<PAGE>

                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K

[X]    Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
       Act of 1934 for the fiscal year ended December 31, 1998.

[ ]    Transition Report Pursuant to Section 13 or 15(d) of the Securities 
       Exchange Act of 1934

                         Commission File Number 0-20125

                             BASIN EXPLORATION, INC.
             (Exact name of registrant as specified in its charter)

          Delaware                                      84-1143307
  (State or other jurisdiction                (IRS Employer Identification No.)
of incorporation or organization)


           370 Seventeenth Street, Suite 3400, Denver, Colorado 80202
               (Address of principal executive offices) (Zip Code)

                                 (303) 685-8000
              (Registrant's telephone number, including area code)

                    Securities registered pursuant to Section
                               12(b) of the Act:
                                      None
           Securities registered pursuant to Section 12(g) of the Act:
                          Common Stock, $.01 par value
                          ----------------------------
                                (Title of Class)

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

  Indicate by check mark whether the registrant (1) has filed all reports 
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 
1934 during the preceding 12 months (or for such shorter period that the 
registrant was required to file such reports), and (2) has been subject to 
such filing requirements for the past 90 days.

                                 [X] Yes [ ] No

   As of March 25, 1999, the aggregate market value of the approximate 
10,747,700 shares of voting stock held by non-affiliates of the registrant 
was approximately $139,720,000 based upon the closing sale price of the 
Common Stock on the Nasdaq Stock Market on March 25, 1999 of $13.00 per share.

   As of March 25 1999, the registrant had 13,977,000 shares of Common Stock 
outstanding.

                        DOCUMENT INCORPORATED BY REFERENCE

   Parts of the following document are incorporated by reference to Part III 
of this Form 10-K Report: Proxy Statement for the registrant's 1999 Annual 
Meeting of Shareholders.

<PAGE>

                              CROSS-REFERENCE SHEET

<TABLE>
<CAPTION>
PART I                                                                 INTERNAL PAGE
<S>                                                                    <C>
     Item 1.  Business                                                       1
     Item 2.  Properties                                                    12
     Item 3.  Legal Proceedings                                             16
     Item 4.  Submission of Matters to a Vote of Security Holders           16

PART II
     Item 5.  Market for the Registrant's Common Stock and                  16
                Related Shareholder Matters
     Item 6.  Selected Financial Data                                       17
     Item 7.  Management's Discussion and Analysis of                       17
              Financial Condition and Results of Operations
     Item 7A. Quantitative and Qualitative Disclosures
              About Market Risk                                             29
     Item 8.  Financial Statements and Supplementary Data                   29
     Item 9.  Changes and Disagreements with Accountants                    29
                on Accounting and Financial Disclosure

PART III

     Item 10. Directors and Executive Officers of the Registrant            29
     Item 11. Executive Compensation                                        29
     Item 12. Security Ownership of Certain                                 29
              Beneficial Owners and Management
     Item 13. Certain Relationships and Related Transactions                29
     Item 14. Exhibits, Financial Statement Schedules                       32
              and Reports on Form 8-K

</TABLE>

                For Certain Definitions of terms used herein, see page 30.

<PAGE>

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

           This Annual Report on Form 10-K, including information 
incorporated by reference herein, contains statements that are not historical 
facts but are forward-looking statements that 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, estimates, plans or anticipates will, 
should, could or may occur, including such matters as:

           -    amount and nature of capital expenditures,
           -    drilling of wells,
           -    estimated reserves,
           -    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.

           Although the Company believes that the expectations reflected in 
the forward-looking statements are reasonable, we cannot assure you that any 
of these expectations will prove correct or that we will take any actions 
that may have been planned. Factors that could cause actual results to differ 
materially ("Cautionary Disclosures") are described in the Marketing, 
Competition, Regulation and Risk Factors portions of the "Business" section 
of this report and under the "Management's Discussion and Analysis of 
Financial Condition and Results of Operations" section of this report. 
Without limiting the Cautionary Disclosures so described, Cautionary 
Disclosures include, among others:

           -    general economic conditions,
           -    oil and gas price volatility,
           -    the Company's ability to find, acquire, market, develop and 
                produce new properties, 
           -    the risks associated with acquisitions, 
           -    the risks associated with 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 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,
           -    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 the Company's 
                properties,
           -    regulatory developments, and
           -    third-party Year 2000 compliance actions.

All written and oral forward-looking statements attributable to the Company 
or persons acting on its behalf are qualified in their entirety by the 
Cautionary Disclosures. The Company disclaims any obligation to update or 
revise any forward-looking statement in light of actual results or future 
events.

<PAGE>
                                    PART I

ITEM 1.  BUSINESS.

GENERAL

           Basin Exploration, Inc. ("Basin" or the "Company") is engaged in 
the exploration, acquisition, development and exploitation of oil and gas 
properties. The Company's properties are located primarily offshore Louisiana 
and Texas in the shallow waters of the Gulf of Mexico and in the Powder River 
and Green River Basins of Wyoming. As of December 31, 1998, the Company's 
estimated net proved reserves were 127.5 Bcf of natural gas and 8.7 MMBbl of 
oil, or 179.5 Bcfe, with an aggregate pre-tax present value of future net 
revenues of $164.5 million, using 1998 year-end prices held constant and a 
10% discount rate.

           In 1996, the Company changed its primary focus from the Rocky 
Mountain region to the shallow waters of the Gulf of Mexico. To implement 
this change in focus, between late-1995 and mid-1996 the Company added senior 
management and technical personnel, including geoscientists and petroleum 
engineers with extensive experience in the Gulf of Mexico, and strengthened 
its balance sheet by selling its D-J Basin properties in Colorado for $123.5 
million. The Company's divestment of its D-J Basin assets and its commitment 
to Gulf of Mexico exploration significantly changed the character and risk 
profile of its investment activities.

           Since commencing operations in the Gulf of Mexico in 1996, through 
the end of 1998, the Company has participated in drilling 31 Gulf of Mexico 
wells, including 20 that found apparent commercial hydrocarbons. The Company 
has operated 22 of the 31 wells in which it has participated and has retained 
working interests averaging approximately 54% at the time of drilling. As of 
year-end 1998, the Company had assembled a Gulf of Mexico leasehold position 
totaling 218,718 gross acres, or 149,430 net acres, with more than 40 
identified exploration prospects supported by the Company's interpretations 
of three-dimensional ("3-D") seismic data. See "PROPERTIES - Present 
Activities" for information about certain developments subsequent to December 
31, 1998.

           During 1998, the Company invested $106.7 million in oil and gas 
properties, of which approximately 96% related to activities in the Gulf of 
Mexico. Expenditures related to the Gulf of Mexico were primarily for 
drilling 17 exploratory wells, 11 of which found apparent commercial 
hydrocarbons, completion and development activities related to these 
discoveries and discoveries made in the prior year, and for acquisitions of 
seismic data and exploratory leaseholds. Other investments made in 1998 were 
primarily for exploitation and development of the Company's Rocky Mountain 
oil and gas properties, and for exploration activities in the Rocky Mountain 
area. Capital expenditures in 1998, and in 1997 when oil and gas investments 
totaled $105.6 million, were significantly greater than in prior years and 
resulted in a 133% increase in estimated proved oil and gas reserve 
quantities over the two-year period and a substantial increase in undeveloped 
Gulf of Mexico leaseholds. As a result of the large portion of such capital 
expenditures that related to Gulf of Mexico activities, Gulf of Mexico assets 
accounted for 75% of the Company's proved reserves at the end of 1998, 
compared to 9% at the beginning of 1997, and properties in the Gulf of Mexico 
contributed 86% of fourth quarter 1998 average daily net production of 65.9 
MMcfe, versus 0% of the Company's average daily net production of 11.2 MMcfe 
as recently as the second quarter of 1997. Since initiating its Gulf of 
Mexico production from a single property in August 1997, the Company had 
expanded its production base in the area to 14 properties by the end of 1998. 
Four additional properties with proved reserves were under development for 
initial production at that date.

           The Company's capital expenditures in 1998 were funded primarily 
with cash flow from operations, which totaled $33.7 million before changes in 
working capital, and bank debt, which increased from $11 million at the 
beginning of 1998 to $80 million at the close of the year.

           During 1998 the Company produced a total of 22.0 Bcfe, or 60.2 
MMcfe per day, compared to 1997 production of 8.7 Bcfe, or 23.7 MMcfe per 
day. This 154% increase in production combined with a 22% decline in 
weighted-average prices received to generate a 99% increase in revenues. The 
revenue increase resulted in a 120% increase in cash flow from operations 
before changes in working capital, from $15.3 million in 1997 to $33.7 
million in 1998. The Company's production in 1998 was comprised of 80% 
natural gas and 20% oil.

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<PAGE>

           The increase in production from 1997 to 1998 was principally 
attributable to reserves additions made in 1997. The Company did not make any 
significant acquisitions of producing properties in 1998 and wells drilled 
during 1998 did not account for a substantial portion of production during 
the year, due to a typical time lag of several months between drilling a 
discovery in the Gulf of Mexico and first production.

           Reflecting low oil and gas prices at the end of 1998, Basin 
recorded a $30.8 million after-tax, non-cash charge to reduce the carrying 
value of its oil and gas properties. As a result, the Company reported a net 
loss for the year of $28.5 million. Without the non-recurring charge, the 
Company would have reported net income for the year of $2.3 million.

           See "Management's Discussion and Analysis of Financial Condition 
and Results of Operations" for additional discussion regarding the Company's 
history, current business activities and financial performance.

BUSINESS STRATEGY

           Basin's goals are to generate per-share growth in reserves, 
production, earnings and cash flow through exploration, acquisition and 
development of oil and gas properties. The Company seeks to implement these 
goals through the following strategies:

           EXPLORE IN THE SHALLOW WATERS OF THE GULF OF MEXICO. Basin's 
exploration activities are currently focused primarily in the shallow waters 
on the Outer Continental Shelf ("OCS") of the Gulf of Mexico. The Company 
believes that this region has significant remaining undiscovered reserves and 
that the combination of substantial existing infrastructure and the 
effectiveness of 3-D seismic data will reduce exploration risk and enhance 
project economics.

           CAPITALIZE ON TECHNICAL EXPERTISE. Basin has assembled a team of 
geoscientists and petroleum engineers with substantial experience and 
expertise relating to operations in the Gulf of Mexico to generate prospects 
and evaluate acquisition opportunities in that region. Basin has also added 
senior management and technical personnel with substantial operating 
experience outside of the Gulf of Mexico and intends to utilize this in-house 
capability in conjunction with consultants to identify and evaluate growth 
opportunities in selected onshore areas, and to pursue such opportunities 
through acquisitions of properties or through exploration ventures.

           UTILIZE ADVANCED TECHNOLOGY. Basin makes extensive use of advanced 
technologies, including 3-D seismic and computer-aided exploration and 
exploitation ("CAEX") performed on eight Landmark workstations, to better 
define drilling prospects and exploitation opportunities. Basin has licensed 
more than 375,000 miles of conventional 2-D seismic data and approximately 
600 lease blocks of 3-D seismic data covering portions of the Gulf of Mexico.

           BALANCE SIZE AND RISK PROFILE OF EXPLORATION TARGETS. Basin seeks 
to conduct a drilling program that is balanced between large-target 
exploration prospects relative to the Company's existing reserve base and 
lower-risk, smaller exploration prospects, generally near existing 
infrastructure, which reduces development costs and expedites commencement of 
production. This balance is intended to mitigate risk while still gaining 
exposure to meaningful growth in reserves and production.

