BELCO OIL & GAS CORP, 424B5, 1998-03-05

BELCO OIL & GAS CORP
424B5, 1998-03-05
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1
Filed Pursuant to Rule 424(b)(5)
Registration No. 333-42107

PROSPECTUS SUPPLEMENT TO PROSPECTUS DATED DECEMBER 24, 1997

3,800,000 SHARES

BELCO OIL & GAS CORP.

6 1/2% CONVERTIBLE PREFERRED STOCK
(LIQUIDATION PREFERENCE $25.00 PER SHARE)
---------------------
[BELCO LOGO]

The 6 1/2% Convertible Preferred Stock, par value $.01 per share (the
"Preferred Stock"), of Belco Oil & Gas Corp., a Nevada corporation ("Belco" or
the "Company"), is convertible at the option of the holder at any time, unless
previously redeemed, into shares of Common Stock, par value $.01 per share (the
"Common Stock"), of the Company, at an initial conversion rate of 1.1292 shares
of Common Stock for each share of Preferred Stock (equivalent to a conversion
price of $22.14 per share of Common Stock), subject to adjustment in certain
events. The outstanding Common Stock is listed on the New York Stock Exchange
under the symbol "BOG". On March 4, 1998, the last sale price of the Common
Stock on the New York Stock Exchange was $18 per share.

The Preferred Stock is redeemable at any time on and after March 15, 2001,
at the option of the Company, in whole or in part, initially at a redemption
price of $26.1375 per share, and thereafter at prices decreasing ratably
annually to $25.00 per share on and after March 15, 2008, plus accrued and
unpaid dividends. Dividends on the Preferred Stock will accrue and are
cumulative from the date of issuance and are payable quarterly commencing June
15, 1998. See "Description of Preferred Stock". Robert A. Belfer, the Company's
Chairman and Chief Executive Officer, and members of his family have agreed to
purchase 600,000 shares of Preferred Stock in this offering (the "Offering").

The Preferred Stock has been approved for listing on the New York Stock
Exchange, subject to official notice of issuance, under the symbol "BOG Pr".

SEE "RISK FACTORS" BEGINNING ON PAGE S-11 FOR CERTAIN CONSIDERATIONS
RELEVANT TO AN INVESTMENT IN THE PREFERRED STOCK OFFERED HEREBY.

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 SUPPLEMENT OR THE PROSPECTUS TO WHICH IT
RELATES. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

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

<TABLE>
<CAPTION>
INITIAL PUBLIC UNDERWRITING PROCEEDS TO
OFFERING PRICE DISCOUNT(1)(2) COMPANY(2)(3)
-------------- -------------- -------------
<S> <C> <C> <C>
Per Share............................................ $25.00 $.9375 $24.0625
Total(4)............................................. $95,000,000 $3,562,500 $91,437,500
</TABLE>

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

(1) The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933. See
"Underwriting".

(2) The Underwriters and the Company have agreed that the selling concession of
$337,500 relating to the shares of Preferred Stock sold to Mr. Belfer and
his family will be reimbursed to the Company, thereby increasing the
Company's proceeds from the Offering by such amount.

(3) Before deducting estimated expenses of $300,000 payable by the Company.

(4) The Company has granted to the Underwriters an option for 30 days after the
date of this Prospectus Supplement to purchase up to an additional 570,000
shares of Preferred Stock at the initial public offering price per share,
less the underwriting discount, solely to cover over-allotments. If such
option is exercised in full, the total initial public offering price,
underwriting discount and proceeds to the Company will be $109,250,000,
$4,096,875 and $105,153,125, respectively. See "Underwriting".

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

The shares of Preferred Stock offered hereby are offered severally by the
Underwriters, as specified herein, subject to receipt and acceptance by them and
their right to reject any order in whole or in part. It is expected that the
shares will be ready for delivery in New York, New York on or about March 10,
1998, against payment therefor in immediately available funds.

GOLDMAN, SACHS & CO. SALOMON SMITH BARNEY
HOWARD, WEIL, LABOUISSE, FRIEDRICHS
INCORPORATED

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

The date of this Prospectus Supplement is March 4, 1998
<PAGE> 2

CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE PREFERRED STOCK
AND THE COMMON STOCK, INCLUDING OVER-ALLOTMENT, STABILIZING AND SHORT-COVERING
TRANSACTIONS IN SUCH SECURITIES, AND THE IMPOSITION OF A PENALTY BID IN
CONNECTION WITH THE OFFERING. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE
"UNDERWRITING".
S-2
<PAGE> 3

SUMMARY

The following summary is qualified in its entirety by, and should be read
in conjunction with, the more detailed information and financial statements
(including the notes thereto) appearing elsewhere in this Prospectus Supplement.
Unless the context requires otherwise, all references in this Prospectus
Supplement to "Belco" or the "Company" refer to Belco Oil & Gas Corp. and its
consolidated subsidiaries. The pro forma information included in this Prospectus
Supplement gives effect to the 1997 Acquisition (as defined herein) described
below in "-- Recent Developments." Certain terms relating to the oil and gas
business are defined in "Glossary of Oil and Gas Terms."

THE COMPANY

Belco Oil & Gas Corp. is an independent energy company engaged in the
exploration for and the acquisition, exploitation, development and production of
natural gas and oil primarily in the Rocky Mountains, the Permian Basin, the
Mid-Continent region and the Austin Chalk Trend. Since its inception in April
1992, the Company has grown its reserve base largely through a balanced program
of exploration and development drilling and through acquisitions. The Company
concentrates its activities primarily in four core areas in which it has
accumulated detailed geologic knowledge and has developed significant management
and technical expertise. Additionally, the Company structures its participation
in natural gas and oil exploration and development activities to minimize
initial costs and risks, while permitting substantial follow-on investment. In
November 1997, the Company completed a significant acquisition by purchasing
Coda Energy, Inc. ("Coda"). See "-- Recent Developments."

The Company has achieved substantial growth in reserves, production,
revenues and EBITDA since 1992. Belco's estimated proved reserves have increased
at a compound annual growth rate of 55%, from 67 Bcfe as of December 31, 1992 to
604 Bcfe as of December 31, 1997. Average daily production has increased from 4
MMcfe per day in 1992 to approximately 217 MMcfe per day for the nine months
ended September 30, 1997 on a pro forma basis. Similarly, the growth in the
Company's EBITDA has been substantial, increasing from $2.9 million for the year
ended December 31, 1992, to $105.5 million for the year ended December 31, 1996.
The Company's pro forma EBITDA for the nine months ended September 30, 1997 was
$104.4 million. The Company's low cost structure is evidenced by its general and
administrative expenses of $0.06 per Mcfe and lease operating expenses of $0.14
per Mcfe in 1996. For the three years ended December 31, 1996, the Company's
operating cash inflows per Mcfe averaged $1.65 and its finding costs averaged
approximately $0.80 per Mcfe.

The Company's operations are currently focused in the Rocky Mountains,
primarily in the Green River (which includes the Moxa Arch Trend), Wind River
and Big Horn Basins, the Permian Basin in west Texas, the Mid-Continent region
in Oklahoma and north Texas, and the Austin Chalk Trend in both Texas and
Louisiana. At December 31, 1997, the Company had estimated proved reserves of
604 Bcfe with a pre-tax Present Value of $505 million (exclusive of $5.5 million
related to price risk management activities). As of December 31, 1997, Belco
held or controlled approximately 2.1 million gross (975,000 net) undeveloped
acres and had an interest in approximately 2,866 gross (1,768 net) wells of
which Belco operated 1,777.

BUSINESS STRENGTHS

The Company believes that it has certain strengths that provide it with
significant competitive advantages, including the following:

Proven Growth Record. The Company has generated consistent growth
through a balanced exploration and development program and through
acquisitions. From January 1, 1993 through December 31, 1997, the Company's
compounded annual growth in proved reserves was 60%. For the period January
1, 1994 through September 30, 1997, production increased by 52% and EBITDA
increased by 67% on a historical compounded annual basis.
S-3
<PAGE> 4

Successful Drilling Record. Since inception through September 30,
1997, the Company has drilled 566 gross (238 net) wells of which 494 gross
(210 net) were producing at September 30, 1997.

Substantial Drilling Inventory. The Company has spent in excess of $75
million since January 1, 1996 to increase its acreage position from
approximately 330,000 gross (146,000 net) undeveloped acres to
approximately 2.1 million gross (975,000 net) undeveloped acres at December
31, 1997. The Company believes that this acreage position will provide it
with significant drilling opportunities for at least the next three years.

Acquisition and Exploitation Activities. The Company continuously
reviews potential acquisitions of proved producing properties, including
properties with significant development potential. While the Company's
Houston division has historically grown through exploration and development
activity, the Company's Dallas division focuses its operations on
identifying and implementing property acquisitions and the subsequent
exploitation and development of the acquired properties. From January 1,
1992 through December 31, 1997, the Company's Dallas division made 12
significant acquisitions and numerous smaller incremental acquisitions,
identified, engineered and implemented nine new waterfloods, drilled 333
wells, converted 255 wells to water injection and increased proved reserves
at a compound annual growth rate of approximately 22%.

Strategic Alliances. The Company has formed strategic alliances with
experienced industry partners such as Amoco Production Company, Union
Pacific Resources Group, OXY USA, Snyder Oil Company and Tom Brown, Inc. In
cases where the Company is not the operator, the alliance has been
structured to enable the Company to become integrally involved with the
drilling and production decision making process. These strategic alliances
also provide the Company with the benefits of shared technological
expertise, while affording the Company the opportunity to diversify risk.

Experienced and Committed Management. Belco's senior management team
has extensive experience in the oil and gas industry. In particular, the
Company's Chairman and Chief Executive Officer, Robert A. Belfer, began his
career in the oil and gas industry in 1958 with Belco Petroleum Corporation
("BPC"), which grew to become a Fortune 500 company with operations
primarily in the Rocky Mountains and offshore Peru. In 1983, BPC merged
with InterNorth, a predecessor of Enron Corp. The Company's experienced
technical staff includes nine petroleum engineers, six production
engineers, eleven geologists and one geophysicist, who have, on average,
over 23 years of experience in the oil and gas industry. Mr. Belfer has
agreed to purchase 250,000 shares of Preferred Stock in the Offering.
Following completion of the Offering, Mr. Belfer and his family will own
approximately 77% of the outstanding shares of the Common Stock and 15.8%
of the outstanding shares of the Preferred Stock.

BUSINESS STRATEGY

The key elements of the Company's strategy are as follows:

S-4
<PAGE> 5

its existing holdings. In addition, the Company has other exploitation and
development opportunities which it plans to pursue. For the nine months
ended September 30, 1997 on a pro forma basis, the Company made capital
expenditures for drilling operations and leasehold acquisitions of
approximately $127.5 million (before property sales of approximately $14
million to third parties), and the Company estimates fourth quarter capital
expenditures will exceed $30 million. The Company currently has budgeted
$170 million for capital expenditures for drilling operations and for
producing property and leasehold acquisitions in 1998.

Pursue Selective Acquisitions. The Company continually reviews
potential acquisitions of oil and gas properties or businesses that
complement its existing operations and that provide long term growth
opportunities. The Company focuses its attention on potential acquisitions
principally within its core operating areas or in areas that may establish
a new core area and generally have (i) high working interests; (ii) long
lived reserves; (iii) operational control or the ability to exercise
significant influence over operations; and (iv) significant development
potential.

Utilize Advanced Technology. The Company extensively uses advanced
technology, including equipment designed specifically for drilling deep
horizontal wells, the application of innovative hydraulic fracturing
techniques, 3-D seismic and state-of-the-art enhanced recovery techniques.
To date, the Company has acquired approximately 154 square miles of 3-D
seismic data and 58,535 thousand miles of 2-D seismic data in its core
geographic areas.

Maintain Low Cost Structure. The Company's management team is focused
on maintaining a low cost structure to maximize cash flow and earnings. As
part of this strategy, the Company focuses on core operating areas where it
can achieve economies of scale. The Company believes that maintaining its
low cost structure is one of the factors that has allowed the Company to
have profitable operations in volatile pricing environments.

Reduce Commodity Price Volatility. The Company engages in a wide
variety of commodity price risk management transactions with the objective
of achieving more predictable revenues and cash flows and reducing its
exposure to fluctuations in natural gas and oil prices.

Maintain Financial Flexibility. The Company is committed to
maintaining financial flexibility in order to pursue exploration and
development activities and to pursue selective acquisitions. The Company
has funded its growth through internally generated cash flow, bank credit
facilities and proceeds from debt and equity offerings. The Company intends
to use the net proceeds from the Offering primarily to reduce indebtedness
incurred to finance the 1997 Acquisition.

RECENT DEVELOPMENTS

In November 1997, Belco completed the acquisition of Coda for consideration
of approximately $324 million plus 1.667 million three-year warrants to purchase
Common Stock at $27.50 per share (the "1997 Acquisition"). The assets acquired
in the 1997 Acquisition are concentrated in the Permian Basin of west Texas and
the Mid-Continent region of Oklahoma and north Texas. The 1997 Acquisition
materially added to the Company's reserve base, extended the Company's reserve
life from approximately 5.3 years to approximately 8 years, and established a
balanced reserve mix of 51% oil and 49% natural gas. With the 1997 Acquisition,
the Company established its Dallas, Texas division, which is focused on
acquisition and exploitation activities, including secondary recovery
operations.

In February 1998, the Company completed the acquisition of additional
properties in its Permian Basin core area for $37.5 million (the "Permian
Acquisition"). The properties consist of approximately 10.8 MMBOE of estimated
proved reserves and would add approximately 11% to the Company's estimated year
end 1997 reserves at a cost of approximately $3.50 per BOE, bringing total
Company estimated proved reserves to approximately 669 Bcfe.

S-5
<PAGE> 6

In February 1998, the Company merged Coda into Belco and assumed the
obligations under the Coda Notes (as defined herein). See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."

The Company's executive offices are located at 767 Fifth Avenue, 46th
Floor, New York, New York 10153, and its telephone number is (212) 644-2200.

YEAR-END OPERATING RESULTS

On February 24, 1998, the Company announced results for the quarter and
year ended December 31, 1997. A summary of the information released appears in
the table and discussion below. The information set forth below should be read
in conjunction with the Company's consolidated financial statements and the
notes thereto incorporated by reference in the accompanying Prospectus. In
addition, the information set forth below will be superseded in its entirety by
the Company's Annual Report on Form 10-K for the year ended December 31, 1997 to
be filed on or before March 31, 1998. See "Available Information" and
"Incorporation of Certain Documents by Reference" in the accompanying
Prospectus. The financial and operating data presented below are not audited and
are not necessarily indicative of the results that may be expected for future
periods.

<TABLE>
<CAPTION>
THREE MONTHS ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31,
------------------ -------------------
1997 1996 1997 1996
-------- ------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS
AND OPERATIONS DATA)
<S> <C> <C> <C> <C>
FINANCIAL DATA(1):
Total revenues................................. $ 42,367 $28,204 $126,760 $116,396
Pro forma net income........................... $(85,243) $ 9,431 $(56,908) $ 42,636
Pro forma basic net income per common share.... $ (2.70) $ 0.30 $ (1.80) $ 1.42
Pro forma diluted net income per common share.. $ (2.70) $ 0.30 $ (1.80) $ 1.42
Weighted average common shares
outstanding................................. 31,582 31,500 31,582 29,986
OPERATIONS DATA:
Average Daily Production:
Oil (bbls).................................. 6,291 2,407 3,547 2,169
Natural gas (Mcf)........................... 138,451 132,274 136,193 140,134
Average Sales Price:
Oil (per bbl)............................... $ 18.48 $ 23.39 $ 19.28 $ 21.30
Natural gas (per Mcf)....................... $ 2.32 $ 2.39 $ 2.11 $ 2.00
UNIT ECONOMICS (PER MCFE):
Oil and gas sales revenues (unhedged).......... $ 2.48 $ 2.68 $ 2.26 $ 2.14
Commodity price risk management activities
Cash........................................ (.36) .08 (.13) 0.06
Non-cash.................................... .43 (.70) .02 (.17)
Oil and gas operating expenses................. (.38) (.14) (.22) (.14)
General and administrative..................... (.09) (.06) (.07) (.06)
Depreciation, depletion and amortization....... (.89) (.82) (.81) (.73)
-------- ------- -------- --------
Pre-tax operating profit(2).................... $ 1.19 $ 1.04 $ 1.05 $ 1.10
======== ======= ======== ========
Gross cash margin(3)........................... $ 1.65 $ 2.56 $ 1.84 $ 2.00
======== ======= ======== ========
</TABLE>

(footnotes on following page)

S-6
<PAGE> 7

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

(1) The pro forma amounts present the Company as if it was a taxable corporation
for all periods and are based on the average number of shares outstanding
during the period assuming the shares issued in connection with the
Combination were outstanding for all periods.

(2) The three months and year ended December 31, 1997 exclude a ceiling test
writedown of $150 million (non-cash).

(3) Gross cash margin is pre-tax margin plus depreciation, depletion and
amortization and includes non-cash effects of commodity price risk
management activities.

The net loss for the fourth quarter of 1997 of $85.2 million and the net
loss for the year ended December 31, 1997 of $56.9 million were significantly
impacted by a full cost ceiling writedown of oil and gas properties of $150
million ($98 million net of tax) in the fourth quarter of 1997. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Overview."

THE OFFERING

Securities Offered......... 3,800,000 shares of Preferred Stock (4,370,000
shares if the Underwriters' over-allotment option
is exercised in full). Mr. Belfer, the Company's
Chairman and Chief Executive Officer, and members
of his family have agreed to purchase 600,000
shares of Preferred Stock in the Offering. See
"Underwriting."

Dividends.................. Cumulative from the date of original issue at the
annual rate of $1.625 per share, payable quarterly
commencing June 15, 1998 when, as and if declared
by the Board of Directors. The Company may not have
sufficient current or accumulated earnings and
profits as determined for federal income tax
purposes at the time it makes a distribution; in
that event, distributions to corporate holders,
that exceed the Company's earnings and profits,
will not qualify for the dividends received
deduction. See "Certain Federal Income Tax
Considerations -- Dividends on Preferred Stock."

Liquidation Preference..... $25.00 per share, plus accrued and unpaid
dividends.

Conversion Rights.......... The Preferred Stock will be convertible at the
option of the holder at any time, unless previously
redeemed, into shares of Common Stock at an initial
conversion rate of 1.1292 shares of Common Stock
for each share of Preferred Stock (equivalent to a
conversion price of $22.14 per share of Common
Stock), subject to adjustment in certain events.
Until March 10, 2001, upon any Change of Control
(as defined herein) that is not a Common Stock
Transaction (as defined herein), each holder of
Preferred Stock shall, in the event that the Market
Value (as defined herein) at such time is less than
the Conversion Price, have a one time option to
convert such holder's shares of Preferred Stock
into shares of Common Stock at a conversion price
equal to the greater of (i) Market Value of the
Common Stock as of the date of the Change of
Control and (ii) $12.00. In lieu of issuing the
shares of Common Stock issuable upon conversion in
the event of a Change of Control, the Company may,
at its option, make a cash payment equal to the
Market Value of the shares of Common

S-7
<PAGE> 8

Stock otherwise issuable. See "Description of
Preferred Stock -- Conversion Rights."

Redemption at the Option of
the Company.............. The Preferred Stock may not be redeemed prior to
March 15, 2001. At any time on or after such date,
the Preferred Stock may be redeemed in whole or in
part at the option of the Company initially at
$26.1375 per share and thereafter at prices
decreasing ratably to an amount equivalent to
$25.00 per share on and after March 15, 2008, in
each case plus accrued and unpaid dividends, if
any, to the redemption date.

Voting Rights.............. The holders of the Preferred Stock will not have
any voting rights, except as required by applicable
law and except that, among other things, whenever
accumulated and unpaid dividends on the Preferred
Stock are equal to or exceed the equivalent of six
quarterly dividends payable on the Preferred Stock,
the holders of the Preferred Stock, voting
separately as a class with the holders of shares of
any other series of parity stock upon which like
voting rights have been conferred and are
exercisable, will be entitled to elect two
directors to the Board of Directors until the
dividend arrearage has been paid or amounts have
been set apart for such payment. Such voting rights
will terminate when all accumulated and unpaid
dividends have been paid in full or declared and
funds set apart for payment in full. The term of
office of all directors so elected will terminate
immediately upon such payment or setting apart for
payment. See "Description of Preferred
Stock -- Voting Rights."

Ranking.................... The Preferred Stock will have priority over the
Common Stock with respect to the payment of
dividends and upon the liquidation, dissolution or
winding up of the Company.

Use of proceeds............ To repay a portion of outstanding indebtedness
under the Company's credit facility ($121 million
at February 28, 1998), thereby creating additional
borrowing capacity which, together with any
remaining net proceeds, will be used to fund the
Company's planned exploration and development
activities and possible future acquisitions, as
well as other general corporate purposes. See "Use
of Proceeds."

New York Stock Exchange
symbol................... BOG Pr

RISK FACTORS

See "Risk Factors" for a discussion of certain factors that should be
considered in connection with an investment in the Preferred Stock, the
uncertainty of oil and gas prices and certain risks associated with an
investment in the Preferred Stock.

S-8
<PAGE> 9

SUMMARY RESERVE DATA

The following table sets forth summary information with respect to the
Company's estimated net proved oil and gas reserves as of December 31, 1997.
Information in this Prospectus Supplement as of December 31, 1997 relating to
properties with 94% of the Company's estimated net proved oil and gas reserves
and the estimated future net revenues attributable thereto is based upon the
reserve report ("Miller and Lents Report") prepared by Miller and Lents, Ltd.
("Miller and Lents"), independent petroleum engineers. All calculations of
estimated net proved reserves have been made in accordance with the rules and
regulations of the Securities and Exchange Commission (the "Commission") and,
except as otherwise indicated, give no effect to federal or state income taxes
otherwise attributable to estimated future net revenues from the sale of oil and
gas. The present value of estimated future net revenues has been calculated
using a discount factor of 10%. See "Risk Factors -- Uncertainty of Estimates of
Oil and Gas Reserves" and "Experts."

<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1997
----------------------------------------------
PROVED DEVELOPED PROVED UNDEVELOPED TOTAL
---------------- ------------------ ------
<S> <C> <C> <C>
Estimated proved reserves:
Gas (Bcf)....................................... 226.1 71.1 297.2
Oil (MMBbls).................................... 41.3 9.9 51.2
Total (Bcfe)...................................... 473.6 130.5 604.1
Estimated future net revenue before income taxes
(in millions)(1)................................ $792.1 $139.9 $932.0
Present value of estimated future net revenues
before income taxes discounted at 10% (in
millions)(1).................................... $442.0 $ 62.9 $504.9
</TABLE>

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

(1) Estimated future net revenue before income taxes represents estimated future
gross revenue to be generated from the production of proved reserves, net of
estimated production and future development costs, using average December
1997 prices, which were $2.30 per Mcf of gas and $17.28 per barrel of oil
without giving effect to commodities price risk management activities
accounted for as hedges. At December 31, 1997, the estimated future net
revenue before income taxes and the present value of such estimated future
net revenue before income taxes related to such activities were $5.9 million
and $5.5 million, respectively (based on oil and gas prices in effect at
December 31, 1997), which amounts have not been added to estimated future
net revenue before income taxes and its present value as shown above. If
such amounts were added, estimated future net revenue before income taxes
would equal $798 million (Proved Developed) and $938 million (Total) and
present values of such estimated future net revenues before income taxes
would equal $447.5 million (Proved Developed) and $510.4 million (Total).

SUMMARY PRODUCTION, PRICE AND COST DATA

<TABLE>
<CAPTION>
PRO FORMA(1)
-------------
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED
--------------------------- SEPTEMBER 30,
1994 1995 1996 1997
------- ------- ------- -------------
<S> <C> <C> <C> <C>
Production Data:
Oil and condensate (MBbls)....................... 691 961 794 3,151
Natural gas (MMcf)............................... 17,482 37,047 51,289 40,448
Natural gas equivalent (MMcfe)................... 21,628 42,813 56,053 59,354
Unit Economics (per Mcfe):
Oil and gas sales revenues (unhedged)............ $ 1.86 $ 1.61 $ 2.14 $ 2.43
Commodity price risk management activities
-- Cash....................................... .03 .22 .06 (.04)
-- Non-Cash................................... -- -- (.17) (.09)
Oil and gas operating expenses................... (.25) (.14) (.14) (.55)
General and administrative....................... (.10) (.06) (.06) (.05)
Depreciation, depletion and amortization......... (.65) (.64) (.73) (1.09)
------- ------- ------- -------
Pre-tax operating profit(2)(3)................... $ 0.89 $ 0.99 $ 1.10 $ 0.61
======= ======= ======= =======
Gross cash margin(4)............................. $ 1.54 $ 1.63 $ 2.00 $ 1.79
======= ======= ======= =======
</TABLE>

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

(1) Gives pro forma effect to the 1997 Acquisition as if it had occurred on
January 1, 1997.

(2) Pro forma amount for nine months ended September 30, 1997 excludes a ceiling
test writedown of $150 million (non-cash) or $2.53 per Mcfe.

(3) Pre-tax operating profit for the year ended December 31, 1996 excludes
interest income and interest expense of $2.6 million and $0, respectively.
Pro forma pre-tax operating profit for the nine months ended September 30,
1997 excludes interest income and interest expense of $3.2 million and $17.3
million, respectively.

(4) Gross cash margin is pre-tax operating profit plus depreciation, depletion
and amortization and including non-cash effects of commodity price risk
management activities.

S-9
<PAGE> 10

SUMMARY FINANCIAL DATA

The following table sets forth summary historical and pro forma financial
data for the Company as of and for each of the periods indicated. The following
information should be read in conjunction with "Selected Historical Financial
Data," "Management's Discussion and Analysis of Financial Condition and Results
of Operations" and the historical and pro forma financial statements of the
Company and the related notes thereto included elsewhere in this Prospectus
Supplement.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
YEAR ENDED DECEMBER 31, --------------------
------------------------------ PRO FORMA
1994 1995 1996 1997 1997(1)
-------- -------- -------- -------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues
Oil and gas sales........................................ $ 40,362 $ 68,767 $119,710 $ 89,742 $ 144,322
Commodity price risk management activities............... 550 9,480 (5,967) (7,674) (7,674)
Interest................................................. 195 353 2,653 2,326 3,249
-------- -------- -------- -------- ---------
Total revenues............................................. 41,107 78,600 116,396 84,394 139,897
-------- -------- -------- -------- ---------
Costs and expenses
Oil and gas operating expenses........................... 5,510 5,824 7,847 6,657 32,391
Depreciation, depletion and amortization................. 14,072 27,590 40,904 32,190 64,564
Writedown of oil and gas properties(2)................... -- -- -- -- 150,000
General and administrative............................... 2,269 2,597 3,059 2,476 3,061
Interest................................................. -- -- -- -- 17,251
-------- -------- -------- -------- ---------
Total costs and expenses................................... 21,851 36,011 51,810 41,323 267,267
-------- -------- -------- -------- ---------
Income (loss) before taxes................................. 19,256 42,589 64,586 43,071 (127,370)
Pro forma provision (benefit) for income taxes(3).......... 5,030 13,852 21,953 14,752 (43,551)
-------- -------- -------- -------- ---------
Pro forma net income (loss)(3)............................. $ 14,226 $ 28,737 $ 42,633 $ 28,319 $ (83,819)
======== ======== ======== ======== =========
Pro forma earnings (loss) per share(1)(4)
Basic.................................................... $ .57 $ 1.15 $ 1.42 $ .90 $ (2.65)
======== ======== ======== ======== =========
Diluted.................................................. $ .57 $ 1.15 $ 1.42 $ .89 $ (2.65)
======== ======== ======== ======== =========
Weighted Average Common Shares Outstanding................. 25,000 25,000 29,986 31,582 31,582
======== ======== ======== ======== =========
OPERATING AND OTHER DATA:
EBITDA(5).................................................. $ 33,328 $ 70,179 $105,490 $ 75,261 $ 104,445
Capital expenditures....................................... 52,230 71,387 142,712 101,994 127,504
Net cash provided by operating activities.................. 28,126 62,037 108,059 79,041 102,781
BALANCE SHEET DATA (END OF PERIOD):
Working capital............................................ $ 14,357 $ 446 $ 48,667 $142,857 $ 9,058
Total assets............................................... 101,625 145,550 303,918 487,416 679,213
Long term debt, including current maturities............... 6,930 22,000 -- 150,000 351,090
Total stockholders' equity................................. 89,890 105,015 233,203 261,707 174,207
</TABLE>

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

(1) The pro forma statement of operations data, operating and other data and
balance sheet data include pro forma adjustments to reflect the 1997
Acquisition.

(2) In the quarter ended December 31, 1997, the Company will record a non-cash
$150 million ceiling test provision, which includes the effect of a non-cash
$101 million "gross up" pursuant to FASB 109 attributable to the 1997
Acquisition and other factors. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Overview."

(3) Gives pro forma effect to the application of federal and state income taxes
to the Company as if it were a taxable corporation for the periods
presented. 1996 excludes a one-time non-cash deferred tax charge of $30.1
million recognized as a result of the combination of ownership interests in
certain entities and direct interests in oil and gas properties and certain
hedge transactions (the "Combination") consummated on March 29, 1996 in
connection with the Company's initial public offering.

(4) Pro forma earnings per share has been computed as if the 25,000,000 shares
of Common Stock that were issued in connection with the Combination had been
outstanding for all years prior to 1996.

(5) EBITDA represents income from continuing operations plus income taxes,
interest expense, depletion, depreciation and amortization expense and
writedown of oil and gas properties. EBITDA is not presented as an indicator
of the Company's operating performance, an indicator of cash available for
discretionary spending or a measure of liquidity. EBITDA is not a measure of
financial performance prepared in accordance with generally accepted
accounting principles and may not be comparable to other similarly titled
measures of other companies.

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FORWARD-LOOKING STATEMENTS

This Prospectus Supplement includes "forward-looking statements" within the
meaning of Section 27A of the Securities Act and Section 21E of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than
statements of historical facts included in this Prospectus Supplement (including
the information incorporated by reference therein), including without limitation
statements under "Summary," "Risk Factors," "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and "Business and
Properties" regarding planned capital expenditures, the availability of capital
resources to fund capital expenditures, estimates of proved reserves, the number
of anticipated wells to be drilled in 1998 and thereafter, the Company's
financial position, business strategy and other plans and objectives for future
operations, are forward-looking statements. Although the Company believes that
the expectations reflected in such forward-looking statements are reasonable, it
can give no assurance that such expectations will prove to have been correct.
There are numerous uncertainties inherent in estimating quantities of proved oil
and natural gas reserves and in projecting future rates of production and timing
of development expenditures, including many factors beyond the control of the
Company. Reserve engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact way,
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 made by different engineers often vary from one another. In
addition, results of drilling, testing and production subsequent to the date of
an estimate may justify revisions of such estimate and such revisions, if
significant, would change the schedule of any further production and development
drilling. Accordingly, reserve estimates are generally different from the
quantities of oil and natural gas that are ultimately recovered. Additional
important factors that could cause actual results to differ materially from the
Company's expectations are disclosed under "Risk Factors" and elsewhere in this
Prospectus Supplement. All subsequent written and oral forward-looking
statements attributable to the Company or persons acting on its behalf are
expressly qualified in their entirety by such factors.

RISK FACTORS

In addition to the other information set forth elsewhere in this Prospectus
Supplement and the Prospectus, the following factors relating to the Company
should be carefully considered when evaluating an investment in the Preferred
Stock.

VOLATILITY OF OIL AND GAS PRICES; MARKETABILITY OF PRODUCTION

The Company's revenue, profitability and future rate of growth are
substantially dependent upon the prevailing prices of, and demand for, oil and
natural gas. The Company's ability to maintain or increase its borrowing
capacity and to obtain additional capital on attractive terms is also
substantially dependent upon oil and gas prices. Prices for oil and natural gas
are subject to wide fluctuation in response to relatively minor changes in the
supply of and demand for oil and natural gas, market uncertainty and a variety
of additional factors that are beyond the control of the Company. These factors
include the level of consumer product demand, weather conditions, domestic and
foreign governmental regulations, the price and availability of alternative
fuels, political conditions in the Middle East, the foreign supply of oil and
natural gas, the price of oil and gas imports and overall economic conditions.
From time to time, oil and gas prices have been depressed by excess domestic and
imported supplies. There can be no assurance that current price levels will be
sustained. It is impossible to predict future oil and natural gas price
movements with any certainty. Declines in oil and natural gas prices may
adversely affect the Company's financial condition, liquidity and results of
operations and may reduce the amount of the Company's oil and natural gas that
can be produced economically. Market prices for oil and gas have generally
declined since December 1997. Additionally, substantially all of the Company's
sales of oil and natural gas are made in the spot market or pursuant to
contracts based on spot market prices and
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<PAGE> 12

not pursuant to long-term fixed price contracts. With the objective of reducing
price risk, the Company enters into hedging transactions with respect to a
portion of its expected future production. There can be no assurance, however,
that such hedging transactions will reduce risk or mitigate the effect of any
substantial or extended decline in oil or natural gas prices. Any substantial or
extended decline in the prices of oil or natural gas would have a material
adverse effect on the Company's financial condition and results of operations.

In addition, the marketability of the Company's production depends upon the
availability and capacity of gas gathering systems, pipelines and processing
facilities. Federal and state regulation of oil and gas production and
transportation, general economic conditions and changes in supply and demand all
could adversely affect the Company's ability to produce and market its oil and
natural gas. If market factors were to change dramatically, the financial impact
on the Company could be substantial. The availability of markets and the
volatility of product prices are beyond the control of the Company and represent
a significant risk. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Overview" and "Business and
Properties -- Marketing."

Volatile oil and gas prices make it difficult to estimate the value of
producing properties for acquisition and often cause disruption in the market
for oil and gas producing properties, as buyers and sellers have difficulty
agreeing on such value. Price volatility also makes it difficult to budget for
and project the return on acquisitions and development and exploration projects.

UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES

This Prospectus Supplement contains estimates of the Company's proved oil
and gas reserves and the estimated future net revenues therefrom based upon the
Company's estimates and the Miller and Lents Report that rely upon various
assumptions, including assumptions required by the Commission as to oil and gas
prices, drilling and operating expenses, capital expenditures, taxes and
availability of funds. The process of estimating oil and gas reserves is
complex, requiring significant decisions and assumptions in the evaluation of
available geological, geophysical, engineering and economic data for each
reservoir. As a result, such estimates are inherently imprecise. Actual future
production, oil and gas prices, revenues, taxes, development expenditures,
operating expenses and quantities of recoverable oil and gas reserves may vary
substantially from those estimated in the Company's estimates and the Miller and
Lents Report. Any significant variance in these assumptions could materially
affect the estimated quantity and value of reserves set forth in this Prospectus
Supplement. In addition, the Company's proved reserves may be subject to
downward or upward revision based upon production history, results of future
exploration and development, prevailing oil and gas prices and other factors,
many of which are beyond the Company's control. Actual production, revenues,
taxes, development expenditures and operating expenses with respect to the
Company's reserves will likely vary from the estimates used, and such variances
may be material.

Approximately 22% of the Company's total proved reserves at December 31,
1997 were undeveloped, which are by their nature less certain. Recovery of such
reserves will require significant capital expenditures and successful drilling
operations. The reserve data set forth in the Company's estimates and the Miller
and Lents Report assumes that substantial capital expenditures by the Company
will be required to develop such reserves. Although cost and reserve estimates
attributable to the Company's oil and gas reserves have been prepared in
accordance with industry standards, no assurance can be given that the estimated
costs are accurate, that development will occur as scheduled or that the results
will be as estimated. See "Business and Properties -- Oil and Gas Reserves."

The present value of future net revenues referred to in this Prospectus
Supplement should not be construed as the current market value of the estimated
oil and gas reserves attributable to the Company's properties. In accordance
with applicable requirements of the Commission, the esti-

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<PAGE> 13

mated discounted future net cash flows from proved reserves are generally based
on prices and costs as of the date of the estimate, whereas actual future prices
and costs may be materially higher or lower. Actual future net cash flows also
will be affected by increases in consumption by gas purchasers and changes in
governmental regulations or taxation. The timing of actual future net cash flows
from proved reserves, and thus their actual present value, will be affected by
the timing of both the production and the incurrence of expenses in connection
with development and production of oil and gas properties. In addition, the 10%
discount factor, which is required by the Commission to be used in calculating
discounted future net cash flows for reporting purposes, is not necessarily the
most appropriate discount factor based on interest rates in effect from time to
time and risks associated with the Company or the oil and gas industry in
general.

RESERVE REPLACEMENT

As is customary in the oil and gas exploration and production industry, the
Company's future success depends upon its ability to find, develop or acquire
additional oil and gas reserves that are economically recoverable. Unless the
Company replaces its estimated proved reserves (through development, exploration
or acquisition), the Company's proved reserves will generally decline as they
are produced.

Exploratory drilling and, to a lesser extent, development drilling involve
a high degree of risk that no commercial production will be obtained or that the
production will be insufficient to recover drilling and completion costs. The
costs of drilling, completing and operating wells are uncertain. The Company's
drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, including title problems, weather conditions, compliance with
governmental requirements and shortages or delays in the delivery of equipment.
Furthermore, completion of a well does not assure a profit on the investment or
a recovery of drilling, completion and operating costs. See "Business and
Properties -- Costs Incurred and Drilling Results."

The Company's current strategy includes increasing its reserve base through
acquisitions of leaseholds with drilling potential and by continuing to exploit
its existing properties. There can be no assurance, however, that the Company's
exploration and development projects will result in significant additional
reserves or that the Company will have continuing success drilling productive
wells at economically viable costs. Furthermore, while the Company's revenues
may increase if prevailing oil and gas prices increase significantly, the
Company's finding costs for additional reserves could also increase. For a
discussion of the Company's reserves, see "Business and Properties -- Oil and
Gas Reserves."

CEILING LIMITATION WRITEDOWNS

The Company reports its operations using the full cost method of accounting
for oil and gas properties. Under the full cost accounting rules, the net
capitalized costs of oil and gas properties may not exceed a "ceiling limit",
calculated at the end of each quarter, which is based upon the present value of
estimated future net cash flows from proved reserves, discounted at 10%, plus
the lower of cost or fair market value of unproved properties, net of related
tax effects. If net capitalized costs of oil and gas properties exceed the
ceiling limit, the Company is subject to a ceiling limitation writedown to the
extent of such excess. A ceiling limitation writedown is a charge to earnings
which does not impact cash flows. However, such writedowns impact the amount of
the Company's stockholders' equity. The risk that the Company will be required
to write down the carrying value of its oil and gas properties increases when
oil and gas prices are depressed or volatile. Application of these rules during
periods of relatively low oil or gas prices, even if temporary, may result in a
ceiling writedown. In addition, writedowns may occur if the Company makes
additional acquisitions or has substantial downward revisions in its estimated
proved reserves. The recent significant declines in oil and gas prices increase
the risk that the Company is required to record a ceiling limitation writedown.
See -- Volatility of Oil and Natural Gas Prices." The Company will record in its
fourth quarter ended December 31, 1997 a non-cash writedown of approximately
$150 million
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<PAGE> 14

($98 million after tax), a significant portion of which is attributable to the
1997 Acquisition. No assurance can be given that the Company will not experience
additional ceiling limitation writedowns in the future. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."

SUBSTANTIAL CAPITAL REQUIREMENTS

The Company makes, and will continue to make, substantial expenditures for
the development, exploration, acquisition and production of oil and natural gas
reserves. The Company incurred capital expenditures of $142.7 million during
1996 and in excess of $160 million (before property sales of approximately $14
million to third parties) during 1997. The Company has budgeted $170 million for
capital expenditures for producing properties and leasehold acquisitions and
drilling operations in 1998. Management believes that the Company will have
sufficient cash provided by operating activities, borrowings under its credit
facility and any remaining proceeds from the Offering to fund planned capital
expenditures in 1998. However, if revenues or cash flows from operations
decrease as a result of lower oil and natural gas prices or operating
difficulties, the Company may be limited in its ability to expend the capital
necessary to undertake or complete its planned drilling program, or it may be
forced to raise additional debt or equity proceeds to fund such expenditures.
The Company's credit facility currently limits the amounts the Company may
borrow to $150 million, subject to increase or decrease based upon borrowing
base adjustments. After giving effect to the application of the estimated net
proceeds from the Offering, the Company will have $30.0 million of outstanding
borrowings under its bank credit facility. There can be no assurance that
additional debt or equity financing or cash generated by operations will be
available to meet these requirements. See "Use of Proceeds" and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."

ACQUISITION RISKS

The Company continues to pursue the acquisition of oil and gas properties
and businesses. Although no definitive agreements have been reached regarding
any such acquisitions, if consummated such acquisitions may have a material
impact on the Company's business. Any acquisition by the Company must satisfy
the applicable covenants set forth in the indenture governing the Company's
8 7/8% Senior Subordinated Notes due 2007 (the "8 7/8% Indenture"), the
indenture governing Coda's 10 1/2% Senior Subordinated Notes due 2006 (the "Coda
Indenture") and the credit agreement (the "Credit Agreement") relating to the
Company's Credit Facility (as defined herein).

Successful acquisition of producing properties generally requires accurate
assessments of (i) recoverable reserves; (ii) future oil and gas prices and
operating costs; (iii) potential environmental and other liabilities; and, (iv)
other factors. Such assessments are necessarily inexact and their accuracy
inherently uncertain. It generally is not feasible to review in detail every
individual property involved in an acquisition. Ordinarily, review efforts are
focused on the higher-valued properties. Nevertheless, even a detailed review of
all properties and records may not reveal existing or potential problems nor
will it permit the Company to become sufficiently familiar with the properties
to assess fully their deficiencies and capabilities. Inspections are not always
performed on every well, and environmental problems, such as groundwater
contamination, are not necessarily observable even when an inspection is
undertaken.

HOLDING COMPANY STRUCTURE

The Company conducts all of its operations through subsidiaries.
Accordingly, the Company relies on dividends and cash advances from its
subsidiaries to provide funds necessary to meet its obligations, and the Company
will rely upon such sources of funds to pay dividends on the Preferred Stock.
The ability of any such subsidiary to pay dividends or make cash advances is
subject to

S-14
<PAGE> 15

applicable laws and contractual restrictions, including restrictions under
credit agreements between such subsidiary and third party lenders, as well as
the financial condition and operating requirements of such subsidiary.

RESTRICTIONS UPON ABILITY TO PAY DIVIDENDS

The ability of the Company to make dividend payments on the Preferred Stock
will be dependent on the Company's future performance and liquidity. In
addition, the Credit Agreement, the 8 7/8% Indenture and the Coda Indenture
contain restrictions on the ability of the Company to pay cash dividends on its
capital stock, including the Preferred Stock. The Credit Agreement permits the
Company to pay cash dividends of up to $25,000,000 in the aggregate and
restricts additional dividends to 50% of the Company's cumulative consolidated
net income (as defined in the Credit Agreement) (or if such consolidated net
income is a deficit, 100% of such deficit) from October 1, 1997, subject to
increases and decreases to such cumulative amount based on other adjustments
specified in the Credit Agreement. The Credit Agreement also prohibits the
Company from paying cash dividends if there is a default or event of default
under the Credit Agreement. The 8 7/8% Indenture permits the Company to pay cash
dividends of up to $25,000,000 in the aggregate and restricts additional
dividends to 50% of the Company's cumulative consolidated net income (as defined
in the 8 7/8% Indenture) (or if such consolidated net income is a deficit, 100%
of such deficit) from October 1, 1997, subject to increases and decreases to
such cumulative amount based on other adjustments specified in the 8 7/8%
Indenture. The 8 7/8% Indenture also prohibits the payment of cash dividends in
the event that (i) the Company would not be permitted to incur $1.00 of
additional indebtedness under the 8 7/8% Indenture at the time of a proposed
dividend payment based on its inability to satisfy a fixed charge coverage ratio
or (ii) there is a default or event of default under the 8 7/8% Indenture. In
February 1998, the Company merged Coda into the Company and, in connection
therewith, assumed the obligations of Coda, and became subject to the
restrictions, under the Coda Indenture. The Coda Indenture permits the Company
to pay cash dividends of up to $5,000,000 in the aggregate and restricts
additional dividends to 50% of the Company's cumulative consolidated net income
(as defined in the Coda Indenture) (or if such consolidated net income is a
deficit, 100% of such deficit) from April 1, 1996, subject to increases and
decreases to such cumulative amount based on other adjustments specified in the
Coda Indenture. The Company believes that it will have capacity in addition to
the $5,000,000 under the Coda Indenture, based on such adjustments. The Coda
Indenture also prohibits the payment of cash dividends in the event that (i) the
Company would not be permitted to incur $1.00 of additional indebtedness under
the Coda Indenture at the time of a proposed dividend payment based on its
inability to satisfy a fixed charge coverage ratio or (ii) there is a default or
event of default under the Coda Indenture.

OPERATING HAZARDS AND UNINSURED RISKS; PRODUCTION CURTAILMENTS

Oil and gas drilling and production activities are subject to numerous
risks, many of which are beyond the Company's control. These risks include the
risk that no commercially productive oil or natural gas reservoirs will be
encountered, that operations may be curtailed, delayed or canceled and that
title problems, weather conditions, compliance with governmental requirements,
mechanical difficulties or shortages or delays in the delivery of drilling rigs,
work boats and other equipment may limit the Company's ability to market its
production. There can be no assurance that new wells drilled by the Company will
be productive or that the Company will recover all or any portion of its
investment. Drilling for oil and natural gas may involve unprofitable efforts,
not only from dry wells but also from wells that are productive but do not
produce sufficient net revenues to return a profit after drilling, operating and
other costs. In addition, the Company's properties may be susceptible to
hydrocarbon drainage from production by other operators on adjacent properties.

Industry operating risks include the risk of fire, explosions, blow-outs,
pipe failure, abnormally pressured formations and environmental hazards such as
oil spills, gas leaks, ruptures or dis-

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<PAGE> 16

charges 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. Additionally, many of the Company's
oil and gas operations are located in an area that is subject to tropical
weather disturbances, some of which can be severe enough to cause substantial
damage to facilities and possibly interrupt production. 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 any
insurance will be adequate to cover losses or liabilities. The Company cannot
predict the continued availability of insurance at premium levels that justify
its purchase. Losses and liabilities arising from uninsured or under-insured
events could have a material adverse effect on the financial condition and
results of operations of the Company.

From time to time, due primarily to contract terms, pipeline interruptions
or weather conditions, the producing wells in which the Company owns an interest
may be subject to production curtailments. The curtailments may vary from a few
days to several months. In most cases the Company will be provided only limited
notice as to when production will be curtailed and the duration of such
curtailments. The Company is currently not curtailed on any of its production.

COMPETITION

The Company operates in a highly competitive environment. The Company
competes with major and independent oil and gas companies for the acquisition of
desirable oil and gas properties, as well as for the equipment and labor
required to develop and operate such properties. Many of these competitors have
financial and other resources substantially greater than those of the Company.
See "Business and Properties -- Competition."

