BELCO OIL & GAS CORP, 424B5, 2000-11-28

BELCO OIL & GAS CORP
424B5, 2000-11-28
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1

Filed Pursuant to Rule 424(b)(5)
Registration No. 333-42107
SUBJECT TO COMPLETION, DATED NOVEMBER 27, 2000

THE INFORMATION IN THIS PROSPECTUS SUPPLEMENT IS NOT COMPLETE AND MAY BE
CHANGED. A REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED
AND IS EFFECTIVE. THIS PROSPECTUS SUPPLEMENT IS NOT AN OFFER TO SELL THESE
SECURITIES AND IT IS NOT SOLICITING AN OFFER TO BUY THESE SECURITIES IN ANY
STATE WHERE THE OFFER OR SALE IS NOT PERMITTED.

PROSPECTUS SUPPLEMENT
(TO PROSPECTUS DATED DECEMBER 24, 1997)

4,000,000 SHARES

[BELCO LOGO]
BELCO OIL & GAS CORP.
COMMON STOCK
$ PER SHARE

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

Belco Oil & Gas Corp. is offering and selling 4,000,000 shares of its common
stock with this prospectus supplement.

The common stock is listed on the New York Stock Exchange under the symbol
"BOG." On November 27, 2000, the last reported sale price for the common stock
on the New York Stock Exchange was $9.50 per share.

INVESTING IN THE COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" BEGINNING ON
PAGE S-12 OF THIS PROSPECTUS SUPPLEMENT.

<TABLE>
<CAPTION>
PER SHARE TOTAL
--------- --------
<S> <C> <C>
Price to the public.............................. $ $
Underwriting discount............................
Proceeds to Belco................................
</TABLE>

We have granted an over-allotment option to the underwriters. Under this option,
the underwriters may elect to purchase a maximum of 600,000 additional shares
from us within 30 days following the date of this prospectus supplement to cover
over-allotments.

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

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS
PROSPECTUS SUPPLEMENT OR THE ACCOMPANYING PROSPECTUS IS TRUTHFUL OR COMPLETE.
ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

CIBC WORLD MARKETS DAIN RAUSCHER WESSELS

The date of this prospectus supplement is , 2000.
<PAGE> 2
[Description of Prospectus Supplement artwork

Title centered at the top of the page reads "Belco Core Areas." Graphic depicts
a green and brown relief map of the United States with four areas delineated in
dark green. Each of the following textual phrases lies outside the map and is
connected to one of the four green areas by an arrow:

"Rocky Mountain 149 BCFE reserves," "Mid-Continent 144 BCFE reserves,"
"Permian Basin 247 BCFE reserves" and "Gulf Coast 101 BCFE reserves."

Caption centered below the map reads: "December 31, 1999 Total Proved Reserves
of 641 BCFE."

Text below caption, with the name of each region in green lettering, reads:

"Rocky Mountain exploration potential on 1.4 million gross acres, gas
development drilling and horizontal exploration and development drilling
for oil

Gulf Coast exploration drilling, gas development through horizontal and
vertical drilling programs

Permian Basin secondary recovery and exploitation through waterfloods,
recompletions and drilling

Mid-Continent secondary recovery and exploitation through waterfloods,
recompletions and drilling"]
<PAGE> 3

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PROSPECTUS SUPPLEMENT

About this Prospectus Supplement............................ S-4
Cautionary Statement About Forward-Looking Statements....... S-4
Where You Can Find More Information......................... S-4
Prospectus Supplement Summary............................... S-5
Risk Factors................................................ S-12
Use of Proceeds............................................. S-19
Price Range of Common Stock and Dividend Policy............. S-19
Capitalization.............................................. S-20
Selected Historical Financial Information................... S-21
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. S-23
Business.................................................... S-32
Management.................................................. S-39
Underwriting................................................ S-41
Legal Matters............................................... S-42
Experts..................................................... S-43
Glossary of Certain Industry Terms.......................... S-43
Index to Consolidated Financial Statements.................. F-1

PROSPECTUS

Available Information....................................... 2
Incorporation of Certain Documents by Reference............. 3
The Company................................................. 3
Use of Proceeds............................................. 3
Ratios of Earnings to Fixed Charges and Earnings to Combined
Fixed Charges and Preferred Stock Dividends............... 4
Description of Debt Securities.............................. 4
Description of Capital Stock................................ 14
Plan of Distribution........................................ 20
Validity of Securities...................................... 21
Experts..................................................... 21
</TABLE>

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

Our principal executive offices are located at 767 Fifth Avenue, 46th Floor, New
York, New York 10153. Our telephone number is (212) 644-2200.

As used in this prospectus supplement, the terms "Belco," "Company," "we,"
"our," and "us" refer to Belco Oil & Gas Corp. and its subsidiaries (unless the
context indicates a different meaning), and the term "common stock" means our
common stock, par value $0.01 per share. The term "you" refers to a prospective
investor. We have included definitions of technical terms important to an
understanding of our business under "Glossary of Certain Industry Terms"
beginning on page S-43.

The underwriters are offering these shares subject to various conditions and may
reject all or any part of any order.

S-3
<PAGE> 4

ABOUT THIS PROSPECTUS SUPPLEMENT

This document is in two parts. The first part is the prospectus supplement,
which describes our business and the specific terms of this offering. The second
part is the base prospectus, which gives more general information, some of which
may not apply to this offering. Generally, when we refer only to the
"prospectus," we are referring to both parts combined.

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

This prospectus supplement, the base prospectus and the information incorporated
by reference contain forward-looking statements with respect to the financial
condition, results of operations, plans, objectives, future performance and
business of Belco. Forward-looking statements typically are identified by use of
terms such as "may," "will," "expect," "anticipate," "estimate," "believe," and
similar words, although some forward-looking statements are expressed
differently. These statements appear in a number of places and include
statements regarding our plans, beliefs or current expectations, including those
plans, beliefs and expectations of our officers and directors with respect to,
among other things, future operating results or the ability to generate income
or cash flows.

These forward-looking statements involve certain risks and uncertainties. When
considering such forward-looking statements, you should keep in mind the risk
factors and other cautionary statements in this prospectus supplement, the base
prospectus and the information incorporated by reference. You should understand
that various factors, in addition to those discussed elsewhere in this
prospectus supplement, the base prospectus and in the documents referred to or
incorporated by reference in this document, could affect the future results of
Belco and could cause actual results to differ materially from those expressed
in these forward-looking statement, including the risks described under "Risk
Factors."

You are cautioned not to place undue reliance on these forward-looking
statements, which speak only as of the date of this prospectus supplement and
the base prospectus or, in the case of documents incorporated by reference, the
dates of those documents.

All subsequent written and oral forward-looking statements attributable to Belco
or any person acting on its behalf are expressly qualified in their entirety by
the cautionary statements contained or referred to in this section.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and special reports, proxy statements and other
information with the SEC. You may read and copy any document we file at the
SEC's Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549.
Please call the SEC at 1-800-SEC-0330 for further information on the operation
of the Public Reference Room. Our SEC filings are also available to the public
at the SEC's web site at www.sec.gov. The SEC allows us to "incorporate by
reference" the information we file with them, which means that we can disclose
important information to you by referring you to those documents. The
information incorporated by reference is considered to be part of this
prospectus, and later information filed with the SEC will update and supersede
this information. See "Incorporation of Certain Documents by Reference" in the
base prospectus.

You may request a copy of filings that we incorporate by reference at no cost,
by writing or telephoning us at the following address:

767 Fifth Street, 46th Floor
New York, New York 10153
Attn: Secretary
Telephone: (212) 644-2200

S-4
<PAGE> 5

PROSPECTUS SUPPLEMENT SUMMARY

This prospectus supplement summary highlights selected information from this
prospectus supplement but may not contain all of the information that is
important to you. This prospectus supplement includes specific terms of the
offering of our common stock, information about our business and financial data.
We encourage you to read this prospectus supplement, including the "Risk
Factors" section in this prospectus supplement, the base prospectus and the
documents we incorporate by reference, before making an investment decision.

THE COMPANY

- Rocky Mountain

- Gulf Coast

- Permian Basin

- Mid-Continent

In these areas we have accumulated detailed geologic and geophysical knowledge
and have developed significant technical and operational expertise. At December
31, 1996, our estimated proved reserves were approximately 305 Bcfe and our
reserve to production ratio was approximately 5 to 1. Through a balanced growth
strategy, we have increased our estimated proved reserves to approximately 641
Bcfe at December 31, 1999, while also increasing our reserve to production ratio
to over 10 to 1. We believe our platform of stable long-lived reserves coupled
with our exploration, acquisition and development activities position Belco for
future growth.

We have significant exploration, exploitation and development drilling
activities in our Rocky Mountain and Gulf Coast core areas, with a $58.2 million
drilling budget in these areas for 2001. We currently control approximately 1.4
million gross undeveloped acres in the Rocky Mountain area, which represents one
of the larger leasehold positions among independents in this area. This acreage
position is concentrated in the Green River, Wind River and Big Horn Basins of
Wyoming. To date, we have identified 11 significant multi-well prospects on this
acreage, and we are continuing to evaluate additional opportunities in this
area. In addition, we have ongoing drilling programs in the Moxa Arch of Wyoming
and the Williston Basin of North Dakota. We have drilled over 200 gross wells in
the Moxa Arch since 1992 and have budgeted to drill an additional 20 gross wells
by the end of 2001. We drilled our first Mission Canyon horizontal well in the
Williston Basin in late 1999. We currently have two rigs active in the Williston
Basin and have completed 11 wells on four different discoveries. We have
identified over 75 additional potential exploration and development drilling
locations in this expanding play.

In the upper Gulf Coast area of Texas, we have completed an approximately 140
square mile 3-D seismic survey targeting objectives from the shallow Yegua
formation to the lower Wilcox formation. Our geological and geophysical team has
identified eight potential lower Wilcox prospects using this 3-D seismic data.
We are currently completing the first directional well to test the lower Wilcox
and are preparing to drill a second lower Wilcox well on another prospect. We
also have a significant ongoing development drilling program in the Elm Grove
field of Northern Louisiana, where we have three rigs operating.

In the Permian Basin and Mid-Continent core areas, we concentrate primarily on
exploiting properties with proved reserves. Our exploitation activities include
secondary recovery operations, the drilling of development or infill wells,
workovers, and recompletions in other productive zones. We have currently
budgeted $12.8 million for these activities in 2001. We believe that the
long-lived nature of these reserves and our low-risk exploitation activities in
these core areas provide a stable base for growth of our reserves and
production.

S-5
<PAGE> 6

At December 31, 1999, we had estimated proved reserves of 641 Bcfe, of which
approximately 75% were proved developed and 50% were gas. These reserves had a
present value of approximately $635.0 million using oil and gas prices as of
December 31, 1999, which averaged $2.14 per Mcf for gas and $23.79 per Bbl for
oil. If oil and gas prices as of September 30, 2000 were used in this
determination (assuming no other changes since December 31, 1999, for such items
as production, dispositions, acquisitions or revisions based on subsequent
data), our estimated proved reserves at December 31, 1999 would have increased
to 664 Bcfe (due to the extension of the economic life of the properties) and
the present value would have increased to $1.2 billion. Using oil and gas prices
as of September 30, 2000 would have resulted in average prices of $4.98 per Mcf
for gas and $29.05 per Bbl for oil. These present value calculations also do not
give effect to the value of our commodity price risk management liabilities,
which were $31.7 million at December 31, 1999 and $152.1 million at September
30, 2000.

For the nine months ended September 30, 2000, we had commodity price risk
management settlements that equated to approximately 95% of our oil production
and approximately 65% of our gas production. These positions at September 30,
2000, which cover production through 2003, equated to approximately 86.8 Bcfe,
or approximately 13% of our estimated proved reserves at December 31, 1999. For
the three months ending December 31, 2000, we have commodity price risk
management positions that equate to approximately 90% of our estimated oil
production at a weighted average price of $18.75 per Bbl and approximately 55%
of our estimated gas production at a weighted average price of $2.40 per MMbtu.
For 2000, we estimate our oil and gas production will be approximately 65 Bcfe,
of which approximately 63% will be gas. We intend to reduce our level of
commodity price risk management positions over time. As existing positions
expire, we intend to reduce our total positions to no more than approximately
50% of our production in the future.

For the nine months ended September 30, 2000, we had net average daily
production of 178.9 MMcfe, revenues of $148.8 million, EBITDA of $85.8 million
and cash flow from operating activities of $72.0 million. We spent approximately
$146.7 million on capital projects during this period, including approximately
$44.6 million for the drilling of 80 gross development wells, 98 recompletions
and workover projects; approximately $23.8 million for the drilling of 21 gross
exploration wells; and approximately $70.0 million for the acquisition of 86
Bcfe of proved reserves estimated as of the date of acquisition. During this
period our success rate for drilling development wells was 96% and our success
rate for drilling exploration wells was 71%. For the three months ending
December 31, 2000, we have budgeted approximately $24.0 million for additional
drilling and other capital projects.

RECENT DEVELOPMENTS

Since December 31, 1999, we have purchased oil and gas properties in our core
areas for an aggregate purchase price of approximately $70.0 million. The
primary assets acquired were oil properties located in the Lodgepole field in
the Williston Basin of North Dakota and gas properties located in the Elm Grove
field in Louisiana. The Lodgepole acquisition added an estimated 24.6 Bcfe of
proved reserves at the date of acquisition. The properties acquired in the
Williston Basin have extremely low lifting costs thereby providing attractive
operating margins and are in close proximity to our Mission Canyon horizontal
drilling area. The Elm Grove acquisition added an estimated 51.3 Bcfe of proved
reserves at the date of acquisition and over 80 proved undeveloped drilling
locations. Since the Elm Grove acquisition, we have drilled 28 gross development
wells and increased our net gas production from 5.3 MMcf per day at the time of
acquisition to an approximate current rate of 11.0 MMcf per day.

We have also acquired additional interests in a number of our existing operated
properties. The acquisitions completed in 2000 have added an estimated 5.4
MMBbls of oil and 53.3 Bcf of gas to our proved reserves at an acquisition cost
of $0.82/Mcfe.

We sold two North Texas fields effective August 1, 2000 for approximately $10.1
million and retained volumetric production payments totaling 246,000 Bbls. At
the time we sold these fields, our total net production from both fields was
approximately 1,200 BOPD. By selling these higher lifting cost fields, we
streamlined our operations by eliminating 436 producing wells and 212 water
injection wells.

S-6
<PAGE> 7

OUR STRATEGY

Our primary objective is to increase net asset value per share by increasing oil
and gas reserves, production, cash flow and net income through development and
exploratory drilling, by acquiring and exploiting proven oil and gas properties
and by maintaining a low operating and corporate cost structure. The elements of
our strategy include the following:

Balanced Growth Initiatives. We pursue growth on both a strategic and
opportunistic basis. Our growth initiatives include:

- development drilling of lower risk infill and stepout locations;

- exploratory drilling of higher risk, higher potential prospects generally
supported by 3-D seismic analysis;

- exploitation efforts such as secondary recovery operations, well workovers,
recompletions and fracture stimulations; and

- strategic acquisitions of properties in our core areas with proved reserves,
established production histories, exploration or development potential and a
high percentage of operational control.

We believe we can create significant value by applying our technical and
operational skills to acquire properties and by achieving cost and marketing
efficiencies from our core area infrastructures. We may use our common stock as
acquisition currency when we believe it will be beneficial to our stockholders.

Core Area Concentration. We have focused our assets and operations in four core
areas. This focus enables us to achieve operational and economic efficiencies
and to build a strong technical knowledge base of the geology and reservoir
characteristics common to these areas. We seek to obtain operational control of
our major properties, which allows us to manage the selection and timing of our
drilling and exploitation projects. We operate properties representing
approximately 75% of our estimated proved reserves at December 31, 1999. By
creating concentrated areas of reserves and production, we are often able to
negotiate more favorable product marketing and field service agreements. The
complementary nature and varying characteristics of our core areas allows us to
selectively focus on adding long-lived or high deliverability production, oil or
gas reserves, and lower risk or higher risk projects as industry conditions and
corporate objectives warrant.

Leverage Core Competencies. In order to successfully implement our balanced
growth strategy, we have developed several core competencies. We have a
technical staff of 27 geologists, geophysists and engineers and have extensive
experience in 3-D seismic analysis, horizontal drilling and development of low
permeability gas sands through advanced fracture stimulations. We also have a
long history of successful design and implementation of waterflood recovery in
the Permian Basin and Mid-Continent areas.

S-7
<PAGE> 8

THE OFFERING

Common stock offered.................... 4,000,000 shares(1)

Common stock to be outstanding after the
offering................................ 36,342,015 shares(1)(2)

Use of proceeds......................... To reduce indebtedness incurred to
finance acquisitions.

New York Stock Exchange symbol.......... BOG
---------------------------

(1) Does not include up to 600,000 shares of common stock that the underwriters
may purchase if they exercise their over-allotment option.

(2) Does not include 1,775,750 shares of common stock issuable upon exercise of
outstanding stock options or 3,696,549 shares of common stock issuable upon
conversion of our outstanding shares of 6 1/2% convertible preferred stock.

RISK FACTORS

Before investing in our common stock, you should consider the risk factors and
the impact from various events that could adversely affect our business. See
"Risk Factors" beginning on page S-12.

S-8
<PAGE> 9

SUMMARY CONSOLIDATED FINANCIAL AND OPERATING DATA

You should read the following information together with "Selected Historical
Financial Information," "Management's Discussion and Analysis of Financial
Condition and Results of Operations," and the historical financial statements
and related notes included or incorporated by reference in this prospectus
supplement and the base prospectus. The results of operations for the nine
months ended September 30, 2000 should not be regarded as indicative of results
for the full year.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
------------------- -----------------------------------------------------
2000 1999 1999 1998 1997 1996 1995
-------- -------- -------- --------- -------- -------- --------
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales, net of cash hedging
activities(1).......................... $148,841 $104,215 $141,932 $ 129,916 $129,994 $119,710 $ 68,767
Non-hedge commodity price risk management
activities cash settlements(1)(2)...... (22,738) (121) (2,442) 172 (1,551) 3,417 9,480
Interest and other....................... 714 675 1,134 1,730 3,245 2,653 353
-------- -------- -------- --------- -------- -------- --------
Total revenues......................... 126,817 104,769 140,624 131,818 131,688 125,780 78,600
Costs and Expenses:
Oil and gas operating expenses........... 25,427 22,162 29,854 33,615 7,358 6,296 4,012
Production taxes......................... 10,924 6,986 9,314 7,232 5,400 1,551 1,812
Depreciation, depletion and
amortization........................... 41,666 40,259 54,182 56,102 46,684 40,904 27,590
Impairment of oil and gas properties..... -- -- -- 229,000 150,000 -- --
Impairment of equity securities.......... -- -- 450 24,216 -- -- --
General and administrative............... 4,651 3,651 4,940 5,216 3,913 3,059 2,597
Interest expense......................... 18,632 16,188 21,021 21,013 1,668 -- --
Non-cash change in fair value of
derivatives(1)......................... 70,614 45,225 34,094 (18,912) 4,928 9,384 --
-------- -------- -------- --------- -------- -------- --------
Total costs and expenses............... 171,914 134,471 153,855 357,482 219,951 61,194 36,011
-------- -------- -------- --------- -------- -------- --------
Income (loss) before income taxes.......... (45,097) (29,702) (13,231) (225,664) (88,263) 64,586 42,589
Provision (benefit) for income taxes(3).... (15,784) (10,396) (4,631) (78,107) (31,355) 21,953 13,852
-------- -------- -------- --------- -------- -------- --------
Net income (loss)(3)....................... (29,313) (19,306) (8,600) (147,557) (56,908) 42,633 28,737
Preferred stock dividends.................. (4,692) (5,205) (6,884) (5,406) -- -- --
-------- -------- -------- --------- -------- -------- --------
Net income (loss) available to common
stock.................................... $(34,005) $(24,511) $(15,484) $(152,963) $(56,908) $ 42,633 $ 28,737
======== ======== ======== ========= ======== ======== ========
Net income (loss) per share of common
stock, basic and diluted(3).............. $ (1.09) $ (0.78) $ (0.49) $ (4.85) $ (1.80) $ 1.42 $ 1.15
======== ======== ======== ========= ======== ======== ========
Weighted average common shares
outstanding(4)........................... 31,259 31,600 31,642 31,529 31,538 29,986 25,000
======== ======== ======== ========= ======== ======== ========
OTHER FINANCIAL DATA:
EBITDA(5).................................. $ 85,815 $ 71,970 $ 96,516 $ 85,755 $115,017 $114,874 $ 70,179
Capital expenditures....................... 136,030 51,827 73,183 126,506 564,459 142,712 71,387
Cash flow from operating activities........ 72,005 54,264 78,044 86,345 101,523 108,059 62,037
BALANCE SHEET DATA (AT END OF PERIOD):
Total assets............................... $618,614 $501,941 $510,973 $ 505,536 $697,109 $303,918 $145,550
Long-term debt............................. 374,819 302,013 306,744 294,990 352,090 -- 22,000
Total stockholders' equity................. 80,068 112,329 113,972 138,292 184,648 233,203 105,015
</TABLE>

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Footnotes on next page.

S-9
<PAGE> 10

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

(1) Through June 30, 2000, we reported all commodity price risk management
activities, hedge and non-hedge, including non-cash gains or losses, as
components of revenue, which, in management's opinion, can materially
distort the amount of actual revenues received due to the volatile nature
of oil and gas prices. Effective with the nine months ended September 30,
2000, all periods have been restated to report commodity price risk
management hedge settlements as part of oil and gas revenues, commodity
price risk management non-hedge settlements as a separate revenue component
and unrealized commodity price risk management non-cash gains or losses as
a component of costs and expenses. The restatement of all such amounts did
not result in any changes to previously reported net income or loss,
including per share amounts.
(2) Includes cash premiums received and paid.
(3) 1996 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 in
connection with our initial public offering. See note 1 of notes to the
consolidated financial statements.
(4) Earnings per share have 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. See note 1 of notes to the
consolidated financial statements.
(5) EBITDA is defined as net income attributable to common stock, plus
interest, income taxes, depreciation, depletion and amortization, preferred
dividends, impairments of oil and gas properties and equity securities and
non-cash change in fair value of derivatives. EBITDA is not a measure of
income or cash flow in accordance with generally accepted accounting
principles, but is presented as a supplemental financial indicator as to
our ability to service or incur debt. EBITDA is not presented as an
indicator of cash available for discretionary spending. EBITDA is a
financial measure commonly used in our industry and should not be
considered in isolation or as a substitute for net income, net cash
provided by operating activities or any other measure of financial
performance prepared in accordance with generally accepted accounting
principles or as a measure of our profitability or liquidity. Because
EBITDA excludes some, but not all, items that affect net income and may
vary among companies, the EBITDA presented above may not be comparable to
similarly titled measures of other companies.
(6) Includes the effect of cash hedge settlements.

S-10
<PAGE> 11

SUMMARY OIL AND GAS RESERVE DATA

Our estimated proved reserves and present values at December 31, 1999, 1998,
1997, 1996 and 1995 are shown in the following table. The estimates at December
31, 1996 and 1995 were prepared by Miller and Lents, Ltd., our independent
petroleum engineers. For December 31, 1999, 1998 and 1997 approximately 83%, 83%
and 94%, respectively, of the quantities of proved reserves on an Mcfe basis
aggregating 84%, 92% and 96%, respectively, of the present values were estimated
by Miller and Lents, Ltd. Our internal petroleum engineers estimated the
remaining proved reserves and present values in those years. In accordance with
SEC guidelines, the estimates of proved reserves and present values were made
using oil and gas sales prices and costs in effect at the end of each period
indicated and were held constant throughout the life of the properties. The
estimated value of proved reserves set forth below have been adjusted for hedge
positions that were not reviewed by Miller and Lents, Ltd. See note 14 of notes
to consolidated financial statements. See "Cautionary Statement About Forward
Looking Statements" and "Risk Factors."

