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                                 UNITED STATES
                      SECURITIES AND EXCHANGE COMMISSION
                            WASHINGTON, D.C. 20549

                                   FORM 10-K

(Mark One)
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
   ACT OF 1934

                  For the fiscal year ended December 31, 2001

                                      OR

[_]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
   EXCHANGE ACT OF 1934

                         Commission File Number 0-9498

                         MISSION RESOURCES CORPORATION
            (Exact name of registrant as specified in its charter)

              Delaware                               76-0437769
  (State or other jurisdiction of                 (I.R.S. Employer
   incorporation or organization)               Identification No.)


  1331 Lamar, Suite 1455, Houston,                     77010
               Texas                                 (Zip Code)
  (Address of principal executive
              offices)

      Registrant's telephone number, including area code: (713) 495-3000

       Securities registered pursuant to Section 12(b) of the Act: None

          Securities registered pursuant to Section 12(g) of the Act:

     Common Stock, $0.01 par value                NASDAQ/NMS
     Preferred Stock purchase rights

   Indicate by check mark whether the registrant (1) has filed all reports
required by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months and (2) has been subject to such filing requirements
for the past 90 days. Yes [X] No [_]

   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 10-K or any amendment
to this Form 10-K. [X]

   The aggregate market value of the voting stock held by non-affiliates of
the registrant at March 21, 2002 was approximately $72,167,829.

   As of March 21, 2002, the number of outstanding shares of the registrant's
common stock was 23,585,632.

   Documents Incorporated by Reference: Portions of the registrant's annual
proxy statement, to be filed within 120 days after December 31, 2001, are
incorporated by reference into Part III.

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                 MISSION RESOURCES CORPORATION AND SUBSIDIARIES

                           Annual Report on Form 10-K
                      For the Year Ended December 31, 2001

                               TABLE OF CONTENTS

<TABLE>
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                                                                                   Page
                                                                                  Number
                                                                                  ------
<S>        <C>                                                                    <C>
PART I
  Item 1.  Business.............................................................     3
  Item 2.  Properties...........................................................     9
  Item 3.  Legal Proceedings....................................................    19
  Item 4.  Submission of Matters to a Vote of Security Holders..................    19

PART II
  Item 5.  Market for the Registrant's Common Equity and Related Stockholder
            Matters.............................................................    20
  Item 6.  Selected Financial Data..............................................    21
  Item 7.  Management's Discussion and Analysis of Financial Condition and
            Results of Operations...............................................    22
  Item 7a. Quantitative and Qualitative Disclosures About Market Risk...........    37
  Item 8.  Financial Statements and Supplementary Data..........................    39

PART III
  Item 9.  Changes in and Disagreements with Accountants on Accounting and
            Financial Disclosure................................................    79
  Item 10. Directors and Executive Officers of the Registrant...................    79
  Item 11. Executive Compensation...............................................    79
  Item 12. Security Ownership of Certain Beneficial Owners and Management.......    79
  Item 13. Certain Relationships and Related Transactions.......................    79

PART IV
  Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K......    79
  Signatures.....................................................................   86
</TABLE>

                                       2
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                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

                                    PART I

Item 1. Business

Forward Looking Statements

   This annual report on Form 10-K includes "forward-looking statements"
within the meaning of Section 27A of the Securities Act of 1933, as amended
(the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934
("Exchange Act"). All statements other than statements of historical fact are
forward-looking statements. Forward-looking statements are subject to risks
and uncertainties and include information concerning future operations.
Although we believe that in making such statements our expectations are based
upon reasonable assumptions, such statements may be influenced by factors that
could cause actual outcomes and results to be materially different from those
projected. Mission can give no assurances that the assumptions upon which
these statements are based will prove to have been correct. Important factors
that could cause actual results to differ materially from the expectations
("cautionary statements") are disclosed under Risk Factors and elsewhere
herein. All subsequent written and oral forward-looking statements
attributable to Mission or persons acting on its behalf are expressly
qualified by the cautionary statements.

General

   Mission Resources Corporation ("Mission" or the "Company") is an
independent oil and gas exploration and production company. Mission acquires,
develops and produces crude oil and natural gas primarily in the Permian Basin
of West Texas, along the Texas and Louisiana Gulf Coast and in the Gulf of
Mexico. At December 31, 2001, estimated net proved reserves, using constant
prices which were in effect at such date, totaled 39 million barrels ("MMBBL")
of oil, 2 MMBBL of natural gas liquids ("NGL"), and 154 billion cubic feet
("BCF") of natural gas for a total of 67 million barrels of oil equivalent
("MMBOE"). Approximately 62% of the estimated net proved reserves were oil or
NGL, and approximately 75% of the reserves were developed.

   In order to facilitate greater comparability with its peer group by the
financial community, Mission changed its fiscal year to the calendar year,
beginning January 1, 1998. This resulted in a six-month transition period of
July 1, 1997 through December 31, 1997.

Business Strategy

   Mission's primary business objective is to create value through expanded
reserves and production which, in turn, results in per-share increases in net
asset value, cash flow and earnings. Mission pursues this goal using a
combination of the following elements of our business strategy:

  .  Create and pursue corporate mergers and acquisitions--We continually
     evaluate opportunities to acquire attractively priced reserves, through
     corporate transactions or property acquisitions. Targeted acquisitions
     improve the quality of our property portfolio, add significant
     exploitation and exploration potential, achieve economies of scale in
     operations, and improve our exposure in the financial markets.

  .  Realize the value of core properties through exploitation and
     development--We seek to improve our success rates, reduce our finding
     and operating costs, and source prospects for development drilling by
     using an array of technologies, including 3-D seismic data, and
     reservoir stimulation modeling. Operationally, we use horizontal
     drilling, enhanced recovery methods and advanced completion and
     production techniques to be cost effective. These activities can
     increase production, cash flow and, in some cases, reserves.

  .  Employ technical expertise to pursue growth through low- to moderate-
     risk exploration--Technology-driven interdisciplinary teams composed of
     geologists, geophysicists and engineers generate and evaluate
     exploration opportunities based on 3-D seismic evaluation, seismic
     processing and modeling

                                       3
<PAGE>

    tools, and computer-aided exploration systems. Using this approach, we
    maximize the identification and quantification of opportunities and
    reduce risk through the application of complementary experience, know-how
    and technology. To limit our risk, we reduce our participation in certain
    exploratory prospects through sale of interests to industry partners.

  .  Optimize base asset operations--To reduce and control operating costs,
     we regularly review our property base to identify non-core and lower
     margin assets. These assets are divested to allow redeployment of
     capital to expand more profitable operations or to reduce outstanding
     debt. At the same time, we expand operations through selective
     acquisitions within our core areas where we have proven technical and
     management expertise.

  .  Maintain financial flexibility--Our operating objective is to keep
     capital spending within generated cash flow, and use free cash flow to
     repay bank debt. Periodically, we may refinance our bank debt when
     conditions are favorable. Given our acquisition strategy, debt levels
     will vary from time to time. Our long-term objectives are to limit debt
     levels to 50 percent of debt-to-book capitalization and maintain $100
     million of unused bank capacity. We also use commodity price hedges,
     interest rate swaps and other financial strategies to reduce financial
     risks.

2001 Merger

   On May 16, 2001, Bellwether Exploration Company ("Bellwether") merged with
Bargo Energy Company ("Bargo") and changed its name to Mission Resources
Corporation. Simultaneously with the merger, Bellwether increased its
authorized capital stock to 65.0 million shares and amended its 1996 Stock
Incentive Plan to increase the number of shares reserved for issuance under the
plan by 2.0 million shares. Under the merger agreement, holders of Bargo's
stock and options received a combination of cash and Mission common stock. The
merger was accounted for using the purchase method of accounting.

   The merger was financed through the issuance of $80.0 million in Mission
common stock to Bargo option holders and shareholders, and an initial draw down
under a new credit facility of $166.0 million used to refinance Bargo's and
Bellwether's then existing credit facilities and to pay the cash portion of the
purchase price of the Bargo common stock and options, and the amount incurred
by Bargo to redeem its preferred stock immediately prior to the merger. Mission
issued $125.0 million of additional senior subordinated notes on May 29, 2001
and used most of the net proceeds to reduce borrowings under the new credit
facility.

Oil and Gas Activities

   During 2000, after substantial analysis of its property portfolio in 1999,
Mission divested several non-core properties. By December 31, 2000, Mission had
sold approximately 6.4 MMBOE, or 17%, of its beginning of the year proved
reserves, for gross proceeds of approximately $49.0 million.

   During 2001, Mission sold several non-core domestic oil and gas properties,
its Ecuadorian interests, as discussed below, and its interests in the Snyder
and Diamond M gas plants. Gross proceeds from these transactions totaled
approximately $40.0 million. Approximately 14.3 MMBOE of proved reserves were
sold. Approximately 8 MMBOE of sold reserves were burdened by $35.0 million in
capital commitments.

Ecuador

   In December 1998, Mission was the successful bidder for the Charapa field
concession in Ecuador and, as a result, was awarded a contract for production
and exploration of crude oil in the Charapa field. The contract provided
Mission with approximately 45% of the crude oil produced above a base
production curve defined by the hydrocarbon subsidiary of the Ecuadorian
government. Mission was also entitled to recoup lease operating expenses
associated with the base production. Mission took over operations of the field
in January 2000. In February 2000, Mission took over operations of another
Ecuadorian field, the Tiguino field. The contract with the government was
similar for both fields. A Mission subsidiary operated the field on behalf of
Petroleos Colombianos ("Petrocol"), which had been granted a 25% interest and
operatorship by the Ecuadorian

                                       4
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government. Mission negotiated with Petrocol and other interest owners and by
July 2000 had increased its interest to 70% and had been assigned the field
operatorship. Final government approval of the transaction transferring
ownership and operatorship in the Tiguino field was obtained in August 2001.
Such approval was necessary for the agreements to be accepted in Ecuador.

   In June 2001, with an effective date of May 31, 2001, Mission entered into
an agreement to sell its wholly owned subsidiaries, Bellwether International
and Petrobell, to a Canadian company. Due to widening price differentials and
higher operating costs, the economics of the Ecuador investment were no longer
acceptable to Mission. The sale was contingent upon the receipt of final
government approval of the Tiguino field transfer of ownership to Petrobell.
These subsidiaries are party to the concessions of the Charapa and Tiguino
fields in Ecuador. This transaction divested Mission of all interest in
Ecuador, resulting in a net loss on the sale of $12.7 million and relieved it
of approximately $35 million in capital spending commitments. Under the
agreement, Mission retained two receivables: 1) a receivable of approximately
$900,000 to be collected out of oil sales from the partner in the Tiguino
field, and 2) a $1.0 million escrow receivable from the purchaser to be
settled before year end upon resolution of negotiations with the Ecuadorian
government concerning production levels. In the fourth quarter of 2001,
management deemed the $1.0 million receivable to be uncollectible due to a
lack of success in negotiating with the Ecuador government, increasing the
loss on the sale to $12.7 million reported in 2001.

Markets

   Mission's ability to market oil and gas from its wells depends upon
numerous domestic and international factors beyond the Company's control,
including:

  .  the extent of domestic production and imports of oil and gas,

  .  the proximity of gas production to gas pipelines,

  .  the availability of capacity in such pipelines,

  .  the demand for oil and gas by utilities and other end users,

  .  the availability of alternate fuel sources,

  .  the effects of inclement weather,

  .  state, federal and international regulation of oil and gas production,
     and

  .  federal regulation of gas sold or transported in interstate commerce.

   No assurances can be given that Mission will be able to market all of the
oil or gas it produces or that favorable prices can be obtained for the oil
and gas Mission produces. Mission from time to time may enter into crude oil
and natural gas price collars, swaps or other similar hedge transactions to
reduce its exposure to price fluctuations.

   In view of the many uncertainties affecting the supply of and demand for
oil, gas and refined petroleum products, Mission is unable to predict future
oil and gas prices and demand or the overall effect such prices and demand
will have on Mission. The marketing of oil and gas by Mission can be affected
by a number of factors, which are beyond our control, the exact effects of
which cannot be accurately predicted.

   Sales to Torch affiliates accounted for approximately 32%, 24% and 22% of
fiscal year 2001, 2000 and 1999 oil and gas revenues, respectively. The
contract with Torch was for an initial three-year term from December 1996,
renewable month to month after such term. It provided for payment of index
pricing (tied to Inside FERC postings) less gathering and transportation
charges to point of delivery. The contract was re-negotiated in mid-2001 to
remove the index pricing provision. There are no other significant delivery
commitments and substantially all of Mission's U.S. oil and gas production was
sold at market responsive pricing by a marketing affiliate of Torch, as agent
for Mission. Mission's Ecuadorian crude oil was sold to YPF and accounted for
approximately 4% and 1% of the total company oil and gas revenue for 2000 and
2001, respectively. Commencing in early 2002, sales to Torch marketing
affiliates are being replaced by sales to third parties.

                                       5
<PAGE>

Substantially all of Mission's oil and gas production will be sold at market
responsive pricing. Mission carefully reviews the creditworthiness of those
companies it chooses to contract with for oil or gas sales. Not only are
financial statements reviewed and published credit ratings verified, but each
company's overall reputation in the industry is considered. We do not believe
that the loss of any single customer or contract would materially affect
Mission's business.

Regulation

 Federal Regulations

   Transportation of Gas--Mission's sales of natural gas are affected by the
availability, terms and cost of transportation. The rates, terms and
conditions applicable to the interstate transportation of gas by pipelines are
regulated by the Federal Energy Regulatory Commission ("FERC") under the
Natural Gas Act ("NGA"), as well as under section 311 of the Natural Gas
Policy Act ("NGPA"). Since 1985, the FERC has implemented regulations intended
to increase competition within the gas industry by making gas transportation
more accessible to gas buyers and sellers on an open-access, non-
discriminatory basis.

   FERC has announced several important transportation-related policy
statements and rule changes, including a statement of policy and final rule
issued February 25, 2000, concerning alternatives to its traditional cost-of-
service rate-making methodology to establish the rates interstate pipelines
may charge for their services. The final rule revises FERC's pricing policy
and current regulatory framework to improve the efficiency of the market and
further enhance competition in natural gas markets.

   Sales and Transportation of Oil--Sales of oil and condensate can be made by
Mission at market prices and are not subject at this time to price controls.
The price received from the sale of these products will be affected by the
cost of transporting the products to market. FERC regulations govern the rates
that may be charged by oil pipelines by use of an indexing system for setting
transportation rate ceilings. In certain circumstances, the new rules permit
oil pipelines to establish rates using traditional cost of service and other
methods of rate making.

   Legislative Proposals--In the past, Congress has been very active in the
area of gas regulation. In addition, there are legislative proposals pending
in the state legislatures of various states, which, if enacted, could
significantly affect the petroleum industry. At the present time it is
impossible to predict what proposals, if any, might actually be enacted by
Congress or the various state legislatures and what effect, if any, such
proposals might have on the Mission's operations.

   Federal, State or Indian Leases--In the event that Mission conducts
operations on federal, state or Indian oil and gas leases, such operations
must comply with numerous regulatory restrictions, including various
nondiscrimination statutes, and certain of such operations must be conducted
pursuant to certain on-site security regulations and other appropriate permits
issued by the Bureau of Land Management ("BLM") or, in the case of the
Company's Outer Continental Shelf ("OCS") leases in federal waters, Minerals
Management Service ("MMS") or other appropriate federal or state agencies.
Mission's outer continental shelf leases in federal waters are administered by
the MMS and require compliance with detailed MMS regulations and orders. The
MMS has promulgated regulations implementing restrictions on various
production-related activities, including restricting the flaring or venting of
natural gas. Under certain circumstances, the MMS may require any company
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 March 15, 2000, the MMS issued a final
rule effective June 2000, which amends its regulations governing the
calculation of royalties and the valuation of crude oil produced from federal
leases. Among other matters, this rule amends the valuation procedure for the
sale of federal royalty oil by eliminating posted prices as a measure of value
and relying instead on arm's length sales prices and spot market prices as
market value indicators. Because Mission sells most of its production in the
spot market and, therefore, pays royalties on production from federal leases
based on spot prices, it is not anticipated that this final rule will have a
material impact on Mission.

                                       6
<PAGE>

   The Mineral Leasing Act of 1920 (the "Mineral Act") prohibits direct or
indirect ownership of any interest in federal onshore oil and gas leases by a
foreign citizen of a country that denies "similar or like privileges" to
citizens of the United States. Such restrictions on citizens of a "non-
reciprocal" country include ownership or holding or controlling stock in a
corporation that holds a federal onshore oil and gas lease. If this
restriction is violated, the corporation's lease can be canceled in a
proceeding instituted by the United States Attorney General. Although the
regulations of the BLM (which administers the Mineral Act) provide for agency
designations of non-reciprocal countries, there are presently no such
designations in effect. Mission owns interests in numerous federal onshore oil
and gas leases. It is possible that Mission common stock will be acquired by
citizens of foreign countries, which at some time in the future might be
determined to be non-reciprocal under the Mineral Act.

State Regulations

   General--Most states regulate the production and sale of oil and gas,
including:

  .  requirements for obtaining drilling permits,

  .  the method of developing new fields,

  .  the spacing and operation of wells and

  .  the prevention of waste of oil and gas resources.

   The rate of production may be regulated and the maximum daily production
allowable from both oil and gas wells may be established on a market demand or
conservation basis or both.

   Mission owns certain natural gas pipeline facilities that it believes meet
the traditional tests the FERC has used to establish a pipeline's status as a
gatherer not subject to FERC jurisdiction under the NGA. State regulation of
gathering facilities generally includes various safety, environmental, and in
some circumstances, nondiscriminatory take requirements, but does not
generally entail rate regulation.

Environmental Regulations

   General--Mission's activities are subject to existing federal, state and
local laws and regulations governing environmental quality and pollution
control. Activities of Mission with respect to gas facilities, including the
operation and construction of pipelines, plants and other facilities for
transporting, processing, treating or storing gas and other products, are also
subject to stringent environmental regulation by state and federal authorities
including the Environmental Protection Agency ("EPA"). Risks are inherent in
oil and gas exploration and production operations, and no assurance can be
given that significant costs and liabilities will not be incurred in
connection with environmental compliance issues. Mission also cannot predict
what effect future regulation or legislation, enforcement policies issued
thereunder, and claims for damages to property, employees, other persons and
the environment resulting from its operations could have on its activities.

   Solid and Hazardous Waste--Mission currently owns or leases, and has in the
past owned or leased, numerous properties that for many years have been used
for the exploration and production of oil and gas. Although Mission believes
it has utilized operating and waste disposal practices that were standard in
the industry at the time, hydrocarbons or other solid wastes may have been
disposed or released on or under the properties owned or leased by Mission or
on or under locations where such wastes have been taken for disposal. In
addition, many of these properties are or have been owned or operated by third
parties. Mission has had no control over such parties' treatment of
hydrocarbons or other solid wastes and the manner in which such substances may
have been disposed or released. State and federal laws applicable to oil and
gas wastes and properties have gradually become stricter over time. Under new
laws, Mission could be required to remove or remediate previously disposed
wastes (including wastes disposed or released by prior owners or operators) or
property contamination (including groundwater contamination by prior owners or
operators) or to perform remedial plugging operations to prevent future
contamination.

                                       7
<PAGE>

   Mission generates wastes, including hazardous wastes, that are subject to
the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The EPA and various state agencies have limited the disposal
options for certain wastes, including wastes designated as hazardous under
RCRA and state analogs ("Hazardous Waste"). Furthermore, it is possible that
certain wastes generated by Mission's oil and gas operations that are
currently exempt from treatment as "hazardous wastes" may in the future be
designated as "hazardous wastes" under RCRA or other applicable statutes, and
therefore be subject to more rigorous and costly operating and disposal
requirements.

   Superfund--The federal Comprehensive Environmental Response, Compensation
and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes joint
and several liability for costs of investigation and remediation and for
natural resource damages, without regard to fault or the legality of the
original conduct, on certain classes of persons with respect to the release
into the environment of substances designated under CERCLA as hazardous
substances ("Hazardous Substances"). These classes of persons or so-called
potentially responsible parties ("PRPs") include the current and certain past
owners and operators of a facility where there is or has been a release or
threat of release of a Hazardous Substance and persons who disposed of or
arranged for the disposal of the Hazardous Substances released at the site.
CERCLA also authorizes the EPA and, in some cases, third parties, to take
actions in response to threats to the public health or the environment and to
seek to recover from the PRPs the costs of such action. Although CERCLA
generally exempts "petroleum" from the definition of Hazardous Substance, in
the course of its operations, Mission has generated and will generate wastes
that may fall within CERCLA's definition of "hazardous substances." Mission
may also be an owner or operator of sites on which "hazardous substances" have
been released. Mission may be responsible under CERCLA for all or part of the
costs to investigate and remediation and natural resource damages at sites
where hazardous substances have been released. Mission, to its knowledge has
not been named a PRP under CERCLA nor does Mission know of any prior owners or
operators of its properties that are named as PRPs related to their ownership
or operation of such property.

   Clean Water Act--The Clean Water Act ("CWA") imposed restrictions and
strict controls regarding the discharge of wastes, including produced waters
and other oil and natural gas wastes, into waters of the United States, a term
broadly defined. These controls have become more stringent over the years, and
it is probable that additional restrictions will be imposed in the future.
Permits must be obtained to discharge pollutants into federal waters. The CWA
provides for civil, criminal and administrative penalties for unauthorized
discharges of pollutants and of oil or hazardous substances. State laws
governing discharges to water also provide varying civil, criminal and
administrative penalties and impose liabilities in the case of a discharge of
petroleum or its derivatives, or other hazardous substances, into state
waters. In addition, the EPA has promulgated regulations that may require us
to obtain permits to discharge storm water runoff, including discharges
associated with construction activities. In the event of an authorized
discharge of wastes, Mission may be liable for penalties and costs.

   Oil Pollution Act--The Oil Pollution Act of 1990 ("OPA"), which amends and
augments oil spill provisions of CWA, imposes certain duties and liabilities
on certain "responsible parties" related to the prevention of oil spills and
damages resulting from such spills in United States waters and adjoining
shorelines. A liable "responsible party" includes the owner or operator of a
facility or vessel that is a source of an oil discharge or poses the
substantial threat of discharge, or the lessee or permittee of the area in
which a discharging facility covered by OPA is located. OPA assigns joint and
several liability, without regard to fault, to each liable party for oil
removal costs and a variety of public and private damages. Few defenses exist
to the liability imposed by OPA. In the event of an oil discharge or
substantial threat of discharge, Mission may be liable for costs and damages.

   The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. Certain amendments to the OPA that were enacted in 1996 require owners
and operators of offshore facilities that have a worst case oil spill
potential of more than 1,000 barrels to demonstrate financial responsibility
in amounts ranging from $10 million in specified state

                                       8
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waters and $35 million in federal outer continental shelf ("OCS") waters, with
higher amounts, up to $150 million based upon worst case oil spill discharge
volume calculations. Mission believes that it currently has established
adequate proof of financial responsibility for its offshore facilities.

   Air Emissions--Mission's operations are subject to local, state and Federal
regulations for the control of emissions of air pollution. Federal and State
laws require new and modified sources of air pollutants to obtain permits
prior to commencing construction. Major sources of air pollutants are subject
to more stringent, federally imposed requirements including additional
permits. Particularly stringent requirements may be imposed on major sources
located in areas designated as not meeting National Ambient Air Quality
Standards established by the EPA. Some of Mission's facilities, particularly
those along the Gulf Coast and in California, may be in non-attainment areas,
but the specific location of these facilities is needed to make that
determination. Federal and state laws designate to control hazardous (toxic)
air pollutants, might require installation of additional controls.
Administrative enforcement actions for failure to comply strictly with air
pollution regulations or permits are generally resolved by payment of monetary
fines and correction of any identified deficiencies. Alternatively, regulatory
agencies could bring lawsuits for civil penalties or require Mission to forego
construction, modification or operation of certain air emission sources.

   Coastal Coordination--There are various federal and state programs that
regulate the conservation and development of coastal resources. The federal
Coastal Zone Management Act ("CZMA") was passed in 1972 to preserve and, where
possible, restore the natural resources of the Nation's coastal zone. The CZMA
provides for federal grants for state management programs that regulate land
use, water use and coastal development.

