LOUIS DREYFUS NATURAL GAS CORP, S-3/A, 1997-02-18

LOUIS DREYFUS NATURAL GAS CORP
S-3/A, 1997-02-18
CRUDE PETROLEUM & NATURAL GAS

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<PAGE>

AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 18, 1997
REGISTRATION NO. 333-21321
- ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

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

AMENDMENT NO. 1
TO
FORM S-3
REGISTRATION STATEMENT
Under
THE SECURITIES ACT OF 1933

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

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

OKLAHOMA 73-1098614
(State or jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

14000 QUAIL SPRINGS PARKWAY, SUITE 600
OKLAHOMA CITY, OKLAHOMA 73134
(405) 749-1300
(Address, including zip code, and telephone number, including
area code, of Registrant's principal executive offices)

PETER B. FRITZINGER
14000 QUAIL SPRINGS PARKWAY, SUITE 600
OKLAHOMA CITY, OKLAHOMA 73134
(405) 749-1300
(Name, address, including zip code, and telephone number, including
area code, of agent for service)

COPY TO:
MICHAEL M. STEWART JOHN W. WHITE
CROWE & DUNLEVY, A PROFESSIONAL CORPORATION CRAVATH, SWAINE & MOORE
1800 MID-AMERICA TOWER WORLDWIDE PLAZA
20 NORTH BROADWAY 825 EIGHTH AVENUE
OKLAHOMA CITY, OKLAHOMA 73102 NEW YORK, NEW YORK 10019
(405) 235-7700 (212) 474-1000

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC:
As soon as practicable after the Registration Statement becomes effective.

If the only securities being registered on this Form are being offered
pursuant to dividend or interest reinvestment plans, please check the following
box. [ ]

If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, other than securities offered only in connection with dividend or interest
reinvestment plans, check the following box. [ ]

If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]

If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]

If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT
SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS
REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH
SECTION 8(a) OF THE SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION
STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING
PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.

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

<PAGE>

The following legend will appear in the left margin of the following cover page
of the Prospectus:

Information contained herein is subject to completion or amendment. A
Registration Statement relating to these securities has been filed with the
Securities and Exchange Commission. These securities may not be sold nor may
offers to buy be accepted prior to the time the Registration Statement
becomes effective. This Prospectus shall not constitute an offer to sell or
the solicitation of an offer to buy nor shall there be any sale of these
securities in any State in which such offer, solicitation or sale would be
unlawful prior to registration or qualification under the securities laws of
any such State.

<PAGE>

Subject to Completion
_____________, 1997

PROSPECTUS

5,500,000 SHARES

LOUIS DREYFUS NATURAL GAS CORP.

COMMON STOCK
($.01 PAR VALUE)

Of the shares of Common Stock, $.01 par value per share (the "Common Stock"),
being offered, 2,750,000 shares are being sold by Louis Dreyfus Natural Gas
Corp. (the "Company"), and 2,750,000 shares are being sold by the Selling
Shareholder. See "Selling Shareholder and Principal Shareholders." The Company
will not receive any of the proceeds from the sale of shares of Common Stock by
the Selling Shareholder.

Of the shares being offered, 4,675,000 shares are being offered in the United
States and Canada (the "U.S. Offering") and 825,000 shares are being offered in
a concurrent international offering outside the United States and Canada (the
"International Offering" and, collectively with the U. S. Offering, the
"Offerings"), subject to transfers between the U.S. Underwriters and the
International Underwriters. The Price to Public and Underwriting Discount per
share will be identical for the U.S. Offering and the International Offering.
See "Underwriting." The closings of the U.S. Offering and International
Offering are conditioned upon each other.

The Common Stock is listed on the New York Stock Exchange under the symbol "LD."
On February ___, 1997, the last reported sale price for the Common Stock, as
reported on the New York Stock Exchange Composite Transactions Tape, was $_____
per share. See "Price Range of Common Stock and Dividend Policy."

SEE "RISK FACTORS" COMMENCING ON PAGE 9 OF THIS PROSPECTUS FOR A DESCRIPTION
OF CERTAIN FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH AN INVESTMENT IN
THE COMMON STOCK.

THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS
A CRIMINAL OFFENSE.

<TABLE>
<CAPTION>
___________________________________________________________________________________________
PROCEEDS TO
PRICE TO UNDERWRITING PROCEEDS TO SELLING
PUBLIC DISCOUNT COMPANY(1) SHAREHOLDER(1)
<S> <C> <C> <C> <C>
Per Share. . . . . $ $ $ $
Total (2) . . . . .$ $ $ $

___________________________________________________________________________________________
</TABLE>

(1) Before deducting offering expenses estimated at $350,000, all of which are
payable by the Company.

(2) The Selling Shareholder has granted to the U.S. Underwriters and the
International Underwriters 30-day options to purchase up to an aggregate of
825,000 shares of Common Stock at the Price to Public, less Underwriting
Discount, solely to cover over-allotments, if any. If the Underwriters
exercise such options in full, the total Price to Public, Underwriting
Discount and Proceeds to Selling Shareholder will be $ , $
and $ , respectively. See "Underwriting."

The shares are offered subject to receipt and acceptance by the Underwriters, to
prior sale and to the Underwriters' right to reject any order in whole or in
part and to withdraw, cancel or modify the offer without notice. It is expected
that delivery of the shares will be made at the office of Salomon Brothers Inc,
Seven World Trade Center, New York, New York, or through the facilities of The
Depository Trust Company, on or about , 1997.

SALOMON BROTHERS INC
CREDIT SUISSE FIRST BOSTON
HOWARD, WEIL, LABOUISSE, FRIEDRICHS
INCORPORATED
MORGAN STANLEY & CO.
INCORPORATED

The date of this Prospectus is , 1997.

<PAGE>

Map of southwestern United States indicating by use of shaded areas and symbols
the Company's properties in relation to the general location of known oil and
gas producing geological formations.

IN CONNECTION WITH THE OFFERINGS, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK AT
A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH
TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE. SUCH STABILIZING,
IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.

<PAGE>

PROSPECTUS SUMMARY

THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY THE MORE DETAILED
INFORMATION AND FINANCIAL STATEMENTS AND THE NOTES THERETO APPEARING
ELSEWHERE IN THIS PROSPECTUS. EXCEPT AS OTHERWISE INDICATED, THE INFORMATION
CONTAINED IN THIS PROSPECTUS ASSUMES THAT THE UNDERWRITERS' OVER-ALLOTMENT
OPTIONS WILL NOT BE EXERCISED. UNLESS THE CONTEXT OTHERWISE REQUIRES,
REFERENCES TO THE "COMPANY" REFER TO LOUIS DREYFUS NATURAL GAS CORP.
(INCLUDING ITS SUBSIDIARIES AND PREDECESSORS) AND REFERENCES TO S.A. LOUIS
DREYFUS ET CIE REFER TO S.A. LOUIS DREYFUS ET CIE AND ITS SUBSIDIARIES (OTHER
THAN THE COMPANY AND ITS SUBSIDIARIES). S.A. LOUIS DREYFUS ET CIE IS ALSO
REFERRED TO HEREIN AS THE "SELLING SHAREHOLDER." INVESTORS SHOULD CAREFULLY
CONSIDER THE INFORMATION SET FORTH IN "RISK FACTORS." CERTAIN CAPITALIZED
AND OTHER TERMS RELATING TO THE OIL AND GAS INDUSTRY ARE DEFINED IN
"CERTAIN DEFINITIONS."

THE COMPANY

GENERAL

Louis Dreyfus Natural Gas Corp. (the "Company") is a large independent
energy company engaged in the acquisition, development and exploration of
natural gas and oil properties, and in the production and marketing of
natural gas and crude oil. The Company's reserve base is primarily located
in the Sonora area of West Texas, the Mid-Continent region, the Permian
Basin, and the Texas Gulf Coast. As of December 31, 1996, the Company had
proved reserves of 990 Bcfe with a Present Value of $1.1 billion. The
Company operates over 84% of its reserves, of which 86% is natural gas and
83% is proved developed. The Company has a long-lived asset base with a
reserve life of 13.2 years at December 31, 1996.

The Company has grown its production and reserves primarily through low
cost acquisitions and development drilling. Since 1990, the Company has
completed a significant number of reserve acquisitions including three
acquisitions ranging in size from $87 million to $180 million. Through its
acquisition and leasing programs, the Company has accumulated interests in
1.4 million gross acres with 1,200 potential drilling locations, of which 343
have been assigned proved undeveloped reserves. The Company has exploited
its properties through an aggressive development drilling program, achieving
a drilling success rate of 96% since 1990. More recently, the Company has
emphasized exploratory drilling as an integral component of its operating
strategy. During 1996, the Company achieved success in this effort, as
evidenced by its completion of 18 of 25 exploratory wells.

The Company's balanced strategy of acquisitions and growth through
drilling has enabled the Company to replace 408% of its production since 1990
at an average finding cost of $.71 per Mcfe. By increasing its production
and reserves, the Company has significantly grown its earnings per share and
cash flow as outlined in the table below:

<TABLE>
<CAPTION>
COMPOUND
YEARS ENDED DECEMBER 31, ANNUAL
-------------------------------------------------------------------- GROWTH
1991 1992 1993 1994 1995 1996 RATE
-------- -------- -------- -------- -------- -------- -----
<S> <C> <C> <C> <C> <C> <C> <C>
Production (MMcfe)............. 19,985 28,650 43,179 54,321 61,434 75,004 30.3%

Proved reserves (MMcfe)........ 211,478 376,521 627,222 689,924 876,076 990,179 36.2

Earnings per share............. $ .09 $ .09 $ .11 $ .39 $ .40 $ .76 53.2

Net cash provided by
operating activities (M$).... $ 16,514 $ 22,272 $ 52,666 $ 80,894 $ 89,515 $101,761 43.9
</TABLE>

<PAGE>

BUSINESS STRATEGY

The Company's business strategy is to generate strong and consistent
growth in reserves, production, earnings and cash flow. The Company
implements this strategy through the following:

EXPANDED EXPLORATION PROGRAM. Stepped up exploration activity in the
Company's core regions exposes the Company to higher potential
production and reserve additions. The Company has a staff of 22
geoscientists and reservoir engineers who have extensive experience in
the use of advanced technologies, including 3-D seismic analysis,
computer aided mapping and reservoir simulation modeling. During 1996, the
Company invested $15 million in connection with exploration prospects,
including drilling, seismic data collection and lease acquisitions.
Approximately $7 million of the 1996 exploration budget was used for early
stage lease acquisitions and seismic data collection, which have created a
foundation for an expanded exploration program in 1997 and 1998. The Company
has allocated $25 million, or 25%, of its current capital budget for
additional exploration activities in 1997.

GROWTH THROUGH DRILLING. In 1994, 1995 and 1996, the Company replaced
116%, 120% and 153%, respectively, of its production through the drilling of
745 gross (450 net) wells, adding 251 Bcfe of proved reserves (including
revisions of previous estimates). The Company conducts development drilling
in areas where multiple productive oil and gas bearing formations are likely
to be encountered, thus reducing dry hole risk.

STRATEGIC ACQUISITIONS. Since January 1, 1990, the Company has grown
rapidly by investing $629 million to acquire approximately 1 Tcfe of
proved reserves at an average acquisition cost of $0.66 per Mcfe. The
Company believes the cost of these acquisitions compares favorably to
industry averages. The acquisitions have been geographically concentrated
in the core regions where the Company possesses considerable operating
expertise and realizes economies of scale. The Company principally targets
acquisitions which have significant development potential, are in close
proximity to existing properties, have a high degree of operatorship and can
be integrated with minimal incremental administrative cost.

PRICE RISK MANAGEMENT. The Company manages a portion of the risks
associated with decreases in prices of natural gas and crude oil through
long-term fixed-price physical delivery contracts and financial contracts.
Since 1990, the Company has generated $41 million in additional revenues
through its price risk management strategies. At December 31, 1996, the
pre-tax present value (discounted at 10%) of the future net revenues for
such contracts, based on the difference between contract prices and forward
market prices, was approximately $190 million. These fixed-price contracts
provide a base of predictable cash flows for a portion of the Company's gas
and oil sales, thereby enabling the Company to pursue its capital
expenditures with a greater degree of assurance. Recently, a lesser portion
of the Company's production has been hedged due to the Company's reluctance
to sell into a forward market where prices trend down or are essentially
flat over the next several years. In 1996, approximately 50% of the
Company's production was sold pursuant to fixed-price contracts, reduced
from 84% in 1995.

The address of the Company's principal executive offices is 14000 Quail
Springs Parkway, Suite 600, Oklahoma City, Oklahoma 73134, and its telephone
number at such address is (405) 749-1300.

<PAGE>

THE OFFERING

<TABLE>
<CAPTION>
<S> <C>
Common Stock offered by:
The Company
U.S. Offering ............................ 2,337,500 shares
International Offering ................... 412,500 shares
Total .................................. 2,750,000 shares
Selling Shareholder
U.S. Offering ............................ 2,337,500 shares (1)
International Offering ................... 412,500 shares (1)
Total .................................. 2,750,000 shares (1)
Common Stock outstanding before the Offerings ..... 27,801,500 shares (2)
Common Stock outstanding after the Offerings ...... 30,551,500 shares (1)(2)
Use of Proceeds ................................... Initially to reduce the outstanding balance of its
revolving credit facility and subsequently the Company
intends to use the increased availability thereunder for
increased exploratory and development drilling, acquisitions
of oil and gas reserves, recompletion and reworking of
existing wells and other corporate purposes.
NYSE Symbol ....................................... LD
</TABLE>

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

(1) Does not include up to 825,000 shares of Common Stock which may be sold by
the Selling Shareholder pursuant to the Underwriters' over-allotment
options. See "Underwriting."

(2) Does not include 992,500 shares of Common Stock reserved for issuance
pursuant to outstanding options granted under the Company's Stock Option
Plan.

FORWARD-LOOKING STATEMENTS

All statements in this Prospectus concerning the Company other than
purely historical information (collectively "Forward-Looking Statements")
reflect the current expectations of management and are based on the Company's
historical operating trends, its proved reserve and Fixed-Price Contracts (as
defined elsewhere herein) positions as of December 31, 1996 and other
information currently available to management. These statements assume, among
other things, that no significant changes will occur in the operating
environment for the Company's oil and gas properties and that there will be
no material acquisitions or divestitures except as disclosed herein. The
Company cautions that the Forward-Looking Statements are subject to all the
risks and uncertainties incident to the acquisition, development and
marketing of, and exploration for, oil and gas reserves. These risks include,
but are not limited to, commodity price risk, environmental risk, drilling
risk, reserve, operations and production risk, and counterparty risk. Many of
these risks are described elsewhere herein. See "Risk Factors" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations." Moreover, the Company may make material acquisitions, modify its
Fixed-Price Contract positions by entering into new contracts or terminating
existing contracts, or enter into financing transactions. None of these can
be predicted with certainty and, accordingly, are not taken into
consideration in the Forward-Looking Statements made herein. For all of the
foregoing reasons, actual results may vary materially from the
Forward-Looking Statements and there is no assurance that the assumptions
used are necessarily the most likely.

5
<PAGE>

SUMMARY FINANCIAL DATA

The summary financial data set forth below should be read in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results
of Operations" and the Consolidated Financial Statements of the Company and
the Notes thereto included elsewhere herein. The summary financial data as
of December 31, 1992, 1993, and 1994, and for the years ended December 31,
1992 and 1993, have been derived from audited consolidated financial
statements of the Company previously filed with the Securities and Exchange
Commission but not contained or incorporated herein.

YEARS ENDED DECEMBER 31,
---------------------------------------------------------------------------
1992 1993 1994 1995 1996
----------- ------------ ------------ ---------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Oil and gas sales.............................. $ 59,821 $ 92,912 $ 138,584 $ 163,366 $ 185,558
Other income (loss)............................ 630 2,269 1,953 (418) 3,947
----------- ----------- ------------ ------------ ------------
Total revenues............................ 60,451 95,181 140,537 162,948 189,505
----------- ----------- ------------ ------------ ------------
Operating costs................................ 16,217 26,715 33,713 35,352 44,615
General and administrative..................... 6,448 11,822 15,309 16,631 16,325
Exploration costs.............................. -- -- -- -- 4,965
Depreciation, depletion and amortization....... 25,148 38,649 53,321 57,796 65,278
Impairment of oil and gas properties (1)....... -- -- 5,300 15,694 --
Interest....................................... 9,939 14,364 16,856 21,736 26,822
----------- ----------- ------------ ------------ ------------
Total expenses............................ 57,752 91,550 124,499 147,209 158,005
----------- ----------- ------------ ------------ ------------
Income before income taxes..................... 2,699 3,631 16,038 15,739 31,500
Income taxes................................... 820 1,371 5,292 4,722 10,398
----------- ----------- ------------ ------------ ------------
Net income..................................... $ 1,879 $ 2,260 $ 10,746 $ 11,017 $ 21,102
----------- ----------- ------------ ------------ ------------
----------- ----------- ------------ ------------ ------------

Net income per share........................... $ .09 $ .11 $ .39 $ .40 $ .76
Weighted average common shares outstanding..... 20,000 21,042 27,800 27,800 27,800

STATEMENT OF CASH FLOWS AND OTHER FINANCIAL
DATA:
Net cash provided by operating activities
before working capital changes............ $ 29,788 $ 44,607 $ 76,139 $ 89,102 $ 100,981
Net cash provided by operating activities...... 22,272 52,666 80,894 89,515 101,761
Net cash used in investing activities.......... 126,666 180,038 102,969 171,540 150,857
Net cash provided by financing activities...... 98,450 138,559 13,701 80,629 55,261
EBITDA (2)..................................... 40,096 59,228 94,844 111,809 128,880

AS OF DECEMBER 31,
-----------------------------------------------------------------------------
1992 1993 1994 1995 1996
----------- ------------ ------------ ---------- -----------
(IN THOUSANDS)
BALANCE SHEET DATA:
Oil and gas properties, net.................... $ 260,451 $ 432,842 $ 483,214 $ 584,900 $ 652,257
Total assets................................... 290,354 481,488 528,261 634,937 733,613
Long-term debt, including current portion...... 191,631 203,955 215,010 314,760 343,907
Stockholders' equity........................... 74,166 213,818 224,564 242,581 263,693

_____________________

</TABLE>

(1) The impairment for 1994 was recorded in connection with the sale
of approximately one-half of the Company's ownership in an
offshore property. The impairment for 1995 was recorded in
connection with the adoption of SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and Long-Lived Assets to be
Disposed Of." See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Results of
Operations -- Fiscal Year 1995 Compared to Fiscal Year 1994 --
Impairment of Oil and Gas Properties."
(2) EBITDA is earnings (excluding gains and losses on sales and
retirements of assets, exploration costs and non-cash charges) before
interest, income taxes, and depreciation, depletion and amortization.
EBITDA should not be considered an alternative to net income as an
indicator of the Company's operating performance or an alternative to
cash flows as a measure of liquidity.

<PAGE>

SUMMARY OPERATING DATA
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------------------------------------------
1992 1993 1994 1995 1996
---------- ---------- --------- ---------- ----------
<S> <C> <C> <C> <C> <C>
OPERATING DATA:
OIL AND GAS SALES (M$):
Wellhead oil sales................................... $ 20,321 $ 34,542 $ 29,207 $ 28,973 $ 39,372
Effects of Fixed-Price Contracts (1)................. -- 1,516 5,064 1,077 (3,198)
---------- ---------- --------- ---------- -----------
Total oil sales...................................... $ 20,321 $ 36,058 $ 34,271 $ 30,050 36,174
---------- ---------- --------- ---------- -----------
---------- ---------- --------- ---------- -----------
Wellhead natural gas sales:
Sales under Sonora Gas Contract (2)............. $ -- $ 4,108 $ 39,408 $ 49,500 $ --
Other sales..................................... 37,878 56,803 55,945 60,573 148,244
---------- ---------- --------- ---------- -----------
Total........................................... 37,878 60,911 95,353 110,073 148,244
Effects of Fixed-Price Contracts (1)................. 1,622 (4,057) 8,960 23,243 1,140
---------- ---------- --------- ---------- -----------
Total natural gas sales.............................. $ 39,500 $ 56,854 $ 104,313 $ 133,316 $ 149,384
---------- ---------- --------- ---------- -----------
---------- ---------- --------- ---------- -----------
PRODUCTION:
Oil production (MBbls)............................... 1,082 2,106 1,873 1,695 1,849
Natural gas production (MMcf):
Sold under Sonora Gas Contract (2).............. -- 1,076 10,247 12,692 --
Other production................................ 22,158 29,464 32,835 38,572 63,910
---------- ---------- --------- ---------- -----------
Total........................................... 22,158 30,540 43,082 51,264 63,910
---------- ---------- --------- ---------- -----------
---------- ---------- --------- ---------- -----------
Total equivalent production (MMcfe).................. 28,650 43,179 54,321 61,434 75,004

Oil production hedged by Fixed-Price Contracts
(MBbls)......................................... -- 650 1,698 1,464 1,241
Gas production hedged by Fixed-Price Contracts
(BBtu).......................................... 22,158 28,775 32,308 31,579 32,508

AVERAGE SALES PRICE:
Oil price (per Bbl):
Wellhead price.................................. $ 18.78 $ 16.40 $ 15.59 $ 17.09 21.29
Effects of Fixed-Price Contracts (1)............ -- .72 2.71 .64 (1.73)
---------- ---------- --------- ---------- -----------
Total........................................... $ 18.78 $ 17.12 $ 18.30 $ 17.73 $ 19.56
---------- ---------- --------- ---------- -----------
---------- ---------- --------- ---------- -----------
Average fixed price received under Fixed-Price
Contracts.................................. $ -- $ 19.89 $ 20.15 $ 19.12 $ 19.53
Net effective cash realization (3).............. -- 94% 92% 93% 96%
Natural gas price (per Mcf):
Sales under Sonora Gas Contract (2)............. $ -- $ 3.82 $ 3.85 $ 3.90 --
Other wellhead sales............................ 1.71 1.93 1.70 1.57 2.32
---------- ---------- --------- ---------- -----------
Average price................................... 1.71 1.99 2.21 2.15 2.32
Effects of Fixed-Price Contracts (1)............ .07 (.13) .21 .45 .02
---------- ---------- --------- ---------- -----------
Total........................................... $ 1.78 $ 1.86 $ 2.42 $ 2.60 $ 2.34
---------- ---------- --------- ---------- -----------
---------- ---------- --------- ---------- -----------
Average fixed price received under Fixed-Price
Contracts.................................. $ 2.00 $ 2.17 $ 2.31 $ 2.40 $ 2.43
Net effective cash realization (3).............. 94% 87% 89% 97% 97%
Natural gas equivalent price (per Mcfe)......... $ 2.09 $ 2.15 $ 2.55 $ 2.66 $ 2.47

EXPENSES AND COSTS INCURRED (PER MCFE):
Lease operating expenses............................. $ .45 $ .50 $ .51 $ .47 $ .47
Production taxes..................................... .12 .12 .11 .11 .12
General and administrative........................... .23 .27 .28 .27 .22
Depreciation, depletion and amortization - oil and
gas properties (4)............................. .85 .85 .92 .88 .82
Finding costs........................................ .67 .71 .92 .70 .71
_________________________

</TABLE>

(1) Effects of Fixed-Price Contracts represent the hedging results from the
Company's Fixed-Price Contracts. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Fixed Price
Contracts."

<PAGE>

(2) The Sonora Gas Contract is a wellhead take or pay gas contract which
expired on December 31, 1995. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Sonora Gas Contract."
(3) Represents the net effective cash price realized for the
Company's hedged production as a percentage of the fixed prices
in the Company's Fixed-Price Contracts. Natural gas results for
1996 do not include the effects of a $4.3 million basis loss. See
"Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Fixed-Price Contracts -- Market Risk."
(4) Does not include impairment losses of $5.3 million and $15.7 million
recorded for the years ended December 31, 1994 and 1995, respectively.
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Results of Operations -- Fiscal Year 1995
Compared to Fiscal Year 1994."

SUMMARY RESERVE DATA
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------------------------------------------------------
1992 1993 1994 1995 1996
--------- ----------- --------- ----------- ------------
(DOLLAR AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
OIL AND GAS RESERVE DATA (1):
Net proved reserves:
Gas (MMcf).................................... 272,691 502,018 574,025 753,919 849,199
Oil (MBbls)................................... 17,305 20,867 19,317 20,360 23,497
Total (MMcfe)................................. 376,521 627,222 689,924 876,076 990,179
Reserve replacement ratio (2)........................ 676% 714% 219% 430% 254%
Reserve life (in years).............................. 13.1 14.5 12.7 14.3 13.2
Estimated future net revenues including Fixed-
Price Contracts (3)........................... $757,650 $1,167,940 $1,219,760 $1,531,501 $2,417,430
Present Value including Fixed-Price Contracts (3).... 395,238 588,986 616,005 737,512 1,117,734
Present Value excluding Fixed-Price Contracts (3).... 294,441 455,362 358,766 524,354 1,303,709
___________________________________

</TABLE>

(1) Includes for 1996, data relating to the Company's Levelland properties
consisting of 34 Bcfe of reserves which were sold in January 1997 for
$27.1 million (the "Levelland Sale").
(2) The reserve replacement ratio is a percentage determined by dividing the
estimated reserves added during a year from exploration and development
activities, acquisitions of proved reserves and revisions of previous
estimates by the oil and gas volumes produced during that year.
(3) Estimated future net revenues and Present Value give no effect to
federal or state income taxes attributable to estimated future net
revenues. See "Business and Properties -- Reserves."

<PAGE>

RISK FACTORS

In addition to the other information set forth elsewhere in this
Prospectus, the following factors should be considered when evaluating an
investment in the shares of Common Stock offered hereby.

EFFECTS OF CHANGING OIL AND GAS PRICES; HEDGING RISKS

The Company's future financial condition and results of operations are
dependent upon the prices received for the Company's oil and gas production.
Oil and gas prices have historically been volatile and are likely to continue
to be volatile in the future. Prices for oil and gas are subject to
fluctuations in response to relatively minor changes in supply, demand,
market uncertainty and a variety of additional factors that are beyond the
control of the Company. These factors include political stability in the
Middle East and elsewhere, the foreign supply of oil and gas, the price of
foreign imports, government regulations and taxes, the price and availability
of alternative fuels, weather conditions and the overall economic
environment.

The Company has entered into long-term fixed-price physical delivery
contracts, energy swaps, collars, futures contracts, basis swaps and options
(collectively, "Fixed-Price Contracts") covering a significant portion of its
anticipated future production from existing proved oil and gas reserves and
may enter into similar arrangements in the future. Such arrangements reduce
the Company's risk to declines in oil and gas prices, but also limit the
Company's ability to benefit from any increase in those prices. For the year
ended December 31, 1996, Fixed-Price Contracts covered 51% of the Company's
natural gas production and 67% of its oil production. As of December 31,
1996, Fixed-Price Contracts hedged 349 Bcf of natural gas and 362 Mbbls of
oil to be produced in future periods, which constitutes 41% and 2% of the
estimated proved reserves of gas and oil, respectively, at such date. The
Company's revenues are more sensitive to natural gas price changes because
approximately 86% of its proved reserves on an equivalent unit of production
basis at December 31, 1996 were natural gas. A significant portion of the
Company's reserves are not covered by Fixed-Price Contracts, and any
substantial or extended decline in the price of oil or gas would have a
material adverse effect on the Company's financial condition and results of
operations. Extended periods of low prices for oil or natural gas could
affect the Company's willingness to complete planned drilling activities and
would result in downward adjustments to its estimated reserves and/or future
net revenues.

This Prospectus contains estimates of the future net revenues and
present value of the Company's Fixed-Price Contracts as of certain dates that
are computed based on the difference between the prices provided by the
Fixed-Price Contracts and forward market prices as of the specified date.
Such estimates do not necessarily represent the fair market value of the
Company's Fixed-Price Contracts or the actual future net revenues that will
be received. The forward market prices for natural gas and oil are highly
volatile, are dependent upon supply and demand factors in such forward
market, and may not correspond to the actual market prices at the settlement
dates of the Company's Fixed-Price Contracts. Such forward market prices are
available in a limited over-the-counter market and are obtained from sources
the Company believes to be reliable.

The Company's hedging practices are subject to a number of risks,
including credit and market risks.

CREDIT RISK OF FIXED-PRICE CONTRACT COUNTERPARTIES. The counterparties
to the Company's Fixed-Price Contracts are comprised of independent power
producers, pipeline marketing affiliates, financial institutions, a
municipality and S.A. Louis Dreyfus et Cie, among others. Should a
counterparty to a contract default on a contract, there can be no assurance
that the Company would be able to enter into a new contract with a third
party on terms comparable to the original contract. The loss of a contract
would subject a greater portion of the Company's oil and gas production to
market prices and could adversely affect the carrying value of the Company's
oil and gas properties and the amount of borrowing capacity available under
the Credit Facility. The Company is a party to two Fixed-Price Contracts,
both long-term physical delivery contracts, with independent power producers
which sell electrical power under firm, fixed-price contracts to Niagara
Mohawk Corporation ("NIMO"), a New York state utility. The Company's
Fixed-Price Contracts with such independent power producers covered an
aggregate of 106 Bcf of natural gas as of December 31, 1996. At December 31,
1996, the net present value of the differential between the fixed prices
provided by these contracts and forward market prices, as adjusted for basis
and discounted at 10%, was $135 million, or 71% of such net present value
attributable to all of the Company's Fixed-Price Contracts. The premium in
the fixed prices in these contracts are not reflected in the Company's
financial statements until realized. Such contracts contributed $.9 million
to 1996 revenues. The ability of such independent power producers to perform
their obligations to the Company is largely dependent on the continued
performance by NIMO of its power purchase obligations. NIMO has taken
aggressive regulatory, judicial and contractual actions in recent years
seeking to curtail power purchase obligations, including its obligations to
the independent power producers that are counterparties to the Company's
Fixed-Price Contracts described above, and has further stated that its future
financial prospects are dependent on its ability to resolve these
obligations, along with a number of other matters. To the extent NIMO is
successful in reducing its obligations to purchase power from the Company's
counterparties, the ability of such counterparties to continue to purchase
natural gas from the Company under existing Fixed-Price Contracts may be
adversely affected, which may in turn have an adverse effect on the Company.
Currently, the Company cannot predict the likelihood of NIMO's being
successful in its attempts to curtail its obligations. For further
description of counterparties to the Company's Fixed-Price Contracts see
"Business and Properties -- Marketing -- Counterparties."

MARKET RISK. If the Company's proved reserves are produced at rates
less than anticipated, the volumes specified under the Fixed-Price Contracts
may exceed production volumes. In such case, the Company would be required
to satisfy its contractual commitments at market prices in effect for each
settlement period, which may be above the contract price, without a
corresponding offset in wellhead revenue for any excess volumes.

<PAGE>

While the Company expects future production volumes to be equal to or greater
than the volumes provided in its contracts, there can be no assurance that it
will produce such volumes. In addition, the differential between the
floating price paid under each energy swap contract, or the cost of gas to
supply physical delivery contracts, and the price received at the wellhead
for the Company's production is termed "basis" and is the result of
differences in location, quality, contract terms, timing and other variables.
The effective price realizations that result from the Company's Fixed-Price
Contracts are affected by changes in basis. For the years ended December 31,
1994, 1995 and 1996, the Company realized on an Mcf basis approximately 11%,
3% and 3% less than the prices specified in its natural gas Fixed-Price
Contracts, respectively, due to basis. Such results do not include a $4.3
million basis loss recognized in the fourth quarter of 1995, discussed
in "Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Fixed-Price Contracts -- Market Risk." For its oil
production hedged by crude oil Fixed-Price Contracts, the Company realized
approximately 8%, 7% and 4% less than the specified contract prices for such
years, respectively. Basis movements can result from a number of variables,
including regional supply and demand factors, changes in the Company's
portfolio of Fixed-Price Contracts and the composition of the Company's
producing property base. Basis movements are generally considerably less
than the price movements affecting the underlying commodity, but their effect
can be significant. The Company actively manages its exposure to basis
movements and from time to time enters into contracts designed to reduce such
exposure. However, there can be no assurance that fluctuations in basis will
not occur in the future and that such fluctuations will not be significant.