RISKS OF PRICE RISK MANAGEMENT TRANSACTIONS

In order to manage its exposure to price risks in the marketing of its oil
and natural gas, the Company has in the past and expects to continue to enter
into oil and natural gas price risk management arrangements with respect to a
portion of its expected production. These arrangements may include futures
contracts on the New York Mercantile Exchange ("NYMEX"), fixed price delivery
contracts and financial swaps. While intended to reduce the effects of
volatility of the price of oil and natural gas, such transactions may limit
potential gains by the Company if oil and natural gas prices were to rise or
fall substantially over the price established by the arrangement. In addition,
such transactions may expose the Company to the risk of financial loss in
certain circumstances, including instances in which (i) production is less than
expected; (ii) if there is a widening of price differentials between delivery
points for the Company's production and the delivery point assumed in the
arrangement; (iii) the counterparties to the Company's future contracts fail to
perform under the contract; or (iv) a sudden, unexpected event materially
impacts oil or natural gas prices. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources" and "Business and Properties -- Price Risk Management Transactions."

GOVERNMENTAL REGULATION

Oil and gas operations are subject to various United States federal, state
and local governmental regulations that change from time to time in response to
economic or political conditions. Matters subject to regulation include
discharge permits for drilling operations, drilling and abandonment bonds,
reports concerning operations, the spacing of wells, and unitization and pooling
of properties and taxation. From time to time, regulatory agencies have imposed
price controls and limitations on production by restricting the rate of flow of
oil and gas wells below actual production capacity in order to conserve supplies
of oil and gas. In addition, the production, handling, storage, transportation
and disposal of oil and gas, by-products thereof and other substances and
materials produced
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<PAGE> 17

or used in connection with oil and gas operations are subject to regulation
under federal, state and local laws and regulations primarily relating to
protection of human health and the environment. The Company may also be subject
to substantial clean-up costs for any toxic or hazardous substance that may
exist under any of its current properties or properties that it has operated in
the past. To date, expenditures related to complying with these laws and for
remediation of existing environmental contamination have not been significant in
relation to the results of operations of the Company.

Although the Company believes it is in substantial compliance with all
applicable laws and regulations, the requirements imposed by such laws and
regulations are frequently changed and subject to interpretation. In addition,
the recent trend toward stricter standards in environmental legislation and
regulation is likely to continue. For instance, legislation has been proposed in
Congress from time to time that would reclassify certain crude oil and natural
gas exploration and production wastes as "hazardous wastes" which would make the
reclassified wastes subject to much more stringent handling, disposal and
clean-up requirements. If such legislation were to be enacted, it could have a
significant impact on the operating costs of the Company, as well as the oil and
gas industry in general. The Company could incur substantial costs to comply
with environmental laws and regulations, and the Company is unable to predict
the ultimate cost of compliance with these requirements or their effect on its
production. See "Business and Properties -- Regulation."

RELIANCE ON KEY PERSONNEL

The Company depends, and will continue to depend in the foreseeable future,
on the services of its officers and key employees with extensive experience and
expertise in evaluating and analyzing producing oil and gas properties and
drilling prospects, maximizing production from oil and gas properties and
marketing oil and gas production. The ability of the Company to retain its
officers and key employees is important to the continued success and growth of
the Company.

The Company is dependent upon Robert A. Belfer, the Company's Chairman and
Chief Executive Officer, and Laurence D. Belfer, the Company's President and
Chief Operating Officer, in addition to certain of its other executive officers.
The unexpected loss of the services of one or more of these individuals could
have a detrimental effect on the Company. The Company does not maintain key man
life insurance on any of its officers or key employees. See "Management."

CONTROL BY CERTAIN STOCKHOLDERS

Following completion of the Offering, Robert A. Belfer, his spouse, his
children, his sisters, their spouses, their children and trusts for their
children and grandchildren will own approximately 77% of the outstanding shares
of the Common Stock and 15.8% of the outstanding shares of the Preferred Stock.
As a result, such stockholders will be able to effectively control the outcome
of certain matters requiring a stockholder vote, including the election of
directors. Such ownership of Common Stock may have the effect of delaying,
deferring or preventing a change of control of the Company and may adversely
affect the voting and other rights of other stockholders.

CERTAIN POTENTIAL CONFLICTS OF INTERESTS

Robert A. Belfer is a director of Enron Corp. ("Enron"). Enron, primarily
through its majority owned subsidiary, Enron Oil & Gas Company ("EOG"), is
involved in the exploration, development and production of oil and gas. Mr.
Belfer is not a director of EOG. While the Company's activities have not
historically overlapped with the activities of Enron or EOG, the Company may in
the future compete for certain opportunities with Enron or EOG. To the extent
any conflict from such future competition may arise, Mr. Belfer intends to
excuse himself from participating in any decisions of the Board of Directors of
Enron related to such opportunities.

Coda was acquired from Joint Energy Investment Development Investments
Limited Partnership ("JEDI") and certain members of Coda management. The general
partner of JEDI is an affiliate

S-17
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of Enron. The consideration paid and issued by the Company for Coda was
determined in an arms' length negotiations among the Company, Coda and the
stockholders of Coda (including JEDI).

ABSENCE OF PRIOR MARKET FOR PREFERRED STOCK

Prior to the Offering of the Preferred Stock, there has been no public
market for the Preferred Stock. The Preferred Stock has been approved for
listing on the New York Stock Exchange, subject to official notice of issuance.
Certain of the Underwriters have indicated that they currently intend to make a
market in the Preferred Stock; however, they are not obligated to do so and any
market making with respect to the Preferred Stock may be discontinued at any
time without notice. See "Underwriting." The market price of the Preferred Stock
can be expected to fluctuate with changes in the financial markets and economic
conditions, the financial condition and prospects of the Company and other
factors that generally influence the market prices of securities.

USE OF PROCEEDS

The estimated net proceeds to the Company from the Offering, after
deducting underwriting discounts and estimated offering expenses, will be
approximately $91.5 million ($105.2 million if the Underwriters' over-allotment
option is exercised in full). The Company intends to use all of the net proceeds
to repay a portion of the outstanding indebtedness under its credit facility
($121 million at February 28, 1998), thereby creating additional borrowing
capacity which will be used to fund the Company's planned exploration and
development activities and possible future acquisitions, as well as other
corporate purposes.

The Company's credit agreement with commercial lenders provides for a $150
million facility with a current borrowing base of $150 million that matures on
September 30, 2002 (the "Credit Facility"). The amount of the borrowing base at
any time is determined by reference to the collateral value of the Company's
proved reserves. Borrowings under the Credit Facility are unsecured and bear
interest currently at a rate equal to LIBOR plus 7/8%. On December 31, 1997,
the interest rate on the outstanding borrowings under the Credit Facility was
6.75% per annum. Amounts currently outstanding under the Credit Facility were
incurred primarily to fund the 1997 Acquisition. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources."

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<PAGE> 19

CAPITALIZATION

The following table sets forth as of September 30, 1997, (i) the historical
capitalization of the Company, (ii) the pro forma capitalization of the Company
after giving effect to the 1997 Acquisition and (iii) the pro forma
capitalization of the Company as adjusted to give effect to the sale of the
Preferred Stock offered hereby and the application of the net proceeds as
described in "Use of Proceeds." The table should be read in conjunction with the
Unaudited Pro Forma Consolidated Financial Statements and the Consolidated
Financial Statements and Notes thereto and "Management's Discussion and Analysis
of Financial Condition and Results of Operations" included elsewhere in this
Prospectus Supplement.

<TABLE>
<CAPTION>
SEPTEMBER 30, 1997
--------------------------------------
PRO FORMA
HISTORICAL PRO FORMA AS ADJUSTED
---------- --------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Senior long-term debt (including current maturities):
Credit Facility.................................... $ -- $ 84,000 $ 30,000(1)
8 7/8% Senior subordinated notes due 2007.......... 150,000 150,000 150,000
10.5% Senior subordinated notes due 2006, including
unamortized premium of $7,090,000............... -- 117,090 117,090
-------- -------- --------
Total long-term debt, including current
maturities.................................... 150,000 351,090 297,090
-------- -------- --------
Stockholders' equity:
Preferred stock, $.01 par value; 10,000,000 shares
authorized; none outstanding historical and pro
forma; 3,800,000 shares outstanding pro forma as
adjusted........................................ -- -- 38
Common stock, $.01 par value; 120,000,000 shares
authorized; 31,582,000 shares issued and
outstanding at September 30, 1997............... 316 316 316
Additional paid-in capital......................... 186,807 196,807 288,282
Retained earnings (deficit)........................ 76,563 (20,937) (20,937)
Unearned compensation.............................. (1,204) (1,204) (1,204)
Notes receivable for equity interest............... (775) (775) (775)
-------- -------- --------
Total stockholders' equity...................... 261,707 174,207 265,404
-------- -------- --------
Total capitalization....................... $411,707 $525,297 $562,494
======== ======== ========
</TABLE>

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

(1) Subsequent to September 30, 1997, the Company increased the outstanding
balance of the Credit Facility by $37 million to $121 million in connection
with the Permian Acquisition. See "Summary -- Recent Developments." After
considering this acquisition and the application of the net proceeds of the
Offering, the pro forma balance outstanding under the Credit Facility will
be approximately $30 million.

S-19
<PAGE> 20

PRICE RANGE OF COMMON STOCK

The Common Stock is traded on the NYSE under the symbol "BOG." The
following table sets forth, on a per share basis for the periods indicated, the
range of high and low sales prices of the Common Stock as reported by the NYSE
during the periods shown.

<TABLE>
<CAPTION>
HIGH LOW
-------- -------
<S> <C> <C>
1996
First Quarter (commencing March 25, 1996)................. $22.875 $21.625
Second Quarter............................................ 35.50 22.25
Third Quarter............................................. 37.25 21.25
Fourth Quarter............................................ 29.125 23.00
1997
First Quarter............................................. $28.50 $18.125
Second Quarter............................................ 24.00 18.25
Third Quarter............................................. 22.1875 18.125
Fourth Quarter............................................ 22.4375 18.25
1998
First Quarter (through March 4, 1998)..................... $19.125 $17.125
</TABLE>

On March 4, 1998, the last reported sale price of the Common Stock as
reported on the NYSE was $18.00 per share. On December 31, 1997, the outstanding
shares of the Common Stock were held by approximately 115 holders of record.

DIVIDEND POLICY

For the foreseeable future, the Company anticipates that it will use any
earnings generated from operations to finance the growth of the Company and that
it will not pay cash dividends to holders of the Common Stock. Any future cash
dividends to holders of Common Stock would depend on future earnings, capital
requirements, the Company's financial condition and other factors deemed
relevant by the Board of Directors. Holders of the Preferred Stock will be
entitled to receive, when, as and if declared by the Board of Directors of the
Company, out of the funds of the Company legally available therefor, annual cash
dividends at the rate of $1.625 per share, payable quarterly in arrears on March
15, June 15, September 15 and December 15 of each year, commencing June 15, 1998
or if such day is not a business day, the next succeeding business day.
Dividends on the Preferred Stock will be cumulative from the date of original
issuance. The payment of dividends on the Common Stock and the Preferred Stock
is restricted by the terms of the 8 7/8% Indenture, the Coda Indenture and the
Credit Agreement. See "Risk Factors -- Restrictions on Ability to Pay
Dividends," "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources" and "Description of
Preferred Stock -- Dividends."

S-20
<PAGE> 21

SELECTED HISTORICAL FINANCIAL DATA

The following table sets forth selected financial data regarding the
Company as of and for each of the periods indicated. The historical financial
data as of and for the three years ended December 31, 1996, are derived from the
financial statements of the Company audited by Arthur Andersen LLP, independent
public accountants. The financial data as of September 30, 1997 and for the nine
months ended September 30, 1997 and 1996, are derived from the Company's
unaudited financial statements, which, in the opinion of management, include all
adjustments (which consist only of normal recurring adjustments) necessary for a
fair presentation of the financial position and results of operations of the
Company for such interim periods. The following data should be read in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the Company's financial statements and notes
thereto.

<TABLE>
<CAPTION>
PERIOD FROM
INCEPTION
(APRIL 30, NINE MONTHS ENDED
1992) TO YEAR ENDED DECEMBER 31, SEPTEMBER 30,
DECEMBER 31, ------------------------------------------ --------------------
1992 1993 1994 1995 1996 1996 1997
------------ -------- -------- -------- --------- -------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues
Oil and gas sales....................... $ 3,536 $ 19,255 $ 40,362 $ 68,767 $ 119,710 $ 83,930 $ 89,742
Commodity price risk management
activities............................ -- -- 550 9,480 (5,967) 2,413 (7,674)
Interest................................ 80 57 195 353 2,653 1,849 2,326
-------- -------- -------- -------- --------- -------- ---------
Total revenues.......................... 3,616 19,312 41,107 78,600 116,396 88,192 84,394
-------- -------- -------- -------- --------- -------- ---------
Costs and expenses
Oil and gas operating expenses.......... 289 2,495 5,510 5,824 7,847 5,826 6,657
Depreciation, depletion and
amortization.......................... 401 4,098 14,072 27,590 40,904 29,891 32,190
General and administrative.............. 424 856 2,269 2,597 3,059 2,444 2,476
-------- -------- -------- -------- --------- -------- ---------
Total costs and expenses.................. 1,114 7,449 21,851 36,011 51,810 38,161 41,323
-------- -------- -------- -------- --------- -------- ---------
Income before taxes....................... 2,502 11,863 19,256 42,589 64,586 50,031 43,071
Pro forma provision for income taxes(1)... 637 1,504 5,030 13,852 21,953 17,011 14,752
-------- -------- -------- -------- --------- -------- ---------
Pro forma net income(1)(2)................ $ 1,865 $ 10,359 $ 14,226 $ 28,737 $ 42,633 $ 33,020 $ 28,319
======== ======== ======== ======== ========= ======== =========
Pro forma earnings per share(1)(2)(3):
Basic................................... $ .07 $ .41 $ .57 $ 1.15 $ 1.42 $ 1.12 $ .90
======== ======== ======== ======== ========= ======== =========
Diluted................................. $ .07 $ .41 $ .57 $ 1.15 $ 1.42 $ 1.12 $ .89
======== ======== ======== ======== ========= ======== =========
Weighted Average Common Shares
Outstanding............................. 25,000 25,000 25,000 25,000 29,986 29,476 31,582
======== ======== ======== ======== ========= ======== =========
STATEMENT OF CASH FLOWS DATA:
EBITDA(3)................................. $ 2,903 $ 15,961 $ 33,328 $ 70,179 $ 105,490 $ 79,922 $ 75,260
Capital expenditures...................... 15,744 32,647 52,230 71,387 142,712 103,751 101,994
Cash flow from operating activities....... 729 14,351 28,126 62,037 108,059 76,713 79,041
Cash flow from investing activities....... (13,086) (33,698) (52,670) (65,133) (143,826) (97,757) (134,026)
Cash flow from financing activities....... 14,115 18,708 30,376 (2,299) 77,684 77,339 150,000
BALANCE SHEET DATA:
Working capital........................... $ 1,184 $ 3,108 $ 14,357 $ 446 $ 48,667 $ 62,779 $ 142,857
Total assets.............................. 19,671 50,248 101,625 145,550 303,918 281,098 487,416
Long-term debt, including current
maturities.............................. -- -- 6,930 22,000 -- -- 150,000
Total stockholders' equity................ 16,617 47,188 89,890 105,015 233,203 223,483 261,707
</TABLE>

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

(1) Gives pro forma effect to the application of federal and state income taxes
to the Company as if it were a taxable corporation for the periods
presented. 1996 excludes a one-time non-cash deferred tax charge of $30.1
million recognized as a result of the Combination consummated on March 29,
1996 in connection with the Company's initial public offering.

(2) Does not give pro forma effect to the 1997 Acquisition.

(3) Pro forma earnings per share has been computed as if the 25,000,000 shares
of Common Stock that were issued in connection with the Combination had been
outstanding for all years prior to 1996.

(4) EBITDA represents income from continuing operations plus income taxes,
interest expense, depletion, depreciation and amortization expense and
writedown of oil and gas properties. EBITDA is not presented as an indicator
of the Company's operating performance, an indicator of cash available for
discretionary spending or a measure of liquidity. EBITDA is not a measure of
financial performance prepared in accordance with generally accepted
accounting principles and may not be comparable to other similarly titled
measures of other companies.

S-21
<PAGE> 22

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

The following discussion is intended to assist in the understanding of the
Company's historical financial position and results of operations for each year
in the two year period ended December 31, 1996 and for the nine months ended
September 30, 1997 and 1996. The following discussion is based on the Company's
historical financial results and, except as indicated, does not include a
discussion of the pro forma results related to the 1997 Acquisition. The
Company's Condensed Consolidated Financial Statements and notes thereto included
elsewhere in this Prospectus Supplement should be referred to in conjunction
with the following discussion. In addition, reference is made to the Unaudited
Pro Forma Consolidated Financial Statements included elsewhere in this
Prospectus Supplement, which give effect to the 1997 Acquisition.

OVERVIEW

Since its inception in April 1992, the Company has grown rapidly, with
substantially all of its growth coming "through the drill bit" and the 1997
Acquisition. The Company's participation in exploration and development
activities in the Moxa Arch Trend of Wyoming and in the Austin Chalk Trend in
the Giddings Field of Texas are principally responsible for the substantial
expansion of production, revenues and reserves since the Company's inception.

On November 26, 1997, in the 1997 Acquisition the Company acquired all of
the outstanding capital stock of Coda, an independent energy company that is
principally engaged in the acquisition and exploitation of producing oil and
natural gas properties. Coda's properties are principally located in the Permian
Basin of west Texas and the Mid-Continent region of Oklahoma and north Texas.
The 1997 Acquisition approximately doubled the Company's reserve base to 604
Bcfe at December 31, 1997, extended the Company's reserve life from
approximately 5.3 years to approximately 9 years, and established a balanced
reserve mix of approximately 51% oil and 49% natural gas.

The Unaudited Pro Forma Consolidated Financial Statements report pro forma
oil and gas revenues (unhedged) for the combined entities of $144.3 million for
the nine month period ended September 30, 1997. For the same period, pro forma
volumes of natural gas and oil production for the combined entities are reported
at 40.4 Bcf and 3.15 MMBO (million barrels of oil), respectively. For the first
nine months of 1997, pro forma natural gas production represented approximately
63% of total production on an Mcfe basis, with the remaining 37% represented by
oil production.

The Company has accounted for the 1997 Acquisition using the purchase
method of accounting for business combinations. In accordance with the Statement
of Financial Accounting Standards Board No. 109 ("FASB 109"), the Company will
record, in the fourth quarter ended December 31, 1997, a one-time non-cash
deferred tax liability of approximately $101 million to reflect the difference
between the tax basis of Coda's assets and liabilities and the amounts recorded
for financial reporting purposes for such assets and liabilities.

Based on the Company's year-end 1997 estimated proved reserves, the Company
will record in the fourth quarter ended December 31, 1997 a non-cash ceiling
test provision of approximately $150 million ($98 million after tax). The
ceiling test provision includes the effect of the non-cash $101 million FASB 109
"gross up" attributable to the 1997 Acquisition on the Company's full cost pool
at December 31, 1997 and the PV10 value of year-end 1997 reserves, which were
significantly impacted by lower product prices when compared to year-end 1996
prices, among other items.

The Company's revenue, profitability and future rate of growth are
substantially dependent upon prevailing prices for natural gas, oil and
condensate. These prices are dependent upon numerous factors beyond the
Company's control, such as economic, political and regulatory developments and
competition from other sources of energy. The energy markets have historically
been very volatile, and there can be no assurance that oil and natural gas
prices will not be subject

S-22
<PAGE> 23

to wide fluctuations in the future. A substantial or extended decline in oil and
natural gas prices could have a material adverse effect on the Company's
financial position, results of operations and access to capital, as well as the
quantities of natural gas and oil reserves that the Company may economically
produce. Natural gas produced is sold under contracts that primarily reflect
spot market conditions for their particular area. The Company markets its oil
with other working interest owners on spot price contracts and typically
receives a premium compared to the price posted for such oil.

The Company utilizes commodity swaps and options and other commodity price
risk management transactions for a portion of its oil and natural gas production
to achieve a more predictable cash flow and to reduce its exposure to price
fluctuations. The Company accounts for these transactions as hedging activities
or uses mark-to-market accounting for those contracts that do not qualify for
hedge accounting. As of December 31, 1997, the Company had various natural gas
and oil price risk management contracts in place with respect to substantial
portions of its estimated production for 1998 and 1999 and with respect to
lesser portions of its estimated production for thereafter. The Company expects
from time to time to either add to or reduce the amount of price risk management
contracts that it has in place in keeping with its price risk management
strategy.

The following table sets forth certain operations data of the Company for
the periods presented:

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------- -----------------
1994 1995 1996 1996 1997
------- ------- -------- ------- -------
<S> <C> <C> <C> <C> <C>
Oil and Gas Sales (in thousands)(1).... $40,362 $68,767 $119,710 $83,930 $89,742
Weighted Average Sales Prices
(Unhedged):
Oil (per Bbl)........................ $ 16.48 $ 17.35 $ 21.30 $ 20.36 $ 19.92
Gas (per Mcf)........................ $ 1.67 $ 1.42 $ 2.00 $ 1.84 $ 2.04
Net Production Data:
Oil (MBbls).......................... 691 961 794 575 716
Gas (MMcf)........................... 17,482 37,047 51,289 39,252 36,973
Gas equivalent (MMcfe)............... 21,628 42,813 56,053 42,702 41,269
Data per Mcfe:
Oil and gas sales revenues
(unhedged)........................ $ 1.86 $ 1.61 $ 2.14 $ 1.97 $ 2.17
Commodity price risk management
activities -- Cash................ .03 .22 .06 .06 (0.05)
-- Non-Cash.................. -- -- (.17) -- (0.14)
Oil and gas operating expenses....... (.25) (.14) (.14) (.14) (.16)
General and administrative........... (.10) (.06) (.06) (.06) (.06)
Depreciation, depletion and
amortization...................... (.65) (.64) (.73) (.70) (.78)
------- ------- -------- ------- -------
Pre-tax operating profit(2).......... $ 0.89 $ 0.99 $ 1.10 $ 1.13 $ 0.98
------- ------- -------- ------- -------
Number of wells drilled or drilling:
Gross................................ 87 118 80 60 94
Net.................................. 22 34 34 26 46
</TABLE>

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

(1) Oil and gas sales exclude results related to commodity price risk management
activities reported separately.

(2) Excludes interest income and expense.

S-23
<PAGE> 24

RESULTS OF OPERATIONS -- SEPTEMBER 30, 1997 COMPARED TO SEPTEMBER 30, 1996

Revenues

For the first nine months of 1997, oil and gas sales revenues (unhedged)
increased $5.8 million, or 7%, to $89.7 million over the prior year comparable
period. The revenue increase is the result of higher year to date average price
realizations for natural gas (11%) while the price of oil declined by 2%. Oil
production volume during the first nine months of 1997 increased 141,000
barrels, or 25%, over the prior year period due to new production from Louisiana
Austin Chalk properties coming on stream. Natural gas production declined by 6%
when compared to the first nine months of 1996.

As a result of the substantial oil and gas price increases which occurred
in the first quarter of 1997 (which had a positive overall impact on oil and gas
sales revenues), commodity price risk management activities during the first
nine months of 1997 resulted in a net pre-tax loss of $7.7 million, consisting
of $2.1 million in realized losses and a $5.6 million unrealized mark-to-market
loss. The impact of such activities on an Mcfe basis amounted to a net loss of
$0.19 ($0.05 cash loss and non-cash loss of $0.14) and a gain of $0.06 (all
cash) per Mcfe for the first nine months of 1997 and 1996, respectively.

Costs and Expenses

Production and Operating Expenses. Production and operating expenses
including associated taxes increased 16% from $5.8 million in the first nine
months of 1996 to $6.7 million for the comparable period in 1997 due mainly to
the increased number of wells on line and higher costs associated with new oil
wells and a growing population of older wells. Operating costs were $0.16 per
Mcfe for the first nine months of 1997 when compared to $0.14 per Mcfe in the
first nine months of 1996.

Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization ("DD&A"), for the nine months of 1997 increased 8% over the prior
year comparable period, from $29.9 million to $32.2 million, primarily due to
increased exploration costs and the drilling of deeper and higher cost wells.

General and Administrative Expenses. General and administrative expenses
("G&A") increased a modest 1% in the first nine months of 1997 to $2.5 million
when compared to the $2.4 million incurred in the first nine months of 1996. The
rate per Mcfe for G&A costs was unchanged at $0.06.

Income Before Income Taxes

The Company's income before income taxes for the first nine months of 1997
decreased by approximately $7.0 million, or 14%, to $43.1 million from $50.0
million in the prior year period. The decrease over the prior year comparable
period is due principally to commodity price risk management activities and, to
a lesser extent, lower production.

Income Taxes

Income tax expenses for the first nine months of 1997 were $14.8 million
utilizing an estimated effective income tax rate of 34.25%. In connection with
the Combination, the Company became a taxable corporation and, as a result, was
required to record a one-time, non-cash charge in the amount of $29.9 million
during the first half of 1996 to establish a deferred tax liability related to
prior years on its balance sheet due to the change in the tax status of the
Company. At year end 1996, this estimated amount was increased to $30.1 million
following the completion of related income tax returns.

S-24
<PAGE> 25

RESULTS OF OPERATIONS--1996 COMPARED TO 1995

Revenues

Oil and natural gas sales revenues for the year 1996 (unhedged) increased
74% to $119.7 million when compared to the $68.8 million realized in 1995. The
substantial increase is principally identified with the addition of new Giddings
Field wells, in both the Navasota and Independence areas of the Company's
operations, and higher average prices realized for both oil and natural gas.
Weighted average oil and natural gas prices (unhedged) increased 23% and 41%,
respectively, when compared to 1995 price realizations. Production volume in
1996 on an Mcfe basis (using 6 Mcf of gas for 1 barrel of oil) increased 31%
over the prior year to 56,053 MMcfe. Daily production increased to 153,150 Mcfe
for 1996 compared to 117,300 Mcfe for 1995.

Commodity price risk management activities resulted in a pre-tax loss of
$6.0 million for 1996 which included (1) a realized hedging loss of $83,000, (2)
net realized losses on settlements of non-hedging transactions totaling $3.9
million, (3) net premiums received totaling $7.4 million and (4) a non-cash
unrealized loss for mark-to-market accounting of $9.4 million. As a result of
the substantial oil and natural gas price increases which occurred in the fourth
quarter of 1996 (which had a positive impact on oil and gas sales revenues), the
Company recorded a fourth quarter pre-tax loss of $8.4 million from commodity
price risk management activities which included a $4.2 million non-cash charge
for unrealized losses related to required mark-to-market accounting. The 1995
results of operations included pre-tax income of $9.5 million related to
realized hedging gains. The impact of such activities on an Mcfe basis amounted
to a loss of $0.11 ($0.06 cash gain and a non-cash loss of $0.17) and a gain of
$0.22 (all cash) per Mcfe for 1996 and 1995, respectively.

Interest income realized during 1996 was $2.7 million compared to $0.4
million for 1995 due to higher average cash balances principally attributable to
the proceeds of the Company's initial public offering.

Costs and Expenses

Production and Operating Expenses. Production and operating expenses
including associated taxes in 1996 amounted to $7.9 million, an increase of 35%
over the $5.8 million incurred in the prior year. Operating costs on an Mcfe
basis were flat at $0.14 per Mcfe for both 1996 and 1995. A substantial portion
of the Company's natural gas production from wells drilled prior to September
1996 in the downdip Giddings Field qualifies for exemption from Texas state
production taxes. This exemption will continue for production through August 31,
2001.

Depreciation, Depletion and Amortization. DD&A costs related to oil and gas
properties totaled $40.9 million for 1996, a 48% increase over the $27.6 million
incurred in the 1995 comparable period. The Company's average DD&A rate per Mcfe
for 1996 was $0.73 compared to a rate of $0.64 per Mcfe in 1995. The increased
rate primarily reflects the higher average cost of drilling deeper wells and
costs associated with the unsuccessful East Texas Cotton Valley Reef Trend
exploration activities.

General and Administrative Expenses. G&A totaled $3.1 million for 1996, net
of capitalized G&A costs directly related to the Company's oil and natural gas
exploration and development efforts, an 18% increase over the prior year. The
increase reflects the addition of new employees hired to assist with the
Company's expanding activities and additional costs incurred in connection with
becoming a publicly traded entity. On an Mcfe basis, G&A costs were flat at
$0.06 for both 1996 and 1995. Operations G&A expenses for 1996 in the amount of
$3.1 million have been capitalized to oil and gas property accounts. The
increase of $1.8 million over the 1995 comparable amount reflects the Company's
rapidly expanding exploration and development efforts.

S-25
<PAGE> 26

Income Before Income Taxes

The Company's income before income taxes for 1996 was $64.6 million, a 52%
increase over the $42.6 million realized in the prior year comparable period.
The increase is directly related to increased production from new well additions
in the Giddings Field and substantially higher average prices realized for both
oil and natural gas.

Income Taxes

Income tax expenses for 1996 amounted to $46.4 million. The provision for
taxes includes a one-time, non-cash charge in the amount of $30.1 million that
was required as a result of the Combination which changed the tax status of the
Company.

RESULTS OF OPERATIONS -- 1995 COMPARED TO 1994

Revenues

During 1995, oil and natural gas sales revenues (unhedged) increased $28.4
million, or 70%, to $68.8 million as compared to 1994. The revenue increase is
principally the result of new Giddings Field well additions in the Navasota
River and Independence areas of the Company's operations. Production volume on
an Mcfe basis increased to 42.8 MMcfe, representing an increase of 98% over the
prior year. Natural gas production represented approximately 87% of the
Company's total production on an Mcfe basis. This significant improvement in
revenues was achieved despite a decline in the Company's average wellhead
natural gas prices in 1995. Weighted average wellhead natural gas prices
(unhedged) were down approximately 15% from 1994 prices and weighted average
wellhead oil prices were up approximately 5% from 1994 prices.

Commencing in late 1993, marketing activities associated with sales of
natural gas and crude oil also included natural gas, crude oil price swap and
option transactions, along with other commodity price hedging of natural gas and
crude oil and condensate prices. These transactions added approximately $9.5
million to net operating revenues for 1995. The average Mcfe price realized for
these transactions amounted to $0.22 per Mcfe for 1995. During 1995, revenues
per Mcfe, including revenue from hedges, totaled $1.83.

Costs and Expenses

Production and Operating Expenses. Production and operating expenses
increased 6% from $5.5 million in 1994 to $5.8 million in 1995. On an Mcfe
basis, operating costs decreased 44% to $0.14 for 1995, compared to $0.25 for
1994. The decrease is due mainly to an increase in the number of highly
productive wells in the Giddings Field.

Depreciation, Depletion and Amortization. DD&A for 1995 increased 96%, from
$14.1 million to $27.6 million, due to increased production. Lower well costs
due to efficiencies achieved related to the Company's experience in its existing
operating areas coupled with the Company's ability to achieve a higher level of
reserve additions for its 1995 wells resulted in a DD&A rate of $0.64 per Mcfe
for 1995, compared to $0.65 per Mcfe in 1994, a 2% reduction.

General and Administrative Expenses. G&A for 1995 increased 14%, from $2.3
million for 1994 to $2.6 million for 1995. The higher G&A expenses for 1995
primarily relate to increases in the number of employees due to a higher level
of overall activity for the Company as well as increases in employee salaries
and benefits. G&A expenses totaling $1.2 million and $0.1 million have been
capitalized to oil and gas property accounts for 1995 and 1994, respectively.

Income Before Income Taxes. The Company's income before income taxes for
1995 increased by approximately $23.3 million, or 121% to $42.6 million from
$19.3 million in the prior year period. Increases in revenues were generated
primarily by increases in production from new well additions in the Giddings
Field and were partially offset by increases in operating costs and expenses
related

S-26
<PAGE> 27

to the new additions and lower natural gas and oil prices. Additionally, the
Company realized approximately $9.5 million related to its commodity price risk
management activities for 1995.

LIQUIDITY AND CAPITAL RESOURCES

General

On March 29, 1996, the Company successfully completed an initial public
offering of 6,500,000 shares of Common Stock. The initial public offering
provided the Company with approximately $113 million net of offering expenses.
Proceeds from the offering were used to repay approximately $35 million of
indebtedness under the Company's previous credit facility, fund capital
expenditures and for other general corporate purposes. The remaining proceeds
from the offering, together with cash flows from operations, were used to fund
planned capital expenditures, including lease acquisitions, commitments, other
working capital requirements and general corporate purposes.

In September, 1997 the Company entered into a new five-year $150 million
Credit Agreement dated September 23, 1997 (the "Credit Facility") with The Chase
Manhattan Bank, N.A., as administrative agent (the "Agent") and other lending
institutions (the "Banks"). The Credit Facility provides for an aggregate
principal amount of revolving loans of up to the lesser of $150 million or the
Borrowing Base (as defined) as in effect from time to time, which includes a
subfacility from the Agent for letters of credit of up to $25 million. The
Borrowing Base is currently set at $150 million. The borrowing base will be
redetermined by the Agent and the Banks semi-annually based upon their usual and
customary oil and gas lending criteria as such exist from time to time. In
addition, the Company may request two additional redeterminations and the Banks
may request one additional redetermination per year.

Indebtedness of the Company under the Credit Facility is secured by a
pledge of the capital stock of each of the Company's material subsidiaries.

Indebtedness under the Credit Facility bears interest at a floating rate
based (at the Company's option) upon (i) the ABR with respect to ABR Loans or
(ii) the Eurodollar Rate for one, two, three or six months (or nine or twelve
months if available to the Banks) Eurodollar Loans, plus the Applicable Margin.
The ABR is the greater of (i) the Prime Rate, (ii) the Base CD Rate plus 1% or
(iii) the Federal Funds Effective Rate plus 1/2 of 1%. The Applicable Margin for
Eurodollar Loans varies from 0.50% to 0.875% depending on the Borrowing Base
usage. Borrowing Base usage is determined by a ratio of (i) outstanding Loans
and letters of credit to (ii) the then effective Borrowing Base. Interest on ABR
Loans will be payable quarterly in arrears and interest on Eurodollar Loans is
payable on the last day of the interest period therefor and, if longer than
three months, at three month intervals.

The Company is required to pay to the Banks a commitment fee based on the
committed undrawn amount of the lesser of the aggregate commitments or the then
effective Borrowing Base during a quarterly period equal to a percent that
varies from 0.20% to 0.30% depending on the Borrowing Base usage.

In September 1997, the Company issued $150 million of 8 7/8% Senior
Subordinated Notes due 2007 (the "8 7/8% Notes"). Interest on the Notes accrues
at the rate of 8 7/8% per annum and is payable semi-annually in arrears on March
15 and September 15 of each year, commencing on March 15, 1998. The 8 7/8% Notes
mature on September 15, 2007 unless previously redeemed. Except under limited
circumstances, the 8 7/8% Notes are not redeemable at the Company's option prior
to September 15, 2002. Thereafter, the 8 7/8% Notes will be subject to
redemption at the option of the Company, in whole or in part, at specified
redemption prices, plus accrued and unpaid interest, if any, thereon to the
applicable redemption date. In addition, upon a change of control (as defined in
the indenture pursuant to which the 8 7/8% Notes were issued (the "8 7/8%
Indenture")) the Company is required to offer and redeem the 8 7/8% Notes for
cash at 101% of the principal amount, plus accrued and unpaid interest, if any,
thereon to the applicable date of repurchase.

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The 8 7/8% Notes are general unsecured obligations of the Company and are
subordinated in right of payment to all existing and future Senior Debt (as
defined in the 8 7/8% Indenture) of the Company, which includes borrowings under
the Credit Facility described above. The 8 7/8% Notes rank pari passu in right
of payment with any existing or future senior subordinated debt of the Company
and rank senior in right of payment to all other subordinated indebtedness of
the Company.

Coda has $109,000,000 principal amount outstanding of 10 1/2% Senior
Subordinated Notes due 2006 (the "Coda Notes"). Interest on the Coda Notes
accrues at the rate of 10 1/2% per annum and is payable semi-annually in arrears
on April 1 and October 1 of each year. Except under limited circumstances, the
Coda Notes are not redeemable at the Company's option prior to April 1, 2001.
Thereafter the Coda Notes will be subject to redemption at specified prices,
plus accrued and unpaid interest, if any, thereon to the applicable redemption
date. The acquisition by the Company of Coda required Coda to make an offer to
purchase the Coda Notes at a purchase price of 101% of principal amount which
expired on January 9, 1998. $1 million principal amount of Coda Notes were
tendered and accepted for purchase under this offer.

The Coda Notes are general unsecured obligations of Coda and are
subordinated in right of payment to all existing and future Senior Debt (as
defined) of Coda, including any bank debt. The indenture pursuant to which the
Coda Notes were issued (the "Coda Indenture") contains restrictions on the
ability of Coda to make distributions to Belco and to incur additional
indebtedness, except that Coda may incur up to $250,000,000 of bank debt under
certain circumstances. The Company contributed $23,000,000 to Coda upon its
acquisition to enable it to repay its bank debt in full. The Company does not
intend for Coda to incur any additional debt, and intends to finance Coda's
operations with Coda's cash flow from operations and advances or capital
contributions from the Company.

In February 1998, the Company merged Coda into Belco and assumed the
obligations under the Coda Notes and the Coda Indenture.

In December 1997, the Company entered into two interest rate swap
agreements converting two fixed rate obligations to floating rate obligations.
The first agreement covers $100 million of 8.875% long-term debt (comparable to
the interest rate on the 8 7/8% Notes) and obligates the Company to pay an
initial rate of 8.175% through September 15, 1998. Thereafter, the rate is
redetermined at each six month period through September 15, 2007. The floating
rates are capped at 8.875% through September 15, 2001 and at 10% from March 15,
2002 through September 15, 2007. The second agreement covers $110 million of
10.5% long-term debt (comparable to the interest rate on the Coda Notes) and
obligates the Company to pay an initial rate of 9.8881% through April 1, 1998.
Thereafter, the rate is redetermined at each six month period through 2003.
Floating rates on this agreement are capped at 10.5% through October 1, 1999 and
11.625% from April 1, 2000 through April 1, 2003. The two agreements will reduce
the Company's interest expense by approximately $1 million through October 1,
1998.

Cash Flow

Net operating cash flow (pre-tax), a measure of performance for exploration
and production companies, is generally derived by adjusting net income to
eliminate the effects of the non-cash depreciation, depletion and amortization
expense, provision for deferred income taxes and non-cash effects of commodity
price risk management activities. Net operating cash flow (pre-tax) before
changes in working capital was approximately $78.4 million and $78.5 million for
the first nine months of 1997 and 1996, respectively. The Company had working
capital amounting to $142.9 million as of September 30, 1997, a substantial
increase from the $48.7 million available as of December 31, 1996. This increase
is the result of the application of the net proceeds from the offering of the
Notes.

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Capital Expenditures

For 1997, the Company incurred capital expenditures in excess of $160
million, before property sales of approximately $14 million to third parties.

The Company intends to fund its future capital expenditures, commitments
and working capital requirements through cash flows from operations, borrowings
under the Credit Facility or other potential financings. If there are changes in
oil and natural gas prices, however, that correspondingly affect cash flows and
the Borrowing Base under the Credit Facility, the Company has the discretion and
ability to adjust its capital budget. The Company believes it will have
sufficient capital resources and liquidity to fund its capital expenditures and
meet its financial obligations as they come due.

1997 Acquisition

In November 1997, the Company completed the 1997 Acquisition by purchasing
Coda. The Company paid an aggregate of approximately $192 million in cash ($150
million plus a $42 million adjustment for proceeds from the disposition of
Taurus Energy Corp. ("Taurus"), a subsidiary of Coda, which occurred on the day
prior to closing of the 1997 Acquisition) and issued warrants to purchase
1,666,667 shares of Common Stock to the holders of the outstanding common stock,
preferred stock and options to purchase common stock of Coda. Concurrently with
the closing of the 1997 Acquisition, the Company contributed $23 million to Coda
that Coda utilized, together with the funds from the disposition of Taurus, to
repay all of the debt outstanding under Coda's revolving credit facility
(approximately $65 million in principal amount), plus accrued interest thereon,
and such credit facility was thereafter terminated. The Company funded the cash
portion of the consideration and the cash contribution to Coda through cash on
hand and borrowings of $84 million under the Credit Facility.

Commodity Price Risk Management Transactions

Certain of the Company's commodity price risk management arrangements
require the Company to deliver cash collateral or other assurances of
performance to the counterparties in the event that the Company's payment
obligations with respect to its commodity price risk management transactions
exceed certain levels.

With the primary objective of achieving more predictable revenues and cash
flows and reducing the exposure to fluctuations in oil and natural gas prices,
the Company has entered into price risk management transactions of various kinds
with respect to both oil and natural gas. While the use of certain of these
price risk management arrangements limits the downside risk of adverse price
movements, it may also limit future revenues from favorable price movements. The
Company engages in transactions such as selling covered calls or straddles which
are marked-to-market at the end of the relevant accounting period. Since the
futures market historically has been highly volatile, these fluctuations may
cause significant impact on the results of any given accounting period. The
Company has entered into price risk management transactions with respect to a
substantial portion of its estimated production for the remainder of 1998 and
with respect to substantial portions of its estimated production for 1999 and
2000 and lesser amounts thereafter. The Company continues to evaluate whether to
enter into additional price risk management transactions for 1998 and future
years. In addition, the Company may determine from time to time to unwind its
then existing price risk management positions as part of its price risk
management strategy.

Environmental Matters

threatened against the Company. There can be no assurance, however, that current
regulatory requirements will not change, currently unforeseen environmental
incidents will not occur or past noncompliance with environmental laws will not
be discovered on the Company's properties.

Recent Accounting Pronouncements

In February 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 128 -- "Earnings per
Share" effective for interim and annual periods after December 15, 1997. This
statement replaces primary earnings per share ("EPS") with a newly defined basis
EPS and modifies the computation of diluted EPS. For periods prior to 1997, the
Company's basic and diluted EPS computed using the requirements of SFAS 128 are
the same as the Company's pro forma net income per common share.

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BUSINESS AND PROPERTIES

GENERAL

Belco is an independent energy company engaged in the exploration for and
the acquisition, exploitation, development and production of natural gas and oil
primarily in the Rocky Mountains, the Permian Basin, the Mid-Continent region
and the Austin Chalk Trend. Since its inception in April 1992, the Company has
grown its reserve base largely through a balanced program of exploration and
development drilling and through acquisitions. The Company concentrates its
activities primarily in four core areas in which it has accumulated detailed
geologic knowledge and has developed significant management and technical
expertise. Additionally, the Company structures its participation in natural gas
and oil exploration and development activities to minimize initial costs and
risks, while permitting substantial follow-on investment. In November 1997, the
Company completed a significant acquisition by purchasing Coda. See
"Summary -- Recent Developments."

The Company has achieved substantial growth in reserves, production,
revenues and EBITDA since 1992. Belco's estimated proved reserves have increased
at a compound annual growth rate of 55% from 67 Bcfe as of December 31, 1992 to
604 Bcfe as of December 31, 1997. Average daily production has increased from 4
MMcfe per day in 1992 to approximately 217 MMcfe per day for the nine months
ended September 30, 1997 on a pro forma basis. Similarly, the growth in the
Company's EBITDA has been substantial, increasing from $2.9 million for the year
ended December 31, 1992, to $105.5 million for the year ended December 31, 1996.
The Company's pro forma EBITDA for the nine months ended September 30, 1997 was
$104.4 million. The Company's low cost structure is evidenced by its general and
administrative expenses of $0.06 per Mcfe and lease operating expenses of $0.14
per Mcfe in 1996. For the three years ended December 31, 1996, the Company's
operating cash inflows per Mcfe averaged $1.65 and its finding costs averaged
approximately $0.80 per Mcfe.

BUSINESS STRENGTHS

The Company believes that it has certain strengths that provide it with
significant competitive advantages, including the following:

Proven Growth Record. The Company has generated consistent growth
through a balanced exploration and development program and through
acquisitions. From January 1, 1993 through December 31, 1997, the Company's
compounded annual growth in reserves was 60%. For the period January 1,
1994 through September 30, 1997, production increased by 52% and EBITDA
increased by 67% on a historical compounded annual basis.

Successful Drilling Record. Since inception through September 30,
1997, the Company has drilled 566 gross (238 net) wells of which 494 gross
(210 net) were producing at September 30, 1997.

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December 31, 1997. The Company believes that this acreage position will
provide it with significant drilling opportunities for at least the next
three years.

High Operating Margins. The Company's drilling success, its high
impact wells and low cost structure have enabled it to generate a pre-tax
gross cash margin (unhedged oil and gas sales less general and
administrative and operating expenses), on a pro forma basis, of $1.79 per
Mcfe for the nine months ended September 30, 1997. This margin compares
favorably to an average of $1.32 per Mcfe experienced by public companies
which the Company believes are peer companies (based on publicly filed
industry data) for the same period. This peer group consists of the
following companies: Barrett Resources Corp., Forcenergy Inc., Nuevo Energy
Co., HS Resources, Inc., Seagull Energy Corp., United Meridian Corp., Cross
Timbers Oil Co., Vintage Petroleum, Inc. and Lomak Petroleum, Inc.

Experienced and Committed Management. Belco's senior management team
has extensive experience in the oil and gas industry. In particular, the
Company's Chairman and Chief Executive Officer, Robert A. Belfer, began his
career in the oil and gas industry in 1958 with BPC, which grew to become a
Fortune 500 company with operations primarily in the Rocky Mountains and
offshore Peru. In 1983, BPC merged with InterNorth, a predecessor of Enron
Corp. The Company's experienced technical staff includes nine petroleum
engineers, six production engineers, eleven geologists and one
geophysicist, who have, on average, over 23 years of experience in the oil
and gas industry. Mr. Belfer has agreed to purchase 250,000 shares of
Preferred Stock in the Offering. Following completion of the Offering, Mr.
Belfer and his family will own approximately 77% of the outstanding shares
of the Common Stock and 15.8% of the outstanding shares of the Preferred
Stock.

BUSINESS STRATEGY

The key elements of the Company's strategy are as follows:

Pursue a Balanced Drilling Program. Belco believes that there are
significant exploratory, exploitation and development opportunities in the
acreage positions that the Company has assembled in the Rocky Mountains,
the Permian Basin, the Mid-Continent region and the Austin Chalk Trend. The
Company has identified more than three years of drilling inventory based on
its existing holdings. In addition, the Company has other exploitation and
development opportunities which it plans to pursue. For the nine months
ended September 30, 1997 on a pro forma basis, the Company made capital
expenditures for drilling operations and leasehold acquisitions of
approximately $127.5 million (before property sales of approximately $14
million to third
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parties), and the Company estimates fourth quarter capital expenditures
will exceed $30 million. The Company currently has budgeted $170 million
for capital expenditures for drilling operations and producing property and
leasehold acquisitions in 1998.