   In Texas, the Texas Legislature enacted the Coastal Coordination Act in
1991 ("CCA"). The CCA provides for the coordination among local and state
authorities to protect coastal resources through regulating land use, water,
and coastal development. The act establishes the Texas Coastal Management
Program (CMP). The CMP is limited to the nineteen counties that border the
Gulf of Mexico and its tidal bays. The act provides for the review of state
and federal agency rules and agency actions for consistency with the goals and
policies of the Coastal Management Plan. This review may impact agency
permitting and review activities and add an additional layer of review to
certain activities undertaken by Mission.

   OSHA and other Regulations--Mission is subject to the requirements of the
federal Occupational Safety and Health Act ("OSHA") and comparable state
statutes. The OSHA hazard communication standard, the Environmental Protection
Agency community right-to-know regulations under Title III of CERCLA and
similar state statutes require Mission to organize and/or disclose information
about hazardous materials used or produced in its operations. Mission believes
that it is in substantial compliance with these applicable requirements.

Competition

   The oil and gas industry is highly competitive in all of its phases.
Mission encounters competition from other oil and gas companies in all areas
of its operations, including the acquisition of reserves and producing
properties and the marketing of oil and gas. Many of these companies possess
greater financial and other resources than Mission. Competition for producing
properties is affected by the amount of funds available to Mission,
information about a producing property available to Mission and any standards
established by Mission for the minimum projected return on investment.
Competition may also be presented by alternate fuel sources.

Item 2. Properties

Domestic Properties

   Mission's domestic exploration, development and acquisition activities are
focused in three core areas: along the Texas/Louisiana Gulf Coast, in the
Permian Basin, and in the Gulf of Mexico. Mission primarily owns working
interests in domestic wells. The owner of a working interest is required to
pay its share of operating costs whereas the owner of royalty interests
receives a share of revenues.

                                       9
<PAGE>

   Reserve life is a measure of the productive life of an oil and gas property
or a group of oil and gas properties, expressed in years. The reserve life
index equals the estimated net proved reserves attributable to a property or
group of properties divided by production from the property or group of
properties for the four fiscal quarters preceding the date as of which the
proved reserves were estimated.

   The discounted present value is the present value, discounted at 10%, of
the pre-tax future net cash flows attributable to estimated net proved
reserves. This amount is calculated assuming the oil and gas production
attributable to the proved reserves estimated in the independent engineer's
reserve report using year end prices for production and assuming costs will
remain constant. The assumed costs are subtracted from the assumed revenues,
resulting in a stream of pre-tax future net cash flows.

   Gulf Coast--The fields in this area are located onshore in Louisiana and
Texas. These fields produce gas as the primary product. Mission owns an
interest in approximately 242 economically producing wells and the reserves
from these wells account for about 53% of the discounted present value.
Mission's average reserve life is 12 years. Mission's average working interest
in the wells is approximately 35 percent.

   Permian Basin--The fields in this area are located in West Texas and New
Mexico. The West Texas fields produce oil and the New Mexico fields produce
gas as the primary product. Mission owns an interest in approximately 3,223
economically producing wells and the reserves from these wells account for
about 29% of the discounted present value. Mission's average reserve life is
13 years. Mission's average working interest in the wells is approximately 11
percent.

   Gulf of Mexico--The fields in this area are located in state and federal
waters offshore Louisiana and Texas. These fields produce gas as the primary
product. Mission owns an interest in approximately 92 economically producing
wells and the reserves from these wells account for about 8% of the discounted
present value. Mission's average reserve life is 3 years. Mission's average
working interest in the wells is approximately 20 percent.

   Other--Non-core fields are located primarily in California, Oregon,
Oklahoma, East Texas and Wyoming. Mission owns an interest in approximately
375 economically producing wells and the reserves from these wells account for
about 10% of the discounted present value.

International Properties

   Ecuador--Mission operated two concessions in Ecuador, each of which
contained one producing field. The working interest in the Charapa field was
90% and the working interest in the Tiguino field was 70%. Oil was the only
sales product from both fields. Both fields were subject to contracts with the
Ecuador government, under which Mission had a share of production above
specified base levels. In June 2001 the interests in Ecuador properties were
sold; therefore, no Ecuadorian reserves are reported as of December 31, 2001.

Reserves

   Estimated net proved oil and gas reserves at December 31, 2001 increased
approximately 113% from December 31, 2000. Reserves of approximately 43 MMBOE
were added as a result of the May 2001 merger, and approximately 8 MMBOE were
added as a result of property acquisitions. Properties, with proved reserves
totaling 12 MMBOE, were sold during 2001. The Company has not filed oil or gas
reserve information with any foreign government or federal authority or agency
that contain reserves materially different than those presented herein.

                                      10
<PAGE>

   The following table sets forth certain information as of December 31, 2001
for Mission's core areas (dollars in thousands).

<TABLE>
<CAPTION>
                                                      Estimated Net Proved
                             Net Production(1)              Reserves
                         ------------------------- -------------------------- Discounted
                          Oil &            Oil      Oil &             Oil     Future Net
                           NGL    Gas   Equivalent   NGL     Gas   Equivalent    Cash
          Area           (MBBLS) (MMCF)   (MBOE)   (MBBLS) (MMCF)    (MBOE)    Flows(3)
          ----           ------- ------ ---------- ------- ------- ---------- ----------
<S>                      <C>     <C>    <C>        <C>     <C>     <C>        <C>
Gulf Coast..............    607   6,139   1,630     8,763   95,675   24,709    $194,615
Gulf of Mexico..........    528   8,184   1,892     1,602   20,611    5,037      27,331
Permian Basin...........  1,220   1,919   1,540    23,375   25,523   27,628     107,519
Other(2)................  1,043   1,355   1,269     7,858   12,273    9,904      35,969
                          -----  ------   -----    ------  -------   ------    --------
                          3,398  17,597   6,331    41,598  154,082   67,278    $365,434
                          =====  ======   =====    ======  =======   ======    ========
</TABLE>
--------
(1) Net production includes operations from the fields acquired from Bargo
    beginning May 16, 2001.
(2) Properties located in East Texas are included in this category.
(3) Future cash flows discounted at 10 percent.

   In general, estimates of economically recoverable oil and natural gas
reserves and of the future net cash flows therefrom are based upon a number of
factors and assumptions, such as historical production from the properties,
assumptions concerning future oil and natural gas prices, future operating
costs and the assumed effects of regulation by governmental agencies, all of
which may vary considerably from actual results. All such estimates are to
some degree speculative, and classifications of reserves are only attempts to
define the degree of speculation involved. Estimates of the economically
recoverable oil and natural gas reserves attributable to any particular group
of properties, classifications of such reserves based on risk of recovery and
estimates of future net cash flows expected therefrom, prepared by different
engineers or by the same engineers at different times, may vary substantially.
Mission's actual production, revenues, severance and excise taxes and
development and operating expenditures with respect to its reserves will vary
from such estimates, and such variances could be material.

   Estimates with respect to proved reserves that may be developed and
produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves rather than actual production history.
Estimates based on these methods are generally less reliable than those based
on actual production history. Subsequent evaluation of the same reserves based
upon production history will result in variations, which may be substantial,
in the estimated reserves.

   In accordance with applicable requirements of the Securities and Exchange
Commission ("SEC"), the estimated discounted future net cash flows from
estimated proved reserves are based on prices and costs as of the date of the
estimate unless prices or costs subsequent to that date are contractually
determined. Additionally, the impact of financial derivatives is not
considered. Actual future prices and costs may be materially higher or lower
than prices or costs as of the date of the estimate. Actual future net cash
flows also will be affected by factors such as actual production, supply and
demand for oil and natural gas, curtailments or increases in consumption by
natural gas purchasers, changes in governmental regulations or taxation and
the impact of inflation on costs.

Acreage

   The following table sets forth the developed and undeveloped oil and gas
acreage in which Mission held an interest as of December 31, 2001. Undeveloped
acreage is considered to be those leased acres 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 or not such acreage contains
proved reserves. A gross acre in the following table refers to the number of
acres in which Mission owns a working interest. The number of net acres is the
sum of the fractional ownership of working interests Mission owns in the gross
acres. A net acre is deemed to exist when the sum of fractional ownership of
working interests in gross acres equals one. All of Mission's developed and
undeveloped acreage is domestic.

                                      11
<PAGE>

<TABLE>
<CAPTION>
                                                                 Gross     Net
                                                               --------- -------
   <S>                                                         <C>       <C>
   Developed Acreage:
     Gulf Coast...............................................    92,246  30,994
     Gulf of Mexico...........................................   182,291  35,181
     Permian Basin............................................   206,448  37,721
     Other....................................................    76,751  20,536
                                                               --------- -------
       Total Developed Acreage................................   557,736 124,432
                                                               --------- -------
   Undeveloped Acreage:
     Gulf Coast...............................................    25,693  12,588
     Gulf of Mexico...........................................    52,785  17,935
     Permian Basin............................................   914,961 306,803
     Other....................................................    72,819  31,485
                                                               --------- -------
       Total Undeveloped Acreage.............................. 1,066,258 368,811
                                                               --------- -------
       Total Company Acreage.................................. 1,623,994 493,243
                                                               ========= =======
</TABLE>

   Mission believes title to its oil and gas properties is good and defensible
in accordance with standards generally accepted in the oil and gas industry,
subject to such exceptions which, in its opinion, are not so material as to
detract substantially from the use or value of such properties. Mission's
properties are typically subject, in one degree or another, to one or more of
the following:

  .  royalties;

  .  overriding royalties;

  .  a variety of contractual obligations (including, in some cases,
     development obligations) arising under operating agreements, farmout
     agreements, production sales contracts and other agreements that may
     affect the properties or their titles;

  .  back-ins and reversionary interests;

  .  liens that arise in the normal course of operations, such as those for
     unpaid taxes, statutory liens securing obligations to unpaid suppliers
     and contractors and contractual liens under operating agreements;

  .  pooling, unitization and communitization agreements, declarations and
     orders; and

  .  easements, restrictions, rights-of-way and other matters that commonly
     affect oil and gas producing property.

   To the extent that such burdens and obligations affect Mission's rights to
production revenues, they have been taken into account in calculating net
revenue interests and in estimating the size and value of Mission's reserves.
Mission believes that the burdens and obligations affecting its properties are
conventional in the industry for properties of the kind owned by Mission.

   See "Risk Factors" for a discussion of estimates of oil and gas reserves.

Productive Wells

   The following table sets forth Mission 's gross and net interests in
productive oil and gas wells as of December 31, 2001. Productive wells are
defined as producing wells and wells capable of production. Gross wells, as it
applies to wells in the following tables, refer to the number of wells in
which Mission owned a working interest. A "net well" is deemed to exist when
the sum of fractional ownership working interests in gross wells equals one.
The number of net wells is the sum of the fractional ownership of working
interests owned directly by Mission in gross wells.

                                      12
<PAGE>

<TABLE>
<CAPTION>
                                                                     Gross  Net
                                                                     ----- -----
   <S>                                                               <C>   <C>
   Oil Wells:
     Gulf Coast.....................................................   188   114
     Gulf of Mexico.................................................    74    12
     Permian Basin.................................................. 1,067   179
     Other..........................................................   384   224
                                                                     ----- -----
       Total Oil Wells.............................................. 1,713   529
                                                                     ----- -----
   Gas Wells:
     Gulf Coast.....................................................   183    62
     Gulf of Mexico.................................................   217    32
     Permian Basin.................................................. 2,422   464
     Other..........................................................   181    31
                                                                     ----- -----
       Total Gas Wells.............................................. 3,003   589
                                                                     ----- -----
       Total Wells.................................................. 4,716 1,118
                                                                     ===== =====
</TABLE>

Production

   Mission's principal production volumes during the fiscal year ended
December 31, 2001 were from the states of Louisiana, Texas, and New Mexico,
from federal waters offshore California and from federal and state waters in
the Gulf of Mexico. Because they were sold June 1, 2001, the Charapa and
Tiguino fields in Ecuador accounted for only about 2.8 % of total 2001 oil
production.

   Data relating to production volumes, average sales prices, average unit
production costs and oil and gas reserve information appears in Note 13 of the
Notes to Consolidated Financial Statements--Supplemental Information.

Drilling Activity and Present Activities

   During the last three fiscal years the Company's principal domestic
drilling activities occurred along the Texas and Louisiana Gulf Coast, in the
Gulf of Mexico, Oregon and New Mexico. Development of the Charapa and Tiguino
fields in Ecuador accounted for all international activities.

   The following tables set forth the results of drilling activity for the
last three fiscal years.

                               Exploratory Wells

<TABLE>
<CAPTION>
                                           Gross                   Net
                                   ---------------------- ----------------------
                                               Dry                    Dry
                                   Productive Holes Total Productive Holes Total
                                   ---------- ----- ----- ---------- ----- -----
   <S>                             <C>        <C>   <C>   <C>        <C>   <C>
   1999--Domestic.................      8        4    12     3.75    2.04   5.79
   2000--Domestic.................      7        6    13     3.98    1.96   5.94
   2000--Ecuador..................     --       --    --       --      --     --
   2001--Domestic.................      2        6     8     0.92    1.13   2.05

                               Development Wells

<CAPTION>
                                           Gross                   Net
                                   ---------------------- ----------------------
                                               Dry                    Dry
                                   Productive Holes Total Productive Holes Total
                                   ---------- ----- ----- ---------- ----- -----
   <S>                             <C>        <C>   <C>   <C>        <C>   <C>
   1999--Domestic.................     13        2    15     4.39    0.14   4.53
   2000--Domestic.................     46        8    54    15.01    2.70  17.71
   2000--Ecuador..................      1        3     4     0.07    2.70   3.40
   2001--Domestic.................     48        7    55    14.24    5.13  19.37
</TABLE>

   Six domestic wells were in progress as of December 31, 2001.

                                      13
<PAGE>

Gas Plants

   In late 2001, Mission sold its interests in the Snyder and Diamond M Gas
Plants for gross proceeds of $11.5 million. The Point Pedernales Gas Plant,
located in California, is operated by Nuevo Energy Company in conjunction with
the Point Pedernales field from which the processed gas is produced. Mission's
19.7% interest in this plant is no longer reported separately, primarily
because it does not process gas from third parties and therefore does not
generate revenue apart from the related Point Pedernales field. The revenues
and expenses of the plant are reported as NGL revenue and part of production
expenses for the Point Pedernales field.

Risk Factors

 Volatility of Oil and Gas Prices and Markets

   Prices for oil and gas are subject to large fluctuations in response to
relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors beyond Mission's control.
These factors include:

  .  weather conditions in the United States,

  .  the condition of the United States economy,

  .  the actions of the Organization of Petroleum Exporting Countries,

  .  governmental regulation,

  .  political stability in the Middle East and elsewhere,

  .  the foreign supply of oil and gas,

  .  the price of foreign imports, and

  .  the availability of alternate fuel sources.

   Any substantial and extended decline in the price of oil or gas would have
an adverse effect on the carrying value of Mission's proved reserves, its
borrowing capacity, its ability to obtain additional capital, and its
revenues, profitability and cash flows.

   Volatile oil and gas prices make it difficult to estimate the value of
producing properties in connection with acquisitions and often cause
disruption in the market for oil and gas producing properties as buyers and
sellers have difficulty agreeing on transaction values. Price volatility also
makes it difficult to budget for and project the return on acquisitions and
exploitation, development and exploration projects.

   The availability of a ready market for oil and natural gas production also
depends on a number of factors, including the demand for and supply of oil and
natural gas and the proximity of reserves to, and the capacity of, oil and
natural gas gathering systems, pipelines or trucking and terminal facilities.
Wells may temporarily be shut-in for lack of a market or due to inadequacy or
unavailability of pipeline or gathering system capacity.

 Ability to Replace Reserves

   Mission's future performance depends upon its ability to find, develop and
acquire additional oil and gas reserves that are economically recoverable. The
proved reserves of Mission will generally decline as those reserves are
depleted. Mission therefore must locate and develop or acquire new oil and gas
reserves to replace those being depleted by production. No assurances can be
given that Mission will be able to find and develop or acquire additional
reserves at an acceptable cost.

 Acquisition Risks

   The rapid growth of Mission and its predecessor companies in recent years
has been attributable in significant part to domestic acquisitions of oil and
gas properties. Mission expects to continue to evaluate and,

                                      14
<PAGE>

where appropriate, pursue acquisition opportunities on terms management
considers favorable to Mission. There can be no assurance that suitable
acquisition candidates will be identified in the future, or that Mission will
be able to finance such acquisitions on favorable terms. In addition, Mission
competes against other companies for acquisitions, and there can be no
assurances that it will be successful in the acquisition of any material
property interests. Further, there can be no assurances that any future
acquisitions made by Mission will be integrated successfully into its
operations or will achieve desired profitability objectives.

   The successful acquisition of producing properties requires an assessment
of:

  .  recoverable reserves,

  .  future production rates,

  .  exploration and exploitation potential and timing,

  .  future oil and natural gas prices,

  .  operating costs,

  .  infrastructure requirements,

  .  potential environmental and other liabilities and

  .  other factors beyond our control.

   In connection with such an assessment, Mission will perform a review of the
properties that it believes to be generally consistent with industry
practices. Nonetheless, the resulting assessments are inexact and their
accuracy is inherently uncertain, and such a review may not reveal all
existing or potential problems, nor will it necessarily permit Mission to
become sufficiently familiar with the properties to fully assess their merits
and deficiencies. Inspections may not always be performed on every well, and
structural and environmental problems are not necessarily observable even when
an inspection is undertaken. In addition, sellers of properties may be
unwilling or financially unable to indemnify Mission for known or unknown
liabilities at the time of an acquisition.

   Additionally, significant acquisitions can change the nature of the
operations and business of Mission depending upon the character of the
acquired properties, which may be substantially different in operating and
geologic characteristics and geographic location from existing properties.
While Mission's operations are focused in Texas, Louisiana, New Mexico and the
Gulf of Mexico, there is no assurance that Mission will not pursue
acquisitions or properties located in other geographic areas.

 Drilling Risks

   Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by Mission will be productive or that Mission
will recover all or any portion of its investment. Drilling for oil and
natural gas may involve unprofitable efforts, not only from dry wells, but
also from wells that are productive but do not produce sufficient net revenues
to return a profit after drilling, operating and other costs. The cost of
drilling, completing and operating wells is often uncertain and cost overruns
are common. Mission's drilling operations may be curtailed, delayed or
canceled as a result of numerous factors, many of which are beyond its
control, including:

  .  title problems,

  .  weather conditions,

  .  compliance with governmental requirements,

  .  shortages or delays in the delivery of equipment and services, and

  .  drilling and operations difficulties.

                                      15
<PAGE>

 Substantial Capital Requirements

   Mission makes, and will continue to make, substantial capital expenditures
for the exploitation, exploration, acquisition and production of oil and gas
reserves. Historically, Mission has financed these expenditures primarily with
the sale of senior subordinated notes, proceeds from bank borrowings, sales of
its common stock and cash flow from operations. We believe that Mission will
have sufficient cash flow provided by operating activities, the proceeds of
equity and debt offerings and borrowings under bank debt to fund planned
capital expenditures. If revenues or Mission's borrowing base decrease as a
result of lower oil and gas prices, operating difficulties or declines in
reserves, Mission may have limited ability to expend the capital necessary to
undertake or complete future drilling programs. There can be no assurance that
additional debt or equity financing or cash generated by operations will be
available to meet these requirements.

 Significant Leverage and Debt Service

   Mission's level of indebtedness has several important effects on its future
operations, including:

  .  a substantial portion of Mission's cash flow from operations must be
     dedicated to the payment of interest on its indebtedness and will not be
     available for other purposes,

  .  covenants contained in Mission's debt obligations require Mission to
     meet certain financial tests, and other restrictions limit its ability
     to borrow additional funds or dispose of assets and may affect Mission's
     flexibility in planning for, and reacting to, changes in its business,
     including possible acquisition activities, and

  .  Mission's ability to obtain financing in the future for working capital,
     capital expenditures, acquisitions, general corporate purposes or other
     purposes may be impaired.

   Mission's ability to meet its debt service obligations and to reduce its
total indebtedness will be dependent upon future performance, which will be
subject to general economic conditions and to financial, business and other
factors affecting the operations of Mission, many of which are beyond its
control. There can be no assurance that Mission's future performance will not
be adversely affected by such economic conditions and financial, business and
other factors.

 Outsourcing Agreement

   Mission currently has 27 employees. Mission is party to a Master Service
Agreement ("MSA") dated October 1, 1999, and four specific contracts which
required Torch and its subsidiaries to administer certain of Mission's
activities including oil and gas marketing, operation of oil and gas
properties, accounting, risk management, legal and information technology. At
the end of 2001 the Company gave notice to Torch that the agreements covering
accounting, risk management, legal, information technology and operation of
oil and gas properties would be cancelled or allowed to expire in 2002. We
believe that the experienced professional, technical and administrative
personnel and the access to suitable accounting and reporting systems
necessary for Mission to operate effectively can be obtained elsewhere.

 Conflicts of Interest Related to Outsourcing

   Mr. J. P. Bryan served as Chief Executive Officer of Bellwether from August
1999 through May 2000. He continues to be a member of the Mission board of
directors. Mr. Bryan is also Senior Managing Director of Torch and owns shares
representing 23% of the shares of Torch on a fully diluted basis. Mr. Bryan
also owned 1,061,750 shares of Bargo before the merger. Mr. Tim Goff, former
Chairman of Bargo and current member of Mission's board of directors, is a
non-compensated advisor to Torch regarding potential oil and gas property
acquisitions. As discussed above, Torch and subsidiaries provide outsourcing
services to Mission.

   Torch and subsidiaries render outsourcing services to other independent oil
and gas companies and may manage or render management or administrative
services for other energy companies in the future. These services

                                      16
<PAGE>

may include the review and recommendation of potential acquisitions. It is
possible that conflicts may occur between Mission and these other companies in
connection with possible acquisitions or otherwise in connection with the
services rendered by Torch. Although the MSA provides for procedures to
reconcile conflicts of interest between these other companies and Mission, no
assurances can be made that such procedures will fully protect Mission from
losses which may occur if a conflict between it and these other companies
arises.

 Estimates of Oil and Gas Reserves

   This document contains estimates of oil and gas reserves owned by Mission,
and the future net cash flows attributable to those reserves. There are
numerous uncertainties inherent in estimating quantities of proved reserves
and cash flows attributable to such reserves, including factors beyond the
control of Mission and the reserve engineers. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact manner. The accuracy of an estimate of
quantities of reserves, or of cash flows attributable to such reserves, is a
function of:

  .  the available data,

  .  assumptions regarding future oil and gas prices and expenditures for
     future development and exploitation activities, and

  .  engineering and geological interpretation and judgment.

   Additionally, reserves and future cash flows may be subject to material
downward or upward revisions based upon production history, development and
exploitation activities and prices of oil and gas. Actual future production,
revenue, taxes, development expenditures, operating expenses, quantities of
recoverable reserves and the value of cash flows from such reserves may vary
significantly from the assumptions and estimates set forth herein. In
addition, reserve engineers may make different estimates of reserves and cash
flows based on the same available data. In calculating reserves on an oil
equivalent basis, gas was converted to an oil equivalent at the ratio of one
Bbl of oil to six MCF of gas. While this ratio approximates the energy
equivalency of oil to gas on a Btu basis, it may not represent the relative
prices received by Mission on the sale of its oil and gas production.

   The estimated quantities of proved reserves and the discounted present
value of future net cash flows attributable to estimated proved reserves set
forth herein were prepared in accordance with the rules of the SEC, and are
not intended to represent the fair market value of such reserves.

 Hedging of Production

   Mission may, from time to time, reduce its exposure to the volatility of
oil and gas prices by hedging a portion of its production. In a typical hedge
transaction, Mission will have the right to receive from the counterparty to
the hedge, the excess of the fixed price specified in the hedge over a
floating price based on a market index, multiplied by the quantity hedged. If
the floating price exceeds the fixed price, Mission is required to pay the
counterparty this difference multiplied by the quantity hedged. In such case,
Mission is required to pay the difference regardless of whether it had
sufficient production to cover the quantities specified in the hedge.
Significant reductions in production at times when the floating price exceeds
the fixed price could require Mission to make payments under the hedge
agreements even though such payments are not offset by sales of production.
Hedging will also prevent Mission from receiving the full advantage of
increases in oil or gas prices above the fixed amount specified in the hedge.