For a further discussion of risks associated with Fixed-Price Contracts,
see "Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Fixed-Price Contracts."

<PAGE>

CUSTOMER CONCENTRATION

The Company's oil and gas sales at the wellhead are sold under contracts
with various purchasers. For the year ended December 31, 1996, the Company
had gas sales to three unrelated purchasers that approximated 18% , 13% and
11% of total revenues. While the Company believes that alternative
purchasers are available, if necessary, to purchase its production at prices
substantially similar to those being received from its current major
customers, the loss of a significant customer could have a material adverse
effect on the Company's results of operations and financial condition.

ESTIMATES OF RESERVES AND FUTURE NET CASH FLOWS

There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves, including many factors beyond the control of the
Company. The reserve data set forth herein represent only estimates. Reserve
engineering is a subjective process of estimating underground accumulations
of oil and gas that cannot be measured in an exact manner, and the accuracy
of any reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result,
estimates of different engineers often vary. These estimates 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 gas reserves may vary substantially from
those assumed in the estimates. The Company's reserves and future cash flows
may be subject to revisions, based upon production results, results of future
development, oil and gas prices, performance of counterparties under
Fixed-Price Contracts, operating and development costs and other factors.
Any downward adjustment in the Company's estimated reserves could adversely
affect the Company's future prospects. For further information on reserves,
future net revenues and the standardized measure of discounted future net
cash flows, see Note 12 of the Notes to the Company's Consolidated Financial
Statements.

CERTAIN OPERATIONAL RISKS

The Company's operations are subject to the risks and uncertainties
associated with drilling for, and production and transportation of, oil and
gas. The Company must incur significant expenditures for the identification
and acquisition of properties and for the drilling and completion of wells.
Drilling activities are subject to numerous risks, including the risk that no
commercially productive oil or gas reservoirs will be encountered.
Exploratory drilling involves more risk than development drilling because it
is designed to test formations which have not yet been assigned proved
reserves. The Company's prospects for future growth and profitability will
depend on its ability to replace current reserves through drilling,
acquisitions, or both. The Company's ability to market its oil and gas
production depends upon, among other factors, the availability and capacity
of oil and gas gathering systems and pipelines, many of which are beyond the
Company's control. In addition, Federal and state regulation of oil and gas
production and transportation, general economic conditions, changes in supply
and in demand could adversely affect the Company's ability to market its oil
and gas production.

OPERATING HAZARDS AND UNINSURED RISKS

The Company's operations are subject to the risks inherent in the oil
and gas industry, including the risks of fire, explosions, blow-outs, pipe
failure, abnormally pressured formations and environmental accidents such as
oil spills, gas leaks, salt water spills and leaks, ruptures or discharges of
toxic gases, the occurrence of any of which could result in substantial
losses to the Company due to injury or loss of life, severe damage to or
destruction of property, natural resources and equipment, pollution or other
environmental damage, clean-up responsibilities, regulatory investigation and
penalties and suspension of operations. The Company's operations may be
materially curtailed, delayed or canceled as a result of numerous factors,
including the presence of unanticipated pressure or irregularities in
formations, accidents, title problems, weather conditions, compliance with
governmental requirements and shortages or delays in the delivery of
equipment.

<PAGE>

In accordance with customary industry practice, the Company maintains
insurance against some, but not all, of the risks described above. There can
be no assurance that the levels of insurance maintained by the Company will
be adequate to cover any losses or liabilities. The Company cannot predict
the continued availability of insurance or its availability at commercially
acceptable premium levels.

GOVERNMENTAL AND ENVIRONMENTAL REGULATION

The Company's operations are subject to numerous federal and state laws
and regulations relating to the drilling for and production of oil and gas,
the protection of the environment and worker health and safety, including
those relating to the discharge of pollutants into the environment, the
handling and disposal of solid and hazardous wastes and the cleanup of
properties contaminated by hazardous wastes and other materials. The Company
has made and will continue to make expenditures to comply with environmental
and health and safety requirements. These requirements have generally become
more stringent in recent years, often imposing greater liability on an
increasing number of parties. Because the requirements imposed by such laws
and regulations are frequently changed, the Company is unable to predict the
effect or cost of compliance with such requirements or their effects on oil
and gas use or prices. In addition, legislative proposals are frequently
introduced in Congress and state legislatures which, if enacted, might
significantly affect the oil and gas industry. In view of the many
uncertainties that exist with respect to any legislative proposals, the
effect on the Company of any legislation which might be enacted cannot be
predicted. There can be no assurance that laws or regulations enacted in the
future or changes to existing laws and regulations will not adversely affect
the Company's business, financial condition or results of operations. For
further information concerning governmental and environmental regulations
affecting the Company, see "Business" in the Company's Annual
Report on Form 10-K for the year ended December 31, 1996.

COMPETITION

The oil and gas industry is highly competitive. The Company competes in
the areas of proved reserve and undeveloped acreage acquisitions and the
development, production and marketing of oil and gas, as well as contracting
for equipment and securing personnel, with major oil and gas companies, other
independent oil and gas concerns, gas marketing companies and individual
producers and operators. Many of these competitors have financial and other
resources which substantially exceed those available to the Company.
Competition in the regions in which the Company owns properties may result
in occasional shortages or unavailability of drilling rigs and other
equipment used in drilling activities as well as limited availability and
access to pipelines. Such circumstances could result in curtailment of
activities, increased costs, delays or losses in production or revenues or
cause interests in oil and gas leases to lapse.

RELATIONSHIP WITH S.A. LOUIS DREYFUS ET CIE

S.A. Louis Dreyfus et Cie beneficially owns 74.2%, and after the
Offerings will beneficially own 58.5%, of the outstanding Common Stock of the
Company and, through its ability to elect all directors of the Company,
effectively controls all matters upon which stockholders vote and which
relate to the management of the Company. The Company and S.A. Louis Dreyfus
et Cie have in the past entered into significant intercompany transactions
and agreements incident to their respective businesses and may continue to do
so in the future. The Company and S.A. Louis Dreyfus et Cie have entered into
a services agreement pursuant to which S.A. Louis Dreyfus et Cie provides
various services to the Company upon request. It is the intention of S.A.
Louis Dreyfus et Cie and the Company that the Company operate independently
other than receiving services under the services agreement. For a description
of the services provided and the transactions entered into between the
Company and S.A. Louis Dreyfus, see "Business and Properties -- Relationship
Between the Company and S.A. Louis Dreyfus et Cie." While S.A. Louis Dreyfus
et Cie has advised the Company that it does not currently intend to engage in
the acquisition and development of, or exploration for, oil and gas except
through its beneficial ownership of Common Stock of the Company, the nature
of the respective businesses of the Company and S.A. Louis Dreyfus et Cie may
give rise to conflicts of interest between them. For a further description of
the nature of the potential conflicts of interest between the Company and
S.A. Louis Dreyfus et Cie, see "Business and Properties -- Potential
Conflicts of Interest."

<PAGE>

USE OF PROCEEDS

The net proceeds from the sale of the 2,750,000 shares of Common Stock
offered by the Company hereby are estimated to be approximately $________.
The Company will not receive any proceeds from the sale of Common Stock by
the Selling Shareholder. The Company initially will use the net proceeds of
the Offerings to reduce the outstanding balance of its revolving credit
facility. Subsequently, the Company intends to use the increased
availability under its revolving credit facility for increased exploratory
and development drilling, acquisitions of oil and gas reserves, recompletion
and reworking of existing wells and other corporate purposes.

The Company's revolving credit facility provides up to $300 million in
borrowings and letters of credit, with letters of credit limited to
$75 million of such availability (the "Commitment"). The Commitment reduces at
the rate of $18.75 million per quarter commencing October 31, 1999 through
July 31, 2003. Total borrowings and letters of credit under the credit
facility are limited to the lesser of the Commitment and the "Oil and Gas
Reserves Loan Value." The Oil and Gas Reserves Loan Value is a borrowing base
calculation determined by a periodic valuation of the Company's oil and gas
reserves and Fixed-Price Contracts. The Oil and Gas Reserves Loan Value was
most recently reset in December 1996 at $330 million. The Company has relied
upon the credit facility to provide funds for acquisitions and to provide
letters of credit to meet the Company's margin requirements under Fixed-Price
Contracts. As of December 31, 1996, the Company had $235 million of principal
($211 million as adjusted to reflect the application of the net proceeds from
the Levelland Sale in January 1997) and $3.3 million of letters of credit
outstanding under the credit facility and the effective interest rate for
borrowings (after giving effect to interest rate swaps) was 6.3%.

<PAGE>

CAPITALIZATION

The following table sets forth as of December 31, 1996 (i) the total
capitalization of the Company and (ii) the total capitalization of the
Company as adjusted to give effect to the issuance and sale of the shares of
Common Stock in the Offerings and application of the net proceeds to the
Company initially to reduce indebtedness under its revolving credit facility
as set forth in "Use of Proceeds." The following table should be read in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the Company's Consolidated Financial
Statements and the Notes thereto appearing elsewhere in this Prospectus.

DECEMBER 31, 1996
---------------------------
ACTUAL AS ADJUSTED
----------- -----------
(IN THOUSANDS)

Current portion of long-term debt. . . . . . . $ -- $ --
------------ -----------
------------ -----------
Long-term debt:
Revolving credit facility . . . . . . . . . 235,000 (1)
Other bank debt . . . . . . . . . . . . . . 10,000 10,000
9 1/4% Senior Subordinated Notes due 2004 . 98,907 98,907
------------ -----------
Total long-term debt . . . . . . . . . . 343,907 (1)
------------ -----------

Stockholders' equity:
Preferred stock, $.01 par value, 10,000,000
shares authorized, none outstanding. . . . -- --

Common Stock, $.01 par value, 100,000,000
shares authorized, 27,800,750 shares
outstanding, 30,550,750 shares
outstanding as adjusted. . . . . . . . . . 278 306

Additional paid-in capital. . . . . . . . . 197,301
Retained earnings . . . . . . . . . . . . . 66,114 66,114(1)
------------ -----------
Total stockholders' equity . . . . . . . 263,693
------------ -----------
Total capitalization . . . . . . . . . . $607,600 $
------------ -----------
------------ -----------

______________________________

(1) After giving effect to the Levelland Sale in January 1997 and the
application of the $24 million of net proceeds therefrom, the amount
outstanding under the revolving credit facility and total long-term
debt, as adjusted for the Offerings, would be $________ and $________,
respectively, and retained earnings would be $71,639,000.

<PAGE>

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

The Common Stock is listed on the New York Stock Exchange ("NYSE") and
traded under the symbol "LD". As of ____________, 1997, the Company had
27,801,500 shares of Common Stock outstanding, and the closing price of its
Common Stock on the NYSE was $________ per share. The high and low sales
prices for the Company's Common Stock during each quarter in the years ended
December 31, 1995 and 1996 were as follows:

1995 1996
----------------- -----------------
HIGH LOW HIGH LOW
------ ------ ------ ------
QUARTER:
First............... $14.38 $11.25 $15.13 $10.38
Second.............. 16.50 13.88 15.13 10.75
Third............... 15.00 12.00 15.75 13.25
Fourth.............. 15.63 13.13 18.00 15.00

The Company has paid no dividends, cash or otherwise, subsequent to the
date of the initial public offering of the Common Stock in November 1993.
Certain provisions of the Company's bank credit facility and the indenture
agreement for the Company's 9-1/4% Senior Subordinated Notes due 2004
restrict the Company's ability to declare or pay cash dividends unless
certain financial ratios are maintained. Although it is not currently
anticipated that any cash dividends will be paid on the Common Stock in the
foreseeable future, the Board of Directors will review the Company's dividend
policy from time to time. In determining whether to declare dividends and the
amount of dividends to be declared, the Board will consider relevant factors,
including the Company's earnings, its capital needs and its general financial
condition.

<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

GENERAL. Since its acquisition by S.A. Louis Dreyfus et Cie in 1990,
the Company's oil and gas reserves and production have grown significantly as
the result of a number of proved reserve acquisitions and its active drilling
program. The Company's business strategy is to generate strong and consistent
growth in reserves, production, earnings and cash flow through a balanced
program of exploration and development drilling and strategic acquisitions of
oil and gas properties.

Over the three-year period ended December 31, 1996, the Company acquired
an aggregate 322 Bcfe for a total consideration of $191.4 million, or $.59
per Mcfe. The Company intends to continue its strategy of acquiring producing
properties with significant development potential in its core regions.

The Company has maintained an active drilling program over the
three-year period ended December 31, 1996. The Company drilled 745 gross
wells (450 net wells), with an overall drilling success rate of 96%, adding
251 Bcfe of reserves (including revisions of previous estimates) to its
proved reserve base during this period. The year ended December 31, 1996,
marked the third consecutive year that the Company had replaced its
production by both its acquisition and drilling programs. Total finding
costs (total costs incurred to acquire, explore and develop oil and gas
properties divided by the increase in proved reserves through acquisitions of
proved properties, extensions and discoveries, and revisions of previous
estimates) over this three-year period averaged $.75 per Mcfe.

Recently, the Company has increasingly emphasized exploratory drilling
as an integral component of its operating strategy. During 1996, the Company
invested $15 million in connection with exploration prospects, including
drilling, seismic data collection and leasehold acquisition activities. The
Company has allocated $25 million, or 25%, of its current capital budget for
exploratory activities in 1997.

From 1990 through 1993, the Company's portfolio of Fixed-Price Contracts
hedged substantially all of its natural gas production. During that period,
the Company entered into several Fixed-Price Contracts which contained
attractive fixed natural gas prices relative to the acquisition cost of
proved reserves. Over the past few years, competition in Fixed-Price
Contracts has increased, the opportunities for attractive Fixed-Price
Contracts have diminished, and spot prices for natural gas became
significantly higher than nearby forward market prices. In response to these
changes, a progressively smaller share of the Company's production and
reserve growth has been hedged due to management's reluctance to sell into a
forward market where prices trend down or are essentially flat over the next
several years. Management believes that the current relationship between
cash flow protection and exposure to oil and gas prices is an appropriate
balance for the Company. However, the Company may decide to hedge a greater
or smaller share of production in the future, depending upon market
conditions, capital investment considerations and other factors. See "--
Fixed-Price Contracts".

RESULTS OF OPERATIONS -- FISCAL YEAR 1996 COMPARED TO FISCAL YEAR 1995

NET INCOME AND CASH FLOWS FROM OPERATING ACTIVITIES. For the year ended
December 31, 1996, the Company reported net income of $21.1 million, or
$.76 per share, on total revenue of $189.5 million. This compares with net
income of $11.0 million, or $.40 per share, on total revenue of $162.9 million
for the year ended December 31, 1995. Cash flows from operating activities
(before working capital changes) for 1996 also reflected significant
improvement, increasing 13% to $101.0 million from the $89.1 million reported
for 1995. The improvement in earnings and cash flows was achieved primarily
through growth in oil and gas production. In addition, earnings for the year
ended December 31, 1995 were reduced by a $15.7 million pre-tax

<PAGE>

impairment recorded in connection with the adoption of SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of" ("SFAS 121"). These items are discussed in greater detail
below. Cash flows provided by operating activities, inclusive of the net
change in working capital, increased to $101.8 million in 1996 compared to
$89.5 million for 1995, also due principally to the 1996 increase in
production.

PRODUCTION. The Company experienced significant growth in total
production for the year ended December 31, 1996 in relation to 1995. On a
natural gas equivalent basis, the Company produced 75.0 Bcfe, an increase of
22% compared to 61.4 Bcfe produced during 1995. Natural gas production for
1996 was 63.9 Bcf, a 25% increase over the 51.3 Bcf produced in 1995. Oil
production in 1996 increased 9% to 1.8 MMBbls compared to 1.7 MMBbls produced
in 1995. These increases are attributable to the results of the Company's
exploration and development drilling activities and acquisition of proved
reserves.

OIL AND GAS PRICES. On a natural gas equivalent basis, the Company
realized an average price of $2.47 for 1996, a 7% decrease from the $2.66
received in 1995. The Company's 1996 gas production yielded an average price
of $2.34 per Mcf, a 10% decrease compared to 1995's average price of
$2.60 per Mcf. This decrease is primarily attributable to the expiration in
December 1995 of a contract which paid $3.90 per Mcf for approximately 25% of
the Company's total gas production in 1995. See "-- Sonora Gas Contract."
The impact of Fixed-Price Contracts in effect for the years ended December
31, 1996 and 1995 was to increase the average gas price by $.02 per Mcf and
$.45 per Mcf, respectively. The average oil price received during 1996
improved 10% to $19.56 per Bbl compared to $17.73 per Bbl for 1995.
Fixed-Price Contracts decreased the average oil price in 1996 by $1.73 per
Bbl and increased the average oil price in 1995 by $.64 per Bbl.

The net effect of higher gas production and lower gas prices for 1996
was to increase gas sales by 12% to $149.4 million in relation to
$133.3 million reported for 1995. The effect of higher oil prices and higher
oil production was to increase oil sales for 1996 to $36.2 million, a 20%
increase from 1995. The aggregate impact of the Fixed-Price Contracts hedging
the Company's oil and gas production was to decrease oil and gas revenue by
$2.1 million in 1996 and to increase oil and gas revenue by $24.3 million in
1995. See "-- Fixed-Price Contracts."

OTHER INCOME (LOSS). The Company realized other income for 1996 of $3.9
million compared to a net loss of $.4 million for 1995. Other income (loss)
for 1996 and 1995 included $1.7 million and $1.3 million, respectively, of
proceeds received pursuant to the settlement of a legal claim. The net loss
for 1995 was primarily the result of a $4.3 million basis loss recorded in
the fourth quarter of 1995. See "-- Fixed-Price Contracts -- Market Risk."

OPERATING COSTS. Operating costs, which include lease operating
expenses and production taxes, increased to $44.6 million for 1996 compared
to $35.4 million for 1995. This increase is principally attributable to
producing properties acquired and wells drilled during the periods presented
and to higher production taxes associated with the 1996 increase in oil and
gas revenue. On a natural gas equivalent unit of production basis, lease
operating expenses were $.47 per Mcfe for both 1996 and 1995.

GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense
("G&A") for 1996 was $16.3 million compared to $16.6 million for 1995. This
decrease is primarily attributable to an increase in overhead and cost
recoveries from third parties which exceeded increases in personnel and
related costs. G&A per natural gas equivalent unit of production was
$.22 per Mcfe for 1996 compared to $.27 per Mcfe for 1995. This improvement
is attributable to a significant increase in production for 1996 which did not
entail a proportionate increase in personnel and related costs.

EXPLORATION COSTS. Exploration costs, comprised of exploratory
geological and geophysical costs, exploratory dry holes and leasehold
impairment costs, were $5.0 million for the year ended December 31,

<PAGE>

1996. This amount includes $2.5 million of seismic acquisition costs
incurred during 1996. No exploratory dry holes were drilled and no
exploratory geological and geophysical costs were incurred during 1995.

DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense ("DD&A") for the year ended December 31, 1996 was $65.3
million compared to $57.8 million for 1995. This increase is mainly due to
higher production levels for 1996 compared to 1995. The oil and gas DD&A
rate per equivalent unit of production was $.82 per Mcfe for 1996 compared to
$.88 per Mcfe in 1995. The improved DD&A rate for 1996 was principally due
to favorable reserve finding cost results for the periods presented and to an
impairment charge taken in the fourth quarter of 1995 upon the adoption of
SFAS 121. See "-- Impairment of Oil and Gas Properties" below.

IMPAIRMENT OF OIL AND GAS PROPERTIES. In the fourth quarter of 1995,
the Company adopted the provisions of SFAS 121, pursuant to which the
Company's oil and gas properties are reviewed on a field-by-field basis for
indications of impairment. The implementation of SFAS 121 resulted in a
pre-tax impairment charge of $15.7 million for the year ended December 31,
1995, affecting approximately 5% of the Company's 327 fields. No impairment
was incurred for the year ended December 31, 1996.

INTEREST EXPENSE. Interest expense for 1996 was $26.8 million compared
to $21.7 million for 1995. This increase is primarily attributable to higher
average long-term debt balances outstanding during 1996. The net impact of
interest rate swaps in effect during the years ended December 31, 1996 and
1995 was to increase interest expense by $.9 million in 1996 and to decrease
interest expense by $.3 million in 1995. See "-- Capital Resources and
Liquidity."

INCOME TAXES. For 1996, the Company recorded a tax provision of $10.4
million on pre-tax income of $31.5 million, an effective rate of 33%. This
compares to a provision of $4.7 million, or 30% on pre-tax income of $15.7
million for 1995. The effective rate for both years was lower than the
statutory rate primarily due to the availability of Section 29 credits.

RESULTS OF OPERATIONS -- FISCAL YEAR 1995 COMPARED TO FISCAL YEAR 1994

NET INCOME AND CASH FLOWS FROM OPERATING ACTIVITIES. For the year ended
December 31, 1995, the Company reported net income of $11.0 million, or $.40
per share, on total revenue of $162.9 million. This compares with net income
of $10.7 million, or $.39 per share, on total revenue of $140.5 million in
1994. This improvement in earnings was achieved despite a $15.7 million
pre-tax charge recorded in the fourth quarter upon the adoption of SFAS 121.
Cash flows from operating activities (before working capital changes) for the
year ended December 31, 1995 reflected significant improvement, increasing
17% to $89.1 million from the $76.1 million reported for 1994. The
improvements in earnings and cash flows were primarily the result of a
significant increase in gas production and higher prices provided by the
Company's Fixed-Price Contracts. These items are discussed in greater detail
below. Cash flows provided by operating activities, inclusive of the net
change in working capital, increased to $89.5 million for 1995 compared to
$80.9 million in 1994, principally for the reasons discussed above.

PRODUCTION. The Company experienced growth in total oil and gas
production for the year ended December 31, 1995 in relation to 1994. On a
natural gas equivalent basis, the Company produced 61.4 Bcfe for 1995
compared to 54.3 Bcfe for 1994, an increase of 13%. Natural gas production
for 1995 was 51.3 Bcf, a 19% increase over the 43.1 Bcf produced in 1994.
This significant increase was primarily the result of proved reserve
acquisitions made during 1995, the largest of which was the July 1995
acquisition of oil and gas properties in the Sonora field for $86.6 million,
and the Company's drilling program. Oil production for 1995 declined 10% to
1.7 MMBbls of oil compared to 1.9 MMBbls produced in 1994.

<PAGE>

OIL AND GAS PRICES. On a natural gas equivalent basis, the Company
realized an average price of $2.66 per Mcfe during 1995, an increase of 4%
compared to $2.55 per Mcfe for 1994. The Company's 1995 gas production
yielded an average price of $2.60 per Mcf, a 7% increase over the average
price of $2.42 per Mcf for 1994. The Company's average gas price for 1995
was enhanced $.45 per Mcf as a result of the Company's Fixed-Price Contracts.
The average gas price for 1994 was enhanced $.21 per Mcf as a result of
Fixed-Price Contracts in effect for that period. The average oil price for
1995 decreased 3% to $17.73 per Bbl in relation to $18.30 per Bbl received in
1994. The average oil price for 1995 was enhanced $.64 per Bbl as a result
of Fixed-Price Contracts in effect during the year. For 1994, the effect of
Fixed-Price Contracts was to increase the average oil price by $2.71 per Bbl.

The effect of higher gas production and higher gas prices in 1995 was to
increase gas sales by 28% to $133.3 million compared to $104.3 million for
1994. The effect of lower oil production and lower oil prices in 1995 was to
decrease oil sales by 12% to $30.1 million compared to $34.3 million for
1994. The aggregate impact of the Fixed-Priced Contracts hedging the
Company's oil and gas production was to increase oil and gas revenues by
$24.3 million and $14.0 million for the years ended December 31, 1995 and
1994, respectively.

OTHER INCOME (LOSS). Other income (loss) for 1995 reflected a net loss
of $.4 million compared to income of $2.0 million reported for 1994. The
major components of the 1995 amount include a $4.3 million basis loss, a $1.3
million gain resulting from the settlement of a legal claim and $1.1 million
of well services income. The 1994 amount was primarily comprised of well
services income. See "-- Fixed-Price Contracts -- Market Risk."

OPERATING COSTS. Operating costs, which include lease operating
expenses and production taxes, increased to $35.4 million for 1995, compared
to $33.7 million for 1994. This increase is principally due to the operating
costs of the Sonora oil and gas properties acquired in July 1995. On a
natural gas equivalent unit of production basis, lease operating expenses for
1995 were $.47 per Mcfe compared to $.51 per Mcfe in 1994. This improvement
is attributable to operational efficiencies achieved in certain of the
Company's major operating areas, a reduction in remedial work performed on
properties acquired in prior periods and a reduction in lease operating
expenses associated with the West Delta 152 working interest sold in January
1995.

GENERAL AND ADMINISTRATIVE EXPENSE. G&A for 1995 was $16.6 million
compared to $15.3 million for 1994. This increase is principally the result
of an increase in personnel to accommodate the growth experienced by the
Company. On a natural gas equivalent unit of production basis, G&A costs were
$.27 per Mcfe for 1995 compared to $.28 per Mcfe for 1994. This favorable
change is primarily attributable to production from the July 1995 acquisition
of Sonora oil and gas properties which did not require a proportionate
increase in G&A.

DEPRECIATION, DEPLETION AND AMORTIZATION. DD&A for the year ended
December 31, 1995 was $57.8 million compared to $53.3 million for 1994. This
increase is attributable to the 1995 increase in production discussed
previously. On a natural gas equivalent unit of production basis, the 1995
oil and gas DD&A rate was $.88 per Mcfe compared to $.92 per Mcfe for 1994.
This improvement in 1995 was primarily the result of proved reserves acquired
during the year at a lower cost per Mcfe.

In January 1995, the Company completed the sale of approximately 50% of
its ownership in West Delta 152, a Company-operated offshore property, to an
unrelated third party for a sale price of $12 million. The buyer assumed
operations in February 1995. For the year ended December 31, 1994, in
connection with an earlier sale transaction involving West Delta 152 which
was not ultimately consummated, the Company

<PAGE>

recorded a $5.3 million impairment charge. Such charge approximated the book
loss incurred upon the ultimate sale of the property interest.

INTEREST EXPENSE. Interest expense for 1995 was $21.7 million compared
to $16.9 million for 1994. This increase is principally attributable to
higher average outstanding indebtedness incurred in conjunction with 1995
acquisitions. The net impact of interest rate swaps in effect during the
years ended December 31, 1995 and 1994 was to decrease interest expense by
$.3 million in 1995 and to increase interest expense by $1.7 million in 1994.

INCOME TAXES. For 1995, the Company recorded a tax provision of $4.7
million on pre-tax income of $15.7 million, an effective rate of 30%. This
compares to a provision of $5.3 million on pre-tax income of $16.0 million
for 1994, an effective rate of 33%. In the fourth quarter of 1995, the
Company recorded a $7.0 million capital contribution and a corresponding
reduction in deferred taxes payable in connection with the utilization of
certain tax attributes in its federal income tax return which were generated
prior to the Company's initial public offering. Because these attributes
were not deducted in the consolidated federal income tax return of S.A. Louis
Dreyfus et Cie, they became available to the Company.

CAPITAL RESOURCES AND LIQUIDITY

GENERAL. During the three-year period ended December 31, 1996, the
Company funded its activities primarily through cash provided by operating
activities, proceeds from the issuance of the 9-1/4% Senior Subordinated
Notes due 2004 and bank borrowings. The following table shows the amounts
provided by the more significant sources of cash and the net cash used in
investing activities during this period.

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------
1994 1995 1996
---------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
SOURCES OF FUNDS
Net cash provided by operating activities
before working capital changes.................... $ 76,139 $ 89,102 $ 100,981
Effects of working capital changes................... 4,755 413 780
Net proceeds from issuance of subordinated debt...... 96,317 -- --
Net bank borrowings (repayments)..................... (80,822) 99,603 29,000
Net repayments to S.A. Louis Dreyfus et Cie.......... (6,736) -- --
Proceeds from issuance of Fixed-Price Contract....... 22,028 -- --
Proceeds from modification or cancellation of
Fixed-Price Contracts............................. -- -- 26,226
---------- --------- ---------
$ 111,681 $ 189,118 $ 156,987
---------- --------- ---------
---------- --------- ---------

CASH USED IN INVESTING ACTIVITIES
Acquisition of proved reserves....................... $ 31,079 $ 118,652 $ 36,125
Exploration and development drilling................. 67,764 64,889 88,680
Undeveloped acreage and seismic data................. 4,953 1,717 9,418
Other property and asset additions, net of sales
and other......................................... (827) (13,718) 16,634
---------- --------- ---------
$ 102,969 $ 171,540 $ 150,857
---------- --------- ---------
---------- --------- ---------
</TABLE>

The Company's income (excluding gains and losses on sales and
retirements of assets, exploration costs and non-cash charges) before
deduction for interest, income taxes, and DD&A (EBITDA) increased from $94.8
million in 1994 to $111.8 million in 1995 and $128.9 million in 1996.
Increases in EBITDA have occurred primarily as a result of increases in the
Company's oil and gas sales. EBITDA should not be considered an

20
<PAGE>

alternative to net income as an indicator of the Company's operating
performance or an alternative to cash flows as a measure of liquidity.

CREDIT FACILITY. The Company has a revolving credit facility with a
syndicate of banks, as most recently amended July 31, 1996 to reduce the
pricing and extend the maturity (the "Credit Facility"), which provides up to
$300 million in borrowings and letters of credit, with letters of credit
limited to $75 million of such availability. The Commitment reduces at the
rate of $18.75 million per quarter commencing October 31, 1999 through July
31, 2003. Borrowings and letters of credit under the Credit Facility are
limited to the lesser of the Commitment and the Oil and Gas Reserves Loan
Value. The Oil and Gas Reserves Loan Value is a borrowing base calculation
determined by a periodic valuation of the Company's oil and gas reserves and
Fixed-Price Contracts. The Oil and Gas Reserves Loan Value was most recently
reset in December 1996 at $330 million. The Company has relied upon the
Credit Facility to provide funds for acquisitions and to provide letters of
credit to meet the Company's margin requirements under Fixed-Price Contracts.
See "-- Fixed-Price Contracts -- Margining." As of December 31, 1996, the
Company had $235.0 million of principal and $3.3 million of letters of credit
outstanding under the Credit Facility.

The Company has the option of borrowing at a LIBOR-based interest rate
or the Base Rate (approximating the prime rate). The agreement also provides
for a competitive bid option for borrowings under the facility. The LIBOR
interest rate margin and the commitment fee payable under the Credit Facility
are subject to a sliding scale based on the relationship of outstanding
indebtedness to the discounted present value of the Company's oil and gas
reserves and Fixed-Price Contracts. The LIBOR interest rate margin varies
from .25% to .55% per annum. At December 31, 1996, the applicable interest
rate was LIBOR plus .30%. The Credit Facility also requires the payment of a
facility fee equal to .20% of the Commitment.

The Credit Facility contains various affirmative and restrictive
covenants. These covenants, among other things, limit additional
indebtedness, the extent to which volumes under Fixed-Price Contracts can
exceed proved reserves in any year and in the aggregate, the sale of assets
and the payment of dividends, and require the Company to meet certain
financial tests. Borrowings under the Credit Facility are unsecured.

The Company has entered into interest rate swaps to hedge the interest
rate exposure associated with the Credit Facility. As of December 31, 1996,
the Company had fixed the interest rate on average notional amounts of $153
million, $99 million and $33 million for the years ended December 31, 1997,
1998, and 1999, respectively. Under the interest rate swaps, the Company
receives the LIBOR three-month rate (5.6% at December 31, 1996) and pays an
average rate of 6.1% for 1997, 6.3% for 1998 and 6.5% for 1999. The notional
amounts are less than the maximum amount anticipated to be available under
the Credit Facility in such years. As of December 31, 1996, the effective
interest rate for borrowings under the Credit Facility was 6.3%. In June
1996, the Company entered into an additional interest rate swap under which
the Company pays the LIBOR three-month rate and receives 7.1% on a notional
amount of $25 million. This interest rate swap matures in June 2004.

