARRYING       ESTIMATED        CARRYING        ESTIMATED
                                                       VALUE        FAIR VALUE         VALUE         FAIR VALUE
                                                    -----------     -----------     -----------     -----------
                                                                           (IN THOUSANDS)
      <S>                                           <C>             <C>             <C>             <C>
      Bank debt...................................  $ (313,800)     $ (316,568)     $ (255,600)     $ (260,494)
      6 7/8% Senior Notes due 2007................    (199,156)       (193,646)       (199,034)       (177,012)
      9 1/4% Senior Subordinated Notes due 2004...     (93,953)        (96,061)       (100,588)        (99,591)
      Interest rate swaps.........................       1,756           1,756           5,660           5,660
                                                    -----------     -----------     -----------     -----------
      Total.......................................  $ (605,153)     $ (604,519)     $ (549,562)     $ (531,437)
                                                    ===========     ===========     ===========     ===========
</TABLE>


      The fair value of bank debt at December 31, 2000 and 1999 was determined
by utilizing an estimated market credit spread for bank debt with comparable
terms and credit quality. 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 these securities. The fair value of the interest rate
swaps was based on market interest rates as of each respective date.

     We expect 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 these interest rate swaps. The fair
value of these swaps until settlement will be subject to change as market
interest rates change. Increases in market interest rates would have an adverse
effect on results of operations since the majority of our bank debt interest
rate exposure is unhedged.

ITEM 8 -- FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     Our consolidated financial statements and supplementary data are presented
on pages F-1 through F-26 inclusive, found at the end of this report.

ITEM 9 --    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
             FINANCIAL DISCLOSURE

     None.

                                    PART III

ITEM 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     The information required under Item 10 will be contained in our definitive
proxy statement for the 2001 Annual Meeting of Shareholders 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, 2000.

ITEM 11 -- EXECUTIVE COMPENSATION

     The information required under Item 11 will be contained in the proxy
statement for the 2001 Annual Meeting of Shareholders 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 for the 2001 Annual Meeting of Shareholders 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 for the 2001 Annual Meeting of Shareholders and is incorporated herein
by reference.


                                       37
<PAGE>


                                     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 Financial Statement 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.

<TABLE>
<CAPTION>

   EXHIBIT
     NO.                   DESCRIPTION OF EXHIBIT
   -------                 ----------------------
   <S>        <C>
       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    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).

       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 fiscal year
              ended December 31, 1998).

      10.2    Form of Indemnification Agreement with directors of the Registrant
              (incorporated by reference to Exhibit 10.2 of the Registrant's
              Registration Statement on Form S-1, Registration No. 33-69102).

      10.3    Registration Rights Agreement between the Registrant and Louis
              Dreyfus Natural Gas Holdings Corp. (incorporated by reference to
              Exhibit 10.3 of the Registrant's Registration Statement on Form
              S-1, Registration No. 33-76828).

      10.4    Amendment dated December 22, 1993 to Registration Rights Agreement
              between the Registrant, Louis Dreyfus Natural Gas Holdings Corp.
              and S.A. Louis Dreyfus et Cie (incorporated by reference to
              Exhibit 10.4 of the Registrant's Registration Statement on Form
              S-1, Registration No. 33-76828).

      10.5    Services Agreement between the Registrant and Louis Dreyfus
              Holding Company, Inc. (incorporated by reference to Exhibit 10.5
              of the Registrant's Registration Statement Form S-1, Registration
              No. 33-76828).

      10.6    Credit Agreement dated as of October 14, 1997, among Louis Dreyfus
              Natural Gas Corp., as Borrower, Bank of Montreal, as
              Administrative Agent, Chase Manhattan Bank, as Syndication Agent,
              NationsBank of Texas, N.A., as Documentation Agent, and certain
              other lenders signatory thereto (incorporated by


                                       38
<PAGE>


              reference to Exhibit 10.1 of the Registrant's Form 8-K dated
              October 14, 1997).

     *10.7    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).

     *10.8    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).

     *10.9    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).

     *10.10   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).

     *10.11   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).

     *10.12   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).

     *10.13   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).

     *10.14   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).

     *10.15   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).

     *10.16   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).

     *10.17   Louis Dreyfus Natural Gas Corp. Non-employee Director Deferred
              Stock Trust Agreement dated December 1, 1998 (incorporated by
              reference to Exhibit 10.18 of the Registrant's Annual Report on
              Form 10-K for the year ended December 31, 1999).

     *10.18   Amendment No. 1 to Louis Dreyfus Natural Gas Corp. Deferred Stock
              Trust Agreement dated September 30, 1998 (incorporated by
              reference to Exhibit 10.19 of the Registrant's Annual Report on
              Form 10-K for the year ended December 31, 1999).

     *10.19   Louis Dreyfus Natural Gas Corp. Non-Employee Director Deferred
              Stock Compensation Program as adopted effective July 23, 1998
              (incorporated by reference to Exhibit 10.20 of the Registrant's
              Annual Report on Form 10-K for the year ended December 31, 1999).

     *10.20   Louis Dreyfus Natural Gas Corp. 2000 Employee Stock Purchase Plan
              dated May 16, 2000 (incorporated by reference to the Registrant's
              Registration Statement on Form S-8, Registration No. 333-37490).

      21.1    List of subsidiaries of the Registrant.




                                       39
<PAGE>


      23.1    Consent of Independent Auditors.

      24.1    Powers of Attorney.
</TABLE>


   ------------------------------------
        *  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.




                                       40
<PAGE>


                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

                                             LOUIS DREYFUS NATURAL GAS CORP.

Date: February 27, 2001                      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.

<TABLE>
<CAPTION>

       SIGNATURES                            TITLE                                  DATE
<S>                           <C>                                            <C>
MARK E. MONROE*               President, Chief Executive Officer and         February 27, 2001
----------------------------  Director (principal executive officer)
Mark E. Monroe


RICHARD E. BROSS*             Executive Vice President and Director          February 27, 2001
----------------------------
Richard E. Bross


/s/ JEFFREY A. BONNEY         Executive Vice President and Chief             February 27, 2001
----------------------------  Financial Officer (principal financial
Jeffrey A. Bonney             and accounting officer)


SIMON B. RICH, JR.*           Chairman of the Board of Directors             February 27, 2001
----------------------------
Simon B. Rich, Jr.


MARK ANDREWS*                 Vice Chairman of the Board of Directors        February 27, 2001
----------------------------
Mark Andrews


GERARD LOUIS-DREYFUS*         Director                                       February 27, 2001
----------------------------
Gerard Louis-Dreyfus


E. WILLIAM BARNETT*           Director                                       February 27, 2001
----------------------------
E. William Barnett


DANIEL R. FINN, JR.*          Director                                       February 27, 2001
----------------------------
Daniel R. Finn, Jr.


PETER G. GERRY*               Director                                       February 27, 2001
----------------------------
Peter G. Gerry


JOHN H. MOORE*                Director                                       February 27, 2001
----------------------------
John H. Moore


JAMES R. PAUL*                Director                                       February 27, 2001
----------------------------
James R. Paul


NANCY K. QUINN*               Director                                       February 27, 2001
----------------------------
Nancy K. Quinn


ERNEST F. STEINER*            Director                                       February 27, 2001
----------------------------
Ernest F. Steiner


*By: /s/ JEFFREY A. BONNEY                                                   February 27, 2001
    ------------------------
    Jeffrey A. Bonney
    ATTORNEY-IN-FACT

</TABLE>

                                      41
<PAGE>


                         LOUIS DREYFUS NATURAL GAS CORP.
   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE

------------------------------------------------------------------------------

<TABLE>
<CAPTION>

CONSOLIDATED  FINANCIAL  STATEMENTS                                                                           PAGE
                                                                                                              ----
<S>                                                                                                           <C>
Report of Independent Auditors..............................................................................   F-2
Consolidated Balance Sheets:
    December 31, 2000 and 1999..............................................................................   F-3
Consolidated Statements of Operations:
    Years ended December 31, 2000, 1999 and 1998............................................................   F-4
Consolidated Statements of Stockholders' Equity:
    Years ended December 31, 2000, 1999 and 1998............................................................   F-5
Consolidated Statements of Cash Flows:
    Years ended December 31, 2000, 1999 and 1998............................................................   F-6
Notes to Consolidated Financial Statements..................................................................   F-7


CONSOLIDATED FINANCIAL STATEMENT SCHEDULE

Schedule II - Consolidated Valuation and Qualifying Accounts................................................  F-26

</TABLE>

    All other schedules for which provision is made in the applicable accounting
regulations of the Securities and Exchange Commission are not required under the
related instructions or are inapplicable and therefore have been omitted.



                                    F-1
<PAGE>


                         REPORT OF INDEPENDENT AUDITORS


The Board of Directors and Stockholders
Louis Dreyfus Natural Gas Corp.

