<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, 1999.

    [ ] 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 27, 2000, the aggregate market value of the approximate
15,520,000 shares of voting stock held by non-affiliates of the registrant was
approximately $190,000,000 based upon the closing sale price of the Common Stock
on the Nasdaq Stock Market on March 27, 2000 of $12.25 per share.

     As of March 27 2000, the registrant had 18,517,000 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 2000 Annual
Meeting of Shareholders.

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<PAGE>

Forward-Looking Statements

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

     . amount and nature of capital expenditures;
     . drilling of wells;
     . estimated reserves at December 31, 1999;
     . timing and amount of future production of oil and gas;
     . business strategies;
     . operating costs and other expenses;
     . cash flow and anticipated liquidity;
     . prospect development and property acquisitions;
     . marketing of oil and gas; and
     . Year 2000 compliance activities.

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

     . general economic conditions;
     . oil and gas price volatility;
     . our ability to find, acquire, market, develop and produce new properties;
     . the risks associated with acquisitions and exploration;
     . operating hazards attendant to the oil and gas business;
     . downhole drilling and completion risks that are generally not recoverable
       from third parties or insurance;
     . uncertainties in the estimation of proved reserves and in the projection
       of future rates of production and timing of development expenditures;
     . potential mechanical failure or underperformance of significant wells;
     . the strength and financial resources of Basin's competitors;
     . Basin's ability to find and retain skilled personnel;
     . climatic conditions;
     . availability of capital;
     . availability and cost of material and equipment;
     . delays in anticipated start-up dates;
     . environmental risks;
     . actions or inactions of third-party operators of Basin's properties;
     . regulatory developments; and
     . third-party Year 2000 compliance actions.

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

                             CROSS-REFERENCE SHEET

<TABLE>
<CAPTION>
Part I                                                                Internal Page
                                                                      -------------
<S>                                                                   <C>
     Item 1.     Business                                                         1
     Item 2.     Properties                                                      14
     Item 3.     Legal Proceedings                                               18
     Item 4.     Submission of Matters to a Vote of Security Holders             18

Part II

     Item 5.     Market for the Registrant's Common Stock and                    19
                 Related Shareholder Matters
     Item 6.     Selected Financial Data                                         20
     Item 7.     Management's Discussion and Analysis of                         21
                 Financial Condition and Results of Operations
     Item 7A.    Quantitative and Qualitative Disclosures                        29
                 About Market Risk
     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 31.
<PAGE>

                                    PART I

ITEM 1.   BUSINESS.

General

Basin is an independent oil and gas company engaged in the exploration,
development and acquisition of oil and gas properties located in the shallow
waters of the Gulf of Mexico and selected areas of the onshore United States,
including the Gulf Coast and the Powder River and Green River Basins of Wyoming.
In 1996, we sold a significant portion of our developed properties in the Rocky
Mountain region in order to commence an active exploratory drilling program in
the Gulf of Mexico. Since that time, we have increased our proved reserves,
production and operating cash flow primarily through our Gulf of Mexico
operations. As of December 31, 1999, our proved reserves totaled approximately
210 Bcfe. Approximately 64% of our estimated proved reserves at December 31,
1999 are gas and 64% are located in the Gulf of Mexico.

Through December 1999, we have participated in the drilling of 52 wells in the
Gulf of Mexico, 35 of which have found apparent commercial hydrocarbons,
yielding a 67% success rate. We have owned an average working interest of 53% in
these 52 wells and have operated 38, or 73%, of them. During 1999, we
participated in drilling 21 wells in the Gulf of Mexico, including 17
exploratory wells and four development wells. Fifteen of these, or 71%, found
apparent commercial hydrocarbons, including 11 of the exploratory wells and all
four development wells. We also participated in five onshore exploratory wells
in 1999, including one discovery and one well that was testing at year-end in
the Green River Basin.

The majority of our proved reserves in the Gulf of Mexico are attributable to
Miocene-age sands, within an area known as the Miocene trend. The Miocene trend
is a prolific oil and gas producing area characterized by subtle hydrocarbon
indicators, which are more readily detectable using 3-D seismic data that has
become available since the mid-1990s. This trend is primarily located in water
depths of less than 150 feet, near existing infrastructure.

Basin's onshore activities include exploring and developing oil and gas
properties in southern Louisiana and Texas and in several areas in the Rocky
Mountain region, including the Powder River and Green River Basins of Wyoming.
Although the shallow waters of the Gulf of Mexico will remain our primary area
of exploratory focus in 2000, we believe that the longer reserve life and
exposure to more diverse opportunities offered by operations in onshore
provinces will complement our offshore efforts. During 1999, we enhanced our
onshore capabilities through the addition of experienced personnel and
acquisitions of geophysical data. Our onshore properties accounted for 11% of
our production and approximately 14% of our capital investments during 1999.

Our average daily net oil and gas production in 1999 was 89 MMcfe, representing
a 48% increase over our 1998 average daily net production of 60 MMcfe.
Approximately 84% of our total production in 1999 was natural gas. Our 1999
revenues and cash flow from operations before working capital changes increased
from 1998 levels by 47% and 57%, to approximately $72 million and $53 million,
respectively. Our average realized prices were approximately the same in 1998
and 1999 on an energy equivalent basis, net of hedging affects. For 1999, our
revenue per Mcfe of production averaged $2.20 and our cash flow from operations
per Mcfe equaled $1.62.

The increase in our production from 1998 to 1999 was largely attributable to
reserve additions from Gulf of Mexico discoveries made in 1998. We did not make
any significant acquisitions of proved properties in 1999 and wells drilled in
1999 did not account for a substantial portion of our 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. Additional properties brought on
line in 1999 increased our production base in the Gulf of Mexico from 14 at the
beginning of the year to 19 by the end of the year. We had six additional
properties with discovery wells under development for initial sustained
production as of December 31, 1999. We expect all of these are expected to
commence producing during 2000.

Our capital expenditures totaled $81.9 million in 1999, before reflecting
recoupments of $10.7 that resulted primarily from the sale of partial interests
in exploratory prospects. Our 1999 capital investments principally related to
exploratory drilling, development of discoveries made in 1999 or in the prior
year, acquisitions of seismic data and exploratory leaseholds, and property
exploitation activities. Our 1999 net capital investments of $71.2 million,
after recoupments, were funded primarily with cash flow from operations, and the
residual was funded with borrowings under a revolving line of credit with our
banks. Although our capital investments exceeded cash flow from operations in
1999, we reduced our total debt during the year as the result of realizing
approximately $67

                                       1
<PAGE>

million of net proceeds from a common stock offering completed in June 1999. Our
long-term debt at the end of 1999 totaled $34 million, compared to $80 million
at the beginning of the year.

To facilitate our continued exploration activities, we have assembled
undeveloped leasehold positions totaling 313,061 gross acres, or 193,013 net
acres, as of December 31, 1999. We have also acquired the rights to more than
1,100 lease blocks of 3-D seismic data covering portions of the Gulf of Mexico,
which we have integrated with geological interpretations by our technical
personnel to develop a multi-year inventory of 43 exploratory prospects in the
Gulf as of December 31, 1999. We are also integrating 3-D seismic data in our
prospect generation in the Rocky Mountain and onshore Gulf Coast regions.

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

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

Explore in the shallow waters of the Gulf of Mexico. Our exploration activities
are focused primarily in the shallow waters of the Gulf of Mexico. We believe
that this region has significant remaining undiscovered reserves and that the
combination of a substantial existing infrastructure of production platforms,
pipelines, and processing facilities, and the effectiveness of 3-D seismic data,
will reduce exploration risk and enhance project economics.

Capitalize on technical expertise. We have assembled teams of geoscientists and
petroleum engineers with substantial experience and expertise in generating
prospects, evaluating acquisition opportunities, and managing drilling and
production operations. We intend to use this in-house capability to identify and
pursue growth opportunities in the Gulf of Mexico and in selected areas onshore.

Apply advanced technology. We use advanced technologies, including 3-D seismic
data and computer-aided exploration, to better define exploration prospects and
development opportunites. Basin has acquired rights to more than 1,100 lease
blocks of 3-D seismic data covering portions of the Gulf of Mexico, and we are
in the process of acquiring 3-D data over several exploration prospect areas
onshore.

Balance size and risk profile of exploration targets. We generally seek to
conduct a drilling program that is balanced between exploration prospects with
significant potential relative to our existing reserve base and smaller, lower
risk prospects. This balance is intended to mitigate risk while providing
exposure to meaningful growth in reserves and production.

Generate prospects internally. Our geoscientists internally generate prospects
using our geological and geophysical databases and Landmark workstations. This
allows us to retain large working interests and operating control and either to
defray our capital investment by selling promoted interests or to increase our
prospect inventory by swapping for interests in third-party generated prospects.
We have internally generated more than 75% of our Gulf of Mexico prospects and
we are currently focusing our efforts on internal generation of both offshore
and onshore prospects.

Operate core properties. We operate properties accounting for more than 68% of
our estimated proved reserves at December 31, 1999. Operating allows us to
exercise greater control over the cost, timing and character of our exploration,
development and production activities.

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

Maintain financial flexibility. Basin seeks to maintain financial flexibility in
order to pursue exploration and development activities and take advantage of
acquisition opportunities. As of December 31, 1999, we had total debt of $34
million, leaving $56 million of our revolving line of credit undrawn. As of the
same date, our total debt per Mcfe of estimated proved reserves was $0.16. Since
we anticipate that our 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.

                                       2
<PAGE>

Marketing

Basin sells its gas and natural gas liquids from Gulf of Mexico properties under
short-term contracts of one year or less at market prices to various gas
purchasers. These sales may involve delivery of gas to onshore points under firm
or interruptible transportation agreements or sales at the wellhead. We sell oil
from our Gulf of Mexico properties under short-term contracts at market prices.
Basin enters into liquids transportation and separation agreements to deliver
its condensate onshore, and generally sells its crude oil at the wellhead.

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, Basin does not anticipate that it will have difficulty in
marketing its production in this region at prevailing spot market prices.

We sell the majority of our gas and natural gas liquids from fields in the Rocky
Mountain region 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. We generally sell oil from
our Rocky Mountain properties under term contracts that yield a premium over
local posted prices.

We believe that the loss of one or more of our current oil or natural gas spot
purchasers would not have a material adverse effect on our business because any
individual purchaser would be readily replaceable by another purchaser who would
be expected to pay approximately the same sales price.

Demand for natural gas is highly seasonal. As a result, the price received for
spot market natural gas may vary significantly between seasonal periods. To
date, Basin generally has been able to sell its available spot market natural
gas at prevailing spot market prices, and our volumes sold have not fluctuated
due to seasonality. There is no assurance, however, that we 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. We anticipate that such markets will continue to be volatile in the
foreseeable future. Oil and gas price fluctuations have a significant impact on
our business since virtually all of our operating revenues are ordinarily
derived from sales of our oil and gas production. We periodically enter into oil
and gas price hedging agreements as we deem conditions to warrant. Such
transactions affecting the three-year period ended December 31, 1999, 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 ours, which may
adversely affect our ability to compete successfully. In addition, many of
Basin'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.

Regulation

The following discussion of regulation of the oil and gas industry is
necessarily brief and is not intended to constitute a complete discussion of the
various statutes, rules, regulations or governmental orders to which operations
of Basin may be subject.

Regulation of Sales and Transportation of Liquid Hydrocarbons and Natural Gas

There are currently no federal price controls on liquid hydrocarbons (including
oil and natural gas liquids). As a result, Basin sells oil produced from its
properties at unregulated market prices.

                                       3
<PAGE>

The transportation and sale of natural gas in interstate commerce is regulated
under the Natural Gas Act ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA")
and regulations promulgated thereunder by the Federal Energy Regulatory
Commission ("FERC").  The Natural Gas Wellhead Decontrol Act of 1989 deregulated
all wellhead gas sales effective January 1, 1993.  As a result, Basin's gas
sales are not directly regulated.

After Basin's gas is produced and sold, its interstate transportation and resale
is regulated by the FERC.  The transportation and resale of natural gas
transported and resold within the state of its production is usually regulated
by the state involved.  Although federal and state regulation of the
transportation and resale of Basin's natural gas does not have a material direct
impact on Basin, such regulation does have a material impact on the market for
Basin's gas and the price Basin receives for its gas.

Commencing in the mid-1980s and continuing until the present, the FERC has
adopted regulations designed to make interstate gas markets flexible and
competitive.  These regulations now require interstate pipelines to transport
natural gas owned by others on a nondiscriminatory basis and have resulted in a
flexible and competitive national market for natural gas.  Current gas market
conditions are a result of how the FERC has chosen to exercise its authority.
The FERC retains authority to change these regulations.  Basin has no reason to
predict changes, but changes in the regulation of interstate gas transportation
and resales could have a material impact on the market for Basin's gas
production and the price Basin receives for its gas production.

The FERC has additional regulatory authority over pipelines operating on or
across the OCS under the Outer Continental Shelf Lands Act (the "OCSLA").  The
OCSLA requires all pipelines to provide open-access, non-discriminatory service.
The OCSLA allows the FERC to exempt pipeline facilities meeting a statutory
definition of "feeder lines" from the requirements of the OCSLA.  The FERC has
suggested that the nature of offshore operations and its separate regulatory
authority under the OCSLA could justify broadening the definition of "gathering"
in the OCS.  Gathering is exempt from regulation under the NGA.  Basin cannot
predict what, if any, change in the regulation of OCS facilities will occur.

If the FERC decides that it should regulate fewer OCS facilities under the NGA,
or if it is determined that the FERC's jurisdiction over crude oil and natural
gas transportation on the OCS is more limited than previously asserted, Basin
could face higher transmission costs for its OCS natural gas production and,
possibly, reduced access to OCS transmission capacity.  Upon the successful
development of its offshore exploration prospects, Basin expects to own and
operate facilities that Basin believes will be gathering lines.  If the FERC
decides to make it harder to qualify for the NGA gathering exception in the OCS,
Basin's OCS facilities could be subject to regulation as interstate pipelines
and that regulation could have a material impact on Basin.

