BASIN EXPLORATION INC, 424B5, 1999-06-18

BASIN EXPLORATION INC
424B5, 1999-06-18
CRUDE PETROLEUM & NATURAL GAS

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<PAGE>
FILED PURSUANT TO RULE 424(b)(5)
REGISTRATION NO. 333-36143

Prospectus Supplement to Prospectus dated October 2, 1997.

[LOGO]

4,000,000 Shares

BASIN EXPLORATION, INC.
Common Stock
------------------

Basin Exploration, Inc. is offering 3,750,000 of the shares to be sold in
the offering. The selling stockholder is offering an additional 250,000 shares
to be sold in the offering. Basin will not receive any of the proceeds from the
sale of shares sold by the selling stockholder.

Basin's common stock is quoted on the Nasdaq National Market under the
trading symbol "BSNX". The last reported sale price of Basin's common stock on
June 17, 1999 was $16.69 per share.

SEE "RISK FACTORS" BEGINNING ON PAGE S-11 TO READ ABOUT FACTORS YOU SHOULD
CONSIDER BEFORE BUYING SHARES OF THE COMMON STOCK.

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

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY OTHER REGULATORY BODY
HAS APPROVED
OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ADEQUACY OR ACCURACY OF
THIS PROSPECTUS.
ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

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

<TABLE>
<CAPTION>
Per Share Total
----------- --------------
<S> <C> <C>
Initial price to public.................................................... $ 16.50 $ 66,000,000
Underwriting discount...................................................... $ 0.94 $ 3,760,000
Proceeds, before expenses, to Basin........................................ $ 15.56 $ 58,350,000
Proceeds, before expenses, to the selling stockholder...................... $ 15.56 $ 3,890,000
</TABLE>

The underwriters may, under certain circumstances, purchase up to an
additional 600,000 shares from Basin and the selling stockholder at the initial
price to public less the underwriting discount.

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

The underwriters expect to deliver the shares against payment in New York,
New York on June 23, 1999.

GOLDMAN, SACHS & CO.

BANC OF AMERICA SECURITIES LLC

DAIN RAUSCHER WESSELS
A DIVISION OF DAIN
RAUSCHER INCORPORATED
<PAGE>
PETRIE PARKMAN & CO.

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

Prospectus Supplement dated June 17, 1999.
<PAGE>
[3 MAPS]

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<PAGE>
SUMMARY

THE FOLLOWING SUMMARY HIGHLIGHTS SELECTED INFORMATION WE HAVE INCLUDED OR
INCORPORATED BY REFERENCE IN THIS PROSPECTUS SUPPLEMENT. IT DOES NOT, HOWEVER,
CONTAIN ALL INFORMATION THAT MAY BE IMPORTANT TO YOU. THIS PROSPECTUS
SUPPLEMENT, THE ACCOMPANYING PROSPECTUS, AND THE DOCUMENTS INCORPORATED BY
REFERENCE INTO THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS
INCLUDE INFORMATION ABOUT THIS OFFERING, OUR BUSINESS AND OUR FINANCIAL AND
OPERATING CONDITION. WE ENCOURAGE YOU TO READ EACH OF THOSE DOCUMENTS IN THEIR
ENTIRETY BEFORE MAKING AN INVESTMENT DECISION.

IN THIS PROSPECTUS SUPPLEMENT WE REFER TO BASIN EXPLORATION, INC. AS "WE",
"OUR", "US" OR "BASIN", UNLESS THE CONTEXT CLEARLY INDICATES OTHERWISE. IN THE
ACCOMPANYING PROSPECTUS WE REFER TO BASIN EXPLORATION, INC. AS "BASIN" AND THE
"COMPANY", UNLESS THE CONTEXT CLEARLY INDICATES OTHERWISE.

ABOUT BASIN

Basin is an independent oil and gas company engaged in the exploration,
development and acquisition of oil and gas properties located primarily in the
shallow waters of the Gulf of Mexico. We are also active in selected areas of
the onshore United States, including the Gulf Coast and the Powder River and
Green River Basins of Wyoming. In 1996, we sold a significant portion of our
developed properties in the Rocky Mountain region in order to commence an active
exploratory drilling program in the Gulf of Mexico. Since that time we have
substantially increased our proved reserves, production and cash flow from
operations. Through May 1999, we have participated in the drilling of 37 wells
in the Gulf of Mexico, 23 of which have been commercially successful, yielding a
62% success rate. As of December 31, 1998, our proved reserves totaled 180 Bcfe,
133% above our proved reserves of 77 Bcfe at December 31, 1996 and 30% greater
than our proved reserves of 138 Bcfe at December 31, 1997. Approximately 71% of
our proved reserves are gas and 75% are located in the Gulf of Mexico.

Our average daily net production for 1998 was 60 MMcfe, a 154% increase over
our 1997 average daily net production of 24 MMcfe. For the quarter ended March
31, 1999, our average daily net production was 76 MMcfe, of which 85% was gas
and 15% was oil. By early April 1999, we had brought into production a
substantial portion of our year-end 1998 proved non-producing reserves, and
during April 1999 our average daily net production exceeded 100 MMcfe. Our
revenues and cash flow from operations in 1998 increased from 1997 levels by 97%
and 120%, to $48.7 million and $33.7 million, despite significantly lower prices
for oil and gas in 1998. For 1998, our cash flow from operations per Mcfe of
production was $1.53, which we believe was among the highest within the
independent oil and gas sector.

Approximately 70% of our proved reserves in the Gulf of Mexico are
attributable to Miocene-age sands within an area known as the Miocene trend. The
Miocene trend is a prolific oil and gas producing area characterized by subtle
hydrocarbon indicators, which are more readily detectable using 3-D seismic data
that has become available since the mid-1990s. This trend is primarily located
in water depths of less than 150 feet near existing infrastructure, offering
favorable drilling and development costs. We believe that there are significant
remaining undiscovered reserves within the Miocene trend. We explore for these
reserves by applying technical expertise specific to the trend utilizing modern
3-D seismic data.

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integrated this database with geological interpretations by our technical
personnel to develop a multi-year inventory of more than 45 drilling prospects
supported by 3-D seismic data.

Basin's onshore activities include exploring and developing oil and gas
properties in southern Louisiana and Texas and in the Powder River and Green
River Basins of Wyoming. We have recently enhanced our onshore capabilities
through the addition of experienced personnel and acquisitions of geophysical
data. We plan to allocate approximately 15% of our capital expenditure budget in
1999 toward exploring and developing onshore properties. Although the shallow
waters of the Gulf of Mexico will remain our primary area of focus, we believe
that the longer reserve life and exposure to more diverse opportunities offered
by these areas will complement our offshore efforts. Our onshore properties
accounted for 11% of our production during the quarter ended March 31, 1999.

We believe the current operating environment offers us attractive investment
opportunities. Until recently, low prevailing oil and gas prices constrained
capital availability and capital expenditures for oil and gas companies. The
resulting decline in drilling activity has caused a substantial reduction in
costs for oil field services. In addition, competition for exploratory
leaseholds and property acquisitions has decreased as capital-constrained
companies have sought to strengthen their balance sheets. Furthermore, prices
for West Texas Intermediate oil and Henry Hub gas, as reflected on the New York
Mercantile Exchange, have increased from $12.05 per Bbl and $1.95 per MMBtu at
year-end 1998 to $18.03 per Bbl and $2.27 per MMBtu on May 15, 1999. We are
pursuing the offering to take advantage of these favorable investment
conditions, and we plan to use the additional borrowing capacity resulting from
the offering to significantly increase our exploration and development
activities.

Basin's principal executive offices are located at 370 Seventeenth Street,
Suite 3400, Denver, Colorado 80202. Our telephone number is (303) 685-8000.

RECENT DEVELOPMENTS

During 1999, Basin has sold assets consisting primarily of Gulf of Mexico
exploratory prospects for total proceeds of approximately $8 million. Based on
receipt of these proceeds, additional borrowing capacity following the offering,
and our current projections of cash flow from operations, we plan to increase
our capital expenditure budget for 1999 from $65 million to $95 million. We
expect this increase in our capital expenditure budget to generate approximately
a 50% increase in our drilling activity in 1999 over our original plans for the
year.

STRATEGY

Our goals are to generate per-share growth in reserves, production, earnings
and cash flow through exploration, acquisition and development of oil and gas
properties. We seek to achieve these objectives through the following
strategies:

EXPLORE IN THE SHALLOW WATERS OF THE GULF OF MEXICO. Our exploration
activities are focused primarily in the shallow waters of the Gulf of Mexico, a
prolific producing area that we believe has substantial future potential. In
particular, we have targeted the Miocene trend, which offers favorable drilling
and operating costs and readily available and affordable 3-D seismic data. It
also offers a substantial existing infrastructure of production platforms,
pipelines, and processing facilities.

CAPITALIZE ON TECHNICAL EXPERTISE. We have assembled a team of
geoscientists and petroleum engineers with substantial Gulf of Mexico experience
and expertise in generating prospects, evaluating acquisition opportunities, and
managing drilling and production operations. We have also recently added senior
management and technical personnel with substantial onshore operating

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<PAGE>
experience, and we intend to use this in-house capability to identify and pursue
growth opportunities in selected onshore areas.

APPLY ADVANCED TECHNOLOGY. We use advanced technologies, including 3-D
seismic data and computer-aided exploration to better define exploration
prospects and development opportunities. Basin has licensed more than 600 lease
blocks of 3-D seismic data and 375,000 miles of conventional 2-D seismic data
covering portions of the Gulf of Mexico.

BALANCE SIZE AND RISK PROFILE OF EXPLORATION TARGETS. We generally seek to
conduct a drilling program that is balanced between exploration prospects with
significant potential relative to our existing reserve base and smaller, lower
risk prospects. This balance is intended to mitigate risk while providing
exposure to meaningful growth in reserves and production.

GENERATE PROSPECTS INTERNALLY. Basin's team of geoscientists internally
generates prospects using its technical database and Landmark workstations. This
allows us to retain large working interests and operating control and either to
defray our capital investment by selling promoted interests or to increase our
prospect inventory by swapping for interests in third-party generated prospects.
We have internally generated more than 75% of our Gulf of Mexico prospects.

OPERATE CORE PROPERTIES. During April 1999, we operated properties
accounting for approximately 74% of our production. Operating allows us to
exercise greater control over the cost, timing and character of our exploration,
development and production activities.

PURSUE SELECTIVE ACQUISITIONS. We actively seek to acquire interests in
proved oil and gas properties with exploration or development potential to
augment operations in our core areas and to establish positions in new areas.

MAINTAIN FINANCIAL FLEXIBILITY. Basin is committed to maintaining financial
flexibility in order to pursue exploration and development activities and take
advantage of acquisition opportunities. The offering will enhance our financial
flexibility by reducing our debt. As of March 31, 1999, after giving effect to
receipt of the net proceeds of the offering, we would have had total debt of $33
million, leaving $57 million of our revolving line of credit undrawn. As of the
same date, after giving effect to the offering, our total debt per Mcfe of 1998
year-end proved reserves would have been $0.18. We believe this level of debt
per Mcfe is among the lowest within the independent oil and gas sector.

RISK FACTORS

See "Risk Factors" for a discussion of certain factors that should be
considered in connection with an investment in the common stock.

S-5
<PAGE>
THE OFFERING

<TABLE>
<S> <C> <C>
Common stock offered by Basin.......................................... 3,750,000 shares
Common stock offered by the selling stockholder........................ 250,000 shares
----------
Total shares offered................................................... 4,000,000 shares
----------
----------
Common stock outstanding after the offering............................ 17,817,000 shares(1)
</TABLE>

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

(1) Excludes 1,269,500 shares of common stock reserved for issuance upon the
exercise of outstanding stock options, 168,062 shares of common stock
issuable on exercise of outstanding warrants, and 562,500 shares issuable
pursuant to the underwriters' option to purchase additional shares. See
"Capitalization" and "Underwriting".

<TABLE>
<S> <C>
Use of Proceeds..... We intend to use the net proceeds from the offering for repayment of
debt under our revolving line of credit. Basin will use the increased
borrowing capacity under our revolving line of credit, along with cash
flow from operations, to increase exploration, development and
acquisition activities and for general corporate purposes.

Basin will not receive any proceeds from the sale of common stock by
the selling stockholder, Michael S. Smith, Basin's Chief Executive
Officer, President and largest stockholder. Mr. Smith is selling
250,000 shares of the 3,036,229 shares he beneficially owns. After the
offering, and assuming no exercise of the underwriters' option to
purchase additional shares, Mr. Smith will beneficially own 15.6% of
Basin's common stock (14.9% if the underwriters' option is exercised).
See "Selling Stockholder".

Nasdaq National
Market Symbol....... BSNX
</TABLE>

S-6
<PAGE>
SUMMARY OIL AND GAS RESERVE INFORMATION

In the table below, we provide summary information regarding our estimated
net proved oil and gas reserves as of December 31, 1998, and present values of
estimated future net cash flows related to these proved reserves, which have
been calculated using a 10% per annum discount factor. Our proved reserves and
the related future net cash flows as of December 31, 1998 have been estimated
using average prices of $1.99 per Mcf of gas and $10.31 per barrel of oil that
we were realizing at that date, without escalation in future periods. On that
date, closing prices quoted on the New York Mercantile Exchange were $1.95 per
MMBtu of Henry Hub gas and $12.05 per barrel of West Texas Intermediate oil. One
MMBtu is approximately equivalent to one Mcf of gas. Ryder Scott Company,
independent petroleum engineers, prepared reserve report estimates for certain
of our oil and gas properties as of December 31, 1998 and audited estimates
prepared by our engineers for our other properties as of that date. For a
discussion of the limitations inherent in the accuracy and reliability of
estimations of net proved oil and gas reserves and related future net cash
flows, see "Risk Factors--Reserve estimates are inherently uncertain and depend
on many assumptions that may turn out to be untrue".

<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1998
---------------------------------------
DEVELOPED UNDEVELOPED TOTAL
----------- ------------- -----------
<S> <C> <C> <C>
Oil (MBbls)............................................................. 3,352 5,315 8,667
Gas (MMcf).............................................................. 103,271 24,231 127,502
Total gas equivalents (MMcfe)........................................... 123,383 56,121 179,504

Present value of future net cash flows before income taxes
(in thousands)........................................................ $ 137,775 $ 26,710 $ 164,485
Standardized measure of discounted future net cash flows
(in thousands)........................................................ 149,955
</TABLE>

Since December 31, 1998, oil and gas prices have increased significantly and
the present value of the future net cash flows from our proved reserves has
changed. Based on the New York Mercantile Exchange prices in effect on May 15,
1999 of $18.03 per barrel of West Texas Intermediate oil and $2.27 per MMBtu of
Henry Hub gas, the present value of future net cash flows before income taxes of
Basin's net proved reserves at December 31, 1998 would have been $236 million.

The following table shows Basin's total proved reserves as of December 31,
1998 and Basin's net production for the year ended December 31, 1998 by
geographic area of operations:

<TABLE>
<CAPTION>
PROVED RESERVES
---------------------------------
OIL GAS TOTAL NET PRODUCTION
(MBBLS) (MMCF) (MMCFE) (MMCFE)
----------- --------- --------- ---------------------
<S> <C> <C> <C> <C>
Gulf of Mexico............................................ 4,281 109,626 135,312 18,284
Onshore................................................... 4,386 17,876 44,192 3,682
----- --------- --------- -------
Total..................................................... 8,667 127,502 179,504 21,966
----- --------- --------- -------
----- --------- --------- -------
</TABLE>

S-7
<PAGE>
SUMMARY OPERATING AND FINANCIAL DATA

We have provided in the tables below our selected operating and financial
data. The financial information for each of the three years in the period ended
December 31, 1998 has been derived from our audited financial statements. The
financial information for the three months ended March 31, 1998 and 1999 has
been derived from our unaudited financial statements. You should read the
following financial information in conjunction with our consolidated financial
statements and related notes that are presented elsewhere in this prospectus
supplement.

OPERATING DATA:

Proved reserves at December 31:
Oil (MBbls)............................... 7,870 8,154 8,667
Gas (MMcf)................................ 29,713 89,534 127,502
Total gas equivalents (MMcfe)............. 76,933 138,458 179,504
Reserve replacement ratio(1).............. 80%(2) 307% 251%

Average daily net production:
Oil (Bbls)................................ 1,540 1,435 1,988 2,035 1,838
Gas (Mcf)................................. 13,050 15,094 48,262 37,776 64,479
Total gas equivalents (Mcfe).............. 22,290 23,704 60,190 49,986 75,507

Average sales price per unit including
hedging effects:
Oil (per Bbl)............................. $ 20.03 $ 18.80 $ 13.42 $ 14.69 $ 13.58
Gas (per Mcf)............................. 1.44 2.64 2.21 2.22 1.86
Total gas equivalents (per Mcfe).......... 2.23 2.82 2.21 2.27 1.92
Production cost (per Mcfe)(3)............... $ 0.81 $ 0.68 $ 0.41 $ 0.53 $ 0.37

INCOME STATEMENT DATA:
Total revenue............................... $ 41,663 $ 24,720 $ 48,699 $ 10,256 $ 13,055
Net income (loss)........................... 15,570 2,456 (28,500) 239 (398)
Diluted earnings (loss) per share........... 1.45 0.22 (2.06) 0.02 (0.03)
Weighted average diluted common shares
outstanding............................... 10,730 11,345 13,859 14,237 13,973

OTHER FINANCIAL DATA:
Cash flow from operations before changes in
working capital........................... $ 5,680 $ 15,297 $ 33,658 $ 6,556 $ 8,418
Net cash provided by operating activities... 4,909 15,489 37,834 1,010 11,274
Capital additions........................... 27,741 98,245 107,716 23,281 23,977
</TABLE>

S-8
<PAGE>

<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF MARCH 31, 1999
----------------------------------- ----------------------------
1996 1997 1998 ACTUAL AS ADJUSTED(4)
--------- ----------- ----------- ----------- ---------------
<S> <C> <C> <C> <C> <C>
(IN THOUSANDS)

BALANCE SHEET DATA (AT PERIOD END):
Working capital (deficit).................... $ 19,178 $ (10,036) $ (13,224) $ (16,457) $ (16,457)
Total assets................................. 84,957 161,959 201,163 214,843 214,843
Total debt................................... 424 11,206 80,258 91,156 33,256
Total stockholders' equity................... 68,751 121,365 94,219 94,303 152,203

Common shares outstanding.................... 10,701 13,713 13,965 14,027 17,777
</TABLE>

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(1) Calculated as the sum of proved reserve extensions, discoveries, additions
and revisions divided by production. The reserve replacement ratio excludes
proved property purchases and sales.

(2) 1996 reserve replacement was affected by the divestiture of Basin's
Denver-Julesberg Basin properties, which represented 70% of Basin's proved
reserves at the time.

(3) Includes lease operating expenses and production taxes.

(4) As adjusted to reflect the 3,750,000 shares of common stock offered by Basin
and the application of the estimated $57.9 million of net proceeds to repay
indebtedness under our revolving line of credit. See "Use of Proceeds" for a
discussion of our use of proceeds from the offering.

S-9
<PAGE>
FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus supplement contains
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These
statements express, or are based on, expectations about future events,
activities, or developments that we expect, believe, project, intend, estimate,
plan or anticipate will, should, could or may occur. These include such matters
as:

- amount and nature of capital expenditures;

- drilling of wells;

- estimated reserves at December 31, 1998 and with oil and gas prices as of
May 15, 1999;

- timing and amount of future production of oil and gas;

- business strategies;

- operating costs and other expenses;

- cash flow and anticipated liquidity;

- prospect development and property acquisitions;

- marketing of oil and gas; and

- Year 2000 compliance activities.

There are many factors that could cause these forward-looking statements to
be incorrect, including, but not limited to, the risks described under "Risk
Factors" and "Management's Discussion and Analysis of Financial Condition and
Results of Operations". These factors include, among others:

- general economic conditions;

- oil and gas price volatility;

- our ability to find, acquire, market, develop and produce new properties;

- the risks associated with acquisitions and exploration;

- operating hazards attendant to the oil and gas business;

- downhole drilling and completion risks that are generally not recoverable
from third parties or insurance;

- uncertainties in the estimation of proved reserves and in the projection
of future rates of production and timing of development expenditures;

- potential mechanical failure or underperformance of significant wells;

- the strength and financial resources of Basin's competitors;

- Basin's ability to find and retain skilled personnel;

- climatic conditions;

- availability of capital;

- availability and cost of material and equipment;

- delays in anticipated start-up dates;

- environmental risks;

- actions or inactions of third-party operators of Basin's properties;

- regulatory developments; and

- third-party Year 2000 compliance actions.

When you consider these forward-looking statements, you should keep in mind
these risk factors and the other cautionary statements in this prospectus
supplement. Our forward-looking statements speak only as of the date made.
Neither Basin, any person acting on Basin's behalf nor the underwriters
undertakes any obligation to update any forward-looking statements in this
prospectus supplement, the accompanying prospectus or any statement incorporated
by reference.

S-10
<PAGE>
RISK FACTORS

An investment in our common stock involves significant risks. In particular,
you should carefully consider the following risk factors before you decide to
buy the common stock. You should also carefully read and consider all of the
information we have included in this prospectus supplement and the other risk
factors and information discussed in the accompanying prospectus and in our
reports on Forms 10-K and 10-Q, before you decide to buy the common stock.

OIL AND GAS PRICES FLUCTUATE FREQUENTLY, AND LOW PRICES COULD HAVE A
MATERIAL ADVERSE IMPACT ON OUR BUSINESS.

Prices for oil and gas fluctuate widely and have declined significantly
during 1998. Gas prices affect us more than oil prices, because most of our
production and reserves are gas. At December 31, 1998, 71% of our estimated
proved reserves consisted of gas on an Mcfe basis. In 1998, approximately 80% of
our total production consisted of gas.

Basin's revenues, profitability and future rate of growth substantially
depend on prevailing prices for oil, gas and gas liquids. 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 periodic re-determination based on changing expectations of future
prices. Lower prices may also reduce the estimate of the amount of oil and gas
that we can economically produce. As an example, our estimated proved reserves
at December 31, 1998 of 180 Bcfe with a present value of future net cash flows
before income taxes of $164 million, were lower than they would have been had
prices not declined from year-end 1997.

WE CANNOT PREDICT FUTURE OIL AND GAS PRICES. PRICES MAY DECLINE FURTHER FROM
THEIR 1998 LEVELS.

Among the factors that can cause this fluctuation are:

- RELATIVELY MINOR CHANGES IN, AND UNCERTAINTY SURROUNDING, THE SUPPLY OF
AND DEMAND FOR OIL AND GAS;

- THE LEVEL OF CONSUMER DEMAND;

- WEATHER;

- DOMESTIC AND FOREIGN GOVERNMENTAL REGULATIONS;

- THE PRICE AND AVAILABILITY OF ALTERNATIVE FUELS;

- POLITICAL CONDITIONS IN THE MIDDLE EAST;

- THE PRICE OF OIL AND GAS IMPORTS; AND

- ECONOMIC CONDITIONS IN THE UNITED STATES AND IN OTHER COUNTRIES.

HEDGING OUR PRODUCTION MAY RESULT IN LOSSES.

We periodically enter into commodity hedging transactions, including energy
price swap agreements and other financial arrangements in an effort to mitigate
the potential impact of declines in oil and gas prices. Such arrangements
involve risks. Hedging contracts limit the benefits we would realize if actual
prices rise above the contract prices. Because of low prevailing prices during
the first quarter of 1999, the absence of market indicators suggesting that
prices would rise in the short term, and our desire to protect our cash flow and
borrowing base under our revolving line of credit, we hedged significant
portions of our anticipated 1999 production during the first quarter of 1999.
Since that time, oil and gas prices have risen above levels we had expected. If
prices remain at

S-11
<PAGE>
current levels or increase during the balance of this year, we will have hedging
losses that could be material. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and note 1 of notes to the
December 31, 1998 consolidated financial statements for a description of our
recent hedging activity.

In addition, if our reserves are not produced at the rates we estimated, we
would be required to satisfy our obligations under hedging contracts on
potentially unfavorable terms without the ability to offset the financial impact
through sales of comparable quantities of our own production. Further, the terms
of our hedging contracts are based on many assumptions and estimates such as
costs of transportation to delivery points. Under financial instrument
contracts, we may be at risk for basis differential, which is the difference in
the quoted financial price for contract settlement and the actual price received
at the physical point of delivery. Substantial variations between our
assumptions and estimates and actual results could materially adversely affect
our results from operations. In addition, hedging contracts are subject to the
risk that the other party may prove unable or unwilling to perform its
obligations. Any significant nonperformance could have a material adverse
financial effect on us.

THE FAILURE TO REPLACE OUR RESERVES WOULD ADVERSELY AFFECT OUR LIQUIDITY AND
OPERATIONS.

Unless Basin conducts successful development, exploitation or exploration
activities or acquires properties containing proved reserves, Basin's proved
reserves will decline as those reserves are produced. The rate of decline
depends on a number of factors, including drilling density, completion
procedures, and reservoir characteristics. Further, decline rates vary from the
generally steep declines experienced with production from reservoirs in the Gulf
of Mexico, where we have most of our production, to the relatively slow declines
of long-lived fields in the Rocky Mountain region, where our other producing
properties are located. The market for acquiring proved reserves is extremely
competitive, and we may not be able to buy reserves at reasonable prices.
Basin's drilling operations may be unsuccessful or may be curtailed, delayed or
canceled for many reasons, such as:

- title problems;

- weather conditions;

- compliance with governmental requirements;

- cost overruns;

- shortages of capital;

- mechanical difficulties; and

- shortages in drilling rigs or other equipment.

We may be unable to make the necessary capital investments 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 acquisition, development and exploration activities will result
in reserves added at acceptable costs.

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<PAGE>
PROPERTIES WE BUY CONTAINING PROVED RESERVES MAY NOT PERFORM AS WE
PROJECTED, AND WE MAY NOT BE ABLE TO DISCOVER LIABILITIES CARRIED WITH THE
PROPERTIES OR OBTAIN PROTECTION FROM SELLERS AGAINST THEM.

The successful acquisition of producing properties requires assessments of
many factors, which are inherently inexact and may be inaccurate, including:

- the amount of recoverable reserves;

- future oil and gas prices;

- estimates of operating costs;

- estimates of future development costs; and

- potential environmental and other liabilities.

Our review will not reveal all existing or potential problems, nor will it
permit us to become familiar enough with the properties to assess fully their
deficiencies and capabilities. We may not inspect every well, platform or
pipeline. We cannot necessarily observe structural and environmental problems,
such as pipeline corrosion or groundwater contamination, when an inspection is
made. We may not be able to obtain contractual indemnities from the seller for
liabilities they created. We may be required to assume the risk of the physical
condition of the properties in addition to the risk that the properties may not
perform in accordance with our expectations.

SUBSTANTIAL ACQUISITIONS COULD REQUIRE SIGNIFICANT EXTERNAL CAPITAL AND
COULD CHANGE BASIN'S RISK AND PROPERTY PROFILE.

We frequently engage in bidding and negotiation for producing property
acquisitions, many of which are substantial. If successful in this process, we
may need to alter or increase our capitalization substantially to finance these
acquisitions or joint ventures through the issuance of debt or equity
securities, the sale of production payments or otherwise. These changes in
capitalization may significantly affect our risk profile. Additionally,
significant acquisitions or joint ventures can change the character of our
operations and business. The character of the new properties may be
substantially different in operating or geological characteristics or geographic
location than our existing properties.

EXPLORATION IS A HIGH-RISK ACTIVITY AND THE 3-D SEISMIC AND OTHER ADVANCED
TECHNOLOGIES WE USE ARE EXPENSIVE, REQUIRE EXPERIENCED PERSONNEL, AND CANNOT
ELIMINATE EXPLORATION RISK.

Exploration activities are substantially more risky than development or
exploitation activities. We use 3-D seismic data and other advanced technologies
to reduce our risk, but exploratory drilling remains a speculative activity.
Even when extensively used and properly interpreted, 3-D seismic data and
visualization techniques only assist geoscientists in identifying subsurface
structures and hydrocarbon indicators. They do not conclusively allow the
interpreter to know if hydrocarbons are present or if they are economically
producible. The use of 3-D seismic data and certain other technologies also
requires greater pre-drilling expenditures than traditional drilling strategies.
Basin could incur losses as a result of such expenditures. Poor results from our
exploration activities could have a material adverse effect on our future
results of operations and financial condition.

Prior to 1995, Basin had not conducted operations in the Gulf of Mexico.
This operating area is highly competitive and our success there will depend on
our ability to attract and retain experienced geoscientists and other
professional staff. We currently have ten geoscientists and petroleum engineers
plus two engineering consultants who are experienced in Gulf of Mexico
operations. Loss of these experienced personnel could have a material adverse
impact on Basin's ability to compete in this area.

S-13
<PAGE>
IF WE CANNOT CONTINUE TO ACCESS CAPITAL FROM EXTERNAL SOURCES, WE MAY BE
UNABLE TO EXPAND OUR RESERVES AND PRODUCTION.

Because our capital expenditures have generally exceeded our cash flow, we
require external sources of capital to develop and explore our properties and
acquire additional properties. Our ability to access additional capital will
depend on a number of factors, some of which are beyond our control. These
include our operational success, the status of the capital markets, and oil and
gas prices.

Historically we have addressed our long-term liquidity needs through cash
flows from operations, bank borrowings and the issuance of equity securities. We
continue to examine the following alternate sources of long-term capital:

- traditional reserve-base borrowings or the issuance of long-term debt;

- the sale of common stock, preferred stock or other equity securities;

- the issuance of nonrecourse production-based financing or net profits
interests;

- sales of non-strategic properties;

- sales of interests in prospects and technical information; and

- joint ventures.

We may be unable to execute our operating strategy if we cannot obtain
capital from these sources. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Liquidity and Capital Resources".

OUR DEBT COULD REDUCE OUR FINANCIAL FLEXIBILITY.

At March 31, 1999, our long-term debt equaled $91 million, and we had $19
million available to draw down under our revolving line of credit with our
banks. Our working capital deficit equaled $16.5 million at March 31, 1999,
leaving a net total of $2.5 million of unutilized credit capacity. Under our
revolving line of credit, our banks redetermine our borrowing base at least
semi-annually, and it is possible that any such review could result in a
reduction of our borrowing base. This could occur as a result of weak oil and
gas prices or unsuccessful exploration or development activities. The terms of
our revolving line of credit may impair our ability to obtain additional
financing in the future for working capital, capital expenditures, acquisitions
or general corporate purposes.

WE WROTE DOWN THE CARRYING VALUE OF OUR PROVED RESERVES AT YEAR-END 1998 TO
REFLECT LOW OIL AND GAS PRICES, AND WE COULD EXPERIENCE SUCH WRITE-DOWNS IN THE
FUTURE.

The risk that we will be required to write down the carrying value of our
oil and gas properties increases when oil and gas prices are low. In addition,
write-downs may occur if we have substantial downward adjustments to our
estimated proved reserves. Basin uses the full cost method of accounting to
report operations for oil and gas properties. We capitalize the costs 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 that is based on the present value of estimated future
net cash flows from proved reserves, using constant oil and gas prices and a 10%
discount factor, 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 write-down. This charge does not affect cash flow
from operating activities, but it does reduce the book value of our
stockholders' equity. We review the carrying value of our properties quarterly,
based on prices in effect as of the end of each quarter or as of the time of
reporting results. We may not reverse write-downs even if prices increase in

S-14
<PAGE>
subsequent periods. Primarily because of weak oil and gas prices, we recorded a
ceiling limitation write-down for the fourth quarter of 1998 in the amount of
$30.8 million ($38.5 million pre-tax). We could have another ceiling limitation
write-down in a future period if commodity prices weaken from 1998 year-end
levels.

OUR ABILITY TO MARKET OUR OIL AND GAS PRODUCTION DEPENDS ON THIRD PARTIES
AND ON FLUCTUATING COMMODITY PRICES AND DEMAND WHICH ARE BEYOND OUR CONTROL.

Our ability to market our production depends in substantial part on the
availability and capacity of gathering systems, pipelines, and processing
facilities owned and operated by third parties. Our failure to obtain such
services on acceptable terms could materially harm our business.

Demand for gas is highly seasonal, with demand generally higher in the
colder winter months and in the hot summer months. As a result, the price and
marketability of our spot market gas may vary significantly between seasonal
periods. If market factors dramatically changed, the financial impact on Basin
could be substantial. The availability of markets for our production is beyond
our control.

A SIGNIFICANT PART OF THE VALUE OF OUR PRODUCTION IS CONCENTRATED IN A SMALL
NUMBER OF OFFSHORE PROPERTIES.

During the three months ended March 31, 1999, over 64% of our daily
production was from five properties in the Gulf of Mexico. If mechanical
problems, storms, or other events curtailed a substantial portion of this
production, Basin's cash flow would be materially adversely affected.

RESERVE ESTIMATES ARE INHERENTLY UNCERTAIN AND DEPEND ON MANY ASSUMPTIONS
THAT MAY TURN OUT TO BE UNTRUE.

The process of estimating oil and gas reserves is complex and inherently
uncertain. It requires 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. We must project production rates
and timing of development expenditures. We need to analyze available geological,
geophysical, production and engineering data, and the extent, quality and
reliability of this data can vary. Oil and gas reserve engineering is a
subjective process of estimating accumulations of oil and gas that cannot be
measured in an exact manner. Basin's proved reserve information included in this
prospectus supplement represents only estimates based on reports prepared in
part by independent petroleum engineers and in part by internal Basin engineers.
Estimates from other engineers might differ materially from those shown. The
accuracy of any reserve estimate is a function of the quality and quantity of
available data, engineering and geological interpretation and judgment.

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 our estimates. Any significant variance
could materially affect the estimated quantities and present value of reserves
shown in this prospectus supplement. In addition, we may adjust estimates of
proved reserves to reflect production history, results of exploration and
development, prevailing oil and gas prices and other factors, many of which are
beyond our control.

At December 31, 1998, approximately 31% of our estimated proved reserves
were undeveloped. Recovery of undeveloped reserves generally requires
significant capital expenditures and successful drilling operations. The reserve
data assumes that we will make these expenditures. Although we estimate our
reserves and the costs associated with developing them in accordance with
industry standards, the estimated costs may not be accurate, development may not
occur as scheduled, and results may not be as estimated.

S-15
<PAGE>
You should not assume that the present value of future net cash flows
referred to in this prospectus supplement is the current market value of our
estimated oil and gas reserves. In accordance with SEC requirements, we
generally base the estimated discounted future net cash flows from proved
reserves on prices and costs on 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.

FLUCTUATIONS IN OUR QUARTERLY RESULTS OF OPERATIONS CAN CAUSE SUDDEN CHANGES
IN THE MARKET PRICE OF OUR COMMON STOCK.

Our quarterly results of operations may fluctuate significantly as a result
of variations in oil and gas prices, production performance and changes in
estimated proved reserves. You can expect the market price of our common stock
to decline when our quarterly results decline or when announcements of adverse
events regarding Basin or the industry are made.

THE OIL AND GAS BUSINESS INVOLVES MANY OPERATING RISKS THAT CAN CAUSE
SUBSTANTIAL LOSSES. INSURANCE MAY NOT BE ADEQUATE TO PROTECT AGAINST ALL THESE
RISKS.

The oil and gas business involves a variety of operating risks, including:

- fire;

- explosion;

- blow-out;

- uncontrollable flows of oil, gas, or well fluids;

- natural disasters;

- pipe failure;

- casing collapse;

- stuck tools;

- abnormally pressured formations; and

- environmental hazards such as oil spills, gas leaks, pipeline ruptures and
discharges of toxic gases.

If any of these events occur, Basin could incur substantial losses as a
result of:

- injury or loss of life;

- severe damage to and destruction of property, natural resources and
equipment;

- pollution and other environmental damage;

- clean-up responsibilities;

- regulatory investigation and penalties; and

- suspension of operations.

If we experience any of these problems, it could affect wellbores,
platforms, gathering systems and processing facilities, which could adversely
affect our ability to conduct operations.

S-16
<PAGE>
Offshore operations are subject to a variety of operating risks peculiar to
the marine environment, such as hurricanes or other adverse weather conditions.
These conditions can cause substantial damage to facilities and interrupt
production. As a result, we could incur substantial liabilities to third parties
or governmental entities. Payment of these liabilities could reduce or eliminate
the funds available for exploration, development or acquisitions, or result in
loss of properties.

In accordance with industry practice, Basin maintains insurance against
some, but not all, potential risks. Our coverage includes, but is not limited
to, operator's extra expense, physical damage on certain assets, comprehensive
general liability, automobile, and workers compensation insurance. We cannot
assure you that our insurance will be adequate to cover our losses or
liabilities. For example, insurance may not cover downhole operating risks, such
as the costs of retrieving stuck equipment. Also, we cannot predict whether
insurance will continue to be available at premium levels that justify its
purchase.

OIL AND GAS OPERATIONS ARE SUBJECT TO EXTENSIVE ENVIRONMENTAL AND OTHER
GOVERNMENTAL REGULATION, WHICH CAN AFFECT THE COST, MANNER, OR FEASIBILITY OF
DOING BUSINESS.