We have audited the accompanying consolidated balance sheets of Louis Dreyfus
Natural Gas Corp. (the "Company") as of December 31, 2000 and 1999, and the
related consolidated statements of operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 2000. 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, 2000 and 1999, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended December 31, 2000
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 5, 2001



                                    F-2

<PAGE>

                         LOUIS DREYFUS NATURAL GAS CORP.
                           CONSOLIDATED BALANCE SHEETS
                             (DOLLARS IN THOUSANDS)


<TABLE>
<CAPTION>

                                   A S S E T S
                                                                                                DECEMBER  31,
                                                                                       ---------------------------
                                                                                           2000            1999
                                                                                       -----------     -----------
<S>                                                                                    <C>             <C>
CURRENT ASSETS
Cash and cash equivalents............................................................  $     2,799     $     9,660
Receivables:
   Oil and gas sales.................................................................      109,488          43,782
   Joint interest and other, net.....................................................        9,098           8,923
   Income taxes......................................................................        9,276              --
Fixed-price contracts and other derivatives..........................................        1,004           7,204
Prepaids and other...................................................................        4,623           4,928
                                                                                       -----------     -----------
   Total current assets..............................................................      136,288          74,497
                                                                                       -----------     -----------
PROPERTY AND EQUIPMENT, at cost, based on successful efforts accounting..............    1,951,520       1,636,854
Less accumulated depreciation, depletion and amortization............................     (591,305)       (513,715)
                                                                                       -----------     -----------
                                                                                         1,360,215       1,123,139
                                                                                       -----------     -----------
OTHER ASSETS
Fixed-price contracts and other derivatives..........................................          752          24,493
Other, net...........................................................................        4,710           4,958
                                                                                       -----------     -----------
                                                                                             5,462          29,451
                                                                                       -----------     -----------
                                                                                       $ 1,501,965     $ 1,227,087
                                                                                       ===========     ===========


        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.....................................................................  $    46,065     $    41,216
Accrued liabilities..................................................................       14,984          12,413
Revenues payable.....................................................................       19,794          14,413
Fixed-price contracts and other derivatives..........................................      126,255           4,673
                                                                                       -----------     -----------
   Total current liabilities                                                               207,098          72,715
                                                                                       -----------     -----------
LONG-TERM DEBT                                                                             606,909         555,222
                                                                                       -----------     -----------
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES
Deferred revenue.....................................................................       11,277          13,524
Fixed-price contracts and other derivatives..........................................      103,447          12,008
Deferred income taxes................................................................       19,222          52,341
Other................................................................................       21,193          22,495
                                                                                       -----------     -----------
                                                                                           155,139         100,368
                                                                                       -----------     -----------
COMMITMENTS AND CONTINGENCIES (Notes 7 and 12)

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,
   43,689,774 and 40,230,880 shares, respectively....................................          437             402
Paid-in capital......................................................................      504,989         420,859
Retained earnings....................................................................      126,409          28,149
Accumulated other comprehensive income (loss)........................................      (99,005)         49,981
Treasury stock, at cost, 589 and 32,139 common shares, respectively..................          (11)           (609)
                                                                                       -----------     -----------
                                                                                           532,819         498,782
                                                                                       -----------     -----------
                                                                                       $ 1,501,965     $ 1,227,087
                                                                                       ===========     ===========

</TABLE>



              SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

                                          F-3

<PAGE>

                         LOUIS DREYFUS NATURAL GAS CORP.
                      CONSOLIDATED STATEMENTS OF OPERATIONS
                      (IN THOUSANDS, EXCEPT PER SHARE DATA)


<TABLE>
<CAPTION>

                                                                                    YEARS ENDED DECEMBER 31,
                                                                           ---------------------------------------
                                                                              2000           1999           1998
                                                                           ----------    ----------     ----------
<S>                                                                        <C>           <C>            <C>
REVENUES
Oil and gas sales........................................................  $  489,703    $  290,878     $  271,575
Change in derivative fair value..........................................     (15,562)         (442)        17,346
Other income.............................................................       3,144        12,170          4,462
                                                                           ----------    ----------     ----------
                                                                              477,285       302,606        293,383
                                                                           ----------    ----------     ----------
EXPENSES
Operating costs..........................................................      86,915        66,039         66,295
General and administrative...............................................      24,144        23,995         25,971
Exploration costs........................................................      25,654        14,258         34,543
Depreciation, depletion and amortization.................................     129,323       117,080        131,408
Impairment...............................................................      10,439         4,877         52,522
Interest.................................................................      41,431        40,667         40,849
                                                                           ----------    ----------     ----------
                                                                              317,906       266,916        351,588
                                                                           ----------    ----------     ----------
Income (loss) before income taxes and cumulative effect of accounting
  change.................................................................     159,379        35,690        (58,205)
Income tax provision (benefit) ..........................................      61,119        14,276        (13,924)
                                                                           ----------    ----------     ----------
Net income (loss) before cumulative effect of accounting change..........      98,260        21,414        (44,281)
Cumulative effect of accounting change, net of tax.......................          --            --            964
                                                                           ----------    ----------     ----------
NET INCOME (LOSS)........................................................  $   98,260    $   21,414     $  (43,317)
                                                                           ==========    ==========     ==========


PER SHARE
Basic:
Net income (loss) before cumulative effect of accounting change..........  $     2.35    $      .53     $    (1.10)
Cumulative effect of accounting change...................................          --            --            .02
                                                                           ----------    ----------     ----------
Net income (loss) - basic................................................  $     2.35    $      .53     $    (1.08)
                                                                           ==========    ==========     ==========
Diluted:
Net income (loss) before cumulative effect of accounting change..........  $     2.29    $      .53     $    (1.10)
Cumulative effect of accounting change...................................          --            --            .02
                                                                           ----------    ----------     ----------
Net income (loss) - diluted..............................................  $     2.29    $      .53     $    (1.08)
                                                                           ==========    ==========     ==========


Weighted average number of common shares:
Basic....................................................................      41,830        40,153         40,107
Diluted..................................................................      42,836        40,389         40,107

</TABLE>




                   SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

                                                 F-4

<PAGE>

                                      LOUIS DREYFUS NATURAL GAS CORP.
                            CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                                              (IN THOUSANDS)


<TABLE>
<CAPTION>

                                                                                     ACCUMULATED
                                                           ADDITIONAL                  OTHER                       TOTAL
                                                 COMMON      PAID-IN     RETAINED   COMPREHENSIVE   TREASURY   STOCKHOLDERS'
                                                 STOCK       CAPITAL     EARNINGS      INCOME        STOCK        EQUITY
                                               --------    ----------   ----------  -------------  ---------   -------------
<S>                                            <C>         <C>          <C>         <C>            <C>         <C>
BALANCE AT DECEMBER 31, 1997................   $    401    $  418,751   $   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           --             --         --             324
                                               --------    ----------   ----------  -------------  ---------   -------------
BALANCE AT DECEMBER 31, 1998................        401       419,075        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         1,784           --             --         --           1,785
Treasury shares purchased...................         --            --           --             --       (609)           (609)
                                               --------    ----------   ----------  -------------  ---------   -------------
BALANCE AT DECEMBER 31, 1999................        402       420,859       28,149         49,981       (609)        498,782
                                                                                                               -------------
Comprehensive income:
Net income..................................         --            --       98,260             --         --          98,260
Other comprehensive loss, net of tax:
   Change in fixed-price contract and other
      derivative fair value.................         --            --           --       (183,271)        --        (183,271)
   Reclassification adjustments - contract
      settlements...........................         --            --           --         34,285         --          34,285
                                                                                                               -------------
   Total comprehensive loss.................         --            --           --             --         --         (50,726)
                                                                                                               -------------
Sale of common stock........................         24        70,980           --             --         --          71,004
Exercise of stock options and warrants......         11        12,945           --             --         --          12,956
Treasury shares awarded to directors and
   employees................................         --           205           --             --        598             803
                                               --------    ----------   ----------  -------------  ---------   -------------
BALANCE AT DECEMBER 31, 2000................   $    437    $  504,989   $  126,409  $     (99,005) $     (11)  $     532,819
                                               ========    ==========   ==========  =============  =========   =============

</TABLE>

                   SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

                                                F-5
<PAGE>

                               LOUIS DREYFUS NATURAL GAS CORP.
                            CONSOLIDATED STATEMENTS OF CASH FLOWS
                                       (IN THOUSANDS)

<TABLE>
<CAPTION>

                                                                                  YEARS ENDED DECEMBER 31,
                                                                           ---------------------------------------
                                                                              2000          1999           1998
                                                                           ----------    ----------     ----------
<S>                                                                        <C>           <C>            <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)........................................................  $   98,260    $   21,414     $  (43,317)
Items not affecting cash flows:
   Depreciation, depletion and amortization..............................     129,323       117,080        131,408
   Impairment............................................................      10,439         4,877         52,522
   Deferred income taxes.................................................      58,195        13,745        (14,524)
   Exploration costs.....................................................      25,654        14,258         34,543
   Change in derivative fair value.......................................      15,562           442        (17,346)
   Gain on sale of property..............................................      (1,003)         (398)          (166)
   Other.................................................................       1,012           413          1,799
Net change in operating assets and liabilities:
   Accounts receivable...................................................     (72,735)        2,897         27,529
   Prepaids and other....................................................         305          (356)         8,093
   Accounts payable .....................................................       4,849         2,994        (23,179)
   Accrued liabilities...................................................       2,711           717         (6,646)
   Revenues payable......................................................       5,381         3,473         (3,278)
                                                                           ----------    ----------     ----------
                                                                              277,953       181,556        147,438
                                                                           ----------    ----------     ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development expenditures.................................    (238,845)     (143,521)      (222,400)
Acquisition of proved oil and gas properties.............................    (167,432)      (34,784)        (4,500)
Additions to other property and equipment................................      (5,122)       (1,560)        (2,615)
Proceeds from sale of property and equipment.............................      11,399        12,659         14,413
Change in other assets...................................................         419          (456)          (172)
                                                                           ----------    ----------     ----------
                                                                             (399,581)     (167,662)      (215,274)
                                                                           ----------    ----------     ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from bank borrowings............................................     573,250       368,169        475,362
Repayments of bank borrowings............................................    (515,050)     (409,769)      (443,662)
Repayments of subordinated notes.........................................      (6,549)           --             --
Sale of common stock.....................................................      71,004            --             --
Proceeds from contract termination.......................................          --        44,153         40,136
Proceeds from stock options and warrants exercised.......................      11,280         1,710            324
Sale (purchase) of treasury shares.......................................          49          (609)            --
Change in deferred revenue...............................................      (2,247)       (2,027)        (1,836)
Change in gains from price-risk management activities....................     (13,260)       (5,762)        (2,321)
Change in other long-term liabilities....................................      (3,710)       (2,638)        (3,166)
                                                                           ----------    ----------     ----------
                                                                              114,767        (6,773)        64,837
                                                                           ----------    ----------     ----------
Change in cash and cash equivalents......................................      (6,861)        7,121         (2,999)
Cash and cash equivalents, beginning of year.............................       9,660         2,539          5,538
                                                                           ----------    ----------     ----------
Cash and cash equivalents, end of year...................................  $    2,799    $    9,660     $    2,539
                                                                           ==========    ==========     ==========