<TABLE>
<CAPTION>
AT DECEMBER 31,
--------------------------------------------
1999 1998 1997 1996 1995
-------- ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
ESTIMATED PROVED OIL AND GAS RESERVES:
Gas reserves (Bcf):
Proved developed........................................ 224.1 213.5 226.1 184.9 140.7
Proved undeveloped...................................... 98.0 72.0 71.1 100.1 63.5
-------- ------ ------ ------ ------
Total................................................. 322.1 285.5 297.2 285.0 204.2
======== ====== ====== ====== ======
Oil reserves (MMBbls):
Proved developed........................................ 42.4 41.5 41.3 2.1 1.8
Proved undeveloped...................................... 10.7 11.6 9.9 1.2 0.7
-------- ------ ------ ------ ------
Total................................................. 53.1 53.1 51.2 3.3 2.5
======== ====== ====== ====== ======
Total estimated proved reserves (Bcfe).................... 640.7 604.1 604.4 304.8 218.9
ESTIMATED VALUE OF PROVED RESERVES (IN MILLIONS)(1):
Total present value....................................... $ 626.5 $360.6 $510.4 $415.5 $206.5
Future net inflows before income taxes.................... 1,246.2 711.2 938.0 747.3 294.6
PRICES USED IN CALCULATING END OF YEAR PROVED RESERVES:
Gas (per Mcf)............................................. $ 2.14 $ 2.20 $ 2.30 $ 3.68 $ 1.96
Oil (per Bbl)............................................. 23.79 10.85 17.28 25.13 18.38
OTHER RESERVE DATA:
Reserve to production ratio (in years).................... 10.6 9.7 10.5 5.4 5.1
Gas reserves as a percent of total proved reserves........ 50.3% 47.3% 49.1% 93.4% 93.3%
Proved developed reserves as a percent of total proved
reserves................................................ 74.7% 76.6% 78.4% 64.7% 69.3%
</TABLE>

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

(1) Includes the effect of hedge positions.

S-11
<PAGE> 12

RISK FACTORS

You should carefully consider the following risk factors, in addition to the
other information included or incorporated by reference in this prospectus
supplement and the base prospectus, before purchasing shares of our common
stock. In addition, please read "Cautionary Statement About Forward-Looking
Statements" on page S-4 of this prospectus supplement, where we describe
additional uncertainties associated with our business and the forward-looking
statements included or incorporated by reference in this prospectus supplement
and the base prospectus. Each of these risk factors could adversely affect our
business, operating results and financial condition, as well as adversely affect
the value of your investment in our common stock.

OIL AND GAS PRICES ARE VOLATILE, AND AN EXTENDED DECLINE IN PRICES COULD
ADVERSELY AFFECT BELCO'S REVENUES, CASH FLOWS AND PROFITABILITY.

Our revenues, operating results, profitability, future rate of growth and the
carrying value of our oil and gas properties depend substantially upon the
prevailing prices of oil and gas. We expect the markets for oil and gas to
continue to be volatile. Prices also affect the amount of cash flow available
for capital expenditures and our ability to borrow money or raise additional
capital. The amount we can borrow from banks is subject to redetermination based
on current prices. In addition, we may have ceiling test writedowns when prices
decline. Lower prices may also reduce the amount of oil and gas that we can
produce economically.

We cannot predict future oil and gas prices. Factors that can cause oil and gas
prices to fluctuate include:

- relatively minor changes in the supply of and demand for oil and gas;

- market uncertainty;

- the level of consumer and industrial 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 gas;

- the price of oil and gas imports; and

- overall economic conditions.

OUR RECENT COMMODITY PRICE RISK MANAGEMENT ACTIVITIES HAVE RESULTED IN LOSSES.
OUR COMMODITY PRICE RISK MANAGEMENT TRANSACTIONS MAY LIMIT OUR POTENTIAL GAINS.

In 1999 and for the first nine months of 2000, we recorded non-hedge commodity
price risk management losses of $36.5 million and $93.4 million, respectively.
These losses consisted of $2.4 million and $22.7 million in cash settlements and
$34.1 million and $70.6 million in unrealized non-cash mark-to-market losses due
to substantial increases in commodity prices for 1999 and the nine months ended
September 30, 2000, respectively. For the three months ending December 31, 2000,
we have commodity price risk management positions that equate to approximately
90% of our estimated oil production at a weighted average price of $18.75 per
Bbl and 55% of our estimated gas production at a weighted average price of $2.40
per MMbtu. We expect to incur additional hedge and non-hedge related cash
settlement costs through the remainder of calendar year 2000 assuming commodity
prices remain at current levels. We believe that our losses from commodity price
risk management transactions will increase significantly due to price increases
since September 30, 2000. We can give you no assurance as to the ultimate size
of these losses.

For the year 2001, Belco has approximately 6,082 BOPB and 85,000 MMBtu of gas
per day committed at average prices of $19.60 per Bbl of oil and $2.45 per MMBtu
of gas. The committed volumes assume the

S-12
<PAGE> 13

NYMEX forward curve reference prices as of September 30, 2000. No estimate of
settlements or mark-to-market gains or losses are determinable as such amounts
are contingent upon commodity prices at the time of production. We cannot assure
you that we will not experience additional losses from these activities.

Certain of Belco's commodity price risk management arrangements require Belco to
deliver cash collateral or other assurances of performance to the counterparties
in the event that Belco's payment obligations with respect to its commodity
price risk management transactions exceed certain levels. Two of the inherent
risks of a price risk management program are margin requirements and
collateralization. Certain transactions may be subject to margin calls under
certain conditions including change of ownership control, rating agency activity
or default. Belco's current collateral requirement is $27.5 million consisting
of $26.5 million in letters of credit and $1.0 million in cash deposits. We can
give you no assurance that we will have sufficient financial resources to meet
any additional collateral requirements.

In order to manage our exposure to price volatility in marketing our oil and
gas, we enter into oil and gas price risk management arrangements for a portion
of our expected production. These transactions are limited in life. While
intended to reduce the effects of volatile oil and gas prices, commodity price
risk management transactions may limit our potential gains if oil and gas prices
were to rise substantially over the price established by the arrangements. In
addition, our commodity price risk management transactions may expose us to the
risk of financial loss in certain circumstances, including instances in which:

- our production is less than expected;

- there is a widening of price differentials between delivery points for our
production and time delivery point assumed in the hedge arrangement; or

- the counterparties to our contracts fail to perform the contracts.

WE MAY NOT BE ABLE TO GENERATE OR OBTAIN SUFFICIENT CAPITAL TO EXECUTE OUR
OPERATING STRATEGY.

We have experienced, and expect to continue to experience, substantial capital
needs as a result of our exploration, development and acquisition strategies. We
have historically addressed our capital needs by using our bank credit facility,
using cash provided by operating activities and issuing debt and equity
securities.

We continue to examine the following alternative sources of capital:

- bank borrowings or the issuance of debt securities;

- the sale of common stock or preferred stock;

- sales of non-strategic properties;

- sales of prospect and technical information; and

- joint venture financing.

The availability of these sources of capital will depend upon a number of
factors, some of which are beyond our control. These factors include general
economic and financial market conditions, oil and gas prices and the value and
performance of Belco. We will be unable to fully execute our operating strategy
if we cannot generate or obtain sufficient capital from these or other sources.

ESTIMATES OF OIL AND GAS RESERVES ARE UNCERTAIN AND INHERENTLY IMPRECISE.

This prospectus supplement and information incorporated by reference in the
prospectus contain estimates of our proved reserves and the estimated future net
revenues from our proved reserves. These estimates are based upon various
assumptions, including assumptions required by the SEC relating 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. The process involves significant decisions and assumptions in the
evaluation of available geological, geophysical, engineering and economic data
for each reservoir. Therefore, these estimates are inherently imprecise.

S-13
<PAGE> 14

Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves most likely will vary from these estimates. Such variations may be
material. In addition, we may adjust estimates of proved reserves to reflect
production history, results of exploration and development drilling, prevailing
oil and gas prices and other factors, many of which are beyond our control. In
certain situations, hydrocarbon reservoirs underlying our properties may extend
beyond the boundaries of our own acreage into acreage owned by others. In this
case, our properties may also be susceptible to hydrocarbon drainage from
production by the operators on those adjacent properties. Any significant
variance could materially affect the estimated quantities and present value of
our proved reserves.

At December 31, 1999, approximately 25% of our estimated proved reserves were
undeveloped. Recovery of undeveloped reserves requires significant capital
expenditures and successful drilling operations. The estimates of our future
reserves include the assumption that we will make significant capital
expenditures to develop our reserves, including $28.0 million in 2001. Although
we have prepared estimates of our oil and gas reserves and the costs associated
with these reserves in accordance with industry standards, we cannot assure you
that the estimated costs are accurate, that development will occur as scheduled
or that the results will be as estimated.

You should not assume that the present value referred to in this prospectus
supplement or in the information incorporated by reference in the base
prospectus is the current market value of our estimated oil and gas reserves. In
accordance with SEC requirements, the estimate of present value is generally
based on prices and costs as of the date of the estimate. Actual future prices
and costs may be materially higher or lower than the prices and costs as of the
date of the estimate. Any changes in consumption by oil and gas purchasers or in
governmental regulations or taxation will also affect actual future net cash
flows.

We have included in this prospectus supplement certain reserve information and
present values that were calculated using oil and gas prices at September 30,
2000. We have calculated this reserve information using estimates of oil and gas
reserves at December 31, 1999. We have not recalculated our reserve volumes at
September 30, 2000 to account for production, acquisitions, dispositions or
revisions since December 31, 1999. This information was included solely to
demonstrate the effect of the dramatic rise in oil and gas prices on the value
of our proved reserves. As described above, the present values may not represent
actual values of our proved reserves.

The timing of both the production and the expenses from the development and
production of oil and gas properties will affect both the timing of actual
future net cash flows from proved reserves and their present value. In addition,
the 10% discount factor, which is required by the SEC to be used in calculating
discounted future net cash flows for reporting purposes, is not necessarily the
most accurate discount factor. The effective interest rate at various times and
the risks associated with our business or the oil and gas industry in general
will affect the accuracy of the 10% discount factor.

LEVERAGE MAY ADVERSELY AFFECT FINANCIAL CONDITION, OUR ABILITY TO FINANCE OUR
OPERATIONS AND THE CONDUCT OF OUR BUSINESS.

As of September 30, 2000, our long-term debt was $374.8 million, including
$113.6 million outstanding under our bank credit facility. Our long-term debt
represented 82.4% of our total capitalization at September 30, 2000.

Our debt affects our operations in several important ways, including the
following:

- a significant portion of our cash flow from operations is used to pay
interest on our borrowings;

- the covenants contained in the agreements governing our debt limit our
ability to borrow additional funds or to dispose of assets;

- the covenants contained in the agreements governing our debt may affect our
flexibility in planning for, and reacting to, changes in business conditions;

S-14
<PAGE> 15

- a high level of debt may impair our ability to obtain additional financing in
the future for working capital, capital expenditures, acquisitions, general
corporate or other purposes; and

- the terms of the agreements governing our debt permit our creditors to
accelerate payments upon an event of default or a change of control.

In addition, we may incur additional debt in order to make future acquisitions
or develop our properties. A higher level of debt increases the risk that we may
default on our debt obligations. Our ability to meet our debt obligations and to
reduce our level of debt depends on our future performance. General economic
conditions and financial, business and other factors affect our operations and
our future performance. Many of these factors are beyond our control.

If we are unable to repay our debt at maturity out of cash on hand, we could
attempt to refinance such debt, sell assets or repay such debt with the proceeds
of an equity offering. We cannot assure you that we will be able to generate
sufficient cash flow to pay the interest on our debt or that future working
capital, borrowings or equity financing will be available to pay or refinance
such debt. Factors that will affect our ability to raise cash through an
offering of our capital stock or a refinancing of our debt include financial
market conditions and our value and performance at the time of such offering or
other financing. We cannot assure you that any such offering or refinancing can
be successfully completed.

In addition, our bank borrowing base is subject to semi-annual redeterminations.
We could be forced to repay a portion of our bank borrowings due to
redeterminations of our borrowing base. We cannot assure you that we will have
sufficient funds to make such repayments. If we are not able to negotiate
renewals of our borrowings or arrange new financing, we may have to sell
significant assets. Any such sale could have a material adverse effect on our
business and financial results.

LOWER OIL AND GAS PRICES INCREASE THE RISK OF CEILING LIMITATION WRITEDOWNS.

We use the full cost method to account for our oil and gas operations. As a
result, we capitalize the cost to acquire, explore for and develop oil and gas
properties. Under full cost accounting rules, the net capitalized costs of oil
and gas properties may not exceed a "ceiling limit," 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. If net capitalized costs of oil and gas properties exceed the
ceiling limit, we must charge the amount of the excess to earnings. This is
called a "ceiling limitation writedown." This charge does not reduce cash flow
from operating activities, but does reduce the book value of our net tangible
assets and our stockholders' equity. The risk that we will be required to write
down the carrying value of oil and gas properties increases when oil and gas
prices are low or volatile. In addition, writedowns may occur if we experience
substantial downward adjustments to our estimated proved reserves, increases in
estimates of development costs or deterioration in exploration and exploitation
results. In 1998 and 1997, we recorded $229.0 million ($148.9 million after-tax)
and $150.0 million ($97.5 million after-tax), respectively, in non-cash ceiling
limitation writedowns after applying substantially lower commodity prices to
estimated recoverable reserves. We may experience ceiling limitation writedowns
in the future.

OUR ABILITY TO REPLACE PRODUCTION WITH NEW RESERVES IS HIGHLY DEPENDENT ON
ACQUISITIONS OR SUCCESSFUL DEVELOPMENT AND EXPLORATION ACTIVITIES.

In general, the volume of production from oil and gas properties declines as
reserves are depleted. Our reserves will decline as they are produced, unless we
acquire properties with proved reserves or conduct successful exploration and
development activities. Our future oil and gas production is highly dependent
upon our level of success in finding or acquiring additional reserves. The
business of exploring for, developing or acquiring reserves is capital intensive
and uncertain. We may be unable to make the necessary capital investment to
maintain or expand our oil and gas reserves if cash flow from operations is
reduced and external sources of capital become limited or unavailable. We cannot
assure you that our future exploration and development activities will result in
additional proved reserves or that we will be

S-15
<PAGE> 16

able to drill productive wells at acceptable costs. In addition, we may not be
able to acquire new properties with proved reserves at acceptable costs.

OUR EXPLORATION ACTIVITIES INVOLVE A HIGH DEGREE OF RISK AND MAY NOT BE
COMMERCIALLY SUCCESSFUL.

Oil and gas exploration involves a high degree of risk that hydrocarbons will
not be found, that they will not be found in commercial quantities, or that
their production will be insufficient to recover drilling, completion and
operating costs. The 3-D seismic data and other technologies we may use do not
allow us to know conclusively prior to drilling a well that oil or gas is
present or economically producible. The cost of drilling, completing and
operating a well is often uncertain, and cost factors can adversely affect the
economics of a project. Furthermore, completion of a well does not guarantee
that it will be profitable or even that it will result in recovery of drilling,
completion and operating costs. Therefore, we may not earn revenues with respect
to, or recover costs spent on, our exploration activities.

OUR SECONDARY RECOVERY PROJECTS REQUIRE SIGNIFICANT EXPENDITURES AND MAY NOT BE
COMMERCIALLY SUCCESSFUL.

Secondary recovery operations, such as waterflooding projects, may require us to
spend a significant amount of capital without any increase in production.
Although waterflooding requires significant capital expenditures, the total
amount of reserves that can be recovered through waterflooding is uncertain. In
addition, there is generally a delay between the initiation of water injection
into a formation containing hydrocarbons and any increase in production that may
result from the injection. The degree of success, if any, of any secondary
recovery program depends on a large number of factors. These factors include the
porosity, permeability and heterogeneity of the formation, the technique used
and the location of injection wells.

OUR OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF OIL AND GAS DRILLING AND
PRODUCTION ACTIVITIES.

Oil and gas drilling and production activities are subject to numerous risks,
including the risk that no commercially productive oil or gas reservoirs will be
found. The cost of drilling and completing wells is often uncertain. Oil and gas
drilling and production activities may be shortened, delayed or canceled as a
result of a variety of factors, many of which are beyond our control. These
factors include:

- unexpected drilling conditions;

- pressure irregularities in formations;

- equipment failures or accidents;

- weather conditions; and

- shortages in experienced labor or shortages or delays in the delivery of
equipment.

We cannot assure you that the new wells we drill or participate in will be
productive or that we will recover all or any of our investment. Drilling for
oil and gas may be unprofitable. Drilling activities can result in dry holes and
wells that are productive but do not produce sufficient net revenues after
operating and other costs. In addition, our properties may be susceptible to
hydrocarbon draining from production by third party operations on adjacent
properties.

HIGHER OIL AND GAS PRICES ADVERSELY AFFECT THE COST AND AVAILABILITY OF DRILLING
AND PRODUCTION SERVICES.

Higher oil and gas prices, such as those we are currently experiencing,
generally stimulate increased demand and result in increased prices for drilling
rigs, crews and associated supplies, equipment and services. In the past, we
have had difficulty securing drilling equipment or crews in certain of our core
areas. We have recently experienced higher costs for drilling rigs and other
related services.

S-16
<PAGE> 17

OUR OIL AND GAS BUSINESS INVOLVES MANY OPERATING RISKS THAT COULD CAUSE US
SUBSTANTIAL LOSSES.

Our operating risks include the risk of fire, explosions, blow-outs, pipe
failure, abnormally pressured formations and environmental hazards.
Environmental hazards include oil spills, gas leaks, ruptures or discharges of
toxic gases. If any of these industry operating risks occur, we could have
substantial losses. Substantial losses may be caused by:

- 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 investigations and penalties; and

- suspension of operations.

In accordance with industry practice, we maintain insurance against some, but
not all, of the risks described above. We cannot assure you that our insurance
will be adequate to cover losses or liabilities. Also, we cannot predict the
continued availability of insurance at premium levels that justify its purchase.

WE OPERATE IN A HIGHLY COMPETITIVE INDUSTRY, WHICH MAY ADVERSELY AFFECT OUR
OPERATIONS.

We operate in a highly competitive environment. We compete with other oil and
gas companies for the acquisition of desirable oil and gas properties and the
equipment and labor required to develop and operate such properties. We also
compete with other oil and gas companies in the marketing and sale of oil and
gas. Many of our competitors have financial and other resources substantially
greater than ours.

OUR ACQUISITIONS ARE SUBJECT TO THE RISKS OF THE UNCERTAINTIES OF RECOVERABLE
RESERVES AND POTENTIAL LIABILITIES.

Our recent growth is due in part to acquisitions of producing properties. The
successful acquisition of producing properties requires an assessment of a
number of factors beyond our control. These factors include recoverable
reserves, future oil and gas prices, operating costs and potential environmental
and other liabilities. Such assessments are inexact and their accuracy is
inherently uncertain. In connection with our assessments, we perform a review of
the subject properties, which we believe is generally consistent with industry
practices. However, such a review will not reveal all existing or potential
problems. In addition, our review may not permit us to become sufficiently
familiar with the properties to fully assess their deficiencies and
capabilities. We do not inspect every well. Even when we inspect a well, we do
not always discover structural, subsurface and environmental problems that may
exist or arise.

We are generally not entitled to contractual indemnification for preclosing
liabilities, including environmental liabilities. Normally, we acquire interests
in properties on an "as is" basis with limited remedies for breaches of
representations and warranties. In addition, competition for producing oil and
gas properties is intense and many of our competitors have financial and other
resources which are substantially greater than those available to us. Therefore,
we cannot assure you that we will be able to acquire oil and gas properties that
contain economically recoverable reserves or that we will complete such
acquisitions on acceptable terms.

OUR OIL AND GAS OPERATIONS ARE SUBJECT TO VARIOUS FEDERAL, STATE AND LOCAL LAWS
AND REGULATIONS THAT MATERIALLY AFFECT OUR OPERATIONS.

Our oil and gas operations are subject to various federal, state and local
regulations. These regulations may be changed in response to economic or
political conditions. Matters regulated 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, federal, state and local governments allege that we have not
complied with their regulations and seek to impose fines on us. We cannot assure

S-17
<PAGE> 18

you that we will not be liable for substantial fines in the future for failing
to comply with federal, state or local laws or regulations.

At various times, regulatory agencies have imposed price controls and
limitations on production. In order to conserve supplies of oil and gas, these
agencies have restricted the rates of flow of oil and gas wells below actual
production capacity. Under federal and state environmental statutes, owners and
operators of certain defined facilities are strictly liable for spills, subject
to certain limitations. A substantial spill from one of our facilities could
have a material adverse effect on our results of operations, competitive
position or financial condition.

Federal, state and local laws regulate production, handling, storage,
transportation and disposal of oil and gas, by-products from oil and gas and
other substances and materials produced or used in connection with oil and gas
operations. To date, we have not been required to spend significant amounts to
comply with these laws or to remediate existing environmental contamination. We
believe that we are in substantial compliance with all applicable laws and
regulations. However, the requirements of such laws and regulations change
frequently. We cannot predict the ultimate cost of compliance with existing or
future requirements or their effect on our operations.

THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT OUR ABILITY TO OPERATE.

We depend, and will continue to depend in the foreseeable future, on the
services of our 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. Our ability to retain our officers and key
employees is important to our continued success and growth. The unexpected loss
of the services of one or more of these individuals could have a detrimental
effect on our business. We do not maintain key man life insurance on any of our
officers or key employees.

THE SIGNIFICANT OWNERSHIP POSITION OF THE BELFER FAMILY COULD LIMIT OUR ABILITY
TO ENTER INTO CERTAIN TRANSACTIONS.

Robert A. Belfer, his son Laurence D. Belfer, his brother-in-law Jack Saltz,
their spouses, and certain trusts for their respective children and
grandchildren own approximately 58.8% of the outstanding shares of our common
stock at September 30, 2000 and approximately 15.7% of the outstanding shares of
our preferred stock at September 30, 2000. 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 Belco and may adversely affect the voting and other rights of other
stockholders.

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<PAGE> 19

USE OF PROCEEDS

The net proceeds of this offering will be $ million ($ if the
underwriter's over-allotment option is exercised in full) after deducting the
underwriting discount and estimated offering expenses of $ .

We will use the net proceeds from this offering to reduce indebtedness under our
credit facility incurred to finance recent acquisitions. We will continue to
have the ability to reborrow amounts repaid under the terms of the credit
facility.

At November 24, 2000, we had $124.4 million of borrowings outstanding under our
credit facility bearing interest at an annual average rate of approximately
8.125%. This indebtedness was incurred primarily to fund the cost of property
acquisitions and a portion of the cost of our exploration and development
activities.

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

Our common stock is listed on the New York Stock Exchange under the symbol
"BOG." The following table sets forth the range of high and low sales prices per
share of common stock for the periods indicated, as reported by the New York
Stock Exchange.

<TABLE>
<CAPTION>
HIGH LOW
------ ------
<S> <C> <C>
1998
First Quarter............................................. $19.00 $16.75
Second Quarter............................................ 17.75 8.13
Third Quarter............................................. 11.25 6.63
Fourth Quarter............................................ 6.88 4.38
1999
First Quarter............................................. 6.38 4.75
Second Quarter............................................ 7.94 5.75
Third Quarter............................................. 7.63 6.25
Fourth Quarter............................................ 7.06 4.94
2000
First Quarter............................................. 11.25 5.25
Second Quarter............................................ 10.50 7.38
Third Quarter............................................. 9.63 8.00
Fourth Quarter (through November 24, 2000)................ $9.50 $8.63
</TABLE>

On November 27, 2000, the last reported sale price of the common stock on the
New York Stock Exchange was $9.50 per share. As of November 21, 2000, there were
119 holders of record of the common stock.

We have not paid in the past, and do not intend to pay, cash dividends on our
common stock. We intend to retain earnings, if any, for the future operation and
development of our business. There are restrictions on our ability to pay
dividends in the Nevada Corporation Law and in certain restrictive provisions in
the indentures executed in connection with our 8.875% Senior Subordinated Notes
due 2007 and our 10.5% Senior Subordinated Notes due 2006. In addition, we have
entered into a credit facility that contains provisions that may have the effect
of limiting or prohibiting the payment of dividends.

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<PAGE> 20

CAPITALIZATION

The following table sets forth our actual capitalization as of September 30,
2000 and our capitalization as adjusted to reflect the sale of 4,000,000 shares
of common stock in this offering and the application of the net proceeds as set
forth under "Use of Proceeds." The following table should be read in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the historical financial statements and related notes included
or incorporated by reference in this prospectus supplement and the base
prospectus.

<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 2000
------------------------
ACTUAL AS ADJUSTED
--------- ------------
(IN THOUSANDS)
<S> <C> <C>
LONG-TERM DEBT:
Credit facility........................................... $113,600 $
8.875% senior subordinated notes due 2007................. 147,000 147,000
10.5% senior subordinated notes due 2006(1)............... 114,219 114,219
-------- --------
Total long-term debt................................... $374,819 $
======== ========
STOCKHOLDERS' EQUITY:
6 1/2% convertible preferred stock, $0.01 par value;
10,000,000 shares authorized; 3,750,700 issued and
outstanding actual and as adjusted(2).................. $ 38 $ 38
Common stock, $0.01 par value; 120,000,000 shares
authorized; 31,805,240 shares issued actual and
35,805,240 issued as adjusted.......................... 318 358
Additional paid-in capital................................ 294,555
Retained deficit.......................................... (211,116) (211,116)
Treasury stock, 313,575 shares............................ (1,921) (1,924)
Unearned compensation..................................... (1,053) (1,053)
Notes receivable for equity interest...................... (753) (753)
-------- --------
Total stockholders' equity............................. 80,068
-------- --------
Total capitalization.............................. $454,887 $454,887
======== ========
</TABLE>

---------------------------
(1) $109 million face value carried at purchase accounting acquisition value of
106% of par amortized over the life of the notes.