In addition to FERC regulation of interstate pipelines under the NGA, various
state commissions also regulate the rates and services of pipelines whose
operations are purely intrastate in nature.  To the extent intrastate pipelines
elect to transport gas in interstate commerce under certain provisions of the
NGPA, those transactions are subject to limited FERC regulation under the NGPA.

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.

State and Local Regulation of Drilling and Production

State regulations govern operational matters such as permits and bonds for
drilling, reclamation and plugging, spacing and pooling of wells, and reporting
requirements.  The states in which Basin operates or plans to operate also have
a variety of statutes and regulations governing conservation matters, ranging
from establishment of maximum rates of production from oil and gas wells to the
proration of production to the market demand for oil and gas to the limitation
on ceiling prices for gas sold within the state.  Such regulation could be
applied to restrict the rate at which Basin's wells produce oil or gas below the
rate at which such wells would otherwise be produced, and the amount or timing
of Basin's revenues could thereby be adversely affected.

Also in recent years, pressure has increased in states in which Basin has been
active to increase regulation of the oil and gas industry at the local
government level. Such local regulation in general is aimed at increasing the
involvement of local governments in the permitting of oil and gas operations,
requiring additional restrictions or

                                       4
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conditions on the conduct of operations to reduce the impact on the surrounding
community and increasing financial assurance requirements. Accordingly, such
regulation has the potential to delay and increase the cost, or even in some
cases to prohibit entirely, the conduct of Basin's drilling activities.

Environmental Matters

The drilling for and production, handling, transportation and disposal of oil
and gas and by-products are subject to extensive regulation under federal, state
and local environmental laws. In most instances, the applicable regulatory
requirements relate to water and air pollution control and oilfield management
measures, site restoration, permitting requirements, or restrictions on
operations in environmentally sensitive areas such as coastal zones, wetlands
and wildlife habitat. These requirements increase Basin's cost of doing
business, delay or preclude operations, and create potential liability to
governmental agencies or third parties for environmental damage.  For example,
environmental regulation may in some circumstances impose "strict liability" for
environmental contamination, rendering an owner or operator or other person with
a connection to a property liable for environmental and natural resource damages
and cleanup cost without regard to negligence or fault on the part of such
person.  In addition, state laws often require some form of remedial action to
prevent pollution from former operations, such as closure of inactive pits and
plugging of abandoned wells, and such liability can be imposed on successor
owners.  In connection with its acquisitions, Basin generally performs
environmental assessments. To the extent environmental liabilities have been
identified in acquisitions to date, such liabilities are not material or  we
have negotiated agreements requiring the sellers of the properties to undertake
the required clean-up. Basin has assumed responsibility for some of these
matters identified. Environmental assessments have not been performed on all of
Basin's properties.

To date, expenditures for environmental control facilities and for remediation
have not been significant in relation to the results of operations of Basin.
Basin believes, however, that the trend toward stricter standards in
environmental legislation and regulations is likely to continue.  For instance,
efforts have been made in Congress in the past to amend the Resource
Conservation and Recovery Act to reclassify oil and gas exploration and
production wastes as "hazardous waste," the effect of which would be to further
regulate the handling, transportation and disposal of such waste. If such
legislation were to pass, it could have a significant adverse impact on the
operating costs of Basin, as well as the oil and gas industry in general.

The Oil Pollution Act of 1990 (the "OPA"), as amended in 1996, and regulations
thereunder impose a variety of regulations on "responsible parties" related to
the prevention of oil spills and liability for damages resulting from such
spills in United States waters.  A "responsible party" includes the owner or
operator of a facility or vessel, or the lessee or permittee of the area in
which an offshore facility is located.  The OPA assigns liability to each
responsible party for oil removal costs and a variety of public and private
damages.  While liability limits apply in some circumstances, a party cannot
take advantage of liability limits if the spill was caused by gross negligence
or willful misconduct or resulted from violation of a federal safety,
construction or operating regulation.  If the party fails to report a spill or
to cooperate fully in the cleanup, liability limits likewise do not apply.  Few
defenses exist to the liability imposed by the OPA.

The OPA also imposes ongoing requirements on a responsible party in anticipation
of an oil spill event.  Specifically, the OPA requires a designated applicant
(generally the operator) on behalf of the working interest owners to maintain
proof of at least $35,000,000 of financial responsibility for each offshore
facility (i.e., all wells, platforms and pipelines).  However, higher degrees of
financial responsibility (up to $150,000,000) are required if the estimated
worst case oil spill discharge from a covered facility on the OCS is greater
than 35,000 barrels.  Offshore facilities in state waters are held to a
financial responsibility of $10,000,000 for worst case oil spill discharges of
up to 10,000 barrels, with higher amounts required (again up to $150,000,000) as
the amounts of worst case spill discharges increase.  Financial responsibility
can be established through insurance, guarantee, indemnity, surety bond, letter
of credit, qualification as a self-insurer or a combination thereof.  The 1996
amendments to the OPA eliminated third party suits against guarantors, except
where a responsible party is bankrupt or where the claimant is a federal
governmental agency, and a guarantor's total liability is limited to the amount
of financial responsibility provided.  While the OPA could impose substantial
additional annual costs on Basin or otherwise materially adversely affect Basin,
the impact of these rules should not be any more adverse to Basin than it will
be to other similarly situated owners or operators in the Gulf of Mexico.

The OPA also imposes other requirements, such as the preparation of an oil spill
contingency plan.  Failure to comply with ongoing requirements or inadequate
cooperation during a spill event may subject a responsible party

                                       5
<PAGE>

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

The Federal Water Pollution Control Act ("FWPCA") imposes restrictions and
strict controls regarding the discharge of produced waters and other oil and gas
wastes into navigable waters. Permits must be obtained to discharge pollutants
to waters and to conduct construction activities in waters and wetlands.  The
FWPCA and similar state laws provide for civil, criminal and administrative
penalties for any unauthorized discharges of pollutants and unauthorized
discharges of reportable quantities of oil and other hazardous substances.  Many
state discharge regulations and the Federal National Pollutant Discharge
Elimination System generally limit and may otherwise prohibit the discharge of
produced water and sand, drilling fluids, drill cuttings and certain other
substances related to the oil and gas industry into coastal or offshore waters.
Although the costs to comply with recently enacted zero discharge mandates under
federal or state law may be significant, the entire industry is expected to
experience similar costs and Basin believes that these costs will not have a
material adverse impact on our results of operations or financial position.  In
1992, the Environmental Protection Agency adopted regulations requiring certain
oil and gas exploration and production facilities to obtain permits for storm
water discharges.  Costs may be associated with the treatment of wastewater or
developing and implementing storm water pollution prevention plans.

The Federal Clean Air act, which is designed to be administered and enforced by
individual state implementation plans, imposes permitting requirements and air
emission limitations that can impact oil and gas activities.

The Endangered Species Act ("ESA") seeks to ensure that activities do not
jeopardize endangered or threatened animal, fish and plant species, nor destroy
or modify the critical habitat of such species.  Under the ESA, exploration and
production operations, as well as actions by federal agencies, may not
significantly impair or jeopardize the species or its habitat.  The ESA provides
for criminal penalties for willful violations of the Act.  Other statutes
provide protection to animal and plant species and may apply to Basin's
operations, such as the Marine Mammal Protection Act, the Migratory Bird Treaty
Act, and the National Historic Preservation Act.

New initiatives regulating the disposal of oil and gas waste are also pending or
have been enacted in certain states, including states in which Basin conducts
operations, and these various initiatives could have a similar impact on Basin.
These rules establish significant permitting, record-keeping and compliance
procedures that may require the termination of production from marginal wells
for which the cost of compliance would exceed the value of remaining production
and could lead to the incurring of significant remediation costs for properties
found to have caused groundwater contamination or other environmental problems.

Federal Leases

A significant percentage of Basin's operations is conducted on public lands,
both in the Gulf of Mexico and onshore. Operations on onshore federal leases
must be conducted in accordance with permits issued by the Bureau of Land
Management and are subject to a number of other regulatory restrictions, such as
winter game restrictions and drilling limitations imposed by resource management
plans. Moreover, on certain federal leases, prior approval of drillsite
locations must be obtained from the Environmental Protection Agency.  On large-
scale projects, such as our Powder Mountain project, lessees may be required to
perform Environmental Impact Statements to assess the environmental impact of
potential development, which can delay project implementation or result in the
imposition of environmental restrictions that could have a material impact on
cost or scope.

Offshore leases in the Gulf of Mexico, beyond the limits of state ownership, are
administered by the Minerals Management Service of the United States Department
of the Interior (the "MMS").  Such leases are issued through competitive
bidding, contain relatively standardized terms and require compliance with
detailed MMS regulations and orders pursuant to the OCSLA (which are subject to
change by the MMS).  For offshore

                                       6
<PAGE>

operations, lessees must obtain prior approval for exploration plans and
development and production plans from the MMS and from adjacent states that have
authorized programs under the Federal Coastal Zone Management Act. In addition
to permits required from other agencies (such as the Coast Guard, the Army Corps
of Engineers and the Environmental Protection Agency), lessees must obtain a
permit from the MMS prior to the commencement of drilling. The MMS has
promulgated regulations requiring offshore production facilities located on the
OCS to meet stringent engineering, construction, safety and operational
specifications. The MMS also has regulations restricting the flaring or venting
of natural gas or liquid hydrocarbons. Similarly, the MMS has promulgated other
regulations governing the plugging and abandonment of wells located offshore and
the removal of all production facilities.

The United States Department of Transportation ("DOT"), through its Office of
Pipeline Safety, also imposes certain requirements on parties responsible for
transportation pipelines associated with platforms located on the OCS.  In
October 1995, the MMS indicated its intent to review all of its regulations
governing offshore regulations after the MMS and DOT completed a new Memorandum
of Understanding regarding the agencies' respective authority over offshore
operations.  While that Memorandum of Understanding was finalized in December
1996, the agency has not indicated that this regulatory review has been
completed.

The MMS has entered into a series of Memoranda of Understanding with other
federal agencies, such as the Environmental Protection Agency, Coast Guard, and
Occupational Safety and Health Administration, providing for the MMS to
undertake certain inspection and, in some cases, enforcement responsibility for
the respective regulatory mandates of these agencies.  Those agencies do,
however, retain varying degrees of jurisdiction over OCS operations to establish
and enforce regulatory requirements.

To cover the various obligations of lessees on the OCS, the MMS generally
requires that lessees post substantial bonds or other acceptable assurances that
such obligations will be met.  The cost of such bonds or other surety can be
substantial and there is no assurance that bonds or other surety can be obtained
in all cases.  Basin is currently exempt from the supplemental bonding
requirements of the MMS, but there is no assurance that such exemption will be
maintained.  In 1997, the MMS modified its regulations to, among other things,
(i) impose the duty on any lessee of an offshore lease to meet end-of-lease
obligations if the designated operator is unable to do so, (ii) establish joint
and several liability for plugging and abandonment of wells, removal of
platforms and other facilities, and clearance of well and platform locations,
among OCS lessees, assignees and assignors, thus creating residual liability in
certain parties for these obligations, (iii) increase the level of bond coverage
for drilling deep stratigraphic test wells and (iv) allow the MMS Regional
Director to require, on a case-by-case basis, posting of additional bonds or
other security in order to increase the amount of coverage for end-of-lease
obligations or certain other operations.  These requirements could substantially
increase Basin's current bonding liabilities, and could also impact Basin's
residual liabilities, both with respect to existing leases acquired from third
parties and with respect to leases that it may acquire or dispose of in the
future.

Under certain circumstances, such as significant uncorrected safety violations,
the MMS may require any operations on federal leases to be suspended or
terminated.  Any such suspension or termination could materially and adversely
affect Basin's financial condition and operations.

The MMS has now finalized new rules that change significantly the principles for
valuing crude oil for royalty payments on onshore and offshore federal leases.
The new valuation retains the concept of gross proceeds for calculating
royalties on production sold to third parties in arm's-length transactions.
However, oil sold in non-arm's-length contracts will be valued using index
pricing methods or other benchmarking procedures to determine a deemed arm's-
length price.  The rules define non-arm's-length sales to include sales to
affiliates, certain exchange transactions, sales pursuant to certain call
provisions, and other transactions.  The breadth of these definitions could
cause certain sales by Basin to be impacted and could in some cases require that
it pay royalty on a deemed value higher than that which it actually receives for
its oil. Basin does not expect the new rules to have a material impact on its
royalty payments

In a series of new regulations and rulings, the MMS has also taken an expansive
view of the lessee's duty to market natural gas on behalf of the Federal
Government as lessor.  For example, a new rule has disallowed the deductibility
of certain transportation costs from the calculation of royalty on gas sold off
federal leases, including marketer fees, cash out and other pipeline imbalance
penalties, and long-term storage fees.  The MMS has proposed changes to its
lease forms to codify what it regards as the lessee's duty to market natural gas
at no cost to the lessor and to assess royalty on sales by affiliates or other
transactions off the lease.  Although these new

                                       7
<PAGE>

regulations and rulings have been challenged judicially, the result of such
challenges is impossible to predict. If the challenges fail, the impact of these
regulations and rulings could be to increase Basin's costs of marketing
production from federal leases and in effect impose royalty obligations on
certain downstream sale transactions.

The MMS has also previously proposed gas valuation rules similar to those
described above for oil royalty valuation, i.e., rules which would value gas
sold in certain "non-arm's length" transactions in accordance with defined
indices or other benchmarks. Those proposed rules were withdrawn in 1997, and it
is not known whether the MMS intends to reissue them. The potential effect of
such rules, as with the proposed oil royalty valuation rules, is to move the
valuation point downstream for purposes of royalty calculation and thereby to
impose a royalty obligation on a deemed value higher than proceeds realized by
the lessee from sales netted back to the wellhead. Although Basin does not have
marketing affiliates and does not currently market its production in exchanges
or other transactions that appear to be the target of these regulatory
proposals, Basin cannot predict how the final form of any of these rules could
impact our royalty obligations.