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest...............................  $   39,460    $   39,722     $   38,326
Income taxes paid........................................................      10,572           858            335

</TABLE>




                 SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

                                             F-6
<PAGE>


                         LOUIS DREYFUS NATURAL GAS CORP.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 1 -- SIGNIFICANT ACCOUNTING POLICIES

       GENERAL. Louis Dreyfus Natural Gas Corp. 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, 2000, approximately 44% of our 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. Our accounting policies reflect industry practices and conform
to accounting principles generally accepted in the United States. The more
significant of these policies are briefly described below.

     PRINCIPLES OF CONSOLIDATION AND BASIS OF PRESENTATION. The accompanying
consolidated financial statements include the accounts of Louis Dreyfus Natural
Gas Corp. and our wholly-owned subsidiaries after elimination of all material
intercompany accounts and transactions.

     USE OF ESTIMATES. The preparation of the financial statements in
conformity with generally accepted accounting principles requires us 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. We sell oil and natural gas to various
customers, participate with other parties in the drilling, completion and
operation of oil and natural gas wells, and enter into energy swaps and
physical delivery contracts, some of which are long-term. The majority of our
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. We have established procedures to monitor
credit risk and have not experienced significant credit losses in prior years.
See Note 12 -- Derivatives -- Credit Risk. At December 31, 2000 and 1999, joint
interest and other receivables are shown net of allowance for doubtful accounts
of $.9 million and $1.1 million, respectively.

     PROPERTY AND EQUIPMENT. We utilize 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, these 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 has been otherwise impaired,
the excess carrying value is charged to expense.

     Expenditures made in connection with our drilling program are presented in
the accompanying statements 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,
2000, 1999 and 1998, include $17.8 million, $6.6 million and $30.5 million,
respectively, of costs which have been expensed as exploration costs in the
statement of operations for the corresponding periods.

     The carrying value of our oil and gas properties are reviewed on a
field-by-field basis for indications of impairment whenever events or
circumstances indicate that the remaining carrying value may not be
recoverable. In order to determine whether an impairment has occurred, we
estimate the expected future net cash flows from our oil and gas properties as
of the date of determination, and compare them to the respective carrying value
amounts. These estimated future cash flows are based on proved reserves and
forward market prices for oil and gas that existed as of the date of


                                       F-7
<PAGE>


                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


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 the properties at a
discount rate estimated to be representative of the market for such properties.
The excess is charged to expense and may not be reinstated. For the years ended
December 31, 2000 and 1999, we recognized impairment charges aggregating $10.4
million and $4.9 million, respectively, primarily as the result of downward
revisions to estimated future recoverable reserves from certain single-well
offshore properties identified in the preparation of the respective year-end
reserve study. Overall, we experienced net upward proved reserve revisions of
approximately 2 Bcfe and 12 Bcfe for 2000 and 1999, respectively. For 1998, we
recognized impairment charges aggregating $52.5 million. The associated
impairment reviews were conducted as the result of declining oil and gas prices
during the year which adversely affected the estimated future cash flows from
our oil and gas properties. Lower oil and gas prices or future downward
revisions of reserve estimates could result in future impairment recognition.

     We provide for the estimated cost, at current prices, of dismantling and
removing oil and gas production facilities. These 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, 2000 and 1999, estimated total future dismantling and restoration
costs of $12.5 million and $12.1 million, respectively, were included in other
long-term 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. Included
in depreciation, depletion and amortization expense for the years ended
December 31, 2000, 1999 and 1998 is amortization of other assets totaling $.6
million, $1.4 million and $1.3 million, respectively.

     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 debt issuance costs included in other assets as of December 31, 2000
and 1999, was $2.4 million and $3.1 million, respectively.

     OIL AND GAS SALES AND GAS IMBALANCES. Oil and gas revenues are recognized
as oil and gas is produced and sold. We use the sales method of accounting for
gas imbalances in those circumstances where we have underproduced or
overproduced our ownership percentage in a property. Under this method, a
receivable or a liability is recorded to the extent that an underproduced or
overproduced position in a reservoir cannot be recouped through the production
of remaining reserves. At December 31, 2000 and 1999, we had imbalance
liabilities of $5.2 million and $4.0 million, respectively, and imbalance
receivables of $2.3 million and $1.4 million, respectively.

     INCOME TAXES. We file a consolidated United States income tax return which
includes the taxable income or loss of our 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. We reduce our exposure to unfavorable changes in oil and natural
gas prices by utilizing fixed-price physical delivery contracts, energy swaps,
collars and basis swaps (collectively fixed-price contracts). We also enter
into interest rate swap contracts to reduce exposure to adverse interest rate
fluctuations. In October 1998, we 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 and meeting the effectiveness guidelines of SFAS
133, 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 is recognized


                                       F-8
<PAGE>


                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


immediately in earnings, as is the time value component of our fixed-price
collars. Substantially all of our 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. Proceeds from the monetization of fixed-price contracts prior to their
maturity are classified as financing activities in the accompanying statements
of cash flows.

     Adoption of SFAS 133 in October 1998 resulted in the reclassification of
$62.2 million of deferred gains and $3.3 million of deferred losses resulting
from terminated contracts to accumulated other comprehensive income, recorded
net of deferred income tax effects. In addition, adoption resulted in the
recognition of $1.0 million of net gains reflected as a cumulative effect of an
accounting change. See Note 10 -- Capital Stock and Stockholders' Equity, Note
11 -- Financial Instruments, and Note 12 -- Derivatives. We do 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. Based on the interpretation of these guidelines by the Staff of the
Securities and Exchange Commission in September 1999, the changes in fair value
of all of our derivatives during the period from October 1, 1998 to January 13,
1999 were required to be reported in results of operations, rather than in
other comprehensive income.

     Although certain of our fixed-price contracts may not qualify for special
hedge accounting treatment from time to time under the specific guidelines of
SFAS 133, we have 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 we expect the contracts to continue to mitigate our commodity
price risk in the future. The specific accounting for these contracts, however,
is consistent with the requirements of SFAS 133. See Note 12 -- Derivatives --
Accounting.

     EARNINGS PER SHARE. Basic earnings per share is computed by dividing net
income by the weighted average number of common shares outstanding for the
period. Diluted earnings per share reflects the potential dilution that could
occur if dilutive stock options and warrants were exercised, calculated using
the treasury stock method. The diluted earnings per share calculation for the
years ended December 31, 2000 and 1999 include an increase in potential shares
attributable to dilutive stock options and warrants. Stock options and warrants
were not considered in the diluted earnings per share calculations for 1998 as
the effect would be antidilutive. Options to purchase 292,675 shares of common
stock, with exercise prices ranging from $30.00 per share to $33.78 per share
(with a weighted average price of $31.97 per share) were excluded from the
diluted earnings per share calculation for 2000. See Note 8 -- Employee Benefit
Plans and Note 10 -- Capital Stock and Stockholders' Equity for a description
of potentially dilutive securities.

     STOCK OPTIONS. We account 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 our 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. Our 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:


                                       F-9
<PAGE>

                                     LOUIS DREYFUS NATURAL GAS CORP.
                         NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
<TABLE>
<CAPTION>
                                                                                            DECEMBER 31,
                                                                                      -----------------------
                                                                                         2000         1999
                                                                                      ----------   ----------
                                                                                           (IN THOUSANDS)
     <S>                                                                              <C>          <C>
     Oil and gas properties:
     Proved.........................................................................  $1,880,774   $1,562,581
     Unproved.......................................................................      34,934       39,572
     Accumulated depreciation, depletion and amortization...........................    (575,215)    (497,349)
                                                                                      ----------   ----------
                                                                                       1,340,493    1,104,804
                                                                                      ----------   ----------
     Other property and equipment...................................................      35,812       34,701
     Accumulated depreciation.......................................................     (16,090)     (16,366)
                                                                                      ----------   ----------
                                                                                          19,722       18,335
                                                                                      ----------   ----------
                                                                                      $1,360,215   $1,123,139
                                                                                      ==========   ==========
</TABLE>
     Depreciation, depletion and amortization expense of oil and gas properties
per Mcfe was $.91, $.89 and $1.04 for the years ended December 31, 2000, 1999
and 1998, respectively. These amounts do not include impairment charges
recorded in each year. See Note 1 -- Significant Accounting Policies. For the
years ended December 31, 2000, 1999 and 1998, interest of $2.7 million, $2.0
million and $3.3 million, respectively, was capitalized in connection with our
exploration and development activities. Depreciation of other property and
equipment was $3.7 million, $3.5 million and $4.1 million for the years ended
December 31, 2000, 1999 and 1998, respectively.