(2) The 6 1/2% convertible preferred stock has a liquidation preference of
$25.00 per share.

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<PAGE> 21

SELECTED HISTORICAL FINANCIAL INFORMATION

The selected historical financial information presented below is derived from
our historical financial statements. The historical financial information
presented below for the nine month periods ended September 30, 2000 and 1999 is
derived from our unaudited historical financial statements and includes, in the
opinion of management, all normal and recurring adjustments necessary to present
fairly the data for such periods. The results of operations for the nine months
ended September 30, 2000 should not be regarded as indicative of results for the
full year.

You should read the following information in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the historical financial statements and the notes thereto included or
incorporated by reference in this prospectus supplement and the accompanying
prospectus.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
-------------------- -------------------------------------------------------
2000 1999 1999 1998 1997 1996 1995
--------- -------- -------- --------- --------- --------- --------
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales, net of cash hedging
activities(1)....................... $ 148,841 $104,215 $141,932 $ 129,916 $ 129,994 $ 119,710 $ 68,767
Non-hedge commodity price risk
management activities cash
settlements(1)(2)................... (22,738) (121) (2,442) 172 (1,551) 3,417 9,480
Interest and other.................... 714 675 1,134 1,730 3,245 2,653 353
--------- -------- -------- --------- --------- --------- --------
Total revenues...................... 126,817 104,769 140,624 131,818 131,688 125,780 78,600
Costs and Expenses:
Oil and gas operating expenses........ 25,427 22,162 29,854 33,615 7,358 6,296 4,012
Production taxes...................... 10,924 6,986 9,314 7,232 5,400 1,551 1,812
Depreciation, depletion and
amortization........................ 41,666 40,259 54,182 56,102 46,684 40,904 27,590
Impairment of oil and gas
properties.......................... -- -- -- 229,000 150,000 -- --
Impairment of equity securities....... -- -- 450 24,216 -- -- --
General and administrative............ 4,651 3,651 4,940 5,216 3,913 3,059 2,597
Interest expense...................... 18,632 16,188 21,021 21,013 1,668 -- --
Non-cash change in fair value of
derivatives(1)...................... 70,614 45,225 34,094 (18,912) 4,928 9,384 --
--------- -------- -------- --------- --------- --------- --------
Total costs and expenses............ 171,914 134,471 153,855 357,482 219,951 61,194 36,011
--------- -------- -------- --------- --------- --------- --------
Income (loss) before income taxes....... (45,097) (29,702) (13,231) (225,664) (88,263) 64,586 42,589
Provision (benefit) for income
taxes(3).............................. (15,784) (10,396) (4,631) (78,107) (31,355) 21,953 13,852
--------- -------- -------- --------- --------- --------- --------
Net income (loss)(3).................... (29,313) (19,306) (8,600) (147,557) (56,908) 42,633 28,737
Preferred stock dividends............... (4,692) (5,205) (6,884) (5,406) -- -- --
--------- -------- -------- --------- --------- --------- --------
Net income (loss) available to common
stock................................. $ (34,005) $(24,511) $(15,484) $(152,963) $ (56,908) $ 42,633 $ 28,737
========= ======== ======== ========= ========= ========= ========
Net income (loss) per share of common
stock, basic and diluted(3)........... $ (1.09) $ (0.78) $ (0.49) $ (4.85) $ (1.80) $ 1.42 $ 1.15
========= ======== ======== ========= ========= ========= ========
Weighted average common shares
outstanding(4)........................ 31,259 31,600 31,642 31,529 31,538 29,986 25,000
========= ======== ======== ========= ========= ========= ========
STATEMENT OF CASH FLOWS DATA:
Cash flow from operating activities..... $ 72,005 $ 54,264 $ 78,044 $ 86,345 $ 101,523 $ 108,059 $ 62,037
Cash flow used by investing
activities............................ (135,987) (52,284) (74,542) (138,526) (363,136) (143,826) (65,133)
Cash flow from (used by) financing
activities............................ 63,153 556 (3,832) 42,356 230,400 77,684 (2,299)
Capital expenditures.................... 136,030 51,827 73,183 126,506 564,459 142,712 71,387
BALANCE SHEET DATA:
Working capital(5)...................... $ (62,657) $(14,074) $ (8,389) $ 14,823 $ 36,757 $ 48,667 $ 446
Total assets............................ 618,614 501,941 510,973 505,536 697,109 303,918 145,550
Long-term debt.......................... 374,819 302,013 306,744 294,990 352,090 -- 22,000
Total stockholders' equity.............. 80,068 112,329 113,972 138,291 184,648 233,203 105,015
</TABLE>

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

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<PAGE> 22

received due to the volatile nature of oil and gas prices. Effective with
the nine months ended September 30, 2000, all periods have been restated to
report commodity price risk management hedge settlements as part of oil and
gas revenues, commodity price risk management non-hedge settlements as a
separate revenue component and unrealized commodity price risk management
non-cash gains or losses as a component of costs and expenses. The
restatement of all such amounts did not result in any changes to previously
reported net income or loss, including per share amounts.

(2) Includes cash premiums received and paid.

(3) 1996 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 in
connection with our initial public offering. See note 1 of notes to the
consolidated financial statements.

(4) Earnings per share have been computed as if the 25,000,000 shares of common
stock that were issued in connection with combination had been outstanding
for all years prior to 1996. See note 1 of notes to the consolidated
financial statements.

(5) Excluding the commodity price risk management mark-to-market balance sheet
items, working capital would have been positive $31.0 million at September
30, 2000, $20.1 million at September 30, 1999 and $14.7 million at December
31, 1999.

S-22
<PAGE> 23

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

The following discussion is intended to assist you in understanding our
financial position and results of operations for each year of the three-year
period ended December 31, 1999 and for the unaudited nine month periods ended
September 30, 2000 and 1999. Our financial statements and the notes thereto
included elsewhere in this prospectus supplement contain detailed information
that should be referred to in conjunction with the following discussion.

OVERVIEW

Belco Oil & Gas Corp. is an independent energy company engaged in the
exploration for and the acquisition, exploitation, development and production of
oil and gas in the United States. Our producing properties and exploration
acreage are located within four core areas: Rocky Mountain, Gulf Coast, Permian
Basin, and Mid-Continent. Since Belco's formation in April 1992, Belco has grown
its reserve base largely through a balanced program of exploration and
development drilling and through acquisitions. We concentrate our activities
primarily in the four core areas in which we have accumulated detailed geologic
and geophysical knowledge and have developed significant technical and
operational expertise.

Belco's operations are currently focused in the Rocky Mountain area, primarily
in the Green River (which includes the Moxa Arch), Wind River and Big Horn
Basins of Wyoming; the Gulf Coast, primarily in Texas; the Permian Basin in West
Texas; and the Mid-Continent region in Oklahoma and North Texas. These areas
accounted for approximately 99% of Belco's proved reserves at December 31, 1999.
Belco's reserve base was 641 Bcfe at December 31, 1999 with a reserve to
production ratio of 10.6 years, based on 1999 production. During the first nine
months of 2000, Belco acquired approximately 86 Bcfe of proved reserves
estimated as of the date of acquisition for approximately $70.0 million.

Our revenue, profitability and future rate of growth are substantially dependent
upon prevailing prices for oil, gas and condensate. Commodity prices are subject
to numerous factors beyond our control, such as economic, political and
regulatory developments and competition from other sources of energy. Energy
markets have historically been very volatile, and we can offer no assurance that
oil and gas prices will not be subject to wide fluctuations in the future. A
substantial or extended decline in oil and gas prices could have a material
adverse effect on our financial position, results of operations and access to
capital, as well as the quantities of oil and gas reserves that we may
economically produce. Gas produced is sold under contracts that primarily
reflect spot market conditions for their particular area. We market our oil with
other working interest owners on spot price contracts and typically receive a
small premium to the price posted for such oil. Currently, approximately 63% of
our production volumes relate to the sale of gas (based on six Mcf of gas being
considered equivalent to one barrel of oil).

We utilize commodity swaps and options and other commodity price risk management
transactions related to a portion of our oil and gas production to achieve a
more predictable cash flow, and to reduce our exposure to price fluctuations. We
account for these transactions in compliance with current generally accepted
accounting principles as hedging activities or use mark-to-market accounting for
those contracts that do not qualify for hedge accounting treatment. As of
September 30, 2000, we had various oil and gas commodity price risk management
contracts in place with respect to substantial portions of our estimated
remaining production for calendar year 2000 and with respect to lesser portions
of our estimated production for years 2001, 2002 and 2003. We expect to reduce
the current amount of commodity price risk management contracts that we have in
place over the next 12 to 24 months in an effort to limit our future exposure to
the mark-to-market accounting rules that require immediate recognition of
non-cash unrealized gains and losses, causing large unpredictable swings in
reported results of operations and related earnings per share.

S-23
<PAGE> 24

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

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
------------------- ------------------------------
2000 1999 1999 1998 1997
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Oil and gas sales (hedged) (in
thousands)..................... $148,841 $104,215 $141,932 $129,916 $129,994
Non-hedge commodity price risk
management activities cash
settlements (in thousands)..... (22,738) (121) (2,442) 172 (1,551)
WEIGHTED AVERAGE SALES PRICES:
Oil (per Bbl)
Unhedged.................... $ 28.78 $ 15.75 $ 17.49 $ 13.17 $ 19.28
Hedge settlements........... (3.69) 3.42 1.76 2.92 --
-------- -------- -------- -------- --------
Net realized................ $ 25.09 $ 19.17 $ 19.25 $ 16.09 $ 19.28
Gas (per Mcf)
Unhedged.................... $ 3.04 $ 1.90 $ 1.99 $ 1.86 $ 2.11
Hedge settlements........... (0.67) (0.03) (0.08) (0.17) --
-------- -------- -------- -------- --------
Net realized................ $ 2.37 $ 1.87 $ 1.91 $ 1.69 $ 2.11
NET PRODUCTION DATA:
Oil (MBbls).................... 2,995 2,596 3,439 4,177 1,295
Gas (MMcf)..................... 31,049 29,153 39,738 37,207 49,710
Gas equivalent (MMcfe)......... 49,019 44,732 60,370 62,272 57,479
Gas equivalent (MMcfe per
day)........................ 179 164 165 171 157
OPERATIONS DATA PER MCFE:
Oil and gas sales revenues
(unhedged).................. $ 3.68 $ 2.15 $ 2.31 $ 1.99 $ 2.26
Hedge and non-hedge cash
settlements................. (1.11) 0.17 -- 0.09 (0.13)
Oil and gas operating
expenses.................... (0.52) (0.50) (0.49) (0.48) (0.13)
Production taxes............... (0.22) (0.15) (0.16) (0.18) (0.09)
General and administrative..... (0.09) (0.08) (0.08) (0.08) (0.07)
Depreciation, depletion and
amortization................ (0.85) (0.90) (0.90) (0.90) (0.81)
-------- -------- -------- -------- --------
Pre-tax operating profit(1).... $ 0.89 $ 0.69 $ 0.68 $ 0.44 $ 1.03
======== ======== ======== ======== ========
</TABLE>

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

(1) Excluding non-cash mark-to-market commodity price risk management
activities, ceiling test and securities impairment provisions, interest
income and interest expenses.

RESULTS OF OPERATIONS

Nine Months Ended September 30, 2000 Compared to September 30, 1999

Revenues. For the first nine months of 2000, oil and gas sales revenues net of
hedging activities increased $44.6 million, or 43% to $148.8 million, when
compared to the prior year comparable period. This increase was primarily the
result of both higher production and higher commodity prices. Gas production
increased 7% over the prior year first nine months. Average Mcfe price
realizations net of hedging activities increased by 29% in the first nine months
of 2000 compared to last year's first nine months. Gas production represented
approximately 63% of total production on an Mcfe basis compared to the 65%
reported for the first nine months of 1999. Oil production increased by 15% over
the prior year comparable period due to property acquisitions and newly drilled
well additions during the first nine months of the year.

S-24
<PAGE> 25

Commodity price risk management activities, including hedged and non-hedged
transactions, during the first nine months of 2000 resulted in reported revenue
reductions of $54.5 million compared to incremental revenues of $7.8 million
reported in the prior year comparable period. The first nine months of 2000
reductions consisted of $54.5 million in actual cash settlements paid. In
addition, $70.6 million in non-cash mark-to-market unrealized future losses
related to commodity price risk management activities were recorded under Costs
and Expenses in compliance with current accounting rules. In the prior year
comparable period, $7.8 million in cash settlements were received while the
non-cash mark-to-market unrealized loss component recorded was $45.2 million.

Costs and Expenses. Production and operating expenses (or lifting costs) during
the first nine months of 2000 increased by 15% to $25.4 million compared to
$22.2 million reported in the prior year comparable period. The increase was
related to the addition of wells, both acquired and drilled in the current year.
On an equivalent unit basis, lifting costs were $0.52 per Mcfe for the first
nine months of 2000 compared to $0.50 per Mcfe in the first nine months of 1999.
Production taxes were $0.22 and $0.16 per Mcfe for the first nine months of 2000
and 1999, respectively with the increase related to higher commodity prices.

Depreciation, depletion and amortization (or DD&A) for the nine months ended
September 30, 2000 increased $1.4 million to $41.7 million when compared to the
$40.3 million recorded in the prior year comparable period due to higher
production volumes. The first nine months DD&A rate per Mcfe was $0.85, a 6%
decline as compared to the prior year comparable period when $0.90 per Mcfe was
recorded.

General and administrative expense (or G&A) costs increased by 28% in the first
nine months of 2000 to $4.7 million when compared to the $3.7 million incurred
in the first nine months of 1999 principally due to reduced amounts of such
costs charged to the full cost pool. The rate per Mcfe for such costs increased
from $0.08 to $0.09.

Interest expense is incurred on $147 million of 8 7/8% Senior Subordinated Notes
due 2007 issued in September 1997, $109 million of 10 1/2% Senior Subordinated
Notes due 2006, and bank debt incurred to fund various activities. Interest
expense for the nine months ended September 30, 2000 increased by $2.4 million
to $18.6 million, a 15% increase over the $16.2 million incurred in the prior
year comparable period due to higher interest rates charged and additional
borrowings outstanding under Belco's credit facility partially offset by
additional amounts capitalized during the current year.

Income (Loss) Before Income Taxes. Our reported loss before income tax benefits
for the first nine months of 2000 was $45.1 million. This compares to a pre-tax
loss of $29.7 million reported for the first nine months of 1999. The 2000 and
1999 first nine months reported losses are the result of recognizing the
required non-cash mark-to-market unrealized commodity price risk management
losses as required by current accounting rules. Excluding the effect of the
non-cash mark-to-market unrealized commodity price risk management losses income
before income taxes was $25.6 million and $15.5 million for the first nine
months of 2000 and 1999, respectively.

Income Taxes. For the first nine months of 2000, income tax benefits were
recorded in the amount of $15.8 million as a result of the reported pre-tax
loss. The benefit for income taxes for the comparable nine month period of 1999
was $10.4 million.

Year Ended December 31, 1999 Compared to Year Ended December 31, 1998

Revenues. Oil and gas sales revenues for the year 1999, net of hedging
activities, increased 9% to $141.9 million compared to $129.9 million realized
in 1998. The year over year increase is due to higher commodity prices and
higher gas production partially offset by lower crude oil production. In 1999,
weighted average oil prices realized (hedged) totaled $19.25 per Bbl, a 20%
increase when compared to the $16.09 realized in 1998. The weighted average gas
prices realized (hedged) increased by 13% from $1.69 in 1998 to $1.91 in 1999.
Average daily production volume in 1999 on an Mcfe basis declined by 3% to
165,398 Mcfe.

Non-hedge commodity price risk management activities resulted in a net pre-tax
cash loss of $2.4 million for 1999 compared to a $172,000 pre-tax cash gain in
the prior year. In addition, $34.1 million in non-

S-25
<PAGE> 26

cash mark-to-market unrealized future losses related to commodity price risk
management activities and representing the change in fair value of derivatives
were recorded under Costs and Expenses as required by current accounting rules.
In the prior year, a non-cash gain of $18.9 million was recorded.

Costs and Expenses. Production and operating expenses declined to $29.9 million
or 11% in 1999 when compared to the $33.6 million incurred during 1998. The
decrease is a result of cost reduction efforts in response to lower commodity
prices realized in the first half of 1999 combined with the implementation of
other operating efficiencies on newly operated properties located in Wyoming.
Production taxes increased from $7.2 million in 1998 to $9.3 million in 1999 due
to higher commodity prices realized. On a unit basis, operating costs including
production taxes were $0.65 per Mcfe for 1999 compared to $0.66 per Mcfe for
1998.

Recurring DD&A costs for the year totalled $54.2 million when compared to the
$56.1 million recorded for the prior year. The DD&A rate for the year was
unchanged at $0.90 per Mcfe. For the year 1998, Belco also recorded $229.0
million ($148.9 million after-tax) in non-cash ceiling test provisions as
required by full-cost accounting rules. The provisions were the result of
applying substantially lower commodity prices to estimated recoverable reserves.

G&A costs declined by 5% during 1999 to $4.9 million when compared to the $5.2
million incurred in 1998. The decrease is primarily due to the cost controls
implemented in response to lower commodity prices. The rate per Mcfe for such
costs was unchanged at $0.08 for both years. Exploration related G&A expenses
for 1999 in the amount of $5.5 million have been capitalized to oil and gas
property accounts. The decrease of $0.7 million when compared to 1998 comparable
capitalized amount of $6.2 million principally reflects reduced exploration
activities.

Net interest costs incurred for the year 1999 totalled $25.9 million, with
approximately $4.9 million of this total capitalized to property accounts. The
1999 net total interest cost declined modestly when compared to 1998 when net
total interest costs were $26.1 million, with $5.1 million capitalized.

As a result of the substantial decline in the market value of Big Bear
Exploration Ltd. securities acquired in June 1998, impairment provisions were
$450,000 and $9.7 million in 1999 and 1998, respectively.

Income (Loss) Before Income Taxes. Our reported loss before income tax benefits
for the year 1999 was $13.2 million. This compares to a loss of $225.7 million
reported in 1998. The substantially lower loss reported for 1999 reflects
improved commodity prices and the absence of non-cash ceiling test and
securities impairment provisions of $229.0 million and $24.2 million,
respectively, reported in 1998.

Income Taxes. Income tax benefits were recorded for 1999 in the amount of $4.6
million and $78.1 million for 1998 as a result of reported pre-tax losses.

Year Ended December 31, 1998 Compared to Year Ended December 31, 1997

Revenues. Oil and gas sales revenues for the year 1998 (hedged) declined less
than 1% to $129.9 million when compared to the $130.0 million realized in 1997,
due to substantially lower commodity prices. The year 1997 included only one
month of the operations of Coda Energy, Inc., which we acquired in late 1997. In
1998 weighted average oil prices realized (hedged) totaled $16.09 per Bbl, a 16%
decline when compared to the $19.28 realized in 1997. The weighted average gas
prices realized (hedged) declined 20% from $2.11 in 1997 to $1.69 in 1998.
Average daily production volume in 1998 on an Mcfe basis increased 8% to 170,609
Mcfe.

Non-hedge commodity price risk management activities resulted in a net pre-tax
cash gain of $172,000 for 1998 compared to a net pre-tax cash loss of $1.6
million in 1997. In addition, $18.9 million in non-cash mark-to-market
unrealized future gains related to commodity price risk management activities
and representing the change in fair value of derivatives were recorded under
Costs and Expenses as required by current accounting rules. In the prior year a
non-cash loss of $4.9 million was recorded.

Costs and Expenses. Production and operating expenses increased to $33.6
million in 1998 when compared to the $7.4 million incurred during 1997. The
increase is identified with the growth in oil

S-26
<PAGE> 27

production through secondary recovery techniques following the Coda Energy
acquisition and reflects the higher costs normally associated with such
production when compared to gas. Production taxes increased from $5.4 million in
1997 to $7.2 million due to increased production. On a unit basis, operating
costs including production taxes, were $0.66 per Mcfe for 1998 compared to $0.22
per Mcfe for 1997 which included only one month of Coda Energy's operations.

Recurring DD&A costs for 1998 totalled $56.1 million when compared to the $46.7
million recorded for the prior year. The DD&A rate per Mcfe was $0.90 and $0.81
for 1998 and 1997, respectively. For the year 1998, we also recorded $229.0
million ($148.9 million after-tax) in non-cash ceiling test provisions as
required by full-cost accounting rules. The provisions were the result of
applying substantially lower commodity prices to estimated recoverable reserves.
At December 31, 1997, we recorded a non-cash ceiling test provision of $150.0
million ($97.5 million after tax) based on estimated proved reserves at December
31, 1997.

G&A costs increased by 33% during 1998 to $5.2 million when compared to the $3.9
million incurred in 1997. The increase is primarily due to the addition of
personnel associated with the Coda Energy transaction. The rate per Mcfe for
such costs increased from $0.07 in 1997 to $0.08 in 1998. Exploration related
G&A expenses for 1998 in the amount of $6.2 million have been capitalized to oil
and gas property accounts. The increase of $0.4 million over the 1997 comparable
capitalized amount of $5.8 million principally reflects additional personnel
costs and seismic activities related to a number of exploration projects.

Net interest costs incurred for the years 1998 and 1997 totalled $26.1 million
and $5.4 million, respectively, with approximately $5.1 million and $3.7 million
of these totals capitalized to property accounts.

As a result of the substantial decline in the market value of Chesapeake Energy
Corp. securities acquired when Hugoton Energy Corp. was merged into Chesapeake,
we realized a loss of $14.4 million upon disposition of these securities during
the first nine months of 1998. In addition, a $9.7 million non-cash impairment
provision was recorded to recognize a decline in the value of Big Bear
Exploration securities then owned by Belco.

Income (Loss) Before Income Taxes. Our reported loss before income tax benefits
for the year 1998 was $225.7 million. This compares to a loss of $88.3 million
reported in 1997. The 1998 loss is primarily the result of the non-cash ceiling
test impairment provisions totalling $229.0 million ($148.9 million after-tax)
mandated by full-cost accounting rules. The 1997 loss was principally identified
with purchase price allocations related to the Coda Energy acquisition which
resulted in a required ceiling test provision. Income before income taxes,
excluding the effect of the non-cash impairments and purchase accounting
provisions, was $3.0 million and $61.7 million for 1998 and 1997, respectively.

Income Taxes. Income tax benefits were recorded for 1998 in the amount of $78.1
million and $31.4 million for 1997 as a result of reported pre-tax losses.

LIQUIDITY AND CAPITAL RESOURCES

General

In September 1997, we entered into a five year $150.0 million Credit Agreement
with The Chase Manhattan Bank, N.A., as administrative agent, and other lending
institutions. In June 2000, the credit facility was amended and restated and now
provides for an aggregate principal amount of revolving loans of up to the
lesser of $250.0 million or a defined borrowing base in effect from time to
time, includes a sub-facility for letters of credit and expires in January 2004.
The borrowing base at September 30, 2000 was $200.0 million with $113.6 million
advanced at that date. Additionally, there were letters of credit outstanding in
the amount of $26.5 million in connection with commodity price risk management
activities. The borrowing base is 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, we may request two additional
redeterminations and the banks may request one additional redetermination per

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<PAGE> 28

year. Our indebtedness under the credit facility is secured by a pledge of the
capital stock of each of our material subsidiaries.

Indebtedness under the credit facility bears interest at a floating rate based
(at our option) upon (i) the ABR (as defined) with respect to ABR Loans or (ii)
the Eurodollar Rate (as defined) for one, two, three or nine months (or nine or
twelve months if available to the banks) for Eurodollar Loans (as defined), plus
the Applicable Margin. The ABR is the greater of (i) the Prime Rate (as
defined), (ii) the Base CD Rate (as defined) plus 1% or (iii) the Federal Funds
Effective Rate (as defined) plus 0.50%. The Applicable Margin for Eurodollar
Loans varies from 1.125% to 1.625% depending on the borrowing base usage.
Borrowing base usage is determined by a ratio of (i) outstanding Loans (as
defined) and letters of credit to (ii) the then effective borrowing base.
Interest on ABR Loans is payable quarterly in arrears and interest on Eurodollar
Loans is payable on the last day of the interest period thereof and, if longer
than three months, at three month intervals.

We are 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
0.25% to 0.50% depending on the borrowing base usage.