 Operating Hazards, Offshore Operations and Uninsured Risks

   Mission's operations are subject to risks inherent in the oil and gas
industry, such as:

  .  blowouts,

  .  cratering,

  .  explosions,

                                      17
<PAGE>

  .  uncontrollable flows of oil, gas or well fluids,

  .  fires,

  .  pollution,

  .  earthquakes and

  .  environmental risks.

   These risks could result in substantial losses to Mission due to injury and
loss of life, severe damage to and destruction of property and equipment,
pollution and other environmental damage and suspension of operations.
Moreover, a portion of Mission's operations are offshore and therefore are
subject to a variety of operating risks which occur in to the marine
environment, such as hurricanes or other adverse weather conditions, to more
extensive governmental regulation, including regulations that may, in certain
circumstances, impose strict liability for pollution damage, and to
interruption or termination of operations by governmental authorities based on
environmental or other considerations.

   Mission's operations could result in a liability for:

  .  personal injuries

  .  property damage

  .  oil spills

  .  discharge of hazardous materials

  .  remediation and clean-up costs and other environmental damages

   Mission could be liable for environmental damages caused by previous
property owners. As a result, substantial liabilities to third parties or
governmental entities may be incurred, the payment of which could have a
material adverse effect on Mission's financial condition and results of
operations. Mission maintains insurance coverage for its operations, including
limited coverage for sudden environmental damages, but does not believe that
insurance coverage for all environmental damages that occur over time is
available at a reasonable cost. Moreover, we do not believe that insurance
coverage for the full potential liability that could be caused by sudden
environmental damages is available at a reasonable cost. Accordingly, Mission
may be subject to liability or the loss of substantial portions of its
properties in the event of certain environmental damages.

 Environmental and Other Regulation

   Mission's operations are subject to numerous laws and regulations governing
the discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations:

  .  require the acquisition of a permit before drilling commences

  .  restrict the types, quantities and concentration of various substances
     that can be released into the environment in connection with drilling
     and production activities

  .  limit or prohibit drilling activities on certain lands lying within
     wilderness, wetlands and other protected areas

  .  impose substantial liabilities for pollution resulting from the
     Company's operations

   Moreover, the recent trend toward stricter standards in environmental
legislation and regulation is likely to continue. For instance, legislation
has been proposed in Congress from time to time that would reclassify certain
oil and gas exploration and production wastes as "hazardous wastes" which
would make the reclassified wastes subject to much more stringent handling,
disposal and clean-up requirements. If such legislation were to be enacted, it
could have a significant impact on Mission's operating costs, as well as the
oil and gas industry in

                                      18
<PAGE>

general. Initiatives to further regulate the disposal of oil and gas wastes
are also pending in certain states, and these various initiatives could have a
similar impact on Mission.

   The Oil Pollution Act of 1990 imposes a variety of regulations on
"responsible parties" related to the prevention of oil spills. The
implementation of new, or the modification of existing, environmental laws or
regulations, including regulations promulgated pursuant to the Oil Pollution
Act of 1990, could have a material adverse impact on Mission.

 Competition

   The oil and gas business is highly competitive. Many competitors have
substantially larger financial resources, staffs and facilities than Mission.
These larger competitors include independent oil and gas producers such as
Apache Corporation, Burlington Resources, Inc., Anadarko Petroleum Inc., and
Ocean Energy, Inc. The availability of funds and information relating to a
property, the standards established by Mission for the minimum projected
return on investment, the availability of alternate fuel sources and the
intermediate transportation of oil and gas are factors which affect Mission's
ability to compete in the marketplace.

Item 3. Legal Proceedings

   Mission has been named as a defendant in certain lawsuits incidental to its
own business. Management does not believe that the outcome of such litigation
will have a material adverse impact on Mission.

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

     None.

                                      19
<PAGE>

                                    PART II

Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters

   Mission's common stock is traded on the NASDAQ National Market (Symbol:
MSSN). There were approximately 721 stockholders of record as of March 21,
2002. Mission has not paid dividends on its common stock and does not
anticipate the payment of cash dividends in the immediate future as it
contemplates that cash flows will be used for continued growth of our
operations. In addition, certain covenants contained in Mission's financing
arrangements restrict the payment of dividends (see Management's Discussion
and Analysis of Financial Condition and Results of Operations--Financing
Activities and Note 7 of the Notes to Consolidated Financial Statements). The
following table sets forth the range of the high and low sales prices, as
reported by the NASDAQ for Mission common stock for the periods indicated.

<TABLE>
<CAPTION>
                                                                     Sales Price
                                                                     -----------
                                                                     High   Low
                                                                     ----- -----
   <S>                                                               <C>   <C>
   Quarter Ended:
     March 31, 1999................................................. $5.56 $2.69
     June 30, 1999.................................................. $5.75 $3.19
     September 30, 1999............................................. $6.25 $4.00
     December 31, 1999.............................................. $6.19 $3.88

     March 31, 2000................................................. $7.25 $4.19
     June 30, 2000.................................................. $9.88 $5.63
     September 30, 2000............................................. $8.88 $6.69
     December 31, 2000.............................................. $8.50 $5.88

     March 31, 2001................................................. $9.75 $7.56
     June 30, 2001.................................................. $9.00 $6.70
     September 30, 2001............................................. $6.00 $3.80
     December 31, 2001.............................................. $4.14 $2.90
</TABLE>

Treasury Stock Repurchases

   In September 1998, the board of directors authorized the open market
repurchase of up to $5.0 million of Bellwether, now Mission, common stock
during 1998, at times and prices deemed attractive by management. As of
December 31, 2001, we had repurchased 311,000 shares of common stock in open
market transactions at an average purchase price of $6.13 per share. No shares
were purchased in 1999, 2000 or 2001.

                                      20
<PAGE>

Item 6. Selected Financial Data

   The following selected financial data with respect to Mission should be read
in conjunction with the Consolidated Financial Statements and supplementary
information included in Item 8 (amounts in thousands, except per share data).

<TABLE>
<CAPTION>
                                                                  Six Month
                                                                  Transition  Fiscal
                            Year      Year      Year      Year      Period     Year
                           Ended     Ended     Ended     Ended      Ended      Ended
                          Dec. 31,  Dec. 31,  Dec. 31,  Dec. 31,   Dec. 31,  June. 30,
                          2001(2)     2000      1999      1998       1997     1997(1)
                          --------  --------  --------  --------  ---------- ---------
<S>                       <C>       <C>       <C>       <C>       <C>        <C>
Gas revenues............  $ 57,705  $ 62,652  $ 41,559  $ 46,661   $ 26,849  $ 24,323
Oil revenues............    75,530    49,601    26,705    26,991     17,519    15,006
Gas plant revenues......     4,456     6,070     3,830     3,170      2,036     6,652
Interest and other
 income.................     4,386       957     1,335     1,347        609       363
                          --------  --------  --------  --------   --------  --------
  Total revenues........  $142,077  $ 19,280  $ 73,429  $ 78,169   $ 47,013  $ 46,344
Production expenses.....    51,205    30,509    21,532    25,381     13,836    11,437
Transportation costs....        73       270       316       435        205       262
Gas plant expenses......     2,118     2,677     2,366     1,967      1,232     3,322
Depreciation, depletion
 and Amortization.......    45,106    32,654    23,863    39,688     16,352    15,574
Impairment expense......    27,057        --        --    73,899         --        --
Disposition of hedges...        --     8,671        --        --         --        --
Uncollectible gas
 revenues...............     2,189        --        --        --         --        --
Mining venture costs....       914        --        --        --         --        --
Loss on sale of assets..    11,600        --        --        --         --        --
General and
 administrative
 Expenses...............    15,384     9,138     7,848     8,459      3,748     4,042
Interest expense........    23,664    15,375    11,845    11,660      5,978     4,477
Provision for income tax
 (benefit)..............    (9,055)  (12,222)   (3,154)   (6,069)     2,114     2,585
                          --------  --------  --------  --------   --------  --------
  Total expenses........   170,255    87,072    64,616   155,420     43,465    41,699
Cumulative effect of a
 change in accounting
 method, net of deferred
 taxes..................     2,767        --        --        --         --        --
                          --------  --------  --------  --------   --------  --------
Net income (loss).......  $(30,945) $ 32,208  $  8,813  $(77,251)  $  3,548  $  4,645
                          ========  ========  ========  ========   ========  ========
Earnings (loss) per
 common share...........  $ (1.54)  $   2.32  $   0.64  $  (5.50)  $   0.26  $   0.46
Earnings (loss) per
 common share--diluted..  $  (1.54) $   2.27  $   0.63  $  (5.50)  $   0.25  $   0.45
Working capital.........  $    105  $  7,212  $  3,770  $  6,077   $ 13,964  $ 22,783
Long-term debt, net of
 current Maturities(3)..  $261,695  $125,450  $130,000  $104,400   $100,000  $115,300
Stockholders' equity....  $110,240  $ 56,960  $ 23,314  $ 14,489   $ 91,669  $ 87,924
Total assets............  $447,764  $221,545  $171,761  $131,196   $214,757  $222,648
</TABLE>
--------
(1) Includes operations from the Partnership Transactions beginning April 1,
    1997.
(2) Includes operations of Bargo properties beginning May 16, 2001.
(3) Includes, at December 31, 2001, a $1.8 million, unamortized premium on the
    $125 million of bonds issued May 2001.

                                       21
<PAGE>

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

   Mission is an independent oil and gas exploration and production company.
We acquire, develop and produce crude oil and natural gas. Mission's balanced
portfolio comprises long-lived, low-risk assets, like those in the Permian
Basin, and multi-reservoir, high-productivity assets found along the Gulf
Coast and in the Gulf of Mexico. Our operational focus is on acquisitions,
property enhancement through exploitation and development drilling, low- to
moderate-risk exploration, asset redeployment and operating cost reduction.
Mission's primary business objective is to create value through expanded
reserves and production which, in turn, results in per-share increases in net
asset value, cash flow and earnings.

   On May 16, 2001, Bellwether Exploration Company merged with Bargo Energy
Company and changed its name to Mission Resources Corporation.
Contemporaneously with the merger, Bellwether increased its authorized capital
stock to 65.0 million shares and amended its 1996 Stock Incentive Plan to
increase the number of shares reserved for issuance under the plan by 2.0
million shares. Under the merger agreement, holders of Bargo's stock and
options received a combination of cash and Mission common stock. The merger
was accounted for using the purchase method of accounting.

   The merger was financed through the issuance of $80.0 million in Mission
common stock to Bargo option holders and shareholders, and an initial $166.0
million in borrowings under a new credit facility ("Credit Facility").
Borrowings under the Credit Facility were used to pay the cash portion of the
purchase price paid to holders of Bargo common stock and options; to pay the
amount incurred by Bargo in redeeming its preferred stock immediately prior to
the merger; to refinance Bargo's and Bellwether's then-existing credit
facilities; and to pay transaction costs. Mission issued $125.0 million of
additional subordinated notes on May 29, 2001 and used most of the proceeds to
reduce borrowings under the Credit Facility.

Financing Activities

   Mission's outstanding indebtedness totaled $260.0 million at December 31,
2001 with $225.0 million attributable to the 10 7/8% Senior Subordinated Notes
due in 2007 and $35.0 million outstanding under a $200.0 million senior
revolving credit facility with a three-year term.

   Mission acquired producing properties (other than the Bargo merger) for
$23.4 million during 2001, primarily using borrowings under its Credit
Facility

   Mission is party to a $200.0 million credit facility with a syndicate of
lenders. The Credit Facility is a revolving facility, which allows Mission to
borrow, repay and re-borrow under the facility from time to time. The total
amount which may be borrowed under the facility is limited by the borrowing
base periodically set by the lenders based on Mission's oil and gas reserves
and other factors deemed relevant by the lenders. At December 31, 2001,
Mission's borrowing base was $125.0 million. Borrowings under the Credit
Facility bear an annual interest rate, at Mission's election, equal to either:

  .  the Eurodollar rate, plus an applicable margin from 1.5% to 2.5%; or

  .  the greater of (1) the prime rate, as determined by Chase Manhattan
     Bank, or (2) the federal funds rate plus 0.5%, plus a maximum of 1.0%.

   The applicable margin for interest payable on outstanding borrowings is
based on (1) the utilization rate as a percentage of the total amount of funds
borrowed under the Credit Facility to the borrowing base and (2) Mission's
long term debt rating. Commitment fees and letter of credit fees under the
Credit Facility are also based on Mission's utilization rate and long term
debt rating. Commitment fees range from 0% to 0.5% on the unused portion of
the Credit Facility. Letter of credit fees range from 0% to 2.5% of the unused
portion of the $20.0 million letter of credit sub-facility.

   The Credit Facility contains negative covenants that limit Mission's
ability, among other things, to:

  .  incur additional debt;

                                      22
<PAGE>

  .  pay dividends on stock, redeem stock or redeem subordinated debt;

  .  make investments;

  .  create liens in favor of senior subordinated debt and subordinated debt;

  .  sell assets;

  .  sell capital stock of subsidiaries;

  .  guarantee other indebtedness;

  .  enter into agreements that restrict dividends from subsidiaries;

  .  merge or consolidate; and

  .  enter into transaction with affiliates.

   In addition, the Credit Facility requires that certain financial covenants
be maintained:

  .  an interest coverage ratio of earnings before interest, depreciation,
     depletion, amortization, income tax, and extraordinary items, or
     EBITDAX, to net interest expense of at least 2.5 to 1.0;

  .  an asset coverage or current ratio (which includes availability) of at
     least 1.0 to 1.0; and

  .  a ratio of total debt to EBITDAX of no more than 3.5 to 1.0.

   On December 31, 2001, the Company had outstanding borrowings of $35.0
million and was in compliance with its covenants under the Credit Facility.

   Mission met with its lenders on March 5, 2002 to discuss the re-
determination of the borrowing base applicable to the Credit Facility and
effective April 1, 2002 the borrowing base is $100.0 million. Mission also
requested amendments to its debt covenants in response to the late 2001 and
early 2002 decline in prices and their potential impact on 2002 forecast
financial results. Mission's debt covenants for the four quarters of 2002 were
amended with the required ratio of total debt to EBITDAX being increased and
the required interest coverage ratio being reduced. Currently, Mission expects
to be in compliance with such amended covenants in 2002. Borrowings at March
15, 2001, were $45.5 million outstanding under the Credit Facility, but are
expected to be reduced by March 31, 2002 due to proceeds from property sales.

   In April 1997, Mission entered into a senior revolving credit facility
("Senior Credit Facility") in an amount up to $90.0 million, with a borrowing
base of $55.0 million, and a maturity date of November 5, 2003. This Senior
Credit Facility was terminated in favor of the Credit Facility established in
conjunction with the May 16, 2001 merger with Bargo.

   In April 1997, Mission issued $100.0 million of 10 7/8% senior subordinated
notes that mature April 1, 2007. Interest is payable semi-annually on April 1
and October 1. The 10 7/8% senior subordinated notes contain certain
covenants, including limitations on:

  .  incurrence of debt,

  .  other senior subordinated indebtedness,

  .  restricted payments,

  .  liens as well as restrictions

  .  disposition of proceeds of asset sales,

  .  mergers, and

  .  consolidations or sales of assets.

                                      23
<PAGE>

   Additionally, they require Mission to offer to purchase the 10 7/8% senior
subordinated notes in the event of a change of control, as defined in the
indenture.

   In May 2001, Mission issued $125.0 million of additional 10 7/8% senior
subordinated notes due 2007 in a private offering and used most of the
proceeds to reduce borrowings under the Credit Facility. These senior
subordinated notes had terms substantially identical to Mission's senior
subordinated notes due 2007 issued in April 1997. On July 27, 2001 Mission
filed a registration statement on Form S-4 to exchange $225.0 million of
senior subordinated notes due 2007 issued in 1997 and 2001 for $225.0 million
of a new series of registered senior subordinated notes that have
substantially identical terms to the exchanged notes. That exchange was
completed in August 2001.

   Effective September 22, 1998, Mission entered into an eight and one-half
year interest rate swap agreement with a notional value of $80 million. Under
the agreement, Mission receives a fixed interest rate and pays a floating
interest rate based on the simple average of three foreign LIBOR rates.
Floating rates are re-determined for a six-month period each April 1 and
October 1. Through April 1, 2002, the floating rate is capped at 10.875% and
capped at 12.375% thereafter. The floating rate for the period from October 1,
2001 to April 1, 2002 is 9.87%. Beginning January 1, 2001, pursuant to SFAS
No. 133, the swap does not qualify for hedge accounting. Changes in its fair
value are recognized each period as a non-cash component of interest expense.

Liquidity and Capital Resources

   Mission's principal sources of capital for the last three years have been
the issuance of common stock, the sales of non-core properties, debt sources
such as the issuance of bonds or bank credit facility borrowings, and cash
flow from operations. Mission's primary uses of capital have been the funding
of acquisitions and the funding of its exploration and development projects.

 Source of Capital: Issuance of Common Stock

   Mission issued 9.5 million shares of common stock on May 16, 2001 to
holders of Bargo stock and options in order to effect the merger.
Simultaneously with the merger, authorized capital stock was increased to 65.0
million shares.

 Source of Capital: Sale of Properties

   Divestitures of non-core domestic oil and gas properties in the years 2001
and 2000 realized proceeds, after adjustment for transaction costs and interim
operations, of approximately $15.9 million and $46.0 million, respectively.
Additionally, the sale of Mission's Ecuadorian interests in June 2001 netted
approximately $4.8 million and the sale of Mission's interests in the Snyder
and Diamond M gas plants netted approximately $10.9 million. A majority of the
sales proceeds were used to pay down borrowings outstanding under the Credit
Facility.

   Mission intends to divest of additional non-core oil and gas properties in
the first quarter of 2002 for approximately $10.0 to $15.0 million and use the
proceeds to pay down borrowings under the Credit Facility. Although Mission
believes it will be able to generate the desired amount of cash from these
divestitures, it is possible that market conditions could result in the
properties being sold for more or less than originally believed. Should the
divestitures fail to generate the desired amount of cash, Mission may be
required to locate other sources of funds, which could include but are not
limited to, the sale of additional properties or additional borrowings under
its credit facility.

 Source of Capital: Debt

   Mission's outstanding balance under its 10 7/8% senior subordinated notes
was $225.0 million at December 31, 2001 and was $100.0 million at the end of
both 2000 and 1999. Borrowings from banks under Mission's revolving credit
facility were $35.0 million, $25.5 million, and $30.0 million at the end of
fiscal years

                                      24
<PAGE>

2001, 2000, and 1999, respectively. At December 31, 2001, available debt
capacity under the Credit Facility, was $90.0 million. As previously discussed
under "Financing Activities", both Mission's senior subordinated notes and its
credit facility have certain covenants limiting Mission's activities or
requiring specific financial ratios. As of December 31, 2001, Mission was in
compliance with all the covenants. For 2002, Mission has requested and its
banks have agreed to amend the financial ratio requirements. Mission expects
to be able to meet such amended requirements.

   If commodity prices were to continue declining and Mission were unable to
meet these amended requirements, then Mission would negotiate additional
amendments with the banks or obtain a temporary waiver of the covenants from
the banks. Should the banks fail to approve such actions, then Mission would
obtain the funds to repay the outstanding credit facility debt through
property sales or equity financing.

   Mission receives debt ratings from two major rating agencies in the United
States. In determining Mission's debt rating, the agencies consider a number
of items including, but not limited to, debt levels, planned asset sales,
near-term and long-term production growth opportunities, capital allocation
challenges and commodity price levels. Mission's corporate ratings are "B+" by
Standard & Poor's and "B1" by Moody's. Standard & Poor's and Moody's have put
Mission on Credit Watch--negative and on review for downgrade respectively, in
March 2002. There are no "rating triggers" in any of Mission's contractual
obligations that would accelerate scheduled maturities should Mission's debt
ratings fall below a specified level.

 Source of Capital: Operations

   Cash flow from operations before changes in assets and liabilities
("operating cash flow") totaled $44.7 million, $62.6 million, and $30.8
million for the fiscal years 2001, 2000, and 1999, respectively. Mission's
operating cash flow is sensitive to many variables, the most volatile of which
is pricing of the oil, natural gas and NGL produced. Prices for these
commodities are determined primarily by prevailing market conditions. Regional
and worldwide economic growth, weather and other variable factors influence
market conditions for these products. These factors are beyond Mission's
control and are difficult to predict.

   To mitigate some of the risk inherent in oil and natural gas prices,
Mission has entered into various price collars to set minimum and maximum
prices on a portion of its production. Mission's policy is to hedge price risk
on up to 70% of its production through such instruments. Currently, Mission
has hedged forecast production under the various arrangements shown on the
tables below.

Oil Hedges

<TABLE>
<CAPTION>
                                             BBLS                 NYMEX   NYMEX
                                              Per   Total         Price   Price
                    Period                    Day   BBLS    Type  Floor  Ceiling
                    ------                   ----- ------- ------ ------ -------
   <S>                                       <C>   <C>     <C>    <C>    <C>
   Jan. 2002-Mar. 2002...................... 6,000 540,000 Collar $21.50 $31.25
   Apr. 2002-June 2002...................... 5,400 491,400 Collar $21.50 $30.25
   Apr. 2002-June 2002......................   500  45,500 Collar $21.00 $26.25
   Apr. 2002-June 2002......................   500  45,500 Collar $26.00 $25.05
   July 2002-Sep. 2002...................... 4,700 432,400 Collar $21.50 $28.45
   July 2002-Sep. 2002......................   500  46,000 Collar $21.00 $25.03
   July 2002-Sep. 2002......................   500  46,000 Collar $21.00 $26.00
   Oct. 2002-Dec. 2002...................... 4,000 368,000 Collar $21.50 $27.15
   Oct. 2002-Dec. 2002......................   500  46,000 Collar $21.00 $25.01
   Oct. 2002-Dec. 2002......................   500  46,000 Collar $21.00 $25.25
   Jan. 2003-Mar. 2003...................... 2,500 225,000 Collar $20.50 $24.11
   Jan. 2003-Mar.2003.......................   500  45,000 Collar $21.00 $25.00
   Apr. 2003-June 2003...................... 2,500 227,500 Collar $20.50 $24.08
   Apr. 2003-June 2003......................   500  45,500 Collar $21.00 $24.65
   July 2003-Sep. 2003...................... 2,500 230,000 Collar $20.50 $24.05
   July 2003-Sep. 2003......................   500  46,000 Collar $20.50 $24.50
   Oct. 2003-Dec. 2003...................... 2,500 230,000 Collar $20.50 $24.02
   Oct. 2003-Dec. 2003......................   500  46,000 Collar $20.50 $24.25
</TABLE>

                                      25
<PAGE>

Gas Hedges

<TABLE>
<CAPTION>
                                            MCF                    NYMEX  NYMEX
                                            Per                    Price  Price
                   Period                   day   Total MCF  Type  Floro Ceiling
                   ------                  ------ --------- ------ ----- -------
   <S>                                     <C>    <C>       <C>    <C>   <C>
   Jan. 2002-Mar. 2002.................... 11,700 1,053,000 Collar $3.57  $7.00
   Apr. 2002-June 2002.................... 10,200   928,200 Collar $3.00  $6.48
   July 2002-Sep. 2002....................  9,800   901,600 Collar $3.00  $6.60
   July 2002-Sep. 2002.................... 10,000   920,000 Collar $2.50  $3.55
   Oct. 2002-Dec. 2002....................  8,500   782,000 Collar $3.40  $7.00
   Jan. 2003-Mar. 2003.................... 10,000   900,000 Collar $3.00  $4.65
   Apr. 2003-June 2003....................  5,000   455,000 Collar $3.00  $4.02
   Apr. 2003-June 2003....................  5,000   455,000 Collar $3.00  $3.97
   July 2003-Sep. 2003.................... 10,000   920,000 Collar $3.00  $4.10
   Oct. 2003-Nov. 2003.................... 10,000   920,000 Collar $3.00  $4.65
</TABLE>

   By removing the price volatility from these volumes of oil and natural gas
production, Mission has mitigated, but not eliminated, the potential negative
effect of declining prices on its operating cash flow. The potential for
increased operating cash flow due to increasing prices has also been capped.