     Unproved properties at December 31, 2000 consisted primarily of acreage
positions acquired during the previous three years. These properties will be
evaluated over their respective lease terms or as drilling results are
determined. Certain of these acreage positions will be drilled in 2001 in
connection with our exploration drilling program. If proved reserves are not
ultimately discovered in commercial quantities as a result of this drilling
activity, the carrying value of these positions will be charged to expense,
classified as exploration costs in the statement of operations.

     COSTS INCURRED. The following table summarizes the costs incurred in
acquisition, exploration and development activities for the years ended
December 31, 2000, 1999 and 1998, respectively.
<TABLE>
<CAPTION>
                                                                               YEARS ENDED DECEMBER 31,
                                                                         ------------------------------------
                                                                            2000         1999         1998
                                                                         ----------   ----------   ----------
                                                                                    (IN THOUSANDS)
     <S>                                                                 <C>          <C>          <C>
     Property acquisition costs:
     Proved............................................................  $  167,714   $   36,881   $    4,088
     Unproved..........................................................      18,375       10,766       11,815
                                                                         ----------   ----------   -----------
                                                                            186,089       47,647       15,903
     Exploration costs.................................................      23,729       19,409       74,123
     Development costs.................................................     196,741      116,597      136,462
                                                                         ----------   ----------   -----------
                                                                         $  406,559   $  183,653   $  226,488
                                                                         ==========   ==========   ===========
</TABLE>

NOTE 3 -- ACQUISITIONS

     On June 15, 2000, we acquired substantially all of the oil and gas
properties of Costilla Energy, Inc. for approximately $122 million in cash. The
acquired properties were comprised of 135 Bcfe of net proved reserves included
in 1,011 gross (607 net) producing wells at closing. The majority of the
Costilla properties are located within our three core operating areas. The
purchase price for the Costilla acquisition was initially funded through
availability under our revolving bank credit facility. See Note 4 -- Long-Term
Debt and Note 10 -- Capital Stock and Stockholder's Equity. The acquisition has
been accounted for using the purchase method of accounting.

     During 2000, 1999 and 1998, we made numerous other acquisitions of proved
oil and gas properties, the net purchase price of which aggregated $45.8
million, $34.8 million and $4.1 million, respectively. The results of

                                      F-10
<PAGE>


                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


operations related to these acquisitions have been included in the accompanying
statements of operations and cash flows for the periods subsequent to the
closing of each transaction.

NOTE 4 -- LONG-TERM DEBT

     Long-term debt consists of the following:

<TABLE>
<CAPTION>
                                                                                            DECEMBER 31,
                                                                                      -----------------------
                                                                                         2000         1999
                                                                                      ----------   ----------
                                                                                           (IN THOUSANDS)
     <S>                                                                              <C>          <C>
     Bank Debt:
     $450 Million Revolving Credit Facility.........................................  $  300,600   $  255,600
     Other Lines of Credit..........................................................      13,200           --
                                                                                      ----------   ----------
                                                                                         313,800      255,600
     6 7/8% Senior Notes due 2007...................................................     199,156      199,034
     9 1/4% Senior Subordinated Notes due 2004......................................      93,953      100,588
                                                                                      ----------   ----------
                                                                                      $  606,909   $  555,222
                                                                                      ==========   ==========
</TABLE>

     $450 MILLION REVOLVING CREDIT FACILITY. We have a revolving credit
facility with a syndicate of banks which provides up to $450 million in
borrowings. Letters of credit under the credit facility are limited to $75
million of this total availability. The credit facility allows us to draw on
the full $450 million credit line without restrictions tied to periodic
revaluations of our oil and gas reserves provided we continue to maintain an
investment grade credit rating from either Standard & Poor's Ratings Service or
Moody's Investors Service. We currently have senior unsecured credit ratings of
BBB and Baa3 from Standard & Poor's and Moody's, respectively. 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. We
have relied upon the credit facility to provide funds for acquisitions and
drilling activity, and to provide letters of credit for margin requirements
under fixed-price contracts. See Note 12 -- Derivatives. As of December 31,
2000, we had $300.6 million of principal and $71.6 million of letters of credit
outstanding under the credit facility.

     We have 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 our senior debt credit rating. At December 31, 2000, the applicable
interest rate was LIBOR plus 23 basis points. The credit facility also requires
the payment of a facility fee equal to 12 basis points of the total commitment.
The average interest rate for borrowings under the credit facility was 6.9% at
December 31, 2000. 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 6.2%. See Note 12 -- Derivatives for a description
of the interest rate swaps hedging a portion of the credit facility's
outstanding debt.

     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 us to meet certain financial tests.
Borrowings under the credit facility are unsecured.

     OTHER LINES OF CREDIT. We have certain other unsecured lines of credit
available to use, which aggregated $50.1 million as of December 31, 2000. These
short-term lines of credit are primarily used for working capital purposes.
Borrowings under these credit lines totaled $13.2 million as of December 31,
2000. Outstanding letters of credit were immaterial. Repayment of indebtedness
under these credit lines is expected to be made through the revolving bank
credit facility availability.

     6 7/8% SENIOR NOTES DUE 2007. In December 1997, we issued $200 million
principal amount, $198.8 million net of discount, of 6 7/8% Senior Notes due
2007. 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 our


                                      F-11
<PAGE>


                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


ability to enter into sale and leaseback transactions.

       9 1/4% SENIOR SUBORDINATED NOTES DUE 2004. In June 1994, we issued $100
million principal amount, $98.5 million net of discount, of 9 1/4% Senior
Subordinated Notes due 2004. 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. We purchased $6.3 million principal amount of these
notes in the open market during 2000, leaving an outstanding unpaid principal
balance of $93.7 million as of December 31, 2000.

     The amount of required principal payments for the next five years and
thereafter as of December 31, 2000 are as follows: 2001 - $0; 2002 - $313.8
million; 2003 - $0; 2004 - $93.7 million; 2005 - $0; thereafter - $200 million.

NOTE 5 -- INCOME TAXES

     The significant components of income tax expense (benefit) before
cumulative effect of accounting change for the years ended December 31, 2000,
1999 and 1998 are as follows:

<TABLE>
<CAPTION>
                                                                                 YEARS ENDED DECEMBER 31,
                                                                         -------------------------------------
                                                                             2000         1999         1998
                                                                         ----------   ----------   -----------
                                                                                     (IN THOUSANDS)
     <S>                                                                 <C>          <C>          <C>
     Current tax expense:
     Federal...........................................................  $    2,579   $      497   $      527
     State.............................................................         345           34           73
                                                                         ----------   ----------   -----------
                                                                              2,924          531          600
                                                                         ----------   ----------   -----------
     Deferred tax expense (benefit):
     Federal...........................................................      51,325       12,054      (12,766)
     State.............................................................       6,870        1,691       (1,758)
                                                                         ----------   ----------   -----------
                                                                             58,195       13,745      (14,524)
                                                                         ----------   ----------   -----------
                                                                         $   61,119   $   14,276   $  (13,924)
                                                                         ==========   ==========   ===========
</TABLE>

     The provision for income taxes before cumulative effect of accounting
change differed from the computed "expected" income tax provision using
statutory rates on income before income taxes for the following reasons:

<TABLE>
<CAPTION>
                                                                                YEARS ENDED DECEMBER 31,
                                                                         ------------------------------------
                                                                            2000         1999         1998
                                                                         ----------   ----------   ----------
                                                                                    (IN THOUSANDS)
     <S>                                                                 <C>          <C>          <C>
     Computed "expected" income tax....................................  $   55,783   $   12,492   $  (20,372)
     Increases (reductions) in taxes resulting from:
       State income taxes, net of federal benefit......................       4,690        1,121       (1,095)
       Permanent differences (principally related to basis differences
         in oil and gas properties)....................................         525          588        6,133
       Change in valuation allowance...................................          --         (194)       2,667
       Section 29 credits..............................................         (15)        (394)        (851)
       Other...........................................................         136          663         (406)
                                                                         ----------   ----------   ----------
                                                                         $   61,119   $   14,276   $  (13,924)
                                                                         ==========   ==========   ==========
</TABLE>

     As a result of employee stock options exercised during 2000, an additional
$1.7 million tax benefit was realized, reflected in the accompanying balance
sheet for December 31, 2000 as an increase to income taxes receivable and an
increase to additional paid-in capital.