PRIMARY OPERATING AREAS

The Company's operations are currently focused in four core operating
areas: (i) the Rocky Mountains, principally in Wyoming in the Green River
(inclusive of the Moxa Arch Trend), Wind River Basin and Big Horn Basins; (ii)
the Permian Basin of west Texas; (iii) the Mid-Continent region in Oklahoma and
north Texas; and (iv) the Austin Chalk Trend, in both Texas and Louisiana. In
addition to these core areas, the Company conducts operations in the onshore
Gulf Coast region and in Michigan's Central Basin.

Rocky Mountains

The Company maintains a significant acreage position in the Rocky Mountains
of Wyoming on which it conducts an ongoing exploration and development program.
In June 1992, the Company commenced a development drilling program in the Moxa
Arch Trend pursuant to a farmout from Amoco. In 1996, the Company significantly
expanded its acreage and exploration activities by acquiring the rights to up to
approximately 750,000 gross (250,000 net) acres in the Green River, Wind River
and Big Horn Basins in Wyoming, which lie north and east of the Moxa Arch Trend.
At December 31, 1997, the Company controlled approximately 825,000 gross
(260,000 net) undeveloped acres in these three basins.

Moxa Arch Trend. One of the Company's primary operating areas is the Moxa
Arch Trend located in the Greater Green River Basin in southwestern Wyoming,
principally in Lincoln, Sweet-
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water and Uinta Counties. Approximately 22% of the Company's estimated proved
reserves at December 31, 1997 were located in this field. The Company
participates in vertical gas wells in this area which target the Frontier and/or
Dakota formations at depths that range from approximately 10,000 to 12,500 feet.
The Frontier formation is a relatively blanket "tight gas sand" formation, while
the Dakota formation, beneath the Frontier, tends to be a more prolific, but
less predictable channel sand. Production from Moxa Arch wells, particularly
from the Frontier formation, tends to be long-lived, with 25 to 30 year reserve
lives not uncommon.

Through 1997, the Company had participated in 208 gross (62 net) wells in
this field with 142 Frontier wells, 15 Dakota wells and 48 dual completions
(both Frontier and Dakota completed). Average net production for the first nine
months of 1997 was approximately 24.2 MMcfe per day. Forty-seven of the
Company's gross wells drilled in 1992 qualified for the Section 29 Tax Credit of
approximately $0.59 per Mcf, which is attributable to all qualified production
from these wells through 2002.

Beginning in the middle of 1994, the Company substantially reduced the rate
at which it participated in new Moxa Arch Trend wells. This reduction was
primarily due to: (i) Rocky Mountain gas prices which, on both an absolute and
relative basis, experienced a substantial decline in 1994 through late 1996, but
which recovered in late 1996 and early 1997, and (ii) the Bureau of Land
Management ("BLM") which required all operators to perform an environmental
impact study ("EIS") along a portion of the Moxa Arch Trend. In March 1997, the
BLM issued its record of decision; in concluding its review of the EIS, the BLM
has authorized the drilling of approximately 700 natural gas wells in the Moxa
Arch Trend, subject to review of certain air quality components. In May 1997,
the Company re-commenced drilling operations in the Moxa Arch Trend and utilized
2-3 rigs to drill 30 locations in 1997 and plans to have an active drilling
program in 1998. See "-- Regulation -- Environmental Regulation."

Green River, Wind River and Big Horn Basins. Effective November 1, 1996,
the Company entered into an agreement with Andex Partners and Andover Partners
to conduct exploratory operations in the Green River and Wind River Basins of
Wyoming. Under the agreement, the Company has committed to spend a minimum of
$20 million on seismic, leasing and exploratory activities through December 31,
2001 and will initially earn rights to a 50% interest in approximately 300,000
net acres. At December 31, 1997, the Company had participated in 1.95 net wells
with successful tests on 0.91 net wells. These wells were operated by either UPR
or Yates Petroleum Corporation ("Yates").

Effective December 31, 1996, the Company entered into two joint development
agreements with Snyder Oil Company ("SOCO") pursuant to which the Company
acquired or has the right to acquire a 50% interest in 87,321 net acres in the
Wind River Basin of Wyoming and 110,859 net acres in the Big Horn Basin of
Wyoming. Under such agreements, SOCO will be the operator. The Tribal #46, the
initial well on the Company's Wind River acreage, was completed in August 1997
and was producing 2.4 MMcf per day on December 31, 1997. The initial well in the
Big Horn Basin, the Otto 16-4, tested at a rate of over 500 Mcfe per day and is
currently waiting on pipeline connection.

In June 1997, the Company entered into a participation agreement with Tom
Brown, Inc. ("Tom Brown") and Andover Partners covering an approximate one
million acre AMI in the Big Horn Basin and acquired an interest in an initial
100,000 gross (25,000 net) acres. 2-D seismic covering portions of this acreage
has been purchased and is currently being interpreted. The first wells on this
acreage are planned for 1998.

The Company expects to participate in a series of exploratory wells in
these Basins with UPR, SOCO, Tom Brown and Yates serving as primary operators.
These wells will target multiple formations, the most prevalent of which is the
Frontier formation. If initial results are successful, these projects hold the
potential for multi-well developmental drilling programs for the Company over
the next several years.

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Permian Basin

Approximately 29% of the Company's estimated proved reserves at December
31, 1997 were located in the Company's Permian Basin core area. These reserves
are concentrated in six waterflood units: the Andrews Unit, the Shafter Lake San
Andres Unit, the Boyd Mallet Unit, the Nolley Wolfcamp Unit, the SE Adair San
Andres Unit, and the SW Wellman San Andres Unit.

The Company's Permian Basin properties produce primarily from either the
Grayburg/San Andres formation, at an average depth of 4,500 feet, or the
Wolfcamp/Penn formation at an average depth of 9,000 feet. All properties that
produce from these horizons are under secondary recovery, and, based on
analogous properties nearby, are potentially responsive to CO(2) miscible
flooding. Given the existence of nearby CO(2) pipelines, the Company believes
many of its properties in the Permian Basin region contain significant upside
potential based on application of enhanced recovery methods and deeper drilling
which could add to existing reserves.

A significant portion of the Company's total proved reserves in the Permian
Basin region lie in Andrews County, Texas. The Company believes that in 1997 it
was the largest independent producer of oil in Andrews County, with
approximately 3,500 gross BOPD, and realized significant advantages as a result
of its large scale operation. The Company owns two large electrical distribution
systems and two saltwater gathering and disposal systems. The Company has
several yards for both the storage of equipment and the staging of new
development projects. Two of the Company's larger production facilities connect
into a water supply system with excess capacity for expanding existing or
initiating new secondary and enhanced recovery projects. The Company believes
that these systems and facilities provide the Company with a competitive
advantage to acquire additional operated properties in Andrews County.

The Company's largest (by value) Permian basin units are the Andrews Unit,
the Shafter Lake San Andres Unit and the Boyd Mallet Unit.

Andrews Unit. The Andrews Unit produces from the Wolfcamp/Penn formation at
approximately 8,600 feet. The Company has a 98.6% working interest in this 3,230
acre unit. Water injection began in late 1996 with expected response in late
1998. Gross production in November 1997 was approximately 500 BOPD with
injection of over 4,000 BWPD. Plans for 1998 include drilling several wells and
expanding the waterflood operation. The Company believes this waterflood is an
excellent CO(2) or surfactant flooding candidate.

Shafter Lake San Andres Unit. The Shafter Lake San Andres Unit is a 12,880
acre unit in Andrews County, Texas that produces from the Grayburg/San Andres
formation at approximately 4,500 feet. The Company has a 62.9% working interest
in this secondary recovery unit. Gross oil production was 980 BOPD in November
1997. The Company has drilled 32 infill 20 acre locations since becoming
operator of the unit in early 1993. Plans for 1998 include expansion of the
waterflood operation by drilling infill producers and converting certain wells
to injection. The Company believes a large part of this field has potential for
10 acre infill wells as well as CO(2) potential.

Boyd Mallet Unit. This Company operated secondary recovery unit is in the
Levelland-Slaughter field in Hockley County, Texas. The Company has an 87.3%
working interest in this unit which produced approximately 200 BOPD (gross) in
November 1997. The unitized interval is the Grayburg/San Andres formation at
5,000 feet. The Company plans to convert eight wells to water injection in 1998
and to drill several infill wells. Based on the performance of direct offset
CO(2) injection and the excellent waterflood history of this property, CO(2)
operations are scheduled to commence in early 1999.

Recent Acquisition. In February 1998 the Company acquired additional
properties in its Permian Basin core area for $37.5 million. The properties
consist of approximately 10.8 MMBOE of estimated proved reserves and would add
approximately 11% to the Company's estimated year end 1997 estimated proved
reserves at a cost of approximately $3.50 per BOE.
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Mid-Continent Region

The Company's Mid-Continent operations are currently focused in Oklahoma,
north Texas and Kansas, where approximately 28% of its estimated proved reserves
at December 31, 1997 were located.

Oklahoma. Six waterfloods collectively represent a majority of the
Company's proved reserves in the region. These waterfloods are identified as the
Calumet Unit, Crooked Creek Unit, Cutter South Unit, Oakdale Unit, Rush Springs
Unit and the Witcher Unit. All six waterfloods were initiated and unitized by
the Company.

Oakdale Red Fork Unit. The Company owns an 88.9% working interest in
this 3,600 acre unit in northwestern Oklahoma. This Company operated
secondary recovery unit produces from the Redfork formation at 6,400 feet.
Gross oil production was approximately 2,180 BOPD in November 1997. Plans
for 1998 include drilling infill producers and fracture stimulating certain
current producers.

Calumet Cottage Grove Unit. This Company operated secondary recovery
unit consists of 11,400 acres in central Oklahoma. Production is from the
Pennsylvanian Cottage Grove formation at 8,100 feet. Gross production in
November 1997 was approximately 2,340 BOPD. The Company has a 44.1% working
interest in this unit. 1998 plans include drilling several infill and
re-entry wells and converting seven wells to injection.

Witcher Red Fork Unit. The 1,620 acre Company operated Witcher Red
Fork Unit is located in Central Oklahoma. The Company has a 70.7% working
interest in this 6,400 foot secondary recovery unit. November 1997
production was approximately 780 BOPD (gross).

North Texas. The north Texas region stretches from the Chadbourne Ranch
Field in Coke County in the west to the Hosey Driskell Unit in Cass County in
the east. The Electra and Burkburnett Fields represent the properties of the
most significant value in the north Texas region. The Company has drilled 250
wells in these two fields since 1991. In addition to the Company's extensive
inventory of oil and gas opportunities in the north Texas region, the Company
owns three large electrical distribution systems and has extensive field
facilities.

Electra Area. The Electra area produces from shallow Cisco sand lenses
from 150 to 2,100 feet. The Company operated 23 leases in this area with
392 active producers and 165 active injectors. The Company has a 100%
working interest in 22 of these leases and a 75% working interest in one
lease. Gross production for November 1997 was approximately 2,030 BOPD. The
Company drilled two 100% working interest wells in October 1997 that are
each producing in excess of 100 BOPD. 1998 plans include drilling 13
producer and injector wells.

Burkburnett Area. The Burkburnett area also produces from the Cisco
formation from 750 to 1,800 feet. The Company operates 13 leases in this
area with 226 active producers and 132 active injectors. The Company's
working interest is 100% in all leases. Gross production for November 1997
was approximately 800 BOPD. Plans for 1998 include drilling approximately
13 producer and 4 injector wells.

Austin Chalk Trend

Texas -- Giddings Field. Approximately 17% of the Company's estimated
proved reserves at December 31, 1997 were located in the Giddings Field of east
central Texas, principally in Grimes, Washington and Fayette Counties. The
Giddings Field is one of the most actively drilled oil and gas fields in the
United States. The primary producing zone in the Giddings Field is the Austin
Chalk, a fractured carbonate formation that has been highly conducive to the
application of horizontal drilling

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technology. The Austin Chalk formation is encountered in this field at depths
believed by the Company to range between approximately 7,000 and 17,000 feet.

The Company first acquired interests in the Giddings Field in September
1992. During the nine months of 1997, average net production from this field was
approximately 101 MMcfe per day. Through September 30, 1997, the Company had
drilled 184 gross (67 net) wells in this field and continues to control
approximately 315,000 gross undeveloped acres in this area. The Company
currently divides the Giddings Field into three prospect areas: (i) Navasota
River, primarily in Grimes County; (ii) Independence, primarily in Washington
County; and, (iii) River Bend, primarily in Fayette County. The Company expects
to be drilling new wells, including infill wells, and re-entering older wells to
drill additional laterals, in the Giddings Field for the foreseeable future.
Currently, a majority of the Company's interests in this field are held pursuant
to agreements with and operated by Chesapeake Energy Corporation ("Chesapeake")
and, to a lesser extent, UPR and Swift Energy Co. The Company serves as operator
for portions of the River Bend prospect area.

The Company believes that its success in the Giddings Field is attributable
to three principal factors: (i) continued technological advances in horizontal
drilling have significantly lowered finding and development costs in the field;
(ii) the geological setting of the deeper downdip areas of the field has created
more extensive fracturing than in other areas of the Texas Austin Chalk Trend;
and, (iii) the Company's acquisition program in cooperation with other operators
has permitted the creation of larger spacing units, thus reducing possible
competition for reserves from offsetting wells. As a result of these factors,
the Company's deeper downdip wells have, on average, produced greater reserves
per well than average wells in other areas of the Texas Austin Chalk Trend.

The majority of the Company's acreage in the Giddings Field was classified
as a tight sands reservoir by the Texas Railroad Commission. Wells spudded
between June 1989 and September 1996 are exempt from the 7.5% state severance
tax on natural gas through August 2001 available for high cost wells. See
"-- Texas Severance Tax Abatement."

Louisiana. The Louisiana Austin Chalk Trend is an extension of the 200-mile
long Austin Chalk Trend of Texas and represents a continuation of the Company's
exploration and development activities using deep-well horizontal drilling
technology. In December 1994, OXY announced the completion of a single lateral
horizontal Austin Chalk discovery in the Masters Creek area of central
Louisiana, approximately 200 miles east of the Company's activities in the
Giddings Field.

Since 1994, more than two and one-half million acres have been leased in
the Louisiana Austin Chalk Trend by industry participants including the Company,
UPR, Chesapeake, OXY and Sonat, Inc. Recent drilling results for the Company
include the Turner 22#1 well, a dual lateral horizontal well, which was placed
on production in late May and as of January 1, 1998 has produced in excess of
423,00 BOE. In addition, in late November the Company successfully completed its
first horizontal lateral in the "B" zone of the Austin Chalk formation, as
opposed to the "A" zone which has been the target of most Louisiana Austin Chalk
wells to date. This well produced approximately 100,000 BOE in its first month
and highlights additional potential for this play. At December 31, 1997, the
Company owned or had the right to acquire approximately 304,000 net acres in
this trend.

In order to further develop its large acreage position, in December 1996
the Company entered into two AMIs with UPR covering approximately 93,000
combined net acres in Avoyelles, Evangeline, Rapides and St. Landry Parishes,
and one AMI with OXY covering approximately 24,000 combined net acres in St.
Landry Parish. These AMIs, which provide for a sharing of costs and benefits as
well as operations in each such area, allow the Company to expedite the
exploration and development of its acreage position and gain the benefits of
shared expertise with two leading industry partners and experienced horizontal
players. In May 1997, the Company created an additional AMI with OXY by selling
additional fractional interests in approximately 29,500 net acres to OXY for
$12.1 million. The Company also retained a small royalty interest on such
acreage.
S-37
<PAGE> 38

Other Operating Areas

Gulf Coast. In March 1996, the Company entered into an exploration
agreement with Edge Petroleum Corporation ("Edge") pursuant to which the parties
expect to jointly conduct a series of 3-D seismic programs covering potentially
up to 750 square miles onshore in the Gulf Coast region of Texas. Under the
program, Edge and the Company initiated the first 50+ square mile 3-D seismic
shoots targeting the shallower Frio formation and potentially larger reserves in
the deeper Yegua and Wilcox formations. Edge is the operator of any shallow zone
wells drilled under the program and under certain circumstances the Company will
operate prospects targeting deeper zones. At December 31, 1997, Belco and Edge
had acquired seismic options on approximately 15,017 gross acres. As of December
31, 1997, the Company had a 50% working interest in seven productive Frio wells
(out of ten wells drilled), six productive Yegua wells (out of six wells
drilled) and one inconclusive Wilcox well based on the evaluations of the
initial 3-D seismic shoot. The Company plans to participate in additional Frio
wells and Yegua and Wilcox prospects throughout 1998.

Michigan -- Central Basin. In June 1996, the Company entered into an
exploration program with two private oil and gas companies pursuant to which the
Company acquired a 35% interest in approximately 220,000 net acres in the
Central Basin of Michigan with the Company serving as operator. At December 31,
1997, the Company held or controlled interests, including the foregoing, in a
total of approximately 282,000 gross and 73,000 net acres in this basin. The
objectives of this play have been thin gas-bearing sands at depths ranging from
approximately 8,000 to 10,000 feet to be tested by vertical wells as well as
shallower oil zones penetrated by horizontal wells. At year-end 1997, the
Company's drilling program was in the process of testing both the vertical and
horizontal prospects covering different portions of this large acreage position
in order to complete the initial evaluation of this play.

S-38
<PAGE> 39

ACREAGE

The following table sets forth, as of December 31, 1997, the gross and net
acres that the Company owned, controlled or had the right to acquire interests
in both developed and undeveloped acreage. Developed acreage refers to acreage
within producing units and undeveloped acreage refers to acreage that has not
been placed in producing units. "Gross" acres refers to the total number of
acres in which the Company owns a working interest. "Net" acres refers to gross
acres multiplied by the Company's fractional working interest.

<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED(1)
----------------- -------------------
GROSS NET GROSS NET
------- ------- --------- -------
<S> <C> <C> <C> <C>
Rocky Mountains:
Green River Basin............................... 1,920 373 425,995 108,877
Moxa Arch Trend................................. 50,221 27,307 24,850 15,858
Wind River Basin................................ 320 120 182,689 69,525
Big Horn Basin.................................. 160 80 218,874 80,950
Denver-Julesburg Basin.......................... 1,560 1,170 285,718 127,692
Permian Basin..................................... 79,468 36,289 20 20
Mid-Continent Region:
Oklahoma........................................ 115,050 37,987 2,500 750
North Texas..................................... 24,658 19,632 -- --
Kansas.......................................... 17,879 15,536 -- --
Austin Chalk Trend:
Texas-Giddings Field............................ 145,753 49,801 266,698 127,024
Louisiana....................................... 7,576 1,773 356,132 304,303
Other Operating Areas:
Michigan-Central Basin.......................... 3,280 2,000 296,922 90,236
------- ------- --------- -------
Totals.................................. 451,896 194,094 2,129,778 975,518
======= ======= ========= =======
</TABLE>

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

(1) Leases covering approximately half of the undeveloped acreage will expire
within the next four years. However, the Company expects to evaluate this
acreage prior to its expiration. The Company's leases generally provide that
the leases will continue past their primary terms if oil or gas in
commercial quantities is being produced from a well on such leases.

S-39
<PAGE> 40

DRILLING ACTIVITY

The following table sets forth the wells participated in by the Company
during the periods indicated. In the table, "gross" refers to the total wells in
which the Company has a working interest, and "net" refers to gross wells
multiplied by the Company's working interest therein.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1995 1996 1997(1)
------------- --------------- -------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Development:
Productive.............................. 84.0 24.0 64.0(2) 23.0 54.0 23.1
Non-productive.......................... 6.0 1.2 2.0 0.8 4.0 2.2
---- ---- ---- ---- ---- ----
Total................................ 90.0 25.2 66.0 23.8 58.0 25.3
==== ==== ==== ==== ==== ====
Exploratory:
Productive.............................. 5.0 1.9 10.0 7.9 20.0 13.7
Non-productive.......................... 2.0 0.3 3.0 2.4 18.0 6.4
---- ---- ---- ---- ---- ----
Total................................ 7.0 2.2 13.0 10.3 38.0 20.1
==== ==== ==== ==== ==== ====
</TABLE>

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

(1) Does not include 41 gross (17.0 net) wells being drilled at December 31,
1997.

(2) Includes three gross oil and gas wells with multiple completions. Wells with
multiple completions are counted only once for purposes of the above table.

The foregoing drilling activity table does not include drilling activity
for Coda. Coda concentrates on exploiting proved producing properties, including
those with development potential, through secondary recovery operations, the
drilling of development wells or infill wells, workovers, recompletions in other
productive zones and other exploitation techniques. Coda has conducted or
intends to conduct significant secondary recovery/infill drilling programs on
many of its properties.

Secondary recovery projects have represented Coda's primary development
focus over the past four years. Generally, "secondary recovery" refers to
methods of oil extraction in which fluid or gas (usually water, natural gas or
CO(2)) is injected into a formation through input (injector) wells, and oil is
removed from surrounding wells. "Waterflooding" is one proven method of
secondary recovery in which water is injected into an oil reservoir for the
purpose of forcing the oil out of the reservoir rock and into the bore of a
producing well. Waterflood projects are engineered to suit the type of
reservoir, depth and condition of the field. Coda has considerable experience
with and actively employs waterflood techniques in many of its fields in order
to stimulate production.

S-40
<PAGE> 41

VOLUMES, REVENUE, PRICES AND PRODUCTION COSTS

The following table sets forth certain information regarding the production
volumes, revenue, average prices received and average production costs
associated with the Company's sale of oil and natural gas for the periods
indicated. The table does not include results for Coda. See the pro forma
information included in "Summary -- Summary Production, Price and Cost Data."

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------- -----------------
1994 1995 1996 1996 1997
------- ------- -------- ------- -------
<S> <C> <C> <C> <C> <C>
Net Production Data:
Oil (MBbl)............................ 691 961 794 575 716
Gas (MMcf)............................ 17,482 37,047 51,289 39,252 36,973
Gas equivalent (MMcfe)................ 21,628 42,813 56,053 42,701 41,269
Oil and Gas Sales ($ in 000's)(1)....... $40,362 $68,767 $119,710 $83,930 $89,742
Average Sales Price (Unhedged):
Oil ($ per Bbl)....................... $ 16.48 $ 17.35 $ 21.30 $ 20.36 $ 19.92
Gas ($ per Mcf)....................... $ 1.67 $ 1.42 $ 2.00 $ 1.84 $ 2.04
Costs ($ per Mcfe):
Oil and gas operating expenses........ $ 0.25 $ 0.14 $ 0.14 $ 0.14 $ 0.16
General and administrative............ $ 0.10 $ 0.06 $ 0.06 $ 0.06 $ 0.06
Depreciation, depletion and
amortization of oil and gas
properties......................... $ 0.65 $ 0.64 $ 0.73 $ 0.70 $ 0.78
</TABLE>

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

(1) Oil and gas sales exclude results related to commodity price risk management
activities reported separately.

DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES

The following table sets forth certain information regarding the costs
incurred by the Company in its development, exploration and acquisition
activities during the periods indicated. The table does not include information
for Coda.

<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED
------------------------------ SEPTEMBER 30,
1994 1995 1996 1997
------- ------- -------- -------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Development Costs......................... $39,587 $54,451 $ 50,433 $ 45,749
Exploration Costs......................... 1,727 2,382 17,444 30,498
Acquisition Costs:
Unproved properties..................... 10,916 13,643 64,530 20,785
Proved properties....................... -- -- 9,871 4,435
Capitalized Interest...................... -- 911 434 527
------- ------- -------- --------
Total................................ $52,230 $71,387 $142,712 $101,994
======= ======= ======== ========
</TABLE>

OIL AND GAS RESERVES

The Company engaged Miller and Lents to estimate the Company's net proved
reserves, projected future production, estimated future net revenue relating to
properties with 94% of its estimated net proved reserves, and the present value
of such estimated future net revenue as of December 31, 1997. Miller and Lents'
estimates were based upon a review of production histories and other geologic,
economic, ownership and engineering data provided by the Company. In estimating
the reserve quantities that are economically recoverable, Miller and Lents used
selling prices and estimated development and production costs that were in
effect during December 1997 without giving effect to hedging activities. In
accordance with requirements of the Commission, no

S-41
<PAGE> 42

price or cost escalation or de-escalation was considered by Miller and Lents.
Based upon the Miller and Lents Report, the Company has calculated estimated
future net revenues to give effect to the impact of oil and gas commodity
hedges, which are set forth in footnote (4) to the following table.

Horizontal completions are relatively new and, therefore, reserve estimates
for such wells are inherently less certain than estimates of reserves from wells
completed utilizing traditional methods having longer production histories. This
lack of operating history also prevents reservoir engineers from estimating
reserves based on production and pressure performance methods. Reserves assigned
to these properties were necessarily based on analogy with older wells producing
from the same horizons. Reserve estimates based on analogy are less precise than
estimates based on volumetric calculations or analysis of production and
pressure performance.

The table below sets forth information as of December 31, 1997, with
respect to the Company's estimated net proved reserves, 94% of which were
estimated by Miller and Lents. The present value of estimated future net revenue
shown is not intended to represent the current market value of the estimated oil
and gas reserves owned by the Company.

<TABLE>
<CAPTION>
PROVED PROVED
DEVELOPED(1) UNDEVELOPED(2) TOTAL
------------ -------------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Estimated Proved Reserves:
Oil and condensate (MBbls)........................ 41,255 9,905 51,160
Gas (MMcf)(3)..................................... 226,071 71,114 297,185
Gas equivalents (MMcfe)........................... 473,600 130,543 604,143
Estimated Future Net Revenue Before Income
Taxes(4).......................................... $792,085 $139,882 $931,968
Present Value of Estimated
Future Net Revenue Before Income Taxes
(Discounted at 10% Per Annum)(4).................. $441,962 $ 62,942 $504,904
</TABLE>

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

(1) Proved developed reserves are proved reserves which are expected to be
recovered from existing wells with existing equipment and operating methods.

(2) Proved undeveloped reserves are proved reserves which are expected to be
recovered from new wells drilled to known reservoirs on undrilled acreage
for which the existence and recoverability of such reserves can be estimated
with reasonable certainty or from existing wells where a relatively major
expenditure is required to establish production.

(3) Includes natural gas liquids.

(4) Estimated future net revenue before income taxes represents estimated future
gross revenue to be generated from the production of proved reserves, net of
estimated production and future development costs, using average December
1997 prices, which were $2.30 per Mcf of gas and $17.28 per barrel of oil
without giving effect to commodities price risk management activities
accounted for as hedges. At December 31, 1997, the estimated future net
revenue before income taxes and the present value of such estimated future
net revenue before income taxes related to such activities were $5.9 million
and $5.5 million, respectively (based on oil and gas prices in effect at
December 31, 1997), which amounts have not been added to estimated future
net revenue before income taxes and its present value as shown above. If
such amounts were added, estimated future net revenue before income taxes
would equal $798 million (Proved Developed) and $938 million (Total) and
present values of such estimated future net revenues before income taxes
would equal $447.5 million (Proved Developed) and $510.4 million (Total).

The amounts shown are in thousands and do not give effect to non-property
related expenses, such as general and administrative expenses, debt service and
future income tax expense or to depreciation, depletion and amortization.

S-42
<PAGE> 43

The prices used in calculating the estimated future net revenue
attributable to proved reserves do not necessarily reflect market prices for oil
and gas production subsequent to December 1997, which have generally declined.
There can be no assurance that all of the proved reserves will be produced and
sold within the periods indicated, that the assumed prices will actually be
realized for such production or that existing contracts will be honored or
judicially enforced.

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 represents only estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact way, 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
made by different engineers often vary. In addition, results of drilling,
testing and production subsequent to the date of an estimate may justify
revision of such estimates, and such revisions may be material. Accordingly,
reserve estimates are often different from the quantities of oil and gas that
are ultimately recovered. Furthermore, the estimated future net revenue from
proved reserves and the present value thereof are based upon certain
assumptions, including prices, future production levels and costs, that may not
prove correct over time. Predictions about prices and future production levels
are subject to great uncertainty, and this is particularly true as to proved
undeveloped reserves, which are inherently less certain than proved developed
reserves and which comprise a significant portion of the Company's proved
reserves. See "Risk Factors."

PRODUCTIVE WELL SUMMARY

The following table sets forth the Company's ownership in productive wells
at December 31, 1997. Gross oil and gas wells include three with multiple
completions. Wells with multiple completions are counted only once for purposes
of the following table. Production from various formations in wells without
multiple completions is commingled.

<TABLE>
<CAPTION>
PRODUCTIVE WELLS
-----------------
GROSS NET
------- -------
<S> <C> <C>
Gas......................................................... 667 275
Oil......................................................... 2,123 1,470
----- -----
Total............................................. 2,790 1,745
</TABLE>

MARKETING

There are a variety of factors which affect the market for oil and natural
gas, including the extent of domestic production and imports of oil and gas, the
proximity and capacity of natural gas pipelines and other transportation
facilities, demand for oil and gas, the marketing of competitive fuels and the
effects of state and federal regulations of oil and gas production and sales.
The Company has not experienced any difficulties in marketing its oil or gas.
The oil and gas industry also competes with other industries in supplying the
energy and fuel requirements of industrial, commercial and individual customers.

Although the Company seeks to moderate the impact of price volatility
through its commodity price risk management activities, the Company remains
subject to price fluctuations for natural gas sold in the spot market due
primarily to seasonality of demand and other factors beyond the Company's
control. Domestic oil prices generally follow worldwide oil prices, which are
subject to price fluctuations resulting from changes in world supply and demand.

PRODUCTION SALES CONTRACTS

In Wyoming, the Company sells all of its natural gas, natural gas liquids
and condensate from its Moxa Arch wells under a market sensitive long term sales
contract with Amoco Energy Trading Corporation (the "Amoco Gas Contract"). The
price payable to the Company under the Amoco Gas

S-43
<PAGE> 44

Contract for the gas is the Northwest Pipeline Rocky Mountain Index, plus $0.03
per MMBtu, less fuel charges and gathering fees and adjusted for Btu content.
The Amoco Gas Contract expires on January 1, 1999. The Amoco Gas Contract can be
extended by the Company for an additional three year term.

All of the Company's current Wyoming oil and condensate production is sold
at market related prices pursuant to an option held by Amoco.

The Company's Moxa Arch wells are subject to various gathering agreements
with third parties including, as to wells drilled under the Amoco Farmout
Agreement in the Wilson Ranch, Seven Mile Gulch and Bruff areas, a Gas Gathering
and Processing Agreement dated March 20, 1992 with Northwest Pipeline. Gathering
fees under this agreement are currently $0.065 per MMBtu, subject to indexed
escalation, and fuel charges of 0.5%. Gathering fees and fuel charges in the Cow
Hollow/ Shute Creek areas are similar to those under the Amoco Gas Contract.

In Texas, Louisiana and Oklahoma, the Company sells its gas to purchasers
under percentage of proceeds or index-based contracts. Under the percentage of
proceeds contract, the Company receives a fixed percentage of the resale price
received by the purchaser for sales of residue gas and natural gas liquids
recovered after gathering and processing the Company's gas. The Company receives
between 85% and 92% of the proceeds from residue gas sales and from 85% to 90%
of the proceeds from natural gas liquids sales received by the Company's
purchasers when the products are resold. The residue gas and natural gas liquids
sold by these purchasers are sold primarily based on spot market prices. The
revenue received by the Company from the sale of natural gas liquids is included
in natural gas sales. Under indexed-based contracts, the Company receives for
its gas at the wellhead a price per MMBtu tied to indexes published in Inside
FERC or Gas Daily, subject in most cases to a discount to the relevant index in
lieu of a gathering fee.

All of the Company's oil production is sold under market sensitive or spot
price contracts to various purchasers.

Sales to individual customers constituting 10% or more of total oil and gas
sales in 1997 were made to Aquila Southwest Pipeline (32%), GPM Gas Corporation
(22%) and Amoco Gas Trading Corp. (20%).

Management believes that the loss of any one of the above customers would
not have a material adverse effect on the Company's results of operations or its
financial position.

PRICE RISK MANAGEMENT TRANSACTIONS

Commodity Price Risk Management

With the objective of achieving more predictable revenues and cash flows
and reducing the exposure to fluctuations in gas and oil prices, the Company has
entered into price risk management transactions of various types with respect to
both natural gas and oil, as described below. While the use of these
arrangements limits the downside risk of adverse price movements to a certain
extent, it may also limit future revenues from favorable price movements. The
Company had entered into price risk management transactions with respect to a
substantial portion of its production for 1996 and 1997 and with respect to a
substantial portion of its estimated production for 1998 and 1999 and with
respect to lesser portions thereafter. The Company continues to evaluate whether
to enter into additional such transactions for 1998 and future years. In
addition, the Company may determine from time to time to terminate its then
existing hedging and other risk management positions.

All of the Company's price risk management transactions are carried out in
the over-the-counter market and not on the NYMEX, with financial counterparties
having at least an investment grade credit rating. All of these transactions
provide solely for financial settlements relating to closing prices on the
NYMEX.

S-44
<PAGE> 45

The following is a summary of the types of price risk management
transactions in effect as of December 31, 1997.

Swaps. Since all of the Company's natural gas and oil is sold on "floating"
or market related prices, the Company has entered into financial swap
transactions which convert a floating price into a fixed price for a future
month. For any particular swap transaction, the counterparty is required to make
a payment to the Company in the event that the NYMEX Reference Price for any
settlement period is less than the swap price for such hedge, and the Company is
required to make a payment to the counterparty in the event that the NYMEX
Reference Price for any settlement period is greater than the swap price for
such hedge.

Reverse Swaps. When the Company determines it desires to reduce the amount
of swaps because of an assumed favorable outlook for prices it enters into a
reverse swap. Under such a transaction the role of the Company and the role of
the counterparty are reversed.

Collars. A collar provides for an average floor price and an average
ceiling price. For any particular collar transaction, the counterparty is
required to make a payment to the Company if the average NYMEX Reference Price
for the reference period is below the floor price for such transaction, and the
Company is required to make payment to the counterparty if the average NYMEX
Reference Price is above the ceiling price for such transaction.

Options, Puts and Straddles. When the Company believes that it receives a
sufficiently high cash premium (or other consideration) for granting the
counterparty a call or put option, it may enter into such a transaction. If the
Company sold a $23.00 call on oil for $0.40 a barrel in a given month and prices
averaged $22.00 a barrel for such month, the Company would receive a net
realization per barrel of $22.40 ($22.00 plus the $0.40 premium). However, if
for that month the price of oil averaged $25.00 per barrel, the Company would
receive a net realization of $23.40 (the call price, $23.00, plus $0.40). The
Company regards this as a prudent transaction under certain circumstances
provided that the Company always has more physical production for the periods
involved than its related aggregate risk management transactions. A limited
number of these transactions contain negotiated knockout, extendable or leverage
provisions. These provisions either limit price protection beyond a specific
level, contain tiered pricing provisions, allow the option to be extended for a
period of time, or provide for payment based upon a multiple of the underlying
notional volume. The transactions described in this paragraph are required to be
marked to market as to the value of these transactions on the last day of the
accounting period to which such statement relates.

Basis Swaps. Since a substantial portion of the Company's natural gas is
sold under spot contracts with reference to Houston Ship Channel prices and the
Company's price risk management transactions are based on the NYMEX Reference
Price relating to gas delivered to Henry Hub, Louisiana, the Company has entered
into basis swaps that require the counterparty to make a payment to the Company
in the event that the average NYMEX Reference Price per MMBtu for gas delivered
to Henry Hub, Louisiana for a reference period exceeds the average price for
MMBtu for gas delivered at the Houston Ship Channel for such reference period by
more than a stated differential, and requires the Company to make a payment to
the counterparty in the event that the NYMEX Reference Price for Henry Hub
exceeds the price for Houston Ship Channel gas by less than the stated
differential (or in the event that the Houston Ship Channel price exceeds the
Henry Hub price). The Company also sells Wyoming gas at prices based on the
Northwest Pipeline Rocky Mountain Index (an index of prices for gas delivered at
various delivery points on the Northwest Pipeline in the Northern Rocky Mountain
area) and has entered into basis swaps that requires the counterparty to make a
payment to the Company in the event that the average NYMEX Reference Price per
MMBtu for gas delivered at Henry Hub, Louisiana for a reference period exceeds
the stated differential or to have the Company pay to the counterparty if it is
less than the stated differential (or if the Northwest Pipeline Rocky Mountain
index price is greater than the NYMEX reference price).

S-45
<PAGE> 46

Certain of the Company's price risk management transactions were previously
covered by guarantees of, and certain other collateral from Robert A. Belfer.
Subsequent to the Company's initial public offering, all such guarantees have
been terminated and all such collateral has been returned.

TEXAS SEVERANCE TAX ABATEMENT

Production from natural gas wells that have been certified as tight
formations or deep wells by the Texas Railroad Commission ("high cost gas
wells") and that were spudded or completed during the period from June 16, 1989
to September 1, 1996 qualify for an exemption from the 7.5% severance tax in
Texas on natural gas and natural gas liquids produced by such wells prior to
August 31, 2001. The natural gas production from wells drilled on certain of the
Company's properties in the Austin Chalk area qualify for this tax exemption. In
addition, high cost gas wells that are spudded or completed during the period
from September 1, 1996 to August 31, 2002 are entitled to receive a severance
tax reduction upon obtaining a high cost gas certification from the Texas
Railroad Commission within 180 days after first production. The tax reduction is
based on a formula composed of the statewide "median" (as determined by the
State of Texas from producer reports) and the producer's actual drilling and
completion costs. More expensive wells will receive a greater amount of tax
credit. This tax rate reduction remains in effect for 10 years or until the
aggregate tax credits received equal 50% of the total drilling and completion
costs.

LOUISIANA SEVERANCE TAX ABATEMENTS

A five-year exemption from severance tax applies to production from oil and
gas wells that are returned to service after having been inactive for two or
more years or having 30 days or less of production during the past two years. An
application must be made to the Louisiana Department of Natural Resources before
commencement of production during the period beginning July 31, 1994, and ending
June 30, 1998. Upon certification, the five-year exemption period begins from
the date of the application.

All severance tax is suspended for 24 months or until payout of the well
cost is achieved, whichever occurs first, on any horizontally drilled well or
recompletion well from which production commences after July 31, 1994. The term
"horizontal drilling" means high angle drilling of bore holes with 50 to 3,000
plus feet of lateral penetration through productive reservoirs, and "horizontal
recompletion" means horizontal drilling in an existing well bore.

Production of natural gas, gas condensate and oil from any well drilled to
a true vertical depth of more than 15,000 feet and where production starts after
July 31, 1994, is exempt from severance tax for 24 months or until payout of the
well cost, whichever occurs first. The exemption applies to production from any
depth in the wellbore.

Currently, the Louisiana severance tax rate on oil is 12.5% of gross value
and the severance tax on gas is 7.7 cents per Mcf. Only one of the severance tax
exemptions discussed above may be taken on a particular well. The Company
anticipates that a substantial portion of its current and future Louisiana wells
will qualify for one of the two exemptions discussed above.

SECTION 29 TAX CREDIT

The natural gas production from wells drilled on certain of the Company's
properties in the Moxa Arch Trend and Golden Trend Field qualifies for the
Section 29 Tax Credit. The Section 29 Tax Credit is an income tax credit against
regular federal income tax liability with respect to sales of the Company's
production of natural gas produced from tight gas sand formations, subject to a
number of limitations. Fuels qualifying for the Section 29 Tax Credit must be
produced from a well drilled or a facility placed in service after November 5,
1990 and before January 1, 1993, and be sold before January 1, 2003.

S-46
<PAGE> 47

The basic credit, which is currently approximately $0.52 per MMbtu of
natural gas produced from tight sand reservoirs and approximately $1.03 per
MMbtu of natural gas produced from Devonian Shale, is computed by reference to
the price of crude oil and is phased out as the price of oil exceeds $23.50 in
1979 dollars (as adjusted for inflation) with complete phaseout if such price
exceeds $29.50 in 1979 dollars (as adjusted for inflation). Under this formula,
the commencement of phaseout would be triggered if the average price for crude
oil rose above approximately $45 per Bbl in current dollars. The Company
generated approximately $0.9 million of Section 29 Tax Credits in 1996. The
Section 29 Tax Credit may not be credited against the alternative minimum tax,
but under certain circumstances may be carried over and applied against regular
tax liability in future years. Therefore, no assurances can be given that the
Company's Section 29 Tax Credits will reduce its federal income tax liability in
any particular year.

REGULATION

The oil and gas industry is extensively regulated by federal, state and
local authorities. In particular, oil and gas production operations and
economics are affected by price controls, environmental protection statutes and
regulations, tax statutes and other laws relating to the petroleum industry, as
well as changes in such laws, changing administrative regulations and the
interpretations and application of such laws, rules and regulations. In October
1992, comprehensive national energy legislation was enacted which focuses on
electric power, renewable energy sources and conservation. This legislation,
among other things, guarantees equal treatment of domestic and imported natural
gas supplies, mandates expanded use of natural gas and other alternative fuel
vehicles, funds natural gas research and development, permits continued offshore
drilling and use of natural gas for electric generation and adopts various
conservation measures designed to reduce consumption of imported oil. The
legislation may be viewed as generally intended to encourage the development and
use of natural gas. Oil and gas industry legislation and agency regulation are
under constant review for amendment and expansion for a variety of political,
economic and other reasons.

Regulation of Natural Gas and Oil Exploration and Production. The Company's
operations are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units and the density of wells which may
be drilled in and the unitization or pooling of oil and gas properties. In this
regard, some states (such as Oklahoma) allow the forced pooling or integration
of tracts to facilitate exploration while other states (such as Texas) rely on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it
may be more difficult to form units and, therefore, more difficult to develop a
project if the operator owns less than 100% of the leasehold. In addition, state
conservation laws establish maximum rates of production from oil and gas wells,
generally prohibit the venting or flaring of gas and impose certain requirements
regarding the ratability of production. The effect of these regulations may
limit the amount of oil and gas the Company can produce from its wells and may
limit the number of wells or the locations at which the Company can drill. The
regulatory burden on the oil and gas industry increases the Company's costs of
doing business and, consequently, affects its profitability. Inasmuch as such
laws and regulations are frequently expanded, amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
regulations.

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<PAGE> 48

The Company has operations located on federal oil and gas leases, which are
administered by the MMS. Such leases are issued through competitive bidding,
contain relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to the Outer Continental Shelf Lands Act
("OCSLA") (which are subject to change by the MMS). For offshore operations,
lessees must obtain MMS approval for exploration plans and development and
production plans prior to the commencement of such operations. In addition to
permits required from other agencies (such as the Coast Guard, the Army Corps of
Engineers and the Environmental Protection Agency (the "EPA")), lessees must
obtain a permit from the MMS prior to the commencement of drilling. The MMS has
promulgated regulations requiring offshore production facilities located on the
Outer Continental Shelf (the "OCS") to meet stringent engineering and
construction specifications. The MMS proposed additional safety-related
regulations concerning the design and operating procedures for OCS production
platforms and pipelines. These proposed regulations were withdrawn pending
further discussions among interested federal agencies. The MMS also has
regulations restricting the flaring or venting of natural gas, liquid
hydrocarbons and oil without prior authorization. Similarly, the MMS has
promulgated other regulations governing the plugging and abandonment of wells
located offshore and the removal of all production facilities. To cover the
various obligations of lessees on the OCS, the MMS generally requires that
lessees post substantial bonds or other acceptable assurances that such
obligations will be met. The cost of such bonds or other surety can be
substantial and there is no assurance that bonds or other surety can be obtained
in all cases. Under certain circumstances, the MMS may require Company
operations on federal leases to be suspended or terminated. Any such suspension
or termination could materially and adversely affect the Company's financial
condition and operations.

The MMS issued a notice of proposed rulemaking in which it proposed to
amend its regulations governing the calculation of royalties and the valuation
of crude oil produced from federal leases. The proposed rule would modify the
valuation procedures for both arm's length and non-arm's length crude oil
transactions to decrease reliance on posted prices and assign a value to crude
oil that better reflects market value, establish a new MMS form for collecting
value differential data and amend the valuation procedure for the sale of
federal royalty oil. The Company cannot predict at this stage of the rulemaking
proceeding how it might be affected by this amendment to the MMS regulations.

In April 1997, after two years of study, the MMS withdrew proposed changes
to the way it values natural gas for royalty payments. These proposed changes
would have established an alternative market-based method to calculate royalties
on certain natural gas sold to affiliates or pursuant to non-arm's length sales
contracts.

Recently, the MMS has issued a final rule to clarify the types of costs
that are deductible transportation costs for purposes of royalty valuation of
production sold off the lease. In particular, under the rule, the MMS will not
allow deduction of costs associated with marketer fees, cash out and other
pipeline imbalance penalties, or long-term storage fees. The Company cannot
predict what, if any, effect the new rule will have on its operations.

Natural Gas and Oil Marketing and Transportation. Historically, the
transportation and sale for resale of natural gas in interstate commerce have
been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy
Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the
Federal Energy Regulatory Commission (the "FERC"). In the past, the federal
government has regulated the prices at which oil and gas could be sold.
Deregulation of wellhead sales in the natural gas industry began with the
enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was
enacted. This act amended the NGPA to remove both price and non-price controls
from natural gas sold in "first sales" as of January 1, 1993. While sales by
producers of natural gas and all sales of crude oil, condensate and natural gas
liquids can currently be made at uncontrolled market prices, Congress could
reenact price controls in the future.

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Several major regulatory changes have been implemented by the FERC from
1985 to the present that affect the economics of natural gas production,
transportation and sales. In addition, the FERC continues to promulgate
revisions to various aspects of the rules and regulations affecting those
segments of the natural gas industry, most notably interstate natural gas
transmission companies, which remain subject to the FERC's jurisdiction. These
initiatives may also affect the intrastate transportation of gas under certain
circumstances. The stated purposes of many of these regulatory changes is to
promote competition among the various sectors of the gas industry. The ultimate
impact of these complex and overlapping rules and regulations, many of which are
repeatedly subjected to judicial challenge and interpretation, cannot be
predicted.

Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and
636-C (collectively, "Order No. 636"), which, among other things, require
interstate pipelines to "restructure" to provide transportation separate, or
"unbundled," from the pipelines' sales of gas. Also, Order No. 636 requires
pipelines to provide open-access transportation on a basis that is equal for all
gas supplies. Order No. 636 has been implemented as a result of FERC orders in
individual pipeline service restructuring proceedings. In many instances, the
result of the Order No. 636 and related initiatives have been to substantially
reduce or bring to an end the interstate pipelines' traditional roles as
wholesalers of natural gas in favor of providing only storage and transportation
services. The FERC has issued final orders in virtually all pipeline
restructuring proceedings, and has completed a series of one year reviews to
determine whether refinements are required regarding individual pipeline
implementations of Order No. 636.

