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                 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, 1996.

[ ]  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.  [X]

  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 7, 1997, the aggregate market value of the approximate
7,550,000 shares of voting stock held by non-affiliates of the
registrant was approximately $51,900,000 based upon the closing sale
price of the Common Stock on the Nasdaq Stock Market on March 7, 1997
of $6.88 per share.

   As of March 7, 1997, the registrant had 10,779,000 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 1997 Annual Meeting of Shareholders.

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<PAGE>
                         CROSS-REFERENCE SHEET



PART I                                                 INTERNAL PAGE
                                                       -------------

     Item 1.        Business                                      1

     Item 2.        Properties                                   10

     Item 3.        Legal Proceedings                            15

     Item 4.        Submission of Matters to a                   15
                    Vote of Security Holders


PART II

     Item 5.        Market for the Registrant's                  16
                    Common Stock and Related
                    Shareholder Matters

     Item 6.        Selected Financial Data                      17

     Item 7.        Management's Discussion and                  18
                    Analysis of Financial Condition
                    and Results of Operations

     Item 8.        Financial Statements and Supplementary Data  23

     Item 9.        Changes and Disagreements with Accountants   23
                    on Accounting and Financial Disclosure

PART III

     Item 10.       Directors and Executive Officers             23
                    of the Registrant

     Item 11.       Executive Compensation                       23

     Item 12.       Security Ownership of Certain                23
                    Beneficial Owners and Management

     Item 13.       Certain Relationships and Related            23
                    Transactions

     Item 14.       Exhibits, Financial Statement Schedules      26
                    and Reports on Form 8-K


  For Certain Definitions of terms used herein, see internal page 24.
                                PART I


ITEM 1.  BUSINESS.

HISTORY AND OVERVIEW

     Basin Exploration, Inc. ("Basin" or the "Company") is a Denver-
based independent oil and gas company engaged in exploration,
acquisition, development, and production operations in the United
States, including the Gulf of Mexico.

     The Company was formed in 1981 to participate in an emerging
exploitation play in the Denver-Julesburg ("D-J") Basin, primarily
through management of small drilling programs.  Growth accelerated in
1988 when the Company initiated a series of acquisitions of D-J Basin
properties, followed by subsequent exploitation and development.
After an initial public offering of common stock in May 1992, the
Company embarked on an aggressive development program for its D-J
Basin assets, and also expanded its activities to include acquisition
and development of proved properties and exploration for new reserves
in other areas within the Rocky Mountain region.

     From 1988 through 1994, the Company completed acquisitions for a
total cost of $84 million and incurred related development costs
totaling $99 million.  As a result of these activities, Basin
increased its estimated proved reserves 12-fold, from 20 Bcfe at
October 31, 1989 to 247 Bcfe at December 31, 1994.  Due, in part, to
capital constraints, low gas prices in the Rocky Mountain region, and
a reduced inventory of economically viable exploitation projects,
total capital expenditures related to oil and gas properties declined
from $67 million in 1994 to $16 million in 1995.  This reduced level
of investment, plus the effects of lower gas prices and dispositions
of low-margin properties, resulted in a decline in proved reserves at
December 31, 1995 to 207 Bcfe.

     In late 1995, the Company responded to the reduction in its
inventory of exploitation projects, and to its assessment of the
relative attractiveness of alternative investment opportunities, by
determining to implement a strategic redirection incorporating the
following plans: (1) to improve its liquidity by monetizing assets;
(2) to focus its exploration efforts in the Gulf of Mexico rather than
in the Rocky Mountains; (3) to aggressively pursue acquisition
opportunities over a broader geographic area and in coordination with
the Company's exploration activities; and (4) to hire personnel for
management and technical positions who have had direct experience and
favorable track records conducting these planned operations.  Actions
subsequently taken, and certain related consequences, include the
following:

      -   In two transactions closed in March 1996 and June 1996,
          respectively, the Company sold all of its assets in the D-J
          Basin for $123.5 million.  These assets represented
          approximately two-thirds of the Company's wells and 70% of
          its proved oil and gas reserves at December 31, 1995.  These
          transactions enabled the Company to eliminate all of its
          long-term debt utilizing a portion of the sales proceeds and
          created significant liquidity and financial flexibility for
          pursuit of new capital projects.  However, as the Company
          disposed of a substantial portion of its operating assets,
          it has initially experienced significant reductions in oil
          and gas reserves, production and cash flow.  Pro forma the
          disposition of its D-J Basin assets as of December 31, 1995,
          the Company's proved oil and gas reserves at that date
          totaled approximately 63 bcfe.

      -   During the fourth quarter of 1995, the Company discontinued
          Rocky Mountain prospect generation and established an office
          in Houston, Texas to focus initially on exploration in the
          shallow waters of the Gulf of Mexico offshore Louisiana and
          Texas.  The Houston office currently has a staff of nine,
          including senior geoscientists and petroleum engineers, each
          of whom has extensive experience operating in this area.
          The Company is aggressively utilizing advanced technologies
          in its exploration effort, such as three-dimensional ("3-D")
          geophysics and computer-aided exploration ("CAEX"), and has
          acquired state-of-the-art workstations and access to large
          3-D seismic data bases.  In its first year of operations,
          the Company made significant progress in building its 3-D
          seismic data base and its inventory of prospect leaseholds,
          and also drilled four exploratory wells, two of which were
          successful.  The Company's initial Gulf Coast production is
          expected to occur during 1997.

      -   The Company added senior level acquisitions personnel in
          late 1995 and early 1996 to strengthen its ability to
          evaluate and pursue proved oil and gas properties with
          enhancement potential.  During September 1996, the Company
          acquired a 25% interest in the Jepson-Holler Draw secondary
          oil recovery unit in Wyoming, in exchange for $1 million and
          the Company's interests in 18 producing wells.  The Company
          invested an additional $2.9 million on the development of
          this property in 1996.  In February 1997, the Company
          acquired interests in three lease blocks in the Gulf of
          Mexico with proved, nonproducing reserves for $14.4 million.
          See "Present Activities."

                                   1

      -   In conjunction with these changes in strategy and
          operations, five of six vice presidents with the Company at
          the beginning of 1995 left the Company and five individuals
          joined Basin as vice presidents during the period from
          August 1995 through March 1996.  These new vice presidents
          include executive officers who assumed leadership roles in
          the areas of exploration, acquisitions, project development,
          and finance.

     These developments have resulted in the Company being
considerably smaller, as measured by assets, revenues, or employees,
than at the beginning of 1996, but with substantially enhanced
liquidity and capability to pursue new capital projects.  The
Company's divestment of its D-J Basin assets and its commitment to
Gulf of Mexico exploration have also significantly changed the
character and risk profile of its oil and gas capital expenditure
activities.   See "Management's Discussion and Analysis of Financial
Condition and Results Of Operations."

     The Company's proved oil and gas reserves at December 31, 1996
totaled approximately 77 Bcfe and were located primarily in the Powder
and Green River basins in Wyoming and in the shallow waters of the
Gulf of Mexico offshore Louisiana.

BUSINESS STRATEGY

     Basin's business objective is to increase shareholder value
through profitable expansion, development, and production of oil and
gas reserves.  To achieve its objective, the Company intends to:

     .    retain experienced technical staff with successful track
          records;

     .    pursue a diversified mix of exploration and acquisition
          activities;

     .    utilize state-of-the-art technologies, such as CAEX and 3-D
          seismic;

     .    focus operations geographically to leverage regional
          knowledge and develop competitive advantages;

     .    frequently rationalize assets to achieve efficiencies and
          improve operating margins; and

     .    maintain strong financial condition.

EXPLORATION

     Exploration activities have been increasing since 1994 and are
expected to be integral to the Company's future growth.  Prior to
1996, exploration activities were conducted exclusively in the Rocky
Mountain region.  However, in 1996 the Company began to focus its
exploration activities in the shallow waters of the Gulf of Mexico,
off the coasts of Louisiana and Texas.  This change in strategy
reflects a number of considerations, including the following:

      -   The Gulf of Mexico is a prolific oil and gas province and
          the Company believes that significant potential remains for
          discovery of new reserves.

      -   State-of-the-art technologies, such as CAEX and 3-D seismic,
          have been more successfully employed in the Gulf of Mexico
          than in most other regions of the U.S. to improve drilling
          success rates and enhance economic returns.

      -   The extensive amount of seismic and other geologic data
          covering the area is readily available at reasonable cost.

      -   Open access to government-owned mineral rights reduces
          barriers to entry.

      -   This area has a well-developed infrastructure, including oil
          and gas transportation systems and service providers,
          facilitating cost-effective operations and favorable product
          prices.

      -   Typically, operations in this area are characterized by a
          favorable ratio of low-risk development capital to high-risk
          test capital.

     This operating area is highly competitive and the Company
believes that a key to its success will be attraction and retention of
geoscientists and other professional staff with extensive experience
operating in the area.  Accordingly, the Company opened a regional
office in Houston, Texas in December 1995.  This office currently has
a staff of nine, including senior geoscientists and petroleum
engineers, all of whom are experienced in Gulf Coast operations.   In
addition, certain
                                   2

members of the Company's senior management based in Denver have had
considerable experience in providing support for operations in the
Gulf Coast area, both onshore and offshore.

     The Company generates prospect leads through utilization of
regional 2-D and 3-D seismic data bases, integrating regional geology.
The Company bids for leaseholds at federal and state Gulf of Mexico
lease sales and also pursues joint venture and farm-in opportunities
for blocks under existing lease.  Generally, the Company intends to
target prospects with at least 20 Bcfe of estimated reserves
potential, in water depths of less than 300 feet.  Basin will seek to
operate whenever possible, in order to maintain maximum control of
capital and operating costs, and of timing of prospect development.
The Company will typically seek to retain between one-quarter and two-
thirds of each prospect.  The Company also intends to pursue
acquisitions of producing properties in the region where there is
identified exploration or development potential.  Such acquisitions,
with production facilities and equipment already in place, can create
the opportunity for economic development of reserve accumulations that
might otherwise be too small.

     In its first year of Gulf Coast operations, the Company
participated in drilling four exploratory wells, two of which were
successful.  The Company also accumulated an inventory of prospect
acreage.  At December 31, 1996, the Company held leaseholds relating
to 33,340 gross (28,128 net) undeveloped acres in the Gulf of Mexico,
mostly offshore Louisiana.  See "Properties" for additional
information regarding offshore acreage holdings, including "Present
Activities" for information relating to events in 1997.

     Since nine or more months are typically required for platform
fabrication and installation for a new discovery (unless such
infrastructure is already in place), the Company is not anticipating
any significant 1997 contributions of production or cash flow
resulting from current year Gulf Coast exploration.  The company does
expect production during part of 1997 from three of its Gulf of Mexico
properties that are presently attributed proved reserves. See
"Management's Discussion and Analysis of Financial Condition and
Results Of Operations - Liquidity and Capital Resources."

ACQUISITIONS

     Prior to 1996, the Company's growth was achieved primarily
through acquisition of properties with proved and probable reserves,
and subsequent exploitation and development.  The Company initially
executed a series of acquisitions in the D-J Basin, ultimately
creating a substantial base of operations that facilitated development
of in-depth knowledge of the area, including its geologic and
reservoir characteristics, and also enabled the achievement of certain
operating and administrative efficiencies.  Later, the Company
executed two acquisitions of Powder River Basin properties in Wyoming
to establish another base of operations where similar operating
advantages could be achieved.

     In 1996, Basin added senior level acquisitions personnel to
enhance the Company's ability to source, evaluate and capture
acquisition opportunities in a broader geographic area.  The Company
intends to opportunistically pursue property acquisitions with upside
potential in its current operating areas and potentially in other
major producing domestic basins.  Basin intends to utilize advanced
technologies, including 2-D and 3-D seismic data and CAEX where
applicable, to identify properties with upside potential that might be
acquired.  The Company's petroleum engineers will work in conjunction
with the Company's in-house geoscientists or outside consultants,
depending on the area, to effectively integrate such data in
evaluations.  As part of its integrated exploration and acquisition
strategies, Basin will particularly seek to make acquisitions of
producing properties in the Gulf Coast area where exploration
potential has been identified.  Once properties are discovered or
acquired in an area, it is likely that the Company will attempt to
acquire additional properties in the region to achieve operating
advantages.

     The Company will generally focus on acquisition opportunities
where it believes it can enhance the value of properties through one
or more of the following means:

     .    Exploratory drilling

     .    Development drilling

     .    Recompletions

     .    Reservoir stimulation

     .    Secondary or tertiary recovery operations

     .    Cost reductions

                                   3

     The Company's two most recent acquisitions are indicative of such
properties with assessed upside potential.  An interest in the Jepson-
Holler Draw Unit in Wyoming was acquired in September 1996.  This
property was recently unitized for purposes of initiating secondary
recovery operations through waterflooding, and water injection
commenced in January 1997.  In February 1997, the Company acquired
interests in three Gulf of Mexico lease blocks with recently drilled
wells awaiting further development.  In addition to completion and
tie-in of the three wells that have been drilled, the Company believes
these properties hold potential upside that may be realizable through
development drilling and further exploration.  See "Properties."

     Because of intense competition for proved property acquisitions
and other factors, it is impossible to project the timing or dollar
amount of acquisition activity.

MARKETING

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

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

     Demand for natural gas is highly seasonal, with demand generally
higher in the colder winter months and in hot summer months.  As a
result, the price received for spot market natural gas may vary
significantly between seasonal periods.  To date, the Company
generally has been able to sell its available spot market natural gas
at prevailing spot market prices, such that volumes sold have not
materially fluctuated seasonally.  There is no assurance, however,
that the Company will be able to continue to achieve this result.