For each interest rate swap, the differential between the fixed rate and
the floating rate multiplied by the notional amount is the swap gain or loss.
Such gain or loss is included in interest expense in the period for which the
interest rate exposure was hedged. If an interest rate swap is liquidated or
sold prior to maturity, the gain or loss is deferred and amortized as
interest expense over the original contract term. At December 31, 1995 and
1996, the amount of such deferrals was not material.

21
<PAGE>

A reconciliation of the notional amounts of the Company's interest rate
swaps for each of the three years ended December 31, 1994, 1995 and 1996, is as
follows:

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------
1994 1995 1996
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Notional amount of fixed interest rate swaps,
beginning of year ........................... $ 170,000 $ 86,000 $ 203,000
Interest rate swaps added ................... -- 155,000 --
Interest rate swap settlements .............. (29,000) (38,000) (17,000)
Interest rate swaps canceled ................ (55,000) -- --
--------- --------- ---------
Notional amount of fixed interest rate swaps,
end of year ................................. $ 86,000 $ 203,000 $ 186,000
--------- --------- ---------
--------- --------- ---------
Notional amount of floating interest rate
swaps, beginning of year .................... $ -- $ -- $ --
Interest rate swap added .................... -- -- 25,000
--------- --------- ---------
Notional amount of floating interest rate
swaps, end of year .......................... $ -- $ -- $ 25,000
--------- --------- ---------
--------- --------- ---------

</TABLE>

SUBORDINATED NOTES. In June 1994, the Company completed the sale of
$100 million of 9-1/4% Senior Subordinated Notes due 2004 (the "Notes") in a
public offering. The Notes were sold at 98.534% of face value to yield 9.48%
to maturity. Interest is payable semi-annually on June 15 and December 15.
The associated indenture agreement contains certain restrictive covenants
which limit, among other things, the prepayment of the Notes, the incurrence
of additional indebtedness, the payment of dividends and the disposition of
assets.

OTHER. The Company has certain other unsecured lines of credit
available to it which aggregated $53 million as of December 31, 1996. Such
short-term lines of credit are primarily used to meet margining requirements
under Fixed-Price Contracts and for working capital purposes. As of
December 31, 1996, the Company had $10 million of indebtedness and $17.9 million
of letters of credit outstanding under such credit lines. Repayment of
indebtedness thereunder is expected to be made through Credit Facility
availability.

The Company believes that the borrowing capacity currently available and
to be made available upon future Oil and Gas Reserves Loan Value
redeterminations under the Credit Facility, combined with the Company's
internal cash flows, will be adequate to finance the capital expenditure
program budgeted for 1997 and to meet the Company's margin requirements under
its Fixed-Price Contracts. See "--Commitments and Capital Expenditures" and
"-- Fixed-Price Contracts -- Margining." At December 31, 1996, the Company
had working capital of $4.3 million and a current ratio of 1.1 to 1. Total
long-term debt outstanding at December 31, 1996 was $343.9 million. The
Company's long-term debt as a percentage of its total capitalization was 57%.
The amount of required principal payments for the next five years and
thereafter as of December 31, 1996 are as follows: 1997 - $0; 1998 - $0;
1999 - $0; 2000 - $42.1 million; 2001 - $75.0 million; 2002 and thereafter -
$227.9 million.

If the Offerings are consummated, the net proceeds payable to the
Company will be used initially to reduce indebtedness under the Credit
Facility. Subsequently, the Company intends to use the increased availability
under the Credit Facility for increased exploratory and development drilling,
acquisitions of oil and gas reserves, recompletion and reworking of existing
wells and other corporate purposes.

22
<PAGE>

COMMITMENTS AND CAPITAL EXPENDITURES

The Company's primary business strategy has been to increase production
and reserves through exploration and development drilling activities and
through the acquisition of proved oil and gas properties. For the year ended
December 31, 1996, the Company expended $134.2 million in connection with
this strategy, funded principally through internally generated cash flows and
bank borrowings. The most significant 1996 acquisition occurred in April with
the purchase of certain producing oil and gas properties located primarily in
Oklahoma for a total consideration of $32.3 million. The acquired oil and
gas properties consisted of 60 Bcfe of proved reserves. Additionally, the
Company made numerous other acquisitions of proved oil and gas reserves
during 1996 which aggregated 16 Bcfe for a combined purchase price of $3.8
million. The results of operations relating to these acquisitions have been
included in the Company's financial results for the periods subsequent to the
closing of each transaction. In connection with its 1996 drilling program,
the Company expended $98.1 million, drilling 305 gross (162 net) wells,
including 25 gross (8 net) exploratory wells and 280 gross (154 net)
development wells. The Company's drilling activities added 115 Bcfe to its
proved reserve base (including revisions to previous estimates).

In November 1996, the Company purchased a 75-mile pipeline located in
the Sonora area for $15.2 million, including the associated compression
facilities and transportation contracts.

The Company's approved capital budget for 1997 provides for
approximately $100 million in exploration and development drilling
activities. Of these expenditures, $75 million is targeted for development
activities and $25 million for exploration activities to be conducted in its
core operating areas of the Gulf Coast, the Mid-Continent, Sonora and the
Permian basin. Actual levels of exploration and development expenditures may
vary due to many factors, including drilling results, new drilling
opportunities, oil and natural gas prices and acquisition opportunities. The
Company continues to actively search for attractive proved reserve
acquisitions, but is not able to predict the timing or amount of capital
expenditure which may ultimately be employed in acquisitions during 1997.

In January 1997, the Company completed the Levelland Sale. The Company
received total sales proceeds of $27.1 million, subject to closing costs and
adjustments. The sale resulted in an estimated pre-tax gain, after sales
commission, of $8.5 million, to be recorded in the first quarter of 1997.
The proceeds were applied to reduce outstanding indebtedness under the Credit
Facility.

See "-- Fixed-Price Contracts" for a discussion of the Company's
commitments under its Fixed-Price Contracts.

FIXED-PRICE CONTRACTS

DESCRIPTION OF CONTRACTS. The Company has entered into Fixed-Price
Contracts to reduce its exposure to unfavorable changes in oil and gas prices
which are subject to significant and often volatile fluctuation. The
Company's Fixed-Price Contracts are comprised of long-term physical delivery
contracts, energy swaps, collars, futures contracts, basis swaps and option
agreements. These contracts allow the Company to predict with greater
certainty the effective oil and gas prices to be received for its hedged
production and benefit the Company when market prices are less than the fixed
prices provided in its Fixed-Price Contracts. However, the Company will not
benefit from market prices that are higher than the fixed prices in such
contracts for its hedged production. In 1994, Fixed-Price Contracts hedged
98% of the Company's gas production not otherwise subject to fixed prices and
91% of its oil production. In 1995, Fixed-Price Contracts hedged 84% of the
Company's gas production and 86% of its oil production. For the year ended
December 31, 1996, Fixed-Price Contracts hedged 51% of the Company's gas
production and 67% of its oil production. As of December 31, 1996,
Fixed-Price Contracts are in place to hedge 349 Bcf of the Company's
estimated future production from proved gas reserves and 362 MBbls of its
estimated 1997 oil production.

<PAGE>

For energy swap sales contracts, the Company receives a fixed price for
the respective commodity and pays a floating market price, as defined in each
contract (generally NYMEX futures prices or a regional spot market index), to
the counterparty. For physical delivery contracts, the Company purchases gas
in the spot market at floating market prices and delivers such gas to the
contract counterparty at a fixed price. Under energy swap purchase
contracts, the Company pays a fixed price for the commodity and receives a
floating market price.

The following table summarizes the estimated volumes, fixed prices,
fixed-price sales, fixed-price purchases, and future net revenues (as defined
below) attributable to the Company's Fixed-Price Contracts as of December 31,
1996.

<TABLE>
<CAPTION>
YEARS ENDING DECEMBER 31, BALANCE
---------------------------------------------------- THROUGH
1997 1998 1999 2000 2001 2017 TOTAL
-------- -------- -------- -------- -------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
NATURAL GAS SWAPS,
OPTIONS AND FUTURES
SALES CONTRACTS
Contract volumes (BBtu)........... 6,068 13,825 15,825 9,830 7,475 29,832 82,855
Weighted-average fixed price
per MMBtu (1)................... $ 2.27 $ 2.33 $ 2.44 $ 2.46 $ 2.47 $ 3.08 $ 2.65
Future fixed-price sales (M$)..... $ 13,802 $ 32,243 $ 38,629 $ 24,164 $ 18,446 $ 92,005 $ 219,289
Future net revenues (M$) (2)...... $ 999 $ 2,381 $ 3,973 $ 2,489 $ 1,852 $ 22,866 $ 34,560

PURCHASE CONTRACTS
Contract volumes (BBtu)........... (2,425) (9,125) (10,950) -- -- -- (22,500)
Weighted-average fixed price
per MMBtu (1)................... $ 2.05 $ 2.09 $ 2.18 $ -- $ -- $ -- $ 2.13
Future fixed-price
purchases (M$).................. $ (4,973) $(19,108) $(23,880) $ -- $ -- $ -- $ (47,961)
Future net revenues (M$) (2)...... $ 399 $ 602 $ 100 $ -- $ -- $ -- $ 1,101

NATURAL GAS PHYSICAL
DELIVERY CONTRACTS
Contract volumes (BBtu)........... 33,111 36,060 28,204 26,749 27,300 134,096 285,520
Weighted-average fixed price
per MMBtu (1)................... $ 2.49 $ 2.64 $ 2.84 $ 3.04 $ 3.19 $ 4.11 $ 3.42
Future fixed-price sales (M$)..... $ 82,442 $ 95,130 $ 80,125 $ 81,403 $ 86,963 $551,455 $ 977,518
Future net revenues (M$) (2)...... $ 8,902 $ 17,782 $ 18,748 $ 22,486 $ 26,568 $210,070 $ 304,556

TOTAL NATURAL GAS
CONTRACTS (3) (4)
Contract volumes (BBtu)........... 36,754 40,760 33,079 36,579 34,775 163,928 345,875
Weighted-average fixed price
per MMBtu (1)................... $ 2.48 $ 2.66 $ 2.87 $ 2.89 $ 3.03 $ 3.93 $ 3.32
Future fixed-price sales (M$)..... $ 91,271 $108,265 $ 94,874 $105,567 $105,409 $643,460 $1,148,846
Future net revenues (M$) (2)...... $ 10,300 $ 20,765 $ 22,821 $ 24,975 $ 28,420 $232,936 $ 340,217

CRUDE OIL SWAPS AND
FUTURES
Contract volumes (MBbls).......... 362 -- -- -- -- -- 362

24
<PAGE>

Weighted-average fixed price
per Bbl (1) ................... $22.32 $ -- $ -- $ -- $ -- $ -- $22.32
Future fixed-price sales (M$).... $8,080 $ -- $ -- $ -- $ -- $ -- $8,080
Future net revenues (M$)(2) ..... $(172) $ -- $ -- $ -- $ -- $ -- $ (172)
</TABLE>
- ---------------------------------------

(1) The Company expects the prices to be realized for its hedged
production will vary from the prices shown due to location, quality
and other factors which create a differential between wellhead prices
and the floating prices under its Fixed-Price Contracts. See
"-- Fixed-Priced Contracts -- Market Risk."
(2) Future net revenues for any period are determined as the differential
between the fixed prices provided by Fixed-Price Contracts and forward
market prices as of December 31, 1996, as adjusted for basis. Future
net revenues change as market prices and basis fluctuate. See
"-- Fixed-Price Contracts -- Market Risk."
(3) Does not include basis swaps with notional volumes by year, as
follows: 1997 - 21.0 TBtu; 1998 - 24.5 TBtu; 1999 - 19.0 TBtu; 2000 -
21.3 TBtu; 2001 - 9.4 TBtu; and 2002 - 5.5 TBtu.
(4) Does not include 3.0 TBtu of natural gas hedged by fixed-price collars
for January through September 1997 with a weighted-average floor price
of $2.30 per MMBtu and a weighted-average ceiling price of $2.84 per
MMBtu.

A reconciliation of the future amounts to be received (or paid) under
the Company's Fixed-Price Contracts for the three years ended December 31,
1994, 1995 and 1996, is as follows:

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------
1994 1995 1996
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
NATURAL GAS SWAPS - SALES CONTRACTS
Future fixed-price sales, beginning of year ......... $ 232,797 $ 225,901 $ 194,580
Contract additions, net ........................... 43,520 4,958 78,770
Contract settlements and revisions ................ (50,416) (29,664) (10,544)
Contract cancellations (1) ........................ -- (6,615) (43,517)
---------- ---------- ----------
Future fixed-price sales, end of year (2)(3) ........ $ 225,901 $ 194,580 $ 219,289
---------- ---------- ----------
---------- ---------- ----------
NATURAL GAS SWAPS - PURCHASE CONTRACTS
Future fixed-price purchases, beginning of year ..... $ (29,689) $ (9,334) $ (46,656)
Contract additions ................................ (9,334) (46,656) (1,994)
Contract settlements and revisions ................ 22,006 9,334 689
Contract cancellations ............................ 7,683 -- --
---------- ---------- ----------
Future fixed-price purchases, end of year ........... $ (9,334) $ (46,656) $ (47,961)
---------- ---------- ----------
---------- ---------- ----------
NATURAL GAS PHYSICAL DELIVERY CONTRACTS
Future fixed-price sales, beginning of year ......... $1,027,686 $ 963,356 $1,078,779
Contract additions ................................ 34,933 173,274 1,787
Contract settlements and revisions ................ (99,263) (57,851) (103,048)
---------- ---------- ----------
Future fixed-price sales, end of year (3) ........... $ 963,356 $1,078,779 $ 977,518
---------- ---------- ----------
---------- ---------- ----------
CRUDE OIL SWAPS
Future fixed-price sales, beginning of year ......... $ 74,096 $ 39,438 $ 15,400
Contract additions ................................ -- 4,321 16,913
Contract settlements and revisions ................ (34,658) (28,359) (24,233)
---------- ---------- ----------
Future fixed-price sales, end of year ............... $ 39,438 $ 15,400 $ 8,080
---------- ---------- ----------
---------- ---------- ----------
</TABLE>

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

(1) 1996 amounts are attributable to a contract with S.A. Louis Dreyfus et Cie
which was canceled in January 1996. See "-- Fixed-Price Contracts -- Market
Risk."
(2) Does not include any future receipts or payments attributable to
fixed-price collars added in 1996 hedging 3.0 TBtu of natural gas for
January through September 1997.
(3) Does not include any future receipts or payments attributable to the
Company's portfolio of basis swaps.

<PAGE>

ACCOUNTING. The differential between the fixed price and the floating
price for each contract settlement period multiplied by the associated
contract volumes is the contract profit or loss. The realized contract
profit or loss is included in oil and gas sales in the period for which the
underlying commodity was hedged. All of the Company's Fixed-Price Contracts
have been executed in connection with its natural gas and crude oil hedging
program and not for trading purposes. Consequently, no amounts are reflected
in the Company's balance sheets or income statements related to changes in
market value of the contracts. If a Fixed-Price Contract is liquidated or
sold prior to maturity, the gain or loss is deferred and amortized into oil
and gas sales over the original term of the contract. Prepayments received
under Fixed-Price Contracts with continuing performance obligations are
recorded as deferred revenue and amortized into oil and gas sales over the
term of the underlying contract.

In June 1996, the Company and an unaffiliated counterparty to one of its
fixed-price contracts amended the terms of a fixed-priced natural gas
contract to monetize the premium in the fixed prices provided by the
contract. Pursuant to the amendment, the Company received a non-refundable
payment in the amount of $25.0 million. As consideration for this payment,
the weighted-average fixed price over the remaining 17 years of the contract
was reduced from an average price of $3.20 per MMBtu to an average price of
$2.37 per MMBtu, approximating the forward market prices for natural gas at
the time. The payment has been reflected in the Company's balance sheet as a
deferred hedging gain and is being amortized into earnings over the life of
the original contract.

CREDIT RISK. The terms of the Company's Fixed-Price Contracts generally
provide for monthly settlements and energy swap contracts provide for the
netting of payments. The counterparties to the contracts are comprised of
independent power producers, pipeline marketing affiliates, financial
institutions, a municipality and S.A. Louis Dreyfus et Cie, among others. In
some cases, the Company requires letters of credit or corporate guarantees to
secure the performance obligations of the contract counterparty. Should a
counterparty to a contract default on a contract, there can be no assurance
that the Company would be able to enter into a new contract with a third
party on terms comparable to the original contract. The loss of a contract
would subject a greater portion of the Company's oil and gas production to
market prices and could adversely affect the carrying value of the Company's
oil and gas properties and the amount of borrowing capacity available under
the Credit Facility.

Two Fixed-Price Contracts which hedge an aggregate 106 Bcf of natural
gas as of December 31, 1996 are with independent power producers which sell
electrical power under firm fixed-price contracts to Niagara Mohawk
Corporation ("NIMO"), a New York state utility. At December 31, 1996, the
net present value of the differential between the fixed prices provided by
these contracts and forward market prices, as adjusted for basis and
discounted at 10%, was $135 million, or 71% of such net present value
attributable to all of the Company's Fixed-Price Contracts. This premium in
the fixed prices is not reflected in the Company's financial statements until
realized. For the years ended December 31, 1994, 1995 and 1996, these
contracts contributed $5.1 million, $9.6 million and $.9 million,
respectively, to natural gas sales. The ability of these independent power
producers to perform their obligations to the Company is largely dependent on
the continued performance by NIMO of its power purchase obligations to the
counterparties. NIMO in recent years initiated judicial and regulatory
proceedings designed to curtail power purchase obligations under its
contracts with non-regulated power generators. As of December 31, 1996, NIMO
had not been successful in these proceedings. On August 1, 1996, NIMO
announced an offer to terminate 44 independent power contracts, including
those to the Company's counterparties, in exchange for a combination of cash
and debt securities from a newly restructured NIMO. The terms of the offer
have not been made public. At this time, the likelihood of NIMO's proposal
being accepted cannot be predicted, nor can any potential impact on future
counterparty performance if the proposal is accepted. The Company has not
experienced non-performance by any counterparty.

26
<PAGE>

MARKET RISK. The Company's Fixed-Price Contracts at December 31, 1996
hedge 349 Bcf of proved natural gas reserves, substantially all of which are
proved developed reserves, and 362 MBbls of oil, at fixed prices. These
contract quantities represent 41% and 2% of the Company's estimated proved
natural gas and crude oil reserves, respectively, at December 31, 1996. If
the Company's proved reserves are produced at rates less than anticipated,
the volumes specified under the Fixed-Price Contracts may exceed production
volumes. In such case, the Company would be required to satisfy its
contractual commitments at market prices in effect for each settlement
period, which may be above the contract price, without a corresponding offset
in wellhead revenue for any excess volumes. The Company expects future
production volumes to be equal to or greater than the volumes provided in its
contracts.

The differential between the floating price paid under each energy swap
contract, or the cost of gas to supply physical delivery contracts, and the
price received at the wellhead for the Company's production is termed "basis"
and is the result of differences in location, quality, contract terms, timing
and other variables. The effective price realizations which result from the
Company's Fixed-Price Contracts are affected by movements in basis. For the
years ended December 31, 1994, 1995 and 1996, the Company realized on an Mcf
basis approximately 11%, 3% and 3% less than the prices specified in its
natural gas Fixed-Price Contracts, respectively, due to basis. Such results
do not include a $4.3 million basis loss recognized in the fourth quarter of
1995, discussed below. For its oil production hedged by crude oil
Fixed-Price Contracts, the Company realized approximately 8%, 7% and 4% less
than the specified contract prices for such years, respectively. Basis
movements can result from a number of variables, including regional supply
and demand factors, changes in the Company's portfolio of Fixed-Price
Contracts and the composition of the Company's producing property base.
Basis movements are generally considerably less than the price movements
affecting the underlying commodity, but their effect can be significant. A
1% move in price realization for hedged natural gas in 1997 represents a
$913,000 change in gas sales. A 1% change in price realization for hedged
oil production in 1997 represents an $81,000 change in oil sales. The
Company actively manages its exposure to basis movements and from time to
time will enter into contracts designed to reduce such exposure.

In the first quarter of 1996, the Company experienced a significant
widening of basis for certain of its Fixed-Price Contracts. These particular
contracts have floating indices tied to the NYMEX natural gas contract or
involve the purchase of gas in the spot market priced at or near the Henry
Hub delivery point in Louisiana. Due to a significant increase in demand for
natural gas in the Northeastern region of the United States, NYMEX prices for
natural gas rose disproportionately in relation to the regional market prices
received for the Company's natural gas. This temporary loss of correlation
resulted in a $4.3 million charge in the fourth quarter of 1995 (when the
anomaly was identified) to reflect the estimated basis loss incurred. To
reduce exposure to Henry Hub basis volatility, the Company canceled a 20-Bcf
contract with S.A. Louis Dreyfus et Cie in January 1996, receiving $1.6
million in proceeds. These proceeds are being amortized into oil and gas
sales over the original 19-month contract term which commenced January 1996.
The Company has also entered into several basis swaps with unaffiliated
parties which are designed to substantially reduce exposure to basis
volatility over the next six years.

MARGINING. The Company is required to post margin in the form of bank
letters of credit or treasury bills under certain of its Fixed-Price
Contracts. In some cases, the amount of such margin is fixed; in others, the
amount changes as the market value of the respective contract changes, or if
certain financial tests are not met. For the years ended December 31, 1994,
1995 and 1996, the maximum aggregate amount of margin posted by the Company
was $41.0 million, $23.4 million and $25.9 million, respectively. If natural
gas prices were to rise, or if the Company fails to meet the financial tests
contained in certain of its Fixed-Price Contracts, margin requirements could
increase significantly. The Company believes that it will be able to meet
such requirements through the Credit Facility and such other credit lines
that it has or may obtain in the future. If the Company is unable to meet
its margin requirements, a contract could be terminated and the Company could
be required to pay damages to the counterparty which generally approximate
the cost to the counterparty of replacing the contract. At December 31, 1996,
the Company had issued margin in the form of letters of credit and treasury
bills totaling $20.3 million and $5.6 million, respectively. In addition,
approximately 30 Bcf of the

27
<PAGE>

Company's proved gas reserves are mortgaged to a Fixed-Price Contract
counterparty, securing the Company's performance under the associated
contract.

SONORA GAS CONTRACT

During 1995, certain gas production from the Sonora area was dedicated
to a wellhead contract with Lone Star Gas Company, then a division of ENSERCH
Corporation ("Lone Star"), that provided a fixed sales price of $3.90 per Mcf
(the "Sonora Gas Contract"). The Sonora Gas Contract obligated Lone Star to
take or pay for at least 55% of the contracted wells' combined
deliverability. Lone Star was entitled to recoup payments made for gas not
taken in prior years by taking gas in excess of the 55% requirement without
payment and crediting the value of such excess gas against the amount
previously paid. For the years ended December 31, 1994 and 1995, such
recoupment was $16.6 million and $18.0 million, respectively. For the years
ended December 31, 1994 and 1995, sales to Lone Star under the Sonora Gas
Contract were $39.4 million and $49.5 million, respectively, or 28% and 30%
of total oil and gas sales, respectively. This contract expired on December
31, 1995. The production previously dedicated to this contract is being
sold, beginning January 1, 1996, to a third party under a contract at market
sensitive prices.

OUTLOOK FOR FISCAL YEAR 1997

GENERAL. The discussion of the Company's fiscal year 1997 outlook
provided under this caption and other Forward-Looking Statements herein
reflect the current expectations of management and are based on the Company's
historical operating trends, its proved reserve and Fixed-Price Contract
positions as of December 31, 1996 and other information currently available
to management. These statements assume, among other things, that no
significant changes will occur in the operating environment for the Company's
oil and gas properties. Forward-Looking Statements also assume that there will
be no material acquisitions or divestitures except as disclosed herein. See
"Prospectus Summary -- Forward-Looking Statements" and "Risk Factors" for a
discussion of risks and uncertainties in connection with Forward-Looking
Statements.

PRODUCTION. Based on budgeted drilling expenditures for 1997 and
internal reserve estimates, the Company expects continued growth in total oil
and gas production for 1997. See "-- Commitments and Capital Expenditures."

OIL AND GAS PRICES. The Company's Fixed-Price Contracts in 1997 provide
average fixed prices of $2.48 per Mcf and $22.32 per Bbl for its hedged
natural gas and crude oil, respectively, before consideration of basis.
Based on January 1997 quotations for regional natural gas prices for the
balance of 1997 and giving effect to the Company's portfolio of basis swaps,
the Company anticipates price realization percentages comparable to
historical averages. See "-- Fixed-Price Contracts -- Market Risk." As of
December 31, 1996, the Company's Fixed-Price Contracts hedge 37 Bcf
(excluding 3 Bcf of fixed-price collars) of natural gas production in 1997
and 362 MBbls of oil production in 1997. No plans currently exist to
increase or decrease the amount of hedged production volumes for 1997; however,
the Company may decide to hedge a greater or smaller share of production in
the future.

The Company is unable to predict the market prices that will be received
for its unhedged production in 1997. For 1996, average monthly wellhead
prices for its natural gas ranged from $1.90 per Mcf to $3.91 per Mcf and its
oil prices varied from $17.29 per Bbl to $24.65 per Bbl. Because less than
one-half of the Company's estimated 1997 production is hedged by Fixed-Price
Contracts, the Company's 1997 oil and gas revenues are highly sensitive to
commodity price changes.

OTHER INCOME. The Company estimates that it will recognize a net
pre-tax gain of $8.5 million in connection with the Levelland Sale in January
1997 and that its well services income will remain relatively constant with
the prior year's results. Other miscellaneous sources of income, such as
gains or losses on other property

<PAGE>

dispositions, cannot be estimated. In January 1996, the Company received a
$10.8 million promissory note from Midcon Offshore, Inc. in connection with
the settlement of certain litigation. On December 16, 1996, Midcon filed for
protection from its creditors under Chapter 11 of the United States
Bankruptcy Code. Collection of the remaining unpaid interest and principal
on the Midcon note is uncertain and no amounts have been recorded with
respect thereto in the Company's financial statements. The Company will
recognize income as any payments are received. See Note 7 of the Notes to
the Company's Consolidated Financial Statements appearing elsewhere herein.

OPERATING COSTS. Lease operating expenses on an equivalent unit of
production basis are anticipated to remain relatively constant with the prior
year as the result of new production from wells to be drilled in 1997.
Production taxes are expected to be incurred at an average rate of 5% to 6%
of wellhead oil and gas sales.

GENERAL AND ADMINISTRATIVE EXPENSE. The Company anticipates a
relatively modest increase in its G&A costs for 1997. Planned increases in
personnel and personnel costs are expected to be largely offset by increases
in overhead recoveries from third parties.

EXPLORATION COSTS. The Company expects to commit approximately $25
million of its 1997 capital expenditure budget to exploration drilling,
leasehold, seismic and other geological and geophysical costs. Under the
successful efforts method of accounting, the costs associated with
unsuccessful exploration wells are expensed. All exploratory geological and
geophysical costs, budgeted at $3.5 million for 1997, are expensed as
incurred, regardless of ultimate success in the discovery of new reserves.
Remaining exploration costs to be expensed in 1997 will depend on the
Company's exploratory drilling results.

DEPRECIATION, DEPLETION AND AMORTIZATION. Based on the Company's proved
reserve position at December 31, 1996 and assuming 1997 finding cost results
comparable to 1996, the Company's oil and gas DD&A per equivalent unit of
production is expected to decline modestly in 1997, subject to future
revisions in the Company's proved reserve position.

IMPAIRMENT OF OIL AND GAS PROPERTIES. Revisions to prices, reserves or
other factors which would result in a material change in the estimated future
net cash flows for the Company's oil and gas fields during 1997 are not
anticipated. Consequently, while no material impairment charge is expected,
no assurance can be given.

INTEREST EXPENSE. Based on budgeted capital expenditure levels,
estimated proceeds from the Levelland Sale, the estimated proceeds from the
Offerings and estimated cash flows from operating activities, a reduction in
average outstanding indebtedness is anticipated for 1997. Consequently,
interest expense is anticipated to decrease in relation to the prior year.
However, the Company continues to actively search for attractive proved
reserve acquisitions and the Company may expand its exploration and
development activities over budgeted levels, which could cause average
outstanding indebtedness to increase. See "--Capital Resources and
Liquidity" for a discussion of interest rate information for borrowings under
the Credit Facility.

INCOME TAXES. The Company expects that the utilization of Section 29
credits in its tax provision for 1996 will result in an overall effective tax
rate of 34% to 36%.

29
<PAGE>

BUSINESS AND PROPERTIES

GENERAL

The Company is a large independent energy company engaged in the
acquisition, development and exploration of natural gas and oil properties,
and in the production and marketing of natural gas and crude oil. The
Company's reserve base is primarily located in the Sonora area of West Texas,
the Mid-Continent region, the Permian Basin, and the Texas Gulf Coast. As of
December 31, 1996, the Company had proved reserves of 990 Bcfe with a Present
Value of $1.1 billion. The Company operates over 84% of its reserves, of
which 86% is natural gas and 83% is proved developed. The Company has a
long-lived asset base with a reserve life of 13.2 years at December 31, 1996.

The Company was acquired in 1990 by S.A. Louis Dreyfus et Cie to engage
in oil and gas acquisition, development, production and marketing activities.
Subsequent thereto, S.A. Louis Dreyfus et Cie acquired or established other
subsidiaries or affiliates to conduct oil and gas activities which, through a
series of intercompany mergers in September 1993, were transferred to the
Company. In November 1993, the Company completed an initial public offering
of 7.8 million shares of Common Stock with net proceeds of $129.9 million.

<TABLE>
<CAPTION>
COMPOUND
YEARS ENDED DECEMBER 31, ANNUAL
-------------------------------------------------------------------------- GROWTH
1991 1992 1993 1994 1995 1996 RATE
--------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>

Production (MMcfe). . . 19,985 28,650 43,179 54,321 61,434 75,004 30.3%

Proved reserves
(MMcfe). . . . . . . . 211,478 376,521 627,222 689,924 876,076 990,179 36.2

Earnings per share. . . $ .09 $ .09 $ .11 $ .39 $ .40 $ .76 53.2

Net cash provided by
operating activities (M$) $ 16,514 $ 22,272 $ 52,666 $ 80,894 $ 89,515 $101,761 43.9
</TABLE>

BUSINESS STRATEGY

The Company's business strategy is to generate strong and consistent
growth in reserves, production, earnings and cash flow. The Company
implements this strategy through the following:

30
<PAGE>

EXPANDED EXPLORATION PROGRAM. Stepped up exploration activity in the
Company's core regions exposes the Company to higher potential production and
reserve additions. The Company has a staff of 22 geoscientists and reservoir
engineers who have extensive experience in the use of advanced technologies,
including 3-D seismic analysis, computer aided mapping and reservoir
simulation modeling. During 1996, the Company invested $15 million in
connection with exploration prospects, including drilling, seismic data
collection and lease acquisitions. Approximately $7 million of the 1996
exploration budget was used for early stage lease acquisitions and seismic
data collection, which have created a foundation for an expanded exploration
program in 1997 and 1998. The Company has allocated $25 million, or 25%, of
its current capital budget for additional exploration activities in 1997.

GROWTH THROUGH DRILLING. In 1994, 1995 and 1996, the Company replaced 116%,
120% and 153%, respectively, of its production through the drilling of 745
gross (450 net) wells, adding 251 Bcfe of proved reserves (including
revisions of previous estimates). The Company conducts development drilling
in areas where multiple productive oil and gas bearing formations are likely
to be encountered, thus reducing dry hole risk.

STATEGIC ACQUISITIONS. Since January 1, 1990, the Company has grown rapidly
by investing $629 million to acquire approximately 1 Tcfe of proved reserves
at an average acquisition cost of $0.66 per Mcfe. The Company believes the
cost of these acquisitions compares favorably to industry averages. The
acquisitions have been geographically concentrated in the core regions where
the Company possesses considerable operating expertise and realizes economies
of scale. The Company principally targets acquisitions which have
significant development potential, are in close proximity to existing
properties, have a high degree of operatorship and can be integrated with
minimal incremental administrative cost.