Development, production and sale of oil and gas are subject to extensive
federal, state and local environmental and other governmental regulation. We
have made and will continue to make large expenditures to comply with
environmental and other governmental regulations. These regulations could change
in ways that might substantially increase our costs. For example, the Minerals
Management Service of the United States Department of the Interior has proposed
regulations for valuation of oil and gas produced from federal leases, including
offshore leases that could require payment of royalties on the basis of indices
that may not reflect actual prices we receive for our production. Also, the
Federal Energy Regulatory Commission has promulgated major regulatory
initiatives over the past several years that have had a significant impact on
gas pricing and gas pipeline operations, services and rates. Those changes have
significantly altered the marketing of gas, and the effect of these changes on
our ability to market our gas at reasonable prices is uncertain. Offshore
operations are subject to more extensive governmental regulation than onshore
operations. Under the Outer Continental Shelf Lands Act, the Minerals Management
Service regulates development and production of oil and gas in federal waters in
the Gulf of Mexico, and it may suspend or terminate operations for violation of
its rules. These and other environmental regulations could impose liability for
pollution clean up and damages and require cessation of operations in affected
areas. Any such costs, damages, suspension or termination could materially and
adversely affect Basin's financial condition and operations. We are subject to
state and local regulations that impose permitting, reclamation, land use,
conservation, and other restrictions on our ability to drill and produce.

COMPETITION IN OUR INDUSTRY IS INTENSE AND WE ARE SMALLER AND LESS
EXPERIENCED THAN MOST OF OUR COMPETITORS IN THE GULF OF MEXICO.

We compete with major and independent oil and gas companies for property
acquisitions, especially in the Gulf of Mexico. We also compete for the
equipment and labor required to operate and develop such properties. Most of our
competitors have financial and other resources substantially greater than ours.
During 1996, we commenced operations in the Gulf of Mexico, where we had not
previously been active. Competition from major and large independent oil and gas
companies is significantly greater in this area than in the Rocky Mountain
region, where we previously conducted all of our operations.

WE CANNOT CONTROL THE PACE OR TYPE OF ACTIVITIES ON PROPERTIES THAT WE DO
NOT OPERATE.

Some of our properties in the Gulf of Mexico are operated by third parties.
Because we are not the operator, we do not have the ability to control the
nature of operations undertaken, such as the

S-17
<PAGE>
drilling of development wells, or the timing of such operations. This can affect
our cash flow and the timing of our production increases.

OUR PRINCIPAL STOCKHOLDER IS IN A POSITION TO AFFECT CORPORATE TRANSACTIONS
AND OTHER MATTERS.

Basin's principal stockholder, Michael S. Smith, together with members of
his immediate family and trustees for their benefit, beneficially own
approximately 21.4% of Basin's outstanding shares of common stock, and, assuming
no exercise of the underwriters' option to purchase additional shares, 15.6%
after giving effect to this offering. As a result, Mr. Smith is in a position to
substantially influence the outcome of stockholder votes on the election of
directors and other matters. In addition, if Mr. Smith were to sell a
significant number of his shares, the prevailing market price of Basin's common
stock could be adversely affected.

THE LOSS OF MICHAEL S. SMITH OR OTHER SENIOR PERSONNEL COULD ADVERSELY
AFFECT BASIN.

We depend to a large extent on the services of our founder and Chief
Executive Officer, Michael S. Smith, and certain other senior management
personnel. The loss of the services of Mr. Smith or other key personnel could
have a potential adverse effect on Basin's operations.

BASIN AND OUR BUSINESS PARTNERS MAY NOT BE YEAR 2000 COMPLIANT, WHICH COULD
RESULT IN DISRUPTION OF OUR OPERATIONS.

There is no assurance that our Year 2000 readiness project will succeed in
accurately and completely identifying all potential problems or all potentially
affected systems or in remedying all problems in our systems. There is no
assurance that our business partners will likewise succeed in their respective
efforts to remedy their Year 2000 problems or that this will be apparent in time
for us to formulate a contingency plan. Between now and January 2000, there will
be increased competition for people with technical and managerial skills
necessary to deal with the Year 2000 problem. Basin and our business partners
could face shortages of skilled personnel or other resources, such as particular
microprocessors or components containing Year 2000 ready microprocessors. These
shortages might delay or otherwise impair our ability to assure that our
critical systems or our partners' systems are Year 2000 compliant. If there are
Year 2000 related failures in our critical systems or our business partners'
critical systems that create substantial disruptions to our business, the
adverse impact on us could be material. Despite our belief that the cost to
become Year 2000 compliant will not be material, our cost assessments do not
take into account the costs, if any, that might be incurred as a result of Year
2000 related failures that occur despite our compliance efforts. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Year 2000 Readiness Disclosure and Statement".

ANTI-TAKEOVER PROVISIONS ADOPTED BY BASIN COULD DETER CHANGE OF CONTROL
TRANSACTIONS.

Basin's restated certificate of incorporation and bylaws and the provisions
of the Delaware General Corporation Law make it difficult to change control of
Basin and replace incumbent management. We adopted a stockholders' rights plan
in 1996. Under this plan, holders of our common stock received rights
exercisable if a person or group of affiliated persons acquires 15% of our
outstanding common stock or commences a tender or exchange offer that would
result in ownership of 15% or more of our outstanding common stock. Basin has a
classified board of directors under which directors serve staggered three-year
terms, which may hinder or prevent replacement of the entire board of directors
by stockholders at any one meeting. In addition, we have entered into agreements
with certain of our executive officers that would require us to make additional
payments if such officers' employment were terminated, or the terms of such
employment were materially altered, upon a change of control.

S-18
<PAGE>
USE OF PROCEEDS

We estimate that we will receive net proceeds (after deducting the
underwriting discounts and estimated expenses of the offering payable by Basin)
of approximately $57.9 million from this offering. If the underwriters exercise
in full their option to purchase additional shares, estimated net proceeds that
we will receive from the offering will increase to approximately $66.7 million.

We plan to use the net proceeds from the offering to repay a portion of
long-term debt outstanding under our revolving line of credit. This repayment
will create additional borrowing capacity under our revolving line of credit,
which we plan to use, along with cash flow from operations and proceeds from
asset sales, to increase our exploration, development and acquisition
activities, and for other corporate purposes. As of March 31, 1999, we had $91
million of debt outstanding under this line of credit at a weighted average
interest rate of 6.5% per annum. For additional information regarding Basin's
revolving line of credit, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Liquidity and Capital Resources--Revolving
Line of Credit".

Basin will not receive any of the proceeds from the sale of shares by the
selling stockholder. See "Selling Stockholder".

S-19
<PAGE>
CAPITALIZATION

The following table shows Basin's capitalization as of March 31, 1999. It
also shows our capitalization as adjusted to give effect to our receipt of the
estimated net proceeds of the offering of $57.9 million, at the initial price to
public of $16.50 per share.

<TABLE>
<CAPTION>
AS OF MARCH 31, 1999
-------------------------
ACTUAL AS ADJUSTED
----------- ------------
(IN THOUSANDS)
<S> <C> <C>
Long-term debt net of current portion(1)............................................... $ 91,000 $ 33,100
----------- ------------
Stockholders' equity:
Preferred stock, par value $.01 per share, 10,000,000 shares authorized; no shares
issued............................................................................. -- --
Common stock, par value $.01 per share, 50,000,000 shares authorized; 14,213,000
shares issued and 17,963,000 shares issued, as adjusted(2)......................... 142 180
Additional paid-in capital........................................................... 113,618 171,480
Accumulated deficit.................................................................. (16,886) (16,886)
Common stock held in treasury, at cost, 186,000 shares............................... (2,571) (2,571)
----------- ------------
Total stockholders' equity......................................................... 94,303 152,203
----------- ------------
Total capitalization............................................................... $ 185,303 $ 185,303
----------- ------------
----------- ------------
</TABLE>

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

(1) As of May 15, 1999, long-term debt was $102 million.

(2) Excludes 1,269,500 shares of common stock reserved for issuance upon the
exercise of outstanding stock options (at a weighted-average exercise price
of $11.88 per share) granted under Basin's Equity Incentive Plan. Also
excludes 168,062 shares of common stock subject to outstanding warrants
having an exercise price of $14.00 per share. Also excludes 562,500 shares
that may be issued under the underwriters' option to purchase additional
shares that is discussed under "Underwriting".

S-20
<PAGE>
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

Basin common stock is traded on the Nasdaq National Market under the symbol
"BSNX". The following table shows, for the periods indicated, the high and low
reported sales price per share for the common stock as reported by Nasdaq. The
bid quotations for the Nasdaq National Market reflect inter-dealer prices, do
not include retail markups, markdowns or commissions and may not necessarily
reflect actual transactions.

<TABLE>
<CAPTION>
HIGH LOW
--------- ---------
<S> <C> <C>
1997
First Quarter.............................................................................. $ 7.75 $ 5.88
Second Quarter............................................................................. 8.75 6.38
Third Quarter.............................................................................. 17.88 7.63
Fourth Quarter............................................................................. 23.25 16.38
1998
First Quarter.............................................................................. $ 21.06 $ 13.88
Second Quarter............................................................................. 23.25 14.13
Third Quarter.............................................................................. 18.50 9.00
Fourth Quarter............................................................................. 18.25 10.25
1999
First Quarter.............................................................................. $ 14.88 $ 8.44
Second Quarter (through June 17, 1999)..................................................... 18.38 13.00
</TABLE>

On June 17, 1999, the last reported sales price on the Nasdaq National
Market was $16.69 per share. As of June 17, 1999, there were 142 holders of
record of the common stock.

Basin has not in the past paid, and does not intend to pay in the
foreseeable future, cash dividends on the common stock. We currently intend to
retain earnings, if any, for the future operation and development of our
business. Our revolving line of credit contains provisions that may have the
effect of limiting or prohibiting the payment of dividends. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources".

S-21
<PAGE>
SELECTED HISTORICAL FINANCIAL INFORMATION

The following table sets forth certain consolidated financial data for Basin
as of and for each of the periods indicated. The financial information for each
of the three years in the period ended December 31, 1998 has been derived from
our audited consolidated financial statements. The financial information for the
three months ended March 31, 1998 and 1999 has been derived from our unaudited
consolidated financial statements which, in the opinion of our management, have
been prepared on the same basis as the annual consolidated financial statements
and include all adjustments (consisting of only normal recurring adjustments)
necessary for a fair presentation of the financial data for such periods. The
following financial information should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations", which
includes a discussion of factors materially affecting the comparability of the
information presented, and our consolidated financial statements presented
elsewhere in this prospectus supplement. The results for the three months ended
March 31, 1999 are not necessarily indicative of results to be expected for the
full year. Historical financial information is not necessarily predictive of
Basin's future results of operations and financial condition.

<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH
YEAR ENDED DECEMBER 31, 31,
--------------------------------------- --------------------------
1996 1997 1998 1998 1999
----------- ------------ ------------ ------------ ------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue:
Oil and gas sales....................................... $ 18,182 $ 24,401 $ 48,620 $ 10,235 $ 13,042
Gain on sale of assets.................................. 22,472 -- -- -- --
Interest and other...................................... 1,009 319 79 21 13
----------- ------------ ------------ ------------ ------------
41,663 24,720 48,699 10,256 13,055
----------- ------------ ------------ ------------ ------------
Costs and expenses:
Lease operating expenses................................ 4,776 4,600 8,276 2,143 2,455
Production taxes........................................ 1,829 1,260 770 234 76
Depreciation, depletion and amortization................ 7,606 10,622 29,775 5,986 8,546
General and administrative, net......................... 3,850 3,694 4,380 1,112 1,427
Interest and other...................................... 2,272 764 2,030 413 949
Property impairment..................................... -- -- 38,500 -- --
----------- ------------ ------------ ------------ ------------
20,333 20,940 83,731 9,888 13,453
----------- ------------ ------------ ------------ ------------
Income (loss) before income taxes, net.................. 21,330 3,780 (35,032) 368 (398)
Income tax (provision) benefit.......................... (5,760) (1,324) 6,532 (129) --
----------- ------------ ------------ ------------ ------------
Net income (loss)....................................... $ 15,570 $ 2,456 $ (28,500) $ 239 $ (398)
----------- ------------ ------------ ------------ ------------
----------- ------------ ------------ ------------ ------------
Diluted earnings (loss) per share....................... $ 1.45 $ 0.22 $ (2.06) $ 0.02 $ (0.03)
----------- ------------ ------------ ------------ ------------
----------- ------------ ------------ ------------ ------------
Weighted average diluted common shares outstanding...... 10,730 11,345 13,859 14,237 13,973

OTHER FINANCIAL DATA:
Cash flow from operations before changes in working
capital............................................... $ 5,680 $ 15,297 $ 33,658 $ 6,556 $ 8,418
Net cash provided by operating activities............... 4,909 15,489 37,834 1,010 11,274
Capital additions....................................... 27,741 98,245 107,716 23,281 23,977
</TABLE>

S-22
<PAGE>

<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF MARCH 31, 1999
--------------------------------------- -----------------------------
1996 1997 1998 ACTUAL AS ADJUSTED(1)
----------- ------------ ------------ ------------ ---------------
<S> <C> <C> <C> <C> <C> <C>
(IN THOUSANDS)

BALANCE SHEET DATA:
Working capital (deficit).............. $ 19,178 $ (10,036) $ (13,224) $ (16,457) $ (16,457)
Total assets........................... 84,957 161,959 201,163 214,843 214,843
Total debt............................. 424 11,206 80,258 91,156 33,256
Total stockholders' equity............. 68,751 121,365 94,219 94,303 152,203

Common shares outstanding.............. 10,701 13,713 13,695 14,027 17,777
</TABLE>

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

(1) As adjusted to reflect the 3,750,000 shares of common stock offered by Basin
and the application of the estimated $57.9 million of net proceeds to repay
indebtedness under our revolving line of credit. See "Use of Proceeds" for a
discussion of our use of proceeds from the offering.

S-23
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our
results of operations and our present financial condition. Basin's consolidated
financial statements and the accompanying notes contain additional detailed
information that should be referred to when reviewing this material.

Statements in this discussion may be forward-looking. Such forward-looking
statements involve risks and uncertainties, including those discussed below,
that could cause actual results to differ significantly from those expressed.
See "Summary--Forward-Looking Statements".

HISTORY AND OVERVIEW

Basin is a domestic independent oil and gas company that conducts
exploration, acquisition and production activities in the shallow waters of the
Gulf of Mexico and selected areas onshore.

We commenced operations in 1981 and completed an initial public offering of
common stock in 1992. From our inception through 1991, we primarily acquired and
developed properties in the Denver-Julesberg Basin in eastern Colorado. In 1992,
we began expanding into other areas within the Rocky Mountain region and
initiated exploration activities.

During 1995, our capital expenditures on oil and gas properties declined to
$16 million from $67 million the year before. This decline occurred primarily
because of reduced quality investment opportunities in our core operating areas
and limitations on our borrowing capacity under our revolving line of credit.
Depressed regional gas prices contributed to both of these factors.

In response to these developments and our management's assessment of
alternative investment opportunities, we implemented a significant redirection
of our business strategy and operations between late-1995 and mid-1996. The
redirection included:

- adding new financial, technical and business development members to our
senior management;

- selling our Denver-Julesberg Basin properties for $123.5 million;

- creating a Houston-based Gulf of Mexico exploration team through hiring
geoscientists and petroleum engineers with substantial experience
operating in the area;

- acquiring a substantial database of newly available regional 3-D seismic
data and Landmark workstations for our Gulf of Mexico geoscientists to use
in prospect generation; and

- reducing corporate staff and general and administrative overhead.

The sale of our Denver-Julesberg Basin assets enabled us to eliminate our
long-term debt and establish cash reserves, providing us with liquidity for
investments in new capital projects. The sale, however, resulted in a
significant initial decline in our revenue and cash flow, as the assets sold
accounted for approximately 70% of our production and estimated proved oil and
gas reserves at the time.

We began our Gulf of Mexico activities in 1996 with no initial property base
in the region and our early investments related primarily to acquisitions of 3-D
seismic data and exploratory leasehold interests. Our first significant
discovery in the Gulf of Mexico was the Eugene Island Block 65 #1 well, which we
began drilling at the end of 1996 and completed in 1997. Our first production
from Gulf of Mexico assets occurred in August 1997, when we brought two wells
drilled on Eugene Island Block 65 on-line. We added other proved properties in
the Gulf of Mexico in 1997 and 1998 through both exploratory drilling and
acquisitions. As of December 31, 1998, we owned interests in

S-24
<PAGE>
18 properties with proved reserves in the Gulf of Mexico, of which 14 were
producing and four were under development for first production. We established
first production on two of these properties early in the second quarter of 1999.
Basin's estimated proved oil and gas reserves increased from 62.6 Bcfe as of
December 31, 1995, pro forma for the sale of our Denver-Julesberg properties, to
179.5 Bcfe at the end of 1998. As further described below, our net production
has grown significantly since mid-1997, as Gulf of Mexico properties have been
brought on-line.

During 1996, 1997, 1998, and the first three months of 1999, our capital
expenditures on oil and gas activities totaled approximately $22.8 million,
$105.6 million, $106.7 million and $22.5 million, respectively. Over 90% of
these investments relate to our operations in the Gulf of Mexico, including
costs that we incurred for exploratory leaseholds, geological and geophysical
data, exploratory drilling, completion and development activities, and
acquisitions of proved properties. These activities included drilling a total of
37 wells in the Gulf of Mexico through May 15, 1999, of which 23, or 62%, have
been successful.

We closed the first quarter of 1999 with a working capital deficit of
approximately $16.5 million, long-term debt of $91.0 million, and stockholders'
equity of $94.3 million. Stockholders' equity at the end of the period reflected
the impact of a $38.5 million pre-tax non-cash impairment charge in the fourth
quarter of 1998 to reduce the carrying value of our oil and gas properties. This
charge, which was precipitated by low oil and gas prices in effect at the end of
1998, did not impact our cash flow or our borrowing capacity under our revolving
line of credit with our banks.

Basin's initial budget for 1999 provided for capital investments of
approximately $65 million, subject to an increase for proceeds from anticipated
assets sales. With the net proceeds from the offering and approximately $8
million from asset sales to date in 1999, we plan to increase our 1999 budget to
$95 million. Given the prevailing lower cost of oil field services today
compared to 1998, we believe our 1999 budget will result in significantly
greater drilling activity than our $106.7 million of capital expenditures for
1998 yielded in a higher service cost environment. We estimate that this budget
expansion will enable us to increase our exploratory drilling activities during
the year by approximately 50% compared to planned activities under our initial
1999 budget.

OPERATING ENVIRONMENT

Oil and gas price levels, which are volatile and beyond our control,
significantly impact our results of operations. Changes in oil and gas prices
can also affect the amount and terms of external capital resources available to
Basin.

Gas prices generally respond to North American supply and demand conditions,
including the effects of weather. Oil prices reflect global supply and demand
conditions to a greater degree, including the impact on supply of decisions by
petroleum exporting countries. Despite temporary periods of interrupted growth,
oil and gas demand has generally increased over time. Short-term fluctuations in
demand, however, can significantly impact prices. During most of 1998 and the
first quarter of 1999, the markets for both oil and gas generally reflected
ample supply and price weakness due to a number of factors, including a second
consecutive unusually warm winter in North America. Since mid-March 1999, oil
and gas prices have increased, apparently in response to announced production
cut-backs by petroleum exporting countries and expectations of reduced domestic
productive capacity caused by declines in drilling activity. There are
well-developed futures markets for oil and gas that provide indications of
expected future prices for each product. These prices are often substantially
different than current prices reflected on spot markets. Presently, these
futures markets reflect expectations of oil and gas prices sustained at levels
above the levels that prevailed during most of 1998 and early 1999, particularly
for gas, which accounted for 85% of Basin's total production in the first
quarter of 1999. Expectations will change in response to future developments and
indicated future prices may not actually materialize.

S-25
<PAGE>
Hedging transactions can be entered into based on prices reflected in
commodity futures markets. We periodically enter into fixed price sales
agreements or other hedging transactions. We do this to take advantage of prices
that we believe to be attractive and to reduce risks related to potential price
declines, including the risk of being unable to make capital investments at
targeted levels. We have executed various hedging transactions to mitigate our
exposure to declines in oil and gas prices. Because of low prevailing prices and
other factors, we hedged significant portions of our anticipated 1999 production
during the first quarter of 1999. Since that time, oil and gas prices have risen
above levels we expected. If prices remain at current levels or increase during
the balance of this year, we will incur material losses. See "--Liquidity and
Capital Resources". Because our hedges cover only a portion of our anticipated
future production, however, we remain vulnerable to the potential effects of a
decline in prices. Such hedges also can reduce the benefits realized by Basin
from increases in oil and gas prices. See "Risk Factors--Hedging our production
may result in losses".

For much of the past year, the decline in oil and gas prices negatively
impacted the availability of capital resources for most energy companies,
including Basin. Besides unfavorably affecting cash flow, this weakness in oil
and gas prices increased the cost of, and reduced opportunities for, the
issuance of long-term debt and equity securities. Increases in oil and gas
prices, as noted above, have resulted in some recent improvement in these
conditions.

For oil and gas producers, the impairment of capital resources during much
of the past year has been partially mitigated by certain improvements in the
operating environment. We believe that diminished capital resources for energy
companies, in the aggregate, has resulted in significant overall improvement in
the quality and terms of investment opportunities available, compared to the
period preceding the decline in oil and gas prices that occurred in 1998 and
early 1999. In addition to a more favorable market for acquirers of exploratory
prospects or producing properties, there have been substantial reductions in the
costs of oil field goods and services. As an example, the day rate for a typical
shallow-water jack-up drilling rig used by Basin in the Gulf of Mexico has
declined from up to $40,000 in the first half of 1998 to less than $15,000 in
the first quarter of 1999. Other costs have declined by smaller amounts, but
still significantly. The availability and reliability of oil field goods and
services have also improved as capacity use has become less strained. As noted,
these conditions reflect reduced demand for such goods and services in an
environment of relatively low oil and gas prices and, therefore, some reversal
would be expected with stronger oil and gas prices.

Our Gulf of Mexico exploration activities are dependent on our ability to
continue to identify and obtain prospects. We generally use non-proprietary
three-dimensional seismic data, which is also available to our competitors, as a
tool in our prospect generation. This tends to increase competition for, and
cost of, available prospects. Since the beginning of 1998, we successfully
expanded our inventory of potential exploratory drilling locations from
approximately 30 to 45, while drilling 21 test wells. This inventory of
prospects, the majority of which are 100%-owned by Basin, represents more than a
two-year set of drilling opportunities, based on our historical and anticipated
drilling activity levels. However, we face competition for additional prospects
from many better-capitalized oil and gas companies. There is no assurance that
over the longer term we will be able to continue to acquire interests in
prospects at acceptable costs to replenish our inventory of prospects as these
are drilled. Basin seeks to mitigate this risk by pursuing prospect ownership
through a number of avenues, including lease sales, farm-ins, exchanges, and
acquisitions. We also plan to selectively evaluate and pursue other investment
opportunities, including onshore exploration and acquisitions of properties with
proved oil and gas reserves, to complement our core exploration activities in
the Gulf of Mexico.

S-26
<PAGE>
RESULTS OF OPERATIONS

As discussed under "--History and Overview" above, we sold our assets in the
Denver-Julesberg Basin during the first half of 1996 and realized our first
production from Gulf of Mexico properties in August 1997. Therefore, period to
period comparison results of operations may not be meaningful or indicative of
future results. The following operating and financial data, in conjunction with
the discussion below, are provided to assist you in understanding our results of
operations for the periods presented.

<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------- --------------------
1996 1997 1998 1998 1999
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Production:
Oil (MBbl)........................................... 564 524 725 183 165
Gas (MMcf)........................................... 4,776 5,509 17,616 3,400 5,803
Total gas equivalents (MMcfe)........................ 8,160 8,653 21,966 4,498 6,793
Average sales price including hedging effects:
Oil (per Bbl)........................................ $ 20.03 $ 18.80 $ 13.42 $ 14.69 $ 13.58
Gas (per Mcf)........................................ 1.44 2.64 2.21 2.22 1.86
Total gas equivalents (per Mcfe)..................... 2.23 2.82 2.21 2.27 1.92
Sales revenue (in thousands):
Oil sales............................................ $ 11,292 $ 9,844 $ 9,735 $ 2,690 $ 2,246
Gas sales............................................ 6,890 14,557 38,885 7,545 10,796
--------- --------- --------- --------- ---------
Oil and gas sales.................................... $ 18,182 $ 24,401 $ 48,620 $ 10,235 $ 13,042
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Expenses (per Mcfe):
Lease operating expenses............................. $ 0.59 $ 0.53 $ 0.38 $ 0.48 $ 0.36
Production taxes..................................... 0.22 0.14 0.03 0.05 0.01
Depreciation, depletion and amortization............. 0.93 1.23 1.36 1.33 1.26
General and administrative, net...................... 0.47 0.43 0.20 0.25 0.21
</TABLE>

THREE MONTHS ENDED MARCH 31, 1998 AND 1999

REVENUE. Oil and gas sales revenue for the three months ended March 31,
1999 totaled $13.0 million, representing an increase of $2.8 million, or 27%,
compared to the first quarter of 1998. A 51% increase in net oil and gas
production was partially offset by a 15% decline in unit prices, based on net
equivalent unit measures. The increase in oil and gas production is attributable
to contributions in the current period from 13 Gulf of Mexico properties,
compared to seven in the prior-year period. Due to the additional Gulf of Mexico
production, which is predominantly gas, and lower oil production from onshore
properties on which investments were deferred due to low oil prices, gas
increased from 76% of net equivalent units produced in the first quarter of 1998
to 85% of total oil and gas production in the first quarter of 1999. See
"--Liquidity and Capital Resources" for additional discussion of our oil and gas
production. Hedging transactions had the effect of increasing oil and gas sales
by $0.3 million, or $0.08 per Mcfe in the three months ended March 31, 1998, and
by $1.4 million, or $0.20 per Mcfe, in the three months ended March 31, 1999.

LEASE OPERATING EXPENSES. Due to an increased number of producing
properties and higher production levels, lease operating expenses for the three
months ended March 31, 1999 increased by $0.3 million, or 15%, from the amount
reported for the comparable period in the prior year. However, lease operating
expenses per Mcfe produced declined by 25%, from $0.48 in the quarter ended
March 31, 1998 to $0.36 during the three months ended March 31, 1999, due to
increased production in the current period from Gulf of Mexico wells, which
typically have significantly lower average unit operating costs than our Rocky
Mountain properties.

S-27
<PAGE>
PRODUCTION TAXES. Production taxes for the three months ended March 31,
1999 were $0.1 million, representing a decrease of $0.2 million, or 68%,
compared to the comparable period in 1998, due to reduced revenues from onshore
properties caused by lower oil and gas prices and a decline in production from
such properties. Production taxes as a percentage of oil and gas sales for the
three months ended March 31, 1999 were 0.6%, compared to 2.3% in 1998, due to a
greater portion of sales in 1999 attributable to properties in federal waters
offshore, which are generally not subject to production taxes.

DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense for the three months ended March 31, 1999 was $8.5 million,
representing an increase of $2.6 million, or 43%, compared to 1998. The increase
was attributable to the 51% increase in production volumes in 1999 as compared
to 1998, offset by a decrease in the per-unit depletion rate. The depletion rate
of $1.23 per Mcfe produced in the three months ended March 31, 1999 represented
a 4% decrease from the $1.28 per Mcfe average depletion rate during the 1998
period. The lower rate is principally due to the effects of a property
impairment charge recorded by us in the fourth quarter of 1998.

GENERAL AND ADMINISTRATIVE, NET. General and administrative expenses for
the three months ended March 31, 1999, net of amounts capitalized and overhead
reimbursements, were $1.4 million, representing an increase of $0.3 million, or
28%, as compared to the comparable period in 1998. The increase resulted from
incremental costs incurred to manage expanded operations in the Gulf of Mexico
and greater stock-based incentive compensation accruals. Stock compensation
expense relates to annual grants to employees of restricted stock, including
shares awarded to management that will be earned only if certain performance
measures are achieved by Basin. Expense is recognized based on vesting schedules
and changes in the price of our stock during applicable vesting periods.

INTEREST EXPENSE. Interest expense for the three months ended March 31,
1999 totaled $0.9 million, representing an increase of $0.5 million, or 130%,
compared to the first quarter of 1998. The variance was attributable to an
increase in average borrowings offset by a slight decrease in average effective
interest rates. Interest expense in 1999 excludes $0.6 million of interest
capitalized to unproved property costs in accordance with Statement of Financial
Accounting Standards No. 34. During the quarter ended March 31, 1999, Basin had
average outstanding debt of $88.5 million, with an average effective interest
rate of 6.8%, compared to average debt of $22.6 million and an average interest
rate of 6.9% in the comparable 1998 period.

INCOME TAX BENEFIT (PROVISION). The income tax provision for 1998
approximates the amount that would be calculated by applying statutory income
tax rates to income before income taxes. No net income tax benefit has been
recognized in 1999 due to an equivalent increase in the deferred tax asset
valuation allowance.

S-28
<PAGE>
YEARS ENDED DECEMBER 31, 1997 AND 1998

We established our first production from Gulf of Mexico assets in the second
half of 1997. This production, together with production from subsequently added
Gulf of Mexico properties, significantly impacted our results of operations. To
assist in interpreting year-to-year comparisons, please review the following
quarterly data for the two-year period ended December 31, 1998.

<TABLE>
<CAPTION>
MARCH 31, JUNE 30, SEPT. 30, DEC. 31, MARCH 31, JUNE 30, SEPT. 30, DEC. 31,
QUARTER ENDED 1997 1997 1997 1997 1998 1998 1998 1998
- ----------------------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Production:
Oil (MBbl)........... 106 103 147 168 183 189 173 180
Gas (MMcf)........... 403 399 1,688 3,019 3,400 3,936 5,296 4,984
Total gas equivalents
(MMcfe)............ 1,039 1,017 2,570 4,027 4,498 5,070 6,334 6,064
Average sales price
including hedging
effects:
Oil (per Bbl)........ $ 20.41 $ 17.73 $ 18.59 $ 18.62 $ 14.69 $ 14.26 $ 14.74 $ 9.99
Gas (per Mcf)........ 2.69 1.73 2.45 2.86 2.22 2.34 2.18 2.12
Total gas equivalents
(per Mcfe)......... 3.12 2.47 2.67 2.92 2.27 2.35 2.23 2.04
Sales revenue (in
thousands):
Oil.................. $ 2,155 $ 1,828 $ 2,737 $ 3,124 $ 2,690 $ 2,697 $ 2,545 $ 1,803
Gas.................. 1,082 689 4,139 8,647 7,545 9,219 11,553 10,568
----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
Oil and gas.......... $ 3,237 $ 2,517 $ 6,876 $ 11,771 $ 10,235 $ 11,916 $ 14,098 $ 12,371
----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
Expenses (per Mcfe):
Lease operating
expenses........... $ 1.02 $ 0.96 $ 0.40 $ 0.38 $ 0.48 $ 0.48 $ 0.31 $ 0.28
Production taxes..... 0.35 0.27 0.10 0.09 0.05 0.04 0.03 0.02
Depreciation,
depletion and
amortization....... 1.12 1.21 1.16 1.30 1.33 1.33 1.33 1.42
General and
administrative,
net................ 0.76 0.80 0.33 0.31 0.25 0.20 0.18 0.19
</TABLE>

REVENUE. Oil and gas sales for 1998 increased by $24.2 million, or 99%,
compared to 1997, to $48.6 million. This increase resulted from a 154% increase
in combined oil and gas production volumes, partially offset by a 22% decrease
in revenue per net equivalent unit produced, from $2.82 per Mcfe in 1997 to
$2.21 per Mcfe in 1998. Hedging transactions had the effect of reducing oil and
gas sales by $0.5 million, or $0.06 per Mcfe, in 1997 and increasing sales by
$3.5 million, or $0.16 per Mcfe, in 1998.

We attribute the increase in production volumes from 8,653 MMcfe in 1997 to
21,966 MMcfe in 1998 to commencement of production at nine offshore properties
at various times during 1998, and to greater contributions from offshore
properties acquired or brought on-line during the second half of 1997, partially
offset by natural depletion. We attribute the decline in production between the
third and fourth quarters of 1998 largely to the temporary loss of production
from a major well, after cement behind production casing failed to hold,
allowing water to channel into the well. This well was placed back on-line in
the first quarter of 1999 after a re-completion operation.

LEASE OPERATING EXPENSES. Lease operating expenses, or LOE, increased in
1998 from the prior year by $3.7 million, or 80%, but LOE per Mcfe produced
declined by 28% to $0.38, compared to $0.53 in 1997. As shown in the above table
of quarterly data, Basin's LOE per Mcfe has generally improved as Gulf of Mexico
production has increased, beginning with the third quarter of

S-29
<PAGE>
1997. An offset to this pattern in the first half of 1998 primarily reflects
costs related to the absorption of properties acquired in late-1997 from
bankrupt Midcon Offshore, Inc. Typically, our Gulf of Mexico properties have
significantly lower unit operating costs than our Rocky Mountain assets. The
relatively low per-unit operating cost of Basin's Gulf of Mexico properties is
attributable to higher average production rates per well and a higher proportion
of gas production, which is generally less costly to produce than oil.

PRODUCTION TAXES. Production taxes for 1998 decreased from 1997 by $0.5
million, or 39%, as the result of reduced sales revenue from onshore properties.
This reduction reflects both lower production from onshore assets and lower
prices on such production. Production from our properties in federal waters
offshore in the Gulf of Mexico is generally not subject to production taxes,
accounting for the decline in production taxes as a percentage of oil and gas
sales, from 5.2% in 1997 to 1.6% in 1998.

DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense increased from 1997 by $19.2 million, or 180%, in 1998 to
$29.8 million. Most of this increase was attributable to a 154% increase in
production volumes. The average depletion rate (which excludes depreciation
related to non-oil and gas assets) of $1.31 per Mcfe of production in 1998
represents a 17% increase from the $1.12 per Mcfe recorded in 1997. The higher
rate is due to a reduction of estimated proved reserves attributable to lower
oil and gas prices at the end of 1998 than one year earlier, and to a cost for
proved reserves added in 1998 that was above Basin's historical average. The
increased unit cost of additions in 1998 reflects the substantial portion of our
capital expenditures in 1998 related to the Gulf of Mexico, where higher unit
costs are associated with reserves that generally have a higher value per unit
than our onshore properties, due to faster recoveries of reserves, lower
production costs, and higher average realizable gas prices.

GENERAL AND ADMINISTRATIVE EXPENSES, NET. General and administrative
expenses in 1998 increased by $0.7 million, or 19%, from 1997 levels, to $4.4
million. The increase in 1998 resulted primarily from incremental costs incurred
to manage expanded operations in the Gulf of Mexico. On a per Mcfe basis,
general and administrative expenses during the two-year period generally
declined as production volumes increased, as reflected in the table above.

INTEREST AND OTHER EXPENSE. Interest and other expense for 1998 equaled
$2.0 million, representing an increase of $1.3 million, or 166%, compared to
1997. The increase was attributable to an increase in average borrowings offset
by a slight reduction in Basin's average effective interest rate. Interest
expense in 1998 excludes $1.5 million of interest capitalized to unproved
property costs in accordance with Statement of Financial Accounting Standards
No. 34. During 1998, Basin had average outstanding debt of $53.4 million with an
average effective interest rate of 6.6%, compared to average borrowings of $10.2
million and an average effective interest rate of 6.7% in 1997. Substantially
all of the borrowings in both years were under our revolving line of credit.

PROPERTY IMPAIRMENT. During 1998, we recognized a property impairment
charge of $38.5 million as the result of the capitalized costs of our oil and
gas properties exceeding a "ceiling" on such costs computed in accordance with
prescribed guidelines for companies utilizing the full cost accounting method.
The charge, which had no impact on our cash flows or our revolving line of
credit, was associated with unusually low oil prices in effect at the end of
1998. Additional discussion of the charge, including information regarding the
methodology prescribed for computing the full cost ceiling, is presented in note
1 to the December 31, 1998 consolidated financial statements.

INCOME TAX PROVISION. The difference between the income tax benefit
recorded for 1998 and the amount that would be calculated by applying statutory
income tax rates to the loss before income taxes is due primarily to the
establishment of a $5.7 million deferred tax asset valuation

S-30
<PAGE>
allowance. The income tax provision for 1997 approximates the amount that would
be calculated by applying statutory income tax rates to income before income
taxes.

YEARS ENDED DECEMBER 31, 1996 AND 1997

The sale of Basin's Denver-Julesberg Basin assets in the first half of 1996,
and the realization of first production from Gulf of Mexico assets in the second
half of 1997, result in year-to-year comparisons that obscure important changes.
We provide the following quarterly data for the two-year period ended December
31, 1997 to assist you in understanding such changes.