Title to Properties

As is customary in the oil and natural gas industry, Basin makes only a cursory
review of title to farmout acreage and to onshore undeveloped oil and natural
gas leases upon execution of contracts for acquisition of leases.  Prior to the
commencement of drilling operations, a thorough title examination is conducted
and curative work is performed with respect to significant defects.  Basin
performs complete reviews of title to federal and state offshore lease blocks
and onshore producing properties prior to acquisition.  To the extent title
opinions or other investigations reflect material title defects, the seller of
the property, rather than Basin, is typically responsible for curing any such
title defects at its expense.  If Basin were unable to remedy or cure any title
defect of a nature such that it would not be prudent to commence drilling
operations on undeveloped properties, we could suffer a loss of our entire
investment in the property.  We have obtained title opinions on substantially
all of our producing properties and believe that we have satisfactory title to
such properties in accordance with standards generally accepted in the oil and
gas industry.  Our producing properties are mortgaged to our banks or are
subject to a negative pledge in connection with our revolving credit facility.

Abandonment Costs

Basin is responsible for costs associated with the plugging of wells, the
removal of facilities and equipment and site restoration on its oil and gas
properties, pro rata to its working interest.  As of December 31, 1999, Basin's
total estimated undiscounted future abandonment costs for properties in federal
waters in the Gulf of Mexico were approximately $15.5 million.  For onshore
properties, salvage values received for equipment are usually sufficient to
offset abandonment costs.  Estimates of abandonment costs and their timing may
change due to many factors, including actual drilling and production results,
inflation rates, and changes in environmental laws and regulations. We do not
expect to incur significant abandonment costs in 2000.  Estimated future
abandonment costs are added to net unamortized historical oil and gas property
costs for purposes of computing depreciation, depletion and amortization expense
charges.

Employees

At December 31, 1999, Basin had 75 employees, including 11 employed in field
operations and 64 employed in its Denver headquarters or Houston division
office.  None of Basin's employees are subject to a collective bargaining
agreement and Basin considers its relations with its employees to be good.

Risk Factors

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

Oil and gas prices fluctuate frequently, and low prices could have a material
adverse impact on our business.

Prices for oil and gas fluctuate widely. Gas prices affect us more than oil
prices, because most of our reserves and production are gas. At December 31,
1999, 64% of our estimated proved reserves consisted of gas on an Mcfe basis. In
1999, approximately 84% of our total production consisted of gas.

                                       8
<PAGE>

Basin's revenues, profitability and future rate of growth substantially depend
on prevailing prices for oil, gas and gas liquids. Prices also affect the amount
of cash flow available for capital expenditures and our ability to borrow money
or raise additional capital. The amount we can borrow from banks is subject to
periodic re-determination based on changing expectations of future prices, among
other factors. Lower prices may also reduce estimates of the amount of oil and
gas that we can economically produce.

We cannot predict future oil and gas prices. Prices may decline from their 1999
levels.

Among the factors that can cause this fluctuation are:

     . relatively minor changes in, and uncertainty surrounding, the supply of
       and demand for oil and gas;
     . the level of consumer demand, which can be affected by weather, economic
       conditions in the United States and other countries, and other factors;
     . impacts on supply from new technologies, equipment availability, capital
       market conditions, and other factors:
     . domestic and foreign governmental regulations;
     . the price and availability of alternative fuels;
     . political conditions in the Middle East; and
     . the price of oil and gas imports;

Hedging our production may result in losses.

We periodically enter into commodity hedging transactions, including energy
price swap agreements and other financial arrangements in an effort to mitigate
the potential impact of declines in oil and gas prices. Such arrangements
involve risks. Hedging contracts limit the benefits we would realize if actual
prices rise above the contract prices. We experienced hedging losses in 1999.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and Note 1 of Notes to the Consolidated Financial Statements for a
description of our recent hedging activity.

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

The failure to replace our reserves would adversely affect our liquidity and
operations.

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

                                       9
<PAGE>

We may be unable to make the necessary capital investments to maintain or expand
our oil and gas reserves if cash flow from operations is reduced and external
sources of capital become limited or unavailable. We cannot assure you that our
future acquisition, development and exploration activities will result in
reserves added at acceptable costs.

Properties we buy containing proved reserves may not perform as we projected,
and we may not be able to discover liabilities carried with the properties or
obtain protection from sellers against them.

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

     . the amount of recoverable reserves;
     . future oil and gas prices;
     . estimates of operating costs;
     . estimates of future development costs; and
     . potential environmental and other liabilities.

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

Substantial acquisitions could require significant external capital and could
change Basin's risk and property profile.

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

Exploration is a high-risk activity and the 3-d seismic and other advanced
technologies we use are expensive, require experienced personnel, and cannot
eliminate exploration risk.

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

Our principal focus area since 1996 has been the Gulf of Mexico. This operating
area is highly competitive and our success there will depend on our ability to
attract and retain experienced geoscientists and other professional staff. We
currently have twelve geoscientists and petroleum engineers who are experienced
in Gulf of Mexico operations. Loss of these experienced personnel could have a
material adverse impact on Basin's ability to compete in this area.

                                       10
<PAGE>

If we cannot continue to access capital from external sources, we may be unable
to expand our reserves and production.

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

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

     . traditional reserve-based borrowings or the issuance of long-term debt;
     . the sale of common stock, preferred stock or other equity securities;
     . use of nonrecourse production-based financing or sales of net profits
       interests;
     . sales of non-strategic properties;
     . sales of interests in prospects and technical information; and
     . joint ventures.

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

Outstanding debt could reduce our financial flexibility.

At December 31, 1999, our long-term debt equaled $34 million, and we had $56
million available to draw down under our revolving line of credit with our
banks. Our working capital deficit equaled $10.4 million at December 31, 1999,
leaving a net total of $45.6 million of unutilized credit capacity. Under our
revolving line of credit, our banks redetermine our borrowing base at least
semi-annually, and it is possible that any such review could result in a
reduction of our borrowing base. This could occur as a result of weak oil and
gas prices or unsuccessful exploration or development activities. The terms of
our revolving line of credit may impair our ability to obtain additional
financing in the future for working capital, capital expenditures, acquisitions
or general corporate purposes.

We wrote down the carrying value of our proved reserves at year-end 1998 to
reflect low oil and gas prices, and we could experience such write-downs in the
future.

The risk that we will be required to write down the carrying value of our oil
and gas properties increases when oil and gas prices are low. In addition,
write-downs may occur if we have substantial downward adjustments to our
estimated proved reserves. Basin uses the full cost method of accounting to
report operations for oil and gas properties. We capitalize the costs to
acquire, explore for and develop oil and gas properties. Under full cost
accounting rules, the net capitalized costs of oil and gas properties may not
exceed a ceiling limit that is based on the present value of estimated future
net cash flows from proved reserves, using constant oil and gas prices and a 10%
discount factor, plus the lower of cost or fair market value of unproved
properties. If net capitalized costs of oil and gas properties exceed the
ceiling limit, we must charge the amount of the excess to earnings. This is
called a ceiling limitation write-down. This charge does not affect cash flow
from operating activities, but it does reduce the book value of our
stockholders' equity. We review the carrying value of our properties quarterly,
based on prices in effect as of the end of each quarter or as of the time of
reporting results. We may not reverse write-downs even if prices increase in
subsequent periods. Primarily because of weak oil and gas prices, we recorded a
ceiling limitation write-down in the fourth quarter of 1998 in the amount of
$38.5 million ($30.8 million after tax). We could have another ceiling
limitation write-down in a future period if commodity prices decline
significantly.

Our ability to market our oil and gas production depends on third parties and on
fluctuating commodity prices and demand which are beyond our control.

                                       11
<PAGE>

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

Demand for gas is highly seasonal. As a result, the price and marketability of
our spot market gas may vary significantly between seasonal periods. If market
factors dramatically change, the financial impact on Basin could be substantial.
The availability of markets for our production is largely beyond our control.

A significant part of the value of our production is concentrated in a small
number of offshore properties.

During the three months ended December 31, 1999, approximately 68% of our
production was from seven properties in the Gulf of Mexico. If reservoir or
mechanical problems, storms, or other events curtail production from one or more
of our higher-rate properties, Basin's cash flow would be materially adversely
affected.

Reserve estimates are inherently uncertain and depend on many assumptions that
may turn out to be untrue.

The process of estimating oil and gas reserves is complex and inherently
uncertain. It requires various assumptions, including assumptions required by
the Securities and Exchange Commission with respect to future oil and gas
prices, operating expenses, capital expenditures, taxes and availability of
funds. We must project production rates and timing of development expenditures.
We need to analyze available geological, geophysical, production and engineering
data, and the extent, quality and reliability of this data can vary. Oil and gas
reserve engineering is a subjective process of estimating accumulations of oil
and gas that cannot be measured in an exact manner. Basin's proved reserve
information included in this report represents only estimates prepared in part
by independent petroleum engineers and in part by Basin engineers. Estimates
from other engineers might differ materially from those shown. The accuracy of
any reserve estimate is a function of the quality and quantity of available
data, engineering and geological interpretation and judgment.

Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves most likely will vary from our estimates. Any significant variance
could materially affect the estimated quantities and present value of reserves
shown in this report. In addition, we will adjust future estimates of proved
reserves to reflect additional production history, results of exploration and
development, prevailing oil and gas prices and other factors, many of which are
beyond our control.

At December 31, 1999, approximately 29% of our estimated proved reserves
quantities were undeveloped. Recovery of undeveloped reserves generally requires
significant capital expenditures. The reserve data assumes that we will make
these expenditures. Although we estimate our reserves and the costs associated
with developing them in accordance with industry standards, the estimated costs
may not be accurate, development may not occur as scheduled, and results may not
be as estimated.

You should not assume that the present value of future net cash flows referred
to in this report is the current market value of our estimated oil and gas
reserves. In accordance with Securities and Exchange Commission requirements, we
generally base the estimated discounted future net cash flows from proved
reserves on prices and costs on the date of the estimate. Actual future prices
and costs may be materially higher or lower than the prices and costs as of the
date of the estimate.

Fluctuations in our quarterly results of operations and other developments can
cause sudden changes in the market price of our common stock.

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

The oil and gas business involves many operating risks that can cause
substantial losses. Insurance may not be adequate to protect against all these
risks.

                                       12
<PAGE>

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

     . fire;
     . explosion;
     . blow-out;
     . uncontrollable flows of oil, gas, or well fluids;
     . natural disasters;
     . pipe failure;
     . casing collapse;
     . stuck tools;
     . abnormally pressured formations; and
     . environmental hazards such as oil spills, gas leaks, pipeline ruptures
       and discharges of toxic gases.

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

     . injury or loss of life;
     . severe damage to and destruction of property, natural resources and
       equipment;
     . pollution and other environmental damage;
     . clean-up responsibilities;
     . regulatory investigation and penalties; and
     . suspension of operations.

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

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

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

Oil and gas operations are subject to extensive environmental and other
governmental regulation, which can affect the cost, manner, or feasibility of
doing business.

Development, production and sale of oil and gas are subject to extensive
federal, state and local environmental and other governmental regulation. We
have made and will continue to make large expenditures to comply with
environmental and other governmental regulations. These regulations could change
in ways that might substantially increase our costs. For example, the Minerals
Management Service of the United States Department of the Interior has recently
promulgated regulations for valuation of oil and gas produced from federal
leases, including offshore leases, that could require payment of royalties on
the basis of indices that may not reflect actual prices we receive for our
production. Also, the Federal Energy Regulatory Commission has promulgated major
regulatory initiatives over the past several years that have had a significant
impact on gas pricing and gas pipeline operations, services and rates. Those
changes have significantly altered the marketing of gas, and the effect of these
changes on our ability to market our gas at reasonable prices is uncertain.

Offshore operations are subject to more extensive governmental regulation than
onshore operations. Under the Outer Continental Shelf Lands Act, the Minerals
Management Service regulates development and production of oil and gas in
federal waters in the Gulf of Mexico, and it may suspend or terminate operations
for violation of its rules. These and other environmental regulations could
impose liability for pollution clean up and damages and require cessation of
operations in affected areas. Any such costs, damages, suspension or termination
could materially and adversely affect Basin's financial condition and
operations.

                                       13
<PAGE>

We are subject to state and local regulations that impose permitting,
reclamation, land use, conservation, and other restrictions on our ability to
drill and produce.

Competition in our industry is intense and we are smaller than many of our
competitors in the Gulf of Mexico.

We compete with major and independent oil and gas companies for property
acquisitions, especially in the Gulf of Mexico. We also compete for the
equipment and labor required to operate and develop such properties. Most of our
competitors have financial and other resources substantially greater than ours.

We cannot control the pace or type of activities on properties that we do not
operate.

Some of our properties are operated by third parties. Because we are not the
operator, we do not have the ability to control the nature of operations
undertaken, such as the drilling of exploration and development wells, or the
timing of such operations. This can affect our capital expenditures, production
levels and cash flow.

Our principal stockholder is in a position to affect corporate transactions and
other matters.

Basin's principal stockholder, Michael S. Smith, together with members of his
immediate family and trustees for their benefit, beneficially own approximately
15% of Basin's outstanding shares of common stock. As a result, Mr. Smith is in
a position to substantially influence the outcome of stockholder votes on the
election of directors and other matters. In addition, if Mr. Smith were to sell
a significant number of his shares, the prevailing market price of Basin's
common stock could be adversely affected.

The loss of Michael S. Smith or other senior personnel could adversely affect
Basin.

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

Anti-takeover provisions adopted by Basin could deter change of control
transactions.

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

ITEM 2. PROPERTIES.