PRICE RISK MANAGEMENT. The Company manages a portion of the risks associated
with decreases in prices of natural gas and crude oil through Fixed-Price
Contracts. Since 1990, the Company has generated $41 million in additional
revenues through its price risk management strategies. At December 31, 1996,
the pre-tax present value (discounted at 10%) of the future net revenues for
such Fixed-Price Contracts, based on the difference between contract prices
and forward market prices, was approximately $190 million. These Fixed-Price
Contracts provide a base of predictable cash flows for a portion of the
Company's gas and oil sales, thereby enabling the Company to pursue its
capital expenditures with a greater degree of assurance. Recently, a lesser
portion of the Company's production has been hedged due to the Company's
reluctance to sell into a forward market where prices trend down or are
essentially flat over the next several years. In 1996, approximately 50% of
the Company's production was sold pursuant to Fixed-Price Contracts, reduced
from 84% in 1995.

31
<PAGE>

CORE AREAS

The following table sets forth certain information regarding the Company's
activities in each of its principal producing areas.

SONORA MID-CONTINENT PERMIAN(1) GULF COAST TOTAL(1)
------ ------------- ---------- ---------- --------
<S> <C> <C> <C> <C> <C>
PROPERTY STATISTICS: (as of
December 31, 1996)

Proved reserves (Bcfe)........ 494 325 97 74 990

Percent of total proved 50% 33% 10% 7% 100%
reserves......................

Average net daily production 78.1 82.1 27.1 22.5 209.8
(MMcfe) (2)...................

Gross producing wells......... 1,526 2,730 2,773 283 7,312

Net producing wells........... 1,478 803 331 121 2,733

Gross acreage................. 335,000 587,000 335,000 143,000 1,400,000

Net acreage................... 263,000 247,000 203,000 43,000 756,000

Potential drill sites......... 550 250 200 200 1,200

1996 RESULTS:

Gross wells drilled........... 96 82 101 26 305

Gross successful wells........ 93 78 97 21 289

Drilling success.............. 97% 95% 96% 81% 95%

Production (Bcfe)............. 28.1 28.4 10.4 8.1 75.0

Lease operating expense per
Mcfe......................... $0.46 $0.41 $0.56 $0.54 $0.47

BUDGETED 1997 CAPITAL
EXPENDITURES (MM$):

Development................... $34 $28 $11 $2 $75

Exploration................... 2 4 3 16 25
------- ------- ------- ------- ---------
Total......................... $36 $32 $14 $18 $100
------- ------- ------- ------- ---------
------- ------- ------- ------- ---------
</TABLE>
____________________________
(1) Includes the Company's Levelland properties which were sold in January
1997.
(2) Consists of average net daily production for December 1996.

32
<PAGE>

SONORA AREA

The Sonora area is located in the West Texas counties of Schleicher,
Crockett, Sutton and Edwards. It is comprised of five fields, Sawyer, Shurley
Ranch, MMW, Aldwell Ranch and Whitehead, which are located on the northeast side
of the Val Verde Basin of West Central Texas. Development of the Company's
Sonora properties was initiated in the 1970's. Production is predominately from
the Canyon formation at depths ranging from 2,500 to 6,500 feet and the Strawn
formation at depths ranging from 5,000 to 9,000 feet. The majority of the
Company's interest in these properties was accumulated through acquisitions in
1993 and 1995.

CANYON FORMATION. Natural gas in the Canyon formation is stratigraphically
trapped in lenticular sandstone reservoirs and the typical Sonora Area well
encounters numerous such reservoirs over the Canyon formation's gross thickness
of approximately 1,500 feet. The Canyon reservoirs tend to be discontinuous and
to exhibit low porosity and permeability, characteristics which reduce the area
that can be effectively drained by a single well. These characteristics have
encouraged operators in the area to undertake Canyon infill drilling programs
over the years. Initial wells were drilled on 640 acre drilling units, but well
performance characteristics have indicated that denser well spacing is necessary
for effective drainage. The Company continues to downsize these units, and the
fields currently are developed in some areas on 40 acre spacing.

STRAWN FORMATION. The Strawn formation, a shallow-marine, fossiliferous
limestone, produces natural gas from fractures and irregularly distributed
porosity trends draped across anticlinal features. Original field
development took place on 640 acre units, with subsequent infill programs
downsizing to 160 acre density. Testing of the Strawn formation in Sonora
wells, for which the primary drilling objective was the Canyon formation, has
been an attractive play for the Company because the Strawn lies less than
1,000 feet below the Canyon formation. Because of the closeness in depth,
the cost to evaluate the Strawn formation while drilling for the Canyon
formation is relatively minor. The Strawn production is generally commingled
with the Canyon production stream. The Company recently acquired over 10,000
gross acres and plans to drill several 100% working interest wells to test
primarily the Strawn formation in the Buckhorn horst block, a localized
fault-bounded structural feature. The Company is also evaluating the
potential for drilling horizontal wells in the Strawn formation. The Company
is encouraged by recent horizontal activity conducted by other operators west
of the Company's acreage.

ELLENBURGER FORMATION. The Ellenburger formation, which lies approximately
500 feet below the Strawn formation, continues to be a play with interesting
potential in the Sonora area. This formation, which is productive on acreage in
close proximity to the Company's Sonora properties, is expected to produce from
dolomitic porosity in structurally defined traps. Recent drilling into this
formation has resulted in encouraging gas shows and helped define the structural
and reservoir complexity of the Ellenburger. The Company is continuing a
mapping program using 2-D seismic information in conjunction with sub-surface
data obtained in the development of the Canyon and Strawn formations, to
identify locations which are structurally suited for hydrocarbon accumulation in
the Ellenburger. The relatively modest cost to deepen wells to this horizon
make the potential economics of this play highly attractive. The Company
anticipates at least three Ellenburger tests during 1997.

Since 1993, the Company has continued an aggressive development program in
the Sonora area. Through December 31, 1996, the Company had drilled 306 Canyon
and Strawn wells with only 3 dry holes. For 1997, the Company plans to drill an
additional 100 wells in Sonora. A majority of the wells proposed to be drilled
in 1997 are on relatively low risk locations which have not been assigned proved
reserves. Since only a portion of the Company's Sonora acreage is developed on
40 acre density, the Company has identified over 550 undrilled locations on the
Company's acreage of which 132 have been assigned proved undeveloped reserves.
The Company believes that, subject to further study and drilling results,
additional proved reserves will ultimately be attributed to many of the other
locations. In addition to the infill potential, many of the

33
<PAGE>

Company's producing wells in the Sonora area have recompletion possibilities
in existing wellbores from Canyon sands not currently producing.

MID-CONTINENT REGION

The Company was actively involved in the Mid-Continent region when it was
acquired by S.A. Louis Dreyfus et Cie and has subsequently acquired additional
interests in the area through multiple acquisitions that have increased reserves
with minimal additional administrative costs. The Company's properties in the
Mid-Continent region are located in and along the northern shelf of the Anadarko
basin and in Southern Oklahoma. Development of the Company's Mid-Continent
region properties began in the late 1970's. Production is predominately natural
gas from numerous formations of Pennsylvanian and Pre-Pennsylvanian age rock.
Productive depths range from 3,000 to 17,000 feet.

Pre-Pennsylvanian reservoirs include the Chester, Mississippi and Hunton
formations, with greater production from these formations occurring in highly
fractured carbonate intervals. Pennsylvanian reservoirs include the Granite
Wash, Red Fork, Atoka, Morrow and Springer sandstones. These formations have
potential for excellent production and reserves. The stratigraphic nature of
these reservoirs frequently provides for multiple targets in the same
wellbores. Spacing in these formations is generally on 640 acres with
extensive increased density drilling having occurred over the last 15 years.

The Company has pursued an active low risk infill drilling program over
the past three years and plans to drill 80 development wells in the region
during 1997. In addition, the Company has recently commenced drilling an
initial horizontal well to begin evaluating its extensive acreage containing
the Mississippi Lime formation. This well is planned to have a 2,300 foot
lateral extension.

The Company has identified 250 undrilled locations in the
Mid-Continent region, of which 110 have been assigned proved undeveloped
reserves.

PERMIAN REGION

The majority of the Company's interests in this region was acquired in
acquisitions in 1992, 1993 and 1994. The Company is actively involved in
drilling development and exploration wells in the Delaware basin of Southeast
New Mexico and the Val Verde basin and Spraberry trend of West Texas. The
primary drilling objectives in this region are the Delaware, Spraberry, Wolfcamp
and Morrow sands.

DELAWARE FORMATION. The Delaware formation was deposited in broad, braided
channel systems over most of the Delaware basin. The sands range in depth from
3,000 to 5,000 feet with multiple objectives in the Bell Canyon and Cherry
Canyon. Over the past two years, the Company has pursued an active development
program in the Happy Valley field in Eddy County of Southeast New Mexico to
exploit the Delaware formation. Production is predominately oil with reserves
ranging from 75,000 to 150,000 Bbls per well.

SPRABERRY TREND. The Spraberry trend is located in the West Texas
counties of Martin, Midland, Glasscock, Upton, Reagan and Irion. The fields
in the Spraberry trend are located in the Midland basin and are characterized
by the production of both oil and gas from productive zones ranging from the
Lower Clearfork formation at a depth of 4,500 feet, to the Dean formation at
a depth of 7,000 feet, with the majority of the production from the Spraberry
formation. The Spraberry formation, primarily an oil reservoir, produces from
fractured sandstones and siltstones and is chararacterized by low porosity
and permeability. These formation characteristics have encouraged operators
to develop the area on 80 acre spacing. Over the last two years, the Company
has pursued an active infill drilling program in the Spraberry trend which
will continue in 1997.

WOLFCAMP. The Wolfcamp in the Southern Delaware and Val Verde basins
are deposited as submarine fan sequences that are 200 to 800 feet thick and
range in depth from 4,000 to 12,000 feet. During 1996, the Company drilled 5
gross wells in the Brown Bassett area with a 100% success rate. The Company
plans to continue additional development in the field in 1997. Additionally,
the Company plans to drill a second test well in its Pecos Grande prospect,
in which it holds a 56% working interest in 11,000 gross acres in Pecos
County, Texas. The Company drilled a dry hole on this prospect in 1996, but
the Company believes that the prospect has not been adequately tested.

34
<PAGE>

MORROW FORMATION. The Morrow formation consists of northwest to southeast
trending fluvial systems exhibiting excellent porosity and permeability at
depths between 10,500 to 11,500 feet. The Company continues to drill and
participate in Morrow wells in the Artesia area which is situated along the
Northwest shelf of the Delaware basin. Morrow formation gas reserves can range
up to 6 Bcf for a single well.

The Company has identified 200 undrilled locations in the Permian region,
of which 69 have been assigned proved undeveloped reserves.

GULF COAST REGION

The Company's properties in the Gulf Coast Region consist of varying
interests in the A.W.P. (Olmos) Field and the North Tatum Field, as well as in
an offshore Gulf of Mexico platform, West Delta 152, which is its most
significant producing property in this region. At December 31, 1996, the
Company owned between a 20% and 39% non-operated working interest in the West
Delta 152 Field ("West Delta 152") which has 16 producing wells. The wells
produce from an eight-pile, 24-slot platform located in the Gulf of Mexico in
380 feet of water approximately 40 miles south-southwest of Venice, Louisiana.
The Company successfully completed seven of eight wells drilled in 1996. The
Company anticipates that 3 wells will be drilled in West Delta 152 during 1997.

The Company has identified 200 undrilled locations in the Gulf Coast
region, of which 32 have been assigned proved undeveloped reserves.

ACQUISITIONS

The Company has completed a significant number of acquisitions during the
past five years, including three ranging in size from $87 million to $180
million. The following table summarizes the Company's acquisition activity for
the five years ending December 31, 1996:

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------------
1992 1993 1994 1995 1996 TOTAL
------ ------ ----- ------ ----- ------
<S> <C> <C> <C> <C> <C> <C>
SUMMARY ACQUISITION INFORMATION

Estimated proved reserves acquired
(Bcfe)(1)................................. 163.8 296.8 56.1 190.5 75.5 782.7
Acquisition cost (MM$)..................... $116.2 $188.9 $36.6 $118.7 $36.1 $496.5
Acquisition cost per Mcfe ($).............. 0.71 0.64 0.65 0.62 0.48 0.63

</TABLE>
- --------------
(1) Based on the first year-end reserve report prepared following the
acquisition date as adjusted for production between the acquisition date
and year-end.

Senior management is actively involved in the screening of potential
acquisitions and the development and implementation of strategies for specific
acquisitions. The Company's staff of reservoir engineers, geologists,
production engineers, landmen and accountants have substantial experience in
evaluating and acquiring oil and gas reserves. The Company principally seeks
acquisitions in regions in which the Company

35
<PAGE>

believes that its prior experience and existing operations will enable it to
readily integrate the acquired properties into its existing base of
operations.

The Company primarily seeks to acquire operated interests. The Company
prefers to operate its properties whenever possible in order to provide more
control over the operation and development of the properties and the
marketing of the production. The Company frequently seeks to acquire
additional interests in its operated properties from holders of non-operating
interests to increase its percentage ownership at attractive acquisition
prices.

EXPLORATION PROSPECTS

In 1996, the Company began to place more emphasis on exploratory
drilling activities. The Company invested $15 million in 1996 for seismic
and leasehold acquisition and the drilling of 25 wells. The Company has
currently budgeted $25 million for exploration activities in 1997. The
Company's exploration prospects are located throughout its core regions.

YOAKUM GORGE. The Yoakum Gorge project is located within the Company's
Gulf Coast region in Lavaca County, Texas. The Company is currently
reviewing the 150 square miles of high-fold 3-D seismic data that was
obtained in 1996 and is evaluating drilling opportunities on its 60,000 gross
acres. The target zones are the shallow Miocene, Frio, Yegua and Upper
Wilcox sands, ranging in depth from 3,500 to 8,000 feet and the deeper
Lower Wilcox sands from 13,000 to 16,000 feet. The shallow sands were
deposited in a fluvial environment and are often point bar sands with high
porosity and permeability. These sands have a reserve range potential of .5
to 3 Bcf per well and are relatively easy to identify using 3-D seismic. The
Company successfully completed 9 shallow tests during 1996 and plans to drill
up to 40 additional wells during 1997. Initial 3-D seismic interpretation
indicates at least 70 shallow sand leads similar to those drilled in 1996.
During 1997, the Company also plans to drill 4 exploratory wells to test the
Lower Wilcox structures. The Lower Wilcox sands are part of an ancient
deltaic system deposited across an unstable muddy continental shelf. The
rapid subsidence of the underlying beds allowed accumulation of massive
Wilcox sand packages with a high degree of structural complexity. These
deeper structures present higher risk but have greater potential, ranging up
to 100 Bcf per field. The Company holds a 35% working interest in this
project.

SOUTHWEST SPEAKS. The Company has a 25% working interest in this Lower
Wilcox project which is also located in Lavaca County, Texas. The Lower
Wilcox sands are a series of deltaic sands trapped on a growth faulted
structure formed during the Wilcox time. This setting yields multiple zones
with high per well reserves and excellent flow rates. During 1996, the
Company drilled and completed the Pilgreen No. 1 well at a depth of 13,700
feet, with initial production of 5,000 Mcf per day at 7,000 pounds flowing
tubing pressure. This well is believed to have additional productive zones
behind pipe. During 1997, the Company plans to drill at least one well in
this prospect and up to three additional wells, if the results of a planned
seismic project are favorable.

COTTON VALLEY REEF TREND. The Company has a 15% working interest in
26,000 acres in the Cotton Valley Reef trend in Leon and Freestone Counties
of East Texas, an area that has attracted many of the largest independent
producers. The targets are pinnacle reef build-ups at depths ranging from
13,000 to 16,000 feet that formed on the shelf slope in a shallow water
environment during the Jurassic age. These reefs display a dimout on the
Cotton Valley seismic event and therefore are readily identifiable on high
quality 3-D seismic data. They are typically between 300 and 600 feet thick
and can extend across 40 to 80 acres. Discoveries in the region by other
operators have resulted in initial production of up to 40 MMcf per day with
single well reserves of as much as 80 Bcfe. The Company has identified 40
leads based on its 2-D seismic data. The Company plans to begin a 3-D
seismic project of 50 square miles in this area during the first quarter of
1997 with initial drilling to begin by year-end, if the results of the
seismic project are favorable.

36
<PAGE>

PITCHFORK RANCH. The Company has an option to explore on approximately
140,000 acres of the Pitchfork Ranch over the next three years. The
Pitchfork Ranch is located in the Permian region in King and Dickens
Counties, Texas. The Company will be the operator with at least a 77.5%
working interest. Target zones are the Tannehill sand at a depth of 4,500
feet and the Strawn Lime at 5,500 feet. The Tannehill sands were deposited
as northeast to southwest trending channel sands and extend over most of the
acreage. Production is generally found within point bars on structural highs
or in stratigraphic traps. Fields within this meandering channel system of
the Tannehill can have potential reserves of up to 2 MMBbls, with the
opportunity for numerous fields to exist on the ranch. The Company plans to
complete a 30 square mile 3-D seismic project by mid-1997 with initial
drilling to begin later in the year if the results of the seismic project are
favorable.

SON OF BEVO. The Company is the operator and holds a 35% working
interest in this project in Lipscomb County of the Texas Panhandle. The
prolific Upper Morrow, at a depth of 10,000 feet, was deposited in a
meandering river channel environment with gas stratigraphically trapped in
point bars. These point bars can be up to 50 feet thick and have very good
rock properties that yield high flow rates. Using 3-D seismic, the Company
has successfully completed the second of two wells drilled in this area at an
initial flow rate of 5.3 MMcf per day. Seismic interpretations indicate
at least six leads that have seismic signatures similar to those of the
successful completion. The Company plans to commence the next well in the
first quarter of 1997.

OTHER PROJECTS. The Company has other exploration projects in its core
regions, including prospects with potential in the Wolfcamp formation in West
Texas, the Ellenburger formation in Sonora and the Morrow formation in the
Mid-Continent and Permian regions.

MARKETING

FIXED PRICE CONTRACTS. The Company has entered into Fixed-Price Contracts
to reduce its exposure to decreases in oil and gas prices, which are subject to
significant and often volatile fluctuation. The Company's Fixed-Price Contracts
are comprised of long-term physical delivery contracts, energy swaps, collars,
futures contracts, basis swaps and option agreements. These contracts allow the
Company to predict with greater certainty the effective oil and gas prices to be
received for its hedged production and benefit the Company when market prices
are less than the fixed prices provided in its Fixed-Price Contracts. However,
the Company will not benefit from market prices that are higher than the fixed
prices in such contracts for its hedged production. At December 31, 1996, these
contracts hedged 349 Bcf of natural gas and 362 MBbls of oil. The fixed prices
in such contracts generally escalate over the contract term. The Company has
traditionally hedged a significant portion of its natural gas and crude oil
production. In the past three years, a progressively smaller share of the
Company's production and reserve additions have been hedged due to a reluctance
to sell into a forward market where prices trend down or are essentially flat
over the next several years. Management believes that the current relationship
between cash flow protection and exposure to oil and gas prices is an
appropriate balance for the Company. However, the Company may hedge a greater
or smaller share of production in the future, depending on market conditions,
capital investment considerations and other factors.

DELIVERY CONTRACTS. The Company has entered into fixed-price natural gas
delivery contracts with independent power producers, natural gas pipeline
marketing affiliates, a municipality and other end users. Typically, these
contracts require the Company to deliver, and the purchaser to take, specified
quantities of natural gas at specified fixed prices, over the life of the
contracts. The Company meets its fixed-price delivery contract requirements
through purchases of natural gas in markets local to the delivery point at the
most attractive prices available. The contracts generally permit the Company to
deliver natural gas at its choice of several pipeline or customary industry
delivery points, permitting some market flexibility to the Company in purchasing
required natural gas supplies and making deliveries and reducing transportation
risks. Each contract is individually negotiated based on the purchaser's
specified needs.

37
<PAGE>

ENERGY SWAPS. The Company enters into energy swaps as a fixed-price seller
in order to assure itself of fixed prices for the sale of its oil and gas
production. Less frequently, the Company enters into swaps as a fixed-price
purchaser to obtain a fixed-price supply to meet sale commitments at a
particular point in time. The variables in an energy swap transaction are a
fixed price, an index price, a specified quantity and a period. One of the
parties is designated as the fixed-price purchaser ("FPP") and whenever the
fixed price exceeds the index price for a given date or period, the FPP pays
the other party, the fixed-price seller ("FPS"), the difference between the
fixed price and the index price. Whenever the index price is in excess of the
fixed price, the FPS pays the difference between the index price and the fixed
price to the FPP. In this way the parties may, without physical delivery of oil
or gas, counterbalance or hedge against uncertainties and risk created by
fluctuations in oil and gas prices in connection with such party's actual
physical supply, purchase or sale commitments or requirements.

COUNTERPARTIES. The following table summarizes certain information
concerning the Company's natural gas Fixed-Price Contracts and associated
counterparties at December 31, 1996:

NATURAL GAS FIXED-PRICE CONTRACT
VOLUMES BY
COUNTERPARTY

<TABLE>
<CAPTION>
VOLUMES COMMITTED (Bbtu)
-----------------------------------------------------------
ENERGY SWAPS PERCENTAGE OF
DELIVERY ---------------------- COMMITTED
TYPE OF COUNTERPARTY: CONTRACTS SALES PURCHASES COLLARS TOTAL VOLUME
----------- --------- ----------- ----------- --------- -------------
<S> <C> <C> <C> <C> <C> <C>
Independent power producers..................... 175,873 -- -- -- 175,873 50%
Pipeline marketing affiliates................... 85,420 10,955 (1,825) -- 94,550 27%
Financial institutions.......................... -- -- (20,675) 3,010 (17,665) (5%)
Other........................................... 24,227 71,900 -- -- 96,127 28%
------- ------ ------- ----- ------- ----
Total........................................... 285,520 82,855 (22,500) 3,010 348,885 100%
------- ------ ------- ----- ------- ----
------- ------ ------- ----- ------- ----
</TABLE>

For additional information concerning the Company's Fixed-Price
Contracts, see "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Fixed Price Contracts".

WELLHEAD MARKETING.

The majority of the Company's wellhead gas production is sold to a
variety of purchasers on the spot market or dedicated to contracts with
market-sensitive pricing provisions. Substantially all of the undedicated
natural gas produced from Company-operated wells is marketed by the Company.
Additionally, the majority of the oil and condensate from Company-operated
properties is sold on a market sensitive basis. During 1996, the Company had
gas sales to three unrelated purchasers which approximated 18%, 13% and 11%
of total revenues.

In connection with a 1993 acquisition, the Company acquired the rights
to and obligations under the Sonora Gas Contract, a fixed-price, take-or-pay
natural gas contract with Lone Star. The Sonora Gas Contract covered a
substantial portion of the Company's production in the Sonora area and sales
under such contract accounted for 28% and 30% of the Company's total revenues
during 1994 and 1995, respectively. The Sonora Gas Contract, which expired
on December 31, 1995, provided a fixed price of $3.90 per Mcf during 1995.
Subsequent to December 31, 1995, the Company is selling the gas previously
dedicated to the Contract to a third party at market prices which have been
significantly less than the fixed prices provided by the Sonora Gas Contract.

38
<PAGE>

The loss of any wellhead purchaser is not anticipated to have a material
adverse effect on the Company because there are a substantial number of
alternative purchasers in the markets in which the Company sells its wellhead
production.

RESERVES

The following table sets forth the estimated net quantities of the
Company's proved and proved developed reserves as of December 31, 1994, 1995
and 1996, and the estimated future net revenues and Present Values at such
dates.

<TABLE>
<CAPTION>
PROVED RESERVES (1) AS OF DECEMBER 31,
----------------------------------------
1994 1995 1996 (2)
-------- --------- ---------
<S> <C> <C> <C>
ESTIMATED PROVED RESERVES:
Natural gas (Bcf). . . . . . . . . . 574.0 753.9 849.2
Oil (MMBbls) . . . . . . . . . . . . 19.3 20.4 23.5
Total (Bcfe) . . . . . . . . . . . . 689.9 876.1 990.2

Future net revenues (M$) . . . . . . $1,219,760 $1,531,501 $2,417,430
Present Value (M$) . . . . . . . . . $ 616,005 $ 737,512 $1,117,734 (3)

ESTIMATED PROVED DEVELOPED RESERVES:
Natural gas (Bcf). . . . . . . . . . 433.3 630.6 709.7
Oil (MMBbls) . . . . . . . . . . . . 13.1 14.8 17.9
Total (Bcfe) . . . . . . . . . . . . 511.8 719.6 817.1

YEAR-END PRICES USED IN ESTIMATING
FUTURE NET REVENUES:
Natural gas (per Mcf). . . . . . . . $ 2.61 $ 2.60 $ 3.55
Oil (per Bbl). . . . . . . . . . . . $ 16.08 $ 17.80 $ 24.66
</TABLE>
____________________

(1) The year-end prices used to estimate future net revenues include the
effects of the Company's Fixed-Price Contracts which have escalating
fixed prices. Estimated proved reserve quantities have been
determined without regard to such contracts.

(2) Includes 34 Bcfe of proved reserves (of which 24 Bcfe were proved
developed) attributable to the Company's Levelland properties which
were sold in January 1997. Future net revenues and the Present Value
attributable to the Levelland properties were $68.5 million and $35.9
million, respectively, at December 31, 1996.

(3) Increases in the Present Value for 1996 were due, in part, to a
significant increase in December 1996 natural gas and crude oil
prices. Holding the reserve quantities set forth in the December
31, 1996 reserve study (shown above) constant, the impact of using
average 1996 natural gas and oil prices of $2.63 per Mcf and $21.18
per Bbl would have been to lower the Present Value to $834 million.

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

The Company's estimated proved reserves as of December 31, 1996 are
based upon studies prepared by the Company's staff of engineers and reviewed
by Ryder Scott Company, independent petroleum engineers. Estimated
recoverable proved reserves have been determined without regard to any
economic benefit that may be derived from the Company's Fixed-Price
Contracts. Such calculations were prepared using standard geological and
engineering methods generally accepted by the petroleum industry and in
accordance with Securities and Exchange Commission guidelines. The estimated
future net revenues and Present Value, as adjusted for Fixed-Price Contracts,
were based on the engineers' production volume estimates with price
adjustments based on the terms of the Company's Fixed-Price Contracts as of
December 31, 1996. The amounts shown do not give effect to indirect expenses
such as general and administrative expenses, debt service and future income
tax expense or to depletion, depreciation and amortization.

39
<PAGE>

The Company estimates that if all other factors (including the estimated
quantities of economically recoverable reserves) were held constant, a $1.00
per Bbl change in oil prices and a $.10 per Mcf change in gas prices from
those used in calculating the Present Value would change such Present Value
by $11 million and $15 million, respectively.

The prices used in calculating the estimated future net revenues
attributable to proved reserves are determined using the Company's
Fixed-Price Contracts for the corresponding volumes and production periods
adjusted for estimated location and quality differentials. These prices are
on average less than spot market prices at December 31, 1996. If such
Fixed-Price Contracts were not in effect and the Company used December 31,
1996 wellhead prices, the estimated future net revenues attributable to
proved reserves and the Present Value thereof would be $2.6 billion and $1.3
billion, respectively.

There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of the
Company. The reserve data set forth herein represent only estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact manner, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result, estimates
of different engineers often vary. In addition, results of drilling, testing
and production subsequent to the date of an estimate may justify revision of
such estimate. Accordingly, reserve estimates often differ from the quantities
of oil and gas that are ultimately recovered. The meaningfulness of such
estimates is highly dependent upon the accuracy of the assumptions upon which
they were based.

For further information on reserves, future net revenues and the
standardized measure of discounted future net cash flows, see "Note 12 --
Supplemental Information -- Oil and Gas Reserves" in the Consolidated Financial
Statements of the Company appearing elsewhere herein.

COSTS INCURRED AND DRILLING RESULTS

The following table sets forth certain information regarding the costs
incurred by the Company in its acquisition, exploration and development
activities during the periods indicated.

<TABLE>
<CAPTION>
COSTS INCURRED YEARS ENDED DECEMBER 31,
---------------------------------
1994 1995 1996
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>

Property acquisition costs:
Proved. . . . . . . . . . . . . . . . $ 36,575 $118,652 $ 36,125
Unproved. . . . . . . . . . . . . . . 4,953 1,717 6,934
-------- -------- --------
41,528 120,369 43,059
Exploration costs . . . . . . . . . . -- 391 10,610
Development costs . . . . . . . . . . 67,764 64,498 80,553
-------- -------- --------

Total . . . . . . . . . . . . . . . . $109,292 $185,258 $134,222
-------- -------- --------
-------- -------- --------
</TABLE>

40
<PAGE>

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

WELLS DRILLED
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
------------------------------------------------------
1994 1995 1996
-------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Development wells:
Gas.................... 144 131 134 115 179 130
Oil.................... 27 6 114 28 92 19
Dry.................... 4 2 14 5 9 5
----- --- ----- --- ----- ---
Total.................. 175 139 262 148 280 154
----- --- ----- --- ----- ---
----- --- ----- --- ----- ---

Exploratory wells:
Gas.................... -- -- 3 1 18 6
Oil.................... -- -- -- -- -- --
Dry.................... -- -- -- -- 7 2
----- --- ----- --- ----- ---
Total.................. -- -- 3 1 25 8
----- --- ----- --- ----- ---
----- --- ----- --- ----- ---
</TABLE>

As of December 31, 1996, the Company was involved in the drilling, testing
or completing of 8 gross (4 net) development wells.

ACREAGE

The following table sets forth the Company's developed and undeveloped oil
and gas lease acreage as of December 31, 1996. Excluded is acreage in which the
Company's interest is limited to royalty, overriding royalty and other similar
interests.

<TABLE>
<CAPTION>
ACREAGE DEVELOPED UNDEVELOPED
-------------------- --------------------
GROSS NET GROSS NET
------- ------- ------- -------
<S> <C> <C> <C> <C>
Sonora area............. 214,656 175,494 120,080 87,900
Mid-Continent region.... 539,448 216,176 47,390 30,750
Permian region.......... 141,801 41,451 193,572 161,421
Gulf Coast region....... 53,214 19,560 89,437 23,700
------- ------- ------- -------
Total................... 949,119 452,681 450,479 303,771
------- ------- ------- -------
------- ------- ------- -------
</TABLE>
PRODUCTIVE WELL SUMMARY

The following table sets forth the Company's ownership in productive wells
at December 31, 1996. Gross oil and gas wells include 138 wells with multiple
completions. Wells with multiple completions are counted only once for purposes
of the following table.

<TABLE>
<CAPTION>
PRODUCTIVE WELLS PRODUCTIVE WELLS (1)
--------------------
GROSS NET
----- -----
<S> <C> <C>
Gas...................... 3,486 2,248
Oil...................... 3,826 485
----- -----
Total.................... 7,312 2,733
----- -----
----- -----
</TABLE>
(1) Includes 837 gross (95 net) wells in the Company's Levelland properties
which were sold in January 1997.

41
<PAGE>

EMPLOYEES

As of January 31, 1997, the Company had approximately 314 employees.
Management believes that its relations with its employees are satisfactory.
The Company's employees are not covered by a collective bargaining agreement.

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

The Company was acquired by S.A. Louis Dreyfus et Cie in 1990 to engage
in oil and gas acquisition, development, production and marketing activities.
S.A. Louis Dreyfus et Cie's other principal activities include the
international merchandising and exporting of various commodities, ownership
and management of ocean vessels, real estate ownership, development and
management, manufacturing, the marketing of electricity, natural gas and
petroleum products and crude oil refining.

S.A. Louis Dreyfus et Cie currently is the beneficial owner of
approximately 74.2% of the Company's Common Stock and after the Offerings
will beneficially own 58.5% of the Company's Common Stock (55.8% if the
Underwriters' over-allotment option is exercised in full). Through its
ability to elect all directors of the Company, S.A. Louis Dreyfus et Cie has
the ability to control all matters relating to the management of the Company,
including any determination with respect to the acquisition or disposition of
Company assets and the future issuance of Common Stock or other securities of
the Company. S.A. Louis Dreyfus et Cie also has the ability to control the
Company's drilling, development, capital, operating and acquisition
expenditure plans. There is no agreement between S.A. Louis Dreyfus et Cie
and any other party, including the Company, that would prevent S.A. Louis
Dreyfus et Cie from acquiring additional shares of the Common Stock.