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

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

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

     Basin periodically enters into oil and gas price hedging
agreements as conditions are deemed to warrant.  Such transactions
affecting the three year period ended December 31, 1996, 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

                                   4

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

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.

     Price Controls on Liquid Hydrocarbons.

     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.

     Federal Regulation of Sales and Transportation of Natural Gas.

     Historically, the transportation and sale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas
Act ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA") and
regulations promulgated thereunder. The Natural Gas Wellhead Decontrol
Act of 1989 eliminated all regulation of wellhead gas sales effective
January 1, 1993.  As a result, Basin's gas sales are no longer
regulated.

     The transportation and resale in interstate commerce of natural
gas produced and sold by Basin continues to be subject to regulation
by the Federal Energy Regulatory Commission ("FERC") under the NGA.
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 natural gas produced by Basin currently does not have
any material direct impact on Basin, such regulation does have a
material impact on the market for Basin's natural gas production and
the price Basin receives for its natural gas production. Adverse
changes in the regulation affecting Basin's gas markets could have a
material impact on Basin.

     Commencing in the mid-1980s and continuing until the present, the
FERC promulgated several orders designed to correct market distortions
and to make gas markets more flexible and competitive. These orders
have had a profound influence on natural gas markets in the United
States and have, among other things, increased the importance of
interstate gas transportation and encouraged development of a large
spot market for gas.

     On April 8, 1992, the FERC issued Order No. 636 requiring
material restructuring of the sales and transportation services
provided by interstate pipeline companies. The primary element of
Order No. 636 was the mandatory unbundling of interstate gas
transportation from gas sales by the pipelines.  All interstate
pipelines were required to offer transportation services and storage
separately from their gas sales on a nondiscriminatory basis.  Most
pipelines have moved all or almost all of their business of buying and
selling gas to  affiliated marketing companies.

     The transition to unbundled open access transportation occurred
without major apparent market disruption.  The current gas market is
characterized by a large number of gas buyers and sellers and there
appears to have developed a substantial increase in the flexibility of
the natural gas industry and its capacity to respond to changing needs
and conditions.

     Although Order No. 636 does not regulate gas producers such as
Basin, Order No. 636 appears to have achieved the FERC's stated goal
of fostering increased competition within all phases of the natural
gas industry. It is unclear what impact, if any, that increased
competition will have on Basin as a gas producer and seller.

     The Outer Continental Shelf Lands Act (the "OCSLA") requires that
all pipelines operating on or across the Outer Continental Shelf (the
"OCS") provide open-access, non-discriminatory service.  Pursuant to a
February 1996 Policy Statement by the  FERC in Docket No. RM96-5-000,
only certain "feeder lines" as defined in Section 5(f)(2) of the OCSLA
are exempt from the FERC's authority to impose these competitive
requirements.  In addition, under Section 1 of the NGA, the FERC has
regulatory jurisdiction over the transportation and sale of natural
gas in interstate commerce, but it does not

                                   5

 have authority over the "production or gathering" of natural gas.

     In a February 1996 decision in Docket No. RM96-5-000, the FERC
issued a re-evaluation of its test for establishing whether a pipeline
is or is not engaged in the "gathering" of natural gas.  The FERC
decided to retain the "primary function test" as articulated in its
decision in Amerada Hess, 52 FERC 61,268 (1990), with one
            ------------
modification, which is that, in applying the "primary function test"
to offshore facilities, the FERC will presume that facilities located
in deep water are primarily engaged in gathering or production in
recognition of the technology and topography particular to operations
in deep  waters.  Although the Company expects to own and operate
gathering lines upon the successful development of its offshore
exploration prospects, it is unknown what impact this decision will
have on Company operations on the OCS or the Company's production from
the OCS, as implementation of the "primary function test" is generally
made on a case-by-case basis.  If the FERC were to redefine its
jurisdiction over gathering lines more expansively, there could be a
reduction in available pipeline space for existing shippers in the
Gulf of Mexico that own and operate gathering lines.  On the other
hand, if the FERC were to determine that it was no longer necessary to
regulate the rates and service of OCS transmission facilities under
the NGA, the Company could experience an increase in transmission
costs associated with its OCS natural gas production and, possibly,
reduced access to OCS transmission capacity.

     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.  In 1991, the State of
Oklahoma enacted legislation restricting the output of certain high-
volume gas wells in response to prevailing low gas prices and the
States of Texas and Louisiana have considered similar regulatory
initiatives. Any limitation substantially similar to that enacted by
Oklahoma would not have a material impact on Basin's current level of
production, whether for oil or gas, since Basin's wells do not produce
at a level high enough to meet the threshold for restriction contained
in the legislation. However, if similar legislation with lower
thresholds were to be enacted in the states in which Basin operates,
or if Basin acquires or develops properties in state waters in the
Gulf of Mexico or onshore in states such as Texas or Oklahoma having
higher levels of production than the historic levels of Basin's Rocky
Mountain properties, Basin's ability to market its production could be
affected.

     Also in recent years, pressure has increased in states in which
the Company has been active (especially Colorado) to mandate
compensation to surface owners for the effects of oil and gas
operations and 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
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
the Company's drilling activities.

     Environmental Matters.

     The production, handling, transportation and disposal of oil and
gas and by-products are subject to regulation under federal, state and
local environmental laws. In most instances, the applicable regulatory
requirements relate to water and air pollution control and solid waste
management measures or to restrictions on operations in
environmentally sensitive areas such as wetlands or wilderness.  In
connection with its acquisitions, Basin performs environmental
assessments. To the extent environmental liabilities have been
identified, such liabilities are not material or the Company has
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 it is reasonably likely that the trend in
environmental legislation and

                                   6

regulations will continue toward stricter standards. For instance,
efforts have been made in Congress to amend the Resource Conservation
and Recovery Act to reclassify oil and gas 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 responsible party to maintain proof of $35,000,000 of financial
responsibility for traditional offshore facilities.  The President,
however, may establish a higher degree of financial responsibility
($150,000,000) based on risk.  Offshore facilities in state waters are
held to a financial responsibility of $10,000,000 but facilities
transporting, storing or otherwise handling up to 1,000 barrels of oil
at any one time are exempt from these financial responsibilities.
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 the Company or otherwise
materially adversely affect the Company, the impact of these rules
should not be any more adverse to the Company 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 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.

     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. The Colorado Oil and Gas
Conservation Commission, for example, has enacted rules regarding the
disposal of oilfield waste, the closure and remediation of production
pits and reclamation procedures.  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 the Company's operations is conducted
on public lands, both in the Rocky Mountain region and in the Gulf of
Mexico.  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. Moreover, on certain federal leases, prior
approval of drillsite locations must be obtained from the
Environmental Protection Agency.

     Offshore leases in the Gulf of Mexico, beyond the limits of state
ownership, are administered by the United States Department of the
Interior Minerals Management Service (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 operations, lessees must obtain MMS approval for

                                   7

exploration plans and development and production plans prior to the
commencement of such operations.  In addition to permits required from
other agencies (such as the Coast Guard, the Army Corps of Engineers
and the Environmental Protection Agency), 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 and construction
specifications.  The MMS also has regulations restricting the flaring
or venting of natural gas. 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 pipeline 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.  To date, the pertinent
regulations have not been implemented as the contemplated Memorandum
of Understanding has just been finalized.

     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.  In
December 1995, the MMS proposed changes to its bonding requirements
that, if implemented as proposed, would (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)
establish some form of assurance that holders of OCS leases establish
a means of funding their end-of-lease obligations by allowing the MMS
Regional Director to require additional security of lessees and (iv)
increase the level of bond coverage for certain exploration activities
drilling deep stratigraphic test wells and 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
under an existing bond.  If implemented, these requirements could
increase the Company's current bonding liabilities in a substantial
way, and would also impact certain residual liabilities that the
Company may have, both with respect to existing leases acquired from
third parties and with respect to leases that it may dispose of in the
future.

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

     On January 24, 1997, the MMS published a notice of proposed
rulemaking which, if adopted, would significantly change the current
rules governing the value of crude oil for royalty payments on federal
leases.  The new valuation rule would retain the concept of gross
proceeds for calculating royalties on production sold to third parties
in arm's-length transactions, but only in certain narrow
circumstances.  As proposed, the majority of oil sold under arm's-
length contracts as well as non-arm's-length contracts would be valued
using an index pricing method as adjusted for location, quality, and
transportation rather than the contract price.  If adopted as
proposed, the MMS' rule would have a substantial impact on the
Company's royalty payments to the federal government and could in many
cases require that it pay royalty on a value (index price) higher than
that which it actually receives (contract price) for its oil.  As of
this date, the MMS has not finalized or adopted the proposed rule, and
its impact, if any, on the Company is therefore uncertain.

TITLE TO PROPERTIES

     As is customary in the oil and natural gas industry, the Company
makes only a cursory review of title to farmout acreage and to onshore
undeveloped oil and natural gas leases upon execution of the
contracts.  Prior to the commencement of drilling operations, a
thorough title examination is conducted and curative work is performed
with respect to significant defects.  The Company performs complete
reviews of title to federal and state offshore lease blocks prior to
acquisition.  To the extent title opinions or other investigations
reflect material title defects, the seller of the property, rather
than the Company, is typically responsible for curing any such title
defects at its expense.  If the Company 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, the Company
could suffer a loss of its entire investment in the property.  The
Company has obtained title opinions on substantially all of its
producing properties and believes that it has satisfactory title to
such properties in accordance with standards generally accepted in the
oil and gas industry.  The Company's producing properties are
mortgaged to its banks in connection with its revolving credit
facility.

                                   8

OPERATIONAL HAZARDS AND INSURANCE

     The Company's operations are subject to the usual hazards
incident to the drilling and production of oil and gas, such as
blowouts, cratering, explosions, uncontrollable flows of oil, gas or
well fluids, fires, pollution, releases of toxic gas and other
environmental hazards and risks.  These hazards can cause personal
injury and loss of life, severe damage to and destruction of property
and equipment, pollution or environmental damage and suspension of
operations.  Offshore operations are subject to the additional hazards
of marine operations, such as capsizing of vessels, collision and
adverse weather and sea conditions.

     The Company maintains insurance of various types to cover its
operations.  The Company has $1,000,000 of general liability insurance
and an additional $30,000,000 of excess liability insurance.  In
addition, the Company maintains operator's extra expense coverage
which applies to care, custody and control of wells drilled or
completed.  The Company's insurance does not cover every potential
risk associated with the drilling and production of oil and gas.  In
particular, coverage is not obtainable for certain types of
environmental hazards.  The occurrence of a significant adverse event,
the risks of which are not fully covered by insurance, could have a
material adverse effect on the Company's financial condition and
results of operations.  Moreover, no assurance can be given that the
Company will be able to maintain adequate insurance in the future at
rates it considers reasonable.

EMPLOYEES

     At December 31, 1996, Basin had 64 employees, including 19
employed in field operations and 45 employed in its Denver
headquarters or Houston district office.  None of Basin's employees
are subject to a collective bargaining agreement and Basin considers
its relations with its employees to be good.

                                   9

ITEM 2. PROPERTIES.

     Prior to 1996, the Company's oil and gas properties were all
located in the Rocky Mountain region, primarily in the D-J Basin,
Powder River Basin, and Green River Basin.  During 1996, the Company
sold its D-J Basin assets and initiated operations in the Gulf Coast
area, primarily offshore in the Gulf of Mexico.  As of December 31,
1996, the estimated pre-tax present value of future net revenues from
the Company's proved reserves, using year end prices held constant and
a discount rate of 10%, totaled $83,656,000 and was distributed as
follows: Powder River Basin - 58%; Green River Basin - 14%; other
onshore - 9%; Gulf of Mexico - 19%.

     Powder River Basin

     At December 31, 1996, developed reserves accounted for 55% of the
Company's total estimated proved reserve quantities in the Powder
River Basin, and 72% of the related pre-tax present value of future
net revenues.  Approximately 92% of such proved reserves were
concentrated in three fields: Scott, Well Draw, and Jepson-Holler
Draw.  At the end of 1996, the Company owned interests in 224
producing wells and in another 71 locations attributed proved
undeveloped reserves within these fields.  The Jepson-Holler Draw
Field was unitized in 1996 for purposes of initiating secondary
recovery operations in the Shannon formation.  Water injection
commenced in January 1997 and production response is projected to be
evident by late-1998.  Most of the proved reserves estimated for
Jepson-Holler Draw as of December 31, 1996 were categorized as
undeveloped.  The primary product produced from most of the Company's
Powder River Basin properties is oil, but many of the wells also
produce liquids-rich casinghead gas generally requiring processing for
marketing.  Proved reserves are distributed broadly among the wells
and locations in these fields, such that no individual well or
location accounts for a material portion of aggregate quantities
attributed to these properties.  Most of the Company's producing wells
in the Powder River Basin have been online for several years and
production declines are relatively well established.  The Company had
one development well in the Scott Field in process at December 31,
1996 and anticipates drilling 10 to 12 development wells on its Powder
River Basin properties in 1997.

     Green River Basin

     At December 31, 1996, 76% of the Company's estimated proved
reserve quantities in the Green River Basin and 83% of related pre-tax
present value of future net revenue were proved developed.
Approximately 92% of such proved reserve quantities were associated
with the Bird Canyon, Scott Hill, and Horn Canyon fields.  At the end
of 1996, the Company held interests in 11 producing wells and five
proved undeveloped locations within these fields.  Scott Hill Field
produces oil, whereas the Bird Canyon and Horn Canyon Fields produce
predominantly gas.  The producing wells in these fields have been on
line for several years and generally exhibit stable performance
histories, with established decline rates.