   Immediate settlement of the Company's commodity hedges would have increased
future cash flows by $6.1 million at December 31, 2001; however the actual
settlement of such hedges will increase or decrease cash flows over the period
of the hedges.

   It is Mission's policy to only enter into derivative contracts with
investment grade rated counterparties deemed by management as competent and
competitive market makers.

 Use of Capital: Acquisitions

   The merger with Bargo, valued at $280.9 million, was the most significant
acquisition of 2001. Other domestic property acquisitions totaled $23.5
million, $7.1 million and $25.9 million for the years 2001, 2000 and 1999,
respectively. Spending related to the acquisition of the Tiguino field in
Ecuador totaled approximately $249,000 and $2.0 million in the years 2001 and
2000, respectively. Mission is continuously reviewing acquisition
opportunities. Future acquisitions would be funded through additional
borrowings under the Credit Facility or the issuance of equity securities.

 Use of Capital: Exploration and Development

   Mission's expenditures for exploration, including land and seismic costs,
and development of its oil and gas properties totaled $49.4 million, $81.3
million and $30.9 million, for the fiscal years 2001, 2000, and 1999,
respectively. Development activities in Ecuador accounted for approximately
$3.9 million and $10.0 million of expenditures in the years 2001 and 2000,
respectively.

   In December, Mission announced a capital budget for 2002 totaling $33.3
million, with $10.2 million for exploration, $14.3 million for domestic
development, and $8.8 million for seismic data, land and related items.
Mission believes its working capital and operating cash flow will be
sufficient to meet the exploration and development plans detailed in the
budget. This capital budget represents the largest planned use of available
operating cash flow. To a certain degree, the ultimate timing of these capital
expenditures is within Mission's control. Therefore, if oil and gas prices
decline to levels below its acceptable levels, Mission will choose to defer a
portion of these planned 2002 capital expenditures until later periods to
achieve the desired balance between sources and uses of liquidity. In February
2002, Mission announced that the capital budget for 2002 would be reduced to
$27.0 million due to oil and gas price declines.

                                      26
<PAGE>

Critical Accounting Policies

   In December 2001, the Securities and Exchange Commission encouraged public
companies to include in their annual report information on critical accounting
policies. These policies have been defined as those that are very important to
the portrayal of the company's financial condition or results of operations,
and require management's most difficult, subjective or complex judgements.

 Full Cost Method of Accounting for Oil and Gas Assets

   Mission uses the full cost method of accounting for its investment in oil
and gas properties. Under the full cost method of accounting, all costs of
acquisition, exploration and development of oil and gas reserves are
capitalized in a "full cost pool" as incurred. In accordance with the full
cost method, included in the capitalized full costs pool are a portion of
certain employee-related costs incurred for the purpose of finding and
developing oil and gas reserves. Employee-related costs which are directly
attributable to exploration and development are capitalized based on analysis
of time spent on these activities. Amounts capitalized can be significant with
increasing exploration and major development activities particularly in deep
waters.

   Oil and gas properties in the pool, plus estimated future expenditures to
develop proved reserves and future abandonment, site reclamation and
dismantlement costs, are depleted and charged to operations using the unit of
production method based on the ratio of current production to total proved
recoverable oil and gas reserves.

   The full cost method subjects companies to a quarterly calculation of a
"ceiling" or limitation on the amount that may be capitalized on the balance
sheet related to oil and gas properties. To the extent that capitalized costs
(net of depreciation, depletion and amortization) exceed the calculated
ceiling, the excess must be written off to expense. Once incurred, the
writedown of oil and gas properties is not reversible at a later date even if
oil and gas prices increase.

   Mission's discounted present value of its proved oil, natural gas and NGL
reserves is a major component of the ceiling calculation, and represents the
component that requires the most subjective judgements. Estimates of reserves
are forecasts based on engineering data, projected future rates of production,
and the timing of future expenditures. The process of estimating oil, natural
gas and NGL reserves requires substantial judgement, resulting in imprecise
determinations, particularly for new discoveries. Different reserve engineers
may make different estimates of reserve quantities based on the same data.
Mission's reserve estimates are prepared by outside consultants.

   The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. If future significant downward revisions reduce
previously estimated reserve quantities, it could result in a full cost
property writedown. In addition to the impact of these estimates of proved
reserves on the calculation of the ceiling, estimates of proved reserves are
also a significant component of the calculation of DD&A.

   While quantities of proved reserves require substantial judgment, the
associated prices of oil, natural gas and NGL reserves that are included in
the discounted present value of the reserves do not require judgment. The
ceiling calculation dictates that prices and costs in effect as of the last
day of the period are generally held constant indefinitely. Therefore, the
future net revenues associated with the estimated proved reserves are not
based on Mission's assessment of future prices or costs, but rather are based
on such prices and costs in effect as of the end of each quarter when the
ceiling calculation is performed. In calculating the ceiling, Mission adjusts
the end-of-period price by the effect of cash flow hedges in place.

   Because the ceiling calculation dictates that prices in effect as of the
last day of the applicable quarter are held constant indefinitely, the
resulting value is not indicative of the true fair value of the reserves. Oil
and natural gas prices have historically been variable and, on any particular
day at the end of a quarter, can be either substantially higher or lower than
Mission's long-term price forecast more indicative of true fair value. Oil and
gas property writedowns resulting from the application of the full cost
ceiling limitation, and that are caused by

                                      27
<PAGE>

fluctuation in price as opposed to reductions in the underlying quantities of
reserves, should not be viewed as absolute indicators of a reduction in the
ultimate value of the related reserves.

   Oil and gas prices declined sharply in 2001, from near record levels at the
end of 2000, significantly reducing the future net revenues attributable to
Mission's reserves. Using the year end prices of $19.76 per barrel of oil and
$2.73 per MMBTU of gas, adjusted to the wellhead by applying current price
differentials, a pretax impairment charge of $20.8 million ($13.5 million net
of tax) was calculated and recorded. No such write down was required for the
years ended December 31, 2000 and 1999.

 Fair Value of Derivative Instruments

   The estimated fair values of Mission's commodity derivative instruments are
recorded in Mission's consolidated balance sheet. All of Mission's commodity
derivative instruments represent hedges of the price of future oil and natural
gas production. While fair values of such hedging instruments must be
estimated as of the end of each reporting period, the changes in the fair
value for effective hedge instruments are not included in Mission's results of
operations. Instead, the changes in fair value of effective hedging
instruments are recorded directly to stockholders' equity until the hedged oil
or natural gas quantities are produced.

   Estimating the fair values of hedging derivatives would require Mission to
use substantial judgement using a discounted cash flow technique, including
estimates of future NYMEX prices and the appropriate discount rate, making the
resulting fair values inherently imprecise. As a result, Mission chooses to
obtain the fair value of its commodity derivatives from the counterparties to
those contracts. Since the counterparties are market makers, they are able to
provide Mission with a literal market value, or what they would be willing to
settle such contracts for as of the given date.

   Mission also obtains the fair value of its financial derivative contract,
the interest rate swap, from the counterparty to the contract. The interest
rate swap is marked to market each quarter, with any changes in fair value
recorded in earnings, because it does not qualify for hedge accounting.

 Business Combinations and Goodwill

   Mission has grown substantially during the year through the acquisition of
Bargo on May 16, 2001. This acquisition has been accounted for using the
purchase method of accounting, and recent accounting pronouncements prescribe
that all future acquisitions will be accounted for using the purchase method.

   Under the purchase method, the acquiring company adds to its balance sheet
the estimated fair values of the acquired company's assets and liabilities.
Any excess of the purchase price over the fair values of the tangible and
intangible net assets acquired is recorded as goodwill. As of January 1, 2002,
the accounting for goodwill has changed. In prior years, goodwill was
amortized over its estimated useful life. As of 2002, goodwill with an
indefinite useful life is no longer amortized, but instead is assessed for
impairment at least annually.

   There are various assumptions made by Mission in determining the fair
values of an acquired company's assets and liabilities. The most significant
assumptions, and the ones requiring the most judgment, involve the estimated
fair values of the oil and gas properties acquired. To determine the fair
values of these properties, Mission prepares estimates of oil, natural gas and
NGL reserves. These estimates are based on work performed by Mission's outside
consultants. The judgments associated with these estimated reserves are
described earlier in this section in connection with the full cost ceiling
calculation.

   However, there are factors involved in estimating the fair values of
acquired oil, natural gas and NGL properties that require more judgment than
that involved in the full cost ceiling calculation. As stated above, the full
cost ceiling calculation applies current price and cost information to the
reserves to arrive at the ceiling amount. By contrast, the fair value of
reserves acquired in a business combination must be based on Mission's
estimates of future oil, natural gas and NGL prices. In order to reduce the
impact of management judgment and

                                      28
<PAGE>

the possibly resulting inaccuracies, Mission chooses to use future price
forecasts from independent third parties, adjusted to the wellhead for its
historically realized price differentials, in estimating the fair values of
acquisitions. These estimated future prices are applied to the estimated
reserve quantities acquired to arrive at estimates of future net revenues. For
estimated proved reserves, the future net revenues are then discounted using a
15% per annum rate.

   Mission also applies these same general principles in arriving at the fair
value of unproved reserves acquired in a business combination. These unproved
reserves are generally classified as either probable or possible reserves.
Because of their very nature, probable and possible reserve estimates are more
imprecise than those of proved reserves. To compensate for the inherent risk
of estimating and valuing unproved properties, the discounted future net
revenues of probable and possible reserves are reduced by what Mission
considers to be an appropriate risk-weighting factor in each particular
instance. The probable or possible reserves are reviewed on an individual
field basis to determine the appropriate risk-weighting factor for each field.
In aggregate, the discounted future net revenues of probable and possible
reserves are reduced by factors ranging from 30% to 90% to arrive at what
Mission considers to be the appropriate fair values.

   In Mission's business combination with Bargo, the determination of the fair
values of oil and gas properties required more judgment than the fair values
of other current assets and liabilities. The future price forecasts of Goldman
Sachs, as published in January 2001, were applied to the estimated Bargo
reserve quantities obtained from Netherland, Sewell & Associates, Inc. and T.
J. Smith & Company, Inc. in order to obtain estimated future net revenues of
Bargo. The fair value of proved properties acquired was determined by
discounting the resulting estimated future net revenues at a 15% per annum
rate. The fair value of unproved reserves was determined by reducing, due to
risk, the discounted future net revenues of the probable and possible reserves
by a factor of 86%. The risking factor was an aggregate of the factors
determined for each field by Mission's engineering staff.

 Revenue Recognition

   Mission records revenues from sales of crude oil and natural gas when
delivery to the customer has occurred and title has transferred. This occurs
when production has been delivered to a pipeline or a tanker lifting has
occurred. Mission may have an interest with other producers in certain
properties. In this case, Mission uses the sales method to account for sales
of production. It is customary in the industry for various working interest
partners to sell more or less than their entitled share of natural gas
production, creating gas imbalances. Under the sales method, gas sales are
recorded when revenue checks are received or are receivable on the accrual
basis. No provision is made on the balance sheet to account for potential
amounts due to or from Mission related to gas imbalances. The settlement or
disposition of gas balancing positions as of December 31, 2001 is not
anticipated to adversely impact Mission's financial condition.

 Contractual Obligations and Commercial Commitments

   Mission is required to make future payments under contractual obligations.
The following table details those payments (amounts in thousands):

<TABLE>
<CAPTION>
    Contractual Cash
      Obligations:        Total    2002    2003    2004    2005    2006   Thereafter
    ----------------     -------- ------- ------- ------- ------- ------- ----------
<S>                      <C>      <C>     <C>     <C>     <C>     <C>     <C>
Long Term Debt*......... $353,462 $24,469 $24,469 $24,469 $24,469 $24,469  $231,117
Operating Leases........    3,820     819     597     601     601     601       601
                         -------- ------- ------- ------- ------- -------  --------
Total Contractual
 Obligations............ $357,282 $25,288 $25,066 $25,070 $25,070 $25,070  $231,718
                         ======== ======= ======= ======= ======= =======  ========
</TABLE>
--------
* Bond principle of $225.0 million scheduled for repayment in 2007. Bond
  interest is payable April 1 and October 1 of each year.

                                      29
<PAGE>

   Mission has also made various commitments in the future should certain
events occur or conditions exist. The estimated payments related to those
commitments are scheduled on the table below (amounts in thousands):

<TABLE>
<CAPTION>
 Commercial Commitments:    Total   2002   2003   2004    2005   2006  Thereafter
 -----------------------   ------- ------ ------ ------- ------ ------ ----------
 <S>                       <C>     <C>    <C>    <C>     <C>    <C>    <C>
 Line of Credit..........  $35,000 $   -- $   -- $35,000 $   -- $   --    $ --
 Other Commercial
  Commitments............   15,159  6,478  2,301   2,028  1,966  1,935     451
                           ------- ------ ------ ------- ------ ------    ----
   Total Commercial
    Commitments..........  $50,159 $6,478 $2,301 $37,028 $1,966 $1,935     451
                           ======= ====== ====== ======= ====== ======    ====
</TABLE>

                                      30
<PAGE>

Results of Operations

   The table below presents the major components of financial and operating
performance to be discussed (amounts in thousands, except average prices and
per BOE measures):

<TABLE>
<CAPTION>
                                                 Year Ended December 31,
                                                ---------------------------
                                                2001(2)     2000     1999
                                                --------  --------  -------
<S>                                             <C>       <C>       <C>
Oil and gas revenues--US......................  $131,358  $107,938  $68,264
Oil revenues--Ecuador.........................     1,877     4,315       --
Gas plant revenues............................     4,456     6,070    3,830
Interest and other............................     4,386       957    1,335
                                                --------  --------  -------
    Total revenue.............................   142,077   119,280   73,429
Production expenses--US.......................    48,134    27,694   21,515
Production expenses--Ecuador..................     3,071     2,815       17
Transportation Costs..........................        73       270      316
Gas plant expenses............................     2,118     2,677    2,366
Depreciation, depletion and amortization--US..    44,602    31,909   23,863
Depreciation, depletion and amortization--
 Ecuador......................................       504       745       --
Impairment expense............................    27,057        --       --
Disposition of hedges.........................        --     8,671       --
Uncollectible gas revenues....................     2,189        --       --
Mining venture................................       914        --       --
Loss on sale assets...........................    11,600        --       --
General and administrative expenses...........    15,384     9,138    7,848
Interest expense..............................    23,664    15,375   11,845
Income tax benefit............................    (9,055)  (12,222)  (3,154)
                                                --------  --------  -------
Net income (loss) before cumulative effect of
 changes in accounting method.................   (28,178)       --       --
                                                ========  ========  =======
Cumulative effect of a change in accounting
 method, net of deferred tax                       2,767        --       --
                                                ========  ========  =======
Net income (loss).............................  $(30,945) $ 32,208  $ 8,813
                                                ========  ========  =======
Production
  Oil and condensate (MBBLS)--US..............     3,303     2,206    2,080
  Oil and condensate (MBBLS)--Ecuador.........        95       174       -- (1)
  Natural gas (MMCF)..........................    17,597    20,478   18,965
  Oil equivalent (MBOE).......................     6,331     5,793    5,241
Average sales price, including the effect of
 hedges
  Oil and condensate (per BBL)--US............  $  22.30  $  20.53  $ 12.84
  Oil and condensate (per BBL)--Ecuador.......  $  19.76  $  24.80       -- (1)
  Natural gas (per MCF).......................  $   3.28  $   3.06  $  2.19
Average sales price, excluding the effect of
 hedges
  Oil and condensate (per BBL)--US............  $  21.81  $  24.40  $ 14.48
  Oil and condensate (per BBL)--Ecuador.......  $  19.76  $  24.80       -- (1)
  Natural gas (per MCF).......................  $   4.13  $   3.84  $  2.22
Average production expenses per BOE--US.......  $   7.72  $   4.93  $  4.11
Average production expenses per BOE--Ecuador..  $  32.33  $  16.18       -- (1)
Average G&A expenses per BOE..................  $   2.43  $   1.58  $  1.50
Average depletion rate per BOE--US............  $   6.72  $   5.46  $  4.32
Average depletion rate per BOE--Ecuador.......  $   5.31  $   4.28       -- (1)
</TABLE>
--------
(1) There was no Ecuador production in 1999.
(2) Operations of properties acquired from Bargo began May 16, 2001 and
    Ecuador operations ceased June 2001.

                                      31
<PAGE>

   Operations of the gas plants are summarized as follows:

<TABLE>
<CAPTION>
                                                           Year Ended December
                                                                   31,
                                                          ---------------------
                                                          2001(1)  2000   1999
                                                          ------- ------ ------
<S>                                                       <C>     <C>    <C>
Plant product sales volume (MBBLS).......................    203     257    241
Average product sales price per barrel................... $18.15  $20.31 $12.93
</TABLE>
--------
(1) The Snyder gas plant was sold in October 2001 and the Diamond M gas plant
    was sold in November 2001.

 Year Ended 2001 Compared to Year Ended 2000

   Net Income--Net loss for the year ended December 31, 2001 was $30.9
million, or $1.54 per share on a diluted basis, while net income for the year
ended December 31, 2000 was $32.2 million, or $2.27 per share on a diluted
basis. Decreases in oil and gas prices during the year, property impairments
and a loss on sale of assets contributed significantly to the decline in
earnings.

   Oil and Gas Revenues--Oil and gas revenues, were $133.2 million in the year
ended December 31, 2001, compared to $112.3 million for the respective period
in 2000. Total oil revenues increased to $75.5 million for the year 2001 from
$49.6 million for the year 2000. Domestic oil revenues benefited from a 9%
increase in realized oil prices from $20.53 in 2000 to $22.30 in 2001 and a
50% increase in domestic oil production from 2.2 MMBBLS in 2000 to 3.3 MMBBLS
in 2001. The improved domestic oil production was directly related to
acquisitions made in 2001, particularly the Raccoon Bend, Wasson, Levelland
and East Texas fields acquired in the Bargo merger.

   A decrease in Ecuadorian oil revenues of 57% occurred because the fields
were sold at mid-year and realized oil prices declined. Ecuadorian oil
production was 95,000 barrels, sold at $19.76, for the year 2001 compared to
174,000 barrels, sold at $24.80 for the year 2000.

   Gas revenues decreased 9% from $62.7 million in 2000 to $57.7 million in
2001. Average realized gas prices, including hedge impact, had a slightly
favorable impact, increasing 7% from $3.06 per MCF in the year ended December
31, 2000 to $3.28 per MCF in the year ended December 31, 2001. Gas production
declined 14% compared to the previous year with 17,597 MMCF and 20,478 MMCF in
the years 2001 and 2000, respectively. This decline reflects the effects of
the Company's sale of non-core short-life gas properties in 2000 combined with
its shift toward more profitable and predictable, longer-lived oil production.
The Company's Ecuador properties, sold in 2001, did not produce gas.

   The realized prices discussed above include the impact of oil and gas
hedges. A decrease of $13.4 million related to hedge activity was reflected in
oil and gas revenues for the year 2001, while a decrease in oil and gas
revenues of $24.5 million was reflected for the previous year. Ecuadorian oil
production was not hedged

   Gas Plant Revenues--Gas plant revenues were $4.5 million in 2001 compared
to $6.1 million in 2000. Contributing to this decrease was a 11% decline in
average realized plant liquid prices. Also, only 10 months of Snyder gas plant
operations and 11 months of Diamond M gas plant operations are reported in
2001 because the plants were sold within the year.

   Interest and Other Income--Interest and other income increased from
$957,000 reported for the year 2000 to $3.9 million reported for the year
2001. The primary reason for this increase is the inclusion of non-cash hedge
ineffectiveness, as computed under the requirements of SFAS. No. 133, in this
line item. A net gain from hedge ineffectiveness of $4.8 million was recorded
in 2001. Two legal settlements totaling $290,000, $325,000 related to the
Carpatsky transaction and the write off of $0.6 million of various receivables
in 2001 offset the favorable impact of hedge ineffectiveness in 2001. There
were no legal settlements in 2000 and $135,000 of receivables were written off
in 2000.

   Production Expenses--Total production expenses for the year 2001 totaled
$51.2 million compared to $30.5 million in the year 2000. On a barrel
equivalency basis, production expenses were $9.57 in 2001 and $5.27 in

                                      32
<PAGE>

2000. Domestic production expenses increased from $27.7 million in 2000 to
$48.1 million in 2001. Production taxes are included in production expense and
are calculated as a percentage of revenue in many areas; therefore, they vary
much like realized prices. Production taxes on a per BOE basis remained
essentially the same in both years. The most significant contribution to
increased production expenses is the acquisition of properties. As a result of
the acquisitions, there are more wells to operate and many are oil wells that
tend to be higher cost. Additionally, third-party oilfield service costs rose
in response to record commodity prices at the beginning of 2001 and have only
recently begun to decline. Mission has been reviewing its properties for cost
saving opportunities. Some of these opportunities require initial spending in
the form of workovers or acceleration of maintenance and repair projects in
order for future operations to benefit.

   Ecuadorian operations, which were sold in June 2001, account for $2.8
million of total production expenses in the year 2000 and $3.1 million in the
year 2001.

   Gas Plant Expenses--Gas plant expenses decreased 22% from $2.7 million in
2000 to $2.1 million in the year 2001. The decrease is related to the
reduction in gas purchase costs. Also, only 10 months of Snyder gas plant
operations and 11 months of Diamond M gas plant operations are reported in
2001 because the plants were sold within the year.

   Transportation Costs--Transportation costs were not significant in either
2001 or 2000, however the decrease in such costs from $270,000 in 2000 to
$73,000 in 2001 is due to the sale of one field in December 2000. Natural gas
transportation costs for that field were a substantial portion of Mission's
total transportation costs.

   Depreciation, Depletion and Amortization--Depreciation, depletion and
amortization ("DD&A") of domestic properties increased 40% from $31.9 million
in 2000 to $44.6 million in 2001. On a per BOE basis, DD&A increased 23%, from
$5.46 in 2000 to $6.72 in 2001, reflecting increased future development costs
associated with new reserves.

   Depletion of the Ecuadorian full cost pool for 2000 was $745,000 compared
to $504,000 in 2001. The properties were sold in June 2001.

   Impairment Expense--The non-cash impairment expense reported in 2001
consists of a $20.8 million full cost ceiling impairment and the non-recurring
write off of the Company's $6.2 million long-term receivable. The full cost
ceiling impairment is discussed in detail under "Critical Accounting Policies:
Full Cost Method of Accounting for Oil and Gas Assets". The long-term
receivable represented a production payment due from a foreign energy company
which were deemed uncollectible in the fourth quarter of 2001.

   Uncollectible Gas Revenues--Mission chose to write off as uncollectible
$2.2 million receivable from a subsidiary of Enron due to Enron's bankruptcy.

   Mining Venture--Since 1992, Mission has owned an interest in an exploratory
stage mining venture. In 2001, the $729,000 of related costs that were
reported in other assets on the December 31, 2000 Balance Sheet was a non-cash
charge to earnings, plus an additional $185,000 spent in 2001 for soil core
assays and evaluations was charged to earnings.

   Loss on Sale of Assets--The loss on sale of assets consists of a $12.7
million loss on the Company's sale of its Ecuadorian interests offset by a
$1.1 million gain on the sale of the Snyder and Diamond M gas plants.

   General and Administrative Expenses--General and administrative expenses
totaled $15.4 million in the year ended December 31, 2001 as compared to $9.1
million in the year ended December 31, 2000, for an increase of 69%. Salaries
and benefits increased $2.8 million in 2001 over 2000 levels due to Mission's
increased employee count due to the Bargo merger. Also the costs of steps to
reduce future costs, including one-time charge of $1.9 million related to
staff reductions and $620,000 related to the termination of outsourcing
contracts, contributed to the increase.