We entered into interest rate swap agreements converting two long-term debt
fixed rate obligations to floating rate obligations as follows:

<TABLE>
<CAPTION>
AGREEMENT TRANSACTION FIXED FLOATING FLOATING RATE
AMOUNT DATE RATE RATE EXPIRATION DATE(1)
--------- ----------- ------ -------- ------------------
<S> <C> <C> <C> <C>
$100 million........................... 12/97 8.875% 8.875% March 15, 2001
$85 million........................... 12/97 10.500% 11.250% April 1, 2001
$50 million........................... 01/98 8.875% 8.875% March 15, 2001
</TABLE>

---------------------------
(1) Floating rate is redetermined at each six month period following the
expiration through September 15, 2007 currently capped at rates indicated.

The agreements obligate Belco to actually pay the indicated floating rate rather
than the original fixed rate. The floating rates are capped at 8.875% through
March 15, 2002 and at 10% from March 15, 2002 through September 15, 2007 on the
8 7/8% Notes. The floating rates are capped at 11.625% through April 1, 2003 on
the 10 1/2% Notes.

Belco's board of directors has authorized the purchase from time to time, in the
open market or in privately negotiated transactions, of shares of its common
stock and 6 1/2% convertible preferred stock, in an aggregate amount not to
exceed $10.0 million. The current $10.0 million authorization is in addition to
the $10.0 million that was exhausted in December 1999. During the nine months
ending September 30, 2000, Belco purchased 20,700 shares of its preferred stock
for a total cost of $303,000 pursuant to the existing authorization.

Additionally, through November 24, 2000, Belco exchanged 691,000 shares of its
6 1/2% convertible preferred stock for 1,241,675 shares of its common stock. The
liquidation preference of the preferred stock that was exchanged was $17.3
million.

In July 2000, Belco sold its interest in certain North Texas oil properties,
including 436 producing wells for $10.1 million in cash and retained volumetric
production payments which Belco values at approximately $5.0 million.

In April 2000, Belco closed a $24.4 million acquisition of oil and gas
properties adding approximately 51 Bcfe of proved reserves estimated at the time
of acquisition to Belco's reserve base. The transaction was financed through
additional borrowings under the credit facility.

In February 2000, Belco closed a $40.5 million acquisition of oil and gas
properties adding approximately 24.6 Bcfe of proved reserves estimated at the
time of acquisition to Belco's reserve base. The transaction was financed
through additional borrowings under the credit facility.

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<PAGE> 29

In January 2000, Belco purchased $3 million face value of its 8 7/8% Senior
Subordinated Notes due 2007 at a discount in the open market resulting in a
modest gain.

Cash Flow

Our principal sources of cash are operating cash flow and bank borrowings. Cash
flow from operating activities for the nine months ended September 30, 2000 was
$72.0 million, a 33% increase over the prior comparable period when $54.3
million was realized. The increase is primarily the result of higher production
volumes and higher commodity prices.

Net cash used in investing activities for the nine months ended September 30,
2000 and 1999 was $136.0 and $52.3 million, respectively. Investing activities
for these periods include oil and gas property acquisitions in the amount of
$70.0 million and $17.0 million for 2000 and 1999, respectively. In addition,
investing activities generally include exploration and development activities
and proceeds from the sale of properties or other assets.

Net cash provided by financing activities for the nine months ended September
30, 2000 and 1999 was $63.1 million and $556,000, respectively. Net debt
increased by $68.1 million related to property acquisitions. Cash flow from
operations and the disposition of assets funded drilling and other operating
activities during the current year, including preferred dividends paid. Belco's
credit facility and the indentures governing its subordinated debt restrict the
payment of dividends. The entire net proceeds of this offering will increase the
amount of restricted payments available under Belco's 10 1/2% notes indenture,
including for dividend payments on our preferred stock. If we report substantial
losses, including for example unrealized non-cash mark-to-market losses required
by existing accounting rules, dividends on Belco's preferred stock may be
limited or prohibited by the restrictions contained in Belco's 10 1/2% notes
indenture.

Capital Expenditures

Through September 30, 2000, net capital expended by Belco totaled $136.0
million, including $70.0 million identified with the acquisition of properties
and property dispositions of $10.7 million. Capital expenditures for the full
year 2000 are expected to total approximately $160.0 million net.

We intend to fund our future capital expenditures, commitments and working
capital requirements through cash flows from operations, borrowings under the
credit facility or other potential financings, including the sale of equity or
debt securities. If changes in oil and gas prices reduce cash flows and the
borrowing base under our credit facility, we have the discretion and ability to
adjust our capital budget. We believe that we will have sufficient capital
resources and liquidity to fund our capital expenditures and meet all of our
financial obligations through the end of 2001.

Commodity Price Risk Management Transactions

Certain of Belco's commodity price risk management arrangements require Belco to
deliver cash collateral or other assurances of performance to the counterparties
in the event that Belco's payment obligations with respect to its commodity
price risk management transactions exceed certain levels. Two of the inherent
risks of a price risk management program are margin requirements and
collateralization. Certain transactions may be subject to margin calls under
certain conditions including change of ownership control, rating agency activity
or default. Belco's current collateral requirement is $27.5 million consisting
of $26.5 million in letters of credit and $1.0 million in cash deposits. We
believe our borrowing capacity under our credit facility will allow us to be
responsive to additional collateral requirements.

With the primary objective of achieving more predictable revenues and cash
flows, Belco has entered into commodity price risk management transactions of
various kinds with respect to both oil and 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. Belco engages in transactions such as selling options which are
marked-to-market at the end of the relevant accounting

S-29
<PAGE> 30

period. Since the futures market historically has been highly volatile, these
fluctuations may cause significant impact on the reported financial results of
any given accounting period. Belco has entered into price risk management
transactions with respect to a substantial portion of its estimated production
for years 2000 and 2001 and lesser portions of its estimated production
thereafter. Belco continues to evaluate whether to enter into additional price
risk management transactions for future years. We expect to reduce the current
amount of price risk management contracts that we have in place over the next 12
to 24 months in an effort to limit our future exposure to the mark-to-market
accounting rules that require the immediate recognition of non-cash unrealized
gains and losses that cause large unpredictable swings in reported results of
operations, related earnings per share and stockholder equity. As existing
positions expire, we intend to reduce our total positions to no more than
approximately 50% of our production in the future. In addition, Belco may
determine from time to time to unwind its then existing price risk management
positions as part of its price risk management strategy.

We expect to incur additional hedge and non-hedge related cash settlement costs
through the remainder of calendar year 2000 assuming commodity prices remain at
current levels. This cash settlement amount is currently estimated at
approximately $26.0 million for the fourth quarter of 2000 utilizing the
September 30, 2000 forward price curve applied to volumes of oil and gas
expected to be produced during the three month period ending December 31, 2000.
This estimated amount can increase or decrease if commodity prices rise or
decline from the current levels used in developing this estimate. As cash
settlements are made on volumes produced, no additional losses are expected to
be recorded, unless actual prices increase above estimated future prices used in
the September 30, 2000 mark-to-market calculation. Subsequent to September 30,
2000, both oil and gas futures prices have increased slightly and if such
conditions persist, Belco may be required to record additional mark-to-market
unrealized losses. For the year 2001, Belco has approximately 6,082 BOPD and
85,000 MMBtu per day committed at average prices of $19.60 per Bbl of oil and
$2.45 per MMBtu of gas. The committed volumes assume the NYMEX forward curve
reference prices as of September 30, 2000. No estimate of settlements or
mark-to-market gains or losses are determinable as such amounts are contingent
upon commodity prices at the time of production.

In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative
Instruments and Hedging Activities" which was amended by Financial Accounting
Standard No. 138 ("SFAS 138") in June 1999. SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. It
also requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows derivatives gains and losses to offset
related results on the hedged item in the income statement, and requires that a
company must formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting. We will fully adopt SFAS 133 on
January 1, 2001, the effective date as amended by SFAS 138. We have not
completely quantified the impact of adopting SFAS 133 on our financial
statements and have not determined the final method of adoption of SFAS 133.
However, SFAS 133 is expected to increase volatility of stockholder's equity,
reported earnings (losses) and other comprehensive income. The current
preliminary impact of full compliance with SFAS 133 on financial statements as
if the implementation were to have occurred September 30, 2000, Belco would
record an additional $11.5 million in current assets, $1.6 million in
non-current assets, $51.7 million in current liabilities and $19.8 million in
non-current liabilities related to Belco's existing oil and gas hedges based on
the forward price curve in effect at September 30, 2000. These contracts should
also qualify for hedge accounting treatment under SFAS 133. The total potential
net liability of $58.4 million related to qualifying hedge instruments would be
charged to Other Comprehensive Income and appear in the equity section of the
balance sheet. This amount combined with amounts previously recorded on the
balance sheet representing non-cash mark-to-market unrealized losses in the net
amount of $93.7 million represent the full potential exposure of Belco's
commodity price risk management related activities that may or may not be
realized as they are dependent on future commodity prices. After adoption, Belco
will be required to recognize any hedge ineffectiveness in the income statement
each

S-30
<PAGE> 31

period. In addition, Belco has three interest rate swaps that will be affected
by SFAS 133. We currently believe these swaps will qualify for hedge accounting
and as a result, Belco will be required to record an additional $2.4 million in
current liabilities and $8.3 million in non-current liabilities with the
offsetting charge to long-term debt. We would also record $160,000 to the income
statement for the ineffective portion related to these swaps.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Belco's market risk exposures relate primarily to commodity prices, interest
rates and marketable equity securities. Belco enters into various transactions
involving commodity price risk management activities involving a variety of
derivatives instruments. In addition, Belco entered into interest rate swap
agreements to reduce current interest burdens related to its fixed long-term
debt. The derivatives instruments are generally put in place to limit the risk
of adverse oil and gas price movements, however, such instruments can limit
future gains resulting from upward favorable oil and gas price movements.
Recognition of both realized and unrealized gains or losses are reported
currently in Belco's financial statements as required by existing generally
accepted accounting principles. The cash flow impact of all derivative related
transactions is reflected as cash flows from operating activities. As of
September 30, 2000, Belco had, and continues to have, substantial derivative
financial instruments outstanding related to its commodity price risk management
program. See note 3 to notes to unaudited condensed consolidated financial
statements.

S-31
<PAGE> 32

BUSINESS

OVERVIEW

We are an independent energy company engaged in the exploration for and the
acquisition, exploitation, development and production of oil and gas in the
United States, primarily in the Rocky Mountain area, the Gulf Coast region, the
Permian Basin and the Mid-Continent region. Since our inception in April 1992,
we have grown our reserve base through a program of acquisitions, exploration,
exploitation and development drilling. From our inception in 1992 through 1997,
our growth was primarily based upon participating as a non-operator in the
drilling of gas wells in the Austin Chalk, where wells have relatively
short-lived reserves, and in the Moxa Arch. During 1997, in order to establish a
more stable platform for continued growth we determined to increase our degree
of operational control, increase the life of our reserves and to better balance
our reserves between oil and gas. Consistent with this strategy, we acquired
Coda Energy in late 1997 and adopted a balanced growth strategy through
exploitation, exploratory and development drilling and acquisitions in our core
areas. Focusing in core areas allows us to accumulate detailed geologic and
geophysical knowledge, significant operational efficiencies and technical
expertise.

Since 1992, we have achieved substantial growth in reserves, production and
EBITDA. Our estimated proved reserves have increased at a compound annual growth
rate of 38%, from 67 Bcfe as of December 31, 1992 to 641 Bcfe as of December 31,
1999, with a reserve to production ratio of approximately 10.6 years based on
1999 production. Average daily production has increased from four MMcfe per day
in 1992 to approximately 165 MMcfe per day in 1999. Similarly, the growth in our
EBITDA has been substantial, increasing from $2.9 million for the year ended
December 31, 1992, to $96.5 million for the year ended December 31, 1999. Our
low cost structure is evidenced by our general and administrative expenses of
$0.08 per Mcfe and lease operating expenses and production taxes of $0.65 per
Mcfe in 1999.

PRIMARY OPERATING AREAS

Our operations are currently focused in four core operating areas:

- Rocky Mountain: We intend to target additional gas development in Wyoming in
the Green River (inclusive of the Moxa Arch), Wind River and Big Horn Basins.
In addition, we will attempt to increase oil production in the Williston
Basin of North Dakota through the use of horizontal drilling and waterfloods.
In 2001, we expect to spend approximately $37.1 million of our capital
expenditure budget in this area.

- Gulf Coast: We will continue our horizontal exploitation program targeting
the Austin Chalk and Georgetown formations. Our development activities will
focus on our newly acquired interests in the Elm Grove field. In addition, we
expect to test additional Yegua and lower Wilcox objectives identified by
recently processed 3-D seismic data on our HLM prospect. In 2001, we expect
to spend approximately $21.1 million of our capital expenditure budget in
this area.

- Permian Basin: Our primary focus for this area will be on development
drilling and further secondary recovery projects, especially in Andrews
County, Texas. In 2001, we expect to spend approximately $2.6 million of our
capital expenditure budget in this area.

- Mid-Continent: In this mature area, we will continue to expand some of our
larger waterfloods and conduct development drilling activities. In 2001, we
expect to spend approximately $10.3 million of our capital expenditure budget
in this area.

Estimated Proved Reserves and Average Daily Production

Our estimated net proved reserves and average daily production by operating area
as of December 31, 1999 are shown in the following table. Approximately 83% of
the quantities of proved reserves on an Mcfe basis aggregating 84% of the
present value were estimated by our independent petroleum engineers, Miller and
Lents, Ltd. Our internal petroleum engineers estimated the remaining proved
reserves. In accordance

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<PAGE> 33

with guidelines of the SEC, the estimates of proved reserves were made using oil
and gas sales prices at December 31, 1999 and were held constant throughout the
life of the properties. See "Cautionary Statement About Forward Looking
Statements" and "Risk Factors."

<TABLE>
<CAPTION>
AVERAGE
GAS PERCENT OF DAILY
OIL GAS EQUIVALENT PROVED PRODUCTION
(MBbls) (MMcf) (MMcfe) RESERVES (MMcfe)
------- ------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Rocky Mountain......................... 1,497 139,525 148,507 23% 24
Gulf Coast............................. 1,329 93,079 101,055 16 68
Permian Basin.......................... 34,372 41,150 247,379 39 35
Mid-Continent.......................... 15,878 48,394 143,663 22 37
------ ------- ------- --- ---
Total............................. 53,076 322,148 640,604 100% 165
====== ======= ======= === ===
</TABLE>

---------------------------
For additional information concerning our oil and gas reserves and estimates of
future net revenues attributable thereto, see note 14 of the notes to
consolidated financial statements included in this prospectus supplement.

Rocky Mountain

Wyoming. We maintain a significant acreage position in the Rocky Mountains of
Wyoming where we conduct an ongoing exploration and development program. We
commenced a development drilling program in the Moxa Arch trend in June 1992
pursuant to a farmout from Amoco. We significantly expanded our acreage and
exploration activities in 1996 by acquiring the rights 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, 1999,
we controlled approximately 1.2 million gross (351,789 net) undeveloped acres in
these three basins.

Moxa Arch. One of our primary operating areas is the Moxa Arch trend located in
the Green River Basin in Southwestern Wyoming, principally in Lincoln,
Sweetwater and Uinta Counties. Approximately 23% of our estimated proved
reserves at December 31, 1999 were located in this region. We participate in
vertical gas wells drilled 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 sand. Production from Moxa Arch wells, particularly from the
Frontier formation, tends to be long-lived, where 25 to 30 year reserve lives
are common. Since January 1, 1996, we have drilled 47 gross wells in this field,
only four of which were dry holes.

Through 1999, we had participated in 229 gross wells (75 net) in this field with
158 Frontier wells, 18 Dakota wells and 53 dual completions (both Frontier and
Dakota completed in the same well bore). Average net production for the year
ended December 31, 1999 was approximately 22 MMcfe of gas per day. We drilled
eight gross wells (5.6 net) in 1999 and have drilled 16 gross wells (9.7 net) in
the first nine months of 2000. We anticipate drilling approximately 20 gross
wells through the end of 2001. Net average production for October 2000 was
approximately 23 MMcfe of gas per day.

Green River, Wind River, Big Horn and Williston Basins. Effective November 1,
1996, we 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, we committed to spend a minimum of $20.0 million
on seismic, leasing and exploratory activities through December 31, 2001 to earn
rights to a 50% interest in approximately 300,000 net acres. As of October 1,
2000, we have satisfied our entire $20.0 million commitment. Anadarko or Yates
Petroleum Corporation operate most of the acreage.

Effective December 31, 1996, we entered into two joint development agreements
with Snyder Oil Company, now Devon Energy Corp. Under these agreements, we
acquired a 50% interest in approximately 87,321 net acres in the Wind River
Basin of Wyoming and 110,859 net acres in the Big Horn Basin of

S-33
<PAGE> 34

Wyoming. Devon operates these properties and has drilled a total of eight wells
to date on this acreage in both basins. We expect to participate in at least two
wells on these properties in 2001.

In June 1997, we entered into a participation agreement with Tom Brown, Inc. and
Andover Partners covering approximately one million acres of mutual interest in
the Big Horn Basin. Additionally, we acquired an interest in an initial 100,000
gross (25,000 net) acres in the Big Horn Basin. In 2001, we intend to continue
acquiring additional leases in the Big Horn Basin and to drill at least one
exploratory well.

The acreage in this core area was acquired to help us realize our long term goal
of becoming a significant participant in developing the gas potential in the
Rocky Mountains of Wyoming. All three Wyoming basins are receiving renewed
interest by the industry. Outside of the Moxa Arch, we have participated in four
wells in 2000 in the Green River Basin and expect to drill at least 10 wells in
2001. We expect these wells will include both development and exploratory
locations and will target multiple formations. Successful exploratory results
hold the potential for multi-well development drilling programs for us over the
next several years.

North Dakota. Effective March 1, 2000, we acquired interests in the Stadium,
Livestock, Subdivision and Eland units producing from the Lodgepole formation in
Stark County, North Dakota. We operate the five well Stadium unit and both of
the one well units, Subdivision and Livestock. In addition to this acquisition,
we began leasing acreage in 1999 on a series of Mission Canyon prospects within
30 miles of the Stark County units.

Stadium Unit. We have a 51% working interest in the Stadium unit. The prior
owner drilled the first well in 1996 and encountered a total of 150 feet of oil
pay in a 300 foot thick carbonate reef. A total of five wells were drilled prior
to our acquisition. The deepest well was converted to a water injector in 1998
to maintain pressures, and the unit has averaged over 4,000 gross BOPD since
mid-1999. Gross production during October 2000 averaged nearly 4,500 BOPD.

Mission Canyon. We have acquired over 50,000 net acres in four separate
prospects targeting thin oil productive zones in the Mission Canyon interval.
Other operators recognized these zones in the past in several vertical wells,
but often could not complete them economically because nearby wet zones would
also produce along with the oil. We believed the use of horizontal wells would
decrease the tendency for water production from the underlying intervals. We
drilled our first horizontal well in December 1999, and through October 2000 we
drilled a total of 11 wells on four prospects. The typical well is drilled to
approximately 9,600 feet vertical depth and has a 5,000 foot lateral within a
640 acre unit. Crooked Canyon, the most drilled prospect, has seven wells
drilled within a 15 square mile area. The Rocky Hill discovery has two wells,
the North Treetop discovery has one well, and the Manning, an apparent
discovery, has one well. During October 2000, we averaged approximately 500
gross BOPD and over 900 gross Mcf per day from these four prospects. We expect
to continue a two rig program through the rest of 2000 and 2001, expected to
result in the drilling of more than 20 new wells.

Gulf Coast Region

Giddings Field. Approximately 15% of our estimated total proved reserves at
December 31, 1999 were located in the Giddings field of East Central Texas,
principally in Grimes, Washington and Fayette Counties. The primary producing
zone in the Giddings field is the Austin Chalk formation, a fractured carbonate
formation that has been highly conducive to horizontal drilling. In this field,
the Austin Chalk formation ranges in depth between approximately 7,000 and
17,000 feet.

We first acquired interests in the Giddings field in September 1992. During the
year ended December 31, 1999, our average net production from this field was
approximately 61 MMcfe of gas per day. As of October 2000, our net production
averaged 50 MMcfe of gas per day. Through December 31, 1999, we had drilled 260
gross (86 net) wells in this field, and we continue to control approximately
217,000 gross (69,000 net) undeveloped acres in this area. We currently divide
the Giddings field into two primary prospect areas, the Navasota River,
primarily in Grimes County, and Independence, primarily in

S-34
<PAGE> 35

Washington County. We expect to drill new wells, including infill wells, and
re-enter older wells to drill additional laterals in the Giddings field.
Currently, we hold a majority of our interests in this field pursuant to
agreements with the primary operators in this field, Chesapeake Energy
Corporation and, to a lesser extent, Anadarko. Four wells were drilled in the
Independence area in 1999 and four additional wells were drilled through October
2000.

In addition to the Austin Chalk, the Georgetown formation is a secondary target
in both the Navasota and Independence prospect areas. The Georgetown formation
is approximately 200 feet below the base of the Austin Chalk, and like the
Austin Chalk, it is a limestone formation that is best produced from horizontal
well bores. Rather than drill new wells for the Georgetown formation, we have
decided to wait for the Austin Chalk production to decline and then add
horizontal laterals to our original Austin Chalk wells. We participated in one
well in the Navasota area in 1999 and as part of a re-entry program that began
in October 2000 in the Independence area. A total of six Georgetown re-entries
are currently planned through 2001.

HLM Project. We have obtained a 3-D seismic survey on approximately 140 square
miles located in Harris, Montgomery and Liberty Counties in Texas. We conducted
the survey to test the lower Wilcox. The lower Wilcox is a prolific producer
throughout the Texas Gulf Coast and has produced over 250 Bcf of gas from the
North Milton field along the same fault complex as the HLM prospects. In 2000,
we drilled the first lower Wilcox test well as a directional well to a depth of
18,500 feet. As of October 2000, we had tested two lower Wilcox sands and were
completing a third zone in the well. We plan to spud a second lower Wilcox
prospect before year end 2000. We are the operator of and have a 46% working
interest in the lower Wilcox.

Elm Grove. Effective January 1, 2000, we acquired a 37% working interest in 20
wells in the Elm Grove field in Caddo and Bossier Parishes in Northern
Louisiana. The operator, JW Operating, drilled the 20 wells in 17 sections to
extend the Cotton Valley production downdip from the mature Caspiana field. In
addition to the Cotton Valley at 9,500 feet, shallower secondary zones include
the Hosston and Rodessa intervals.

Through October 2000, we had participated in drilling 28 gross wells (10.4 net
wells). Our net production has increased from 5,300 Mcf of gas per day at the
time of the acquisition to approximately 11,000 Mcf of gas per day currently. We
plan to continue a three rig drilling program in 2001, with the drilling of 42
wells budgeted. We plan to drill most of these wells on 160 acre spacing. The
Caspiana field has been successfully downspaced to 80 acre patterns, and the
potential exists for similar spacing throughout our Elm Grove acreage.

In addition, the quality of the Hosston sands increases sufficiently in parts of
the field to merit dual completions or separate wells. Five of the wells drilled
in 2000 were drilled with Hosston objectives.

Permian Basin

Approximately 39% of our estimated proved reserves at December 31, 1999 were
located in our Permian Basin core area. These reserves are concentrated in the
Andrews Unit, the Roundtop Unit, the Shafter Lake San Andres Unit and the Nolley
Wolfcamp Unit.

Our 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. Most of the properties that produce
from these horizons are under secondary recovery. Given nearby CO(2) pipelines
and successful CO(2) floods on nearby properties that are similar to ours, we
believe significant potential remains for enhanced recovery on these properties.
In addition, many of the properties are in a relatively early stage of
waterflood production. This gives us several opportunities for further pattern
enhancement and development drilling.

A significant portion of our total estimated proved reserves in the Permian
Basin region lie in Andrews County, Texas. We produce approximately 2,500 gross
BOPD in Andrews County and realize significant economies of scale from this
large operation. In Andrews County, we own two electrical distribution

S-35
<PAGE> 36

systems, three saltwater gathering and disposal systems and several yards for
both storing equipment and staging new development projects. Two of our larger
production facilities in Andrews County connect into a water supply system with
excess capacity for expanding existing or initiating new secondary and enhanced
recovery projects. We believe that these systems and facilities provide us with
a competitive advantage in acquiring additional operated properties in Andrews
County.

Our largest (by value) Permian Basin units are the Andrews Unit, the Roundtop
Unit and the Shafter Lake San Andres Unit.

Andrews Unit. The Andrews Unit produces from the Wolfcamp/Penn formation at
approximately 8,600 feet. We own and operate a 98.6% working interest in this
3,230 acre unit. In late 1996, we began water injection with initial response
occurring in late 1998. Our gross production from the Andrews Unit in December
1999 was approximately 765 BOPD and with our year-to-date 2000 exploitation
activity, our gross production from the Andrews Unit has increased to over 1,100
BOPD as of October 2000. We anticipate continuing to expand our waterflood
operations during the rest of 2000 and 2001 by drilling at least three
producers, converting eight wells to injection and continuing an aggressive
workover program. We also believe that production from this waterflood unit may
ultimately be enhanced with the use of CO(2) or surfactants with flooding.