     Gulf of Mexico

     The Company's proved reserves in the Gulf of Mexico at December
31, 1996 were all categorized as undeveloped but related to logged pay
sands that were behind-pipe.  These reserves were attributable to two
exploratory wells drilled in the fourth quarter of the year on Eugene
Island (EI) Block 64 and EI Block 65, respectively.  The EI 64 well
was completed in a secondary objective after a deeper primary-
objective sand was found nonproductive.  The well has been suspended
pending completion and tie-in to a nearby platform operated by a third
party.  The more significant apparent discovery was made on EI 65
where the #1 well was drilling over year-end 1996.  Estimated proved
reserves were ultimately attributed to two primary-objective pay sands
in this well, but reported year end reserves pertained only to the
shallower horizon, since the deeper zone was penetrated and logged in
1997.  A second well is currently drilling on EI 65.  It is
anticipated that a production platform and facilities will be
installed on the block later in 1997 to commence production from a
dually-completed #1 well, and if successful the #2 well.  The Company
increased its interests in EI Blocks 64 and 65 in February 1997 as
part of an acquisition.  See "Present Activities" and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources."

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

                                  10

ACREAGE

     The following table sets forth the gross and net acres of
developed and undeveloped oil and gas leases held by the Company as of
December 31, 1996.  Undeveloped acreage includes leasehold interests
which may already have been classified as containing proved
undeveloped reserves.

<TABLE>
<CAPTION>
                                        DEVELOPED ACREAGE<F1>              UNDEVELOPED ACREAGE
                                        ---------------------              -------------------
                                        GROSS           NET                GROSS           NET

<S>                                   <C>            <C>                <C>             <C>
Colorado...........................       790            449               7,383          4,639
Louisiana offshore.................       600            225              31,900         27,588
Montana............................     6,537          6,393              12,974          7,253
Nebraska...........................       480            184                 480            360
North Dakota.......................       480            176               2,160            531
Texas onshore......................       160             49                   -              -
Texas offshore.....................         -              -               1,440            540
Utah...............................     1,762            984              13,713          7,350
Wyoming............................    45,879         26,596              69,098         47,384
                                       ------         ------             -------         ------
        Total......................    56,688         35,056             139,148         95,645
                                       ======         ======             =======         ======

---------------------
<FN>
<F1> Developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation.
     Developed acreage in certain of Basin's properties that include multiple formations with different well
     spacing requirements may be considered undeveloped for certain formations, but have only been included as
     developed acreage in the presentation above.
</FN>
</TABLE>


OIL AND GAS RESERVES

     Basin engaged independent petroleum engineers, Netherland, Sewell
& Associates, Inc. ("Netherland Sewell"), to audit Basin's estimates
of total proved reserves, projected future production, and estimated
future net revenues from production of proved reserves for the
Company's onshore properties as of December 31, 1996.  Basin engaged
Ryder Scott Company Petroleum Engineers to prepare such estimates for
the Company's offshore properties as of such date. These estimates
were based upon a review of production histories and other geologic,
economic, ownership, volumetric and engineering data.  In determining
the estimates of the reserve quantities that are economically
recoverable, oil and gas prices and estimated development and
production costs as of December 31, 1996 were utilized.

     The following table sets forth estimates as of December 31, 1996
derived from Basin's reserve reports. The present values (discounted
at 10 percent) of estimated future net revenues  before income taxes
shown in the table are not intended to represent the current market
value of the estimated oil and gas reserves owned by Basin. For
further information concerning the present value of future net revenue
from these proved reserves, see Unaudited Supplemental Oil and Gas
Reserve Information in the Consolidated Financial Statements.

<TABLE>
<CAPTION>
                                                                               PROVED RESERVES
                                                                    -------------------------------------
                                                                    DEVELOPED     UNDEVELOPED       TOTAL

<S>                                                                <C>            <C>           <C>
Oil (Mbbls)................................................           4,046          3,824          7,870
Gas (MMcf).................................................          19,182         10,531         29,713
Total (MMcfe)..............................................          43,458         33,475         76,933

Future Net Revenue Before Income Taxes
    (in thousands).........................................         $91,717        $68,281       $159,998
Present Value of Future Net Revenue Before Income Taxes
    (in thousands).........................................         $50,856        $32,800       $ 83,656
</TABLE>

                                  11

     The following table sets forth estimates of Basin's total proved
reserves at December 31, 1996 by geographic area of operations:

<TABLE>
<CAPTION>
                                                       PROVED RESERVES
                                                ---------------------------

                                                  OIL       GAS      TOTAL
          GEOGRAPHIC REGION                     (MBBLS)    (MMCF)   (MMCFE)

          <S>                                    <C>      <C>       <C>
          Powder River Basin                      6,697    10,737    50,919

          Greater Green River Basin                 380     8,372    10,652

          Offshore Gulf of Mexico                    49     6,391     6,685

          Other                                     744     4,213     8,677
                                                  -----    ------    ------
       Total                                      7,870    29,713    76,933
                                                  =====    ======    ======
</TABLE>


     There are numerous uncertainties inherent in estimating
quantities of proved reserves and in projecting future rates of
production and timing of development expenditures, including many
factors beyond the control of the producer. The reserve data set forth
herein represent only estimates. Reserve engineering is a subjective
process of estimating underground accumulations of oil and gas that
cannot be measured in an exact way, and the accuracy of any reserve
estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment and the
existence of development plans. In addition, results of drilling,
testing and production subsequent to the date of an estimate may
justify revision of such estimates. Accordingly, reserve estimates are
often different from the quantities of oil and gas that are ultimately
recovered. Further, the estimated future net revenues from proved
reserves and the present value thereof are based upon certain
assumptions, including geologic success, prices, future production
levels and cost, that may not prove correct over time. Predictions
about prices and future production levels are subject to great
uncertainty, and the meaningfulness of such estimates is highly
dependent upon the accuracy of the assumptions upon which they are
based. Oil and gas prices have fluctuated widely in recent years.
There is no assurance that prices will not be materially higher or
lower than the prices utilized in estimating Basin's reserves.

     The weighted average sales prices utilized for purposes of
estimating Basin's proved reserves and future net revenues therefrom
as of December 31, 1996 were $25.35 per Bbl for oil and $3.02 per Mcf
for gas.  These prices are significantly above average prices
prevailing during most of the past several years, and oil and gas
prices have declined from such levels during the first two months of
1997.

                                  12

PRODUCTION

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

<TABLE>
<CAPTION>
                                                   YEAR ENDED DECEMBER 31,
                                                   -----------------------

                                                   1996      1995      1994

             <S>                               <C>       <C>       <C>
             Net production:
             Oil (Mbbls).....................       564     1,153     1,278
             Gas (MMcf)......................     4,776    12,833    14,377
             Total (MMcfe)...................     8,160    19,751    22,045
             Average net daily
              production:
                  Oil (bbls).................     1,540     3,160     3,501
                  Gas (Mcf)..................    13,050    35,154    39,389
                  Total (Mcfe)...............    22,290    54,114    60,395
             Average sales price
              per unit:
                  Oil (bbl)..................   $ 20.03   $ 17.02   $ 15.63
                  Oil, excluding hedging (bbl)  $ 20.88   $ 17.12   $ 15.70
                  Gas (Mcf)..................   $  1.44   $  1.56   $  1.69
                  Gas, excluding hedging
                      and Section 29 tax credit
                      income (Mcf)...........   $  1.44   $  1.34   $  1.55
                  Total (Mcfe)...............   $  2.23   $  2.01   $  2.01
             Production cost per Mcfe........   $   .81   $   .59   $   .55
</TABLE>

     Basin owned 363 gross (229 net) producing oil wells and 57 gross
(39 net) producing gas wells as of December 31, 1996.  A well is
categorized under state reporting regulations as an oil well or a gas
well based upon the ratio of gas to oil produced when it first
commenced production, and such designation may not be indicative of
current production.


DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES

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

<TABLE>
<CAPTION>
                                                 YEARS ENDED DECEMBER 31,
                                               ----------------------------
                                               1996        1995        1994
                                                      (IN THOUSANDS)

<S>                                            <C>       <C>       <C>
Development costs.......................         $4,472    $7,427   $42,113

Exploration costs.......................         10,250     2,003     2,361

Leasehold and
 acquisition costs:
    Unproved properties.................          5,056     2,429     5,275
    Proved properties...................          3,067     3,889    16,751
                                                  -----     -----    ------

Total costs incurred....................        $22,845   $15,748   $66,500
                                                =======   =======   =======
</TABLE>

                                  13

DRILLING ACTIVITY

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

<TABLE>
<CAPTION>
                                                                          YEAR ENDED DECEMBER 31,
                                                                          -----------------------
                                                                 1996             1995             1994
                                                                 ----             ----             ----
                                                            GROSS     NET    GROSS    NET     GROSS      NET

<S>                                                           <C>    <C>       <C>   <C>       <C>    <C>
Development:
  Oil....................................................       3     2.8        4    3.9       137    125.7
  Gas....................................................      --      --       --     --        17     16.5
  Non-productive.........................................       1      .9       --     --         3      2.9
                                                               --     ---       --    ---       ---    -----
    Total................................................       4     3.7        4    3.9       157    145.1
                                                               ==     ===       ==    ===       ===    =====
Exploratory:
  Oil....................................................      --      --        2    1.3         1      1.0
  Gas....................................................      --      --       --     --        --       --
  Non-productive.........................................       3     1.4        2    1.7         3      2.8
                                                               --     ---       --    ---        --      ---
    Total................................................       3     1.4        4    3.0         4      3.8
                                                               ==     ===       ==    ===        ==      ===
</TABLE)

PRESENT ACTIVITIES

     At the end of 1996, the Company was participating in one (1.0
net) development well and two (.75 net) exploratory wells that were in
process.

     The development well was being drilled in the Scott Field in
Wyoming and was successfully completed in 1997. Two (2.0 net)
additional development wells have been drilled and completed in the
Scott Field in 1997, through mid-March.

     The two exploratory wells in process at year end were both
offshore in the Gulf of Mexico, on Eugene Island (EI) Blocks 64 and
65, respectively. Both of these wells were attributed proved
undeveloped reserves as of December 31, 1996. The EI 64 #1 well
completed drilling in November 1996 and was temporarily suspended
after the primary target sand was found non-productive but proved
reserves were established in a shallower secondary objective.  The #1
well on EI 65 was drilling over year end. Estimated proved reserves
reported as of December 31, 1996 include reserves attributable to the
13,000' sand in this well, which was logged prior to year end. An
additional productive sand was encountered in the EI 65 #1 well after
year end in the deeper 13,700' sand before drilling was completed in
February 1997 and the well was temporarily suspended. A second well
was spud on EI 65 in February 1997 and is currently drilling.

     In February 1997, the Company consummated a $14.4 million
acquisition of interests in three Gulf of Mexico lease blocks with
wells awaiting further development to initiate production of proved
reserves. Two of these blocks are EI 64 and EI 65, where, as noted
above, the Company already owned interests. Through this acquisition,
Basin increased its working interests in EI 64 and EI 65 from 37.5%
before payout (BPO) and 47.5% after payout (APO) to 62.5% BPO and
67.5% APO. The third property acquired was a 46.5% interest in most of
East Cameron (EC) Block 378, including a well completed subsea in
January 1997 that is waiting on pipeline installation to connect to a
nearby third party production platform.

     On March 5, 1997, the Company participated in winning bids for 11
tracts at the central Gulf of Mexico lease sale held by the MMS.  Such
tracts comprised 43,306 gross and 28,828 net undeveloped acres
offshore Louisiana.  If all 11 tracts are awarded by the MMS, which
can choose to reject all bids for a given lease, the Company's net
share of the related leasehold bonuses will total approximately
$5,737,000.
                                  14

ITEM 3. 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, will have a material
adverse effect on the Company's financial condition, liquidity or
results of operations.

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

     No matters were submitted for a vote of security holders during
the fourth quarter of 1996.

                                  15

                                PART II

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

     The Company's common stock is traded over the counter on the
Nasdaq National Market System using the symbol "BSNX."  The following
table sets forth, for the periods indicated, the range of high and low
closing prices for the common stock as reported by the Nasdaq National
Market for the last two calendar years.

          1995                   High                 Low
          ----                   ----                 ---

          First Quarter         $11.50              $ 6.38
          Second Quarter          9.13                5.38
          Third Quarter           7.00                4.38
          Fourth Quarter          5.88                3.00


          1996                   High                 Low
          ----                   ----                 ---

          First Quarter         $ 5.25              $ 3.69
          Second Quarter          6.63                5.00
          Third Quarter           7.50                5.75
          Fourth Quarter          7.75                5.63

     On March 7, 1997, the last sale price of the Company's common
stock as reported on the Nasdaq National Market was $6.88.  As of
December 31, 1996 there were 136 owners of record.

     The Company's policy is to retain its earnings to support the
growth of the Company's business.  Accordingly, the Board of Directors
of the Company has never declared cash dividends on its Common Stock
and has no present  plans to do so.  Under the terms of its credit
facility with its banks, the Company may not pay any dividend without
consent of the banks.

                                  16

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 presented elsewhere herein.