                                      33
<PAGE>

   Income Taxes--At December 31, 2000, the Company determined that it was more
likely than not that the deferred tax assets would be realized based on
current projections of taxable income due to higher commodity prices at year
end 2000, and the valuation allowance was decreased by $19.8 million to zero.
At December 31, 2001, however, the Company determined that a portion of the
deferred tax assets would not be realized. In assessing the realizability of
the deferred tax assets, management considers whether it is more likely than
not that some portion or all of the deferred tax assets will not be realized.
The ultimate realization of deferred tax assets is dependent upon the
generation of future taxable income during the periods in which those
temporary differences become deductible. Based upon the projections for future
state taxable income, management believes it is more likely than not that the
Company will not realize its deferred tax asset related to state income taxes.
Based upon the projections of future taxable income, management believes it is
more likely than not that the Company will not realize its deferred tax asset
related to the impairment in Carpatsky, as the reversal of the deferred tax
asset will result in a capital loss for federal income tax purposes, and the
Company does not project any transactions resulting in capital gains to offset
the capital loss. Therefore, the valuation allowance has been increased by
$4.3 million for the year ending December 31, 2001.

   Interest Expense--Interest expense increased 54% to $23.7 million for the
year ended December 31, 2001 from $15.4 million in the year ended December 31,
2000. Increased borrowings under the Credit Facility in 2001 due to the merger
and the additional $125.0 million of bonds issued in May 29, 2001 contributed
to the expense increase. Additionally, a set non-cash gain from the change is
fair value of Mission's interest rate swap was reported as a reduction of 2001
interest expense.

   Cumulative Effect of Change in Accounting Method--The adoption of SFAS
No.133 at January 1, 2001 resulted in the recognition of a non-cash $2.8
million loss, net of taxes, representing the cumulative effect of a change in
accounting method related to an interest rate swap that did not qualify for
hedge accounting treatment.

 Year Ended 2000 Compared to Year Ended 1999

   Net Income--Net income for the year ended December 31, 2000 was $32.2
million, or $2.27 per share on a diluted basis, compared net income for the
year ended December 31, 1999 of $8.8 million, or $0.63 per share on a diluted
basis. Significant increases in oil and gas prices were primarily responsible
for the improvement, but increased production also played a role.

   Oil and Gas Revenues--Oil and gas revenues were $112.3 million in the year
ended December 31, 2000, as compared to $68.3 million for the respective
period in 1999. Oil revenues increased to $49.6 million for the year 2000 from
$26.7 million for the year 1999. Domestic oil revenues benefited from the 60%
increase in realized oil prices from $12.84 in 1999 to $20.53 in 2000.
Improved domestic oil production was primarily due to new wells in Southwest
Louisiana and in the Gulf of Mexico. Sales of 174,000 barrels of Ecuadorian
production, primarily from the Tiguino field, at an average price of $24.80
per barrel, accounted for the remainder of the oil revenue increase. Total oil
production was 2,380,000 barrels during the year ended December 31, 2000
compared to 2,080,000 barrels for the year ended December 31, 1999.

   Gas revenues increased 51% from $41.6 million in 1999 to $62.7 million
reported in 2000. Again, prices accounted for a large portion of the increase.
Realized gas prices averaged $3.06 per MCF, or 40% higher, in the year ended
December 31, 2000 as compared to $2.19 in the year ended December 31, 1999.
Gas production was up 8% compared to the previous year with 20,478 MMCF and
18,965 MMCF in the years 2000 and 1999, respectively. The production increases
were primarily due to continued exploration and development in Texas,
Louisiana, and the Gulf of Mexico fields. Mission's Ecuador properties did not
produce gas.

   The realized prices discussed above include the impact of oil and gas
hedges. A decrease of $24.5 million related to hedge activity was reflected in
oil and gas revenues for the year 2000, while a decrease in oil and gas
revenues of $4.0 million was reflected for the previous year. For the year
2000, approximately 80% of domestic oil production and 73% of domestic gas
production was hedged. Ecuadorian oil production was not hedged.

                                      34
<PAGE>

   Mission entered into a gas swap for $4.60 per MCF on 15,000 MCF per day of
production from November 2000 through October 2001. This offset the hedges
previously existing on forecast production that was sold in late 2001. The
non-cash loss of $8.7 million was recognized in the fourth quarter of 2000
related to the $4.60 swap.

   Gas Plant Revenues--Gas plant revenues were $6.1 million in 2000, compared
to $3.8 million in 1999. A 57% increase in average realized plant liquid
prices contributed to the higher revenue.

   Production Expenses--Production expenses for the year 2000 totaled $30.5
million, as compared to $21.5 million in the year 1999. On a barrel
equivalency basis, production expenses were $5.27 per BOE in 2000 and $4.11 in
1999. Ecuadorian operations, which started in late 1999, account for $2.9
million, or $0.49 per BOE, of this increase. Most of the Ecuadorian field
expenses were non-recurring, including repair and maintenance of production
facilities and replacement of downhole pumps. Production taxes are included in
this production expense category and are calculated as a percentage of revenue
in many areas; therefore, they have increased with the increase in realized
prices, contributing $ 0.28 per BOE. Price inflation has impacted many items
like fuel, contract labor, and specialized services. Finally, the year 2000
included a number of workovers and maintenance projects in order to boost
production levels.

   Gas Plant Expenses--Gas plant expenses increased from $2.4 million in 1999
to $2.7 million in the year 2000, or 13%. Such increase is small when compared
to the 61% increase in revenues. While Snyder Gas Plant costs for purchased
natural gas increased along with commodity prices, the Diamond M plant's gas
purchase costs decreased in proportion to revenues. One of the gas plant
partners, which also provides significant quantities of gas to the plant,
elected to take its reimbursement in-kind, receiving a share of the products.

   Transportation Costs--Transportation costs were not significant in either
2000 or 1999.

   Depreciation, Depletion, and Amortization - DD&A increased 37% to $32.7
million in 2000 versus $23.9 million in 1999. Depletion of the Ecuadorian full
cost pool for this year was $745,000. Improvements in domestic production in
the year 2000 increased the absolute amount of DD&A, but accelerated capital
expenditures caused a $0.99 increase in the per BOE rate. Total company DD&A
per BOE was $5.37 and $4.32 for the years ended December 31, 2000 and 1999,
respectively.

   General and Administrative Expenses--General and administrative expenses
totaled $9.1 million in the year ended December 31, 2000 compared to $7.8
million in the year ended December 31, 1999. Significantly lower than normal
outsourcing costs in 1999 contributed to the difference. Management fees were
$2.9 million in 1999 and $4.7 million in 2000. Prior to October 1999, Mission
was charged a management fee based upon a specified percentage of the average
book value of the Company's total assets, excluding cash, plus a percentage of
operating cash flows. Due to the $73.9 million impairment charge in December
1998, the Company's total assets and resulting percentage of such assets was
reduced. In October 1999, the Company became party to a new MSA and six
specific contracts, which covered comparable outsourcing services to those
contained in the 1999 contract.

   Other significant items in general and administrative expenses included a
$1.7 million charge in 1999 due to a change in management and a $849,000 non-
cash charge in 2000 required due to the difference between exercise and grant
date prices on options awarded to the Company president.

   Interest Expense--Interest expense increased 30% to $15.4 million for the
year ended December 31, 2000 from $11.8 million in the year ended December 31,
1999. Increased interest rates and higher borrowings outstanding during the
period resulted in the increase. Although outstanding debt of $125.5 million
at December 31, 2000 was lower than the $130.0 million outstanding at December
31, 1999, most of the $30.0 million credit facility borrowings in 1999 were
incurred in the latter half of the year, whereas borrowings during 2000
reached maximums of $40.9 million. Additional expenses of $705,000 incurred in
conjunction with the credit facility amendments were also charged to interest
expense in 2000.

                                      35
<PAGE>

   Income Taxes--At December 31, 1999, the Company had a tax valuation
allowance of $19.8 million against its deferred tax assets. A portion of the
valuation allowance was recognized in 1999.In 2000, the Company determined
that it was more likely than not that the deferred assets would be realized,
based upon current projections of taxable income due to higher commodity
prices, and the valuation allowance was removed.

Other Matters

 Dividends

   At present, there is no plan to pay dividends on the common stock. Certain
restrictions contained in Mission's outstanding Notes and New Credit Facility
limit the amount of dividends that may be declared. Mission maintains a
policy, which is subject to review from time to time by the Board of
Directors, of reinvesting its discretionary cash flows for the continued
growth of the company.

 Derivative Financial Instruments

   Mission periodically uses derivative financial instruments to manage oil
and gas price risk and interest rate risk. For purposes of its hedging
activities, Mission divides product price risks into two categories,
fluctuations in the price of oil and gas on the NYMEX and fluctuations in the
difference between NYMEX prices and the price actually received by Mission for
its production (referred to as "basis differential"). From time to time
Mission enters into swap transactions in which it agrees to pay a fixed price
and the counter party to the swap agrees to pay a NYMEX based price.

   Effective September 22, 1998, the Company entered into an eight and a half-
year interest rate swap agreement with a notional value of $80.0 million.
Under the agreement, the Company receives a fixed interest rate and pays a
floating interest rate based on the simple average of three foreign LIBOR
rates. Floating rates are re-determined for a six-month period each April 1
and October 1. Through April 2002 the floating rate is capped at 10.875% and
capped at 12.375% thereafter. The floating rate for the period from October 1,
2001 to April 1, 2002 is 9.87%. Beginning in 2001, the interest rate swap did
not qualify for hedge accounting. It is marked to market quarterly.

 New Accounting Pronouncements

   In July 2001, the FASB issued Statement No. 141, Business Combinations, and
Statement No.142, Goodwill and Other Intangible Assets. Statement No. 141
requires that the purchase method of accounting be used for all business
combinations initiated after June 30, 2001 as well as all purchase method
business combinations completed after June 30, 2001. Statement No. 141 also
specifies criteria that intangible assets acquired in a purchase method
business combination must meet in order to be recognized and reported apart
from goodwill, noting that any purchase price allocable to an assembled
workforce may not be accounted for separately. Statement No. 142 will require
that goodwill and intangible assets with indefinite useful lives no longer be
amortized, but instead tested for impairment at least annually in accordance
with the provisions of Statement No. 142. Statement No. 142 will also require
that intangible assets with definite useful lives be amortized over their
respective estimated useful lives to their estimated residual values, and
reviewed for impairment in accordance with SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.
Mission is required to adopt the provisions of Statement No. 141 immediately
and Statement No. 142 effective January 1, 2002.

   As of the date of adoption, Mission expects to have unamortized goodwill in
the amount of $15.1 million and unamortized identifiable intangible assets in
the amount of $374,300, all of which will be subject to the transition
provisions of Statements No. 141 and No. 142. Amortization expense related to
goodwill was $986,000 for the period ended December 31, 2001. Upon adoption of
SFAS No. 142, amortization of goodwill and intangible assets will cease,
thereby reducing expenses by approximately $456,000 quarterly. Since such
amortization is not an allowable deduction for calculating taxes, Mission's
effective tax rate will decrease. Also,

                                      36
<PAGE>

upon adoption of SFAS No. 142, $277,000 of workforce intangible currently
recorded as unamortized identifiable intangible assets will be subsumed into
goodwill and will not be amortized as it no longer qualifies as a recognizable
intangible asset. Because of the extensive effort needed to comply with
adopting Statements No. 141 and No. 142, it is not practicable to reasonably
estimate all of the potential impacts of adopting these statements on
Mission's financial statements at the date of this report.

   In July 2001, FASB issued Statement No. 143. SFAS No. 143, Accounting for
Asset Retirement Obligations, provides accounting requirements for retirement
obligations associated with tangible long-lived assets, including:

  .  the timing of liability recognition;

  .  initial measurement of the liability;

  .  allocation of asset retirement cost to expense;

  .  subsequent measurement of the liability; and

  .  financial statement disclosures.

   SFAS No. 143 requires that asset retirement cost should be capitalized as
part of the cost of the related long-lived asset and subsequently allocated to
expense using a systematic and rational method. Mission will adopt the
statement effective January 1, 2003. The transition adjustment resulting from
the adoption of SFAS No. 143 will be reported as a cumulative effect of a
change in accounting principle. At this time, Mission cannot reasonably
estimate the effect of the adoption of this statement on either financial
position or results of operations.

   In August 2001, the FASB issued Statement No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets, which will be effective as of
January 1, 2002. SFAS No. 144 requires that long-lived assets to be disposed
of by sale be measured at the lower of the carrying amount or fair value less
cost to sell, whether reported in continuing operations or in discontinued
operations. SFAS No. 144 broadens the reporting of discontinued operations to
include all components of an entity with operations that can be distinguished
from the rest of the entity and that will be eliminated from the ongoing
operations of the entity in a disposal transaction. After its effective date,
SFAS No. 144 will be applied to those transactions where appropriate. At this
time Mission is unable to determine what the future impact of adopting this
statement will have on its financial position or results of operations.

Item 7a. Quantitative and Qualitative Disclosures About Market Risk

   Mission is exposed to market risk, including adverse changes in commodity
prices and interest rate.

   Commodity Price Risk--Mission produces and sells crude oil, natural gas and
natural gas liquids. As a result, its operating results can be significantly
affected by fluctuations in commodity prices caused by changing market forces.
Mission periodically seeks to reduce its exposure to price volatility by
hedging a portion of its production through swaps, options and other commodity
derivative instruments. A combination of options, structured as a collar, are
Mission's preferred hedge instruments because there are no up-front costs and
protection is given against low prices. These hedges assure that the revenues
Mission receives on the hedged production will be at prices no lower than the
price floor and no higher than the price ceiling.

                                      37
<PAGE>

   The following details Mission's hedges of future production that were in
place at March 15, 2002.

Oil Hedges

<TABLE>
<CAPTION>
                                           BBLS                   NYMEX   NYMEX
                                           Per     Total          Price   Price
                   Period                  Day     BBLS     Type  Floor  Ceiling
                   ------                 ------ --------- ------ ------ -------
   <S>                                    <C>    <C>       <C>    <C>    <C>
   Jan. 2002-Mar. 2002...................  6,000   540,000 Collar $21.50 $31.25
   Apr. 2002-June 2002...................  5,400   491,400 Collar $21.50 $30.25
   Apr. 2002-June 2002...................    500    45,500 Collar $21.00 $26.25
   Apr. 2002-June 2002...................    500    45,500 Collar $21.00 $25.05
   July 2002-Sep. 2002...................  4,700   432,400 Collar $21.50 $28.45
   July 2002-Sep. 2002...................    500    46,000 Collar $21.00 $25.03
   July 2002-Sep. 2002...................    500    46,000 Collar $21.00 $26.00
   Oct. 2002-Dec. 2002...................  4,000   368,000 Collar $21.50 $27.15
   Oct. 2002-Dec. 2002...................    500    46,000 Collar $21.00 $25.01
   Oct. 2002-Dec. 2002...................    500    46,000 Collar $21.00 $25.25
   Jan. 2003-Mar. 2003...................  2,500   225,000 Collar $20.50 $24.11
   Jan. 2003-Mar. 2003...................    500    45,000 Collar $21.00 $25.00
   Apr. 2003-June 2003...................  2,500   227,500 Collar $20.50 $24.08
   Apr. 2003-June 2003...................    500    45,500 Collar $21.00 $24.65
   July 2003-Sep. 2003...................  2,500   230,000 Collar $20.50 $24.05
   July 2003-Sep. 2003...................    500    46,000 Collar $20.50 $24.50
   Oct. 2003-Dec. 2003...................  2,500   230,000 Collar $20.50 $24.02
   Oct. 2003-Dec. 2003...................    500    46,000 Collar $20.50 $24.25

Gas Hedges

<CAPTION>
                                           MCF                    NYMEX   NYMEX
                                           Per                    Price   Price
                   Period                  day   Total MCF  Type  Floor  Ceiling
                   ------                 ------ --------- ------ ------ -------
   <S>                                    <C>    <C>       <C>    <C>    <C>
   Jan. 2002-Mar. 2002................... 11,700 1,053,000 Collar $ 3.57 $ 7.00
   Apr. 2002-June 2002................... 10,200   928,200 Collar $ 3.00 $ 6.48
   July 2002-Sep. 2002...................  9,800   901,600 Collar $ 3.00 $ 6.60
   July 2002-Sep. 2002................... 10,000   920,000 Collar $ 2.50 $ 3.55
   Oct. 2002-Dec. 2002...................  8,500   782,000 Collar $ 3.40 $ 7.00
   Jan. 2003-Mar. 2003................... 10,000   900,000 Collar $ 3.00 $ 4.65
   Apr. 2003-June 2003...................  5,000   455,000 Collar $ 3.00 $ 4.02
   Apr. 2003-June 2003...................  5,000   455,000 Collar $ 3.00 $ 3.97
   July 2003-Sep. 2003................... 10,000   920,000 Collar $ 3.00 $ 4.10
   Oct. 2003-Nov. 2003................... 10,000   920,000 Collar $ 3.00 $ 4.65
</TABLE>

   These commodity swap agreements expose Mission to counterparty credit risk
to the extent the counterparty is unable to met its monthly settlement
commitment to Mission. Mission believes it selects creditworthy counterparties
to its hedge transactions. Each of Mission's counterparties have long term
senior unsecured debt ratings of at least A/A2 by Standard & Poor or Moody's.

   Interest Rate Risk--Mission may enter into financial instruments such as
interest rate swaps to manage the impact of interest rates. Effective
September 22, 1998, Mission entered into an eight and one-half year interest
rate swap agreement with a notional value of $80.0 million. Under the
agreement, Mission receives a fixed interest rate and pays a floating interest
rate, subject to a cap, based on the simple average of three foreign LIBOR
rates. Floating rates are re-determined for a six-month period each April 1
and October 1. Through April 1, 2002, the floating rate is capped at 10.875%
and capped at 12.375% thereafter. The floating rate for the period from
October 1, 2001 to April 1, 2002 is 9.87%. Mission's exposure to changes in
interest rates primarily results from short-term changes in the LIBOR rates. A
10% change in the floating LIBOR rates would change interest costs to Mission
by $791,000 per year. This agreement is not held for trading purposes. The
swap provider is a major financial institution, and Mission does not
anticipate non-performance by the provider.

                                      38
<PAGE>

Item 8. Financial Statements and Supplementary Data

                  INDEX TO FINANCIAL STATEMENTS AND SCHEDULES

<TABLE>
<CAPTION>
                                                                          Page
                                                                         Number
                                                                         ------
<S>                                                                      <C>
Independent Auditors' Report............................................   41
Financial Statements:
  Consolidated Balance Sheets as of December 31, 2001 and 2000..........   42
  Consolidated Statements of Operations for the Years Ended December 31,
   2001, 2000 and 1999..................................................   44
  Consolidated Statements of Changes in Stockholders' Equity and
   Comprehensive Loss the Years Ended December 31, 2001, 2000 and 1999..   45
  Consolidated Statements of Cash Flows for the Years Ended December 31,
   2001, 2000 and 1999..................................................   46
  Notes to Consolidated Financial Statements............................   47
</TABLE>

                                       39
<PAGE>

                         INDEPENDENT AUDITORS' REPORT

The Board of Directors and Stockholders of
Mission Resources Corporation and Subsidiaries:

   We have audited the accompanying consolidated balance sheets of Mission
Resources Corporation (formerly Bellwether Exploration Company) and
subsidiaries as of December 31, 2001 and 2000 and the related consolidated
statements of operations, changes in stockholders' equity and comprehensive
loss, and cash flows for each of the years in the three-year period ended
December 31, 2001. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audits.

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

   In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Mission
Resources Corporation and subsidiaries as of December 31, 2001 and 2000 and
the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 2001 in conformity with accounting
principles generally accepted in the United States of America.

   As discussed in note 2 to the consolidated financial statements, the
Company changed its method of accounting for derivative instruments and
hedging activities in 2001.

                                          KPMG LLP

Houston, Texas
February 28, 2002

                                      40
<PAGE>

                 MISSION RESOURCES CORPORATOIN AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                      December 31, December 31,
                                                          2001         2000
                       ASSETS                         ------------ ------------
                                                       (Amounts in thousands)
<S>                                                   <C>          <C>
CURRENT ASSETS:
Cash and cash equivalents............................  $     603    $  14,464
Accounts receivable and accrued revenues.............     25,668       27,724
Current portion of interest rate swap................        180           --
Commodity derivative asset...........................      8,359           --
Notes receivable-affiliate...........................         --        1,281
Prepaid expenses and other...........................      3,879        1,189
                                                       ---------    ---------
  Total current assets...............................     38,689       44,658
                                                       ---------    ---------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties (full cost)
  United States--Unproved properties of $15,530 and
   $11,360 excluded from amortization as of December
   31, 2001 and 2000, respectively...................    753,905      421,408
  Ecuador--No unproved properties as of December 31,
   2001 and 2000, respectively.......................         --       12,988
Gas plant facilities.................................         --       18,452
                                                       ---------    ---------
                                                         753,905      452,848
Accumulated depreciation, depletion and
 amortization--oil and gas...........................   (374,167)    (296,567)
Accumulated depreciation, depletion and
 amortization--gas plant.............................         --       (7,345)
Net property, plant and equipment....................    379,738      148,936
                                                       ---------    ---------
Leasehold, furniture and equipment...................      3,347        2,782
Accumulated depreciation.............................       (916)        (404)
                                                       ---------    ---------
Net leasehold, furniture and equipment...............      2,431        2,378
                                                       ---------    ---------
LONG TERM RECEIVABLE.................................        899        4,554
GOODWILL & OTHER INTANGIBLES.........................     15,436           --
DEFERRED INCOME TAXES................................         --       15,141
OTHER ASSETS.........................................     10,571        5,878
                                                       ---------    ---------
                                                       $ 447,764    $ 221,545
                                                       =========    =========
</TABLE>


                See Notes to Consolidated Financial Statements.

                                       41
<PAGE>

                 MISSION RESOURCES CORPORATION AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                      December 31, December 31,
                                                          2001         2000
        LIABILITIES AND STOCKHOLDERS' EQUITY          ------------ ------------
                                                       (Amounts in thousands,
                                                      except share information)
<S>                                                   <C>          <C>
CURRENT LIABILITIES:
Accounts payable and accrued liabilities.............   $ 38,584     $ 29,960
Commodity derivative liabilities.....................         --        7,486
                                                        --------     --------
  Total current liabilities..........................     38,584       37,446
                                                        --------     --------
LONG-TERM DEBT, including $1.7 million unamortized
 premium on issuance of $125 million bonds...........    261,695      125,450
INTEREST RATE SWAP, excluding current portion........      4,248           --
DEFERRED INCOME TAXES................................     31,177           --
OTHER LIABILITIES....................................      1,820        1,689
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value, 5,000,000 shares
 authorized; none issued or outstanding at December
 31, 2001 and 2000...................................         --           --
  Common stock, $0.01 par value, 60,000,000 shares
   authorized, 23,896,959 and 14,259,626 shares
   issued at December 31, 2001 and December 31, 2000,
   respectively......................................        239          143
Additional paid-in capital...........................    163,735       81,892
Retained deficit.....................................    (54,115)     (23,170)
Treasury stock, at cost, 311,000 shares..............     (1,905)      (1,905)
Other comprehensive income, net of taxes.............      2,286           --
                                                        --------     --------
  Total stockholders' equity.........................    110,240       56,960
                                                        --------     --------
                                                        $447,764     $221,545
                                                        ========     ========
</TABLE>



                See Notes to Consolidated Financial Statements.