Roundtop Unit. We own and operate a 61.6% working interest in this 4,559 acre
unit in Fisher County, Texas. This secondary recovery unit produces from the
Palo Pinto formation at approximately 4,700 feet. We became the operator of this
unit in March 1998. Our gross oil production from this unit was approximately
540 BOPD in December 1999 and was still averaging 540 BOPD at the end of October
2000. The previous operator originally waterflooded this unit with success on a
peripheral injection pattern prior to changing to a five spot pattern. We began
returning the unit to a peripheral flood pattern in 1998 and continued
reconfiguring the injection pattern during 2000. In 2001, we will continue to
install high volume pumps to lower water levels in the wells in the center of
the field with the expectation of obtaining even higher efficiencies from the
overall flood pattern.

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. We have an 81.4% working interest in this
secondary recovery unit. Our gross oil production from this unit averaged 790
BOPD in 1999 and has risen to 820 BOPD at the end of October 2000. We have
drilled 51 infill wells on 20 acre spacing since becoming operator of the unit
in early 1993. In 2000, we drilled nine of those wells on 20 acre spacing along
with six wells on ten acre spacing. We believe operators of other nearby San
Andres fields have successfully drilled to ten acre spacing before CO(2)
injection. The wells we drilled are designed to test the viability of ten acre
locations within the center of the Shafter Lake unit. The preliminary
indications are promising with the two producers each averaging over 50 BOPD
gross. We expect to continue drilling both ten acre and 20 acre spaced wells in
2001 and may use CO(2) flooding as the field matures.

Mid-Continent Region

Our Mid-Continent operations are currently focused in Oklahoma, North Texas and
Kansas, where approximately 22% of our total estimated proved reserves at
December 31, 1999 were located.

Oklahoma. Five waterfloods collectively represent a majority of our proved
reserves in the Mid-Continent region. These waterfloods are identified as the
Oakdale Red Fork Unit, the Calumet Cottage Grove Unit, the Witcher Red Fork
Unit, the Cutter South Unit and the Rush Springs Unit. We initiated and unitized
all of these waterfloods.

Oakdale Red Fork Unit. We own and operate a 97.3% working interest in this
3,600 acre unit in Northwestern Oklahoma. This secondary recovery unit produces
from the Redfork formation at 6,400 feet. Our gross oil production from this
unit was approximately 790 BOPD in December 1999 and 750 BOPD in October 2000.
We drilled two wells during 1999 and drilled two wells and re-entered one well
through

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<PAGE> 37

October 2000. For the rest of 2000 and 2001, we plan to continue to expand our
waterflood to the south with the drilling of two producing and two injection
wells on this unit.

Calumet Cottage Grove Unit. We operate this secondary recovery unit which
consists of 11,400 acres in Central Oklahoma. This unit produces from the
Pennsylvanian Cottage Grove formation at 8,100 feet. Our gross production from
this unit in December 1999 was approximately 1,850 BOPD and 1,890 BOPD in
October 2000. We have a 48.0% working interest in this unit. In 1999, we drilled
a total of eight wells. Through October 2000, we drilled one well, re-entered
two others as producers and performed 13 workovers. During the last quarter of
2000, we plan to drill two additional wells, and during 2001, we plan to drill
six producing wells and two injectors on this unit.

Witcher Red Fork Unit. We operate the 1,620 acre Witcher Red Fork Unit, which
is located in Central Oklahoma. We have an 81.0% working interest in this 6,400
foot mature secondary recovery unit. In December 1999, our gross production from
this unit was approximately 350 BOPD and in October 2000, our gross production
had declined as expected to 250 BOPD.

North Texas. The North Texas region stretches from the Chadbourne Ranch field
in Coke County in the west to several individual leases in Grayson County in the
east. As of December 1999, the Rhombochasm, Katz, Electra and Burkburnett fields
had the most significant value in our North Texas region. We sold both the
Electra and Burkburnett fields effective August 1, 2000 and retained volumetric
production payments totaling 246,000 Bbls. At the time we sold these fields, our
total net production from both fields was approximately 1,200 BOPD. By selling
these higher lifting cost fields, we streamlined our operations by eliminating
approximately 630 active wells, including water injection wells.

DRILLING RESULTS

We participated in the following wells during the periods indicated. In the
table, "gross" refers to the total wells in which we have a working interest,
and "net" refers to gross wells multiplied by our working interest in them.

<TABLE>
<CAPTION>
NINE MONTHS
ENDED YEAR ENDED DECEMBER 31,
SEPTEMBER 30, ------------------------------------------
2000 1999(1) 1998(1)(2) 1997(3)
-------------- ------------ ------------ ------------
GROSS NET GROSS NET GROSS NET GROSS NET
------ ----- ----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
DEVELOPMENT:
Productive...................... 77.0 46.1 46.0 29.4 69.0 47.1 54.0 23.1
Non-productive.................. 3.0 2.4 2.0 1.0 1.0 1.0 4.0 2.2
---- ---- ---- ---- ---- ---- ---- ----
Total......................... 80.0 48.5 48.0 30.4 70.0 48.1 58.0 25.3
==== ==== ==== ==== ==== ==== ==== ====
EXPLORATORY:
Productive...................... 15.0 9.3 11.0 8.2 23.0 9.4 20.0 13.7
Non-productive.................. 6.0 4.6 3.0 2.5 7.0 4.0 18.0 6.4
---- ---- ---- ---- ---- ---- ---- ----
Total......................... 21.0 13.9 14.0 10.7 30.0 13.4 38.0 20.1
==== ==== ==== ==== ==== ==== ==== ====
</TABLE>

---------------------------
(1) Includes 15 gross (11.2 net) and 7 gross (4 net) wells in progress at
December 31, 1999 and 1998, respectively.
(2) Excludes 343 gross (175 net) productive wells acquired during 1998.
(3) Includes results for Coda Energy since November 26, 1997, the date we
acquired Coda Energy.

ACREAGE

The following table sets forth, as of December 31, 1999, the gross and net acres
that we owned, controlled or had the right to acquire interests in for both
developed and undeveloped acreage. Developed acreage means acreage within
producing units and undeveloped acreage means acreage that has not been placed
in

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<PAGE> 38

producing units. "Gross" acres means the total number of acres in which we own a
working interest. "Net" acres means gross acres multiplied by our fractional
working interest.

<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED(1)
----------------- -------------------
GROSS NET GROSS NET
------- ------- --------- -------
<S> <C> <C> <C> <C>
ROCKY MOUNTAIN:
Green River Basin............................. 5,123 480 525,140 138,337
Moxa Arch Trend............................... 24,861 14,619 23,559 14,227
Wind River Basin.............................. 2,077 720 336,202 113,440
Big Horn Basin................................ 643 321 291,188 100,012
Denver-Julesburg Basin........................ 207,365 2,298 177,939 91,279
GULF COAST....................................... 119,954 51,847 449,889 254,668
PERMIAN BASIN.................................... 97,871 49,497 20 20
MID-CONTINENT:
Oklahoma...................................... 119,100 39,635 30,475 10,898
North Texas................................... 36,593 21,777 640 320
Kansas........................................ 37,489 31,488 8,563 8,000
North Dakota.................................. 0 0 4,000 1,858
OTHER OPERATING AREAS:
Arkansas...................................... 56 42 6,001 4,383
Michigan-Central Basin........................ 1,664 702 71,055 12,554
------- ------- --------- -------
Totals...................................... 652,796 213,426 1,924,671 749,996
======= ======= ========= =======
</TABLE>

---------------------------
(1) Leases covering less than half of the undeveloped acreage will expire within
the next three years. However, we expect to evaluate this acreage prior to
its expiration. Our 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.

PRODUCTIVE WELL SUMMARY

The following table sets forth our ownership in productive wells at December 31,
1999. Gross oil and gas wells include 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......................................................... 878.0 344.8
Oil......................................................... 1,828.0 1,099.8
------- -------
Total.................................................. 2,706.0 1,444.6
======= =======
</TABLE>

EMPLOYEES

As of September 30, 2000, we had 166 full time employees, none of whom is
represented by organized labor unions. We consider our employee relations to be
good.

S-38
<PAGE> 39

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............... 65 Chairman of the Board and Chief Executive Officer
Laurence D. Belfer............. 34 Director, Vice-Chairman
Grant W. Henderson............. 41 Director, President and Chief Operating Officer
Dominick J. Golio.............. 54 Senior Vice President -- Finance, Chief Financial
Officer, Treasurer and Secretary
Shiv K. Sharma................. 58 Senior Vice President -- Engineering
Steven L. Mueller.............. 47 Senior Vice President -- Exploration and Production
Graham Allison................. 60 Director
Daniel C. Arnold............... 70 Director
Alan D. Berlin................. 60 Director
Jack Saltz..................... 68 Director
</TABLE>

Robert A. Belfer is our Chairman of the Board and Chief Executive Officer. Mr.
Belfer began his career at Belco Petroleum Corporation in 1958 and became
Executive Vice President in 1964, President in 1965 and Chairman of the Board in
1984. Belco Petroleum Corporation 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 Belco Petroleum Corporation
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 with us, Mr. Belfer
serves on the board of Enron. 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 is our Vice-Chairman. Mr. Belfer joined us as Vice President
in September 1992. He was promoted to Executive Vice President in May 1995 and
Chief Operating Officer in December 1995, was named President in April 1997 and
Vice-Chairman in March 1999. 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).

Grant W. Henderson is our President and Chief Operating Officer. He is also one
of our directors. He was named President effective March 1, 1999 and Chief
Operating Officer effective May 2000, and prior to his promotions he served as
Senior Vice President-Corporate Development. Mr. Henderson was formerly
President and Chief Financial Officer of Coda and 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 in February 1996. Mr. Henderson was
previously employed by NationsBank, beginning in 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.

Dominick J. Golio is our Senior Vice President -- Finance, Chief Financial
Officer, Treasurer . 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 our company. Mr. Golio
is a Certified

S-39
<PAGE> 40

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 is our Senior Vice President -- Engineering. Mr. Sharma began his
career in 1967 as a Reservoir Engineer with Shell Oil Company. In 1970, he
joined Belco Petroleum Corporation 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 our 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 is our Senior Vice President -- Exploration and Production.
Mr. Mueller began his career in 1975 as a Geological Engineer at Tenneco Oil,
Lafayette. He advanced at Tenneco Oil 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 our company. Mr. Mueller has over 24 years experience in
exploring for and exploiting oil and gas fields both onshore and offshore. He
holds a BS in Geological Engineering from the Colorado School of Mines (1975).

S-40
<PAGE> 41

UNDERWRITING

We have entered into an underwriting agreement with the underwriters named
below. CIBC World Markets Corp. and Dain Rauscher Incorporated are acting as
representatives of the underwriters.

The underwriting agreement provides for the purchase of a specific number of
shares of common stock by each of the underwriters. The underwriters'
obligations are several, which means that each underwriter is required to
purchase a specified number of shares, but is not responsible for the commitment
of any other underwriter to purchase shares. Subject to the terms and conditions
of the underwriting agreement, each underwriter has severally agreed to purchase
the number of shares of common stock set forth opposite its name below:

<TABLE>
<CAPTION>
NUMBER OF SHARES
UNDERWRITER ----------------
<S> <C>
CIBC World Markets Corp................................
Dain Rauscher Incorporated.............................
---------
Total............................................. 4,000,000
=========
</TABLE>

The underwriters have agreed to purchase all of the shares offered by this
prospectus supplement (other than those covered by the over-allotment option
described below) if any are purchased. Under the underwriting agreement, if an
underwriter defaults in its commitment to purchase shares, the commitments of
non-defaulting underwriters may be increased or the underwriting agreement may
be terminated, depending on the circumstances.

The shares should be ready for delivery on or about , 2000 against
payment in immediately available funds. The underwriters are offering the shares
subject to various conditions and may reject all or part of any order. The
representatives have advised us that the underwriters propose to offer the
shares directly to the public at the public offering price that appears on the
cover page of this prospectus supplement. In addition, the representatives may
offer some of the shares to other securities dealers at such price less a
concession of $ per share. The underwriters may also allow, and such dealers
may reallow, a concession not in excess of $ per share to other dealers.
After the shares are released for sale to the public, the underwriters may
change the offering price and other selling terms at various times.

We have granted the underwriters an over-allotment option. This option, which is
exercisable for up to 30 days after the date of this prospectus supplement,
permits the underwriters to purchase a maximum of 600,000 additional shares from
us to cover over-allotments. If the underwriters exercise all or part of this
option, they will purchase shares covered by the option at the public offering
price that appears on the cover page of this prospectus supplement, less the
underwriting discount. If this option is exercised in full, the total price to
the public will be $ , and the total proceeds to us will be $ . The
underwriters have severally agreed that, to the extent the over-allotment option
is exercised, they will each purchase a number of additional shares
proportionate to the underwriter's initial amount reflected in the foregoing
table.

The following table provides information regarding the amount of the discount to
be paid to the underwriters by us:

<TABLE>
<CAPTION>
TOTAL WITHOUT EXERCISE OF TOTAL WITH FULL EXERCISE OF
PER SHARE OVER-ALLOTMENT OPTION OVER-ALLOTMENT OPTION
--------- ------------------------- ---------------------------
<S> <C> <C> <C>
Belco Oil & Gas Corp............... $ $ $
</TABLE>

We estimate that our total expenses of the offering, excluding underwriting
discount, will be approximately $ .

We have agreed to indemnify the underwriters against certain liabilities,
including liabilities under the Securities Act of 1933.

S-41
<PAGE> 42

We and our senior executive officers and directors have agreed to a 90 day "lock
up" with respect to all shares of our common stock and other securities that
they beneficially own, including securities that are convertible into shares of
common stock and securities that are exchangeable or exercisable for shares of
common stock. This means that, for a period of 90 days following the date of
this prospectus supplement, we and such persons may not offer, sell, pledge or
otherwise dispose of these securities subject to the lock up without the prior
written consent of CIBC World Markets Corp.

Rules of the SEC may limit the ability of the underwriters to bid for or
purchase shares before the distribution of the shares is completed. The
underwriters may engage in the following activities in accordance with the
rules:

- Stabilizing transactions -- The representatives may make bids or purchases
for the purpose of pegging, fixing or maintaining the price of the shares, so
long as stabilizing bids do not exceed a specific maximum.

- Over-allotments and syndicate covering transactions -- The underwriters may
sell more shares of our common stock in connection with this offering than
the number of shares than they have committed to purchase. This
over-allotment creates a short position for the underwriters. This short
sales position may involve either "covered" short sales or "naked" short
sales. Covered short sales are short sales made in an amount not greater than
the underwriters' over-allotment option to purchase additional shares in this
offering described above. The underwriters may close out any covered short
position either by exercising their over-allotment option or by purchasing
shares in the open market. To determine how they will close the covered short
position, the underwriters will consider, among other things, the price of
shares available for purchase in the open market, as compared to the price at
which they may purchase shares through the over-allotment option. Naked short
sales are short sales in excess of the over-allotment option. The
underwriters must close out any naked short position by purchasing shares in
the open market. A naked short position is more likely to be created if the
underwriters are concerned that, in the open market after pricing, there may
be downward pressure on the price of the shares that could adversely affect
investors who purchase shares in this offering.

- Penalty bids -- If the representatives purchase shares in the open market in
a stabilizing transaction or syndicate covering transaction, they may reclaim
a selling concession from the underwriters and selling group members who sold
those shares as part of this offering.

Similar to other purchase transactions, the underwriters' purchases to cover the
syndicate short sales or to stabilize the market price of our common stock may
have the effect of raising or maintaining the market price of our common stock
or preventing or mitigating a decline in the market price of our common stock.
As a result, the price of the shares of our common stock may be higher than the
price that might otherwise exist in the open market. The imposition of a penalty
bid might also have an effect on the price of the shares if it discourages
resales of the shares.

Neither we nor the underwriters make any representation or prediction as to the
effect that the transactions described above may have on the price of the
shares. These transactions may occur on the New York Stock Exchange or
otherwise. If such transactions are commenced, they may be discontinued without
notice at any time.

LEGAL MATTERS

The validity of the shares of common stock being offered hereby and certain
other legal matters in connection with this offering are being passed upon for
Belco by Vinson & Elkins L.L.P., New York, New York. Certain legal matters
related to the shares of common stock will be passed upon for the Underwriters
by Haynes and Boone, LLP. Certain matters of Nevada law will be passed upon by
Woodburn and Wedge. Vinson & Elkins L.L.P. and Haynes and Boone, LLP will rely
upon the opinion of Woodburn and Wedge as to matters of Nevada law. Haynes and
Boone, LLP from time to time acts as counsel to Belco with respect to certain
matters.

S-42
<PAGE> 43

EXPERTS

The audited financial statements as of December 31, 1999 and 1998 and for each
of the three years in the period ended December 31, 1999, included elsewhere and
incorporated by reference in this prospectus supplement have been audited by
Arthur Andersen LLP, independent public accountants, as indicated in their
report with respect thereto, and are included herein in reliance upon the
authority of said firm as experts in accounting and auditing in giving said
report.

Certain of the information included and incorporated by reference in this
prospectus supplement regarding proved reserves at December 31, 1999, 1998,
1997, 1996 and 1995, 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.

GLOSSARY OF CERTAIN INDUSTRY TERMS

The definitions set forth below shall apply to the indicated terms as used in
this prospectus supplement. All volumes of 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.

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

Bcf. One billion cubic feet of gas.

Bcfe. One billion cubic feet of gas equivalent. Determined using the ratio of
one barrel of crude oil to six Mcf of gas.

BOPD. Barrels of oil per day.

Behind-the-pipe. Hydrocarbons in a potentially producing horizon penetrated by
a well bore the production of which has been postponed pending the production of
hydrocarbons from another formation penetrated by the well bore. The
hydrocarbons are classified as proved but non-producing reserves.

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

Development well. A well drilled with the proved boundaries of an oil or gas
reservoir with the intention of completing the stratigraphic horizon known to be
productive.

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

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

Farmin or farmout. An agreement under which the owner of a working interest in
an oil and gas lease assigns the working interest or a portion thereof to
another party who desires to drill on the leased acreage. Generally, the
assignee is required to drill one or more wells in order to earn its interest in
the acreage. The assignor usually retains a royalty or reversionary interest in
the lease. The interest received by an assignee is a "farmin" while the interest
transferred by the assignor is a "farmout."

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

S-43
<PAGE> 44

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

Mcf. One thousand cubic feet of gas.

Mcfe. One thousand cubic feet of gas equivalent. Determined using the ratio of
one barrel of crude oil to six mcf of gas.

MMBbls. One million Bbls.

MMBtu. One million Btus.

MMcf. One million cubic feet of gas.

MMcfe. One million cubic feet of gas equivalent. Determined using the ratio of
one barrel of crude oil to six mcf of gas.

Net acres or net wells. The sum of the fractional working interests owned in
gross acres or gross wells.

Non-producing reserves. Non-producing reserves consist of (i) reserves from
wells that have been completed and tested but are not yet producing due to lack
of market or minor completion problems that are expected to be correct, and (ii)
reserves currently behind-the-pipe in existing wells which are expected to be
productive due to both the well log characteristics and analogous production in
the immediate vicinity of the well.

NYMEX. New York Mercantile Exchange.

Present value. When used with respect to oil and gas reserves, present value
means the estimated future gross revenue to be generated from the production of
proved reserves, net of estimated production and future development costs and
production and ad valorem taxes, using prices and costs in effect as of the date
of the report or estimate held constant over the life of the reserves, other
than adjustments called for in contracts, without giving effect to non-property
related expenses such as general and administrative expenses, debt service and
future income tax expense or to depreciation, depletion and amortization,
discounted using an annual discount rate of 10%.

Productive well. A well that is found to be capable of producing hydrocarbons
in sufficient quantities to justify completion as an oil or gas well.

Proved developed reserves. Proved reserves that can be expected to be recovered
from existing wells with existing equipment and operating methods. Additional
oil and gas expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing the natural forces and
mechanisms of primary recovery should be included as "proved developed reserves"
on after testing by a pilot project or after the operation of an installed
program has confirmed through production response that increased recovery will
be achieved.

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

Proved undeveloped reserves. 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. Reserves on undrilled acreage shall be
limited to those drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other undrilled units
can be claimed only where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves be attributable
to any acreage for which an application of fluid injection or other improved
recovery techniques is contemplated, unless such techniques have been proved
effective by actual tests in the area and in the same reservoir.

Recompletion. An operation to abandon the production of oil and/or gas from a
well in one zone within the existing well bore and to make the well produce oil
and/or gas from a different, separately producible zone within the existing
wellbore.

S-44
<PAGE> 45

Reserve to production ratio. The estimated productive life of a proved
reservoir based upon the economic limit of such reservoir producing hydrocarbons
in paying quantities assuming certain price and cost parameters. For purposes of
this prospectus, the reserve to production ratio is calculated by dividing the
proved reserves (on a Mcfe basis) at the end of the period by production volumes
for the previous 12 months.

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

Secondary recovery. A method of oil and gas extraction in which energy sources
extrinsic to the reservoir are utilized.

Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.

Working interest. The operating interest which gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all costs of exploration to development and operations and all risks in
connection therewith.

S-45
<PAGE> 46

BELCO OIL & GAS CORP. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants.................. F-2
Consolidated Balance Sheets as of December 31, 1999 and
1998................................................... F-3
Consolidated Statements of Operations for the Years Ended
December 31, 1999, 1998 and 1997....................... F-4
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1999, 1998 and 1997........... F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 1998 and 1997....................... F-6
Notes to Consolidated Financial Statements................ F-7

UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidated Balance Sheet at September 30,
2000................................................... F-30
Condensed Consolidated Statements of Operations for the
Nine Months Ended September 30, 2000 and 1999.......... F-31
Condensed Consolidated Statement of Stockholders' Equity
for the Nine Months Ended September 30, 2000........... F-32
Condensed Consolidated Statements of Cash Flows for the
Nine Months Ended September 30, 2000 and 1999.......... F-33
Notes to Unaudited Condensed Consolidated Financial
Statements............................................. F-34
</TABLE>

F-1
<PAGE> 47

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, 1999 and 1998,
and the related consolidated statements of operations, stockholders' equity and
cash flows for each of the three years in the period ended December 31, 1999.
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 auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.

In our opinion, the 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, 1999 and 1998, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1999, in conformity with accounting principles generally
accepted in the United States.