Although Order No. 636 does not directly regulate natural gas producers
such as the Company, the FERC has stated that Order No. 636 is intended to
foster increased competition within all phases of the natural gas industry. It
is unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company and its natural gas
marketing efforts. The United States Court of Appeals for the District of
Columbia Circuit (the "Court") recently issued its decision in the appeals of
Order No. 636. The Court largely upheld the basic tenets of Order No. 636,
including the requirements that interstate pipelines "unbundle" their sales of
gas from transportation and that pipelines provide open-access transportation on
a basis that is equal for all gas suppliers. The Court remanded several
relatively narrow issues for further explanation by the FERC. In doing so, the
Court made it clear that the FERC's existing rules on the remanded issues would
remain in effect pending further consideration. The Company believes that the
issues remanded for further action do not appear to materially affect it. The
United States Supreme Court has decided not to review the Court's decision
regarding Order No. 636. In February 1997, the FERC issued Order No. 636-C, its
order on remand from the Court. Order 636-C is currently pending on rehearing
before the FERC. Although Order No. 636 could provide the Company with
additional market access and more fairly applied transportation service rates,
terms and conditions, it could also subject the Company to more restrictive
pipeline imbalance tolerances and greater penalties for violations of those
tolerances. The Company does not believe, however, that it will be affected by
any action taken with respect to Order No. 636 materially differently than other
natural gas producers and marketers with which it competes.

The FERC has issued a statement of policy and a request for comments
concerning alternatives to its traditional cost-of-service rate making
methodology. This policy statement articulates the criteria that the FERC will
use to evaluate proposals to charge market-based rates for the transportation of
natural gas. The policy statement also provides that the FERC will consider
proposals for negotiated rates for individual shippers of natural gas, so long
as a cost-of-service-based rate is available as a recourse rate. A number of
pipelines have obtained FERC authorization to charge negotiated rates. The FERC
also has requested comments on whether it should allow gas pipelines the
flexibility to negotiate the terms and conditions of transportation service with
prospective shippers. The Company cannot predict what further action the FERC
will take on these matters, however, the Company does not believe that it will
be affected by any action taken materially differently than other natural gas
producers and marketers with which it competes.

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<PAGE> 50

The FERC has announced its intention to reexamine certain of its
transportation-related policies, including the manner in which interstate
pipeline shippers may release interstate pipeline capacity under Order No. 636
for resale in the secondary market, and the price shippers can charge for
released capacity. In February 1997, the FERC announced a broad inquiry into
issues facing the natural gas industry, to assist the FERC in establishing
regulatory goals and priorities. In November 1997, the FERC issued a proposed
rulemaking to further standardize pipeline transportation tariffs that, if
implemented as proposed, could adversely affect the reliability of scheduled
interruptible transportation service. In December 1997, the FERC requested
comments on the financial outlook of the natural gas pipeline industry,
including among other matters, whether the FERC's current rate making policies
are suitable in the current industry environment. While any resulting FERC
action would affect the Company only indirectly, the FERC's current rules and
policies may have the effect of enhancing competition in natural gas markets by,
among other things, encouraging non-producer natural gas marketers to engage in
certain purchase and sale transactions. The Company cannot predict what action
the FERC will take on these matters, nor can it accurately predict whether the
FERC's actions will achieve the goal of increasing competition in markets in
which the Company's natural gas is sold. However, the Company does not believe
that it will be affected by any action taken materially differently than other
natural gas producers and marketers with which it competes.

The FERC has issued a policy statement on how interstate natural gas
pipelines can recover the costs of new pipeline facilities. While the FERC's
policy statement on new construction cost recovery affects the Company only
indirectly, in its present form, the new policy should enhance competition in
natural gas markets and facilitate construction of gas supply laterals. The FERC
has denied requests for rehearing of this policy statement. The FERC has issued
numerous orders approving the spin-down or spin-off by interstate pipelines of
their gathering facilities. A "spin-off" is a FERC-approved sale of gathering
facilities to a non-affiliate. A "spin-down" is a transfer of gathering
facilities to an affiliate. These approvals were given despite the strong
protests of a number of producers concerned that any diminution in FERC's
oversight of interstate pipeline-related gathering services might result in a
denial of open access or otherwise enhance the pipeline's monopoly power. The
FERC's lead decision in this area has been largely affirmed by an appellate
court. While the FERC has stated that it will retain limited jurisdiction over
such gathering facilities and will hear complaints concerning any denial of
access, it is unclear what effect the FERC's gathering policy will have on
producers such as the Company and the Company cannot predict what further action
the FERC will take on these matters. One possible result of the FERC's actions
may be increased state regulatory oversight of gathering.

Commencing in October 1993, the FERC issued a series of rules (Order Nos.
561 and 561-A) establishing an indexing system under which oil pipelines will be
able to change their transportation rates, subject to prescribed ceiling levels.
The indexing system, which allows or may require pipelines to make rate changes
to track changes in the Producer Price Index for Finished Goods, minus one
percent, became effective January 1, 1995. The FERC's decision in this matter
was recently affirmed by the Court. The Company is not able at this time to
predict the effects of Order Nos. 561 and 561-A, if any, on the transportation
costs associated with oil production from the Company's oil producing
operations.

Additional proposals and proceedings that might affect the oil and gas
industry are pending before the FERC and the courts. The Company cannot predict
when or whether any such proposals may become effective. In the past, the
natural gas industry has been heavily regulated. There is no assurance that the
regulatory approach currently pursued by the FERC will continue indefinitely.
Notwithstanding the foregoing, the Company does not anticipate that compliance
with existing federal, state and local laws, rules and regulations will have a
material or significantly adverse effect upon the capital expenditures, earnings
or competitive position of the Company.

Environmental Regulation. Activities of the Company with respect to the
exploration, development and production of oil and natural gas are subject to
stringent environmental regulation by state
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and federal authorities including the EPA. Such regulation has increased the
cost of planning, designing, drilling, operating and in some instances,
abandoning wells. In most instances, the regulatory requirements relate to the
handling and disposal of drilling and production waste products and waste
created by water and air pollution control procedures. Although the Company
believes that compliance with existing environmental regulations will not have a
material adverse effect on operations or earnings, the risks of substantial
costs and liabilities are inherent in oil and gas operations, and there can be
no assurance that significant costs and liabilities, including civil and
criminal penalties, will not be incurred. Moreover, it is possible that other
developments, such as stricter environmental laws and regulations, and claims
for damages to property or persons resulting from the Company's operations could
result in substantial costs and liabilities to the Company.

The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
with respect to the release of a "hazardous substance" into the environment.
These persons include the owner and operator of the disposal site or sites where
the release occurred and companies that disposed or arranged for the disposal of
the hazardous substances released at such site. Persons who are or were
responsible for releases of hazardous substances under CERCLA may be subject to
joint and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment and for damages to
natural resources, and it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the hazardous substances released into the environment.

The Company generates wastes, including hazardous wastes, that are subject
to the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The EPA and various state agencies have limited the approved
methods of disposal for certain hazardous and nonhazardous wastes. Furthermore,
it is possible that certain wastes generated by the Company's oil and natural
gas operations that are currently exempt from treatment as "hazardous wastes"
may in the future be designated as "hazardous wastes" under RCRA or other
applicable statutes and therefore be subject to more rigorous and costly
operating and disposal requirements.

The Company currently owns or leases, and has in the past owned or leased,
numerous properties that for many years have been used for the exploration and
production of oil and gas. Although the Company has utilized operating and
disposal practices that were standard in the industry at the time, hydrocarbons
or other wastes may have been disposed of or released on or under the properties
owned or leased by the Company or on or under other locations where such wastes
have been taken for disposal. In addition, many of these properties have been
owned or operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under the Company's control. These
properties and the wastes disposed thereon may be subject to CERCLA, RCRA and
analogous state laws. Under such laws, the Company could be required to remove
or remediate previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination (including
groundwater contamination by prior owners or operators) or to perform remedial
plugging operations to prevent future contamination.

The Oil Pollution Act of 1990 (the "OPA") amends certain provisions of the
Federal Water Pollution Control Act of 1972, commonly referred to as the Clean
Water Act ("CWA") and other statutes as they pertain to the prevention of and
response to oil spills into navigable waters. The OPA subjects owners and
operators of facilities to strict joint and several liability for all
containment and cleanup costs and certain other public and private damages
arising from a spill, including, but not limited to, the costs of responding to
a release of oil to surface waters. OPA establishes a liability limit for
onshore facilities of $350 million and for offshore facilities, all removal
costs plus $75 million, however, a party cannot take advantage of liability
limits if the spill is caused by gross negligence or willful misconduct or
resulted from a violation of a federal safety, construction or
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operating regulation. If a party fails to report a spill or cooperate in the
cleanup, liability limits likewise do not apply. The CWA provides penalties for
any discharges of petroleum product in reportable quantities and imposes
substantial liability for the costs of removing a spill. State laws for the
control of water pollution also provide varying civil and criminal penalties and
liabilities in the case of releases of petroleum or its derivatives into surface
waters or into the ground. Federal regulations under the CWA and OPA require
certain owners or operators of facilities that store or otherwise handle oil,
such as the Company, to prepare and implement spill prevention, control and
countermeasure plans and facility response plans relating to the possible
discharge of oil into surface waters. In addition, the CWA and analogous state
laws require permits to be obtained to authorize discharges into surface waters
or to construct facilities in wetland areas. With respect to certain of its
operations, the Company is required to maintain such permits or meet general
permit requirements. In 1992, the EPA adopted regulations concerning discharges
of storm water runoff. This program requires covered facilities to obtain
individual permits, participate in a group permit or seek coverage under an EPA
general permit. The Company believes that it is in substantial compliance with
the requirements of the CWA and OPA and that any non-compliance would not have a
material adverse effect on the Company.

In April of 1994, the BLM directed that an EIS be performed along a portion
of the Moxa Arch area of Wyoming. The final EIS was completed in June of 1996.
In March of 1997, the BLM issued its record of decision relating to this EIS.
During the pendency of the EIS and record of decision, regulatory approval to
drill wells in the affected area was difficult to obtain. The BLM's record of
decision authorized the drilling of approximately 700 natural gas wells in the
Moxa Arch, subject to review of certain air quality components. The Company
believes that drilling activity will now resume, albeit subject to the record of
decision.

OPERATING HAZARDS AND INSURANCE

Oil and gas drilling and production activities are subject to numerous
risks, many of which are beyond the Company's control. These risks include the
risk that no commercially productive oil or natural gas reservoirs will be
encountered, that operations may be curtailed, delayed or canceled as a result
of title problems, weather conditions, compliance with governmental
requirements, mechanical difficulties or shortages or delays in the delivery of
equipment and that the availability or capacity of gathering systems, pipelines
or processing facilities may limit the Company's ability to market its
production. There can be no assurance that new wells drilled by the Company will
be productive or that the Company will recover all or any portion of its
investment. Drilling for oil and natural gas may involve unprofitable efforts,
not only from dry wells, but from wells that are productive but do not produce
sufficient net revenues to return a profit after drilling, operating and other
costs.

In addition, the Company's properties may be susceptible to hydrocarbon
drainage from production by other operators on adjacent properties. Industry
operating risks include the risk of fire, explosions, blow-outs, pipe failure,
abnormally pressured formations and environmental hazards such as oil spills,
gas 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. Additionally, the
Company's oil and gas operations are located in an area that is subject to
tropical weather disturbances, some of which can be severe enough to cause
substantial damage to facilities and possibly interrupt production.

The MMS requires lessees of OCS properties to post performance bonds in
connection with the plugging and abandonment of wells located offshore and the
removal of all production facilities. The Company has posted an area wide bond
meeting MMS requirements and has obtained additional supplemental bonding on its
offshore leases as required by the MMS.

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The Company maintains customary oil and gas related third party liability
coverage, which it must renew annually, that insures the Company against certain
sudden and accidental risks associated with drilling, completing and operating
its wells. There can be no assurance that this insurance will be adequate to
cover any losses or exposure to liability or that the Company will be able to
renew its coverage annually. The Company and its subsidiaries carry workers'
compensation insurance in all states in which they operate. While the Company
believes this coverage is customary in the industry, it does not provide
complete coverage against all operating risks.

TITLE TO PROPERTIES

Title to properties is subject to royalty, overriding royalty, carried, net
profits, working and other similar interests and contractual arrangements
customary in the oil and gas industry, to liens for current taxes not yet due
and to other encumbrances. As is customary in the industry in the case of
undeveloped properties, little investigation of record title is made at the time
of acquisition of leasehold interests (other than a preliminary review of local
records). Investigations, including a title opinion of local counsel, are
generally made before commencement of drilling operations. To the extent title
opinions or other investigations reflect title defects, the Company, rather than
the seller of the undeveloped property, is typically responsible to cure any
such title defects at its expense. If the Company were unable to remedy or cure
title defect of a nature such that it would not be prudent to commence drilling
operations on the property, the Company could suffer a loss of its entire
investment in the property. From time to time the Company's title to oil and gas
properties is challenged through legal proceedings. Under the terms of certain
of the Company's joint development, participation and farmout agreements, the
Company's interest (other than interests acquired through holding of leasehold
interests prior to spudding of the well) in each well is conveyed to the Company
upon the successful completion of the well or satisfaction of other conditions.

EMPLOYEES

As of December 31, 1997, the Company had 208 full time employees, none of
whom is represented by organized labor unions. The Company considers its
employee relations to be good.

LEGAL PROCEEDINGS

The Company is not a party to any material pending legal proceedings, other
than ordinary routine litigation incidental to its business that management
believes would not have a material adverse effect on its financial condition or
results of operations.

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MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth the name, age and position of each of the
Company's executive officers and directors:

<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Robert A. Belfer.......... 62 Chairman of the Board and Chief Executive Officer
Laurence D. Belfer........ 31 Director, President and Chief Operating Officer
Philip A. Epstein......... 41 Senior Financial and Legal Advisor and General Counsel
Dominick J. Golio......... 51 Vice President -- Finance, Chief Financial Officer and
Treasurer
Shiv K. Sharma............ 55 Senior Vice President -- Engineering
Steven L. Mueller......... 44 Senior Vice President -- Exploration
Mel Fife.................. 46 Vice President -- Business Development
Gary Hampton.............. 41 Vice President -- Exploration -- Eastern Region
M. Bradford Moody......... 38 Vice President -- Legal and Land
George A. Sheffer......... 45 Vice President -- Operations
Jarl P. Johnson........... 67 Vice Chairman and Chief Operating Officer of Coda
Grant W. Henderson........ 39 President and Chief Financial Officer of Coda
Graham Allison............ 57 Director
Daniel C. Arnold.......... 67 Director
Alan D. Berlin............ 57 Director
Jack Saltz................ 66 Director
Georgiana Sheldon-Sharp... 73 Director
</TABLE>

Robert A. Belfer, Chairman of the Board and Chief Executive Officer of the
Company. Mr. Belfer began his career at BPC in 1958 and became Executive Vice
President in 1964, President in 1965 and Chairman of the Board in 1984. BPC was
an independent oil and gas producer in the United States and abroad, which went
public in 1959. It was one of the larger independent oil and gas companies in
the United States and was included in Fortune's listing of the 500 largest
industrial companies in the United States prior to merging with InterNorth, Inc.
(now Enron Corp.) in 1983. Following the merger, Mr. Belfer became Chief
Operating Officer of BelNorth Petroleum Corp., a combination of oil and gas
producing operations of BPC and InterNorth. He resigned from his position with
InterNorth in 1986 and pursued personal investments in oil and gas and other
industries. In April 1992, Mr. Belfer founded the Company. In addition to his
position at the Company, Mr. Belfer serves on the boards of Enron and NAC Re
Corporation. Mr. Belfer received his undergraduate degree from Columbia College
(A.B. 1955) and a law degree from the Harvard Law School (J.D. 1958).

Laurence D. Belfer, Director, President and Chief Operating Officer of the
Company. Mr. Belfer joined the Company as Vice President in September 1992. He
was promoted to Executive Vice President in May 1995 and Chief Operating Officer
in December 1995 and was named President in April 1997. He is a founder and
Chairman of Harvest Management, Inc., a money management firm. Mr. Belfer
graduated from Harvard University (B.A. 1988) and from Columbia Law School (J.D.
1992).

Philip A. Epstein, Senior Financial and Legal Advisor and General Counsel
of the Company. Mr. Epstein began his career as a corporate associate with the
New York City law firms of Kaye, Scholer, Fierman, Hays & Handler (1984-1987)
and Fried, Frank, Harris, Shriver & Jacobson (1988-1991), specializing in
mergers and acquisitions and corporate finance. Mr. Epstein joined the Belfer
family in 1991 as Investment Counsel, assuming the founding positions of
Executive Vice President, General Counsel and Secretary of the Company in April
1992. Mr. Epstein resigned from these

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<PAGE> 55

positions in December 1992 but continues to serve as Senior Financial and Legal
Advisor and General Counsel to the Company. Mr. Epstein received an
undergraduate degree from the University of Chicago (B.A. 1978), a graduate
degree in Politics and Economics from Oxford University (M.A. Oxon 1981) and his
law degree from Northwestern University of Law (J.D. 1984).

Dominick J. Golio, Vice President -- Finance, Chief Financial Officer and
Treasurer of the Company. Mr. Golio began his career at the New York City office
of Arthur Andersen & Co. in 1972. In 1975, he joined Case, Pomeroy & Company and
Felmont Oil Corporation, its publicly traded affiliate, where he rose to the
position of Vice President Finance. Mr. Golio left Felmont in 1987 following a
merger between Felmont and Homestake Mining Company. He served as Vice President
Finance and Administration at both AEG Corporation, the U.S. electronics
subsidiary of Daimler-Benz North America, until 1991 and at Millmaster Onyx
Group, Inc. until September 1993 at which time he joined the Company. Mr. Golio
is a Certified Public Accountant (NY). He holds undergraduate and graduate
degrees from Pace University (B.B.A. Accounting, 1972, M.B.A. -- Taxation,
1978).

Shiv K. Sharma, Senior Vice President -- Engineering of the Company. Mr.
Sharma began his career in 1967 as a Reservoir Engineer with Shell Oil Company.
In 1970, he joined BPC as a reservoir engineer and was subsequently elected to
Vice President and Senior Vice President of Engineering, a position he held
until his departure from that company in 1988. From 1988 to 1992, Mr. Sharma
worked as a petroleum consultant for several New York companies. He served as a
director and consultant to the Company commencing April 1992 and was elected to
his present position in April 1994. Mr. Sharma received his degrees in petroleum
technology from the Indian School of Mines (B.S. 1963) and petroleum engineering
from Stanford University (M.S. 1966).

Steven L. Mueller, Senior Vice President -- Exploration of the Company. Mr.
Mueller began his career in 1975 as a Geological Engineer at Tenneco Oil,
Lafayette. He advanced at Tenneco Oil, Lafayette to Senior Geological Engineer
in 1979, Project Geological Engineer in 1980 and Division Geological Engineer in
the later part of 1980. Mr. Mueller relocated to San Antonio, Texas in 1985
where he maintained the title of Division Geological Engineer at Tenneco Oil but
had the responsibility of reorganizing and then supervising an 18 member
geological engineering group. Mr. Mueller was then promoted to Division
Exploration Manager in 1987. In 1988, Mr. Mueller joined Fina Oil in Houston,
Texas as Exploration Manager of South Louisiana, and in 1992 he joined American
Exploration in Houston, Texas as Exploitation Vice President. He was with
American Exploration until October of 1996 when he joined the Company. Mr.
Mueller has over 21 years experience in exploring for and exploiting oil and gas
fields both onshore and offshore and an expertise in 3-D seismic, mapping, log
analysis and risk management. He holds a BS in Geological Engineering from the
Colorado School of Mines (1975).

Mel Fife, Vice President -- Business Development of the Company. Mr. Fife
began his career in 1979 as an Independent Landman working for various
companies. Mr. Fife joined Union Pacific Resources Company in 1988 and served as
a Landman until 1994. He joined the Company in November 1995 as Land Manager and
was promoted to Vice President -- Land in January 1997. Mr. Fife has 18 years of
extensive experience in all phases of land in the oil and gas industry. Mr. Fife
is a graduate of Dallas Christian College (1979) from which he received a
Bachelor of Science Degree and attended Emory University's Divinity Program
(1978-1979).

Gary Hampton, Vice President -- Exploration -- Eastern Region of the
Company. Mr. Hampton began his career in 1978 as a Reservoir Geologist for Texas
Eastern (now PanEnergy). Mr. Hampton joined Champlin (currently UPR) in 1980 as
a geologist and remained there until 1984. Mr. Hampton spent the next two years
with Clayton Williams Energy generating prospects and developing acreage plays.
In 1986, he became an independent consultant geologist providing geological
assessments to the energy and environmental industry. Mr. Hampton rejoined
Clayton Williams Energy in 1989 as the geologist responsible for, among other
programs, geological planning associated with the company's Austin Chalk
development program resulting in over

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100 horizontal wells drilled in the Austin Chalk, Buda and Georgetown
formations. Mr. Hampton was named Exploration Manager at Clayton Williams where
he remained until February 1995, at which time he joined the Company as
Manager -- Geology. Mr. Hampton was promoted to Vice President -- Exploration in
January 1996 and renamed Vice President -- Exploration -- Eastern Division in
October 1996. He received a B.S. in Geology from the University of Southern
Mississippi in 1978.

M. Bradford Moody, Vice President -- Legal and Land. Mr. Moody began his
career in 1983 as an Associate with Akin, Gump, Strauss, Hauer & Feld in
Washington D.C., specializing in energy law. In 1988, he joined Pennzoil Company
as an Attorney, and later Senior Attorney, specializing in oil and gas law. He
remained at Pennzoil Company until 1996, at which time he joined the Company as
Senior Attorney. In August 1997, Mr. Moody was named Vice President -- Legal and
Land of the Company. Mr. Moody received his undergraduate degree from Rice
University (B.A. Economics 1980) and also attended Richmond College in London,
England (1978-79). He received his law degree from the University of Texas
School of Law (J.D. 1983).

George A. Sheffer, Vice President -- Operations of the Company. Mr. Sheffer
began his career in 1974 at Chevron USA where he served in the capacities of
Reservoir Engineer, Drilling Representative and Production Engineer. Mr. Sheffer
went on to serve in various engineering management positions with Meridian Oil
and its predecessor Southland Royalty Company from 1979 to 1992. He joined the
Company as Senior Petroleum Engineer in May 1994 after spending two years at
Mearsk Energy, Inc. as Drilling Manager. He was promoted to Vice
President -- Operations at the Company in November 1994. Mr. Sheffer has more
than 20 years of diverse experience in all phases of petroleum engineering and
operations management in the domestic oil and gas industry. Mr. Sheffer has
specialized in horizontal drilling since 1987 in Oklahoma and Texas. He has
extensive experience in the entire Austin Chalk Trend from South Texas to the
Louisiana Border. Mr. Sheffer is a graduate of Pennsylvania State University
(1974) from which he received a degree in Petroleum and Natural Gas Engineering.

Jarl P. Johnson, Vice Chairman and Chief Operating Officer of Coda, has
been active in the oil and natural gas industry since 1953. Mr. Johnson worked
for Phillips Petroleum from 1953 to 1955, and for Kewanee Oil Co. from 1955 to
1978 where he served as Manager of Engineering for 14 years. He worked for
Hamilton Brothers Oil Company from 1978 to 1980 as Vice President of
Engineering. From 1980 to 1986 he was Vice President of Operations for Ensource
Inc. Mr. Johnson formed his own company, PetroJarl, Inc. in 1986 to own
non-operated oil and gas interests. He became President and a director of
Diamond Energy Operating Company ("Diamond") in October 1989. Mr. Johnson joined
Coda as Vice Chairman in 1994 in connection with Coda's acquisition of Diamond
and became Chief Operating Officer of Coda upon consummation of the merger with
JEDI in February 1996. Mr. Johnson obtained a degree in Petroleum Engineering
from the University of Tulsa in 1953.

Grant W. Henderson, President and Chief Financial Officer of Coda, joined
Coda in October 1993 as Executive Vice President and Chief Financial Officer. He
was elected a director of Coda in 1995 and became President of Coda upon
consummation of the merger with JEDI in February 1996. Mr. Henderson was
previously employed by NationsBank, beginning 1981, last serving as Senior Vice
President in its Energy Banking Group. Mr. Henderson is a graduate of Texas Tech
University where he received a B.B.A. degree with a major in finance.

Graham Allison, Director of the Company. Dr. Allison is the Douglas Dillon
Professor of Government at Harvard University. Until March 1994, he served as
Assistant Secretary of Defense for Policy and Plans and continues to serve as
Special Advisor to the Secretary of Defense. From 1977 to 1989, Dr. Allison was
Dean of Harvard's John F. Kennedy School of Government. He was a founding member
of the Trilateral Commission and a Director of the Council on Foreign Relations.
He also formerly served as a Director of the Getty Oil Company, New England
Securities and the Taubman Companies.

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Daniel C. Arnold, Director of the Company. Mr. Arnold practiced law with
the firm of Vinson & Elkins L.L.P. in Houston, Texas from 1953 until 1983. From
January 1983 through April 1988, Mr. Arnold served as a Director, and as
President and later Chairman of First City Bancorporation of Texas, Inc. Mr.
Arnold held a number of positions, including serving as Chairman of the Board
and Chief Executive Officer of Farm & Home Financial Corporation and its wholly
owned subsidiary, Farm and Home Savings Association from February 1989 to April
1991. Currently, Mr. Arnold serves as Director of the Parkway Company and U.S.
Physical Therapy, Inc. and is engaged primarily in managing personal
investments.

Alan D. Berlin, Director of the Company. Mr. Berlin is a partner in the law
firm of Aitken Irvin Lewin Berlin Vrooman & Cohn, LLP where he specializes in
international energy matters, taxation and corporate law. For over five years
prior to joining the firm in 1995, he was engaged in the private practice of
law. Mr. Berlin was a special consultant to the United Nations Department of
Technical Cooperation for Development and the Center for Transnational
Corporations (1989-1994). Mr. Berlin has been appointed an Honorary Associate of
the Centre for Petroleum and Mineral Law and Policy at the University of Dundee,
Scotland, and is a member of the Association of International Petroleum
Negotiators. Mr. Berlin was employed in various positions with BPC from 1977 to
1985 with his last position being President of BPC Peru.

Jack Saltz, Director of the Company. Mr. Saltz is a private investor in oil
and gas, real estate development and other industries. He is President of OTS
Corp., a real estate development company and Chairman of Crown Funding Corp., a
mortgage brokerage firm. He is also President of Highpro Corp., a firm that
invests in oil and gas exploration projects. Mr. Saltz was a major stockholder
of BPC and served BPC in many capacities including Director and Senior Vice
President.

Georgiana Sheldon-Sharp, Director of the Company. Ms. Sheldon-Sharp has
over 30 years of experience in the executive and legislative branches of the
federal government, as well as politics and private business. Her areas of
expertise include defense, foreign affairs and fossil and nuclear energy. She
served as Acting Chairman and Commissioner of the FERC from 1977 to 1985 and
served on the Board of Directors of Enron from 1985 to 1993. Ms. Sheldon-Sharp
currently serves on the Board of Trustees of Keuka College and the Federal
Woman's Award, Inc. and is a member of the Executive Committee of the United
States Energy Association World Energy Conference.

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DESCRIPTION OF PREFERRED STOCK

GENERAL

The following summary description of the preferred stock of the Company
does not purport to be complete and is qualified in its entirety by reference to
the Company's Articles of Incorporation ("Articles of Incorporation") and the
bylaws of the Company, copies of which are filed as exhibits to the Registration
Statement of which this Prospectus Supplement is a part, and to the Certificate
of Designations for the Preferred Stock ("Certificate of Designations"), which
will be filed by the Company with the Commission as an exhibit to a Current
Report on Form 8-K.

The Board of Directors of the Company has authorized the issuance of a
series of preferred stock consisting of up to 4,370,000 shares. The shares of
the Preferred Stock to be issued in the Offering constitute a single series of
the preferred stock of the Company. The Company may, in the future, issue
additional series of preferred stock. When issued and sold for the consideration
herein contemplated, the Preferred Stock will be duly and validly issued, fully
paid and nonassessable. The holders of the Preferred Stock will have no
preemptive rights with respect to any shares of capital stock of the Company or
any other securities of the Company convertible into or carrying rights or
options to purchase any such shares. The Preferred Stock will not be subject to
any sinking fund or other obligation of the Company to redeem or retire the
Preferred Stock. The Preferred Stock has been approved for listing on the New
York Stock Exchange, subject to official notice of issuance. The registrar,
transfer agent and dividend disbursing agent for the Preferred Stock is The Bank
of New York.

RANKING

The Preferred Stock will rank senior to the Common Stock with respect to
the payment of dividends and upon liquidation, dissolution or winding up of the
Company.

DIVIDENDS

Holders of the Preferred Stock will be entitled to receive, when, as and if
declared by the Board of Directors of the Company, out of the funds of the
Company legally available therefor, annual cash dividends at the rate of $1.625
per share, payable quarterly in arrears on March 15, June 15, September 15 and
December 15 of each year, commencing June 15, 1998, or if such day is not a
business day, the next succeeding business day. Dividends on the Preferred Stock
will begin to accumulate and be cumulative from the date of original issuance,
and will be payable to holders of record as they appear on the stock books of
the Company on such record dates, which shall be not more than 60 days nor less
than 10 days preceding the payment dates, as shall be fixed by the Board of
Directors, provided that holders of shares of Preferred Stock called for
redemption on a redemption date falling between a dividend payment record date
and the dividend payment date shall, in lieu of receiving such dividend on the
dividend payment date fixed therefor, receive such dividend payment together
with all other accumulated and unpaid dividends on the date fixed for redemption
(unless such holders convert such shares in accordance with the Certificate of
Designations). Dividends payable per share of Preferred Stock for each quarterly
dividend period will be computed by dividing the annual dividend amount by four.
The amount of dividends payable for the initial dividend period and for any
period shorter or longer than a full quarterly dividend period will be computed
on the basis of a 360-day year of twelve 30-day months. Holders of the Preferred
Stock will not be entitled to any dividends, whether payable in cash, property
or securities, in excess of the full cumulative dividends, as described above.
No interest, or sum of money in lieu of interest, will be payable in respect of
any accumulated and unpaid dividends.

If dividends are not paid in full, or declared in full and sums set apart
for the payment thereof, upon the Preferred Stock and upon any other capital
stock ranking on a parity as to dividends with the Preferred Stock, all
dividends declared upon shares of Preferred Stock and such other parity

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stock will be declared and paid pro rata so that in all cases the amount of
dividends declared per share on the Preferred Stock and such other parity stock
will bear to each other the same ratio that accrued and unpaid dividends per
share on the shares of Preferred Stock and such other parity stock bear to each
other. Except as set forth above, unless full cumulative dividends on all
outstanding shares of the Preferred Stock have been paid or declared and sums
set aside for the payment thereof, dividends (other than dividends paid in
Common Stock or other stock ranking junior to the Preferred Stock as to
dividends and upon liquidation, dissolution or winding up) may not be declared
or paid or set apart for payment, and other distributions may not be made upon
the Common Stock or on any other stock of the Company ranking junior to the
Preferred Stock as to dividends, or upon liquidation, dissolution or winding up,
nor may any Common Stock or any other stock of the Company ranking junior to or
on a parity with the Preferred Stock as to dividends or upon liquidation,
dissolution or winding up be redeemed, purchased or otherwise acquired for any
consideration by the Company (except by conversion into or exchange for stock of
the Company ranking junior to the Preferred Stock as to dividends and upon
liquidation, dissolution or winding up).

Under Nevada law, the Company may declare and make distributions to its
stockholders, unless (i) the Company would not be able to pay its debts as they
become due in the usual course of business or (ii) the Company's total assets
would be less than the sum of its total liabilities plus the amount that would
be needed, if the Company were to be dissolved at the time of such distribution,
to satisfy the preferential rights upon dissolution of stockholders whose
preferential rights are superior to those receiving such distribution. The
Certificate of Designations will provide that the Company will take all actions
required or permitted under Nevada law to permit the payment of dividends on the
Preferred Stock.

LIQUIDATION RIGHTS

In the event of any liquidation, dissolution or winding up of the Company,
whether voluntary or involuntary, the holders of shares of Preferred Stock will
be entitled to receive out of the assets of the Company available for
distribution to stockholders the liquidation preference of $25.00 per share plus
an amount equal to all dividends (whether or not earned or declared) accumulated
and unpaid to the payment date before any payment or distribution of assets is
made to holders of Common Stock or of any other class of stock of the Company
ranking junior to the Preferred Stock upon liquidation, dissolution or winding
up. If upon any liquidation, dissolution or winding up of the Company, the
amounts payable with respect to the Preferred Stock and any other capital stock
ranking as to any such distribution on a parity with the Preferred Stock are not
paid in full, the holders of the Preferred Stock and of such other parity stock
will share ratably in any such distribution of assets in proportion to the full
respective preferential amounts to which they are entitled. After payment of the
full amount of the liquidation preference to which they are entitled, the
holders of shares of Preferred Stock will not be entitled to any further
participation in any distribution of assets by the Company. Neither a
consolidation or merger of the Company with another corporation nor a sale,
lease, exchange or transfer of all or part of the Company's assets for cash,
securities or other property will be considered a liquidation, dissolution or
winding up of the Company for these purposes.

The liquidation preference amount relating to the Preferred Stock is not
necessarily indicative of the price at which the Preferred Stock will actually
trade at or after the time of their issuance, and the Preferred Stock may trade
at prices below its liquidation preference amount. The market price of the
Preferred Stock can be expected to fluctuate with changes in the financial
markets and economic conditions, the financial condition and prospects of the
Company and other factors that generally influence the market prices of
securities.

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CONVERSION RIGHTS

Shares of the Preferred Stock will be convertible at any time at the option
of the holder thereof at an initial conversion price of $22.14 per share of
Common Stock (equivalent to a conversion rate of 1.1292 shares of Common Stock
for each share of Preferred Stock), subject to adjustment as described below,
except that, if shares of Preferred Stock are called for redemption, the
conversion right will terminate at the close of business on the date fixed for
redemption. No fractional shares or securities representing fractional shares of
Common Stock will be issued upon conversion; any fractional shares resulting
from conversion will be paid in cash based upon the last reported sales price of
the Common Stock at the close of business on the first trading day preceding the
date of conversion.

In case the Company shall be a party to any transaction (including, without
limitation, a merger, consolidation, statutory share exchange, sale of all or
substantially all of its assets or recapitalization of the Common Stock), in
each case as a result of which shares of Common Stock shall be converted into
the right to receive stock, securities or other property (including cash or any
combination thereof), each share of Preferred Stock remaining outstanding
following such transaction shall thereafter be convertible into the kind and
amount of shares of stock and other securities and property receivable
(including cash) upon the consummation of such transaction by a holder of that
number of shares or fraction thereof of Common Stock into which such share of
Preferred Stock was convertible immediately prior to such transaction.

The conversion price is subject to adjustment upon certain events,
including: (i) the issuance of Common Stock as a dividend or distribution with
respect to the outstanding Common Stock, subdivisions, splits or combinations of
Common Stock, or the issuance of any shares of capital stock by reclassification
of the Common Stock; (ii) the issuance to all holders of Common Stock of rights
or warrants to subscribe for or purchase Common Stock, in each case at less than
the then current market price per share of Common Stock; and (iii) the payment
of a dividend or making of a distribution to holders of Common Stock of shares
of capital stock of the Company or its subsidiaries (other than Common Stock) or
of evidences of its indebtedness, or of assets, including securities, but
excluding those rights, warrants, dividends and distributions referred to above,
dividends and distributions in connection with the liquidation, dissolution or
winding up of the Company and regular periodic cash dividends payable out of
surplus. Whenever the conversion price is adjusted for any of the events
described above, the Company shall prepare a notice of such adjustment of the
conversion price, setting forth the adjusted conversion price and the effective
date of such adjustment and shall mail such notice of such adjustment of the
conversion price, to the record holders of the shares of Preferred Stock at such
holders' last address as shown on the stock records of the Company.

No adjustment in the conversion price will be required to be made in any
case until cumulative adjustments amount to 1% or more of the conversion price
as last adjusted, but any such adjustment that would otherwise be required to be
made shall be carried forward and taken into account in any subsequent
adjustment. The Company reserves the right, to the extent permitted by law, to
make such reductions in the conversion price in addition to those required in
the foregoing provisions as it, in its sole discretion, shall determine to be
advisable in order that certain stock-related distributions hereafter made by
the Company to its stockholders shall not be taxable to such stockholders.

Holders of shares of Preferred Stock at the close of business on a dividend
payment record date shall be entitled to receive the dividend payable on such
shares on the corresponding dividend payment date (except that holders of shares
called for redemption on a redemption date falling between such dividend payment
record date and the dividend payment date shall, in lieu of receiving such
dividend on the dividend payment date fixed therefor, receive such dividend
payment together with all other accrued and unpaid dividends on the date fixed
for redemption, unless such holders convert such shares in accordance with the
Certificate of Designations) notwithstanding the

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conversion thereof following such dividend payment record date and prior to such
dividend payment date. However, shares of Preferred Stock surrendered for
conversion during the period between the close of business on any dividend
payment record date and the opening of business on the corresponding dividend
payment date (except shares of Preferred Stock called for redemption on a
redemption date during such period) must be accompanied by payment of an amount
equal to the dividend payment with respect to such shares of Preferred Stock
presented for conversion on such dividend payment date. A holder of shares of
Preferred Stock on a dividend payment record date who (or whose transferee)
surrenders any such shares for conversion into shares of Common Stock on the
corresponding dividend payment date will receive the dividend payable by the
Company on such shares of Preferred Stock on such date, and the converting
holder need not include payment in the amount of such dividend upon surrender of
shares of Preferred Stock for conversion on the dividend payment date. Except as
provided above, the Company shall make no payment or allowance for unpaid
dividends, whether or not in arrears, on converted shares of Preferred Stock or
for dividends on the shares of Common Stock issued upon such conversion.

If (i) the Company shall declare a dividend (or any other distribution) on
the Common Stock (other than regular periodic cash dividends payable out of
surplus); (ii) the Company shall authorize the granting to all holders of the
Common Stock of rights or warrants to subscribe for or purchase any shares of
any class or any other rights or warrants, (iii) there shall be any
reclassification of the Common Stock or any consolidation or merger to which the
Company is a party and for which approval of any stockholders of the Company is
required, or a statutory share exchange, or self tender offer by the Company for
all or substantially all of its outstanding shares of Common Stock or the sale
or transfer of all or substantially all of the assets of the Company as an
entity; or (iv) there shall occur the involuntary or voluntary liquidation,
dissolution or winding up of the Company, then the Company shall cause to be
mailed to the holders of shares of Preferred Stock, at the address as shown on
the stock records of the Company, as promptly as possible, but at least 15
business days prior to the applicable date hereinafter specified, a notice
stating (A) the date on which a record is to be taken for the purpose of such
dividend, distribution or granting of rights or warrants, or, if a record is not
to be taken, the date as of which the holders of Common Stock of record to be
entitled to such dividends, distribution or rights or warrants are to be
determined or (B) the date on which such reclassification, consolidation,
merger, statutory share exchange, sale, transfer, liquidation, dissolution or
winding up is expected to become effective, and the date as of which it is
expected that holders of Common Stock shall be entitled to exchange their shares
of Common Stock for securities or other property, if any, deliverable upon such
reclassification, consolidation, merger, statutory share exchange, sale,
transfer, liquidation, dissolution or winding up.

The Company will endeavor to comply with all federal and state securities
laws regulating the offer and delivery of shares of Common Stock upon conversion
of the Preferred Stock and will endeavor to have approved for listing on any
national securities exchange upon which its Common Stock is listed the shares of
Common Stock deliverable upon conversion of the Preferred Stock. The Company
will reserve and keep available from its authorized capital stock a sufficient
number of shares of Common Stock as may be required to effect conversion of the
Preferred Stock. The Company will pay any and all documentary stamp or similar
issue or transfer taxes payable in respect of the issue or delivery of shares of
Common Stock or other securities or property on conversion of the Preferred
Stock pursuant hereto; provided, however, that the Company shall not be required
to pay any tax that may be payable in respect of any transfer involved in the
issue or delivery of shares of Common Stock or other securities or property in a
name other than that of the holder of the shares of Preferred Stock to be
converted, and no such issue or delivery shall be made unless and until the
person requesting such issue or delivery has paid to the Company the amount of
any such tax or established, to the reasonable satisfaction of the Company, that
such tax has been paid.

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In addition, the Credit Agreement, the 8 7/8% Indenture and the Coda
Indenture contain restrictions on the ability of the Company to pay dividends on
the Preferred Stock. Any future credit agreements or other agreements relating
to indebtedness to which the Company becomes a party may contain similar
restrictions and provisions. See "Risk Factors -- Restrictions Upon Ability to
Pay Dividends."

Change of Control. Notwithstanding the foregoing, until March 10, 2001,
upon a Change of Control (as defined below) that is not a Common Stock
Transaction (as defined below), holders of Preferred Stock shall, if the Market
Value (as defined below) of the Common Stock at such time is less than the
conversion price, have an option for a period of 30 days after the mailing by
the Company to the holders of Preferred Stock of a notice that a Change of
Control has occurred, to convert all of their outstanding shares of Preferred
Stock into shares of Common Stock at an adjusted conversion price equal to the
greater of (i) the Market Value of the Common Stock as of the date of the Change
of Control and (ii) $12.00. The adjusted conversion price will be applicable
only with respect to the first Change of Control that occurs after the issuance
of the Preferred Stock in the Offering. The Company will be required to mail a
notice, within 30 days following the occurrence of a Change of Control,
specifying certain information regarding the Change of Control and the manner in
which shares of Preferred Stock may be converted at the adjusted conversion
price. In lieu of issuing the shares of Common Stock issuable upon conversion in
the event of a Change of Control, the Company may, at its option, make a cash
payment equal to the Market Value of such Common Stock otherwise issuable upon
conversion based on the adjusted conversion price.

"Change of Control" means any of the following events:

(i) the sale, lease, transfer, conveyance or other disposition (other
than by way of merger or consolidation), in one or a series of related
transactions, of all or substantially all of the assets of the Company and
its subsidiaries taken as a whole to any "person" or group of related
persons (a "Group") (as such term is used in Sections 13(d) and 14(d) of
the Exchange Act);

(ii) the consummation of any transaction (including, without
limitation, any purchase, sale, acquisition, disposition, merger or
consolidation) the result of which is that any "person" or Group, other
than one or more Permitted Holders (as defined below), becomes the
"beneficial owner" (as such term is defined in Rule 13d-3 and Rule 13d-5
under the Exchange Act) of more than 50% of the aggregate voting power of
all classes of capital stock of the Company having the right to elect
directors under ordinary circumstances;

(iii) the adoption of a plan relating to the liquidation or
dissolution of the Company; or

(iv) during any period of two consecutive years, individuals who at
the beginning of such period constituted the Board of Directors (together
with any new directors whose elections by such Board of Directors or whose
nomination for election by the shareholders of the Company was approved by
a vote of a majority of the directors of the Company then still in office
who were either directors at the beginning of such period or whose election
or nomination for election was previously so approved) cease for any reason
to constitute a majority of the Board of Directors then in office.

"Common Stock Transaction" means any transaction in which more than 50% of
the value (as determined in good faith by the Board of Directors of the Company)
of the consideration received by holders of the Company's Common Stock consists
of common stock that for each of the ten consecutive trading days prior to the
effective date of the transaction has been admitted for listing or admitted for
listing subject to notice of issuance on a national securities exchange or
quoted on the Nasdaq National Market.

"Market Value" of the Common Stock for any day means the last reported sale
price, regular way, on such day, or, if no sale takes place on such day, the
average of the reported closing bid and
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asked prices on such day, regular way, in either case as reported on the New
York Stock Exchange Consolidated Transactions Tape, or, if the Company's Common
Stock is not listed or admitted to trading on the New York Stock Exchange on
such day, on the principal national securities exchange on which the Company's
Common Stock is listed or admitted to trading, if the Company's Common Stock is
listed on a national securities exchange, or the Nasdaq National Market, or, if
the Company's Common Stock is not quoted or admitted to trading on such
quotation system, on the principal quotation system on which the Company's
Common Stock may be listed or admitted to trading or quoted, or, if not listed
or admitted to trading or quoted on any national securities exchange or
quotation system, the average of the closing bid and asked prices of the
Company's Common Stock in the over-the-counter market on the day in question as
reported by the National Quotation Bureau Incorporated, or a similar generally
accepted reporting service, or, if not so available in such manner, as furnished
by any New York Stock Exchange member firm selected from time to time by the
Board of Directors of the Company for that purpose or, if not so available in
such manner, as otherwise determined in good faith by the Board of Directors of
the Company.

"Permitted Holders" means (1) Robert A. Belfer, Renee E. Belfer, Laurence
D. Belfer and Jack Saltz, (2) the spouses and descendants of such individuals,
(3) the estates or legal representatives of the individuals named in clauses (1)
and (2), and (4) trusts created for the benefit of persons named in clauses (1)
and (2).

The phrase "all or substantially all" of the assets of the Company is
likely to be interpreted by reference to applicable state law at the relevant
time, and will be dependent on the facts and circumstances existing at such
time. As a result, there may be a degree of uncertainty in ascertaining whether
a sale or transfer is of "all of substantially all" of the assets of the
Company.

COMPANY'S RIGHT OF REDEMPTION

Shares of the Preferred Stock will not be redeemable prior to March 15,
2001. The shares of Preferred Stock will be redeemable at the option of the
Company, in whole or in part, at any time or from time to time, out of funds
legally available therefor, on or after March 15, 2001, on not less than 30 nor
more than 60 days' notice by first-class mail at the redemption prices per share
of Preferred Stock set forth below during the 12-month periods beginning on
March 15 of the years shown below, plus in each case an amount equal to accrued
and unpaid dividends, if any, to (and including) the redemption date, whether or
not earned or declared (the "Redemption Price").

<TABLE>
<CAPTION>
YEAR PRICE PER SHARE
---- ---------------
<S> <C>
2001................................................... $26.1375
2002................................................... $25.9750
2003................................................... $25.8125
2004................................................... $25.6500
2005................................................... $25.4875
2006................................................... $25.3250
2007................................................... $25.1625
2008 and thereafter.................................... $25.0000
</TABLE>

If fewer than all of the outstanding shares of Preferred Stock are to be
redeemed, the shares to be redeemed shall be selected pro rata. There is no
mandatory redemption or sinking fund obligation with respect to the Preferred
Stock. In the event that the Company has failed to pay accrued and unpaid
dividends on the Preferred Stock, it may not redeem less than all of the then
outstanding shares of the Preferred Stock until all such accrued and unpaid
dividends and the then current quarterly dividends have been paid in full. After
the date fixed for redemption, unless the Company is in default in providing
money for the payment of the Redemption Price, dividends shall cease to accrue
on the Preferred Stock called for redemption, such shares shall no longer be
deemed to be outstanding and all rights of the holders of such shares as
stockholders of the

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Company shall cease, except the right to receive the moneys payable upon such
redemption, without interest thereon, upon surrender of the certificates
evidencing such shares.