Prior to 1996, our 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, we sold our D-J Basin properties, which represented approximately
70% of our fixed assets at the time, and initiated operations in the Gulf of
Mexico.  Our subsequent investment activities through 1999 have been focused
predominantly on Gulf of Mexico properties. As of December 31, 1999, our
estimated proved reserves totaled approximately 12.6 million barrels of oil and
134.1 Bcf of natural gas, or 209.5 Bcfe.   The estimated pre-tax present value
of future net revenues from these proved reserves, using December 31, 1999
product prices held constant and a discount rate of 10%, totaled approximately
$269.3 million.  Gulf of Mexico properties accounted for 64% of our proved
reserve quantities at December 31, 1999 and 77% of the related pre-tax present
value of future net revenues estimated as of that date.  Weighted average prices
used for purposes of estimating proved reserves at December 31, 1999 were $24.39
per barrel of oil and $2.32 per Mcf of natural gas.

                                       14
<PAGE>

In addition to our proved properties as of December 31, 1999, we owned mineral
rights under 313,061 gross, or 193,013 net, undeveloped acres. We also have
acquired the rights to 3-D seismic data covering approximately 1,100 lease
blocks, and 2-D data covering approximately 375,000 miles, in the Gulf of
Mexico. Our undeveloped acreage in the Gulf of Mexico at the end of 1999
contained 43 exploratory prospects identified by Basin's geoscientists, based
upon their interpretations of 3-D seismic and other data.

Our Gulf of Mexico proved reserves as of December 31, 1999 were distributed
among 25 properties. Production had been established from 19 of these fields at
that date, and the other six fields were under development for first production.
Our working interests in the 25 properties ranged from approximately 8% to 100%,
with an average of 51%. Eleven of the 25 properties account for approximately
72% of our proved reserve quantities and 74% of the related pre-tax present
value of future net revenues from our Gulf of Mexico assets as of December 31,
1999. Basin operates 16 of the 25 properties.  These 16 properties account for
approximately 67% of our total proved reserves in the Gulf of Mexico. As is
generally the case for Gulf of Mexico properties, we expect our properties in
this area to exhibit a high initial production rate followed by a steep decline
in production after a relatively short period.

Most of the proved reserves value related to our onshore assets as of December
31, 1999 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 number of undeveloped locations.  Most of our producing
wells in the Rocky Mountain area have been on-line for several years and their
respective production declines are relatively moderate and well-established.

Additional information related to our 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 our properties as of December 31,
1999, and to audit our estimates of such data for Basin's remaining properties
as of that date.  The estimates prepared by Ryder Scott Company Petroleum
Engineers covered properties that accounted for 28% of our proved reserve
quantities in the Gulf of Mexico as of December 31, 1999, and audits conducted
by Ryder Scott Company covered the other properties.  Estimates prepared by
Ryder Scott Company or our engineers were based upon a review of production
histories and other geologic, economic, ownership, volumetric and engineering
data. In estimating reserve quantities that are economically recoverable, oil
and gas prices and estimated development and production costs as of December 31,
1999 were utilized.

The following table sets forth estimates as of December 31, 1999 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 our estimated proved oil and
gas reserves. For additional information concerning the present value of future
net revenue from these proved reserves, see Unaudited Supplemental Oil and Gas
Reserve Information in the Notes to the Consolidated Financial Statements.

<TABLE>
<CAPTION>
                                                                                     Proved Reserves
                                                           ---------------------------------------------------------
                                                                 Developed           Undeveloped         Total
<S>                                                        <C>                 <C>                 <C>
Oil (MBbls)..............................................             7,465              5,112              12,577
Gas (MMcf)...............................................           104,351             29,702             134,053
Total (MMcfe)............................................           149,141             60,374             209,515
Future Net Revenue Before Income Taxes
  (in thousands).........................................        $  271,351          $ 119,755           $ 391,106
Present Value of Future Net Revenue Before Income Taxes
  (in thousands).........................................        $  202,524          $  66,779           $ 269,303
</TABLE>

The following table sets forth estimates of Basin's total proved reserves at
December 31, 1999 by geographic area of operations:

<TABLE>
<CAPTION>
                                                                                     Proved Reserves
                                                           ---------------------------------------------------------
                                                                    Oil                 Gas              Total
                                                                  (MBbls)             (MMcf)            (MMcfe)
                    <S>                                    <C>                 <C>                 <C>
                    Gulf of Mexico                                 4,047              110,170            134,452
                    Onshore                                        8,530               28,883             75,063
                                                                  ------              -------            -------
                      Total                                       12,577              134,053            209,515
                                                                  ======              =======            =======
</TABLE>

                                       15
<PAGE>

There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the producer. The
reserve data set forth herein represent only estimates. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact way, and the accuracy of any reserve estimate is
a function of the quality of available data and of engineering and geological
interpretation and judgment and the existence of development plans. In addition,
results of drilling, testing and production subsequent to the date of an
estimate may justify revision of such estimates. Accordingly, reserve estimates
are often different from the quantities of oil and gas that are ultimately
recovered. Further, the estimated future net revenues from proved reserves and
the present value thereof are based upon certain assumptions, including future
geologic success, prices, production levels and costs that may not prove
correct. 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 our proved
reserves and future net revenues therefrom as of December 31, 1999 were $24.39
per Bbl for oil and $2.32 per Mcf for gas.

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 it operates, without regard to
ownership (i.e., reserves are reported on a gross operated basis, rather than on
a net interest basis).

Acreage

The following table sets forth the gross and net acres of developed and
undeveloped oil and gas leases held by Basin as of December 31, 1999.

<TABLE>
<CAPTION>
                                                                Developed Acreage/1/                Undeveloped Acreage
                                                         -------------------------------     -------------------------------
                                                              Gross              Net              Gross              Net
<S>                                                      <C>               <C>               <C>               <C>
Louisiana Offshore...................................          104,816            51,991           124,925            93,861
Texas Offshore.......................................           10,440             3,324            17,277            12,815
                                                         -------------     -------------     -------------     -------------
  Total Offshore.....................................          115,256            55,315           142,202           106,676
                                                         -------------     -------------     -------------     -------------
Utah.................................................            2,278             1,978            30,997            25,952
Wyoming..............................................           44,930            25,895           113,346            52,396
Other Onshore........................................            1,909               884            26,516             7,989
                                                         -------------     -------------     -------------     -------------
  Total Onshore......................................           49,117            28,757           170,859            86,337
                                                         -------------     -------------     -------------     -------------

       Total.........................................          164,373            84,072           313,061           193,013
                                                         =============     =============     =============     =============
</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 might be considered undeveloped for certain formations, but have
only been included as developed acreage in the presentation shown.

                                       16
<PAGE>

Production

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

<TABLE>
<CAPTION>
                                                                            Year Ended December 31,
                                                             ----------------------------------------------------
                                                                   1997               1998               1999
                                                             --------------     --------------     --------------
          <S>                                                <C>                <C>                <C>
          Production:
            Oil (MBbls).............................                    524                725                855
            Gas (MMcf)..............................                  5,509             17,616             27,400
            Total (MMcfe)...........................                  8,653             21,966             32,530
          Average Daily Production:
            Oil (Bbls)..............................                  1,435              1,988              2,344
            Gas (Mcf)...............................                 15,094             48,262             75,069
            Total (Mcfe)............................                 23,704             60,190             89,133
          Average Sales Price Per Unit/1/:
            Oil (Bbls)..............................                $ 19.07            $ 11.80            $ 18.17
            Gas (Mcf)...............................                $  2.71            $  2.07            $  2.30
            Total (Mcfe)............................                $  2.88            $  2.05            $  2.41
          Production Costs Per Mcfe.................                $  0.68            $  0.41            $  0.36
</TABLE>

/1/ excluding hedging effects

Basin owned 262 gross (177 net) producing oil wells and 71 gross (42 net)
producing gas wells as of December 31, 1999.  A well is categorized under
government 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,
                                                             ----------------------------------------------------
                                                                   1997               1998               1999
                                                             --------------     --------------     --------------
                                                                                (In thousands)
          <S>                                                <C>                <C>                <C>
          Development Costs..............................         $  17,901           $ 22,671            $32,755

          Exploration Costs..............................            27,995             58,063             40,823

          Property Acquisition Costs:
          Unproved/1/....................................            11,057             22,920             (3,200)
          Proved.........................................            48,680              3,018                831
                                                              -------------      -------------      -------------

          Total Costs Incurred...........................          $105,633           $106,672            $71,209
                                                              =============      =============      =============
</TABLE>

/1/ Excludes $1,113,000, $150,000 and $9,995,000 of costs recouped through the
    resale of partial interests in prospects to industry partners in 1997, 1998
    and 1999, respectively.

                                       17
<PAGE>

Drilling Activity

The following table sets forth the wells drilled and completed by Basin during
the periods indicated.

<TABLE>
<CAPTION>
                                                                    Year Ended December 31,
                                         ----------------------------------------------------------------------------
                                                   1997                       1998                       1999
                                         ----------------------     ----------------------     ----------------------
                                            Gross         Net          Gross         Net          Gross         Net
<S>                                        <C>           <C>          <C>           <C>          <C>           <C>
Development:
  Oil................................            5          5.0             1          1.0             -            -
  Gas................................            1          0.6             -            -             4          2.7
  Non-productive.....................            -            -             -            -             -            -
                                         ---------     --------     ---------     --------     ---------     --------
   Total.............................            6          5.6             1          1.0             4          2.7
                                         =========     ========     =========     ========     =========     ========
Exploratory:
  Oil................................            -            -             -            -             -            -
  Gas................................            5          3.2             8          4.8            11          4.7
  Non-productive.....................            3          1.5             5          2.2             9          5.0
                                         ---------     --------     ---------     --------     ---------     --------
   Total.............................            8          4.7            13          7.0            20          9.7
                                         =========     ========     =========     ========     =========     ========
</TABLE>

Present Activities

On March 15, 2000, Basin submitted apparent winning bids for ten tracts at the
Central Gulf of Mexico lease sale held by the Minerals Management Service.  Such
tracts comprised 43,526 gross and net undeveloped acres offshore Louisiana.  If
all ten tracts are awarded by the Minerals Management Service, which can choose
to reject all bids for a given lease, our aggregate cost for the related
leasehold bonuses will total approximately $5.7 million.

During 2000, through March 27, Basin's Gulf of Mexico activities have included
completion of four (1.8 net) wells that were successfully drilled in 1999,
drilling of three (1.7 net) exploratory wells, of which two (1.3 net) well were
apparent discoveries. Basin also participated in the completion of one (0.2 net)
well in Wyoming.

ITEM 3. LEGAL PROCEEDINGS.

Basin 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 our security holders during the fourth
quarter of 1999

                                       18
<PAGE>

                                    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, 1999 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 Basin'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>
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

1999
First Quarter                         $14.88        $ 8.44         $13.88
Second Quarter                        $20.63        $13.00         $20.06
Third Quarter                         $25.13        $17.88         $24.00
Fourth Quarter                        $24.25        $13.63         $17.63
</TABLE>

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

     During 1999, Basin had no sales of securities that were not registered
under the Securities Act of 1933, except the issuance of 37,045 shares of common
stock pursuant to the cashless exercise of warrants issued by us on November
30, 1994 covering a total of 122,572 shares. Warrants covering a total of 49,760
shares of Basin common stock expired on December 31, 1999. The warrants (and the
shares issued pursuant to exercise of the warrants) were issued in reliance upon
the exemption from registration under Section 4(2) of the Securities Act of
1933, as amended, relative to sales by an issuer not involving a public
offering.

                                       19
<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)                  1995             1996              1997             1998              1999
------------------------------------------------------------------------------------------------------------------------------------
<S>                                              <C>               <C>              <C>               <C>              <C>
Statements of Operations Data:
Revenue:
 Oil Sales                                          $ 19,632          $11,292          $  9,844         $  9,735          $ 13,056
 Gas Sales                                            20,013            6,890            14,557           38,885            58,440
 Gain on Sale of Assets                                    -           22,472                 -                -                 -
 Interest and Other                                      831            1,009               319               79               134
                                               -------------     ------------     -------------     ------------     -------------
                                                      40,476           41,663            24,720           48,699            71,630
                                               -------------     ------------     -------------     ------------     -------------

Costs and Expenses:
 Lease Operating Expenses                              8,196            4,776             4,600            8,276            10,747
 Production Taxes                                      3,478            1,829             1,260              770               914
 Depreciation, Depletion and Amortization             17,202            7,606            10,622           29,775            39,494
 General and Administrative, Net                       5,196            3,752             3,255            3,928             4,928
 Stock Compensation, Net                                 302               98               439              452             1,232
 Interest and Other                                    6,929            2,272               764            2,030             2,279
 Property Impairment                                  26,500                -                 -           38,500                 -
                                               -------------     ------------     -------------     ------------     -------------
                                                      67,803           20,333            20,940           83,731            59,594
                                               -------------     ------------     -------------     ------------     -------------

Income (Loss) Before Income Taxes                    (27,327)          21,330             3,780          (35,032)           12,036
Income Tax (Provision) Benefit                         7,784           (5,760)           (1,324)           6,532                 -
                                               -------------     ------------     -------------     ------------     -------------
Net Income (Loss)                                   $(19,543)         $15,570          $  2,456         $(28,500)         $ 12,036
                                               =============     ============     =============     ============     =============
Basic:
   Earnings (Loss) Per Share                        $  (1.82)         $  1.45          $   0.22         $  (2.06)         $   0.74
   Weighted Average Shares Outstanding                10,710           10,700            11,228           13,859            16,319
Diluted:
   Earnings (Loss) Per Share                        $  (1.82)         $  1.45          $   0.22         $  (2.06)         $   0.72
   Weighted Average Shares Outstanding                10,710           10,730            11,345           13,859            16,676

Balance Sheet Data (at end of period):
Working Capital (Deficit)                           $ (2,211)         $19,178          $(10,036)        $(13,224)         $(10,378)
Net Property and Equipment                           134,598           54,800           149,175          187,811           219,559
Total Assets                                         146,651           84,957           161,959          201,163           248,905
Long-term Debt                                        77,172              218            11,053           80,000            34,000
Total Stockholders' Equity                            53,287           68,751           121,365           94,219           175,163
</TABLE>

                                       20
<PAGE>

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

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

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

History and Overview

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

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

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

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

     . adding new financial, technical and business development members to our
       senior management;
     . selling our Denver-Julesberg Basin properties for $123.5 million;
     . creating a Houston-based Gulf of Mexico exploration team through hiring
       geoscientists and petroleum engineers with substantial experience
       operating in the area;
     . acquiring a substantial database of newly available regional 3-D seismic
       data and Landmark workstations for our Gulf of Mexico geoscientists to
       use in prospect generation; and
     . reducing corporate staff and general and administrative overhead.