<TABLE>
<CAPTION>
MARCH 31, JUNE 30, SEPT. 30, DEC. 31, MARCH 31, JUNE 30, SEPT. 30, DEC. 31,
QUARTER ENDED 1996 1996 1996 1996 1997 1997 1997 1997
- ----------------------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Production:
Oil (MBbl)........... 216 152 98 98 106 103 147 168
Gas (MMcf)........... 2,458 1,465 429 424 403 399 1,688 3,019
Total gas equivalents
(MMcfe)............ 3,754 2,377 1,017 1,012 1,039 1,017 2,570 4,027
Average sales price
including hedging
effects:
Oil (per Bbl)........ $ 17.94 $ 20.84 $ 21.10 $ 22.31 $ 20.41 $ 17.73 $ 18.59 $ 18.62
Gas (per Mcf)........ 1.47 1.32 1.22 1.95 2.69 1.73 2.45 2.86
Total gas equivalents
(per Mcfe)......... 1.99 2.14 2.54 2.98 3.12 2.47 2.67 2.92
Sales revenue (in
thousands):
Oil.................. $ 3,875 $ 3,164 $ 2,064 $ 2,189 $ 2,155 $ 1,828 $ 2,737 $ 3,124
Gas.................. 3,611 1,932 522 825 1,082 689 4,139 8,647
----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
Oil and gas.......... $ 7,486 $ 5,096 $ 2,586 $ 3,014 $ 3,237 $ 2,517 $ 6,876 $ 11,771
----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
Expenses (per Mcfe):
Lease operating
expenses........... $ 0.45 $ 0.56 $ 0.81 $ 0.94 $ 1.02 $ 0.96 $ 0.40 $ 0.38
Production taxes..... 0.19 0.20 0.28 0.34 0.35 0.27 0.10 0.09
Depreciation,
depletion and
amortization....... 0.89 0.89 1.06 1.04 1.12 1.21 1.16 1.30
General and
administrative,
net................ 0.32 0.43 0.79 0.83 0.76 0.80 0.33 0.31
</TABLE>

REVENUE. Oil and gas sales for 1997 increased by $6.2 million, or 34%, to
$24.4 million, due largely to improved average sales prices. An 83% increase in
gas prices, offset by a 6% decrease in oil prices, yielded a 26% increase in
revenue per net equivalent unit produced, from $2.23 per Mcfe in 1996 to $2.82
per Mcfe in 1997. Hedging transactions had the effect of reducing oil and gas
sales by $0.5 million in both years.

Production increased by 6% in net equivalent units, from 8,160 MMcfe in 1996
to 8,653 MMcfe in 1997. The relatively small change in production volumes from
year-to-year obscures significant changes during each year due to the
Denver-Julesberg sales in March and June 1996 and the commencement of Gulf of
Mexico production in August 1997.

In conjunction with the second Denver-Julesberg sale transaction, which
closed in June 1996, Basin recognized a non-recurring $22.5 million gain. Other
revenue reported in both 1996 and 1997 primarily represented interest income on
cash equivalents held after the second Denver-Julesberg sale transaction prior
to redeploying those proceeds into investments in oil and gas properties.

LEASE OPERATING EXPENSES. LOE declined in 1997 from the prior year by $0.2
million, or 4%, and LOE per Mcfe produced declined by 10%, to $0.53 in 1997,
compared to $0.59 in 1996. Again,

S-31
<PAGE>
the relatively small changes from year-to-year do not reflect significant
changes within each year. Average LOE per Mcfe by quarter reflects that both the
properties included in the Denver-Julesberg sales and the Gulf of Mexico
properties that began contributing in the second half of 1997 have significantly
lower unit operating costs than Basin's retained Rocky Mountain assets, which
have high unit operating costs due to relatively low average production rates
per well and a high proportion of oil production, which is generally more costly
to produce than gas.

PRODUCTION TAXES. Production taxes for 1997 decreased from 1996 by $0.6
million, or 31%, as the result of reduced sales from onshore properties in 1997
due to the inclusion in 1996 of production from Denver-Julesberg Basin
properties prior to the Denver-Julesberg sales. Production from properties in
federal waters offshore is generally not subject to production taxes and such
taxes did not increase in the second half of 1997 when Basin added offshore Gulf
of Mexico production. Production taxes therefore declined as a percentage of oil
and gas sales, averaging 5.2% for all of 1997 and 3.3% in the second half of the
year, compared to 10.1% in 1996.

DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense increased in 1997 by $3.0 million, or 40%, to $10.6
million. The average depletion rate of $1.12 per Mcfe of production in 1997
represents a 37% increase from the $0.82 per Mcfe recorded in 1996. The higher
rate is due to the addition of proved reserves in 1997 at a higher average unit
cost than Basin's historical average and to the unfavorable impact on estimated
proved reserves of using lower assumed future oil and gas prices at the end of
1997 than at the end of 1996. The increased unit cost of additions in 1997
reflects the substantial portion of our capital expenditures in 1997 related to
the Gulf of Mexico, where higher unit costs are generally associated with
reserves having a higher value per unit than Basin's onshore properties, due to
typically faster recoveries of reserves, lower production costs, and higher
average realizable gas prices.

GENERAL AND ADMINISTRATIVE EXPENSES, NET. General and administrative
expenses in 1997 decreased by $0.2 million, or 4%, from 1996 levels, to $3.7
million. The decrease in 1997 resulted primarily from staff reductions made in
mid-1996 in conjunction with the Denver-Julesberg sales and related reductions
in office rent expense attributable to Basin's relocation to smaller space.
These savings, which benefited all of 1997 but only a portion of 1996, were
partially offset by higher bonus awards and stock-based incentive compensation
costs recorded in 1997. On a per Mcfe basis, general and administrative expenses
during the two-year period generally varied inversely with production volumes.

INTEREST AND OTHER EXPENSE. Interest and other expense for 1997 was $0.8
million, representing a decrease of $1.5 million, or 66%, compared to 1996. The
decrease was attributable to a decrease in average borrowings after the
Denver-Julesberg sales and a reduction in Basin's average effective interest
rate, reflecting lower prevailing market interest rates and more favorable
borrowing terms obtained after the Denver-Julesberg sales. During 1997, we had
average outstanding debt of $10.2 million with an average effective interest
rate of 6.7%, compared to average borrowings of $28.2 million and an average
effective interest rate of 8.0% in 1996. Substantially all of the borrowings in
both years were under our revolving line of credit.

INCOME TAX PROVISION. The income tax provision for 1997 approximates the
amount that would be calculated by applying statutory income tax rates to income
before income taxes. The 1997 current provision for income taxes was decreased,
and the deferred provision was increased, by approximately $0.5 million due to a
change in estimate of current taxes payable for 1996. The difference between the
income tax provision recorded for 1996 and the amount that would be calculated
by applying statutory income tax rates to income before income taxes is due
primarily to reversal of a previously established $2.2 million deferred tax
asset valuation allowance.

S-32
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES

Historically, Basin's principal sources of capital have been cash flow from
operations, the revolving line of credit, proceeds from asset sales, and
proceeds from sales of common stock. Our principal uses of capital have been for
the exploration, acquisition, and development of oil and gas properties.

Basin's initial budget for 1999 provided for capital investments of
approximately $65 million. With the net proceeds from the offering and
approximately $10 million from asset sales, we will increase our 1999 budget to
$95 million. Given the prevailing lower cost of oil field services today
compared to 1998, we believe our 1999 budget will result in significantly
greater drilling activity than our $106.7 million of capital expenditures for
1998 yielded in a higher service cost environment. We estimate that this budget
expansion will enable us to increase our exploratory drilling activities during
the year by approximately 50% compared to planned activities under our initial
1999 budget.

Basin's accrual-basis capital expenditures during the first quarter of 1999,
plus deposits for five leases for which we submitted apparent winning bids at
the central Gulf of Mexico lease sale held March 17, 1999, totaled approximately
$23.1 million. Net cash provided by operations before changes in working capital
totaled $8.4 million during the first quarter of 1999. Other sources of funds
for investments during the quarter included $11.0 million of net borrowings
under the revolving line of credit, a $3.2 million reduction in net working
capital, and $2.4 million of proceeds from asset sales. Subsequent to March 31,
1999 we received $5.6 million of proceeds from another asset sale. Basin closed
the first quarter of 1999 with a working capital deficit of approximately $16.5
million and long-term debt of $91.0 million, all of which was outstanding under
the revolving line of credit. The borrowing base established under the revolving
line of credit is currently $110 million and will be $90 million following
completion of the offering.

PRODUCTION AND CASH FLOW. Our cash flow from operations is generally
determined by our production level and oil and gas prices. Since 1996, we have
made significant investments to initiate and then expand our operations in the
Gulf of Mexico. These investments have resulted in an increase in our production
from an average rate of 11.2 MMcfe per day in the second quarter of 1997, prior
to commencement of Gulf of Mexico production, to an average of 75.5 MMcfe per
day in the first quarter of 1999. Production added late in the first quarter and
early in the second quarter of 1999 increased our net production rate to a level
above 100 MMcfe per day during April 1999.

Based primarily on estimates reflected in our year-end 1998 reserve reports
and production levels achieved to-date, we anticipate that our net production in
1999 will be at least 50% greater than during 1998, when production totaled
21,966 MMcfe, or an average of 60.2 MMcfe per day. The expected increase is
attributable primarily to projected production from Gulf of Mexico properties
with proved reserves at the end of 1998 that were either on-line for only a
portion of 1998 or had not yet commenced producing. Partially offsetting these
additions will be natural depletion-related declines in production from existing
producing wells. Actual realization of the production increases projected for
the remainder of 1999 will be dependent upon meeting scheduled dates for
commencement of production from wells not yet on-line at the end of 1998, and
upon achieving projected performance from major wells, including certain wells
with little or no production history. Although management and our independent
petroleum engineering consultants believe the projections are reasonable, there
is no assurance that they will be met. See "Risk Factors" and
"Summary--Forward-Looking Statements" for a description of certain risks that
may impact our ability to achieve projected production levels.

MARKETING AND HEDGING TRANSACTIONS. Basin's production is generally sold
under month-to-month contracts at prevailing prices. From time-to-time, however,
as conditions are deemed to warrant, we have entered into hedging transactions
or fixed price sales contracts for a portion of our oil and gas production. The
purposes of these transactions are to limit Basin's exposure to

S-33
<PAGE>
future oil and gas price declines and achieve a more predictable cash flow.
However, such contracts also limit the benefits we would realize if prices
increase. Hedging contracts increased Basin's revenue by $0.3 million and $1.4
million in the three-month periods ended March 31, 1998 and 1999, respectively.
See "Risk Factors--Hedging our production may result in losses".

Through May 7, 1999, Basin had entered into the following fixed price swap
and collar arrangements covering the period beginning April 1, 1999 (one MMBtu
approximates one Mcf of gas):
<TABLE>
<CAPTION>
OIL COLLARS
GAS SWAPS OIL SWAPS ----------------------------
---------------------------------- ---------------------------- NYMEX
AVERAGE DAILY NYMEX AVERAGE DAILY NYMEX AVERAGE DAILY FLOOR
TIME PERIOD VOLUME (MMBTU) PRICE/MMBTU VOLUME (BBL) PRICE/BBL VOLUME (BBL) PRICE/BBL
- ------------------------- ----------------- --------------- --------------- ----------- --------------- -----------
<S> <C> <C> <C> <C> <C> <C>
4/1/99-6/30/99........... 53,300 $ 2.09 1,500 $ 16.67 1,000 $ 14.00
7/1/99-9/30/99........... 50,000 2.10 1,000 14.00
10/1/99-12/31/99......... 38,300 2.09 1,000 14.00
1/1/00-12/31/00.......... 3,300 2.15
1/1/01-12/31/03.......... 10,000 2.15

<CAPTION>
NYMEX
CEILING
TIME PERIOD PRICE/BBL
- ------------------------- -----------
<S> <C>
4/1/99-6/30/99........... $ 16.00
7/1/99-9/30/99........... 16.00
10/1/99-12/31/99......... 16.00
1/1/00-12/31/00..........
1/1/01-12/31/03..........
</TABLE>

In addition, we have periodically entered into spread trades or options
transactions related to oil or gas futures markets. Under a spread trade, fixed
prices under a hedging contract are determined in the future by reference to the
price of an underlying contract. Such positions may enable us to lock in
favorable fixed prices for future hedging positions, but can also result in
unfavorable fixed price contracts if the related reference price declines. As of
May 7, 1999, Basin had an outstanding gas spread trade that provides for a fixed
price for 10,000 MMBtu per day for the period of March 2000 through October 2000
to be established in the future, when so elected by Basin, at a price equal to
the New York Mercantile Exchange February 2000 contract price less $0.41. As of
May 7, 1999, we had also sold the following call options: 20,000 MMBtu of gas
per day for the period from April 1999 through November 1999, at a strike price
of $1.95 per MMBtu; 10,000 MMBtu of gas per day for the period from April 1999
through December 2001, at a strike price of $2.50 per MMBtu; 500 barrels of oil
per day for the period from April 1999 through June 1999, at a strike price of
$16.00 per barrel; and 1,000 barrels of oil per day for the period from July
1999 through December 1999, at a strike price of $16.75 per barrel.

REVOLVING LINE OF CREDIT. Effective January 1, 1999, we entered into a
credit agreement with our existing bank group that provides for borrowings of up
to $110 million under two combined facilities. Facility A, currently established
at $90 million, represents the borrowing base that is considered to be
"conforming" based upon the banks' customary practices and standards in making
conventional borrowing base determinations for oil and gas producers. Facility
B, which is currently established at $20 million, is a shorter-term supplemental
line of credit. Interest rates applied to borrowings under the credit agreement
are determined by reference to the prime rate or LIBOR, at our election.
Facility A provides for a varying spread of 0% to 0.25% to be added to the prime
rate, or 0.75% to 1.5% to be applied to LIBOR, based upon our facility usage
ratio. Facility B provides for a spread of 3.5% to be added to the prime rate,
or 4.75% to be applied to LIBOR, subject to a 0.25% increase in such spreads
effective June 1, 1999.

Our credit agreement provides for borrowings to be revolving loans until
November 30, 2001, at which time the outstanding balance will be converted into
a four-year amortizing term loan unless the credit agreement is amended, and
subject to the scheduled termination of Facility B effective May 31, 2000. The
borrowing base under the credit agreement is scheduled to be re-determined at
three-month intervals until Facility B is retired, and then at six-month
intervals until the revolving loan is converted into a term loan. The next
re-determination is scheduled to occur as of July 1, 1999. Our credit agreement
contains various covenants, including limitations on our ability to incur other
debt, dispose of assets, pay dividends, or repurchase stock. Pursuant to our
credit agreement,

S-34
<PAGE>
substantially all of our producing properties are subject to mortgages in favor
of the banks and our remaining properties are subject to a negative pledge.

The weighted average interest rate on borrowings outstanding under the
credit agreement at March 31, 1999 was 6.5%. Our annual interest costs will
fluctuate based upon fluctuations in short-term interest rates. Assuming debt
outstanding during 1999 remained unchanged from the amount outstanding at March
31, 1999, the annual impact on interest expense of a ten percent change in the
average interest rate would be approximately $0.5 million, before amounts
capitalized. As the interest rate is variable and is reflective of current
market conditions, the carrying value of Basin's debt approximates its fair
value.

Borrowing base re-determinations conducted by the bank group reflect a
number of estimates and assumptions including, but not limited to, future
production from Basin's proved properties, risk factors for proved reserves,
projected oil and gas prices, future operating and development costs, and
interest rates. Changes in such estimates and assumptions can significantly
impact the size of the borrowing base established by the banks. Because these
factors will be influenced by future events, which cannot be forecast with
certitude, we cannot predict what level of borrowing base will be established at
any future determination date. The provision for Facility B was intended, in
part, to provide short-term funds to develop our proved undeveloped and proved
developed nonproducing reserves in the Gulf of Mexico. It is anticipated that
funds drawn under Facility B will be retired through expansion of Facility A, if
our reserve values are sufficiently increased, or that Facility B will be repaid
from cash flows or proceeds from the sale of assets or securities. At May 15,
1999, $90 million was outstanding under Facility A and $12 million was
outstanding under Facility B.

Positive or negative changes in the borrowing base during 1999 could impact
the level of our capital expenditures during the year. Increases, supported by
performance of our properties, drilling results, and/or higher oil and gas
prices, could improve our ability to grow. Decreases would adversely affect our
liquidity and capital resources, potentially resulting in a reduction of planned
capital expenditures or the sale of our assets or the issuance of securities.

CAPITAL EXPENDITURES. Since the beginning of 1996, we have focused our
exploration activities in the shallow waters of the Gulf of Mexico, primarily
off the coast of Louisiana. During the second half of 1998 we began to direct a
small portion of our exploration budget toward onshore opportunities. We also
pursue acquisition and development opportunities in the vicinity of our Gulf of
Mexico exploration operations, in the Rocky Mountain region where we have an
existing base of proved reserves and producing wells, and in certain other major
domestic producing basins where we believe significant upside potential exists.
Our capital expenditures are generally discretionary and activity levels are
determined by a number of factors, including oil and gas prices, availability of
funds, quantity and character of identified investment projects, availability of
service providers, and competition.

Basin's capital expenditures in 1998 totaled approximately $107 million, of
which 96% related to operations in the Gulf of Mexico. Approximately $28 million
was invested in acquisitions of exploratory leaseholds and geological and
geophysical data in the Gulf of Mexico. Approximately $68 million related to
Gulf of Mexico drilling, completion, and related development costs. The
remainder related to small acquisitions of proved reserves and activities
onshore. Gulf of Mexico operations in 1998 included ongoing development of nine
productive wells drilled or acquired in 1997, participation in the drilling of
17 wells, of which 11 were successful, and development costs related to the
successful wells drilled during the year.

Basin's initial budget for 1999 provided for capital investments of
approximately $65 million, subject to an increase for proceeds from anticipated
asset sales. With the net proceeds from the offering and approximately $8
million from asset sales to date in 1999, we plan to increase our 1999 budget to
$95 million. Given the prevailing lower cost of oil field services today
compared to

S-35
<PAGE>
1998, we believe our 1999 budget will result in significantly greater drilling
activity than our $106.7 million of capital expenditures for 1998 yielded in a
higher service cost environment. We estimate that this budget expansion will
enable us to increase our exploratory drilling activities during the year by
approximately 50% compared to planned activities under our initial 1999 budget.
The revised 1999 budget primarily provides for:

- development of seven Gulf of Mexico properties with one or more discovery
wells yet to commence sustained production as of the end of 1998;

- investments in seismic data and prospects;

- participation in approximately nine net (18 to 20 gross) exploratory wells
in the Gulf of Mexico;

- participation in a small number of onshore exploration opportunities;

- development of projected 1999 prospect discoveries; and

- continued exploitation of our other offshore and onshore properties.

This reduced budget for exploratory leaseholds reflects the unusually large
investment made by Basin in 1998 to build a multi-year inventory of drilling
prospects. New investments planned for 1999 will seek to maintain this inventory
level rather than significantly expand it. We also intend to pursue acquisitions
of properties with proved and probable reserves as an integral part of our
overall business strategy, with the expectation that these efforts will result
in significant investment activity over time. At this time, no portion of our
1999 budget has been specifically allocated for acquisitions of proved
properties. If such a transaction is executed, it will likely require a
re-allocation of funds from other planned activities and/or external financing.

During the first quarter of 1999, Basin's accrual-basis capital expenditures
totaled approximately $22.5 million. Such investments were primarily for
development of several Gulf of Mexico properties on which discovery wells were
drilled during the prior year, participation in drilling five (2.5 net) Gulf of
Mexico wells, related completion costs on two (0.8 net) of these wells, and
acquisitions of additional Gulf of Mexico 3-D seismic data and leasehold
interests. At the March 1999 federal Central Gulf of Mexico lease sale, we also
submitted deposits totaling $0.6 million related to five apparent winning bids
aggregating $3.0 million. The Minerals Management Service has subsequently
awarded all five leases to us, and we have paid the remaining 80% of the
respective bid amounts, or an additional total of $2.4 million. This amount was
provided for within our budget for exploration and development activities in the
current year.

The amount and allocation of future capital expenditures will depend on a
number of factors that are not entirely within Basin's control or ability to
forecast, including drilling results, scheduling of activities by other
operators, availability of service providers, success in acquiring prospect
leaseholds, and success in consummating acquisitions of proved properties.
Basin's planned capital expenditures are also based on estimates regarding
availability of capital that depend on assumptions and estimates regarding
production, oil and gas prices, and borrowing base re-determinations under our
revolving line of credit. Due to these uncertainties, and other matters
described under "Risk Factors" and "Summary--Forward-Looking Statements", actual
capital expenditures may vary significantly from current expectations.

YEAR 2000 READINESS DISCLOSURE AND STATEMENT

Readers are cautioned that the forward-looking statements contained in the
following Year 2000 discussion should be read in conjunction with Basin's
disclosures under the heading "Summary-- Forward-Looking Statements" in this
prospectus supplement.

S-36
<PAGE>
Year 2000 issues result from the inability of many computer programs to
accurately calculate, store or use a date subsequent to December 31, 1999. The
date can be erroneously interpreted in a number of different ways; typically the
year 2000 is interpreted as the year 1900. This could result in a system failure
or miscalculations causing disruptions of or errors in operations. Systems
potentially affected include not only information technology systems--computer
systems controlling a company's accounting, land, operations, seismic
processing, and other specialized functions--but also non-information technology
systems controlled by embedded chips, which include many common and specialized
machines and support systems. The effects of the Year 2000 problem can be
exacerbated by the interdependence of computer and telecommunications systems in
the United States and throughout the world. This interdependence can affect us
and the parties with whom we do business.

STATE OF READINESS. We have created an internal committee to assess our
Year 2000 readiness and to lead our remediation efforts. The committee is
composed of the general counsel, chief financial officer, controller, and
manager of information systems. The committee's objective is to prevent loss or
impairment of those functions material to Basin's operations and business
continuity or to avoid potential liability to third parties. At the direction of
the committee, department heads and managers have assessed and remediated our
information technology and non-information technology systems, and have
communicated with our business partners regarding the status of their assessment
and remediation efforts, with the results summarized below.

We have completed an assessment of our information technology systems to
determine whether they are Year 2000 compliant. The licensors of both our core
financial, land and operations software system and the underlying operating
system have certified that such software is Year 2000 compliant. Our Gulf of
Mexico seismic data interpretation software system is not currently Year 2000
compliant, but we have begun an upgrade of that system with software which the
licensor has represented will be compliant. We are also upgrading our reservoir
economics software to make it Year 2000 compliant. Basin expects the upgrade and
testing of these software systems to be completed by July 1999. Additionally, we
have assessed other less critical information technology systems and we believe
them to be compliant.

We also rely on non-information technology systems, such as office
telephones, facsimile machines, HVAC systems and elevators in our leased
offices, security systems, and automated measuring equipment on platforms and
other production facilities, which may have embedded technology such as
micro-controllers. Department heads and managers have identified those non-
information technology systems that may be susceptible to failure or impairment
by reason of Year 2000 problems and that are potentially critical to our
operations and business continuity. Based on that review, Basin has sent written
inquiries to the suppliers of those systems to determine the status of their
Year 2000 compliance. Our communications systems vendors, and the property
managers of the buildings in which our Houston and Denver offices are situated,
have certified their systems to be Year 2000 compliant. We are still receiving
and analyzing responses from vendors of non-information technology systems that
may affect our production operations. The operations department will follow up
those inquiries with telephone interviews to assess the status of such systems.
Assessment and remediation of non-information technology systems should be
completed by September 1999.

We have sent written inquiries to our significant suppliers, customers,
banks, government agencies, benefit plan providers, and others with whom we have
significant business relationships to determine the extent to which we are
vulnerable to those third parties' failure to correct their own Year 2000
issues. To date, we have not received definitive responses from many of these
entities and therefore cannot assess whether they are Year 2000 compliant or how
their failure to be compliant would affect us. Those third parties who have
responded have generally indicated that

S-37
<PAGE>
they are either Year 2000 compliant or expect to be compliant. Our department
heads and managers have compiled a list of critical third parties to whom
telephone follow-up will be made. For Gulf of Mexico operations, these include
representative vendors and suppliers who could supply necessary goods and
services to maintain our production operations and continue any ongoing or
planned drilling activities. We expect to have this follow-up inquiry completed
by July 1999 and we will seek to use those vendors and suppliers providing
adequate assurances regarding their compliance.

ESTIMATED COMPLIANCE COSTS. We have relied primarily on our internal staff
to assess our current Year 2000 readiness and do not anticipate extensive use of
external resources to complete our assessment or remediation. We have not
separately quantified our costs of internal resources on this project but do not
expect that we will incur material costs in remediating our information
technology systems to be Year 2000 compliant. Costs incurred for the purchase of
new software and hardware are capitalized and all other costs are expensed as
incurred. We have not incurred, and do not anticipate that we will incur, costs
for external resources in excess of $100,000 relating to the assessment and
remediation of Year 2000 issues. That estimate does not include the cost of
remediating problems caused by third-party vendors, customers, or other business
partners, which Basin will not be able to fairly estimate until the extent, if
any, of their Year 2000 non-compliance is known.

RISKS OF NON-COMPLIANCE AND CONTINGENCY PLANS. As indicated above, the only
critical information technology systems that we believe are not yet Year 2000
compliant are our seismic data interpretation and reservoir economics systems,
which should be compliant by July 1999. Accordingly, we do not expect Year 2000
issues to cause our information technology systems to have any material adverse
impact on our business, operations or financial condition. We believe that the
potential impact, if any, of our non-critical information technology systems not
being Year 2000 compliant will at most require employees to manually complete
otherwise automated tasks or calculations and should not impact our ability to
continue exploration, drilling, production or sales activities. We are not able
to predict at this time what the impact could be of non-information technology
system failures but do not believe that there will be a material disruption of
our operations.

Until we have completed our inquiries to third parties, we will not be able
to fairly assess the potential impact of their failure to be Year 2000 compliant
on our operations, business, or financial condition. The most reasonably likely
"worst case" impacts could be impairment of our ability to deliver our
production to, or receive payment from, third parties gathering and/or
purchasing our production from affected facilities, impairment of the ability of
third-party suppliers or service companies to provide needed materials or
services to our planned or ongoing operations, thereby necessitating deferral or
shut-in of exploration, development or production operations, and our inability
to execute financial transactions with our banks or other third parties whose
systems fail or misfunction. We have no reason to believe that any of these
contingencies will occur or that our principal vendors, customers, and business
partners will not be Year 2000 compliant.

Basin does not currently have a contingency plan under development or in
place to address these potential problems. We do intend to develop contingency
plans in response to testing our information technology and non-information
technology systems and in response to the results of our third-party inquiries.
These contingency plans may include installing back-up computer systems or
equipment, temporarily replacing systems or equipment with manual processes, and
identifying alternate suppliers, service companies and purchasers. Basin expects
these plans to be complete by October 1999.

Basin's Year 2000 program is a continuing process that may result in changes
to cost esti-
mates and schedules as testing and business partner assessment progresses.
Unexpected Year 2000 compliance problems of either Basin or our vendors,
customers, service providers, or other entities with whom we do business could
have a material adverse impact on our business, financial condition or operating
results.

S-38
<PAGE>
BUSINESS AND PROPERTIES

To facilitate our continued growth, we have assembled undeveloped leasehold
positions totaling 255,141 gross acres, or 180,816 net acres, at December 31,
1998, more than half of which are in the Gulf of Mexico. We have also licensed
more than 600 lease blocks of 3-D seismic data and 375,000 miles of conventional
2-D seismic data covering portions of the Gulf of Mexico. We have integrated
this database with geological interpretations by our technical personnel to
develop a multi-year inventory of more than 45 drilling prospects supported by
3-D seismic data.

S-39
<PAGE>
acquisitions has decreased as capital-constrained companies have sought to
strengthen their balance sheets. Furthermore, prices for West Texas Intermediate
oil and Henry Hub gas, as reflected on the New York Mercantile Exchange, have
increased from $12.05 per Bbl and $1.95 per MMBtu at year-end 1998 to $18.03 per
Bbl and $2.27 per MMBtu on May 15, 1999. We are pursuing the offering to take
advantage of these favorable investment conditions, and we plan to use the
additional borrowing capacity resulting from the offering to significantly
increase our exploration and development activities.

RECENT DEVELOPMENTS

During 1999, our Gulf of Mexico activities have included the completion of
three (1.95 net) exploratory wells that were successfully drilled in 1998, the
drilling of seven (3.45 net) exploratory wells, of which two (0.55 net) wells
were apparent discoveries and two (1.0 net) are currently drilling, and the
drilling of one (0.65 net) successful development well. We also participated in
one (0.60 net) exploratory well in Wyoming, which was abandoned in February 1999
due to an apparent underground blowout. We have since drilled and cased a
replacement well, the cost of which was substantially funded by insurance
proceeds. We are presently testing a secondary objective below the primary
objective formation.

On March 17, 1999, Basin submitted apparent winning bids for five leases at
the federal Central Gulf of Mexico lease sale held by the Minerals Management
Service. These leases cover 24,023 gross and net undeveloped acres offshore
Louisiana. All of these leases, having an aggregate leasehold bonus cost of
approximately $3.0 million, have been awarded to us by the Minerals Management
Service.

STRATEGY

S-40
<PAGE>
BALANCE SIZE AND RISK PROFILE OF EXPLORATION TARGETS. We generally seek to
conduct a drilling program that is balanced between exploration prospects with
significant potential relative to our existing reserve base and smaller, lower
risk prospects. This balance is intended to mitigate risk while providing
exposure to meaningful growth in reserves and production.

PRINCIPAL PRODUCING PROPERTIES

Our principal producing properties are located offshore in the shallow
waters of the Gulf of Mexico and in the Powder River and Green River Basins in
Wyoming.

Our Gulf of Mexico properties accounted for 75% of our proved reserves at
December 31, 1998 and 89% of our production for the quarter ended March 31,
1999. As of December 31, 1998, Basin's Gulf of Mexico proved reserves were
distributed among 18 fields. Production had been established from 14 of these
fields as of that date, and the other four fields were under development for
first production. Our working interests in the 18 fields ranged from
approximately 8% to 100%, with an average of 54%. We operate 11 of the 18 fields
and these 11 properties accounted for approximately 67% of our Gulf of Mexico
production for the quarter ended March 31, 1999 and two-thirds of our total
proved reserves in the Gulf of Mexico at the end of 1998.

Most of Basin's onshore proved reserves as of December 31, 1998 were
concentrated in six fields in the Powder River and Green River Basins. These
reserves were broadly distributed among approximately 200 producing wells, as
well as a limited number of undeveloped locations. Most of our producing wells
in the Rocky Mountain area have been on-line for several years and their
respective production declines are relatively moderate and well-established. No
individual onshore field accounted for more than 3% of the estimated present
value of our reserves at the end of 1998. We own a majority working interest in
most of our onshore proved properties and we act as operator of properties
accounting for 59% of our total proved onshore reserves at the end of 1998. Our
onshore properties accounted for 25% of our proved reserves at December 31, 1998
and 11% of our production for the quarter ended March 31, 1999.

The following table presents information about our ten most valuable
producing properties at December 31, 1998, as measured by the estimated pre-tax
present value of future net cash flows. As shown below, these ten properties
accounted for 80% of Basin's estimated pre-tax present value

S-41
<PAGE>
related to proved reserves at December 31, 1998. These same properties accounted
for 79% of our total oil and gas production in the first quarter of 1999, which
averaged 75.5 MMcfe per day.

<TABLE>
<CAPTION>
PERCENTAGE PERCENTAGE
BASIN BASIN NET OF FIRST OF 12/31/98
WORKING REVENUE QUARTER PRE- TAX
INTEREST INTEREST 1999 NET PV-10
FIELD OPERATOR (%) (%) PRODUCTION VALUE(1)
- ----------------------------------- ------------ ----------- ----------- ---------- ------------
West Cameron Block 45.............. Basin 100% 79% 19% 25%
<S> <C> <C> <C> <C> <C>
West Delta Block 61 S/2............ Basin 65 46 0(2) 11
High Island Block A-568............ Samedan 33 28 14 9
Eugene Island Block 65............. Basin 76 62 9 7
East Cameron Block 378............. Sonat 47 37 8 7
East Cameron Block 34.............. Basin 60 49 3 6
West Cameron Block 56 N/2.......... Basin 67 51 14 6
Eugene Island Block 49............. Basin 100 81 5 3
East Cameron Block 220............. Basin 100 81 4 3
West Cameron Block 172............. IP Petroleum 15 12 3 3
Other Fields....................... 21 20
---- ----
Total............................ 100% 100%
</TABLE>

- ------------------------
(1) Pre-tax PV-10 value refers to the pre-tax present value at December 31, 1998
of estimated future net cash flows before income taxes discounted at 10% per
annum, calculated using unescalated prices and costs in effect on the date
of the applicable reserve reports (unless such prices or costs are subject
to change pursuant to contractual provisions).

(2) First production established during April 1999.

The ten properties shown in the table above are all located in the Gulf of
Mexico. Each of these is briefly described below.

WEST CAMERON BLOCK 45 FIELD. West Cameron Block 45 is located five miles
offshore Louisiana in water depth of 34 feet. We acquired a 100% working
interest in this property in November 1997. The field had been on production
since the 1940s, and had recovered over 500 Bcfe at the time of our acquisition,
but it had never been exploited with the benefit of modern 3-D seismic data and
production had declined to less than 4 MMcfe per day. Before we acquired the
property, we used 3-D seismic to identify several prospects in multiple lower
Miocene-age sands.

In the second and third quarters of 1998, we drilled three successful
exploratory wells on West Cameron Block 45 in separate structural fault blocks.
We modified an existing West Cameron Block 45 platform to handle the additional
production, and we brought the three new wells on-line at various times in late
1998 and 1999. Gross production from the field during the quarter ended March
31, 1999 averaged approximately 20 MMcfe per day.

WEST DELTA BLOCK 61 S/2 FIELD. We acquired a 100% working interest in
certain intervals under the south-half of West Delta Block 61 through a farm-in
from another energy company. The property is located 15 miles offshore Louisiana
in water depth of 105 feet. West Delta Block 61 is part of a producing field
complex that extends into Block 62 to the west, and which has produced in excess
of 75 Bcf of gas and 1.0 MMBbl of oil and condensate from multiple Miocene-age
sands. Twelve wells had been drilled on West Delta Block 61 prior to our
farm-in.

Using data from a new 3-D seismic survey, we identified an undrilled
structural fault block with several seismic amplitude anomalies. We drilled the
#8 well in the second quarter of 1998 to test the field and in early 1999, we
drilled and completed the #B-2 development well, and subsequently installed a
platform and a pipeline that connected the facility to a nearby third-party
platform for processing. Production from both the #8 and the #B-2 wells
commenced in early April 1999.

S-42
<PAGE>
HIGH ISLAND BLOCK A-568 FIELD. High Island Block A-568 is located 100 miles
offshore Texas in 280 feet of water. We purchased a 33.3% working interest in
this block as part of the November 1997 acquisition that also included interests
in West Cameron Block 45. Prior to our acquisition, 15 wells had been drilled on
High Island Block A-568 and cumulative production from the field had exceeded
105 Bcfe from multiple Pleistocene-age sands. In the second half of 1997, prior
to our acquisition, the joint owners drilled two new wells in the field to
exploit potential reserves identified with 3-D seismic data. We had identified
the drilling potential using 3-D data before the wells were drilled, but had
been unsuccessful in attempts to acquire the property beforehand. Both wells
were drilled from an existing production platform, expediting development, and
first sales occurred in November 1997 and January 1998, respectively.

EUGENE ISLAND BLOCK 65 FIELD. We acquired a 100% working interest in Eugene
Island Block 65 in April 1996, at the first federal Gulf of Mexico lease sale in
which Basin participated. The property is located 18 miles offshore Louisiana in
water depth of 21 feet. Two wells previously drilled on the block by another
operator had established marginal production and had then been abandoned.
Utilizing new 3-D seismic data, we were able to identify two prospective traps
in multiple Miocene-age sands that had not been tested. We subsequently drilled
two successful exploratory wells on this block, after promoting interests out to
partners while retaining control of operations. We initiated production from
both wells in August 1997, within seven months of drilling the discovery well,
after installing a production platform with facilities and a connecting
pipeline.

In November 1998, the #2 well on Eugene Island Block 65 stopped producing
after cement behind production casing failed to hold, allowing water to channel
into the well. We conducted a workover and re-completion operation to seal off
the water and returned the well to production in March 1999.

We owned a 37.5% working interest in Eugene Island Block 65 when the
discovery well was drilled, and have increased our ownership interests in the
field over time through purchasing the interests of two partners and earning
reversionary interests when project payout was reached in September 1998.
Currently, we own a 76.4% working interest in the lease, but also retain the
remaining 23.6% working interest in the #2 well until 400% of costs related to
the recent repair are recouped, due to a partner's election not to participate
in the operation.

EAST CAMERON BLOCK 378 FIELD. East Cameron Block 378 is located 110 miles
offshore Louisiana, in water depth of approximately 450 feet. In February 1997,
we acquired a 46.5% working interest in a discovery well that had recently been
drilled and completed subsea on the block. The operator of the property
initiated production from the well in July 1998, after laying lines to connect
the well to a nearby third-party platform for processing.