The Company has an agreement ("Services Agreement") with S.A. Louis
Dreyfus et Cie pursuant to which S.A. Louis Dreyfus et Cie provides to the
Company various services (principally insurance-related services). Such
services historically have been supplied to the Company by S.A. Louis Dreyfus
et Cie, and the Services Agreement provides for the further delivery of such
services, but only to the extent requested by the Company. The Company
reimburses S.A. Louis Dreyfus et Cie for a portion of the salaries of
employees performing requested services based on the amount of time expended
("Hourly Charges"), all direct third party costs incurred by S.A. Louis
Dreyfus et Cie in rendering requested services and overhead costs equal to
40% of the Hourly Charges. The Services Agreement will continue until
terminated by either party upon 60 days prior written notice to the other
party in accordance with the terms of the Services Agreement. In the event
of termination of the Services Agreement by S.A. Louis Dreyfus et Cie, the
Company has an option to continue the agreement for up to 180 days to enable
it to arrange for alternative services.

POTENTIAL CONFLICTS OF INTEREST

The nature of the respective businesses of the Company and S.A. Louis
Dreyfus et Cie may give rise to conflicts of interest between such companies.
Conflicts could arise, for example, with respect to intercompany transactions
between the Company and S.A. Louis Dreyfus et Cie, competition in the
marketing of natural gas, the issuance of additional shares of voting
securities, the election of directors or the payment of dividends by the
Company.

The Company and S.A. Louis Dreyfus et Cie have in the past entered into
significant intercompany transactions and agreements incident to their
respective businesses. Such transactions and agreements have related to,
among other things, the purchase and sale of natural gas, the financing of
acquisition, development and marketing activities of the Company and the
provision of certain corporate services. It is the intention of S.A. Louis
Dreyfus et Cie and the Company that the Company operate independently, other
than receiving services as contemplated by the Services Agreement, but S.A.
Louis Dreyfus et Cie and the Company may enter into other material
intercompany transactions. In any event, the Company intends that the terms
of any

42
<PAGE>

future transactions and agreements between the Company and S.A. Louis Dreyfus
et Cie will be at least as favorable to the Company as could be obtained from
unaffiliated third parties.

S.A. Louis Dreyfus et Cie has advised the Company that it does not
currently intend to engage in the acquisition and development of, or
exploration for, oil and gas except through its beneficial ownership of
Common Stock. However, as part of S.A. Louis Dreyfus et Cie's business
strategy, S.A. Louis Dreyfus et Cie may, from time to time, acquire other
businesses primarily engaged in other activities, which may also include oil
and gas acquisition, exploration and development activities as part of such
acquired businesses. S.A. Louis Dreyfus et Cie is also actively engaged in
the trading of oil and gas which includes the use of Fixed-Price Contracts.
The Company has not adopted any special procedures to address potential
conflicts of interest between the Company and S.A. Louis Dreyfus et Cie
relating to such potential competition. However, the Company does not
currently anticipate that any potential competition with S.A. Louis Dreyfus
et Cie for Fixed-Price Contracts would adversely affect its ability to hedge
its production.

43
<PAGE>

MANAGEMENT

EXECUTIVE OFFICERS AND DIRECTORS

The executive officers and directors of the Company are as follows:

NAME AGE POSITION
---- --- --------
<S> <C> <C>
Mark E. Monroe 42 President, Chief Executive Officer and Director
Jeffrey A. Bonney 40 Vice President and Chief Accounting Officer
Richard E. Bross 48 Executive Vice President and Director
Peter B. Fritzinger 39 Chief Financial Officer and Treasurer
Ronnie K. Irani 40 Executive Vice President - Engineering
and Exploration
Kevin R. White 39 Executive Vice President - Corporate Development and
Strategic Planning and Secretary
Simon B. Rich, Jr. 52 Chairman of the Board of Directors
Daniel R. Finn, Jr. 53 Director
John J. Hogan, Jr. 52 Director
Gerard Louis-Dreyfus 64 Director
James R. Paul 62 Director
James T. Rodgers, III 62 Director

</TABLE>

All directors hold office until the next annual meeting of stockholders
of the Company and until their successors have been duly elected and
qualified. The executive officers of the Company are elected by the Board of
Directors and serve at its discretion.

The following is a brief description of the business background of each
of the executive officers and directors of the Company.

MARK E. MONROE is President and Chief Executive Officer of the Company
and has been a director of the Company since 1986. Mr. Monroe joined the
Company in 1980, which was then known as Bogert Oil Company and which was
later acquired by S.A. Louis Dreyfus et Cie, and served as Vice President and
Chief Financial Officer of the Company until April 1991. From April 1991
until September 1993, Mr. Monroe served as a Vice President of Louis Dreyfus
Energy Corp., an indirect subsidiary of S.A. Louis Dreyfus et Cie, engaged in
oil and natural gas trading and marketing. Mr. Monroe rejoined the Company in
September 1993 and served as Chief Operating Officer until his election to
his present position in August 1996. Mr. Monroe holds a B.B.A. degree from
the University of Texas and is a Certified Public Accountant.

JEFFREY A. BONNEY is Vice President and Chief Accounting Officer of the
Company. Mr. Bonney joined the Company in November 1993. From April 1990 to
November 1993, Mr. Bonney was the Vice President and Controller of Hadson
Energy Resources Corporation, an international oil and gas concern. Prior
thereto, Mr. Bonney held various management positions with other independent
oil and gas companies. He began his career as an auditor with Deloitte,
Haskins & Sells in 1978. Mr. Bonney is a Certified Public Accountant and
holds a B.S. in Accounting from Oklahoma Christian University.

RICHARD E. BROSS is Executive Vice President of the Company and was
elected as a director of the Company in September 1993. Mr. Bross joined the
Company in 1991 and served as its President until September 1993. Prior to
joining the Company, Mr. Bross served in various capacities at Argent Energy,
Inc. (previously named Woods Petroleum Corporation) from 1977 until 1991,
culminating with his appointment as Executive Vice President and Chief
Operating Officer in September 1990. Mr. Bross joined Argent Energy, Inc. in
1977 after working for Gulf Oil Corporation for seven years in various
engineering functions. Mr. Bross holds

44
<PAGE>

a B.S. degree in Mechanical Engineering from the University of Missouri and
an M.B.A. from Oklahoma City University.

PETER B. FRITZINGER is Chief Financial Officer and Treasurer of the
Company. Prior to his election to this position in September 1993, Mr.
Fritzinger served as Vice President - Finance and as Treasurer of Louis
Dreyfus Energy Corp. beginning in April 1991. From 1980 to 1991, Mr.
Fritzinger held various positions with Morgan Guaranty Trust Company of New
York. Mr. Fritzinger holds a B.A. in Math and Psychology from Amherst
College.

RONNIE K. IRANI is Executive Vice President - Engineering and
Exploration of the Company. He joined the Company in March 1991 from Argent
Energy, Inc. (previously named Woods Petroleum Corporation) where he had
worked for the previous 12 years. At Argent Energy, Inc., Mr. Irani held the
title of Manager of Reservoir Engineering. Mr. Irani holds a B.S. in
Chemistry from Bombay University, India, a B.S. and M.S. in Petroleum
Engineering from the University of Oklahoma and an M.B.A. from Oklahoma City
University.

KEVIN R. WHITE is Executive Vice President - Corporate Development and
Strategic Planning and Secretary of the Company. Mr. White joined the Company
in 1983, which was then known as Bogert Oil Company, and served in various
capacities prior to appointment to his present position, including Assistant
Controller, Controller and Manager of Corporate Development. From 1981 until
1982, Mr. White was employed as an auditor with Arthur Andersen & Co. and
Ernst & Young. Mr. White is a Certified Public Accountant and holds B.S. and
M.S. degrees in Accounting from Oklahoma State University.

SIMON B. RICH, JR. has been a director of the Company since 1990 and has
served as Chairman of the Board of Directors since August 1996. Mr. Rich is
Managing Director and Chief Operating Officer of Duke/Louis Dreyfus LLC, a
company 50% owned by S.A. Louis Dreyfus et Cie engaged in natural gas,
petroleum product and electric power trading and marketing. From September
1993 until August 1996, Mr. Rich served as President and Chief Executive
Officer of the Company. From 1990 to 1993, Mr. Rich served as Executive Vice
President of Louis Dreyfus Energy Corp. From 1986 to 1990, Mr. Rich served as
Executive Vice President-Development and Strategic Planning of S.A. Louis
Dreyfus et Cie. Mr. Rich holds a B.A. in Economics from Duke University.

DANIEL R. FINN, JR. has been a director of the Company since 1990. Mr.
Finn is Chief Executive Officer of Duke/Louis Dreyfus LLC. Mr. Finn has been
employed by S.A. Louis Dreyfus et Cie or its subsidiaries since 1972, serving
in various capacities, including Vice President of worldwide wheat
merchandising, Senior Vice President of worldwide grain merchandising and
President and Chairman of the Board of Directors of Louis Dreyfus Energy
Corp. In addition, Mr. Finn is Executive Vice President and a director of
Louis Dreyfus Holding Company Inc., a subsidiary of S.A. Louis Dreyfus et
Cie. Mr. Finn holds a B.A. in Economics from Fairfield University and an
M.B.A. in Finance from Northwestern University.

JOHN J. HOGAN, JR. was elected to the Board of Directors of the Company
in September 1993. Mr. Hogan has been with the law firm of Dewey Ballantine,
New York since 1969. He also serves as a director of several other
industrial corporations. Mr. Hogan holds a B.A. in Economics from Fordham
University and J.D. and M.B.A. degrees from Columbia University.

GERARD LOUIS-DREYFUS has been a director of the Company since September
1993. Mr. Louis-Dreyfus is the President and Chief Executive Officer of S.A.
Louis Dreyfus et Cie, the parent company of the Louis Dreyfus worldwide
organization of companies. S.A. Louis Dreyfus et Cie is privately owned by
family members and has been in business for over 140 years. The principal
activities of the Louis Dreyfus group include the international merchandising
and exporting of various commodities, ownership and management of ocean
vessels, real estate ownership, development and management, manufacturing,
and natural gas, petroleum product and electric power marketing. Mr.
Louis-Dreyfus is the great-grandson of the founder. Mr.

45
<PAGE>

Louis-Dreyfus is a graduate of Duke University and Duke University School of
Law. Upon graduation he joined the firm of Dewey Ballantine, New York, until
1965 when he joined S.A. Louis Dreyfus et Cie.

JAMES R. PAUL was elected to the Board of Directors of the Company in
February 1994. Mr. Paul retired in January 1994 from The Coastal Corporation
after twenty years of service in various executive capacities, including
President and Chief Executive Officer from 1989, and a director from 1981,
until his retirement. Mr. Paul holds a B.S. in Business Administration from
Wichita State University.

JAMES T. RODGERS, III was elected to the Board of Directors of the
Company in February 1994. Mr. Rodgers retired in 1992 from Anadarko Petroleum
Corporation after sixteen years of service in various executive capacities,
including President and Chief Operating Officer from 1986, and a director
from 1979, until his retirement. Mr. Rodgers holds an M.S. from the
University of Texas and a B.S. from Louisiana State University both in
Petroleum Engineering. Mr. Rodgers also serves on the Board of Directors of
Barrett Resources Corp., a publicly-held independent oil and gas company.

<PAGE>

SELLING SHAREHOLDER AND PRINCIPAL SHAREHOLDERS

The following table sets forth certain information as of February 1,
1997 with respect to the ownership of the Company's Common Stock by (i) the
Selling Shareholder, (ii) each other person known by the Company to own
beneficially more than five percent of its Common Stock, including any
"group" as that term is used in Section 13(d)(3) of the Securities Exchange
Act of 1934, as amended (the "Exchange Act"), (iii) each director of the
Company, (iv) the chief executive officer and the three other most highly
compensated executive officers of the Company and (v) all executive officers
and directors as a group.

<TABLE>
<CAPTION>
Shares Owned Shares To Be Owned
Before Offerings(1) Shares To Be After Offering (1)(2)
------------------- Sold In ---------------------
Name and Address Number Percent Offering(2) Number Percent
- ---------------- ------ ------- ----------- ------ -------
<S> <C> <C> <C> <C> <C>
S. A. Louis Dreyfus et Cie (3) 20,630,000 74.2% 2,750,000 17,880,000 58.5%

Mutuelles AXA, AXA and The 2,238,100 8.0% - 2,238,100 7.3%
Equitable Companies Incor-
porated, as a group (4)

Mark E. Monroe (5) 95,000 * - 95,000 *

Richard E. Bross (5) 53,250 * - 53,250 *

Peter B. Fritzinger (5) 31,000 * - 31,000 *

Ronnie K. Irani (5) 46,450 * - 46,450 *

Simon B. Rich, Jr. (5) 92,600 * - 92,600 *

Daniel R. Finn, Jr. (6) 13,000 * - 13,000 *

John J. Hogan, Jr. (6)(7) 12,000 * - 12,000 *

Gerard Louis-Dreyfus (6) 11,000 * - 11,000 *

James R. Paul (6) 9,000 * - 9,000 *

James T. Rodgers, III (6) 8,000 * - 8,000 *

All executive officers and directors 410,050 1.5% - 410,050 1.3%
as a group (12 persons) (8)
</TABLE>

_________________

* The percentage of shares beneficially owned does not exceed one percent
of the outstanding shares of the class.

(1) This table is based upon information supplied by officers, directors and
principal shareholders and applicable Schedules 13D or 13G filed with the
Securities and Exchange Commission. Unless otherwise indicated in the
footnotes to this table and subject to community property laws where
applicable, each of the shareholders named in this table has sole voting and
investment power with respect to the shares indicated as beneficially owned.
The percentage of ownership for each person is calculated in accordance with
rules of the Securities and Exchange Commission without regard to shares of
Common Stock issuable upon exercise of outstanding stock options, except that
any shares a person is deemed

47
<PAGE>

to own by having a right to acquire by exercise of an option are considered
outstanding solely for purposes of calculating such person's percentage
ownership.

(2) Assumes that the Underwriters' over-allotment options covering 825,000
additional shares will not be exercised and that the respective beneficial
owners listed in the table will not purchase any shares in the Offerings.

(3) S.A. Louis Dreyfus et Cie, 87 Avenue de la Grande Armee, 75782 Paris,
France, shares voting and investment power over all of the shares indicated as
beneficially owned by it with its direct or indirect wholly owned
subsidiaries, Louis Dreyfus Holding Company Inc. and Louis Dreyfus Commercial
Activities Inc., 10 Westport Road, Wilton, Connecticut 06897-0810 and, as to
20,000,000 of such shares, shares voting and investment power with Louis
Dreyfus Natural Gas Holdings Corp, 3411 Silverside Road, Suite 210E Baynard
Bldg., Wilmington, Delaware 19810-4804. Such 20,000,000 shares have been
pledged to certain banks to secure loans made to the Selling Shareholder in
the ordinary course of its business. A default by the Selling Shareholder
under the terms of such arrangements could result in the sale of all or a
portion of the pledged shares and a change in control of the Company. The
shares to be sold by the Selling Shareholder in the Offerings will have been
released from such pledge prior to the delivery of such shares for sale in the
Offerings.

(4) The named group consists of (i) a group collectively referred to as
Mutuelles AXA, consisting of Alpha Assurances I.A.R.D. Mutuelle and Alpha
Assurances Vie Mutuelle, 101-100 Terrasse Boieldieu, 92042 Paris La Defense,
France; AXA Assurances I.A.R.D. Mutuelle and AXA Assurances Vie Mutuelle, La
Grande Arche, Pari Nord, 92044 Paris La Defense, France; and Uni Europe
Assurances Mutuelle, 24 Rue Drouot, 75009 Paris, France; (ii) AXA, 23 Avenue
Matignon, 75008 Paris, France; and (iii) The Equitable Companies Incorporated,
787 Seventh Avenue, New York, New York, 10019 as a parent holding company of
Alliance Capital Management L.P. and The Equitable Life Assurance Society of
the United States. The group has sole investment power for all of the shares
indicated as beneficially owned and sole voting power over 1,740,400 of such
shares. Beneficial ownership information is as of December 31, 1995.

(5) Includes shares which the named individuals have the right to acquire by
exercise of stock options granted under the Company's Stock Option Plan, which
are currently exercisable as follows: ; Monroe - 85,000; Bross -51,250;
Fritzinger - 22,500; Irani - 43,750; and Rich - 85,000.

(6) Includes 8,000 shares which the named individual has the right to acquire
by exercise of currently exercisable stock options granted under the Company's
Stock Option Plan.

(7) Includes 1,000 shares owned by Mr. Hogan's wife as custodian for two of
their children as to which Mr. Hogan disclaims beneficial ownership.

(8) Includes 361,250 shares which directors and executive officers as a group
have a right to acquire by exercise of options granted under the Company's
Stock Option Plan which are currently exercisable.

<PAGE>

DESCRIPTION OF CAPITAL STOCK

The authorized capital stock of the Company consists of 10,000,000
shares of Preferred Stock, par value $.01 per share ("Preferred Stock"), of
which no shares were outstanding as of the date of this Prospectus, and
100,000,000 shares of Common Stock, par value $.01 per share, of which
27,801,500 shares were outstanding as of February 1, 1997.

COMMON STOCK

The Common Stock possesses ordinary voting rights for the election of
directors and in respect of other corporate matters, each share being
entitled to one vote. There are no cumulative voting rights, meaning that
the holders of a majority of the shares voting for the election of directors
can elect all the directors if they choose to do so. The Common Stock
carries no preemptive rights and is not convertible, redeemable or
assessable, or entitled to the benefits of any sinking fund. The holders of
Common Stock are entitled to dividends in such amounts and at such times as
may be declared by the Board of Directors out of funds legally available
therefor. See "Price Range of Common Stock and Dividend Policy." After the
Offerings, S. A. Louis Dreyfus et Cie will beneficially own 58.5% of the
issued and outstanding Common Stock (or 55.8 % if the Underwriters'
over-allotment options are exercised in full) and will continue indirectly to
have the voting power necessary to determine the outcome of all matters upon
which stockholders of the Company vote. See "Business and Properties --
Relationship Between the Company and S.A. Louis Dreyfus et Cie."

Upon liquidation or dissolution of the Company, holders of Common Stock
are entitled to share ratably in all net assets available for distribution to
stockholders after payment of any liquidation preferences to holders of
Preferred Stock. All outstanding shares of Common Stock are, and the shares
of Common Stock to be sold by the Company in the Offerings when issued will
be, duly authorized, validly issued, fully paid and nonassessable.

See "Price Range of Common Stock and Dividend Policy" for information
concerning the high and low sales prices of the Common Stock for each quarter
during the two most recent fiscal years and other matters affecting holders
of the Common Stock.

PREFERRED STOCK

The Board of Directors has the authority, without further approval or
action by the stockholders, to issue shares of Preferred Stock in one or more
series and to fix the rights, preferences, privileges and restrictions
thereof, including dividend rights, conversion rights, voting rights, terms
of redemption, liquidation preferences, sinking fund terms and the number of
shares constituting any additional series of Preferred Stock or the
designation of such series. The issuance of Preferred Stock could adversely
affect the voting power of holders of Common Stock and the likelihood that
such holders will receive dividend payments and payments upon liquidation and
could have the effect of delaying or preventing a change in control of the
Company. The Company has no current plans to issue any shares of Preferred
Stock.

OKLAHOMA LAW AND CERTAIN CHARTER PROVISIONS

The Company's Certificate of Incorporation provides that, pursuant to
Oklahoma law, its directors will not be liable for monetary damages for
breach of the directors' fiduciary duty of care to the Company and its
stockholders. The provision in the Certificate of Incorporation does not
eliminate the duty of care and, in appropriate circumstances, equitable
remedies such as injunctive or other forms of non-monetary relief will remain
available under Oklahoma law. However, such remedies may not be effective in
all cases. In addition, each director will continue to be subject to
liability for breach of the director's duty of loyalty to the Company, as
well as for acts or omissions not in good faith or involving intentional
misconduct, for knowing violations of law, for actions leading to improper
personal benefit to the director, and for payment of dividends or approval

<PAGE>

of stock repurchases or redemptions that are unlawful under Oklahoma law.
The provision also does not affect a director's responsibilities under any
other law, such as the state or federal securities laws.

Under Section 1031 of the Oklahoma General Corporation Act, the Company
has broad powers to indemnify its directors and officers against liabilities
they may incur in such capacities, including liabilities under the Securities
Act of 1933, as amended (the "Securities Act").

The Company's Certificate of Incorporation provides that the Company
shall indemnify its directors and officers to the fullest extent permitted by
Oklahoma law. The Certificate of Incorporation requires the Company to
indemnify such persons against expenses, judgments, fines, settlements and
other amounts incurred in connection with any proceeding, whether actual or
threatened, to which any such person may be made a party by reason of the
fact that such person is or was a director or an officer of the Company or
any of its affiliated enterprises, provided such person acted in good faith
and in a manner such person reasonably believed to be in or not opposed to
the best interests of the Company, and with respect to any criminal
proceeding, had no reasonable cause to believe his conduct was unlawful.
However, in the case of a derivative action, an officer or director will not
be entitled to indemnification in respect of any claim, issue or matter as to
which such person is adjudged to be liable to the Company, unless and only to
the extent that the court in which the action was brought determines that
such person is fairly and reasonably entitled to indemnity for expenses.

In addition, the Company has entered into Indemnification Agreements
with each director of the Company which require the Company to indemnify such
persons against certain liabilities and expenses incurred by any such persons
by reason of their status or service as directors of the Company and which
set forth procedures that will apply in the event of a claim for
indemnification under such agreements. The Indemnification Agreements also
require that the Company use commercially reasonable efforts to maintain
policies of directors' and officers' liability insurance. The Company
believes that these agreements enhance its ability to attract and retain
highly qualified directors.

As of the date of this Prospectus, there is no pending litigation or
proceeding involving a director or officer of the Company as to which
indemnification is being sought nor is the Company aware of any threatened
litigation that may result in claims for indemnification by any officer or
director.

TRANSFER AGENT AND REGISTRAR

ChaseMellon Shareholder Services, L.L.C. serves as the transfer agent
and registrar of the Common Stock.

<PAGE>

CERTAIN UNITED STATES TAX CONSEQUENCES
TO NON-UNITED STATES HOLDERS

The following is a discussion of the principal United States federal
income and estate tax consequences of the ownership and disposition of the
Common Stock applicable to Non-United States Holders of such Common Stock.
For the purpose of this discussion, a "Non-United States Holder" is a person
other than (i) an individual who is a citizen or resident of the United
States, (ii) a corporation or partnership created or organized in the United
States or under the law of the United States or any state or (iii) an estate
or trust, the income of which is includable in gross income for United States
federal income tax purposes regardless of its source. This discussion does
not deal with all aspects of United States federal income and estate taxation
and does not deal with foreign, state and local tax consequences that may be
relevant to Non-United States Holders in light of their particular
circumstances. Furthermore, the following discussion is based on current
provisions of the Internal Revenue Code of 1986, as amended (the "Code"), and
administrative and judicial interpretations as of the date hereof, all of
which are subject to change.

Prospective foreign investors are urged to consult their tax advisors
regarding the United States federal, state and local, and Non-United States,
income and other tax consequences of owning and disposing of the Common Stock.

DIVIDENDS

Generally, any dividend paid to a Non-United States Holder of the Common
Stock will be subject to United States withholding tax at a rate of 30% of
the gross amount of the dividend or at a lesser applicable treaty rate.
Dividends received by a Non-United States Holder that are effectively
connected with a United States trade or business conducted by such holder are
subject to tax at ordinary federal income tax rates and will be exempt from
withholding if the Non-United States Holder files Internal Revenue Service
Form 4224. A non-United States corporation receiving such effectively
connected dividends may also be subject to an additional "branch profits tax"
which is imposed, under certain circumstances, at a rate of 30% (or such
lower rate as may be specified by an applicable treaty) of the non-United
States corporation's effectively connected earnings and profits, subject to
certain adjustments.

Under current United States Treasury regulations, dividends paid to an
address outside the United States are presumed to be paid to a resident of
such country absent knowledge of the status of the shareholder to the
contrary for purposes of the withholding rules, including application of any
more favorable tax treaty provisions, discussed above. However, under
proposed United States Treasury regulations not currently in effect, a
Non-United States Holder of Common Stock who wishes to claim the benefit of
an applicable treaty rate would be required to satisfy applicable
certification and other requirements.

If the Company does not have earnings and profits, a distribution will
be treated as a return of capital and, to the extent it exceeds a Non-United
States Holder's basis in the Common Stock, as capital gain, rather than a
dividend. Where excess amounts have been withheld, the Non-United States
Holder may obtain a refund of the excess by filing an appropriate claim for
refund with the United States Internal Revenue Service.

DISPOSITION OF COMMON STOCK

A Non-United States Holder will generally not be subject to United
States federal withholding tax in respect of amounts realized on a
disposition of Common Stock and, except as discussed below, regular United
States federal income tax will not apply to gain realized on the disposition
of Common Stock, provided that:

(i) the gain is not effectively connected with the conduct of a
trade or business of the Non-United States Holder in the United States,

<PAGE>

(ii) in the case of a non corporate Non-United States Holder, such
Holder (a) is not present in the United States for 183 or more days in
the taxable year of the disposition (as calculated under certain
provisions of the Code or (b) if so present in the United States, such
individual's "tax home" for federal income tax purposes is not in the
United States and the gain is not attributable to an office or other fixed
place of business maintained in the United States by such individual, and

(iii) if the Company is or has been a "United States Real
Property Holding Corporation" ("USRPHC") at any time during the shorter
of the holder's holding period or the five-year period ending on the
date of disposition, (a) the Common Stock is or was during the calendar
year of disposition regularly traded on a domestic established
securities market, and (b) the Non-United States Holder has not held,
directly or indirectly, at any time during the shorter of the holder's
holding period and the five-year period ending on the date of
disposition, more than 5% of the Common Stock.

The Company believes it currently is and will continue to be a USRPHC.
As a result of such status, unless the exception described below applies,
Non-United States Holders generally will be subject to tax on any gain
realized on a sale or disposition of Common Stock at ordinary federal income
tax rates and will be subject to a 10% withholding tax on the amount realized
upon such disposition. Any amount withheld will be creditable against such
holder's United States federal income tax liability. However, under an
exception to the tax on dispositions of USRPHC interests, no federal income
tax will apply to taxable dispositions of Common Stock if the Non-United
States Holder does not own (directly or indirectly) more than five percent of
the outstanding class of Common Stock any time during the five-year period
ending on the date of the disposition, provided that the Common Stock is
"regularly traded on an established securities market" within the meaning of
Section 897(c)(3) of the Code at the time of disposition. Accordingly, if the
Company's Common Stock is listed on the New York Stock Exchange at the time
of the disposition and the circumstances described in (i) and (ii) above do
not apply, recognized gain from such disposition of Common Stock by a
Non-United States Holder generally will not be subject to United States
federal income tax unless such holder owns (directly or indirectly) more than
five percent of the outstanding class of Common Stock at any time during the
five-year period ending on the date of disposition.

If the Common Stock ceases to be listed on the New York Stock Exchange
and is not otherwise considered to be "regularly traded" on an established
market under Temporary United States Treasury regulations during the relevant
time period described in the preceding paragraph, all Non-United States
Holders (including holders of 5% or less of the outstanding Common Stock)
will generally be subject to United States federal income tax with respect to
gain recognized on disposition of Common Stock. Due to the complexity of
these rules, Non-United States Holders should consult with their tax advisers
before a disposition of Common Stock.

BACKUP WITHHOLDING AND INFORMATION REPORTING

Under Treasury regulations, the Company must report annually to the IRS
the amount of dividends paid to each Non-United States Holder and the federal
income tax, if any, withheld with respect to such dividends. Such
information may be made available by the IRS to the tax authorities in a
foreign country under the provisions of an applicable tax treaty or
information exchange agreement.

Payments of dividends to a Non-United States Holder at an address
outside the United States will generally not be subject to backup
withholding. The payment of the proceeds of the disposition of Common Stock
to or through the United States office of a broker is subject to information
reporting and backup withholding at a rate of 31% unless the owner certifies
its Non-United States status under penalties of perjury or otherwise
establishes an exemption. The payment of the proceeds of the disposition by
a Non-United States Holder of Common Stock to or through a foreign office of a

52
<PAGE>

broker will not be subject to backup withholding. However, information
reporting will apply to such payments of proceeds to or through a foreign
office of a broker that is a United States person or a United States-related
person unless such broker has documentary evidence in its files of the
owner's Non-United States status or the owner otherwise establishes an
exemption.

Proposed United States Treasury regulations not currently in effect
provide, among other things, that payments of dividends to a Non-United
States Holder would generally be subject to information reporting and backup
withholding unless such Non-United States Holder satisfies certain
certification requirements or otherwise establishes an exemption.

Amounts withheld under the backup withholding rules do not constitute a
separate United States federal income tax. Rather, such amounts withheld
from a payment to a Non-United States Holder will be allowed as a credit
against such Non-United States Holder's federal income tax liability and any
amounts withheld in excess of such federal income tax liability may be
refunded to such Non-United States Holder.

ESTATE TAX

Common Stock owned, or treated as owned, by an individual who is a
Non-United States Holder at the time of his death will be included in such
holder's gross estate for United States federal estate tax purposes, unless
an applicable estate tax treaty provides otherwise.

UNDERWRITING

Subject to the terms and conditions set forth in an underwriting
agreement (the "U.S. Underwriting Agreement") among the Company, the Selling
Shareholder and each of the underwriters named below (the "U.S.
Underwriters"), for whom Salomon Brothers Inc, Credit Suisse First Boston
Corporation, Howard, Weil, Labouisse, Friedrichs Incorporated and Morgan
Stanley & Co. Incorporated are acting as representatives (the "U.S.
Representatives"), the Company and the Selling Shareholder have agreed to
sell each of the U.S. Underwriters and each such U.S. Underwriter has
severally agreed to purchase from the Company and the Selling Shareholder the
aggregate number of shares of Common Stock set forth opposite its name below:

NUMBER
U.S. UNDERWRITERS OF SHARES
- ----------------- ----------

Salomon Brothers Inc.............................................
Credit Suisse First Boston Corporation...........................
Howard, Weil, Labouisse, Friedrichs Incorporated.................
Morgan Stanley & Co. Incorporated................................

-----------

Total 4,675,000
-----------
-----------

In addition, the Company and the Selling Shareholder have entered into
an underwriting agreement (the "International Underwriting Agreement") with
the International Underwriters named therein, for whom Salomon Brothers
International Limited, Credit Suisse First Boston (Europe) Limited, Howard,
Weil, Labouisse, Friedrichs Incorporated and Morgan Stanley & Co.
International Limited are acting as representatives (the "International
Representatives"), providing for the concurrent offer and sale of shares of
Common Stock outside the U.S. and Canada. The closing with respect to the
sale of the shares of Common Stock pursuant to the U.S.

<PAGE>

Underwriting Agreement is a condition to the closing with respect to the sale
of the shares of Common Stock pursuant to the International Underwriting
Agreement, and the closing with respect to the sale of the shares of Common
Stock pursuant to the International Underwriting Agreement is a condition to
the closing with respect to sale of the shares of Common Stock pursuant to
the U.S. Underwriting Agreement. The public offering price and underwriting
discounts and concessions per share for the U.S. Offering and the
International Offering will be identical.

The U.S. Underwriting Agreement provides that the several U.S.
Underwriters will be obligated to purchase all the shares of Common Stock
being offered (other than the shares covered by the over-allotment option
described below), if any are purchased. In the event of default by any U.S.
Underwriters, the U.S. Underwriting Agreement provides that, in certain
circumstances, the purchase commitments of the non-defaulting U.S.
Underwriters may be increased or the U.S. Underwriting Agreement may be
terminated.

The U.S. Underwriters have advised the Company that they propose
initially to offer the Common Stock directly to the public at the public
offering price set forth on the cover page of this Prospectus and to certain
dealers at such price less a concession not in excess of $ per share. The
U.S. Underwriters may allow, and such dealers may reallow, a concession not
in excess of $ per share on sales to certain other dealers. After the
initial offering, the price to public and concessions to dealers may be
changed.