The Company will not be prohibited from purchasing the Preferred Stock in
the open market or in negotiated transactions except as provided under
"-- Dividends" above.

VOTING RIGHTS

The holders of the Preferred Stock will have no voting rights, except as
described below, as described in the accompanying Prospectus or as required by
law. In exercising any such vote, each outstanding share of Preferred Stock will
be entitled to one vote, excluding shares held by the Company or any entity
controlled by the Company, which shares shall have no voting rights.

Whenever dividends on the Preferred Stock have not been paid in an
aggregate amount equal to at least six quarterly dividends on such shares
(whether or not consecutive), the holders of the Preferred Stock (voting
separately as a class with the holders of any stock ranking on a parity as to
dividends with the Preferred Stock on which like voting rights have been
conferred and are exercisable) will be entitled to elect two directors to the
Board of Directors either by written consent or at an annual or special meeting
of stockholders of the Company held during the period such dividends remain in
arrears. Such voting rights will terminate when all such dividends accrued and
in default have been paid in full or declared and funds set apart for payment in
full. The term of office of all directors so elected will terminate immediately
upon such payment or setting apart for payment.

In addition to the voting rights described in the Prospectus, the
affirmative vote or consent of the holders of at least two-thirds of the
outstanding shares of any series of Preferred Stock, voting as a separate class,
will be required for any amendment, alteration or repeal, whether by merger,
consolidation or otherwise, of the Articles of Incorporation that will (i)
increase or decrease the aggregate number of authorized shares of such series or
of Preferred Stock, (ii) increase or decrease the par value of the Preferred
Stock, (iii) effect an exchange, reclassification or cancellation of all or part
of the shares of such series or of the Preferred Stock, (iv) effect an exchange,
or create a right of exchange, of all or any part of the shares of another class
into the shares of such series or of Preferred Stock, (v) change the
designations, preferences, limitations or relative rights of the shares of such
series or the Preferred Stock, (vi) change the shares of such series or the
Preferred Stock into the same or a different number of shares of the same class
or series or another class or series, (vii) create a new class or series of
shares having rights and preferences equal, prior or superior to the shares of
such series or the Preferred Stock, or increase the rights and preferences of
any class or series having rights and preferences equal, prior or superior to
the shares of such series or the Preferred Stock, or increase the rights and
preferences of any class or series having rights or preferences later or
inferior to the shares of such series or the Preferred Stock in such a manner as
to become equal, prior or superior to the shares of such class or series, (viii)
divide the shares of Preferred Stock into series and fix and determine the
designation of such series and the variations in the relative rights and
preferences between the shares of such series, (ix) limit or deny the existing
preemptive rights of the shares of such series or of the Preferred Stock, or (x)
cancel or otherwise affect dividends on the shares of such series or the
Preferred Stock that had accrued but had not been declared. The foregoing
provisions are not applicable to the designation of any series by the Board of
Directors in the manner described under the heading "Description of Capital
Stock -- Preferred Stock -- General" in the Prospectus.

S-64
<PAGE> 65

CERTAIN FEDERAL INCOME TAX CONSIDERATIONS

The following is a summary of certain federal income tax consequences of
acquiring, owning and disposing of the Preferred Stock. This summary does not
purport to be complete and does not address the tax consequences to holders that
are subject to special tax rules, such as financial institutions, insurance
companies, regulated investment companies, personal holding companies,
corporations subject to the alternative minimum tax, S corporations, foreign
investors, broker-dealers and tax-exempt entities. This summary does not address
any tax consequences arising under the laws of any state, locality or foreign
jurisdiction. This summary is based on the Internal Revenue Code of 1986, as
amended (the "Code"), Treasury regulations and proposed regulations, court
decisions and current administrative rulings and pronouncements of the Internal
Revenue Service ("IRS"), all of which are subject to change, possibly with
retroactive effect, and assumes that Preferred Stock will be held as a "capital
asset" (generally, property held for investment) as defined in the Code.
PROSPECTIVE PURCHASERS ARE ADVISED TO CONSULT THEIR OWN TAX ADVISORS REGARDING
THE APPLICATION OF U.S. FEDERAL INCOME TAX LAWS, AS WELL AS THE LAWS OF ANY
STATE, LOCAL OR FOREIGN TAXING JURISDICTION, TO THEIR SITUATIONS.

DIVIDENDS ON PREFERRED STOCK

Distributions with respect to the Preferred Stock will constitute
"dividends" for federal income tax purposes to the extent that the Company has
current or accumulated earnings and profits for federal income tax purposes.
Distributions paid to corporations may qualify for the dividends received
deduction under section 243 of the Code, subject to the limitations discussed
below. To the extent, if any, that a holder receives a distribution with respect
to Preferred Stock that would otherwise constitute dividends for federal income
tax purposes but that exceeds the holder's allocable share of the Company's
current and accumulated earnings and profits, the excess will be treated as a
nontaxable return of capital which will reduce the stockholder's tax basis in
the Preferred Stock; any amount in excess of the holder's basis will be treated
as capital gain. A reduction in tax basis could result in increased capital gain
upon a sale or other disposition of the Preferred Stock.

Dividends on the Preferred Stock received by corporate holders will be
eligible for the 70% dividends-received deduction under section 243 of the Code,
subject to limitations generally applicable to the dividends-received
deductions, including those contained in sections 246 and 246A of the Code and
the corporate alternative minimum tax. Prospective corporate purchasers of
Preferred Stock should consult their own tax advisors to determine whether these
limitations might apply to them.

EXTRAORDINARY DIVIDENDS

If a corporate holder receives an "extraordinary dividend" from the Company
with respect to Preferred Stock which it has not held for more than two years
before the dividend announcement date, the holder's basis in the Preferred Stock
will be reduced (but not below zero) by the portion of the dividend which is
deductible by reason of the dividends received deduction. The reduction in basis
of Preferred Stock is treated as occurring at the beginning of the ex-dividend
date of the extraordinary dividend to which the reduction relates. If, because
of the limitation on reducing basis below zero, any portion of an extraordinary
dividend that is deductible by reason of the dividends received deduction has
not been applied to reduce basis, such amount will be treated as gain from the
sale or exchange of stock for the taxable year in which the extraordinary
dividend is received. An "extraordinary dividend" on the Preferred Stock would
include a dividend that (i) equals or exceeds 5% of the holder's adjusted tax
basis in the stock, treating all dividends having ex-dividend dates within an
85-day period as one dividend or (ii) exceeds 20% of the holder's adjusted tax
basis (determined without regard to any reduction for the non-taxed portion of
prior extraordinary

S-65
<PAGE> 66

dividends) in the stock, treating all dividends having ex-dividend dates within
a 365-day period as one dividend. A holder may elect to use the fair market
value of the stock as of the day before the ex-dividend date rather than its
adjusted basis for purposes of applying the 5% or 20% limitation if the holder
is able to establish such fair market value to the satisfaction of the IRS. An
"extraordinary dividend" would also include any amount treated as a dividend in
the case of a redemption of the Preferred Stock that (i) is non-pro rata as to
all stockholders or (ii) was treated as a dividend because the holding of
options was treated as stock ownership under the constructive stock ownership
rules of Section 318 of the Code, without regard to the period the holder held
the stock.

Special rules apply with respect to a "qualified preferred dividend," which
would include any fixed dividend payable no less often than annually with
respect to the Preferred Stock provided the Preferred Stock is not in arrears as
to dividends when acquired and the actual rate of return on the Preferred Stock
does not exceed 15% calculated by reference to the lower of the stockholder's
basis in the Preferred Stock or its liquidation preference. The extraordinary
dividend rules will not apply to a qualified preferred dividend if the
stockholder has held the Preferred Stock for more than five years. If the
stockholder disposes of the Preferred Stock before it has been held for more
than five years, the aggregate reduction in basis will not exceed the excess of
the qualified preferred dividends paid during the period held by the stockholder
over the qualified preferred dividends which would have been paid during such
period on the basis of a stated rate of return as determined under section
1059(e)(3) of the Code.

The length of time that a stockholder is deemed to have held Preferred
Stock for purposes of the extraordinary dividend rules is determined under
principles similar to those applicable for purposes of the dividends received
deduction discussed above.

CONVERSION OF PREFERRED STOCK INTO COMMON STOCK

No gain or loss generally will be recognized upon conversion of shares of
Preferred Stock into shares of Common Stock, except with respect to any cash
paid in lieu of fractional shares of Common Stock. The holder's tax basis in the
Common Stock received upon conversion will be equal to the holder's tax basis in
the shares of Preferred Stock converted. The holding period of the Common Stock
will include the holding period of the shares of Preferred Stock converted.

ADJUSTMENT OF CONVERSION PRICE

Holders of Preferred Stock may be deemed to have received a constructive
distribution of stock that is taxable as a dividend where the conversion ratio
of the Preferred Stock is adjusted unless the change in conversion ratio is made
pursuant to a bona fide, reasonable adjustment formula which has the effect of
preventing the dilution of the interest of the holders. Adjustments to
compensate for taxable distributions of cash or property to other stockholders
are not considered as made pursuant to a bona fide adjustment formula. The
adjustment to the Conversion Price that occurs as a result of a Change of
Control will not qualify as being pursuant to a bona fide reasonable adjustment
formula. In addition, certain of the other possible adjustments provided with
respect to the Preferred Stock may not qualify as being pursuant to a bona fide
reasonable adjustment formula. If a nonqualifying adjustment were made, the
holders of Preferred Stock could be deemed to have received a taxable stock
dividend.

REDEMPTION OR OTHER DISPOSITION OF STOCK

In the event the Company exercises its right to redeem the Preferred Stock,
the redemption proceeds will generally be treated as a sale or exchange if the
holder does not own, actually or constructively, within the meaning of section
318 of the Code, any stock of the Company other than the stock redeemed. If a
holder does own, actually or constructively, such other stock, a redemption of
stock may be treated as a dividend to the extent of the Company's current or
accumulated earnings and profits (as determined for federal income tax
purposes). Such dividend treatment

S-66
<PAGE> 67

would not apply and the redemption would be treated as a sale or exchange if the
redemption is "substantially disproportionate" with respect to the holder under
section 302(b)(2) of the Code or is "not essentially equivalent to a dividend"
with respect to the holder under section 302(b)(1) of the Code. A distribution
to a holder will be "not essentially equivalent to a dividend" if it results in
a "meaningful reduction" in the holder's stock interest in the Company. A
redemption of stock for cash that results in a reduction in the proportionate
interest in the Company (taking into account any constructive ownership) of a
holder whose relative stock interest in the Company is minimal and who exercises
no control over corporate affairs may be regarded as a "meaningful reduction" in
the holder's stock interest in the Company. In all cases, amounts of cash
received upon redemption of the Preferred Stock which represents declared and
unpaid dividends will be subject to taxation in the manner discussed under
"-- Dividends on Preferred Stock" above.

If a redemption of stock is treated as a distribution that is taxable as a
dividend, the amount of the distribution will be measured by the amount received
by the holder. The holder's adjusted tax basis in the redeemed stock will be
transferred to his remaining stock holdings in the Company. If the holder does
not retain any stock ownership in the Company, the holder may lose such basis
entirely.

Upon a redemption of stock that is not treated as a distribution taxable as
a dividend or upon a sale or other disposition of stock, the holder will
recognize capital gain or loss equal to the difference between the amount of
cash and the fair market value of property received and the holder's adjusted
tax basis in the stock that is redeemed, sold or disposed of. Such gain or loss
would be long-term capital gain or loss if the holding period for the stock
exceeded one year. For corporate taxpayers, long-term capital gains are taxed at
the same rate as ordinary income. For individual taxpayers, net capital gains
(the excess of the taxpayer's net long-term capital gains over his net
short-term capital losses) are subject to a maximum tax rate of (i) 28%, if such
stock was held for more than one year but not more than 18 months or (ii) 20%,
if such stock was held for more than 18 months. The deductibility of capital
losses are restricted and, in general, may only be used to reduce capital gains
to the extent thereof. However, individual taxpayers generally may deduct
annually $3,000 of capital losses in excess of their capital gains. Capital
losses which cannot be utilized because of the aforementioned limitation are,
for corporate taxpayers carried back three years and, in most circumstances,
carried forward for five years; for individual taxpayers, capital losses may
only be carried forward without a time limitation.

PROPOSED LEGISLATION

The President has previously proposed legislation which would reduce the
70% dividends-received deduction to 50%. Although such legislation was not
enacted as part of the recently enacted Taxpayer Relief Act of 1997, it cannot
be predicted with certainty whether in the future such proposal will be enacted
into law or, if enacted, what would be its effective date. Corporate holders of
stock are urged to consult their own tax advisors regarding the possible effects
of such proposed legislation.

BACKUP WITHHOLDING

Under the backup withholding provisions of the Code and applicable Treasury
regulations, a holder of Preferred Stock may be subject to backup withholding at
the rate of 31% with respect to dividends on, or the proceeds of a sale,
conversion or redemption of, the Preferred Stock, unless such holder (i) is a
corporation or comes within certain other exempt categories and, when required,
demonstrates this fact or (ii) provides a taxpayer identification number,
certifies as to no loss of exemption from backup withholding and otherwise
complies with applicable requirements of the backup withholding rules. Any
amount withheld from a payment to a holder under the backup withholding rules is
allowable as a refund or as a credit against such holder's federal income tax
liability, provided that the required information is furnished to the IRS.

S-67
<PAGE> 68

THE FOREGOING SUMMARY IS INCLUDED FOR GENERAL INFORMATION ONLY.
ACCORDINGLY, EACH STOCKHOLDER IS URGED TO CONSULT WITH HIS OR HER OWN TAX
ADVISOR WITH RESPECT TO THE TAX CONSEQUENCES OF THE HOLDING AND DISPOSING OF
PREFERRED STOCK, INCLUDING THE APPLICATION AND EFFECT OF THE LAWS OF ANY STATE,
LOCAL, FOREIGN OR OTHER TAXING JURISDICTION.

LEGAL MATTERS

Certain legal matters in connection with the shares of Common Stock offered
hereby are being passed upon for the Company by Vinson & Elkins L.L.P., Houston,
Texas, and for the Underwriters by Andrews & Kurth L.L.P., Houston, Texas.
Certain maters of Nevada law will be passed upon by Woodburn & Wedge, Reno,
Nevada. Vinson & Elkins L.L.P. and Andrews & Kurth L.L.P. will rely upon the
opinion of Woodburn & Wedge as to matters of Nevada law.

EXPERTS

The consolidated financial statements of the Company and subsidiaries as of
December 31, 1995 and 1996, and for each of the three years in the period ended
December 31, 1996, included in this Prospectus Supplement, have been audited by
Arthur Andersen LLP, independent public accountants, as indicated in their
reports with respect thereto, and are included herein in reliance upon the
authority of said firm as experts in accounting and auditing in giving said
reports.

The information included in this Prospectus Supplement regarding proved
reserves as of December 31, 1997 and the related future net revenues and the
present value thereof is derived, as and to the extent described herein, from
the reserve report prepared by Miller and Lents, Ltd., independent oil and gas
consultants, and, to such extent, are included herein in reliance upon the
authority of such firm as experts with respect to such report.

S-68
<PAGE> 69

GLOSSARY OF OIL AND GAS TERMS

The definitions set forth below shall apply to the indicated terms as used
in this Prospectus Supplement. All volumes of natural gas referred to herein are
stated at the legal pressure base of the state or area where the reserves exist
and at 60 degrees Fahrenheit and in most instances are rounded to the nearest
major multiple.

AMI. Area of mutual interest.

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

Bcf. Billion cubic feet.

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

BOE. Barrel of oil equivalent (converting six Mcf of natural gas to one Bbl
of oil).

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.

Completion. The installation of permanent equipment for the production of
oil or natural gas, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.

Developed acreage. The number of acres that are allocated or assignable to
producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.

Exploratory well. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.

Finding costs. Total costs incurred in oil and gas acquisition, exploration
and development activities and capitalized interest divided by total reserve
additions, including purchases of minerals in place, extensions, discoveries,
revisions and other additions.

Gross acres or gross wells. The total acres or wells, as the case may be,
in which a working interest is owned.

Liquids. Crude oil, condensate and natural gas liquids.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

Mcf/d. One thousand cubic feet per day.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMS. Mineral Management Service of the United States Department of the
Interior.

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMbtu. One million Btus.

MMcf. One million cubic feet.

S-69
<PAGE> 70

MMcfe. One million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Net acres or net wells. The sum of the fractional working interests owned
in gross acres or gross wells, as the case may be.

Oil. Crude oil and condensate.

Operating cash inflows per Mcfe. Net operating cash inflows as listed in
the Consolidated Statements of Cash Flows in the Consolidated Financial
Statements divided by net gas equivalent production for the applicable periods.

Present Value or PV10. When used with respect to oil and natural gas
reserves, 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 indicated, without giving effect
to non-property related expenses such as general and administrative expenses,
debt service and future income tax expenses or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%.

Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

Proved developed nonproducing reserves. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.

Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production to market.

Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that 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 location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.

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 well bore in
another formation from that in which the well has been previously completed.

Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.

Royalty interest. An interest in an oil and natural gas property entitling
the owner to a share of oil or natural gas production free of costs of
production.

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 natural gas regardless of whether such acreage contains proved
reserves.

Updip. A higher point in the reservoir.

Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.

Workover. Operations on a producing well to restore or increase production.

S-70
<PAGE> 71

BELCO OIL & GAS CORP. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
Unaudited Pro Forma Consolidated Condensed Financial
Statements................................................ F-2
Unaudited Pro Forma Consolidated Condensed Statements of
Operations for the year ended December 31, 1996........... F-3
Unaudited Pro Forma Consolidated Condensed Statement of
Operations for the nine months ended September 30, 1997... F-4
Unaudited Pro Forma Consolidated Condensed Balance Sheet as
of September 30, 1997..................................... F-5
Notes to Unaudited Pro Forma Consolidated Condensed
Financial Statements...................................... F-7

UNAUDITED INTERIM CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Condensed Consolidated Balance Sheets at September 30, 1997
and December 31, 1996 (Unaudited)......................... F-11
Condensed Consolidated Statements of Operations for the nine
months ended September 30, 1997 and 1996 (Unaudited)...... F-12
Condensed Consolidated Changes in Stockholders' Equity for
the nine months ended September 30, 1997 (Unaudited)...... F-13
Condensed Consolidated Statements of Cash Flows for the nine
months ended September 30, 1997 and 1996 (Unaudited)...... F-14
Notes to Condensed Consolidated Financial Statements........ F-15

CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants.................... F-18
Consolidated Balance Sheets as of December 31, 1996 and
1995...................................................... F-19
Consolidated Statements of Operations for the years ended
December 31, 1996, 1995 and 1994.......................... F-20
Consolidated Statements of Stockholders' Equity for the
years ended December 31, 1996, 1995 and 1994.............. F-21
Consolidated Statements of Cash Flows for the years ended
December 31, 1996, 1995 and 1994.......................... F-22
Notes to Consolidated Financial Statements.................. F-23
</TABLE>

F-1
<PAGE> 72

BELCO OIL & GAS CORP. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED CONDENSED
FINANCIAL STATEMENTS

The following unaudited consolidated condensed financial statements and
related notes are presented to show the pro forma effects of the merger of Coda
Energy, Inc. (Coda) with and into a wholly owned subsidiary of Belco Oil & Gas
Corporation (Belco).

The Coda transaction, hereinafter referred to as the "Merger", was
completed November 26, 1997 and will be reported using the purchase method of
accounting.

The condensed statements of operations are presented to show income from
continuing operations as if the Merger occurred as of the beginning of the
respective periods. The pro forma condensed balance sheet is based on the
assumption that the Merger occurred on September 30, 1997.

Belco accounted for the acquisition of Coda using the purchase method of
accounting for business combinations. In accordance with the Statement of
Financial Accounting Standards Board No. 109 ("FASB 109"), Belco recorded in the
fourth quarter ended December 31, 1997 a one-time non-cash deferred tax
liability of approximately $101 million to reflect the difference between the
tax basis of Coda's assets and liabilities and the amounts recorded for
financial reporting purposes for such assets and liabilities.

Belco recorded in the fourth quarter ended December 31, 1997 a non-cash
ceiling test provision of $150 million ($98 million after tax), which is also
reflected in the Unaudited Pro Forma Statements of Operations as of September
30, 1997. The ceiling test provision includes the effect of the non-cash $101
million FASB 109 "gross up" attributable to the Coda acquisition on Belco's full
cost pool at year-end 1997 and adjustments to the SEC PV10 value of year-end
1997 reserves, which were significantly impacted by lower product prices when
compared to year-end 1996 prices, among other items. The present value of
estimated future net revenues before income taxes of Belco's proved reserves
were $505 million as of December 31, 1997 (exclusive of price risk management
transactions) based on average prices of $17.55 per barrel of oil and $2.20 per
Mcf. This compared to prices of approximately $25.13 per barrel of oil and $3.68
per Mcf used in calculating year-end 1996 proved reserves.

Pro forma data is based on assumptions and include adjustments as explained
in the notes to the unaudited pro forma consolidated condensed financial
statements. The pro forma data is not necessarily indicative of the financial
results that would have occurred had the transactions been effective on and as
of the dates referenced above, and should not be viewed as indicative of
operations in future periods. The unaudited pro forma consolidated condensed
financial statements should be read in conjunction with the notes thereto,
Belco's Annual Report on Form 10-K for the fiscal year ended December 31, 1996,
Belco's Quarterly Reports on Form 10-Q for the quarters ended March 31, 1997,
June 30, 1997 and September 30, 1997, Coda's Annual Report on Form 10-K for the
fiscal year ended December 31, 1996, and Coda's Quarterly Reports on Form 10-Q
for the quarters ended March 31, 1997, June 30, 1997 and September 30, 1997.

F-2
<PAGE> 73

BELCO OIL & GAS CORP. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED CONDENSED
STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1996
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
MERGER
BELCO CODA PRO FORMA
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales.......................... $119,710 $ 76,769 $ -- $196,479
Commodity price risk management
activities.............................. (5,967) -- (5,967)
Gas gathering and processing............... -- 44,875 (44,875)(b) --
Interest and other......................... 2,653 2,307 4,960
-------- -------- --------- --------
Total Revenues..................... 116,396 123,951 (44,875) 195,472
-------- -------- --------- --------
OPERATING EXPENSES
Oil and gas operating expenses............. 7,847 32,167 40,014
Depreciation, depletion and amortization... 40,904 26,614 (3,082)(b) 75,587
11,151(c)
General and administrative................. 3,059 2,398 (786)(f) 4,671
Gas gathering and processing............... -- 37,392 (37,392)(b) --
Interest................................... -- 15,657 13,772(a) 23,551
(4,097)(b)
(9,281)(e)
7,500(h)
Stock option compensation.................. -- 3,199 3,199
Writedown of oil and gas properties........ -- 83,305 (83,305)(g) --
-------- -------- --------- --------
Total Costs and Expenses..................... 51,810 200,732 (105,520) 147,022
-------- -------- --------- --------
INCOME (LOSS) BEFORE INCOME TAXES............ 64,586 (76,781) 60,645 48,450
Provision (benefit) for income taxes......... 21,953 (27,194) (465)(b) 16,554
22,260(d)
-------- -------- --------- --------
PRO FORMA NET INCOME......................... $ 42,633 $(49,587) $ 38,850 $ 31,896
======== ======== ========= ========
BASIC AND DILUTED PRO FORMA NET INCOME PER
COMMON SHARE............................... $ 1.42 $ 1.06
======== ========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING... 29,986 29,986
======== ========
</TABLE>

The accompanying notes to unaudited pro forma
financial statements are an integral part of these statements

F-3
<PAGE> 74

BELCO OIL & GAS CORP. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED CONDENSED
STATEMENTS OF OPERATIONS
FOR THE NINE-MONTHS ENDED SEPTEMBER 30, 1997
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
MERGER
BELCO CODA PRO FORMA
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales........................... $89,742 $54,580 $ -- $ 144,322
Commodity price risk management
activities............................... (7,674) -- -- (7,674)
Gas gathering and processing................ -- 32,712 (32,712)(b) --
Interest and other.......................... 2,326 846 77(b) 3,249
------- ------- --------- ---------
Total Revenues...................... 84,394 88,138 (32,635) 139,897
------- ------- --------- ---------
OPERATING EXPENSES
Oil and gas operating expenses.............. 6,657 25,734 32,391
Depreciation, depletion and amortization.... 32,190 20,202 (2,394)(b) 64,564
14,566(c)
General and administrative.................. 2,476 1,172 (587)(f) 3,061
Gas gathering and processing................ -- 27,956 (27,956)(b) --
Interest.................................... -- 12,128 10,329(a) 17,251
(3,466)(b)
(7,340)(e)
5,600(h)
Writedown of oil and gas properties......... -- -- 150,000(g) 150,000
------- ------- --------- ---------
Total Costs and Expenses...................... 41,323 87,192 138,752 267,267
------- ------- --------- ---------
INCOME (LOSS) BEFORE INCOME TAXES............. 43,071 946 (171,387) (127,370)
Provision (benefit) for income taxes.......... 14,752 625 (55)(b) (43,551)
(58,873)(d)
------- ------- --------- ---------
PRO FORMA NET INCOME (LOSS)................... $28,319 $ 321 $(112,459) $ (83,819)
======= ======= ========= =========
PRO FORMA NET INCOME (LOSS) PER COMMON SHARE
BASIC....................................... $ 0.90 $ (2.65)
======= =========
DILUTED..................................... $ 0.89 $ (2.65)
======= =========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
BASIC....................................... 31,582 31,582
======= =========
DILUTED..................................... 31,704 31,582
======= =========
</TABLE>

The accompanying notes to unaudited pro forma
financial statements are an integral part of these statements

F-4
<PAGE> 75

BELCO OIL & GAS CORP. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED CONDENSED
BALANCE SHEET
AS OF SEPTEMBER 30, 1997
(IN THOUSANDS)

<TABLE>
<CAPTION>
MERGER
BELCO CODA PRO FORMA
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents............. $138,488 $ 8,708 $ 1,864(b) $ 17,264
(149,884)(g)
1,188(i)
16,900(l)
Accounts receivable, oil and gas...... 24,717 12,486 (5,113)(b) 32,090
Assets from commodity price risk
management activities.............. -- -- -- --
Advances to oil and gas operators..... 986 467 (94)(b) 1,359
Other current assets.................. 26 650 3(b) 679
-------- -------- --------- ---------
Total current assets.......... 164,217 22,311 (135,136) 51,392
AMOUNTS DUE FROM STOCKHOLDERS........... -- 1,188 (1,188)(i) --
PROPERTY AND EQUIPMENT:
Proved oil and gas properties......... 319,552 271,731 (150,000)(m) 591,174
(271,731)(d)
421,622(e)
Unproved oil and gas properties....... 83,277 1,000 (1,000)(d) 110,277
27,000(e)
Gas plants and processing systems..... -- 36,539 (36,539)(b) --
Other properties...................... -- 4,521 (45)(b) 6,000
(4,476)(d)
6,000(e)
Less: Accumulated depreciation,
depletion and amortization......... (118,865) (42,996) 4,372(b) (118,865)
38,624(d)
-------- -------- --------- ---------
Net property and equipment.... 283,964 270,795 33,827 588,586
-------- -------- --------- ---------
OTHER ASSETS............................ 39,235 3,306 (540)(b) 39,235
(2,766)(d)
-------- -------- --------- ---------
Total Assets.................. $487,416 $297,600 $(105,803) $ 679,213
======== ======== ========= =========
</TABLE>

The accompanying notes to unaudited pro forma
financial statements are an integral part of these statements

F-5
<PAGE> 76

BELCO OIL & GAS CORP. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED CONDENSED
BALANCE SHEET
AS OF SEPTEMBER 30, 1997
(IN THOUSANDS)

<TABLE>
<CAPTION>
MERGER
BELCO CODA PRO FORMA
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities... $ 8,812 $ 16,976 $ (3,444)(b) $ 29,344
7,000(c)
Liabilities from commodity price risk
management activities................... 12,534 -- 12,534
Income taxes payable....................... 14 473 (31)(b) 456
-------- -------- --------- --------
Total current liabilities.......... 21,360 17,449 3,525 42,334
-------- -------- --------- --------
LONG-TERM DEBT............................... 150,000 67,100 (67,100)(k) 234,000
84,000(l)
10 1/2% SUBORDINATED NOTES................... 110,000 7,090(j) 117,090
DEFERRED INCOME TAXES........................ 52,105 37,396 (562)(b) 109,338
(52,500)(m)
(36,834)(d)
109,733(h)
LIABILITIES FROM COMMODITY PRICE RISK
MANAGEMENT ACTIVITIES...................... 2,244 -- 2,244
-------- -------- --------- --------
Total liabilities.................. 225,709 231,945 47,352 505,006
STOCKHOLDERS' EQUITY
Preferred stock......................... -- 20,000 (20,000)(a) --
Common stock............................ 316 9 (9)(a) 316
Additional paid-in capital.............. 186,807 94,551 (94,551)(a) 196,807
10,000(f)
Retained earnings (deficit)............. 76,563 (47,968) 38,023(a) (20,937)
(97,500)(m)
9,945(b)
Unearned compensation................... (1,204) -- (1,204)
Notes receivable for equity interest.... (775) (937) 937(a) (775)
-------- -------- --------- --------
Total stockholders' equity......... 261,707 65,655 (153,155) 174,207
======== ======== ========= ========
Total Liabilities And Stockholders'
Equity........................... $487,416 $297,600 $(105,803) $679,213
======== ======== ========= ========
</TABLE>

The accompanying notes to unaudited pro forma
financial statements are an integral part of these statements.

F-6
<PAGE> 77

BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED
CONDENSED FINANCIAL STATEMENTS

BASIS OF PRESENTATION

The unaudited pro forma consolidated condensed statements of operations
relative to the Merger are based on the audited historical financial statements
of Belco for the year ended December 31, 1996 and the audited historical
financial statements of Coda for the 319 days ended December 31, 1996 and
unaudited historical financial statements of Coda for the 47 days ended February
16, 1996 and on the unaudited historical financial statements of Coda and Belco
for the nine months ended September 30, 1997. The pro forma information relating
to the Merger reflects the combination of Belco's and Coda's historical results
of operations, as adjusted to exclude the downstream gas gathering and
processing operations of Coda conducted through its Subsidiary, Taurus Energy
Corp. (Taurus). Differences in accounting policies and methods between Belco and
Coda were reviewed and considered to have an immaterial impact on the combined
pro forma financial results. Certain historical Coda data have been reclassified
to conform to Belco's historical presentations.

PRO FORMA ADJUSTMENTS

The Unaudited Pro Forma Statements of Operations Reflect the Following
Adjustments:

(a) Record interest expense and amortization of deferred financing costs
associated with Belco's recent $150 million debt issuance. Interest
expense was computed using an 8 7/8 percent rate on $150 million.

(b) Adjust Coda historical to eliminate the effects of Coda's downstream
operations conducted by Taurus, net of any intercompany allocations.
The Taurus operations are not part of the Merger.

(d) Record pro forma income tax provision (benefit) relating to the pro
forma adjustments assuming an effective federal and state rate of
approximately 34 percent.

(e) Record capitalized interest assuming, on a preliminary basis that $27
million of the purchase price is initially classified as unproved
property costs and considering Belco's unproved property costs of
$77.6 million and $83.3 million at December 31, 1996 and September 30,
1997, respectively, for which interest was not previously incurred or
capitalized.

(f) Adjust Coda historical to eliminate the effects of Taurus's general
and administrative expenses, net of any intercompany allocations.

(g) Record pro forma ceiling test provision of $150 million ($98 million
after tax) on a consolidated basis at September 30, 1997 and remove
the Coda stand alone December 31, 1996 ceiling test provision. The
September 30, 1997 ceiling test provision includes the effect of the
non-cash $110 million FASB 109 "gross up" attributable to the Coda
acquisition on Belco's full cost pool at year-end 1997 and adjustments
to the SEC PV 10 value of year-end 1997 reserves, which were
significantly impacted by lower product prices when compared to
year-end 1996 prices, among other items.

(h) Record pro forma interest on credit line draw in connection with the
Merger using an assumed interest rate of 8 7/8 for the year ended
December 31, 1996 and the nine months ended September 30, 1997,
respectively. See (l) below.

F-7
<PAGE> 78
The Unaudited Pro Forma Balance Sheets Reflect the Following adjustments:

(a) Adjust historical combined preferred stock, common stock, paid-in
capital and retained earnings, net of Taurus account balances to
eliminate the historical carrying value of Coda's stockholders'
equity. The impact of these entries does not result in a change to
total combined stockholders' equity.

(b) Adjust Coda historical to eliminate the balances of Taurus operations.
Taurus is not part of the Merger.

(d) To eliminate Coda's historical balances, net of Taurus, as applicable.
See note (b).

(e) Record purchase price allocation as follows:

<TABLE>
<S> <C>
$422 million Proved oil and gas property cost
$ 27 million Unproved oil and gas property costs
$ 6 million Building and other assets
</TABLE>

(f) Record fair value of warrants issued in connection with the Merger.

(g) Record $149.9 million cash paid in connection with the purchase of
Coda's common and preferred stock.

(h) Record deferred tax liability assumed in connection with the Merger.

(i) Record the pro forma receipt of cash received at closing from
stockholders from subscription agreement.

(j) Record premium on 10 1/2% Subordinated notes to reflect debt at fair
market value.

(k) Record repayment of Coda's long-term bank debt, including $42 million
upon the Disposition of Taurus (see Note (b)).

(l) Record Belco's credit line draw in connection with the merger ($84
million) and excess cash from draw of $16.9 million.

(m) Record full cost impairment of proved oil and gas properties at
September 30, 1997 as described in note (g) to the statement of
operations footnotes.

F-8
<PAGE> 79

BELCO OIL & GAS CORP. AND SUBSIDIARIES

UNAUDITED PRO FORMA SUPPLEMENTAL OIL AND GAS DISCLOSURE

The following table sets forth certain unaudited pro forma information
concerning Belco's proved oil and gas reserves at December 31, 1996, giving
effect to the Merger as if the Merger had occurred on January 1, 1996. There are
numerous uncertainties inherent in estimating the quantities of proved reserves
and projecting future rates of production and timing of development
expenditures. The following reserve data represents estimates only and should
not be construed as being exact.

<TABLE>
<CAPTION>
NATURAL GAS (MMCF)
--------------------------------
BELCO CODA PRO FORMA
------- ------ ---------
<S> <C> <C> <C>
Balance at December 31, 1995.............................. 204,170 37,130 241,300
Purchase of minerals in place............................. 21,993 236 22,229
Extensions, discoveries and other additions............... 87,319 4,982 92,301
Revisions of previous estimates........................... 22,799 604 23,403
Production................................................ (51,289) (3,810) (55,099)
Sale of properties........................................ -- (97) (97)
------- ------ -------
Balance at December 31, 1996.............................. 284,992 39,045 324,037
======= ====== =======
Proved developed reserves
December 31, 1995....................................... 140,725 31,496 172,221
December 31, 1996....................................... 184,904 33,255 218,159
</TABLE>

<TABLE>
<CAPTION>
OIL AND NATURAL GAS LIQUIDS (MBBLS)
------------------------------------
BELCO CODA PRO FORMA
------- -------- -----------
<S> <C> <C> <C>
Balance at December 31, 1995................................ 2,452 42,590 45,042
Purchase of minerals in place............................... 162 1,260 1,422
Extensions, discoveries and other additions................. 1,411 121 1,532
Revisions of previous estimates............................. 96 2,579 2,675
Production.................................................. (794) (3,379) (4,173)
Sale of properties.......................................... -- (134) (134)
----- ------ ------
Balance at December 31, 1996................................ 3,327 43,037 46,364
===== ====== ======
Proved developed reserves
December 31, 1995......................................... 1,838 25,877 27,715
December 31, 1996......................................... 2,070 33,895 35,965
</TABLE>

F-9
<PAGE> 80

BELCO OIL & GAS CORP. AND SUBSIDIARIES

UNAUDITED PRO FORMA SUPPLEMENTAL OIL AND GAS DISCLOSURE -- (CONTINUED)

The following table sets forth unaudited pro forma information concerning
the discounted future net cash flows from proved oil and gas reserves of Belco
as of December 31, 1996, net of income tax expense, and giving effect to the
Merger as if the Merger had occurred on January 1, 1996. Income tax expense has
been computed using assumptions relating to the future tax rates and the
permanent differences and credits under the tax laws relating to oil and gas
activities at December 31, 1996, and do not take into account subsequent changes
in tax laws. The information should be viewed only as a form of standardized
disclosure concerning possible future cash flows that would result under the
assumptions used, and should not be viewed as indicative of fair market value.

Standardized measure of discounted future net cash flows relating to proved
reserves, net of income tax expense as of December 31, 1996:

<TABLE>
<CAPTION>
BELCO CODA PRO FORMA
---------- ---------- ----------
(THOUSANDS)
<S> <C> <C> <C>
Future cash inflows(1)....................... $1,071,550 $1,208,793 $2,280,343
Future production and development costs...... (324,220) (431,250) (755,470)
---------- ---------- ----------
Future net inflows before income taxes(1).... 747,330 777,543 1,524,873
Discount at 10% annual rate.................. (331,800) (329,677) (661,477)
---------- ---------- ----------
Discounted future net cash flows before
income taxes............................... 415,530 447,866 863,396
Pro forma discounted future income taxes..... (134,957) (120,007) (254,964)
---------- ---------- ----------
Standardized measure of discounted future net
cash flows................................. $ 280,573 $ 327,859 $ 608,432
========== ========== ==========
</TABLE>

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

(1) Belco's oil and gas commodity hedges included in future cash inflows totaled
($60.8) million at December 31, 1996, and such hedges included in discounted
future net cash flows before income taxes totaled ($55.2) million at
December 31, 1996.

Change in standardized measure of discounted future net cash flows related
to proved oil and gas reserves for the year ended December 31, 1996:

<TABLE>
<CAPTION>
BELCO CODA PRO FORMA
--------- -------- ---------
(THOUSANDS)
<S> <C> <C> <C>
Balance, December 31, 1995....................... $ 148,509 $220,742 $ 369,251
Sales, net of production costs................... (111,780) (44,602) (156,382)
Net change in prices and production costs........ 145,133 130,774 275,907
Extensions and discoveries, net of related
costs.......................................... 153,920 12,338 166,258
Changes in estimated future development costs.... 24,618 9,894 34,512
Revisions in quantities.......................... 50,309 48,120 98,429
Purchases of minerals in place................... 7,843 7,655 15,498
Accretion of discount............................ 20,651 36,318 56,969
Change in income taxes........................... (76,957) (92,945) (169,902)
Sales of reserves in place....................... (435) (435)
Other, principally revisions in estimates of
timing of production........................... (81,673) -- (81,673)
--------- -------- ---------
Balance, December 31, 1996....................... $ 280,573 $327,859 $ 608,432
========= ======== =========
</TABLE>

F-10
<PAGE> 81

BELCO OIL & GAS CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
(UNAUDITED)

ASSETS

<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1997 1996
------------- ------------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents................................. $ 138,488 $ 43,473
Accounts receivable, oil and gas.......................... 24,717..... 28,934
Assets from commodity price risk management activities.... -- 2,249
Advances to oil and gas operators......................... 986 69
Other current assets...................................... 26 456
--------- --------
Total current assets.............................. 164,217 75,181
--------- --------
PROPERTY AND EQUIPMENT:
Oil and gas properties at cost based on full-cost
accounting
Proved oil and gas properties.......................... 319,552 237,150
Unproved oil and gas properties........................ 83,277 77,570
Less -- Accumulated depreciation, depletion and
amortization......................................... (118,865) (86,490)
--------- --------
Net property and equipment........................ 283,964 228,230
--------- --------
OTHER ASSETS................................................ 39,235 507
--------- --------
Total assets...................................... $ 487,416 $303,918
========= ========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities.................. $ 8,812 $ 16,886
Liabilities from commodity price risk management
activities............................................. 12,534 7,220
Income taxes payable...................................... 14 2,408
--------- --------
Total current liabilities......................... 21,360 26,514
--------- --------
LONG-TERM DEBT.............................................. 150,000 --
DEFERRED INCOME TAXES....................................... 52,105 39,967
LIABILITIES FROM COMMODITY PRICE RISK MANAGEMENT
ACTIVITIES................................................ 2,244 4,234
STOCKHOLDERS' EQUITY
Preferred stock, $.01 par value; 10,000,000 shares
authorized; none issued or outstanding................. -- --
Common stock ($.01 par value, 120,000,000 shares
authorized; 31,582,000 shares issued and outstanding at
September 30, 1997).................................... 316 316
Additional paid-in capital................................ 186,807 186,703
Retained earnings......................................... 76,563 48,244
Unearned compensation..................................... (1,204) (1,285)
Notes receivable for equity interest...................... (775) (775)
--------- --------
Total stockholders' equity........................ 261,707 233,203
--------- --------
Total liabilities and stockholders' equity........ $ 487,416 $303,918
========= ========
</TABLE>

The accompanying notes are an integral part of these condensed financial
statements.

F-11
<PAGE> 82

BELCO OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED)

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
------------------
1997 1996
------- -------
<S> <C> <C>
REVENUES:
Oil and gas sales......................................... $89,742 $83,930
Commodity price risk management........................... (7,674) 2,413
Interest and other........................................ 2,326 1,849
------- -------
Total revenues.................................... 84,394 88,192
------- -------
COSTS AND EXPENSES:
Oil and gas operating expenses............................ 6,657 5,826
Depreciation, depletion and amortization.................. 32,190 29,891
General and administrative................................ 2,476 2,444
------- -------
Total costs and expenses.......................... 41,323 38,161
------- -------
INCOME BEFORE INCOME TAXES.................................. 43,071 50,031
PROVISION FOR INCOME TAXES.................................. 14,752 41,143(a)
------- -------
NET INCOME.................................................. $28,319 $ 8,888(a)
======= =======
PRO FORMA NET INCOME
Income before income taxes................................ $43,071 $50,031
Pro forma provision for income taxes...................... 14,752 17,011
------- -------
Pro forma net income.............................. $28,319 $33,020
======= =======
PRO FORMA NET INCOME PER COMMON SHARE
BASIC..................................................... $ 0.90 $ 1.12
======= =======
DILUTED................................................... $ 0.89 $ 1.12
======= =======
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
BASIC..................................................... 31,582 29,476
======= =======
DILUTED................................................... 31,704 29,476
======= =======
</TABLE>

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

(a) Includes a one-time non-cash deferred tax charge of $29.9 million recognized
as a result of the Combination consummated on March 29, 1996 in connection
with the Company's Initial Public Offering and discussed in the Belco Oil &
Gas Corp. Prospectus dated March 25, 1996. The pro forma amounts present the
Company as if a taxable corporation for all periods and is based on the
average number of shares outstanding during the period assuming the
Combination had occurred on January 1, 1996.

The accompanying notes are an integral part of these condensed financial
statements.

F-12
<PAGE> 83

BELCO OIL & GAS CORP.

CONDENSED CONSOLIDATED CHANGES IN STOCKHOLDERS' EQUITY
(IN THOUSANDS)
(UNAUDITED)

<TABLE>
<CAPTION>
NOTES
COMMON STOCK ADDITIONAL RECEIVABLE
--------------- PAID-IN UNEARNED RETAINED FOR EQUITY
SHARES AMOUNT CAPITAL COMPENSATION EARNINGS INTEREST TOTAL
------ ------ ---------- ------------ -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE, December 31,
1996.................. 31,577 $316 $186,703 $(1,285) $48,244 $(775) $233,203
------ ---- -------- ------- ------- ----- --------
Restricted stock
issued................ 5 -- 104 81 -- -- 185
Net Income.............. -- -- -- -- 28,319 -- 28,319
------ ---- -------- ------- ------- ----- --------
BALANCE, September 30,
1997.................. 31,582 $316 $186,807 $(1,204) $76,563 $(775) $261,707
====== ==== ======== ======= ======= ===== ========
</TABLE>

The accompanying notes are an integral part of these condensed financial
statements.

F-13
<PAGE> 84

BELCO OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
----------------------
1997 1996
--------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 28,319 $ 8,888
Adjustments to reconcile net income to net operating cash
inflows
Depreciation, depletion and amortization............... 32,190 29,891
Deferred tax provision(a).............................. 12,138 39,625
Amortization of restricted stock compensation.......... 185 70
Commodity price risk management activities............. 5,572 --
Changes in operating assets and liabilities --
Accounts receivable, oil and gas..................... 4,217 (5,721)
Revenues and royalties payable....................... -- 3,437
Income taxes payable................................. (2,394) 340
Other current assets................................. 430 183
Accounts payable and accrued liabilities............. (1,616) --
--------- ---------
Net operating cash inflows........................ 79,041 76,713
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures.................. (101,994) (103,751)
Investment in Hugoton Energy Corp......................... (30,870) --
Changes in accounts payable and accrued liabilities for
oil and gas expenditures............................... (6,272) 5,773
Proceeds from sale of oil and gas properties.............. 13,885 --
Change in advances to oil and gas operators............... (917) 45
Changes in other assets................................... (7,858) 100
Other..................................................... -- 76
--------- ---------
Net investing cash outflows....................... (134,026) (97,757)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from initial public offering..................... -- 113,115
Long-term borrowings...................................... 150,000 13,300
Long-term debt repayments................................. -- (35,300)
Equity distributions...................................... -- (13,865)
Other..................................................... -- 89
--------- ---------
Net financing cash inflows........................ 150,000 77,339
--------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............ 95,015 56,295
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD............ 43,473 1,556
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD.................. $ 138,488 $ 57,851
========= =========
</TABLE>

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

(a) Prior to March 29, 1996, the earnings of the Company were not subject to
corporate income taxes as the Company, prior to the Combination, was a group
of non-taxpaying entities. See Note 4.

The accompanying notes are an integral part of these condensed financial
statements.

F-14
<PAGE> 85

BELCO OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- ACCOUNTING POLICIES

The financial statements included herein have been prepared by the Company,
without audit, pursuant to the rules and regulations of the Securities and
Exchange Commission and reflect all adjustments which are, in the opinion of
management, necessary to present a fair statement of the results for the interim
periods, on a basis consistent with the annual audited financial statements. All
such adjustments are of a normal recurring nature. The results of operations for
the interim period are not necessarily indicative of the results to be expected
for an entire year. Certain information, accounting policies, and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been omitted pursuant to such
rules and regulations, although the Company believes that the disclosures are
adequate to make the information presented not misleading. These financial
statements should be read in conjunction with the Company's Form 10-K for the
calendar year 1996 which includes financial statements and notes thereto.