EAST CAMERON BLOCK 34 FIELD. We acquired a 60% working interest in East
Cameron Block 34 at the March 1997 federal Central Gulf of Mexico lease sale.
The property is located seven miles offshore Louisiana in water depth of 37
feet. East Cameron Block 34 is part of a producing field complex that extends
into Block 33 to the west which produced in excess of 390 Bcf of gas and 2.5
MMBbl of condensate from multiple Miocene-age sands. Five wells had been drilled
on the block prior to our acquisition. Before acquiring the block, Basin
acquired a 3-D seismic survey and identified three prospects in multiple
Miocene-age sands.

In the first quarter of 1998, after drilling a non-commercial well on the
block at the beginning of the year, Basin drilled a second exploratory well to
test a separate prospect. Production commenced from the well in the fourth
quarter of 1998 after installation of a caisson platform with facilities and a
pipeline connection. Basin has identified another prospect on the block that
will be considered for drilling at a later date.

S-43
<PAGE>
WEST CAMERON BLOCK 56 N/2 FIELD. We acquired a 100% working interest in
certain intervals under the northeast quarter of West Cameron Block 56 through
farm-in. We retained a 66.7% working interest and operations after bringing in
an industry partner on a promoted basis prior to drilling a test well.

This block is located seven miles offshore Louisiana in water depth of 35
feet. It is part of a producing field complex extending into West Cameron Block
45 to the north, which has produced more than 400 Bcf of gas and 13 MMBbl of oil
and condensate from multiple Miocene-age sands. Prior to our farm-in, 23 wells
had been drilled on West Cameron Block 56. Utilizing 3-D seismic data, we
identified an undrilled structural fault block with a seismic anomaly. In the
third quarter of 1997, we drilled a successful exploratory well on the prospect.
We initiated production from this well in April 1998 after installing a caisson
facility and pipeline to connect the well to a production platform on adjacent
West Cameron Block 45. As part of a separate transaction closed in November
1997, we acquired the farmor's residual interest in West Cameron Block 56 and
its 100% working interest in West Cameron Block 45, along with certain other
properties.

EUGENE ISLAND BLOCK 49 FIELD. This property is found 20 miles offshore
Louisiana, in water depth of 20 feet. We acquired a 100% working interest in
Eugene Island Block 49 at the March 1997 federal Central Gulf of Mexico lease
sale. Another company drilled a well on this block in 1992 that encountered gas
in three zones, but was not completed. Utilizing new 3-D seismic data and
conventional well log analysis, we identified a prospect with multiple
upper-Miocene sand objectives in a better structural location than encountered
by this abandoned well. We also identified two additional modest-sized prospects
on the block.

In the third quarter of 1997, we drilled the primary prospect and commenced
completion operations after finding commercial reserves. Production commenced
from the well in the third quarter of 1998 after we installed a caisson platform
and a pipeline to connect the facility to a nearby third-party production
platform for processing.

EAST CAMERON BLOCK 220 FIELD. We obtained our 100% working interest in this
producing property through an acquisition in November 1997. The block is located
65 miles offshore Louisiana in 118 feet of water. The East Cameron Block 220
Field has produced over 78 Bcf from 17 wells since October 1980, including
approximately 42 Bcf from shallow Pleistocene reservoirs and over 36 Bcf from a
deeper Pliocene reservoir. East Cameron Block 220 is part of a producing field
complex that includes adjacent blocks 219 and 221. Production from the property
had declined to uneconomic rates and was shut-in at the time we acquired the
block. Our principal interest in the property related to several prospective
exploratory locations that we identified with 3-D seismic data prior to making
the acquisition. During the first half of 1998, we restored production from two
existing well-bores through workovers and in late-1998 we drilled a successful
exploratory well from an existing platform on the block. Production from the new
well was initiated in the first quarter of 1999. We anticipate drilling another
exploratory well on the block later this year, as further discussed below.

WEST CAMERON BLOCK 172 FIELD. This property is located 27 miles offshore
Louisiana in 49 feet of water. We acquired a 15% working interest in West
Cameron Block 172 from another energy company in 1998 after identifying several
undrilled prospective fault closures with new 3-D seismic data. The block is
part of a field complex that had previously produced approximately 60 Bcfe from
Miocene-age sands out of six wells. We participated in drilling an unsuccessful
well on a shallow prospect on the block in early 1998, but then participated in
drilling three successful wells on the property during the second half of 1998
and early 1999. Each of these wells encountered multiple Miocene-age sands below
a true vertical depth of 8,800 feet. Production from the first two discovery
wells was initiated in December 1998 and January 1999 and the third well is
expected to commence production during the third quarter of this year.

S-44
<PAGE>
EXPLORATORY PROSPECTS
OFFSHORE EXPLORATORY PROSPECTS

Basin currently has an inventory of more than 45 undrilled prospects in the
Gulf of Mexico. The following table shows information regarding those leases on
which we have identified one or more undrilled prospects. Virtually all of our
Gulf of Mexico prospects are supported by 3-D seismic data.

<TABLE>
<CAPTION>
BASIN BASIN NET
WORKING REVENUE
INTEREST INTEREST LEASE
PROSPECT OPERATOR (%) (%) EXPIRATION
- ----------------------------------------------- ------------- ----------- ----------- ---------
East Cameron Block 34.......................... Basin 60 49 (1)
<S> <C> <C> <C> <C>
East Cameron Block 44.......................... Basin 100 81 07/01/03
East Cameron Block 51.......................... Basin 100 81 07/01/03
East Cameron Block 65.......................... Basin 75 61 06/01/03
East Cameron Block 220......................... Basin 50 40 (1)
Chieftain
East Cameron Block 255......................... Int'l 40 32 08/01/02
East Cameron Block 271......................... Basin 100 81 07/01/04
East Cameron Block 378......................... Hall-Houston 23 17 (1)
Eugene Island Block 13......................... Basin 100 74 01/12/02
Eugene Island Block 65......................... Basin 76 62 (1)
Eugene Island Block 82......................... Basin 50 41 09/01/01
Galveston Block 190............................ Houston Expl. 23 18 12/31/03
Chieftan
Grand Isle Block 66............................ Int'l 40 32 08/01/02
Main Pass Block 265............................ Basin 50 40 07/01/03
Mississippi Canyon Block 110................... Shell 8 6 07/31/02
Mustang Island Block A65....................... Basin 100 81 10/01/03
South Marsh Island Block 286................... Basin 100 81 07/01/02
South Pass Block 47............................ Basin 50 40 05/01/04
Vermilion Block 16............................. Basin 60 49 07/01/02
Vermilion Block 48............................. Basin 100 82 06/01/01
Vermilion Block 83............................. Basin 50 40 08/01/03
Vermilion Block 267 N/2........................ Basin 40 32 05/01/02
West Cameron Block 62.......................... Basin 100 81 06/01/03
West Cameron Block 69.......................... Basin 100 82 07/01/01
West Cameron Block 72.......................... Basin 100 82 06/01/01
West Cameron Block 104......................... Basin 100 82 07/01/01
West Cameron Block 287......................... Basin 100 81 07/01/04
Chieftain
West Cameron Block 300......................... Int'l 25 20 06/30/00
West Cameron Block 476......................... Basin 50 40 06/01/03
West Delta Block 63............................ Basin 50 40 06/01/03
West Delta Block 87............................ Basin 100 81 08/01/03
West Delta Block 98............................ Basin 100 81 07/01/04
West Delta Block 121........................... Vastar 25 20 08/01/03
West Delta Block 122........................... Vastar 25 18 (2)
West Delta Block 131........................... Basin 100 81 07/01/04
West Delta Block 140........................... Basin 100 81 08/01/03
AVERAGE (36 LEASES)............................ 68 55
</TABLE>

(1) Lease held for an indefinite extended term so long as production continues.

(2) Lease extension granted by the Minerals Management Service pending
development for production.

S-45
<PAGE>
Described below are twelve of the exploratory prospects that Basin expects
to drill during the next twelve months, including several that we assess as
being among our higher potential prospects. We can give no assurance that we
will drill these prospects during the next year or afterwards, as drilling plans
are affected by many factors, including some that may not be in our control. See
"Risk Factors--Exploration is a high risk activity and the 3-D seismic and other
advanced technologies we use are expensive, require experienced personnel, and
cannot eliminate exploration risk".

EAST CAMERON BLOCK 65 PROSPECT. We acquired a 100% working interest in East
Cameron Block 65 at the March 1998 federal central Gulf of Mexico lease sale for
approximately $3.7 million, and subsequently sold a 25% working interest in the
prospect on a promoted basis and recouped a proportionate share of our
investment. We plan to sell or exchange additional interests in the property in
order to own between 30% and 50% at the time of drilling. Our prospect targets
Miocene-age sands below 15,000 feet. We anticipate drilling the prospect in the
second half of 1999. The property is located 25 miles offshore Louisiana in
water depth of 55 feet.

EAST CAMERON BLOCK 220 PROSPECT. East Cameron Block 220 is located 65 miles
offshore Louisiana in 118 feet of water. We acquired a 100% working interest in
this producing property as part of a November 1997 transaction. The field has
produced a total 78 Bcfe from two shallow Pleistocene-age structures
approximately 3,000 feet deep and from a deeper Pliocene-age structure found at
approximately 11,000 feet. The prospect's primary objectives are approximately
600 feet deeper than the lowest producing Pliocene-age sands in the East Cameron
Block 220 Field. The objective sands are lower Pliocene-age sands characterized
by 3-D seismic data anomalies that correlate with proved reservoirs in the upper
Pliocene-age section. The trap is the same faulted structure that traps
hydrocarbons in the upper Pliocene sand horizon, and the equivalent-age sands
are found at adjacent Block 219 to the east. We recently sold a 50% working
interest in the exploratory rights, but not the proved reserves, on the block on
a promoted basis and anticipate drilling a well later this year to evaluate this
prospect.

EAST CAMERON BLOCK 378 PROSPECT. This block is located 110 miles offshore
Louisiana in 450 feet of water. We acquired a 23.25% working interest in the
exploratory rights on this block in February 1997 as a part of an acquisition
that also included a 46.5% interest in the discovery well described above. The
seller retained half of its original interest. The exploratory prospect targets
Pleistocene-age sands that exhibit several stacked anomalies below 11,000 feet
true vertical depth, on the flank of a salt dome. Basin participated in
reprocessing the 3-D seismic data across the block in order to improve the
imaging of the salt-sediment interface. We expect the operator to propose
drilling a test well in late 1999 or early 2000 to evaluate this prospect.

GALVESTON BLOCK 190 PROSPECT. We acquired a 45% working interest in
Galveston Block 190 at the August 1998 federal Western Gulf of Mexico lease sale
for approximately $1.0 million and subsequently sold one-half of our interest to
a working interest partner on a promoted basis and recouped a proportionate
share of our investment. The block is located 15 miles offshore Texas in 40 feet
of water. Our main objective on this prospect will be Miocene-age sands found at
14,200 feet, along a fault that is part of the same system of faults that traps
shallower sands at Galveston Block 189. Seismic data does not evidence
hydrocarbon indicators for this prospect, due to the formation depth and
pressure environment, but a recent 3-D seismic survey indicates that the
prospect is structurally updip of a well that tested hydrocarbons from the same
sands. When drilling the test well to evaluate our main objective, we will also
test a shallower prospect in shallower Miocene-age sands in an upthrown
structural closure. We currently anticipate that the operator will propose
drilling a test well on the block later this year.

MAIN PASS BLOCK 265 PROSPECT. We acquired a 100% working interest in Main
Pass Block 265 for approximately $3.3 million at the March 1998 federal Central
Gulf of Mexico lease sale. Subsequently, we sold 25% working interests to each
of two partners on a promoted basis and

S-46
<PAGE>
recouped a proportionate share of our investment. Our principal targets on the
block, which is located 45 miles offshore Louisiana in water depth of 230 feet,
are two separate stratigraphic traps in the Miocene-age sand interval below
12,000 feet. Both prospects exhibit good anomalies with strong hydrocarbon
indicators analogous to numerous fields discovered in the same area utilizing
recent 3-D seismic data. We anticipate drilling the first test well to a true
vertical depth of 12,500 feet in the third quarter of 1999.

SOUTH PASS BLOCK 47 PROSPECT. This property is located eight miles offshore
Louisiana in 225 feet of water. We acquired a 100% working interest in South
Pass Block 47 at the March 1999 federal Central Gulf of Mexico lease sale for
approximately $0.2 million and subsequently sold a 50% working interest in the
prospect on a promoted basis, recouping a proportionate share of our investment.
Two wells drilled by another company previously produced approximately 21 Bcfe
from this block. Using recent 3-D seismic data, we identified two separate
prospects on the block in Pliocene-age sands that exhibit strong anomalies
similar to anomalies evidenced by productive fields along the trend. We
anticipate drilling a test well to a true vertical depth of approximately 10,000
feet later this year to evaluate the first of these prospects.

VERMILION BLOCK 16 PROSPECT. This block is located three miles offshore
Louisiana in 25 feet of water. Basin acquired a 60% working interest in the
lease at the March 1997 federal Central Gulf of Mexico lease sale for
approximately $0.3 million. It is an 800-acre federal lease bordering Louisiana
state waters. The prospect is located in a prolific lower-Miocene trend, called
the Rob M, that has produced in excess of 2.7 trillion cubic feet of gas
equivalents from the same age sands about three miles southeast at the Vermilion
25/26 Field. This prospect covers a much smaller area and has much smaller
reserve potential than the Vermilion 25/26 Field, but it exhibits analogous
features. Our prospect straddles a lease line and resides on both Vermilion
Block 16 and Vermilion Block 25, which is held by another company. As a result,
we anticipate that a test well will most likely be drilled on a joint basis
after an equitable split of prospect ownership is negotiated between owners of
both blocks. Therefore, we cannot now quantify our ultimate ownership interest
in the prospect or predict the timing of a test well. We do, however, expect
these matters to be resolved to facilitate drilling a test well later this year
or in 2000 to an anticipated target depth of approximately 16,000 feet.

VERMILION BLOCK 83 PROSPECT. This block is located 23 miles offshore
Louisiana in water depth of 55 feet. We acquired a 100% working interest in
Vermilion Block 83 for approximately $2.3 million at the March 1998 federal
Central Gulf of Mexico lease sale. Subsequently, we sold 25% working interests
to each of two partners on a promoted basis and recouped a proportionate share
of our investment. The prospect targets Miocene-age sand. The prospect is
supported by an anomaly evident on new 3-D seismic data that appears to be
analogous to one found at the Vermilion Block 84, which has produced
approximately 52 Bcfe to date. We have commenced the drilling of a test well to
a planned true vertical depth of approximately 9,000 feet to evaluate this
prospect.

VERMILION BLOCK 267 N/2 PROSPECT. This half-block is located 70 miles
offshore Louisiana in 160 feet of water. We acquired a 40% working interest in
this lease at the March 1997 federal Central Gulf of Mexico lease sale for
approximately $0.2 million. This prospect targets Pliocene age sands at 11,300
feet which exhibit good anomalies with strong hydrocarbon indicators on 3-D
seismic. The lease offsets an adjacent producing field that has produced
approximately 85 Bcfe to-date. We anticipate drilling a test well later this
year to evaluate this prospect.

WEST DELTA BLOCK 63 PROSPECT. This property is located 20 miles offshore
Louisiana in water depth of 125 feet. We acquired a 100% working interest in
West Delta Block 63 for approximately $3.2 million at the March 1998 federal
Central Gulf of Mexico lease sale, and subsequently brought in a 50% working
interest partner on a promoted basis and recouped a proportionate share of our
investment. The block was previously part of the West Delta Block 62 Field
complex and became available just prior to the lease sale. The principal targets
on this block are in the Miocene-age sand

S-47
<PAGE>
interval, in two separate structural traps formed along the same fault system as
on West Delta Block 62. Another company previously drilled one of the prospects,
which tested positive for hydrocarbons but was not developed. Using recent 3-D
seismic data, we anticipate being able to encounter the same sands in an
improved structural position and to evaluate additional untested sands. The
second prospect is located updip of a well that produced hydrocarbons from the
same sands but was not located in an optimal position on the structure and
prematurely watered out. As with the other prospect on this block, we anticipate
using a recent 3-D seismic survey to enhance the positioning of a well to
develop the potential reserves. We have commenced the drilling of a test well to
a planned true vertical depth of approximately 14,000 feet to evaluate the
initial prospect on this block. If that well is successful, we will also likely
drill a second well this year to evaluate the second prospect on the block.

WEST CAMERON BLOCK 72 PROSPECT. This property is located 11 miles offshore
Louisiana in water depth of 38 feet. We acquired a 100% working interest in West
Cameron Block 72 at the April 1996 federal Central Gulf of Mexico lease sale for
approximately $0.4 million. This prospect targets multiple Miocene-age sands
below a true vertical depth of 10,500 feet. These normally pressured water-drive
reservoirs produced in excess of 100 Bcf of gas and 1.9 MMBbl of condensate
between 1970 and 1995. Utilizing recent 3-D seismic data and conventional well
log analysis, we have identified a prospect that is correlative to those
abandoned wells in an improved structural location. We plan to sell or exchange
interests in the property in order to own between 30% and 50% at the time of
drilling, and anticipate drilling a test well in the second half of 1999 or in
2000.

WEST DELTA BLOCKS 121 AND 122 PROSPECT. These two contiguous blocks are
located on the north flank of a salt dome, found 28 miles offshore Louisiana in
270 feet of water. We acquired a 50% working interest in West Delta Block 122
through a farm-in in mid-1997 and proceeded to exchange one-half of our interest
in the block for an interest in another prospect before drilling. An earlier
lessee of West Delta Block 122 had produced less than one million barrels of oil
and approximately one Bcf of gas from two wells on the block, between 1967 and
1969. We first identified our prospect using 2-D seismic data and then acquired
a 1996 3-D seismic survey prior to negotiating a farm-in.

In the third quarter of 1997, we participated in a successful exploratory
well drilled on West Delta Block 122. A second well followed immediately, to
evaluate a separate prospect on the block. This well was also a discovery, but
the well was ultimately abandoned due to mechanical problems that occurred
during drilling operations. We anticipate that this second well will be
re-drilled at a later date as part of the overall development of the field. In
March 1998, the partners in West Delta Block 122 jointly submitted the high bid
for adjacent West Delta Block 121 at a federal Central Gulf of Mexico lease
sale. We paid approximately $1.6 million for our 25% working interest share of
West Delta Block 121. Development plans for West Delta Blocks 121 and 122
include installation in the third quarter of 1999 of a 12-slot platform capable
of supporting a drilling rig and pipelines to transport production to a nearby
platform for processing. The operator plans to initiate production from the
field in the fourth quarter of 1999, and to resume drilling on the property
later this year or in 2000. In addition to development potential established on
these blocks, the joint owners have identified several prospective exploratory
locations. Future drilling on West Delta Blocks 121 and 122 is expected to
evaluate prospects in Pliocene-age sands trapped against a salt dome that
exhibit anomalies on 3-D seismic data at depths between 9,500 feet and 14,000
feet.

ONSHORE PROSPECTS

We plan to invest approximately 15% of our total capital budget during 1999
in exploration and development activities outside of the Gulf of Mexico. Our
objectives for this diversification are to establish one or more substantial
operating areas to gain increased exposure over time to high quality investment
opportunities, in order to balance our risk profile and enhance shareholder

S-48
<PAGE>
returns. We believe that the current depressed level of capital investments in
the domestic exploration and production industry affords us an unusually
favorable opportunity to gain entry and establish a strategic base of operations
in areas that we assess as having desirable attributes for new investments. We
have identified two principal onshore areas in which we plan to pursue
opportunities that we believe will be complementary to our core activities in
the Gulf of Mexico.

We believe that the onshore Gulf Coast provides one of the best
opportunities for us to establish a new impact area. Many sand formations and
trapping structures in the onshore Gulf Coast are analogous to those found in
the Gulf of Mexico, offering comparable advantages, such as the effectiveness of
3-D seismic data in identifying favorable drilling opportunities. A recent
re-focusing away from this area by several major and large independent oil and
gas companies has resulted in substantial reductions in the cost of 3-D seismic
data and improvements in the availability of exploratory leaseholds. Drilling
and other service costs have also significantly declined from the levels of 1997
and early 1998. Recently, we have negotiated access to 2,000 square miles of 3-D
seismic data covering a prospective area in southern Louisiana. We have also
acquired a 19% working interest in an exploratory prospect that we expect to be
tested later this year. Further, we are negotiating to acquire additional 3-D
seismic data and prospect participation interests.

We will also target certain basins in the Rocky Mountain region where we
believe application of technological advancements can significantly enhance
drilling success rates or reserve recovery factors. Important technological
improvements during the past several years in drilling, completion, fracture
stimulation and 3-D seismic data have been applied in this region to enhance
project returns. An example of this potential is the active basin-centered gas
play in the greater Green River Basin in Wyoming, where tight sands gas
production at some fields has been made economic through improved fracture
stimulation techniques. Basin is currently participating in one exploration play
of this type, at our Powder Mountain Prospect.

POWDER MOUNTAIN PROSPECT. Basin operates this 19,000-acre federal unit,
which is located in the southeast portion of the Greater Green River Basin of
Wyoming. Basin owns a 60% working interest before payout and 45% after project
payout. The main prospect target is the basin-centered, tight-gas sand intervals
of the Lance formation found at depths between 11,400 feet and 12,900 feet.
Three wells previously drilled on or near our acreage block penetrated the Lance
formation, although the wells were targeting deeper objectives. Data from these
earlier wells indicate the presence of up to 400 feet of over-pressured,
gas-saturated tight sand intervals in the Lance Formation.

Basin began drilling its initial well in the unit in late1998, but
subsequently lost the well due to mechanical complications caused by an
abnormally high-pressured sand in a secondary objective just below the Lance
Formation. We abandoned the well and have since drilled and cased a replacement
well, the expense of which was substantially funded by insurance proceeds. Logs
confirm the presence of thick, highly pressured, tight gas sands. We expect to
proceed with multiple fracture stimulation treatments of the Lance formation
after initially testing a formation below the Lance. We identify the principal
risks in this exploratory prospect as the adequacy of sand permeability and
effectiveness of fracture stimulation, which remain undetermined. The stabilized
production tests obtained from these treatments will begin to indicate the
economic viability of the play. If the results are encouraging, future
development could potentially include drilling multiple wells to develop the gas
reserves in place.

S-49
<PAGE>
OIL AND GAS RESERVES

Basin engaged Ryder Scott Company, independent petroleum engineers, to
prepare estimates of proved reserves, projected future production, and related
future net cash flows for certain of our properties as of December 31, 1998, and
to audit Basin's estimates of such data for our remaining properties as of that
date. Ryder Scott Company prepared reserve report estimates for certain of our
oil and gas properties as of December 31, 1998 and audited estimates prepared by
our engineers for our other properties as of that date. Estimates prepared by
Ryder Scott Company or Basin's engineers were based upon a review of production
histories and other geologic, economic, ownership, volumetric and engineering
data. In determining the estimates of the reserves that are economically
recoverable, oil and gas prices and estimated development and production costs
as of December 31, 1998 were utilized.

The following table sets forth estimates as of December 31, 1998 derived
from Basin's reserve reports. The present values (discounted at 10 percent) of
estimated future net cash flows before income taxes shown in the table are not
intended to represent the current market value of the estimated oil and gas
reserves owned by Basin. For further information concerning the present value of
future net cash flows from these proved reserves, see Unaudited Supplemental Oil
and Gas Reserve Information in the December 31, 1998 consolidated financial
statements.

<TABLE>
<CAPTION>
PROVED RESERVES
---------------------------------------
DEVELOPED UNDEVELOPED TOTAL
----------- ------------- -----------
<S> <C> <C> <C>
Oil (MBbls)......................................... 3,352 5,315 8,667
Gas (MMcf).......................................... 103,271 24,231 127,502
Total gas equivalents (MMcfe)....................... 123,383 56,121 179,504

Future net cash flows before income taxes (in
thousands)........................................ $ 170,691 $ 45,413 $ 216,104
Present value of future net cash flows before income
taxes (in thousands).............................. $ 137,775 $ 26,710 $ 164,485
</TABLE>

Since December 31, 1998 oil and gas prices have increased significantly and
the present value of the future net cash flows from our proved reserves has
changed. Based on the New York Mercantile Exchange in effect on May 15, 1999 of
$18.03 per barrel of West Texas Intermediate oil and $2.27 per MMBtu of Henry
Hub gas, the present value of future net cash flows before income taxes of
Basin's net proved reserves at December 31, 1998 would have been $236 million.

The following table shows Basin's total proved reserves at December 31, 1998
and Basin's net production for the year ended December 31, 1998 by geographic
area of operations:

<TABLE>
<CAPTION>
PROVED RESERVES
-------------------------------------------
OIL (MBBLS) GAS (MMCF) TOTAL (MMCFE)
------------- ------------ --------------
<S> <C> <C> <C>
Gulf of Mexico.................................... 4,281 109,626 135,312
Onshore........................................... 4,386 17,876 44,192
----- ------------ --------------
Total............................................. 8,667 127,502 179,504
----- ------------ --------------
----- ------------ --------------
</TABLE>

The weighted average sales prices utilized for purposes of estimating
Basin's proved reserves and future net cash flows therefrom as of December 31,
1998 were $10.31 per Bbl for oil and $1.99 per Mcf for gas. These prices are
below the average prices prevailing during most of 1998, when we realized
average oil and gas prices of $11.80 per Bbl and $2.07 per Mcf, respectively,
before hedging effects.

S-50
<PAGE>
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 producer. 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 and the existence of development plans. In addition,
results of drilling, testing and production subsequent to the date of an
estimate may justify revision of such estimates. Accordingly, reserve estimates
are often different from the quantities of oil and gas that are ultimately
recovered. Further, the estimated future net cash flows from proved reserves and
the present value thereof are based upon certain assumptions, including geologic
success, prices, future production levels and cost, that may not prove correct
over time. Predictions about prices and future production levels are subject to
great uncertainty, and the meaningfulness of such estimates is highly dependent
upon the accuracy of the assumptions upon which they are based. Oil and gas
prices have fluctuated widely in recent years. There is no assurance that prices
will not be materially higher or lower than the prices utilized in estimating
Basin's reserves. See "Risk Factors--Oil and gas prices fluctuate frequently,
and low prices could have a material adverse impact on our business".

ACREAGE

The following table illustrates the gross and net acres of developed and
undeveloped oil and gas leases held by Basin as of December 31, 1998.
Undeveloped acreage includes leasehold interests that may already have been
classified as containing proved undeveloped reserves. A gross acre is one in
which a working interest is owned. A net acre is the sum of the fractional
working interests owned in gross acres.

<TABLE>
<CAPTION>
DEVELOPED ACREAGE(1) UNDEVELOPED ACREAGE
-------------------- --------------------
GROSS NET GROSS NET
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Louisiana offshore.................................................. 71,428 40,624 125,333 97,131
Texas offshore...................................................... 10,440 3,324 11,517 8,351
--------- --------- --------- ---------
Total offshore.................................................... 81,868 43,948 136,850 105,482
--------- --------- --------- ---------
Montana............................................................. -- -- 9,335 7,074
Utah................................................................ 1,810 932 14,979 9,639
Wyoming............................................................. 45,048 25,500 87,489 55,662
Other onshore....................................................... 1,910 883 6,488 2,959
--------- --------- --------- ---------
Total onshore..................................................... 48,768 27,315 118,291 75,334
--------- --------- --------- ---------
Total........................................................... 130,636 71,263 255,141 180,816
--------- --------- --------- ---------
--------- --------- --------- ---------
</TABLE>

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

(1) Developed acreage is acreage assigned to producing wells for the spacing
unit of the producing formation. Developed acreage in certain of Basin's
properties that include multiple formations with different well spacing
requirements may be considered undeveloped for certain formations, but have
only been included as developed acreage in the presentation above.

S-51
<PAGE>
PRODUCTION

The following table sets forth Basin's net oil and gas production, average
sales prices, and costs and expenses associated with such production during the
periods indicated.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1996 1997 1998
--------- --------- ---------
<S> <C> <C> <C>
Production:
Oil (MBbls).................................................................. 564 524 725
Gas (MMcf)................................................................... 4,776 5,509 17,616
Total gas equivalents (MMcfe)................................................ 8,160 8,653 21,966
Average daily net production:
Oil (Bbls)................................................................... 1,540 1,435 1,988
Gas (Mcf).................................................................... 13,050 15,094 48,262
Total gas equivalents (Mcfe)................................................. 22,290 23,704 60,190
Average sales price per unit:(1)
Oil (Bbl).................................................................... $ 20.88 $ 19.07 $ 11.80
Gas (Mcf).................................................................... 1.44 2.71 2.07
Total gas equivalents (Mcfe)................................................. 2.29 2.88 2.05
Production costs per Mcfe(2)................................................... $ 0.81 $ 0.68 $ 0.41
</TABLE>

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

(1) Excluding hedging effects.

(2) Production costs include lease operating expense and production taxes.

Basin owned 306 gross (202 net) producing oil wells and 77 gross (49 net)
producing gas wells as of December 31, 1998. A well is categorized under state
reporting regulations as an oil well or a gas well based upon the ratio of gas
to oil produced when it first commenced production, and such designation may not
be indicative of current production.

DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES

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

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1996 1997 1998
--------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Development costs........................................................... $ 4,472 $ 17,901 $ 22,671
Exploration costs........................................................... 10,250 27,995 58,063
Property acquisition costs:
Unproved(1)............................................................... 5,056 11,057 22,920
Proved.................................................................... 3,067 48,680 3,018
--------- ----------- -----------
Total costs incurred........................................................ $ 22,845 $ 105,633 $ 106,672
--------- ----------- -----------
--------- ----------- -----------
</TABLE>

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

(1) Excludes $4,914,000, $1,113,000 and $150,000 of costs recouped through the
resale of partial interests in prospects to industry partners in 1996, 1997
and 1998, respectively.

S-52
<PAGE>
DRILLING ACTIVITY

The following table sets forth the wells drilled and completed by Basin
during the periods indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------
1996 1997 1998
---------------------- ---------------------- -----------
GROSS NET GROSS NET GROSS
----------- --- ----------- --- -----------
<S> <C> <C> <C> <C> <C>
Development:
Oil................................................................ 3 2.8 5 5.0 1
Gas................................................................ - - 1 0.6 -
Non-productive..................................................... 1 .9 - - -
-- -- -- -- --
Total............................................................ 4 3.7 6 5.6 1
-- -- -- -- --
-- -- -- -- --

Exploratory:
Oil................................................................ - - - - -
Gas................................................................ - - 5 3.2 8
Non-productive..................................................... 3 1.4 3 1.5 5
-- -- -- -- --
Total............................................................ 3 1.4 8 4.7 13
-- -- -- -- --
-- -- -- -- --

NET
---
<S> <C>
Development:
Oil................................................................ 1.0
Gas................................................................ -
Non-productive..................................................... -
--
Total............................................................ 1.0
--
--
Exploratory:
Oil................................................................ -
Gas................................................................ 4.8
Non-productive..................................................... 2.2
--
Total............................................................ 7.0
--
--
</TABLE>

S-53
<PAGE>
MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth the names, ages and titles of the executive
officers and the members of the board of directors of Basin:

<TABLE>
<CAPTION>
NAME AGE POSITION
- ---------------------------------------------------- --------- ----------------------------------------------------
<S> <C> <C>
Michael S. Smith(1)................................. 44 Chairman of the Board, President and Chief Executive
Officer
Neil L. Stenbuck(1)................................. 46 Chief Financial Officer, Treasurer, Vice President
and Director
Howard L. Boigon(1)................................. 52 Vice President-General Counsel, Secretary and
Director
Thomas J. Corley.................................... 39 Vice President-Engineering and Production
Patrick A. Jackson.................................. 46 Vice President-Onshore Exploration
Dalton F. Polasek................................... 47 Vice President-Gulf Coast Engineering
David A. Pustka..................................... 45 Vice President-Gulf Coast Exploration
Samuel D. Winegrad.................................. 40 Vice President-Corporate Development
Donald H. Anderson(2)(3)............................ 50 Director
John F. Greene(2)(3)................................ 58 Director
J. Paul Hellstrom(2)................................ 58 Director
Michael A. Nicolais(2).............................. 73 Director
Larry D. Unruh(2)(3)................................ 48 Director
</TABLE>

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

(1) Member of the Executive Committee.

(2) Member of the Compensation and Incentive Committee.

(3) Member of the Audit Committee.

MICHAEL S. SMITH is Chairman of the Board, President, Chief Executive
Officer, a director and a founder of Basin. Mr. Smith has been Chairman of the
Board since 1983 and has been a director since inception. Mr. Smith was elected
President and Chief Executive Officer in 1988. Mr. Smith is past president and a
director of the Colorado Oil and Gas Association and served on the State of
Colorado Governor's Minerals, Energy & Geology Policy Advisory Board.

NEIL L. STENBUCK is Vice President-Finance, Chief Financial Officer,
Treasurer and a director of Basin. He joined Basin in 1995. He was previously
with United Meridian Corporation where he served as vice president--capital via
the 1994 merger between UMC and General Atlantic Resources, Inc., where he held
the same position beginning in 1989. He joined General Atlantic in 1987 as vice
president--finance and accounting. Mr. Stenbuck is a certified public
accountant.

HOWARD L. BOIGON is Vice President-General Counsel, Secretary and a director
of Basin. Mr. Boigon joined Basin in March 1992. Previously, he had been a
partner in the Denver office of Davis, Graham & Stubbs since 1978, having been
with the firm since 1973 specializing in the practice of oil and gas law. Mr.
Boigon began representing Basin as outside counsel in 1989. He is past president
and currently a director of the Colorado Oil and Gas Association, a member of
the Executive Committee of RMOGA-Colorado and a member of the Advisory Board of
the International Oil and Gas Educational Center of the Southwestern Legal
Foundation. He has served as Chair of the Mineral Law Section of the Colorado
Bar Association and Trustee of the Rocky Mountain Mineral Law Foundation. He has
lectured and written on various topics of oil and gas law.

S-54
<PAGE>
THOMAS J. CORLEY is Vice President-Engineering and Production of Basin. He
joined Basin in March 1996. For the previous three years he was vice
president-manager of engineering at St. Mary Land & Exploration Company where he
was responsible for the acquisition efforts and engineering functions of the
company. From 1983 to 1993 he held various positions of increasing
responsibility at General Atlantic Resources, Inc., involving operations,
acquisitions and reservoir engineering and served there last as director of
acquisitions. Mr. Corley is a member of the Society of Petroleum Engineers and
served as a distinguished panel member at the 1995 SPE Annual Meeting.

PATRICK A. JACKSON is Vice President-Onshore Exploration. Mr. Jackson joined
Basin in February 1999. He spent the previous 19 years actively exploring in the
United States and around the world with Amoco Production Company. From 1996 to
1999 Mr. Jackson was a member of a small team that evaluated the risks and
opportunities of prospects in Amoco's worldwide portfolio. From 1993 to 1996 he
served as Amoco's Onshore United States Exploration Manager. Prior to 1993, his
responsibilities included prospect generation and evaluation, and management in
the western United States.

DALTON F. POLASEK, JR. is Vice President-Gulf Coast Engineering of Basin.
Mr. Polasek has been employed in that position since February 1996. From 1994 to
1996, he was employed by SMR Energy Income Funds, as vice president of
engineering. From 1991 to 1994, Mr. Polasek served as the director of Gulf Coast
acquisitions/engineering for General Atlantic Resources. Prior to joining
General Atlantic, Mr. Polasek served as manager of planning and business
development for Mark Producing Company from 1983 to 1991.

DAVID A. PUSTKA is Vice President-Gulf Coast Exploration and Gulf Coast
Division Manager of Basin. He joined Basin in November 1995. From 1992 to 1995
he was vice president in charge of United States exploration for British-Borneo
Exploration, Inc., a wholly-owned subsidiary of British-Borneo Petroleum
Syndicate, PLC. From 1983 to 1992, he was responsible for exploration activities
at Walter Oil & Gas Corporation, a privately held Gulf of Mexico exploration
company, becoming a vice president in 1990. Mr. Pustka is a member of the
American Association of Petroleum Geologists and the Houston Geological Society.

SAM D. WINEGRAD is Vice President-Corporate Development of Basin. He joined
Basin in August 1995. Mr. Winegrad was previously with United Meridian
Corporation where he was vice president-land, the same position he occupied at
General Atlantic Resources, Inc. at the time of its merger in 1994 with UMC. He
joined General Atlantic in 1987 and became vice president-land the same year.