Each U.S. Underwriter has severally agreed that, as part of the
distribution of the U.S. Offering, (i) it is not purchasing any shares of
Common Stock for the account of anyone other than a United States or Canadian
Person (as defined below) and (ii) it has not offered or sold, and will not
offer or sell, directly or indirectly, any shares of Common Stock or
distribute this Prospectus to any person outside the United States or Canada
or to anyone other than a United States or Canadian Person. Each
International Underwriter has severally agreed that, as part of the
distribution of the International Offering, (i) it is not purchasing any
shares of Common Stock for the account of any United States or Canadian
Person, and (ii) it has not offered or sold, and will not offer or sell,
directly or indirectly, any shares of Common Stock or distribute any
Prospectus related to the International Offering to any person within the
United States or Canada or to any United States or Canadian Person. The
foregoing limitations do not apply to stabilization transactions or to
certain other transactions specified in the Agreement Between U.S.
Underwriters and International Underwriters described below. "United States
or Canadian Person" means any person who is a natural citizen or resident of
the United States or Canada, any corporation, partnership or other entity
created or organized in or under the laws of the United States or Canada, or
any political subdivision thereof, any estate or trust the income of which is
subject to United States or Canadian federal income taxation, regardless of
the source of its income (other than a foreign branch of any United States or
Canadian Person), and includes any United States or Canadian branch of a
person other than a United States or Canadian Person.

Each U.S. Underwriter that will offer or sell shares of Common Stock in
Canada as part of the distribution has severally agreed that such offers and
sales will be made only pursuant to an exemption from the prospectus
requirements in each jurisdiction in Canada in which such offers and sales
are made. Each International Underwriter has severally agreed that (i) it has
not offered or sold and will not offer or sell in the United Kingdom, by
means of any document, any International Securities other than to persons
whose ordinary business it is to buy or sell shares or debentures, whether as
principal or agent or in circumstances which do not constitute an offer to
the public within the meaning of the Companies Act 1985; (ii) it has complied
with and will comply with all applicable provisions of The Financial Services
Act 1986 with respect to anything done by it in relation to the International
Securities, in, from or otherwise involving the United Kingdom; and (iii) it
has only issued or passed on and will only issue and pass on to any person in
the United Kingdom any document received by it in connection with the issue
of the International Securities if that person is of a kind described in
Article 9(3) of the Financial Services Act 1986 (Investment Advertisements)
(Exemptions) Order 1992 or a person to whom the document may otherwise
lawfully be issued or passed on.

54
<PAGE>

The U.S. Underwriters and the International Underwriters have
entered into an agreement that provides for the coordination of their
activities (the "Agreement Between U.S. Underwriters and International
Underwriters"). Pursuant to the Agreement Between U.S. Underwriters and
International Underwriters, sales may be made between the U.S. Underwriters
and the International Underwriters of such number of shares of Common Stock
as may be mutually agreed. The per share price of any shares of Common Stock
so sold shall be the initial public offering price set forth on the cover
page of this Prospectus, less an amount not greater than the concession to
securities dealers set forth above. To the extent that there are sales
between the U.S. Underwriters and the International Underwriters pursuant to
the Agreement Between U.S. Underwriters and International Underwriters, the
number of shares initially available for sale by the U.S. Underwriters or by
the International Underwriters may be more or less than the amount appearing
on the cover page of this Prospectus.

The Selling Shareholder has granted to the U.S. Underwriters and the
International Underwriters options to purchase up to an additional aggregate
of 701,250 and 123,750 shares of Common Stock, respectively, at the initial
public offering price less the aggregate underwriting discounts and
concessions, solely to cover over-allotments. Either or both options may be
exercised at any time up to 30 days after the date of this Prospectus. To the
extent that the U.S. Underwriters and International Underwriters exercise
such options, each of the U.S. Underwriters or International Underwriters, as
the case may be, will be committed, subject to certain conditions, to
purchase a number of option shares proportionate to such U.S. Underwriter's
or International Underwriter's initial commitment, as applicable.

For a period of 90 days after the date of this Prospectus, the Company,
the Selling Shareholder, and each director and executive officer of the
Company have agreed not to offer, sell, contract to sell or otherwise dispose
of any shares of Common Stock, any other capital stock of the Company or any
security convertible into or exercisable or exchangeable for Common Stock or
any such other capital stock, file or cause to be filed a registration
statement with the Commission in respect of, or establish or increase a put
equivalent position or liquidate or decrease a call equivalent position
within the meaning of Section 16 of the Exchange Act with respect to any
shares of capital stock of the Company or publicly announce the intention to
effect any such transaction, in each case, without the prior written consent
of Salomon Brothers Inc and Salomon Brothers International Limited, except
(a) the Company may register the Common Stock and the Company and the Selling
Shareholder may sell the shares of Common Stock offered in the Offerings, (b)
the Selling Shareholder may sell the shares of Common Stock pursuant to the
exercise of the Underwriters' over-allotment options and (c) the Company may
issue securities pursuant to the Company's stock option or other benefit or
incentive plans maintained for its officers, directors or employees.

No action has been taken or will be taken in any jurisdiction by the
Company, the U.S. Underwriters or the International Underwriters that would
permit a public offering of the shares offered hereby in any jurisdiction
where action for that purpose is required, other than the United States.
Persons who come into possession of this Prospectus are required by the
Company, the U.S. Underwriters and the International Underwriters to inform
themselves about and to observe any restrictions as to the offering of the
shares offered hereby and the distribution of this Prospectus.

The shares of Common Stock may not be offered or sold directly or
indirectly in Hong Kong by means of this document or any other offering
material or document other than to persons whose ordinary business it is to
buy or sell shares or debentures, whether as principal or as agent. Unless
permitted to do so by the securities laws of Hong Kong, no person may issue
or cause to be issued in Hong Kong this document or any amendment or
supplement thereto or any other information, advertisement or document
relating to the shares of Common Stock other than with respect to shares of
Common Stock intended to be disposed of to persons outside Hong Kong or to
persons whose business involves the acquisition, disposal or holding of
securities, whether as principal or as agent.

<PAGE>

The shares of Common Stock have not been registered under the Securities
and Exchange law of Japan and are not being offered and may not be offered or
sold directly or indirectly in Japan or to residents of Japan, except
pursuant to applicable Japanese laws and regulations.

Purchasers of the shares of Common Stock offered hereby may be required
to pay stamp taxes and other charges in accordance with the laws and
practices of the country of purchase in addition to the offering price set
forth on the cover page hereof.

The Company and the Selling Shareholder have agreed to indemnify the
U.S. Underwriters against certain civil liabilities, including certain
liabilities under the Securities Act or contribute to payments the U.S.
Underwriter may be required to make in respect thereof.

LEGAL MATTERS

The legality of the Common Stock offered hereby will be passed upon for
the Company by Crowe & Dunlevy, A Professional Corporation, Oklahoma City,
Oklahoma, and certain legal matters will be passed upon for the Underwriters
by Cravath, Swaine & Moore, New York, New York.

EXPERTS

The consolidated financial statements and related financial statement
schedule of the Company at December 31, 1995 and 1996 and for each of the
three years in the period ended December 31, 1996, included herein or
incorporated herein by reference from the Company's Annual Report on Form
10-K for the year ended December 31, 1996, have been audited by Ernst & Young
LLP, independent auditors, as set forth in their report thereon appearing
herein and incorporated herein by reference. Such consolidated financial
statements and financial statement schedule are included herein or
incorporated herein by reference in reliance upon the report of Ernst & Young
LLP given upon the authority of such firm as experts in auditing and
accounting.

Certain estimates of oil and gas reserves of the Company and related
information as of December 31, 1996 included herein and in the Company's
Annual Report on Form 10-K for the year ended December 31, 1996 and
incorporated herein by reference to such Annual Report on Form 10-K have been
reviewed by Ryder Scott Company as set forth in their report with respect
thereto, and all such information has been so included and incorporated in
reliance on the authority of such firm as experts regarding the matters
addressed in their report.

AVAILABLE INFORMATION

The Company is subject to the informational requirements of the Exchange
Act, and, in accordance therewith, files reports, proxy statements and other
information with the Securities and Exchange Commission (the "Commission").
Reports, proxy statements and other information filed by the Company can be
inspected and copied at the public reference facilities maintained by the
Commission at 450 Fifth Street, N.W., Judiciary Plaza, Room 1024, Washington,
D.C. 20549 and at its Regional Offices at Seven World Trade Center, Suite
1300, New York, New York 10048 and at Citicorp Center, 500 West Madison
Street, Suite 1400, Chicago, Illinois 60611. Copies of such materials also
may be obtained at prescribed rates from the Public Reference Section of the
Commission, 450 Fifth Street, N.W., Judiciary Plaza, Washington, D.C. 20549.
In addition, the Commission maintains a web site that contains reports, proxy
and information statements and other information regarding registrants that
file electronically with the Commission at http://www.sec.gov. The Common
Stock of the Company is listed on the New York Stock Exchange, and similar
information concerning the Company may also be inspected and copied at the
offices of the New York Stock Exchange, 20 Broad Street, New York, New York
10005.

The Company has filed with the Commission a Registration Statement on
Form S-3 (together with any exhibits, amendments and schedules thereto, the
"Registration Statement"), of which this Prospectus constitutes a part, under
the Securities Act. This Prospectus does not contain all the information set
forth in or incorporated by reference in the Registration Statement, certain

<PAGE>

parts of which are omitted in accordance with the rules and regulations of
the Commission. For further information with respect to the Company and the
shares offered hereby, reference is made to the Registration Statement.
Copies of the Registration Statement are on file at the offices of the
Commission and may be obtained upon payment of prescribed fees, or may be
examined without charge at the Public Reference Section of the Commission
described above. Statements contained in this Prospectus concerning the
provisions of any contract, agreement or other document filed with the
Registration Statement as exhibits are necessarily summaries of such
documents, and each such statement is qualified in its entirety by reference
to the copy of the applicable document filed with the Commission.

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

The following documents heretofore filed by the Company with the
Commission pursuant to the Exchange Act are incorporated herein by reference:
(a) Annual Report on Form 10-K for the year ended December 31, 1996; and (b)
the description of the Company's Common Stock contained in the Company's
Registration Statement on Form 8-A dated October 19, 1993. All documents
filed by the Company pursuant to Section 13(a), 13(c), 14 or 15(d) of the
Exchange Act after the date of this Prospectus and prior to the termination
of the Offerings shall be deemed to be incorporated herein by reference and
to be a part hereof from the date of filing of such documents.

Any statement contained in a document all or a portion of which is
incorporated herein shall be deemed to be modified or superseded for purposes
of this Prospectus to the extent that a statement contained herein modifies
or supersedes such statement. Any such statement so modified or superseded
shall not be deemed, except as so modified or superseded, to constitute a
part of this Prospectus.

The Company will furnish without charge to each person, including any
beneficial owner of Common Stock, to whom a copy of this Prospectus has been
delivered, upon the written or oral request of such person, a copy of any of
the foregoing documents incorporated by reference herein, except for the
exhibits to such documents (unless such exhibits are specifically
incorporated by reference into the information that this Prospectus
incorporates). Requests for such copies should be directed to Louis Dreyfus
Natural Gas Corp., Attention: Investor Relations, 14000 Quail Springs
Parkway, Suite 600, Oklahoma City, Oklahoma 73134 (telephone: (405) 749-1300).

CERTAIN DEFINITIONS

The terms defined in this section are used throughout this Prospectus:

BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to oil or other liquid hydrocarbons.

BCF. Billion cubic feet.

BCFE. Billion cubic feet of natural gas equivalent, determined using
the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

BTU. British thermal unit, which is the heat required to raise the
temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

BBTU. Billion Btus.

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

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

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

<PAGE>

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

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

ESTIMATED FUTURE NET REVENUES. Revenues from production of oil and gas,
net of all production-related taxes, lease operating expenses and capital
costs.

EXPLORATORY WELL. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.

FINDING COST. Total costs incurred to acquire, explore and develop oil
and gas properties divided by the increase in proved reserves through
acquisition of proved properties, extensions and discoveries, improved
recoveries and revisions of previous estimates.

GROSS ACRE. An acre in which a working interest is owned.

GROSS WELL. A well in which a working interest is owned.

INFILL DRILLING. Drilling for the development and production of proved
undeveloped reserves that lie within an area bounded by producing wells.

LEASE OPERATING EXPENSE. All direct costs associated with and necessary
to operate a producing property.

MBBL. Thousand barrels.

MBTU. Thousand Btus.

MCF. Thousand cubic feet.

MCFE. Thousand cubic feet of natural gas equivalent, determined using
the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

MMBBL. Million barrels.

MMBTU. Million Btus.

MMCF. Million cubic feet.

MMCFE. Million cubic feet of natural gas equivalent, determined using
the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

NATURAL GAS LIQUIDS. Liquid hydrocarbons which have been extracted from
natural gas (e.g., ethane, propane, butane and natural gasoline).

NET ACRES OR NET WELLS. The sum of the fractional working interests
owned in gross acres or gross wells.

OVERRIDING ROYALTY INTEREST. An interest in an oil and gas property
entitling the owner to a share of oil and gas production free of well or
production costs.

PRESENT VALUE. When used with respect to oil and gas reserves, present
value means the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production and future
development costs, using prices and costs in effect as of the date of the
report or estimate, without giving effect to non-property related expenses
such as general and administrative expenses, debt service and future income

<PAGE>

tax expense or to depreciation, depletion and amortization, discounted using
an annual discount rate of 10%. The prices used to estimate future revenues
include the effects of the Company's Fixed-Price Contracts except where
otherwise specifically noted. Estimated quantities of proved reserves are
determined without regard to such contracts.

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

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

PROVED RESERVES. The estimated quantities of oil and gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions.

PROVED UNDEVELOPED RESERVES. Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion.

RECOMPLETION. The completion for production of an existing wellbore in
another formation from that in which the well has previously been completed.

RESERVE LIFE. A measure of how long it will take to produce a quantity
of reserves, calculated by dividing estimated reserves by production for the
twelve months immediately preceding the date of determination (in gas
equivalents).

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.

<PAGE>

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PAGE
----
Report of Independent Auditors.................................... F-2
Consolidated Balance Sheets:
December 31, 1995 and 1996................................... F-3
Consolidated Statements of Income:
Years ended December 31, 1994, 1995 and 1996................. F-4
Consolidated Statements of Stockholders' Equity:
Years ended December 31, 1994, 1995 and 1996................. F-5
Consolidated Statements of Cash Flows:
Years ended December 31, 1994, 1995 and 1996................. F-6
Notes to Consolidated Financial Statements ....................... F-7

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, 1995 and 1996,
and the related consolidated statements of income, stockholders' equity and
cash flows for each of the three years in the period ended December 31, 1996.
These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of the
Company at December 31, 1995 and 1996, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1996 in conformity with generally accepted accounting
principles.

As discussed in Note 1 of the notes to the consolidated financial
statements, effective October 1, 1995, the Company adopted Statement of
Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of."

ERNST & YOUNG LLP

Oklahoma City, Oklahoma
January 31, 1997

F-2

<PAGE>

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

A S S E T S
<TABLE>
<CAPTION>

DECEMBER 31,
-----------------------
1995 1996
--------- ---------
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents........................ $ 1,584 $ 7,749
Receivables:
Oil and gas sales........................... 23,443 33,579
Joint interest and other, net............... 5,300 5,358
Deposits......................................... 3,900 5,592
Inventory and other.............................. 3,095 3,147
--------- ---------
Total current assets........................ 37,322 55,425
--------- ---------
PROPERTY AND EQUIPMENT, at cost, based on
successful efforts accounting............... 778,348 922,721
Less accumulated depreciation, depletion,
amortization and impairment................. (188,495) (250,856)
--------- ---------
589,853 671,865
--------- ---------
OTHER ASSETS, net............................... 7,762 6,323
--------- ---------
$ 634,937 $ 733,613
--------- ---------
--------- ---------

L I A B I L I T I E S A N D S T O C K H O L D E R S ' E Q U I T Y

CURRENT LIABILITIES
Accounts payable................................. $ 21,458 $ 36,415
Accrued liabilities.............................. 7,912 7,251
Revenues payable................................. 4,687 7,419
--------- ---------
Total current liabilities................... 34,057 51,085
BANK DEBT........................................ 216,000 245,000
SUBORDINATED DEBT................................ 98,760 98,907
DEFERRED REVENUE................................. 25,627 19,049
DEFERRED HEDGING GAINS........................... -- 26,226
OTHER LONG-TERM LIABILITIES...................... 4,285 6,961
DEFERRED INCOME TAXES............................ 13,627 22,692
--------- ---------
392,356 469,920
--------- ---------

COMMITMENTS AND CONTINGENCIES (Notes 7 and 11)
STOCKHOLDERS' EQUITY
Preferred stock, par value $.01; 10 million
shares authorized; no shares outstanding....... -- --
Common stock, par value $.01; 100 million shares
authorized; issued and outstanding,
27,800,000 and 27,800,750 shares, respectively. 278 278
Additional paid-in capital....................... 197,291 197,301
Retained earnings................................ 45,012 66,114
--------- ---------
242,581 263,693
--------- ---------
$ 634,937 $ 733,613
--------- ---------
--------- ---------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

F-3
<PAGE>

LOUIS DREYFUS NATURAL GAS CORP.
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------
1994 1995 1996
-------- -------- --------
<S> <C> <C> <C>
REVENUES
Oil and gas sales ................................. $138,584 $163,366 $185,558
Other income (loss) ............................... 1,953 (418) 3,947
-------- -------- --------
140,537 162,948 189,505
-------- -------- --------

EXPENSES
Operating costs ................................... 33,713 35,352 44,615
General and administrative ........................ 15,309 16,631 16,325
Exploration costs ................................. -- -- 4,965
Depreciation, depletion, and amortization ......... 53,321 57,796 65,278
Impairment of oil and gas properties .............. 5,300 15,694 --
Interest .......................................... 16,856 21,736 26,822
-------- -------- --------
124,499 147,209 158,005
-------- -------- --------
Income before income taxes ........................ 16,038 15,739 31,500
Income taxes ...................................... 5,292 4,722 10,398
-------- -------- --------
NET INCOME ........................................ $ 10,746 $ 11,017 $ 21,102
-------- -------- --------
-------- -------- --------

Net income per share .............................. $ .39 $ .40 $ .76
-------- -------- --------
-------- -------- --------
Weighted average common shares outstanding......... 27,800 27,800 27,800
-------- -------- --------
-------- -------- --------
</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>
COMMON STOCK
---------------- ADDITIONAL TOTAL
PAR PAID-IN RETAINED STOCKHOLDERS'
SHARES VALUE CAPITAL EARNINGS EQUITY
------ ---- -------- ------- --------
<S> <C> <C> <C> <C> <C>
BALANCE AT DECEMBER 31, 1993 ........ 27,800 $278 $190,291 $23,249 $213,818
Net income .......................... -- -- -- 10,746 10,746
------ ---- -------- ------- --------
BALANCE AT DECEMBER 31, 1994 ........ 27,800 278 190,291 33,995 224,564
Contribution by affiliate ........... -- -- 7,000 -- 7,000
Net income .......................... -- -- -- 11,017 11,017
------ ---- -------- ------- --------
BALANCE AT DECEMBER 31, 1995 ........ 27,800 278 197,291 45,012 242,581
Exercise of stock options ........... 1 -- 10 -- 10
Net income .......................... -- -- -- 21,102 21,102
------ ---- -------- ------- --------
BALANCE AT DECEMBER 31, 1996 ........ 27,801 $278 $197,301 $66,114 $263,693
------ ---- -------- ------- --------
------ ---- -------- ------- --------
</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,
--------------------------------------
1994 1995 1996
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income .............................................. $ 10,746 $ 11,017 $ 21,102
Items not affecting cash flows:
Depreciation, depletion, amortization and impairment .. 61,146 74,097 65,278
Deferred income taxes ................................. 3,183 3,348 9,065
Exploration costs ..................................... -- -- 4,965
Other ................................................. 1,064 640 571
--------- --------- ---------
76,139 89,102 100,981
Net change in operating assets and liabilities:
Accounts receivable ................................... (4,441) (8,578) (10,194)
Deposits .............................................. (1,265) (679) (1,692)
Inventory and other ................................... (113) (1,074) (52)
Accounts payable ...................................... 5,939 5,982 14,957
Accrued liabilities ................................... 4,267 40 (661)
Revenues payable ...................................... 368 412 2,732
Deferred revenue ...................................... -- 4,310 (4,310)
--------- --------- ---------
80,894 89,515 101,761
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Oil and gas property expenditures ....................... (103,796) (185,258) (134,222)
Additions to other property and equipment ............... (1,738) (1,528) (17,660)
Proceeds from sale of property and equipment ............ 3,947 15,125 1,101
Change in other assets (1,382) 121 (76)
--------- --------- ---------
(102,969) (171,540) (150,857)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term bank borrowings ................. 50,928 240,350 241,240
Repayments of long-term bank borrowings ................. (131,750) (140,747) (212,240)
Net proceeds from issuance of subordinated debt ......... 96,317 -- --
Repayments to affiliate ................................. (6,736) -- --
Proceeds from stock options exercised ................... -- -- 10
Proceeds from issuance of fixed-price contract .......... 22,028 -- --
Change in deferred revenue .............................. (16,727) (18,590) (2,268)
Change in deferred hedging gains ........................ -- -- 26,226
Change in other long-term liabilities ................... (359) (384) 2,293
--------- --------- ---------
13,701 80,629 55,261
--------- --------- ---------
Change in cash and cash equivalents ..................... (8,374) (1,396) 6,165
Cash and cash equivalents, beginning of year ............ 11,354 2,980 1,584
--------- --------- ---------
Cash and cash equivalents, end of year .................. $ 2,980 $ 1,584 $ 7,749
--------- --------- ---------
--------- --------- ---------

SUPPLEMENTAL DISCLOSURES OF CASH FLOW
INFORMATION
Interest paid, net of capitalized interest .............. $ 16,983 $ 18,851 $ 25,254
Income taxes paid ....................................... 225 3,533 1,387
--------- --------- ---------
$ 17,208 $ 22,384 $ 26,641
--------- --------- ---------
--------- --------- ---------
</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

The accounting policies of Louis Dreyfus Natural Gas Corp. ("LDNG" or the
"Company") reflect industry practices and conform to generally accepted
accounting principles. The more significant of such policies are briefly
described below.

GENERAL. LDNG is an independent energy company primarily engaged in the
acquisition, development, exploration, production and marketing of natural gas
and crude oil. At December 31, 1996, approximately 74% of the Company's common
stock was owned by various subsidiaries of Societe Anonyme Louis Dreyfus & Cie
(collectively "S.A. Louis Dreyfus et Cie"). See Note 6 -- Transactions with
Related Parties and Note 8 -- Employee Benefit Plans.

PRINCIPLES OF CONSOLIDATION AND BASIS OF PRESENTATION. The accompanying
consolidated financial statements include the accounts of LDNG and its
wholly-owned subsidiaries after elimination of all material intercompany
accounts and transactions. Certain reclassifications have been made in the
financial statements for the years ended December 31, 1994 and 1995 to
conform to the financial statement presentation for the year ended
December 31, 1996.

USE OF ESTIMATES. The preparation of the financial statements in
conformity with generally accepted accounting principles requires management
to make estimates and assumptions that affect the amounts reported in the
financial statements and accompanying notes. Actual results could differ
from those estimates.

CASH AND CASH EQUIVALENTS. Cash and cash equivalents consist of all demand
deposits and funds invested in short-term investments with original maturities
of three months or less.

CONCENTRATION OF CREDIT RISK. The Company sells oil and natural gas to
various customers, participates with other parties in the drilling, completion
and operation of oil and natural gas wells and enters into long-term energy
swaps and physical delivery contracts. The majority of the Company's accounts
receivable are due from purchasers of oil and natural gas and from fixed-price
contract counterparties. Certain of these receivables are subject to collateral
or margin requirements. The Company has established procedures to monitor
credit risk and has not experienced significant credit losses in prior years.
See Note 11 -- Fixed-Price Contracts -- Credit Risk. As of December 31, 1995
and 1996, the Company's joint interest and other receivables are shown net of
allowance for doubtful accounts of $1.1 million.

INVENTORY. Inventory consists primarily of tubular goods and is carried at
the lower of cost or market.

PROPERTY AND EQUIPMENT. The Company utilizes the successful efforts method
of accounting for oil and natural gas producing activities. Costs incurred in
connection with the drilling and equipping of exploratory wells are capitalized
as incurred. If proved reserves are not found, such costs are charged to
expense. Other exploration costs, including delay rentals, are charged to
expense as incurred. Development costs, which include the costs of drilling and
equipping development wells, whether successful or unsuccessful, are capitalized
as incurred. All general and administrative costs are expensed as incurred.
Depletion of acquired properties is computed by the unit-of-production method on
a field basis using proved reserves. Depreciation, depletion and amortization
of capitalized development costs, which include the costs of unsuccessful
development drilling, is computed by the unit-of-production method on a field
basis using proved developed reserves.

In 1995, the Company adopted the provisions of Statement of Financial
Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of " ("SFAS 121"). Pursuant to
SFAS 121, the Company's oil and gas properties are reviewed on a field-by-field
basis for

F-7

<PAGE>

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

indications of impairment. The implementation of SFAS 121 resulted in an
impairment charge of $15.7 million for the year ended December 31, 1995.

The Company provides for the estimated cost, at current prices, of
dismantling and removing oil and gas production facilities. Such estimated
costs are capitalized and amortized over the life of the related oil and gas
property. As of December 31, 1996, the Company had accrued estimated total
future dismantling and restoration costs of $1.9 million.

Depreciation of other property and equipment is provided by using the
straight-line method over estimated useful lives of three to 20 years.

DEBT ISSUANCE COSTS. Debt issuance costs are amortized over the term of
the associated debt instrument using the straight-line method. The unamortized
balance of such costs included in other assets as of December 31, 1995 and 1996,
was $5.3 million and $4.2 million, respectively.

OIL AND GAS SALES AND GAS IMBALANCES. Oil and gas revenues are recognized
as oil and gas is produced and sold. The Company uses the sales method of
accounting for gas imbalances in those circumstances where the Company has
underproduced or overproduced its ownership percentage in a property. Under
this method, a liability is recorded to the extent that the Company's
overproduced position in a reservoir cannot be recouped through the production
of remaining reserves. The Company's net underproduced imbalance position at
December 31, 1995 and 1996 was not material.

INCOME TAXES. The Company files a consolidated United States income tax
return which includes the taxable income or loss of its subsidiaries. Deferred
federal and state income taxes are provided on all significant temporary
differences between the financial statement carrying amounts of assets and
liabilities and their respective tax bases.

HEDGING. The Company reduces its exposure to unfavorable changes in oil
and natural gas prices by utilizing fixed-price physical delivery contracts,
energy swaps, collars, futures contracts, basis swaps and options
(collectively "Fixed-Price Contracts"). The Company has also entered into
interest rate swap contracts to reduce its exposure to interest rate
fluctuations. Gains and losses from hedging transactions are recognized in
income and are reflected as cash flows from operating activities in the
periods for which the underlying commodity or interest rate was hedged. If
the necessary correlation (generally a correlation coefficient of 80% or
greater) to the commodity or interest rate being hedged ceases to exist, the
differential between the market value and the carrying value of the affected
contracts is recognized as a gain or loss in the period that the permanent
loss of correlation is identified, with future changes in market value
recognized as a gain or loss in the period of change. When a temporary loss
of correlation has occurred, the anomalous basis differential attributable to
the affected contracts is recognized as a gain or loss in the period in which
the loss of effectiveness is identified. See Note 4 -- Long-Term Debt,
Note 10 -- Financial Instruments and Note 11 -- Fixed-Price Contracts. The
Company does not hold or issue financial instruments with leveraged features.

EARNINGS PER SHARE. Primary and fully diluted earnings per common share
are based on the weighted average number of shares of Common Stock outstanding.
The effects of common equivalent shares were immaterial or were not dilutive for
each of the periods presented. Accordingly, primary and fully diluted earnings
per share are the same for all periods presented.

STOCK OPTIONS AND EQUIVALENT RIGHTS. No accounting is made with respect to
stock options until they are exercised, as all options have been granted at a
price equal to the market value of the Company's Common Stock at the date of
grant. Upon exercise, the excess of the proceeds over the par value of the
shares issued is credited to additional paid-in capital. For stock equivalent
rights, the value to be paid upon exercise is

F-8

<PAGE>

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

charged to earnings over the respective vesting period or as the price of the
Company's Common Stock changes after such rights have become fully vested.
See Note 8 -- Employee Benefit Plans.

NOTE 2 -- PROPERTY AND EQUIPMENT

CAPITALIZED COSTS. The Company's oil and gas acquisition, exploration and
development activities are conducted primarily in Texas, Oklahoma and New
Mexico. The following table summarizes the capitalized costs associated with
these activities:

DECEMBER 31,
----------------------
1995 1996
---------- ----------
(IN THOUSANDS)
<S> <C> <C>
Oil and gas properties:
Proved ........................................... $ 765,278 $ 889,240
Unproved ......................................... 2,280 6,657
Accumulated depreciation, depletion, amortization
and impairment ................................. (182,658) (243,640)
--------- ---------
584,900 652,257
--------- ---------

Other property and equipment ..................... 10,790 26,824
Accumulated depreciation ......................... (5,837) (7,216)
--------- ---------
4,953 19,608
--------- ---------
$ 589,853 $ 671,865
--------- ---------
--------- ---------
</TABLE>

Depreciation, depletion and amortization expense ("DD&A") of oil and gas
properties per Mcfe was $.92, $.88 and $.82 for the years ended December 31,
1994, 1995 and 1996, respectively. Such amounts do not include a $5.3 million
impairment recorded in connection with the sale of an offshore property in 1994
or a $15.7 million impairment recorded in conjunction with the adoption of
SFAS 121 in 1995. See Note 1 -- Significant Accounting Policies. For the years
ended December 31, 1995 and 1996, the Company capitalized $266,000 and $431,000
of interest, respectively, in connection with its exploration and development
activities. No interest was capitalized for the year ended December 31, 1994.

Unproved properties at December 31, 1996 consist primarily of lease
acquisition costs incurred during 1996. The Company will evaluate such
properties over their respective lease terms.

COSTS INCURRED. The following table summarizes the costs incurred in the
Company's acquisition, exploration and development activities for the years
ended December 31, 1994, 1995 and 1996, respectively.

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------
1994 1995 1996
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition costs:
Proved ............................ $ 36,575 $118,652 $ 36,125
Unproved .......................... 4,953 1,717 6,934
-------- -------- --------
41,528 120,369 43,059
Exploration costs ................. -- 391 10,610
Development costs ................. 67,764 64,498 80,553
-------- -------- --------
$109,292 $185,258 $134,222
-------- -------- --------
-------- -------- --------
</TABLE>

F-9

<PAGE>

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

NOTE 3 -- PROPERTY ACQUISITIONS

OIL AND GAS PROPERTIES. In November 1993, the Company acquired certain
producing oil and gas properties in the Sonora area of West Texas ("Sonora").
The associated purchase price included the assumption of a deferred
recoupment liability owed to a purchaser of certain gas production from the
acquired properties. For the years ended December 31, 1994 and 1995, the
purchaser recouped $16.6 million and $18.0 million, respectively, by taking
gas in excess of contractually required volumes without payment therefor and
crediting the value of such gas against the deferred recoupment liability.
The amounts recouped by the purchaser have been reflected as gas sales and as
cash flows from operating activities for 1994 and 1995; the corresponding
reduction in the deferred recoupment liability, which was fully recouped as
of December 31, 1995, has been presented as cash flows used in financing
activities.