                                       42
<PAGE>

                 MISSION RESOURCES CORPORATION AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
                                          Year Ended   Year Ended   Year Ended
                                         December 31, December 31, December 31,
                                             2001         2000         1999
                                         ------------ ------------ ------------
                                           (Amounts in thousands, except per
                                                      share data)
<S>                                      <C>          <C>          <C>
REVENUES:
  Gas revenues.........................    $ 57,705     $ 62,652     $41,559
  Oil revenues--United States..........      73,653       45,286      26,705
  Oil revenues--Ecuador................       1,877        4,315          --
  Gas plant revenues...................       4,456        6,070       3,830
  Interest and other income............       4,386          957       1,335
                                           --------     --------     -------
                                            142,077      119,280      73,429
                                           --------     --------     -------
COSTS AND EXPENSES:
  Production expenses--United States...      48,134       27,694      21,515
  Production expenses--Ecuador.........       3,071        2,815          17
  Transportation costs.................          73          270         316
  Gas plant expenses...................       2,118        2,677       2,366
  Depreciation, depletion and
   amortization--United States.........      44,602       31,909      23,863
  Depreciation, depletion and
   amortization--Ecuador...............         504          745          --
  Impairment expense...................      27,057           --          --
  Disposition of hedges................          --        8,671          --
  Uncollectible gas revenues...........       2,189           --          --
  Mining venture.......................         914           --          --
  Loss on sale of assets...............      11,600           --          --
  General and administrative expenses..      15,384        9,138       7,848
  Interest expense.....................      23,664       15,375      11,845
                                           --------     --------     -------
                                            179,310       99,294      67,770
                                           --------     --------     -------
Income (loss) before income tax benefit
 and cumulative effect of a change in
 accounting method.....................     (37,233)      19,986       5,659
Provision for income tax benefit.......      (9,055)     (12,222)     (3,154)
                                           --------     --------     -------
Income (loss) before cumulative effect
 of a change in accounting method......    $(28,178)    $ 32,208     $ 8,813
Cumulative effect of a change in
 accounting method, net of tax of
 $1,633................................       2,767           --          --
                                           --------     --------     -------
Net income (loss)......................    $(30,945)    $ 32,208     $ 8,813
                                           ========     ========     =======
Income (loss) before cumulative effect
 of a change in accounting method......    $  (1.41)    $   2.32     $  0.64
                                           ========     ========     =======
Income (loss) before cumulative effect
 of a change in accounting method--
 diluted...............................    $  (1.41)    $   2.27     $  0.63
                                           ========     ========     =======
Net income (loss) per share............    $  (1.54)    $   2.32     $  0.64
                                           ========     ========     =======
Net income (loss) per share--diluted...    $  (1.54)    $   2.27     $  0.63
                                           ========     ========     =======
Weighted average common shares
 outstanding...........................      20,051       13,899      13,854
                                           ========     ========     =======
Weighted average common shares
 outstanding--diluted..................      20,241       14,175      13,896
                                           ========     ========     =======
</TABLE>

                See Notes to Consolidated Financial Statements.

                                       43
<PAGE>

                 MISSION RESOURCES CORPORATION AND SUBSIDIARIES

                       CONSOLIDATED STATEMENTS OF CHANGES
                 IN STOCKHOLDERS' EQUITY AND COMPREHENSIVE LOSS

<TABLE>
<CAPTION>
                                          Preferred
                          Common Stock      Stock     Additional     Other               Treasury Stock
                          ------------- -------------  Paid-in   Comprehensive Retained  --------------
                          Shares Amount Shares Amount  Capital      Income     Deficit   Shares Amount    Total
                          ------ ------ ------ ------ ---------- ------------- --------  ------ -------  --------
<S>                       <C>    <C>    <C>    <C>    <C>        <C>           <C>       <C>    <C>      <C>
Balance December 31,
 1998...................  14,165  $142    --    $--    $ 80,442         --     $(64,191)  (311) $(1,904) $ 14,489
                          ======  ====   ===    ===    ========     ======     ========   ====  =======  ========
Stock options exercised
 and related tax
 effect.................       4    --    --     --          13         --           --     --       --        13
Treasury shares
 purchased..............      --    --    --     --          --         --           --     --       (1)       (1)
Net income..............      --    --    --     --          --         --        8,813     --       --     8,813
                          ------  ----   ---    ---    --------     ------     --------   ----  -------  --------
Balance December 31,
 1999...................  14,169  $142    --    $--    $ 80,455         --     $(55,378)  (311) $(1,095) $ 23,314
                          ======  ====   ===    ===    ========     ======     ========   ====  =======  ========
Stock options exercised
 and related tax
 effects................      91     1    --     --         588         --           --     --       --       589
Compensation expense--
 stock options..........      --    --    --     --         849         --           --     --       --       849
Treasury shares
 purchased..............      --    --    --     --          --         --           --     --       --        --
Net income..............      --    --    --     --          --         --       32,208     --       --    32,208
                          ------  ----   ---    ---    --------     ------     --------   ----  -------  --------
Balance December 31,
 2000...................  14,260  $143    --    $--    $ 81,892                $(23,170)  (311) $(1,905) $ 56,960
                          ======  ====   ===    ===    ========     ======     ========   ====  =======  ========
Stock options exercised
 and related tax
 effects................     177     2    --     --       1,139         --           --     --       --     1,141
Issuance of common stock
 related to merger......   9,460    94    --     --      79,905         --           --     --       --    79,999
Compensation expense--
 stock options..........      --    --    --     --         799         --           --     --       --       799
Treasury shares
 purchased..............      --    --    --     --          --         --           --     --       --        --
Comprehensive loss:
 Net loss...............      --    --    --     --          --         --      (30,945)    --       --   (30,945)
 Hedge activity.........      --    --    --     --          --      2,286           --     --       --     2,286
                                                                                                         --------
Total comprehensive
 loss...................      --    --    --     --          --         --           --     --       --   (28,659)
                          ------  ----   ---    ---    --------     ------     --------   ----  -------  --------
Balance December 31,
 2001...................  23,897  $239    --    $--    $163,735     $2,286     $(54,115)  (311) $(1,905) $110,240
                          ======  ====   ===    ===    ========     ======     ========   ====  =======  ========
</TABLE>


                See Notes to Consolidated Financial Statements.

                                       44
<PAGE>

                 MISSION RESOURCES CORPORATION AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                         Year Ended   Year Ended   Year Ended
                                        December 31, December 31, December 31,
                                            2001         2000         1999
                                        ------------ ------------ ------------
                                                (Amounts in thousands)
<S>                                     <C>          <C>          <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................  $ (30,945)    $ 32,208     $  8,813
Adjustments to reconcile net income
 (loss) to net cash provided by
 operating activities:
  Depreciation, depletion and
   amortization........................     45,106       32,654       23,863
  Gain on Interest rate swap...........       (332)          --           --
  Gain due to hedge ineffectiveness....     (4,767)          --           --
  Mining venture.......................        729           --           --
  Cumulative effect of a change in
   accounting method, net of deferred
   tax.................................      2,767           --           --
  Amortization of stock options........        799          849           --
  Amortization of deferred financing
   costs and bond premium..............      1,877          559          831
  Loss on sale of assets...............     11,600           --           --
  Disposition of hedges................         --        8,671           --
  Impairment expense...................     27,057           --           --
  Other................................        455           --           --
  Deferred taxes.......................     (9,650)     (12,307)      (2,739)
                                         ---------     --------     --------
                                            44,696       62,634       30,768
Changes in assets and liabilities, net
 of acquisition effects:
  Accounts receivable and accrued
   revenues............................      5,669      (13,370)       2,101
  Prepaid expenses and other...........     (3,025)         373          157
  Accounts payable and accrued
   liabilities.........................     (5,611)      12,217        6,265
  Due to affiliates....................         --           --         (125)
  Abandonment costs....................     (1,371)      (1,531)        (136)
  Other................................         --         (215)        (411)
                                         ---------     --------     --------
NET CASH FLOWS PROVIDED BY OPERATING
 ACTIVITIES............................     40,358       60,108       38,619
CASH FLOWS FROM INVESTING ACTIVITIES:
  Acquisitions of oil and gas
   properties..........................    (24,159)      (7,078)     (25,889)
  Acquisitions of Bargo oil and gas
   properties..........................   (142,028)          --           --
  Proceeds on sale of oil and gas
   properties, net.....................     15,868       45,906        5,139
  Proceeds on sale of assets, net......     15,668           --           --
  Additions to oil and gas properties..    (48,040)     (81,294)     (30,904)
  Additions to gas plant facilities....     (1,047)        (677)        (369)
  Additions to leasehold, furniture and
   equipment...........................       (527)      (2,462)        (448)
  Investment in outside companies......         --           --       (4,426)
  Note receivable......................         --       (1,281)          --
  Other................................         --         (446)      (1,071)
                                         ---------     --------     --------
NET CASH FLOWS USED IN INVESTING
 ACTIVITIES............................  $(184,265)    $(47,332)    $(57,968)
                                         =========     ========     ========
</TABLE>

                See Notes to Consolidated Financial Statements.

                                       45
<PAGE>

                 MISSION RESOURCES CORPORATION AND SUBSIDIARIES

               CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

<TABLE>
<CAPTION>
                                          Year Ended   Year Ended   Year Ended
                                         December 31, December 31, December 31,
                                             2001         2000         1999
                                         ------------ ------------ ------------
                                                 (Amounts in thousands)
<S>                                      <C>          <C>          <C>
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings...............   $ 208,754     $ 31,400     $ 42,000
Net proceeds from stock option
 exercises.............................         899          496           12
Payments of long-term debt.............    (199,204)     (35,950)     (16,400)
Proceeds from issuance of senior
 subordinated notes due 2007, including
 premium                                    126,875
Credit facility costs..................      (7,278)        (359)        (172)
                                          ---------     --------     --------
NET CASH FLOWS (USED IN) PROVIDED BY
 FINANCING ACTIVITIES..................     130,046       (4,413)      25,440
                                          ---------     --------     --------
Net increase (decrease) in cash and
 cash equivalents......................     (13,861)       8,363        6,091
Cash and cash equivalents at
 beginning of period...................      14,464        6,101           10
                                          ---------     --------     --------
Cash and cash equivalents at end
 of period.............................   $     603     $ 14,464     $  6,101
                                          =========     ========     ========
</TABLE>

<TABLE>
<S>                                                               <C>
Supplemental schedule of non-cash investing and financing
 activities:
<CAPTION>
                                                                   Year Ended
                                                                  December 31,
                                                                      2001
                                                                  ------------
<S>                                                               <C>
Fair value of assets and liabilities acquired:
  Net current assets and other assets............................   $  2,453
  Property, plant, and equipment.................................    260,893
  Goodwill and intangibles.......................................     16,601
  Deferred tax liability.........................................    (56,610)
                                                                    --------
Total allocated purchase price...................................   $223,337
Less non-cash consideration--issuance of stock...................   $ 80,000
Less cash acquired in transaction................................      1,309
                                                                    --------
Cash used for business acquisition, net of cash acquired.........   $142,028
                                                                    ========
</TABLE>


                See Notes to Consolidated Financial Statements.

                                       46
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

   Mission Resources Corporation (the "Company") is an independent oil and gas
exploration and production company. We acquire, develop and produce crude oil
and natural gas. Mission's balanced portfolio comprises long-lived, low-risk
assets, like those in the Permian Basin, and multi-reservoir, high-
productivity assets found along the Gulf Coast and in the Gulf of Mexico. Our
operational focus is on acquisitions, property enhancement through
exploitation and development drilling, low- to moderate-risk exploration,
asset redeployment and operating cost reduction.

   On May 16, 2001, Bellwether Exploration Company ("Bellwether") merged with
Bargo Energy Company ("Bargo") and changed its name to Mission Resources
Corporation. Simultaneously with the merger, Bellwether increased its
authorized capital stock to 65.0 million shares and amended its 1996 Stock
Incentive Plan to increase the number of shares reserved for issuance under
the plan by 2.0 million shares. Under the merger agreement, holders of Bargo's
stock and options received a combination of cash and Mission common stock. The
merger was accounted for using the purchase method of accounting.

2. Summary of Significant Accounting Policies

 Principles of Consolidation

   The consolidated financial statements include the accounts of Mission
Resources Corporation and its wholly-owned subsidiaries. Snyder Gas Plant
Venture and NGL/Torch Gas Plant Venture and their 11.9% and 32.0% investments
in the Snyder and Diamond M-Sharon Ridge Gas Plants have been pro rata
consolidated through September 1999 at which time the joint ventures were
dissolved. Although the joint ventures were dissolved, the Company retained
its interests in the gas plants on the parent company's books until the
interests in both gas plants were sold in 2001.

   In 1999 the Company reflected its investment in Carpatsky using the equity
method. The Company's December 30, 1999 investment in Carpatsky did not result
in the reflection of any equity in earnings during 1999. Due to different
business and cultural approaches, foreign regulations and financial
limitations, the Company did not have significant influence over Carpatsky;
therefore the investment in Carpatsky was reflected using the cost method in
2000. In June 2001, the Company exchanged its interests in Carpatsky for a
production payment on Carpatsky's producing properties, reporting $6.2 million
as a long term receivable. In fourth quarter of 2001, due to increased
uncertainties in world markets and declining commodity prices and
uncertainties related to the collectibility of the receivable, it was charged
to income as part of the impairments on the Statement of Operations.

 Oil and Gas Properties

   Full Cost Pool--The Company utilizes the full cost method to account for
its investment in oil and gas properties. Under this method, all costs of
acquisition, exploration and development of oil and gas reserves (including
such costs as leasehold acquisition costs, geological expenditures, dry hole
costs and tangible and intangible development costs and direct internal costs)
are capitalized as the cost of oil and gas properties when incurred. Direct
internal costs which are capitalized are primarily the salary and benefits of
geologists and engineers directly involved in acquisition, exploration and
development activities, and amounted to $3.2 million, $3.3 million and $1.7
million in the years ended December 31, 2001, 2000 and 1999, respectively.
Until June 2001, the Company had two full cost pools: United States and
Ecuador. As of December 31, 2001 only the United States full cost pool
remained. The Company's interests in Ecuador were sold June 2001 for gross
proceeds of $8.5 million. Because the Ecuador sale involved the entire full
cost pool, the book value of the pool was removed from the Balance Sheet and
the resulting $12.7 million excess of book value over proceeds was reported as
part of the loss on sale of assets on the Statement of Operations.

                                      47
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   Depletion--The cost of oil and gas properties, the estimated future
expenditures to develop proved reserves, and estimated future abandonment,
site remediation and dismantlement costs are depleted and charged to
operations using the unit-of-production method based on the ratio of current
production to proved oil and gas reserves as estimated by independent
engineering consultants. Costs directly associated with the acquisition and
evaluation of unproved properties are excluded from the amortization
computation until it is determined whether or not proved reserves can be
assigned to the properties or whether impairment has occurred. Depletion
expense per equivalent barrel of domestic production was approximately $6.72
in 2001, $5.47 in 2000, and $4.32 in 1999. Depletion expense per equivalent
barrel of Ecuador production was $4.28 in 2000.

   Unproved Property Costs--The following table shows, by category of cost and
date incurred, the domestic unproved property costs excluded from amortization
(amounts in thousands):

<TABLE>
<CAPTION>
                                                                   Total at
                               Leasehold Exploration Development December 31,
                                 Costs      Costs       Costs        2001
                               --------- ----------- ----------- ------------
   <S>                         <C>       <C>         <C>         <C>
   Costs Incurred During
    Periods Ended:
     December 31, 2001........  $ 5,869    $2,877        $48       $ 8,794
     December 31, 2000........      350        --         --           350
     December 31, 1999........    4,958        --         --         4,958
     Prior....................    1,428        --         --         1,428
                                -------    ------        ---       -------
                                $12,605    $2,877        $48       $15,530
                                =======    ======        ===       =======
</TABLE>

   Such costs fall into four broad categories:

  .  Material projects which are in the last one to two years of seismic
     evaluation;

  .  Material projects currently being marketed to third parties;

  .  Leasehold and seismic costs for projects not yet evaluated; and

  .  Drilling and completion costs for projects in progress at year end which
     have not resulted in the recognition of reserves at December 2001. This
     category of costs will transfer into the full cost pool in 2002.

   Included in leasehold costs are land and seismic costs incurred in the
current and prior years by the Company and are still in the evaluation stage.
Approximately $1.8 million, $2.8 million and $1.2 million were evaluated and
moved to the full cost pool in 2001, 2000 and 1999, respectively.

   Sales of Properties--Dispositions of oil and gas properties held in the
domestic full cost pool are recorded as adjustments to capitalized costs, with
no gain or loss recognized unless such adjustments would significantly alter
the relationship between capitalized costs and proved reserves of oil and gas.
Net proceeds from property sales of $15.9 million, $ 46.0 million, and $ 5.1
million were recorded in such manner during the years 2001, 2000, and 1999,
respectively.

   Impairment -- To the extent that capitalized costs of oil and gas
properties, net of accumulated depreciation, depletion and amortization,
exceed the discounted future net revenues of proved oil and gas reserves net
of deferred taxes, such excess capitalized costs would be charged to
operations. Oil and gas prices declined throughout 2001, ending trading for
the year at $19.76 per barrel of oil (NYMEX WTI Cushing) and $2.73 per MMBTU
of gas (NYMEX Henry Hub). Such closing prices, adjusted to the wellhead to
reflect adjustments for marketing, quality and heating content, were used to
determine discounted future net revenues for the Company. In addition, the
Company elected to adjust discounted future net revenues to reflect the
potential impact of its

                                      48
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

commodity hedges that qualify for hedge accounting under SFAS No. 133. This
adjustment was calculated by taking the difference between the closing NYMEX
prices originally used and the price floors on the Company's hedges multiplied
by the hedged volumes that were included in proved reserves. This calculation
resulted in an increase in discounted future net revenues of $5.7 million
because prices prevailing at December 31, 2001 were consistently lower than
the Company's price floors.

   The Company's capitalized costs were in excess of these adjusted discounted
future net revenues. The Company recorded an oil and gas property impairment
of $20.8 million in 2001. Had the impact of hedges been omitted from this
calculation, the impairment would have been $24.3 million in 2001. No such
impairment to capitalized costs was required for 2000 or 1999.

   Any reference to oil and gas reserve information in the Notes to
Consolidated Financial Statements is unaudited.

 Gas Plants and Gas Gathering System

   Gas plant facilities include the costs to acquire certain gas plants and to
secure rights-of-way. Capitalized costs associated with gas plants facilities
are amortized primarily over the estimated useful lives of the various
components of the facilities utilizing the straight-line method. The estimated
useful lives of such assets range from four to fifteen years.

   Effective September 1, 1999, NGL Associates , the Company's partner in the
Torch-NGL Joint Venture and the Snyder Gas Plant Joint Venture (the
"Ventures"), was given 16.5% of the Ventures' interests in order to satisfy
requirements of the joint ventures. The result of this transfer of interests
was the dissolution of the joint ventures. Mission's interest in the gas
plants was reduced to 11.9% and 32.0% in the Snyder and Diamond M gas plants,
respectively.

   On October 1, 2001 the Company sold its interest in the Snyder gas plant
and Diamond M gas plant for gross proceeds of $11.5 million and recorded a
gain of $1.1 million which was recorded as part of sale of assets on the
Statement of Operations.

   Prior year financial statements have been restated to present gas plant
revenues on a gross basis in compliance with EITF 99-19. The presentation did
not impact previously reported net income (loss) or net income (loss) per
share for the periods presented.

   The Company sold its gas gathering subsidiary for $40,000 on March 1, 1999.

 Revenue Recognition and Gas Imbalances

   The Company uses the sales method of accounting for revenue. Under this
method, oil and gas revenues are recorded for the amount of oil and natural
gas production sold to purchasers on its behalf. Revenues are recognized and
accrued as production occurs. Sales to subsidiaries of Torch Energy Advisors
("Torch") accounted for greater than 10% of oil and gas revenues in 2001,
2000, and 1999. The sales amounts were $43.3 million, $26.9 million, and $14.9
million, respectively, and were part of domestic revenues. No other purchaser
accounted for more than 10% of revenues.

   Gas imbalances are created, but not recorded, when the sales amount is not
equal to the Company's entitled share of production. The Company's entitled
share is calculated as the total or gross production of the property
multiplied by the Company's decimal interest in the property. The Company had
a net imbalance liability, at fair

                                      49
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

value, determined by applying average realized prices for the year to the
imbalance volumes of $0.7 million, $2.3 million, and $1.2 million at December
31, 2001, 2000 and 1999, respectively.

   A certain portion of the gas balancing liability is related to properties
approaching depletion; therefore, cash settlement may be likely. The Company
is taking steps divest itself of such properties or to extend the productive
life of such reserves.

 Receivables

   The Company uses the specific write off method of accounting for
receivables other than accruals. Joint interest billing receivables represent
those amounts due to the Company as operator of an oil and gas property by the
other working interest partners. Since these partners could also be the
operator of other properties in which the Company is a working interest
partner, the interdependency of the partners tends to assure timely payment.
The Company has recognized bad debt expense, included in interest and other
income on the Statement of Operations, of $430,000, $135,000 and $23,000
related to such receivables for the years ended December 31, 2001, 2001 and
1999, respectively.

   A portion of the Company's November 2001 gas production was sold under
contract to a subsidiary of Enron Corporation ("Enron"). Payment for that
production totaling $2.2 million was due in December 2001 and has not been
received. Due to Enron's bankruptcy filing and continued legal difficulties,
the Company chose to write off the entire amount due from Enron. A separate
line for uncollectible gas revenues was added to the Statement of Operations
in order to clearly segregate the $2.2 million charge to income recognized in
2001 due to Enron's failure to make payment.

 Income Taxes

   Deferred taxes are accounted for under the asset and liability method of
accounting for income taxes. Under this method, deferred income taxes are
recognized for the tax consequences of "temporary differences" by applying
enacted statutory tax rates applicable to future years to differences between
the financial statement carrying amounts and the tax basis of existing assets
and liabilities. The effect on deferred taxes of a change in tax rates is
recognized in income in the period the change occurs.

 Statements of Cash Flows

   For cash flow presentation purposes, the Company considers all highly
liquid debt instruments purchased with an original maturity of three months or
less to be cash equivalents. Interest paid in cash for the years ended
December 31, 2001, 2000 and 1999, was $19.0 million, $13.8 million, and $11.1
million, respectively. Income tax refunds received in cash for December 31,
1999 were $437,000. Income taxes paid in cash, net of cash refunds, for the
years ended December 31, 2001 and 2000 were $2.5 million and $109,000,
respectively.

 Benefit Plans

   During 1993, the Company adopted the Mission Resources Simplified Employee
Pension Plan (the "Savings Plan") whereby all employees of the Company are
eligible to participate. The Savings Plan is administered by a Plan
Administrator appointed by the Company. Eligible employees may contribute a
portion of their annual compensation up to the legal maximum established by
the Internal Revenue Service for each plan year. The Company matches
contributions up to a maximum of 6% each plan year. Employee contributions are
immediately vested and employer contributions have a five-year vesting period.
Amounts contributed by the Company to the Savings Plan for the years ended
December 31, 2001, 2000 and 1999 were $405,000, $312,000, and $191,000,
respectively.

                                      50
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Deferred Compensation Plan

   In late 1997, the Company adopted the Mission Deferred Compensation Plan.
This plan, which is not required to be funded, allows selected employees the
option to defer a portion of their compensation until their retirement or
termination. Such deferred compensation is invested in any one or more of six
mutual funds managed by American Funds Service Company ("Fund Manager") at the
direction of the employees. The Company designated Southwest Guaranty Trust
Company as Trustee to supervise the Fund Manager. The market value of these
investments is included in current assets at December 31, 2001, 2000 and 1999
and was approximately $124,000, $25,000, and $98,000, respectively.

 Mining Venture

   During fiscal year 1992, Mission acquired an average 24.4% interest in
three mining ventures (the "Mining Venture") from an unaffiliated individual
for $128,500. At the time of such acquisition, J. P. Bryan, a member of the
Mission Board of Directors, his brother, Shelby Bryan and Robert L. Gerry III
(the "Affiliated Group"), owned an average 21.5% interest in the Mining
Venture. Mission's interest in the Mining Venture increased as it paid costs
of the venture while the interest of the Affiliated Group decreased. Through
December 31, 2001, Mission spent an additional $185,000 primarily for soil
core assays and evaluations. These exploratory costs, plus the $729,000
accumulated on the Balance Sheet in Other Assets as of December 31, 2000, were
charged to earnings in 2001.

 Goodwill

   In evaluating the recovery of goodwill, Mission Resources compared the
undiscounted future cash flows of its operations to the historical value of
its net assets. An impairment of goodwill is measured as the excess in the
historical value of the company's net assets over the undiscounted future cash
flows of its operations.