                                                      F-12
<PAGE>


                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


     Deferred tax assets and liabilities resulting from differences between the
financial statement carrying amounts and the tax bases of assets and
liabilities, consist of the following:

<TABLE>
<CAPTION>
                                                                                             DECEMBER 31,
                                                                                      -----------------------
                                                                                         2000         1999
                                                                                      ----------   ----------
                                                                                            (IN THOUSANDS)
     <S>                                                                              <C>          <C>
     Deferred tax liabilities:
     Capitalized costs and related depreciation, depletion and amortization.........  $  134,383   $   93,414
     Fixed-price contracts and other derivatives....................................       1,595       12,045
     Other..........................................................................      12,042          102
                                                                                      ----------   ----------
                                                                                         148,020      105,561
                                                                                      ----------   ----------
     Deferred tax assets:
     Deferred revenue...............................................................       4,284        5,139
     Fixed-price contracts and other derivatives....................................      87,287        6,339
     Alternative minimum tax credits................................................       6,136        6,136
     Net operating loss carryforwards...............................................      60,855       85,074
     Other..........................................................................         735          735
                                                                                      ----------   ----------
                                                                                         159,297      103,423
     Valuation allowance for net operating loss carryforwards.......................     (30,499)     (50,203)
                                                                                      ----------   ----------
                                                                                         128,798       53,220
                                                                                      ----------   ----------
     Net deferred tax liability.....................................................  $   19,222   $   52,341
                                                                                      ==========   ==========
</TABLE>

     At December 31, 2000, we had U.S. Federal net operating loss carryforwards
of $174 million that expire beginning in 2001 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 $87
million may 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. We are pursuing a strategy
anticipated to increase the utilization of net operating loss carryforwards
otherwise expected to expire by as much as $46 million. This anticipated
benefit will be recognized in the tax provision when realized.

NOTE 6 -- TRANSACTIONS WITH RELATED PARTIES

     FIXED-PRICE CONTRACT ACTIVITY. In 1993, we 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 year ended December 31, 2000, this contract resulted in
a realized hedging loss of $7.4 million included in results of operations. For
the years ended December 31, 1999 and 1998, the contract resulted in realized
hedging gains of $3.4 million and $2.9 million, respectively.

     GENERAL AND ADMINISTRATIVE EXPENSE. We are a party to a services agreement
under which S.A. Louis Dreyfus et Cie provides certain administrative and
support services (principally insurance and related services) on our behalf.
These services are billed to us at amounts approximating cost. General and
administrative expenses for the years ended December 31, 2000, 1999 and 1998
include $.4 million, $.5 million and $1.4 million, respectively, for such
services.

NOTE 7 --  COMMITMENTS AND CONTINGENCIES

     LITIGATION. Louis Dreyfus Natural Gas Corp. 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 an underground hydrocarbon plume within the city of McAllen,
Texas. The lawsuit alleges that gas wells and related pipeline facilities
operated by us, and other facilities operated by other defendants, caused the
plume. In August 1999, the plaintiffs' experts produced reports that suggested
we might be considered a significant contributor to the


                                      F-13
<PAGE>


                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


plume. Our investigation into this matter has not found any leaks or discharges
from our facilities. In addition, our investigation has revealed the plume to
be unrelated to our gas wells and facilities. Trial is not anticipated to
commence until the second half of 2001. We will vigorously defend our interests
in this case. We do not presently expect the ultimate outcome of the case to
have a material adverse impact on our financial position or results of
operations; however, results of litigation are inherently unpredictable and
this estimate may change in the future.

     We were a defendant in various other legal proceedings as of December 31,
2000, which are routine and incidental to our business. We will vigorously
defend our interests in these proceedings. While the ultimate results of these
proceedings cannot be predicted with certainty, we do not believe that the
outcome of these matters will have a material adverse effect on our financial
position or results of operations.

     RENTAL COMMITMENTS. Minimum annual rental commitments as of December 31,
2000 under noncancellable office space leases are as follows: 2001 - $2.6
million; 2002 - $2.1 million; 2003 - $2.0 million; 2004 - $1.0 million; 2005
and thereafter - $5.2 million. Approximately $800,000 of such rental
commitments is included in other accrued liabilities as of December 31, 2000.
Rent expense included in results of operations for the three years ended
December 31, 2000, 1999 and 1998 was $1.6 million, $1.5 million and $2.1
million, respectively.

NOTE 8 -- EMPLOYEE BENEFIT PLANS

     401(k) PLAN. Our 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. Pursuant to the plan provisions, employee
contributions can be made up to 17% of compensation. Employer contributions are
discretionary. Employees vest in employer contributions at 20% per year of
service. For the years ended December 31, 2000, 1999 and 1998, we contributed
$1.4 million, $1.3 million and $1.2 million, respectively, to the 401(k) plan.

     EMPLOYEE STOCK PURCHASE PLAN. The Louis Dreyfus Natural Gas Corp. 2000
Employee Stock Purchase Plan provides eligible employees with the opportunity
to purchase shares of our common stock through payroll deductions at a discount
from the market value of the shares and on a tax-favorable basis.

     STOCK COMPENSATION PLANS. The Louis Dreyfus Natural Gas Corp. Deferred
Stock Trust, established in 1998, serves as a depositary for restricted stock
awards granted pursuant to the underlying agreement. Common stock contributed
to the trust can be distributed to the beneficiary only upon termination of
employment or other specified events. Also in 1998, we established a separate
deferred stock trust for use in compensating our non-employee directors. At
December 31, 2000, these trusts held a combined 107,427 shares of common stock.
Compensation expense of $614,000 was recorded for the year ended December 31,
2000, relating to stock awards granted under these trust agreements.

     Officers, directors and certain key employees have been granted options
to purchase common stock under the 1993 Stock Option Plan, as amended. 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 may
be granted under the plan. The maximum number of common shares presently
issuable is three million shares, subject to appropriate equitable adjustment
in the event of a reorganization, stock split, stock dividend, reclassification
or other change affecting the common stock. As of December 31, 2000 and 1999,
options to purchase 144,870 shares and 418,920 shares of common stock,
respectively, were available for grant. 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 equals the market price of the common 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


                                       F-14
<PAGE>

                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


if the stock options issued after December 31, 1994 were accounted for using
the fair value method. The fair value of stock options issued for each year
was estimated at the date of grant using a Black-Scholes option pricing model.
Valuation assumptions for option grants in 2000, 1999 and 1998 included the
following: risk-free interest rates of 5.9%, 5.8% and 4.9%, respectively; no
dividends over the option term; stock price volatility factors of .50, .37 and
 .36, 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.

     The SFAS 123 pro forma information is as follows:


<TABLE>
<CAPTION>

                                                                                YEARS ENDED DECEMBER 31,
                                                                         -------------------------------------
                                                                            2000         1999         1998
                                                                         ----------   ----------   -----------
                                                                         (IN THOUSANDS, EXCEPT PER SHARE DATA)
     <S>                                                                 <C>          <C>          <C>
     Net income (loss).................................................  $   95,443   $   18,988   $  (45,194)
     Net income (loss) per share.......................................        2.23          .47        (1.13)

</TABLE>

     The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions, including expected stock price
volatility. Because these stock options issued under the option plan 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 our opinion, the existing models do not necessarily
provide a reliable single measure of stock option fair value.

     Stock option transactions for 2000, 1999 and 1998 are summarized as
follows:


<TABLE>
<CAPTION>

                                                                           YEARS ENDED DECEMBER 31,
                                         --------------------------------------------------------------------------------------
                                                    2000                           1999                         1998
                                         -----------------------------  --------------------------   --------------------------
                                                          WEIGHTED-                   WEIGHTED-                     WEIGHTED-
                                                           AVERAGE                     AVERAGE                       AVERAGE
                                           SHARES       EXERCISE PRICE    SHARES    EXERCISE PRICE     SHARES     EXERCISE PRICE
                                         ----------     --------------  ----------  --------------   ----------   --------------
     <S>                                 <C>            <C>             <C>         <C>              <C>         <C>
     Outstanding at beginning of year     2,368,817           $  17.38   2,124,580        $  16.85    1,708,330         $  19.03
     Granted.........................       292,675              31.97     426,000           19.16    1,054,750            15.51
     Exercised.......................      (743,115)             17.07    (159,513)          15.45      (22,500)           15.05
     Canceled........................       (18,625)             16.79     (22,250)          14.44     (616,000)           20.68
                                         ----------                     ----------                   ----------
     Outstanding at end of year......     1,899,752              19.76   2,368,817           17.38    2,124,580            16.85
                                         ==========                     ==========                   ==========

     Exercisable at end of year......       862,080              17.86   1,148,317           17.21      909,830            17.27
                                         ==========                     ==========                   ==========

     Weighted-average fair value of
       options granted during year...    $    16.19                     $     8.05                   $     6.17
                                         ==========                     ==========                   ==========

</TABLE>

  ----------------------------------

     Outstanding options to acquire 292,675 shares of stock at December 31, 2000
had exercise prices ranging from $30.00 to $33.78 per share (20,000 of which are
exercisable at a weighted-average exercise price of $30.00 per share), had a
weighted-average exercise price of $31.97, and had a weighted-average remaining
contractual life of 9.8 years. Outstanding options to acquire 914,440 shares of
stock at December 31, 2000 had exercise prices ranging from $18.00 to $23.16 per
share (478,440 of which are exercisable at a weighted-average price of $20.34
per share), had a weighted- average exercise price of $20.29, and had a
weighted-average remaining contractual life of 7.1 years. The balance of options
outstanding at December 31, 2000 had exercise prices ranging from $12.47 to
$16.69 per share (363,640 of which are exercisable at a weighted-average price
of $13.93 per share), had a weighted-average exercise price of $13.90, and had a
weighted-average remaining contractual life of 7.2 years.