           GENERATE PROSPECTS INTERNALLY. Basin's team of geoscientists 
internally generates prospects using the Company's technical data bases and 
workstations. The Company believes that internally generating prospects will 
enable it to retain large working interests and operating control and to 
either bring in partners on a promoted basis or swap for interests in 
third-party generated prospects. Although the Company primarily relies on 
internal generating activities for prospect leads, the Company also evaluates 
outside-generated opportunities. Several outside-generated prospects have 
been obtained in conjunction with the originating party's participation in 
prospects generated by the Company. Basin focuses its current prospect 
generating activities primarily offshore Louisiana in the near-shore Miocene 
trends, integrating subsurface geology with a regional grid of 3-D seismic 
data. The Miocene trend is characterized by geologic structures with 
favorable reservoir parameters and conditions where subtle hydrocarbon 
indicators are sometimes apparent.

           OPERATE CORE PROPERTIES. At December 31, 1998, Basin served as 
operator for properties accounting for more than 65% of the Company's proved 
reserve quantities. Serving as operator allows the Company to exert greater 
control 

                                       2

<PAGE>

over the cost, timing and character of its exploration, development 
and production activities. Although the Company favors acting as operator, it 
does participate in outside-operated projects that it deems attractive.

           PURSUE SELECTIVE ACQUISITIONS. Basin actively seeks to acquire 
interests in proved oil and gas properties with exploration, exploitation or 
development potential to augment operations in its core areas and to 
establish positions in new areas. Generally, the Company focuses on 
acquisition opportunities where it believes it can enhance the value of the 
acquired assets through one or more of the following means: (i) exploratory 
drilling; (ii) development drilling; (iii) workovers; (iv) recompletions; (v) 
fracture stimulation; (vi) secondary recovery operations; and (vii) cost 
reductions.

            MAINTAIN FINANCIAL FLEXIBILITY. Basin seeks to maintain financial 
flexibility in order to be able to take advantage of identified investment 
opportunities. Since the Company anticipates that its capital expenditures 
are likely to exceed cash flow from operations in the foreseeable future, 
periodic sales of assets or securities may be required, in addition to 
utilization of bank debt, in order to provide funds for such investments. At 
times, preservation or restoration of financial flexibility may be dependent 
on such sales of assets or securities.

MARKETING

           The Company's gas and natural gas liquids from Gulf of Mexico 
properties are sold under short-term contracts at market prices to various 
gas purchasers. These sales may involve delivery of gas to onshore points 
under the Company's firm and interruptible transportation agreements or sales 
at the wellhead. Oil from the Company's Gulf of Mexico properties is sold 
under short-term contracts at market prices. The Company enters into liquids 
transportation and separation agreements to deliver its crude oil and 
condensate onshore.

           Because of the well-developed transportation infrastructure and 
the relatively large number of active oil and gas purchasers in the Gulf 
Coast area, including in the Gulf of Mexico where the Company conducts 
exploration and acquisition activities, the Company does not anticipate that 
it will have difficulty in marketing its production in this region at 
prevailing spot market prices.

           The majority of the Company's gas and natural gas liquids from 
fields in the Rocky Mountain region are sold under marketing arrangements 
where prices received are responsive to changes in regional spot markets. 
These include short-term contracts under which gas is delivered and sold into 
interstate pipelines at market-sensitive prices, and long-term (often for the 
life of the lease) percentage-of-proceeds contracts with gas processors.

           KN Gas Gathering ("KNGG") purchases virtually all of the Company's 
Powder River Basin gas and natural gas liquids from the Company's operated 
wells at netback prices similar to other percentage-of-proceeds contracts in 
the area. The KNGG contract does not have minimum take provisions and thus 
the Company's realization of proceeds depends on KNGG's ability to find a 
market for the Company's gas and natural gas liquids. If KNGG were to cease 
purchasing the Company's gas, the Company believes that it could sell its gas 
and natural gas liquids to other purchasers and processors in the area, 
although such sales would require capital expenditures for gathering system 
modification and might not be on terms as favorable as those characterizing 
the KNGG sales. The Company does not believe that the loss of KNGG as a 
purchaser would have a material adverse effect on the Company.

           Oil from the Company's Rocky Mountain properties is generally sold 
under term contracts that yield a premium over local posted prices.

           Demand for natural gas is highly seasonal, with demand generally 
higher in the colder winter months and in 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, and the 
volumes sold have not materially fluctuated seasonally. There is no 
assurance, however, that the Company will be able to continue to achieve this 
result.

           For much of the past decade, the markets for oil and natural gas 
have been volatile. The Company anticipates that such markets will continue 
to be volatile in the foreseeable future. Oil and gas price fluctuations have 
a significant impact on the Company's business since virtually all of the 
Company's operating revenues are ordinarily derived from sales of its oil and 
gas production. The Company believes that the loss of one or more of its 
current oil or natural gas spot purchasers would not have a material adverse 
effect on the Company's business because any individual purchaser should be 
readily replaceable by another purchaser who could be expected to pay 
approximately the same sales price.

                                       3

<PAGE>

           Basin periodically enters into oil and gas price hedging 
agreements as conditions are deemed to warrant. Such transactions affecting 
the three year period ended December 31, 1998, or currently in effect with 
respect to subsequent periods, are described below under "Management's 
Discussion and Analysis of Financial Condition and Results Of Operations - 
Liquidity and Capital Resources" and in the Notes to Consolidated Financial 
Statements.

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.

RISK FACTORS

           In addition to the other information set forth elsewhere in this 
Form 10-K, you should carefully consider the following factors relating to 
Basin when evaluating the Company.

OIL AND GAS PRICES, AND HEDGING - OIL AND GAS PRICES ARE CURRENTLY LOW AND 
DEPEND ON FACTORS OUT OF OUR CONTROL. LOW PRICES COULD HAVE A MATERIAL 
ADVERSE IMPACT ON OUR BUSINESS. WE MAY HEDGE SOME OF OUR PRODUCTION TO REDUCE 
PRICE RISK, BUT THAT MAY ALSO REDUCE OUR GAIN FROM PRICE INCREASES.           

           Prices for oil and natural gas fluctuate widely and have declined 
significantly over the past year. The weighted average market prices being 
received by Basin for natural gas decreased from approximately $2.32 per Mcf 
at December 31, 1997 to $1.99 per Mcf at December 31, 1998. During the same 
twelve-month period, average crude oil prices received by Basin decreased 
from $16.34 per barrel to $10.31 per barrel.

           Natural gas prices affect Basin more than oil prices, because most 
of our production and reserves are natural gas. At December 31, 1998, 71% of 
our estimated proved reserves consisted of natural gas on an Mcfe basis, and 
in 1998 approximately 80% of our total production consisted of natural gas.

           Basin's revenues, profitability and future rate of growth 
substantially depend on prevailing prices for oil, gas and natural 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 re-determination based on 
changing expectations of future prices. Lower prices may also reduce the 
amount of oil and natural gas that Basin can produce economically. As an 
example, our estimated proved reserves at December 31, 1998 were lower than 
they would have been had prices not declined from year-end 1997.

           We cannot predict future oil and natural gas prices and prices may 
decline further. Among the factors that can cause this fluctuation are:

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

           - market uncertainty;

           - the level of consumer product demand;

           - weather;

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           - domestic and foreign governmental regulations;

           - the price and availability of alternative fuels;

           - political conditions in the Middle East;

           - the foreign supply of oil and natural gas;

           - the price of oil and gas imports; and

           - economic conditions in the United States and in other countries.

           We periodically enter into energy price swap agreements and other 
financial arrangements to attempt to mitigate the effects of oil and natural 
gas price fluctuations. See Item 7, "Management's Discussion and Analysis of 
Financial Condition and Results of Operations," and Note 1 of Notes to 
Consolidated Financial Statements for a description of our recent hedging 
activity. Such arrangements are subject to a number of risks. 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 anticipated profit margins and our ability to manage price risk. 
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. 
Furthermore, hedging contracts limit the benefits we would realize if actual 
prices rise above the contract prices.

REPLACEMENT  OF  RESERVES - WE MAY NOT BE ABLE TO REPLACE  RESERVES  AND THE  
FAILURE TO DO SO WOULD  ADVERSELY  AFFECT THE  COMPANY'S LIQUIDITY AND 
OPERATIONS.

           Unless Basin conducts successful development, exploitation or 
exploration activities or acquires properties containing proved reserves, the 
proved reserves of Basin will decline as reserves are produced. Decline rates 
depend on a number of factors, including drilling density, completion 
procedures, and reservoir characteristics. They vary from generally steep 
declines of production from reservoirs in the Gulf of Mexico, where Basin has 
most of its production, to relatively slow declines of long-lived fields in 
the Rocky Mountain region, where our other properties are located. The market 
for acquiring proved reserves is extremely competitive, and we may not be 
able to buy reserves for development and exploitation 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. 
Because of low oil and gas prices, we have reduced our projected capital 
expenditure budget from the level of the past two years. This may result in 
drilling fewer wells and could reduce our reserves growth below that of prior 
years. We cannot assure you that our future acquisition, development, 
exploitation and exploration activities will result in reserves added at 
acceptable costs.

ACQUISITION RISKS - ACQUIRED PROPERTIES 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. SUBSTANTIAL ACQUISITIONS COULD 
REQUIRE SIGNIFICANT CAPITAL INFUSIONS AND COULD CHANGE BASIN'S RISK AND 
PROPERTY PROFILE.

           Our recent growth is due in part to acquisitions of producing 
properties. The successful acquisition of producing properties requires 
assessments of many factors. These include recoverable reserves, future oil 
and gas 

                                       5

<PAGE>

prices, operating costs, future development costs, and potential 
environmental and other liabilities. These assessments are inherently inexact 
and their accuracy uncertain. In connection with such assessments, we review 
the targeted properties in a manner we believe is prudent and consistent with 
industry practice. However, such a review will not reveal all existing or 
potential problems or permit a buyer to become familiar enough with the 
properties to assess fully their deficiencies and capabilities. We may not 
inspect every well, platform or pipeline. Structural and environmental 
problems, such as pipeline corrosion or groundwater contamination, are not 
necessarily observable even when an inspection is made. We may not be able to 
obtain contractual indemnities from the seller for pre-closing liabilities. 
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.

           Basin constantly evaluates acquisition and joint venture 
opportunities and frequently engages in bidding and negotiation for 
acquisitions, many of which are substantial. If successful in this process, 
Basin may need to alter or increase its 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 Basin's risk profile. 
Additionally, significant acquisitions or joint ventures can change the 
character of the operations and business of Basin depending upon the 
character of the properties, which may be substantially different in 
operating or geological characteristics or geographic location than existing 
properties. We cannot assure you that Basin will be successful in the 
acquisition or development of any material property interests.

EXPLORATION RISKS - BASIN'S GROWTH STRATEGY SUBSTANTIALLY DEPENDS ON THE 
SUCCESS OF ITS EXPLORATION, A HIGH-RISK ACTIVITY. BASIN USES 3-D SEISMIC AND 
OTHER ADVANCED TECHNOLOGIES TO MITIGATE EXPLORATION RISK, BUT SUCH 
TECHNOLOGIES ARE EXPENSIVE, REQUIRE EXPERIENCED PERSONNEL, AND CANNOT 
ELIMINATE EXPLORATION RISK.

            Basin has spent a large portion of its capital budget on 
exploration in recent years and anticipates continuing to do so in the 
future. 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 utilized 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. In addition, 
the use of 3-D seismic data and certain other technologies requires greater 
pre-drilling expenditures than traditional drilling strategies and 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. Basin had conducted no 
previous operations in the Gulf of Mexico prior to opening its regional 
office in late 1995 in Houston, Texas. This operating area is highly 
competitive and Basin's success there will depend on its ability to attract 
and retain experienced geoscientists and other professional staff. Basin's 
Houston office currently has ten geoscientists and petroleum engineers plus 
two engineering consultants, all of whom are experienced in Gulf Coast 
operations. Loss of these experienced personnel could have a material adverse 
impact on Basin's ability to compete in this area.