 Comprehensive Income

   Comprehensive income includes all changes in a company's equity except
those resulting from investments by owners and distributions to owners. The
Company's total comprehensive income for the twelve months ended December 31,
2001 and 2000 was as follows (in thousands):

<TABLE>
<CAPTION>
                                                               Twelve Months
                                                               Ended December
                                                                    31,
                                                              -----------------
                                                                2001     2000
                                                              --------  -------
   <S>                                                        <C>       <C>
   Net income (loss)......................................... $(30,945) $32,208
   Cumulative effect attributable to adoption of
    SFAS No. 133, net of tax.................................  (19,328)      --
   Hedge accounting for derivative instruments, net of tax...   21,614       --
                                                              --------  -------
   Comprehensive income (loss)............................... $(28,659) $32,208
                                                              ========  =======
</TABLE>

   The accumulated balance of other comprehensive income related to cash flow
hedges, net of taxes, is as follows (in thousands):

<TABLE>
   <S>                                                                 <C>
   Balance at December 31, 2000....................................... $     --
   Cumulative effect of accounting change.............................  (19,328)
   Net gains on cash flow hedges......................................   13,919
   Reclassification adjustments.......................................   14,934
   Tax effect on hedge activity.......................................   (7,239)
                                                                       --------
   Balance at December 31, 2001....................................... $  2,286
                                                                       ========
</TABLE>


                                      51
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

 Change in Accounting Method

   Effective January 1, 2001, the Company adopted the Statement of Financial
Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments
and Hedging Activities." This statement establishes accounting and reporting
standards requiring that derivative instruments (including certain derivative
instruments embedded in other contracts) be recorded at fair value and
included in the balance sheet as assets or liabilities. The accounting for
changes in the fair value of a derivative instrument depends on the intended
use of the derivative and the resulting designation, which is established at
the inception of a derivative. Accounting for qualified hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the Statement of Operations. For derivative instruments designated as cash
flow hedges, changes in fair value, to the extent the hedge is effective, are
recognized in Other Comprehensive Income until the hedged item is recognized
in earnings. Hedge effectiveness is measured at least quarterly based upon the
relative change in fair value between the derivative contract and the hedged
item over time. Any change in the fair value resulting from ineffectiveness,
as defined by SFAS 133, is recognized immediately in earnings.

   Adoption of SFAS No.133 at January 1, 2001 resulted in the recognition of
$25.3 million of derivative liabilities included in Current Liabilities on the
Balance Sheet and $19.3 million, net of taxes, of hedging losses included in
Accumulated Other Comprehensive Income, a component of Stockholders' Equity,
as the cumulative effect of a change in accounting method. Amounts were
determined as of January 1, 2001 based upon quoted commodity prices. The
Company also recognized a $4.4 million liability and a $2.8 million loss, net
of taxes, as the cumulative effect of a change in accounting method related to
an interest rate swap that did not qualify for hedge accounting treatment.

   Effective September 22, 1998, the Company entered into an eight and one-
half-year interest rate swap agreement with a notional value of $80.0 million.
Under the agreement, the Company receives a fixed interest rate and pays a
floating interest rate based on the simple average of three foreign LIBOR
rates. Floating rates are re-determined for a six-month period each April 1
and October 1. The interest rate swap did not qualify for hedge accounting
under SFAS No. 133 at January 1, 2001. The swap's net value of $4.0 million is
reflected on the balance sheet as a $180,000 current asset and a $4.2 million
long-term liability. The change in the swap's fair value of $332,000 for the
year ended December 31, 2001 has been reflected as a reduction in interest
expense on the Statement of Operations.

   Mission entered into a gas swap for $4.60 per MCF on 15,000 MCF per day of
production from November 2000 through October 2001. This offset hedges
previously existing on forecasted production that was sold in late 2000. A
non-cash loss of $8.7 million was recognized in the fourth quarter of 2000
related to the $4.60 swap, along with a current derivative liability as this
portion of the swap was considered a speculative derivative. The liability was
relieved monthly as the swap was settled. By December 31, 2001, the liability
had been reduced to zero.

   Bargo had entered into one derivative contract, a floor of $21 per barrel
on oil that extended into the year 2001. In adopting SFAS No. 133, it was
determined that the Bargo derivative contract would be marked to market.
Mission acquired this contract at the time of the merger. The contract was
marked to market through December 31, 2001 at such time as the contract
expired and related market value was zero. The actual results of this contract
were offset against the changing market value, resulting in a net derivative
loss of $75,000 recorded to other income on the Statement of Operations for
the year ended December 31, 2001.

 New Accounting Pronouncements

   In July 2001, the Financial Accounting Standards Board issued SFAS No. 141.
Business Combinations, and SFAS No.142, Goodwill and Other Intangible Assets.
SFAS No. 141 requires that the purchase method of

                                      52
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

accounting be used for all business combinations initiated after June 30, 2001
as well as all purchase method business combinations completed after June 30,
2001. SFAS No. 141 also specifies criteria that intangible assets acquired in
a purchase method business combination must meet in order to be recognized and
reported apart from goodwill, noting that any purchase price allocable to an
assembled workforce may not be accounted for separately. SFAS No. 142 will
require that goodwill and intangible assets with indefinite useful lives no
longer be amortized, but instead tested for impairment at least annually in
accordance with the provisions of SFAS No. 142. SFAS No. 142 will also require
that intangible assets with definite useful lives be amortized over their
respective estimated useful lives to their estimated residual values, and
reviewed for impairment in accordance with SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.
Mission is required to adopt the provisions of SFAS No. 141 immediately and
SFAS No. 142 effective January 1, 2002.

   As of the date of adoption, Mission's expects to have unamortized goodwill
in the amount of $15.1 million and unamortized identifiable intangible assets
in the amount of $374,300, all of which will be subject to the transition
provisions of SFASs No. 141 and No. 142. Amortization expense related to
goodwill was $986,000 for the period ended December 31, 2001. Upon adoption of
SFAS No. 142, amortization of goodwill and intangible assets will cease,
thereby reducing expenses by approximately $456,000 quarterly. Also, upon
adoption of SFAS No. 142, $277,000 of workforce intangible currently recorded
as unamortized identifiable intangible assets will be subsumed into goodwill
and will not be amortized as it no longer qualifies as a recognizable
intangible asset. Because of the extensive effort needed to comply with
adopting SFAS No. 141 and No. 142, it is not practicable to reasonably
estimate all of the potential impacts of adopting these statements on the
Mission's financial statements at the date of this report.

   In July 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations, provides accounting requirements for retirement obligations
associated with tangible long-lived assets, including:

  .  the timing of liability recognition;

  .  initial measurement of the liability;

  .  allocation of asset retirement cost to expense;

  .  subsequent measurement of the liability; and

  .  financial statement disclosures.

   SFAS No. 143 requires that asset retirement cost should be capitalized as
part of the cost of the related long-lived asset and subsequently allocated to
expense using a systematic and rational method. Mission will adopt the
statement effective January 1, 2003. The transition adjustment resulting from
the adoption of SFAS No. 143 will be reported as a cumulative effect of a
change in accounting principle. At this time, Mission cannot reasonably
estimate the effect of the adoption of this statement on either financial
position or results of operations.

   In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets, which will be effective as of the beginning
of 2002. SFAS No. 144 requires that long-lived assets to be disposed of by
sale be measured at the lower of the carrying amount or fair value less cost
to sell, whether reported in continuing operations or in discontinued
operations. SFAS No. 144 broadens the reporting of discontinued operations to
include all components of an entity with operations that can be distinguished
from the rest of the entity and that will be eliminated from the ongoing
operations of the entity in a disposal transaction. After its effective date,
SFAS No. 144 will be applied to those transactions where appropriate. At this
time Mission is unable to determine what the future impact of adopting this
statement will have on its financial position or results of operations.

                                      53
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Use of Estimates

   Management of the Company has made a number of estimates and assumptions
relating to the reporting of assets and liabilities and the disclosure of
contingent assets and liabilities as well as reserve information which affects
the depletion calculation and the computation of the full cost ceiling
limitation to prepare these financial statements in conformity with generally
accepted accounting principles in the United States. Actual results could
differ from these estimates.

 Reclassifications

   Certain reclassifications of prior period statements have been made to
conform with current reporting practices. Prior year financial statements have
been restated to present gas plant revenues on a gross basis in accordance
with EITF 99-19 "Reporting Revenue Gross as a Principal verses Net as an
Agent." The presentation did not impact previously reported net income (loss)
or net income (loss) per common share for the periods presented.

3. Acquisitions and Investments

   During the last three fiscal years, the Company has completed or made the
following significant acquisitions and investments:

   Throughout 1998 and 1999, the Company acquired an interest in Carpatsky
Petroleum Incorporated ("Carpatsky"), a Canadian corporation, consisting of
common shares, convertible preferred shares and a warrant to acquire
additional common shares. The total cost of these investments was $4.6
million. This investment did not give the Company the ability to significantly
influence Carpatsky's operations and was accounted for under the cost method.
Additionally, the Company made a loan to Carpatsky of $1.0 million under a
revolving credit facility established in July 1999 and incurred costs on
behalf of Carpatsky of approximately $0.6 million. The Company executed an
agreement with Carpatsky effective June 29, 2001 under which it exchanged the
interests for a production payment in Carpatsky's producing properties. In the
fourth quarter of 2001 due to uncertainties in world markets and declining
commodity prices, the related long-term receivable was charged to income as
part of impairments on the Statement of Operations.

   In December 1998, the Company was the successful bidder for the Charapa
field in Ecuador. With the successful bid, the Company was awarded a contract
for production and exploration of crude oil in the Charapa field. The contract
provides the Company with approximately 45% of the crude oil produced above
the base production curve. The base production curve is defined as the
production profile of the crude oil projected by the Ecuadorian government
hydrocarbons subsidiary. Negotiations with the Ecuadorian government took
place throughout 1999. The Company officially took over operations of Charapa
in January of 2000. In February 2000, the Company took over operations of
another Ecuadorian field, the Tiguino field. The contract with the government
is similar for both fields. A subsidiary operated the field on behalf of
Petroleos Colombianos ("Petrocol"), which had been granted a 25% interest and
operatorship by the Ecuadorian government. The Company negotiated with
Petrocol and other interest owners throughout 2000 ultimately acquiring 70%
and the assignment of operatorship by July 2000. Agreements transferring
ownership and operatorship in the Tiguino field were signed by all parties,
and the approval was received in August 2001. Two months later the Company
sold the subsidiaries that were party to the concessions at a loss of $12.7
million which included a loss on the writedown of a $1.0 million escrow
receivable which was estimated to be settled before year end upon resolution
of negotiations with the Ecuadorian government. The $1.0 million escrow
receivable was written off at year-end due to increased difficulties in
negotiating with the Ecuadorian government which made its collection doubtful.
See Note 1 under "Oil and Gas Properties: Full Cost Pool" for additional
discussion of the sale.


                                      54
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

   On May 16, 2001, Bellwether Exploration Company merged with Bargo Energy
Company and changed its name to Mission Resources Corporation. Under the
merger agreement, Bargo shareholders and optionholders received a combination
of cash and Mission common stock. The merger was accounted for using the
purchase method of accounting and was financed through the issuance of $80.0
million, or 9.5 million shares, of Mission common stock to Bargo option
holders and shareholders, and an initial $166.0 million in borrowings under a
new credit facility ("Credit Facility"). Borrowings under the Credit Facility
were used as follows:

  .  to pay the cash portion of the purchase price to holders of Bargo common
     stock and options,

  .  to pay the amount incurred by Bargo in redeeming its preferred stock
     immediately prior to the merger,

  .  to refinance Bargo's and Bellwether's then-existing credit facilities,
     and

  .  to pay transaction costs.

   The $280.9 million adjusted purchase price allocated to the acquired assets
was $4.1 million to unproved properties, $255.7 million to proved properties,
$1.1 million to current drilling projects, $17.7 million to goodwill and
intangible assets and $2.3 million to current assets, current liabilities and
other non-current assets.

   On May 17, 2001, the Company purchased oil and gas properties in south
Louisiana for a gross sales price of $21.5 million.

4. Related Party Transactions

   As of December 31, 2001, the Company is party to a Master Service Agreement
dated October 1, 1999, ("Master Service Agreement") and four specific
contracts ("Contracts") under which Torch Energy Advisors Incorporated
("Torch") administers certain activities of the Company including oil and gas
marketing, operation of oil and gas properties, accounting, risk management,
legal and information technology. Previously, the Company was party to six
contracts with Torch, but the Land Services Agreement was terminated in early
2001 when the Company brought such function in-house and the Midstream Asset
Management Agreement was terminated upon the sale of the gas plant in the
fourth quarter of 2001. Neither of these two contract terminations resulted in
a termination fee. The Master Services Agreement may be terminated by the
Company upon 90 days prior notice, subject to a fee based on the remaining
terms of the contracts. The remaining contracts have terms ranging from 6
months to 1 year. Neither the Master Service Agreement nor the Contracts may
be terminated by Torch prior to expiration of their initial terms.

   Since the merger of Bargo Energy Company in May 2001 all of the agreements
with Torch were renegotiated except the Corporate Services Agreement. The
current contracts have fixed and variable annual fees ranging from $.4 million
to $4.9 million. For the periods ended December 31, 2001, 2000, and 1999
related fees paid to Torch amounted to $5.5 million, $4.7 million, and $2.9
million, respectively. Subsequent to December 31, 2001, the Company brought
additional functions in-house further reducing the largest agreement with
Torch by $0.3 million annually.

   At the end of 2001 the Company gave notice to Torch that the Company would
be terminating the Corporate Services Agreement effective April 2002 and will
bring such services in-house. A termination fee stipulated by the terms of the
contract of $620,000 has been recognized as part of general and administrative
expense in the Statement of Operations for the year ended December 31, 2001.

   In April 1997, Torch was issued 150,000 shares of the Company's common
stock and a warrant, expiring in April 2002, to purchase 100,000 shares at
$9.90 per share for advisory services rendered in connection with an
acquisition.


                                      55
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

   On August 2, 1999, two senior executives left the Company to pursue other
opportunities. Mr. J. P. Bryan, a member of the board of directors, then was
elected Chairman and CEO effective August 2, 1999. Approximately $1.7 million
of severance costs attributable to this management change were incurred in
August 1999. Mr. J. P. Bryan served as Chief Executive Officer of Bellwether
from August 1999 through May 2000. He continues to be a member of the Mission
board of directors. Mr. Bryan is also Senior Managing Director of Torch and
owns shares representing 23% of the shares of Torch on a fully diluted basis.
Mr. Bryan also owned 1,061,750 shares of Bargo before the merger. Also, Mr.
Tim Goff, former Chairman of Bargo and current member of Mission's board of
directors, is a non-compensated advisor to Torch regarding potential oil and
gas property acquisitions.

   Pursuant to a separation agreement between the Company and one of the
senior executives, the executive entered into a non-recourse promissory note
with a principal amount of $332,872. The loan bears interest at an annual rate
of 7% and is due and payable on August 23, 2002. The loan is secured by 78,323
shares of the Company's common stock. As of December 31, 2001, the outstanding
loan balance of $332,872 was reflected in Other Assets on the Balance Sheet,
while accrued interest of $55,700 was reflected within accounts receivable and
accrued revenues on the Balance Sheet.

   Sales to subsidiaries of Torch accounted for approximately 32%, 24%, and
22% of fiscal year 2001, 2000 and 1999 oil and gas revenues, respectively.

   A subsidiary of Torch markets oil and natural gas production from certain
oil and gas properties in which the Company owns an interest. Such charges
were $417,000, $563,000, and $947,500 in periods ended December 31, 2001, 2000
and 1999, respectively. Prior to the contract revisions the fees were 2% on
all marketed production; therefore a savings is reflected in the year 2000
over previous years.

   Torch has provided services for the evaluation of potential property
acquisitions and due diligence conducted in conjunction with acquisitions
closed at the Company's request. The Company was charged $685,000, $1.3
million, and $357,800 for these costs in periods ended December 31, 2001, 2000
and 1999, respectively.

   Torch operates certain oil and gas interests owned by the Company. The
Company is charged, on the same basis as other third parties, for all
customary expenses and cost reimbursements associated with these activities.
Prior to October 1999, Torch retained such reimbursements as part of its
compensation. After October 1999, overhead reimbursements are retained by the
Company and are reported as reductions to general and administrative expenses.
Operator's overhead charged by Torch and retained as compensation for these
activities for the period ended December 31, 1999 was $1,153,000.

   Torch is the operator of the Snyder Gas Plant. In periods ended December
31, 2001, 2000 and 1999, the fees paid by the Company to Torch were $74,000,
$96,000, and $73,000, respectively.

   During the fiscal year 1992, the Company acquired an average 24.4% interest
in three mining ventures (the "Mining Venture") from an unaffiliated person
for $128,500. At the time of such acquisition, J. P. Bryan, his brother,
Shelby Bryan and Robert L. Gerry III, a director of Nuevo Energy Company (the
"Affiliated Group"), owned an average 21.5% interest in the Mining Venture.
The Company's interest in the Mining Venture increased to 32.5% during 1998 as
it paid costs of the venture while the interest of the Affiliated Group
decreased. On December 31, 1998, the Company impaired the value of the asset
by $465,000, included in the Impairment Expense line of the Statement of
Operations, leaving a $10,000 investment. The impairment was taken because
Mission believed the venture did not have value above $10,000 without further
investments that it did not anticipate would occur. In 1999, the Company
invested $273,000 in the Mining Venture, based upon a third party assay
showing economically mineable grades of several precious minerals, bringing
its recorded investment to

                                      56
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

$283,000 as of December 31, 1999. During 2000, the Company invested $446,000
in the Mining Venture, bringing its recorded investment to $729,000 as of
December 31, 2001 for a 40.7% interest. In 2001, the $729,000 accumulated
costs, plus $185,000 in core assay and evaluation costs incurred throughout
the year were expensed on the Mining Costs line of the Statement of
Operations.

5. Stockholders' Equity

 Common and Preferred Stock

   The Certificate of Incorporation of the Company authorizes the issuance of
up to 30,000,000 shares of common stock and 1,000,000 shares of preferred
stock, the terms, preferences, rights and restrictions of which are
established by the Board of Directors of the Company. Certain restrictions
contained in the Company's loan agreements limit the amount of dividends which
may be declared. There is no present plan to pay cash dividends on common
stock as the Company intends to reinvest its cash flows for continued growth
of the Company.

   In addition to stock options outstanding, the Company has 100,000 warrants
outstanding at an exercise price of $9.90 per share. The expiration date for
the warrants is April 2002.

   A tax benefit related to the exercise of employee stock options of $240,000
in 2001 and $95,000 in 2000 was allocated directly to additional paid in
capital. Such benefit was not material in year 1999.

   On May 16, 2001, Bellwether merged with Bargo Energy Company ("Bargo"). The
resulting company was renamed Mission Resources Corporation. Contemporaneously
with the merger, Bellwether increased its authorized capital stock to 65.0
million shares and amended its 1996 Stock Incentive Plan to increase the
number of shares reserved for issuance under the plan by 2.0 million shares.
As partial consideration in the merger, 9.5 million shares of Mission common
stock were issued to the holders of Bargo common stock and options. The $80
million assigned value of such shares was included in the purchase price.
Concurrent with the merger, all Bellwether employees who held stock options
were immediately vested in those options upon closing of the merger.
Compensation expense of $43,000 was recognized for an estimate of those
employee options that would have expired unexercisable pursuant to its
original terms. The expense was calculated as the excess of the price on the
merger date over the exercise price of the option.

 Shareholder Rights Plan

   In September 1997, the Company adopted a shareholder rights plan to protect
Mission's shareholders from coercive or unfair takeover tactics. Under the
shareholder rights plan, each outstanding share of Mission's common stock and
each share of subsequently issued Mission common stock has attached to it one
right. The rights become exercisable if a person or group acquires or
announces an intention to acquire beneficial ownership of 15% or more of the
outstanding shares of common stock without the prior consent of the Company.
When the rights become exercisable each holder of a right will have the right
to receive, upon exercise of the right, a number of shares of common stock of
the Company which, at the time the rights become exercisable, have a market
price of two times the exercise price of the right. The Company may redeem the
rights for $.01 per right at any time before they become exercisable without
shareholder approval. The rights will expire on September 26, 2007, subject to
earlier redemption by the board of directors of the Company.

                                      57
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Earnings Per Share

   The following represents the reconciliation of the numerator (income) and
denominator (shares) of the earnings per share computation to the numerator
and denominator of the diluted earnings per share computation. The Company's
reconciliation is as follows (amounts in thousands, except per share amounts):

<TABLE>
<CAPTION>
                             Year Ended December 31,   Year Ended December 31,
                                      2001                       2000
                            -------------------------- ------------------------
                             Income   Shares Per Share Income  Shares Per Share
                            --------  ------ --------- ------- ------ ---------
<S>                         <C>       <C>    <C>       <C>     <C>    <C>
Net income (loss).........  $(30,945)                  $32,208
Earnings (loss) per common
 share....................  $(30,945) 20,051  $(1.54)  $32,208 13,899   $2.32
Effect of dilutive
 securities: Options &
 warrants.................        --      --                --    276
                            --------  ------  ------   ------- ------   -----
Earnings (loss) per common
 share--diluted...........  $(30,945) 20,051  $(1.54)  $32,208 14,175   $2.27
                            ========  ======  ======   ======= ======   =====
<CAPTION>
                             Year Ended December 31,
                                      1999
                            --------------------------
                             Income   Shares Per Share
                            --------  ------ ---------
<S>                         <C>       <C>    <C>       <C>     <C>    <C>
Net income................  $  8,813
Earnings per common
 share....................  $  8,813  13,854  $ 0.64
Effect of dilutive
 securities:
 Options & warrants.......        --      42
                            --------  ------  ------
Earnings per common
 share--diluted--.........  $  8,813  13,896  $ 0.63
                            ========  ======  ======
</TABLE>

   Diluted earnings per share were not calculated since the issuance or
conversion of additional securities would have had an antidilutive effect due
to the loss in the period. Options and warrants equal to 2,247,000 in 2001,
584,500 in 2000 and 1,181,499 in 1999 that could potentially dilute basic
earnings per share in the future were not included in the computation of
diluted earnings per share because to do so would have been antidilutive.

 Treasury Stock

   In September 1998, the Company's Board of Directors authorized the
repurchase of up to $5.0 million of the Company's common stock. As of December
31, 1999, 311,000 shares had been acquired at an aggregate price of
$1,905,000. These treasury shares are reported at cost as a reduction to
Stockholders' Equity.

 Stock Incentive Plans

   The Company has stock option plans that provide for granting of options for
the purchase of common stock to directors, officers and employees of the
Company. These stock options may be granted subject to terms ranging from 6 to
10 years at a price equal to the fair market value of the stock at the date of
grant. At year end 2001 167,000 options are available for grants.

   On May 15, 2000 the Company's president was granted 500,000 options with an
exercise price set at the average price for the 30 days prior to the grant
date. Such average price was less than the closing price on the grant date.
The Company is required to recognize compensation expense, over the vesting
period, for the options equal to the difference between the exercise price and
the close price of Mission's stock on the grant date. A charge of $536,000 was
recorded in May 2000, when one-third of the options vested. The remaining
expense was to be charged ratably over the two-year vesting period for the
remaining options. Due to the vesting of all outstanding options in connection
with the merger on May 16, 2001, the remaining $577,000 expense was recognized
as compensation expense in May 2001 bringing the total expense for the year
2001 to $756,000.