ARTHUR ANDERSEN LLP

Dallas, Texas
February 23, 2000

F-2
<PAGE> 48

BELCO OIL & GAS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
DECEMBER 31,
----------------------
1999 1998
---------- ---------
(IN THOUSANDS)
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents (including restricted cash of
$800,000 at
December 31, 1999)...................................... $ 2,105 $ 2,435
Accounts receivable....................................... 24,870 28,464
Income taxes receivable................................... 6,661 --
Assets from commodity price risk management activities.... 2,879 18,643
Other current assets...................................... 3,496 1,005
---------- ---------
Total Current Assets............................... 40,011 50,547
Property and Equipment:
Oil and gas properties at cost based on full-cost
accounting --
Proved oil and gas properties........................... 1,008,261 931,218
Unproved oil and gas properties......................... 71,075 74,935
Less -- Accumulated depreciation, depletion and
amortization........................................... (619,446) (566,613)
---------- ---------
Net oil and gas property.................................. 459,890 439,540
---------- ---------
Building and other equipment.............................. 9,107 8,633
Less -- Accumulated depreciation........................ (2,634) (1,281)
---------- ---------
Net building and other equipment.......................... 6,473 7,352
Other Assets................................................ 4,599 8,097
---------- ---------
Total Assets....................................... $ 510,973 $ 505,536
========== =========

LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable.......................................... $ 17,970 $ 18,372
Liabilities from commodity price risk management
activities.............................................. 17,822 5,393
Accrued interest.......................................... 7,098 6,897
Other accrued liabilities................................. 5,510 5,064
---------- ---------
Total Current Liabilities.......................... 48,400 35,726
Long-Term Debt.............................................. 306,744 294,990
Deferred Income Taxes....................................... 33,638 31,833
Liabilities from Commodity Price Risk Management
Activities................................................ 8,219 4,696
Stockholders' Equity:
Preferred stock, $0.01 par value; 10,000,000 shares
authorized and 3,985,000 and 4,312,000 outstanding at
December 31, 1999 and 1998, respectively................ 40 43
Common Stock, $0.01 par value; 120,000,000 shares
authorized; 31,797,300 and 31,609,900 issued and
outstanding at December 31, 1999 and 1998,
respectively............................................ 318 316
Additional paid-in capital................................ 297,225 301,416
Retained earnings deficit................................. (177,111) (161,627)
Treasury Stock, 704,900 shares............................ (4,317) --
Unearned compensation..................................... (1,430) (1,082)
Notes receivable for equity interest...................... (753) (775)
---------- ---------
Total Stockholders' Equity......................... 113,972 138,291
---------- ---------
Total Liabilities and Stockholders' Equity......... $ 510,973 $ 505,536
========== =========
</TABLE>

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

F-3
<PAGE> 49

BELCO OIL & GAS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------
1999 1998 1997
----------- ------------ -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
Revenues:
Oil and gas sales, net of cash hedging activities(1)...... $141,932 $ 129,916 $129,994
Non-hedge commodity price risk management activities cash
settlements(1)......................................... (2,442) 172 (1,551)
Interest.................................................. 1,134 1,730 3,245
-------- --------- --------
Total revenues.................................... 140,624 131,818 131,688
-------- --------- --------
Costs and Expenses:
Oil and gas operating expenses............................ 29,854 33,615 7,358
Production taxes.......................................... 9,314 7,232 5,400
Depreciation, depletion and amortization.................. 54,182 56,102 46,684
Impairment of oil and gas properties...................... -- 229,000 150,000
Impairment of equity securities........................... 450 24,216 --
General and administrative................................ 4,940 5,216 3,913
Interest expense.......................................... 21,021 21,013 1,668
Non-cash change in fair value of derivatives(1)........... 34,094 (18,912) 4,928
-------- --------- --------
Total costs and expenses.......................... 153,855 357,482 219,951
-------- --------- --------
Income (Loss) Before Income Taxes........................... (13,231) (225,664) (88,263)
Provision (Benefit) for Income Taxes........................ (4,631) (78,107) (31,355)
-------- --------- --------
Net Income (Loss)........................................... (8,600) (147,557) (56,908)
Preferred Stock Dividends................................... (6,884) (5,406) --
-------- --------- --------
Net Income (Loss) Available to Common Stock................. $(15,484) $(152,963) $(56,908)
======== ========= ========
Earnings (Loss) Per Share of Common Stock, Basic and Fully
Diluted................................................... $ (0.49) $ (4.85) $ (1.80)
======== ========= ========
Average Number of Common Shares Used in Computation, Basic
and Fully Diluted......................................... 31,642 31,529 31,538
======== ========= ========
</TABLE>

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

(1) Amounts restated to report CPRM hedge settlements as a part of oil and gas
revenues, CPRM non-hedge settlements as a separate revenue component and
unrealized CPRM non-cash gains or losses as a component of costs and
expenses. The restatement of all such amounts did not result in any changes
to previously reported net income or loss, including per share amounts.

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

F-4
<PAGE> 50

BELCO OIL & GAS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>

NOTES
PREFERRED STOCK COMMON STOCK ADDITIONAL RETAINED RECEIVABLE
--------------- --------------- PAID-IN UNEARNED EARNINGS FOR EQUITY
SHARES AMOUNT SHARES AMOUNT CAPITAL COMPENSATION (DEFICIT) INTEREST
------ ------ ------ ------ ---------- ------------ --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1996.... -- $-- 31,577 $316 $186,703 $(1,285) $ 48,244 $(775)
----- --- ------ ---- -------- ------- --------- -----
Restricted stock issued....... -- -- 5 -- 123 192 -- --
Exercise of stock options..... -- -- 2 -- 38 -- --
Issuance of warrants.......... -- -- -- -- 10,000 -- -- --
Unrealized loss on marketable
equity securities........... -- -- -- -- -- -- -- --
Net income (loss)............. -- -- -- -- -- -- (56,908) --
----- --- ------ ---- -------- ------- --------- -----
BALANCE, DECEMBER 31, 1997.... -- $-- 31,584 $316 $196,864 $(1,093) $ (8,664) $(775)
===== === ====== ==== ======== ======= ========= =====
Comprehensive Income..........
Issuance of Preferred Stock... 4,370 $44 -- -- $105,025 -- -- --
Repurchase of Preferred
Stock....................... (58) (1) -- -- (806) -- -- --
Restricted Stock Issued
(Net)....................... -- -- 25 -- 333 11 -- --
Unrealized loss on marketable
equity securities........... -- -- -- -- -- -- -- --
Net income (loss)............. -- -- -- -- -- -- (147,557) --
Preferred Dividend paid....... -- -- -- -- -- -- (5,406) --
----- --- ------ ---- -------- ------- --------- -----
BALANCE, DECEMBER 31, 1998.... 4,312 $43 31,609 $316 $301,416 $(1,082) $(161,627) $(775)
===== === ====== ==== ======== ======= ========= =====
Comprehensive Income..........
Repurchase of Preferred
Stock....................... (327) $(3) -- -- $ (5,049) -- -- --
Restricted Stock Issued....... -- -- 200 2 1,018 (1,020) -- --
Restricted Stock Forfeited.... -- -- (12) -- (160) 160 -- --
Restricted Stock Amortized.... -- -- -- -- -- 512 -- --
Net Income (Loss)............. -- -- -- -- -- -- (8,600) --
Preferred Dividend Paid....... -- -- -- -- -- -- (6,884) --
Treasury Stock Acquisitions... -- -- -- -- -- -- -- --
Payment Received.............. -- -- -- -- -- -- -- 22
----- --- ------ ---- -------- ------- --------- -----
BALANCE, DECEMBER 31, 1999.... 3,985 $40 31,797 $318 $297,225 $(1,430) $(177,111) $(753)
===== === ====== ==== ======== ======= ========= =====
Comprehensive Income..........

<CAPTION>
UNREALIZED
TREASURY LOSS ON
COMMON STOCK MARKETABLE
---------------- EQUITY COMPREHENSIVE
SHARES AMOUNT SECURITIES TOTAL INCOME
------ ------- ---------- --------- -------------
<S> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1996.... -- $ -- $ -- $ 233,203 --
---- ------- ------- --------- ---------
Restricted stock issued....... -- -- -- 315 --
Exercise of stock options..... -- -- -- 38 --
Issuance of warrants.......... -- -- -- 10,000 --
Unrealized loss on marketable
equity securities........... -- -- (2,000) (2,000) (1,320)
Net income (loss)............. -- -- -- (56,908) (56,908)
---- ------- ------- --------- ---------
BALANCE, DECEMBER 31, 1997.... -- $ -- $(2,000) $ 184,648
==== ======= ======= =========
Comprehensive Income.......... $ (58,228)
=========
Issuance of Preferred Stock... -- -- -- $ 105,069 --
Repurchase of Preferred
Stock....................... -- -- -- (807) --
Restricted Stock Issued
(Net)....................... -- -- -- 344 --
Unrealized loss on marketable
equity securities........... -- -- 2,000 2,000 1,320(a)
Net income (loss)............. -- -- -- (147,557) (147,557)
Preferred Dividend paid....... -- -- -- (5,406) --
---- ------- ------- --------- ---------
BALANCE, DECEMBER 31, 1998.... -- $ -- $ -- $ 138,291
==== ======= ======= =========
Comprehensive Income.......... $(146,237)
=========
Repurchase of Preferred
Stock....................... -- -- -- $ (5,052) --
Restricted Stock Issued....... -- -- -- --
Restricted Stock Forfeited.... -- -- -- -- --
Restricted Stock Amortized.... -- -- -- 512 --
Net Income (Loss)............. -- -- -- (8,600) (8,600)
Preferred Dividend Paid....... -- (6,884) --
Treasury Stock Acquisitions... (705) (4,317) -- (4,317) --
Payment Received.............. -- -- -- 22 --
---- ------- ------- --------- ---------
BALANCE, DECEMBER 31, 1999.... (705) $(4,317) $ -- $ 113,972
==== ======= ======= =========
Comprehensive Income.......... $ (8,600)
=========
</TABLE>

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

(a) Represents a reclassification adjustment for $2.0 million gross ($1.32
million net of tax) unrealized loss recognized in comprehensive income in
1997, but recognized in net income during 1998.

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

F-5
<PAGE> 51

BELCO OIL & GAS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------
1999 1998 1997
-------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)........................................ $ (8,600) $(147,557) $ (56,908)
Adjustments to reconcile net income (loss) to net
operating cash inflows --
Depreciation, depletion and amortization.............. 54,182 56,102 46,684
Impairment of oil and gas properties.................. -- 229,000 150,000
Impairment of equity securities....................... 450 9,773 --
Deferred tax benefit.................................. (4,856) (78,107) (31,536)
Commodity price risk management activities............ 5,901 2,942 (1,248)
Other................................................. 203 (19) 353
Changes in operating assets and liabilities --
Commodity price risk management..................... 28,193 (21,869) --
Accounts receivable................................. 3,617 15,208 1,850
Marketable equity securities........................ -- 30,884 --
Other current assets................................ (1,292) 247 (65)
Accounts payable and accrued liabilities............ 246 (10,259) (7,607)
-------- --------- ---------
Net operating cash inflows....................... 78,044 86,345 101,523
-------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures................. (73,932) (133,078) (140,975)
Proceeds from sale of oil and gas properties............. 215 6,292 13,949
Changes in accounts payable and accrued liabilities for
oil and gas expenditures.............................. -- -- 11,726
Change in advances to oil and gas operators.............. -- -- (277)
Purchase of Coda Energy, Inc............................. -- -- (214,896)
Purchase of marketable equity securities................. -- (10,467) (30,884)
Changes in other assets.................................. (351) (22) (1,779)
Other property additions................................. (474) (1,251) --
-------- --------- ---------
Net investing cash outflows...................... (74,542) (138,526) (363,136)
-------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings..................................... 53,500 68,000 85,000
Net proceeds from issuance of subordinated notes......... -- -- 145,400
Long-term debt repayments................................ (41,100) (124,500) --
Proceeds from issuance of Preferred Stock................ -- 105,069 --
Dividends on Preferred Stock............................. (6,884) (5,406) --
Repurchase of Common Stock............................... (4,317) -- --
Repurchase of Preferred Stock............................ (5,052) (807) --
Other.................................................... 21 -- --
-------- --------- ---------
Net financing cash inflows (outflows)............ (3,832) 42,356 230,400
-------- --------- ---------
Increase (decrease) in cash and cash equivalents........... (330) (9,825) (31,213)
Cash and cash equivalents at beginning of period........... 2,435 12,260 43,473
-------- --------- ---------
Cash and cash equivalents at end of period................. $ 2,105 $ 2,435 $ 12,260
======== ========= =========
</TABLE>

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

F-6
<PAGE> 52

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 CURRENT 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 presently conducted in the
United States. The Company's operations are focused in four core areas including
the Permian Basin (west Texas), the Mid-Continent (Oklahoma, north Texas and
Kansas), the Rocky Mountains (Wyoming), and the Austin Chalk (Texas 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. 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 7).

NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements for the periods presented include the
accounts of the Company and its wholly-owned subsidiaries including one month of
Coda operations for 1997. The Company's interests in the Moxa Arch investment
programs (the 1992 Moxa Arch Drilling Program, the 1993 Moxa Arch Drilling
Program, the Moxa Arch 1992 Offset Drilling Program and the Moxa Arch 1993
Offset Drilling

F-7
<PAGE> 53
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Program) (collectively, the "Programs") 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.

CASH EQUIVALENTS

The Company considers all highly liquid investments with an original maturity of
three months or less to be cash equivalents. At December 31, 1999 cash includes
$800,000 of funds on deposit with a counterparty and related to Commodity Price
Risk Management Activities. The depository amount varies from day to day and
dependent on the movement of commodity prices. Subsequent to calendar year-end
1999 the Company has deposited substantial amounts due to the run-up in the
price of oil during the first quarter of 2000 through mid-March.

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 $5,492,000, $6,054,000 and $5,769,000
of related internal costs during 1999, 1998 and 1997, 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 (PV10). If capitalized costs exceed this limit, the excess
is charged to depreciation, depletion and amortization.

The PV10 value of the Company's year-end 1999 estimated proved reserves were
well in excess of the ceiling test limit. For the full year ended December 31,
1998 the Company recorded $229 million ($149 million after tax) in non-cash
ceiling test provisions as required by full cost accounting rules. The
provisions were the result of applying substantially lower commodity prices to
estimated recoverable reserves.

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.

Buildings, equipment and gas processing facilities are depreciated on a
straight-line basis over the estimated useful lives of the assets, which range
from three to 20 years.

MANAGEMENT FEES

The Company manages three investment programs, which were formed during
1992-1994 to acquire and develop interests in certain drilling prospects located
in the Moxa Arch trend in Wyoming. 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

F-8
<PAGE> 54
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 $305,000 for both 1999 and 1998 and
$297,000 during 1997.

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, 1999, 1998 and 1997, totaled $4,881,000, $5,123,000 and
$3,742,000, respectively.

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. Commodity derivatives
contracts, which are usually placed with major financial institutions that the
Company believes are minimal credit risks, may take the form of futures
contracts, swaps or options. The oil and gas reference prices upon which these
commodity derivatives contracts are based reflect various market indices that
have a high degree of historical correlation with actual prices received by the
Company. 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. In the event of a loss of correlation between changes in oil
and gas reference prices under a commodity derivatives contract and actual oil
and gas prices, a gain or loss is recognized currently to the extent the
commodity derivatives have not offset changes in actual oil and gas prices.

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 14).

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 a gain or loss in the period of change.

In June 1998, the Financial Accounting Standards Board issued Statement No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("FAS 133"). FAS
133 is effective for fiscal years beginning after June 15, 2000. FAS 133
requires all derivatives to be recorded on the balance sheet at fair value and
established "special accounting" for the following three different types of
hedges: hedges of changes in the fair value of assets, liabilities, or firm
commitments (referred to as fair value hedges); hedges of the variable cash
flows of forecasted transactions (cash flow hedges); and hedges of foreign
currency exposures of net investments in foreign operations. Though the
accounting treatment and criteria for each of the three types of hedges is
unique, they all result in offsetting changes in fair values or cash flows of
both the hedge and the hedged item being recognized in earnings in the same
period with no net impact on reported earnings. Changes in fair value of
derivatives that do not meet the criteria of one of these three categories of
hedges are included in income and reported as either gain or loss for the
current period. Transition adjustments resulting from adoption must be
recognized in income and comprehensive income, as appropriate, as a cumulative
effect of an accounting change. Belco has not yet determined the effect of total
compliance, but it is not expected to materially impact the financial statements
of the Company.

F-9
<PAGE> 55
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

GAS BALANCING/REVENUE RECOGNITION

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, 1999 and 1998 were not significant.

INCOME TAXES

The Company accounts for income taxes under the provisions of 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.

NET INCOME (LOSS) PER COMMON SHARE

Basic and diluted net income (loss) per common share have been computed in
accordance with SFAS No. 128, "Earnings Per Share," which the Company adopted at
year end 1997. Net income per share amounts for prior periods have been restated
to conform with the provisions of the new standard. Basic net income per common
share is computed by dividing income available to common shareholders, after the
payment of dividends to preferred stockholders, by the weighted average number
of common shares outstanding for the periods. Diluted net income per common
share reflects the potential dilution that could occur if securities or other
contracts to issue common stock were exercised or converted into common stock.
Calculations of basic and diluted net income (loss) per common share are
illustrated in Note 12.

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 7 and 14).

NOTE 3 -- ACQUISITION OF CODA ENERGY, INC.

On November 26, 1997, Belco completed the Merger (the "Merger") of its
subsidiary Belco Acquisition Sub, Inc. ("Belco Sub"), a Delaware corporation
with and into Coda Energy, Inc., a Delaware corporation. The Merger was effected
pursuant to the terms of an Agreement and Plan of Merger, dated as of October
31, 1997, by and among Belco, Belco Sub and Coda. In connection with the Merger,
Belco paid $324 million, including $214 million in cash, assumption of $110
million in debt (face value), and the issuance of warrants to purchase 1,666,667
shares of common stock, par value $0.01 per share, of Belco (the "Belco Common
Stock") to the holders of the outstanding common stock, preferred stock and
options to purchase common stock of Coda. The warrants are exercisable for a
period of three years commencing on November 26, 1998 at an exercise price of
$27.50 per share. The warrant exercise price

F-10
<PAGE> 56
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

and the number of shares of Belco Common Stock that may be issued pursuant to
the exercise of the warrants will be adjusted to prevent dilution in the event
of stock splits, stock dividends and certain other events affecting the capital
structure of Belco.

The acquisition of Coda has been accounted for using the purchase method of
accounting and has been included in the financial statements of the Company
since the date of acquisition. The purchase price has been allocated to the
assets purchased and the liabilities assumed based upon the fair values on the
date of acquisition as follows (in thousands):

<TABLE>
<S> <C>
Value of proved and unproved oil and gas properties
acquired.................................................. $ 437,431
Value of building and other assets acquired................. 6,470
Working capital acquired, net............................... 5,534
Assumed deferred tax liability.............................. (101,616)
Long-term debt assumed...................................... (117,090)
Transaction costs and other................................. (5,833)
Issuance of warrants........................................ (10,000)
---------
Net cash paid, including capital contributed...... $ 214,896
=========
</TABLE>

NOTE 4 -- LONG TERM DEBT

Long term debt consists of the following at December 31, 1999 and 1998 (in
thousands):

<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1999 1998
-------- --------
<S> <C> <C>
Revolving credit facility due 2002.......................... $ 42,000 $ 29,500
8 7/8% Senior Subordinated Notes due 2007................... 150,000 150,000
10 1/2% Senior Subordinated Notes due 2006, including
premium totaling approximately $5.7 and $6.5 million for
1999 and 1998, respectively............................... 114,744 115,490
-------- --------
Total Debt........................................ 306,744 294,990
Less: Current maturities.................................... -- --
-------- --------
Long term debt.............................................. $306,744 $294,990
======== ========
</TABLE>

In September, 1997 the Company entered into a five-year $150 million Credit
Agreement dated September 23, 1997 (as amended, 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 at December 31, 1999 was set at $150 million with
$42.0 million advanced to the Company at that date. The borrowing base is
redetermined by the Agent and the Banks semi-annually, determined solely at
their discretion, predicated on the Company's oil and gas reserve value. In
addition, the Company may request two additional redeterminations and the Banks
may request one additional redetermination per year. During 1999, the Credit
Facility weighted average interest rate was approximately 6.0%.

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. Covenants
contained in the Credit Facility require the Company to maintain a minimum
Interest Coverage Ratio, Current Ratio and Leverage Ratio (Indebtedness to
EBITDA). The Company and its subsidiaries may not incur any indebtedness other
than indebtedness falling within the enumerated exceptions contained in the
Credit Facility. In addition, the Company's

F-11
<PAGE> 57
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

various debt instruments contain certain restrictive covenants that, among other
things, limit the ability of the Company to pay dividends.

Indebtedness under the Credit Facility bears interest at a floating rate based
(at the Company's option) upon (i) the ABR (as defined below) 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) with respect to 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 0.50%.
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 therefore
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 the 8 7/8% Notes. Interest
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.

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.

As of December 31, 1999, the Company had outstanding $109 million face value of
the 10 1/2% Notes. The debt was assumed in connection with the acquisition of
Coda in 1997 and was recorded at $117.1 million, including premium, reflecting
the fair value at the date of acquisition. The 10 1/2% Notes bear interest at an
annual rate of 10 1/2% payable semiannually in arrears on April 1 and October 1
of each year. The Notes are general, unsecured obligations of the Company, are
subordinated in right of payment to all Senior Debt (as defined in the Indenture
governing the 10 1/2% Notes) of the Company, and are senior in right of payment
to all future subordinated debt of the Company. On February 25, 1998, the
Company merged Coda into Belco and Belco assumed the obligations under the Coda
Indenture. Effective with the merger, the 10 1/2% Notes became pari passu in
right of payment with the 8 7/8% Notes.

The 10 1/2% Notes were issued pursuant to an Indenture, which contains certain
covenants that, among other things, limit the ability of Coda and its restricted
subsidiaries (as defined in the Indenture) to incur additional indebtedness and
issue Disqualified Stock (as defined in the Indenture), pay dividends, make
distributions, make investments, make certain other restricted payments, enter
into certain transactions with affiliates, dispose of certain assets, incur
liens securing pari passu or subordinated indebtedness of the Company and engage
in mergers and consolidations.

F-12
<PAGE> 58
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The 10 1/2% Notes are not redeemable by the Company prior to April 1, 2001.
After April 1, 2001, the 10 1/2% Notes will be subject to redemption at the
option of the Company, in whole or in part, at the redemption prices set forth
in the Indenture, plus accrued and unpaid interest thereon to the applicable
redemption date.

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 7/8% 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 7/8% through September 15, 2001 and at 10% from March 15, 2002
through September 15, 2007. The second agreement covers $110 million of 10 1/2%
long-term debt (comparable to the interest rate on the 10 1/2% 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 1/2% through October 1, 1999
and 11.625% from April 1, 2000 through April 1, 2003.

NOTE 5 -- RELATED-PARTY TRANSACTIONS

The Company's executive offices are leased from its Chairman and approximately
$250,000 was paid under such lease in 1999, 1998 and 1997. Management believes
the fee compares favorably to the terms which might have been available from a
non-affiliated party.

Certain employees of the Company had an ownership interest in certain oil and
gas properties held by the Company as of December 31, 1995. The Company had
receivables of $753,000 and $775,000 as of December 31, 1999 and 1998,
respectively, and related to amounts loaned to employees in connection with
purchases of oil and gas interests from such employees. The notes receivable
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).

NOTE 6 -- INCOME TAXES

Total provision (benefit) for income taxes consists of the following:

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------
1999 1998 1997
------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Current:
Federal(1).......................................... $(6,661) $ 20 $ (192)
State............................................... 225 87 373
------- -------- --------
(6,436) 107 181
Deferred:(1).......................................... 1,805 (78,214) (31,536)
------- -------- --------
Total income tax provision (benefit)........ $(4,631) $(78,107) $(31,355)
======= ======== ========
</TABLE>

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

(1) The 1999 federal income tax amount reflects a tax benefit of $6.7 million
for which a refund claim was filed in late 1999. Accordingly, this amount
was recorded as an income tax refund receivable as of December 31, 1999. The
refund was received in January 2000.

F-13
<PAGE> 59
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------
1999 1998 1997
------- -------- --------
<S> <C> <C> <C>
Statutory federal income taxes........................ $(4,631) $(78,982) $(30,892)
State income tax, net of federal benefit.............. 146 57 242
Section 29 tax credits................................ -- -- (850)
Capital loss valuation allowance...................... (161) 875 --
Other................................................. 15 (57) 145
------- -------- --------
Provision (benefit) for income taxes.................. $(4,631) $(78,107) $(31,355)
======= ======== ========
</TABLE>

The principal components of the Company's net deferred income tax liability are
as follows:

<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31,
-------------------
1999 1998
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Deferred income tax assets:
Commodity price risk management activities................ $ -- $ 3,940
Net operating loss........................................ 21,416 12,092
Capital loss.............................................. 4,495 5,055
Other..................................................... 8,095 5,983
-------- --------
$ 34,006 $ 27,070
-------- --------
Deferred income tax liabilities:
Depreciation, depletion and amortization.................. $(60,834) $(55,369)
Commodity price risk management activities................ (1,875) --
Other..................................................... (4,221) (2,659)
-------- --------
(66,930) (58,028)
Valuation allowance......................................... (714) (875)
-------- --------
Net deferred income tax liability................. $(33,638) $(31,833)
======== ========
</TABLE>

As a result of the acquisition of Coda, the Company succeeded to net operating
loss carryforwards ("NOLs") for income tax purposes that expire from 2000
through 2004. Due to a change of ownership (as defined by the Tax Return Act of
1986) which occurred prior to the acquisition by the Company, the utilization of
the Coda NOLs is severely restricted. At December 31, 1999, the Company
estimates that approximately $12.4 million of the Coda NOLs is available to
offset future income. For the year ended December 31, 1999, the Company
generated an NOL of approximately $48.8 million which can be carried forward
from 2000 to 2020. In addition to the NOLs, at December 31, 1999, the Company
has approximately $12.8 million of capital loss carry forwards which may be used
to offset capital gains realized over the next four years. A valuation allowance
of $2.0 million was established against the capital loss carryforward since this
amount is not expected to meet the realization test. The Company also has $0.6
million of alternative minimum tax ("AMT") credit carryovers. AMT credits may be
carried forward indefinitely.

F-14
<PAGE> 60
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

The basic credit, which is currently approximately $0.52 per MMBtu of natural
gas produced from tight sand reservoirs and approximately $1.06 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 $48 per Bbl in current dollars. The Company estimates
that it generated approximately $0.6 million of Section 29 Tax Credits in 1999.
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 produced 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 May 24, 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 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 14).