</TABLE>
<TABLE>
<CAPTION>
                                                           YEAR ENDED DECEMBER 31,
                                         ----------------------------------------------------------
                                         1996        1995           1994         1993        1992
                                                    (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                    <C>         <C>            <C>          <C>         <C>
INCOME STATEMENT DATA:
  Revenue:
    Oil sales. . . . . . . . . . . . .  $11,292     $19,632        $19,971      $13,725     $11,409
    Gas sales  . . . . . . . . . . . .    6,890      20,013         24,255       24,139      10,349
    Gain on sale of assets . . . . . .   22,472          --             --           --          --
    Interest and other . . . . . . . .    1,009         831            161          104         353
                                         ------      ------         ------       ------      ------
                                         41,663      40,476         44,387       37,968      22,111
                                         ------      ------         ------       ------      ------

  Costs and expenses:
    Lease operating expenses . . . . .    4,776       8,196          8,642        7,105       5,418
    Production taxes . . . . . . . . .    1,829       3,478          3,432        2,918       1,794
    Depreciation, depletion and
       amortization. . . . . . . . . .    7,606      17,202         18,163       12,311       5,839
    General and administrative, net. .    3,850       5,498          4,641        4,182       2,997
    Interest expense . . . . . . . . .    2,254       6,432          3,618        3,160       1,801
    Property impairment. . . . . . . .       --      26,500             --           --         --
    Other  . . . . . . . . . . . . . .       18         497             --           --         --
                                         ------      ------         ------       ------      ------
                                         20,333      67,803         38,496       29,676      17,849
                                         ------      ------         ------       ------      ------

  Income (loss) before income taxes  .   21,330     (27,327)         5,891        8,292       4,262
  Income tax (provision) benefit . . .   (5,760)      7,784         (2,236)      (3,142)       (753)
                                         ------      ------         ------       ------      ------

  Net income (loss)  . . . . . . . . .  $15,570    $(19,543)       $ 3,655      $ 5,150     $ 3,509
                                         ======     =======         ======        =====       =====

  Earnings (loss) per share  . . . . .    $1.45      $(1.82)       $   .34      $   .67     $   .57
                                           ====       =====          =====        =====       =====

  Weighted average common
    shares outstanding . . . . . . . .   10,700      10,710         10,813        7,650       6,188

<CAPTION>
                                                             AS OF DECEMBER 31,
                                         ---------------------------------------------------------
                                         1996        1995           1994         1993        1992
                                                               (IN THOUSANDS)
<S>                                    <C>        <C>           <C>          <C>         <C>
BALANCE SHEET DATA:
Working capital
  (deficit). . . . . . . . . . . . . .  $19,178    $ (2,211)     $  (5,646)   $     106   $    (102)
Net property and equipment . . . . . .   54,800     134,598        165,807      116,133      64,662
Total assets . . . . . . . . . . . . .   84,957     146,651        184,855      131,520      75,161
Long-term debt . . . . . . . . . . . .      218      77,172         77,199       41,819      36,606
Total stockholders' equity . . . . . .   68,751      53,287         72,575       67,183      24,701
</TABLE>

                                  17

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

RESULTS OF OPERATIONS - YEARS ENDED DECEMBER 31, 1996 AND 1995

REVENUE.  Excluding a $22,472,000 gain on sale of assets recognized
during 1996, revenue for 1996 was $19,191,000, representing a decrease
of $21,285,000, or 53%, as compared to 1995. The following table
reflects the Company's average oil and gas prices and its average
daily oil and gas production for the years presented:

                                   YEAR ENDED DECEMBER 31,
                                   -----------------------
                               1996        1995      % CHANGE
Average price:
  Oil (per bbl). . .          $20.03      $17.02         18
  Gas (MMcf) . . . .          $ 1.44      $ 1.56         (8)

Average daily  production:
  Oil (bbl). . . . .           1,540       3,160        (51)
  Gas (Mcf). . . . .          13,050      35,154        (63)

The decreases in average daily production were primarily attributable
to the combined effects of sales of producing properties during 1996
and 1995 and natural production declines.  As more fully described
below under Liquidity and Capital Resources, the Company consummated
two transactions during 1996 in which all of its assets in the D-J
Basin were sold.  As of December 31, 1995, these assets represented
approximately two-thirds of the Company's producing wells and 70% of
its proved oil and gas reserves.  In conjunction with the second
transaction, the Company recognized a $22,472,000 gain.  Excluding
production and sales from such D-J Basin properties, average oil and
gas prices and average daily oil and gas production for the periods
presented were:

                                  YEAR ENDED DECEMBER 31,
                                  -----------------------
                               1996        1995      % CHANGE
Average price:
  Oil (per bbl). . .          $20.32      $17.61         15
  Gas (per Mcf). . .           $1.33       $1.09         22

Average daily production:
  Oil (Bbl). . . . .           1,118       1,341        (17)
  Gas (Mcf). . . . .           4,871       5,517        (12)

During 1995, the Company also recognized gas revenue for payments
received with respect to transferred Section 29 tax credits in the
amount of $2,857,000.

Other revenue in 1995 was primarily derived from a small processing
facility that was decommissioned late in the year.  In 1996, other
revenue related mainly to interest income on cash equivalents held
after the second D-J Basin asset sale transaction.

LEASE OPERATING EXPENSES.  Lease operating expenses for 1996 were
$4,776,000, a decrease of $3,420,000, or 42%, compared to 1995.  Lease
operating costs per Mcfe produced during 1996 averaged $.59 compared
to $.42 in 1995.   These higher costs per Mcfe were caused primarily
by the increased portion of the Company's total active wells that are
oil wells, with typically higher unit operating costs, following the
sale of the D-J Basin assets.

PRODUCTION TAXES.  Production taxes for 1996 were $1,829,000, a
decrease of $1,649,000, or 47%, compared to 1995.  Production taxes as
a percent of oil and gas sales for 1996 were 10.1%, compared to 8.8%
in 1995.  The increased average tax rate was due to a greater portion
of sales occurring in higher-tax jurisdictions in 1996.

DEPRECIATION, DEPLETION AND AMORTIZATION.  Depreciation, depletion and
amortization expense for 1996 was $7,606,000, a decrease of
$9,596,000, or 56%, as compared to 1995.  The decrease was primarily
attributable to the lower production volumes

                                  18

in 1996 as compared to 1995.  The depletion rate of $.82 per Mcfe
produced in 1996 was slightly lower than the $.84 per Mcfe average
depletion rate during 1995.

PROPERTY IMPAIRMENT.  During 1995, the Company recognized a property
impairment charge of $26.5 million, as the result of the capitalized
costs of its oil and gas properties exceeding a "ceiling" on such
costs computed in accordance with prescribed accounting guidelines.

GENERAL AND ADMINISTRATIVE, NET.  General and administrative expenses
for 1996 were $3,850,000, a decrease of $1,648,000, or 30%, as
compared to 1995.  The decreases resulted primarily from staff
reductions made during the second half of 1995 and the first half of
1996 and partially due to reductions in office rent expense as a
result of relocating and decreasing the size of the corporate
headquarters.

INTEREST EXPENSE.  Interest expense for 1996 totaled $2,254,000
representing a decrease of $4,178,000, or 65%, as compared to 1995.
The decrease was principally attributable to lower average borrowings
as a result of asset sales proceeds applied to debt retirement during
1996, as summarized below:

                                       YEAR ENDED DECEMBER 31,
                                       -----------------------
                                           1996        1995

Average borrowings (in thousands)      $ 28,200     $ 78,800

Average interest rate on borrowings        8.0%        7.3%


INCOME TAX BENEFIT (PROVISION).  The difference between the income tax
provision for 1996 and the income tax benefit for 1995, and the
amounts that would be calculated by applying statutory income tax
rates to income before income taxes is due primarily to the 1996
reversal of the $2,196,000 deferred tax asset valuation allowance
established during 1995.

RESULTS OF OPERATIONS - YEARS ENDED DECEMBER 31, 1995 AND 1994

REVENUE.  Revenue for 1995 was $40,476,000, a decrease of $3,911,000,
or 9%, as compared to 1994.  The following table reflects the
Company's average oil and gas prices and its average daily oil and gas
production for the years presented:

                                  YEAR ENDED DECEMBER 31,
                                  -----------------------
                               1996        1995     % CHANGE
Average price:
  Oil (per bbl). . .          $17.02      $15.63         9
  Gas (per Mcf). . .          $ 1.56       $1.69        (8)

Average daily production:
  Oil (Bbl). . . . .           3,160       3,501       (10)
  Gas (Mcf). . . . .          35,154      39,389       (11)


The declines in production are partially attributable to the sale of
marginal properties during 1995. Lower production also resulted from
normal depletion-related declines that were not fully offset by new
drilling and recompletion activities.  The Company recognized gas
revenues for payments received with respect to transferred Section 29
tax credits, in the amounts of $2,857,000 and $2,123,000 for the years
ended December 31, 1995 and 1994, respectively.

LEASE OPERATING EXPENSES.  Lease operating expenses for 1995 were
$8,196,000, a decrease of $446,000, or 5%, compared to 1994.  Lease
operating costs per Mcfe produced during 1995 averaged $.42 compared
to $.39 in 1994.  These higher costs per Mcfe were caused primarily by
a decline in the number of new wells brought on line, since such wells
typically have relatively high initial production rates, generating
average unit production costs that are lower than more mature
properties.

PRODUCTION TAXES.  Production taxes for 1995 were $3,478,000, an
increase of $46,000, or 1%, compared to 1994.  Production taxes as a
percent of oil and gas sales for 1995 were 8.8%, compared to 7.8% in
1994.  The increased average tax rate was due to a greater portion of
sales occurring in higher-tax jurisdictions in 1995.

                                  19

DEPRECIATION, DEPLETION AND AMORTIZATION.  Depreciation, depletion and
amortization expense for 1995 was $17,202,000, a decrease of $961,000,
or 5%, as compared to 1994.  The decrease was attributable to the
lower production volumes in 1995 as compared to 1994, as the average
depletion rate of $.84 per Mcfe produced in 1995 was higher than the
$.77 per Mcfe rate in 1994.  The increase reflects investment costs
per Mcfe of reserves added during the second half of 1994 and in 1995
which were above the Company's historical average, as well as a
reduction in estimated proved reserves at December 31, 1995 due, in
part, to the effects of using lower gas prices in determining economic
production limits.

PROPERTY IMPAIRMENT.  During 1995, the Company recognized a property
impairment charge of $26.5 million, as the result of the capitalized
costs of its oil and gas properties exceeding a "ceiling" on such
costs computed in accordance with prescribed accounting guidelines.

GENERAL AND ADMINISTRATIVE, NET.  General and administrative expenses
for 1995 were $5,498,000, an increase of $857,000, or 18%, as compared
to 1994.  The increase is primarily due to smaller recoveries from
third-party working interest owners and nonrecurring charges of
$545,000 related to staff reductions, settlement of a legal dispute,
and an unsuccessful corporate acquisition effort.  The lower
recoveries resulted from the Company's acquisition in late-1994 of
additional working interests in certain properties that it operates
and reduced billings for drilling and completion overhead due to a
less active property development program in 1995.  Decreases in gross
general and administrative expenses resulting from late-1995
reductions in office staff and other administrative costs had minimal
impact in 1995.

INTEREST EXPENSE.  Interest expense for 1996 totaled $6,432,000, an
increase of $2,814,000, or 78%, as compared to 1994.  This increase
was due to the combined effects of increased average borrowings and
higher interest rates, as summarized below:

                                       YEAR ENDED DECEMBER 31,
                                       ----------------------
                                          1996         1995

Average borrowings (in thousands)      $ 78,800     $ 55,600

Average interest rate on borrowings        7.3%         5.7%

INCOME TAX BENEFIT (PROVISION).  The difference between the income tax
benefit for 1995, and the amount that would be calculated by applying
statutory income tax rates to the loss before income taxes is due to
the establishment of a $2,196,000 deferred tax asset valuation
allowance during 1995.

LIQUIDITY AND CAPITAL RESOURCES

In February 1996, the Company entered into two agreements pursuant to
which it sold all of its assets in the D-J Basin, effective January 1,
1996, for an aggregate adjusted sales price of $123.5 million. The
sale of approximately one-third of these D-J Basin assets was closed
in March 1996 and the sale of the remainder was closed in June 1996.
Combined, these transactions resulted in the disposition of two-thirds
of the Company's total wells and approximately 70% of its estimated
proved oil and gas reserves as of December 31, 1995. A portion of the
sales proceeds was used to repay all outstanding long-term debt and
the remainder, net of transaction costs, was initially invested in
short-term, interest-bearing cash equivalents pending redeployment
into new oil and gas investments. The Company's remaining producing
properties after the sale were primarily mature oil and gas fields in
the Powder River Basin, Green River Basin, and elsewhere in the Rocky
Mountain region.

In August 1996, following the sale of the D-J Basin assets, the
Company entered into an amended and restated credit agreement with its
existing bank group that improved certain terms, including fees and
interest rates, applicable under the line of credit. The amended
credit agreement provides for the interest rate on borrowings to be
determined by reference to either the prime rate or LIBOR, at the
Company's election.  A varying spread of 0% to 0.5% is added to the
prime rate, or 0.625% to 1.25% is applied to LIBOR,  based upon the
Company's debt-to-capitalization ratio at the time. The credit
agreement provides for borrowings to be revolving loans until August
1, 1999, at which time the outstanding balance will be converted into
a four-year amortizing 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. The borrowing base under the revolving credit
facility was established at $25 million in August 1996 and is
scheduled to be redetermined as of April 30, 1997 and generally
thereafter at six month intervals until converted into a term loan.
The Company is anticipating that at the next redetermination date the
borrowing base will be established at a level at or above the present
level of $25 million, but there can be no assurance that this will
occur. As of December 31, 1996, there were no borrowings outstanding
under the facility. In addition to availability under the credit line,
the Company's capital resources at December 31, 1996 included
approximately $19.2 million of net working capital, inclusive of $22
million of cash and cash equivalents.