DONALD H. ANDERSON is a director of Basin. He was elected to that position
in November 1997. He is the executive director and a principal of Western Growth
Capital LLC, a Colorado-based private equity investment and consulting firm. He
joined WGC in March 1997 and has assumed responsibility for the firm's private
equity and consulting services activities. Prior to joining WGC, Mr. Anderson
was chairman, president and chief executive officer of PanEnergy Services,
PanEnergy's non-jurisdictional operating subsidiary, from December 1994 until
PanEnergy's announced merger with Duke Energy in March 1997. In that capacity,
he was responsible for PanEnergy's gas and electric marketing, gas gathering and
processing, and crude oil and gas liquids trading and pipeline transportation
activities. Mr. Anderson was previously president, chief operating officer and
director of Associated Natural Gas Corporation, the primary purchaser of our
production in the Denver-Julesberg Basin, from 1989 until its merger with
PanEnergy in 1994. He is a director of Genesis Energy, LLC.

JOHN F. GREENE is a director of Basin. He was elected to that position in
February 1996. From 1985 until his retirement in 1995, he served as executive
vice president of exploration and production for the Louisiana Land and
Exploration Company, where he served on the board of directors from 1989 until
his retirement. From 1981 to 1985, Mr. Greene was president and chief executive

S-55
<PAGE>
officer for Milestone Petroleum and then executive vice president of exploration
for Meridian Oil and Gas Company via its merger with Milestone. He began his
career at Continental Oil Company holding various positions including director
of exploratory projects for onshore and offshore offices and division
exploration manager for the western United States. Mr. Greene serves as a
director of the Colorado Wyoming Reserve Company, an oil and gas exploration
company.

J. PAUL HELLSTROM is a director of Basin. He was elected to that position in
March 1992. Mr. Hellstrom was employed by The First Boston Corporation from 1975
to 1989. At the time of his retirement in 1989, Mr. Hellstrom was co-head of
First Boston's Real Estate Group, earlier having served as head of its Energy
and Project Finance Groups. Prior to joining First Boston, he was a first vice
president in charge of the Project Finance Group at Blyth Eastman Dillon & Co.,
Inc. and an Assistant Treasurer with Manufacturers Hanover Trust Company. Mr.
Hellstrom currently serves as a director of First Reserve Corporation. First
Reserve is a direct investor in natural resource and energy-related industries.

MICHAEL A. NICOLAIS is a director of Basin. He was elected to that position
in March 1992. Since April 1993 he has been employed by Carret & Co., Inc. as
Senior Managing Director. From June 1991 to April 1993, he was employed by
Goldman Capital Management, Inc. as Managing Director. From 1949 to 1991, Mr.
Nicolais was employed by The Clark Estates, Inc., serving as president from 1968
to 1990. Mr. Nicolais served as a director of Mesa Petroleum Company from 1969
until 1984. He serves as a director of Hitox Corp. of America.

LARRY D. UNRUH is a director of Basin. He was elected to that position in
March 1992. Since 1982 he has been the managing tax partner at Hein +
Associates, certified public accountants. During 1980 and 1981, he was chief
financial officer of Otis Energy Inc. Prior to 1980, Mr. Unruh held tax and
accounting positions with Hein + Associates, Coopers & Lybrand and Peat, Marwick
Mitchell & Co. Mr. Unruh is a certified public accountant and is a member of the
Federal Tax Division of American Institute of Certified Public Accountants. Mr.
Unruh serves as a director of Altris Software, Inc., an electronic imaging
company.

S-56
<PAGE>
SELLING STOCKHOLDER

The following table sets forth certain information regarding the beneficial
ownership of the common stock as of June 17, 1999, and as adjusted to reflect
the offering of 250,000 shares by the selling stockholder, Michael S. Smith, the
Chairman of the Board, President, and Chief Executive Officer of Basin, and
3,750,000 shares by Basin:

<TABLE>
<CAPTION>
SHARES BENEFICIALLY SHARES BENEFICIALLY
OWNED PRIOR TO THE OWNED AFTER THE
OFFERING OFFERING(2)
------------------------ NUMBER OF SHARES TO BE ------------------------
SELLING STOCKHOLDER NUMBER PERCENT SOLD IN THE OFFERING NUMBER PERCENT
- ----------------------------------------- ----------- ----------- ---------------------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Michael S. Smith(1) ..................... 3,036,229 21.4 250,000 2,786,229 15.6
Suite 3400
370 Seventeenth St.
Denver, CO 80202
</TABLE>

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

(1) Includes 2,390,628 shares held by Mr. Smith; 304,300 shares held by Iris
Smith, Mr. Smith's wife; 96,000 shares held by trusts for Mr. Smith's
children, of which Mr. Smith is trustee; 4,000 shares held by Mr. Smith's
children; and 76,468 shares held by KaiTar Foundation, a nonprofit
charitable foundation of which Mrs. Smith is president and Mr. Smith is
vice-president. Mr. Smith has no voting or investment power with respect to
the shares held by Iris Smith and disclaims beneficial ownership of such
shares. Mr. Smith, in his capacity as the trustee of the trusts for his
children and as vice president of KaiTar Foundation, has voting and
investment power with respect to the shares held in such capacity and may be
deemed to be the beneficial owner of such shares but disclaims beneficial
ownership of such shares. Also includes options for 94,167 shares
exercisable within 60 days, 10,666 shares of restricted stock the
restrictions on which lapse on February 3, 2000, and 60,000 performance
shares, the restrictions on which lapse December 31, 1999, December 31, 2000
and December 31, 2001 in equal amounts of 20,000 shares per year.

(2) Excludes the underwriters' option to purchase up to 562,500 additional
shares from Basin and up to 37,500 additional shares from Mr. Smith pursuant
to the terms of the underwriting agreement. If this option is exercised in
full, Mr. Smith will beneficially own 2,748,729 shares or 14.9% of the
common stock.

The preceding information regarding the selling stockholder supersedes the
information under the heading "Selling Stockholder" in the accompanying
prospectus.

EXPERTS

The consolidated financial statements for each of the three years ended
December 31, 1998 included 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 giving said report.

Estimates of Basin's historical onshore oil and gas reserves as of December
31, 1995, 1996 and 1997 are based upon engineering studies prepared by Basin and
audited by the independent engineering firm of Netherland Sewell & Associates,
Inc. Estimates of historical offshore reserves of Basin as of December 31, 1996,
1997 and 1998 and onshore oil and gas reserves as of December 31, 1998 are based
upon engineering studies either prepared by the independent engineering firm of
Ryder Scott Company Petroleum Engineers or prepared by Basin and audited by
Ryder Scott Company Petroleum Engineers. Such estimates are included in reliance
upon the authority of such firms as experts in such matters.

VALIDITY OF COMMON STOCK

The validity of the shares of common stock offered hereby will be passed
upon for Basin by Davis, Graham & Stubbs LLP, Denver, Colorado. The validity of
the shares of common stock offered hereby will be passed upon for the
underwriters by Sullivan & Cromwell, New York, New York.

S-57
<PAGE>
INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
---------
<S> <C>
Interim Consolidated Financial Statements (Unaudited):

Consolidated Statements of Operations for the three months ended March 31, 1998 and 1999................... F-1

Consolidated Balance Sheets as of December 31, 1998 and March 31, 1999..................................... F-2

Consolidated Statements of Cash Flow for the three months ended March 31, 1998 and 1999.................... F-3

Consolidated Statements of Changes in Stockholders' Equity for the period from January 1, 1998 through
March 31, 1999........................................................................................... F-4

Notes to Consolidated Financial Statements................................................................. F-5

Audited Consolidated Financial Statements:

Report of Independent Public Accountants................................................................... F-6

Consolidated Statements of Operations for the years ended December 31, 1996, 1997, and 1998................ F-7

Consolidated Balance Sheets as of December 31, 1997 and 1998............................................... F-8

Consolidated Statements of Cash Flow for the years ended December 31, 1996, 1997 and 1998.................. F-9

Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 1996, 1997 and
1998..................................................................................................... F-10

Notes to Consolidated Financial Statements................................................................. F-11
</TABLE>

F-i
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
FOR THE THREE MONTHS
ENDED
MARCH 31,
--------------------
1998 1999
--------- ---------
<S> <C> <C>
(IN THOUSANDS,
EXCEPT PER SHARE
DATA)
REVENUE:
Oil sales.................................................................................. $ 2,690 $ 2,246
Gas sales.................................................................................. 7,545 10,796
Interest and other......................................................................... 21 13
--------- ---------
10,256 13,055
--------- ---------
COSTS AND EXPENSES:
Lease operating expenses................................................................... 2,143 2,455
Production taxes........................................................................... 234 76
Depreciation, depletion and amortization................................................... 5,986 8,546
General and administrative, net............................................................ 1,112 1,427
Interest expense........................................................................... 413 949
--------- ---------
9,888 13,453
--------- ---------
INCOME (LOSS) BEFORE INCOME TAXES.......................................................... 368 (398)
Income tax provision....................................................................... 129 --
--------- ---------
NET INCOME (LOSS).......................................................................... $ 239 $ (398)
--------- ---------
--------- ---------
BASIC:
Earnings (loss) per share................................................................ $ 0.02 $ (0.03)
Weighted average shares outstanding...................................................... 13,784 13,973
DILUTED:
Earnings (loss) per share................................................................ $ 0.02 $ (0.03)
Weighted average shares outstanding...................................................... 14,237 13,973
</TABLE>

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

F-1
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 1998 AND MARCH 31, 1999

<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
1998 1999
-------------- ------------
<S> <C> <C>
(IN THOUSANDS, EXCEPT SHARE
DATA)
ASSETS
CURRENT ASSETS:
Cash and equivalents.............................................................. $ 331 $ 20
Accounts receivable............................................................... 10,036 9,227
Prepaids and other................................................................ 2,752 3,791
-------------- ------------
13,119 13,038
-------------- ------------
PROPERTY AND EQUIPMENT, at cost:
Oil and gas properties, under the full cost method of accounting
Proved.......................................................................... 265,826 287,299
Unproved........................................................................ 34,039 33,902
Less accumulated depreciation, depletion and amortization......................... (113,462) (121,819)
-------------- ------------
186,403 199,382
Furniture and equipment, net...................................................... 1,408 1,306
-------------- ------------
187,811 200,688
-------------- ------------
OTHER ASSETS........................................................................ 233 1,117
-------------- ------------
$ 201,163 $ 214,843
-------------- ------------
-------------- ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable.................................................................. $ 12,465 $ 14,409
Accrued liabilities............................................................... 13,620 14,930
Current portion of long-term debt................................................. 258 156
-------------- ------------
26,343 29,495
-------------- ------------
LONG-TERM DEBT, net of current portion.............................................. 80,000 91,000
OTHER LONG-TERM OBLIGATIONS......................................................... 601 45
STOCKHOLDERS' EQUITY:
Preferred stock, par value $.01 per share; 10,000,000 shares authorized, no shares
issued and outstanding.......................................................... -- --
Common stock, par value $.01 per share, 50,000,000 shares authorized, 14,151,000
and 14,213,000 shares issued, respectively...................................... 142 142
Additional paid-in capital........................................................ 113,136 113,618
Accumulated deficit............................................................... (16,488) (16,886)
Common stock held in treasury, at cost, 186,000 shares............................ (2,571) (2,571)
-------------- ------------
94,219 94,303
-------------- ------------
$ 201,163 $ 214,843
-------------- ------------
-------------- ------------
</TABLE>

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

F-2
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW

<TABLE>
<CAPTION>
FOR THE THREE MONTHS
ENDED
MARCH 31,
----------------------
1998 1999
---------- ----------
<S> <C> <C>
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)...................................................................... $ 239 $ (398)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities--
Depreciation, depletion and amortization............................................. 5,986 8,546
Deferred income tax expense.......................................................... 129 --
Stock compensation expense........................................................... 202 254
Other................................................................................ -- 16
---------- ----------
6,556 8,418
Changes in operating assets and liabilities--
Decrease (increase) in--
Receivables........................................................................ (6,104) 809
Prepaids and other................................................................. 174 (939)
(Decrease) increase in--
Accounts payable and accrued expenses.............................................. 657 2,982
Ad valorem taxes and other......................................................... (273) 4
---------- ----------
Net cash provided by operating activities............................................ 1,010 11,274
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital additions...................................................................... (23,281) (23,977)
Deposits on offshore leases............................................................ (3,989) (566)
Proceeds from sale of property and equipment........................................... 20 2,438
---------- ----------
Net cash used in investing activities................................................ (27,250) (22,105)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable and long-term debt......................................... 31,500 23,500
Principle payments on notes payable and long-term debt................................. (5,538) (12,602)
Proceeds from sale of stock............................................................ -- 62
Debt issuance costs and other.......................................................... (5) (440)
---------- ----------
Net cash provided by financing activities............................................ 25,957 10,520
---------- ----------
DECREASE IN CASH AND EQUIVALENTS......................................................... (283) (311)
CASH AND EQUIVALENTS, beginning of period................................................ 531 331
---------- ----------
CASH AND EQUIVALENTS, end of period...................................................... $ 248 $ 20
---------- ----------
---------- ----------
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest................................................................. $ 283 $ 1,369
---------- ----------
---------- ----------
Cash paid for income taxes............................................................. $ -- $ --
---------- ----------
---------- ----------
</TABLE>

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

F-3
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
FOR THE PERIOD FROM JANUARY 1, 1998 THROUGH MARCH 31, 1999

<TABLE>
<CAPTION>
RETAINED
COMMON STOCK ADDITIONAL TREASURY STOCK EARNINGS TOTAL
---------------------- PAID-IN ---------------------- (ACCUMULATED STOCKHOLDERS'
SHARES AMOUNT CAPITAL SHARES AMOUNT DEFICIT) EQUITY
--------- ----------- ----------- ----------- --------- -------------- --------------
<S> <C> <C> <C> <C> <C> <C> <C>
(IN THOUSANDS)
BALANCES, January 1, 1998............. 13,833 $ 138 $ 110,627 (120) $ (1,412) $ 12,012 $ 121,365
Issuance of common stock.............. 130 2 627 -- -- -- 629
Exercise of warrants for common
stock............................... 79 1 1,107 (62) (1,108) -- --
Purchase of treasury stock............ -- -- -- (4) (51) -- (51)
Issuance and vesting of restricted
stock............................... 109 1 775 -- -- -- 776
Net income (loss)..................... -- -- -- -- -- (28,500) (28,500)
--------- ----- ----------- --- --------- -------------- --------------
BALANCES, December 31, 1998........... 14,151 142 113,136 (186) (2,571) (16,488) 94,219
Issuance of common stock.............. 12 -- 62 -- -- -- 62
Issuance and vesting of restricted
stock............................... 50 -- 420 -- -- -- 420
Net income (loss)..................... -- -- -- -- -- (398) (398)
--------- ----- ----------- --- --------- -------------- --------------
BALANCES, March 31, 1999.............. 14,213 $ 142 $ 113,618 (186) $ (2,571) $ (16,886) $ 94,303
--------- ----- ----------- --- --------- -------------- --------------
--------- ----- ----------- --- --------- -------------- --------------
</TABLE>

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

F-4
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) UNAUDITED FINANCIAL STATEMENTS

In the opinion of management, the accompanying unaudited consolidated
financial statements contain all adjustments (consisting only of normal
recurring items) necessary to present fairly the financial position of Basin
Exploration, Inc. and its wholly-owned subsidiaries as of March 31, 1999, and
the results of operations and cash flows for the three-month periods presented.
Certain information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted pursuant to the Securities and Exchange
Commission's rules and regulations. The results of operations for the periods
presented are not necessarily indicative of the results to be expected for the
full year. Management believes the disclosures made are adequate to ensure that
the information is not misleading and suggests that these financial statements
be read in conjunction with Basin's Consolidated Financial Statements and Notes
for the three years in the period ended December 31, 1998 included elsewhere in
this prospectus supplement.

(2) ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities. The Statement establishes accounting and reporting
standards requiring that every derivative instrument including certain
derivative instruments embedded in other contracts be recorded on the balance
sheet as either an asset or liability measured at its fair value and that
changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Basin is required to adopt
the statement as of January 1, 2000, but may implement the Statement as of the
beginning of any fiscal quarter prior to that date. Statement 133 cannot be
applied retroactively. Basin has not yet quantified the impacts of adopting
Statement 133 or determined the timing or method of adoption. However, Statement
133 could increase the volatility of the Company's earnings and other
comprehensive income.

(3) ACCOUNTING FOR OIL AND GAS PROPERTIES

Basin follows the full cost method of accounting for oil and gas properties.
Under this method, all costs associated with the acquisition, exploration and
development of oil and gas properties are capitalized. If capitalized costs, net
of amortization and related deferred taxes, exceed the full cost ceiling, the
excess would be expensed in the period such excess occurs. Calculation of the
full cost ceiling includes an estimate of the discounted value of future net
cash flows attributable to proved reserves using various assumptions and
parameters consistent with promulgations of the Securities and Exchange
Commission, and such calculation is sensitive to changes in prevailing oil and
gas sales prices. Oil and natural gas prices are volatile and reflect seasonal
factors, as well as other supply and demand conditions. A decline in prices
subsequent to April 1, 1999 could result in a requirement that Basin recognize
an impairment expense in a future period.

F-5
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders and Board of Directors of
Basin Exploration, Inc.:

We have audited the accompanying consolidated balance sheets of Basin
Exploration, Inc. and subsidiaries as of December 31, 1998 and 1997, and the
related consolidated statements of operations, changes in stockholders' equity
and cash flow for each of the three years in the period ended December 31, 1998.
These consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the consolidated financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the consolidated 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 consolidated financial position of
Basin Exploration, Inc. and subsidiaries as of December 31, 1998 and 1997, and
the results of their operations and their cash flow for each of the three years
in the period ended December 31, 1998, in conformity with generally accepted
accounting principles.

ARTHUR ANDERSEN LLP

Denver, Colorado,
February 24, 1999.

F-6
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1996 1997 1998
--------- --------- ----------
(IN THOUSANDS, EXCEPT PER SHARE
DATA)
<S> <C> <C> <C>
REVENUE:
Oil sales................................................................... $ 11,292 $ 9,844 $ 9,735
Gas sales................................................................... 6,890 14,557 38,885
Gain on sale of assets...................................................... 22,472 -- --
Interest and other.......................................................... 1,009 319 79
--------- --------- ----------
41,663 24,720 48,699
--------- --------- ----------
COSTS AND EXPENSES:
Lease operating expenses.................................................... 4,776 4,600 8,276
Production taxes............................................................ 1,829 1,260 770
Depreciation, depletion and amortization.................................... 7,606 10,622 29,775
General and administrative, net............................................. 3,850 3,694 4,380
Interest and other.......................................................... 2,272 764 2,030
Property impairment......................................................... -- -- 38,500
--------- --------- ----------
20,333 20,940 83,731
--------- --------- ----------
INCOME (LOSS) BEFORE INCOME TAXES............................................. 21,330 3,780 (35,032)
Income tax (provision) benefit................................................ (5,760) (1,324) 6,532
--------- --------- ----------
NET INCOME (LOSS)............................................................. $ 15,570 $ 2,456 $ (28,500)
--------- --------- ----------
--------- --------- ----------
BASIC:
Earnings (loss) per share................................................... $ 1.45 $ 0.22 $ (2.06)
Weighted average shares outstanding......................................... 10,700 11,228 13,859
DILUTED:
Earnings (loss) per share................................................... $ 1.45 $ 0.22 $ (2.06)
Weighted average shares outstanding......................................... 10,730 11,345 13,859
</TABLE>

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

F-7
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1997 1998
----------- ------------
(IN THOUSANDS, EXCEPT PER
SHARE DATA)
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and equivalents................................................................. $ 531 $ 331
Accounts receivable.................................................................. 8,348 10,036
Prepaids and other................................................................... 3,805 2,752
----------- ------------
12,684 13,119
----------- ------------
PROPERTY AND EQUIPMENT, at cost:
Oil and gas properties, under the full cost method of accounting
Proved............................................................................. 177,704 265,826
Unproved........................................................................... 15,669 34,039
Less accumulated depreciation, depletion and amortization............................ (46,284) (113,462)
----------- ------------
147,089 186,403
Furniture and equipment, net......................................................... 2,086 1,408
----------- ------------
149,175 187,811
OTHER ASSETS........................................................................... 100 233
----------- ------------
$ 161,959 $ 201,163
----------- ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable..................................................................... $ 8,087 $ 12,465
Accrued liabilities.................................................................. 12,067 11,998
Accrued ad valorem taxes............................................................. 2,394 1,622
Income taxes payable................................................................. 19 --
Current portion of long-term debt.................................................... 153 258
----------- ------------
22,720 26,343
LONG-TERM DEBT, net of current portion................................................. 11,053 80,000
OTHER LONG-TERM OBLIGATIONS............................................................ 266 601
DEFERRED INCOME TAXES.................................................................. 6,555 --
COMMITMENTS AND CONTINGENCIES (Note 5)
STOCKHOLDERS' EQUITY:
Preferred stock, par value $.01 per share; 10,000,000 shares authorized, no shares
issued and outstanding............................................................. -- --
Common stock, $.01 par value, 50,000,000 shares authorized, 13,833,000 and 14,151,000
shares issued, respectively........................................................ 138 142
Additional paid-in capital........................................................... 110,627 113,136
Retained earnings (accumulated deficit).............................................. 12,012 (16,488)
Common stock held in treasury, at cost, 120,000 and 186,000 shares, respectively..... (1,412) (2,571)
----------- ------------
121,365 94,219
----------- ------------
$ 161,959 $ 201,163
----------- ------------
----------- ------------
</TABLE>

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

F-8
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW

<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
-------------------------------------
1996 1997 1998
----------- ---------- ------------
(IN THOUSANDS)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)....................................................... $ 15,570 $ 2,456 $ (28,500)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities--
Gain on sale of assets................................................ (22,472) -- --
Depreciation, depletion and amortization.............................. 7,606 10,622 29,775
Deferred income tax expense (benefit)................................. 4,760 1,795 (6,555)
Property impairment................................................... -- 38,500
Stock compensation expense............................................ 98 439 452
Amortization of debt issuance costs................................... 118 -- --
Other................................................................. -- (15) (14)
----------- ---------- ------------
5,680 15,297 33,658
Changes in operating assets and liabilities--
Decrease (increase) in--
Restricted cash..................................................... 578 -- --
Receivables......................................................... 1,664 (3,188) (1,693)
Prepaids and other.................................................. (1,861) (1,438) 919
(Decrease) increase in--
Accounts payable and accrued liabilities............................ 103 5,692 5,406
Ad valorem taxes and other.......................................... (2,255) 107 (437)
Income taxes payable................................................ 1,000 (981) (19)
----------- ---------- ------------
Net cash provided by operating activities............................. 4,909 15,489 37,834
----------- ---------- ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital additions....................................................... (27,741) (98,245) (107,716)
Proceeds from sale of property and equipment............................ 125,625 195 52
Asset sale transaction costs............................................ (5,257) -- --
----------- ---------- ------------
Net cash provided by (used in) investing activities................... 92,627 (98,050) (107,664)
----------- ---------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable and long-term debt.......................... 8,594 53,000 85,245
Principal payments on notes payable..................................... (85,517) (42,218) (16,193)
Proceeds from sale of stock, net........................................ 84 50,320 629
Purchase of treasury stock and options.................................. (287) (33) (51)
----------- ---------- ------------
Net cash provided by (used in) financing activities................... (77,126) 61,069 69,630
----------- ---------- ------------
INCREASE (DECREASE) IN CASH AND EQUIVALENTS............................... 20,410 (21,492) (200)
CASH AND EQUIVALENTS, beginning of year................................... 1,613 22,023 531
----------- ---------- ------------
CASH AND EQUIVALENTS, end of year......................................... $ 22,023 $ 531 $ 331
----------- ---------- ------------
----------- ---------- ------------
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest.................................................. $ 2,327 $ 637 $ 3,133
Cash paid for taxes..................................................... $ -- $ 981 $ (23)
</TABLE>

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

F-9
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31, 1996, 1997 AND 1998
-------------------------------------------------------------------------------------------
RETAINED
COMMON STOCK ADDITIONAL TREASURY STOCK EARNINGS
---------------------- PAID-IN ---------------------- (ACCUMULATED STOCKHOLDERS'
SHARES AMOUNT CAPITAL SHARES AMOUNT DEFICIT) EQUITY
--------- ----------- ----------- ----------- --------- -------------- --------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCES, December 31, 1995........... 10,724 $ 107 $ 59,288 (32) $ (94) $ (6,014) $ 53,287
Purchase of treasury stock and
options........................... -- -- (250) (24) (38) -- (288)
Issuance and vesting of restricted
stock and stock options........... 33 1 181 -- -- -- 182
Net income.......................... -- -- -- -- -- 15,570 15,570
--------- ----- ----------- --- --------- -------------- --------------
BALANCES, December 31, 1996........... 10,757 108 59,219 (56) (132) 9,556 68,751
Issuance of common stock............ 3,001 30 51,340 -- -- -- 51,370
Common stock offering costs......... -- -- (499) -- -- -- (499)
Purchase of treasury stock.......... -- -- -- (64) (1,280) -- (1,280)
Issuance and vesting of restricted
stock............................. 75 -- 567 -- -- -- 567
Net income.......................... -- -- -- -- -- 2,456 2,456
--------- ----- ----------- --- --------- -------------- --------------
BALANCES, December 31, 1997........... 13,833 138 110,627 (120) (1,412) 12,012 121,365
Issuance of common stock............ 130 2 627 -- -- -- 629
Exercise of warrants for common
stock............................. 79 1 1,107 (62) (1,108) -- --
Purchase of treasury stock.......... -- -- -- (4) (51) -- (51)
Issuance and vesting of restricted
stock............................. 109 1 775 -- -- -- 776
Net income (loss)................... -- -- -- -- -- (28,500) (28,500)
--------- ----- ----------- --- --------- -------------- --------------
BALANCES, December 31, 1998........... 14,151 $ 142 $ 113,136 (186) $ (2,571) $ (16,488) $ 94,219
--------- ----- ----------- --- --------- -------------- --------------
--------- ----- ----------- --- --------- -------------- --------------
</TABLE>

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

F-10
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION AND OPERATIONS--The consolidated financial statements include
the financial statements of Basin Exploration, Inc. and its wholly owned
subsidiaries (collectively referred to as "Basin"). Basin operates its business
and reports its operations as one business segment. Basin is engaged in the
exploration, development and production of natural gas and crude oil. Basin's
principal producing area is offshore in the Gulf of Mexico. Basin, as operator
of jointly-owned oil and gas properties, sells a significant amount of such
production to certain major customers (see Note 8), and pays vendors for oil and
gas services. Joint interest receivables are subject to collection under terms
of operating agreements which generally provide lien rights.

The accompanying financial statements present the operations of Basin on a
consolidated basis. All significant intercompany accounts and transactions have
been eliminated in consolidation. 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.

CASH EQUIVALENTS--Cash equivalents are comprised of highly liquid
instruments with original maturities of three months or less. The total carrying
amount of cash and equivalents approximates the fair value of such instruments.

OIL AND GAS PROPERTIES--Basin follows the full cost method of accounting for
oil and gas properties. Under this method, all costs associated with the
development, exploration and acquisition of oil and gas properties are
capitalized in Basin's one cost center (full cost pool), which is the
continental United States including the Gulf of Mexico. Payroll and other
internal costs capitalized include salaries and related fringe benefits paid to
employees directly engaged in the acquisition, exploration and development of
oil and gas properties as well as all other directly identifiable, internal
costs associated with these activities. Payroll and other internal costs
associated with production operations and general corporate activities are
expensed in the period incurred. Future development, site restoration,
dismantlement and abandonment costs, net of salvage values, are estimated on a
property-by-property basis based on prevailing prices and are amortized to
expense, along with the capitalized costs discussed above, using the
unit-of-production method based upon actual production and estimates of proved
reserve quantities. Accumulated depreciation, depletion and amortization is
recorded on the balance sheet as a reduction to property, plant and equipment
costs. Basin invests in unevaluated oil and gas properties and related assets
for the purpose of future exploration for proved reserves. The costs of such
assets are included in unproved oil and gas properties at the lower of cost or
estimated fair market value and are not subject to amortization. Proceeds from
sales of oil and gas properties are credited to the full cost pool with no gain
or loss recognized unless such adjustments would significantly alter the
relationship between capitalized costs and proved reserves of oil and gas.

Under full cost accounting rules promulgated by the Securities and Exchange
Commission, if net capitalized costs of oil and gas properties, less related
deferred income taxes, exceed the full cost ceiling at the end of a fiscal
quarter, the excess is charged to expense in that period. The full cost ceiling
is calculated as the estimated present value of future net cash flows from
proved oil and gas reserves using a 10% discount factor and unescalated oil and
gas prices as of the end of the period, or shortly thereafter, plus the book
value of unproved oil and gas properties. Calculation

F-11
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
of the full cost ceiling may be particularly sensitive to changes in expected
production rates or the level of oil and gas prices, which may be volatile due
to seasonal factors and other influences.

Basin recognized a $38,500,000 non-cash impairment charge ($30,750,000 after
income tax) for the quarter ended December 31, 1998, based on a ceiling test
calculation that utilized average realized prices of $10.23 per barrel of oil
and $1.87 per Mcf of natural gas. A decline in prices could result in a
requirement that Basin recognize additional impairment expense in a future
period.

FURNITURE AND EQUIPMENT--Furniture and equipment are depreciated over
estimated useful lives of four to seven years. Maintenance and repair costs are
expensed as incurred.

INCOME TAXES--Basin computes income taxes in accordance with Statement of
Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes."
SFAS 109 requires an asset and liability approach which results in the
recognition of deferred tax liabilities and assets for the expected future tax
consequences of temporary differences between the carrying amounts and the tax
bases of those assets and liabilities. SFAS 109 also requires the recording of a
valuation allowance if it is more likely than not that some portion or all of a
deferred tax asset will not be realized.

HEDGING ACTIVITIES--Basin periodically enters into commodity derivative
contracts and fixed-price physical contracts to manage its exposure to oil and
gas price volatility. Commodity derivatives contracts, which are placed with
major financial institutions or other counterparties of high credit quality that
Basin believes are minimal credit risks, may take the form of futures contracts,
swaps or options. The reference prices of these commodity derivatives contracts
are based upon crude oil and natural gas futures which have a high degree of
historical correlation with actual prices received by Basin. Basin accounts for
its commodity derivatives contracts using the hedge (deferral) method of
accounting. Under this method, realized gains and losses from Basin's price risk
management activities are recognized in oil and gas revenue when the associated
production occurs and the resulting cash flows are reported as cash flows from
operating activities. Gains and losses from commodity derivatives contracts that
are closed before the hedged production occurs are deferred until the production
month originally hedged. 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 would be recognized currently to the
extent the commodity derivatives contract did not offset changes in actual oil
and gas prices.

Basin recognized a reduction in oil revenue of $480,000 and $144,000 under
hedging agreements in 1996 and 1997, respectively. Basin recognized a reduction
in gas revenue of $383,000 under hedging agreements in 1997. Basin recognized
increases in oil and gas revenue of $1,175,000 and $2,357,000, respectively,
under hedging agreements in 1998.

F-12
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
As of February 24, 1999, Basin was a party to the following fixed price swap
arrangements (one MMBtu approximates one Mcf of natural gas):

<TABLE>
<CAPTION>
OIL GAS
-------------------------- ------------------------------
AVERAGE DAILY AVERAGE DAILY
TIME PERIOD VOLUME (BBL) $/BBL VOLUME (MMBTU) $/MMBTU
- --------------------------------------------------------- --------------- --------- ----------------- -----------
<S> <C> <C> <C> <C>
1/1/99 -- 3/31/99........................................ 1,000 17.00 30,167 2.15
4/1/99 -- 6/30/99........................................ 1,000 17.00 33,297 2.18
7/1/99 -- 9/30/99........................................ 30,000 2.20
10/1/99 -- 12/31/99...................................... 25,000 2.16
1/1/00 -- 12/31/01....................................... 10,000 2.15
</TABLE>

In addition, Basin periodically enters into spread trades or options
transactions related to oil or natural gas futures markets. Under a spread
trade, fixed prices under a hedging contract are determined in the future by
reference to the price of an underlying contract. Such positions may enable
Basin to lock in favorable fixed prices for future hedging positions, but can
also result in unfavorable fixed price contracts if the reference price
represented by the underlying contract declines. As of February 24, 1999, Basin
had entered into spread trades for natural gas providing for a fixed price for
20,000 MMBtu per day for the period of March 2000 through September 2000 to be
established in the future upon an election by Basin by reference to the
underlying NYMEX October 1999 contract price less $0.28. Basin also had sold
call options for 10,000 MMBtu of natural gas per day for the period from March
1999 through April 1999 with a strike price of $1.93 per MMBtu, and from January
1999 through December 2001 with an average strike price of $2.50 per MMBtu. Call
options had also been sold covering a quantity of 1,000 barrels of oil per day
for the period from July 1999 through December 1999, at a strike price of $16.75
per barrel.

In accordance with SFAS 107, "Disclosures About Fair Value of Financial
Instruments," Basin has estimated the fair value of its hedging arrangements at
December 31, 1998, utilizing the then-applicable crude oil and natural gas
strips. While it is not Basin's intention to terminate any of the arrangements,
it is estimated that Basin would have received approximately $1,170,000 to
terminate the then-existing arrangements on December 31, 1998. Due to the
volatility of crude oil and natural gas prices, the fair market value may not be
representative of the actual gain or loss that will ultimately be realized by
Basin.

In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133"). 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 market value and that
changes in the derivative's fair market value be recognized currently in
earnings unless specific hedge accounting criteria are met. SFAS 133 is
effective for Basin in 2000, but early adoption is allowed. Basin has not yet
quantified the impacts of adopting SFAS 133 or determined the timing or method
of adoption. However, SFAS 133 could increase volatility in earnings and other
comprehensive income.

EARNINGS (LOSS) PER SHARE--Basin adopted SFAS 128, "Earnings Per Share,"
beginning with the fourth quarter of 1997. All prior period earnings per share
have been restated to conform to the provisions of the statement. Basic earnings
per share is computed based on the weighted average

F-13
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
number of common shares outstanding. Diluted earnings per share is computed
based on the weighted average number of common shares outstanding adjusted for
the incremental shares attributed to outstanding options and warrants to
purchase common stock. Options to purchase 171,500 and 30,000 shares in 1996 and
1997, respectively, were not included in the computation of diluted earnings per
share because the option exercise price was greater than the average market
price of Basin's common stock. All options and warrants to purchase common
shares were excluded from the computation of diluted earnings per share in 1998
because they were antidilutive as a result of Basin's net loss in that year.

In connection with the acquisition of Sterling Energy Corp. in November
1994, Basin issued warrants to purchase 300,000 shares of Basin's common stock
at an exercise price of $14.00 per share. Such warrants became exercisable on
October 13, 1994 and have an expiration date of December 31, 1999. During 1997
and 1998, 48,523 and 79,145 warrants were exercised, respectively. The remaining
172,332 warrants were outstanding at December 31, 1998.

COMPREHENSIVE INCOME--Basin adopted SFAS 130, "Comprehensive Income,"
beginning with the fourth quarter of 1997. There are no components of
comprehensive income which have been excluded from net income and, therefore, no
separate statement of comprehensive income has been presented.

(2) ACQUISITIONS AND DIVESTITURES OF OIL AND GAS PROPERTIES

In February 1996, Basin entered into agreements pursuant to which it sold
all of its assets in the Denver-Julesberg Basin in two transactions closed in
March and June 1996, respectively, for an aggregate sales price of $123,500,000,
effective January 1, 1996. Combined, these transactions resulted in Basin
selling its interests in approximately two-thirds of its producing wells and 70%
of its proved oil and gas reserves at December 31, 1995. Basin recognized a gain
of $22,472,000 in conjunction with the second transaction. Revenue and expenses
associated with the sold properties were included in Basin's results of
operations through the respective closing dates.

Basin consummated an acquisition of certain oil and gas properties from
Midcon Offshore, Inc. on November 26, 1997. The purchase price was approximately
$31,300,000, subject to normal post-closing adjustments. Basin was the high
bidder at a bankruptcy court proceeding conducted to sell such assets, which
were comprised principally of working interests in six federal lease blocks on
the outer-continental shelf in the Gulf of Mexico, and the related platforms and
production facilities. Approximately $5,000,000 of the purchase price was
attributed to prospective drilling locations. The acquisition was accounted for
as a purchase and, accordingly, the operating results of the acquired assets
have been included in Basin's consolidated financial statements since the
closing date.