FUTURE CAPITAL REQUIREMENTS - BASIN'S CAPITAL EXPENDITURES HAVE GENERALLY 
EXCEEDED ITS CASH FLOW. IF WE CANNOT CONTINUE TO ACCESS CAPITAL FROM EXTERNAL 
SOURCES, WE WILL HAVE LESS CAPABILITY TO GROW OUR RESERVES AND PRODUCTION.    

        We need substantial capital to develop and explore our properties and 
acquire additional properties. We will use cash flows from operations to fund 
these expenditures to the extent available. However, generally our capital 
investments have exceeded our cash flows. Historically we have addressed our 
long-term liquidity needs through 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;

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           -  sales of interests in prospects and technical information; and

           -  joint ventures.

           Basin's 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. 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."

EFFECTS OF LEVERAGE - OUR DEBT COULD REDUCE OUR FINANCIAL FLEXIBILITY AND 
UNDER CERTAIN CIRCUMSTANCES COULD REQUIRE PRINCIPAL REDUCTIONS THAT WE ARE 
UNABLE TO MAKE.

           We have significant indebtedness.  At year-end 1998, the amount of 
our long-term debt was $80 million, and we had $30 million available to draw 
down under our credit agreement with our banks. Our working capital deficit 
was $13.2 million at year-end 1998, leaving a net total of $16.8 million of 
unutilized credit capacity. Under our credit agreement, our borrowing base is 
re-determined at least semi-annually by our banks, 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.

           There are several effects of this leverage on Basin:

           - it may impair our ability to obtain additional financing in the
future for working capital, capital expenditures, acquisitions or general
corporate purposes;

           - a portion of our cash flow from operations must be dedicated to the
payment of interest on our existing indebtedness, which will reduce the
availability of our cash flow to fund working capital, capital expenditures and
other corporate needs;

           - our credit agreement contains restrictive covenants that limit 
our ability to engage in certain transactions;

           - our borrowings under our bank credit facility are at floating 
rates, which may make us vulnerable to increases in interest rates;

           - our credit agreement requires us to make regular interest 
payments, and at the end of the revolving period to make scheduled principal 
payments. In addition, we must make principal payments if our outstanding 
borrowings exceed our borrowing base, as it may periodically be re-determined 
by the banks. If we default in such payments, which may be made in 
installments over six months, our lenders would be entitled to accelerate the 
payment of all amounts owed under our credit facility. We cannot assure you 
that future borrowings or debt or equity financing will be available to pay 
or refinance such required obligations. Our failure to remedy such a default 
could result in a foreclosure by the banks of their mortgages on the 
properties containing our proved reserves.

CEILING LIMITATION WRITE-DOWNS

           We use the full cost method of accounting to report our operations 
for oil and gas properties. Basin capitalizes 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" which is based upon 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 impact cash 
flow from operating activities, but it does reduce the book value of our 
shareholders' equity. 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 Basin has substantial 
downward adjustments to its estimated proved reserves. We review the carrying 
value of our properties quarterly, based on prices in effect as of the end of 
each fiscal quarter (or the time of reporting results). We may not reverse 

                                       7

<PAGE>

any such write-downs even if prices increase in subsequent periods, but such 
write-downs do result in reduced subsequent charges for depreciation, 
depletion and amortization. Primarily because of weak oil and gas prices, 
Basin 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 cannot assure you 
that we will not have another ceiling limitation write-down in a future 
period if commodity prices continue to weaken.

MARKETING OF PRODUCTION; SEASONALITY

           The marketability of Basin's production depends in substantial 
part on the availability and capacity of gathering systems, pipelines, and 
processing facilities owned and operated by third parties. Federal and state 
regulation of production and transportation, general economic conditions, and 
changes in supply and demand all 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 and marketability of our spot market natural gas may vary 
significantly between seasonal periods. If market factors dramatically 
changed, the financial impact on Basin could be substantial. The availability 
of markets is beyond our control.

CONCENTRATION OF VALUE

           At December 31, 1998, over 80% of our daily production was from 12 
wells on nine platforms 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. UNCERTAINTY OF 
ESTIMATES OF OIL AND GAS RESERVES - RESERVE ESTIMATES ARE INHERENTLY 
UNCERTAIN AND DEPEND ON MANY ASSUMPTIONS WHICH MAY TURN OUT TO BE UNTRUE.     
       This Form 10-K contains estimates of our proved oil and gas reserves 
and the estimated future net revenues from such reserves. Basin's historical 
proved reserve information incorporated by reference in this Form 10-K 
represents only estimates based on reports prepared in part by independent 
petroleum engineers and in part by internal Basin engineers. 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. Production rates and timing of 
development expenditures must be projected. Available geological, 
geophysical, production and engineering data must be analyzed, 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, 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.

           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 those estimated. Any 
significant variance could materially affect the estimated quantities and 
present value of reserves set forth in this Form 10-K. 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. Our reserves at December 31, 1998 were 
lower than they would have been if oil and gas prices in effect at year-end 
1997 were still in effect.

           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 
have estimated our reserves and the costs associated with developing them in 
accordance with industry standards, we cannot assure you that the estimated 
costs are accurate, that development will occur as scheduled or that the 
results will be as estimated.

           You should not assume that the present value of future net 
revenues referred to in this Form 10-k is the current market value of our 
estimated oil and gas reserves. In accordance with SEC requirements, the 
estimated discounted future net cash flows from proved reserves are generally 
based on prices and costs as of the date of the estimate. Actual future 
prices and costs may be materially higher or lower than the prices and costs 
as of the date 

                                       8

<PAGE>
of the estimate. Recent significant declines in oil and gas prices have 
reduced Basin's present value of future net revenues. See "Oil and Gas 
Prices; Hedging." Any material changes in aggregate consumption by gas 
purchasers or in governmental regulations or taxation could also affect 
actual future net cash flows. The timing of development of oil and gas 
properties will affect both the production and the timing of actual future 
net cash flows from proved reserves and their present value. In addition, the 
10% discount factor, which is required by the SEC to be used in calculating 
discounted future net cash flows for reporting purposes, is not necessarily 
an appropriate discount factor for estimating the value of oil and gas 
reserves. The effective interest rate at various times and the risk 
associated with Basin, the properties, or the oil and gas industry in general 
will affect the reasonableness of the 10% discount factor.

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

           Basin's 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. The market price of our 
common stock can be expected to decline when our quarterly results decline or 
when announcements of adverse events regarding the Company or the industry 
are made.

OPERATING HAZARDS - THE OIL AND GAS BUSINESS INVOLVES MANY OPERATING RISKS 
WHICH 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. 
These include the risk of 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. 
The occurrence of any of these events could result in substantial losses to 
Basin. Losses can occur from 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. These problems can affect wellbores, 
platforms, gathering systems and processing facilities, and any significant 
problems related to those facilities could adversely affect Basin's ability 
to conduct its operations. Moreover, 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 possibly interrupt production. In 
addition, Basin may be liable for environmental damages caused by previous 
owners of properties it purchases. As a result, Basin 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 Basin's properties.

           In accordance with industry practice, Basin maintains insurance 
against some, but not all, potential risks. Basin's coverages include, but 
are 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 
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.

ENVIRONMENTAL REGULATION - OIL AND GAS OPERATIONS ARE SUBJECT TO EXTENSIVE 
ENVIRONMENTAL REGULATION WHICH CAN INCREASE COSTS, CREATE MAJOR LIABILITIES, 
OR PRECLUDE OPERATIONS.

            Oil and gas operations are subject to extensive regulation under 
federal, state and local environmental laws. Generally, regulation relates to 
water and air pollution control and solid waste management, permitting, or 
restrictions on operations in environmentally sensitive areas, such as 
coastal zones, wetlands, and wildlife habitat. We have not performed 
environmental assessments on all of our acquired properties. To date, our 
expenditures for environmental control facilities and for remediation have 
not been significant in relation to our results of operations. We believe, 
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 impose absolute liability for environmental damage and allow interruption 
or termination of business activities by government 

                                       9
<PAGE>

authorities. The Oil Pollution Act of 1990 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 our operating 
costs. Initiatives regulating the disposal of exploration and production 
waste are also pending or have been enacted in states in which Basin conducts 
operations, and these initiatives could have a similar impact on Basin.

GOVERNMENTAL REGULATION - OIL AND GAS OPERATIONS ARE SUBJECT TO EXTENSIVE 
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 governmental regulation. Areas covered 
include operations permits, 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 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 Basin receives 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 our ability to market our gas at reasonable prices is 
uncertain. Regulatory agencies in the past 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, the Minerals Management 
Service regulates development and production of oil and gas in federal waters 
in the Gulf of Mexico. The Minerals Management Service may suspend or 
terminate operations for violation of its rules. Any such suspension or 
termination could materially and adversely affect Basin'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 - WE ARE SMALLER AND LESS EXPERIENCED THAN MOST OF OUR 
COMPETITORS IN THE GULF OF MEXICO.

           Competition in the oil and gas industry is intense, particularly 
in the Gulf of Mexico. We compete with major and independent oil and gas 
companies for property acquisitions and for the equipment and labor required 
to operate and develop such properties. Most of Basin's competitors have 
financial and other resources substantially greater than ours. We commenced 
operations in the Gulf of Mexico area during 1996, 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 Basin had conducted all of its previous operations.

PRINCIPAL STOCKHOLDER - HE 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 18% 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 Basin's Common Stock could be adversely affected.

                                       10

<PAGE>

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 in Denver 
and Houston. The loss of the services of Mr. Smith or other key personnel 
could have a potential adverse effect on Basin's operations.

YEAR 2000 READINESS  DISCLOSURE AND STATEMENT - BASIN OR ITS BUSINESS  
PARTNERS MAY NOT BE YEAR 2000 COMPLIANT,  WHICH COULD RESULT IN DISRUPTION OF 
OUR OPERATIONS.

           Basin expects to have completed its assessment, identification, 
remediation and testing of the Year 2000 readiness of its critical 
Information Technology ("IT") systems and its non-IT systems containing 
embedded microprocessors before January 1, 2000, and to have received 
satisfactory assurances by that date from its business partners that they 
will be Year 2000 compliant insofar as their goods or services are material 
to Basin's business. However, there is no assurance that Basin's 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 its systems. There is no assurance that Basin's business partners 
will likewise succeed in their respective efforts to remedy their Year 2000 
problems or that this will be apparent in time for Basin to formulate a 
contingency plan.

           Between now and 2000 there will be increased competition for 
people with technical and managerial skills necessary to deal with the Year 
2000 problem, and Basin or its 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 Basin's ability to assure that its critical systems 
or its partners systems are Year 2000 compliant.

           It is particularly difficult to find and remediate all embedded 
microprocessors in non-IT systems. Some of the embedded microprocessors that 
fail to operate or that produce anomalous results may create system 
disruptions or failures. Some of these disruptions or failures may spread 
from the systems in which they are located to other systems causing adverse 
effects upon Basin's ability to maintain production operations, conduct new 
drilling operations, execute financial transactions, manage its reporting or 
fulfill its legal obligations. The embedded microprocessor problem is widely 
recognized as one of the more difficult aspects of the Year 2000 problems 
across industries and throughout the world. The possible adverse impact of 
the embedded microprocessor problem is not, and will not be, unique to Basin. 
           If there are Year 2000-related failures in critical systems of 
Basin or its business partners that create substantial disruptions to Basin's 
business, the adverse impact on Basin could be material. Additionally, Year 
2000 costs are difficult to estimate accurately because of unanticipated 
vendor delays, technical difficulties, the impact of tests of third-party 
systems, and similar events. Moreover, despite Basin's belief that its costs 
in becoming Year 2000 compliant will not be material, its 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 its compliance efforts.