                                  20

Prior to sale of its D-J Basin assets the Company had a working
capital deficit and little unutilized capacity under its revolving
credit facility. The D-J Basin asset sales significantly improved the
Company's liquidity but also significantly reduced its oil and gas
production and, consequently, its operating cash flow. Prior to 1995
the Company's investments in oil and gas properties typically exceeded
its cash flow from operating activities, with the excess funded
primarily with bank borrowings and proceeds from equity offerings. The
Company's total capital expenditures on oil and gas properties totaled
$22.8 million in 1996, $15.7 million in 1995, and $66.5 million in
1994. By comparison, cash flows from operating activities before
changes in operating assets and liabilities totaled $5.7 million in
1996, $17.1 million in 1995, and $25 million in 1994. The large
decline in capital expenditures from 1994 to 1995 was due, in part, to
liquidity constraints that developed when declining Rocky Mountain gas
prices unfavorably impacted cash flow and borrowing capacity and
reduced the number of economically viable development projects within
the Company's asset base.  The Company's capital expenditures are
generally discretionary and activity levels are determined by a number
of factors, including oil and gas prices, interest rates, availability
of funds, quantity and character of identified investment projects,
availability of service providers, and competition. The Company
intends to use the improved liquidity resulting from the D-J Basin
asset sales to make new investments in oil and gas properties, through
acquisition and development of proved properties, exploration, and
exploitation of its property base.

The Company had no extraordinary capital expenditure commitments
pending at December 31, 1996. However, in February 1997 the Company
acquired, for $14.4 million, interests in three Gulf of Mexico lease
blocks with recently drilled wells that were attributed proved
reserves but which required additional development to commence
production. Development plans for these properties are discussed later
in this section. Also, on March 5, 1997 the Company participated in
winning bids for 11 tracts at the central Gulf of Mexico lease sale
held by the federal government's Minerals Management Service (MMS). If
all 11 tracts are awarded by the MMS, which can choose to reject all
bids for a given lease,  the Company's net share of the related
leasehold bonuses will total approximately $5.7 million.

During the past several years the Company has been increasing its
capital expenditures on exploration activities. Exploration activities
generally have greater investment risk but a higher targeted rate of
return than acquisition and development activities. The range of
possible investment outcomes is ordinarily much greater for
exploration than for other oil and gas investments. In 1996 the
Company began focusing its exploration activities in the shallow
waters of the Gulf of Mexico, offshore Louisiana and Texas. The
Company had conducted no previous operations in the area and began the
period with no prospect inventory. To conduct its Gulf Coast
exploration activities the Company formed a Houston office staffed
with experienced Gulf Coast geoscientists, engineers, and support
personnel. During its initial year of operations in the Gulf Coast
area the Company invested approximately $14.9 million in related
exploration activities, including costs relating to leaseholds that
were unproved at December 31, 1996 but net of $4.9 million of costs
recouped through resale of partial interests in prospects to industry
partners. Such investments primarily related to acquisitions of
seismic data and mineral leaseholds, and participation in drilling
four exploratory wells, two of which were successful. Because the
successful wells were drilled late in the year, the Company did not
incur significant related development costs in 1996. The Company's
exploration plans for 1997 anticipate participation in five to ten new
exploratory test wells, but only one such well has yet been scheduled
and the actual number of test wells drilled may be more or less than
anticipated.

The two successful wells noted above were drilled on Eugene Island
(EI) Blocks 64 and 65, respectively. Both wells were attributed proved
reserves as of December 31, 1996 but were categorized as undeveloped
at that date because substantial future operations were required in
order to make the wells capable of production. The EI 64 #1 well is
expected to commence production in the second quarter of 1997 after
completion and tie-in to a nearby production platform owned and
operated by a third party.  It is expected that a production platform
will be installed on the EI 65 property in the third quarter of 1997
to produce the #1 well and, if it is successful, the #2 well which is
currently drilling.

Through the $14.4 million acquisition consummated in February 1997,
the Company increased its interests in EI Blocks 64 and 65. The third
property acquired was an interest in East Cameron (EC) Block 378. A
well on EC 378 was completed subsea in January 1997 and is waiting on
pipeline installation to connect to a nearby third party production
platform. Initial production from EC 378 is expected to commence
during the third or fourth quarter of 1997.

The Company's capital budget for calendar 1997, excluding acquisitions
not already consummated, is approximately $55 million, allocated as
follows: approximately $15 million is provided for acquisitions of
proved properties; approximately $20 million is provided for
acquisitions of prospect leaseholds, seismic data procurement, and
exploratory drilling costs; approximately $15 million relates to
anticipated development of the Company's existing property base,
including EI 64, EI 65, EC 378, and the Company's Rocky Mountain
assets; and approximately $5 million is provided for other activities,
including current year development of assumed exploratory discoveries.
Much of this budget is dependent on future developments that are not
entirely within the Company's control and which may not occur. The
Company's actual capital expenditures may vary significantly from
these estimates. Further, the Company intends to continue to pursue
acquisitions of proved properties, primarily in the Gulf Coast and
Rocky Mountain regions, which, while not budgeted, could be very
significant.

                                  21

Management believes that the current-year budget, as described above,
can be funded without new sources of capital, by utilizing net working
capital at the beginning of the period, projected cash flow, and
borrowings under the revolving credit facility with the Company's bank
group. Cash flow is expected to increase significantly during the
latter part of the year when EI 64 and 65 and EC 378 are projected to
be on-line; however, these properties have not produced before and the
forecast on-line dates and production rates may not be achieved. If
conditions warrant, the Company may consider raising additional
capital through issuance of debt or equity securities. Should the
Company undertake a large acquisition, issuing such securities or
monetizing assets would likely be required to fund the transaction. In
the absence of additional liquidity, the Company's ability to fund
investment activities in future periods will be significantly affected
by the results obtained from investments made in 1997.

Changes In Prices

The Company's revenue, cash flow, and the value of its oil and gas
properties have been, and will continue to be, affected by changes in
oil and natural gas prices.  The Company's ability to maintain current
borrowing capacity and to obtain additional capital on attractive
terms is also substantially dependent on oil and natural gas prices.
As such, changes in oil and gas prices can significantly affect the
amount of the Company's capital expenditures.  Oil and natural gas
prices are subject to significant seasonal and other fluctuations that
are beyond the Company's ability to control or predict.  The Company
periodically enters into product swap agreements in order to hedge
against the volatility of product prices.  Although the Company enters
into the agreements to limit exposure to price decreases, the
agreements also limit the Company's ability to benefit from
significant price increases on the contract volumes.  Effective July
1, 1996, the Company entered into a crude oil swap agreement with a
contract volume of 10,000 barrels per month through December 31, 1997.
This agreement provides for the cash settlement of the differential
between the $18.32 per barrel contract price and the average closing
NYMEX crude oil price during each month.  The Company has also entered
into a crude oil collar arrangement effective for calendar 1997 on an
additional 10,000 barrels per month.  This agreement provides for the
cash settlement of the differential between the monthly average
closing NYMEX price and the contract floor of $19.50 per barrel or the
contract ceiling of $24.35 per barrel, if the average monthly NYMEX
price falls outside of the range defined by such contract floor and
contract ceiling.  Any gain or loss realized on these agreements is
included as a component of oil sales in the month of production.

CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS

Statements that are not historical facts contained in this report are
forward-looking statements that involve risks and uncertainties that
could cause actual results to differ from projected results.  Such
statements address activities, events or developments that the Company
expects, believes, projects, intends or anticipates will or may occur,
including such matters as future capital, development and exploration
expenditures (including the amount and nature thereof), drilling of
wells, reserve estimates (including estimates of future net revenues
associated with such reserves and the present value of such future net
revenues), future production of oil and gas, business strategies,
expansion and growth of the Company's operations, cash flow and
anticipated liquidity, prospect development and property acquisition,
obtaining financial or industry partners for prospect or program
development, or marketing of oil and gas.  Factors that could cause
actual results to differ materially ("Cautionary Disclosures") are
described, among other places, in the Marketing, Competition, and
Regulation sections in this Form 10-K and under the caption
"Management's Discussion and Analysis of Financial Condition and
Results of Operations."  Without limiting the Cautionary Disclosures
so described, Cautionary Disclosures include, among others: general
economic conditions, the market price of oil and natural gas, the
risks associated with exploration, the Company's ability to find,
acquire, market, develop and produce new properties, operating hazards
attendant to the oil and natural gas business, the Company's
inexperience in the Gulf of Mexico, uncertainties in the estimation of
proved reserves and in the projection of future rates of production
and timing of development expenditures, the strength and financial
resources of the Company's competitors, the Company's ability to find
and retain skilled personnel, climatic conditions, labor relations,
availability and cost of material and equipment, delays in anticipated
start-up dates, environmental risks, the results of financing efforts,
and regulatory developments.  All written and oral forward-looking
statements attributable to the Company or persons acting on its behalf
are expressly qualified in their entirety by the Cautionary
Disclosures, including without limitation those contained in the
President's letter contained in the Annual Report to Stockholders.
The Company disclaims any obligation to update or revise any forward-
looking statement to reflect events or circumstances occurring
hereafter or to reflect the occurrence of anticipated or unanticipated
events.

                                  22

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(a) 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 1997 Annual Meeting of Stockholders (the "Proxy Statement") to be
filed with the Securities and Exchange Commission no later than April
30, 1997.

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.

                                  23

                          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.

                                  24

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

     MMBtu. One million Btus.

     MMcf. One million cubic feet.

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

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

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

     Present value of future net revenues. Estimated future net
revenues discounted at a rate of ten percent per annum.

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

     Proved developed reserves. Reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.

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

     Proved undeveloped location. A site on which a development well
can be drilled consistent with local spacing rules for the purpose of
recovering proved reserves.

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

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

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

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

                                  25

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

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

                                                                  PAGE

Report of Independent Public Accountants . . . . . . . . . . . . . F-1

Consolidated Statements of Operations for the years ended
     December 31, 1996, 1995, and 1994 . . . . . . . . . . . . . . F-2

Consolidated Balance Sheets as of December 31, 1996 and 1995 . . . F-3

Consolidated Statements of Cash Flow for the years
     ended December 31, 1996, 1995 and 1994. . . . . . . . . . . . F-5

Consolidated Statements of Changes in Stockholders' Equity
     for the years ended December 31, 1996, 1995 and 1994. . . . . F-7

Notes to Consolidated Financial Statements . . . . . . . . . . . . F-8





     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 Combined Financial Statements and Notes thereto.

                                  26

               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, 1996 and
1995, 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, 1996.  These consolidated financial
statements are the responsibility of the Company's management.  Our
responsibility is to express an opinion on these consolidated finan-
cial statements based on our audits.

     We conducted our audits in accordance with generally accepted
auditing standards.  Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the
consolidated financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the consolidated financial statements.  An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the
overall financial statement presentation.  We believe that our audits
provide a reasonable basis for our opinion.

     In our opinion, the consolidated financial statements referred to
above present fairly, in all material respects, the consolidated
financial position of Basin Exploration, Inc. and subsidiaries as of
December 31, 1996 and 1995, and the results of their operations and
their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting
principles.




                                   /s/ARTHUR ANDERSEN LLP
                                   ARTHUR ANDERSEN LLP

Denver, Colorado,
 February 14, 1997.