F-14
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(3) LONG-TERM DEBT

<TABLE>
<CAPTION>
DECEMBER 31
--------------------
1997 1998
--------- ---------
<S> <C> <C>
(IN THOUSANDS)
Revolving credit facility.............................................. $ 11,000 $ 80,000
Other notes............................................................ 206 258
--------- ---------
11,206 80,258
Less: current portion................................................ (153) (258)
--------- ---------
Long-term debt, net of current portion................................. $ 11,053 $ 80,000
--------- ---------
--------- ---------
</TABLE>

Effective January 1, 1999, Basin entered into an Amended and Restated Credit
Agreement (the "Credit Agreement") with its existing bank group. The Credit
Agreement provides for borrowings of up to $110,000,000 under two combined
facilities. Facility A, initially established at $90,000,000, represents the
borrowing base that is considered to be "conforming" , based upon the bank's
then-current customary practices and standards in making conventional borrowing
base determinations for oil and gas producers. Such practices and standards are
intended to be substantially similar to the bank group's present practices,
except for market-induced changes relating to pricing, costs and risk factors
related to oil and gas reserves. Facility B, initially established at
$20,000,000, is a shorter-term supplemental line of credit. The Credit Agreement
provides for the interest rate on borrowings to be determined by reference to
the prime rate or LIBOR, at Basin's election. Facility A provides for a varying
spread of 0% to 0.25% to be added to the prime rate, or 0.75% to 1.5% to be
applied to LIBOR, based upon Basin's facility usage ratio at the time. Facility
B provides for a spread of 3.5% to be added to the prime rate or 4.75% to be
applied to LIBOR, subject to a 0.25% increase in such spreads effective June 1,
1999. The Credit Agreement provides for borrowings to be revolving loans until
November 30, 2001, at which time the outstanding balance will be converted into
a four-year amortizing term loan unless the Credit Agreement has been amended to
extend the revolving period, and subject to the scheduled termination of
Facility B effective May 31, 2000. The borrowing base under the Credit Agreement
is scheduled to be re-determined as of March 1, 1999 and generally at
three-month intervals thereafter until Facility B is retired, and then at
six-month intervals until converted into a term loan. The Credit Agreement
contains various covenants, including ones that could limit Basin's ability to
incur other debt, dispose of assets, pay dividends, or repurchase stock.
Pursuant to the agreement governing the Credit Agreement, substantially all of
Basin's producing properties are subject to mortgages in favor of the banks and
Basin's remaining properties are subject to a negative pledge. The weighted
average interest rate on borrowings outstanding under the Credit Agreement at
December 31, 1998 was 6.2%.

Outstanding debt at December 31, 1998 is payable as follows (in thousands):

<TABLE>
<S> <C>
1999.............................................................. $ 258
2000.............................................................. --
2001.............................................................. --
2002.............................................................. 20,000
2003.............................................................. 20,000
Thereafter........................................................ 40,000
---------
$ 80,258
---------
---------
</TABLE>

F-15
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(4) BENEFIT PLANS

401(K) SAVINGS--Basin has a 401(k) profit sharing plan (the "Plan").
Eligible employees may make voluntary contributions to the Plan, which may be
matched by Basin, at its discretion, up to 6 percent of the employee's eligible
compensation. Basin has historically matched the first three percent of
employees' eligible compensation that is contributed under the Plan. The amount
of employee contributions is limited as specified in the Plan. At its
discretion, Basin may also make additional contributions to the Plan. Basin
expensed $96,000, $183,000 and $208,000, with respect to the Plan for the years
ended December 31, 1996, 1997 and 1998, respectively.

STOCK PLAN--Under Basin's Equity Incentive Plan, officers, key employees,
consultants and directors of Basin are eligible to receive incentive stock
options, non-qualified stock options, restricted stock and performance shares.
The restricted stock and performance shares awarded under the plan entitle the
grantee to the rights of a shareholder, including the right to receive any
dividends and to vote such shares, but the shares are restricted as to sale,
transfer or encumbrance. At December 31, 1998, a total of approximately
1,758,000 shares were available for grant under the plans. Options granted
generally vest over three to four years, and expire after ten years. A total of
1,175,000 shares of Basin's common stock are subject to such plans as of
December 31, 1998, including 186,000 non-vested shares of restricted stock and
performance shares and 989,000 outstanding stock options.

The following table summarizes stock options activity for the years
presented:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1996 1997 1998
---------- --------- ----------
<S> <C> <C> <C>
Balance, beginning of period................................................. 702,500 649,000 773,500
Granted...................................................................... 252,500 202,500 345,000
Exercised.................................................................... (33,500) (78,000) (129,500)
Forfeited/canceled........................................................... (272,500) -- --
---------- --------- ----------
Balance, end of period....................................................... 649,000 773,500 989,000
---------- --------- ----------
---------- --------- ----------
</TABLE>

Additional information regarding outstanding options at December 31, 1998 is
as follows:

<TABLE>
<CAPTION>
NUMBER OF WEIGHTED WEIGHTED AVERAGE NUMBER OF WEIGHTED
OPTIONS AVERAGE REMAINING LIFE IN OPTIONS AVERAGE
RANGE OF EXERCISE PRICES PER SHARE OUTSTANDING EXERCISE PRICE YEARS EXERCISABLE EXERCISE PRICE
- ----------------------------------- ------------ --------------- ------------------- ------------ ---------------
<S> <C> <C> <C> <C> <C>
$13.25 -- $20.38................... 464,000 $ 15.48 8.0 109,000 $ 16.13
$7.63 -- $11.00.................... 165,000 $ 9.64 4.4 131,667 $ 9.52
$5.13 -- $7.00..................... 215,000 $ 6.32 7.6 138,333 $ 6.15
$3.88 -- $4.94..................... 145,000 $ 4.27 7.1 100,833 $ 4.21
--
------------ ------- ------------ -------
989,000 $ 10.87 7.0 479,833 $ 8.94
--
--
------------ ------- ------------ -------
------------ ------- ------------ -------
</TABLE>

Basin granted 25,000, 23,000 and 59,000 shares of restricted stock during
1996, 1997 and 1998, respectively. Related compensation expense was recognized
in the amounts of approximately

F-16
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(4) BENEFIT PLANS (CONTINUED)
$98,000, $120,000 and $409,000 for the years ended December 31, 1996, 1997 and
1998, respectively. Cumulatively through December 31, 1998, 73,000 shares of
restricted stock had been forfeited, 53,000 shares were no longer subject to
restriction, and 81,000 shares of restricted stock remained subject to
forfeiture.

Basin granted 55,000 and 50,000 performance shares during 1997 and 1998,
respectively. In order for the performance shares to be released to the grantee,
Basin must attain certain performance goals by the end of a three-year
performance cycle which begins with the year of award. Related compensation
expense was recognized in the amount of $447,000 and $367,000 for the years
ended December 31, 1997 and 1998, respectively.

In October 1995, the Financial Accounting Standards Board issued SFAS 123,
"Accounting for Stock-Based Compensation." SFAS 123 is effective for 1996 and
after and recommends a fair value based method of accounting for employee stock
compensation, including stock options. However, companies may choose to account
for stock compensation using the intrinsic value based method as prescribed by
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," and provide pro forma disclosures of net income and earnings per
share as if the fair value based method had been applied. Basin has elected to
continue to account for stock compensation using the intrinsic value based
method.

Had Basin elected to follow SFAS 123, the fair value of each option grant
would have been estimated on the date of grant using the Black-Sholes
option-pricing model with the following weighted-average assumptions and
effects:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1996 1997 1998
--------- --------- ----------
<S> <C> <C> <C>
Assumptions:
Risk free interest rate...................................................... 6.75% 5.75% 5.75%
Expected dividend yield...................................................... 0% 0% 0%
Expected life in years....................................................... 5 5 5
Expected volatility.......................................................... 55% 58% 58%
Weighted average fair value per share.......................................... $ 2.73 $ 5.66 $ 8.40
Pro forma net income (loss) (in thousands)..................................... $ 15,468 $ 2,285 $ (29,315)
Pro forma diluted earnings (loss) per share.................................... $ 1.44 $ 0.20 $ (2.12)
</TABLE>

F-17
<PAGE>
(5) COMMITMENTS AND CONTINGENCIES

LEASES--Basin is the primary obligor under various noncancelable office
space operating lease arrangements. Basin also subleases certain office space to
and from third parties under various noncancelable lease arrangements. The
following is a schedule of future minimum lease payments under these leases at
December 31, 1998:

<TABLE>
<CAPTION>
FUTURE MINIMUM FUTURE MINIMUM
LEASE OBLIGATIONS LEASE RECEIPTS
------------------- -------------------
(IN THOUSANDS)
<S> <C> <C>
1999.......................................... $ 596 $ 186
2000.......................................... 136 --
----- -----
$ 732 $ 186
----- -----
----- -----
</TABLE>

Payments related to these lease obligations were approximately $707,000,
$990,000 and $1,096,000 for the years ended December 31, 1996, 1997 and 1998,
respectively. Related receipts were $89,000, $502,000 and $506,000 in the years
ended December 31, 1996, 1997 and 1998.

LEGAL PROCEEDINGS--Basin, from time to time, is involved in various legal
and administrative proceedings and claims of various types which arise in the
ordinary course of its business. While any litigation contains an element of
uncertainty, in the opinion of management, none of these actions, either
individually or in the aggregate, are likely to have a material adverse effect
on Basin's financial condition, liquidity or results of operations.

(6) INCOME TAXES

The components of the provision (benefit) for income taxes are as follows:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1996 1997 1998
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Current provision (benefit):
Federal......................................................................... $ 950 $ (434) $ (58)
State........................................................................... 50 (37) 81
--------- --------- ---------
1,000 (471) 23
--------- --------- ---------
Deferred provision (benefit):
Federal......................................................................... 4,760 1,795 (6,555)
State........................................................................... -- -- --
--------- --------- ---------
4,760 1,795 (6,555)
--------- --------- ---------
Provision (benefit for income taxes).............................................. $ 5,760 $ 1,324 $ (6,532)
--------- --------- ---------
--------- --------- ---------
</TABLE>

F-18
<PAGE>
(6) INCOME TAXES (CONTINUED)
Reconciliations of income tax provisions (benefit) computed at the federal
statutory rate with income tax provisions recorded by Basin for each of the past
three years are as follows:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1996 1997 1998
--------- --------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Income (loss) before income taxes.............................................. $ 21,330 $ 3,780 $ (35,032)
Computed tax (benefit) at the applicable federal statutory rate................ 7,252 1,285 (11,911)
State income tax (benefit), net of federal tax effect.......................... 704 39 (350)
Deferred tax assets valuation allowance........................................ (2,196) -- 5,729
--------- --------- ----------
Income tax provision (benefit)................................................. $ 5,760 $ 1,324 $ (6,532)
--------- --------- ----------
--------- --------- ----------
</TABLE>

The tax effects of significant temporary differences representing deferred
tax assets and liabilities are as follows:

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1997 1998
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Deferred tax (assets) liabilities:
Oil and gas properties and equipment...................................................... $ 7,581 $ (2,357)
Net operating loss carryforward........................................................... -- (2,505)
Percentage depletion carryforward......................................................... -- (589)
Alternative minimum tax credit carryforward............................................... (1,026) (278)
Valuation allowance....................................................................... -- 5,729
--------- ---------
Net deferred tax liability.................................................................. $ 6,555 $ --
--------- ---------
--------- ---------
</TABLE>

(7) RELATED PARTY TRANSACTIONS

Prior to its initial public offering, Basin advanced $559,000 to its
principal stockholder at an annual interest rate of 9 percent. Pursuant to the
terms of the note, the principal stockholder elected to surrender 28,217 shares
of Basin's common stock to Basin in the fourth quarter of 1997 to settle the
note. The surrendered shares are reflected as treasury stock in the accompanying
statement of changes in stockholders' equity.

(8) OIL AND GAS ACTIVITIES

Basin's oil and gas operations are conducted solely in the United States.
Certain information concerning these activities follows:

F-19
<PAGE>
(8) OIL AND GAS ACTIVITIES (CONTINUED)
MAJOR PURCHASERS--The following parties purchased ten percent or more of
Basin's oil and gas production:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
PURCHASER 1996 1997 1998
- ------------------------------------------------------------------------------------------- --------- --------- ---------
<S> <C> <C> <C>
Texaco..................................................................................... (a) 46% 28%
Dynegy..................................................................................... (a) (a) 26%
Eighty-Eight Oil........................................................................... 26% 21% (a)
PanEnergy.................................................................................. 43% (a) (a)
</TABLE>

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

(a) less than ten percent

COSTS INCURRED--Costs incurred in oil and gas operations and related
depletion per equivalent unit-of-production were as follows:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1996 1997 1998
--------- ----------- -----------
(IN THOUSANDS, EXCEPT FOR GAS
EQUIVALENT DATA)
<S> <C> <C> <C>
Property acquisition--
Unproved(1)............................................................... $ 5,056 $ 11,057 $ 22,920
Proved.................................................................... 3,067 48,680 3,018
Exploration costs........................................................... 10,250 27,995 58,063
Development costs........................................................... 4,472 17,901 22,671
--------- ----------- -----------
Gross expenditures.......................................................... $ 22,845 $ 105,633 $ 106,672
--------- ----------- -----------
--------- ----------- -----------
Depletion per one thousand cubic feet of gas equivalent..................... $ 0.82 $ 1.12 $ 1.31
--------- ----------- -----------
--------- ----------- -----------
</TABLE>

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

(1) Excludes $4,914,000, $1,113,000 and $150,000 of costs recouped through the
resale of partial interests in prospects to industry partners in 1996, 1997
and 1998, respectively.

COSTS NOT BEING AMORTIZED--Oil and gas property costs not being amortized at
December 31, 1998, consisted of $34,039,000 of leasehold and seismic costs, of
which $2,669,000, $3,312,000 and $28,058,000 were incurred in 1996, 1997 and
1998, respectively. Basin anticipates that substantially all unevaluated costs
will be classified as evaluated costs within three years.

UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

There are numerous uncertainties inherent in estimating quantities of proved
reserves and projected future rates of production and timing of development
expenditures, including many factors beyond the control of the producer. The
reserve data and standardized measures 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 of different engineers often vary. In addition, results of drilling,
testing and production subsequent to the date of an estimate may justify
revision of such estimate. Accordingly, reserve estimates will vary from the
quantities of oil and gas that are ultimately recovered. Further, the estimated
future net cash flows from proved reserves and the present value thereof are
based upon certain assumptions, including geologic success, and future

F-20
<PAGE>
(8) OIL AND GAS ACTIVITIES (CONTINUED)
prices, production levels and costs, that may not prove correct over time.
Predictions of future production levels are subject to great uncertainty, and
the meaningfulness of such estimates is highly dependent upon the accuracy of
the assumptions upon which they are based. Oil and gas prices have fluctuated
widely in recent years. The calculated weighted average sales prices utilized
for the purposes of estimating Basin's proved reserves and future net cash flows
were: $25.35 per barrel of oil and $3.02 per Mcf of gas at December 31, 1996;
$16.34 per barrel of oil and $2.32 per Mcf of gas at December 31, 1997 and
$10.31 per barrel of oil and $1.99 per Mcf of gas at December 31, 1998.
Estimated reserve quantities and standardized measures set forth herein utilize
such prices (which were based on prevailing sales prices at the time) held
constant in future periods and a 10% discount rate.

All of Basin's reserves are located onshore or offshore in the United
States. The following tables include estimates for Basin's onshore and offshore
reserves combined. Estimates of onshore reserves were prepared by Basin's
engineers and audited by Netherland, Sewell & Associates, Inc. at December 31,
1995, 1996 and 1997 and by Ryder Scott Company Petroleum Engineers at December
31, 1998. Estimates of offshore reserves were either prepared by Ryder Scott
Company Petroleum Engineers, or prepared by Basin's engineers and audited by
Ryder Scott Company Petroleum Engineers.

ANALYSES OF CHANGES IN PROVED RESERVES

The following table sets forth information regarding Basin's estimated net
total proved and proved developed oil and gas reserve quantities:

<TABLE>
<CAPTION>
OIL GAS
(MBBLS) (MMCF)
--------- ----------
<S> <C> <C>
Balance, December 31, 1995................................................................. 12,606 131,436
Revisions................................................................................ 52 (451)
Extensions, discoveries and additions.................................................... 49 6,391
Production............................................................................... (564) (4,776)
Sales of reserves in-place............................................................... (6,559) (104,140)
Purchases of reserves in-place........................................................... 2,286 1,253
--------- ----------
Balance, December 31, 1996................................................................. 7,870 29,713
Revisions................................................................................ (1,439) (6,488)
Extensions, discoveries and additions.................................................... 1,458 32,911
Production............................................................................... (524) (5,509)
Sales of reserves in-place............................................................... (56) (1,015)
Purchases of reserves in-place........................................................... 845 39,922
--------- ----------
Balance, December 31, 1997................................................................. 8,154 89,534
Revisions................................................................................ (1,486) (6,136)
Extensions, discoveries and additions.................................................... 2,057 57,888
Production............................................................................... (725) (17,616)
Purchases of reserves in-place........................................................... 667 3,832
--------- ----------
Balance, December 31, 1998................................................................. 8,667 127,502
--------- ----------
--------- ----------
Proved developed reserves--
December 31, 1996........................................................................ 4,046 19,182
December 31, 1997........................................................................ 4,863 82,571
December 31, 1998........................................................................ 3,352 103,271
</TABLE>

F-21
<PAGE>
STANDARDIZED MEASURE

The following table presents the standardized measure of discounted future
net cash flows related to proved oil and gas reserves:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------
1996 1997 1998
------------ ----------- -----------
<S> <C> <C> <C>
(IN THOUSANDS)
Future production revenues................................................ $ 289,105 $ 341,310 $ 342,618
Future production costs................................................... (108,522) (79,550) (71,609)
Future development costs.................................................. (20,583) (40,829) (54,905)
Future income taxes....................................................... (39,101) (31,723) (17,894)
------------ ----------- -----------
Future net cash flows..................................................... 120,899 189,208 198,210
Discount factor at 10% per annum.......................................... (57,593) (53,726) (48,255)
------------ ----------- -----------
Standardized measure of discounted future net cash flows(1)............... $ 63,306 $ 135,482 $ 149,955
------------ ----------- -----------
------------ ----------- -----------
</TABLE>

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

(1) Total future net cash flows before income taxes discounted at 10% per annum
are $83,656,000, $160,230,000 and $164,485,000 as of December 31, 1996, 1997
and 1998, respectively.

The estimate of future income taxes is based on the future net cash flows
from proved reserves adjusted for the tax basis of the oil and gas properties
but without consideration of general and administrative and interest expenses.
For standardized measure purposes Basin estimates future income taxes using the
"year-by-year" method. For ceiling test purposes Basin estimates future income
taxes using the "short-cut" method.

A summary of changes in the standardized measure of discounted future net
cash flows is as follows:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------
1996 1997 1998
------------ ----------- -----------
<S> <C> <C> <C>
(IN THOUSANDS)
Standardized measure of discounted future net cash flows, beginning of
year.................................................................... $ 117,248 $ 63,306 $ 135,482
Changed in sales prices and production costs.............................. 17,693 (34,217) (51,857)
Changes in estimated future development costs............................. (1,819) 6,973 3,061
Sales of minerals-in-place................................................ (83,530) (1,019) --
Purchase of minerals-in place............................................. 10,887 65,644 7,537
Revisions of previous quantity estimates.................................. (169) (11,065) (9,015)
Costs incurred that reduced future development costs...................... -- 2,253 474
Extensions, discoveries and improved recovery............................. 16,286 67,973 91,660
Sales of oil and gas, net of production costs and taxes................... (11,577) (18,541) (39,574)
Accretion of discount..................................................... 12,907 8,366 16,023
Net change in future income taxes......................................... (8,530) (4,398) 10,218
Changes in timing of production and other................................. (6,090) (9,793) (14,054)
------------ ----------- -----------
Standardized measure of discounted future net cash flows, end of year..... $ 63,306 $ 135,482 $ 149,955
------------ ----------- -----------
------------ ----------- -----------
</TABLE>

F-22
<PAGE>
UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA

<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH TOTAL
--------- --------- --------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
1997
Revenue.............................................. $ 3,412 $ 2,566 $ 6,906 $ 11,836 $ 24,720
Gross profit from operations......................... 1,814 1,269 5,589 9,869 18,541
Net income (loss).................................... 9 (570) 966 2,051 2,456
Earnings (loss) per share:
Basic.............................................. -- (0.05) 0.09 0.16 0.22
Diluted............................................ -- (0.05) 0.09 0.16 0.22

1998
Revenue.............................................. $ 10,256 $ 11,908 $ 14,144 $ 12,391 $ 48,699
Gross profit from operations......................... 7,858 9,262 11,932 10,522 39,574
Net income (loss).................................... 239 746 1,242 (30,727) (28,500)
Earnings (loss) per share:
Basic.............................................. 0.02 0.05 0.09 (2.21) (2.06)
Diluted............................................ 0.02 0.05 0.09 (2.21) (2.06)
</TABLE>

Gross profit from operations is comprised of oil and gas sales less lease
operating expenses and production taxes. The net loss for the fourth quarter of
1998 includes a property impairment of $38,500,000. Earnings (loss) per share is
computed independently for each of the quarters presented and, therefore, may
not sum to the totals for the year.

F-23
<PAGE>
UNDERWRITING

Basin Exploration, Inc., the selling stockholder and the underwriters named
below have entered into an underwriting agreement with respect to the shares
being offered. Subject to certain conditions, each underwriter has severally
agreed to purchase the number of shares indicated in the following table.
Goldman, Sachs & Co., Banc of America Securities LLC, Dain Rauscher Wessels, a
division of Dain Rauscher Incorporated, and Petrie Parkman & Co., Inc. are the
representatives of the underwriters.

<TABLE>
<CAPTION>
UNDERWRITERS NUMBER OF SHARES
- ------------------------------------------------------------------------------------ ------------------
<S> <C>
Goldman, Sachs & Co................................................................. 1,275,000
Banc of America Securities LLC...................................................... 637,500
Dain Rauscher Wessels, a division of Dain Rauscher Incorporated..................... 637,500
Petrie Parkman & Co., Inc........................................................... 637,500
J.C. Bradford & Co.................................................................. 203,125
Hanifen, Imhoff Inc................................................................. 203,125
Morgan Keegan & Company, Inc........................................................ 203,125
Southcoast Capital Corporation...................................................... 203,125
----------
Total............................................................................. 4,000,000
----------
----------
</TABLE>

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

If the underwriters sell more shares than the total number set forth in the
table above, the underwriters have an option to buy up to an additional 600,000
shares from Basin and the selling stockholder to cover such sales. They may
exercise that option for 30 days. If any shares are purchased pursuant to this
option, the underwriters will severally purchase shares in approximately the
same proportion as set forth in the table above.

The following tables show the per share and total underwriting discounts and
commissions to be paid to the underwriters by Basin and the selling stockholder.
Such amounts are shown assuming both no exercise and full exercise of the
underwriters' option to purchase additional shares.
<TABLE>
<CAPTION>
Paid by Basin
----------------------------
No Exercise Full Exercise
------------- -------------
<S> <C> <C>
Per Share................................................... $ 0.94 $ 0.94
Total....................................................... $ 3,525,000 $ 4,053,750

Paid by the Selling
Stockholder
----------------------------
No Exercise Full Exercise
------------- -------------
<S> <C> <C>
Per Share................................................... $ 0.94 $ 0.94
Total....................................................... $ 235,000 $ 270,250
</TABLE>

Shares sold by the underwriters to the public will initially be offered at
the initial price to public set forth on the cover of this prospectus
supplement. Any shares sold by the underwriters to securities dealers may be
sold at a discount of up to $0.55 per share from the initial price to public.
Any such securities dealers may resell any shares purchased from the
underwriters to certain other brokers or dealers at a discount of up to $0.10
per share from the initial price to public. If all the shares are not sold at
the initial price to public, the representatives may change the price and the
other selling terms.

Basin, the selling stockholder and certain officers and directors of Basin
have agreed with the underwriters not to sell or dispose of or hedge any of
their common stock or securities convertible

U-1
<PAGE>
into or exchangeable for shares of common stock during the period from the date
of this prospectus supplement continuing through the date 90 days after the date
of this prospectus supplement, except with the prior written consent of the
representatives. This agreement does not apply to the issuance of common stock
by Basin pursuant to any existing employee benefit plans or outstanding
warrants.

In connection with the offering, the underwriters may purchase and sell
shares of common stock in the open market. These transactions may include short
sales, stabilizing transactions and purchases to cover positions created by
short sales. Short sales involve the sale by the underwriters of a greater
number of shares than they are required to purchase in the offering. Stabilizing
transactions consist of certain bids or purchases made for the purpose of
preventing or retarding a decline in the market price of the common stock while
the offering is in progress.

The underwriters also may impose a penalty bid. This occurs when a
particular underwriter repays to the underwriters a portion of the underwriting
discount received by it because the representatives have repurchased shares sold
by or for the account of such underwriter in stabilizing or short covering
transactions.

These activities by the underwriters may stabilize, maintain or otherwise
affect the market price of the common stock. As a result, the price of the
common stock may be higher than the price that otherwise might exist in the open
market. If these activities are commenced, they may be discontinued by the
underwriters at any time. These transactions may be effected on the Nasdaq
National Market, in the over-the-counter market or otherwise.

Petrie Parkman & Co., Inc. owns 11,103 shares of common stock and warrants
to purchase 652 shares of common stock. The warrants have an exercise price of
$14.00 per share and a December 31, 1999 expiration date.

Basin and the selling stockholder estimate that their share of the total
expenses of the offering, excluding underwriting discounts and commissions, will
be approximately $450,000 and $10,000, respectively.

Basin and the selling stockholder have agreed to indemnify the several
underwriters against certain liabilities, including liabilities under the
Securities Act of 1933.

U-2
<PAGE>
PROSPECTUS

$200,000,000

[LOGO]
BASIN EXPLORATION, INC.

DEBT SECURITIES
COMMON STOCK
PREFERRED STOCK
WARRANTS

Basin Exploration, Inc. (the "Company" or "Basin") may offer from time to
time (i) debt securities ("Debt Securities"), consisting of debentures, notes,
bonds and/or other unsecured evidences of indebtedness in one or more series,
(ii) shares of the Company's common stock, $.01 par value ("Common Stock"),
(iii) shares of preferred stock, $.01 par value ("Preferred Stock"), in one or
more series, or (iv) warrants to purchase Debt Securities, Preferred Stock or
Common Stock. The foregoing securities are collectively referred to as the
"Securities." Any Securities may be offered with other Securities or separately.
The Securities will be offered at an aggregate initial offering price not to
exceed US $200,000,000 or the equivalent (based on the applicable exchange rate
at the time of sale), if Debt Securities of the Company are issued in principal
amounts denominated in one or more foreign currencies or currency units as shall
be designated by the Company at prices and on terms to be determined at the time
of sale.

SEE "RISK FACTORS" FOR CERTAIN CONSIDERATIONS RELEVANT TO AN INVESTMENT IN
THE SECURITIES.

This Prospectus will be supplemented by one or more accompanying Prospectus
Supplements, which will set forth with regard to the particular Securities in
respect of which this Prospectus is being delivered (i) in the case of Debt
Securities, the title; aggregate principal amount; currency of denomination
(which may be in U.S. dollars, in any other currency, currencies or currency
unit, including the European Currency Unit); maturity; interest rate, if any
(which may be fixed or variable), or method of calculation thereof; time of
payment of any interest; form of payment of any interest whether in the form of
cash, additional Debt Securities, Common Stock or some combination thereof; any
terms for redemption at the option of the Company or the holder; any terms for
sinking fund payments; any index or other method used to determine the amounts
payable; the ranking of such Debt Securities (whether senior, senior
subordinated or subordinated); any conversion or exchange rights, at the option
of the Company or the holder; any listing on a securities exchange; the initial
public offering price and any other terms in connection with the offering and
sale of such Debt Securities; (ii) in the case of Common Stock, the number of
shares of Common Stock, the terms of the offering thereof and information
regarding the selling stockholder, if any; (iii) in the case of Preferred Stock,
the designation, stated value and liquidation preference per share; the initial
public offering price per share and the number of shares to be offered; dividend
rate (or method of calculation); dates on which dividends shall be payable and
dates from which dividends shall accrue; any redemption or sinking fund
provisions; any conversion or exchange rights; any listing of the Preferred
Stock on a securities exchange; and any other terms in connection with the
offering and sale of such Preferred Stock; and (iv) in the case of Warrants, the
number and terms thereof, the designation and the number of Securities issuable
upon their exercise; the exercise price; any listing of the Warrants or the
underlying Securities on a securities exchange and any other terms in connection
with the offering, sale and exercise of the Warrants. The Prospectus Supplement
will also contain information, as applicable, about certain United States
federal income tax considerations relating to the Securities in respect of which
this Prospectus is being delivered.

The Company's Common Stock is quoted on the Nasdaq National Market (Symbol:
"BSNX"). Each Prospectus Supplement will indicate if the Securities offered
thereby will be quoted on any market or listed on any securities exchange.

The Company may sell Securities to or through one or more underwriters, and
may also sell Securities directly to other purchasers or through agents. See
"Plan of Distribution." Each Prospectus Supplement will set forth the names of
any underwriters, dealers or agents involved in the sale of the Securities in
respect of which this Prospectus is being delivered, and any applicable fee,
commission or discount arrangements with them.
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.
<PAGE>
THIS PROSPECTUS MAY NOT BE USED TO CONSUMMATE SALES OF SECURITIES UNLESS
ACCOMPANIED BY A PROSPECTUS SUPPLEMENT.

THE DATE OF THIS PROSPECTUS IS OCTOBER 2, 1997.
<PAGE>
AVAILABLE INFORMATION

The Company is subject to the informational 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 may be inspected and copied at the public
reference facilities of the Commission, Room 1024, Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549, as well as at the following Regional
Offices: 7 World Trade Center, Suite 1300, New York, New York 10048, and
Citicorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661.
Copies of such material can be obtained from the Commission by mail at
prescribed rates. Requests should be directed to the Commission's Public
Reference Section, Room 1024, Judiciary Plaza, 450 Fifth Street, N.W.,
Washington D.C. 20549. The Commission also maintains a website at
http://www.sec.gov that contains reports, proxy statements, and other
information. The Company's Common Stock is quoted on the Nasdaq National Market.
Reports, proxy and information statements and other information relating to the
Company can be inspected at the offices of the Nasdaq Stock Market, Inc., 1735 K
Street, Washington, D.C., 20006.

The Company has filed with the Commission a Registration Statement on Form
S-3 (herein, together with all amendments and exhibits, referred to as the
"Registration Statement") under the Securities Act of 1933 (the "Securities
Act") with respect to the Securities offered by this Prospectus. This
Prospectus, which forms part of the Registration Statement, does not contain all
of the information set forth in the Registration Statement, certain parts of
which have been omitted in accordance with the rules and regulations of the
Commission. For further information with respect to the Company and the
Securities, reference is hereby made to such Registration Statement, including
the exhibits filed therewith. The Registration Statement and the exhibits
thereto can be obtained by mail from or inspected and copied at the public
reference facilities maintained by the Commission as described in the prior
paragraph.

The Company distributes to its stockholders annual reports containing
audited consolidated financial statements and quarterly reports containing
unaudited financial information for the first three quarters of each year.

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

The following documents filed by the Company with the Commission are
incorporated by reference in this Prospectus:

(1) Annual Report on Form 10-K for the year ended December 31, 1996, filed
with the Commission on March 31, 1997;

(2) Amendment to Annual Report on Form 10-K for the year ended December 31,
1996 on Form 10-K/A-1, filed with the Commission on June 5, 1997;

(3) Quarterly Report on Form 10-Q for the period ended March 31, 1997, filed
with the Commission on May 15, 1997;

(4) Quarterly Report on Form 10-Q for the period ended June 30, 1997, filed
with the Commission on August 12, 1997;

(5) Registration Statement on Form 8-A filed with the Commission on February
27, 1996, relating to the Company's Stockholders' Rights Plan;

(6) The description of the Common Stock contained in the Company's
Registration Statement on Form 8-A dated April 24, 1992, filed with the
Commission on April 27, 1992.

All documents subsequently filed by the Company pursuant to Sections 13(a),
13(c), 14 or 15(d) of the Exchange Act prior to the termination of the offering
of the Securities offered hereby shall be deemed to be incorporated by reference
in this Prospectus and to be a part hereof from the date of filing of such

2
<PAGE>
documents. Any statement contained in a document incorporated or deemed to be
incorporated by reference 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 or in any Prospectus Supplement, modifies or
supersedes such statement. Any 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 a copy of
this Prospectus is delivered, on the oral or written request of such person, a
copy of any or all of the documents incorporated herein by reference (other than
exhibits, unless such exhibits are specifically incorporated by reference in
such documents). Requests for such copies should be directed to the Secretary,
370 Seventeenth Street, Suite 3400, Denver, Colorado 80202, telephone: (303)
685-8000, facsimile: (303) 685-8010.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Prospectus includes and incorporates by reference statements that are
not purely historical and are "forward-looking statements" within the meaning of
Section 27A of the Securities Act and Section 21E of the Exchange Act. All
statements, other than statements of historical facts, included or incorporated
by reference in this Prospectus, involve risks and uncertainties that could
cause actual results to differ from projected results. Such statements address
activities, events or developments that the Company expects, believes, projects,
intends or anticipates will or may occur, including such matters as future
capital, development and exploration expenditures (including the amount and
nature thereof), drilling of wells, future production of oil and gas, business
strategies, cash flow and anticipated liquidity, prospect development and
property acquisition, or marketing of oil and gas. Factors that could cause
actual results to differ materially ("Cautionary Disclosures") include, among
others: general economic conditions, the market price of oil and natural gas,
the risks associated with exploration, the Company's ability to find, acquire,
market, develop and produce new properties, operating hazards attendant to the
oil and natural gas business, downhole drilling and completion risks that are
generally not recoverable from third parties or insurance, concentration of the
Company's production in a small number of properties in the Gulf of Mexico,
uncertainties in the estimation of proved reserves and in the projection of
future rates of production and timing of development expenditures, potential
mechanical failure of individually significant productive wells, the strength
and financial resources of the Company's competitors, the Company's ability to
find and retain skilled personnel, climatic conditions, labor relations,
availability and cost of material and equipment, delays in anticipated start-up
dates, environmental risks, the results of financing efforts, actions or
inactions of third-party operators of the Company's properties, regulatory
developments, and other factors described in this Prospectus and in any
Prospectus Supplement and in the Company's annual reports on Form 10-K,
quarterly reports on Form 10-Q and current reports on Form 8-K filed with the
Commission. Many of such factors are beyond the Company's ability to control or
predict. All forward-looking statements included or incorporated by reference in
this Prospectus are based on information available to the Company on the date
hereof, and the Company assumes no obligation to update such forward-looking
statements as a result of new information, future events or otherwise. Although
the Company believes that the assumptions and expectations reflected in such
forward-looking statements are reasonable, it can give no assurance that such
expectations will prove to have been correct or that the Company will take any
actions that may presently be planned. Prospective investors are cautioned not
to put undue reliance on forward-looking statements. Certain important factors
that could cause actual results to differ materially from the Company's
expectations are disclosed under "Risk Factors" and elsewhere in this
Prospectus. All written and oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by the Cautionary Disclosures.

3
<PAGE>
RISK FACTORS

PROSPECTIVE PURCHASERS OF THE SECURITIES SHOULD CAREFULLY READ THIS
PROSPECTUS, ANY PROSPECTUS SUPPLEMENT DELIVERED HEREWITH, AND THE DOCUMENTS
INCORPORATED BY REFERENCE HEREIN AND THEREIN. OWNERSHIP OF SECURITIES INVOLVES
CERTAIN RISKS. IN DETERMINING WHETHER TO PURCHASE THE SECURITIES, PROSPECTIVE
INVESTORS SHOULD CONSIDER CAREFULLY THE FOLLOWING RISK FACTORS AND THE OTHER
INFORMATION CONTAINED IN THIS PROSPECTUS, IN ADDITION TO THE OTHER RISK FACTORS
AND INFORMATION SET FORTH IN ANY PROSPECTUS SUPPLEMENT DELIVERED HEREWITH.

OIL AND GAS PRICES; HEDGING

Basin's revenues and profitability are substantially dependent upon
prevailing prices for oil, gas and natural gas liquids. For much of the past
decade, the markets for oil and natural gas have been extremely volatile. The
Company anticipates that such markets will continue to be volatile in the
foreseeable future. In general, future prices of oil, gas and natural gas
liquids are dependent upon numerous external factors such as various economic,
political and regulatory developments and competition from other sources of
energy. The unsettled nature of the energy market and the unpredictability of
worldwide political developments, including, for example, actions of OPEC
members, make it particularly difficult to estimate future prices of oil, gas
and natural gas liquids. Any significant decline in the price of oil, gas or
natural gas liquids for an extended period would have a material adverse effect
on the Company's financial condition and results of operations, and would, under
certain circumstances, result in a reduction in funds available under the
Company's bank credit facilities and impair access to other sources of capital.

From time to time, as conditions are deemed to warrant, the Company enters
into energy price swap arrangements to reduce its sensitivity to oil and gas
price volatility. Such arrangements are subject to a number of risks. If the
Company's reserves are not produced at the rates estimated by the Company due to
inaccuracies in the reserve estimation process, operational difficulties or
regulatory limitations, the Company would be required to satisfy its obligations
under hedging contracts on potentially unfavorable terms without the ability to
hedge that risk through sales of comparable quantities of its own production.
Further, the terms under which the Company enters into hedging contracts are
based on assumptions and estimates of numerous factors such as cost of
production and pipeline and other transportation costs to delivery points. Under
financial instrument contracts, the Company may also be at risk for basis
differential, which is the difference in the quoted financial price for contract
settlement and the actual price received at the physical point of delivery.
Substantial variations between the assumptions and estimates used by the Company
and actual results experienced could materially adversely affect the Company's
anticipated profit margins and its ability to manage the risk associated with
fluctuations in oil and gas prices. In addition, hedging contracts are subject
to the risk that the other party may prove unable or unwilling to perform its
obligations under such contracts. Any significant nonperformance could have a
material adverse financial effect on the Company. Furthermore, hedging contracts
limit the benefits the Company would realize if actual prices rise above the
contract prices.