                                    F-15

<PAGE>


                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


NOTE 9 -- SIGNIFICANT CUSTOMERS

     Our oil and gas production is sold under contracts with various purchasers.
For the year ended December 31, 2000, gas sales to Enron Corp., Duke Energy, and
PG&E Corp. approximated 17%, 17% and 14% of total revenues, respectively. 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.
We believe that alternative purchasers are available, if necessary, to purchase
our production at prices substantially similar to those received from these
significant purchasers in 2000.

NOTE 10 -- CAPITAL STOCK AND STOCKHOLDERS' EQUITY

       COMMON STOCK. The following table presents our common stock activity for
the periods presented:


<TABLE>
<CAPTION>

                                                                                 YEARS ENDED DECEMBER 31,
                                                                             --------------------------------
                                                                              2000         1999         1998
                                                                             ------       ------       ------
                                                                                      (IN THOUSANDS)
     <S>                                                                     <C>          <C>          <C>
     Common Stock Activity:
     Balance, beginning of year........................................      40,199       40,110       40,088
     Sale of common stock..............................................       2,405           --           --
     Exercise of warrants..............................................         363           --           --
     Exercise of stock options.........................................         690          121           22
     Treasury shares reissued (purchased)..............................          32          (32)          --
                                                                             ------       ------       ------
     Balance, end of year..............................................      43,689       40,199       40,110
                                                                             ======       ======       ======

</TABLE>

     In 2000, we sold 2.4 million shares of common stock at $31.00 per share
($29.53 per share net of underwriting discount) in a public offering. Proceeds
from the offering of $70.9 million received in July 2000 were applied to reduce
a majority of the indebtedness incurred in connection with the acquisition of
properties from Costilla Energy, Inc. In addition, an indirect wholly-owned
subsidiary of S.A. Louis Dreyfus et Cie sold 1.6 million shares of our common
stock in the offering. Subsequent to the offering, S.A. Louis Dreyfus et Cie
through its subsidiaries owned 19.2 million shares, or approximately 44% of the
total issued and outstanding common shares.

     WARRANTS. At December 31, 2000, warrants were outstanding to purchase
317,566 shares of common stock, all of which were exercisable. The warrants have
an exercise price of $17.69 per share and expire in December 2004. During 2000,
740,987 warrants were exercised resulting in the issuance of 363,541 shares of
common stock. Additional warrants to purchase 356,489 shares expired unexercised
in April 1999. All warrants were originally issued in 1997 in connection with
the acquisition of American Exploration Company.














                                    F-16

<PAGE>

                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     OTHER COMPREHENSIVE INCOME. The components of other comprehensive income
and related tax effects for the years ended December 31, 2000, 1999 and 1998 are
shown as follows:
<TABLE>
<CAPTION>
                                                                                         TAX          NET OF
                                                                            GROSS       EFFECT         TAX
                                                                         ----------   ----------   ----------
                                                                                    (IN THOUSANDS)
     <S>                                                                 <C>          <C>          <C>
     Year ended December 31, 2000:
     Change in fixed-price contract and other derivative fair value....  $ (295,599)  $ (112,328)  $ (183,271)
     Reclassification adjustments - contract settlements...............      55,299       21,014       34,285
                                                                         ----------   ----------   ----------
                                                                         $ (240,300)  $  (91,314)  $ (148,986)
                                                                         ==========   ==========   ==========
     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
                                                                         ==========   ==========   ==========
</TABLE>
NOTE 11 -- 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 that we held as of December 31, 2000 and 1999, and the
methods and assumptions used to estimate their fair value:

<TABLE>
<CAPTION>
                                                               DECEMBER 31, 2000         DECEMBER 31, 1999
                                                            -----------------------   -----------------------
                                                              CARRYING      FAIR       CARRYING       FAIR
                                                               AMOUNT       VALUE       AMOUNT        VALUE
                                                            -----------   ---------   ----------    ---------
                                                                              (IN THOUSANDS)
     <S>                                                    <C>           <C>         <C>          <C>
     Derivative assets:
       Fixed-price natural gas swaps......................  $       --   $       --   $   16,433   $   16,433
       Fixed-price natural gas collars....................          --           --        1,323        1,323
       Fixed-price natural gas delivery contracts.........          --           --        7,921        7,921
       Fixed-price crude oil swaps........................          --           --          360          360
       Interest rate swaps................................       1,756        1,756        5,660        5,660
     Derivative liabilities:
       Fixed-price natural gas swaps......................     (55,923)     (55,923)      (4,329)      (4,329)
       Fixed-price natural gas collars....................     (26,054)     (26,054)          --           --
       Fixed-price natural gas delivery contracts.........    (146,234)    (146,234)      (9,081)      (9,081)
       Natural gas basis swaps............................      (1,491)      (1,491)      (3,271)      (3,271)
     Bank debt (1)........................................    (313,800)    (316,568)    (255,600)    (260,494)
     6 7/8% Senior Notes due 2007 (1).....................    (199,156)    (193,646)    (199,034)    (177,012)
     9 1/4% Senior Subordinated Notes due 2004 (1)........     (93,953)     (96,061)    (100,588)     (99,591)
</TABLE>
     -------------------------------
     (1) - Carrying amounts do not include capitalized debt issuance costs. See
           Note 1 -- Significant Accounting Policies -- Debt Issuance Costs.

     Cash and cash equivalents, receivables, accounts payable, accrued
liabilities and revenues payable 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, 2000 and 1999
was estimated based on market prices

                                    F-17
<PAGE>

                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


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 our estimation of contract performance risk and
counterparty credit risk. The fair value of derivative instruments which
contain options (such as collar structures) has been estimated based on
remaining term, volatility and other factors. The terms and conditions of our
fixed-price delivery contracts and certain financial swaps are uniquely
tailored to our circumstances. In addition, certain of the 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. We have relied upon near-term market quotations,
longer-term over-the-counter market quotations and other market information
to determine fair value estimates. See Note 12 -- Derivatives -- Accounting.

     The change in carrying value of fixed-price contracts and interest rate
swaps in the December 31, 2000 balance sheet compared to the December 31, 1999
balance sheet resulted from a significant increase in market prices for natural
gas and an increase in interest rates. Derivative liabilities reflected as
current in the December 31, 2000 balance sheet represent the estimated fair
value of fixed-price contract settlements scheduled to occur over the subsequent
twelve- month period based on market prices for oil and gas as of the balance
sheet date. The offsetting increase in value of the hedged future production has
not been accrued in the accompanying balance sheet, creating the appearance of a
working capital deficit from these contracts. The contract settlement amounts
are not due and payable until the monthly period that the related underlying
hedged transaction occurs. In some cases the recorded liability for certain
contracts significantly exceeds the total settlement amounts that would be paid
to a counterparty based on prices in effect at the balance sheet date due to
option time value. Since we expect to hold these contracts to maturity, this
time value component has no direct relationship to actual future contract
settlements and consequently does not represent a liability which will be
settled in cash or realized in any way.

     The vast majority of all fixed-price contract fair value changes are
reflected in accumulated other comprehensive income on the face of the balance
sheet, shown net of deferred tax effect. At December 31, 2000, this accounting
treatment resulted in a cumulative unrealized reduction in stockholders' equity
of $99.0 million, giving the appearance that a loss in net enterprise value was
experienced as a result of increases in market oil and gas prices. Except for
the effect of basis movements, we expect 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 our oil and natural gas reserves.
Because only 13% of the future production from our natural gas reserves is
hedged, higher oil and gas prices actually increase our net enterprise value, as
is apparent in the standardized measure calculation. This change in reserve
value, however, is not reflected in our balance sheet. See Note 12 --
Derivatives and Note 13 -- Supplemental Information - Oil and Gas Reserves.

       The fair value of bank debt at December 31, 2000 and 1999 was determined
by utilizing an estimated market credit spread for bank debt with comparable
terms and credit quality. 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 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.
These valuations are based on market interest rates as of the determination
date.

NOTE 12 -- DERIVATIVES

     DESCRIPTION OF CONTRACTS. We utilize fixed-price contracts to reduce
exposure to unfavorable changes in oil and gas prices which are subject to
significant and often volatile fluctuation. Fixed-price contracts are comprised
of long- term delivery contracts, energy swaps, collars and basis swaps. These
contracts allow us to predict with greater certainty the effective oil and gas
prices to be received for hedged production and benefit operating cash flows and
earnings when market prices are less than the fixed prices provided in the
contracts. However, we will not benefit from market prices

                                    F-18

<PAGE>

                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


that are higher than the fixed prices in the contracts for hedged production.
For the years ended December 31, 2000, 1999 and 1998, fixed-price contracts
hedged 44%, 55% and 50%, respectively, of our gas production and 40%, 19% and
16%, respectively, of our oil production. Fixed-price contracts as of December
31, 2000, hedge 82 Bcf of future gas production in 2001, and 120 Bcf
thereafter.

     For energy swap contracts, we receive a fixed price for the respective
commodity and pay 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 delivery
contracts, we purchase gas in the spot market at floating market prices and
deliver gas to the contract counterparty at a fixed price. 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 we receive the fixed price and pay 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 basis swaps, we receive the
floating market price for NYMEX futures and pay 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 fixed-price
contracts as of December 31, 2000. We expect the prices to be realized for
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 delivery contracts, and the
price received at the wellhead for our hedged 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, 2000, as adjusted for basis. Future net revenues
change with changes in market prices and basis. See "-- Market Risk."