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

We began our Gulf of Mexico activities in 1996 with no initial property base in
the region and our early investments related primarily to acquisitions of 3-D
seismic data and exploratory leasehold interests. Our first significant
discovery in the Gulf of Mexico was the Eugene Island Block 65 #1 well, which we
began drilling at the end of 1996 and completed in 1997. Our first production
from Gulf of Mexico assets occurred in August 1997, when we brought two wells
drilled on Eugene Island Block 65 on-line. We added other proved properties in
the Gulf of Mexico in 1997, 1998 and 1999 through both exploratory drilling and
acquisitions. As of December 31, 1999, we owned interests in 25 properties with
proved reserves in the Gulf of Mexico, of which six were under development for
first production.  Basin's estimated proved oil and gas reserves increased from
62.6 Bcfe as of December 31, 1995, pro forma the sale of our Denver-Julesberg
properties, to 209.5 Bcfe at the end of 1999. As further described below, our
net production has grown significantly since mid-1997, as additional Gulf of
Mexico properties have been brought on-line.

During 1997, 1998, and 1999, our capital expenditures on oil and gas activities,
net of costs recouped through the resale of partial interests in prospects to
industry partners, totaled approximately $105.6 million, $106.7 million

                                       21
<PAGE>

and $71.2 million, respectively. Over 90% of these investments related to our
operations in the Gulf of Mexico, including costs that we incurred for
exploratory leaseholds, geological and geophysical data, exploratory drilling,
completion and development activities, and acquisitions of proved properties.
Although our net capital expenditures were lower in 1999 than in 1998, we were
able to drill a greater number of wells in 1999, due to reduced costs for oil
field services and less net investment for prospect inventory accumulation. From
the beginning of 1996, when we initiated operations in the Gulf of Mexico,
through the end of 1999, Basin drilled a total of 52 wells in the Gulf, of which
35, or 67%, were successful.

We closed 1999 with a working capital deficit of approximately $10.4 million,
long-term debt of $34.0 million, and stockholders' equity of $175.2 million.

Operating Environment

Oil and gas price levels, which are volatile and beyond our control,
significantly impact our results of operations. Changes in oil and gas prices
can also affect the amount and terms of external capital resources available to
Basin. Generally, periods of low oil and gas prices are characterized by
decreased costs for oilfield services and property interests and reduced
competition for investment opportunities, partially mitigating the effects of
price level changes.

Gas prices generally respond to North American supply and demand conditions,
including the effects of weather. Oil prices reflect global supply and demand
conditions to a greater degree, including the impact on supply of decisions by
petroleum exporting countries. Despite temporary periods of interrupted growth,
oil and gas demand has generally increased over time. Short-term fluctuations in
demand, however, can significantly impact prices. During most of 1998 and the
first quarter of 1999, the markets for both oil and gas generally reflected
ample supply and price weakness due to a number of factors, including a second
consecutive unusually warm winter in North America. Since mid-March 1999, oil
and gas prices have increased, apparently in response to production cut-backs by
petroleum exporting countries, expectations of reduced domestic productive
capacity caused by declines in drilling activity, and demand growth associated
with economic expansion. There are well-developed futures markets for oil and
gas that provide indications of expected future prices for each product. These
prices are often substantially different than current prices reflected on spot
markets. Presently, these futures markets reflect expectations of relatively
strong average prices for oil and gas in 2000, compared with the past several
years. Expectations will change in response to future developments and indicated
future prices may not actually materialize.

Hedging transactions can be entered into based on prices reflected in commodity
futures markets. We periodically enter into fixed price sales agreements or
other hedging transactions. We do this to take advantage of prices that we
believe to be attractive and to reduce risks related to potential price
declines, including the risk of being unable to make capital investments at
targeted levels. Because we do not ordinarily enter into hedges that would cover
all of our anticipated production for any given time period, we remain
vulnerable to the effects of a decline in prices even when hedging positions are
established. Hedging contracts also can reduce the benefits realized by Basin
from increases in oil and gas prices. See "Risk Factors--Hedging our production
may result in losses".

Our Gulf of Mexico exploration activities are dependent on our ability to
continue to identify and obtain prospects. We generally use non-proprietary
three-dimensional seismic data, which is also available to our competitors, as a
tool in our prospect generation. This tends to increase competition for, and
cost of, available prospects. Since beginning exploration in the Gulf of Mexico,
we have successfully expanded our inventory of potential exploratory drilling
locations from zero to 43 at the end of 1999, while drilling 46 test wells. This
inventory of prospects, the majority of which are 100%-owned by Basin,
represents more than a two-year set of drilling opportunities, based on our
historical and anticipated drilling activity levels. However, we face
competition for additional prospects from many better-capitalized oil and gas
companies. There is no assurance that over the longer term we will be able to
continue to acquire interests in prospects at acceptable costs to replenish our
inventory of prospects as these are drilled. See  "Risk Factors--The failure to
replace our reserves would adversely affect our liquidity and operations." Basin
seeks to mitigate this risk by pursuing prospect ownership through a number of
avenues, including lease sales, farm-ins, exchanges, and acquisitions. We also
plan to selectively evaluate and pursue other investment opportunities,
including onshore exploration and acquisitions of properties with proved oil and
gas reserves, to complement our core exploration activities in the Gulf of
Mexico.

                                       22
<PAGE>

Results of Operations

The table of operating and financial data shown below and the discussion that
follows are provided to assist you in understanding our results of operations
for the periods presented.

<TABLE>
<CAPTION>
                                                                                       Year Ended December 31,
                                                                        --------------------------------------------------------
                                                                            1997                  1998                  1999
                                                                        ------------          ------------          ------------
<S>                                                                     <C>                   <C>                  <C>
Production:
   Oil (MBbl)                                                                    524                   725                   855
   Gas (MMcf)                                                                  5,509                17,616                27,400
   Total Gas Equivalents (MMcfe)                                               8,653                21,966                32,530

Average Realized Sales Price:
   Oil (per Bbl)                                                        $      18.80          $      13.42         $       15.26
   Gas (per Mcf)                                                        $       2.64          $       2.21         $        2.13
   Total Gas Equivalents (per Mcfe)                                     $       2.82          $       2.21         $        2.20

Revenue (in thousands):
   Oil Sales                                                            $      9,844          $      9,735         $      13,056
   Gas Sales                                                            $     14,557          $     38,885         $      58,440
   Total Oil and Gas Sales                                              $     24,401          $     48,620         $      71,496

Expenses (per Mcfe):
   Lease Operating Expense                                              $       0.53          $       0.38         $        0.33
   Production Taxes                                                     $       0.14          $       0.03         $        0.03
   Depreciation, Depletion and Amortization                             $       1.23          $       1.36         $        1.21
   General and Administrative, Net                                      $       0.38          $       0.18         $        0.15
</TABLE>

1999 Compared to 1998

Revenue.  Oil and gas sales revenue for the year ended December 31, 1999 totaled
$71.5 million, representing an increase of $22.9 million, or 47%, compared to
1998.  A 48% increase in net oil and gas production was negligibly offset by a
less than 1% decline in average realized unit prices (net of hedging effects),
based on net equivalent unit measures.  The increase in oil and gas production
was attributable primarily to initiation of production from discoveries drilled
in the Gulf of Mexico in 1998 and early 1999. During 1999, we obtained
production from 19 Gulf of Mexico properties, compared to 14 in the prior year.
Due to the additional Gulf of Mexico production, which is predominantly gas, and
lower oil production from onshore properties on which investments were deferred
during the first half of 1999 due to low oil prices, gas increased from 80% of
net equivalent units produced in 1998 to 84% of total oil and gas production in
1999.  See "Liquidity and Capital Resources" for additional discussion of our
oil and gas production.  Hedging transactions had the effect of increasing oil
and gas sales in 1998 by $3.5 million, or $0.16 per Mcfe, while decreasing oil
and gas sales in 1999 by $7.0 million, or $0.21 per Mcfe.

Lease Operating Expenses.  Due to an increased number of producing properties
and higher production levels, lease operating expenses for the year ended
December 31, 1999 increased by $2.5 million, or 30%, from the amount reported
for the prior year.  However, lease operating expenses per Mcfe produced
declined by 13%, from $0.38 in 1998 to $0.33 in 1999, due to increased
production in the current period from Gulf of Mexico wells, which typically have
significantly lower average unit operating costs than our Rocky Mountain
properties.

Production Taxes.  Production taxes for the year ended December 31, 1999 totaled
$0.9 million, representing an increase of $0.1 million, or 19%, compared to
1998.  The increase was attributable to greater revenue from our onshore
properties in 1999, principally due to higher oil prices. The increase related
to prices was partially offset by reduced tax rates on new production and
revisions to previous estimates.  Production taxes as a percentage of oil and
gas sales for the year ended December 31, 1999 were 1.3%, compared to 1.6% in
1998, due to a greater portion of sales in 1999 attributable to properties in
federal waters offshore, which are generally not subject to production taxes.

                                       23
<PAGE>

Depreciation, depletion and amortization.  Depreciation, depletion and
amortization expense for the year ended December 31, 1999 was $39.5 million,
representing an increase of $9.7 million, or 33%, compared to 1998.  The
increase was attributable to the 48% increase in production volumes in 1999, as
compared to 1998, offset by a decrease in the per-unit depletion rate. The
depletion rate of $1.19 per Mcfe produced in 1999 represented a 9% reduction
from the $1.31 per Mcfe average depletion rate during the 1998 period. The lower
rate is principally due to the effects of a property impairment charge recorded
in the fourth quarter of 1998.

General and administrative, net.  General and administrative expenses were $4.9
million in 1999, net of overhead reimbursements and amounts capitalized. This
represented an increase of $1.0 million, or 25%, as compared to 1998.  The
increase resulted primarily from incremental costs incurred to manage expanded
operations in the Gulf of Mexico. General and administrative expenses increased
at a slower rate than production, resulting in a 17% decline in general and
administrative expenses per Mcfe produced, from $0.18 in 1998 to $0.15 in 1999.

Stock compensation, net.  Stock compensation expense for the year ended December
31, 1999, net of amounts capitalized, was $1.2 million, representing an increase
of $0.8 million, or 173%, as compared to 1998. The increased expense reflects,
in part, appreciation in the price of Basin's common stock from $12.56 per share
at December 31, 1998 to $17.63 per share at December 31, 1999. Stock
compensation expense relates to annual grants to employees of restricted stock,
including shares awarded to senior management that will be earned only if
certain performance measures are achieved by Basin.  Expense is recognized based
on vesting schedules, projections of performance, and changes in the price of
our common stock during the applicable vesting period.

Interest expense.  Interest expense for the year ended December 31, 1999 totaled
$2.3 million, representing an increase of $0.3 million, or 12%, compared to
1998.  The variance was attributable to an increase in average borrowings and
higher average effective interest rates. During 1999, Basin had average
outstanding debt of $61.1 million, with an average effective interest rate of
6.7%, compared to average debt of $53.4 million and an average interest rate of
6.6% in 1998. Interest capitalized to unproved property costs in accordance with
Statement of Financial Accounting Standards No. 34 was $2.0 million in 1999, as
compared to $1.5 million in 1998.

Income tax benefit (provision).  The difference between the income tax benefit
recorded for 1998 and the amount that would be calculated by applying statutory
income tax rates to the loss before income taxes is due primarily to the
establishment of a $5.7 million deferred tax asset valuation allowance.  No net
income tax expense was recorded in 1999 due to utilization of $4.2 million of
this deferred tax asset valuation allowance.

1998 Compared to 1997

Revenue.  Oil and gas sales for 1998 increased over the prior year by 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. Our average net realized oil and gas prices declined
from $2.82 per Mcfe in 1997 to $2.21 per Mcfe in 1998. Hedging transactions had
the effect of reducing our oil and gas sales in 1997 by $0.5 million, or $0.06
per Mcfe, and increasing sales in 1998 by $3.5 million, or $0.16 per Mcfe.

We established our first production from Gulf of Mexico assets in the second
half of 1997. The 154% increase in production volumes in 1998 was attributable
to greater contributions from five offshore properties that were acquired or
brought on-line during the second half of 1997 and to the commencement of
production at nine additional offshore properties at various times during 1998.
These additions were partially offset by natural production declines.

Lease Operating Expenses.  Lease operating expenses increased in 1998 from the
prior year by $3.7 million, or 80%, but lease operating expense per Mcfe
produced declined by 28% to $0.38, from $0.53 in 1997. Basin's lease operating
expense per Mcfe generally improved on a per-unit basis as Gulf of Mexico
production increased, beginning with the third quarter of 1997. Typically, our
Gulf of Mexico properties have significantly lower unit operating costs per unit
of production than our Rocky Mountain assets. The relatively low per-unit
operating cost of our 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.

                                       24
<PAGE>

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

Depreciation, depletion and amortization.  Depreciation, depletion and
amortization expense increased by 180%, from $10.6 million in 1997 to $29.8
million in 1998. Most of this increase was attributable to a 154% increase in
production volumes. The average depletion rate (which excludes depreciation
related to non-oil and gas assets) of $1.31 per Mcfe of production in 1998
represents a 17% increase from the $1.12 per Mcfe recorded in 1997. The higher
rate is due to a reduction of estimated proved reserves attributable to lower
oil and gas prices at the end of 1998 than one year earlier, and to a cost for
proved reserves added in 1998 that was above Basin's historical average. The
increased unit cost of additions in 1998 reflects the substantial portion of our
capital expenditures in 1998 related to the Gulf of Mexico, where higher unit
costs are associated with reserves that generally have a higher value per unit
than our onshore properties, due to faster recoveries of reserves, lower
production costs, and higher average realizable gas prices.