                                  F-1

BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
Year Ended December 31,                         1996                1995                1994
----------------------------------------------------------------------------------------------
(in thousands, except per share data)
<S>                                         <C>                 <C>                 <C>
REVENUE:
  Oil sales                                  $ 11,292            $ 19,632            $ 19,971
  Gas sales                                     6,890              20,013              24,255
  Gain on sale of assets                       22,472                  --                  --
  Interest and other                            1,009                 831                 161
----------------------------------------------------------------------------------------------
                                               41,663              40,476              44,387
----------------------------------------------------------------------------------------------
COSTS AND EXPENSES:
  Lease operating expenses                      4,776               8,196               8,642
  Production taxes                              1,829               3,478               3,432
  Depreciation, depletion, and amortization     7,606              17,202              18,163
  General and administrative, net               3,850               5,498               4,641
  Interest expense                              2,254               6,432               3,618
  Property impairment                              --              26,500                  --
  Other                                            18                 497                  --
----------------------------------------------------------------------------------------------
                                               20,333              67,803              38,496
----------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE
INCOME TAXES                                   21,330             (27,327)              5,891
INCOME TAX (PROVISION)
BENEFIT                                        (5,760)              7,784               (2,236)
----------------------------------------------------------------------------------------------
NET INCOME (LOSS)                             $15,570            $(19,543)            $  3,655
----------------------------------------------------------------------------------------------
EARNINGS (LOSS)PER SHARE                    $    1.45          $    (1.82)           $    0.34
----------------------------------------------------------------------------------------------

WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING                             10,700              10,710               10,813
----------------------------------------------------------------------------------------------

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

</TABLE>
                                  F-2

            BASIN EXPLORATION, INC. AND SUBSIDIARIES
            CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                    December 31,                                                      1996                1995
                    ------------------------------------------------------------------------------------------
                    (in thousands)
                    <S>                                                       <C>                 <C>
                    ASSETS
                    CURRENT ASSETS:
                     Cash and equivalents                                      $    22,023         $     1,613
                     Accounts receivable                                             5,108               7,029
                     Stockholder note receivable                                       559                 559
                     Inventory and other                                             2,203               1,116
                    ------------------------------------------------------------------------------------------
                                                                                    29,893              10,317
                    ------------------------------------------------------------------------------------------
                    PROPERTY AND EQUIPMENT, at cost:
                     Oil and gas properties, under the full cost
                      method of accounting
                              Proved                                                78,641             206,880
                              Unproved                                               9,822               5,001
                     Less accumulated depreciation,
                      depletion and amortization                                   (36,581)            (80,961)
                    ------------------------------------------------------------------------------------------
                                                                                    51,882             130,920
                    Furniture and equipment, net                                     2,918               3,678
                    ------------------------------------------------------------------------------------------
                                                                                    54,800             134,598
                    ------------------------------------------------------------------------------------------
                    OTHER ASSETS:
                    Restricted cash                                                     --                 578
                    Other, net                                                         264               1,158
                    ------------------------------------------------------------------------------------------
                                                                                       264               1,736
                    ------------------------------------------------------------------------------------------
                                                                               $    84,957         $   146,651
                    ==========================================================================================

                    The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>



                                  F-3
            BASIN EXPLORATION, INC. AND SUBSIDIARIES
            CONSOLIDATED BALANCE SHEETS--(Continued)

<TABLE>
<CAPTION>
                    December 31,                                                      1996                1995
                    ------------------------------------------------------------------------------------------
                    (in thousands, except  share data)

                    <S>                                                      <C>                 <C>
                    LIABILITIES AND STOCKHOLDERS' EQUITY
                    CURRENT LIABILITIES:
                      Accounts payable and accrued expenses                   $      7,469        $      7,985
                      Accrued ad valorem taxes                                       2,040               4,368
                      Income taxes payable                                           1,000                  --
                      Current portion of long-term debt                                206                 175
                    ------------------------------------------------------------------------------------------
                                                                                    10,715              12,528
                    ------------------------------------------------------------------------------------------
                    LONG-TERM DEBT, net of current portion                             218              77,172
                    AD VALOREM TAXES AND OTHER                                         513               3,664
                    DEFERRED INCOME TAXES                                            4,760                  --
                    COMMITMENTS AND CONTINGENCIES (Note 6)
                    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, 10,757,000 and 10,724,000 shares
                         issued and outstanding, respectively                          108                 107
                      Additional paid-in capital                                    59,219              59,288
                      Retained earnings (accumulated deficit)                        9,556              (6,014)
                      Common stock held in treasury, at cost,
                        56,000 and 32,000 shares, respectively                        (132)                (94)
                    ------------------------------------------------------------------------------------------
                                                                                    68,751              53,287
                    ------------------------------------------------------------------------------------------
                                                                              $     84,957        $    146,651
                    ==========================================================================================

                    The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>


                                  F-4
            BASIN EXPLORATION, INC. AND SUBSIDIARIES
            CONSOLIDATED STATEMENTS OF CASH FLOW

                    <TABLE>
                    <CAPTION>
                    Year ended December 31,                                 1996           1995           1994
                    ------------------------------------------------------------------------------------------
                    (in thousands)
                    <S>                                                 <C>           <C>             <C>
                    CASH FLOWS FROM OPERATING ACTIVITIES:
                      Net income (loss)                                  $15,570       $(19,543)       $ 3,655
                      Adjustments to reconcile net income
                        (loss) to net cash provided by
                            operating activities -
                        Gain on sale of assets                           (22,472)            --             --
                        Depreciation, depletion and amortization           7,606         17,202         18,163
                        Deferred income tax expense (benefit)              4,760         (7,784)         2,470
                        Property impairment                                   --         26,500             --
                        Stock compensation expense                            98            302            354
                        Amortization of debt issuance costs                  118            373            331
                     Changes in operating assets and liabilities -
                        Decrease (increase) in -
                            Restricted cash                                  578            (75)         2,742
                            Receivables                                    1,664          2,594         (2,934)
                            Inventory and other                           (1,861)           206           (928)
                        (Decrease) increase in -
                            Accounts payable and accrued
                              expenses                                       103         (6,947)         2,814
                            Ad valorem taxes                              (2,255)        (1,073)         1,968
                            Unearned income                                 --           (1,435)           876
                            Income taxes payable                           1,000             --           (250)
                    ------------------------------------------------------------------------------------------
                      Net cash provided by operating activities            4,909         10,320         29,261
                    ------------------------------------------------------------------------------------------
                    CASH FLOWS FROM INVESTING ACTIVITIES:
                      Capital additions                                  (27,741)       (17,782)       (62,321)
                      Proceeds from sale of property
                        and equipment                                    125,625          3,941            847
                      Asset sale transaction costs                        (5,257)            --             --
                      Payments received on notes receivable                   --             --            136
                    ------------------------------------------------------------------------------------------
                        Net cash provided by (used in)
                         investing activities                             92,627        (13,841)       (61,338)
                    ------------------------------------------------------------------------------------------
                    CASH FLOWS FROM FINANCING ACTIVITIES:
                       Proceeds from notes payable
                         and long-term debt                                8,594          4,937         39,154
                       Principal payments on notes payable and
                         long-term debt                                  (85,517)        (5,150)       ( 3,988)
                       Proceeds from sale of stock, net                       84            --             (54)
                       Purchase of treasury stock and options               (287)           (47)           (27)
                    ------------------------------------------------------------------------------------------
                       Net cash (used in)
                         provided by financing activities                (77,126)          (260)        35,085
                    ------------------------------------------------------------------------------------------
                    INCREASE (DECREASE) IN CASH
                      AND EQUIVALENTS                                     20,410         (3,781)         3,008
                    CASH AND EQUIVALENTS,
                      beginning of year                                    1,613          5,394          2,386
                    ------------------------------------------------------------------------------------------
                    CASH AND EQUIVALENTS,
                      end of year                                        $22,023       $  1,613        $ 5,394
                    ==========================================================================================

                    The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>


                                  F-5
            BASIN EXPLORATION, INC. AND SUBSIDIARIES
            CONSOLIDATED STATEMENTS OF CASH FLOW--(CONTINUED)

                    <TABLE>
                    <CAPTION>
                    Year ended December 31,                                 1996           1995           1994
                    ------------------------------------------------------------------------------------------
                    (in thousands)
                    <S>                                                 <C>           <C>             <C>
                    SUPPLEMENTAL CASH FLOW INFORMATION:
                      Cash paid for interest                             $ 2,327       $  6,111        $ 3,095
                      Cash paid for taxes                                $    --       $     --        $   156
                    ------------------------------------------------------------------------------------------

                    The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>


                                  F-6
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

<TABLE>
<CAPTION>
                                                                                            Retained
                                                              Additional       Treasury     Earnings
For the Years Ended                          Common Stock      Paid-In           Stock    (Accumulated Stockholders'
December 31, 1996, 1995 and 1994           Shares     Amount    Capital     Shares   Amount   Deficit)     Equity
--------------------------------------------------------------------------------------------------------------------
(in thousands)

<S>                                      <C>          <C>     <C>          <C>     <C>      <C>         <C>
BALANCES, December 31, 1993               10,665       $107    $57,222       (1)    $(20)    $9,874      $67,183
Offering costs                                 -          -        (54)       -        -          -          (54)
Purchase of treasury stock                     -          -          -      (12)     (27)         -          (27)
Issuance of warrants                           -          -      1,464        -        -          -        1,464
Issuance and vesting of restricted
   stock and stock options                    27          -        354        -        -          -          354
Net income                                     -          -          -        -        -      3,655        3,655
--------------------------------------------------------------------------------------------------------------------
BALANCES, December 31, 1994               10,692        107     58,986      (13)     (47)    13,529       72,575
Purchase of treasury stock                     -          -          -      (19)     (47)         -          (47)
Issuance and vesting of restricted
   stock and stock options                    32          -        302        -        -          -          302
Net loss                                       -          -          -        -        -    (19,543)     (19,543)
--------------------------------------------------------------------------------------------------------------------
BALANCES, December 31, 1995               10,724        107     59,288      (32)     (94)    (6,014)      53,287
Purchase of treasury stock and options         -          -       (250)     (24)     (38)         -         (288)
Issuance and vesting of restricted
   stock and stock options                    33          1        181        -        -          -          182
Net income                                     -          -          -        -        -     15,570       15,570
--------------------------------------------------------------------------------------------------------------------
BALANCES, December 31, 1996               10,757      $ 108    $59,219      (56)   $(132)   $ 9,556     $ 68,751
====================================================================================================================

The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>


                                  F-7
               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, as operator of jointly
     owned oil and gas properties, sells a significant amount of such
     production to certain major customers (see Note 9), 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.

          Certain reclassifications have been made to amounts reported
     in previous years to conform to 1996 presentation.

          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.  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.

          If capitalized costs, net of amortization and related
     deferred taxes, exceed the full cost ceiling, the excess would be
     expensed in the period such excess occurs. The full cost ceiling
     includes an estimate of the discounted value of future net
     revenues attributable to proven reserves, using various
     assumptions and parameters consistent with promulgations of the
     Securities and Exchange Commission.  The full cost ceiling may be
     particularly sensitive to changes in prevailing oil and gas sales
     prices or forecast production rates.  The Company recognized
     $26,500,000 of such impairment at September 30, 1995.

          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.

          Inventory -- Inventory of lease and well equipment is stated
          ---------
     at the lower of cost or market determined using the specific
     identification method.

          Furniture and Equipment -- Furniture and equipment is
          -----------------------
     depreciated over estimated useful lives of five to seven years.
     Maintenance and repair costs are expensed as incurred.

                                  F-8

               BASIN EXPLORATION, INC. AND SUBSIDIARIES
        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)


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

          Hedging Activities --  The Company periodically enters into
          ------------------
     agreements with third parties to hedge against the effects of
     fluctuations in future oil and gas prices.  Gains or losses on
     such agreements are deferred and recognized as oil and gas
     revenue when the hedged production occurs.

          At December 31, 1996, the Company was a party to a crude oil
     swap agreement and a crude oil collar arrangement, each with a
     contract volume of 10,000 barrels per month through December 31,
     1997.  The swap agreement provides for the cash settlement of the
     differential between the $18.32 per barrel contract price and the
     average closing NYMEX crude oil price during each month.  The
     collar arrangement provides for the cash settlement of the
     differential between the monthly average closing NYMEX price and
     the contract floor of $19.50 per barrel or the contract ceiling
     of $24.35 per barrel, if the monthly average closing NYMEX price
     falls outside of the range defined by such contract floor and
     contract ceiling.  In accordance with SFAS 107, "Disclosures
     About Fair Value of Financial Instruments," the Company has
     estimated the fair value of its hedging arrangements utilizing
     the NYMEX crude oil strip at December 31, 1996.  While it is not
     the Company's intention to terminate either of the arrangements,
     it is estimated that the Company would have been required to pay
     approximately $525,000 to terminate the arrangements on December
     31, 1996.  As of February 12, 1997, the estimated cost to
     terminate such arrangements was approximately $325,000, inclusive
     of the actual cost of contract settlements through that date.
     Due to the volatility of crude oil prices, the fair market value
     may not be representative of the actual gain or loss that will be
     realized by the Company in 1997.

          The Company recognized a reduction in oil revenue of
     $480,000, $115,000 and $95,000 under hedging agreements in 1996,
     1995 and 1994, respectively.  The Company recognized a reduction
     in gas revenue of $206,000 under hedging agreements in 1994.

          Earnings (Loss) Per Share -- Earnings (loss) per share have
          -------------------------
     been computed based on the weighted average number of common
     shares outstanding.  The impact of dilutive common stock
     equivalents on earnings (loss) per share was immaterial.

(2)  RESTRICTED CASH
     ---------------

          Well Plugging -- The Company was required under a certain
          -------------
     farmout agreement to deposit in an escrow account amounts for
     future plugging and abandonment costs beyond a one-year time
     period. The total cash held in escrow at December 31, 1995, was
     $578,000.  Such escrow account was closed and the funds were
     released to the Company in November 1996.

(3)  ACQUISITIONS AND DIVESTITURES OF OIL AND GAS PROPERTIES
     -------------------------------------------------------

          In February 1996, the Company entered into agreements
     pursuant to which it sold all of its assets in the D-J Basin in
     two transactions closed in March and June 1996, for an aggregate
     sales price of $123,500,000, effective January 1, 1996.
     Combined, these transactions resulted in Basin selling its
     interests in approximately two-thirds of its producing wells and
     70% of its proved oil and gas reserves at December 31, 1995.
     Because the second transaction constituted the sale of a
     significant portion of the Company's total oil and gas reserves
     which would significantly alter the relationship between the
     Company's capitalized costs and its proved reserves, net
     capitalized costs of oil and gas properties were allocated
     between the reserves sold and retained based upon their estimated
     relative reserve quantities as of June 7, 1996 and a resulting
     gain of approximately $22,500,000 was recognized.  A portion of
     the proceeds from the sales was used to payoff all outstanding
     bank debt and residual proceeds, net of transaction costs, were
     invested in short-term interest bearing cash equivalents.
     Revenue and expenses associated with the sold properties were
     included in the Company's results of operations through the
     respective closing dates.