REPLACEMENT OF RESERVES

Basin's future success depends upon its ability to find, develop and/or
acquire additional oil and gas reserves at prices that permit profitable
operations. Except to the extent that Basin conducts successful development,
exploitation or exploration activities or acquires properties containing proved
reserves, the proved reserves of Basin will decline. The rate of decline depends
upon reservoir characteristics and varies from the steep decline rate
characteristic of Gulf of Mexico reservoirs, where Basin has most of its
production, to the relatively slow decline rate characteristic of the long-lived
fields in the Rocky Mountain region, where the Company's other properties are
located. The market for acquiring proved reserves is extremely competitive, and
the Company may not be able to buy reserves for development and exploitation at
prices it considers to be reasonable or within its budgets. The cost of
drilling, completing and operating wells may vary significantly from initial
estimates. Basin's drilling operations may be unsuccessful or may be curtailed,
delayed or canceled as a result of numerous factors not within Basin's control,
including but

4
<PAGE>
not limited to title problems, weather conditions, compliance with governmental
requirements, shortage of capital, mechanical difficulties and shortages or
delays in the delivery of drilling rigs or other equipment. Accordingly, there
can be no assurance that Basin's acquisition, development, exploitation and
exploration activities will result in reserves added at acceptable costs.

ACQUISITION RISKS

Acquisitions of producing oil and gas properties have been a key element of
Basin's success, and Basin will continue to seek acquisitions in the future.
Even though Basin performs a review of the properties in connection with its
acquisitions which it believes is consistent with industry practices, such
reviews are inherently incomplete, and the evaluations resulting therefrom are
necessarily inexact and uncertain. It is generally not feasible to review in
depth every property and all records in connection with an acquisition of many
properties, particularly when the seller does not operate the property.
Ordinarily Basin will focus its due diligence efforts on the higher valued
properties and will spot-check the remainder. However, even an in-depth review
of properties and records may not necessarily reveal existing or potential
problems nor will it permit a buyer to become familiar enough with the
properties to assess fully their deficiencies and capabilities. Inspections may
not be performed on every well, and environmental problems, such as groundwater
contamination, are not necessarily observable even when an inspection is
undertaken. Contractual indemnities may not be obtainable, and the Company may
be required to assume the risk of the physical condition of the properties in
addition to the risk that the properties may not perform in accordance with the
Company's expectations.

EXPLORATION RISKS

With the sale of its D-J Basin properties in 1996, and its initiation of
exploration activities in the Gulf of Mexico, the Company currently is spending
a large portion of its capital budget on exploration. Exploration activities
involve substantially more risk than development or exploitation activities.
Although the Company believes that its use of 3-D seismic data and other
advanced technologies should increase the probability of success of its
exploratory wells and should reduce average finding costs through elimination of
prospects that might otherwise be drilled solely on the basis of 2-D seismic
data and other traditional methods, exploratory drilling remains a speculative
activity. Even when fully utilized and properly interpreted, 3-D seismic data
and visualization techniques only assist geoscientists in identifying subsurface
structures and hydrocarbon indicators and do not conclusively allow the
interpreter to know if hydrocarbons will in fact be present in such structures.
In addition, the use of 3-D seismic data and such technologies requires greater
predrilling expenditures than traditional drilling strategies and the Company
could incur losses as a result of such expenditures. Failure of the Company's
exploration activities would have a material adverse effect on the Company's
future results of operations and financial condition. The Company had conducted
no previous operations in the Gulf of Mexico prior to the opening of its
regional office in late 1995 in Houston, Texas. This operating area is highly
competitive and the Company's success in its activities there will depend on its
ability to attract and retain geoscientists and other professional staff with
extensive experience operating in the area. The Company's Houston office
currently has a staff that includes seven geoscientists and petroleum engineers
plus 3 engineering consultants, all of whom are experienced in Gulf Coast
operations. Loss of these experienced personnel could have a material adverse
impact on the Company's ability to compete in this area.

FUTURE CAPITAL REQUIREMENTS

The Company will require substantial additional capital to further develop
and explore its properties and to acquire additional properties. Cash flows from
operations, to the extent available, will be used to fund these expenditures.
The Company may seek additional capital from traditional reserve base
borrowings, equity and debt offerings, joint ventures, and/or production payment
financing. The Company's ability to access additional capital will depend
significantly on its continued success in exploring for and developing its
reserves and the status of the capital markets at the time such capital is
sought. Accordingly,

5
<PAGE>
there can be no assurance that capital will be available to the Company from any
source or that, if available, it will be on terms acceptable to the Company.
Should sufficient capital not be available, the development and exploration of
the Company's properties could be delayed and, accordingly, the implementation
of the Company's business strategy would be adversely affected.

MARKETING OF PRODUCTION; SEASONALITY

The marketability of Basin's production depends upon the availability and
capacity of gathering systems and pipelines, the effects of federal and state
regulation of such production and transportation, general economic conditions,
supply of and demand for oil and natural gas, all of which could adversely
affect Basin's ability to market its production. Demand for natural gas is
highly seasonal, with demand generally higher in the colder winter months and in
the hot summer months. As a result, the price received for spot market natural
gas may vary significantly between seasonal periods. To date, the Company
generally has been able to sell its available spot market natural gas at
prevailing spot market prices, such that volumes sold have not materially
fluctuated seasonally. There is no assurance, however, that the Company will be
able to continue to achieve this result.

CONCENTRATION OF VALUE

As of the date of this Prospectus, a significant portion of Basin's
production is concentrated in two wells on one platform in the Gulf of Mexico.
If mechanical problems, storms, or other events that caused curtailment or
cessation of such production were to occur, Basin's cash flow would be
materially adversely affected. The Company will remain vulnerable to a
disproportionate impact of delays or interruptions of production from these
wells until it develops a more diversified production base including additional
properties.

ESTIMATES OF RESERVES AND RELATED DATA

Numerous uncertainties are 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 producer. The
reserve data set forth in this Prospectus or incorporated herein by reference
represents only estimates based on available geological, geophysical, production
and engineering data, the extent, quality and reliability of which vary. Oil and
gas reserve engineering is a subjective process of estimating accumulations of
oil and gas that cannot be measured in an exact manner, and estimates of other
engineers might differ materially from those shown. The accuracy of any reserve
estimate is a function of the quality and quantity of available data,
engineering and geological interpretation and judgment. In addition, the
estimates of future net cash flow from proved reserves of the Company and the
present value thereof are based upon certain assumptions about future production
levels, prices, costs and participation, if any, by third parties in the
development of the Company's reserves that may not prove correct over time, for
reasons which may or may not be under the control of or known to the Company.
Any significant variance from these assumptions could materially affect the
quantity and value of the Company's reserves as compared to the estimates
contained in this Prospectus.

FLUCTUATIONS IN QUARTERLY RESULTS

Basin's quarterly results of operations may fluctuate significantly as a
result of variations in oil and gas prices and variations in the Company's
drilling activities. Drilling activities can be affected by a number of factors
including the need to utilize capital for new acquisitions, availability of
permits for drilling or recompletions, weather, seasonal restrictions (such as
growing crops and winter game restrictions), governmental regulations and
available cash flow.

OPERATING HAZARDS

The oil and gas business involves a variety of operating risks, including
the risk of fire, explosion, blow-out, pipe failure, casing collapse, stuck
tools, abnormally pressured formations and environmental hazards

6
<PAGE>
such as oil spills, gas leaks, pipeline ruptures and discharges of toxic gases,
the occurrence of any of which could result in substantial losses to Basin due
to injury and loss of life, loss of or damage to wellbores and/ or drilling or
production equipment, costs of overcoming downhole problems, severe damage to
and destruction of property, natural resources and equipment, pollution and
other environmental damage, clean-up responsibilities, regulatory investigation
and penalties and suspension of operations. Gathering systems and processing
facilities are subject to many of the same hazards and any significant problems
related to those facilities could adversely affect Basin's ability to market its
production. Moreover, offshore operations are subject to a variety of operating
risks peculiar to the marine environment, such as hurricanes or other adverse
weather conditions. Basin maintains insurance against some, but not all,
potential risks; however, there can be no assurance that such insurance will be
adequate to cover any losses or exposure for liability. Insurance may not cover
downhole operating risks, such as the costs of retrieving stuck equipment.
Furthermore, Basin cannot predict whether insurance will continue to be
available at premium levels that justify its purchase or whether insurance will
be available at all to cover the risks faced by the Company.

ENVIRONMENTAL REGULATION

The drilling for and production, handling, transportation and disposal of
oil and gas and by-products are subject to extensive regulation under federal,
state and local environmental laws. In most instances, the applicable regulatory
requirements relate to water and air pollution control and solid waste
management measures, permitting requirements, or restrictions on operations in
environmentally sensitive areas, such as coastal zones, wetlands, and wildlife
habitat. Environmental assessments have not been performed on all of Basin's
properties. To date, expenditures for environmental control facilities and for
remediation have not been significant in relation to the results of operations
of Basin. Basin believes, however, that the trend toward stricter standards in
environmental legislation and regulation is likely to continue. Offshore
operations are subject to more extensive governmental regulation, including
regulation that may, in certain circumstances, impose absolute liability for
environmental damage and allow interruption or termination of business
activities by government authorities based on environmental or other
considerations. The Oil Pollution Act of 1990 (the "OPA") also requires proof of
financial responsibility to cover costs of potential oil spills; the amount of
such required coverage ranges from $35 million to $150 million based on federal
risk assessment. From time to time, legislation has been introduced in Congress
which would reclassify oil and gas production wastes as "hazardous waste" under
the Resource Conservation and Recovery Act. If such legislation were to pass, it
could have a significant adverse impact on the operating costs of Basin, as well
as the oil and gas industry in general. Initiatives regulating the disposal of
exploration and production waste are also pending or have been enacted in
certain states, including states in which Basin conducts operations, and these
various initiatives could have a similar impact on the Company.

GOVERNMENTAL REGULATION

Development, production and sale of oil and gas are subject to extensive
federal, state and local governmental regulation which may be changed from time
to time in response to economic or political conditions. Matters subject to
regulation include, but are not limited to, permits for drilling operations,
drilling, plugging and reclamation bonds, operational practices and reporting,
the spacing of wells, unitization and pooling of properties, taxation and
environmental protection. The Minerals Management Service of the United States
Department of the Interior ("MMS") has proposed regulations for valuation of
crude oil and natural gas produced from federal leases, including offshore
leases, that could require payment of royalties on the basis of indices or
benchmarks that may not reflect actual prices received by the Company for its
production. The Federal Energy Regulatory Commission has promulgated major
regulatory initiatives over the past several years which have had a significant
impact on natural gas pricing and natural gas pipeline operations, services and
rates. Those changes have significantly altered the marketing of natural gas.
Although the purpose of these changes is generally to enhance competition in
natural gas marketing, the effect of these changes on the Company's ability to
market its gas at reasonable

7
<PAGE>
prices from any given property is uncertain. From time to time, regulatory
agencies have imposed price controls and limitations on production by
restricting the rate of flow of oil and gas wells below actual production
capacity in order to conserve supplies of oil and gas. Under the Outer
Continental Shelf Lands Act ("OCSLA") the MMS regulates development and
production of oil and gas in federal waters in the Gulf of Mexico and may
suspend or terminate operations for violation of MMS rules. Any such suspension
or termination could materially and adversely affect the Company's financial
condition and operations. There are many legislative proposals pending in
Congress and in the legislatures of various states that, if enacted, might
significantly affect the oil and gas industry. Basin is not able to predict what
will be enacted and thus what effect, if any, such proposals would have on
Basin.

COMPETITION

Competition in the oil and gas industry is intense, particularly with
respect to the acquisition of producing properties and proved undeveloped
acreage and the acquisition of interests in offshore exploration prospects in
the Gulf of Mexico. Major and independent oil and gas companies, as well as
individuals and drilling programs, actively bid for desirable oil and gas
properties, as well as for the equipment and labor required to operate and
develop such properties. A number of Basin's competitors have financial
resources and exploration and development budgets that are substantially greater
than those of Basin, which may adversely affect the Company's ability to compete
successfully. In addition, many of the Company's larger competitors may be
better able to respond to factors that affect the demand for oil and natural gas
production such as changes in worldwide oil and natural gas prices and levels of
production, the cost and availability of alternative fuels, and the application
of government regulations. The Company commenced operations in the Gulf of
Mexico area during 1996, where it had not previously been active. Competition
from major and large independent oil and gas companies is significantly greater
in this area than in the Rocky Mountain region, where the Company had conducted
all of its previous operations.

PRINCIPAL STOCKHOLDER

Basin's principal stockholder, Michael S. Smith, together with members of
his immediate family and trustees for their benefit, beneficially own
approximately 30% of Basin's outstanding shares. As a result, Mr. Smith is in a
position to substantially influence the outcome of stockholder votes on the
election of directors and other matters. In addition, if Mr. Smith were to sell
a significant number of his shares, the prevailing market price of the Common
Stock could be adversely affected.

DEPENDENCE ON KEY PERSONNEL

Basin depends to a large extent on the services of its founder and CEO,
Michael Smith and certain other senior management personnel. The loss of the
services of Mr. Smith or other key personnel could have a potential adverse
effect on Basin's operations.

ANTI-TAKEOVER PROVISIONS

Basin's Restated Certificate of Incorporation and Bylaws and the provisions
of the Delaware General Corporation Law make it more difficult to change control
of Basin and replace incumbent management. The Company adopted a Stockholders'
Rights Plan in 1996, pursuant to which holders of Common Stock of the Company
received rights which are exercisable if a person or group of affiliated persons
acquires 15% of the Company's outstanding Common Stock or commences a tender or
exchange offer, the consummation of which would result in ownership of 15% or
more of the Company's outstanding Common Stock. See "Description of Capital
Stock--Stockholders' Rights Plan." In addition, the Company has entered into
agreements with certain of its executive officers which would require additional
payments by the Company if such officers' employment were terminated upon a
change of control.

8
<PAGE>
THE COMPANY

GENERAL

Basin Exploration, Inc. ("Basin" or the "Company") is an independent oil and
gas exploration and production company operating in the United States. The
Company's business objective is to efficiently increase its proved oil and gas
reserves in order to grow production, cash flow, and earnings per share. The
Company seeks to accomplish this by exploring for new oil and gas reserves and
acquiring proved properties with exploitation or development potential,
utilizing advanced technologies.

The Company currently conducts exploration activities exclusively in the
shallow waters of the Gulf of Mexico, offshore Louisiana and Texas. Basin seeks
acquisition opportunities both in the vicinity of the Company's exploration
activities offshore and in certain geographic areas onshore where the Company's
staff has had extensive experience, including the Rocky Mountains and onshore
Gulf Coast areas.

Basin's reserves are located primarily in the Gulf of Mexico and in the
Powder River and Green River Basins in Wyoming. At December 31, 1996, the
Company's estimated proved reserves totaled approximately 7.9 MMBbl and 29.7 Bcf
of natural gas, or 76.9 Bcfe. Most of Basin's proved oil and gas reserves are
attributable to Company-operated properties. A significant portion of Basin's
reserves at the beginning of 1996 were located in the Denver-Julesburg ("D-J")
Basin in eastern Colorado, but such reserves were sold in 1996 to provide funds
for other operations, including initiation of operations in the Gulf of Mexico.

Since commencing operations in the Gulf of Mexico in 1996, the Company has
participated in drilling ten wells, of which five have been or are expected to
be completed as producers. The Company has operated all but one of these wells,
with an average working interest at the time of drilling of approximately 51%.
Five of the ten wells drilled to date have been drilled since July 1, 1997,
reflecting a recent acceleration in activity after a start-up period during
which the Company assembled its initial prospect inventory. As of the date of
this Prospectus, the Company has assembled a Gulf of Mexico leasehold inventory
of 96,421 gross acres, comprising 63,248 net acres, with more than 20 identified
potential exploration prospects, all of which are supported by the Company's
interpretations of three-dimensional ("3-D") seismic data. In order to reduce
the risks and costs for acreage, drilling and completion operations, the Company
uses 3-D seismic and computer-aided exploration and exploitation technology in
virtually all of its activities in the Gulf of Mexico. The Company has also
closed acquisitions of Gulf of Mexico proved properties totaling more than $18
million in 1997 through the date of this Prospectus.

Two of the Gulf of Mexico wells that the Company has completed, both located
on Eugene Island Block 65, commenced production in August 1997 and now account
for a substantial portion of the Company's total oil and gas production. The
three other drilled wells that the Company anticipates will commence production,
plus an additional Gulf of Mexico well in which the Company acquired an interest
after it was drilled and completed, are temporarily suspended pending additional
development. Three of these wells, one each on East Cameron Block 378, Eugene
Island Block 83, and West Cameron Block 56, are expected to commence production
shortly before or during the first quarter of 1998.

The Company's onshore oil and gas assets are comprised of properties that
generally have a relatively stable, long-lived production profile. The Company
has identified potential for additional drilling, well deepenings, or secondary
recovery on several of the more valuable properties. The Company intends to
continue to exploit, and to pursue acquisitions to expand, this asset base.

The Company currently has a capital budget established for 1997 of
approximately $60 million, allocated approximately equally to exploration
activities, development, and acquisitions that have already been consummated.
This budget could be increased for additional acquisitions or for development of
additional exploratory discoveries. The 1997 capital budget represents a
significant increase from capital expenditures on oil and gas properties in 1996
and 1995 of approximately $23 million and $16 million, respectively.

9
<PAGE>
HISTORY

Basin commenced operations in 1981 and completed an initial public offering
of its common stock in 1992. From its inception through 1991, the Company
primarily acquired, developed and exploited properties in the D-J Basin. Such
operations were expanded into other areas within the Rocky Mountain region in
1992, and the Company initiated Rocky Mountain exploration activities in 1993.
By December 31, 1994, the Company's estimated proved oil and gas reserves had
grown to 247.2 Bcfe, of which 169.2 Bcfe, or 68.4%, were located in the D-J
Basin.

From 1992 through 1994, the D-J Basin was one of the most active drilling
areas in the United States and the Company was one of the more active and
successful operators in the area. As the basin became increasingly exploited,
however, it was the Company's assessment and experience that the number and
quality of development projects in the area significantly diminished.

During 1995, the Company's capital expenditures on oil and gas properties
declined to $16 million, from $67 million the year before, and its estimated
proved oil and gas reserves declined to 207.1 Bcfe at year-end. Principal
factors contributing to these reductions included: (i) a smaller and
lower-quality inventory of D-J Basin exploitation projects; (ii) insufficient
success in identifying acquisition opportunities and viable exploration plays in
the Company's other Rocky Mountain focus areas; and (iii) liquidity constraints
caused largely by the Company's higher debt levels.

In direct response to these developments, the Company implemented a
significant redirection of its business strategy and operations between
late-1995 and mid-1996, including: (i) the addition of new financial, technical
and business development members to its senior management; (ii) the sale of the
Company's D-J Basin assets, including approximately 70% of the Company's
estimated proved reserves, for $123.5 million; (iii) establishment of a
Houston-based Gulf of Mexico exploration team through the hiring of senior
geoscientists and petroleum engineers with substantial experience operating in
the shallow waters of the Gulf of Mexico; and (iv) a substantial reduction in
corporate general and administrative overhead.

Since the redirection of its business, the Company has significantly
increased its proved reserves and production base through Gulf of Mexico
drilling activity and acquisitions, and it has established a sizable inventory
of Gulf of Mexico leaseholds and prospects for future exploratory drilling.

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<PAGE>
USE OF PROCEEDS

Unless a Prospectus Supplement indicates otherwise, the net proceeds to be
received by the Company from the sale of the Securities will be used for
repayment of indebtedness, to finance the Company's operations, for the
continued development of its oil and gas properties and for other general
corporate purposes. Pending such application, such net proceeds may be invested
in short-term marketable securities.

RATIO OF EARNINGS TO FIXED CHARGES

The ratio of earnings to fixed charges for the Company was as follows for
the years ended December 31, 1996, 1995, 1994, 1993 and 1992:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------
1996 1995 1994 1993
----- ----- ----- -----
<S> <C> <C> <C> <C>
Ratio of earnings to fixed charges (unaudited)....................... 9.6 (a) 2.6 3.5

1992
-----
<S> <C>
Ratio of earnings to fixed charges (unaudited)....................... 3.2
</TABLE>

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

(a) Earnings did not cover fixed charges in 1995 by $27.3 million.

As used in the above calculations, "earnings" means earnings before income
taxes and fixed charges, and "fixed charges" means interest on all indebtedness,
that portion of rental expense that management believes to be representative of
interest expense and capitalized interest.

DESCRIPTION OF DEBT SECURITIES

Debt Securities may be issued from time to time in one or more series by the
Company. The Debt Securities will constitute either indebtedness designated as
Senior Indebtedness ("Senior Debt Securities"), indebtedness designated as
Senior Subordinated Indebtedness ("Senior Subordinated Debt Securities") or
indebtedness designated as Subordinated Indebtedness ("Subordinated Debt
Securities"). The particular terms of each series of Debt Securities offered by
a particular Prospectus Supplement will be described therein. Senior Debt
Securities, Senior Subordinated Debt Securities and Subordinated Debt Securities
will each be issued under a separate indenture (individually an "Indenture" and
collectively the "Indentures") to be entered into prior to the issuance of such
Debt Securities. The Indentures will be substantially identical, except for
provisions relating to subordination. See "Subordination of Senior Subordinated
Debt Securities and Subordinated Debt Securities." A copy of the form of the
Indenture is filed as an Exhibit to the Registration Statement of which this
Prospectus is a part. There will be a separate Trustee (individually a "Trustee"
and collectively the "Trustees") under each Indenture. Information regarding the
Trustee under an Indenture will be included in any Prospectus Supplement
relating to the Debt Securities issued thereunder.

The following discussion includes a summary description of the material
terms of the Indentures, other than terms which are specific to a particular
series of Debt Securities and which will be described in the Prospectus
Supplement relating to such series. The following summaries do not purport to be
complete and are subject to, and are qualified in their entirety by reference
to, all of the provisions of the Indentures, including the definitions therein
of certain terms capitalized in this Prospectus. Wherever particular Sections,
Articles or defined terms of the Indentures are referred to herein or in a
Prospectus Supplement, such Sections, Articles or defined terms are incorporated
herein or therein by reference.

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GENERAL

The Debt Securities will be general unsecured obligations of the Company.
The Indentures do not limit the aggregate amount of Debt Securities which may be
issued thereunder, and Debt Securities may be issued thereunder from time to
time in separate series up to the aggregate amount from time to time authorized
for each series. Debt Securities of a series may be issuable in registered form
without coupons ("Registered Debt Securities"), in bearer form with or without
coupons attached ("Bearer Debt Securities") or in the form of one or more global
Securities in registered or bearer form (each, a "Global Security"). Bearer Debt
Securities, if any, will be offered only to non-United States persons and to
offices located outside the United States of certain United States financial
institutions.

The applicable Prospectus Supplement or Prospectus Supplements will describe
the following terms of the series of Debt Securities in respect of which this
Prospectus is being delivered: (1) the title of such Debt Securities; (2) any
limit on the aggregate principal amount of such Debt Securities; (3) whether
such Debt Securities will be issued as Registered Debt Securities, Bearer Debt
Securities or any combination thereof, and any limitation on issuance of such
Bearer Debt Securities and any provisions regarding the transfer or exchange of
such Bearer Debt Securities, including exchange for Registered Debt Securities
of the same series; (4) whether any of such Debt Securities are to be issuable
in permanent global form and, if so, the terms and conditions, if any, upon
which interests in such Debt Securities in global form may be exchanged, in
whole or in part, for the individual Debt Securities represented thereby; (5)
the person to whom any interest on any Debt Security of the series shall be
payable, if other than the person in whose name the Debt Security is registered
on the Regular Record Date; (6) the date or dates on which such Debt Securities
will mature; (7) the rate or rates of interest, if any, or the method of
calculation thereof, which such Debt Securities will bear, and the basis upon
which interest will be calculated if other than that of a 360-day year of twelve
30-day months; (8) the date or dates from which any such interest will accrue,
the Interest Payment Dates on which any such interest on such Debt Securities
will be payable, the Regular Record Date for any interest payable on any
Interest Payment Date and any provision for the deferral of interest payments;
(9) whether any such interest will be payable in cash, through the issuance of
additional Debt Securities, through the issuance of Common Stock, through some
combination of cash and additional Debt Securities or through some combination
of cash and Common Stock; (10) the place or places where the principal of,
premium, if any, and interest on such Debt Securities will be payable; (11) the
period or periods within which, the events upon the occurrence of which, and the
price or prices at which, such Debt Securities may, pursuant to any optional or
mandatory provisions, be redeemed or purchased, in whole or in part, by the
Company and any terms and conditions relevant thereto; (12) the obligations of
the Company, if any, to redeem or repurchase such Debt Securities pursuant to
any sinking fund or analogous provisions or at the option of the Holders
thereof; (13) the denominations in which any such Debt Securities will be
issuable, if other than denominations of US $1,000 and any integral multiple
thereof; (14) the units of payment of principal of, premium, if any, and
interest on such Debt Securities if other than US dollars, which units may
consist of currency, currencies, currency unit or units, or securities; (15) any
index or formula to be used to determine the amount of payments of principal,
premium, if any, and interest on such Debt Securities, and any commodities,
currencies, currency units or indices, or value, rate or price, relevant to such
determination; (16) if the principal of, premium, if any, or interest on such
Debt Securities is to be payable, at the election of the Company or a Holder
thereof, in one or more currencies or currency units other than that or those in
which such Debt Securities are stated to be payable, the currencies or currency
units in which payment of the principal of, premium, if any, and interest on
such Debt Securities as to which election is made shall be payable, and the
periods within which and the terms and conditions upon which such election is to
be made; (17) if other than the principal amount thereof, the portion of the
principal amount of such Debt Securities of the series which will be payable
upon acceleration of the Maturity thereof; (18) whether such Debt Securities are
subordinate in right of payment to any Senior Indebtedness of the Company and,
if so, the terms and conditions of such subordination and the aggregate
principal amount of such Senior Indebtedness outstanding as of a recent date;
(19) any covenants to which the Company may be subject with respect to such Debt
Securities;

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(20) the applicability of the provisions described under "Defeasance" below;
(21) the terms and conditions, if any, pursuant to which such Debt Securities
are convertible into or exchangeable for Common Stock or other securities; (22)
if the principle amount payable at the Stated Maturity of the Debt Securities is
not determinable upon original issuance or at any time prior to Maturity, the
amount that is deemed to be the principal amount outstanding at any time; (23)
the terms of any guarantee of the payment of principal and interest on the Debt
Securities; (24) any additions, deletions or changes in the Events of Default
with respect to the Debt Securities and (25) any other terms of such Debt
Securities.

Debt Securities may be issued at a discount from their principal amount.
United States federal income tax considerations and other special considerations
applicable to any such Original Issue Discount Securities will be described in
the applicable Prospectus Supplement.

If the purchase price of any series of Debt Securities is denominated in a
foreign currency or currencies or a foreign currency unit or units or if the
principal of, premium, if any, and interest on any series of Debt Securities are
payable in a foreign currency or currencies, a foreign currency unit or units or
in securities, the restrictions, elections, general tax considerations, specific
terms and other information with respect to such series of Debt Securities will
be set forth in the applicable Prospectus Supplement.

Debt Securities may be issued from time to time with payment terms which are
calculated by reference to the value, rate or price of one or more commodities,
currencies, currency units or indices. Holders of such Debt Securities may
receive a principal amount (including premium, if any) on any principal payment
date, or a payment of interest on any interest payment date, that is greater
than or less than the amount of principal (including premium, if any) or
interest otherwise payable on such dates, depending upon the value, rate or
price on the applicable dates of the applicable currency, currency unit,
commodity or index. Information as to the methods for determining the amount of
principal, premium, if any, or interest payable on any date, the currencies,
currency units, commodities or indices to which the amount payable on such date
is linked and any additional tax considerations will be set forth in the
applicable Prospectus Supplement.

SENIOR DEBT SECURITIES

The Senior Debt Securities will rank pari passu with all other unsecured and
unsubordinated debt of the Company and senior to the Senior Subordinated Debt
Securities and Subordinated Debt Securities.

SUBORDINATION OF SENIOR SUBORDINATED DEBT SECURITIES, SUBORDINATED DEBT
SECURITIES AND GUARANTEES

The payment of the principal of, premium, if any, and interest on the Senior
Subordinated Debt Securities and the Subordinated Debt Securities will, to the
extent set forth in the respective Indentures governing such Senior Subordinated
Debt Securities and Subordinated Debt Securities, be subordinated in right of
payment to the prior payment in full of all Senior Indebtedness. Upon any
payment or distribution of assets to creditors upon any liquidation,
dissolution, winding up, reorganization, assignment for the benefit of
creditors, marshalling of assets or any bankruptcy, insolvency or similar
proceedings of the Company, the holders of all Senior Indebtedness will be
entitled to receive payment in full of all amounts due or to become due thereon
before the Holders of the Senior Subordinated Debt Securities or the
Subordinated Debt Securities will be entitled to receive any payment in respect
of the principal of, premium, if any, or interest on such Senior Subordinated
Debt Securities or Subordinated Debt Securities, as the case may be. In the
event of the acceleration of the maturity of any Senior Subordinated Debt
Securities or Subordinated Debt Securities, the holders of all Senior
Indebtedness will be entitled to receive payment in full of all amounts due or
to become due thereon before the Holders of the Senior Subordinated Debt
Securities or Subordinated Debt Securities, as the case may be, will be entitled
to receive any payment upon the principal of, premium, if any, or interest on
such Senior Subordinated Debt Securities or Subordinated Debt Securities, as the
case may be. No payments on account of principal, premium, if any, or interest
in respect of the Senior Subordinated Debt Securities or Subordinated Debt

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Securities may be made if there shall have occurred and be continuing a default
in the payment of principal of (or premium, if any) or interest on any Senior
Indebtedness beyond any applicable grace period, or a default with respect to
any Senior Indebtedness permitting the holders thereof to accelerate the
maturity thereof, or if any judicial proceedings shall be pending with respect
to any such default. For purposes of the subordination provisions, the payment,
issuance or delivery of cash, property or securities (other than stock, and
certain subordinated securities, of the Company) upon conversion, redemption or
otherwise of a Senior Subordinated Debt Security or Subordinated Debt Security
will be deemed to constitute payment on account of the principal of such Senior
Subordinated Debt Security or Subordinated Debt Security, as the case may be.

By reason of such provisions, in the event of insolvency, holders of Senior
Subordinated Debt Securities and Subordinated Debt Securities may recover less,
ratably, than holders of Senior Indebtedness with respect thereto.

The term "Senior Indebtedness," means the obligations of the Company with
respect to (i) Indebtedness of the Company under the Bank Credit Facility and
any renewal, refunding, refinancing, replacement or extension thereof and (ii)
any other Indebtedness of the Company (other than the Securities), whether
outstanding on the date of this Indenture or thereafter created, incurred or
assumed, and any renewal, refunding, refinancing, replacement or extension
thereof, unless, in the case of any particular Indebtedness, the instrument
creating or evidencing the same or pursuant to which the same is outstanding
expressly provides that such Indebtedness shall not be senior in right of
payment to the Securities or that such indebtedness is PARI PASSU with or junior
to the Securities. Notwithstanding the foregoing, Senior Indebtedness shall not
include (i) indebtedness of the Company to a subsidiary of the Company, (ii)
amounts owed for goods, materials or services purchased in the ordinary course
of business, (iii) indebtedness incurred in violation of this Indenture, (iv)
amounts payable or any other Indebtedness to employees of the Company or any
Subsidiary of the Company, (v) any liability for Federal, state, local or other
taxes owed or owing by the Company, (vi) any indebtedness of the Company that,
when incurred and without regard to any election under Section 1111(b) of the
United States Bankruptcy Code, was without recourse to the Company, and (vii)
indebtedness evidenced by Senior Subordinated Debt Securities.

If this Prospectus is being delivered in connection with a series of Senior
Subordinated Debt Securities or Subordinated Debt Securities, the accompanying
Prospectus Supplement or the information incorporated herein by reference will
set forth the approximate amount of Senior Indebtedness outstanding as of the
end of the Company's most recent fiscal quarter.

FORM, EXCHANGE, REGISTRATION, CONVERSION, TRANSFER AND PAYMENT

Debt Securities are issuable in definitive form as Registered Debt
Securities, as Bearer Debt Securities or both. Unless otherwise indicated in an
applicable Prospectus Supplement, Bearer Debt Securities will have interest
coupons attached. Debt Securities are also issuable in temporary or permanent
global form.

Registered Debt Securities of any series (other than a Global Security) will
be exchangeable for other Registered Debt Securities of the same series and of a
like aggregate principal amount and tenor of different authorized denominations.
In addition, with respect to any series of Bearer Debt Securities, at the option
of the holder, subject to the terms of the Indenture, such Bearer Debt
Securities (with all unmatured coupons, except as provided below, and all
matured coupons in default) will be exchangeable into Registered Debt Securities
of the same series of any authorized denominations and of a like aggregate
principal amount and tenor. Bearer Debt Securities surrendered in exchange for
Registered Debt Securities between a Regular Record Date or a Special Record
Date and the relevant date for payment of interest shall be surrendered without
the coupon relating to such date for payment of interest, and interest accrued
as of such date will not be payable in respect of the Registered Debt Security
issued in exchange

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for such Bearer Debt Security, but will be payable only to the holder of such
coupon when due in accordance with the terms of the Indenture.

In connection with its sale during the restricted period (as defined below),
no Bearer Debt Security (including a Debt Security in permanent global form that
is either a Bearer Debt Security or exchangeable for Bearer Debt Securities)
shall be mailed or otherwise delivered to any location in the United States (as
defined under "--Limitations on Issuance of Bearer Debt Securities") and a
Bearer Debt Security may be delivered outside the United States in definitive
form in connection with its original issuance only if prior to delivery the
person entitled to receive such Bearer Debt Security furnishes written
certification, in the form required by the Indenture, to the effect that such
Bearer Debt Security is owned by: (a) a person (purchasing for its own account)
who is not a United States person (as defined under "--Limitations on Issuance
of Bearer Debt Securities"); (b) a United States person who (i) is a foreign
branch of a United States financial institution purchasing for its own account
or for resale or (ii) acquired such Bearer Debt Security through the foreign
branch of a United States financial institution and who for purposes of the
certification holds such Bearer Debt Security through such financial institution
on the date of certification and, in either case, such United States financial
institution certifies to the Company or the distributor selling the Bearer Debt
Security within a reasonable time stating that it agrees to comply with the
requirements of Section 165(j)(3)(A), (B) or (C) of the United States Internal
Revenue Code of 1986, as amended (the "Code"), and the regulations thereunder,
or (c) a United States or foreign financial institution for purposes of resale
within the "restricted period" as defined in United States Treasury Regulations
Section 1.163-5(c)(2)(i)(D)(7). A financial institution described in clause (c)
of the preceding sentence (whether or not also described in clauses (a) and (b))
must certify that it has not acquired the Bearer Debt Security for purpose of
resale, directly or indirectly, to a United States person or to a person within
the United States or its possessions. In the case of a Bearer Debt Security in
permanent global form, such certification must be given in connection with
notation of a beneficial owner's interest therein in connection with the
original issuance of such Debt Security or upon exchange of a portion of a
temporary global Debt Security.

Debt Securities may be presented for exchange as provided above, and
Registered Debt Securities may be presented for registration of transfer (with
the form of transfer endorsed thereon duly executed), at the office or agency of
the Company maintained for such purposes and at any other office or agency
maintained for such purpose with respect to any series of Debt Securities and
referred to in the applicable Prospectus Supplement, without a service charge
and upon payment of any taxes and other governmental charges as described in the
Indenture. Such transfer or exchange will be effected upon the Company or its
agent, as the case may be, being satisfied with the documents of title and
identity of the person making the request.

The Company shall not be required to (i) issue, register the transfer of or
exchange Debt Securities of any series during a period of 15 days prior to the
mailing of a notice of redemption of Debt Securities of that series; or (ii)
register the transfer of or exchange any Debt Security, or portion thereof,
called for redemption, except that any Bearer Debt Security exchangeable for a
Registered Debt Security of that series may be so exchanged during the period
preceding the redemption date therefor which is simultaneously surrendered for
redemption.