ANTI-TAKEOVER PROVISIONS - THESE PROVISIONS 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 more difficult to 
change control of Basin and replace incumbent management. Basin adopted a 
Stockholders' Rights Plan in 1996. Under this Plan, holders of Basin's Common 
Stock received rights exercisable if a person or group of affiliated persons 
acquires 15% of Basin's outstanding Common Stock or commences a tender or 
exchange offer which would result in ownership of 15% or more of Basin's 
outstanding Common Stock. In addition, Basin has entered into agreements with 
certain of its executive officers which would require additional payments by 
Basin if such officers' employment were terminated, or the terms of such 
employment were materially altered, upon a change of control.

                                       11

<PAGE>

ITEM 2. PROPERTIES.

           Prior to 1996, the Company's oil and gas properties were all 
located in the Rocky Mountain region, primarily in the D-J Basin, Powder 
River Basin, and Green River Basin. During 1996, the Company sold its D-J 
Basin assets and initiated operations in the Gulf of Mexico. As of December 
31, 1998, the Company's estimated proved reserves totaled approximately 8.7 
million barrels of oil and 127.5 Bcf of natural gas, or 179.5 Bcfe. The 
estimated pre-tax present value of future net revenues from these proved 
reserves, using December 31, 1998 product prices held constant and a discount 
rate of 10%, totaled approximately $164.5 million. Gulf of Mexico properties 
accounted for 75% of the Company's proved reserve quantities at December 31, 
1998, and 92% of the related pre-tax present value of future net revenues 
estimated as of that date. Weighted average price used for purposes of 
estimating the Company's proved reserves at December 31, 1998 were $10.31 per 
barrel of oil and $1.99 per Mcf of natural gas.

           In addition to its proved properties as of December 31, 1998, the 
Company owned mineral rights under 255,141 gross undeveloped acres, or 
180,816 net undeveloped acres, of which more than half is located in the Gulf 
of Mexico. The Company had also licensed 3-D seismic data covering 
approximately 600 lease blocks, and 2-D data covering approximately 375,000 
miles, in the Gulf of Mexico. The Company's undeveloped acreage in the Gulf 
of Mexico at the end of 1998 contained over 40 exploratory prospects 
identified by the Company's geoscientists, based upon their interpretations 
of 3-D seismic and other data.

           The Company's Gulf of Mexico proved reserves as of December 31, 
1998 were distributed among 18 fields. Production had been established from 
14 of these fields at that date, and the other four fields were under 
development for first production. The Company's working interests in the 18 
fields ranged from approximately 8% to 100%, with an average of 54%. Basin 
operates 11 of the 18 fields. These 11 properties account for approximately 
two-thirds of the Company's total proved reserves in the Gulf of Mexico. Six 
of the properties account for approximately 51% of the Company's proved 
reserve quantities and 67% of its related pre-tax present value of future net 
revenues from Gulf of Mexico assets as of December 31, 1998. These properties 
include Eugene Island Block 65, High Island Block A-568, West Cameron Block 
45, West Cameron Block 56, West Delta Block 61 and West Delta Blocks 121/122. 
As is generally the case for Gulf of Mexico properties, the Company's 
properties in this area are generally expected to exhibit a high initial 
production rate followed by a steep decline in production after a relatively 
short period.

           Most of the Company's proved reserves value related to onshore 
assets as of December 31, 1998 was concentrated in six fields in the Powder 
River and Green River Basins. This value was broadly distributed among 
approximately 200 producing wells, as well as a considerable number of 
undeveloped locations. Most of the Company's 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.

           Additional information related to the Company's properties is set 
forth below in the balance of this section.

OIL AND GAS RESERVES

           Basin engaged Ryder Scott Company Petroleum Engineers, independent 
petroleum engineers, to prepare estimates of proved reserves, projected 
future production, and related future net revenues for certain of the 
Company's properties as of December 31, 1998, and to audit Basin's estimates 
of such data for the Company's remaining properties as of that date. The 
estimates prepared by Ryder Scott Company Petroleum Engineers covered 
properties that accounted for 53% of the Company's proved reserve quantities 
in the Gulf of Mexico as of December 31, 1998, and audits conducted by Ryder 
Scott Company covered the other properties. Estimates prepared by Ryder Scott 
Company or the Company'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 reserve quantities 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 revenues 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 revenue from these proved reserves, see Unaudited 
Supplemental Oil and Gas Reserve Information in the Consolidated Financial 
Statements.

                                       12

<PAGE>

<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 (MMcfe) ..............................................       123,383        56,121      179,504

Future Net Revenue Before Income Taxes
  (in thousands) ...........................................     $ 170,691      $ 45,413    $ 216,104
Present Value of Future Net Revenue Before Income Taxes
  (in thousands)............................................     $ 137,775      $ 26,710    $ 164,485

</TABLE>

           The  following  table sets forth  estimates of Basin's  total proved
reserves at December 31, 1998 by  geographic  area of operations:

<TABLE>
<CAPTION>
                                     PROVED RESERVES
                             ------------------------------
                               OIL         GAS        TOTAL
                             (MBBLS)     (MMCF)      (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>

           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 
revenues 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.

           The weighted average sales prices utilized for purposes of 
estimating Basin's proved reserves and future net revenues 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 the Company realized average oil and gas prices of $11.80 per Bbl and 
$2.07 per Mcf, respectively, before hedging effects.

           As an operator of domestic oil and gas properties, the Company has 
filed Department of Energy Form EIA-23, "Annual Survey of Oil and Gas 
Reserves," as required by Public Law 93-275. There are differences between 
the reserves as reported on Form EIA-23 and as reported herein. The 
differences are attributable to the fact that Form EIA-23 requires that an 
operator report on the total reserves attributable to wells that are operated 
by it, without regard to ownership (I.E., reserves are reported on a gross 
operated basis, rather than on a net interest basis).

                                       13

<PAGE>

ACREAGE

           The following table sets forth the gross and net acres of 
developed and undeveloped oil and gas leases held by the Company as of 
December 31, 1998. Undeveloped acreage includes leasehold interests which may 
already have been classified as containing proved undeveloped reserves.

<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.

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 (MMcfe)..................     8,160       8,653       21,966
Average Daily
 Production:
     Oil (Bbls).....................     1,540       1,435        1,988
     Gas (Mcf)......................    13,050      15,094       48,262
     Total (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 (Mcfe)...................   $  2.29     $  2.88      $  2.05
Production Costs Per Mcfe...........   $  0.81     $  0.68      $  0.41

</TABLE>

-------------------
(1) excluding hedging effects

                                       14

<PAGE>

           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.

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      NET
<S>                                    <C>        <C>      <C>        <C>      <C>        <C>
Development:
   Oil...............................     3       2.8         5       5.0         1       1.0
   Gas...............................     -        -          1       0.6         -        -
   Non-productive....................     1        .9         -       -           -        -
                                        ---       ---       ---       ---       ---       ---
      Total..........................     4       3.7         6       5.6         1       1.0
                                        ---       ---       ---       ---       ---       ---
                                        ---       ---       ---       ---       ---       ---
Exploratory:
   Oil...............................     -        -          -       -           -        -
   Gas...............................     -        -          5       3.2         8       4.8
   Non-productive....................     3       1.4         3       1.5         5       2.2
                                        ---       ---       ---       ---       ---       ---
      Total..........................     3       1.4         8       4.7        13       7.0
                                        ---       ---       ---       ---       ---       ---
                                        ---       ---       ---       ---       ---       ---

</TABLE>

PRESENT ACTIVITIES

           On March 17, 1999, the Company submitted apparent winning bids for 
five tracts at the Central Gulf of Mexico lease sale held by the MMS. Such 
tracts comprised 24,023 gross and net undeveloped acres offshore Louisiana. 
If all five tracts are awarded by the MMS, which can choose to reject all 
bids for a given lease, the Company's aggregate cost for the related 
leasehold bonuses will total approximately $3.0 million.

           During 1999, through March 17, the Company's Gulf of Mexico 
activities have included completion of three (1.95 net) exploratory wells 
that were successfully drilled in 1998, drilling of two (0.80 net) 
exploratory wells, of which one (0.15 net) well was an apparent discovery, 
and the drilling of one successful development (0.65 net) well. The 

                                       15

<PAGE>

Company also participated in one (0.60 net) exploratory well in Wyoming, 
which was abandoned in February 1999 due to an apparent underground blowout, 
but which is currently being re-drilled.

ITEM 3. LEGAL PROCEEDINGS.

           The Company is not currently involved in any material legal 
proceedings.

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

           No matters were submitted for a vote of security holders during 
the fourth quarter of 1998.

                                    PART II


ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER 
MATTERS.

           Basin's common stock began trading on the NASDAQ National Market 
System on May 13, 1992 under the symbol "BSNX". As of December 31, 1998 there 
were approximately 2,000 beneficial owners of the Company's common stock. The 
following table sets forth, for the periods indicated, the range of high and 
low sales prices, and the closing price at the end of the period, for the 
Company's common stock as reported by the Nasdaq National Market for the last 
two calendar years.

<TABLE>
<CAPTION>
                    HIGH                  LOW               CLOSE
<S>                 <C>                 <C>                  <C>
1997                
First Quarter       $ 7.75               $ 5.88              $ 6.88
Second Quarter      $ 8.75               $ 6.38              $ 7.75
Third Quarter       $17.88               $ 7.63              $16.75
Fourth Quarter      $23.25               $16.38              $17.75

1998
First Quarter       $21.06               $13.88              $20.63
Second Quarter      $23.25               $14.13              $17.63
Third Quarter       $18.50               $ 9.00              $16.56
Fourth Quarter      $18.25               $10.25              $12.56

</TABLE>

           The Company's policy is to retain earnings to support the growth 
of the Company's business. Accordingly, the Board of Directors of the Company 
has never declared a cash dividend on its Common Stock and has no present 
plan to do so. A credit agreement with the Company's bank group limits the 
Company's ability to pay dividends, re-acquire shares of its common stock or 
make certain other distributions.

                                       16

<PAGE>

ITEM 6. SELECTED FINANCIAL DATA.

           The following table sets forth selected consolidated financial 
data for Basin as of the dates and for the periods indicated. The data set 
forth in this table should be read in conjunction with "Management's 
Discussion and Analysis of Financial Condition and Results of Operations" and 
the Consolidated Financial Statements and the related notes thereto that 
follow.

<TABLE>
<CAPTION>
(In thousands, except per share data)
                                                                 1994         1995         1996         1997             1998
                                                               --------     --------     --------     --------         -------
<S>                                                            <C>          <C>          <C>          <C>             <C>
STATEMENTS OF OPERATIONS DATA:
Revenue:
   Oil Sales                                                   $ 19,971     $ 19,632     $ 11,292     $  9,844        $  9,735
   Gas Sales                                                     24,255       20,013        6,890       14,557          38,885
   Gain on Sale of Assets                                            --           --       22,472           --               -
   Interest and Other                                               161          831        1,009          319              79
                                                               --------     --------     --------     --------         -------
                                                                 44,387       40,476       41,663       24,720          48,699
                                                               --------     --------     --------     --------         -------
Costs and expenses:
   Lease Operating Expenses                                       8,642        8,196        4,776        4,600           8,276
   Production Taxes                                               3,432        3,478        1,829        1,260             770
   Depreciation, Depletion and Amortization                      18,163       17,202        7,606       10,622          29,775
   General and Administrative, Net                                4,641        5,498        3,850        3,694           4,380
   Interest and Other                                             3,618        6,929        2,272          764           2,030
   Property Impairment                                               --       26,500           --           --          38,500
                                                               --------     --------     --------     --------         -------
                                                                 38,496       67,803       20,333       20,940          83,731
                                                               --------     --------     --------     --------         -------

Income (Loss) Before Income Taxes                                 5,891      (27,327)      21,330        3,780         (35,032)
Income Tax (Provision) Benefit                                   (2,236)       7,784       (5,760)      (1,324)          6,532
                                                               --------     --------     --------     --------         -------
Net Income (Loss)                                              $  3,655     $(19,543)    $ 15,570     $  2,456        $(28,500)
                                                               --------     --------     --------     --------         -------
                                                               --------     --------     --------     --------         -------
Basic:
    Earnings (Loss) Per Share                                  $    .34     $  (1.82)    $   1.45     $    .22        $  (2.06)
    Weighted Average Shares Outstanding                          10,813       10,710       10,700       11,228          13,859
Diluted:
    Earnings (Loss) Per Share                                  $    .34     $  (1.82)    $   1.45     $    .22        $  (2.06)
    Weighted Average Shares Outstanding                          10,879       10,710       10,730       11,345          13,859

BALANCE SHEET DATA (AT END OF PERIOD):
Working Capital (Deficit)                                      $ (5,646)    $ (2,211)    $ 19,178     $(10,036)       $(13,224)
Net Property and Equipment                                      165,807      134,598       54,800      149,175         187,811
Total Assets                                                    184,855      146,651       84,957      161,959         201,163
Long-term Debt                                                   77,199       77,172          218       11,053          80,000
Total Stockholders' Equity                                       72,575       53,287       68,751      121,365          94,219

</TABLE>

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

           The following discussion is intended to assist in an understanding 
of the Company's results of operations for the three-year period ended 
December 31, 1998 and its present financial condition. The Company's 
consolidated financial statements and notes thereto, which are presented 
elsewhere herewith, contain additional detailed information that should be 
referred to in conjunction with a review of this material.