                                  F-9

                BASIN EXPLORATION, INC AND SUBSIDIARIES
        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

          In November 1994 the Company acquired all of the outstanding
     stock of Sterling Energy Corp. ("Sterling") for aggregate
     consideration of approximately $15.4 million consisting of
     approximately $10.1 million in cash, the assumption of $3.6
     million of net liabilities, warrants to purchase 300,000 shares
     of the Company's common stock at an exercise price of $14.00
     valued at $1.5 million, and $.2 million in transaction expenses.
     The acquisition included producing and non-producing oil and gas
     properties and undeveloped acreage located in the Scott and Draw
     fields in Converse County, Wyoming and in the Tohonadla field in
     San Juan County, Utah, as well as a gas
     processing plant located in Wyoming.  The acquisition was funded
     partially with an increased revolving credit facility.  The
     Company accounted for the Sterling acquisition using purchase
     accounting and began consolidating the results as of the December
     1994 close date.

(4)  LONG-TERM DEBT
     --------------

<TABLE>
<CAPTION>
          December 31,                                       1996           1995
          ----------------------------------------------------------------------
          (in thousands)

          <S>                                           <C>            <C>
          Revolving credit facility                      $     0        $77,000
          Other notes                                        424            347
          ---------------------------------------------------------------------
                                                             424         77,347
             Less: Current portion                          (206)          (175)
          ---------------------------------------------------------------------
          Long-term debt, net of current portion         $   218        $77,172
          =====================================================================
</TABLE>

          On August 6, 1996, the Company entered into an Amended and
     Restated Credit Agreement with its existing bank group.  The
     initial borrowing base was set at $25,000,000 and is scheduled to
     be determined as of April 30, 1997 for the following six month
     period.  The Credit Agreement provides for the interest rate on
     borrowings to be determined based on the prime rate or LIBOR, at
     the Company's election.  A varying spread above the prime rate
     ranging from 0% to 0.5% and over LIBOR ranging from 0.625% to
     1.25% will be applied based upon the Company's applicable debt-
     to-capitalization ratio.  The Credit Agreement provides for
     borrowings to be revolving loans until August 1, 1999, at which
     time the outstanding balance is scheduled to convert to a four
     year amortizing 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.  The note may be secured by the Company's oil
     and gas properties in certain circumstances, at the election of
     the lending banks.  There were no borrowings outstanding under
     the facility at December 31, 1996.

          Effective May 31, 1995, in order to improve management of
     interest rate risk, Basin entered into an interest rate swap
     agreement.  Under the agreement, the Company fixed the LIBOR
     reference rate on a notional amount of $50 million at 6 percent
     per annum through May 31, 1996.

          Debt is payable as follows:

<TABLE>
<CAPTION>
                                         (in thousands)
               ----------------------------------------
               <S>                             <C>
               1997                             $   206
               1998                                 152
               1999                                  66
               ----------------------------------------
                                                $   424
               ========================================
</TABLE>


(5)  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.  The Company may, at its
     discretion, make additional contributions to the Plan.  The
     Company expensed $96,000, $195,000, and $261,000, with respect to
     the Plan for the years ended December 31, 1996, 1995 and 1994,
     respectively.

                                 F-10

                BASIN EXPLORATION, INC AND SUBSIDIARIES
        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

          Stock Plan -- Under the Company's Employees' Equity
          ----------
     Incentive Plan and Non-Employee Directors' Stock Option Plan,
     officers, key employees, consultants and directors of the Company
     are eligible to receive incentive stock options, non-qualified
     stock options and restricted stock.  At December 31, 1996, a
     total of approximately 1,365,000 shares were available for grant
     under the plans.  Shares granted generally vest over three to
     four years, and expire after ten years.  A total of 684,000
     shares of the Company's common stock are subject to such plans as
     of December 31, 1996, including 35,000 unvested shares of
     restricted stock and 649,000 outstanding stock options.

          The following table summarizes the changes in  stock
     options:

<TABLE>
<CAPTION>
               Year Ended December 31,                 1996           1995            1994
               ---------------------------------------------------------------------------
               <S>                                <C>            <C>              <C>
               Balance, beginning of period         702,500        541,833         426,833
                Granted                             252,500        265,000         115,000
                Exercised                           (33,500)             -               -
                Forfeited/Canceled                 (272,500)      (104,333)              -
               ---------------------------------------------------------------------------
               Balance, end of period               649,000        702,500         541,833
               ===========================================================================
</TABLE>

          At December 31, 1996, the weighted average exercise price
     and weighted average remaining life for options outstanding was
     $6.55 per share and 8.3 years, respectively.  Additional
     information regarding the outstanding options at December 31,
     1996, is as follows.

<TABLE>
<CAPTION>
                                                   Number of      Number of            Range of
                                                     Options        Options     Exercise Prices
                                                 Outstanding    Exercisable           Per Share
          -------------------------------------------------------------------------------------
                                                    <C>            <C>         <C>
                                                      54,000         53,167     $11.00 - $14.50
                                                     112,500         94,167      $7.63 -  $9.50
                                                     235,000         51,667      $5.13 -  $6.88
                                                     247,500         25,833      $3.88 -  $4.94
          -------------------------------------------------------------------------------------
                                                     649,000        224,834
          =====================================================================================
</TABLE>

          In connection with its initial public offering ("IPO") in
     1992, the Company granted options to two officers to purchase
     100,000 shares each of the Company's common stock at a price
     substantially below the IPO price of $9.50 per share.  The
     Company recognized compensation expense related to these options
     of approximately $97,000 and $233,000 for the years ended
     December 31, 1995 and 1994, respectively.

          The Company granted 25,000, 32,000, and 25,000 shares of
     restricted stock during 1996, 1995 and 1994, respectively.
     Related compensation expense was recognized in the amounts of
     approximately $98,000, $205,000, and $121,000 for the years ended
     December 31, 1996, 1995, and 1994, respectively.  Cumulatively
     through December 31, 1996, 35,000 shares of restricted stock
     remained subject to forfeiture, 48,000 shares of restricted stock
     had been forfeited and 42,000 shares were no longer subject to
     restriction.

          In connection with the Sterling acquisition, the Company
     issued warrants to purchase 300,000 shares of the Company's
     common stock at an exercise price of $14.00 per share.  Such
     warrants became exercisable on October 13, 1994 and have an
     expiration date of December 31, 1999.

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

                                 F-11

               BASIN EXPLORATION, INC. AND SUBSIDIARIES
       NOTES TO CONSOLIDATED FINANCIAL STATEMENTS --(CONTINUED)


          Had the Company elected to follow SFAS 123, the fair value
     of each option grant would have been estimated on the date of
     grant using the Black-Sholes option-pricing model with the
     following weighted-average assumptions used for grants in 1996
     and 1995: risk free interest rate of 6.75%; expected dividend
     yield of 0%; expected life of 5 years; and expected volatility of
     55%.  Based upon these assumptions, the weighted average fair
     value of options granted during 1996 and 1995 was $2.73 and $2.96
     per share, respectively.  SFAS 123 would have had no significant
     impact on reported operating results for the years ended December
     31, 1996 and 1995.


(6)  COMMITMENTS AND CONTINGENCIES
     -----------------------------

          Leases -- The Company is the primary obligor under various
          ------
     noncancelable office space operating lease arrangements.  The
     Company also subleases certain office space to and from third
     parties under various noncancellable lease arrangements.  The
     following is a schedule of future minimum lease payments under
     these leases:

<TABLE>
<CAPTION>
                                                             Future minimum      Future minimum
                                                          lease obligations      lease receipts
          -------------------------------------------------------------------------------------
          (in thousands)

          <S>                                                      <C>                 <C>
          1997                                                      $   955             $   501
          1998                                                          955                 501
          1999                                                          923                 478
          2000                                                          107                  --
          -------------------------------------------------------------------------------------
                                                                    $ 2,940             $ 1,480
          =====================================================================================
</TABLE>

          Payments related to these leases obligations were
     approximately $707,000, $710,000, and $435,000 for the years
     ended December 31, 1996, 1995 and 1994, respectively.

          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 will have a material
     adverse effect on results the Company's financial condition,
     liquidity or results of operations.


(7)  INCOME TAXES
     ------------


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

<TABLE>
<CAPTION>
          Year ended December 31,                                 1996          1995           1994
          -----------------------------------------------------------------------------------------
          (in thousands)

          <S>                                                 <C>          <C>             <C>
          Current provision (benefit):
            Federal                                            $   950      $     --        $  (234)
            State                                                   50            --             --
          ------------------------------------------------------------------------------------------
                                                                 1,000            --           (234)
          ------------------------------------------------------------------------------------------
          Deferred provision (benefit):
           Federal                                               4,760        (6,970)         2,176
           State                                                    --          (814)           294
          ------------------------------------------------------------------------------------------
                                                                 4,760        (7,784)         2,470
          ------------------------------------------------------------------------------------------
          Provision (benefit) for income taxes                 $ 5,760      $ (7,784)       $ 2,236
          ==========================================================================================
</TABLE>



                                 F-12

                BASIN EXPLORATION, INC AND SUBSIDIARIES
        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)


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

<TABLE>
<CAPTION>
          Year ended December 31,                                    1996           1995        1994
          ------------------------------------------------------------------------------------------
          (in thousands)

          <S>                                                   <C>           <C>           <C>
          Income (loss) before income taxes                      $ 21,330      $ (27,327)    $ 5,891
          ==========================================================================================
          Computed tax at the applicable federal statutory rate  $  7,252      $  (9,291)    $ 2,003
          State income tax, net of federal tax benefits               704           (689)        194
          Deferred tax assets valuation allowance                  (2,196)         2,196          --
          Other                                                        --             --          39
          Income tax provision (benefit)                         $  5,760      $  (7,784)    $ 2,236
          ==========================================================================================
</TABLE>


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

<TABLE>
<CAPTION>
          December 31,                                                               1996       1995
          ------------------------------------------------------------------------------------------
          (in thousands)

          <S>                                                                   <C>        <C>
          Deferred tax liabilities:
            Oil and gas properties and equipment                                 $ 6,235    $ 2,315
          -----------------------------------------------------------------------------------------
          Deferred tax assets:
            Alternative minimum tax credit carry forward                          (1,475)      (545)
            Net operating loss carry forwards                                         --     (3,914)
            Other                                                                     --        (52)
            Less deferred tax assets valuation allowance                              --      2,196
          -----------------------------------------------------------------------------------------
                                                                                  (1,475)    (2,315)
          -----------------------------------------------------------------------------------------
          Net deferred tax liability                                              $ 4,760   $     --
          ==========================================================================================
</TABLE>

          As of December 31, 1996, the Company has alternative minimum
     tax credit carry forwards for income tax purposes of
     approximately $1,475,000 which may be utilized to reduce future
     tax liability of the Company.  These carry forwards have no
     expiration date.


(8)  RELATED PARTY TRANSACTIONS
     --------------------------

          Prior to the IPO, the Company advanced $559,000 to its
     principal stockholder at an annual interest rate of 9 percent.
     The note was amended in 1996 and the balance is now due in
     December 1997 with interest only payments due quarterly.

                                 F-13

                BASIN EXPLORATION, INC AND SUBSIDIARIES
        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)


(9)  OIL AND GAS ACTIVITIES
     ----------------------

          The Company's oil and gas operations are conducted 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.

     Purchaser
     Year ended December 31,        1996      1995      1994
     -------------------------------------------------------

     PanEnergy                       43%       62%       77%
     Eighty-Eight Oil Company        26%       16%        (a)

     (a) less than ten percent


          Section 29 Tax Credits -- The Company received $1.5 million
          ----------------------
     and $3 million in 1995 and 1994 respectively, for Section 29 tax
     credits associated with gas production from various oil and gas
     properties of the Company.  Such proceeds were recorded as
     unearned income and recognized as incremental gas revenues as the
     gas was produced and the credits earned.  The Company recognized
     approximately $2,857,000 and $2,123,000 of additional gas revenue
     during the years ended December 31, 1995 and 1994, respectively,
     related to the amortization of this unearned income.

          Costs Incurred -- Costs incurred in oil and gas operations
          --------------
     and related depreciation, depletion and amortization per
     equivalent unit-of-production are as follows:


Year Ended December 31,               1996          1995         1994
----------------------------------------------------------------------
(in thousands)

Property acquisition-
  Unproved                        $   5,056/1/   $  2,429    $   5,275
  Proved                              3,067         3,889
16,751
Exploration costs                    10,250         2,003        2,361
Development costs                     4,472         7,427       42,113
----------------------------------------------------------------------
Gross expenditures                $  22,845     $  15,748    $  66,500
======================================================================

Depletion per one thousand cubic
           feet of gas equivalent $   0.82      $    0.84    $    0.77
======================================================================

     /1/  Excludes $4,914,000 of costs recouped through the resale of
partial interests in prospects to industry partners.


          Costs Not Being Amortized -- Oil and gas property costs not
          -------------------------
     being amortized at December 31, 1996, consisted of $9,822,000 of
     leasehold and seismic costs, of which $9,058,000, $488,000 and
     $276,000 were incurred in 1996, 1995 and 1994, respectively.  The
     Company anticipates that substantially all unevaluated costs will
     be classified as evaluated costs within the next three years.

                                 F-14

               BASIN EXPLORATION, INC. AND SUBSIDIARIES
       NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
------------------------------------------------------

     The determination of oil and gas reserves is complex and highly
interpretive.  Assumptions used to estimate reserve information may
significantly increase or decrease such reserves in future periods.
The estimates of reserves are subject to continuing changes and,
therefore, an accurate determination of reserves may not be possible
for many years because of the time needed for development, drilling,
testing and studies of the reservoirs.  The following unaudited table,
based upon estimates of onshore reserves prepared by the Company's
engineers and audited by Netherland, Sewell & Associates, Inc. at
December 31, 1996, 1995 and 1994 and estimates of offshore reserves
prepared by Ryder Scott Company Petroleum Engineers at December 31,
1996, sets forth the estimated quantities of proved oil and gas
reserves for the Company and the changes in total proved reserves as
of December 31, 1996, 1995, and 1994.  All such reserves are located
in the United States.