NOTE 2 -- ORGANIZATION AND PRINCIPLES OF COMBINATION

The Company was organized as a Nevada corporation in January of 1996 in
connection with the combination of assets (the "Combination") consisting of
ownership interests (the "Combined Assets") in certain entities and direct
interests in oil and gas properties and certain hedge transactions owned by
members of the Robert A. Belfer family and by employees of the predecessors and
entities related thereto. The Company and the owners of the Combined Assets
entered into an Exchange and Subscription Agreement and Plan of Reorganization
dated as of January 1, 1996 (the "Exchange Agreement") that provided for the
issuance by the Company of an aggregate of 25,000,000 shares of common stock to
such owners in exchange for the Combined Assets on March 29, 1996, the date the
Offering closed. The owners of the Combined Assets received shares of common
stock proportionate to the value of the Combined Assets underlying their
ownership interests in the predecessors and the direct interests.

The Combination was accounted for as a reorganization of entities under
common control because of the common control of the stockholders of the Nevada
corporation and by virtue of their direct ownership of the entities and
interests exchanged. Accordingly, the net assets acquired in the Combination
have been recorded at the historical cost basis of the affiliated predecessor
owners.

On March 29, 1996, the Company completed its initial public offering (the
"Offering") issuing 6.5 million shares at $19 per share. Net proceeds totaled
$113.1 million after Offering costs of $10.4 million.

NOTE 3 -- PRO FORMA NET INCOME PER SHARE

Basic Pro forma net income per share is based on the weighted average
number of shares of common stock outstanding. The computation assumes that the
Company was incorporated during the periods presented and presents the shares
issued in connection with the Combination as outstanding for all periods.
Diluted earnings per share includes the effects of common stock equivalent
shares (stock options) and restricted stock for the nine month period ended on
September 30, 1997 and 1996, respectively.

NOTE 4 -- INCOME TAXES

Prior to March 29, 1996, the earnings of the Company were not subject to
corporate income taxes as the Company, prior to the Combination, was a
combination of non-taxpaying entities,

F-15
<PAGE> 86
BELCO OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

including Subchapter S, limited liability corporations, partnership and joint
venture entities and individual interests.

Accordingly, taxable earnings were directly taxable to the individual
owners through the date of the Combination. As a result of the Combination
consummated on March 29, 1996, the Company became a taxpaying entity and
recorded, in the first quarter of 1996, a $29.9 million one-time, non-cash
charge to earnings to establish a deferred tax liability. The historical
provision for income taxes for the nine months ended September 30, 1996 includes
the one-time charge. The pro forma provision for income taxes reflected in the
Condensed Consolidated Statements of Operations for the nine month periods ended
September 30, 1997 and 1996 have been presented to reflect the Company's income
taxes under the assumption that the Company was a taxpaying entity since its
inception.

The differences between the statutory federal income taxes and the
Company's pro forma effective taxes is summarized as follows (in thousands):

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
------------------
1997 1996
------- -------
<S> <C> <C>
Statutory federal income taxes.............................. $15,075 $17,511
State income tax, net of federal benefit.................... 121 60
Section 29 tax credits...................................... (656) (575)
Other....................................................... 212 15
------- -------
Pro forma provision for income taxes........................ $14,752 $17,011
======= =======
</TABLE>

NOTE 5 -- COMMODITY PRICE RISK MANAGEMENT ACTIVITIES

The Company periodically enters into commodity hedging transactions such as
swaps and options in order to manage its exposure to oil and gas price
volatility. Gains and losses related to qualifying hedges of the Company's oil
and gas production are deferred and recognized as revenues as the associated
production occurs. Reference is made to the December 31, 1996 financial
statements of Belco Oil & Gas Corp. included herein for a more thorough
discussion of the Company's commodity hedging activities.

The Company uses the mark-to-market method of accounting for instruments
that do not qualify for hedge accounting. Under mark-to-market accounting, those
contracts which do not qualify for hedge accounting are reflected at market
value at the end of the period with resulting unrealized gains and losses
recorded as assets and liabilities in the consolidated balance sheet. Under such
method, changes in the market value of outstanding financial instruments are
recognized as unrealized gain or loss in the period of change.

For the nine months ended September 30, 1997, the Company had net losses of
$7.7 million ($7.9 million in cash settlements paid, $5.8 million in cash
premiums received and $5.6 million in recognized non-cash marked-to-market loss)
compared to a $2.4 million net gain all cash reported in the first nine months
of 1996 related to its price risk management activities.

NOTE 6 -- INVESTMENT IN HUGOTON ENERGY CORPORATION

In June 1997 the Company purchased 2,940,000 shares of common stock of
Hugoton Energy Corporation (Hugoton) at $10.50 per share or a total investment
of $30.9 million. This investment is presently carried at cost on the Company's
Balance Sheet.

F-16
<PAGE> 87
BELCO OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 7 -- SUBSEQUENT EVENT

On November 3, 1997, the Company announced that it had entered a definitive
merger agreement to acquire all of the outstanding stock of Coda Energy, Inc.
(Coda) from an affiliate of Enron Capital & Trade Resources Corp. holding 95% of
the common stock of Coda, and certain members of Coda's senior management. Belco
closed the transaction in late November, 1997.

F-17
<PAGE> 88

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Belco Oil & Gas Corp.:

We have audited the accompanying consolidated balance sheets of Belco Oil &
Gas Corp. (a Nevada Corporation) and subsidiaries as of December 31, 1996 and
1995, and the related consolidated statements of operations, 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Belco Oil &
Gas Corp. and subsidiaries as of December 31, 1996 and 1995, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1996, in conformity with generally accepted accounting
principles.

ARTHUR ANDERSEN LLP

Houston, Texas
February 28, 1997

F-18
<PAGE> 89

BELCO OIL & GAS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1996 1995
-------- --------
(IN THOUSANDS)
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents................................. $ 43,473 $ 1,556
Accounts receivable, oil and gas.......................... 28,934 16,979
Assets from commodity price risk management activities.... 2,249 --
Advances to oil and gas operators......................... 69 45
Other current assets...................................... 456 401
-------- --------
Total Current Assets.............................. 75,181 18,981
-------- --------
PROPERTY AND EQUIPMENT:
Oil and gas properties at cost based on full-cost
accounting --
Proved oil and gas properties.......................... 237,150 152,081
Unproved oil and gas properties........................ 77,570 19,927
Less -- Accumulated depreciation, depletion and
amortization.......................................... (86,490) (45,771)
-------- --------
Net property and equipment........................ 228,230 126,237
-------- --------
OTHER ASSETS................................................ 507 332
-------- --------
Total Assets...................................... $303,918 $145,550
======== ========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities.................. $ 16,886 $ 8,440
Distribution payable...................................... -- 10,095
Liabilities from commodity price risk management
activities............................................. 7,220 --
Income taxes payable...................................... 2,408 --
-------- --------
Total Current Liabilities......................... 26,514 18,535
LONG-TERM DEBT.............................................. -- 22,000
DEFERRED INCOME TAXES....................................... 39,967 --
LIABILITIES FROM COMMODITY PRICE RISK MANAGEMENT
ACTIVITIES................................................ 4,234 --
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares
authorized; none issued or outstanding................. -- --
Common Stock, $0.01 par value; 120,000,000 shares
authorized; 31,577,300 shares issued and outstanding at
December 31, 1996...................................... 316 --
Additional paid-in capital................................ 186,703 --
Retained earnings......................................... 48,244 --
Combined equity of predecessor entities................... -- 105,849
Unearned compensation..................................... (1,285) --
Notes receivable for equity interest...................... (775) (834)
-------- --------
Total Stockholders' Equity........................ 233,203 105,015
-------- --------
Total Liabilities and Stockholders' Equity........ $303,918 $145,550
======== ========
</TABLE>

The accompanying notes to consolidated financial statements are an
integral part of these statements.

F-19
<PAGE> 90

BELCO OIL & GAS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------
1996 1995 1994
----------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
REVENUES:
Oil and gas sales...................................... $119,710 $68,767 $40,362
Commodity price risk management activities............. (5,967) 9,480 550
Interest............................................... 2,653 353 195
-------- ------- -------
Total revenues................................. 116,396 78,600 41,107
-------- ------- -------
COSTS AND EXPENSES:
Oil and gas operating expenses......................... 7,847 5,824 5,510
Depreciation, depletion and amortization............... 40,904 27,590 14,072
General and administrative............................. 3,059 2,597 2,269
-------- ------- -------
Total costs and expenses....................... 51,810 36,011 21,851
-------- ------- -------
INCOME BEFORE INCOME TAXES............................... 64,586 42,589 19,256
-------- ------- -------
PROVISION FOR INCOME TAXES(a)............................ 46,404 -- --
-------- ------- -------
NET INCOME............................................... $ 18,182 $42,589 $19,256
PRO FORMA NET INCOME:
Income before income taxes............................. $ 64,586 $42,589 $19,256
Pro forma provision for income taxes................... 21,953 13,852 5,030
-------- ------- -------
Pro forma net income........................... $ 42,633 $28,737 $14,226
======== ======= =======
PRO FORMA BASIC AND DILUTED NET INCOME PER COMMON
SHARE.................................................. $ 1.42 $ 1.15 $ 0.57
======== ======= =======
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING............................................ 29,986 25,000 25,000
======== ======= =======
</TABLE>

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

(a) Includes a one-time non-cash deferred tax charge of $30.1 million recognized
as a result of the Combination consummated on March 29, 1996. See Note 1.
Historical basic and diluted net income per share, including the deferred
tax charge, was $0.61 for the year ended December 31, 1996. The pro forma
amounts present the Company as if a taxable corporation for all periods and
are based on the average number of shares outstanding during the period
assuming the shares issued in connection with the Combination were
outstanding for all periods.

The accompanying notes to consolidated financial statements are an
integral part of these statements.

F-20
<PAGE> 91

BELCO OIL & GAS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)

<TABLE>
<CAPTION>
NOTES
COMMON STOCK ADDITIONAL COMBINED RECEIVABLE
--------------- PAID-IN UNEARNED RETAINED PREDECESSOR FOR EQUITY
SHARES AMOUNT CAPITAL COMPENSATION EARNINGS EQUITY INTEREST TOTAL
------ ------ ---------- ------------ -------- ----------- ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE, December 31,
1993.................... -- $ -- $ -- $ -- $ -- $ 47,188 $ -- $ 47,188
------ ---- -------- ------- ------- -------- ----- --------
Contributions............. -- -- -- -- -- 50,040 -- 50,040
Distributions............. -- -- -- -- -- (26,468) -- (26,468)
Issuance of employee notes
receivable.............. -- -- -- -- -- -- (126) (126)
Income before income
taxes................... -- -- -- -- -- 19,256 -- 19,256
------ ---- -------- ------- ------- -------- ----- --------
BALANCE, December 31,
1994.................... -- $ -- $ -- $ -- $ -- $ 90,016 $(126) $ 89,890
------ ---- -------- ------- ------- -------- ----- --------
Contributions............. -- -- -- -- -- 4,512 -- 4,512
Distributions............. -- -- -- -- -- (31,268) -- (31,268)
Issuance of employee notes
receivable.............. -- -- -- -- -- -- (868) (868)
Repayment of employee
notes receivable........ -- -- -- -- -- -- 160 160
Income before income
taxes................... -- -- -- -- -- 42,589 -- 42,589
------ ---- -------- ------- ------- -------- ----- --------
BALANCE, December 31,
1995.................... -- $ -- $ -- $ -- $ -- $105,849 $(834) $105,015
------ ---- -------- ------- ------- -------- ----- --------
Exchange combination...... 25,000 250 72,142 -- -- (72,392) -- --
Public stock offering, net
of costs of $10.4
million................. 6,500 65 113,050 -- -- -- -- 113,115
Restricted stock issued... 77 1 1,511 (1,285) -- -- -- 227
Repayment of employee
notes receivable........ -- -- -- -- -- -- 59 59
Distributions to
predecessor owners...... -- -- -- -- -- (3,395) -- (3,395)
Net Income(a)............. -- -- -- -- 48,244 (30,062) -- 18,182
------ ---- -------- ------- ------- -------- ----- --------
BALANCE, December 31,
1996.................... 31,577 $316 $186,703 $(1,285) $48,244 $ -- $(775) $233,203
------ ---- -------- ------- ------- -------- ----- --------
</TABLE>

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

(a) Includes a one-time non-cash deferred tax charge of $30.1 million recognized
as a result of the Combination consummated on March 29, 1996. See Note 1.

The accompanying notes to consolidated financial statements are an integral part
of these statements.

F-21
<PAGE> 92

BELCO OIL & GAS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------
1996 1995 1994
--------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income(a)........................................ $ 18,182 $ 42,589 $ 19,256
Adjustments to reconcile net income to net operating
cash inflows
Depreciation, depletion and amortization.......... 40,904 27,590 14,072
Deferred tax provision(a)......................... 39,967 -- --
Amortization of restricted stock compensation..... 227 -- --
Commodity price risk management activities........ 9,436 (570) 277
Changes in operating assets and liabilities
Accounts receivable, oil and gas................ (11,955) (6,445) (6,084)
Other current assets............................ (286) -- --
Accounts payable and accrued liabilities........ 11,584 (1,127) 605
--------- -------- --------
Net operating cash inflows................... 108,059 62,037 28,126
--------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures............. (142,712) (71,387) (52,230)
Changes in accounts payable and accrued liabilities
for oil and gas expenditures...................... (730) 5,243 721
Change in advances to oil and gas operators.......... (24) 1,566 (1,012)
Changes in other assets.............................. (360) (555) (149)
--------- -------- --------
Net investing cash outflows.................. (143,826) (65,133) (52,670)
--------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from initial public offering.................. 113,115 -- --
Long-term borrowings................................... 13,300 17,170 6,930
Long-term debt repayments.............................. (35,300) (2,100) --
Equity contributions................................... -- 4,512 50,040
Equity distributions................................... (13,490) (21,173) (26,468)
Employee loans, net.................................... 59 (708) (126)
--------- -------- --------
Net financing cash inflows (outflows)........ 77,684 (2,299) 30,376
--------- -------- --------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS....... 41,917 (5,395) 5,832
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD....... 1,556 6,951 1,119
--------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD............. $ 43,473 $ 1,556 $ 6,951
========= ======== ========
</TABLE>

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

(a) Prior to March 29, 1996, the earnings of the Company were not subject to
corporate income taxes as the Company, prior to the Combination, was a group
of non-taxpaying entities. See Note 1.

The accompanying notes to consolidated financial statements are an
integral part of these statements.

F-22
<PAGE> 93

BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- ORGANIZATION AND NATURE OF OPERATIONS

Organization

Belco Oil & Gas Corp. was organized as a Nevada corporation in January 1996
in connection with the combination of assets (the "Combination") consisting of
ownership interests (the "Combined Assets") in certain entities and direct
interests in oil and gas properties and certain hedge transactions owned by the
predecessors and entities related thereto. On March 29, 1996, Belco Oil & Gas
Corp. completed its initial public offering (the "Offering") issuing 6,500,000
shares of Common Stock at $19 per share. Belco Oil & Gas Corp. and the owners of
the Combined Assets entered into an Exchange and Subscription Agreement and Plan
of Reorganization dated as of January 1, 1996 (the "Exchange Agreement") that
provided for the issuance by the Company of an aggregate of 25,000,000 shares of
Common Stock to such owners in exchange for the Combined Assets on March 29,
1996, the date the Offering closed. The owners of the Combined Assets received
shares of Common Stock proportionate to the value of the Combined Assets
underlying their ownership interests in the predecessors and the direct
interests.

The Combination was accounted for as a reorganization of entities under
common control because of the common control of the stockholders of Belco Oil &
Gas Corp. and by virtue of their direct ownership of the entities and interests
exchanged. Accordingly, the net assets acquired in the Combination have been
recorded at the historical cost basis of the affiliated predecessor owners.

Belco Oil & Gas Corp. and its subsidiaries and prior to March 29, 1996, the
combined predecessor entities, are referred to herein as "Belco" or the
"Company".

Nature of Operations

The Company is an independent energy company engaged in the exploration,
development and production of natural gas and oil. The Company operates in this
single industry segment, and all operations are conducted in the United States.
The Company's operations are presently focused in the Giddings Field (east
central Texas), the Moxa Arch Trend (southwest Wyoming) and to a lesser extent
the Golden Trend Field (southern Oklahoma) and Louisiana.

Substantially all of the Company's production is sold under market
sensitive contracts. The Company's revenue, profitability and future rate of
growth are substantially dependent upon the price of, and demand for, oil,
natural gas and natural gas liquids. Prices for oil and natural gas are subject
to wide fluctuation in response to relatively minor changes in the supply of and
demand for oil and natural gas, market uncertainty and a variety of additional
factors that are beyond the control of the Company. These factors include the
level of consumer product demand, weather conditions, domestic and foreign
governmental regulations, the price and availability of alternative fuels,
political conditions in the Middle East, the foreign supply of oil and natural
gas, the price of foreign imports and overall economic conditions. The Company
is affected more by fluctuations in natural gas prices than oil prices, because
a majority of its production (92 percent during 1996 on a volumetric equivalent
basis) was natural gas. With the objective of reducing price risk, the Company
has entered into hedging and related price risk management transactions with
respect to a significant amount of its expected future production (see Note 6).

NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements for the year ended December 31, 1996
include the accounts of the Company and its wholly owned subsidiaries. The
Company's interests in the Moxa Arch investment programs (the 1992 Moxa Arch
Drilling Program, the 1993 Moxa Arch Drilling
F-23
<PAGE> 94
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Program and the Moxa Arch 1992 Offset Drilling Program) are accounted for using
the proportionate consolidation method of accounting for investments in oil and
gas property interests, whereby the Company's share of each program's assets,
liabilities, revenues and expenses is included in the appropriate accounts of
the consolidated financial statements. All material intercompany balances and
transactions have been eliminated.

For the years ended December 31, 1995 and 1994, the combined accounts are
prepared using the historical costs and results of operations of the combined
predecessor entities as if such entities had always been combined.

Property and Equipment

The Company follows the full-cost method of accounting for oil and gas
properties. Accordingly, all costs associated with acquisition, exploration and
development of oil and gas reserves, including directly related internal costs,
are capitalized. The Company capitalized $3,065,000, $1,181,000 and $127,000 of
internal costs during 1996, 1995 and 1994, respectively.

Oil and gas properties are amortized on the unit-of-production method using
estimates of proved reserve quantities. Investments in unproved properties are
not amortized until proved reserves associated with the projects can be
determined or until impairment occurs. The amortizable base includes estimated
future development costs and, where significant, dismantlement, restoration and
abandonment costs, net of estimated salvage values.

In addition, the capitalization costs of proved oil and gas properties are
subject to a "ceiling test," which limits such costs to the estimated present
value net of related tax effects, discounted at a 10 percent interest rate, of
future net cash flows from proved reserves, based on current economic and
operating conditions. If capitalized costs exceed this limit, the excess is
charged to depreciation, depletion and amortization.

Sales and other dispositions of proved and unproved properties are
accounted for as adjustments of capitalized costs with no gain or loss
recognized, unless significant reserves are involved. Abandonments of properties
are accounted for as adjustments of capitalized costs with no loss recognized.

Management Fees

The Company manages three investment Programs, which were formed during
1992-1994 to acquire and develop interests in certain drilling prospects. The
Company offered, to certain qualified investors, the opportunity to invest in
the prospects through participation in the Programs. In return for its
management activities on behalf of the Programs, the Company earns an annual
management fee of one percent of committed capital. After elimination of
management fees received from affiliated entities, including predecessor owners,
the Company earned management fees totaling $583,000, $602,000 and $763,000
during 1996, 1995 and 1994, respectively. Such management fees have been
credited to oil and gas property costs.

Capitalization of Interest

Interest costs related to the acquisition and development of unproved
properties are capitalized to oil and gas properties. Interest costs capitalized
for the years ended December 31, 1996 and 1995, totaled $434,000 and $911,000,
respectively. Interest costs for the year ended December 31, 1994, were not
significant.

F-24
<PAGE> 95
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Accounting for Commodity Price Risk Management Activities

The Company periodically engages in price risk management activities in
order to manage its exposure to oil and gas price volatility. Gains and losses
related to qualifying hedges of the Company's oil and gas production are
deferred and are recognized as revenues as the associated production occurs.

Estimates of future cash flows applicable to oil and gas commodity hedges
are reflected in future cash flows from proved reserves in the supplemental oil
and gas disclosures, with such estimates based on prices in effect as of the
date of the reserve report (See Note 13).

Transactions that do not qualify for hedge accounting are accounted for
using the mark-to-market method. Under such method, the financial instruments
are reflected at market value at the end of the period with resulting unrealized
gains and losses recorded as assets and liabilities in the consolidated
financial statements. Changes in the market value of outstanding financial
instruments are recognized as gain or loss in the period of change.

Revenue Recognition

Revenue from oil and gas sales is recorded on an accrual basis as title is
transferred with deliveries at the wellhead.

Gas Balancing

The Company uses the sales method to account for natural gas imbalances.
Under the sales method, the Company recognizes revenues based on the amount of
gas sold to purchasers, which may differ from the amounts to which the Company
is entitled based on its interests in the properties. However, revenue is
deferred and a liability is recorded for those properties where production sold
by the Company exceeds its entitled share of remaining natural gas reserves. Gas
balancing obligations as of December 31, 1996 and 1995 were not significant.
Additionally, gas imbalances are generally reflected as adjustments to reported
gas reserves and future cash flows in the supplemental oil and gas disclosures.

Income Taxes

The Company accounts for income taxes under the provisions of Statement of
Financial Accounting Standards (SFAS) No. 109 "Accounting for Income Taxes,"
which provides for an asset and liability approach for accounting for income
taxes. Under this approach, deferred tax assets and liabilities are recognized
based on anticipated future tax consequences, using currently enacted tax laws,
attributable to differences between financial statement carrying amounts of
assets and liabilities and their respective tax bases. Deferred tax assets are
reduced by a valuation allowance when, based upon management's estimate, it is
more likely than not that a portion of the deferred tax assets will not be
realized in a future period.

The earnings for the years ended December 31, 1995 and 1994 were not
subject to corporate income taxes as the Company was a combination of
nontaxpaying entities, including Subchapter S, limited liability corporations,
partnership and joint venture entities and individual interest. Accordingly,
earnings were directly taxable to the individual owners. The pro forma provision
for income tax is an estimate of the Company's income taxes that would have been
provided in accordance with SFAS No. 109, if the Company were a taxable entity
during the periods presented (See Note 5).

F-25
<PAGE> 96
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Stock-Based Compensation

The Company accounts for employee stock-based compensation using the
intrinsic value method prescribed by Accounting Principles Board (APB) Opinion
No. 25, "Accounting for Stock Issued to Employees." Accordingly, the adoption of
SFAS No. 123, "Accounting for Stock-Based Compensation" in 1996 had no effect on
the Company's results of operations.

Equity Distribution Payable

Undistributed production revenues for 1995, net of costs and expenses
through December 31, 1995 were estimated at $10.1 million for distribution to
the predecessor owners in 1996. This amount was accrued as an equity
distribution payable at December 31, 1995. Actual required distributions totaled
$13.5 million and were distributed in 1996.

Cash Equivalents

The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.

Pro Forma Net Income Per Share

Basic pro forma net income per share is based on the weighted average
number of shares of Common Stock outstanding. The computation assumes that the
Company was incorporated during the periods presented and presents the shares
issued in connection with the Combination as outstanding for all periods.
Diluted net income per share includes the effects of common stock equivalent
shares (stock options) and restricted stock.

Use of Estimates

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. Significant
estimates with regard to these financial statements include the estimated fair
value of oil and gas commodity price risk management contracts and the estimate
of proved oil and gas reserve volumes and the related discounted future net cash
flows therefrom (See Notes 6 and 13).

NOTE 3 -- DEBT

In December 1994, Belco Energy L.P. entered into a three-year revolving
credit facility with The Chase Manhattan Bank N.A. (the "Bank"). Semiannually,
the Bank will make a determination of the Company's borrowing base, determined
solely at the discretion of the Bank. The Company may request two additional
borrowing base redeterminations per annum. At December 31, 1996 the Credit
Facility was $30 million with a borrowing base of $15 million.

Principal outstanding, if any, is due and payable upon maturity in December
1997 with interest due quarterly. The terms of the agreement provide for
interest at rates ranging from the prime rate plus .25 percent to .375 percent,
or the Eurodollar Rate (ER) plus 1.75 percent to 1.875 percent. The applicable
margin over the prime rate or ER varies depending on the aggregate advances
outstanding as a percentage of the borrowing base. The unused portions of the
borrowing base are subject to a .25 percent commitment fee.

F-26
<PAGE> 97
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Covenants contained in the revolving credit agreement limit Belco Energy
L.P.'s ability to incur additional indebtedness, create liens on its assets and
prohibit speculative transactions in any commodities or futures market. Belco
Energy L.P. is also limited in its ability to make loans, investments or
guarantees and distributions of retained earnings. At December 31, 1996
restricted retained earnings totaled approximately $30 million. Additionally,
Belco Energy L.P. is required to maintain a minimum tangible net worth ($30
million) and certain ratios of leverage (not greater than 1.5:1) and interest
coverage (earnings before interest, taxes and depreciation, depletion and
amortization to interest expense of not less than 2.75:1). The Bank has the
ability in the event of default to perfect a security interest in certain of the
Company's properties.

The Company repaid all of its outstanding bank debt in March 1996 and as of
December 31, 1996, there was no outstanding balance. The credit facility remains
in effect to finance future obligations of the Company.

NOTE 4 -- RELATED PARTY TRANSACTIONS

The Company enters into a substantial portion of its Commodity Price Risk
Management Activities with Enron Capital & Trade Resources, a subsidiary of
Enron Corp. The Company's Chairman serves on the board of directors of Enron
Corp. These agreements were entered into in the ordinary course of business of
the Company and are on terms that the Company believes are no less favorable
than the terms of similar arrangements with third parties. Pursuant to the terms
of these agreements, (i) ECT has paid to the Company a net amount of
approximately $5,243,000 with respect to 1996, (ii) ECT has paid to the Company
a net amount of approximately $5,370,000 with respect to 1995 and (iii) the
Company paid to ECT a net amount of approximately $22,000 with respect to 1994.

The Company's executive offices are leased from its Chairman and $250,000
was paid under such lease in 1996. Lease expense for the Company's executive
offices for the period from inception through 1995 was paid by the Chairman,
with no reimbursement. The Company has recorded an office space and service
expense and a corresponding capital contribution of approximately $250,000 and
$200,000 for the periods ended December 31, 1995 and 1994, respectively, based
on an estimated allocation of space occupied. The Company's remaining commitment
related to the office space and service charge is $250,000 per year through
1999. Management believes the fee compares favorably to the terms which might
have been available from a non-affiliated party.

Additionally, from inception through March 31, 1996, the Company's Chairman
did not draw any compensation from the Company. The Company has recorded salary
and benefits expense and a corresponding capital contribution of $150,000 for
each of the periods ended December 31, 1995 and 1994, based on estimates of time
devoted to the Company and using expected 1996 compensation. In 1996, the
Chairman commenced receiving compensation.

Certain employees of the Company had an ownership interest in certain oil
and gas properties held by the Company as of December 31, 1995, and 1994. The
Company had receivables of $775,000, $834,000 and $126,000 as of December 31,
1996, 1995 and 1994, respectively, related to amounts loaned to employees in
connection with employee purchases of oil and gas interests. Such receivables
have been recorded as a reduction of equity in the consolidated balance sheets,
as such interests were exchanged for Common Stock in the Combination (see Note
1). The Company also had payables of $102,000 and $81,000 to the employees at
December 31, 1995 and 1994, respectively, related to revenues generated by the
properties in which the employees had such ownership interest.

F-27
<PAGE> 98
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In 1995, the Company engaged Midway Partners LLC (Midway) to serve as
advisor in connection with certain financial matters of the Company, including
the Combination and the potential initial public offering of the Company's
Common Stock. The Company's Senior Financial and Legal Advisor and General
Counsel is one of two managing partners and principals of Midway. In connection
with such engagement, the Company has paid Midway an advisory fee of $50,000. In
1996, upon consummation of the offering, the Company paid Midway an additional
$200,000.

NOTE 5 -- INCOME TAXES

Prior to March 29, 1996, the earnings of the Company were not subject to
corporate income taxes as the Company, prior to the Combination, was a
combination of non-taxpaying entities, including Subchapter S, limited liability
corporations, partnership and joint venture entities and individual interests.
Accordingly, taxable earnings were directly taxable to the individual owners
through the date of the Combination. As a result of the Combination consummated
on March 29, 1996, the Company became a taxpaying entity and recorded, in the
first quarter of 1996, a $30.1 million one-time, non-cash charge to earnings to
establish a deferred tax liability (discussed further below). The historical
provision for income taxes for the year ended December 31, 1996 includes the
one-time charge. The pro forma provision for income taxes reflected in the
Consolidated Statements of Operations for the years ended December 31, 1996,
1995 and 1994 has been presented to reflect the Company's income taxes under the
assumption that the Company was a taxpaying entity since its inception.

Although the effective date of the Exchange Agreement is January 1, 1996,
each owner of the Combined Assets will be required under existing federal income
tax rules and regulations to include in its taxable income, for all periods
ending on the date of or prior to the completion of the Combination (March 29,
1996), its allocable portion of the taxable income attributable to the Combined
Assets and will be entitled to all tax benefits related to the Combined Assets
through the completion of the Combination on March 29, 1996.

Total provision for income taxes consists of the following:

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, 1996
-----------------
(IN THOUSANDS)
<S> <C>
Payable currently:
Federal................................................... $ 6,345
State..................................................... 92
-------
6,437
-------
Deferred:................................................... 39,967
-------
Total provision for income taxes............................ $46,404
=======
</TABLE>

The differences between the statutory federal income taxes and the
Company's pro forma effective taxes is summarized as follows (in thousands):

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------
1996 1995 1994
------- ------- -------
<S> <C> <C> <C>
Statutory federal income taxes...................... $22,605 $14,906 $ 6,740
State income tax, net of federal benefit............ 80 115 50
Section 29 tax credits.............................. (947) (909) (1,530)
Other............................................... 215 (260) (230)
------- ------- -------
Pro forma provision for income taxes................ $21,953 $13,852 $ 5,030
======= ======= =======
</TABLE>

F-28
<PAGE> 99
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The principal components of the Company's net deferred income tax liability
at December 31, 1996 are as follows (in thousands):

<TABLE>
<CAPTION>
1996
-------
<S> <C>
Deferred income tax assets
Commodity price risk management activities................ $(1,494)
Other..................................................... (245)
-------
(1,739)
-------
Deferred income tax liabilities
Depreciation, depletion and amortization.................. 41,159
Other..................................................... 547
-------
41,706
-------
Net deferred income tax liability........................... $39,967
=======
</TABLE>

Section 29 Tax Credit

The basic credit, which is currently approximately $0.52 per MMBtu of
natural gas produced from tight sand reservoirs and approximately $1.03 per
MMBtu of natural gas produced from Devonian Shale, is computed by reference to
the price of crude oil and is phased out as the price of oil exceeds $23.50 in
1979 dollars (as adjusted for inflation) with complete phaseout if such price
exceeds $29.50 in 1979 dollars (as adjusted for inflation). Under this formula,
the commencement of phaseout would be triggered if the average price for crude
oil rose above approximately $45 per Bbl in current dollars. The Company
estimates that it generated approximately $0.9 million of Section 29 Tax Credits
in 1996. The Section 29 Tax Credit may not be credited against the alternative
minimum tax, but under certain circumstances may be carried over and applied
against regular tax liability in future years. Therefore, no assurances can be
given that the Company's Section 29 Tax Credits will reduce its federal income
tax liability in any particular year. As production from qualified wells
decline, the production based tax credit will also decline.

Texas Severance Tax Abatement

Production from natural gas wells that have been certified as tight
formations or deep wells by the Texas Railroad Commission ("high cost gas
wells") and that are spudded or completed during the period from June 16, 1989
to September 1, 1996 qualify for an exemption from the 7.5% severance tax in
Texas on natural gas and natural gas liquids produced by such wells prior to
August 31, 2001. The natural gas production from wells drilled on certain of the
Company's properties in the Austin Chalk area qualify for this tax reduction. In
addition, high cost gas wells that are spudded or completed during the period
from September 1, 1996 to August 31, 2002 are entitled to receive a severance
tax reduction upon obtaining a high cost gas certification from the Texas
Railroad Commission within 180 days after first production. The tax reduction is
based on a formula composed of the statewide "median" (as determined by the
State of Texas from producer reports) and the producer's actual drilling and
completion costs. More expensive wells will receive a greater

F-29
<PAGE> 100
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

amount of tax credit. This tax rate reduction remains in effect for 10 years or
until the aggregate tax credits received equal 50% of the total drilling and
completion costs. The reduction in severance taxes for such wells is reflected
as a reduction in oil and gas operating expenses and an increase in the
standardized measure of discounted future net cash flows relating to proved oil
and gas reserves (See Note 13).

NOTE 6 -- COMMODITY PRICE RISK MANAGEMENT ACTIVITIES AND FAIR VALUE OF FINANCIAL
INSTRUMENTS

Hedging Transactions

With the objective of achieving more predictable revenues and cash flows
and reducing the exposure to fluctuations in gas and oil prices, the Company has
entered into hedging transactions of various kinds with respect to both gas and
oil. While the use of these hedging arrangements limits the downside risk of
adverse price movements, it may also limit future revenues from favorable price
movements. As of December 31, 1996, the Company had entered into hedging
transactions with respect to a significant portion of its estimated production
for 1997 and to a lesser extent its estimated production for 1998 and 1999. The
Company continues to evaluate whether to enter into additional hedging
transactions for future years. In addition, the Company may determine from time
to time to terminate its then existing hedging positions if market conditions
warrant.

The following table and notes thereto cover the Company's pricing and notional
volumes on open natural gas and oil commodity hedges as of December 31, 1996:

<TABLE>
<CAPTION>
PRODUCTION PERIODS
------------------------------------
1997 1998 1999 TOTAL
------- ------- ------ -------
<S> <C> <C> <C> <C>
Gas
Price swaps -- receive fixed price (thousand
MMBtu)(1)(6)............................. 14,305 3,665 -- 17,970
Average price, per MMBtu................. $ 2.10 $ 2.01 -- $ 2.08
Collars and options (thousand MMBtu)(2)..... 8,350 9,885 -- 18,235
Average floor price, per MMBtu........... $ 2.05 $ 1.92 -- $ 1.98
Average ceiling price, per MMBtu......... $ 2.44 $ 2.16 -- $ 2.29
Price swaps -- pay fixed price (thousand
MMBtu)(3)................................ 8,777 1,070 -- 9,847
Average price, per MMBtu................. $ 2.20 $ 2.30 -- $ 2.21
Basis swaps (thousand MMBtu)(4)(5).......... 35,158 10,950 -- 46,108
Average basis differential, per MMBtu.... $ .20 $ .39 -- $ .25
Oil
Price swaps -- receive fixed price
(MBbls)(1)............................... 301 35 -- 336
Average price, per Bbl................... $ 18.49 $ 18.49 -- $ 18.49
Collars and options (MBbls)(2).............. 353 242 25 620
Average floor price, per Bbl............. $ 18.22 $ 17.21 $17.00 $ 17.78
Average ceiling price, per Bbl........... $ 21.16 $ 18.92 $18.50 $ 20.18
Price swaps -- pay fixed price (MBbls)(3)... 60 -- -- 60
Average price, per Bbl................... $ 21.70 -- -- $ 21.70
</TABLE>

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

(1) For any particular swap transaction, the counterpart is required to make a
payment to the Company in the event that the NYMEX Reference Price for any
settlement period is less than the swap price for such hedge, and the
Company is required to make a payment to the counterparty in the event that
the NYMEX Reference Price for any settlement period is greater than the swap
price for such hedge.

F-30
<PAGE> 101
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(2) For any particular collar transaction, the counterparty is required to make
a payment to the Company if the average NYMEX Reference Price for the
reference period is below the floor price for such transaction, and the
Company is required to make payment to the counterparty if the average NYMEX
Reference Price is above the ceiling price for such transaction.

(3) In order to close certain commodity price hedge positions, the Company
entered into various swap positions where the Company is the fixed-price
payer on the swap. In these transactions, the counterparty is required to
make a payment to the Company in the event that the NYMEX Reference Price
for any settlement period is greater than the swap price, and the Company is
required to make a payment to the counterparty in the event that the NYMEX
Reference Price for any settlement period is less than the swap price.

(4) Since most of the Company's gas is sold under spot contracts with reference
to Houston Ship Channel prices and substantially all of the Company's hedge
transactions are based on the NYMEX Reference Price, the Company has entered
into basis swaps that require the counterparty to make a payment to the
Company in the event that the average NYMEX Reference Price per MMBtu for a
reference period exceeds the average price per MMBtu for gas delivered at
the Houston Ship Channel for such reference period by a stated differential,
and requires the Company to make a payment to the counterparty in the event
that the NYMEX Reference Price exceeds the Houston Ship Channel price by
less than a stated differential (or in the event that the Houston Ship
Channel price exceeds the NYMEX Reference Price). The Company also sells its
Wyoming gas at prices based on the Northwest Pipeline Rocky Mountain Index
and has entered into basis swaps that require the counterparty to make a
payment to the Company in the event that the NYMEX Reference Price per MMBtu
for a reference period exceeds the Northwest Pipeline Rocky Mountain Index
Price by more than a stated differential and requires the Company to make a
payment to the counterparty in the event that the NYMEX Reference Price
exceeds the Northwest Pipeline Rocky Mountain Index Price by less than a
stated differential (or in the event that the Northwest Pipeline Rocky
Mountain Index Price is greater than the NYMEX Reference Price).

(5) Does not include 3,650 thousand MMBtu of basis swaps in 1997 that are
extendable at the election of the counterparty.

(6) Does not include 1,825 and 8,205 thousand MMBtu of swaps in 1997 and 1998,
respectively, that are extendable at the election of the counterparty.

All of the above transactions were carried out in the over-the-counter
market, and not on the NYMEX, with financial counterparties having at least an
investment grade credit rating. All of these transactions provide solely for
financial settlements related to closing prices on the NYMEX.

In 1995 and 1994, a realized hedging gain of $9.5 million and $550,000,
respectively, was included in Commodity Price Risk Management Revenues. At
December 31, 1995, the Company had net deferred losses of $145,000 for settled
derivative contracts and net deferred premium costs of $86,000, relative to
future production periods. The current portion of these amounts are included in
other current assets and the long term portion in other assets.

In 1996, a realized hedging loss of $83,000 was included in Commodity Price
Risk Management Revenues. At December 31, 1996, the Company had accrued
liabilities of $307,000 for settled derivative contracts and net deferred
premium costs of $465,000, relative to future production periods. These amounts
are included in Price Risk Management Activities as a current liability and
current asset, respectively.

Non-Hedging Transactions

As described in Note 2, the Company uses the mark-to-market method of
accounting for instruments that do not qualify for hedge accounting. The 1996
results of operations included an

F-31
<PAGE> 102
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

aggregate pre-tax loss of $5.9 million related to these activities which
included (1) net realized losses on settlements totaling $3.9 million, (2) net
premiums received totaling $7.4 million and (3) the unrealized loss resulting
from net change in the value of the Company's mark-to-market portfolio of price
risk management activities for the year ended December 31, 1996 of $9.4 million,
all included in Commodity Price Risk Management Revenues. As a result of the
increase in oil and natural gas prices which occurred in the fourth quarter, the
Company recorded a fourth quarter pre-tax loss of $8.4 million from Commodity
Price Risk Management Activities which included a $4.2 million ($2.77 million
net of tax) non-cash charge for unrealized losses related to mark-to-market
accounting requirements. At December 31, 1996, the Company's consolidated
balance sheet reflects $1.8 million and $11.2 million of price risk management
assets and liabilities, respectively, which includes primarily the
mark-to-market reserve. The Company had not entered into any financial
instruments that did not qualify for hedge accounting prior to 1996.

The following table and notes thereto cover the Company's pricing and
notional volumes on open natural gas and oil financial instruments at December
31, 1996, that do not qualify for hedge accounting:

<TABLE>
<CAPTION>
PRODUCTION PERIODS
-------------------------------------
1997 1998 1999 TOTAL
------- ------- ------- -------
<S> <C> <C> <C> <C>
Gas
Straddles (thousand MMBtu)(1)................ 1,825 -- -- 1,825
Average price, per MMBtu.................. $ 2.24 -- -- $ 2.24
Calls Sold (thousand MMBtu)(2)............... 11,260 10,950 -- 22,210
Average price, per MMBtu.................. $ 2.04 $ 2.27 -- $ 2.15
Puts Sold (thousand MMBtu)(2)................ 5,360 1,093 -- 6,453
Average price, per MMBtu.................. $ 1.98 $ 2.00 -- $ 1.98
Price swaps -- pay fixed price (thousand
MMBtu).................................... 5,430 -- -- 5,430
Average price, per MMBtu.................. $ 1.99 -- -- $ 1.99
Oil
Calls Sold (MBbls)(2)........................ 301 68 6 375
Average price, per Bbl.................... $ 22.41 $ 22.21 $ 22.00 $ 22.37
Puts Sold (MBbls)(2)......................... -- 60 -- 60
Average price, per Bbl.................... -- $ 19.75 -- $ 19.75
</TABLE>

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

(1) A straddle is a combination of a put sold and a call sold. The Company is
required to make a payment to the counterparty in the event that the NYMEX
Reference Price for any settlement period is greater than the ceiling price
or less than the floor price. The Company receives a significant premium
upon entering into such contract.

(2) Calls sold or puts sold under written option contracts, in return for a
significant premium received by the Company upon initiation of the contract,
the Company is required to make a payment to the counterparty in the event
that the NYMEX Reference Price for any settlement period is greater than the
price of the call sold, or less than the price of the put sold.

Fair Value of Financial Instruments

The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments at December 31, 1996 and 1995. SFAS No.
107 defines the fair value of a financial instrument as the amount at which the
instrument could be exchanged in a current transaction between willing parties.

F-32
<PAGE> 103
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

<TABLE>
<CAPTION>
DECEMBER 31, 1996 DECEMBER 31, 1995
------------------ -----------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ------- -------- ------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Cash and cash equivalents...................... $43,473 $43,473 $1,556 $1,556
Long-term bank debt............................ -- -- 22,000 22,000
Oil and gas commodity -- Hedges................ 158 (8,555) 231 9,200
-- Non-hedges............ (9,363) (9,363) -- --
</TABLE>

The following methods and assumptions were used to estimate the fair value
of the financial instruments summarized in the above table. The carrying values
of trade receivables and trade payables included in the accompanying
consolidated balance sheets approximated market value at December 31, 1996 and
1995.

Cash and Cash Equivalents

The carrying amounts approximate fair value because of the short maturity
of those instruments.

Long-Term Debt

The fair value of the Company's debt is assumed to be the same as the
carrying value because the interest rate is variable and is reflective of market
rates.

Oil and Gas Commodity Financial Instruments

The estimated fair value of oil and gas commodity financial instruments has
been determined by using available market data and applying certain valuation
methodologies. In some cases, quotes of termination values were available.
Judgment is necessarily required in interpreting market data, and the use of
different market assumptions or estimation methodologies could result in
different estimates of fair value.

NOTE 7 -- COMMITMENTS AND CONTINGENCIES

Future Contingencies Related to the Moxa Arch Programs

From 1992 to 1994, the Company established three Moxa Arch investment
programs: the 1992 Moxa Arch Drilling Program, the 1993 Moxa Arch Drilling
Program, and the Moxa Arch 1992 Offset Drilling Program. The Programs were
established to develop certain drilling prospects acquired as a result of a
farmout agreement with Amoco Production Company and others. The Company offered
certain qualified investors (the Investors) the opportunity to invest in the
prospects through participation in the Programs. The Programs have invested
$116.6 million in connection with the development of the Moxa Arch Trend of
Southwest Wyoming. Through October 30, 1996, the Company owned approximately
55.20 percent of the 1992 Moxa Arch Drilling Program, 32.45 percent of the 1993
Moxa Arch Drilling Program, and 58.21 percent of the Moxa Arch 1992 Offset
Drilling Program. On October 31, 1996 the Company purchased from certain third
party investors interests (the "Acquired Interests") in the Belco Oil & Gas
Corp. 1992, 1993 and 1992 Offset Moxa Arch Drilling Programs. The effective date
of the purchase was October 31, 1996 for financial reporting purposes. The
Acquired Interests represent incremental working interests in the Company's
natural gas wells in the Moxa Arch trend located in Lincoln, Sweetwater and
Uinta Counties, Wyoming. The Company paid aggregate cash consideration of $9.9
million plus an 80% participation in potential natural gas price increases (net
of incremental production costs) associated with

F-33
<PAGE> 104
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

production from the wells through July 31, 1999 (the "Price Participation
Right"). After the purchase, the Company's interest in these programs was
increased to 81.5% of the 1992 Moxa Arch Drilling Program, 74.0% of the 1993
Moxa Arch Drilling Program, and 80.5% of the Moxa Arch 1992 Offset Drilling
Program. The transaction was accounted for using the purchase method of
accounting.

The remaining third party investors in the Programs may "put" their
interest to Belco annually through 2003, based upon a valuation by a nationally
recognized independent petroleum engineering firm of the discounted net present
value of the future net revenues from production of proved reserves attributable
to the interests. The put amount is to be calculated based upon certain
specified parameters including prices, discount factors and reserve life. No
investor under the Programs exercised the put right in 1996. The Company is not
obligated to repurchase in any one calendar year more than 30% of the interests
originally acquired by the program investors (including, for purposes of this
calculation, the Company's interest). The Company's purchase price under the put
right has not been calculated given that no investors have exercised such right.
However, using reserve values presented in Note 13, Standardized Measure of
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (SEC
basis using year end prices and a 10% discount rate), the maximum purchase price
if all remaining investors exercised the put option would not be material to the
Company as of December 31, 1996.

Lease Commitments

At December 31, 1996, the Company had operating leases covering office
space. Minimum rental commitments under such operating leases are as follows (in
thousands):

<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31
-----------
<S> <C>
1997...................................................... $ 354
1998...................................................... 365
1999...................................................... 250
-----
Total............................................. $ 969
=====
</TABLE>

For the years ended December 31, 1996, 1995 and 1994, total rental expense
was approximately $329,000, $317,000 and $200,000, respectively.

Legal Proceedings

The Company is a named defendant in 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.

Environmental Matters

The Company's operations are subject to various federal, state and local
laws and regulations relating to the protection of the environment, which have
become increasingly stringent. The Company believes its current operations are
in material compliance with current environmental laws and regulations. There
are no environmental claims pending or, to the Company's knowledge, threatened
against the Company. There can be no assurance, however, that current regulatory
requirements will not change, currently unforeseen environmental incidents will
not occur or past noncompliance with environmental laws will not be discovered
on the Company's properties.