                                    F-19

<PAGE>

                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


<TABLE>
<CAPTION>


                                                      YEARS ENDING DECEMBER 31,              BALANCE
                                     ----------------------------------------------------    THROUGH
                                       2001       2002       2003       2004       2005        2017       TOTAL
                                     ---------  --------   --------   --------   --------   ---------   ---------
                                                      (DOLLARS IN THOUSANDS, EXCEPT PRICE DATA)
    <S>                              <C>        <C>        <C>        <C>        <C>        <C>         <C>
    NATURAL GAS SWAPS:
    Contract volumes (BBtu).......      32,340     6,697      5,650      5,650      5,650       6,483      62,470
    Weighted-average fixed
      price per MMBtu (1).........   $    4.90  $   2.65   $   2.92   $   3.12   $   3.32   $    3.41   $    4.02
    Future fixed-price sales......   $ 158,579  $ 17,766   $ 16,492   $ 17,608   $ 18,740   $  22,082   $ 251,267
    Future net revenues (2).......   $ (36,849) $(11,542)  $ (5,028)  $ (3,276)  $ (2,089)  $  (1,901)  $ (60,685)

    NATURAL GAS DELIVERY
      CONTRACTS:
    Contract volumes (BBtu).......      17,814    17,689     14,819      6,634      5,314      38,116     100,386
    Weighted-average fixed
      price per MMBtu (1).........   $    2.38  $   2.46   $   2.53   $   2.53   $   2.63   $    3.01   $    2.68
    Future fixed-price sales......   $  42,464  $ 43,461   $ 37,428   $ 16,802   $ 13,978   $ 114,760   $ 268,893
    Future net revenues (2).......   $ (71,426) $(32,751)  $(18,105)  $ (7,569)  $ (5,519)  $ (31,932)  $(167,302)

    NATURAL GAS COLLARS:
    Contract volumes (BBtu):
      Floor.......................      31,800     7,300         --         --         --          --      39,100
      Ceiling.....................      31,800     7,300         --         --         --          --      39,100
    Weighted-average fixed-
      price per MMBtu (1):
      Floor.......................   $    4.57  $   2.84   $     --   $     --   $     --   $      --   $    4.25
      Ceiling.....................   $    6.28  $   3.94   $     --   $     --   $     --   $      --   $    5.84
    Future fixed-price sales (4)..   $ 145,447  $ 20,732   $     --   $     --   $     --   $      --   $ 166,179
    Future net revenues (2).......   $ (16,201) $ (3,902)  $     --   $     --   $     --   $      --   $ (20,103)

    TOTAL NATURAL GAS CONTRACTS
      (3):
    Contract volumes (BBtu).......      81,954    31,686     20,469     12,284     10,964      44,599     201,956
    Weighted-average fixed
      price per MMBtu (1).........   $    4.23  $   2.59   $   2.63   $   2.80   $   2.98   $    3.07   $    3.40
    Future fixed-price sales (4)..   $ 346,490  $ 81,959   $ 53,920   $ 34,410   $ 32,718   $ 136,842   $ 686,339
    Future net revenues (2).......   $(124,476) $(48,195)  $(23,133)  $(10,845)  $ (7,608)  $ (33,833)  $(248,090)

</TABLE>

     -------------------------------

     (1) - The prices to be realized for hedged production are expected to vary
           from the prices shown due to basis. See "Market Risk."
     (2) - Future net revenue amounts as presented above are undiscounted and
           have not been adjusted for contract performance risk or counterparty
           credit risk. Bracketed amounts represent decreases to future natural
           gas sales. See Note 11 -- Financial Instruments.
     (3) - Does not include basis swaps with notional volumes by year, as
           follows: 2001 - 9.4 TBtu; and 2002 - 5.5 TBtu.
     (4) - Assumes floor prices for natural gas collar volumes.

     The estimates of future net revenues from 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. We have relied upon near-term market quotations,
longer-term over-the-counter market quotations and other market information to
determine 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 11 -- Financial
Instruments for estimated fair value information.

     ACCOUNTING. All fixed-price contracts have been executed in connection with
our natural gas and crude oil hedging program. The differential between the
fixed price and the floating price for each contract settlement period
multiplied by the associated contract volume 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 production was hedged. For fixed-price contracts
qualifying as cash flow hedges pursuant to SFAS 133, changes in fair value for
volumes not yet settled are shown as adjustments to other comprehensive income.
For those contracts not qualifying as cash flow hedges, changes in fair value
are recognized in earnings. The fair value of all fixed-price contracts are
recorded as assets or liabilities in the balance sheet.


                                    F-20


<PAGE>

                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


     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. Included in
accumulated other comprehensive income at December 31, 2000 and 1999, were
pretax unamortized deferred gains of $86.4 million and $99.7 million,
respectively, related to terminated contracts. These deferred gains are recorded
net of deferred tax effect. 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, 2000, 1999 and 1998, oil and gas sales
included $62.3 million of net losses, $1.5 million of net gains and $23.1
million of net gains, respectively, associated with realized gains and losses
under fixed-price contracts.

     Change in derivative fair value for the years ended December 31, 2000, 1999
and 1998 was comprised of the following:


<TABLE>
<CAPTION>

                                                                                  YEARS ENDED DECEMBER 31,
                                                                           ------------------------------------
                                                                              2000         1999         1998
                                                                           ----------   ----------   ----------
                                                                                      (IN THOUSANDS)
     <S>                                                                   <C>          <C>          <C>
     CHANGE IN DERIVATIVE FAIR VALUE
     Change in fair value for derivatives not qualifying for hedge
         accounting......................................................  $   (2,632)  $    9,740   $   17,346
     Amortization of derivative fair value gains and losses recognized
         in earnings prior to actual cash settlement.....................      (6,501)      (2,943)          --
     Ineffective portion of derivatives qualifying for hedge accounting,
         including the time value component of collars...................      (6,429)      (7,239)          --
                                                                           ----------   ----------   ----------
                                                                           $  (15,562)  $     (442)  $   17,346
                                                                           ==========   ==========   ==========

</TABLE>

     Amounts recorded in change in derivative fair value do not represent cash
gains or losses. Rather, these amounts are temporary valuation swings in
contracts or portions of contracts that are not entitled to receive hedge
accounting treatment. All amounts initially recorded in this caption are
ultimately reversed within this same caption over the respective contract terms.
Despite certain fixed-price contracts failing the effectiveness guidelines of
SFAS 133 from time to time, fixed-price contracts continue to be effective in
achieving the risk management objectives for which they were intended.

     In addition to the future net settlements identified in the table under
"--Description of Contracts", we expect the following adjustments in 2001: (1)
oil and gas sales will include $13.9 million of gains from the amortization of
deferred gains from price-risk management activities, (2) interest expense will
include $.4 million of loss from the amortization of deferred interest rate
hedging losses, and (3) change in derivative fair value in the statement of
operations will include a loss of $4.7 million relating to the unwinding of
previously recognized net gains in this caption as actual contract cash
settlements are realized and the time value component of options reverse.

     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 pipeline marketing affiliates, financial institutions, an
independent power producer, a municipality, and other end users. In some cases,
we require 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 we would be able to enter
into a new contract with a third party on terms comparable to the original
contract. We have not experienced non-performance by any counterparty.

     Cancellation or termination of a fixed-price contract would subject a
greater portion of our gas production to market prices, which, in a low price
environment, could have an adverse effect on our future operating results. In
addition, the associated carrying value of the contract would be removed from
the balance sheet.

                                    F-21

<PAGE>

                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


       In October 1999 and June 1998, we agreed to the termination of two
long-term fixed-price natural gas delivery contracts. These terminations
resulted in the receipt of cash in the amount of $44.2 million and $40.1
million, respectively. The associated realized gains have 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 our 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
fixed-price contracts are affected by movements in basis. For the years ended
December 31, 2000, 1999 and 1998, we received on an Mcf basis approximately 2%,
6% and 6% less than the prices specified in natural gas fixed-price contracts,
respectively, due to basis. For oil production hedged by crude oil fixed-price
contracts, we realized approximately 6%, 7% and 10% 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
our portfolio of fixed-price contracts and the composition of our 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 2001
represents a $3.5 million change in gas sales. We actively manage exposure to
basis movements and from time to time will enter into contracts designed to
reduce such exposure.

     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 our hedged oil and natural gas production. Because the majority of
our future estimated oil and gas production is unhedged, declining oil and gas
prices could have a material adverse effect on future results of operations and
operating cash flows.

     MARGIN. We are required to post margin in the form of bank letters of
credit or treasury bills under certain fixed-price contracts. In some cases,
the amount of 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, 2000, 1999 and 1998, the maximum aggregate
amount of margin posted was $70.8 million, $23.5 million and $23.7 million,
respectively. If natural gas prices were to rise, or if we failed to meet the
financial tests contained in certain fixed-price contracts, margin requirements
could increase significantly. We believe that margin requirements will be
adequately met through bank credit facility availability, other existing lines
of credit, or credit lines that may be obtained in the future. If we are unable
to meet margin requirements, a contract could be terminated and we could be
required to pay damages to the counterparty which generally approximate the cost
to the counterparty of replacing the contract. At December 31, 2000, margin had
been issued in the form of letters of credit totaling $70.8 million. Subsequent
to December 31, 2000, margin requirements under fixed-price contracts to two
counterparties were reduced, resulting in a $44 million reduction in posted
margin.