General and administrative expenses, net.  General and administrative expenses
in 1998 increased by 21% from 1997 levels, to $3.9 million. The increase in 1998
resulted primarily from incremental costs incurred to manage expanded operations
in the Gulf of Mexico. On a per-unit basis, general and administrative expenses
generally declined during the two-year period as production volumes increased,
and averaged $0.18 per Mcfe of production in 1998 compared to $0.38 per Mcfe in
1997.

Stock compensation, net.  Stock compensation expense for the year ended December
31, 1998, net of amounts capitalized, was $0.5 million, representing an increase
of less than $0.1 million, or 3%, as compared to 1997.  Stock compensation
expense relates to annual grants to employees of restricted stock, including
shares awarded to senior management that will be earned only if certain
performance measures are achieved by Basin.  Expense is recognized based on
vesting schedules, projections of performance, and changes in the price of our
common stock during the applicable vesting period.

Interest and other expense.  Interest and other expense for 1998 totaled $2.0
million, representing an increase of $1.3 million, or 166%, compared to 1997.
The increase was attributable to greater average borrowings outstanding offset
by a slight reduction in Basin's average effective interest rate. During 1998,
Basin had average outstanding debt of $53.4 million with an average effective
interest rate of 6.6%, compared to average borrowings of $10.2 million and an
average effective interest rate of 6.7% in 1997. Substantially all of the
borrowings in both years were under our revolving line of credit. 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.

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

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

Liquidity and Capital Resources

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

                                       25
<PAGE>

Basin's gross accrual-basis capital expenditures during 1999 totaled
approximately $81.9 million. Net capital expenditures totaled approximately
$71.2 million, after reflecting $10.7 million of proceeds from asset sales,
which primarily represented recoupments from partners upon sales of partial
interests in prospects. Our principal sources of funds in 1999 were $52.8
million of net cash provided by operations before changes in working capital,
and $67.1 million of net proceeds from the sale of common stock. During 1999, we
used these funds to repay $46 million of long-term debt and to increase our net
working capital by $2.8 million, in addition to funding our net capital
investments. At the end of 1999, we had a working capital deficit of
approximately $10.4 million and long-term debt outstanding under our revolving
line of credit of $34.0 million. The borrowing base established under our
revolving line of credit is currently $90 million.

Production and cash flow.  Our cash flow from operations is generally determined
primarily by our production level and realized oil and gas prices. Since 1996,
we have made significant investments to initiate and then expand our operations
in the Gulf of Mexico. These investments have resulted in an increase in our
production from an average rate of 11.2 MMcfe per day in the second quarter of
1997, prior to commencement of Gulf of Mexico production, to an average of 89.1
MMcfe per day in 1999.

Based primarily on estimates reflected in our year-end 1999 reserve reports, we
anticipate that our net production in 2000 will be at least 10% greater than
during 1999, when production totaled 32.5 Bcfe.  The expected increase is
attributable primarily to projected production from Gulf of Mexico properties
with proved reserves at the beginning of 2000 that were either on-line for only
a portion of 1999 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 2000 will be dependent upon meeting scheduled dates for
commencement of production from wells not yet on-line at the end of 1999, and
upon achieving projected performance from major wells, including certain wells
with little or no production history.  Although management and our independent
petroleum engineering consultants believe the projections are reasonable, there
is no assurance that they will be met.  See "Risk Factors--Reserve estimates are
inherently uncertain and depend on many assumptions that may turn out to be
untrue." and "Summary--Forward-Looking Statements" for a description of certain
risks that may impact our ability to achieve projected production levels.

Marketing and hedging transactions.  Basin's production is generally sold under
month-to-month contracts at prevailing prices.  From time-to-time, however, as
we think conditions warrant, we have entered into hedging transactions or fixed
price sales contracts for a portion of our oil and gas production.  The purposes
of these transactions are to limit Basin's exposure to future oil and gas price
declines and achieve a more predictable cash flow, and to take advantage of
prices that we view as attractive. However, such contracts also limit the
benefits we would realize if prices increase.  Hedging transactions had the
effect of increasing oil and gas sales by $3.5 million, or $0.16 per Mcfe, in
1998, while decreasing oil and gas sales by $7.0 million, or $0.21 per Mcfe, in
1999.  See "Risk Factors--Hedging our production may result in losses".

Through February 4, 2000, Basin had entered into the following fixed price swap
arrangements covering the period beginning January 1, 2000 (one MMBtu
approximates one Mcf of gas):

<TABLE>
<CAPTION>
                                     Oil                        Gas
                          ------------------------  ---------------------------
                          Average Daily             Average Daily
     Time Period          Volume (Bbl)     $/Bbl    Volume (MMBtu)    $/MMBtu
     -----------          -------------  ---------  --------------  -----------
     <S>                  <C>            <C>        <C>             <C>
     1/1/00 - 12/31/00        413           25.92          3,306        2.15
     1/1/01 - 12/31/03                                    10,000        2.15
</TABLE>

As of February 4, 2000, Basin had also sold call options for 10,000 MMBtu of gas
per day for the period from January 2000 through December 2001, at an average
strike price of $2.50 per MMBtu. At December 31, 1999, the estimated fair value
of the open oil and gas price hedging contracts was an unrealized loss of
approximately $3.1 million.

Revolving line of credit.  Effective January 1, 1999, and as subsequently
amended, we entered into a credit agreement with our existing bank group that
provides for borrowings of up to $150 million.  The maximum amount that we can
draw is limited to the borrowing base that is periodically established by the
bank group. Interest rates applied to borrowings under the credit agreement are
determined by reference to the prime rate or

                                       26
<PAGE>

LIBOR, at our election. A varying spread of 0% to 0.25% is added to the prime
rate, or a spread of 0.75% to 1.5% is applied to LIBOR, based upon our facility
usage ratio. Our credit agreement contains various covenants, including
limitations on our ability to incur other debt, dispose of assets, pay
dividends, or repurchase stock. Pursuant to our credit agreement, substantially
all of our producing properties are subject to mortgages in favor of the banks
and our remaining properties are subject to a negative pledge.

Our credit agreement provides for borrowings to be revolving loans until
November 30, 2002, at which time the outstanding balance will be converted into
a four-year amortizing term loan unless the credit agreement is amended.  The
borrowing base under the credit agreement is scheduled to be re-determined at
six-month intervals until the revolving loan is converted into a term loan. Our
borrowing base is currently set at $90 million, and the next re-determination is
scheduled to occur as of June 1, 2000.  Borrowing base re-determinations
conducted by the bank group reflect a number of estimates and assumptions
including, but not limited to, future production from Basin's proved properties,
risk factors for estimates of proved reserves, future oil and gas prices, future
operating and development costs, and future interest rates.  Changes in such
estimates and assumptions can significantly impact the size of the borrowing
base established by the banks.  Because these factors will be influenced by
future events, which cannot be forecast with certitude, we cannot predict what
level of borrowing base will be established at any future determination date.

The weighted average interest rate on borrowings outstanding under the credit
agreement at December 31, 1999 was 7.1%.  Our annual interest costs will
fluctuate based upon changes in short-term interest rates and borrowings
outstanding.  Assuming debt outstanding during 2000 remained unchanged from the
amount outstanding at December 31, 1999, the annual impact on interest expense
of a ten percent change in the average interest rate would be approximately $0.2
million, before amounts capitalized.  As the interest rate is variable and is
reflective of current market conditions, the carrying value of Basin's debt
approximates its fair value.

Positive or negative changes in the borrowing base during 2000 could impact the
level of our capital expenditures during the year.  Increases, supported by
performance of our properties, drilling results, and/or higher oil and gas
prices, could improve our ability to grow.  Decreases would adversely affect our
liquidity and capital resources, potentially resulting in a reduction of planned
capital expenditures or the sale of assets or the issuance of securities.

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

Basin's gross capital expenditures in 1999 totaled approximately $81.9 million.
Our net capital expenditures in 1999 totaled approximately $71.2 million, after
reflecting $10.7 million of proceeds from asset sales. Gulf of Mexico operations
accounted for approximately 86% of our aggregate gross capital investments in
1999. These investments principally related to the ongoing development of seven
properties with productive wells drilled in earlier periods, participation in
the drilling of 21 wells, development costs related to the 15 of these wells
that were successful, and costs related to identification and acquisition of
exploratory prospects.

The remainder of our 1999 investments was associated with our onshore
activities. These included participation in five exploratory wells, development
costs related to two of these, exploitation of various Rocky Mountain
properties, investments in seismic data and leaseholds for future exploration,
and small proved property acquisitions.

Basin's initial exploration and development budget for 2000 provides for net
capital investments of approximately $85 million.  This budget primarily
provides for:

 - development of six Gulf of Mexico properties with one or more discovery wells
   yet to commence sustained production as of the end of 1999;

                                       27
<PAGE>

 - participation in approximately six to eight net (15 to 20 gross) wells in the
   Gulf of Mexico, most of which are expected to be exploratory wells;

 - participation in approximately three net (five gross) onshore exploration
   prospects;

 - development of projected year 2000 exploratory discoveries;

 - continued exploitation of our other offshore and onshore properties; and

 - acquisitions of seismic data and exploratory leaseholds, both in the Gulf of
   Mexico and onshore.

Subject to realization of our projected production volumes and average oil and
gas prices in 2000, we anticipate being able to fund the substantial majority of
our planned capital investments this year with cash flow from operations. We
plan to utilize current capacity under our revolving line of credit for the
estimated residual.

We also intend to pursue acquisitions of properties with proved and probable
reserves as an integral part of our overall business strategy. This strategy
contemplates pursuing onshore proved properties to further establish core
operating areas complementary to our Gulf of Mexico operations, and Gulf of
Mexico properties with identified upside potential. We expect that these efforts
will result in significant investment activity over time. However, we presently
have not specifically allocated any portion of our 2000 budget for acquisitions
of proved properties. If such a transaction is executed, it may require a re-
allocation of funds from other planned activities and/or external financing, in
addition to utilization of our revolving line of credit with our banks. In such
instance, our overall capital budget for the year would likely be increased,
potentially significantly.

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

Year 2000 Readiness Disclosure and Statement

The forward-looking statements contained in the following Year 2000 discussion
should be read in conjunction with our 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 Basin and the
parties with whom it does business.

Basin created an internal committee to assess its Year 2000 readiness and to
lead its remediation efforts.   At the direction of the committee, department
heads and managers assessed and remediated Basin's IT and non-IT systems and
communicated with Basin's business partners regarding the status of their
assessment and remediation efforts.  To date, Basin has not encountered any
material Year 2000 problems with its IT and non-IT systems and has suffered no
material adverse effects from this issue.

Through December 31, 1999, Basin spent less than $100,000 on its Year 2000
remediation efforts, none of which was capitalized.  This figure does not
include the cost of Year 2000-compliant software upgrades to various IT systems
that Basin installed primarily for reasons unrelated to Year 2000 concerns,
although the cost of such upgrades was not material.  Basin did not retain
consultants to advise it regarding its Year 2000 investigation and

                                       28
<PAGE>

remediation.  Basin did not specifically track its internal costs of addressing
the Year 2000 issue.  However, management does not believe these internal costs
were material.

Basin currently has no reason to believe that any Year 2000 compliance failures
occurred or will occur with its systems or those of its significant business
partners.  However, there can be no assurance that all Year 2000 problems that
could affect Basin through its business partners have been identified and
corrected.  Therefore, there can be no assurance that currently unknown Year
2000 issues will not materially impact Basin's results of operations or
adversely affect its relationships with vendors, customers and other business
partners in the year 2000.

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 direct 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 2000 Annual Meeting of Stockholders
(the "Proxy Statement") to be filed with the Securities and Exchange Commission
no later than April 30, 2000.

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).

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.

                                       30
<PAGE>

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, 1998 and 1999..    34

Consolidated Statements of Operations for the years ended
  December 31, 1997, 1998, and 1999...........................    35

Consolidated Statements of Cash Flow for the years
  ended December 31, 1997, 1998 and 1999......................    36

Consolidated Statements of Changes in Stockholders' Equity
  for the years ended December 31, 1997, 1998 and 1999........    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, 1999 and 1998, 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, 1999.
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 auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the 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, 1999 and 1998, and the
results of their operations and their cash flow for each of the three years in
the period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States.


                                                 ARTHUR ANDERSEN LLP

Denver, Colorado,
 February 4, 2000.