F-34
<PAGE> 105
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 8 -- CASH FLOW INFORMATION

The Company paid $4.0 million in income taxes during the 1996 period with
the remaining 1996 liability for such taxes due in the first quarter of 1997. No
income taxes were paid by the Company in 1995 and 1994 because the applicable
taxes were paid by the individual owners of the affiliated entities and
properties now included in the Company (See Note 5).

NOTE 9 -- CUSTOMER INFORMATION

Concentrations of Credit Risk

The Company's revenues are derived from uncollateralized sales to customers
in the oil and gas industry. The concentration of credit risk in a single
industry affects the Company's overall exposure. The Company has not experienced
significant credit losses on such sales.

Major Customers

Oil and gas sales for 1996 include $44.6 million, $37.7 million and $11.7
million in revenues received from three customers. Also, 1996 revenues included
net losses in the amount of $5.9 million related to Commodity Price Risk
Management Activities. Oil and gas sales for 1995 include $7.9 million, $21.1
million, $17.2 million and $14.0 million in revenues received from four
customers. Also, 1995 revenues include commodity price risk management gains
totaling $9.5 million. Oil and gas sales for 1994 include $15.1 million, $7.6
million, $4.9 million and $9.7 million in revenues received from four customers.
No other customers individually accounted for 10 percent or more of revenues.

NOTE 10 -- EMPLOYEE BENEFIT PLAN

Retirement Plan

The Company adopted a 401(k) and savings plan for its employees on January
1, 1995. The plan qualifies under Section 401(k) of the Internal Revenue Code as
a salary reduction plan. Under the plan, but subject to certain limitations
imposed under the Internal Revenue Code, eligible employees are permitted to (a)
defer receipt of up to 15 percent of their compensation on a pre-tax basis
(salary deferral contributions) or (b) contribute up to 10 percent of their
compensation to the plan on an after-tax basis. The plan provides for a Company
matching contribution in an amount equal to 50 percent of a participant's salary
deferral contributions that are not in excess of 6 percent of such participant's
compensation. The plan also permits the Company, in its sole discretion, to make
a contribution that is allocated on the last day of each calendar year to
certain eligible participants. Company matching and discretionary contributions
are vested over a period of five years at the rate of 20 percent per year.

During 1996 and 1995, the Company incurred $62,443 and $37,293,
respectively, in connection with this plan.

Performance Unit Plan

In 1996, Belco adopted a performance unit plan which is a long-term
incentive compensation plan to be administered by the Stock Option Committee of
the Board of Directors. All employees of the Company are eligible to receive an
award of performance units under the plan. A performance unit has a performance
period that is four consecutive calendar years beginning with and including the
calendar year in which the performance unit is granted. The value of a
performance unit will be determined based on the ranking of the Company's return
on Common Stock during an applicable performance period compared to the return
on the shares of Common Stock of certain companies
F-35
<PAGE> 106
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

with which the Company competes; however, the maximum value is $2.00 per unit.
While payments with respect to performance units will normally be made at the
end of the four year performance period, pro-rated payments may also be made at
an earlier time in the event a participant's employment with the Company is
involuntarily terminated without cause or is terminated by reason of retirement,
death or disability. Payments with respect to performance units will be made in
a single sum and may be made in cash, Common Stock or a combination thereof as
the Stock Option Committee in its sole discretion may determine. During 1996,
the Company granted 250,000 performance units. As of December 31, 1996 the
Company has made no cash payments in connection with this plan.

NOTE 11 -- CAPITAL STOCK

Exchange Agreement and Public Equity Offering

On March 29, 1996, the Exchange Agreement was consummated resulting in the
issuance of 25,000,000 shares to the Predecessor Owners (See Note 1). In
addition, on March 29, 1996, the Company completed its initial public offering
issuing 6,500,000 shares at $19 per share. Net proceeds totaled $113.1 million
after offering costs of $10.4 million.

Stock Incentive Plans

On March 25, 1996, the Company adopted a Stock Incentive Plan (the Plan)
under which options for shares of Belco's Common Stock may be granted to
officers and employees for up to 2,250,000 shares of Common Stock. Under the
Plan, options granted may either be incentive stock options or non-qualified
stock options with a maximum term of 10 years and are granted at no less than
the fair market of the stock at the date of grant. Options vest 20% per year
until fully vested five years from the date of grant.

A separate plan has been established under which options for shares of
Belco's Common Stock may be granted to non-employee directors for up to
approximately 158,000 shares of Common Stock. The plan provides that each
non-employee director be granted stock options for 3,000 shares annually as of
the date of the Annual Meeting. The option price of shares issued is equal to
the fair market value of the stock on the date of grant. All options vest 33
1/3% per year, beginning one year from date of grant, until fully vested and
expire ten years after the date of grant.

A summary of the status of the Company's plans (the Plans) as of December
31, 1996 and the changes during the year then ended is presented below:

<TABLE>
<CAPTION>
NUMBER OF WEIGHTED AVERAGE
OPTIONS EXERCISE PRICE
---------- ----------------
<S> <C> <C>
Outstanding at beginning of year........................ -- $ --
Granted............................................... 409,000 20.91
Exercised............................................. -- --
Forfeited............................................. (8,000) 20.09
Expired............................................... -- --
---------- ------
Outstanding at end of year.............................. 401,000 $20.91
========== ======
Exercisable at end of year.............................. -- $ --
========== ======
Available for grant at end of year...................... 1,929,700
==========
Weighted average fair value of options granted during
the year.............................................. $ 12.73
==========
</TABLE>

F-36
<PAGE> 107
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table summarizes information about stock options outstanding
at December 31, 1996:

<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------------------------------- -------------------------------
WEIGHTED
NUMBER AVERAGE WEIGHTED NUMBER WEIGHTED
OUTSTANDING AT REMAINING AVERAGE EXERCISABLE AT AVERAGE
RANGE OF PRICES 12/31/96 CONTRACTUAL LIFE EXERCISE PRICE 12/31/96 EXERCISE PRICE
--------------- -------------- ---------------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C>
$19.00.................... 310,000 9.25 $19.00 -- $--
$24.06-32.68.............. 91,000 9.56 27.40 -- --
------- ---
401,000 9.31 $20.91 -- $--
=======
</TABLE>

As permitted by SFAS No. 123, the Company applies APB Opinion No. 25 and
related Interpretations in accounting for its stock option plans. Accordingly,
no compensation expense has been recognized for the Plans. Had compensation
costs been determined based on the fair value at the grant dates consistent with
the method of SFAS No. 123, the Company's pro forma net income and pro forma
earnings per share would have been reduced to the pro forma amounts indicated
below (in thousands, except for per share amounts):

<TABLE>
<S> <C>
Pro Forma Net Income As Reported................................. $42,633
Pro Forma................................... 42,117
Pro Forma Basic and Diluted Earnings Per Share As Reported....... $ 1.42
Pro Forma......... $ 1.40
</TABLE>

The fair value of grants was estimated on the date of grant using the
Black-Scholes options pricing model with the following weighted average
assumptions used: risk-free interest rate of 6.74 percent, expected volatility
of 31.0 percent, expected lives of 7.5 years and no dividend yield. The pro
forma amounts shown above may not be representative of future results since this
is the first year for the Plans.

Under the Stock Incentive Plan, participants may be granted stock without
cost (restricted stock). During 1996, 77,300 shares of restricted stock were
issued under the Plan. The restrictions on disposition lapse 20% each year and
non vested shares must be forfeited in the event employment ceases. Unearned
compensation was charged for the market value of the restricted shares at the
date the shares were issued. The unearned compensation is shown as a reduction
of stockholders' equity in the accompanying consolidated balance sheet and is
being amortized ratably as the restrictions lapse. During 1996, $227,000 was
charged to expense relating to the Plan.

F-37
<PAGE> 108
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 12 -- SUPPLEMENTAL QUARTERLY FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE
AMOUNTS):

<TABLE>
<CAPTION>
QUARTERS
----------------------------------------
FIRST SECOND THIRD FOURTH
------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C>
1996
Revenues............................... $28,610 $31,555 $28,027 $28,204
======= ======= ======= =======
Costs and Expenses..................... $12,118 $12,837 $13,206 $13,649
======= ======= ======= =======
Pro Forma Net Income................... $11,066 $12,354 $ 9,782 $ 9,431
======= ======= ======= =======
Basic and Diluted Pro Forma Net Income
Per Share........................... $ 0.44 $ 0.39 $ 0.31 $ 0.30
======= ======= ======= =======
1995
Revenues............................... $15,701 $19,456 $20,728 $22,715
======= ======= ======= =======
Costs and Expenses..................... $ 7,070 $ 8,910 $ 9,015 $11,016
======= ======= ======= =======
Pro Forma Net Income................... $ 5,783 $ 7,066 $ 7,848 $ 8,040
======= ======= ======= =======
Basic and Diluted Pro Forma Net Income
Per Share........................... $ 0.23 $ 0.28 $ 0.31 $ 0.33
======= ======= ======= =======
</TABLE>

The sum of the individual quarterly pro forma net income per share amounts
may not agree with year to date pro forma net income per share as each period's
computation is based on the weighted average number of common shares outstanding
during that period.

NOTE 13 -- SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCING
ACTIVITIES (UNAUDITED):

Capitalized Costs

The following table sets forth the capitalized costs and related
accumulated depreciation, depletion and amortization relating to the Company's
oil and gas production, exploration and development activities as of December
31, 1996 and 1995 (in thousands):

<TABLE>
<CAPTION>
1996 1995
-------- --------
<S> <C> <C>
Proved properties........................................... $237,150 $152,081
Unproved properties......................................... 77,570 19,927
-------- --------
Total capitalized costs..................................... 314,720 172,008
Less accumulated depreciation, depletion and amortization... (86,490) (45,771)
-------- --------
Net capitalized costs....................................... $228,230 $126,237
======== ========
</TABLE>

Costs Not Being Amortized

The following table sets forth a summary of unproved oil and gas property
costs not being amortized at December 31, 1996, by the year in which such costs
were incurred (in thousands):

<TABLE>
<CAPTION>
1996 1995 1994 1993 TOTAL
------- ------- ------ ------ -------
<S> <C> <C> <C> <C> <C>
Leasehold and seismic................... $57,568 $10,491 $8,085 $1,426 $77,570
</TABLE>

F-38
<PAGE> 109
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Costs Incurred

The following table sets forth the costs incurred in oil and gas
acquisition, exploration and development activities as of December 31, 1996,
1995 and 1994 (in thousands):

<TABLE>
<CAPTION>
1996 1995 1994
-------- ------- -------
<S> <C> <C> <C>
Property acquisitions costs
Proved......................................... $ 9,871 $ -- $ --
Unproved....................................... 64,530 13,643 10,916
Exploration costs................................ 17,444 2,382 1,727
Development costs................................ 50,433 54,451 39,587
Capitalized interest............................. 434 911 --
-------- ------- -------
Total costs incurred................... $142,712 $71,387 $52,230
======== ======= =======
</TABLE>

Results of Operations for Oil and Gas Producing Activities

The following table sets forth revenue and direct cost information relating
to the Company's oil and gas exploration and production activities as of
December 31, 1996, 1995 and 1994 (in thousands):

<TABLE>
<CAPTION>
1996 1995 1994
-------- ------- -------
<S> <C> <C> <C>
Oil and gas revenues (including commodity price
risk management activities).................... $113,743 $78,247 $40,912
Costs and expenses
Lease operating expenses....................... 7,024 4,136 3,431
Production taxes............................... 823 1,688 2,079
Depreciation, depletion and amortization....... 40,904 27,590 14,072
-------- ------- -------
Results of operations from producing activities
before income taxes............................ 64,992 44,833 21,330
Pro forma provision for income taxes............. 22,095 14,638 5,756
-------- ------- -------
Pro forma results of operations from producing
activities..................................... $ 42,897 $30,195 $15,574
======== ======= =======
Amortization rate per Mcf equivalent,
recurring...................................... $ .73 $ .64 $ .65
======== ======= =======
</TABLE>

Oil and Gas Reserve Information

The following summarizes the policies used by the Company in preparing the
accompanying oil and gas reserves and the changes in such standardized measure
of discounted future net cash flows relating to proved oil and gas reserves and
the changes in such standardized measure from period to period.

Proved reserves are estimated quantities of crude oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods.

Proved oil and gas reserve quantities and the related discounted future net
cash flows (without giving effect to hedging activities) as of December 31, 1996
and 1995 are based on estimates prepared by Miller & Lents, independent
petroleum engineers. Such estimates have been prepared

F-39
<PAGE> 110
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

in accordance with guidelines established by the Securities and Exchange
Commission (SEC). Reserve estimates for periods prior to December 31, 1995 were
not prepared by an independent petroleum engineer. While reserve reports for
years ended prior to December 31, 1995 were not prepared contemporaneously, they
have been prepared by an in-house engineer on a basis generally consistent with
the Miller & Lents report. The Company used the December 31, 1995 Miller & Lents
estimates as an initial basis and adjusted such data for actual production and
extensions, discoveries and other additions in 1994 to determine the relevant
data for each of these periods. The Company also calculated the reserve
economics at the end of 1994 using oil and gas prices in effect as of the end of
the year.

The standardized measure of discounted future net cash flows from
production of proved reserves was developed by first estimating the quantities
of proved reserves and the future periods during which they are expected to be
produced based on year-end economic conditions. The estimated future cash flows
from proved reserves were then determined based on year-end prices, except in
those instances where fixed contracts provide for a higher or lower amount.
Estimates of future cash flows applicable to oil and gas commodity hedges have
been prepared by the Company and are reflected in future cash flows from proved
reserves with such estimates based on prices in effect as of the date of the
reserve report. Additionally, future cash flows were reduced by estimated
production costs, costs to develop and produce the proved reserves, and when
significant, certain abandonment costs, all based on year-end economic
conditions. Future net cash flows have been discounted by 10 percent in
accordance with SEC guidelines.

The standardized measure of discounted future net cash flows does not
purport, nor should it be interpreted, to present the fair value of the
Company's oil and gas reserves. An estimate of fair value would also take into
account, among other things, the recovery of reserves not presently classified
as proved, anticipated future changes in prices and costs and a discount factor
more representative of the time value of money and the risks inherent in reserve
estimates.

Under SEC rules, companies that follow full cost-accounting methods are
required to make quarterly "ceiling test" calculations. Under this test, proved
oil and gas property costs may not exceed the present value of estimated future
net revenues from proved reserves, discounted at 10 percent, as adjusted for
related tax effects and deferred tax reserves. Application of these rules during
periods of relatively low oil and gas prices, even if of short-term duration,
may result in write-downs.

F-40
<PAGE> 111
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES
(IN THOUSANDS)

<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------
1996 1995 1994
---------- -------- --------
<S> <C> <C> <C>
Future cash inflows(2).................................. $1,071,550 $427,213 $244,782
Future production costs................................. (253,159) (96,643) (55,364)
Future development costs................................ (71,061) (36,003) (8,655)
---------- -------- --------
Future net inflows before income taxes(2)............... 747,330 294,567 180,763
Discount at 10% annual rate............................. (331,800) (88,058) (70,978)
Discounted future net cash flows before income
taxes.............................................. 415,530 206,509 109,785
Pro forma discounted future income taxes(1)............. (134,957) (58,000) (29,000)
---------- -------- --------
Standardized measure of discounted future net cash
flows................................................. $ 280,573 $148,509 $ 80,785
========== ======== ========
</TABLE>

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

(1) The earnings of the Company were not subject to corporate income taxes prior
to March 29, 1996 as the Company was a combination of nontaxpaying entities.
Concurrent with the Exchange Agreement (see Note 1), the Company became a
taxable corporation. The estimated pro forma income taxes as of December 31,
1995 and 1994, discounted at 10%, have been presented assuming the Company
was a taxable entity for all periods.

(2) Oil and gas commodity hedges included in future cash inflows totaled ($60.8)
million, $7.6 million and $14.0 million at December 31, 1996, 1995 and 1994,
respectively, and such hedges included in discounted future net cash flows
before income taxes totaled ($55.2) million, $7.2 million and $12.4 million
at December 31, 1996, 1995 and 1994, respectively.

F-41
<PAGE> 112
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CHANGES IN STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Balance, Beginning of year............................... $148,509 $ 80,785 $ 61,108
Sales and transfers of oil and gas produced, net of
production costs....................................... (111,780) (72,423) (35,402)
Net change in sales price and production costs........... 145,133 11,390 (11,205)
Extensions and discoveries............................... 153,920 104,549 38,812
Purchases of minerals in place........................... 7,843 -- --
Changes in estimated future development costs............ 24,618 8,655 835
Revisions in quantities.................................. 50,309 -- --
Accretion of discount.................................... 20,651 10,979 8,511
Other, principally revisions in estimates of timing of
production............................................. (81,673) 33,574 23,126
Change in income taxes................................... (76,957) (29,000) (5,000)
-------- -------- --------
Balance, End of year..................................... $280,573 $148,509 $ 80,785
======== ======== ========
</TABLE>

F-42
<PAGE> 113
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

RESERVE QUANTITY INFORMATION

PROVED RESERVES

<TABLE>
<CAPTION>
OIL GAS
(MBBLS) (MMCF)
------- -------
<S> <C> <C>
Balance at December 31, 1993................................ 963 86,854
Purchases of minerals in place............................ -- --
Extensions, discoveries and other additions............... 1,657 45,283
Revisions of previous estimates........................... -- --
Sales of minerals in place................................ -- --
Production................................................ (691) (17,482)
----- -------
Balance at December 31, 1994................................ 1,929 114,655
Purchases of minerals in place............................ -- --
Extensions, discoveries and other additions............... 1,484 126,562
Revisions of previous estimates........................... -- --
Sales of minerals in place................................ -- --
Production................................................ (961) (37,047)
----- -------
Balance at December 31, 1995................................ 2,452 204,170
Purchases of minerals in place............................ 162 21,993
Extensions, discoveries and other additions............... 1,411 87,319
Revisions of previous estimates........................... 96 22,799
Sales of minerals in place................................ -- --
Production................................................ (794) (51,289)
----- -------
Balance at December 31, 1996................................ 3,327 284,992
===== =======
Proved Developed Reserves
December 31, 1993........................................... 938 86,223
December 31, 1994........................................... 1,793 100,113
December 31, 1995........................................... 1,838 140,725
December 31, 1996........................................... 2,070 184,904
</TABLE>

F-43
<PAGE> 114

UNDERWRITING

Subject to the terms and conditions set forth in the Underwriting
Agreement, the Company has agreed to sell to each of the Underwriters named
below, and each of such Underwriters has severally agreed to purchase from the
Company, the respective number of shares of Preferred Stock set forth opposite
its name below:

<TABLE>
<CAPTION>
NUMBER OF
SHARES OF
UNDERWRITER PREFERRED STOCK
----------- ---------------
<S> <C>
Goldman, Sachs & Co. ....................................... 1,520,000
Smith Barney Inc............................................ 1,520,000
Howard, Weil, Labouisse, Friedrichs Incorporated............ 760,000
----------
Total............................................. 3,800,000
==========
</TABLE>

Under the terms and conditions of the Underwriting Agreement, the
Underwriters are committed to take and pay for all of the shares offered hereby,
if any are taken.

The Underwriters propose to offer the shares of Preferred Stock in part
directly to the public at the initial public offering price set forth on the
cover page of this Prospectus Supplement, and in part to certain securities
dealers at such price less a concession of $.5625 per share. The Underwriters
may allow, and such dealers may reallow, a concession not in excess of $.10 per
share to certain brokers and dealers. After the shares of Common Stock are
released for sale to the public, the offering price and other selling terms may
from time to time be varied by the Underwriters.

In connection with the Offering, the Underwriters may purchase and sell the
Preferred Stock or Common Stock in the open market. These transactions may
include over-allotment and stabilizing transactions and purchases to cover short
positions created by the Underwriters in connection with the offering.
Stabilizing transactions consist of certain bids or purchases for the purpose of
preventing or retarding a decline in the market price of the Preferred Stock or
Common Stock and short positions created by the Underwriters involve the sale by
the Underwriters of a greater number of shares of Preferred Stock than they are
required to purchase from the Company in the offering. The Underwriters also may
impose a penalty bid, whereby selling concessions allowed to other
broker-dealers in respect of the securities sold in the offering for their
account may be reclaimed by the Underwriters if such shares of Preferred Stock
are repurchased by the Underwriters in stabilizing or covering transactions.
These activities may stabilize, maintain or otherwise affect the market price of
the Preferred Stock or Common Stock, which may be higher than the price that
might otherwise prevail in the open market; and these activities, if commenced,
may be discontinued at any time. These transactions may be effected on the NYSE,
in the over-the-counter market or otherwise.

Prior to this offering of the Preferred Stock, there has been no public
market for the Preferred Stock. The Preferred Stock has been approved for
listing on the New York Stock Exchange, subject to official notice of issuance.
Certain of the Underwriters have indicated that they currently intend to make a
market in the Preferred Stock; however, they are not obligated to do so and any
market making with respect to the Preferred Stock may be discontinued at any
time without notice.

The Company has granted to the Underwriters an option exercisable for 30
days after the date of this Prospectus Supplement to purchase up to an aggregate
of 570,000 additional shares of Preferred Stock solely to cover over-allotments,
if any. If the Underwriters exercise their over-allotment option, the
Underwriters have severally agreed, subject to certain conditions, to purchase
approximately the same percentage thereof that the number of shares to be
purchased by each of them, as shown in the foregoing table, bears to the
3,800,000 shares of Preferred Stock offered. In addition, Robert A. Belfer, the
Company's Chairman and Chief Executive Officer, and members of his family have
agreed to purchase 600,000 shares of Preferred Stock in the Offering. The
Underwriters and the Company have agreed that the selling concession of $337,500
relating to the

U-1
<PAGE> 115

shares of Preferred Stock sold to Mr. Belfer and his family will be reimbursed
to the Company, thereby increasing the Company's proceeds from the Offering by
such amount.

The Company and its executive officers and directors have agreed not to
offer to sell, sell, grant any option to purchase or otherwise dispose of any
shares of any capital stock of the Company (or securities convertible into, or
exchange for capital stock of the Company), directly or indirectly, for a period
of 90 days after the date of this Prospectus Supplement, without the prior
written consent of Goldman, Sachs & Co., except for (i) grants of stock options
by the Company to its officers, directors and employees and issuance of stock
upon exercise of options held by such persons, (ii) shares of capital stock
issued by the Company in connection with the acquisition of assets or capital
stock of any company engaged in the oil and gas business and (iii) shares of
Common Stock of the Company issuable upon exercise of warrants granted in
connection with the acquisition of Coda by the Company.

Certain of the Underwriters have performed investment banking services for
the Company for which they received customary compensation.

The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act.

U-2
<PAGE> 116

PROSPECTUS

BELCO OIL & GAS CORP.

DEBT SECURITIES
PREFERRED STOCK
COMMON STOCK
---------------------
Belco Oil & Gas Corp. ("Belco" or the "Company") may offer and sell from
time to time, (i) unsecured debt securities, in one or more series, consisting
of notes, debentures or other evidences of indebtedness (the "Debt Securities"),
(ii) shares of preferred stock, par value $.01 per share, in one or more series
(the "Preferred Stock"), and (iii) shares of common stock, par value $.01 per
share (the "Common Stock"). The Company may offer and sell up to $500,000,000
aggregate public offering price of Debt Securities, Preferred Stock and Common
Stock (collectively, the "Securities").

The specific terms of the particular Securities to be issued will be set
forth in a supplement to this Prospectus (a "Prospectus Supplement"), which will
be delivered together with this Prospectus, including, where applicable, (i) in
the case of Debt Securities, the specific designation, aggregate principal
amount, ranking as senior or subordinated Debt Securities, currency of payment,
maturity, rate or rates (or method of determining the same) and time or times
for the payment of interest, if any, any exchangeability or conversion terms or
any terms for optional or mandatory redemption or repurchase, or payment of
additional amounts or any sinking fund provisions and any other specific terms
of such Debt Securities, will be set forth in the Prospectus Supplement, (ii) in
the case of Preferred Stock, the specific designation, number of shares and
liquidation value thereof and the dividend, liquidation, redemption, voting and
other rights, including conversion or exchange rights, if any, and any other
special terms, and (iii) in the case of Common Stock, the number of shares. The
Prospectus Supplement will also contain information regarding the initial public
offering price, the net proceeds to the Company and, where applicable, the
United States Federal income tax considerations relating to the Securities
covered by the Prospectus Supplement.

The Securities may be sold directly by the Company to investors, through
agents designated from time to time or to or through underwriters or dealers.
See "Plan of Distribution." If any agents of the Company or any underwriters are
involved in the sale of any Securities in respect of which the Prospectus is
being delivered, the names of such agents or underwriters and any applicable
commissions or discounts will be set forth in the Prospectus Supplement.
---------------------
The Common Stock is traded on the New York Stock Exchange under the symbol
"BOG." Any Common Stock sold pursuant to a Prospectus Supplement will be listed
on such exchange, subject to official notice of issuance.
---------------------
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.
---------------------
This Prospectus may not be used to consummate sales of the Securities
unless accompanied by a Prospectus Supplement.

THE DATE OF THIS PROSPECTUS IS DECEMBER 24, 1997.
<PAGE> 117

NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY
REPRESENTATION IN CONNECTION WITH THIS OFFERING OTHER THAN THOSE CONTAINED OR
INCORPORATED BY REFERENCE IN THIS PROSPECTUS OR AN APPLICABLE PROSPECTUS
SUPPLEMENT AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT
BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY UNDERWRITER,
DEALER OR AGENT. THIS PROSPECTUS AND ANY APPLICABLE PROSPECTUS SUPPLEMENT DO NOT
CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY SECURITIES
OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE
SUCH OFFER OR SOLICITATION IN SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS
PROSPECTUS OR ANY PROSPECTUS SUPPLEMENT 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 DATE HEREOF OR THEREOF.

IN CONNECTION WITH THIS OFFERING, UNDERWRITERS, IF ANY, MAY OVER-ALLOT OR
EFFECT THE TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICES OF THE
OFFERED SECURITIES AT LEVELS ABOVE THOSE WHICH MIGHT OTHERWISE PREVAIL IN THE
OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE,
IN THE OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH STABILIZATION, IF COMMENCED,
MAY BE DISCONTINUED AT ANY TIME.

AVAILABLE INFORMATION

The Company is subject to the information requirements of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"), and in accordance
therewith files reports, proxy statements and other information with the
Securities and Exchange Commission (the "Commission"). Such reports, proxy
statements, and other information filed by the Company with the Commission can
be inspected and copied at the public reference facilities maintained by the
Commission at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington,
D.C. 20549 and at the following Regional Offices of the Commission: Chicago
Regional Office, Citicorp Center, 500 West Madison Street, Suite 1400, Chicago,
Illinois 60661 and New York Regional Office, Seven World Trade Center, New York,
New York 10048. Copies of such material can be obtained from the Public
Reference Section of the Commission at 450 Fifth Street, N.W., Washington, D.C.
20549, at prescribed rates. The Commission maintains a World Wide Web site on
the Internet at http://www.sec.gov that contains reports, proxy and information
statements and other information regarding registrants that file electronically
with the Commission. In addition, reports, proxy statements and other
information concerning the Company can be inspected at the New York Stock
Exchange, 20 Broad Street, New York, New York 10005, on which exchange the
Common Stock is listed.

This Prospectus constitutes a part of a Registration Statement on Form S-3
(together with all amendments and exhibits thereto, the "Registration
Statement") filed by the Company with the Commission under the Securities Act of
1933, as amended (the "Securities Act"). This Prospectus omits certain of the
information contained in the Registration Statement in accordance with the rules
and regulations of the Commission. Reference is hereby made to the Registration
Statement and exhibits thereto for further information with respect to the
Company and the securities offered hereby. Any statements contained herein
concerning the provisions of any document filed as an exhibit to the
Registration Statement or otherwise filed with the Commission are not
necessarily complete, and in each instance reference is made to the copy of such
document so filed. Each such statement is qualified in its entirety by such
reference.

2
<PAGE> 118

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

The following documents filed by the Company with the Commission under the
Exchange Act (File No. 1-12634) are incorporated by reference in this
Prospectus:

(a) the Company's Annual Report on Form 10-K for the year ended
December 31, 1996;

(b) the Company's Quarterly Reports on Form 10-Q for the quarters
ended March 31, 1997, June 30, 1997 and September 30, 1997;

(d) the description of the Common Stock contained in the Registration
Statement on Form 8-A.

All documents filed by the Company pursuant to Section 13(a), 13(c), 14 or
15(d) of the Exchange Act subsequent to the date of this Prospectus and prior to
the termination of the offering of the Securities pursuant hereto shall be
deemed to be incorporated by reference herein and to be a part hereof from the
date of filing of such document. Any statement contained herein or in a document
incorporated or deemed to be incorporated by reference herein shall be deemed to
be modified or superseded for purposes of this Prospectus to the extent that a
statement contained herein or in any other subsequently filed document which
also is or is deemed to be incorporated by reference 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 provide without charge to each person to whom this
Prospectus is delivered, upon written or oral request of such person, a copy of
any or all of the documents that are incorporated by reference in this
Prospectus (other than exhibits to such documents, unless such exhibits are
specifically incorporated by reference into such documents). Requests should be
directed to the Secretary, Belco Oil & Gas Corp., 767 Fifth Avenue, 46th Floor,
New York, New York 10153, telephone number (212) 644-2200.

THE COMPANY

Belco Oil & Gas Corp. is an independent energy company engaged in the
exploration for and the acquisition, exploitation, development and production of
natural gas and oil properties primarily in the Rocky Mountains, Texas,
Oklahoma, Louisiana and Michigan.

The principal executive offices of Belco are located at 767 Fifth Avenue,
46th Floor, New York, New York 10153, and its telephone number is (212)
644-2200. The "Company" and "Belco" refer to Belco Oil & Gas Corp. and its
subsidiaries and predecessors, unless otherwise indicated or the context
requires otherwise.

USE OF PROCEEDS

Except as may otherwise be described in the Prospectus Supplement relating
to an offering of Securities, the net proceeds from the sale of the Securities
offered pursuant to this Prospectus and such Prospectus Supplement will be used
for general corporate purposes, which may include the repayment of existing
indebtedness and the financing of capital expenditures and acquisitions. Any
specific allocation of the net proceeds of an offering of Securities by the
Company to a specific purpose will be determined at the time of such offering
and will be described in the related Prospectus Supplement.

3
<PAGE> 119

RATIOS OF EARNINGS TO FIXED CHARGES AND EARNINGS
TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

A description of the Company's ratio of earnings to fixed charges or
earnings to combined fixed charges and preferred stock dividends, as applicable,
on a consolidated basis, will appear in an applicable Prospectus Supplement.

DESCRIPTION OF DEBT SECURITIES

The Debt Securities will constitute either senior debt of the Company
("Senior Debt Securities"), or subordinated debt of the Company ("Subordinated
Debt Securities"). Debt Securities may be issued from time to time under one or
more indentures, each dated as of a date on or prior to the issuance of the Debt
Securities to which it relates. Senior Debt Securities and Subordinated Debt
Securities may be issued pursuant to separate indentures (respectively, a
"Senior Debt Indenture" and a "Subordinated Debt Indenture"), in each case
between the Company and a trustee (a "Trustee"), which may be the same Trustee,
and in the form that has been filed as an exhibit to the Registration Statement
of which this Prospectus is a part, subject to such amendments or supplements as
may be adopted from time to time. The Senior Debt Indenture and the Subordinated
Debt Indenture are sometimes hereinafter referred to individually as an
"Indenture" and collectively as the "Indentures." The Indentures will be subject
to, and will be governed by, the Trust Indenture Act of 1939, as amended. The
following summaries of provisions of the Indentures and the Debt Securities do
not purport to be complete and such summaries are subject to the detailed
provisions of the applicable Indenture to which reference is hereby made for a
full description of such provisions, including the definition of certain terms
used herein. Wherever particular sections or defined terms of the applicable
Indenture are referred to, such sections or defined terms are incorporated
herein by reference as part of the statement made, and the statement is
qualified in its entirety by such reference. The Indentures are substantially
identical, except for certain covenants of the Company and provisions relating
to subordination and conversion.

The Debt Securities may be issued from time to time in one or more series.
The following description of the Debt Securities sets forth certain general
terms and provisions of the Debt Securities of all series. The particular terms
of each series of Debt Securities offered by any Prospectus Supplement (the
"Offered Debt Securities") will be described therein.

PROVISIONS APPLICABLE TO BOTH SENIOR AND SUBORDINATED DEBT SECURITIES

General. The Debt Securities will be unsecured senior or subordinated
obligations of the Company and may be issued from time to time in one or more
series. Unless otherwise indicated in an applicable Prospectus Supplement, the
Indentures do not limit the amount of Debt Securities, debentures, notes or
other types of indebtedness that may be issued by the Company or any of its
subsidiaries nor do they restrict transactions between the Company and its
affiliates or the payment of dividends or other distributions by the Company to
its stockholders. In addition, other than as may be set forth in any Prospectus
Supplement, the Indentures do not and the Debt Securities will not contain any
covenants or other provisions that are intended to afford holders of the Debt
Securities special protection in the event of either a change of control of the
Company or a highly leveraged transaction by the Company.

The rights of the Company's creditors, including holders of Debt
Securities, will be limited to the assets of the Company and will not be an
obligation of any of its subsidiaries. The operations of the Company are
currently conducted almost entirely through subsidiaries. Accordingly, the
Company's cash flow and its consequent ability to service debt, including the
Debt Securities, are dependent, in large part, upon the earnings of its
subsidiaries and the distribution of those earnings to the Company, whether by
dividends, loans or otherwise. The payment of dividends and the making of loans
and advances to the Company by its subsidiaries may be subject to statutory or
contractual
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restrictions, are contingent upon the earnings of those subsidiaries and are
subject to various business considerations. Any right of the Company to receive
assets of any of its subsidiaries upon their liquidation or reorganization (and
the consequent right of the holders of the Debt Securities to participate in
those assets) will be effectively subordinated to the claims of that
subsidiary's creditors (including trade creditors and tort claimants), except to
the extent that the Company is itself recognized as a creditor of such
subsidiary, in which case the claims of the Company would still be subordinate
to any security interests in the assets of such subsidiary and any indebtedness
of such subsidiary senior to that held by the Company.

Reference is made to the Prospectus Supplement for the following terms of
and information relating to the Offered Debt Securities (to the extent such
terms are applicable to such Offered Debt Securities): (i) the title of the
Offered Debt Securities; (ii) classification as either Senior Debt Securities or
Subordinated Debt Securities and any other terms or provisions of the Offered
Debt Securities affecting the ranking or priority of the Offered Debt
Securities; (iii) whether the Offered Debt Securities that constitute
Subordinated Debt Securities are convertible into Common Stock and, if so, the
terms and conditions upon which such conversion will be effected including the
initial conversion price and any adjustments thereto in addition to or different
from those described herein, the conversion period and other conversion
provisions in addition to or in lieu of those described herein; (iv) any limit
on the aggregate principal amount of the Offered Debt Securities; (v) whether
any of the Offered Debt Securities are to be issuable in global form; (vi) the
price or prices (expressed as a percentage of the aggregate principal amount
thereof) at which the Offered Debt Securities will be issued; (vii) the date or
dates on which the principal of the Offered Debt Securities is payable; (viii)
the rate or rates per annum (or the method by which such will be determined) at
which the Offered Debt Securities will bear interest, if any, the date or dates
from which any such interest will accrue, on which interest shall be payable and
on which a record shall be taken for the determination of holders of Offered
Debt Securities to whom such interest is payable or the method by which such
rate or rates or date or dates shall be determined or both; (ix) any mandatory
or optional sinking fund or analogous provisions; (x) each office or agency
where, subject to the terms of the Indentures, the principal of and any premium
and interest on the Offered Debt Securities will be payable and each office or
agency where, subject to the terms of the Indentures, the Offered Debt
Securities may be presented for registration of transfer or exchange; (xi) the
right, if any, or obligation, if any, of the Company to redeem the Offered Debt
Securities and the period or periods, if any, within which and the price or
prices at which the Offered Debt Securities may, pursuant to any optional or
mandatory redemption provisions, be redeemed, in whole or in part, and the other
detailed terms and provisions of any such optional or mandatory redemption;
(xii) the denominations in which any Offered Debt Securities will be issuable,
if other than denominations of $1,000 and any integral multiple thereof; (xiii)
the currency or currencies (including composite currencies) in which payment of
principal of and any premium and interest on the Offered Debt Securities is
payable if other than United States dollars; (xiv) if the amount of payments of
principal of and any premium and interest on the Offered Debt Securities are to
be determined with reference to an index, the manner in which such amounts are
to be determined; (xv) information with respect to book-entry procedures, if
any; (xvi) any deletions from, modification of or additions to the Events of
Default or covenants of the Company with respect to such Offered Debt
Securities; and (xvii) any other terms of the Offered Debt Securities not
inconsistent with the provisions of the Indentures. Any such Prospectus
Supplement will also describe any special provisions for the payment of
additional amounts with respect to the Offered Debt Securities.

Debt Securities may be issued as Original Issue Discount Securities. An
Original Issue Discount Security is a Debt Security, including any zero-coupon
security, which is issued at a price lower than the amount payable upon the
Stated Maturity thereof and which provides that upon redemption or acceleration
of the maturity thereof an amount less than the amount payable upon the Stated
Maturity thereof and determined in accordance with the terms of such Debt
Security shall become due and payable. Special United States federal income tax
considerations applicable to Debt Securities issued at an original issue
discount, including Original Issue Discount Securities, and
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special United States tax considerations and other terms and restrictions
applicable to any Debt Securities which are offered exclusively to United States
Aliens or denominated in other than United States dollars, will be set forth in
a Prospectus Supplement relating thereto.

Global Securities. The Debt Securities of a series may be issued in whole
or in part in the form of one or more global securities ("Global Securities")
that will be deposited with, or on behalf of, a depositary (the "Depositary")
identified in the Prospectus Supplement relating to such series. Global
Securities may be issued only in fully registered form and in either temporary
or permanent form. Unless and until it is exchanged in whole or in part for the
individual Debt Securities represented thereby, a Global Security (i) may not be
transferred except as a whole and (ii) may only be transferred (A) by the
Depositary for such Global Security to its nominee, (B) by a nominee of such
Depositary to such Depositary or another nominee of such Depositary or (C) by
such Depositary or any such nominee to a successor Depositary or nominee of such
successor Depositary (Section 2.8).

The specific terms of the depositary arrangement with respect to a series
of Debt Securities will be described in the Prospectus Supplement relating to
such series. The Company anticipates that the following provisions will
generally apply to depositary arrangements.

Upon the issuance of a Global Security, the Depositary for such Global
Security or its nominee will credit, on its book-entry registration and transfer
system, the respective principal amounts of the individual Debt Securities
represented by such Global Security to the accounts of persons that have
accounts with such Depositary. Such accounts shall be designated by the dealers,
underwriters or agents with respect to such Debt Securities or by the Company if
such Debt Securities are offered and sold directly by the Company. Ownership of
beneficial interests in a Global Security will be limited to persons that have
accounts with the applicable Depositary ("participants") or persons that may
hold interests through participants. Ownership of beneficial interests in such
Global Security will be shown on, and the transfer of that ownership will be
effected only through, records maintained by the applicable Depositary or its
nominee (with respect to interests of participants) and the records of
participants (with respect to interests of persons other than participants). The
laws of some states require that certain purchasers of securities take physical
delivery of such securities in definitive form. Such limits and such laws may
impair the ability to transfer beneficial interests in a Global Security.

So long as the Depositary for a Global Security or its nominee is the
registered owner of such Global Security, such Depositary or its nominee, as the
case may be, will be considered the sole owner or holder of the Debt Securities
of the series represented by such Global Security for all purposes under the
Indenture governing such Debt Securities. Except as provided below, owners of
beneficial interests in a Global Security will not be entitled to have any of
the individual Debt Securities of the series by such Global Security registered
in their names, will not receive or be entitled to receive physical delivery of
any such Debt Securities in definitive form and will not be considered the
owners or holders thereof under the Indenture governing such Debt Securities.

Payment of principal of, premium, if any, and interest, if any, on
individual Debt Securities represented by a Global Security registered in the
name of a Depositary or its nominee will be made to the Depositary or its
nominee, as the case may be, as the registered owner of the Global Security
representing such Debt Securities. The Company expects that the Depositary for a
series of Debt Securities or its nominee, upon receipt of any payment of
principal of, premium, if any, and interest, if any, in respect of a Global
Security representing any such Debt Securities, immediately will credit
participants' accounts with payments in amounts proportionate to their
respective beneficial interests, if any, and interest, if any, in respect of a
Global Security representing any such Debt Securities, immediately will credit
participants' accounts with payments in amounts proportionate to their
respective beneficial interests in the principal amount of such Global Security
for such Debt Securities as shown on the records of such Depositary or its
nominee. The Company also expects that payments by participants to owners of
beneficial interests in such Global Security held through

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such participants will be governed by standing instructions and customary
practices, as is now the case with securities held for the accounts of customers
in bearer form or registered in "street name." Such payments will be the
responsibility of such participants. Neither the Company, the Trustee for such
Debt Securities, any paying agent nor the registrar for such Debt Securities
will have any responsibility or liability for any aspect of the records relating
to or payments made on account of beneficial ownership interests of the Global
Security for such Debt Securities or for maintaining, supervising or reviewing
any records relating to such beneficial ownership interests.

If the Depositary for a series of Debt Securities is at any time unwilling,
unable or ineligible to continue as depositary and a successor depositary is not
appointed by the Company within 90 days, the Company will issue individual Debt
Securities of such series in exchange for the Global Security representing such
series of Debt Securities. In addition, the Company may at any time and in its
sole discretion, subject to any limitations described in the Prospectus
Supplement relating to such Debt Securities, determine not to have any Debt
Securities of a series represented by one or more Global Securities and, in such
event, will issue individual Debt Securities of such series in exchange for the
Global Security or Securities representing such series of Debt Securities.
Further, if the Company so specifies with respect to the Debt Securities of a
series, an owner of a beneficial interest in a Global Security representing Debt
Securities of such series may, on terms acceptable to the Company, the Trustee
and the Depositary for such Global Security, receive individual Debt Securities
of such series in exchange for such beneficial interests, subject to any
limitations described in the Prospectus Supplement relating to such Debt
Securities. In any such instance, an owner of a beneficial interest in a Global
Security will be entitled to physical delivery of individual Debt Securities of
the series represented by such Global Security equal in principal amount to such
beneficial interest and to have such Debt Securities registered in its name.
Individual Debt Securities of such series so issued will be issued in registered
form and in denominations, unless otherwise specified by the Company, of $1,000
and integral multiples thereof.

Certain Definitions. The following definitions are applicable to the
discussions of the Indentures (Article One).

"Indebtedness," with respect to any person, means:

(a)(i) the principal of and premium, if any, and interest, if any, on
indebtedness for money borrowed of such person, indebtedness of such person
evidenced by bonds, notes, debentures or similar obligations, and any
guaranty by such Person of any indebtedness for money borrowed or
indebtedness evidenced by bonds, notes, debentures or similar obligations
of any other person, whether any such indebtedness or guaranty is
outstanding on the date of the Indenture or is thereafter created, assumed
or incurred, (ii) the principal of and premium and interest, if any, on
indebtedness incurred, assumed or guaranteed by such Person in connection
with the acquisition by it or any of its subsidiaries of any other
businesses, properties or other assets and (iii) lease obligations that
such Person capitalizes in accordance with Statement of Financial
Accounting Standards No. 13 promulgated by the Financial Accounting
Standards Board or such other generally accepted accounting principles as
may be from time to time in effect;

(b) any other indebtedness of such Person, including any indebtedness
representing the balance deferred and unpaid of the purchase price of any
property or interest therein, including any such balance that constitutes a
trade payable, and any guaranty, endorsement or other contingent obligation
of such Person in respect of any indebtedness of another that is
outstanding on the date of the Indenture or is thereafter created, assumed
or incurred by such Person;

(c) obligations of such Person under interest rate, commodity or
currency swaps, caps, collars, options and similar arrangements;

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<PAGE> 123

(d) obligations of such Person for the reimbursement of any obligor on
any letter of credit, banker's acceptance or similar credit transaction;
and

(e) any amendments, modifications, refundings, renewals or extensions
of any indebtedness or obligation described as Indebtedness in clauses (a)
through (d) above.

"Subsidiary" means any corporation of which the Company, or the Company and
one or more Subsidiaries, or any one or more Subsidiaries, directly or
indirectly own voting securities entitling any one or more of the Company and
its Subsidiaries to elect a majority of the directors, either at all times or,
so long as there is no default or contingency which permits the holders of any
other class or classes of securities to vote for the election of one or more
directors.

Events of Default. Unless otherwise specified in the Prospectus Supplement,
an Event of Default is defined under each Indenture with respect to the Debt
Securities of any series issued under such Indenture as being: (a) default in
the payment of any installment of interest upon any of the Debt Securities of
such series when due, continued for 30 days; (b) default in the payment of
principal of or premium, if any, with respect to Debt Securities of such series
when due and payable either at maturity, upon redemption, by declaration or
otherwise; (c) default in the payment or satisfaction of any sinking fund or
other purchase obligation with respect to Debt Securities of such series when
due and payable; (d) default in the performance of any other covenant of the
Company applicable to Debt Securities of such series, continued for 60 days
after written notice to the Company by the Trustee or to the Company and the
Trustee by the holders of at least 25% in aggregate principal amount of the Debt
Securities of such series then outstanding; (e) certain events of bankruptcy,
insolvency or reorganization; and (f) default under any bond, debenture, note or
other evidence of Indebtedness for money borrowed by the Company (or, in the
case of the Senior Debt Indenture, any Subsidiary) or under any mortgage,
indenture or instrument under which there may be issued or by which there may be
secured or evidenced any Indebtedness for money borrowed of the Company (or, in
the case of the Senior Debt Indenture, any Subsidiary) resulting in the
acceleration of such Indebtedness, or any default in payment of such
Indebtedness (after expiration of any applicable grace periods and presentation
of any debt instrument, if required), if the aggregate amount of all such
Indebtedness that has been so accelerated and with respect to which there has
been such a default in payment shall exceed $10,000,000 and there shall have
been a failure to obtain rescission or annulment of all such accelerations or to
discharge all such defaulted Indebtedness within 10 days after written notice of
the type specified in the foregoing clause (d) (Section 5.1).

If any Event of Default shall occur and be continuing, the Trustee or the
holders of not less than 25% in aggregate principal amount of the Debt
Securities of such series then outstanding, by notice in writing to the Company
(and to the Trustee, if given by the holders), may declare the principal (or, in
the case of any series of Debt Securities originally issued at a discount from
their stated principal amount, such portion of the principal amount as may be
specified in the terms of such series) of all of the Debt Securities of such
series and the interest, if any, accrued thereon to be due and payable
immediately, but the holders of a majority in aggregate principal amount of the
Debt Securities of such series then outstanding, by notice in writing to the
Company and the Trustee, may rescind and annul such declaration and its
consequences if all defaults under such Indenture are cured or waived (Section
5.1).