HISTORY AND OVERVIEW

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

                                       17

<PAGE>

           The Company commenced operations in 1981 and completed an initial 
public offering of its common stock in 1992. From its inception through 1991, 
Basin primarily acquired, developed and exploited properties in the 
Denver-Julesburg ("D-J") Basin in eastern Colorado. The Company subsequently 
expanded into other areas within the Rocky Mountain region and initiated 
exploration activities.

           During 1995, the Company's capital expenditures on oil and gas 
properties declined to $16 million, from $67 million the year before, due 
primarily to fewer quality investment opportunities identified in the 
Company's core operating areas and limited unutilized borrowing capacity 
under the Company's revolving line of credit with its bank group (the "Credit 
Facility"). Each of these factors was exacerbated by depressed regional gas 
prices.

           In response to these developments and management's assessment of 
alternative investment opportunities, the Company implemented a significant 
redirection of its business strategy and operations between late-1995 and 
mid-1996, which included: (i) the addition of new financial, technical and 
business development members to its senior management; (ii) the sale of its 
D-J Basin properties for $123.5 million (the "D-J Sales"); (iii) 
establishment of a Houston-based Gulf of Mexico exploration team through 
hiring 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.

           The D-J Sales, which occurred in two transactions closed in March 
and June 1996, enabled the Company to eliminate its long-term debt and 
establish cash reserves, thus providing considerable liquidity for 
investments in new capital projects. However, the divestitures reduced the 
Company's estimated proved oil and gas reserves and production rates at the 
time by approximately 70%, resulting in a significant initial decline in 
revenue and cash flow.

           The Company began Gulf of Mexico activities in 1996 with no 
initial property base in the region and early investments related primarily 
to acquisitions of three-dimensional seismic data and exploratory leasehold 
interests and overhead. The Company's first significant discovery in the Gulf 
of Mexico was the Eugene Island Block 65 #1 well, which was drilling at the 
end of 1996 and completed in 1997. The Company realized first production from 
Gulf of Mexico assets in August 1997 when it brought two wells drilled on 
Eugene Island Block 65 on-line, providing the first significant addition to 
the Company's producing property base following the D-J Sales. The Company 
added other proved properties in the Gulf of Mexico in 1997 and 1998 through 
both exploratory drilling and acquisitions and as of December 31, 1998 owned 
interests in 18 proved properties in the area, of which 14 were producing and 
four were under development for first production. Several of the properties 
producing at that date also had proved nonproducing reserves under 
development. Through December 31, 1998, the Company had drilled a total of 31 
wells in the Gulf of Mexico, of which 20, or 65%, had been successful. The 
Company's estimated proved oil and gas reserves increased from 62.6 Bcfe as 
of December 31, 1995, pro forma the D-J Sales, to 179.5 Bcfe at the end of 
1998. As described below, Basin's net production has increased significantly 
since mid-1997, as Gulf of Mexico properties have been brought on-line, and 
the Company expects further increases in 1999.

           During 1998, the Company's capital expenditures totaled 
approximately $107 million. Approximately 96% of these investments related to 
operations in the Gulf of Mexico, including costs incurred for exploratory 
leaseholds, geological and geophysical data, exploratory drilling, and 
completion and development activities. Capital expenditures in 1998 were 
funded with a combination of cash flow, working capital, and borrowings under 
the Credit Facility.

           The Company closed 1998 with a working capital deficit of 
approximately $13 million, long-term debt of $80 million, and stockholders' 
equity of $94 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 the Company's oil 
and gas properties. This charge, which had no impact on the Company's cash 
flow or its borrowing capacity under the Credit Facility, was precipitated by 
low oil and gas prices in effect at year-end.

           The Company's preliminary budget for 1999 provides for capital 
investments of approximately $65 million, subject to potential increase 
should proceeds be realized from asset sales. This budget provides for 
exploratory drilling activities comparable to the level of such activities in 
1998, and for continued expeditious development of drilling successes. The 
1999 budget provides for a smaller current year investment in prospect 
leaseholds than in 1998, and anticipates cost savings realizable from lower 
rates for drilling rigs and other oilfield goods and services than were 

                                       18

<PAGE>

applicable during much of 1998. This budget may be revised up or down due to 
a number of factors, including future developments that impact availability 
of capital.

OPERATING ENVIRONMENT

           Basin's results of operations are significantly impacted by oil 
and gas price levels, which are volatile and largely beyond the Company's 
control. Changes in oil and gas prices can also impact the amount and terms 
of external capital resources available to the Company.

           Gas prices generally respond to North American supply and demand 
conditions, including the effects of weather, whereas 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 can significantly impact prices, 
however. During the past several months, the markets for both oil and gas 
have generally reflected ample supply and price weakness due to a number of 
factors, including a second consecutive unusually warm winter in North 
America. There are well-developed futures markets for oil and gas that 
provide indications of expected future prices for each product. These prices 
are frequently substantially different than current prices reflected on the 
spot market. Presently, these markets reflect expectations of a future 
recovery of oil and gas prices, particularly for gas, which accounted for 80% 
of the Company's total production in 1998. Expectations will change in 
response to future developments and higher future prices may not actually 
materialize.

           Hedging transactions can be entered into based on prices reflected 
in commodity futures markets. The Company periodically enters into fixed 
price sales agreements or other hedging transactions to take advantage of 
prices that it believes to be attractive and to reduce volatility of net 
price realizations. The Company has executed various hedging transactions to 
mitigate its exposure to further commodity price weakness, as described 
herein under Liquidity and Capital Resources and in the Notes to Consolidated 
Financial Statements. However, since its hedges cover only a portion of its 
anticipated future production, the Company remains vulnerable to the 
potential effects of low prices.

           The decline in oil and gas prices during the past year has 
negatively impacted access to capital resources for most energy companies, 
including Basin. Besides unfavorably affecting cash flow, this weakness in 
oil and gas prices has increased the cost of issuing long-term debt or equity 
securities and made the ability to issue such securities, at any price, less 
certain.

           For oil and gas producers, these effects have been partially 
mitigated by improvements in the environment for acquisition of proved and 
unproved oil and gas properties, and costs of conducting exploration and 
development activities. In the opinion of management, diminished capital 
resources for energy companies, in the aggregate, has resulted in significant 
overall improvement of the quality and terms of investment opportunities that 
are currently available, compared to the period preceding the decline in oil 
and gas prices that occurred during the past year. In addition to an enhanced 
market for acquirors of exploratory prospects or producing properties, there 
have been substantial reductions in the costs of oilfield goods and services. 
At various times in the recent past, demand for oil and gas drilling rigs and 
other oilfield products and services has strained available capacity, leading 
to high cost levels, delays in obtaining materials and services, and 
instances of decreased quality of goods and services. Such conditions do not 
presently apply, and availability of and costs for such goods and services 
have improved markedly since mid-1998. As an example, the day rate for a 
typical shallow-water jack-up drilling rig used by the Company in the Gulf of 
Mexico has declined from approximately $40,000 to $15,000. Other costs have 
declined by smaller amounts, but still significantly. As noted, these 
conditions reflect reduced demand for such goods and services in an 
environment of relatively low oil and gas prices and, as such, some reversal 
would be expected if oil and gas prices strengthen.

           The Company's Gulf of Mexico exploration activities are dependent 
on the Company's ability to continue to identify prospects and obtain 
interests in prospect leaseholds. The Company generally utilizes speculative 
three-dimensional seismic data as a tool in its prospect generation. This 
data is not proprietary and is available to competitors, which tends to 
increase the number of potential competitors for, and cost of, available 
prospects. During 1998, the Company was successful in expanding its inventory 
of potential exploratory drilling locations from approximately 30 to 40, 
while drilling 16 test wells. The Company also participated in submitting 
high bids for five leases with identified exploratory prospects at a Central 
Gulf of Mexico lease sale held in March 1999. This inventory of prospects, 
the majority of which are 100%-owned by the Company, represents more than a 
two-year set of drilling opportunities for Basin, based on both historical 
and anticipated drilling activity levels. However, the Company faces 

                                       19

<PAGE>

competition for prospects from many better-capitalized oil and gas companies 
and there is no assurance that over the longer term, the Company will be able 
to continue to acquire interests in prospects at acceptable costs to 
replenish its inventory of prospects as these are drilled. The Company seeks 
to mitigate this risk by pursuing prospect ownership through a number of 
avenues, including lease sales, farm-ins, exchanges, and acquisitions. The 
Company also plans to selectively evaluate and pursue other investment 
opportunities, including onshore exploration and acquisitions of properties 
with proved oil and gas reserves, to complement its core exploration 
activities in the Gulf of Mexico.

RESULTS OF OPERATIONS

           The following table sets forth certain operating information for 
the three years ended December 31, 1998. Because a substantial portion of the 
Company's operations was conducted in the D-J Basin through mid-1996 when the 
D-J Sales were consummated, and because the Company initiated Gulf of Mexico 
operations in 1996 and realized its first production from Gulf of Mexico 
properties in August 1997, period-to-period comparisons of results of 
operations may not be meaningful or indicative of future results.

<TABLE>
<CAPTION>
                                                         Year Ended December 31,
                                                       1996        1997        1998
                                                       ----        ----        ----
<S>                                                 <C>         <C>         <C>
Production:
   Oil (MBbl)                                           564         524         725
   Gas (MMcf)                                         4,776       5,509      17,616
   Total Gas Equivalents (MMcfe)                      8,160       8,653      21,966

Average Sales Price:
   Oil (per Bbl)                                    $ 20.03     $ 18.80     $ 13.42
   Gas (per Mcf)                                    $  1.44     $  2.64     $  2.21
   Total Gas Equivalents (per Mcfe)                 $  2.23     $  2.82     $  2.21

Revenue (in thousands):
   Oil Sales                                        $11,292     $ 9,844     $ 9,735
   Gas Sales                                        $ 6,890     $14,557     $38,885
   Total Oil and Gas Sales                          $18,182     $24,401     $48,620

Expenses (per Mcfe):
   Lease Operating Expenses                         $  0.59     $  0.53     $  0.38
   Production Taxes                                 $  0.22     $  0.14     $  0.03
   Depreciation, Depletion, and Amortization        $  0.93     $  1.23     $  1.36
   General and Administrative, Net                  $  0.47     $  0.43     $  0.20

</TABLE>


                                       20

<PAGE>

1998 COMPARED TO 1997

           As noted, the Company established its first production from Gulf 
of Mexico assets in the second half of 1997. This development, and production 
subsequently added from other Gulf of Mexico properties, significantly 
impacted the Company's results of operations. To assist in interpreting 
year-to-year comparisons, the following quarterly data is provided for the 
two-year period ended December 31, 1998.