ANALYSES OF CHANGES IN PROVED RESERVES
--------------------------------------
<TABLE>
<CAPTION>
                                                                                      OIL            GAS
---------------------------------------------------------------------------------------------------------
                                                                                    (Mbbls)        (MMcf)

<S>                                                                                <C>           <C>
Balance, December 31, 1993                                                          11,270        148,688
     Revisions                                                                        (107)        (9,539)
     Extensions, discoveries and additions                                           1,351         20,269
     Production                                                                     (1,278)       (14,377)
     Sales of reserves in-place                                                        (46)          (664)
     Purchases of reserves in-place                                                  3,951         11,953
----------------------------------------------------------------------------------------------------------
Balance, December 31, 1994                                                          15,141        156,330
     Revisions                                                                      (1,656)       (21,172)
     Extensions, discoveries and additions                                             931         10,936
     Production                                                                     (1,153)       (12,833)
     Sales of reserves in-place                                                       (751)        (4,957)
     Purchases of reserves in-place                                                     94          3,132
----------------------------------------------------------------------------------------------------------
Balance, December 31, 1995                                                          12,606        131,436
     Revisions                                                                          52           (451)
     Extensions, discoveries, and additions                                             49          6,391
     Production                                                                       (564)        (4,776)
     Sales of reserves in-place                                                     (6,559)      (104,140)
     Purchases of reserves in-place                                                  2,286          1,253
----------------------------------------------------------------------------------------------------------
Balance, December 31, 1996                                                           7,870         29,713
==========================================================================================================

Proved developed reserves -
     December 31, 1994                                                              10,544        128,664
==========================================================================================================
     December 31, 1995                                                               8,397        106,410
==========================================================================================================
     December 31, 1996                                                               4,046         19,182
==========================================================================================================
</TABLE>

STANDARDIZED MEASURE
--------------------

     The unaudited standardized measure of discounted future net cash
flows related to proved oil and gas reserves are as follows:

December 31,                           1996        1995        1994
----------------------------------------------------------------------
(in thousands)

Future production revenues         $  289,105  $  439,415  $  505,636
Future production costs              (108,522)   (155,087)   (163,244)
Future development costs              (20,583)    (45,907)    (49,293)
Future income taxes                   (39,101)    (25,644)    (45,252)
----------------------------------------------------------------------
Future net cash flows                 120,899     212,777     247,847
Discount                              (57,593)    (95,529)   (106,495)
----------------------------------------------------------------------
Standardized measure of discounted
   future net cash flows/1/        $   63,306  $  117,248   $ 141,352
======================================================================

     /1/ Total future net cash flows before income taxes discounted at
10% per annum are $83,656,000, $129,068,000 and $162,858,000 as of
December 31, 1996, 1995 and 1994, respectively.


                                 F-15

               BASIN EXPLORATION, INC. AND SUBSIDIARIES
       NOTES TO CONSOLIDATED FINANCIAL STATEMENTS --(CONTINUED)


     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>
Year Ended December 31,                                                         1996           1995           1994
-------------------------------------------------------------------------------------------------------------------
(in thousands)

<S>                                                                       <C>            <C>            <C>
Standardized measure of discounted future
  net cash flows, beginning of year                                        $  117,248     $  141,352     $  110,227
Changes in sales prices and production costs                                   17,693         (8,382)        (5,688)
Changes in estimated future
  development costs                                                            (1,819)           448          4,407
Sales of minerals-in-place                                                    (83,530)        (3,866)          (339)
Purchase of minerals-in-place                                                  10,887          2,696         26,849
Revisions of previous quantity estimates                                         (169)       (18,026)        (7,604)
Costs incurred that reduced
  future development costs                                                        --           5,422         24,421
Extensions, discoveries and
  improved recovery                                                            16,286          7,086         13,397
Sales of oil and gas, net of
  production costs and taxes                                                  (11,577)       (27,971)       (32,152)
Accretion of discount                                                          12,907         16,286         13,648
Net change in future income taxes                                              (8,530)         9,665          4,743
Changes in production rates (timing)
  and other                                                                    (6,090)        (7,462)       (10,557)
-------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted
  future net cash flows, end of year                                       $   63,306   $    117,248    $   141,352
===================================================================================================================
</TABLE>

     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 estimates.
Accordingly, reserve estimates are often different from the quantities
of oil and gas that are ultimately recovered.  Further, the estimated
future net revenues from proved reserves and the present value thereof
are based upon certain assumptions, including geologic success,
prices, future production levels and 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 and $25.35 per barrel of oil and $3.02 per Mcf of gas at December
31, 1996, $18.64 per barrel of oil and $1.56 per Mcf of gas at
December 31, 1995 and $16.44 per barrel of oil and $1.63 per Mcf of
gas at December 31, 1994.

                                 F-16

               BASIN EXPLORATION, INC. AND SUBSIDIARIES
       NOTES TO CONSOLIDATED FINANCIAL STATEMENTS --(CONTINUED)


UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA
-----------------------------------------------
(in thousands except per share amounts)(unaudited)
<TABLE>
<CAPTION>
1996                                                                 First     Second    Third     Fourth    Total
-------------------------------------------------------------------------------------------------------------------
<S>                                                                <C>       <C>       <C>       <C>       <C>
Revenue                                                             $ 7,576   $27,680   $ 3,015   $ 3,392   $41,663
Gross profit from operations                                          5,084     3,295     1,484     1,714    11,577
Net income (loss)                                                      (916)   16,375         2       109    15,570
Earnings (loss) per
 common share                                                          (.09)     1.53        --       .01      1.45
===================================================================================================================

<CAPTION>
1995
-------------------------------------------------------------------------------------------------------------------
<S>                                                                <C>       <C>       <C>       <C>       <C>
Revenue                                                             $11,535   $10,192   $ 8,661   $10,088   $40,476
Gross profit from operations                                          8,220     7,136     5,561     7,054    27,971
Net income (loss)                                                       325      (271)  (20,197)      600   (19,543)
Earnings (loss) per
 common share                                                           .03      (.02)    (1.88)      .05     (1.82)
===================================================================================================================
</TABLE>

                                 F-17
(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, 1994/7/
     2.2    --      Plan of Merger between Basin Sterling, Inc. and
                    Basin Exploration, Inc. dated November 22, 1994/8/
     2.3    --      Plan of Merger between Basin Operating Company and
                    Basin Exploration, Inc. dated December 14, 1994/8/
     3.1    --      Restated Certificate of Incorporation of Basin./2/
     3.2    --      Restated Bylaws of Basin./2/
     4.1    --      Common Stock Certificate of Basin./2/
     10.1   --      Equity Incentive Plan as amended June 6, 1996./1/
     10.2   --      Directors' Stock Option Plan as amended June 6,
                    1996./1/
     10.3   --      Key Employee Participation Plan./2/
     10.4   --      Employment Agreement dated March 31, 1992 by and
                    between Basin and Michael S. Smith./3/
     10.5   --      Gulf Coast Geoscientist Overriding Royalty
                    Interest Plan dated November 30, 1995./10/
     10.6   --      Form of Rights Agreement dated as of February 24,
                    1996, between Basin Exploration, Inc. and
                    Corporate Stock Transfer, Inc. as Rights Agent./9/
     10.7   --      Performance Shares Plan approved February 4,
                    1997./1/
     10.8   --      Change of Control Employment Agreement dated
                    October 13, 1995 between Basin Exploration, Inc.
                    and Howard L. Boigon./10/
     10.9   --      Employment Agreement dated August 28, 1995 between
                    Basin Exploration, Inc. and Samuel D.
                    Winegrad./10/
     10.10  --      Employment Agreement dated June 28, 1995 between
                    Basin Exploration, Inc. and Neil L. Stenbuck./10/
     10.11  --      Employment Agreement dated November 10, 1995
                    between Basin Exploration, Inc. and David A.
                    Pustka./10/
     10.12  --      Employment Agreement dated February 23, 1996
                    between Basin Exploration, Inc. and Thomas J.
                    Corley./1/
     10.13  --      Assignment and Assumption of Lease dated December
                    18, 1995 by and between Team, Inc., as original
                    Tenant, Basin Exploration, Inc., as New Tenant,
                    and FC Tower Property Partners, L.P., as
                    Landlord./9/
     10.14  --      First Supplement to Amended Mortgage, Security
                    Agreement, Assignment, Financing Statement and
                    Fixture Filing dated May 8, 1995 by and between
                    Basin Exploration, Inc. and Basin Gas Ltd. to
                    NationsBank of Texas, N.A., as successor
                    collateral agent for the benefit of Colorado
                    National Bank, Union Bank and NationsBank of
                    Texas, N.A./8/
     10.15  --      Second Supplement to Amended Mortgage, Security
                    Agreement, Assignment, Financing Statement and
                    Fixture Filing dated May 8, 1995 by and between
                    Basin Exploration, Inc., and Basin Gas Ltd. to
                    NationsBank of Texas, N.A. in its capacity as the
                    successor collateral agent for the benefit of
                    Colorado National Bank, Union Bank and NationsBank
                    of Texas, N.A./10/
     10.16  --      Agreement for Purchase and Sale of Assets
                    (Monetization) dated February 24, 1996 by and
                    between Basin Exploration, Inc., HS Resources,
                    Inc. and Orion Acquisition, Inc./7/
     10.17  --      Agreement for Purchase and Sale of Assets
                    (Wattenberg), dated February 24, 1996 by and
                    between Basin Exploration, Inc., HS Resources,
                    Inc. and Orion Acquisition, Inc./7/
     10.18  --      Lease of Office Space dated September 25, 1992,
                    between Brookfield Republic Inc. and Basin
                    Operating Company, as amended/4/*
     10.19  --      First Lease of Additional Office Space dated as of
                    December 1, 1994, between Brookfield Republic,
                    Inc. and Basin Operating Company./6/*
     10.20  --      Amended and Restated Credit Agreement dated August
                    6, 1996 between the Company and Colorado National
                    Bank, Union Bank of California, N.A. and
                    NationsBank of Texas, N.A./11/
     10.21  --      Purchase and Sale Agreement dated February 13,
                    1997, between Hall-Houston Oil Company et al as
                    Sellers and Basin Exploration, Inc. as Buyer./1/**
     21     --      Subsidiaries./1/
     23.1   --      Consent of Arthur Andersen LLP/1/
     23.2   --      Consent of Netherland, Sewell & Associates,
                    Inc./1/
     23.3   --      Consent of Ryder Scott Company/1/
     27     --      Financial Data Schedule./1/

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

                                  27

     /1/    Filed herewith.

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

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

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

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

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

     /7/    Filed as an Exhibit to Form 8-K filed on March 6, 1996,
            and incorporated herein by reference.

     /8/    Filed as an Exhibit to Form 10-K filed on March 28, 1995,
            and incorporated herein by reference.

     /9/    Filed as an Exhibit to Form 8-K filed on February 26,
            1996, and incorporated herein by reference.

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

     /11/   Filed as an Exhibit to Form 10-Q filed on August 14, 1996,
            and incorporated herein by reference.

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

     **     Confidential treatment has been requested for portions of
            this Exhibit.


  (b) Reports on Form 8-K

None

                                  28

                              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 17, 1997             -------------------------------------
                                 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>                      <S>                                <S>
/s/ MICHAEL S. SMITH     President, Chief Executive         March 17, 1997
----------------------------------Officer and Chairman of the
Michael S. Smith         Board (Principal Executive Officer)


/s/ HOWARD L. BOIGON     Vice President - General Counsel   March 17, 1997
----------------------------------Secretary and Director
Howard L. Boigon


/s/ NEIL L. STENBUCK     Vice President, Chief Financial    March 17, 1997
----------------------------------Officer and Director
Neil L. Stenbuck


/s/ JAMES A. TUELL       Controller, Principal Accounting   March 17, 1997
----------------------------------Officer
James A. Tuell

/s/ JOHN F. GREENE       Director                           March 17, 1997
----------------------------------
John F. Greene

/s/ J. PAUL HELLSTROM    Director                           March 17, 1997
----------------------------------
J. Paul Hellstrom

/s/ MICHAEL A. NICOLAIS  Director                           March 17, 1997
----------------------------------
Michael A. Nicolais

/s/ LARRY D. UNRUH       Director                           March 17, 1997
----------------------------------
Larry D. Unruh
</TABLE>

                                  29

                             EXHIBIT INDEX


EXHIBIT
NUMBER                 DESCRIPTION OF EXHIBITS              PAGE NO.
-------                -----------------------              --------



10.1     --    Equity Incentive Plan as amended June 6, 1996.    71

10.2     --    Directors' Stock Option Plan as amended
               June 6, 1996.                                     90

10.7     --    Performance Shares Plan approved
               February 4, 1997.                                 98

10.12    --    Employment Agreement dated February 23, 1996
               between Basin Exploration, Inc. and
               Thomas J. Corley.                                 107

10.21    --    Purchase and Sale Agreement dated
               February 13, 1997, between Hall-Houston
               Oil Company et al as Sellers and Basin
               Exploration, Inc. as Buyer.                       118

21       --    Subsidiaries                                      157

23.1     --    Consent of Arthur Andersen LLP                    158

23.2     --    Consent of Netherland, Sewell & Associates, Inc.  159

23.3     --    Consent of Ryder Scott Company                    160

27       --    Financial Data Schedule                           161


                                  30