                                       33
<PAGE>

BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
For the Years Ended December 31, (in thousands, except share data)                             1998            1999
-------------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>             <C>
ASSETS
CURRENT ASSETS:
  Cash and Equivalents                                                                $         331   $       3,777
  Accounts Receivable                                                                        10,036          20,332
  Prepaids and Other                                                                          2,752           4,739
                                                                                         ----------      ----------
                                                                                             13,119          28,848
                                                                                         ----------      ----------
PROPERTY AND EQUIPMENT, at cost:
  Oil and Gas Properties, Under the Full Cost Method of Accounting
    Proved                                                                                  265,826         343,872
    Unproved                                                                                 34,039          26,567
  Less Accumulated Depreciation, Depletion and Amortization                                (113,462)       (152,234)
                                                                                         ----------      ----------
                                                                                            186,403         218,205
  Furniture and Equipment, Net                                                                1,408           1,354
                                                                                         ----------      ----------
                                                                                            187,811         219,559

OTHER ASSETS                                                                                    233             498
                                                                                         ----------      ----------
                                                                                      $     201,163   $     248,905
                                                                                         ==========      ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
  Accounts Payable                                                                    $      12,465   $      12,187
  Accrued Liabilities                                                                        13,620          27,039
  Current Portion of Long-Term Debt                                                             258               -
                                                                                         ----------      ----------
                                                                                             26,343          39,226

LONG-TERM DEBT, net of current portion                                                       80,000          34,000
OTHER LONG-TERM OBLIGATIONS                                                                     601             516
DEFERRED INCOME TAXES                                                                             -               -
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,
    14,151,000 and 18,460,000 Shares Issued, Respectively                                       142             185
  Additional Paid-In Capital                                                                113,136         179,430
  Retained Earnings (Accumulated Deficit)                                                   (16,488)         (4,452)
  Common Stock Held In Treasury, At Cost, 186,000 and No Shares, Respectively                (2,571)              -
                                                                                         ----------      ----------
                                                                                             94,219         175,163
                                                                                         ----------      ----------
                                                                                      $     201,163   $     248,905
                                                                                         ==========      ==========
</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)                  1997           1998          1999
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>            <C>            <C>
REVENUE:
  Oil Sales                                                                     $      9,844   $      9,735   $    13,056
  Gas Sales                                                                           14,557         38,885        58,440
  Interest and Other                                                                     319             79           134
                                                                                   ---------      ---------      --------
                                                                                      24,720         48,699        71,630
                                                                                   ---------      ---------      --------
COST AND EXPENSES:
  Lease Operating Expenses                                                             4,600          8,276        10,747
  Production Taxes                                                                     1,260            770           914
  Depreciation, Depletion and Amortization                                            10,622         29,775        39,494
  General and Administrative, Net                                                      3,255          3,928         4,928
  Stock Compensation, Net                                                                439            452         1,232
  Interest and Other                                                                     764          2,030         2,279
  Property Impairment                                                                      -         38,500             -
                                                                                   ---------      ---------      --------
                                                                                      20,940         83,731        59,594
                                                                                   ---------      ---------      --------

INCOME (LOSS) BEFORE INCOME TAXES                                                      3,780        (35,032)       12,036
INCOME TAX (PROVISION) BENEFIT                                                        (1,324)         6,532             -
                                                                                   ---------      ---------      --------
NET INCOME (LOSS)                                                               $      2,456   $    (28,500)  $    12,036
                                                                                   =========      =========      ========
BASIC:
  Earnings (Loss) Per Share                                                     $       0.22   $      (2.06)  $      0.74
  Weighted Average Shares Outstanding                                                 11,228         13,859        16,319
DILUTED:
  Earnings (Loss) Per Share                                                     $       0.22   $      (2.06)  $      0.72
  Weighted Average Shares Outstanding                                                 11,345         13,859   xx     16,676
</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)                               1997          1998          1999
--------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>          <C>           <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net Income (Loss)                                                     $    2,456   $   (28,500)  $    12,036
   Adjustments To Reconcile Net Income (Loss)
     To Net Cash Provided By Operating Activities -
     Depreciation, Depletion and Amortization                               10,622        29,775        39,494
     Deferred Income Tax Expense (Benefit)                                   1,795        (6,555)            -
     Property Impairment                                                         -        38,500             -
     Stock Compensation Expense                                                439           452         1,232
     Amortization of Debt Issuance Costs                                         -             -            68
     Other                                                                     (15)          (14)          (26)
                                                                         ---------    ----------    ----------
                                                                            15,297        33,658        52,804
  Changes In Operating Assets and Liabilities -
       Decrease (Increase) In -
               Receivables                                                  (3,188)       (1,693)       (9,291)
               Prepaids and Other                                           (1,438)          919        (1,788)
       (Decrease) Increase In -
               Accounts Payable and Accrued Liabilities                      5,799         4,969         7,172
               Income Tax Payable                                             (981)          (19)            -
                                                                         ---------    ----------    ----------
  Net Cash Provided By Operating Activities                                 15,489        37,834        48,897
                                                                         ---------    ----------    ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Capital Additions                                                        (98,245)     (107,716)      (76,162)
  Proceeds From Sale of Property and Equipment                                 195            52        10,657
                                                                         ---------    ----------    ----------
  Net Cash Used In Investing Activities                                    (98,050)     (107,664)      (65,505)
                                                                         ---------    ----------    ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Proceeds From Notes Payable and Long-Term Debt                            53,000        85,245        54,500
  Principal Payments On Notes Payable                                      (42,218)      (16,193)     (100,758)
  Debt Issuance Costs                                                            -             -          (538)
  Proceeds From Sale of Stock, Net                                          50,320           629        67,149
  Purchase of Treasury Stock                                                   (33)          (51)         (299)
                                                                         ---------    ----------    ----------
  Net Cash Provided By Financing Activities                                 61,069        69,630        20,054
                                                                         ---------    ----------    ----------
INCREASE (DECREASE) IN CASH AND EQUIVALENTS                                (21,492)         (200)        3,446
CASH AND EQUIVALENTS, Beginning of Year                                     22,023           531           331
                                                                         ---------    ----------    ----------
CASH AND EQUIVALENTS, End of Year                                       $      531   $       331   $     3,777
                                                                         =========    ==========    ==========
SUPPLEMENTAL CASH FLOW INFORMATION
       Cash Paid For Interest                                           $      637   $     1,656   $     2,523
       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, 1997, 1998 and 1999 (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, 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 Loss                                    -          -           -           -            -        (28,500)      (28,500)
                                       ---------  ---------  ----------  ----------   ----------  -------------   -----------
BALANCES, December 31, 1998               14,151        142     113,136        (186)      (2,571)       (16,488)       94,219
   Issuance of Common Stock                4,433         44      67,939           -            -              -        67,983
   Common Stock Offering Costs                 -          -        (465)          -            -              -          (465)
   Exercise of Warrants for Common
    Stock                                    123          1       1,715         (86)      (1,716)             -             -
   Purchase of Treasury Stock                  -          -           -         (30)        (669)             -          (669)
   Issuance and Vesting of
    Restricted Stock                          55          1       2,058           -            -              -         2,059
   Retirement of Treasury Stock             (302)        (3)     (4,953)        302        4,956              -             -
   Net Income                                  -          -           -           -            -         12,036        12,036
                                       ---------  ---------  ----------  ----------   ----------  -------------   -----------
BALANCES, December 31, 1999               18,460       $185    $179,430           -      $     -       $ (4,452)     $175,163
                                       =========  =========  ==========  ==========   ==========  =============   ===========
</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. Interest expense of
$1,477,000 and $1,979,000 was capitalized to unproved property costs in
accordance with SFAS 34 in the years ended December 31, 1998 and 1999,
respectively. 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 effects) 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.

Income Taxes - The Company computes income taxes in accordance with Statement of
------------
Financial Accounting

                                       38
<PAGE>

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 reductions in oil and gas revenue of  $144,000 and
$383,000, respectively, 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.  The Company recognized reductions in oil and
gas revenue of $2,488,000 and $4,478,000, respectively, under hedging agreements
in 1999.

As of February 4, 2000, 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>
        1/1/00 - 12/31/00                413               25.92            3,306              2.15
        1/1/01 - 12/31/03                                                  10,000              2.15
</TABLE>

The Company also had sold call options for 10,000 MMBtu of natural gas per day
for the period from January 2000 through December 2001 with an average strike
price of $2.50 per MMBtu.

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, 1999, utilizing the then-applicable crude oil and
natural gas price strips. While it is not the Company's intention to terminate
any of the arrangements, it is estimated that the Company would have paid
approximately $3,100,000 to terminate the then-existing arrangements on December
31, 1999. 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 SFAS 133,
"Accounting for Derivative Instruments and Hedging Activities."   SFAS 133
establishes accounting and reporting standards requiring that, unless specific
hedge accounting criteria are met, every derivative instrument, including
certain derivative instruments embedded in other contracts, be recorded on the
balance sheet as either an asset or liability measured at its fair market value
and that changes in the derivative's fair market value be recognized currently
in earnings.  SFAS 133 is effective for the Company in 2001, 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

                                       39
<PAGE>

outstanding adjusted for the incremental shares attributed to outstanding
options and warrants to purchase common stock. Options to purchase 30,000 shares
in 1997 and 50,000 shares in 1999 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,
Basin 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.  During 1997, 1998, and 1999, 48,523, 79,145 and 122,572
warrants were exercised, respectively. The remaining 49,760 warrants expired on
December 31, 1999.

Comprehensive Income - 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 OF OIL AND GAS PROPERTIES
     --------------------------------------

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.

(3)   LONG-TERM DEBT

<TABLE>
<CAPTION>
                                          For Year Ended December 31,
                                          ---------------------------
(in thousands)                              1998               1999
                                          --------           --------
<S>                                       <C>                <C>
Revolving Credit Facility                  $80,000            $34,000
Other Notes                                    258                  -
                                           --------------------------
                                            80,258             34,000
Less: Current Portion                         (258)                 -
                                           --------------------------
Long-Term Debt, Net of Current Portion     $80,000            $34,000
                                           ==========================
</TABLE>

Effective January 1, 1999, and as subsequently amended, the Company entered into
an Amended and Restated Credit Agreement (the "Credit Agreement") with its bank
group.  The Credit Agreement provides for borrowings of up to $150,000,000, with
the interest rate on borrowings to be determined by reference to the prime rate
or LIBOR, at the Company's election.  A varying spread of 0% to 0.25% is added
to the prime rate, or a spread of 0.75% to 1.5% is applied to LIBOR, based upon
the Company's facility usage ratio. The Credit Agreement provides for borrowings
to be revolving loans until November 30, 2002, 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. The borrowing
base under the Credit Agreement, established at $90,000,000 as of December 1,
1999, is scheduled to be re-determined as of June 1, 2000 and generally at six-
month intervals thereafter 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, 1999 was 7.1%.

Outstanding debt at December 31, 1999 is payable as follows (in thousands):

                         2000                $      -
                         2001                       -
                         2002                       -
                         2003                   8,500
                         2004                   8,500
                         Thereafter            17,000
                                              -------
                                              $34,000
                                              =======

                                       40
<PAGE>

(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 $183,000,  $208,000 and $241,000 with respect to the Plan for
the years ended December 31, 1997, 1998 and 1999, 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. Options granted generally vest over three to four
years, and expire after ten years. At December 31, 1999, approximately 1,896,000
shares were available for grant under the plan. Of this total, an aggregate of
1,467,000 shares of the Company's common stock are subject to prior issuances
under such plan as of December 31, 1999, including 224,000 non-vested shares of
restricted stock and performance shares and 1,243,000 outstanding stock options.

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

<TABLE>
<CAPTION>
                                                                   For the Year Ended December 31,
                                                  ------------------------------------------------------------------
                                                         1997                    1998                    1999
                                                  ------------------       ------------------     ------------------
<S>                                                 <C>                    <C>                    <C>
Balance, Beginning of Period                              649,000                 773,500                 989,000
Granted                                                   202,500                 345,000                 405,000
Exercised                                                 (78,000)               (129,500)               (121,000)
Forfeited/Canceled                                              -                       -                 (30,000)
                                                  ---------------         ---------------         ---------------
Balance, End of Period                                    773,500                 989,000               1,243,000
                                                  ===============         ===============         ===============
</TABLE>

Additional information regarding outstanding options at December 31, 1999 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>
$15.00 - $23.56      422,000          $17.18               8.4      142,000          $16.67
$12.00 - $14.50      419,000          $13.26               7.7       74,833          $13.97
$ 7.63 - $11.00      137,500          $ 9.69               4.6      121,000          $ 9.63
$ 5.13 - $ 7.00      150,500          $ 6.49               6.7      125,500          $ 6.39
$ 3.88 - $ 4.88      114,000          $ 4.22               6.1      114,000          $ 4.22
                   ---------          ------               ---      -------          ------
                   1,243,000          $12.55               7.0      577,333          $10.15
                   =========          ======               ===      =======          ======
</TABLE>

The Company granted 23,000 and 59,000 shares of restricted stock during 1997 and
1998, respectively. Related compensation expense was recognized in the amounts
of approximately $120,000, $409,000 and $466,000 for the years ended December
31, 1997, 1998 and 1999, respectively. An additional 19,000 shares of restricted
stock were granted in January 2000. Cumulatively through December 31, 1999,
79,000 shares of restricted stock had been forfeited, 64,000 shares were no
longer subject to restriction, and 64,000 shares of restricted stock remained
subject to forfeiture.

The Company granted 55,000, 50,000 and 55,000 performance shares during 1997,
1998 and 1999, 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. Expense is
recognized based on vesting schedules, projections of performance, and changes
in the price of the Company's common stock during the applicable vesting period.
Related compensation expense was recognized in the amounts of $447,000, $367,000
and $1,593,000, for the years ended December 31, 1997, 1998 and 1999,
respectively.

                                       41
<PAGE>

In October 1995, the Financial Accounting Standards Board issued SFAS 123,
"Accounting for Stock-Based Compensation." SFAS 123 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.

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-Scholes option-
pricing model with the following weighted-average assumptions and effects:

<TABLE>
<CAPTION>
                                                            For the Year Ended December 31,
                                                  --------------------------------------------------
                                                      1997               1998              1999
                                                  ------------       -------------     -------------
<S>                                                 <C>              <C>               <C>
Assumptions:
   Risk Free Interest Rate                                5.75%               5.75%             5.50%
   Expected Dividend Yield                                   0%                  0%                0%
   Expected Life in Years                                    5                   5                 5
   Expected Volatility                                      58%                 58%               60%
Weighted Average
   Fair Value Per Share                                 $ 5.66            $   8.40           $  8.05
Pro Forma Net Income
   (Loss)(in thousands)                                 $2,285            $(29,315)          $10,818
Pro Forma Diluted Earnings
   (Loss) Per Share                                     $ 0.20            $  (2.12)          $  0.65
</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 from third parties under various noncancelable lease arrangements. The
following is a schedule of future minimum lease obligations under these leases
at December 31, 1999:

Future minimum lease obligations (in thousands)

                    2000                     $  679
                    2001                        788
                    2002                        894
                    2003                        951
                    2004                        976
                    Thereafter                  106
                                             ------
                                             $4,394
                                             ======

Payments related to such lease obligations were approximately $990,000,
$1,096,000 and $591,000 for the years ended December 31, 1997, 1998 and 1999,
respectively. The Company formerly subleased office space to third parties, the
related receipts were $502,000, $506,000 and $186,000 in the years ended
December 31, 1997, 1998 and 1999.

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.