<TABLE>
<CAPTION>

Quarter Ended                          March 31    June 30    Sept. 30    Dec. 31    March 31    June 30    Sept. 30    Dec. 31
                                        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:
   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%, 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.

           The increase in production volumes from 8,653 MMcfe in 1997 to 
21,966 MMcfe in 1998 was attributable to commencement of production at nine 
offshore properties at various times during 1998, and greater contributions 
from offshore properties acquired or brought on-line during the second half 
of 1997, partially offset by natural depletion. The decline in production 
between the third and fourth quarters of 1998 was largely due to the 
temporary loss of production from a major well, which was placed back on-line 
in the first quarter of 1999, after a re-completion operation.

           LEASE OPERATING EXPENSES. Lease operating expenses ("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, the Company's LOE per Mcfe has 
generally improved as Gulf of Mexico production has increased, beginning with 
the third quarter of 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, the 
Company's Gulf of Mexico properties have significantly lower unit operating 
costs than its Rocky Mountain assets. The relatively low per-unit operating 
cost of the Company'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 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 price realizations on such production. Production from properties 
in federal waters offshore 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 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 

                                       21

<PAGE>

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 the Company's historical average. The increased unit cost of 
additions in 1998 reflects the substantial portion of the Company's 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 
the Company's 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 
was $2.0 million, representing an increase of $1.3 million, or 166%, compared 
to 1997. The variance was attributable to an increase in average borrowings 
offset by a slight reduction in the Company'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, the Company 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 interest rate 
of 6.7% in 1997. Substantially all of the borrowings in both years were under 
the Credit Facility.

           PROPERTY IMPAIRMENT. During 1998, the Company recognized a 
property impairment charge of $38.5 million, as the result of the capitalized 
costs of its 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 the Company's 
cash flows or its bank 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 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 establishment of a $5.7 million deferred tax asset valuation 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.

1997 COMPARED TO 1996

           The sale of the Company's D-J Basin assets in the first half of 
1996 and realization of first production from Gulf of Mexico assets in the 
second half of 1997 result in year-to-year comparisons that obscure important 
underlying trends. To assist in understanding such trends, the following 
quarterly data is provided for the two-year period ended December 31, 1997.

<TABLE>
<CAPTION>
Quarter Ended                          March 31    June 30    Sept. 30    Dec. 31    March 31    June 30    Sept. 30    Dec. 31
                                        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:
   Oil (per Bbl)                       $ 17.94     $ 20.84    $ 21.10     $ 22.31    $ 20.41     $ 17.73    $ 18.59     $ 18.62
   Gas (perMcf)                        $  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>

                                       22

<PAGE>

           REVENUE. Oil and gas sales for 1997 increased by $6.2 million, or 
34%, to $24.4 million, due largely to improved average price realizations. 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 masks significant changes during each 
year due to the D-J Sales in March and June 1996 and the commencement of Gulf 
of Mexico production in August 1997.

           In conjunction with the second D-J Sale transaction, which closed 
in June 1996, the Company 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 D-J 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, the relatively small changes from 
year-to-year do not reflect significant variances within each year. Average 
LOE per Mcfe by quarter reflects that both the properties included in the D-J 
Sales and the Gulf of Mexico properties that began contributing in the second 
half of 1997 have significantly lower unit operating costs than the Company'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 by $0.6 
million, or 31%, as the result of reduced sales from onshore properties in 
1997, due to inclusion in 1996 of production from D-J Basin properties prior 
to the D-J 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 as the Company added 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 by $3.0 million, or 40%, in 1997 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 the Company's historical average and to the 
unfavorable impact on estimated proved reserve quantities 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 the Company's 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 the Company'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 D-J Sales and related 
reductions in office rent expense attributable to the Company's relocation to 
smaller space. These savings, which benefitted 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 variance was attributable to a decrease in average borrowings 
after the D-J Sales and a reduction in the Company's average effective 
interest rate, reflecting lower prevailing market interest rates and more 
favorable borrowing terms obtained after the D-J Sales. During 1997, the 
Company 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 interest rate of 8.0% in 1996. Substantially all of 
the borrowings in both years were under the Credit Facility.

                                       23
<PAGE>

           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 fiscal 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.

LIQUIDITY AND CAPITAL RESOURCES

           Historically, the Company's principal sources of capital have been 
cash flow from operations, the Credit Facility, proceeds from asset sales, 
and proceeds from sales of common stock. The Company's principal uses of 
capital have been for the exploration, acquisition, development and 
exploitation of oil and gas properties.

           The Company's oil and gas capital expenditures during 1998 totaled 
approximately $106.7 million. Net cash provided by operations before changes 
in working capital totaled $33.7 million. The remainder of 1998 capital 
expenditures was funded primarily through a $69.0 million increase in 
borrowings under the Credit Facility and a $3.2 million reduction in net 
working capital. The Company closed 1998 with a working capital deficit of 
approximately $13.2 million and long-term debt of $80.0 million, all of which 
was outstanding under the Credit Facility. The borrowing base established 
under the Credit Facility as of January 1, 1999 was $110 million.

           For 1999, the Company has established an initial budget for 
exploration and development activities of approximately $65 million, subject 
to potential increase for proceeds from asset sales, if any. The Company 
plans to fund such investments with cash flow from operations, which is 
expected to increase from 1998 levels because of projected production 
increases, and additional borrowings under the Credit Facility. This budget 
is subject to revision to reflect future developments. It may be impacted by 
oil and gas price levels, future re-determinations of the borrowing base 
under the Credit Facility, and other factors. Although this budget is not 
predicated on a future sale of securities, the Company may choose to issue 
securities in certain circumstances, in which case the level of the Company's 
capital expenditures in 1999 would likely increase. Compared to actual 
capital expenditures in 1998, the lower budget presently established for 1999 
reflects a number of considerations including, but not limited to, lower 
assumed oil and gas prices and higher initial debt levels. The impact on 
drilling activity in the current year, compared to 1998, is expected to be 
modest, as most of the decline in expenditures is expected to be offset by 
lower service sector costs or reflected in reduced investments for 
acquisitions of prospect leaseholds. The Company's investments in leaseholds 
in 1998 significantly increased its inventory of exploratory prospects in the 
Gulf of Mexico, to a level representing a multi-year set of drilling 
opportunities. The Company's initial budget for 1999 anticipates investments 
at a level to approximately maintain, rather than significantly expand, its 
inventory of Gulf of Mexico prospects.

           PRODUCTION AND CASH FLOW. The Company's cash flow from operations 
is generally determined largely by its production level and oil and gas 
prices. Since 1996, the Company has made significant investments to initiate 
and then expand its operations in the Gulf of Mexico. These investments have 
resulted in a production ramp-up that increased the Company's 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 68.8 MMcfe per day in the third 
quarter of 1998, before a decline to 65.9 MMcfe per day in the fourth quarter 
of 1998 when a significant well was taken off-line for re-completion 
operations. Based primarily on estimates reflected in the Company's year-end 
1998 reserve reports, the Company anticipates that its net production in 1999 
will be at least 50% greater than during 1998, when production totaled 21,966 
MMcfe. The expected increase is attributable 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 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 to-date. 
Although management and the Company's independent engineering consultants 
believe the projections are reasonable, there is no assurance that they will 
be met.

           MARKETING AND HEDGING TRANSACTIONS. The Company's production is 
generally sold under month-to-month contracts at prevailing prices. From 
time-to-time, however, as conditions are deemed to warrant, Basin has entered 
into 

                                       24

<PAGE>

hedging transactions or fixed price sales contracts for a portion of its oil 
and gas production. The purposes of these transactions are to limit the 
Company's exposure to future oil and gas price declines and achieve a more 
predictable cash flow. However, such contracts also limit the benefits the 
Company would realize if prices increase. Hedging contracts reduced the 
Company's total revenue by $0.5 million in each of 1996 and 1997, and 
increased revenue by $3.5 million in 1998.

           As of February 24, 1999, the Company 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, the Company 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 the Company 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, the Company 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 the Company by reference to the underlying NYMEX October 1999 contract 
price less $0.28. The Company 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. At 
December 31, 1998, the estimated fair value of the open oil and gas price 
hedging contracts was an unrealized gain of approximately $1,170,000.

           CREDIT FACILITY. Effective January 1, 1999, the Company 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 million under two combined facilities. Facility A was initially 
established at $90 million and represents the borrowing base that is 
considered to be "conforming" based upon the bank's customary practices and 
standards in making conventional borrowing base determinations for oil and 
gas producers. Facility B, initially established at $20 million, 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 the Company'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 the Company's 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. 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 
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 converted into a term loan. The Credit 
Agreement contains various covenants, including ones that could limit the 
Company's ability to incur other debt, dispose of assets, pay dividends, or 
repurchase stock. Pursuant to the Credit Agreement, substantially all of the 
Company's producing properties are subject to mortgages in favor of the banks 
and the Company'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%. The Company's 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 the end of 1998, the impact on interest expense, before 
amounts capitalized, of a ten percent change in the average interest rate 
would be 

                                       25

<PAGE>

approximately $500,000. As the interest rate is variable and is reflective of 
current market conditions, the carrying value of the Company'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 the Company'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, the Company 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 the Company's 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 the Company's reserve values are sufficiently increased, or that Facility 
B will be repaid from cash flows or proceeds from asset or security sales. At 
March 19, 1999, $90 million was outstanding under Facility A and $2.5 million 
was outstanding under Facility B.

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

           CAPITAL EXPENDITURES. Since the beginning of 1996, Basin has 
focused its exploration activities in the shallow waters of the Gulf of 
Mexico, primarily off the coast of Louisiana. Recently, the Company began to 
direct a small portion of its exploration budget toward onshore 
opportunities, and it pursues acquisition, development, and exploitation 
opportunities in the vicinity of the Company's Gulf of Mexico exploration 
operations, in the Rocky Mountain region where Basin has an existing base of 
proved reserves and producing wells, and in certain other major domestic 
producing basins where the Company believes significant upside potential 
exists. The Company's 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.

           The Company'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 proved property 
acquisitions 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.

           The Company currently estimates that its capital expenditures for 
exploration and development in 1999 will be approximately $65 million, 
subject to potential increase if proceeds are realized from asset sales. This 
budget primarily provides for: development of seven properties with one or 
more successful wells yet to commence sustained production as of the end of 
1998; investments in seismic data and prospect leaseholds; participation in 
approximately six net (13 to 15 gross) exploratory wells in the Gulf of 
Mexico; participation in a small number of onshore exploration opportunities; 
development of assumed 1999 prospect discoveries; and continued exploitation 
of the Company's other offshore and onshore properties. Although several 
locations for planned 1999 exploratory drilling have been identified, a 
significant portion of the 1999 exploration budget is currently unallocated, 
pending acquisition of drilling partners and formation of joint ventures to 
conduct exploratory operations. The smaller budget in 1999, compared to 
actual expenditures in 1998, is not expected to require a significant 
reduction in drilling activity because of a planned substantial reduction in 
acquisitions of exploratory leaseholds in 1999 and benefits expected to be 
realized from the substantial decline in service sector costs during the past 
year. The reduced budget for exploratory leaseholds reflects the unusually 
large investment made by the Company in 1998 to initially establish a 
multi-year inventory of drilling prospects. New investments planned for 1999 
will seek to approximately maintain this inventory level rather than 
significantly expand it.

           The Company also intends to pursue acquisitions of properties with 
proved and probable reserves as an integral part of its overall business 
strategy, with the expectation that these efforts will result in significant 
investment activity over time. At this time, no portion of the Company's 1999 
budget has been specifically allocated for acquisitions of proved 

                                       26

<PAGE>

properties. If such a transaction is executed, it will likely require a 
re-allocation of budget from other planned activities and/or external 
financing.