In July 1995, the Company purchased certain additional producing oil and
gas properties in Sonora for $86.6 million. The acquired oil and gas
properties consisted of approximately 700 producing wells, 100,000 gross
acres and an estimated 139 Bcfe of proved reserves. The acquisition was
accounted for as a purchase; accordingly, the results of operations relating
to this acquisition are included in the Company's financial results for the
periods subsequent to closing. The following unaudited pro forma results of
operations data gives effect to the acquisition as if the transaction had
been consummated as of January 1, 1994 and 1995, respectively. The unaudited
pro forma information is presented for illustrative purposes only and is not
necessarily indicative of the actual results that would have occurred had the
acquisition been consummated as of January 1, 1994 or 1995, respectively, or
of future results of operations. The information has been adjusted for (1)
oil and gas sales and related operating costs, (2) amortization of the oil
and gas properties based on the purchase price, (3) incremental general and
administrative expenses associated with the ownership of the properties, and
(4) incremental interest expense resulting from the borrowings made under the
Credit Facility, as hereinafter defined, to fund the acquisition.
<TABLE>
<CAPTION>

YEARS ENDED DECEMBER 31,
------------------------
1994 1995
---------- ----------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
<S> <C> <C>
Unaudited pro forma information:
Revenues............................... $162,816 $176,933
Net income............................. 12,163 12,158
Net income per share................... .44 .44
</TABLE>

During 1994, 1995 and 1996, the Company made numerous other acquisitions
of proved oil and gas properties, the net purchase price of which aggregated
$36.6 million, $32.1 million and $36.1 million, respectively. The results of
operations related to such acquisitions have been included in the
accompanying statements of income and cash flows for the periods subsequent
to the closing of each transaction.

OTHER. In November 1996, the Company purchased a 75-mile pipeline
located in Sonora for $15.2 million, including the associated compression
facilities and transportation contracts. Amortization of the purchase price
is computed by the unit-of-production method using proved reserves.

F-10

<PAGE>

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

NOTE 4 -- LONG-TERM DEBT

Long-term debt consists of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------
1995 1996
---------- ----------
(IN THOUSANDS)
<S> <C> <C>
BANK DEBT
Revolving bank credit facility (A)........... $209,000 $235,000
Other lines of credit (B).................... 7,000 10,000
-------- --------
216,000 245,000
SUBORDINATED DEBT (C)........................ 98,760 98,907
-------- --------
$314,760 $343,907
-------- --------
-------- --------
</TABLE>
(A) The Company has a revolving credit facility with a syndicate of
banks, as most recently amended July 31, 1996 to reduce the pricing and
extend the maturity (the "Credit Facility"), which provides up to $300
million in borrowings and letters of credit (the "Commitment"). The
Commitment reduces at the rate of $18.75 million per quarter commencing
October 31, 1999 through July 31, 2003. Borrowings and letters of credit
under the Credit Facility are limited to the lesser of the Commitment or the
Oil and Gas Reserves Loan Value. The Oil and Gas Reserves Loan Value is a
borrowing base calculation determined by a periodic valuation of the
Company's oil and gas reserves and Fixed-Price Contracts. The Oil and Gas
Reserves Loan Value was most recently reset in December 1996 at $330 million.
The maximum amount of letters of credit available for issuance under the
Credit Facility is limited to $75 million. The Company has relied upon the
Credit Facility to provide funds for acquisitions and to provide letters of
credit to meet the Company's margin requirements under Fixed-Price Contracts.
See Note 11 -- Fixed-Price Contracts. As of December 31, 1996, the Company
had $235.0 million of principal and $3.3 million of letters of credit
outstanding under the Credit Facility.

F-11

<PAGE>

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

For each interest rate swap, the differential between the fixed rate and
the floating rate multiplied by the notional amount is the swap gain or
loss. Such gain or loss is included in interest expense in the period for
which the interest rate exposure was hedged. If an interest rate swap is
liquidated or sold prior to maturity, the gain or loss is deferred and
amortized as interest expense over the original contract term. At
December 31, 1995 and 1996, the amount of such deferrals was not material.

(B) The Company has certain other unsecured lines of credit available to it,
which aggregated $53 million as of December 31, 1996. Such short-term
lines of credit are primarily used to meet margining requirements under
Fixed-Price Contracts and for working capital purposes. At December 31,
1996, the Company had $10 million of indebtedness and $17.9 million of
letters of credit outstanding under these credit lines. Repayment of
indebtedness thereunder is expected to be made through Credit Facility
availability.

(C) In June 1994, the Company completed the sale of $100 million of 9-1/4%
Senior Subordinated Notes due 2004 (the "Notes") in a public offering. The
Notes were sold at 98.534% of face value to yield 9.48% to maturity.
Interest is payable semi-annually on June 15 and December 15. The
associated indenture agreement contains certain restrictive covenants which
limit, among other things, the prepayment of the Notes, the incurrence of
additional indebtedness, the payment of dividends and the disposition of
assets.

The amount of required principal payments for the next five years and
thereafter as of December 31, 1996 are as follows: 1997 - $0; 1998 - $0; 1999 -
$0; 2000 - $42.1 million; 2001 - $75.0 million; 2002 and thereafter - $227.9
million.

NOTE 5 -- INCOME TAXES

The significant components of income tax expense for the years ended
December 31, 1994, 1995 and 1996 are as follows:

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------------------
1994 1995 1996
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Current tax expense:
Federal ............. $ 1,716 $ 1,195 $ 1,159
State ............... 393 179 174
------- ------- -------
2,109 1,374 1,333
------- ------- -------

Deferred tax expense:
Federal ............. 3,056 3,033 8,271
State ............... 127 315 794
------- ------- -------
3,183 3,348 9,065
------- ------- -------
$ 5,292 $ 4,722 $10,398
------- ------- -------
------- ------- -------

</TABLE>

F-12
<PAGE>

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

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

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------
1994 1995 1996
-------- ------- --------
<S> <C> <C> <C>
(IN THOUSANDS)
Computed "expected" income tax ......................... $ 5,613 $ 5,509 $11,025
Increases (reductions) in taxes resulting from:
State income taxes, net of federal benefit ........ 338 321 629
Permanent differences (principally related to basis
differences in oil and gas properties) ....... 298 861 265
Section 29 credits ................................ (2,269) (2,090) (2,028)
Other ............................................. 1,312 121 507
------- ------- --------
$ 5,292 $ 4,722 $10,398
------- ------- --------
------- ------- --------
</TABLE>

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,
--------------------------
1995 1996
------- -------
<S> <C> <C>
(IN THOUSANDS)
Deferred tax liabilities:
Capitalized costs and related depreciation,
depletion, amortization and impairment ... $25,653 $43,416
Other ......................................... 817 825
------- -------
26,470 44,241
------- -------
Deferred tax assets:
Deferred revenue and hedging gains ............ 9,738 17,251
Alternative minimum tax credits ............... 3,105 4,298
------- -------
12,843 21,549
------- -------
Net deferred tax liability .................... $13,627 $22,692
------- -------
------- -------
</TABLE>

In 1995, the Company recorded a $7.0 million capital contribution and a
corresponding reduction in deferred taxes payable in connection with the
utilization of certain tax attributes in its federal income tax return. Such
attributes were generated prior to the Company's initial public offering but
were not deducted in the consolidated federal income tax return of the
Company's U.S. parent.

NOTE 6 -- TRANSACTIONS WITH RELATED PARTIES

FIXED-PRICE CONTRACT ACTIVITY. In 1991, one long-term sales contract
was assigned to the Company at S.A. Louis Dreyfus et Cie's net carrying value
of $9.7 million. Amortization of this contract approximated $2.5 million and
$607,000 for the years ended December 31, 1994 and 1995, respectively, and
has been reflected in the accompanying statements of income as a reduction of
oil and gas sales. This contract expired in March 1995.

In 1993, the Company entered into a fixed-price sales contract with S.A.
Louis Dreyfus et Cie covering 33 Bcf of natural gas over a five-year period
beginning in 1996, at a weighted-average fixed price of $2.49 per Mcf. In
conjunction with the execution of a 75-Bcf physical delivery contract with a
third party in July 1995, the Company canceled 3 Bcf of fixed-price sales
under this contract. The Company received approximately $760,000 as
consideration for this partial cancellation. Such consideration was deferred
and subsequently amortized into earnings during 1996 (the period covered by
the term of the canceled contract volumes).

F-13
<PAGE>

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

The Company uses the commodity trading resources of S.A. Louis Dreyfus
et Cie when purchasing natural gas futures contracts on the NYMEX. In that
regard, the Company reimburses S.A. Louis Dreyfus et Cie for margin posted by
the affiliate on behalf of the Company. At December 31, 1995 and 1996,
margin of $3.9 million and $5.6 million, respectively, had been posted on the
Company's behalf by S.A. Louis Dreyfus et Cie under this arrangement.

In 1994, the Company entered into two Fixed-Price Contracts with S.A.
Louis Dreyfus et Cie. The first of these was a fixed-price sale which hedged
20 Bcf of natural gas production from certain wells in the Sonora area,
commencing January 1, 1996. This natural gas swap provided a weighted-
average fixed price of approximately $2.18 per Mcf. In January 1996, the
Company canceled this contract and received $1.6 million upon termination.
The proceeds are being amortized into earnings over the original 19-month
term of the contract. The second contract, also a natural gas swap, provided
for the purchase by the Company of 1.8 Bcf of natural gas during the first
quarter of 1995, at a fixed price of $1.81 per Mcf.

Also during 1994, in connection with the monthly purchase of natural gas
to supply certain of the Company's fixed-price delivery contracts, the
Company purchased 318 MMcf from S.A. Louis Dreyfus et Cie at an average price
of $2.21 per Mcf and sold 45 MMcf to S.A. Louis Dreyfus et Cie at an average
price of $2.30 per Mcf.

In 1996, the Company entered into a ten-year, 20-Bcf fixed-price sale
with Duke/Louis Dreyfus L.L.C., an affiliate, which commences June 1997. The
fixed prices in this contract range from $2.05 to $2.51 per MMBtu.

GENERAL AND ADMINISTRATIVE EXPENSE. In September 1993, the Company
entered into a services agreement with S.A. Louis Dreyfus et Cie pursuant to
which the Company is billed for certain administrative and support services
provided by S.A. Louis Dreyfus et Cie at amounts approximating cost. Amounts
paid to S.A. Louis Dreyfus et Cie under this agreement (principally for
insurance costs) aggregated $605,000, $756,000 and $907,000 for the years
ended December 31, 1994, 1995 and 1996, respectively.

INTEREST. In October 1992, S.A. Louis Dreyfus et Cie assigned a third
party interest rate swap contract to the Company with a declining notional
amount of approximately $94 million pursuant to which the Company paid an
annual fixed interest rate of 5.9%. This contract matured in 1995.

OTHER. At December 31, 1995 and 1996, the Company owed S.A. Louis
Dreyfus et Cie approximately $.5 million and $2.3 million, respectively,
principally for posted margin and miscellaneous general and administrative
expenses. Such amounts are included in accounts payable in the accompanying
balance sheets.

NOTE 7 -- COMMITMENTS AND CONTINGENCIES

LITIGATION. On December 22, 1995, the United States District Court for
the Western District of Oklahoma entered a $10.8 million judgment in favor of
the Company against Midcon Offshore, Inc. ("Midcon") in connection with
non-performance by Midcon under an agreement to purchase a certain offshore
oil and gas property. The judgment amount was in addition to a $1.3 million
deposit previously paid by Midcon to the Company. As a result of the
judgment, the Company recognized the $1.3 million deposit paid by Midcon as
other income in 1995. In January 1996, Midcon delivered a $10.8 million
promissory note to the Company secured by first and second liens on assets of
Midcon, payable in full on or before December 15, 1996 in settlement of
disputes in connection with this litigation. During 1996, the Company
received principal and interest payments on the promissory note totaling $1.7
million which have been reflected in the accompanying financial statements as
other income. On December 16, 1996, Midcon filed for protection from its
creditors under Chapter 11 of the United States Bankruptcy Code in the United
States Bankruptcy Court, Southern District of Texas, Corpus

F-14
<PAGE>

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

Christi Division. On January 24, 1997, Midcon filed an action in the
bankruptcy court alleging that Midcon's action in connection with the
settlement constituted fraudulent transfers or avoidable preferences and
seeking a return of amounts paid. The Company considers the allegations of
Midcon to be without merit and will vigorously defend against this action.
Collection of the remaining unpaid interest and principal on the Midcon note
is uncertain and no amounts have been recorded with respect thereto in the
accompanying financial statements as of December 31, 1996. The Company will
recognize income as any payments are received.

The Company is not a defendant in any additional pending legal
proceedings other than routine litigation incidental to its business. While
the ultimate results of these proceedings cannot be predicted with certainty,
the Company does not believe that the outcome of these matters will have a
material adverse effect on the Company.

RENTAL COMMITMENTS. Minimum annual rental commitments as of December
31, 1996 under noncancelable office space leases are as follows: 1997 - $1.8
million; 1998 - $1.7 million; 1999 and thereafter - $0. Approximately $1.8
million of such rental commitments is included in other long-term liabilities
as of December 31, 1996, presented net of estimated future rental income of
$1.0 million to be received over the next two years.

NOTE 8 -- EMPLOYEE BENEFIT PLANS

401(k) AND PENSION PLANS. Through June 30, 1994, the employees of the
Company were eligible for pensions under a defined benefit plan sponsored by
S.A. Louis Dreyfus et Cie. Benefits under the plan were based on years of
service and compensation levels. The Company's net periodic pension costs,
which were an allocation of S.A. Louis Dreyfus et Cie's net pension costs of
the plan attributable to the employees of the Company, totaled $405,000 for
the year ended December 31, 1994, including termination costs. At June 30,
1994, the Company's participation in S.A. Louis Dreyfus et Cie's pension plan
was discontinued.

S.A. Louis Dreyfus et Cie also sponsored a plan to provide retirement
benefits under Section 401(k) of the Internal Revenue Code for all employees,
including those of the Company, who have completed a specified term of
service. Employee contributions, up to 6% of compensation, were matched 50%
by the Company. The Company's contributions vested over a five-year period
and totaled $276,000 for the year ended December 31, 1994. The Company's
participation in this plan was terminated on December 31, 1994.

In December 1994, the Board of Directors adopted the Louis Dreyfus
Natural Gas Profit Sharing and 401(k) Plan and Trust Agreement (the "401(k)
Plan"). Effective January 1, 1995, the Company's employees who have completed
a specified term of service are eligible for participation in the 401(k)
Plan. Employee contributions can be made up to 6% of compensation. Employer
contributions are discretionary. Employees vest in Company contributions at
20% per year of service. For the years ended December 31, 1995 and 1996, the
Company contributed $788,000 and $878,000, respectively, to the 401(k) Plan.

STOCK COMPENSATION PLANS. Certain officers of the Company are
participants in the Louis Dreyfus Deferred Compensation Stock Equivalent Plan
sponsored by S.A. Louis Dreyfus et Cie. Under this plan, participants were
awarded stock equivalent rights ("SERs") expressed as a number of stock
equivalent units. SERs are paid in cash following the termination of
employment with the S.A. Louis Dreyfus et Cie group, based on the average
trading prices of the Company's Common Stock during the month of December in
the year of, or preceding, termination of employment. At December 31, 1994,
1995 and 1996, SERs totaling 85,000 stock equivalent units were outstanding.
Recorded compensation expense attributable the SERs was $523,000, $441,000
and $383,000 for the years ended December 31, 1994, 1995 and 1996,
respectively. The SERs become fully vested on December 31, 1997.

F-15

<PAGE>

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

In October 1993, the Board of Directors approved, and the Company's sole
stockholder adopted, the Company's 1993 Stock Option Plan (the "Option
Plan"). Under the Option Plan, the Company may grant both incentive stock
options intended to qualify under Section 422 of the Internal Revenue Code
and options which are not qualified as incentive stock options. The maximum
number of shares of Common Stock issuable under the Option Plan is 1,000,000
shares, subject to appropriate equitable adjustment in the event of a
reorganization, stock split, stock dividend, reclassification or other change
affecting the Company's Common Stock. All officers and directors of the
Company, and other key employees who hold positions of significant
responsibility, are eligible to receive awards under the Option Plan.
Options granted become exercisable at the rate of 25% per year commencing one
year after the date of grant, with the exception of those granted to
non-employee directors which vest and become fully exercisable on the date of
grant. The exercise price of each option equals the market price of the
Company's stock on the date of grant and an option's expiration date is ten
years from the date of issuance.

The Company accounts for the issuance of stock options in accordance
with Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued
to Employees" ("APB 25"). Under APB 25, no compensation expense is
recognized in the financial statements for options granted with an exercise
price equal to the market price of the underlying stock on the date of grant.
The following pro forma information, as required by Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation"
("SFAS 123"), presents net income and earnings per share information as if
the Company had accounted for stock options issued in 1995 and 1996 using the
fair value method prescribed by that statement. The fair value of issued
stock options was estimated at the date of grant using a Black-Scholes option
pricing model with the following assumptions for 1995 and 1996: risk-free
interest rates of 6.0% and 6.6%, respectively; no dividends over the option
term; stock price volatility factors of .32 and .31, respectively, and a
weighted average expected option life of five years for both years. The
estimated fair value, as determined by the model, is amortized to expense
over the respective vesting period. The SFAS 123 pro forma information
presented below is not necessarily indicative of the pro forma effects to be
presented in future periods due to the future impact of nonvested awards
granted in 1995 and 1996. Additionally, option awards made prior to 1995
have been excluded.

The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting
restrictions and are fully transferable. In addition, option valuation
models require the input of highly subjective assumptions including the
expected stock price volatility. Because the Company's employee stock
options have characteristics significantly different from those of traded
options, and because changes in the subjective input assumptions can
materially affect the fair value estimate, in management's opinion, the
existing models do not necessarily provide a reliable single measure of fair
value of its stock options.

The SFAS 123 pro forma information is as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------
1995 1996
-------- --------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
<S> <C> <C>
Net income . . . . . . . . . . . $ 10,847 $ 20,698
Net income per share . . . . . . . .39 .74
</TABLE>

F-16

<PAGE>

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

Stock option transactions for 1994, 1995 and 1996 are summarized as
follows:

YEARS ENDED DECEMBER 31,
---------------------------------------------------------------------------------
1994 1995 1996
------------------------ ------------------------ -------------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
SHARES EXERCISE PRICE SHARES EXERCISE PRICE SHARES EXERCISE PRICE
------- -------------- ------- -------------- ------- --------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning
of year ...................... 500,000 $ 18.00 515,000 $ 18.06 792,000 $ 16.42
Granted ........................ 15,000 19.88 294,000 13.64 212,000 14.39
Exercised ...................... -- -- -- -- (750) 13.69
Canceled ....................... -- -- (17,000) 18.00 (10,000) 16.71
------- ------- -------
Outstanding at end of year ..... 515,000 18.06 792,000 16.42 993,250 15.98
------- ------- -------
------- ------- -------

Exercisable at end of year ..... 125,000 18.00 275,250 17.60 469,000 17.08
------- ------- -------
------- ------- -------
Weighted-average fair value of
options granted during year ... $ 8.41 $ 5.27 $ 5.71
------- ------- -------
------- ------- -------
</TABLE>

Outstanding options to acquire 491,000 shares of stock at December 31,
1996 had exercise prices ranging from $18.00 to $19.88 per share and had a
weighted-average remaining contractual life of 6.9 years. The balance of
options outstanding at December 31, 1996 had exercise prices ranging from
$12.63 to $14.44 per share and a weighted-average remaining contractual life
of 9.1 years.

NOTE 9 -- SIGNIFICANT CUSTOMERS

The Company's oil and gas sales at the wellhead are sold under contracts
with various purchasers. The Company had gas sales to two unrelated
purchasers which approximated 10% and 28% of total revenues for the year
ended December 31, 1994. Sales to one unrelated purchaser in 1995
represented 30% of total revenues. For the year ended December 31, 1996, the
Company had gas sales to three unrelated purchasers which approximated 18%,
13% and 11% of total revenues. The Company believes that alternative
purchasers are available, if necessary, to purchase its production at prices
substantially similar to those being received by these purchasers.

F-17
<PAGE>

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

NOTE 10 -- FINANCIAL INSTRUMENTS

The following information is provided regarding the estimated fair value
of certain on- and off-balance sheet financial instruments employed by the
Company as of December 31, 1995 and 1996, and the methods and assumptions
used to estimate the fair value of such financial instruments:

<TABLE>
<CAPTION>
DECEMBER 31, 1995 DECEMBER 31, 1996
------------------------- ------------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
---------- --------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Fixed-price natural gas energy swaps:
Sales contracts ........................ $ (760) $ 29,500 $ -- $ 19,000
Purchase contracts ..................... -- (4,000) -- 1,000
Fixed-price natural gas collars ............. n/a n/a -- 1,000
Fixed-price natural gas physical delivery
contracts (1) .......................... 2,186 209,000 1,940 168,000
Natural gas basis swaps ..................... n/a n/a -- 1,000
Fixed-price crude oil energy swaps .......... -- 1,000 -- --
Bank debt (2) ............................... (216,000) (216,000) (245,000) (245,000)
Subordinated debt (2) ....................... (98,760) (108,695) (98,907) (106,000)
Interest rate swaps - fixed ................. 152 (3,319) -- (1,000)
Interest rate swaps - floating .............. n/a n/a -- 1,000
</TABLE>

- ----------------------------------------
(1) The Company's fixed-price delivery contracts, which are not
financial instruments pursuant to Statement of Financial Accounting
Standards No. 107, are presented for informational purposes only. See
Note 11 -- Fixed-Price Contracts.
(2) Carrying amounts do not include capitalized debt issuance costs. See
Note 1 -- Significant Accounting Policies.

Cash and cash equivalents, accounts receivable, short-term investments,
deposits, accounts payable, revenues payable and accrued restoration
liabilities were each estimated to have a fair value approximating the
carrying amount due to the short maturity of those instruments or to the
criteria used to determine carrying value in the financial statements.

The "fair value" of the Company's Fixed-Price Contracts as of December
31, 1995 and 1996, was estimated based on market prices of natural gas and
crude oil for the periods covered by the contracts. The net differential
between the fixed (or floating) prices in each contract and market prices for
future periods, as adjusted for estimated basis, has been applied to the
volumes covered by each contract to arrive at an estimated future value.
This future value was then discounted at 10%. Due to the characteristics of
the Company's contracts, an established market does not exist to determine a
true fair value. Many factors, such as performance, basis and credit risks,
have not been considered in the foregoing calculation. See Note 11 --
Fixed-Price Contracts. This calculation measures the amount by which such
contracts are in- or out-of-the money in relation to market prices at each
respective year-end. Since Fixed-Price Contracts are used to hedge natural
gas and crude oil prices, any change in the value associated with such
contracts is expected to be offset by an opposite change in the value of the
Company's reserves.

The fair value of bank debt at December 31, 1995 and 1996 was
estimated to approximate the carrying amount. The fair value of subordinated
debt as of such dates is determined by applying an estimated credit spread to
quoted yields for treasury notes with comparable maturities to such debt.
The fair value of the Company's interest rate swaps for each of the years
presented is based on quoted market prices as of such dates.

F-18

<PAGE>

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

NOTE 11 -- FIXED-PRICE CONTRACTS

The following table summarizes the estimated volumes, fixed prices,
fixed-price sales, fixed-price purchases and future net revenues (as defined
below) attributable to the Company's Fixed-Price Contracts as of December 31,
1996.

F-19
<PAGE>

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

<TABLE>
<CAPTION>
YEARS ENDING DECEMBER 31, BALANCE
------------------------------------------------------------- THROUGH
1997 1998 1999 2000 2001 2017 TOTAL
--------- --------- --------- --------- --------- --------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
NATURAL GAS SWAPS,
OPTIONS AND FUTURES
SALES CONTRACTS
Contract volumes (BBtu). . . . . . 6,068 13,825 15,825 9,830 7,475 29,832 82,855
Weighted-average fixed price
per MMBtu (1). . . . . . . . . . $ 2.27 $ 2.33 $ 2.44 $ 2.46 $ 2.47 $ 3.08 $ 2.65
Future fixed-price sales (M$). . . $13,802 $ 32,243 $ 38,629 $ 24,164 $ 18,446 $ 92,005 $ 219,289
Future net revenues (M$)(2). . . . $ 999 $ 2,381 $ 3,973 $ 2,489 $ 1,852 $ 22,866 $ 34,560

PURCHASE CONTRACTS
Contract volumes (BBtu). . . . . . (2,425) (9,125) (10,950) -- -- -- (22,500)
Weighted-average fixed price
per MMBtu (1). . . . . . . . . . $ 2.05 $ 2.09 $ 2.18 $ -- $ -- $ -- $ 2.13
Future fixed-price purchases (M$). $(4,973) $(19,108) $(23,880) $ -- $ -- $ -- $ (47,961)
Future net revenues (M$)(2). . . . $ 399 $ 602 $ 100 $ -- $ -- $ -- $ 1,101

NATURAL GAS PHYSICAL
DELIVERY CONTRACTS
Contract volumes (BBtu). . . . . . 33,111 36,060 28,204 26,749 27,300 134,096 285,520
Weighted-average fixed price
per MMBtu (1). . . . . . . . . . $ 2.49 $ 2.64 $ 2.84 $ 3.04 $ 3.19 $ 4.11 $ 3.42
Future fixed-price sales (M$). . . $82,442 $ 95,130 $ 80,125 $ 81,403 $ 86,963 $551,455 $ 977,518
Future net revenues (M$)(2). . . . $ 8,902 $ 17,782 $ 18,748 $ 22,486 $ 26,568 $210,070 $ 304,556

TOTAL NATURAL GAS
CONTRACTS (3)(4)
Contract volumes (BBtu). . . . . . 36,754 40,760 33,079 36,579 34,775 163,928 345,875
Weighted-average fixed price
per MMBtu (1). . . . . . . . . . $ 2.48 $ 2.66 $ 2.87 $ 2.89 $ 3.03 $ 3.93 $ 3.32
Future fixed-price sales (M$). . . $91,271 $108,265 $ 94,874 $105,567 $105,409 $643,460 $1,148,846
Future net revenues (M$)(2). . . . $10,300 $ 20,765 $ 22,821 $ 24,975 $ 28,420 $232,936 $ 340,217

CRUDE OIL SWAPS AND FUTURES
Contract volumes (MBbls). . . . . . 362 -- -- -- -- -- 362
Weighted-average fixed price
per Bbl (1) . . . . . . . . . . . $ 22.32 $ -- $ -- $ -- $ -- $ -- $ 22.32
Future fixed-price sales (M$) . . . $ 8,080 $ -- $ -- $ -- $ -- $ -- $ 8,080
Future net revenues (M$)(2) . . . . $ (172) $ -- $ -- $ -- $ -- $ -- $ (172)

</TABLE>

- ----------

(2) Future net revenues for any period are determined as the
differential between the fixed prices provided by Fixed-Price
Contracts and forward market prices as of December 31, 1996, as
adjusted for basis. Future net revenues change as market prices and
basis fluctuate. See "Market Risk."

(3) Does not include basis swaps with notional volumes by year, as
follows: 1997 - 21.0 TBtu; 1998 - 24.5 TBtu; 1999 - 19.0 TBtu; 2000
- 21.3 TBtu; 2001 - 9.4 TBtu; and 2002 - 5.5 TBtu.

(4) Does not include 3.0 TBtu of natural gas hedged by fixed-price
collars for January through September 1997 with a weighted-average
floor price of $2.30 per MMBtu and a weighted-average ceiling price
of $2.84 per MMBtu.

The estimates of the future net revenues and present value of the
Company's Fixed-Price Contracts contained herein are computed based on the
difference between the prices provided by the Fixed-Price Contracts and
forward market prices as of the specified date. Such estimates do not
necessarily represent the fair market value of the Company's Fixed-Price
Contracts or the actual future net revenues that will be received. The
forward market prices for natural gas and oil are highly volatile, are
dependent upon supply and demand factors in such forward market and may not
correspond to the actual market prices at the settlement dates of the
Company's Fixed-Price Contracts. Such forward market prices are available in
a limited over-the-counter market and are obtained from sources the Company
believes to be reliable.

F-20
<PAGE>

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

liquidated or sold prior to maturity, the gain or loss is deferred and
amortized into oil and gas sales over the original term of the contract.
Prepayments received under Fixed-Price Contracts with continuing performance
obligations are recorded as deferred revenue and amortized into oil and gas
sales over the term of the underlying contract. Also see Note 1 --
Significant Accounting Policies -- Hedging.

Two Fixed-Price Contracts which hedge an aggregate 106 Bcf of natural
gas as of December 31, 1996 are with independent power producers who sell
electrical power under firm fixed-price contracts to Niagara Mohawk
Corporation ("NIMO"), a New York state utility. As of December 31, 1996, the
net present value of the differential between the fixed prices provided by
these contracts and forward market prices, as adjusted for basis and
discounted at 10%, was $135 million, or 71% of such net present value
attributable to all of the Company's Fixed-Price Contracts. This premium in
the fixed prices is not reflected in the Company's financial statements until
realized. For the years ended December 31, 1994, 1995 and 1996, these
contracts contributed $5.1 million, $9.6 million and $.9 million,
respectively, to natural gas sales. The ability of these independent power
producers to perform their obligations to the Company is largely dependent on
the continued performance by NIMO of its power purchase obligations to the
counterparties. NIMO in recent years initiated judicial and regulatory
proceedings designed to curtail power purchase obligations under its
contracts with non-regulated power generators. As of December 31, 1996, NIMO
had not been successful in these proceedings. On August 1, 1996, NIMO
announced an offer to terminate 44 independent power contracts, including
those to the Company's counterparties, in exchange for a combination of cash
and debt securities from a newly restructured NIMO. The terms of the offer
have not been made public. At this time, the likelihood of NIMO's proposal
being accepted cannot be predicted, nor can any potential impact on future
counterparty performance if the proposal is accepted. The Company has not
experienced non-performance by any counterparty.

MARKET RISK. The Company's Fixed-Price Contracts at December 31, 1996,
hedge 349 Bcf of proved natural gas reserves, substantially all of which are
proved developed reserves, and 362 MBbls of oil, at fixed prices. These
contract quantities represent 41% and 2% of the Company's estimated proved
natural gas and crude oil reserves, respectively, as of December 31, 1996.
If the Company's proved reserves are produced at rates less than anticipated,
the volumes specified under the Fixed-Price Contracts may exceed production
volumes. In such case, the Company would be required to satisfy its
contractual commitments at market prices

F-21
<PAGE>

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

in effect for each settlement period, which may be above the contract price,
without a corresponding offset in wellhead revenue for any excess volumes.
The Company expects future production volumes to be equal to or greater than
the volumes provided in its contracts.

The differential between the floating price paid under each energy swap
contract, or the cost of gas to supply physical delivery contracts, and the
price received at the wellhead for the Company's production is termed "basis"
and is the result of differences in location, quality, contract terms, timing
and other variables. The effective price realizations which result from the
Company's Fixed-Price Contracts are affected by movements in basis. For the
years ended December 31, 1994, 1995 and 1996, the Company received on an Mcf
basis approximately 11%, 3% and 3% less than the prices specified in its
natural gas Fixed-Price Contracts, respectively, due to basis. Such results
do not include a $4.3 million basis loss recognized in the fourth quarter of
1995, discussed below. For its oil production hedged by crude oil
Fixed-Price Contracts, the Company realized approximately 8%, 7% and 4% less
than the specified contract prices for such years, respectively. Basis
movements can result from a number of variables, including regional supply
and demand factors, changes in the Company's portfolio of Fixed-Price
Contracts and the composition of the Company's producing property base.
Basis movements are generally considerably less than the price movements
affecting the underlying commodity, but their effect can be significant. A
1% move in price realization for hedged natural gas in 1997 represents a
$913,000 change in gas sales. A 1% change in price realization for hedged
oil production in 1997 represents an $81,000 change in oil sales. The
Company actively manages its exposure to basis movements and from time to
time will enter into contracts designed to reduce such exposure.

F-22

<PAGE>

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

NOTE 12 -- SUPPLEMENTAL INFORMATION - OIL AND GAS RESERVES (UNAUDITED)

The following information summarizes the Company's net proved reserves
of crude oil and natural gas and the present values thereof for the three
years ended December 31, 1994, 1995 and 1996. Reserve estimates for these
years have been prepared by the Company's petroleum engineers and reviewed by
an independent engineering firm. All studies have been prepared in
accordance with regulations prescribed by the Securities and Exchange
Commission. Future net revenue is estimated by such engineers using oil and
gas prices in effect as of the end of each respective year with price
escalations permitted only for those properties which have wellhead contracts
allowing specific increases. Future operating costs estimated in each study
are based on historical operating costs incurred. Reserve quantity estimates
are calculated without regard to prices in the Company's Fixed-Price
Contracts.