                                       42
<PAGE>

(6)  INCOME TAXES
     ------------

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

<TABLE>
<CAPTION>
                                            For the Year Ended December 31,
                                           ---------------------------------
(in thousands)                               1997        1998        1999
                                           ---------  ----------  ----------
<S>                                        <C>        <C>         <C>
Current Provision (Benefit):
 Federal                                      $ (434)    $   (58)    $     -
 State                                           (37)         81           -
                                              ------     -------     -------
                                                (471)         23           -
                                              ------     -------     -------
Deferred Provision (Benefit):
 Federal                                       1,795      (6,555)          -
 State                                             -           -           -
                                              ------     -------     -------
                                               1,795      (6,555)          -
                                              ------     -------     -------

Provision (Benefit) For Income Taxes          $1,324     $(6,532)    $     -
                                              ======     =======     =======
</TABLE>

Reconciliations of income tax provisions (benefits) 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>
                                            For the Year Ended December 31,
                                           ---------------------------------
(in thousands)                               1997        1998        1999
                                           ---------  ----------  ----------
<S>                                        <C>        <C>         <C>
Income (Loss) Before Income Taxes             $3,780    $(35,032)    $12,036
Computed Tax (Benefit) at the Applicable
 Federal Statutory Rate                       $1,285    $(11,911)    $ 4,092
State Income Tax (Benefit),
 Net of Federal Tax Effect                        39        (350)        120
Change in Deferred Tax
 Assets Valuation Allowance                        -       5,729      (4,212)
                                              ------    --------     -------
Income Tax Provision (Benefit)                $1,324    $ (6,532)    $     -
                                              ======    ========     =======
</TABLE>

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

<TABLE>
<CAPTION>
                                                For Year Ended December 31,
(in thousands)                                     1998           1999
                                                -----------    -----------
<S>                                             <C>            <C>

Deferred Tax (Assets) Liabilities:
 Oil and Gas Properties and Equipment               $(2,357)       $ 4,754
 Net Operating Loss Carryforward                     (2,505)        (5,404)
 Percentage Depletion Carryforward                     (589)          (589)
 Alternative Minimum Tax Credit Carryforward           (278)          (278)
 Valuation Allowance                                  5,729          1,517
                                                    -------        -------
Net Deferred Tax Liability                          $     -        $     -
                                                    =======        =======
</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.

                                       43
<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>
                                                 For the Year Ended December 31,

Purchaser                                           1997      1998      1999
---------                                         --------  --------  --------
<S>                                               <C>       <C>       <C>

Texaco                                                 46%        28%       (a)
Dynegy                                                 (a)        26%       34%
Eighty-Eight Oil                                       21%        (a)       (a)
H & N Gas                                              (a)        (a)       23%
</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>
                                                 For the Year Ended December 31,
                                                 -------------------------------
(in thousands, except for gas equivalent data)      1997      1998      1999
                                                  --------  --------  --------
<S>                                               <C>       <C>       <C>
Property Acquisition-
 Unproved/1/                                      $ 11,057  $ 22,920  $(3,200)
 Proved                                             48,680     3,018      831
Exploration Costs                                   27,995    58,063   40,823
Development Costs                                   17,901    22,671   32,755
                                                  --------  --------  -------

Gross Expenditures                                $105,633  $106,672  $71,209
                                                  ========  ========  =======

Depletion Per One Thousand
 Cubic Feet of Gas Equivalent                        $1.12     $1.31    $1.19
                                                  ========  ========  =======
</TABLE>

/1/ Excludes $1,113,000, $150,000 and $9,995,000 of costs recouped through the
resale of partial interests in prospects
to industry partners in 1997, 1998 and 1999, respectively.

Costs Not Being Amortized - Oil and gas property costs not being amortized at
-------------------------
December 31, 1999, consisted of $26,567,000 of leasehold and seismic costs, of
which $2,075,000, $1,607,000, $10,553,000 and $12,332,000 were incurred in 1996,
1997, 1998 and 1999, 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 Company's proved reserves and future net revenue
were: $16.34 per barrel of oil and $2.32 per Mcf of gas at December 31, 1997;
$10.31 per barrel of oil and $1.99 per Mcf of gas at December 31, 1998; and
$24.39 per barrel of oil and $2.32 per Mcf of gas at December 31, 1999.

                                       44
<PAGE>

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, 1996 and 1997 and by Ryder Scott Company Petroleum Engineers at
December 31, 1998 and 1999.  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.

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
                                                   (MBbl)            (MMcf)
                                                -----------       -----------
<S>                                             <C>               <C>
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
   Revisions                                          3,090            (9,506)
   Extensions, Discoveries and Additions              1,477            42,953
   Production                                          (855)          (27,400)
   Purchases of Reserves In-place                       198               504
                                                -----------       -----------
Balance, December 31, 1999                           12,577           134,053
                                                ===========       ===========
Proved Developed Reserves -
   December 31, 1997                                  4,863            82,571
   December 31, 1998                                  3,352           103,271
   December 31, 1999                                  7,465           104,351
</TABLE>

                                       45
<PAGE>

STANDARDIZED MEASURE

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

<TABLE>
<CAPTION>
                                                  For the Year Ended December 31,
                                                 ---------------------------------
(in thousands)                                      1997       1998        1999
                                                 ----------  ---------  ----------
<S>                                              <C>         <C>        <C>
Future Production Revenues                        $341,310   $342,618   $ 617,290
Future Production Costs                            (79,550)   (71,609)   (151,431)
Future Development Costs                           (40,829)   (54,905)    (74,753)
Future Income Taxes                                (31,723)   (17,894)    (59,383)
                                                  --------   --------   ---------
Future Net Cash Flows                              189,208    198,210     331,723
Discount Factor at 10% Per Annum                   (53,726)   (48,255)   (105,321)
                                                  --------   --------   ---------
Standardized Measure
 of Discounted Future
 Net Cash Flows/1/                                $135,482   $149,955   $ 226,402
                                                  ========   ========   =========
</TABLE>

/1/ Total future net cash flows before income taxes discounted at 10% per annum
are $160,230,000, $164,485,000 and $269,303,000 as of December 31, 1997, 1998
and 1999, 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.

A summary of changes in the standardized measure of discounted future net cash
flows is as follows:
<TABLE>
<CAPTION>
                                                  For the Year Ended December 31,
                                                 ---------------------------------
(in thousands)                                      1997       1998        1999
                                                 ----------  ---------  ----------
<S>                                              <C>         <C>        <C>
Standardized Measure of Discounted Future
 Net Cash Flows, Beginning of Year               $ 63,306     $135,482    $149,955
Changes in Sales Prices and Production Costs      (34,217)     (51,857)     80,247
Changes in Estimated Future
 Development Costs                                  6,973        3,061     (10,464)
Sales of Minerals-in-place                         (1,019)           -           -
Purchase of Minerals-in-place                      65,644        7,537       1,410
Revisions of Previous Quantity Estimates          (11,065)      (9,015)     14,798
Costs Incurred That Reduced Future
 Development Costs                                  2,253          474      14,004
Extensions, Discoveries and Improved Recovery      67,973       91,660      84,125
Sales of Oil and Gas, Net of Production
 Costs and Taxes                                  (18,541)     (39,574)    (59,835)
Accretion of Discount                               8,366       16,023      16,449
Net Change in Future Income Taxes                  (4,398)      10,218     (28,371)
Changes in Timing Of Production and Other          (9,793)     (14,054)    (35,916)
                                                 --------     --------    --------
Standardized Measure of Discounted Future
 Net Cash Flows, End of Year                     $135,482     $149,955    $226,402
                                                 ========     ========    ========
</TABLE>

                                       46
<PAGE>

UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA

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

1999
Revenue                            $13,055   $20,312  $19,466  $ 18,797   $ 71,630
Gross Profit From Operations        10,511    17,067   16,283    15,974     59,835
Net Income (Loss)                     (398)    3,447    4,417     4,570     12,036
Earnings (Loss) Per Share:
 Basic                               (0.03)     0.24     0.24      0.25       0.74
 Diluted                             (0.03)     0.23     0.23      0.24       0.72
</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.

                                       47
<PAGE>

 (a)(3) Exhibits

   Exhibit
   Number                          Description of Exhibits
   ------                          -----------------------

     2.1       Agreement and Plan of Merger between Sterling Energy Corporation,
               Basin Energy, Inc. and Basin Exploration, Inc. dated October 13,
               1994/4/
     2.2       Plan of Merger between Basin Sterling, Inc. and Basin
               Exploration, Inc. dated November 22, 1994/4/
     2.3       Plan of Merger between Basin Operating Company and Basin
               Exploration, Inc. dated December 14, 1994./5/
     3.1       Restated Certificate of Incorporation of Basin./2/
     3.2       Restated Bylaws of Basin, as amended February 23, 2000./1/
     4.1       Common Stock Certificate of Basin./2/
    10.1       Equity Incentive Plan as amended May 12, 1999./11/
    10.2       Employment Agreement dated March 31, 1992 by and between Basin
               Exploration, Inc. and Michael S. Smith./3/
    10.3       Gulf Coast Geoscientist Overriding Royalty Interest Plan as
               amended November 10, 1999./12/
    10.4       Onshore Geoscientist Overriding Royalty Interest Plan dated
               August 24, 1999./12/
    10.5       Form of Rights Agreement dated as of February 24, 1996, between
               Basin Exploration, Inc. and Corporate Stock Transfer, Inc. as
               Rights Agent./6/
    10.6       Performance Shares Plan approved February 4, 1997./8/
    10.7       Change of Control Employment Agreement dated October 13, 1995
               between Basin Exploration, Inc. and Howard L. Boigon./7/
    10.8       Amendment to Change of Control Employment Agreement dated June 2,
               1999 between Basin Exploration, Inc. and Howard L. Boigon./11/
    10.9       Change of Control Agreement dated August 28, 1997 between Basin
               Exploration, Inc. and Samuel D. Winegrad./11/
   10.10       Change of Control Agreement dated August 1, 1997 between Basin
               Exploration, Inc. and Neil L. Stenbuck./12/
   10.11       Employment Agreement dated February 1, 1999, between Basin
               Exploration, Inc. and David A. Pustka./10/
   10.12       Change of Control Agreement dated March 24, 1999 between Basin
               Exploration, Inc. and Thomas J. Corley./1/
   10.13       Employment Agreement dated January 28, 1999, between Basin
               Exploration, Inc. and Patrick A. Jackson./10/
   10.14       Change of Control Agreement dated May 12, 1999 between Basin
               Exploration, Inc. and Dalton F. Polasek./1/
   10.15       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./9/
   10.16       Amended and Restated Credit Agreement dated January 1, 1999 among
               the Company and NationsBank, N.A., U.S. Bank National Association
               and Union Bank of California, N.A./10/
   10.17       First Amendment of Amended and Restated Credit Agreement dated
               July 1, 1999 among the Company, NationsBank, N.A., U.S. Bank
               National Association and Union Bank of California, N.A./11/
   10.18       Second Amendment of Amended and Restated Credit Agreement dated
               October 15, 1999 among the Company and U.S. Bank National
               Association, Union Bank of California, Toronto Dominion (Texas),
               Inc. and Bank of America National Trust and Savings
               Association./12/
   10.19       Third Amendment of Amended and Restated Credit Agreement dated
               December 1, 1999, among Basin Exploration, Inc. and U.S. Bank
               National Association, Union Bank of California, Toronto Dominion
               (Texas), Inc. and Bank of America National Trust and Savings
               Association./12/
      21       Subsidiaries/1/
    23.1       Consent of Arthur Andersen LLP/1/
    23.2       Consent of Ryder Scott Company/1/
      27       Financial Data Schedule /1/

               /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.

                                       48
<PAGE>

               /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 Form 8-K filed on December 10, 1994,
                    and incorporated herein by reference.
               /5/  Filed as an Exhibit to Form 10-K filed on March 28, 1995,
                    and incorporated herein by reference.
               /6/  Filed as an Exhibit to Form 8-K filed on February 26, 1996,
                    and incorporated herein by reference.
               /7/  Filed as an Exhibit to Form 10-K filed on March 28, 1996,
                    and incorporated herein by reference.
               /8/  Filed as an Exhibit to Form 10-K filed on March 31, 1997,
                    and incorporated herein by reference.
               /9/  Filed as an Exhibit to Form 8-K filed on December 11, 1997,
                    and incorporated herein by reference.
               /10/ Filed as an Exhibit to Form 10-K filed on March 30, 1999,
                    and incorporated herein by reference.
               /11/ Filed as an Exhibit to Form 10-Q filed on August 16, 1999,
                    and incorporated herein by reference.
               /12/ Filed as an Exhibit to Form 10-Q filed on November 15, 1999
                    and incorporated herein by reference.

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

   (b)              Reports on Form 8-K
                    None

                                       49
<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 27, 2000                          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.

<TABLE>
<CAPTION>
Signature                                                                 Title                               Date
---------                                                                 -----                               ----
<S>                                                            <C>                                       <C>
/s/ MICHAEL S. SMITH                                           President, Chief Executive                March 27, 2000
-----------------------------------------
Michael S. Smith                                               Officer and Chairman of the
                                                               Board (Principal Executive Officer)

/s/ HOWARD L. BOIGON                                           Vice President - General Counsel,         March 27, 2000
-----------------------------------------
Howard L. Boigon                                               Secretary and Director

/s/ NEIL L. STENBUCK                                           Vice President, Chief Financial           March 27, 2000
-----------------------------------------
Neil L. Stenbuck                                               Officer and Director

/s/ JAMES A. TUELL                                             Controller, Chief Accounting              March 27, 2000
-----------------------------------------
James A. Tuell                                                 Officer

_________________________________________                      Director                                  March 27, 2000
Donald H. Anderson

/s/ JOHN F. GREENE                                             Director                                  March 27, 2000
-----------------------------------------
John F. Greene

_________________________________________                      Director                                  March 27, 2000
J. Paul Hellstrom

/s/ MICHAEL A. NICOLAIS                                        Director                                  March 27, 2000
-----------------------------------------
Michael A. Nicolais

/s/ LARRY D. UNRUH
-----------------------------------------                      Director                                  March 27, 2000
Larry D. Unruh
</TABLE>

                                       50