           The amount and allocation of future capital expenditures will 
depend on a number of factors that are not entirely within the Company'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. The Company'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 the Company's Credit Agreement. Due to these 
uncertainties, actual capital expenditures may vary significantly from 
current expectations.

           Should the Company seek to increase its capital expenditure budget 
for 1999 to respond to drilling opportunities that it deems exceptional, to 
fund development of a greater number or larger-sized exploratory successes 
than assumed, or for acquisitions of proved and probable reserves or prospect 
leaseholds, the Company may consider raising additional capital through 
issuance of debt and/or equity securities. The Company may also seek 
additional debt or equity financing in the absence of a specific planned 
increase in capital expenditures, in order to increase financial flexibility 
to capitalize on future opportunities.

           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 the Company's disclosures under the headings "Forward Looking 
Statements" and "Risk Factors" in this report.

           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 ("IT") systems -- computer systems controlling a 
company's accounting, land, operations, seismic processing, and other 
specialized functions -- but also non-IT 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 the Company 
and the parties with whom it does business.

           STATE OF READINESS. The Company has created an internal committee 
to assess the Company's Year 2000 readiness and to lead its 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 the 
Company'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 the Company's IT and non-IT systems, 
and have communicated with the Company's business partners regarding the 
status of their assessment and remediation efforts, with the results 
summarized below.

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

           The Company also relies on non-IT systems, such as office 
telephones, facsimile machines, HVAC systems and elevators in its 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-IT 
systems which may be susceptible to failure or impairment by reason of Year 
2000 problems and which are potentially critical to the Company's operations 
and business continuity. Based on that review, the Company 

                                       27

<PAGE>

has sent written inquiries to the suppliers of those systems to determine 
their Year 2000 compliance. The vendors of the Company's communications 
systems and the property managers of the buildings in which the Company's 
Houston and Denver offices are situated have certified their systems to be 
Year 2000 compliant. The Company is still receiving and analyzing responses 
from vendors of those non-IT systems that may affect the Company's 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-IT systems should be completed by September 1999.  

           The Company has sent written inquiries to its significant 
suppliers, customers, banks, government agencies, benefit plan providers, and 
others with whom the Company has significant business relationships to 
determine the extent to which the Company is vulnerable to those third 
parties' failure to correct their own Year 2000 issues. To date, the Company 
has 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 the Company. Those third parties who 
have responded have generally indicated that they are either Year 2000 
compliant or expect to be compliant. 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 the 
Company's production operations and continue any ongoing or planned drilling 
activities. The Company expects to have this follow-up inquiry completed by 
July 1999 and will utilize those vendors and suppliers providing adequate 
assurances regarding their compliance.

           ESTIMATED COMPLIANCE COSTS. The Company has relied primarily on 
its internal staff to assess its current Year 2000 readiness and does not 
anticipate extensive use of external resources to complete its assessment or 
remediation. The Company has not separately quantified its costs of internal 
resources on this project but does not expect that it will incur material 
costs in remediating its IT 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. The Company has not incurred, and does not 
anticipate that it 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 the Company 
will not be able to 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 IT systems which the Company believes are not yet Year 2000 
compliant are its seismic data interpretation and reservoir economics 
systems, which should be compliant by July 1999. Accordingly, the Company 
does not expect Year 2000 issues to cause its IT systems to have any material 
adverse impact on its business, operations or financial condition. The 
Company believes that the potential impact, if any, of its non-critical IT 
systems not being Year 2000 compliant will at most require employees to 
manually complete otherwise automated tasks or calculations and should not 
impact the Company's ability to continue exploration, drilling, production or 
sales activities. The Company is not able to predict at this time what the 
impact could be of non-IT system failures but does not believe that there 
will be a material disruption of the Company's operations.

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

            The Company does not currently have a contingency plan under 
development or in place to address these potential problems. The Company does 
intend to develop contingency plans in response to testing its IT and non-IT 
systems and in response to the results of its 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. The 
Company 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 estimates and schedules as testing and business partner 
assessment progresses. Unexpected Year 2000 compliance problems of either the 
Company 

                                       28

<PAGE>

or its vendors, customers, service providers, or other entities with whom it 
does business could have a material adverse impact on the Company's business, 
financial condition or operating results.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

           The Company's exposure to interest rate risk and commodity price 
risk is discussed in Item 7. Management's Discussion and Analysis of 
Financial Condition and Results of Operations under the headings "Operating 
Environment", "Liquidity and Capital Resources - Marketing and hedging 
transactions" and "Liquidity and Capital Resources - Credit facility". The 
Company has no exposure to foreign currency exchange rate risks or to any 
other market risks.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

           The Consolidated Financial Statements that constitute Item 8 are 
attached at the end of this report. An index to the Consolidated Financial 
Statements appears in Item 14 of this report.

ITEM 9. CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND 
FINANCIAL DISCLOSURE.

           None.

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

           The information required by this item is incorporated by reference 
from the sections entitled "Management" and "Disclosure of Filings by 
Insiders" in the Company's definitive Proxy Statement for its 1999 Annual 
Meeting of Stockholders (the "Proxy Statement") to be filed with the 
Securities and Exchange Commission no later than April 30, 1999.

ITEM 11. EXECUTIVE COMPENSATION.

           The information required by this item is incorporated by reference 
from the section entitled "Executive Compensation" in the Proxy Statement. 
Nothing in this report shall be construed to incorporate by reference the 
Board Compensation Committee Report on Executive Compensation or the 
Performance Graph which are contained in the Proxy Statement, which are 
expressly not incorporated herein.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

           The information required by this item is incorporated by reference 
from the section entitled "Security Ownership of Certain Beneficial Owners 
and Management" in the Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

           The information required by this item is incorporated by reference 
from the section entitled "Certain Relationships and Other Transactions" in 
the Proxy Statement.

                                       29

<PAGE>

                               CERTAIN DEFINITIONS

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

           ACREAGE HELD BY PRODUCTION. Acreage covered by an oil and gas 
lease which has a producing well on it, or which is pooled with a lease or 
leases having one or more producing wells on them, so the lease is maintained 
in effect for the duration of such production.

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

           BCF. Billion cubic feet (of gas).

           BCFE. Billion cubic feet (of gas) equivalent.

           BEHIND-PIPE RESERVES. Proved reserves in a formation in which 
production casing has already been set in the wellbore, but from which 
production has not commenced.

           BTU. British thermal unit.

           COMMINGLE.  The combining of production from more than one zone in 
the same well to produce from multiple zones at the same time.

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

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

           DRILLING LOCATIONS. A site on which a well can be drilled 
consistent with local spacing rules for the purpose of recovering possible, 
probable or proved reserves.

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

           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.

           FARMOUT.  An assignment of an interest in a drilling  location and 
related acreage  conditional upon the drilling of a well on that location.

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

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

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

           MBTU. One thousand Btus.

           MCF. One thousand cubic feet (of gas).

                                       30

<PAGE>

           MCFE. One thousand cubic feet of natural gas equivalent. In 
reference to crude oil or other liquid hydrocarbons, equivalents are 
determined using the ratio of one Bbl of crude oil or other liquid 
hydrocarbon to 6 Mcf of gas.

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

           MMBTU. One million Btus.

           MMCF. One million cubic feet.

           MMCFE. One million cubic feet (of gas) equivalent.

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

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

           PRESENT VALUE OF FUTURE NET REVENUES. Estimated future net 
revenues discounted at a rate of ten percent per annum.

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

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

           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.

           PROVED UNDEVELOPED LOCATION. A site on which a development well 
can be drilled consistent with local spacing rules for the purpose of 
recovering proved reserves.

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

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

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

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

                                       31

<PAGE>

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

       (a)(1) and (a)(2) Financial Statements and Financial Statement Schedules

<TABLE>
<CAPTION>
                                                                         PAGE
                                                                         ----
<S>                                                                      <C>
Report of Independent Public Accountants...............................    33

Consolidated Balance Sheets as of December 31, 1997 and 1998...........    34

Consolidated Statements of Operations for the years ended
  December 31, 1996, 1997, and 1998....................................    35

Consolidated Statements of Cash Flow for the years
  ended December 31, 1996, 1997 and 1998...............................    36

Consolidated Statements of Changes in Stockholders' Equity
  for the years ended December 31, 1996, 1997 and 1998.................    37

Notes to Consolidated Financial Statements.............................    38

</TABLE>

           All other schedules are omitted because the required information 
is not applicable or is not present in amounts sufficient to require 
submission of the schedule or because the information required is included in 
the Consolidated Financial Statements and Notes thereto.

                                       32

<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.


                                       33

<PAGE>

BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>

December 31, (in thousands, except per share data)                            1997            1998  
---------------------------------------------------------------------------------------------------
<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.

                                       34

<PAGE>

BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
For the years ended December 31, (in thousands, except per share data)        1996            1997          1998
-------------------------------------------------------------------------------------------------------------------
<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.

                                       35

<PAGE>


BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW

<TABLE>
<CAPTION>
For the years ended December 31, (in thousands)                               1996            1997          1998 
-------------------------------------------------------------------------------------------------------------------
<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)
   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.

                                       36

<PAGE>


BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

For the years ended December 31, 1996, 1997 and 1998 (in thousands)
-------------------------------------------------------------------

<TABLE>
<CAPTION>
                                                                                                       Retained
                                                  Common Stock      Additional     Treasury Stock      Earnings
                                                 ---------------      Paid-In    -----------------   (Accumulated   Stockholders'
                                                 Shares   Amount      Capital    Shares     Amount     Deficit)        Equity    
                                                 ------   ------    ----------   ------     ------   ------------   -------------
<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.

                                       37

<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" or the 
"Company"). 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. The Company'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 
the Company 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 - The Company 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 the Company'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. The Company 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 
revenues 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 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.

           The Company 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 the Company 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.

                                       38

<PAGE>

           INCOME TAXES - The Company 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 - The Company 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 the Company 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 the Company. The Company accounts 
for its commodity derivatives contracts using the hedge (deferral) method of 
accounting. Under this method, realized gains and losses from the Company'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.

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

           As of February 24, 1999, the Company 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, the Company 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 the Company 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, the Company 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 the Company by reference to the underlying NYMEX October 1999 contract 
price less $0.28. The Company 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," the Company 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 the Company's intention to 
terminate any of the arrangements, it is estimated that the Company would 
have 

                                       39

<PAGE>

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 the Company.

           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 the 
Company in 2000, but early adoption is allowed. The Company 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 - The Company 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 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 the Company'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 the Company's net loss in that year.

           In connection with the acquisition of Sterling Energy Corp. in 
November 1994, the Company issued warrants to purchase 300,000 shares of the 
Company'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 - The Company 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, the Company entered into agreements pursuant to 
which it sold all of its assets in the D-J 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. The Company recognized a gain of $22,472,000 in conjunction with the 
second transaction. Revenue and expenses associated with the sold properties 
were included in the Company'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 the Company's 
consolidated financial statements since the closing date.

                                       40

<PAGE>

(3)   LONG-TERM DEBT

<TABLE>
<CAPTION>
                                                 December 31,
                                            -----------------------
(in thousands)                                1997          1998
                                              ----          ----
<S>                                         <C>           <C>
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, the Company 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 the Company'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 the Company'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 l, 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 the 
Company'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 the Company's producing properties are subject to 
mortgages in favor of the banks and the Company'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>

(4)   BENEFIT PLANS

           401(k) SAVINGS - The Company has a 401(k) profit sharing plan (the 
"Plan"). Eligible employees may make voluntary contributions to the Plan, 
which may be matched by the Company, at its discretion, up to 6 percent of 
the employee's eligible compensation. The Company 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, the Company may also make 
additional contributions to the Plan. The Company 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 the Company's Equity Incentive Plan, officers, 
key employees, consultants and directors of the Company 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. 

                                       41

<PAGE>

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 the Company'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>

    Range of           Number of         Weighted         Weighted Average       Number of        Weighted
 Exercise Prices       Options           Average           Remaining Life        Options          Average
    Per Share        Outstanding      Exercise Price         in 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>

           The Company 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 $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.