NOTE 7 -- COMMODITY PRICE RISK MANAGEMENT ACTIVITIES AND FAIR VALUE OF FINANCIAL
INSTRUMENTS

OIL AND GAS 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, 1999, the Company had entered into hedging
transactions with respect to a significant portion of its estimated oil
production for 2000 and approximately 50% of its estimated natural gas
production. Similar transactions were entered into covering lower quantities of
its estimated production for

F-15
<PAGE> 61
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the years 2001-2002. 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, 1999:

<TABLE>
<CAPTION>
PRODUCTION PERIODS
--------------------------
2000 2001 TOTAL
------- ------ -------
<S> <C> <C> <C>
Gas --
Price swaps -- receive fixed price (thousand
MMBtu)(1)(5)........................................ 4,890 -- 4,890
Average price, per MMBtu............................ $ 2.29 -- $ 2.29
Collars and options (thousand MMBtu)(2)................ 12,785 9,125 21,910
Average floor price, per MMBtu...................... $ 1.47 $ 1.91 $ 1.63
Average ceiling price, per MMBtu.................... $ 2.62 $ 2.85 $ 2.73
Price swaps -- pay fixed price (thousand MMBtu)(3)..... 310 -- 310
Average price, per MMBtu............................ $ 2.81 -- $ 2.81
Basis swaps (thousand MMBtu)(4)........................ 7,320 -- 7,320
Average basis differential, per MMBtu.................. $ (0.49) -- $ (0.49)
Oil --
Price swaps -- receive fixed price (MBbls)(1)(3)(7).... 610 268 878
Average price, per Bbl.............................. $ 18.81 $17.99 $ 18.56
Collars and options (MBbls)(2)(6)...................... 959 184 1,143
Average floor price, per Bbl........................ $ 16.95 $17.71 $ 17.06
Average ceiling price, per Bbl...................... $ 19.81 $20.90 $ 19.99
</TABLE>

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

(1) 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.

(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) The Company 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 920, 19,155 and 3,650 thousand MMBtu of swaps in 2000
through 2002, respectively, that are extendable at the election of the
counterparty.

(6) Does not include 108 and 13 MBbls of collars in 2001 and 2002, respectively,
that are extendable at the election of the counterparty.

(7) Does not include 333, 840, 966, 590 and 31 thousand Bbls of swaps in 2000
through 2004, respectively, that are extendable at the option of the
counterparty.

F-16
<PAGE> 62
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

A realized hedging gain (loss) of $3.9 million, $1.9 million and $(13.1) million
for 1999, 1998 and 1997, respectively, was included in Commodity Price Risk
Management revenues. As of December 31, 1999 and 1998, the Company had no
accrued liabilities settled derivative contracts. These amounts are included in
Price Risk Management activities as assets or liabilities as appropriate.

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 1999 results of
operations included an aggregate pre-tax loss of $33.8 million related to these
activities which included (1) net premiums received totaling $248,000 and (2)
the unrealized loss resulting from net change in the value of the Company's
market-to-market portfolio of price risk management activities for the year
ended December 31, 1999 of $34.1 million, all included in Commodity Price Risk
Management revenues. At December 31, 1999, the Company's consolidated balance
sheet reflects $3.0 million and $26.0 million of price risk management assets
and liabilities, respectively.

F-17
<PAGE> 63
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 1999,
that do not qualify for hedge accounting:

<TABLE>
<CAPTION>
PRODUCTION PERIODS
-------------------------------------------
2000 2001 2002 2003 TOTAL
------ ------ ------ ------ -------
<S> <C> <C> <C> <C> <C>
Gas --
Calls bought (thousand MMBtu)(2)........... 2,120 -- -- -- 2,120
Average price, per MMBtu................ $ 2.98 -- -- -- $ 2.98
Calls Sold (thousand MMBtu)(2)............. 7,320 7,300 -- -- 14,620
Average price, per MMBtu................ $ 2.78 $ 3.23 -- -- $ 3.00
Puts Sold (thousand MMBtu)(2).............. 3,620 -- -- -- 3,620
Average price, per MMBtu................ $ 2.28 -- -- -- $ 2.28
Price Swaps -- receive fixed price
(thousand MBbls)(3)(4).................. 7,320 3,650 -- -- 10,970
Average price, per MMBtu................ $ 2.30 $ 2.51 -- -- $ 2.37
Oil --
Straddles (MBbls)(1)....................... 25 -- -- -- 25
Average price, per Bbl.................. $17.48 -- -- -- $ 17.48
Price Swaps -- pay fixed price (thousand
MMBtu).................................. 45 -- -- -- 45
Average price, per MMBtu................ $22.65 -- -- -- $ 22.65
Price Swaps -- receive fixed price
(MBbls)(3)(5)........................... 1,051 151 13 -- 1,215
Average price, per Bbl.................. $19.27 $17.72 $17.25 -- $ 19.06
Calls Bought (MBbls)(2).................... 150 -- -- -- 150
Average price, per Bbl.................. $19.00 -- -- -- $ 19.00
Calls Sold (MBbls)(2)...................... 2,148 996 714 75 3,933
Average price, per Bbl.................. $20.06 $20.05 $21.86 $22.00 $ 20.42
Puts Sold (MBbls)(2)....................... 986 199 19 -- 1,204
Average price, per Bbl.................. $18.70 $15.81 $16.00 -- $ 18.18
Puts Bought (MBbls)(2)..................... 404 38 -- -- 442
Average price, per Bbl.................. $17.82 $17.17 -- -- $ 17.76
</TABLE>

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

(1) A straddle is a combination of a put sold and a call sold at the same strike
price. 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
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. Conversely, calls or
puts bought in return for the Company's payment of a premium or require the
counterparty to make a payment to the company in the event that the NYMEX
Reference Price on any settlement period is greater than the call price or
less than the put price.

(3) 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 instrument 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 instrument. All of these swaps listed will double the volumes
swapped when the NYMEX Reference Price is above the swap price for such
instrument.

(4) Does not include 3,660 thousand MMBtu of gas swap which have tiered pricing
at which the swap is canceled when the NYMEX Reference Price falls below
$1.80 per MMBtu. The volume doubles when the NYMEX Reference Price rises
above $2.90 per MMBtu.

F-18
<PAGE> 64
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(5) Does not include 341 and 38 MBbls of oil swaps for 2000 and 2001,
respectively, which have tiered pricing at which the swap is canceled when
the NYMEX Reference Price falls below $16.50 per Bbl as to 52% of the
volumes and $18.00 for the remaining volume.

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, 1999 and 1998. 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.

<TABLE>
<CAPTION>
DECEMBER 31, 1999 DECEMBER 31, 1998
------------------- -------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Cash and cash equivalents..................... $ 2,105 $ 2,105 $ 2,435 $ 2,435
Long-term debt................................ 306,744 296,323 294,990 277,180
Interest rate swaps........................... -- (6,549) -- 196
Oil and gas commodity -- Hedges............... -- (8,603) -- 4,584
-- Non-hedges........... (23,066) (23,066) 11,028 14,368
</TABLE>

The carrying values of trade receivables and trade payables included in the
accompanying consolidated balance sheets approximated market value at December
31, 1999 and 1998. The following methods and assumptions were used to estimate
the fair value of the financial instruments summarized in the above table.

CASH AND CASH EQUIVALENTS

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

MARKETABLE EQUITY SECURITIES

In June 1997 the Company purchased 2,940,000 shares of common stock of Hugoton
Energy Corp. ("Hugoton") at $10.50 per share for a total investment of $30.9
million. At December 31, 1997 a non-cash investment valuation provision in the
amount of $2 million was charged to stockholder's equity to reflect the value of
this investment at that date. In March 1998, Hugoton was acquired by Chesapeake
Energy Corporation ("CHK"). In the merger each share of Hugoton common stock was
converted into 1.3 shares of CHK common stock. During 1998 the Company disposed
of its holdings in CHK and realized a loss of $14.4 million.

On June 12, 1998, the Company, through its wholly-owned Canadian subsidiary,
purchased approximately $10.5 million of 5% Convertible Preferred Stock of Big
Bear Exploration, Ltd. ("Big Bear"), a Canadian oil and gas company, at
approximately $0.85 per share with each share convertible into one common share
of Big Bear. Through a subsequent restructuring agreement, Belco's preferred
stock holdings were converted to common stock and then subject to an 11:1
reverse stock split. As a result of the aforementioned transactions, Belco
became the owner of 1,948,052 common shares or approximately 4.6% ownership in
Big Bear. The substantial decline in the market value of Big Bear securities at
year-end 1999 and 1998 required the Company to record $0.45 and $9.7 million in
impairment provisions, respectively.

In January 2000, shareholders of Big Bear approved its acquisition by AVID Oil &
Gas, Ltd. ("AVID"), a Canadian based energy company providing for Big Bear
shareholders to receive 1 share of AVID common stock for every 15 common shares
of Big Bear. As a result of the transaction described above, the

F-19
<PAGE> 65
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Company currently owns 129,870 shares of Avid with an approximate market value
of $190,000 (US) as of December 31, 1999.

LONG-TERM DEBT

The fair value of the Company's revolving credit facility debt of $42.0 million
is assumed to be the same as the carrying value because the interest rate is
variable and is reflective of market rates. The fair value of the 10 1/2% Notes
is based upon the quoted market prices for that issue. The fair value of the
8 7/8% Notes is based upon estimates provided to the Company by independent
banking firms.

INTEREST RATE SWAPS AND OIL AND GAS COMMODITY FINANCIAL INSTRUMENTS

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

NOTE 8 -- 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. 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 production
from the wells through July 31, 1999 (the "Price Participation Right"). In
November 1999, pursuant to the 80% Price Participation Right provision the
Company paid out $2.3 million to former third party investors in the Moxa
Program. 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, 80.5% of the Moxa Arch 1992 Offset Drilling Program,
and 74% of the Moxa Arch 1993 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 through December 31, 1999. 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 14,
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves (SEC basis

F-20
<PAGE> 66
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 1999.

LEASE COMMITMENTS

At December 31, 1999, the Company had operating leases covering office space.
Minimum rental commitments under operating leases are $44,000 for the year 2000.
For the years ended December 31, 1999, 1998 and 1997, total rental expense was
approximately $316,000, $512,000 and $438,000, 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 material 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.

NOTE 9 -- CASH FLOW INFORMATION

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

<TABLE>
<CAPTION>
FOR YEAR ENDED DECEMBER 31,
-----------------------------
1999 1998 1997
-------- -------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash paid (received) during the year for:
Interest, including amounts capitalized................ $26,823 $26,139 $ 307
Income and other taxes, net of (refunds)............... 487 (788) 1,345
</TABLE>

In November 1997, the company acquired Coda for cash, warrants and the
assumption of certain liabilities. See Note 3.

NOTE 10 -- 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 1999 include $26.6 million, $16.1 million, $14.1 million
and $11.9 million in revenues received from four customers. Also, 1999 revenues
included net losses in the amount of $33.8 million related to Commodity Price
Risk Management Activities. Oil and gas sales for 1998 include $28.9 million

F-21
<PAGE> 67
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

and $16.9 million in revenues received from two customers. Also, 1998 revenues
include Commodity Price Risk Management net gains totaling $24.8 million. Oil
and gas sales for 1997 include $40.6 million, $27.9 million and $25.5 million in
revenues received from three customers and Commodity Price Risk Management net
losses of $6.5 million. No other customers individually accounted for 10 percent
or more of revenues.

NOTE 11 -- EMPLOYEE BENEFIT PLANS

RETIREMENT PLAN

The Company provides a 401(k) and savings plan for all its full-time employees.
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 (75% for employees with more than
three years of service) 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 1999, 1998 and 1997, the Company incurred contribution expenses of
$378,000, $398,000 and $99,000, respectively, in connection with this plan.

NOTE 12 -- CAPITAL STOCK

On March 10, 1998 the Company completed the sale of 4.37 million shares of its
6 1/2% Convertible Preferred Stock (the "Preferred Stock"). The Preferred Stock
has a liquidation preference of $25 per share and is convertible at the option
of the holder into shares of the Company's 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. The
Company received net proceeds from the sale of the Preferred Stock of $105.1
million, which was used to pay down bank indebtedness.

In December 1998, the Company's Board of Directors (the "Board") authorized the
purchase from time to time, in the open market or in privately negotiated
transactions, shares of its Common Stock and 6 1/2% Convertible Preferred Stock
in an aggregate amount not to exceed $10 million. This authorization was
exhausted in December 1999. Subsequently, the Board authorized an additional $10
million for the purchase of additional Common and Preferred Shares.

NET INCOME (LOSS) PER COMMON SHARE

Potential common stock not included in the calculation of diluted earnings per
share because to do so would have been antidilutive amounted to 7,673,000,
7,690,000 and 7,562,000 for 1999, 1998 and 1997, respectively.

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

F-22
<PAGE> 68
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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,
1999 and 1998 and the changes during the years then ended is presented below:

<TABLE>
<CAPTION>
1999 1998
------------------------ ------------------------
SHS. UNDER WTD. AVG. SHS. UNDER WTD. AVG.
OPTION EXER. PRICE OPTION EXER. PRICE
---------- ----------- ---------- -----------
<S> <C> <C> <C> <C>
Outstanding, beginning of year......... 1,154,000 $16.25 960,500 $20.31
Granted.............................. 414,500 5.19 433,000 9.82
Exercised............................ -- -- -- --
Forfeited............................ (62,000) 15.00 (239,500) 19.37
---------- ------ ---------- ------
Outstanding, end of year............... 1,506,500 $13.68 1,154,000 $16.25
========== ====== ========== ======
Exercisable, end of year............... 432,300 $18.62 201,500 $20.24
========== ====== ========== ======
Available for grant, end of year....... 901,600 1,254,100
========== ==========
Weighted average fair value of options
granted during the year.............. $ 2.78 $ 10.36
========== ==========
</TABLE>

The following table summarizes information about stock options outstanding at
December 31, 1999.

<TABLE>
<CAPTION>
OPTIONS OUTSTANDING
----------------------------
WEIGHTED OPTIONS EXERCISABLE
NUMBER AVERAGE ------------------------------- NUMBER
OUTSTANDING AT REMAINING WEIGHTED EXERCISABLE AT WEIGHTED
DECEMBER 31, CONTRACTUAL AVERAGE DECEMBER 31, AVERAGE
RANGE OF PRICES 1999 LIFE EXERCISE PRICE 1999 EXERCISE PRICE
--------------- -------------- ----------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C>
$4.88-$6.50........... 369,500 9.19 $ 4.99 -- --
$7.41-$11.00.......... 389,500 8.53 $ 9.80 71,200 $ 9.99
$12.47-$17.63......... 35,000 8.34 $15.42 9,000 $14.26
$18.88-$28.13......... 709,500 7.29 $19.00 350,300 $20.42
$28.81-$29.00......... 3,000 6.58 $29.00 1,800 $29.00
</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 (loss) for calendar
years 1999 and

F-23
<PAGE> 69
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

1998 would have been reduced to the pro forma amounts indicated below (in
thousands, except for per share amounts):

<TABLE>
<CAPTION>
1999 1998
-------- ---------
<S> <C> <C>
Net Income (Loss) Available to Common Stock
As Reported............................................... $(15,484) $(152,963)
Pro Forma................................................. $(15,886) $(154,625)
Basic and Diluted Net Income (Loss) Per Share
As Reported............................................... $ (0.49) $ (4.85)
Pro Forma................................................. $ (0.50) $ (4.90)
</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 in 1999 and 1998, respectively: risk-free interest rate of 5.43
and 5.60 percent, expected volatility of 48.3 and 49.0 percent, expected lives
of 6.0 years and no dividend yield.

Under the Stock Incentive Plan, participants may be granted stock without cost
(restricted stock). During 1999 and 1998, the Company granted 200,000 and 34,700
shares, respectively, of restricted stock with a weighted average fair value
based on the price of the Company's stock on the date of grant of $5.09 and
$15.69 per share, respectively. At December 31, 1999, 223,120 shares remained
unvested, net of 17,800 shares forfeited. The weighted average fair value of
shares forfeited was $18.57. 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 1999 and 1998,
$512,000 and $344,100, respectively, was charged to costs and expenses relating
to the Plan.

NOTE 13 -- SUPPLEMENTAL QUARTERLY FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE
AMOUNTS):

<TABLE>
<CAPTION>
QUARTERS
----------------------------------------
FIRST SECOND THIRD FOURTH
-------- -------- ------- --------
(UNAUDITED)
<S> <C> <C> <C> <C>
1999
Revenues.................................... $ 24,725 $ 19,572 $15,246 $ 49,986
Costs and Expenses.......................... $ 29,666 $ 29,751 $29,830 $ 30,514
Net Income (Loss)........................... $ (3,212) $ (6,617) $(9,480) $ 10,709
Basic and Diluted Net Income (Loss) Per
Common Share.............................. $ (0.16) $ (0.26) $ (0.35) $ 0.29
1998
Revenues.................................... $ 33,351 $ 37,503 $34,690 $ 45,186
Costs and Expenses.......................... $119,286 $108,879 $29,423 $118,805
Net Income (Loss)........................... $(59,393) $(43,846) $ 3,439 $(47,756)
Basic and Diluted Net Income (Loss) Per
Common Share.............................. $ (1.90) $ (1.43) $ 0.05 $ (1.57)
</TABLE>

The sum of the individual quarterly pro forma basic and diluted net income
(loss) per share amounts may not agree with year-to-date pro forma basic and
diluted net income per share as each period's computation is based on the
weighted average number of common shares outstanding during that period. In
addition,

F-24
<PAGE> 70
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

certain potentially dilutive securities were not included in certain of the
quarterly computations of diluted net income per common share because to do so
would have been antidilutive.

NOTE 14 -- 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, 1999 and
1998 (in thousands):

<TABLE>
<CAPTION>
1999 1998
---------- ----------
<S> <C> <C>
Proved properties........................................... $1,008,261 $ 931,218
Unproved properties......................................... 71,075 74,935
---------- ----------
Total capitalized costs..................................... 1,079,336 1,006,153
Less -- Accumulated depreciation, depletion and
amortization.............................................. (619,446) (566,613)
---------- ----------
Net capitalized costs....................................... $ 459,890 $ 439,540
========== ==========
</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, 1999, by the year in which such costs were
incurred (in thousands):

<TABLE>
<CAPTION>
1999 1998 1997 1996 1995 TOTAL
------ ------- ------- ---- ---- -------
<S> <C> <C> <C> <C> <C> <C>
Leasehold and seismic............. $8,046 $ 6,128 $56,184 $177 $542 $71,077
</TABLE>

COSTS INCURRED

The following table sets forth the costs incurred in oil and gas acquisition,
exploration and development activities as of December 31, 1999, 1998 and 1997
(in thousands):

<TABLE>
<CAPTION>
1999 1998 1997
------- -------- --------
<S> <C> <C> <C>
Property Acquisitions Costs --
Proved(1)........................................... $17,608 $ 56,695 $443,930
Unproved............................................ 10,390 14,414 24,226
Exploration costs..................................... 10,943 18,597 46,939
Development costs..................................... 29,576 37,969 59,571
Capitalized interest.................................. 4,881 5,123 3,742
Property sales........................................ (215) (6,292) (13,949)
------- -------- --------
Total costs incurred........................ $73,183 $126,506 $564,459
======= ======== ========
</TABLE>

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

(1) Acquisition of proved properties in 1997 includes $437.4 million relative to
the acquisition of Coda of which $50 million was allocated to unproved
property costs.

F-25
<PAGE> 71
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 1999, 1998 and 1997 (in thousands):

<TABLE>
<CAPTION>
1999 1998 1997
-------- --------- --------
<S> <C> <C> <C>
Oil and gas revenues (including commodity price risk
management activities)............................ $105,396 $ 149,000 $123,515
Costs and expenses --
Lease operating expenses.......................... 33,683 36,969 9,365
Production taxes.................................. 5,485 3,878 3,393
Impairment of oil and gas properties.............. -- 229,000 150,000
Depreciation, depletion and amortization.......... 52,833 54,863 46,684
-------- --------- --------
Results of operations from producing activities
before income taxes............................... 13,395 (175,710) (85,927)
Provision (benefit) for income taxes................ 4,688 (61,498) (30,537)
-------- --------- --------
Results of operations from producing activities..... $ 8,707 $(114,212) $(55,390)
======== ========= ========
Amortization rate per Mcf equivalent, recurring..... $ 0.88 $ 0.88 $ 0.81
======== ========= ========
</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 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) are based on estimates
prepared by Miller & Lents, Ltd., independent petroleum engineers. For December
31, 1999, 1998 and 1997, approximately 83%, 83% and 94%, respectively, of the
quantities of proved reserves on an Mcfe basis aggregating 84%, 92% and 96%,
respectively, of the present value were estimated by Miller and Lents, Ltd. Such
estimates have been prepared in accordance with guidelines established by the
Securities and Exchange Commission (SEC).

There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the Company. The
reserve data set forth herein represent only estimates. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact 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.

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
F-26
<PAGE> 72
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------
1999 1998 1997
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows(1)........................... 1,945,175 $1,215,691 $1,569,976
Future production costs.......................... (588,932) (405,171) (531,583)
Future development costs......................... (110,091) (99,342) (100,427)
---------- ---------- ----------
Future net inflows before income taxes(1)........ 1,246,152 711,178 937,966
Discount at 10% annual rate...................... (619,610) (350,562) (427,562)
---------- ---------- ----------
Discounted future net cash flows before income
taxes.......................................... 626,542 360,616 510,404
Pro forma discounted future income taxes(2)...... (161,213) (7,457) (84,196)
---------- ---------- ----------
Standardized measure of discounted future net
cash flows..................................... $ 465,329 $ 353,159 $ 426,208
========== ========== ==========
</TABLE>

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

(1) Oil and gas commodity hedges included in future cash inflows totaled $(8.6)
million, $4.6 million and $5.9 million at December 31, 1999, 1998, and 1997,
respectively, and such hedges included in discounted future net cash flows
before income taxes totaled $(8.2) million, $4.3 million and $5.5 million at
December 31, 1999, 1998 and 1997, respectively.

(2) The estimated undiscounted future income taxes related to future net inflows
were $354.5, $32.6 and $146.4 million for the years 1999, 1998 and 1997,
respectively.

F-27
<PAGE> 73
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
BALANCE, BEGINNING OF YEAR.................................. $353,159 $426,208 $280,573
Sales and transfers of oil and gas produced, net of
production costs.......................................... (100,075) (83,353) (111,819)
Net change in sales price and production costs.............. 239,549 (142,014) (216,169)
Extensions and discoveries.................................. 65,424 29,730 65,741
Purchases of minerals in place.............................. 21,346 66,409 312,148
Sale of reserves in place................................... (112) (1,401) --
Changes in estimated future development costs............... 33,925 21,382 32,222
Revisions in quantities..................................... (8,841) (39,163) (9,099)
Accretion of discount....................................... 36,062 51,040 41,553
Other, principally revisions in estimates of timing of
production................................................ (21,352) (53,923) (22,267)
Change in income taxes...................................... (153,756) 78,244 53,325
-------- -------- --------
BALANCE, END OF YEAR........................................ $465,329 $353,159 $426,208
======== ======== ========
</TABLE>

RESERVE QUANTITY INFORMATION
PROVED RESERVES

<TABLE>
<CAPTION>
OIL GAS
------- -------
(MBbls) (MMcf)
<S> <C> <C>
Balance at December 31, 1996................................ 3,327 284,992
------ -------
Purchases of minerals in place............................ 45,646 44,855
Extensions, discoveries and other additions............... 2,004 39,248
Revisions of previous estimates........................... 1,478 (22,200)
Production................................................ (1,295) (49,710)
------ -------
Balance at December 31, 1997................................ 51,160 297,185
------ -------
Purchases of minerals in place............................ 9,800 25,903
Extensions, discoveries and other additions............... 249 34,279
Revisions of previous estimates........................... (3,775) (33,977)
Sales of minerals in place................................ (203) (649)
Production................................................ (4,177) (37,208)
------ -------
Balance at December 31, 1998................................ 53,054 285,533
------ -------
Purchases of minerals in place............................ 1,066 20,982
Extensions, discoveries and other additions............... 3,342 57,881
Revisions of previous estimates........................... (947) (2,322)
Sales of minerals in place................................ -- (189)
Production................................................ (3,439) (39,737)
------ -------
Balance at December 31, 1999................................ 53,076 322,148
====== =======
PROVED DEVELOPED RESERVES
December 31, 1996........................................... 2,070 184,904
December 31, 1997........................................... 41,255 226,071
December 31, 1998........................................... 41,475 213,449
December 31, 1999........................................... 42,352 224,143
</TABLE>

F-28
<PAGE> 74
BELCO OIL & GAS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 15 -- SUBSEQUENT EVENTS (UNAUDITED)

In February 2000, the Company closed a $40.5 million acquisition of oil and gas
properties expected to add approximately 2,400 BOE per day to the existing
production base. The transaction was financed through additional borrowings
under the Company's Revolving Credit Facility.