Each Indenture provides that no holder of any series of Debt Securities
then outstanding may institute any suit, action or proceeding with respect to,
or otherwise attempt to enforce, such Indenture, unless (i) such holder
previously shall have given to the Trustee written notice of default and of the
continuance thereof, (ii) the holders of not less than 25% in aggregate
principal amount of such series of Debt Securities then outstanding shall have
made written request to the Trustee to institute such suit, action or proceeding
and shall have offered to the Trustee such reasonable indemnity as it may
require with respect thereto and (iii) the Trustee for 60 days after its receipt
of such notice, request and offer of indemnity, shall have neglected or refused
to institute any such
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<PAGE> 124

action, suit or proceeding; provided that, subject to the subordination
provisions applicable to the Senior Subordinated Debt Securities, the right of
any holder of any Debt Security to receive payment of the principal of, premium,
if any, or interest, if any, on such Debt Security, on or after the respective
due dates, or to institute suit for the enforcement of any such payment shall
not be impaired or affected without the consent of such holder (Section 5.4).
The holders of a majority in aggregate principal amount of the Debt Securities
of such series then outstanding may direct the time, method and place of
conducting any proceeding for any remedy available to the Trustee or exercising
any trust or power conferred on the Trustee with respect to the Debt Securities
of such series, provided that the Trustee may decline to follow such direction
if the Trustee determines that such action or proceeding is unlawful or would
involve the Trustee in personal liability (Section 5.7).

The Company is required to furnish to the Trustee annually a certificate as
to the compliance by the Company with all conditions and covenants under each
Indenture (Section 4.3).

Discharge and Defeasance. Unless otherwise specified in the applicable
Prospectus Supplement, the Company can discharge or defease its obligations with
respect to each series of Debt Securities as set forth below (Article Ten).

The Company may discharge all of its obligations (except those set forth
below) to holders of any series of Debt Securities issued under either Indenture
that have not already been delivered to the Trustee for cancellation and that
have either become due and payable or are by their terms due and payable within
one year (or scheduled for redemption within one year) by irrevocably depositing
with the Trustee cash or U.S. Government Obligations (as defined in such
Indenture), or a combination thereof, as trust funds in an amount certified to
be sufficient to pay when due the principal of and interest, if any, on all
outstanding Debt Securities of such series and to make any mandatory sinking
fund payments thereon when due.

Unless otherwise provided in the applicable Prospectus Supplement, the
Company may also discharge at any time all of its obligations (except those set
forth below) to holders of any series of Debt Securities issued under either
Indenture ("defeasance") if, among other things: (i) the Company irrevocably
deposits with the Trustee cash or U.S. Government Obligations, or a combination
thereof, as trust funds in an amount certified to be sufficient to pay when due
the principal of and interest, if any, on all outstanding Debt Securities of
such series and to make any mandatory sinking fund payments thereon when due and
such funds have been so deposited for 91 days; (ii) such deposit will not result
in a breach or violation of, or cause a default under, any agreement or
instrument to which the Company is a party or by which it is bound; and (iii)
the Company delivers to the Trustee an opinion of counsel to the effect that the
holders of such series of Debt Securities will not recognize income, gain or
loss for United States federal income tax purposes as a result of such
defeasance and that defeasance will not otherwise alter the United States
federal income tax treatment of such holders' principal and interest payments on
such series of Debt Securities. Such opinion must be based on a ruling of the
Internal Revenue Service or a change in United States federal income tax law
occurring after the date of the Indenture relating to the Debt Securities of
such series, since such a result would not occur under current tax law (Section
10.1).

Notwithstanding the foregoing, no discharge or defeasance described above
shall affect the following obligations to or rights of the holders of any series
of Debt Securities: (i) rights of registration of transfer and exchange of Debt
Securities of such series, (ii) rights of substitution of mutilated, defaced,
destroyed, lost or stolen Debt Securities of such series, (iii) rights of
holders of Debt Securities of such series to receive payments of principal
thereof and premium, if any, and interest, if any, thereon, upon the original
due dates therefor (but not upon acceleration), and to receive mandatory sinking
fund payments thereon when due, if any, (iv) rights, obligations, duties and
immunities of the Trustee, (v) rights of holders of Debt Securities of such
series as beneficiaries with respect to property so deposited with the Trustee
payable to all or any of them

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and (vi) obligations of the Company to maintain an office or agency in respect
of Debt Securities of such series (Section 10.1).

Modification of the Indenture. Each Indenture provides that the Company and
the Trustee may enter into supplemental indentures without the consent of the
holders of the Debt Securities to (a) evidence the assumption by a successor
entity of the obligations of the Company under such Indenture, (b) add covenants
or new events of default for the protection of the holders of such Debt
Securities, (c) cure any ambiguity or correct any inconsistency in the
Indenture, (d) establish the form and terms of Debt Securities of any series,
(e) evidence the acceptance of appointment by a successor trustee and (f) secure
such Debt Securities (Section 8.1).

Each Indenture also contains provisions permitting the Company and the
Trustee, with the consent of the holders of not less than a majority in
aggregate principal amount of Debt Securities of each series then outstanding
and affected, to add any provisions to, or change in any manner the rights of
the holders of the Debt Securities of such series; provided that the Company and
the Trustee may not, without the consent of the holder of each outstanding Debt
Security affected thereby, (a) extend the stated final maturity of any Debt
Security, reduce the principal amount thereof, reduce the rate or extend the
time of payment of interest, if any, thereon, reduce or alter the method of
computation of any amount payable on redemption, repayment or purchase by the
Company, change the coin or currency in which principal, premium, if any, and
interest, if any, are payable, reduce the amount of the principal of any
original issue discount security payable upon acceleration or provable in
bankruptcy, impair or affect the right to institute suit for the enforcement of
any payment or repayment thereof or, if applicable, adversely affect any right
of repayment at the option of the holder or (b) reduce the aforesaid percentage
in aggregate principal amount of Debt Securities of any series issued under such
Indenture, the consent of the holders of which is required for any such
modification (Section 8.2).

The Subordinated Debt Indenture may not be amended to alter the
subordination of any outstanding Subordinated Debt Securities without the
written consent of each holder of Senior Indebtedness then outstanding that
would be adversely affected thereby (Section 8.6 of the Subordinated Debt
Indenture).

PROVISIONS APPLICABLE SOLELY TO SENIOR DEBT SECURITIES

Senior Debt Securities will be issued under the Senior Debt Indenture and
will rank pari passu with all other unsecured and unsubordinated debt of the
Company.

PROVISIONS APPLICABLE SOLELY TO SENIOR SUBORDINATED DEBT SECURITIES

Certain Definitions. For purposes of the following discussion, the
following definitions are applicable (Article One of the Subordinated Debt
Indenture).

"Senior Indebtedness" is defined in the Subordinated Debt Indenture as
Indebtedness of the Company outstanding at any time except (a) any Indebtedness
as to which, by the terms of the instrument creating or evidencing the same, it
is provided that such Indebtedness is not senior in right of payment to the
Subordinated Debt Securities, (b) the Subordinated Debt Securities, (c) any
Indebtedness of the Company to a wholly-owned Subsidiary of the Company, (d)
interest accruing after the filing of a petition initiating certain events of
bankruptcy or insolvency unless such interest is an allowed claim enforceable
against the Company in a proceeding under federal or state bankruptcy laws and
(e) trade payables.

"Senior Subordinated Indebtedness" means the Subordinated Debt Securities
and any other Indebtedness of the Company that ranks pari passu with the
Subordinated Debt Securities. Any Indebtedness of the Company that is
subordinate or junior by its terms in right of payment to any other Indebtedness
of the Company shall be subordinate to Subordinated Indebtedness unless the
instrument creating or evidencing the same or pursuant to which the same is
outstanding specifically

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provides that such Indebtedness (i) is to rank pari passu with other Senior
Subordinated Indebtedness and (ii) is not subordinated by its terms to any
Indebtedness of the Company which is not Senior Indebtedness.

"Subordinated Indebtedness" means the Subordinated Debt Securities, any
other Senior Subordinated Indebtedness and any other Indebtedness that is
subordinate or junior in right of payment to Senior Indebtedness.

Subordination. The Subordinated Debt Securities will be subordinate and
junior in right of payment, to the extent set forth in the Subordinated Debt
Indenture, to all Senior Indebtedness of the Company, and the Subordinated Debt
Securities shall in all respects rank pari passu with all other Senior
Subordinated Indebtedness. If (i) the Company should default in the payment of
any principal of, premium, if any, or interest, if any, on any Senior
Indebtedness when the same becomes due and payable, whether at maturity or at a
date fixed for prepayment or by declaration of acceleration or otherwise or (ii)
any other default with respect to Senior Indebtedness shall occur and the
maturity of such Senior Indebtedness has been accelerated in accordance with its
terms, then, upon written notice of such default to the Company by the holders
of such Senior Indebtedness or any trustee therefor, unless and until such
default shall have been cured or waived or such acceleration shall have been
rescinded or such Senior Indebtedness has been paid in full, no direct or
indirect payment (in cash, property, securities, by set-off or otherwise) will
be made or agreed to be made for principal of, premium, if any, or interest, if
any, on any of the Subordinated Debt Securities, or in respect of any
redemption, retirement, purchase or other acquisition of the Subordinated Debt
Securities other than those made in capital stock of the Company (or cash in
lieu of fractional shares thereof) (Sections 13.1 and 13.4 of the Subordinated
Debt Indenture).

If any default (other than a default described in the preceding paragraph)
shall occur under the Senior Indebtedness, pursuant to which the maturity
thereof may be accelerated immediately or the expiration of any applicable grace
periods occurs (a "Senior Nonmonetary Default"), then, upon the receipt by the
Company and the Trustee of written notice thereof (a "Payment Notice") from or
on behalf of holders of such Senior Indebtedness specifying an election to
prohibit such payment and other action by the Company in accordance with the
following provisions of this paragraph, the Company may not make any payment or
take any other action that would be prohibited by the immediately preceding
paragraph during the period (the "Payment Blockage Period") commencing on the
date of receipt of such Payment Notice and ending on the earlier of (i) the
date, if any, on which the holders of such Senior Indebtedness or their
representative notify the Trustee that such Senior Nonmonetary Default is cured
or waived or ceases to exist or the Senior Indebtedness to which such Senior
Nonmonetary Default relates is discharged or (ii) the 179th day after the date
of receipt of such Payment Notice unless the maturity of any Senior Indebtedness
has been accelerated or a default of the type described in clause (e) under the
caption "Events of Default" has occurred and is continuing. Notwithstanding the
provisions described in the immediately preceding sentence, the Company may
resume payments on the Securities after such Payment Blockage Period. No new
payment Blockage Period may be commenced unless and until 360 days have elapsed
since the date of commencement of the Payment Blockage Period resulting from the
immediately prior Payment Notice. No nonpayment default in respect of Senior
Indebtedness that existed or was continuing on the date of delivery of any
Payment Notice to the Company and the Trustee shall be, or be made, the basis
for a subsequent Payment Notice unless such default shall have been cured or
waived for a period of no less than 90 days.

If (i) (A) without the consent of the Company, a receiver, conservator,
liquidator or trustee of the Company or of any of its property is appointed by
the order or decree of any court or agency or supervisory authority having
jurisdiction, and such decree or order remains in effect for more than 60 days
or (B) the Company is adjudicated bankrupt or insolvent or (C) any of its
property is sequestered by court order and such order remains in effect for more
than 60 days or (D) a petition is filed against the Company under any state or
federal bankruptcy, reorganization, arrangement, insolvency, readjustment of
debt, dissolution, liquidation or receivership law of any jurisdiction
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whether now or hereafter in effect, and is not dismissed within 60 days after
such filing; or (ii) the Company (A) commences a voluntary case or other
proceeding seeking liquidation, reorganization, arrangement, insolvency,
readjustment of debt, dissolution, liquidation or other relief with respect to
itself or its debt or other liabilities under any bankruptcy, insolvency or
other similar law now or hereafter in effect or seeking the appointment of a
trustee, receiver, liquidator, custodian or other similar official of it or any
substantial part of its property, or (B) consents to any such relief or to the
appointment of or taking possession by any such official in an involuntary case
or other proceeding commenced against it, or (C) fails generally to, or cannot,
pay its debts generally as they become due or (D) takes any corporate action to
authorize or effect any of the foregoing; or (iii) any Subsidiary of the Company
takes, suffers or permits to exist any of the events or conditions referred to
in the foregoing clause (i) or (ii), then all Senior Indebtedness (including any
interest thereon accruing after the commencement of any such proceedings) will
first be paid in full before any payment or distribution, whether in cash,
securities or other property, is made to any holder of Subordinated Debt
Securities on account of the principal of, premium, if any, or interest, if any,
on such Subordinated Debt Securities. Any payment or distribution, whether in
cash, securities or other property (other than securities of the Company or any
other corporation provided for by a plan of reorganization or readjustment the
payment of which is subordinate, at least to the extent provided in the
subordination provisions with respect to the indebtedness evidenced by the
Subordinated Debt Securities, to the payment of all Senior Indebtedness then
outstanding and to any securities issued in respect thereof under any such plan
of reorganization or readjustment) that would otherwise (but for the
subordination provisions) be payable or deliverable in respect of the
Subordinated Debt Securities of any series will be paid or delivered directly to
the holders of Senior Indebtedness in accordance with the priorities then
existing among such holders until all Senior Indebtedness (including any
interest thereon accruing after the commencement of any such proceedings) has
been paid in full. In the event of any such proceeding, after payment in full of
all sums owing with respect to Senior Indebtedness, the holders of Subordinated
Debt Securities, together with the holders of any obligations of the Company
ranking on a parity with the Subordinated Debt Securities, will be entitled to
be repaid from the remaining assets of the Company the amounts at that time due
and owing on account of unpaid principal of, premium, if any, and interest, if
any, on the Subordinated Debt Securities and such other obligations before any
payment or other distribution, whether in cash, property or otherwise, shall be
made on account of any capital stock or obligations of the Company ranking
junior to the Subordinated Debt Securities and such other obligations (Section
13.1 of the Subordinated Debt Indenture).

If any payment or distribution of any character, whether in cash,
securities or other property (other than securities of the Company or any other
corporation provided for by a plan of reorganization or readjustment the payment
of which is subordinate, at least to the extent provided in the subordination
provisions with respect to the Subordinated Debt Securities, to the payment of
all Senior Indebtedness then outstanding and to any securities issued in respect
thereof under any such plan of reorganization or readjustment), shall be
received by the Trustee or any holder of any Subordinated Debt Securities in
contravention of any of the terms of the Subordinated Debt Indenture, such
payment or distribution of securities will be received in trust for the benefit
of, and will be paid over or delivered and transferred to, the holders of the
Senior Indebtedness then outstanding in accordance with the priorities then
existing among such holders for application to the payment of all Senior
Indebtedness remaining unpaid to the extent necessary to pay all such Senior
Indebtedness in full (Section 13.1 of the Subordinated Debt Indenture).

By reason of such subordination, in the event of the insolvency of the
Company, holders of Senior Indebtedness may receive more, ratably, than holders
of the Subordinated Debt Securities. Such subordination will not prevent the
occurrence of any Event of Default (as defined in the Subordinated Debt
Indenture) or limit the right of acceleration in respect of the Subordinated
Debt Securities.

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Conversion. The Prospectus Supplement may provide for a right of conversion
of Subordinated Debt Securities into Common Stock (or cash in lieu thereof). The
following provisions will apply to Debt Securities that are convertible
Subordinated Debt Securities unless otherwise provided in the Prospectus
Supplement for such Debt Securities.

The holder of any convertible Subordinated Debt Securities will have the
right exercisable at any time prior to maturity, unless previously redeemed or
otherwise purchased by the Company, to convert such Subordinated Debt Securities
into shares of Common Stock at the conversion price set forth in the Prospectus
Supplement, subject to adjustment. The holder of convertible Subordinated Debt
Securities may convert any portion thereof which is $1,000 in principal amount
or any integral multiple thereof.

In certain events, the conversion price will be subject to adjustment as
set forth in the Subordinated Debt Indenture. Such events include the issuance
of shares of Common Stock of the Company as a dividend or distribution on the
Common Stock; subdivisions and reclassifications of the Common Stock; the
issuance to all holders of Common Stock of rights or warrants entitling the
holders thereof (for a period not exceeding 45 days) to subscribe for or
purchase shares of Common Stock at a price per share less than the then current
market price per share of Common Stock (as determined pursuant to the
Subordinated Debt Indenture); and the distribution to holders of Common Stock of
evidences of indebtedness, equity securities (including equity interests in the
Company's Subsidiaries) other than Common Stock, or other assets (excluding cash
dividends) or rights or warrants to subscribe for securities (other than those
referred to above). No adjustment of the conversion price will be required
unless an adjustment would require a cumulative increase or decrease of at least
1% in such price or rate. The Company has been advised by its counsel, Vinson &
Elkins L.L.P., that certain adjustments in the conversion price or conversion
rate in accordance with the foregoing provisions may result in constructive
distributions to either holders of the Subordinated Debt Securities or holders
of Common Stock which would be taxable pursuant to Treasury Regulations issued
under Section 305 of the Internal Revenue Code of 1986, as amended. The amount
of any such taxable constructive distribution would be the fair market value of
the Common Stock which is treated as having been constructively received, such
value being determined as of the time the adjustment resulting in the
constructive distribution is made.

Fractional shares of Common Stock will not be issued upon conversion, but,
in lieu thereof, the Company will pay a cash adjustment based on the then
current market price for the Common Stock. Upon conversion, no adjustments will
be made for accrued interest or dividends, and therefore convertible
Subordinated Debt Securities surrendered for conversion between the record date
for an interest payment and the interest payment date (except convertible
Subordinated Debt Securities called for redemption on a redemption date during
such period) must be accompanied by payment of an amount equal to the interest
thereon which the registered holder is to receive.

In the case of any consolidation or merger of the Company (with certain
exceptions) or any conveyance, transfer or lease of the properties and assets of
the Company substantially as an entirety to any Person, each holder of
convertible Subordinated Debt Securities, after the consolidation, merger,
conveyance, transfer or lease, will have the right to convert such convertible
Subordinated Debt Securities only into the kind and amount of securities, cash
and other property which the holder would have been entitled to receive upon or
in connection with such consolidation, merger, conveyance, transfer or lease, if
the holder had held the Common Stock issuable upon conversion of such
convertible Subordinated Debt Securities immediately prior to such
consolidation, merger, conveyance, transfer or lease.

CONCERNING THE TRUSTEE

Pursuant to the Trust Indenture Act of 1939, as amended, should a default
occur with respect to either the Senior Debt Securities or the Subordinated Debt
Securities, the Trustee would be required to resign as Trustee under one of the
Indentures within 90 days of such default unless such default were cured, duly
waived or otherwise eliminated.
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DESCRIPTION OF CAPITAL STOCK

GENERAL

The Company is currently authorized to issue 120,000,000 shares of its
Common Stock, par value $.01 per share, of which 31,582,000 shares were
outstanding on November 30, 1997, and 10,000,000 shares of Preferred Stock, par
value $.01 per share, none of which were outstanding on such date. As of
November 30, 1997, the Company had outstanding 1,666,667 warrants to purchase an
equal number of shares of Common Stock at an exercise price of $27.50 (the
"Warrants"). The Warrants are exercisable for three years after the date of
issuance commencing one year after the date of issuance. The number of shares of
Common Stock into which each Warrant is exercisable as well as the exercise
price are subject to adjustment in the case of stock dividends, subdivisions,
combinations and reclassifications.

COMMON STOCK

Holders of Common Stock are entitled to one vote per share in the election
of directors and on all other matters submitted to a vote of common stockholders
and are not entitled to cumulative voting rights. Holders of Common Stock are
entitled to receive ratably such dividends, if any, as may be declared by the
Board of Directors out of funds legally available therefore, subject to any
preferential dividend rights of holders of outstanding Preferred Stock. Upon the
liquidation, dissolution or winding up of the Company, the holders of Common
Stock are entitled to receive ratably the net assets of the Company available
after payment of all debts and other liabilities, subject to the prior rights of
any outstanding shares of Preferred Stock. Holders of Common Stock have no
preemptive, subscription, redemption or conversion rights.

PREFERRED STOCK

The Board of Directors of the Company is empowered, without approval of the
stockholders, to cause shares of Preferred Stock to be issued in one or more
series, with the numbers of shares of each series to be determined by the Board
of Directors in its sole discretion. The Board of Directors is authorized to fix
and determine variations in the voting power, designations, preferences, and
relative, participating, optional or other special rights (including, without
limitation, special voting rights, rights to receive dividends or assets upon
liquidation, rights of conversion into Common Stock or other securities,
redemption provisions and sinking fund provisions) between series and between
the Preferred Stock or any series thereof and the Common Stock, and the
qualifications, limitations or restrictions of such rights. Shares of Preferred
Stock or any series thereof may have full or limited voting powers, or be
without voting powers.

Although the Company has no present intention to issue shares of Preferred
Stock, the issuance of shares of Preferred Stock, or the issuance of rights to
purchase such shares, could be used to discourage an unsolicited acquisition
proposal. For instance, the issuance of a series of Preferred Stock might impede
a business combination by including class voting rights that would enable the
holders to block such a transaction; or such issuance might facilitate a
business combination by including voting rights that would provide a required
percentage vote of the stockholders. In addition, under certain circumstances,
the issuance of Preferred Stock could adversely affect the voting power of the
holders of the Common Stock. Although the Board of Directors is required to make
any determination to issue such stock based on its judgment as to the best
interests of the stockholders of the Company, the Board of Directors could act
in a manner that would discourage an acquisition attempt or other transaction
that some majority of the stockholders might believe to be in their best
interest or in which stockholders might receive a premium for their stock over
the then market price for such stock. The Board of Directors does not at present
intend to seek stockholder approval prior to any issuance of currently
authorized stock unless otherwise required by law or the regulations of the
exchange on which its Common Stock is listed.

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The following description of the terms of the Preferred Stock sets forth
certain general terms and provisions of the Preferred Stock to which any
Prospectus Supplement may relate. Certain terms of a series of the Preferred
Stock offered by any Prospectus Supplement will be described in the Prospectus
Supplement relating to such series of the Preferred Stock. If so indicated in
the Prospectus Supplement, the terms of any such series may differ from the
terms set forth below. The following description of the Preferred Stock
summarizes certain provisions of the Company's Articles of Incorporation and is
subject to and qualified in its entirety by reference to the Articles of
Incorporation.

General. Under the Company's Articles of Incorporation, the Board of
Directors is authorized, without further approval of the stockholders, to issue
Preferred Stock in series and with respect to each series, to fix its
designations, voting rights, amounts of preference upon distribution of assets,
rates of dividends, premiums of redemption, conversion rights and other
variations, if any, qualifications, limitations and restrictions. It is not
possible to state the actual effect of the authorization and issuance of a new
series of Preferred Stock upon the rights of holders of the Common Stock and
other series of Preferred Stock unless and until the Board of Directors
determines the attributes of such new series of Preferred Stock and the specific
rights of its holders. Such effects might include, however, (i) restrictions on
dividends on Common Stock and other series of Preferred Stock if dividends on
such new series of Preferred Stock have not been paid; (ii) dilution of the
voting power of Common Stock and other series of Preferred Stock to the extent
that such new series of Preferred Stock has voting rights, or to the extent that
any such new series of Preferred Stock is convertible into Common Stock; (iii)
dilution of the equity interest of Common Stock and other series of Preferred
Stock; and (iv) limitation on the right of holders of Common Stock and other
series of Preferred Stock to share in the Company's assets upon liquidation
until satisfaction of any liquidation preference attributable to such new series
of Preferred Stock. While the ability of the Company to issue Preferred Stock
provides flexibility in connection with possible acquisitions and other
corporate purposes, its issuance could be used to impede an attempt by a third
party to acquire a majority of the outstanding voting stock of the Company.

The Preferred Stock will have the dividend, liquidation, redemption and
voting rights set forth below unless otherwise provided in the Prospectus
Supplement relating to a particular series of the Preferred Stock. Reference is
made to the Prospectus Supplement relating to the particular series of the
Preferred Stock offered thereby for specific terms, including: (i) the
designation of such Preferred Stock, the number of shares offered and the
liquidation value thereof; (ii) the price at which such Preferred Stock will be
issued; (iii) the dividend rate (or method of calculation), the dates on which
dividends shall be payable, whether such dividends shall be cumulative or
noncumulative and, if cumulative, the dates from which dividends shall commence
to accumulate; (iv) the liquidation preference thereof; (v) any redemption or
sinking fund provisions; (vi) any conversion or exchange provisions of such
Preferred Stock; and (vii) any additional dividend, liquidation, redemption,
sinking fund and other rights, preferences, limitations and restrictions of such
Preferred Stock.

The Preferred Stock will, when issued, be fully paid and nonassessable.
Unless otherwise specified in the Prospectus Supplement relating to a particular
series of the Preferred Stock, each series of the Preferred Stock will rank on a
parity as to dividends and distributions in the event of a liquidation with each
other series of the Preferred Stock, if any. Holders of Preferred Stock will
have no preemptive rights to subscribe for or purchase shares of capital stock.

Dividend Rights. Holders of the Preferred Stock of each series will be
entitled to receive, when, as and if declared by the Board of Directors, out of
assets of the Company legally available therefor, cash dividends at such rates
and on such dates as are set forth in the Prospectus Supplement relating to such
series of the Preferred Stock. Such rate may be fixed or variable or both. Each
such dividend will be payable to the holders of record as they appear on the
stock books of the Company on such record dates as will be fixed by the Board of
Directors or a duly authorized committee thereof. Dividends on any series of the
Preferred Stock may be cumulative or noncumulative, as
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<PAGE> 131

provided in the Prospectus Supplement relating thereto. If the Board of
Directors fails to declare a dividend payable on a dividend payment date on any
series of Preferred Stock for which dividends are noncumulative, then the right
to receive a dividend in respect of the dividend period ending on such dividend
payment date will be lost, and the Company shall have no obligation to pay the
dividend accrued for that period, whether or not dividends are declared for any
future period.

No full dividends will be declared or paid or set apart for payment on
preferred stock of any series ranking, as to dividends, on a parity with or
junior to any series of Preferred Stock for any period unless full dividends
have been or contemporaneously are declared and paid, or declared and a sum
sufficient for the payment thereof set apart for such payment on such series of
Preferred Stock for the then-current dividend period and, if such Preferred
Stock is cumulative, all other dividend periods terminating on or before the
date of payment of such full dividends. When dividends are not paid in full upon
any series of the Preferred Stock and any other preferred stock ranking on a
parity as to dividends with such series of the Preferred Stock, all dividends
declared upon such series of the Preferred Stock and any other preferred stock
ranking on a parity as to dividends will be declared pro rata so that the amount
of dividends declared per share on such series of the Preferred Stock and such
other preferred stock will in all cases bear to each other the same ratio that
accrued dividends, including, in the case of cumulative Preferred Stock,
accumulations, if any, in respect of prior dividend periods, per share on such
series of the Preferred Stock and such other preferred stock bear to each other.
Except as provided in the preceding sentence, unless full dividends, including,
in the case of cumulative Preferred Stock, accumulations, if any, in respect of
prior dividend periods, on all outstanding shares of any series of the Preferred
Stock have been paid or declared and set aside for payment, no dividends (other
than a dividend or distribution paid in shares of, or warrants, rights or
options exercisable for or convertible into, Common Stock or another stock
ranking junior to such series of the Preferred Stock as to dividends and upon
liquidation) will be declared or paid or set aside for payment or other
distributions made upon the Common Stock or any other stock of the Company
ranking junior to or on a parity with the Preferred Stock as to dividends or
upon liquidation, nor will any Common Stock or any other stock of the Company
ranking junior to or on a parity with such series of the Preferred Stock as to
dividends or upon liquidation be redeemed, purchased or otherwise acquired for
any consideration (or any moneys be paid to or made available for a sinking fund
for the redemption of any shares of any such stock) by the Company (except by
conversion into or exchange for stock of the Company ranking junior to such
series of the Preferred Stock as to dividends and upon liquidation). No
interest, or sum of money in lieu of interest, shall be payable in respect of
any dividend payment or payments which may be in arrears.

The amount of dividends payable for each dividend period will be computed
by annualizing the applicable dividend rate and dividing by the number of
dividend periods in a year, except that the amount of dividends payable for the
initial dividend period or any period longer or short other than a full dividend
period shall be computed on the basis of 30-day months and a 360-day year.

Each series of Preferred Stock will be entitled to dividends as described
in the Prospectus Supplement relating to such series, which may be based upon
one or more methods of determination. Different series of the Preferred Stock
may be entitled to dividends at different dividend rates or based upon different
methods of determination.

Rights Upon Liquidation. In the event of any voluntary or involuntary
liquidation, dissolution or winding up of the Company, the holders of each
series of Preferred Stock will be entitled to receive out of assets of the
Company available for distribution to stockholders, before any distribution of
assets is made to holders of Common Stock or any other class of stock ranking
junior to such series of the Preferred Stock upon liquidation, liquidating
distributions in the amount set forth in the Prospectus Supplement relating to
such series of the Preferred Stock plus an amount equal to accrued and unpaid
dividends for the then-current dividend period and, if such series of the
Preferred Stock is cumulative, for all dividend periods prior thereto. If, upon
any voluntary or involuntary liquidation, dissolution or winding up of the
Company, the amounts payable with respect
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<PAGE> 132

to the Preferred Stock of any series and any other shares of stock of the
Company ranking as to any such distribution on a parity with such series of the
Preferred Stock are not paid in full, the holders of the Preferred Stock of such
series and of such other shares will share ratably in any such distribution of
assets of the Company in proportion to the full respective preferential amounts
to which they are entitled. After payment of the full amount of the liquidating
distribution to which they are entitled, the holders of such series of Preferred
Stock will have no right or claim to any of the remaining assets of the Company.
Neither the sale of all or substantially all the property or business of the
Company nor the merger or consolidation of the Company into or with any other
corporation shall be deemed to be a dissolution, liquidation or winding up,
voluntary or involuntary, of the Company.

Redemption. A series of the Preferred Stock may be redeemable, in whole or
in part, at the option of the Company, and may be subject to mandatory
redemption pursuant to a sinking fund, in each case upon terms, at the times and
at the redemption prices set forth in the Prospectus Supplement relating to such
series.

The Prospectus Supplement relating to a series of Preferred Stock that is
subject to mandatory redemption will specify the number of shares of such series
of Preferred Stock that will be redeemed by the Company in each year commencing
after a date to be specified, at a redemption price per share to be specified,
together with an amount equal to any accrued and unpaid dividends thereon to the
date of redemption. The redemption price may be payable in cash, capital stock
or in cash received from the net proceeds of the issuance of capital stock of
the Company, as specified in the Prospectus Supplement relating to such series
of Preferred Stock.

If fewer than all the outstanding shares of any series of the Preferred
Stock are to be redeemed, whether by mandatory or optional redemption, the
selection of the shares to be redeemed will be determined by lot or pro rata as
may be determined by the Board of Directors or a duly authorized committee
thereof, or by any other method which may be determined by the Board of
Directors or such committee to be equitable. From and after the date of
redemption (unless default shall be made by the Company in providing for the
payment of the redemption price), dividends shall cease to accrue on the shares
of Preferred Stock called for redemption and all rights of the holders thereof
(except the right to receive the redemption price) shall cease.

In the event that full dividends, including accumulations in the case of
cumulative Preferred Stock, on any series of the Preferred Stock have not been
paid, such series of the Preferred Stock may not be redeemed in part and the
Company may not purchase or acquire any shares of such series of the Preferred
Stock otherwise than pursuant to a purchase or exchange offer made on the same
terms to all holders of such series of the Preferred Stock.

Conversion or Exchange Rights. The Prospectus Supplement for any series of
the Preferred Stock will state the terms, if any, on which shares of such series
are convertible into, or exchangeable for, securities of the Company or another
person.

Voting Rights. Unless otherwise determined by the Board of Directors and
indicated in the Prospectus Supplement relating to a particular series of
Preferred Stock, the holders of the Preferred Stock will not be entitled to
vote, except as set forth below or except as expressly required by applicable
law. In the event the Company issues shares of any series of Preferred Stock
with voting rights, including any voting rights in the case of dividend
arrearages, unless otherwise specified in the Prospectus Supplement relating to
a particular series of Preferred Stock, each such share will be entitled to one
vote on matters on which holders of such series of the Preferred Stock are
entitled to vote. In the case of any series of Preferred Stock having one vote
per share on matters on which holders of such series are entitled to vote, the
voting power of such series, on matters on which holders of such series and
holders of other series of preferred stock are entitled to vote as a single
class, will depend on the number of shares in such series, not on the aggregate
liquidation preference or initial offering price of the shares of such series of
Preferred Stock.

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Except as otherwise set forth in a Prospectus Supplement, the affirmative
vote or consent of the holders of at least a majority of the outstanding shares
of any series of Preferred Stock, voting as a separate class, will be required
for any amendment, alteration or repeal, whether by merger, consolidation or
otherwise, of the Articles of Incorporation that will (i) increase or decrease
the aggregate number of authorized shares of such series or of Preferred Stock,
(ii) increase or decrease the par value of the Preferred Stock, (iii) effect an
exchange, reclassification or cancellation of all or part of the shares of such
series or of the Preferred Stock, (iv) effect an exchange, or create a right of
exchange, of all or any part of the shares of another class into the shares of
such series or of Preferred Stock, (v) change the designations, preferences,
limitations or relative rights of the shares of such series or the Preferred
Stock, (vi) change the shares of such series or the Preferred Stock into the
same or a different number of shares of the same class or series or another
class or series, (vii) create a new class or series of shares having rights and
preferences equal, prior or superior to the shares of such series or the
Preferred Stock, or increase the rights and preferences of any class or series
having rights and preferences equal, prior or superior to the shares of such
series or the Preferred Stock, or increase the rights and preferences of any
class or series having rights or preferences later or inferior to the shares of
such series or the Preferred Stock in such a manner as to become equal, prior or
superior to the shares of such class or series, (viii) divide the shares of
Preferred Stock into series and fix and determine the designation of such series
and the variations in the relative rights and preferences between the shares of
such series, (ix) limit or deny the existing preemptive rights of the shares of
such series or of the Preferred Stock, or (x) cancel or otherwise affect
dividends on the shares of such series or the Preferred Stock that had accrued
but had not been declared. The foregoing provisions are not applicable to the
designation of any series by the Board of Directors in the manner described
under the heading "General" above. If the holders of the outstanding shares of
Preferred Stock are entitled to vote as a class on a proposed amendment and the
amendment would affect all series of such class (other than any series of which
no shares are outstanding or any series that is not affected by the amendment)
equally, then the holders of the separate series shall not be entitled to
separate class votes, but shall instead vote together as one class.
Notwithstanding the foregoing, the approval of a proposed amendment to the
Articles of Incorporation that would solely effect changes in the designations,
preferences, limitations and relative rights, including voting rights, of one or
more series of shares that have been established by the Board of Directors as
described above under the heading "General," shall not require the approval of
the holders of the outstanding shares of any class or series other than such
series if the preferences, limitations and relative rights of such series after
giving effect to such amendment and of any series that may be established as a
result of a reclassification of such series are, in each case, within those
permitted to be fixed and determined by the Board of Directors with respect to
the establishment of any new series of shares pursuant to the authority granted
the Board of Directors as described above under the heading "General."

AUTHORIZED BUT UNISSUED SHARES

Authorized but unissued shares of Common Stock or Preferred Stock can be
reserved for issuance by the Board of Directors from time to time without
further stockholder action for proper corporate purposes, including stock
dividends or stock splits, raising equity capital and structuring future
corporate transactions, including acquisitions.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Common Stock is The Bank of New
York, New York, New York.

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ANTI-TAKEOVER PROVISIONS

Nevada's "Combination with Interested Stockholders Statute," "Nevada
Revised Statutes sec. 78.411-78.444, which applies to any Nevada corporation
subject to the reporting requirements of section 12 of the Securities Exchange
Act of 1934, prohibits an "interested stockholder" from entering into a
"combination" with the corporation, unless certain conditions are met. A
"combination" includes (a) any merger with an "interested stockholder," or any
other corporation which is or after the merger would be, an affiliate or
associate of the interested stockholder, (b) any sale, lease, exchange,
mortgage, pledge, transfer or other disposition of assets, in one transaction or
a series of transactions, to or with an "interested stockholder," having (i) an
aggregate market value equal to 5% or more of the aggregate market value of the
corporation's assets, (ii) an aggregate market value equal to 5% or more of the
aggregate market value of all outstanding shares of the corporation, or (iii)
representing 10% or more of the earning power or net income of the corporation,
(c) any issuance or transfer of shares of the corporation or its subsidiaries,
to the "interested stockholder," having an aggregate market value equal to 5% or
more of the aggregate market value of all the outstanding shares of the
corporation, (d) the adoption of any plan or proposal for the liquidation or
dissolution of the corporation proposed by the "interested stockholder," (e)
certain transactions which would result in increasing the proportion of shares
of the corporation owned by the "interested stockholder," or (f) the receipt of
benefits by an "interested stockholder," except proportionately as a
stockholder, of any loans, advances or other financial benefits provided by the
corporation. An "interested stockholder" is a person who (i) directly or
indirectly owns 10% or more of the voting power of the outstanding voting shares
of the corporation or (ii) an affiliate or associate of the corporation which at
any time within three years before the date in question was the beneficial
owner, directly or indirectly, of 10% or more of the voting power of the then
outstanding shares of the corporation.

A corporation to which the statute applies may not engage in a
"combination" within three years after the interested stockholder acquired its
shares, unless the combination or the interested stockholder's acquisition of
shares was approved by the board of directors before the interested stockholder
acquired the shares. If this approval is not obtained, the combination may be
consummated after the three year period expires of either (a)(i) the board of
directors of the corporation approved, prior to such person becoming an
interested stockholder, the combination or the purchase of Shares by the
interested stockholder or (ii) the combination is approved by the affirmative
vote of holders of a majority of voting power not beneficially owned by the
interested stockholder at a meeting called no earlier than three years after the
date the interested stockholder became such or (b) the aggregate amount of cash
and the market value of consideration other than cash to be received by holders
of common shares and holders of any other class or series of shares meets the
minimum requirements set forth in Section 78.441 through 78.443, inclusive, and
prior to the consummation of the combination, except in limited circumstances,
the "interested stockholder" would not have become the beneficial owner of
additional voting shares of the corporation.

Nevada's "Control Share Acquisition Statute," Nevada Revised Statute
sec. 78.378-78.3793, prohibits an acquiror, under certain circumstances, from
voting shares of a target corporation's stock after crossing certain threshold
ownership percentages, unless the acquiror obtains the approval of the target
corporation's stockholders. The Control Share Acquisition Statute only applies
to Nevada corporations with at least 200 stockholders, including at least 100
record stockholders who are Nevada residents, and which do business directly or
indirectly in Nevada. The Company does not intend to "do business" in Nevada
within the meaning of the Control Share Acquisition Statute. Therefore, it is
unlikely that the Control Share Acquisition Statute will apply to the Company.
The statute specifies three thresholds: at least one-fifth but less than
one-third, at least one-third but less than a majority, and a majority or more,
of the outstanding voting power. Once an acquiror crosses one of the above
thresholds, shares with it acquired in the transaction taking it over the
threshold or within ninety days thereof become "Control Shares" which are
deprived of the right to vote until a majority of the disinterested stockholders
restore that right. A

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special stockholders' meeting may be called at the request of the acquiror to
consider the voting rights of the acquiror's shares no more than 50 days (unless
the acquiror agrees to a later date) after the delivery by the acquiror to the
corporation of an information statement which sets forth the range of voting
power that the acquiror has acquired or proposes to acquire and certain other
information concerning the acquiror and the proposed control share acquisition.
If no such request for a stockholders' meeting is made, consideration of the
voting rights of the acquiror's shares must be taken at the next special or
annual stockholders' meeting. If the stockholders fail to restore voting rights
to the acquiror, or if the acquiror fails to timely deliver an information
statement to the corporation, then the corporation may, if so provided in its
Articles or Bylaws, call certain of the acquiror's shares for redemption at the
average price paid for the control shares by the acquiror. The Company's
Articles and Bylaws do not currently permit it to call an acquiror's shares for
redemption under these circumstances. The Control Share Acquisition Statute also
provides that in the event the stockholders restore full voting rights to a
holder of Control Shares that owns a majority of the voting stock, then all
other stockholders who do not vote in favor of restoring voting rights to the
Control Shares may demand payment for the "fair value" of their shares (which is
generally equal to the highest price paid by the acquiror in the transaction
subjecting the acquiror to the statute).

20
<PAGE> 136

PLAN OF DISTRIBUTION

GENERAL

The Company may sell Securities to or through underwriters or dealers, and
also may sell Securities directly to other purchasers or through agents. The
distribution of the Securities may be effected from time to time in one or more
transactions at a fixed price or prices, which may be changed, or at market
prices prevailing at the time of sale, at prices related to such prevailing
market prices or at negotiated prices.

In connection with the sale of Securities, underwriters may receive
compensation from the Company, or purchasers of Securities for whom they may act
as agents, in the form of discounts, concessions or commissions. Underwriters,
dealers and agents that participate in the distribution of Securities may be
deemed to be underwriters, and any discounts or commissions received by them
from the Company or the purchasers of Securities, as the case may be, and any
profit on the resale of Securities by them may be deemed to be underwriting
discounts and commissions under the Securities Act. Any such person who may be
deemed to be an underwriter with respect to a sale of Securities will be
identified, and any such compensation received from the Company will be
described, in the Prospectus Supplement relating to such Securities.

Unless otherwise set forth in the Prospectus Supplement relating to a
particular series of Securities, the obligations of the underwriters to purchase
such series of Securities will be subject to certain conditions precedent and
each of the underwriters with respect to such series of Securities will be
obligated to purchase all of the Securities of such series allocated to it if
any such Securities are purchased. Any initial public offering price and any
discounts or concessions allowed, reallowed, or paid to dealers may be changed
from time to time.

The Securities (other than the Common Stock), when first issued, will have
no established trading market. Any underwriters or agents to or through whom
Securities are sold by the Company for public offering and sale may make a
market in such Securities, but such underwriters or agents will not be obligated
to do so and may discontinue any market making at any time without notice. No
assurance can be given as to the liquidity of the trading market for any such
Securities.

Underwriters and agents may engage in transactions with, or perform
services for, the Company in the ordinary course of business.

Under agreements which may be entered into by the Company, underwriters,
dealers and agents who participate in the distribution of Securities may be
entitled to indemnification by the Company against or contribution toward
certain liabilities, including liabilities under the Securities Act.

DELAYED DELIVERY ARRANGEMENT

If so indicated in the Prospectus Supplement, the Company will authorize
underwriters or other persons acting as the Company's agents to solicit offers
by certain institutions to purchase Securities from the Company pursuant to
contracts providing for payment and delivery on a future date. Institutions with
which such contracts may be made include commercial and savings banks, insurance
companies, pension funds, investment companies, educational and charitable
institutions and others, but in all cases will be subject to the approval of the
Company. The obligations of any purchaser under any such contract will be
subject to the condition that the purchase of the Securities shall not at the
time of delivery be prohibited under the laws of any jurisdiction to which such
purchaser is subject. The underwriters and such agents will not have any
responsibility in respect of the validity or performance of such contracts.

21
<PAGE> 137

VALIDITY OF SECURITIES

The validity of the Securities will be passed upon for the Company by
Woodburn & Wedge, Reno, Nevada, and Vinson & Elkins L.L.P., Houston, Texas, and
will be passed upon for any agents, dealers or underwriters by counsel named in
the applicable Prospectus Supplement. Certain legal matters with respect to
certain of the Securities may be passed upon for the underwriters or agents by
Andrews & Kurth L.L.P., Houston, Texas. Andrews & Kurth L.L.P. from time to time
acts as counsel to the Company with respect to certain matters.

EXPERTS

The consolidated financial statements of the Company and subsidiaries as of
December 31, 1995 and 1996, and for each of the three years in the period ended
December 31, 1996, incorporated by reference in this Prospectus, have been
audited by Arthur Andersen LLP, independent public accountants, as indicated in
their reports with respect thereto, and are included herein in reliance upon the
authority of said firm as experts in accounting and auditing in giving said
reports.

The information incorporated by reference in this prospectus regarding
proved reserves as of December 31, 1996 and the related future net revenues and
the present value thereof is derived, as and to the extent described herein,
from the reserve report prepared by Miller and Lents, Ltd., independent oil and
gas consultants, and, to such extent, are included herein in reliance upon the
authority of such firm as experts with respect to such report.

22
<PAGE> 138
==============================================================

NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY
REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS SUPPLEMENT OR THE
PROSPECTUS, AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT
BE RELIED UPON AS HAVING BEEN AUTHORIZED. THIS PROSPECTUS SUPPLEMENT AND THE
PROSPECTUS DO NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO
BUY ANY SECURITIES OTHER THAN THE SECURITIES DESCRIBED IN THIS PROSPECTUS
SUPPLEMENT OR AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY SUCH
SECURITIES IN ANY CIRCUMSTANCES IN WHICH SUCH OFFER OR SOLICITATION IS UNLAWFUL.
NEITHER THE DELIVERY OF THIS PROSPECTUS SUPPLEMENT OR THE PROSPECTUS NOR ANY
SALE MADE HEREUNDER OR THEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY
IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE
THE DATE HEREOF OR THAT THE INFORMATION CONTAINED HEREIN OR THEREIN IS CORRECT
AS OF ANY TIME SUBSEQUENT TO ITS DATE.

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

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PROSPECTUS SUPPLEMENT
Summary............................... S-3
Forward-Looking Statements............ S-11
Risk Factors.......................... S-11
Use of Proceeds....................... S-18
Capitalization........................ S-19
Price Range of Common Stock........... S-20
Dividend Policy....................... S-20
Selected Historical Financial Data.... S-21
Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................... S-22
Business and Properties............... S-31
Management............................ S-54
Description of Preferred Stock........ S-58
Certain Federal Income Tax
Considerations...................... S-65
Legal Matters......................... S-68
Experts............................... S-68
Glossary of Oil and Gas Terms......... S-69
Index to Financial Statements......... F-1
Underwriting.......................... U-1
PROSPECTUS
Available Information................. 2
Incorporation of Certain Documents by
Reference........................... 3
The Company........................... 3
Use of Proceeds....................... 3
Description of Debt Securities........ 4
Description of Capital Stock.......... 14
Plan of Distribution.................. 21
Validity of Securities................ 22
Experts............................... 22
</TABLE>

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3,800,000 SHARES

BELCO OIL & GAS CORP.

6 1/2% CONVERTIBLE PREFERRED STOCK
(LIQUIDATION PREFERENCE $25.00 PER SHARE)

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[BELCO LOGO]

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GOLDMAN, SACHS & CO.

SALOMON SMITH BARNEY

HOWARD, WEIL,
LABOUISSE, FRIEDRICHS
INCORPORATED

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