The reliability of any reserve estimate is a function of the quality of
available information and of engineering interpretation and judgment. Such
estimates are susceptible to revision in light of subsequent drilling and
production history or as a result of changes in economic conditions.

ESTIMATED QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED). The following
table sets forth the Company's estimated proved reserves, all of which are
located in the United States, for the years ended December 31, 1994, 1995 and
1996:
<TABLE>
<CAPTION>

1994 1995 1996
----------------------- ---------------------- -------------------
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
------- ------ ------- ------ ------- ------
<S> <C> <C> <C> <C> <C> <C>
PROVED RESERVES
Beginning of year..................... 20,867 502,018 19,317 574,025 20,360 753,919
Acquisition of proved reserves........ 1,569 46,649 1,439 181,867 2,173 62,497
Extensions and discoveries............ 210 54,439 949 66,382 2,643 76,873
Revisions of previous estimates....... (1,344) 15,219 1,544 (7,738) 335 19,939
Sales of reserves in place............ (112) (1,218) (1,194) (9,353) (165) (119)
Production............................ (1,873) (43,082) (1,695) (51,264) (1,849) (63,910)
------ ------- ------ ------- ------ -------
End of year (1)....................... 19,317 574,025 20,360 753,919 23,497 849,199
------ ------- ------ ------- ------ -------
------ ------- ------ ------- ------ -------
PROVED DEVELOPED RESERVES
Beginning of year..................... 14,839 378,000 13,089 433,306 14,839 630,604
------ ------- ------ ------- ------ -------
------ ------- ------ ------- ------ -------

End of year (1)....................... 13,089 433,306 14,839 630,604 17,894 709,712
------ ------- ------ ------- ------ -------
------ ------- ------ ------- ------ -------
</TABLE>
-------------------------------------

(1) Totals for 1996 includes 5.5 MMBbls of proved oil reserves
and 1.5 Bcf of proved natural gas reserves attributable to the
Company's Levelland properties which were sold in January 1997.
See Note 13 -- Subsequent Event.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED).
The following table reflects the standardized measure of discounted future
net cash flows relating to the Company's interests in proved oil and gas
reserves. The future net cash inflows were developed as follows:

(1) - Estimates were made of quantities of proved
reserves and the future periods in which they are expected
to be produced based on year-end economic conditions.

(2) - The estimated cash flows from future production of proved
reserves were prepared on the basis of prices received at
December 31, 1994, 1995 and 1996, as adjusted for the
effects of the Company's existing Fixed-Price Contracts,
as follows: 1994 - $16.08 per Bbl, $2.61 per Mcf; 1995 -
$17.80 per Bbl, $2.60 per Mcf; and 1996 - $24.66 per Bbl,
$3.55 per Mcf.

F-23

<PAGE>

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

(3) - The resulting future gross revenue streams were reduced
by estimated future costs to develop and to produce the
proved reserves, based on year-end estimates.

(4) - Future income taxes were computed by applying the
appropriate statutory tax rates to the future pre-tax net
cash flows less the current tax basis of the properties
involved and related carryforwards, giving effect to
permanent differences and tax credits.

(5) - The resulting future net revenue streams were reduced to
present value amounts by applying a 10% discount factor.

F-24

<PAGE>

LOUIS DREYFUS NATURAL GAS CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------------------
1994 1995 1996
------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows................................................. $ 1,806,890 $ 2,325,573 $ 3,596,493
Future production costs............................................. (467,704) (686,476) (1,053,989)
Future development costs............................................ (119,426) (107,596) (125,074)
Discount at 10% per year............................................ (603,755) (793,989) (1,299,696)
------------ ------------ ------------
Net present value of future net revenues............................ 616,005 737,512 1,117,734
Discounted future income taxes...................................... (139,184) (174,215) (314,290)
------------ ------------ ------------
Standardized measure of discounted future net cash flows (1) (2).... $ 476,821 $ 563,297 $ 803,444
------------ ------------ ------------
------------ ------------ ------------

</TABLE>
-------------------------------------
(1) The standardized measure of discounted future net cash flows
excluding the effect of the Company's Fixed-Price Contracts was
$316.8 million, $431.0 million and $922.6 million as of December
31, 1994, 1995 and 1996, respectively.

(2) The standardized measure of discounted future net cash flows as of
December 31, 1996 includes $25.8 million attributable to the
Company's Levelland properties which were sold in January 1997.
See Note 13 -- Subsequent Event.

The standardized measure information in the preceding table was derived
from estimates of the Company's proved oil and gas reserves contained in
studies prepared by petroleum engineers. These studies calculate the
discounted present value of future net revenues from the Company's proved oil
and gas reserves, determined without regard for the Company's Fixed-Price
Contracts or consideration for future income tax consequences, at $359
million, $524 million and $1.304 billion as of December 31, 1994, 1995 and
1996, respectively. The standardized measure calculation, prepared pursuant
to the provisions of Statement of Financial Accounting Standards No. 69, does
not purport to represent the fair market value of the Company's oil and gas
reserves. The foregoing information is presented for comparative purposes as
of the Company's year-end and is not intended to reflect any changes in value
which may result from future price fluctuations.

Increases in the standardized measure calculation and the net present
value of future net revenues, including the effects of Fixed-Price Contracts,
for 1996 were due, in part, to a significant increase in December 1996
natural gas and crude oil prices. Holding the reserve quantities set forth
in the December 31, 1996 reserve study constant, the impact of using average
1996 natural gas and oil prices of $2.63 per Mcf and $21.18 per Bbl would
have been to lower the standardized measure and present value calculations to
$632 million and $834 million, respectively.

F-25

<PAGE>

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

CHANGES RELATING TO THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
CASH FLOWS (UNAUDITED). The principal changes in the standardized measure of
discounted future net cash flows attributable to the Company's oil and gas
reserves for the years ended December 31, 1994, 1995 and 1996, were as
follows:

YEARS ENDED DECEMBER 31,
----------------------------------------
1994 1995 1996
---------- --------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Balance, beginning of year..................................... $ 457,579 $ 476,821 $ 563,297
Acquisitions of proved reserves................................ 32,105 116,229 116,263
Extensions and discoveries, net of future development costs.... 28,731 52,823 147,817
Revisions of previous quantity estimates....................... 7,493 1,623 26,431
Oil and gas sales, net of production costs..................... (104,871) (128,014) (140,943)
Sales of reserves in place..................................... (1,935) (7,953) (614)
Net changes in sales prices and production costs............... 13,303 48,242 140,205
Development costs incurred and changes in estimated future
development costs......................................... 3,188 30,279 13,099
Net change in income taxes..................................... (7,776) (35,031) (140,076)
Accretion of discount.......................................... 58,899 61,600 73,751
Changes in timing of production and other (1).................. (9,895) (53,322) 4,214
------------ ------------ ------------

Balance, end of year........................................... $ 476,821 $ 563,297 $ 803,444
------------ ------------ ------------
------------ ------------ ------------
</TABLE>

(1) The decrease in this caption for 1995 reflects the impact of
a higher average discount rate resulting from a change in the timing
of future cash flows.

NOTE 13 -- SUBSEQUENT EVENT

In January 1997, the Company completed the sale of its West Texas
Levelland field to an unrelated third party. The Company received total
sales proceeds of $27.1 million, subject to closing costs and adjustments.
The sale will result in an estimated pre-tax gain, after sales commission, of
$8.5 million, to be recorded in the first quarter of 1997. At December 31,
1996, the Levelland field had 5.5 MMBbls of proved oil reserves and 1.5 Bcf
of proved natural gas reserves, net to the Company's interest. The proceeds
were applied to outstanding indebtedness under the Credit Facility.

F-26

<PAGE>

LOUIS DREYFUS NATURAL GAS CORP.
Notes to Consolidated Financial Statements (continued)

NOTE 14 -- QUARTERLY RESULTS (unaudited)

<TABLE>
<CAPTION>
1995 1996
---------------------------------------- ----------------------------------------
FIRST SECOND THIRD FOURTH FIRST SECOND THIRD FOURTH
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) . . . . . . . . . $39,410 $38,173 $43,554 $41,811 $39,850 $45,816 $48,988 $54,851
Operating profit (loss) (2). . 17,526 17,594 18,596 (50) 14,570 17,376 20,395 22,392
Net income (loss) (2). . . . . 5,804 5,732 5,591 (6,110) 2,252 4,534 6,510 7,806
Net income (loss) per share. . .21 .21 .20 (.22) .08 .16 .23 .28
</TABLE>

- ----------------------------------------
(1) Increases in revenues are largely attributable to development
activities during 1995 and 1996 and the acquisition of proved reserves
in the third quarter of 1995 and the second quarter of 1996. See
Note 3 -- Property Acquisitions.
(2) The operating loss and the net loss in the fourth quarter of 1995 were
primarily due to a $15.7 million impairment charge recorded in
connection with the adoption of SFAS 121 and the recognition of a $4.3
million basis loss. See Note 1 -- Significant Accounting Policies and
Note 11 -- Fixed-Price Contracts.

F-27
<PAGE>

NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN OR
INCORPORATED BY REFERENCE IN THIS PROSPECTUS IN CONNECTION WITH THE OFFER
MADE BY THIS PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION OR
REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE
COMPANY, THE SELLING SHAREHOLDER OR ANY OF THE UNDERWRITERS. NEITHER THE
DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY
CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE
AFFAIRS OF THE COMPANY SINCE THE DATES AS OF WHICH INFORMATION IS GIVEN IN
THIS PROSPECTUS. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER OR SOLICITATION
BY ANYONE IN ANY JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION IS NOT
AUTHORIZED OR IN WHICH THE PERSON MAKING SUCH OFFER OR SOLICITATION IS NOT
QUALIFIED TO DO SO OR TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH
SOLICITATION.

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

TABLE OF CONTENTS

PAGE
----

Prospectus Summary ............................................ 3
Risk Factors .................................................. 9
Use of Proceeds ............................................... 13
Capitalization ................................................ 14
Price Range of Common Stock and
Dividend Policy ............................................ 15
Management's Discussion and Analysis
of Financial Condition and Results
of Operations .............................................. 16
Business and Properties ....................................... 30
Management .................................................... 44
Selling Shareholder and Principal
Shareholders ............................................... 47
Description of Capital Stock .................................. 49
Certain United States Tax Consequences
to Non-United States Holders ............................... 51
Underwriting .................................................. 53
Legal Matters ................................................. 56
Experts ....................................................... 56
Available Information ......................................... 56
Incorporation of Certain
Documents by Reference ..................................... 57
Certain Definitions ........................................... 57
Index to Consolidated Financial
Statements ................................................. F-1

5,500,000 SHARES

LOUIS DREYFUS
NATURAL GAS
CORP.

COMMON STOCK
($.01 PAR VALUE)

SALOMON BROTHERS INC

CREDIT SUISSE FIRST BOSTON

HOWARD, WEIL
LABOUISSE, FRIEDRICHS
INCORPORATED

MORGAN STANLEY & CO.
INCORPORATED

Prospectus
Dated , 1997

<PAGE>

[ALTERNATE INTERNATIONAL PAGE]

Subject to Completion
_____________, 1997
PROSPECTUS

5,500,000 SHARES

LOUIS DREYFUS NATURAL GAS CORP.

COMMON STOCK
($.01 PAR VALUE)

Of the shares being offered, 825,000 shares are being offered outside the
United States and Canada (the "International Offering") and 4,675,000 shares
are being offered in a concurrent offering in the United States and Canada
(the "U.S. Offering" and, collectively with the International Offering, the
"Offerings"), subject to transfers between the International Underwriters and
the U.S. Underwriters. The Price to Public and Underwriting Discount per share
will be identical for the International Offering and the U.S. Offering. See
"Underwriting." The closings of the International Offering and U.S. Offering
are conditioned upon each other.

The Common Stock is listed on the New York Stock Exchange under the symbol
"LD." On February ___, 1997, the last reported sale price for the Common
Stock, as reported on the New York Stock Exchange Composite Transactions Tape,
was $_____ per share. See "Price Range of Common Stock and Dividend Policy."

SEE "RISK FACTORS" COMMENCING ON PAGE 9 OF THIS PROSPECTUS FOR A DESCRIPTION
OF CERTAIN FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH AN INVESTMENT
IN THE COMMON STOCK.

- ------------------------------------------------------------------------------
PROCEEDS TO
PRICE TO UNDERWRITING PROCEEDS TO SELLING
PUBLIC DISCOUNT COMPANY(1) SHAREHOLDER(1)

Per Share. . . . . . . .$ $ $ $
Total (2). . . . . . .. $ $ $ $
- -------------------------------------------------------------------------------

(1) Before deducting offering expenses estimated at $350,000, all of which are
payable by the Company.
(2) The Selling Shareholder has granted to the International Underwriters and
the U.S. Underwriters 30-day options to purchase up to an aggregate of 825,000
shares of Common Stock at the Price to Public, less Underwriting Discount,
solely to cover over-allotments, if any. If the Underwriters exercise such
options in full, the total Price to Public, Underwriting Discount and Proceeds
to Selling Shareholder will be $___________, $___________ and $___________,
respectively. See "Underwriting."

SALOMON BROTHERS INTERNATIONAL LIMITED
CREDIT SUISSE FIRST BOSTON
HOWARD, WEIL, LABOUISSE, FRIEDRICHS
INCORPORATED
MORGAN, STANLEY & CO.
INTERNATIONAL

The date of this Prospectus is _____________________, 1997.

<PAGE>

[ALTERNATE INTERNATIONAL PAGE] UNDERWRITING

Subject to the terms and conditions set forth in an underwriting
agreement (the "International Underwriting Agreement") among the Company, the
Selling Shareholder and each of the underwriters named below (the
"International Underwriters"), for whom Salomon Brothers International
Limited, Credit Suisse First Boston (Europe) Limited, Howard, Weil,
Labouisse, Friedrichs Incorporated and Morgan Stanley & Co. International
Limited are acting as representatives (the "International Representatives"),
the Company and the Selling Shareholder have agreed to sell each of the
International Underwriters and each such International Underwriter has
severally agreed to purchase from the Company and the Selling Shareholder the
aggregate number of shares of Common Stock set forth opposite its name below:

NUMBER
INTERNATIONAL UNDERWRITERS OF SHARES
- -------------------------- ---------
Salomon Brothers International Limited ........................
Credit Suisse First Boston (Europe) Limited ...................
Howard, Weil, Labouisse, Friedrichs Incorporated ..............
Morgan Stanley & Co. International Limited ....................

---------
Total ................................................... 825,000
---------
---------
In addition, the Company and the Selling Shareholder have entered into
an underwriting agreement (the "U.S. Underwriting Agreement") with the U.S.
Underwriters named therein, for whom Salomon Brothers Inc, Credit Suisse
First Boston Corporation, Howard, Weil, Labouisse, Friedrichs Incorporated
and Morgan Stanley & Co. Incorporated are acting as representatives (the
"U.S. Representatives"), providing for the concurrent offer and sale of
shares of Common Stock in the U.S. and Canada. The closing with respect to
the sale of the shares of Common Stock pursuant to the International
Underwriting Agreement is a condition to the closing with respect to the sale
of the shares of Common Stock pursuant to the U.S. Underwriting Agreement,
and the closing with respect to the sale of the shares of Common Stock
pursuant to the U.S. Underwriting Agreement is a condition to the closing
with respect to sale of the shares of Common Stock pursuant to the
International Underwriting Agreement. The public offering price and
underwriting discounts and concessions per share for the International
Offering and the U.S. Offering will be identical.

<PAGE>

[ALTERNATE INTERNATIONAL PAGE]

related to the International Offering to any person within the United States
or Canada or to any United States or Canadian Person. The foregoing
limitations do not apply to stabilization transactions or to certain other
transactions specified in the Agreement Between U.S. Underwriters and
International Underwriters described below. "United States or Canadian
Person" means any person who is a natural citizen or resident of the United
States or Canada, any corporation, partnership or other entity created or
organized in or under the laws of the United States or Canada, or any
political subdivision thereof, any estate or trust the income of which is
subject to United States or Canadian federal income taxation, regardless of
the source of its income (other than a foreign branch of any United States or
Canadian Person), and includes any United States or Canadian branch of a
person other than a United States or Canadian Person.

The U.S. Underwriters and the International Underwriters have entered
into an agreement that provides for the coordination of their activities (the
"Agreement Between U.S. Underwriters and International Underwriters").
Pursuant to the Agreement Between U.S. Underwriters and International
Underwriters, sales may be made between the U.S. Underwriters and the
International Underwriters of such number of shares of Common Stock as may be
mutually agreed. The per share price of any shares of Common Stock so sold
shall be the initial public offering price set forth on the cover page of
this Prospectus, less an amount not greater than the concession to securities
dealers set forth above. To the extent that there are sales between the U.S.
Underwriters and the International Underwriters pursuant to the Agreement
Between U.S. Underwriters and International Underwriters, the number of
shares initially available for sale by the U.S. Underwriters or by the
International Underwriters may be more or less than the amount appearing on
the cover page of this Prospectus.

For a period of 90 days after the date of this Prospectus, the Company,
the Selling Shareholder, and each director and executive officer of the
Company have agreed not to offer, sell, contract to sell or otherwise dispose
of any shares of Common Stock, any other capital stock of the Company or any
security convertible into or exercisable or exchangeable for Common Stock or
any such other capital stock, file or cause to be filed a registration
statement with the Commission in respect of, or establish or increase a put
equivalent position or liquidate or decrease a call equivalent position
within the meaning of Section 16 of the Exchange Act with respect to any
shares of capital stock of the Company or publicly announce the intention to
effect any such transaction, in each case, without the prior written consent
of Salomon Brothers Inc and Salomon Brothers International Limited except (a)
the Company may register the Common Stock and the Company and the

<PAGE>

[ALTERNATE INTERNATIONAL PAGE]

Selling Shareholder may sell the shares of Common Stock offered in the
Offerings, (b) the Selling Shareholder may sell the shares of Common Stock
pursuant to the exercise of the Underwriters' over-allotment options and (c)
the Company may issue securities pursuant to the Company's stock option or
other benefit or incentive plans maintained for its officers, directors or
employees.

<PAGE>

[ALTERNATE INTERNATIONAL PAGE]

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

TABLE OF CONTENTS

PAGE
----

5,500,000 SHARES

LOUIS DREYFUS
NATURAL GAS
CORP.

COMMON STOCK
($.01 PAR VALUE)

SALOMON BROTHERS
INTERNATIONAL LIMITED

CREDIT SUISSE FIRST BOSTON

HOWARD, WEIL
LABOUISSE, FRIEDRICHS
INCORPORATED

MORGAN STANLEY & CO.
INTERNATIONAL

PROSPECTUS
DATED , 1997

<PAGE>
PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION

Set forth below is an itemization of the costs, other than underwriting
discounts and commissions, incurred by the Registrant in connection with the
offer and sale of the securities registered hereby. Pursuant to a
Registration Rights Agreement between the Registrant and the Selling
Shareholder, all such costs are payable by the Registrant. All amounts shown
are estimates except the Securities and Exchange Commission registration fee,
the NASD fee and the NYSE listing fee.

Securities and Exchange Commission
Registration Fee ......................................... $ 33,062
NASD Fee .................................................... 11,411
NYSE Listing Fee ............................................ 22,150
Blue Sky Fees and Expenses (including fees of counsel) ...... 20,000
Printing Expenses ........................................... 75,000
Legal Fees and Expenses (other than Blue Sky) ............... 50,000
Accounting Fees and Expenses ................................ 35,000
Transfer Agent and Registrar Fees ........................... 5,000
Miscellaneous ............................................... 98,377
--------
Total .................................................... $350,000
--------
--------

ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS

The Registrant's Certificate of Incorporation provides that, pursuant to
Oklahoma law, its directors shall not be liable for monetary damages for
breach of the directors' fiduciary duty of care to the Registrant and its
stockholders. The provision in the Certificate of Incorporation does not
eliminate the duty of care and, in appropriate circumstances, equitable
remedies such as injunctive or other forms of non-monetary relief will remain
available under Oklahoma law. In addition, each director will continue to be
subject to liability for breach of the director's duty of loyalty to the
Registrant, as well as for acts or omissions not in good faith or involving
intentional misconduct, for knowing violations of law, for actions leading to
improper personal benefit to the director, and for payment of dividends or
approval of stock repurchases or redemptions that are unlawful under Oklahoma
law. The provision also does not affect a director's responsibilities under
any other law, such as the state or federal securities laws.

Under Section 1031 of the Oklahoma General Corporation Act, the
Registrant has broad powers to indemnify its directors and officers against
liabilities they may incur in such capacities, including liabilities under
the Securities Act of 1933, as amended (the "Securities Act").

The Registrant's Certificate of Incorporation provides that the
Registrant shall indemnify its directors and officers to the fullest extent
permitted by Oklahoma law. The Certificate of Incorporation requires the
Registrant to indemnify such persons against expenses, judgments, fines,
settlements and other amounts incurred in connection with any proceeding,
whether actual or threatened, to which any such person may be made a party by
reason of the fact that such person is or was a director or an officer of the
Registrant or any of its affiliated enterprises, provided such person acted
in good faith and in a manner such person reasonably believed to be in or not
opposed to the best interests of the Registrant, and, with respect to any
criminal proceeding, had no reasonable cause to believe his conduct was
unlawful. However, in the case of a derivative action, an officer or director
will not be entitled to indemnification in respect of any claim, issue or
matter as to which such person is adjudged to be liable to the Registrant,
unless and only to the extent that the court in which the action was brought
determines that such person is fairly and reasonably entitled to indemnity
for expenses.

The Registrant has entered into Indemnification Agreements with each
director of the Registrant which require the Registrant to indemnify such
persons against certain liabilities and expenses incurred by any such persons by
reason of their status or service as directors of the Registrant. The
Indemnification Agreements also set forth procedures that will apply in the

II-1

<PAGE>

event of a claim for indemnification under such agreements. In addition, the
Indemnification Agreements require that the Registrant use commercially
reasonable efforts to maintain policies of directors' liability insurance.

At present, there is no pending litigation or proceeding involving a
director or officer of the Registrant as to which indemnification is being
sought nor is the Registrant aware of any threatened litigation that may
result in claims for indemnification by any officer or director.

Pursuant to a Registration Rights Agreement between the Registrant and
the Selling Shareholder, the Registrant has agreed to indemnify the Selling
Shareholder and its officers, directors and controlling persons, and the
Selling Shareholder has agreed to indemnify the Company and its officers,
directors and controlling persons, against certain liabilities under the
Securities Act or otherwise.

The Underwriting Agreement filed as an exhibit to this registration
statement provides for indemnification by the Underwriters of the Registrant
and its officers, directors and controlling persons, and by the Registrant of
the Underwriters for certain liabilities arising under the Securities Act or
otherwise.

Insofar as indemnification for liabilities arising under the Securities
Act may be permitted to directors, officers or persons controlling the
Registrant pursuant to the foregoing provisions, the Registrant understands
that the Securities and Exchange Commission is of the opinion that such
indemnification may contravene public policy as expressed in the Securities
Act and is, therefore, unenforceable.

ITEM 16. EXHIBITS

See Index to Exhibits immediately following the Signature Pages hereto.

ITEM 17. UNDERTAKINGS

Insofar as indemnification for liabilities arising under the Securities
Act may be permitted to directors, officers and controlling persons of the
Registrant pursuant to the provisions described in Item 15 above, or
otherwise, the Registrant has been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public
policy as expressed in the Securities Act and is, therefore, unenforceable.
In the event that a claim for indemnification against such liabilities (other
than the payment by the Registrant of expenses incurred or paid by a
director, officer or controlling persons of the Registrant in the successful
defense of any action, suit or proceeding) is asserted by such director,
officer or controlling person in connection with securities being registered,
the Registrant will, unless in the opinion of its counsel the matter has been
settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against
public policy as expressed in the Securities Act and will be governed by the
final adjudication of such issue.

The undersigned Registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities
Act, the information omitted from the form of prospectus filed as part of
this registration statement in reliance upon Rule 430A and contained in a
form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4)
or 497(h) under the Securities Act shall be deemed to be a part of this
registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the
Securities Act, each post-effective amendment that contains a form of
prospectus shall be deemed to be a new registration statement relating to the
securities offered therein, and the offering of such securities at that time
shall be deemed to be the initial bona fide offering thereof.

The undersigned Registrant hereby further undertakes that, for purposes
of determining any liability under the Securities Act, each filing of the
Registrant's annual report pursuant to Section 13(a) or Section 15(d) of the
Securities Exchange Act of 1934 that is incorporated by reference in the
registration statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such
securities at that time shall be deemed to be the initial bona fide offering
thereof.

II-2

<PAGE>

SIGNATURES

Pursuant to the requirements of the Securities Act, the Registrant
certifies that it has reasonable ground to believe that it meets all of the
requirements for filing on Form S-3 and has duly caused this Amendment No. 1 to
the Registration Statement to be signed on its behalf by the undersigned,
thereunto duly authorized, in the City of Oklahoma City, State of Oklahoma, on
February 18, 1997.

LOUIS DREYFUS NATURAL GAS CORP.

By: /s/ Peter B. Fritzinger
---------------------------
Peter B. Fritzinger
Chief Financial Officer

Pursuant to the requirements of the Securities Act, this registration
statement has been signed by the following persons in the capacities and on the
dates indicated.

Signature Title Date
--------- ----- ----

Mark E. Monroe * President, Chief Executive February 18, 1997
- ------------------- Officer and Director (principal
Mark E. Monroe executive officer)

Richard E. Bross * Executive Vice President February 18, 1997
- ------------------- and Director
Richard E. Bross

/s/ Peter B. Fritzinger Chief Financial Officer and February 18, 1997
- ------------------------ Treasurer (principal financial
Peter B. Fritzinger officer)

Jeffrey A. Bonney * Vice President and Chief February 18, 1997
- ------------------- Accounting Officer
Jeffrey A. Bonney (principal accounting officer)

Simon B. Rich, Jr. * Chairman of the Board of February 18, 1997
- ------------------- Directors
Simon B. Rich, Jr.

Daniel R. Finn, Jr. * Director February 18, 1997
- -------------------
Daniel R. Finn, Jr.

John J. Hogan, Jr. * Director February 18, 1997
- -------------------
John J. Hogan, Jr.

Gerard Louis-Dreyfus * Director February 18, 1997
- --------------------
Gerard Louis-Dreyfus

James T. Rodgers, III * Director February 18, 1997
- ---------------------
James T. Rodgers, III

* By /s/ Peter B. Fritzinger
-----------------------
Peter B. Fritzinger
Attorney-in-fact

II-3

<PAGE>

LOUIS DREYFUS NATURAL GAS CORP.
AMENDMENT NO. 1 TO FORM S-3 REGISTRATION STATEMENT

INDEX TO EXHIBITS

NO. DESCRIPTION
- --- -----------
1.1* Form of Underwriting Agreement.

2.1 Plan of Reorganization and Agreement of Merger dated August 31, 1993
among the Registrant, LDRC Energy, Inc., Louis Dreyfus Reserves
Holding Corp., Louis Dreyfus Reserves Corp. and Louis Dreyfus Gas
Holdings, Inc. (Incorporated by reference to Exhibit 2.1 of the
Registrant's Registration Statement on Form S-1, Registration
No. 33-69102).

2.2 Plan of Reorganization and Agreement of Merger dated October 22, 1993
among the Registrant, Louis Dreyfus Exchanges Ltd., LDNG Hydrocarbons,
Inc. and LDNG Gas Company, Inc. (Incorporated by reference to Exhibit
2.2 of the Registrant's Registration Statement on Form S-1,
Registration No. 33-69102).

4.1 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).

4.2 Certificate of Merger of the Registrant dated September 9, 1993
(Incorporated by reference to Exhibit 3.2 of the Registrant's
Registration Statement on Form S-1, Registration No. 33-69102).

4.3 Amended and Restated Bylaws of the Registrant (Incorporated by
reference to Exhibit 3.3 of the Registrant's Registration Statement on
Form S-1, Registration No. 33-69102).

4.4 Certificate of Merger of the Registrant dated November 1, 1993
(Incorporated by reference to Exhibit 3.4 of the Registrant's
Registration Statement on Form S-1, Registration No. 33-69102).

5.1* Opinion of Crowe & Dunlevy, A Professional Corporation, as to legality
of the Common Stock registered hereby.

23.1 Consent of Ernst & Young LLP.

23.2 Consent of Ryder Scott Company.

23.3* Consent of Crowe & Dunlevy, A Professional Corporation (Contained in
Exhibit 5.1).

24.1* Powers of Attorney of Mark E. Monroe, Richard E. Bross, Jeffrey A.
Bonney, Daniel R. Finn, Jr., John J. Hogan, Jr. and James T.
Rodgers, III.

24.2 Powers of Attorney of Peter B. Fritzinger, Simon B. Rich, Jr., and
Gerard Louis-Dreyfus.

- --------------------------
* Previously filed.

II-4

<PAGE>

EXHIBIT 23.1

<PAGE>

CONSENT OF INDEPENDENT AUDITORS

We consent to the reference to our firm under the caption "Experts" and to
the use of our report dated January 31, 1997, with respect to the consolidated
financial statements of Louis Dreyfus Natural Gas Corp. in Amendment No. 1 to
the Registration Statement (Form S-3, No. 333-21321) and related Prospectus of
Louis Dreyfus Natural Gas Corp. for the registration of 6,325,000 shares of
its common stock.

We also consent to the incorporation by reference therein of our report
dated January 31, 1997, with respect to the consolidated financial statements
and schedule of Louis Dreyfus Natural Gas Corp. included in its Annual Report
(Form 10-K) for the year ended December 31, 1996, filed with the Securities
and Exchange Commission.

ERNST & YOUNG LLP

Oklahoma City, Oklahoma
February 14, 1997

<PAGE>

EXHIBIT 23.2

<PAGE>

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the reference in Amendment No. 1 to the Registration
Statement on Form S-3 of Louis Dreyfus Natural Gas Corp., and the related
Prospectus, to our report dated January 22, 1997 relating to our review of
the oil and gas reserves of Louis Dreyfus Natural Gas Corp. as of December
31, 1996. We also consent to all references to our firm included in or made a
part of such Registration Statement and Prospectus.

RYDER SCOTT COMPANY
PETROLEUM ENGINEERS

Houston, Texas
February 14, 1997

<PAGE>

EXHIBIT 24.2

<PAGE>

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that the undersigned hereby constitutes and
appoints Jeffrey A. Bonney, Peter B. Fritzinger and Mark E. Monroe, and each of
them, his true and lawful attorney-in-fact and agent, with full power of
substitution and resubstitution, for him and in his name, place and stead, in
any and all capacities to sign the registration statement on Form S-3 under the
Securities Act of 1933 of Louis Dreyfus Natural Gas Corp. (the "Corporation")
relating to the offer and sale of shares of Common Stock to the public by the
Corporation and the selling shareholder named in the Registration Statement, and
any and all amendments thereto (including post-effective amendments), and to
file the same, with exhibits thereto and other documents in connection
therewith, with the Securities and Exchange Commission, granting unto each said
attorney-in-fact and agent full power and authority to do and perform each and
every act and thing requisite and necessary to be done, as fully to all intents
and purposes as he might or could do in person, hereby ratifying and confirming
all that said attorney-in-fact and agent or any of them, or their or his
substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

DATED this 10th day of February, 1997.

SIGNATURE TITLE

/S/ Peter B. Fritzinger Chief Financial Officer and Treasurer
----------------------- -------------------------------------

Peter B. Fritzinger
-----------------------
(Please print name)

<PAGE>

POWER OF ATTORNEY

DATED this 6th day of February, 1997.

SIGNATURE TITLE

/S/ Simon B. Rich, JR. Chairman of the Board of Directors
---------------------- ------------------------------------

Simon B. Rich, JR.
----------------------
(Please print name)

<PAGE>

POWER OF ATTORNEY

DATED this 6th day of February, 1997.

SIGNATURE TITLE

/S/ Gerard Louis-Dreyfus Director
------------------------ ------------------------

Gerard Louis-Dreyfus
------------------------
(Please print name)