Due to the sustained higher oil prices subsequent to year-end, the Company
expects to incur additional cash settlement costs and non-cash mark-to-market
losses related to its commodity price risk management activities unless prices
at March 31, 2000 decline below levels at December 31, 1999.

F-29
<PAGE> 75

BELCO OIL & GAS CORP.

CONDENSED CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>
SEPTEMBER 30,
2000
(IN THOUSANDS, -------------
EXCEPT SHARE AND
PER SHARE DATA)
(UNAUDITED)
<S> <C>
ASSETS

Current Assets:
Cash and cash equivalents................................. $ 1,276
Accounts receivable....................................... 34,720
Income taxes receivable................................... -
Assets from commodity price risk management activities.... 8,893
Commodity price risk management related funds on
deposit................................................. 1,000
Other current assets...................................... 6,247
----------
Total current assets............................... 52,136
----------
Property and Equipment:
Oil and gas properties at cost based on full cost
accounting --
Proved oil and gas properties........................... 1,136,430
Unproved oil and gas properties......................... 78,937
Less -- Accumulated depreciation, depletion and
amortization.......................................... (660,031)
----------
Net oil and gas properties................................ 555,336
----------
Building and other equipment.............................. 9,054
Less -- Accumulated depreciation........................ (3,563)
----------
Net building and other equipment.......................... 5,491
----------
Other Assets................................................ 5,651
----------
Total assets....................................... $ 618,614
==========

LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable.......................................... $ 23,235
Liabilities from commodity price risk management
activities.............................................. 72,831
Accrued interest.......................................... 7,481
Other accrued liabilities................................. 11,246
----------
Total current liabilities.......................... 114,793
----------
Long-term debt.............................................. 374,819
Deferred income taxes....................................... 17,870
Liabilities from commodity price risk management
Activities................................................ 31,064
Stockholders' Equity:
6 1/2% Convertible Preferred Stock, $.01 par value;
10,000,000 shares authorized; 3,750,700 issued and
outstanding at September 30, 2000....................... 38
Common Stock ($.01 par value, 120,000,000 shares
authorized; 31,805,240 shares issued at September 30,
2000.................................................... 318
Additional paid-in capital................................ 294,555
Retained earnings (deficit)............................... (211,116)
Treasury Stock, 313,575 shares at September 30, 2000...... (1,921)
Unearned compensation..................................... (1,053)
Notes receivable for equity interest...................... (753)
----------
Total stockholders' equity......................... 80,068
----------
Total liabilities and stockholders' equity......... $ 618,614
==========
</TABLE>

The accompanying notes are an integral part of these condensed financial
statements.
F-30
<PAGE> 76

BELCO OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
-------------------------
2000 1999
---------- ----------
(IN THOUSANDS, EXCEPT PER
SHARE DATA)
(UNAUDITED)
<S> <C> <C>
Revenues:
Oil and gas sales, net of cash hedging activities......... $148,841 $104,215
Non-hedge commodity price risk management activities cash
settlements(a)......................................... (22,738) (121)
Interest and other........................................ 714 675
-------- --------
Net Revenues...................................... 126,817 104,769
-------- --------
Costs and Expenses:
Oil and gas operating expenses............................ 25,427 22,162
Production taxes.......................................... 10,924 6,986
Depreciation, depletion and amortization.................. 41,666 40,259
General and administrative................................ 4,651 3,651
Interest expenses......................................... 18,632 16,188
Non-cash change in fair value of derivatives.............. 70,614 45,225
-------- --------
Total costs and expenses.......................... 171,914 134,471
-------- --------
Income (Loss) Before Income Taxes........................... (45,097) (29,702)
Provision (Benefit) for Income Taxes........................ (15,784) (10,396)
-------- --------
Net Income (Loss)........................................... (29,313) (19,306)
Preferred Stock Dividends................................... (4,692) (5,205)
-------- --------
Net Income (Loss) Applicable to Common Stock................ $(34,005) $(24,511)
======== ========
Net Income (Loss) Per Share of Common Stock,
Basic and Fully Diluted................................... $ (1.09) $ (0.78)
======== ========
Average Number of Common Shares Used in Computation, Basic
and Fully Diluted......................................... 31,259 31,600
======== ========
</TABLE>

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

(a) Includes cash premiums received and paid.

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

F-31
<PAGE> 77

BELCO OIL & GAS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
NOTES
PREFERRED STOCK COMMON STOCK ADDITIONAL RETAINED RECEIVABLE
--------------- --------------- PAID-IN UNEARNED EARNINGS FOR EQUITY
SHARES AMOUNT SHARES AMOUNT CAPITAL COMPENSATION (DEFICIT) INTEREST
------ ------ ------ ------ ---------- ------------ --------- ----------
(IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1999........ 3,985 $40 31,797 $318 $297,225 $(1,430) $(177,111) $(753)
----- --- ------ ---- -------- ------- --------- -----
Exchanges of Preferred Stock to
Common Stock.................... (215) (2) - - (2,394) - - -
Exercise of stock options......... - - 1 - 9 - - -
Repurchase of Preferred Stock..... (21) - - - (303) - - -
Restricted Stock Issued........... - - 10 - 49 (49) - -
Restricted Stock Forfeited........ - - (3) - (31) 31 - -
Restricted Stock Amortized........ - - - - - 395 - -
Net Income (Loss)................. - - - - - - (29,313) -
Preferred Dividend Paid........... - - - - - - (4,692) -
Treasury Stock Acquisitions....... - - - - - - - -
Payment Received.................. - - - - - - - -
----- --- ------ ---- -------- ------- --------- -----
BALANCE, SEPTEMBER 30, 2000....... 3,751 $38 31,805 $318 $294,555 $(1,053) $(211,116) $(753)
===== === ====== ==== ======== ======= ========= =====
Comprehensive Income..............

<CAPTION>
TREASURY
COMMON STOCK
---------------- COMPREHENSIVE
SHARES AMOUNT TOTAL INCOME
------ ------- -------- -------------
(IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1999.. (705) $(4,317) $113,972 $ -
---- ------- -------- --------
Exchanges of Preferred Stock
Common Stock.............. 391 2,396 - -
Exercise of stock options... - - 9
Repurchase of Preferred Stoc - - (303) -
Restricted Stock Issued..... - - -
Restricted Stock Forfeited.. - - - -
Restricted Stock Amortized.. - - 395 -
Net Income (Loss)........... - - (29,313) (29,313)
Preferred Dividend Paid..... - - (4,692) -
Treasury Stock Acquisitions. - - - -
Payment Received............ - - - -
---- ------- -------- --------
BALANCE, SEPTEMBER 30, 2000. (314) $(1,921) $ 80,068
==== ======= ========
Comprehensive Income........ $(29,313)
========
</TABLE>

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

F-32
<PAGE> 78

BELCO OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------
2000 1999
--------- --------
(IN THOUSANDS)
(UNAUDITED)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss.................................................. $ (29,313) $(19,306)
Adjustments to reconcile net income (loss) to net
operating cash inflows --
Depreciation, depletion and amortization............... 41,666 40,259
Deferred tax benefit................................... (15,784) (10,396)
Commodity price risk management activities............. 21,619 10,904
Other.................................................. 275 150
Changes in operating assets and liabilities --
Commodity price risk management...................... 48,995 14,427
Accounts receivable, oil and gas..................... (3,279) 6,300
Commodity price risk management funds on deposit..... (1,000) 19,895
Other current assets................................. (2,558) (5,242)
Accounts payable and accrued liabilities............. 11,384 (2,727)
--------- --------
Net operating cash inflows........................ 72,005 54,264
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures.................. (76,729) (34,688)
Purchases of oil and gas properties....................... (69,959) (17,141)
Proceeds from sale of oil and gas properties.............. 10,658 2
Other property additions.................................. (417) (308)
Sale of gas plant......................................... 317 -
Changes in other assets................................... 143 (149)
--------- --------
Net investing cash outflows....................... (135,987) (52,284)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repurchase of bonds....................................... (2,850) -
Repurchases of common stock............................... - (649)
Repurchases of preferred stock............................ (303) (1,090)
Long-term borrowings...................................... 255,700 25,500
Long-term debt repayments................................. (184,100) (18,000)
Preferred dividend paid................................... (4,692) (5,205)
Credit agreement fees..................................... (611) -
Other..................................................... 9 -
--------- --------
Net financing cash inflows........................ 63,153 556
Increase (decrease) in cash and cash equivalents............ (829) 2,536
Cash and Cash Equivalents At Beginning of Period............ 2,105 2,435
--------- --------
Cash and Cash Equivalents At End of Period.................. $ 1,276 $ 4,971
========= ========
</TABLE>

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

F-33
<PAGE> 79

BELCO OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- ACCOUNTING POLICIES

We have prepared the financial statements included herein, without audit,
pursuant to the rules and regulations of the SEC. These financial statements
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 we believe that the disclosures are adequate to make the
information presented not misleading. These financial statements should be read
in conjunction with our Form 10-K for the calendar year 1999, which includes
financial statements and notes thereto.

NOTE 2 -- USE OF ESTIMATES

NOTE 3 -- COMMODITY PRICE RISK MANAGEMENT ACTIVITIES (OR CPRM)

We periodically enter into CPRM transactions such as swaps and options in order
to manage our exposure to oil and gas price volatility. Gains and losses related
to hedges of our oil and gas production that qualify for hedge accounting
treatment are deferred and recognized as revenues as the associated production
occurs.

We use the mark-to-market method of accounting for instruments that do not
qualify for hedge accounting treatment. Under mark-to-market accounting, those
contracts that do not qualify for hedge accounting treatment 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.

The tables and related notes set forth in this footnote and summarized below
provide details about the volumes and prices of all open Belco CPRM commitments,
hedge and non-hedge, as of September 30, 2000. Since most of the contracts
covering a substantial portion of the committed volumes were entered into in
1997 and early 1998 when commodity prices were substantially below current
commodity price levels, it is not possible to estimate future average prices to
be realized given the broad ranges covering both volumes and prices committed at
different points in time. A summary of committed volumes and

F-34
<PAGE> 80

prices by year, assuming the NYMEX forward curve reference prices for oil and
gas as of September 30, 2000 is as follows:

<TABLE>
<CAPTION>
AVERAGE
VOLUME REALIZED
YEAR PER DAY PRICE
---- ------- --------
<S> <C> <C> <C>
Oil -- Barrels per day...................................... 2000 9,848 $19.00
2001 6,082 $19.60
2002 4,930 $21.00
2003 1,479 $19.10
</TABLE>

<TABLE>
<CAPTION>
AVERAGE
VOLUME REALIZED
YEAR PER DAY PRICE
---- ------- --------
<S> <C> <C> <C>
Gas -- MMBtu per day........................................ 2000 70,815 $2.40
2001 85,000 $2.45
2002 35,000 $2.75
2003 10,000 $3.35
</TABLE>

Through June 30, 2000, we reported unrealized CPRM non-cash gains or losses as a
component of revenue which, in management's opinion, can materially distort the
amount of actual revenues received due to the volatile nature of commodity
prices. For the quarter ending September 30, 2000 and year to date, we reported
unrealized CPRM non-cash gains or losses as a component of costs and expenses.

For the three months ended September 30, 2000, we recorded, as required by
existing accounting rules, non-hedge CPRM losses of $30.7 million, consisting of
$9.7 million in cash settlements and $21.0 million in unrealized non-cash
mark-to-market losses. This compares to a $23.3 million net loss consisting of
$1.0 million in cash settlements paid and $22.2 million in unrealized non-cash
mark-to-market losses reported for the 1999 comparable period. For the first
nine months of 2000, we recorded non-hedge CPRM losses of $93.4 million,
consisting of $22.7 million in cash settlements and $70.6 million in unrealized
non-cash mark-to-market losses due to substantial increases in commodity prices
through September 30, 2000. For the first nine months of 1999, we recorded
non-hedge CPRM losses of $45.3 million consisting of $0.1 million in cash
settlements paid and $45.2 million in unrealized non-cash mark-to-market losses.
Letters of credit and cash deposits in the amount of $27.5 million in favor of
counterparties were outstanding at September 30, 2000 and related to unrealized
non-cash mark-to-market and potential hedge losses at that date.

The following table and notes thereto cover our pricing and notional volumes on
open natural gas and oil commodity hedges as of September 30, 2000:

<TABLE>
<CAPTION>
PRODUCTION PERIODS
----------------------------------
2000 2001 2002 2003
------ ------- ------ ------
<S> <C> <C> <C> <C>
GAS(1):
Price swaps sold -- receive fixed price
(thousand MMBtu)(2)............................. 1,535 905 - 913
Average price, per MMBtu........................ $ 2.34 $ 2.30 - $ 3.35
Price swaps bought -- pay fixed price
(thousand MMBtu)(3)............................. (388) (1,825) - -
Average price, per MMBtu........................ $ 3.75 $ 3.80 - -
Sub-total -- net swap volume
(thousand MMBtu)........................... 1,147 (920) - -
------ ------- ------ ------
</TABLE>

F-35
<PAGE> 81

<TABLE>
<CAPTION>
PRODUCTION PERIODS
----------------------------------
2000 2001 2002 2003
------ ------- ------ ------
<S> <C> <C> <C> <C>
Collars (thousand MMBtu)(4)........................ 3,528 9,125 5,475 2,738
Average floor price, per MMBtu.................. $ 1.39 $ 1.91 $ 2.50 $ 2.85
Average ceiling price, per MMBtu................ $ 2.68 $ 2.85 $ 3.49 $ 4.58
------ ------- ------ ------
Purchased options (thousand MMBtu)................. (1,150) - - -
------ ------- ------ ------
Average ceiling (call) price.................... $ 3.29 - - -
Total net hedge related gas volumes
(thousand MMBtu)................................ 3,525 8,205 5,475 3,651
====== ======= ====== ======
OIL:
Price swaps sold - receive fixed price
(MBbls)(2)(3)................................... 420 1,170 660 240
Average price, per Bbl.......................... $18.57 $ 19.54 $19.51 $19.60
Price swaps bought -- pay fixed price
(MBbls)(2)(3)................................... (336) (75) - -
Average price, per Bbl.......................... $25.25 $ 28.87 - -
Sub-total -- net swap volumes................. 84 1,095 660 240
------ ------- ------ ------
Purchased collars -- (Mbbls)(4).................... (45) - - -
Average floor price, per Bbl.................... $18.45 - - -
Average ceiling price, per Bbl.................. $21.80 - - -
------ ------- ------ ------
Collars sold (MBbls)(4)............................ 360 300 120 -
------ ------- ------ ------
Average floor price, per Bbl.................... $17.88 $ 18.30 $19.00 -
Average ceiling price, per Bbl.................. $21.23 $ 22.12 $22.63 --
Total net hedge related oil volumes (MBbls)........ 399 1,395 780 240
====== ======= ====== ======
</TABLE>

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

(1) Belco sells the majority of 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 Belco 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 Belco 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). Natural gas volumes covered by basis transactions include 1,380
MMBtu at $0.50 and 3,650 MMBtu at $0.27 for the balance of 2000 and year
2001, respectively.

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

(3) In order to close certain commodity price hedge positions, Belco entered
into various swap positions where Belco is the fixed-price payer on the
swap. In these transactions, the counterparty is required to make a payment
to Belco in the event that the NYMEX Reference Price for any settlement
period is greater than the swap price, and Belco 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) For any particular collar transaction, the counterparty is required to make
a payment to Belco if the average NYMEX Reference Price for the reference
period is below the floor price for such transaction, and Belco is required
to make payment to the counterparty if the average NYMEX Reference Price is
above the ceiling price for such transaction.

NON-HEDGING TRANSACTIONS

We use the mark-to-market method of accounting for instruments that do not
qualify for hedge accounting treatment. The first nine months of 2000 results of
operations included an aggregate non-cash pre-tax loss of $70.6 million related
to these activities resulting from net change in the value of Belco's market-to-

F-36
<PAGE> 82

market portfolio of CPRM activities. At September 30, 2000, Belco's consolidated
balance sheet reflects $10.2 million and $103.9 million of CPRM assets and
liabilities, respectively.

The following table and notes thereto cover Belco's pricing and notional volumes
on open natural gas and oil financial instruments at September 30, 2000, that do
not qualify for hedge accounting:

<TABLE>
<CAPTION>
PRODUCTION PERIODS
-----------------------------------
2000 2001 2002 2003
------- ------- ------ ------
<S> <C> <C> <C> <C>
GAS:
Calls bought (thousand MMBtu)(1)................. (1,380) - - -
Average price, per MMBtu....................... $ 2.97 - - -
Calls sold (thousand MMBtu)(1)................... 2,760 3,650 3,650 -
Average price, per MMBtu....................... $ 2.82 $ 3.23 $ 2.91 -
Sub-total net call volume (thousand
MMBtu)............................... 1,380 3,650 3,650 -
------- ------- ------ ------
Price Swaps Sold -- receive fixed price (thousand
MMBtu)(2)...................................... 1,840 3,650 - -
Average price, per MMBtu....................... $ 2.30 $ 2.51 -
Price Swaps Bought -- pay fixed price (thousand
MMBtu)(2)...................................... - (1,365) - -
Average price, per MMBtu....................... - $ 3.29 - -
Sub-total net swap volume.............. 1,840 2,285 - -
------- ------- ------ ------
Puts Sold (thousand MMBtu)(1).................... (230) (1,365) - -
------- ------- ------ ------
Average price, per MMBtu....................... $ 3.79 $ 3.21 - -
Extension Swaps Sold -- receive fixed price
(thousand MMBtu)............................... - 18,250 3,650 -
------- ------- ------ ------
Average price, per MMBtu....................... - $ 2.56 $ 2.65 -
Total non-hedge gas volumes (thousand
MMBtu)............................... 2,990 22,820 7,300 -
======= ======= ====== ======
OIL:
Price Swaps Bought -- pay fixed price (MBbl)..... (90) - - -
Average price, per Bbl......................... $ 22.10 - - -
Price Swaps Sold -- receive fixed price
(MBbls)(2)..................................... 105 120 - -
Average price, per Bbl......................... $ 18.87 $ 17.25 - -
Sub-total net swap volume.............. 15 120 - -
------- ------- ------ ------
Calls Bought (MBbls)(1).......................... - - - -
Average price, per Bbl......................... - - - -
Calls Sold (MBbls)(1)............................ 630 840 720 -
Average price, per Bbl......................... $ 20.12 $ 20.21 $22.00 -
Sub-total net call volume.............. 630 840 720 -
------- ------- ------ ------
Puts Sold (MBbls)(1)............................. (228) (255) - -
Average price, per Bbl......................... $ 21.22 $ 19.78 - -
Puts Bought (MBbls)(1)........................... 90 - -
Average price, per Bbl......................... $ 17.17 - - -
Sub-total net puts volume.............. (138) (255) - -
------- ------- ------ ------
Extension Swaps Sold, receive fixed price
(MBbls)........................................ - - 300 300
------- ------- ------ ------
Average price, per Bbl......................... - - $18.86 $18.86
Extension Collars Sold........................... - 120 - -
------- ------- ------ ------
Average ceiling price.......................... - $ 20.35 - -
Average floor price............................ - $ 17.50 - -
Total non-hedge oil volumes (MBbls).... 507 825 1,020 300
======= ======= ====== ======
</TABLE>

F-37
<PAGE> 83

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

(1) Calls sold or puts sold under written option contracts, in return for a
premium received by Belco upon initiation of the contract. Belco 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. Conversely, calls or puts bought in
return for Belco's payment of a premium require the counterparty to make a
payment to Belco in the event that the NYMEX Reference Price on any
settlement period is greater than the call price or less than the put price.

(2) For any particular swap transaction, the counterparty is required to make a
payment to Belco in the event that the NYMEX Reference Price for any
settlement period is less than the swap price for such instrument and Belco
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 instrument.

NOTE 4 -- CAPITAL STOCK

Through September 2000, we exchanged 213,900 shares of our 6 1/2% convertible
preferred stock for 391,325 shares of our common stock. The preferred shares
that were exchanged had a liquidation preference of $5.35 million.

Belco's credit facility and the indentures governing its subordinated debt
restrict the payment of dividends. As a result of recording substantial
unrealized non-cash mark-to-market losses required by existing accounting rules,
dividends on Belco's preferred stock may be limited or prohibited by the
restriction contained in Belco's 10 1/2% bond indenture. Payment of the December
2000 dividend and the March 2001 dividend on Belco's preferred stock will be
permitted. Subsequent dividends will be contingent upon the sale of equity
interests or sufficient net income to restore dividend payment capacity under
the indenture.

Net Income (Loss) Per Common Share

A reconciliation of the components of basic and diluted net income (loss) per
common share for the three and nine months ended September 30, 2000 and 1999 is
presented in the table below (in thousands, except per share amounts):

<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------- -------------------
2000 1999 2000 1999
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Basic net income (loss) per share:
Net loss.................................... $ (8,591) $ (9,480) $(29,313) $(19,306)
Less: preferred stock dividends............. (1,540) (1,727) (4,692) (5,205)
-------- -------- -------- --------
Loss attributable to common stockholders...... $(10,131) $(11,207) $(34,005) $(24,511)
======== ======== ======== ========
Weighted average shares of common stock
outstanding................................. 31,427 31,600 31,259 31,600
-------- -------- -------- --------
Basic net income (loss) per share............. $ (0.32) $ (0.35) $ (1.09) $ (0.78)
======== ======== ======== ========
Diluted net income (loss) per share:
Weighted average shares of common stock
outstanding.............................. 31,427 31,600 31,259 31,600
Effect of dilutive securities:
Preferred stock, warrants and stock
options(1)............................... - - - -
-------- -------- -------- --------
Average shares of common stock outstanding
including dilutive securities............... 31,427 31,600 31,259 31,600
======== ======== ======== ========
Diluted net loss per share.................... $ (0.32) $ (0.35) $ (1.09) $ (0.78)
======== ======== ======== ========
</TABLE>

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

(1) Amounts are not included in the computation of diluted net loss per share
because to do so would have been antidilutive.

F-38
<PAGE> 84

NOTE 5 -- LONG TERM DEBT

Long term debt consists of the following at September 30, 2000 and 1999 (in
thousands):

<TABLE>
<CAPTION>
SEPTEMBER 30,
-------------------
2000 1999
-------- --------
<S> <C> <C>
Revolving credit facility due 2004.......................... $113,600 $ 42,000
8 7/8% Senior Subordinated Notes due 2007................... 147,000 150,000
10 1/2% Senior Subordinated Notes due 2006, including
premium totaling approximately $5.7 and $6.5 million for
2000 and 1999, respectively............................... 114,219 114,744
-------- --------
Total Debt........................................ 374,819 306,744
Less: Current maturities.................................... - -
-------- --------
Long term debt.............................................. $374,819 $306,744
======== ========
</TABLE>

As of September 30, 2000, Belco's effective interest rate on the outstanding
balance of $113.6 million on its line of credit was approximately 8.25% per
annum.

Belco's outstanding letters of credit totaled $26.5 million at September 30,
2000.

Total interest cash expense paid for the nine months ended September 30, 2000
was approximately $23.3 million of which $5.2 million was capitalized.

F-39
<PAGE> 85

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> 86

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> 87

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.

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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
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
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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 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.

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<PAGE> 90

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 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.
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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;

(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.

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<PAGE> 92

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 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).

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<PAGE> 93

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 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,

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<PAGE> 94

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 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).

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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 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

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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.

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.

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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.

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,

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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 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.

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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 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

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<PAGE> 101

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.

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

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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.

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

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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 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).

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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.

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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.

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[BELCO LOGO]

BELCO OIL & GAS CORP.
4,000,000 SHARES
COMMON STOCK
---------------------------------------------
PROSPECTUS SUPPLEMENT
---------------------------------------------
, 2000
CIBC WORLD MARKETS

DAIN RAUSCHER WESSELS
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YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS
PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING BASE PROSPECTUS.
NO DEALER, SALESPERSON OR OTHER PERSON IS AUTHORIZED TO
GIVE INFORMATION THAT IS NOT CONTAINED IN THIS PROSPECTUS
SUPPLEMENT AND THE ACCOMPANYING BASE PROSPECTUS. THIS
PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING BASE PROSPECTUS
ARE NOT AN OFFER TO SELL NOR ARE THEY SEEKING AN OFFER TO
BUY THESE SECURITIES IN ANY JURISDICTION WHERE THE OFFER OR
SALE IS NOT PERMITTED. THE INFORMATION CONTAINED IN THIS
PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING BASE PROSPECTUS
IS CORRECT ONLY AS OF THE DATE OF THIS PROSPECTUS
SUPPLEMENT, REGARDLESS OF THE TIME OF DELIVERY OF THIS
PROSPECTUS SUPPLEMENT OR ANY SALE OF THESE SECURITIES.