PAYMENT AND PAYING AGENTS

Unless otherwise indicated in the applicable Prospectus Supplement, payment
of principal of (and premium, if any) and interest on Bearer Debt Securities
will be payable, subject to any applicable laws and regulations, in the
designated currency or currency unit, at the offices of such Paying Agents
("Paying Agents") outside the United States as the Company may designate from
time to time, at the option of the holder, by check or by transfer to an account
maintained by the payee with a bank located outside the United States; provided,
however, that the written certification described above under "--Form, Exchange,
Registration, Conversion, Transfer and Payment" has been delivered prior to the
first actual payment of

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interest. Unless otherwise indicated in the applicable Prospectus Supplement,
payment of interest on Bearer Debt Securities on any Interest Payment Date will
be made only against surrender to the Paying Agent of the coupon relating to
such Interest Payment Date. No payment with respect to any Bearer Debt Security
will be made at any office or agency of the Company in the United States or by
check mailed to any address in the United States or by transfer to any account
maintained with a bank located in the United States, nor shall any payments be
made in respect of Bearer Debt Securities upon presentation to the Company or
its designated Paying Agents within the United States. Notwithstanding the
foregoing, payments of principal of (and premium, if any) and interest on Bearer
Debt Securities denominated and payable in US dollars will be made at the office
of the Company's Paying Agent in the United States, if (but only if) payment of
the full amount thereof in US dollars at all offices or agencies outside the
United States is illegal or effectively precluded by exchange controls or other
similar restrictions.

Unless otherwise indicated in the applicable Prospectus Supplement, payment
of principal of (and premium, if any) and interest on Registered Debt Securities
will be made in the designated currency or currency unit at the office of such
Paying Agent or Paying Agents as the Company may designate from time to time,
except that at the option of the Company payment of any interest may be made by
check mailed to the address of the person entitled thereto as such address shall
appear in the Security Register. Unless otherwise indicated in an applicable
Prospectus Supplement, payment of any installment of interest on Registered Debt
Securities will be made to the person in whose name such Registered Debt
Security is registered at the close of business on the Regular Record Date for
such interest.

Unless otherwise indicated in the applicable Prospectus Supplement, the
Corporate Trust Office of the Trustee will be designated as a Paying Agent for
the Trustee for payments with respect to Debt Securities which are issuable
solely as Registered Debt Securities, and the Company will maintain a Paying
Agent outside the United States for payments with respect to Debt Securities
(subject to limitations described above in the case of Bearer Debt Securities)
which are issued solely as Bearer Debt Securities, or as both Registered Debt
Securities and Bearer Debt Securities. Any Paying Agents outside the United
States and any other Paying Agents in the United States initially designated by
the Company for the Debt Securities will be named in an applicable Prospectus
Supplement. The Company may at any time designate additional Paying Agents or
rescind the designation of any Paying Agent or approve a change in the office
through which any Paying Agent acts, except that, if Debt Securities of a series
are issued solely as Registered Debt Securities, the Company will be required to
maintain a Paying Agent in each Place of Payment for such series and, if Debt
Securities of a series are issued as Bearer Securities, the Company will be
required to maintain (i) a Paying Agent in the United States for principal
payments with respect to any Registered Debt Securities of the series (and for
payments with respect to Bearer Debt Securities of the series in the
circumstances described above, but not otherwise), and (ii) a Paying Agent in a
Place of Payment located outside the United States where Securities of such
series and any coupons appertaining thereto may be presented and surrendered for
payment.

All monies paid by the Company to a Paying Agent for the payment of
principal of and any premium or interest on any Debt Security which remain
unclaimed at the end of two years after such principal, premium or interest
shall have become due and payable will (subject to applicable escheat laws) be
repaid to the Company and the holder of such Debt Security or any coupon will
thereafter look only to the Company for payment thereof.

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TEMPORARY GLOBAL SECURITIES

If so specified in the applicable Prospectus Supplement, all or any portion
of the Debt Securities of a series which are issuable as Bearer Debt Securities
will initially be represented by one or more temporary global Debt Securities,
without interest coupons, to be deposited with a common depository in London for
the Euroclear System ("Euroclear") and CEDEL S.A. ("CEDEL") for credit to the
designated accounts. On and after the date determined as provided in any such
temporary global Debt Security and described in the applicable Prospectus
Supplement, each such temporary global Debt Security will be exchangeable for
definitive Bearer Debt Securities, definitive Registered Debt Securities or all
or a portion of a permanent global security, or any combination thereof, as
specified in the applicable Prospectus Supplement, but, unless otherwise
specified in the applicable Prospectus Supplement, only upon written
certification in the form and to the effect described under "--Form, Exchange,
Registration, Conversion, Transfer and Payment." No Bearer Debt Security
delivered in exchange for a portion of a temporary global Debt Security will be
mailed or otherwise delivered to any location in the United States in connection
with such exchange.

Unless otherwise specified in the applicable Prospectus Supplement, interest
in respect of any portion of a temporary global Debt Security payable in respect
of an Interest Payment Date occurring prior to the issuance of definitive Debt
Securities or a permanent global Debt Security will be paid to each of Euroclear
and CEDEL with respect to the portion of the temporary global Debt Security held
for its account. Each of Euroclear and CEDEL will undertake in such
circumstances to credit such interest received by it in respect of a temporary
global Debt Security to the respective accounts for which it holds such
temporary global Debt Security only upon receipt in each case of written
certification in the form and to the effect described above under "--Form,
Exchange, Registration, Conversion, Transfer and Payment" as of the relevant
Interest Payment Date regarding the portion of such temporary global Debt
Security on which interest is to be so credited.

PERMANENT GLOBAL SECURITIES

If any Debt Securities of a series are issuable in permanent global form,
the applicable Prospectus Supplement will describe the circumstances, if any,
under which beneficial owners of interests in any such permanent global Debt
Securities may exchange such interests for Debt Securities of such series and of
like tenor and principal amount in any authorized form and denomination. No
Bearer Debt Security delivered in exchange for a portion of a permanent global
Debt Security shall be mailed or otherwise delivered to any location in the
United States in connection with such exchange.

BOOK-ENTRY DEBT SECURITIES

The Debt Securities of a series may be issued in whole or in part in the
form of one or more Global Securities that will be deposited with, or on behalf
of, a depositary ("Depositary") or its nominee identified in the applicable
Prospectus Supplement. In such a case, one or more Global Securities will be
issued in a denomination or aggregate denomination equal to the portion of the
aggregate principal amount of Outstanding Debt Securities of the series to be
represented by such Global Security or Securities. The specific terms of the
depositary arrangement with respect to any portion of a series of Debt
Securities and the rights of, and limitations on, owners of beneficial interests
in any such Global Security representing all or a portion of a series of Debt
Securities will be described in the applicable Prospectus Supplement.

LIMITATIONS ON ISSUANCE OF BEARER DEBT SECURITIES

In compliance with United States federal tax laws and regulations, Bearer
Debt Securities (including securities in permanent global form that are either
Bearer Debt Securities or exchangeable for Bearer Debt Securities) will not be
offered or sold during the restricted period (as defined in United States
Treasury Regulations Section 1.163-5(c)(2)(i)(D)(7)) (generally, the first 40
days after the closing date,

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and, with respect to unsold allotments, until sold) within the United States or
to United States persons (each as defined below) other than to an office located
outside the United States of a United States financial institution (as defined
in Section 1.165-12(c)(1)(v) of the United States Treasury Regulations),
purchasing for its own account or for resale or for the account of certain
customers, that provides a certificate stating that it agrees to comply with the
requirements of Section 165(j)(3)(A), (B) or (C) of the Code and the United
States Treasury Regulations thereunder, or to certain other persons described in
Section 1.163-5(c)(2)(i)(D)(1)(iii)(B) of the United States Treasury
Regulations. Moreover, such Bearer Debt Securities will not be delivered in
connection with their sale during the restricted period within the United
States. Any underwriters and dealers participating in the offering of Bearer
Debt Securities must covenant that they will not offer or sell during the
restricted period any Bearer Debt Securities within the United States or to
United States persons (other than the persons described above) or deliver in
connection with the sale of Bearer Debt Securities during the restricted period
any Bearer Debt Securities within the United States and that they have in effect
procedures reasonably designed to ensure that their employees and agents who are
directly engaged in selling the Bearer Debt Securities are aware of the
restrictions described above. No Bearer Debt Security (other than a temporary
global Bearer Debt Security) will be delivered in connection with its original
issuance nor will interest be paid on any Bearer Debt Security until receipt by
the Company of the written certification described above under "--Form,
Exchange, Registration, Conversion, Transfer and Payment." Each Bearer Debt
Security, other than a temporary global Bearer Debt Security, will bear a legend
to the following effect: "Any United States person who holds this obligation
will be subject to limitations under the United States federal income tax laws,
including the limitations provided in Sections 165(j) and 1287(a) of the
Internal Revenue Code."

As used herein, "United States person" means any citizen or resident of the
United States, any corporation, partnership or other entity created or organized
in or under the laws of the United States and any estate or trust the income of
which is subject to United States federal income taxation regardless of its
source, and "United States" means the United States of America (including the
states and the District of Columbia) and its possessions.

EVENTS OF DEFAULT

The following will be Events of Default under the Indenture with respect to
Debt Securities of any series: (a) failure to pay principal (or premium, if any)
on any Debt Security of that series when due; (b) failure to pay any interest on
any Debt Security of that series when due, which failure continues for 30 days;
(c) failure to perform any other covenant of the Company in the applicable
Indenture or any other covenant to which the Company may be subject with respect
to Debt Securities of that series (other than a covenant solely for the benefit
of a series of Debt Securities other than that series), which failure continues
for 90 days after written notice as provided in the applicable Indenture; and
(d) certain events of bankruptcy, insolvency or reorganization.

If an Event of Default with respect to Outstanding Debt Securities of any
series shall occur and be continuing, either the Trustee or the Holders of at
least 25% in principal amount of the Outstanding Debt Securities of that series,
by notice as provided in the applicable Indenture, may declare the principal
amount (or, if the Debt Securities of that series are Original Issue Discount
Securities, such portion of the principal amount as may be specified in the
terms of that series) of all Debt Securities of that series to be due and
payable immediately, except that upon the occurrence of an Event of Default
specified in (d) above, the principal amount (or in the case of Original Issue
Discount Securities, such portion) of all Debt Securities shall be immediately
due and payable without any action by the Trustee or any Holder. At any time
after a declaration of acceleration with respect to Debt Securities of any
series has been made, but before judgment or decree based on such acceleration
has been obtained, the Holders of a majority in principal amount of the
Outstanding Debt Securities of that series may, under certain circumstances,
rescind and annul such acceleration. For information as to waiver of defaults,
see "Modification and Waiver" below.

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The Indentures will provide that, subject to the duty of the respective
Trustees thereunder during an Event of Default to act with the required standard
of care, each such Trustee will be under no obligation to exercise any of its
rights or powers under the respective Indentures at the request or direction of
any of the Holders, unless such Holders shall have offered to such Trustee
reasonable security or indemnity. Subject to certain provisions, including those
requiring security or indemnification of the applicable Trustee, the Holders of
a majority in principal amount of the Outstanding Debt Securities of any series
will have the right to 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 such Trustee, with respect to the Debt Securities of that
series.

No Holder of a Debt Security of any series will have any right to institute
any proceeding with respect to the applicable Indenture or for any remedy
thereunder, unless such Holder shall have previously given to the applicable
Trustee written notice of a continuing Event of Default and unless the Holders
of at least 25% in aggregate principal amount of the Outstanding Debt Securities
of the same series shall have written requests, and offered reasonable
indemnity, to such Trustee to institute such a proceeding, and the Trustee shall
not have received from the Holders of a majority in aggregate principal amount
of the Outstanding Debt Securities of the same series a direction inconsistent
with such request and shall have failed to institute such proceeding within 60
days. However, such limitations do not apply to a suit instituted by a Holder of
a Debt Security for enforcement of payment of the principal of and interest on
such Debt Security on or after the respective due dates expressed in such Debt
Security.

The Company is required to furnish to the Trustees annually a statement as
to the performance by the Company of its obligations under the respective
Indentures and as to any default in such performance.

MODIFICATION AND WAIVER

The Indenture provides that Supplemental Indentures may be entered into by
the Company and the Trustee without the consent of any Holders of Debt
Securities in certain limited circumstances, including (i) to cure any
ambiguity, omission, defect or inconsistency, (ii) to provide for the assumption
of the obligations of the Company under the Indenture upon the merger,
consolidation or sale or other disposition of all or substantially all of the
assets of the Company and its Subsidiaries taken as a whole and certain other
events specified in the "Merger, Consolidation and Sale of Substantially All
Assets" covenant, (iii) to provide for uncertificated Debt Securities in
addition to or in place of certificated Debt Securities, (iv) to comply with any
requirement of the Commission in order to effect or maintain the qualification
of the Indenture under the Trust Indenture Act of 1939, as amended, (v) to make
any change in the Debt Securities of any or all series that does not adversely
affect the rights of any Holder of Debt Securities of the affected series in any
material respect, (vi) to add Subsidiary guarantors pursuant to the procedures
set forth in the Indentures, and (vii) certain other modifications and
amendments as set forth in the Indenture.

The Indenture contains provisions permitting the Company and the Trustee,
with the written consent of the Holders of not less than a majority in aggregate
principal amount of the Debt Securities, of any series then outstanding, to
execute supplemental indentures or amendments adding any provisions to or
changing or eliminating any of the provisions of the Indenture or modifying the
rights of the Holders of the Debt Securities of such series, except that no such
supplemental indenture, amendment or waiver may, without the consent of all the
Holders of Debt Securities of such series then outstanding, among other things,
(i) reduce the principal amount of Debt Securities of such series whose Holders
must consent to an amendment or waiver, (ii) reduce the rate of or change the
time of payment of interest on any Debt Securities, (iii) change the currency in
which any amount due in respect of the Debt Securities is payable, (iv) reduce
the principal of or any premium on or change the Stated Maturity of any Debt
Securities or alter the redemption or repurchase provisions with respect
thereto, (v) reduce the relative ranking of any Debt Securities, (vi) release
any security that may have been granted in respect of the Debt Securities, (vii)
impair the right of any Holder to institute suit for enforcement of any payment
on or with respect to

19
<PAGE>
such Holder's Debt Securities and (viii) make certain other significant
amendments or modifications as specified in the Indenture.

The Holders of at least a majority in principal amount of the Outstanding
Debt Securities of any series may, on behalf of the Holders of all Debt
Securities of that series, waive compliance by the Company with certain
covenants of the applicable Indenture and any past default under the applicable
Indenture with respect to that series, except a default in the payment of the
principal of, premium, if any, or interest on, any Debt Security of that series
or in respect of a provision which under the applicable Indenture cannot be
modified or amended without the consent of the Holder of each Outstanding Debt
Security of that series affected.

CONSOLIDATION, MERGER AND SALE OF ASSETS

The Company, without the consent of any Holders of any series of outstanding
Debt Securities, may consolidate with or merge into, or transfer or lease its
assets substantially as an entirety (treating the Company and each of its
Subsidiaries as a single consolidated entity) to, any corporation, and any other
corporation may consolidate with or merge into, or transfer or lease its assets
substantially as an entirety to, the Company, provided that the corporation (if
other than the Company) formed by such consolidation or into which the Company
is merged or which acquires or leases the assets of the Company substantially as
an entirety is organized and existing under the laws of the United States of
America or any political subdivision thereof, and assumes the Company's
obligations under each series of Outstanding Debt Securities and the Indentures
applicable thereto and that the Trustee is satisfied that, after giving effect
to such transaction, no Event of Default, and no event which, after notice or
lapse of time or both, would become an Event of Default, shall have occurred and
be continuing.

DEFEASANCE

If so indicated in the applicable Prospectus Supplement with respect to the
Debt Securities of a series, the Company at its option (i) will be discharged
from any and all obligations in respect of the Debt Securities of such series
(except for certain obligations to register the transfer or exchange of Debt
Securities of such series, to replace destroyed, stolen, lost or mutilated Debt
Securities of such series, and to maintain an office or agency in respect of the
Debt Securities and hold moneys for payment in trust) or (ii) will be released
from its obligations to comply with certain covenants specified in the
applicable Prospectus Supplement with respect to the Debt Securities of such
series, and the occurrence of certain Events of Default as specified in the
applicable Prospectus Supplement with respect to the Debt Securities of such
series, shall no longer be Events of Default, if, in either case, the Company
irrevocably deposits with the applicable Trustee, in trust, money, Government
Obligations of the government issuing the currency in which the Debt Securities
of the relevant series are denominated or a combination thereof that through the
payment of interest thereon and principal thereof in accordance with the terms
will provide money in an amount sufficient to pay all the principal of and
premium, if any, and interest on the Securities of such series on the dates such
payments are due (up to the Stated Maturity Date, or the Redemption Date, as the
case may be) in accordance with the terms of such Debt Securities. Such a trust
may only be established if, among other things, (a) 123 days pass after the
deposit is made and during the 123-day period no Event of Default described in
clause (d) under "Events of Default" shall have occurred and be continuing at
the end of such period and (b) the Company shall have delivered an Opinion of
Counsel to the effect that (i) the Holders of the Debt Securities will not
recognize gain or loss for United States federal income tax purposes as a result
of such deposit or defeasance and will be subject to United States federal
income tax in the same manner as if such defeasance had not occurred, and (ii)
the trust resulting from the deposit does not constitute, or is qualified as, a
regulated investment company under the Investment Company Act of 1940. Such
opinion, in the case of defeasance under clause (i) above, must refer to and be
based upon a ruling of the Internal Revenue Service or a change in applicable
federal income tax law occurring after the date of the applicable Indenture. In
the event the Company fails to

20
<PAGE>
comply with its remaining obligations under the applicable Indenture after a
defeasance of such Indenture with respect to the Debt Securities of any series
as described under clause (ii) above and the Debt Securities of such series are
declared due and payable because of the occurrence of any undefeased Event of
Default, the amount of money and Government Obligations on deposit with the
applicable Trustee may be insufficient to pay amounts due on the Debt Securities
of such series at the time of the acceleration resulting from such Event of
Default. However, the Company will remain liable in respect to such payments.

Notwithstanding the description set forth under "Subordination of Senior
Subordinated Debt Securities and Subordinated Debt Securities" above, in the
event that the Company deposits money or Government Obligations in compliance
with the Indenture that governs any Senior Subordinated Debt Securities or
Subordinated Debt Securities, as the case may be, in order to defease all or
certain of its obligations with respect to the applicable series of Debt
Securities, the money or Government Obligations so deposited will not be subject
to the subordination provisions of the applicable Indenture and the indebtedness
evidenced by such series of Debt Securities will not be subordinated in right of
payment to the holders of applicable Senior Indebtedness to the extent of the
money or Government Obligations so deposited.

REGARDING THE TRUSTEES

The Indentures contain certain limitations on the right of each Trustee,
should it become a creditor of the Company, to obtain payment of claims in
certain cases, or to realize for its own account on certain property received in
respect of any such claim as security or otherwise. Each Trustee will be
permitted to engage in certain other transactions; however, if it acquires any
conflicting interest within the meaning of the Trust Indenture Act of 1939 and
there is a default under the Debt Securities issued under the applicable
Indenture, it must eliminate such conflict or resign.

21
<PAGE>
DESCRIPTION OF PREFERRED STOCK

The Company's Certificate of Incorporation currently authorizes the issuance
of 10,000,000 shares of Preferred Stock, par value $.01 per share, issuable in
series. The board of directors of the Company is authorized to approve the
issuance of one or more series of Preferred Stock without further authorization
of the stockholders of the Company and to fix the number of shares, the
designations, the relative rights and preferences and the limitations of any
such series.

At the date of this Prospectus, no shares of preferred stock were issued and
outstanding, and 500,000 shares of Series A Junior Participating Preferred Stock
were reserved for issuance in connection with the Company's Stockholders' Rights
Plan dated February 24, 1996 (the "Rights Plan"). See "Description of Common
Stock--Stockholders' Rights Plan." The terms of the Company's currently
authorized Series A Junior Participating Preferred Stock do not limit the
issuance of other series of Preferred Stock ranking as to dividends and payments
upon liquidation senior to, on a parity with or junior to such existing
Preferred Stock.

The applicable Prospectus Supplement will set forth the number of shares,
particular designation, relative rights and preferences and the limitations of
any series of Preferred Stock in respect of which this Prospectus is delivered.
The particular terms of any such series will include the following:

(i) The maximum number of shares to constitute the series and the
designation thereof;

(ii) The annual dividend rate, if any, on shares of the series, whether such
rate is fixed or variable or both, the date or dates from which
dividends will begin to accrue or accumulate, whether dividends will be
cumulative and whether such dividends shall be paid in cash, Common
Stock or otherwise;

(iii) Whether the shares of the series will be redeemable and, if so, the
price at and the terms and conditions on which the shares of the series
may be redeemed, including the time during which shares of the series
may be redeemed and any accumulated dividends thereon that the holders
of shares of the series shall be entitled to receive upon the
redemption thereof;

(iv) The liquidation preference, if any, applicable to shares of the series;

(v) Whether the shares of the series will be subject to operation of a
retirement or sinking fund and, if so, the extent and manner in which
any such fund shall be applied to the purchase or redemption of the
shares of the series for retirement or for other corporate purposes, and
the terms and provisions relating to the operation of such fund;

(vi) The terms and conditions, if any, on which the shares of the series
shall be convertible into, or exchangeable for, shares of any other
class or classes of capital stock of the Company or another corporation
or any series of any other class or classes, or of any other series of
the same class, including the price or prices or the rate or rates of
conversion or exchange and the method, if any, of adjusting the same;

(vii) The voting rights, if any, of the shares of the series;

(viii) The currency or units based on or relating to currencies in which such
series is denominated and/ or in which payments will or may be payable;

(ix) The methods by which amounts payable in respect of such series may be
calculated and any commodities, currencies or indices, or price, rate
or value, relevant to such calculation;

(x) Any listing of the shares of the series on a securities exchange; and

(xi) Any other preferences and relative, participating, optional or other
rights or qualifications, limitations or restrictions thereof.

22
<PAGE>
Any material United States federal income tax consequences and other special
considerations to any offered Preferred Stock will be described in the
Prospectus Supplement relating to the offering and sale of such Preferred Stock.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for each series of Preferred Stock will be
designated in the related Prospectus Supplement.

DESCRIPTION OF COMMON STOCK

GENERAL

The following is a description of certain general terms and provisions of
the Common Stock. The summary of terms of the Company's Common Stock contained
in this Prospectus does not purport to be complete and is subject to, and
qualified in its entirety by, the provisions of the Company's Restated
Certificate of Incorporation, Bylaws and Rights Plan, each of which has been
incorporated by reference herein.

The Company's Restated Certificate of Incorporation authorizes the issuance
of 50,000,000 shares of Common Stock, $.01 par value. All issued and outstanding
shares of Common Stock are validly issued, fully paid and nonassessable. The
holders of Common Stock are entitled to one vote for each share held on all
matters submitted to a vote of holders of Common Stock. The Common Stock does
not have cumulative voting rights. Each share of Common Stock is entitled to
participate equally in dividends, as and when declared by the Company's board of
directors, and in the distribution of assets in the event of liquidation,
subject in all cases to any prior rights of outstanding shares of the Company's
preferred stock. The shares of Common Stock have no preemptive or conversion
rights, redemption rights or sinking fund provisions.

STOCKHOLDERS' RIGHTS PLAN

On February 24, 1996, the Company's board of directors declared a dividend
distribution of one Preferred Stock Purchase Right (a "Right") for each
outstanding share of Common Stock. The description and terms of the Rights are
set forth in the Rights Agreement which is incorporated herein by reference. The
distribution was made as of March 6, 1996, to stockholders of record on that
date. Each Right entitles the registered holder of Common Stock to purchase from
the Company one one-hundredth (1/100) of a share of preferred stock, designated
as Series A Junior Participating Preferred Stock, at a price of $18.75 per one
one-hundredth (1/100) of a share, subject to adjustments. The Rights will expire
at the close of business on March 6, 2006, unless the expiration date is
extended or unless the Rights are earlier redeemed or exchanged by the Company
as described in the Rights Agreement.

Initially, the Rights will not be exercisable or represented by a separate
certificate but will trade together with the Common Stock. The Rights, unless
redeemed prior thereto, become exercisable only upon the close of business on
the day which is the earlier of (a) the tenth day after a public announcement
that a person or group of affiliated or associated persons, with certain
exceptions as noted in the Rights Agreement, has acquired beneficial ownership
of 15% or more of the Company's outstanding Common Stock (an "Acquiring Person")
or (b) the tenth business day (or such later date as may be determined by the
Company's board of directors prior to such time as any person or group of
affiliated persons becomes an Acquiring Person) after the commencement or
announcement of an intention to commence a tender or exchange offer, the
consummation of which would result in the ownership of 15% or more of the
Company's outstanding Common Stock. All issuances of Common Stock after the date
of the Rights Agreement will include Rights.

23
<PAGE>
TRANSFER AGENT AND REGISTRAR

The co-transfer agents and co-registrars for the Common Stock are Corporate
Stock Transfer, Inc., and First Interstate Bank of California.

LISTING

The Company's Common Stock is quoted on the Nasdaq National Market under the
symbol BSNX.

24
<PAGE>
DESCRIPTION OF WARRANTS

GENERAL

The Company may issue Warrants to purchase shares of Common Stock, shares of
Preferred Stock or Debt Securities. Warrants may be issued, subject to
regulatory approvals, independently or together with any Common Stock, Preferred
Stock or Debt Securities, as the case may be, and may be attached to or separate
from such Common Stock, Preferred Stock or Debt Securities. Each series of
Warrants will be issued under a separate warrant agreement (each a "Warrant
Agreement") to be entered into between the Company and a warrant agent (the
"Warrant Agent"). The Warrant Agent will act solely as an agent of the Company
in connection with the Warrants of such series and will not assume any
obligation or relationship of agency or trust for or with any holders or
beneficial owners of Warrants.

The applicable Prospectus Supplement will describe the following terms of
any Warrants in respect of which this Prospectus is delivered: (i) the title of
such Warrants; (ii) a description of the securities (which may include shares of
Common Stock, shares of Preferred Stock or Debt Securities) for which such
Warrants are exercisable; (iii) the price or prices at which such Warrants will
be issued; (iv) the periods during which the Warrants are exercisable; (v) the
number of shares of Common Stock or Preferred Stock or the amount of Debt
Securities for which each Warrant is exercisable; (vi) the exercise price for
such Warrants, including any changes to or adjustments in the exercise price;
(vii) the currency or currencies, including composite currencies, in which the
exercise price of such Warrants may be payable; (viii) if applicable, the
designation and terms of the shares of Preferred Stock with which such Warrants
are issued; (ix) if applicable, the terms of the Debt Securities with which such
Warrants are issued; (x) if applicable, the number of Warrants issued with each
share of Common Stock or Preferred Stock or Debt Security; (xi) if applicable,
the date on and after which such Warrants and the related shares of Common Stock
or Preferred Stock or Debt Securities will be separately transferable; (xii) if
applicable, a discussion of certain United States federal income tax
considerations; (xiii) any listing of the Warrants on a securities exchange; and
(xiv) any other terms of such Warrants, including terms, procedures and
limitations relating to the exchange and exercise of such Warrants.

SELLING STOCKHOLDER

Common Stock owned by Michael S. Smith, Chairman of the Board, President and
Chief Executive Officer, may be offered for Mr. Smith's account pursuant to this
Prospectus. The following table sets forth information as of September 22, 1997
regarding the Common Stock owned by Mr. Smith, which may be offered hereunder.

<TABLE>
<CAPTION>
SHARES BENEFICIALLY
SHARES BENEFICIALLY
OWNED PRIOR TO THE
OFFERING OWNED AFTER THE OFFERING
----------------------- NUMBER OF SHARES TO BE ------------------------
SELLING STOCKHOLDER NUMBER PERCENT SOLD IN THE OFFERING NUMBER PERCENT
- ------------------------------------------ ---------- ----------- -------------------------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Michael S. Smith.......................... 3,248,150(1) 30.13 Not to exceed 300,000* * *
</TABLE>

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

* To be included in a Prospectus Supplement

(1) Includes 2,675,150 shares held by Mr. Smith; 304,300 shares held by Iris
Smith, Mr. Smith's wife; 96,000 shares held by trusts for Mr. Smith's
children, of which Mr. Smith is trustee; and 92,700 shares held by KaiTar
Foundation, a nonprofit charitable foundation of which Mrs. Smith is
president and Mr. Smith is vice-president. Mr. Smith has no voting or
investment power with respect to the shares held by Iris Smith and disclaims
beneficial ownership of such shares. Mr. Smith, in his capacity as the
trustee of the trusts for his children and as vice president of KaiTar
Foundation, has voting and investment power with respect to the shares held
in such capacity and may be deemed to be the beneficial owner of such shares
but disclaims beneficial ownership of such shares. Also includes options for
60,000 shares exercisable within 60 days and 20,000 performance shares, the
restrictions on which lapse December 31, 1999.

25
<PAGE>
PLAN OF DISTRIBUTION

The Company may offer and sell the Debt Securities, Preferred Stock, Common
Stock and Warrants to or through underwriters or dealers, and also may offer and
sell Debt Securities, Preferred Stock, Common Stock and Warrants directly to
other purchasers or through agents.

The distribution of the Securities may be affected from time to time in one
or more transactions at a fixed price or prices, which may be changed, at market
prices prevailing at the time of sale, at prices related to such market prices
or at negotiated prices.

Each Prospectus Supplement will set forth the terms of the offering of the
particular series of Securities to which the Prospectus Supplement relates,
including the name or names of any underwriters, dealers or agents, the purchase
price or prices of the Securities, the proceeds to the Company or the selling
stockholder, if applicable, from the sale of such series of Securities, the use
of such proceeds, any initial public offering price or purchase price of such
series of Securities, any underwriting discount or commission, any discounts,
concessions or commissions allowed or reallowed or paid by any underwriters to
other dealers, any commissions paid to any agents, and the securities exchanges,
if any, on which such Securities will be listed. Any initial public offering
price or purchase price and any discounts, concessions or commissions allowed or
reallowed or paid by any underwriter to other dealers may be changed from time
to time.

In connection with distributions of Common Stock or otherwise, the Company
may enter into hedging transactions with broker-dealers in connection with which
such broker-dealers may sell Common Stock registered hereunder in the course of
hedging through short sales the positions they assumed with the Company.

In connection with the sale of the Securities, underwriters or agents may
receive compensation from the Company, the selling stockholder, if applicable,
or from purchasers of Securities for whom they may act as agents in the form of
discounts, concessions or commissions. Underwriters may sell Securities to or
through dealers, and such dealers may receive compensation in the form of
discounts, concessions or commissions from the underwriters and/or commissions
from the purchasers for whom they may act as agents. 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
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
underwriter or agent will be identified, and any such compensation received from
the Company will be described, in the applicable Prospectus Supplement.

The sale of all or a portion of the shares of Common Stock offered hereby by
the Selling Stockholder may be effected from time to time on any exchange on
which the Common Stock is then listed at prevailing prices at the time of such
sale, at prices related to such prevailing prices or at negotiated prices. The
Selling Stockholder may sell all or a portion of the shares offered hereby in
private transactions or in the over-the-counter market at prices related to the
prevailing prices of the shares on the Nasdaq National Market.

Under agreements which may be entered into by the Company, underwriters and
agents who participate in the distribution of Securities may be entitled to
indemnification by the Company or the selling stockholder against certain
liabilities, including liabilities under U.S. securities legislation.

The Company may grant underwriters who participate in the distribution of
Securities an option to purchase additional Securities to cover over-allotments,
if any.

Certain underwriters and selling group members (if any) who are qualifying
registered market makers on the Nasdaq National Market may engage in passive
market making transactions in the Common Stock on the Nasdaq National Market in
accordance with Rule 10b-6A under the Securities Exchange Act of 1934, as
amended, during the two business day period before commencement of offers or
sales of the Common Stock.

26
<PAGE>
The place and date of delivery for the Securities in respect of which this
Prospectus is being delivered will be set forth in the applicable Prospectus
Supplement.

If so indicated in the applicable Prospectus Supplement, the Company will
authorize underwriters or agents to solicit offers by certain institutions to
purchase Securities from the Company pursuant to delayed delivery contracts
providing for payment and delivery at 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 such institutions must be approved by
the Company. Unless otherwise set forth in the applicable Prospectus Supplement,
the obligations of any purchaser under any such contract will not be subject to
any conditions except that (i) the purchase of the Securities shall not at the
time of delivery be prohibited under the laws of the jurisdiction to which such
purchaser is subject, and (ii) if the Securities are also being sold to
underwriters acting as principals for their own account, the underwriters shall
have purchased such Securities not sold for delayed delivery. The underwriters
and such other persons will not have any responsibility in respect of the
validity or performance of such contracts.

Unless otherwise indicated in the applicable Prospectus Supplement, the
Securities in respect of which this Prospectus is being delivered (other than
Common Stock) will be a new issue of securities, will not have an established
trading market when issued and will not be listed on any securities exchange.
Any underwriters or agents to or through whom such 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.

Certain of the underwriters and their affiliates may from time to time
perform various commercial banking and investment banking services for the
Company, for which customary compensation is received.

EXPERTS

The consolidated financial statements of the Company, included in its Annual
Report on Form 10-K for the year ended December 31, 1996, incorporated by
reference in this Prospectus and elsewhere in the Registration Statement have
been audited by Arthur Andersen LLP, independent public accountants, as
indicated in their report with respect thereto, and are incorporated herein in
reliance upon the authority of said firm as experts in giving said report.
Future financial statements of the Company and the reports thereon of Arthur
Andersen LLP, or any successor independent accounting firm that has audited the
Company's financial statements, also will be incorporated by reference in this
Prospectus and elsewhere in the Registration Statement in reliance upon the
authority of such firm as experts in giving those reports to the extent said
firm has audited those financial statements and consented to the use of their
reports thereon.

Estimates of historical onshore oil and natural gas reserves of the Company
as of December 31, 1994, 1995 and 1996, incorporated by reference herein are
based upon engineering studies prepared by the Company and audited by the
independent engineering firm of Netherland, Sewell & Associates, Inc. Estimates
of historical offshore reserves of the Company as of December 31, 1996,
incorporated by reference herein are based upon engineering studies prepared by
the independent engineering firm of Ryder Scott Company Petroleum Engineers.
Such estimates are incorporated by reference herein (to the extent covered by
consents filed with the Commission) in reliance upon the authority of such firms
as experts in such matters.

LEGAL MATTERS

Certain legal matters relating to the validity of the Securities will be
passed upon for the Company by Davis, Graham & Stubbs LLP, Denver, Colorado.
Certain legal matters will be passed upon for the underwriters, if any, by the
counsel named in the applicable Prospectus Supplement.

27
<PAGE>
GLOSSARY

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

2-D SEISMIC DATA. Seismic data that are acquired and processed to yield a
two-dimensional cross section of the subsurface.

3-D SEISMIC DATA. Seismic data that are acquired and processed to yield a
three-dimensional picture of the subsurface.

BCF. Billion cubic feet (of gas).

BCFE. Billion cubic feet (of gas) equivalent.

EXPLOITATION. The conduct of a drilling or recompletion operation intended
to recover reserves from a formation known to be productive in the area or on
trend with existing production but not classifiable as proved.

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

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

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

NET ACRES. The sum of the fractional working interests owned in gross acres.

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

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

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 to share in
the production.

28
<PAGE>
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No dealer, salesperson or other person is authorized to give any information
or to represent anything not contained in this prospectus. You must not rely on
any unauthorized information or representations. This prospectus is an offer to
sell only the shares offered hereby, but only under circumstances and in
jurisdictions where it is lawful to do so. The information contained in this
prospectus is current only as of its date.

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TABLE OF CONTENTS

Prospectus Supplement

<TABLE>
<CAPTION>
Page
---------
<S> <C>
Summary........................................ S-3
Risk Factors................................... S-11
Use of Proceeds................................ S-19
Capitalization................................. S-20
Price Range of Common Stock and Dividend
Policy....................................... S-21
Selected Historical Financial Information...... S-22
Management's Discussion and Analysis of
Financial Condition and Results of
Operations................................... S-24
Business and Properties........................ S-39
Management..................................... S-54
Selling Stockholder............................ S-57
Experts........................................ S-57
Validity of Common Stock....................... S-57
Index to Financial Statements.................. F-i
Underwriting................................... U-1

Prospectus
Available Information.......................... 2
Incorporation of Certain Documents by
Reference.................................... 2
Special Note Regarding Forward-Looking
Statements................................... 3
Risk Factors................................... 4
The Company.................................... 9
Use of Proceeds................................ 11
Ratio of Earnings to Fixed Charges............. 11
Description of Debt Securities................. 11
Description of Preferred Stock................. 22
Description of Common Stock.................... 23
Description of Warrants........................ 25
Selling Stockholder............................ 25
Plan of Distribution........................... 26
Experts........................................ 27
Legal Matters.................................. 27
Glossary....................................... 28
</TABLE>

4,000,000 Shares

BASIN EXPLORATION, INC.

Common Stock

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[LOGO]

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GOLDMAN, SACHS & CO.
BANC OF AMERICA SECURITIES LLC
DAIN RAUSCHER WESSELS

A DIVISION OF DAIN RAUSCHER INCORPORATED

PETRIE PARKMAN & CO.

Representatives of the Underwriters

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