           The Company 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, the Company 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. The Company has elected to continue to account for stock 
compensation using the intrinsic value based method.

                                       42

<PAGE>

           Had the Company 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>

(5)   COMMITMENTS AND CONTINGENCIES

           LEASES - The Company is the primary obligor under various 
noncancelable office space operating lease arrangements. The Company 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 - The Company, 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 the Company's financial condition, liquidity or 
results of operations.

                                       43

<PAGE>

(6)   INCOME TAXES

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

<TABLE>
<CAPTION>
                                            Year Ended December 31,
                                       ---------------------------------
(in thousands)                          1996         1997         1998
                                       -------     -------      --------
<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>

           Reconciliations of income tax provisions (benefit) computed at the 
federal statutory rate with income tax provisions recorded by the Company for 
each of the past three years are as follows:

<TABLE>
<CAPTION>
                                            Year Ended December 31,
                                       ---------------------------------
(in thousands)                          1996         1997         1998
                                       -------     -------      --------
<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,
                                                   ---------------------
(in thousands)                                       1997         1998
                                                   --------     --------
<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, the Company 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 the Company 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. 

                                       44

<PAGE>

(8) OIL AND GAS ACTIVITIES

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

           MAJOR PURCHASERS - The following parties purchased ten percent or 
more of the Company'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,
                                                                ---------------------------
(in thousands, except for gas equivalent data)                   1996       1997      1998
                                                                ------     ------    ------
<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. The Company 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 revenues 
from proved reserves and the present value thereof are based upon certain 
assumptions, including geologic success, and future 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 the 

                                       45

<PAGE>

Company's proved reserves and future net revenue 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 the Company's reserves are located onshore or offshore in 
the United States. The following tables include estimates for the Company's 
onshore and offshore reserves combined. Estimates of onshore reserves were 
prepared by the Company'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 the Company's engineers and audited by Ryder Scott Company 
Petroleum Engineers.

                                       46

<PAGE>

ANALYSES OF CHANGES IN PROVED RESERVES

           The following table sets forth information regarding the Company'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>

STANDARDIZED MEASURE

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


<TABLE>
<CAPTION>
                                                                          December 31,
                                                                -------------------------------
(in thousands)                                                    1996         1997        1998
                                                                 ------       ------      ------
<S>                                                             <C>          <C>         <C>
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 the Company estimates 
future income taxes using the "year-by-year" method. For ceiling test 
purposes the Company estimates future income taxes using the "short-cut" 
method.

                                       47

<PAGE>

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

<TABLE>
<CAPTION>
                                                                    Year Ended December 31,
                                                                -------------------------------
(in thousands)                                                    1996         1997        1998
                                                                 ------       ------      ------
<S>                                                             <C>          <C>         <C>
Standardized Measure of Discounted Future
   Net Cash Flows, Beginning of Year                            $117,248     $ 63,306    $135,482
Changes 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>

UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA

<TABLE>
<CAPTION>
(in thousands, except per share amounts)
                                             First              Second        Third         Fourth         Total
                                             -----              ------        -----         ------         -----
<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.

                                       48

<PAGE>

   (a)(3) Exhibits

<TABLE>
<CAPTION>
   EXHIBIT
   NUMBER                                          DESCRIPTION OF EXHIBITS
   ------                                          -----------------------
<S>                 <C>
        2.1    --   Agreement and Plan of Merger between Sterling Energy Corporation, 
                    Basin Energy, Inc. and Basin Exploration, Inc. dated October 13, 1994(5)
        2.2    --   Plan of Merger between Basin Sterling, Inc. and Basin Exploration, Inc. 
                    dated November 22, 1994(5)
        2.3    --   Plan of Merger between Basin Operating Company and Basin Exploration, Inc. 
                    dated December 14, 1994(7)
        3.1    --   Restated Certificate of Incorporation of Basin.(2)
        3.2    --   Restated Bylaws of Basin.(2)
        4.1    --   Common Stock Certificate of Basin.(2)
       10.1    --   Equity Incentive Plan as amended May 5, 1998.(14)
       10.3    --   Key Employee Participation Plan.(2)
       10.4    --   Employment Agreement dated March 31, 1992 by and between Basin and Michael S. Smith.(3)
       10.5    --   Gulf Coast Geoscientist Overriding Royalty Interest Plan dated November 30, 1995.(9)
       10.6    --   Form of Rights Agreement dated as of February 24, 1996, between Basin 
                    Exploration, Inc. and Corporate Stock Transfer, Inc. as Rights Agent.(8)
       10.7    --   Performance Shares Plan approved February 4, 1997.(10)
       10.8    --   Change of Control Employment Agreement dated October 13, 1995 between Basin
                    Exploration, Inc. and Howard L. Boigon.(9)
       10.9    --   Employment Agreement dated August 28, 1995 between Basin Exploration, Inc. 
                    and Samuel D. Winegrad.(9)
       10.10   --   Employment Agreement dated June 28, 1995 between Basin Exploration, Inc. 
                    and Neil L. Stenbuck.(9)
       10.11   --   Employment Agreement dated November 10, 1995 between Basin Exploration, Inc. 
                    and David A. Pustka.(9)
       10.12   --   Employment Agreement dated February 23, 1996 between Basin Exploration, Inc. 
                    and Thomas J. Corley.(10)
       10.13   --   Assignment and Assumption of Lease dated December 18, 1995 by and between 
                    Team, Inc., as original Tenant, Basin Exploration, Inc., as New Tenant, and 
                    FC Tower Property Partners, L.P., as Landlord.(8)
       10.16   --   Lease of Office Space dated September 25, 1992, between Brookfield Republic Inc. 
                    and Basin Operating Company, as amended(4)+
       10.17   --   First Lease of Additional Office Space dated as of December 1, 1994, between 
                    Brookfield  Republic, Inc. and Basin Operating Company.(6)+
       10.18   --   Purchase and Sale Agreement dated February 13, 1997, between Hall-Houston Oil 
                    Company et al as Sellers and Basin Exploration, Inc. as Buyer.(10)+
       10.19   --   First Amendment of Amended and Restated Credit Agreement dated August 6, 1996 
                    between the Company and Colorado National Bank, Union Bank of California, N.A. 
                    and NationsBank of Texas, N.A. dated June 11, 1997.(11)
       10.20   --   Order of the United States Bankruptcy Court for the Southern District of Texas 
                    Corpus Christi Division, dated November 18, 1997, with exhibits, including the 
                    Agreement of Purchase and Sale.(12)
       10.21   --   Second Amendment of Amended and Restated Credit Agreement dated August 6, 1996 
                    between the Company and Colorado National Bank, Union Bank of California, N.A. 
                    and NationsBank of Texas, N.A. dated November 1, 1997.(13)
       10.22   --   Third Amendment of Amended and Restated Credit Agreement dated August 6, 1996 
                    between the Company and U.S. Bank National Association, Union Bank of 
                    California, N.A. and NationsBank of Texas, N.A. dated April 30, 1998.(14)
       10.23   --   Fourth Amendment of Amended and Restated Credit Agreement dated August 6, 1996 
                    between the Company and U.S. Bank National Association, Union Bank of 
                    California, N.A. and Nationsbank, N.A., dated August 20, 1998.(15)
       10.24   --   Amended and Restated Credit Agreement dated January 1, 1999 among the Company and  
                    Nationsbank, N.A., U.S. National Association and Union Bank of California, N.A.(1)
       10.25   --   Employment Agreement dated January 28, 1999, between Basin Exploration, Inc. and Patrick A. Jackson.(1)
       10.26   --   Employment Agreement dated February 1, 1999, between Basin Exploration, Inc. and David A. Pustka.(1)

</TABLE>

                                       49

<PAGE>

<TABLE>
<S>                 <C>

       21      --   Subsidiaries.(1)
       23.1    --   Consent of Arthur Andersen LLP.(1)
       23.2    --   Consent of Ryder Scott Company.(1)
       27      --   Financial Data Schedule.(1)

</TABLE>

-------------------
 (1)   Filed herewith.

 (2)   Filed as an Exhibit to Basin's Registration Statement on Form S-1 as 
       filed on March 17, 1992, Registration No. 33-46486, and incorporated 
       herein by reference.

 (3)   Filed as an Exhibit to Amendment No. 1 to Basin's Registration 
       Statement on Form S-1 as filed on April 21, 1992, Registration No. 
       33-46486, and incorporated herein by reference.

 (4)   Filed as an Exhibit to Basin's Registration Statement on Form S-1 as 
       filed on October 25, 1993, Registration No. 33-70802, and incorporated 
       herein by reference.

 (5)   Filed as an Exhibit to Form 8-K filed on December 10, 1994, and 
       incorporated herein by reference.

 (6)   Filed as an Exhibit to Form 10-K/A-1 filed on June 26, 1995 and 
       incorporated herein by reference.

 (7)   Filed as an Exhibit to Form 10-K filed on March 28, 1995, and 
       incorporated herein by reference.

 (8)   Filed as an Exhibit to Form 8-K filed on February 26, 1996, and 
       incorporated herein by reference.

 (9)   Filed as an Exhibit to Form 10-K filed on March 28, 1996, and 
       incorporated herein by reference.

(10)   Filed as an Exhibit to Form 10-K filed on March 31, 1997, and 
       incorporated herein by reference.

(11)   Filed as an Exhibit to Form 10-Q filed on August 12, 1997, and 
       incorporated herein by reference.

(12)   Filed as an Exhibit to Form 8-K filed on December 11, 1997, and 
       incorporated herein by reference.

(13)   Filed as an Exhibit to Form 10-K filed on March 31, 1998, and 
       incorporated herein by reference.

(14)   Filed as an Exhibit to Form 10-Q filed on May 14, 1998, and 
       incorporated herein by reference.

(15)   Filed as an Exhibit to Form 10-Q filed on November 13, 1998, and 
       incorporated herein by reference.

+      Confidential treatment has been granted for portions of these Exhibits.


  (b) Reports on Form 8-K

             None.

                                       50

<PAGE>

                                   SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the 
registrant has duly caused this report to be signed on its behalf by the 
undersigned, thereunto duly authorized.


                                       BASIN EXPLORATION, INC.


                                       By: /s/ MICHAEL S. SMITH
                                          ---------------------------
Date: March 29, 1999                      Michael S. Smith
                                          PRESIDENT, CHIEF EXECUTIVE OFFICER
                                          AND CHAIRMAN OF THE BOARD

Pursuant to the requirements of the Securities Exchange Act of 1934, this 
report has been signed below by the following persons in the capacities and 
on the dates indicated.

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

 /s/ MICHAEL S. SMITH        President, Chief Executive           March 29, 1999
------------------------     Officer and Chairman of the
   Michael S. Smith          Board (Principal Executive Officer)

 /s/ HOWARD L. BOIGON        Vice President - General Counsel,    March 29, 1999
------------------------     Secretary and Director
   Howard L. Boigon          


 /s/ NEIL L. STENBUCK        Vice President, Chief Financial      March 29, 1999
------------------------     Officer and Director
   Neil L. Stenbuck          


  /s/ JAMES A. TUELL         Controller, Principal Accounting     March 29, 1999
------------------------     Officer
    James A. Tuell           

/s/ DONALD H. ANDERSON       Director                             March 29, 1999
------------------------
  Donald H. Anderson

  /s/ JOHN F. GREENE         Director                             March 29, 1999
------------------------
    John F. Greene

 /s/ J. PAUL HELLSTROM       Director                             March 29, 1999
------------------------
   J. Paul Hellstrom

/s/ MICHAEL A. NICOLAIS      Director                             March 29, 1999
------------------------
  Michael A. Nicolais

 /s/ LARRY D. UNRUH          Director                             March 29, 1999
------------------------
   Larry D. Unruh


                                       51