     INTEREST RATE SWAPS. We have interest rate swaps designed to hedge the
interest rate exposure associated with borrowings under the bank credit
facility. As of December 31, 2000, we had fixed the interest rate on average
notional amounts of $125 million and $94 million for the years ended December
31, 2001 and 2002, respectively. Under the interest rate swaps, we receive the
LIBOR three-month rate (6.4% at December 31, 2000) and pay 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 bank credit facility
for the respective 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.
This 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, 2000 and 1999,
we had deferred termination losses of $2.4 million and $2.8 million,
respectively, recorded net of tax in accumulated other comprehensive income.
Interest rate swaps decreased interest expense during

                                    F-22

<PAGE>

                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


2000 by $1.9 million. The impact of interest rate swap settlements in 1999 and
1998 was not material.

NOTE 13 -- SUPPLEMENTAL INFORMATION - OIL AND GAS RESERVES (UNAUDITED)

     The following information summarizes our net proved reserves of crude oil
and natural gas and the present values of proved reserves for the three years
ended December 31, 2000, 1999 and 1998. Reserve estimates for these years have
been prepared by our 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
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 our estimated proved reserves, all of which are located in the
United States, for the years ended December 31, 2000, 1999 and 1998. Proved oil
and gas reserves are the estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, that is, prices and costs as
of the date the estimate is made. Proved developed reserves are proved reserves
that can be expected to be recovered through existing wells with existing
equipment and operating methods.

<TABLE>
<CAPTION>
                                                      2000                   1999                  1998
                                               --------------------   -------------------   ------------------
                                                 OIL         GAS        OIL        GAS        OIL       GAS
                                               (MBBLS)      (MMCF)    (MBBLS)     (MMCF)    (MBBLS)    (MMCF)
                                               -------    ---------   -------   ---------   -------  ---------
     <S>                                       <C>        <C>         <C>       <C>         <C>      <C>
     PROVED RESERVES:
     Beginning of year......................    28,372    1,294,029    24,416   1,193,666    29,109  1,028,752
     Acquisition of proved reserves.........     5,796      169,568       436      38,352       166      6,270
     Extensions and discoveries.............     1,767      264,629     1,328     199,687     1,943    246,382
     Revisions of previous estimates (1)....       271          807     5,736     (22,506)   (3,165)    19,974
     Sales of reserves in place.............       (88)        (709)     (579)     (7,191)     (207)    (6,646)
     Production.............................    (2,860)    (119,855)   (2,965)   (107,979)   (3,430)  (101,066)
                                               -------    ---------   -------   ---------   -------  ---------
     End of year............................    33,258    1,608,469    28,372   1,294,029    24,416  1,193,666
                                               =======    =========   =======   =========   =======  =========
     PROVED DEVELOPED RESERVES:
     Beginning of year......................    23,943    1,064,739    20,722   1,026,834    24,321    899,196
     End of year............................    27,903    1,313,590    23,943   1,064,739    20,722  1,026,834
</TABLE>
     -------------------------------
     (1) - The crude oil volume revision for 1998 was primarily the result of a
           significant reduction in year-end 1998 crude oil prices compared to
           the prior year-end. 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 our 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-23
<PAGE>

                         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: 2000 - $25.38 per Bbl, $6.07 per Mcf; 1999 - $24.36 per Bbl,
           $2.19 per Mcf; and 1998 - $9.46 per Bbl, $2.07 per Mcf. These prices
           do not include the effect of the 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.


<TABLE>
<CAPTION>

                                                                                    DECEMBER 31,
                                                                      ---------------------------------------
                                                                          2000         1999           1998
                                                                      -----------   -----------   -----------
                                                                                  (IN THOUSANDS)
     <S>                                                              <C>           <C>           <C>
     Future cash inflows (1).......................................   $10,612,100   $ 3,521,914   $ 2,695,864
     Future production costs.......................................    (2,310,885)   (1,169,263)     (870,420)
     Future development costs......................................      (281,871)     (216,211)     (148,595)
     Future income taxes...........................................    (2,649,077)     (460,504)     (278,363)
                                                                      -----------   -----------   -----------
                                                                        5,370,267     1,675,936     1,398,486
     Discount at 10% per year......................................    (2,830,443)     (813,818)     (678,780)
                                                                      -----------   -----------   -----------
     Standardized measure of discounted future net cash flows (1)..   $ 2,539,824   $   862,118   $   719,706
                                                                      ===========   ===========   ===========

</TABLE>

     -------------------------------

     (1) - Future cash inflows and the standardized measure of discounted
           future net cash flows are based on period end oil and gas wellhead
           prices and do not include the effect on future cash flows from our
           fixed-price contracts.

     The standardized measure information in the preceding table was derived
from estimates of our proved oil and gas reserves contained in studies prepared
by our petroleum engineers and reviewed by independent 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 our oil and gas reserves. The foregoing
information is presented for comparative purposes as of the respective year-end
and is not intended to reflect any changes in value which may result from
subsequent 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 our oil and gas reserves for
the years ended December 31, 2000, 1999 and 1998, were as follows:


                                    F-24

<PAGE>

                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


<TABLE>
<CAPTION>

                                                                                YEARS ENDED DECEMBER 31,
                                                                         ------------------------------------
                                                                            2000         1999          1998
                                                                         ----------   ----------   ----------
                                                                                    (IN THOUSANDS)
     <S>                                                                 <C>          <C>          <C>

     Balance, beginning of year........................................  $  862,118   $  719,706   $  873,500
     Acquisitions of proved reserves...................................     388,133       39,877        4,236
     Extensions and discoveries, net of future development costs.......     694,182      194,059      183,231
     Revisions of previous quantity estimates..........................       5,645        9,118          676
     Oil and gas sales, net of production costs........................    (465,047)    (223,298)    (182,131)
     Sales of reserves in place........................................        (384)      (8,236)      (7,769)
     Net changes in sales prices and production costs..................   2,032,565      153,701     (234,815)
     Development costs incurred and changes in estimated future
        development costs..............................................      39,365      (14,138)      41,121
     Net change in income taxes........................................  (1,006,549)     (96,236)      37,783
     Accretion of discount.............................................     104,972       81,107      100,265
     Changes in timing of production and other.........................    (115,176)       6,458      (96,391)
                                                                         ----------   ----------   ----------
     Balance, end of year..............................................  $2,539,824   $  862,118   $  719,706
                                                                         ==========   ==========   ==========

</TABLE>

                                    F-25

<PAGE>

                         LOUIS DREYFUS NATURAL GAS CORP.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


NOTE 14 -- QUARTERLY RESULTS  (UNAUDITED)


<TABLE>
<CAPTION>

                                                  2000                                   1999
                                ---------------------------------------   -------------------------------------
                                 FOURTH     THIRD     SECOND     FIRST    FOURTH     THIRD    SECOND     FIRST
                                QUARTER    QUARTER    QUARTER   QUARTER   QUARTER   QUARTER   QUARTER   QUARTER
                                --------   --------   -------   -------   -------   -------   -------   -------
                                                       (IN THOUSANDS, EXCEPT PER SHARE DATA)
     <S>                        <C>        <C>        <C>       <C>       <C>       <C>       <C>       <C>

     Revenues (1).............  $174,366   $134,461   $88,004   $80,454   $93,115   $89,946   $62,422   $57,123
     Operating profit (2).....   102,965     58,585    42,343    37,743    30,022    27,012    24,438    12,023
     Net income (loss) (3)....    50,908     29,425     9,072     8,855    12,641    13,048      (454)   (3,821)
     Net income (loss) per
       share - diluted........      1.15       0.66      0.22      0.22      0.31      0.32     (0.01)    (0.10)

</TABLE>

     -------------------------------

     (1) -  The revenue decrease in the first quarter of 2000 is primarily
            attributable to change in derivative fair value. The revenue
            increases in the third and fourth quarters of 2000 were favorably
            impacted by higher oil and gas prices.
     (2) -  The increases in operating profits for the third and fourth quarters
            of 2000 are attributable to higher oil and gas prices.
     (3) -  Net losses in the first and second quarters of 1999 resulted from
            lower oil and gas prices and higher gas production. Net income in
            the third and fourth quarters of 2000 resulted primarily from higher
            oil and gas prices.


                                    F-26

<PAGE>

                         LOUIS DREYFUS NATURAL GAS CORP.
          SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
                                 (IN THOUSANDS)


<TABLE>
<CAPTION>

                                                  BALANCE AT                                                    BALANCE AT
                                                 BEGINNING OF                                                     END OF
                                                    PERIOD      ADDITIONS (1)  DEDUCTIONS (2)     OTHER (3)       PERIOD
                                                 ------------   -------------  --------------    ----------     ----------
   <S>                                           <C>            <C>            <C>               <C>            <C>
   DESCRIPTION:
   December 31, 2000:
   Allowance for doubtful accounts - Joint
     interest and other receivables............  $      1,114   $          --  $           57    $      168     $      889
                                                 ============   =============  ==============    ==========     ==========

   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
                                                 ============   =============  ==============    ==========     ==========

</TABLE>

   ---------------------------------

   (1)  - Additions relate to provisions for doubtful accounts.
   (2)  - Deductions relate to the write-off of accounts receivable deemed
          uncollectible.
   (3)  - Reclassification adjustment.



















                                    F-27