                                      58
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   A summary of activity in the stock option plans is set forth below:

<TABLE>
<CAPTION>
                                                                   Option Price
                                                                      Range
                                                        Number of  ------------
                                                         shares     Low   High
                                                        ---------  ----- ------
   <S>                                                  <C>        <C>   <C>
   Balance at December 31, 1998........................ 1,268,500  $4.38 $12.38
     Granted...........................................   653,500  $3.34 $ 6.22
     Surrendered.......................................  (390,000) $3.34 $10.19
     Exercised.........................................    (4,000) $3.34 $ 3.34
                                                        ---------
   Balance at December 31, 1999........................ 1,528,000  $3.34 $12.38
     Granted...........................................   917,500  $4.25 $ 8.75
     Surrendered.......................................   (51,999) $3.34 $ 7.97
     Exercised.........................................   (90,835) $3.34 $ 7.63
                                                        ---------
   Balance at December 31, 2000........................ 2,302,666  $3.34 $12.38
     Granted........................................... 1,984,000  $5.71 $ 8.80
     Surrendered.......................................  (124,500) $4.59 $12.38
     Exercised.........................................  (177,331) $3.34 $ 7.63
                                                        ---------
   Balance at December 31, 2001........................ 3,984,835  $3.34 $12.38
                                                        =========  ===== ======
   Exercisable at December 31, 2001.................... 2,898,165  $3.34 $12.38
                                                        =========  ===== ======
</TABLE>

   Detail of stock options outstanding and options exercisable at December 31,
2001 follows:

<TABLE>
<CAPTION>
                                        Outstanding              Exercisable
                              ------------------------------- ------------------
                                          Weighted   Weighted           Weighted
                                          Average    Average            Average
                                         Remaining   Exercise           Exercise
   Range of Exercise Prices    Number   Life (Years)  Price    Number    Price
   ------------------------   --------- ------------ -------- --------- --------
   <S>                        <C>       <C>          <C>      <C>       <C>
   1994 Plan $3.34 to $
    8.25....................    483,835     4.4       $5.51     483,835  $5.51
   1996 Plan $3.34 to
    $12.38..................  3,501,000     8.7       $7.47   2,414,330  $7.02
                              ---------                       ---------
       Total................  3,984,835                       2,898,165
                              =========                       =========
</TABLE>

   The estimated weighted average fair value per share of options granted
during 2001, 2000, and 1999 was $3.15, $12.75, and $11.68, respectively. The
fair value of each option grant is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted-average
assumptions.

  .  For 2001, expected stock price volatility of 69%; a risk free interest
     rate of 5.3%; and an average expected option life of 10 years

  .  For 2000, expected stock price volatility of 65%; a risk free interest
     rate of 5.1%; and an average expected option life of 10 years

  .  For 1999, expected stock price volatility of 93%; a risk free interest
     rate of 6.5%; and an average expected option life of 10 years

                                      59
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   Had compensation expense for stock-based compensation been determined based
on the fair value at the date of grant, the Company's net income and earnings
per share would have been reduced to the pro forma amounts indicated below (in
thousands, except share information):

<TABLE>
<CAPTION>
                                          Year Ended   Year Ended   Year Ended
                                         December 31, December 31, December 31,
                                             2001         2000         1999
                                         ------------ ------------ ------------
   <S>                                   <C>          <C>          <C>
   Net income (loss)
     As reported........................   $(30,945)    $32,208      $  8,813
     Pro forma..........................   $(35,007)    $24,955      $(19,516)
   Earnings (loss) per share
     As reported........................   $  (1.54)    $  2.32      $  0 .64
     Pro forma..........................   $  (1.75)    $  1.80      $  (1.41)
   Diluted earnings (loss) per share
     As reported........................   $  (1.54)    $  2.27      $  0 .63
     Pro forma..........................   $  (1.75)    $  1.76      $  (1.41)
</TABLE>

6. Derivative Instruments and Hedging Activities

   In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities. This statement established standards of
accounting for and disclosures of derivative instruments and hedging
activities. As amended SFAS No. 133 was effective for fiscal quarters
beginning after January 1, 2001. As discussed in Note 1, the Company adopted
SFAS No. 133 on January 1, 2001.

   The Company periodically uses derivative financial instruments to manage
oil and gas price risk; generally commodity price swap agreements which
provide for the Company to receive or make counterparty payments on the
differential between a fixed price and a variable indexed price for natural
gas or crude oil. Hedging activities decreased revenues by $13.4 million,
$24.5 million and $4.0 million for the years 2001, 2000 and 1999,
respectively.

                                      60
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The following tables detail the Company's hedges of future production,
which were in place at December 31, 2001.

Oil Hedges

<TABLE>
<CAPTION>
                                                                  NYMEX   NYMEX
                                          BBLS     Total          Price   Price
                  Period                 Per Day   BBLS     Type  Floor  Ceiling
                  ------                 ------- --------- ------ ------ -------
   <S>                                   <C>     <C>       <C>    <C>    <C>
   Jan. 2002-Mar. 2002..................  6,000    540,000 Collar $21.50 $31.25
   Apr. 2002-Jun. 2002..................  5,400    491,400 Collar $21.50 $30.25
   Jul. 2002-Sep. 2002..................  4,700    432,400 Collar $21.50 $28.45
   Oct. 2002-Dec. 2002..................  4,000    368,000 Collar $21.50 $27.15

Gas Hedges

<CAPTION>
                                                                  NYMEX   NYMEX
                                           MCF                    Price   Price
                  Period                 Per Day Total MCF  Type  Floor  Ceiling
                  ------                 ------- --------- ------ ------ -------
   <S>                                   <C>     <C>       <C>    <C>    <C>
   Jan. 2002-Mar. 2002.................. 11,700  1,053,000 Collar $ 3.57 $ 7.00
   Apr. 2002-Jun. 2002.................. 10,200    928,200 Collar $ 3.00 $ 6.48
   Jul. 2002-Sep. 2002..................  9,800    901,600 Collar $ 3.00 $ 6.60
   Oct. 2002-Dec. 2002..................  8,500    782,000 Collar $ 3.40 $ 7.00
   Jan. 2003-Mar. 2003.................. 10,000    900,000 Collar $ 3.00 $ 4.65
   Apr. 2003-Jun. 2003..................  5,000    455,000 Collar $ 3.00 $ 4.02
   Apr. 2003-Jun. 2003..................  5,000    455,000 Collar $ 3.00 $ 3.97
   Jul. 2003-Sep. 2003.................. 10,000    920,000 Collar $ 3.00 $ 4.10
   Oct. 2003-Nov. 2003.................. 10,000    920,000 Collar $ 3.00 $ 4.65
</TABLE>

   As discussed in Note 1, in 2001 the Company began accounting for the
collars designated as cash flow hedges in accordance with SFAS No. 133. As a
result, changes in the fair value of the cash flow hedges are recognized in
Other Comprehensive Income until the hedged item is recognized in earnings,
and any change in the fair value due to ineffectiveness is recognized
immediately in earnings. For the year 2001, a $4.8 million net gain was
recorded as part of interest and other income on the Statement of Operations
due to hedge ineffectiveness. The Company expects to transfer the remaining
balance of Accumulated Other Comprehensive Income to earnings over the next
two years.

   Mission entered into a gas swap for $4.60 per MCF on 15,000 MCF per day of
production from November 2000 through October 2001. This offset hedges
previously existing on forecasted production that was sold in late 2000. A
related non-cash loss of $8.7 million was recognized in the fourth quarter of
2000, along with a current derivative liability, as this portion of the swap
was considered a speculative derivative. The liability was relieved monthly as
the swap was settled and is zero at December 31, 2001.

   Bargo had entered into one derivative, a floor of $21 per Bbl on oil that
extended into the year 2001. In adopting SFAS No. 133, it was determined that
these derivative contracts would be marked to market. The Company acquired
these contracts at the time of the merger. The contract terminated in December
2001; therefore, no related asset or liability remains.

   Effective September 22, 1998, the Company entered into an eight and one-
half year interest rate swap agreement with a notional value of $80 million.
Under the agreement, the Company receives a fixed interest rate and pays a
floating interest rate based on the simple average of three foreign LIBOR
rates. Floating rates are redetermined for a six-month period each April 1 and
October 1. The interest rate swap did not qualify for hedge

                                      61
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

accounting under SFAS No. 133 and is therefore marked to market each quarter.
For the year 2001, a net gain of $332,000 was recorded as a reduction of
interest expense related to the change in the fair value of the interest rate
swap.

7. Determination of Fair Values of Financial Instruments

   Fair value for cash, short-term investments, receivables and payables
approximates carrying value. The interest rate swap and the commodity
derivatives are also reflected on the Balance Sheet at fair value. The
following table details the carrying values and approximate fair values of the
Company's other investments and long-term debt at December 31, 2001 and 2000
(in thousands).

<TABLE>
<CAPTION>
                                    December 31, 2001      December 31, 2000
                                  ---------------------- ----------------------
                                  Carrying   Approximate Carrying   Approximate
                                    Value    Fair Value    Value    Fair Value
                                  ---------  ----------- ---------  -----------
<S>                               <C>        <C>         <C>        <C>
Assets (Liabilities):
Long-term debt: (See Note 8)
Bank Credit Facility............. $ (35,000)  $ (35,000) $ (25,450)  $(25,450)
Senior Subordinated Notes,
 excluding $1.7 million
 unamortized premium on $125
 million bonds................... $(225,000)  $(202,500) $(100,000)  $(89,440)
</TABLE>

8. Long-Term Debt

   Long-term debt is comprised of the following at December 31, 2001 and 2000
(in thousands):

<TABLE>
<CAPTION>
                                                     December 31, December 31,
                                                         2001         2000
                                                     ------------ ------------
   <S>                                               <C>          <C>
   Bank credit facility.............................   $ 35,000     $ 25,450
   10 7/8% Senior Subordinated Notes................    225,000      100,000
                                                       --------     --------
   Subtotal.........................................    260,000      125,450
   Premium on $125 million Senior Subordinated
    Notes...........................................      1,695           --
                                                       --------     --------
   Long-term debt...................................   $261,695     $125,450
                                                       ========     ========
</TABLE>

   Debt maturities by fiscal year are as follows (amounts in thousands):

<TABLE>
   <S>                                                                  <C>
   2002................................................................ $     --
   2003................................................................ $     --
   2004................................................................ $ 35,000
   2005................................................................ $     --
   2006................................................................ $     --
   Thereafter.......................................................... $225,000
                                                                        --------
                                                                        $260,000
                                                                        ========
</TABLE>

   In April 1997, the Company entered into a senior revolving unsecured credit
facility ("Senior Credit Facility") in an amount up to $90.0 million, with a
borrowing base to be re-determined semi-annually, and a maturity date of
November 5, 2003. On May 20, 1999 the borrowing base was re-determined to be
$55.0 million. Subsequent amendments reflecting the impact of the property
sales in 2000 have reduced the borrowing base to $34.5 million at December 31,
2000. At December 31, 2000, there was $24.5 million in borrowings outstanding
under the Senior Credit Facility.

                                      62
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   Under the Senior Credit Facility, the Company could elect an interest rate
based either on a margin plus London Interbank Offered Rate ("LIBOR") or the
higher of the prime rate or the sum of 0.5% of 1% plus the Federal Funds Rate.
For LIBOR borrowings, the interest rate will vary from LIBOR plus 1.0% to
LIBOR plus 3.5% based upon the borrowing base usage. The Senior Credit
Facility contains various covenants including certain required financial
measurements for current and interest ratios and consolidated tangible net
worth. As of December 31, 2000 the Company was in compliance with all debt
covenants. In addition, the Senior Credit Facility contains the following
limitations:

  .  Mission and its subsidiaries will not sell all or substantially all of
     their assets to another person,

  .  none of Mission or its subsidiaries will incur additional indebtedness
     with the exception of permitted indebtedness,

  .  the indebtedness of Mission's subsidiaries will not exceed 10% of
     consolidated tangible net worth (indebtedness from subsidiaries to
     Mission or guarantors is permitted),

  .  none of Mission or its subsidiaries will make any restricted payments or
     restricted investments unless no default exists under the Senior Credit
     Facility and all such restricted payments and investments made since
     closing do not exceed the sum of (A) $5 million plus (B) 25%
     consolidated net income (less 100% of losses) plus (C) net cash proceeds
     of non-redeemable stock, provided, there are no payments made on
     permitted subordinated debt prior to stated maturity.

   On May 16, 2001, concurrent with the Bargo merger previously discussed, the
Senior Credit Facility was replaced with a $200.0 million credit facility
("Credit Facility") with an initial borrowing base of $185.0 million. The
borrowing base is determined from time to time by lenders based on the
Company's reserves and other factors deemed relevant by the lenders. Such
borrowing base was adjusted for acquisitions and financing activities,
primarily the issuance of senior subordinated notes, and at December 31, 2001
was $125.0 million with $90.0 million available. The interest rate on
borrowings is determined based upon the Company's credit rating and borrowing
base utilization. Interest can be either Prime plus a margin of up to 1% or
LIBOR plus a margin of 1.5% to 2.5%. The Credit Facility contains various
covenants including certain required financial measurements for current ratio,
ratio of total debt to EBITDAX and interest coverage ratio. Restrictions are
placed on debt, liens, dividends, leases and capital spending in foreign
operations. On December 31, 2001, $35.0 million was outstanding under the
Credit Facility and the Company was in compliance with its covenants under the
Credit Facility.

   Mission met with its lenders on March 5, 2002 to discuss the re-
determination of the borrowing base applicable to the Credit Facility and
effective April 1, 2002 the borrowing base has been redetermined at $100.0
million. Mission also requested amendments to its debt covenants in response
to the late 2001 and early 2002 decline in prices. Mission's debt covenants
for the four quarters of 2002 were amended with the required ratio of total
debt to EBITDAX being increased and the required interest coverage ratio being
reduced Borrowings through March 15, 2001, were $45.5 million outstanding
under the Credit Facility.

   In April 1997, the Company issued $100.0 million of 10 7/8% Senior
Subordinated Notes that mature April 1, 2007. On May 29, 2001, the Company
issued an additional $125.0 million of Senior Subordinated Notes due 2007 with
identical terms to the notes issued in April 1997 (collectively "Notes") at a
premium of $1.9 million. The premium is included in long-term debt on the
Balance Sheet. It will be amortized as a reduction of interest expense over
the life of the notes so that the effective interest rate on these additional
bonds is 10.5%. For the year 2001, approximately $200,000 of the premium had
been amortized. Interest on the Notes is payable semi-annually on April 1 and
October 1. The Notes will be redeemable, in whole or in part, at the option of
the Company at any time on or after April 1, 2002 at 105.44% which decreases
annually to 100.00% on April 1, 2005 and thereafter, plus accrued and unpaid
interest. In the event of a change of control of the Company, as

                                      63
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

defined in the indenture, each holder of the Notes will have the right to
require the Company to repurchase all or part of such holder's Notes at an
offer price in cash equal to 101.0% of the aggregate principal amount thereof,
plus accrued and unpaid interest to the date of purchase. The Notes contain
certain covenants, including limitations on indebtedness, restricted payments,
transactions with affiliates, liens, guarantees of indebtedness by
subsidiaries, dividends and other payment restrictions affecting restricted
subsidiaries, issuance and sales of restricted subsidiary stock, disposition
of proceeds of asset sales, and restrictions on mergers, and consolidations or
sales of assets.

9. Income Taxes

   Income tax expense (benefit) is summarized as follows (in thousands):

<TABLE>
<CAPTION>
                                          Year Ended   Year Ended   Year Ended
                                         December 31, December 31, December 31,
                                             2001         2000         1999
                                         ------------ ------------ ------------
   <S>                                   <C>          <C>          <C>
   Current
     Federal............................   $     --     $     67     $  (425)
     State..............................        595           18          10
   Deferred
     Federal............................   $(10,488)    $(13,506)    $(2,994)
     Foreign............................      ( 300)         300          --
     State..............................      1,138          899         255
                                           --------     --------     -------
   Total income tax benefit.............   $ (9,055)    $(12,222)    $(3,154)
                                           ========     ========     =======
</TABLE>

   The tax effect of temporary differences that give rise to significant
portions of the deferred tax assets and liabilities at December 31, 2001 and
2000 is as follows:

<TABLE>
<CAPTION>
                                                      December 31, December 31,
                                                          2001         2000
                                                      ------------ ------------
   <S>                                                <C>          <C>
   Net operating loss carryforwards..................   $ 12,487     $10,091
   Percentage depletion carryforwards................        279         271
   Alternative minimum tax credit carryforwards......        742         752
   Property, plant and equipment.....................         --       3,087
   State income taxes................................      2,134       1,138
   Impairment of interest in Carpatsky...............      2,186          --
   Other.............................................      1,689          --
                                                        --------     -------
   Total gross deferred tax assets...................     19,517      15,339
                                                        --------     -------
   Less valuation allowance..........................     (4,320)         --
                                                        --------     -------
   Net deferred income tax assets....................     15,197      15,339
                                                        --------     -------
   Property, plant and equipment.....................    (45,143)         --
   Taxes in SFAS No. 133 balance sheet account.......     (1,231)         --
   Foreign income taxes..............................         --        (198)
                                                        --------     -------
   Total deferred income tax liability...............    (46,374)       (198)
                                                        --------     -------
   Net deferred income tax asset (liability).........   $(31,177)    $15,141
                                                        ========     =======
</TABLE>

   At December 31, 2000, the Company determined that it was more likely than
not that the deferred tax assets would be realized based on current
projections of taxable income due to higher commodity prices at year end 2000,
and the valuation allowance was decreased by $19.8 million to zero. At
December 31, 2001, however, the

                                      64
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Company determined that a portion of the deferred tax assets would not be
realized. In assessing the realizability of the deferred tax assets,
management considers whether it is more likely than not that some portion or
all of the deferred tax assets will not be realized. The ultimate realization
of deferred tax assets is dependent upon the generation of future taxable
income during the periods in which those temporary differences become
deductible. Based upon the projections for future state taxable income,
management believes it is more likely than not that the Company will not
realize its deferred tax asset related to state income taxes. Based upon the
projections of future taxable income, management believes it is more likely
than not that the Company will not realize its deferred tax asset related to
the impairment in Carpatsky, as the reversal of the deferred tax asset will
result in a capital loss for federal income tax purposes, and the Company does
not project any transactions resulting in capital gains to offset the capital
loss. Therefore, the valuation allowance has been increased by $4.3 million
for the year ending December 31, 2001.

   A tax benefit related to the cumulative effect of a change in accounting
method of $1,663,000 was recorded and shown as part of the cumulative effect
on the consolidated statements of operations.

   A tax benefit related to the exercise of employee stock options of
approximately $240,000 and $95,000 was allocated directly to additional paid-
in capital in 2001 and 2000, respectively. Such benefit was not material in
1999.

   Total income tax differs from the amount computed by applying the Federal
income tax rate to income before income taxes, minority interest, and
cumulative adjustment. The reasons for the differences are as follows:

<TABLE>
<CAPTION>
                                          Year Ended   Year Ended   Year Ended
                                         December 31, December 31, December 31,
                                             2001         2000         1999
                                         ------------ ------------ ------------
   <S>                                   <C>          <C>          <C>
   Statutory federal income tax rate...      35.0%        34.0%        34.0%
   Increase (decrease) in tax rate
    resulting from:
     State income taxes, net of federal
      benefit..........................      (1.3%)        3.0%         3.1%
     Foreign income taxes, net of
      federal benefit..................       0.5%         1.0%          --
   Non-deductible travel and
    entertainment......................      (0.1%)        0.1%         0.2%
   Non-deductible goodwill
    amortization.......................      (0.9%)         --           --
   Other...............................        --           --          (.8%)
   Change in valuation allowance.......      (8.9%)      (99.3%)      (92.2%)
                                             ----        -----        -----
                                             24.3%       (61.2%)      (55.7%)
                                             ====        =====        =====
</TABLE>

   The Company issued 9.5 million shares of its common stock on May 16, 2001
in its acquisition of Bargo Energy Company. The Company issued 3.4 million
shares of its common stock on July 20, 1994. As a result of the 1994 common
stock issuance, the Company underwent an ownership change. Therefore, the
Company's ability to use a portion of its net operating loss ("NOL")
carryforwards for federal income tax purposes is subject to limitations.

   Section 382 of the Internal Revenue Code significantly limits the amount of
NOL and investment tax credit carryforwards that are available to offset
future taxable income and related tax liability when a change in ownership
occurs.

   At December 31, 2001, the Company had net operating loss carryforwards of
approximately $35.7 million, which will expire in future years beginning in
2002.

                                      65
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


10. Commitments and Contingencies

Lease Commitments

   The minimum future payments under the terms of the Company's office space
operating leases are as follows:

<TABLE>
<CAPTION>
            Year
            Ended
            December
            31         ($ in thousands)
            --------   ---------------
            <S>        <C>
              2002           819
              2003           597
              2004           601
              2005           601
              2006           601
</TABLE>

   Rent expense was $551,000, $509,000 and $16,023 in 2001, 2000 and 1999.

 Contingencies

   The Company has been named as a defendant in certain lawsuits incidental to
its business. Management does not believe that the outcome of such litigation
will have a material adverse impact on the Company.

   Mission is a defendant in Cause No. C-1313-97-D; Garza Energy Trust, et al.
V. Coastal Oil and Gas Corporation, et al.; in the 206th Judicial District
Court of Hidalgo County, Texas. The lawsuit addresses a 748.2 acre gas field
located in the Jeffress East Field and/or Jeffress S.E., Vicksberg Field,
Hidalgo County, Texas. Plaintiffs are royalty interest owners in these
properties and have made a number of claims including failure to properly
develop, drainage, subsurface trespass, improper payment of royalties, and
failure to properly market production. A modified judgement was signed in mid-
December 2001. The judgement awarded the Plaintiff damages of $250,000 against
Mission. Mission has accrued $250,000 as a reduction to earnings reported for
the period ended December 31, 2001.

11. Restructuring

   During the year the Company took several steps planned to enhance its asset
base, improve its cost structure and boost its competitive position in the
business environment presented by low oil and gas prices. Among those steps
were the reduction of staff by almost 50% and the termination of the Company's
administrative, accounting, information technology services and field
operations outsourcing contracts. The Company recorded $2.1 million associated
with these plans. The charge was included in general and administrative
expenses.

   During 2002, the Company has paid termination benefits of approximately
$600,000 associated with the termination of 17 employees and charged this
against the accrued liability. The remaining $1.5 million accrued liability is
expected to be paid in the next few months.

                                      66
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


12. Selected Quarterly Financial Data (amounts in thousands, except per share
data) (Unaudited):

<TABLE>
<CAPTION>
                                                Quarter Ended
                                 ---------------------------------------------
                                                             June
                                 December 31, September 30,   30,    March 31,
                                     2001         2001       2001      2001
                                 ------------ ------------- -------  ---------
   <S>                           <C>          <C>           <C>      <C>
   Revenues.....................   $ 32,522      $40,497    $35,243   $33,815
   Operating income (loss)......   $(39,099)     $ 1,429    $(9,432)  $ 9,869
   Net income (loss)............   $ 29,260      $   693    $(6,007)  $ 3,629
   Earnings (loss) per common
    share.......................   $  (1.24)     $  0.03    $ (0.32)  $  0.46
   Earnings (loss) per common
    shares--diluted.............   $ (1.24)      $  0.03    $(0.32)   $  0.44

<CAPTION>
                                                Quarter Ended
                                 ---------------------------------------------
                                                             June
                                 December 31, September 30,   30,    March 31,
                                     2000         2000       2000      2000
                                 ------------ ------------- -------  ---------
   <S>                           <C>          <C>           <C>      <C>
   Revenue......................   $ 35,924      $31,526    $26,669   $25,162
   Operating income.............   $    680      $ 8,639    $ 5,011   $ 5,656
   Net income...................   $    432      $ 5,357    $ 3,029   $23,390
   Earnings per common share....   $   0.03      $  0.38    $  0.22   $  1.69
   Earnings per common share--
    diluted.....................   $   0.03      $  0.37    $  0.21   $  1.67
</TABLE>

   The income in the quarter ended March 31, 2000 reflects the recognition of
a $19.8 million tax asset based upon increased future net reserves. The loss
in the quarter ended June 30, 2001 reflects the loss on sale of Ecuador
interests. The loss in the quarter ended December 31, 2001 includes the impact
of $27.0 million in pre-tax asset impairments.

13. Pro forma

   The merger with Bargo completed on May 16, 2001 significantly impacted the
future operating results of Mission Resources. The merger was accounted for as
a purchase, and the results of operations are included in Mission's results of
operations from May 16, 2001. The pro forma results are based on assumptions
and estimates and are not necessarily indicative of the Company's results of
operations had the transaction occurred as of January 1, 2000, or of those in
the future.

   The following table presents the unaudited pro forma results of operations
as if the merger had occurred on January 1, 2000 and 2001, respectively
(amounts in thousands, except earnings per share).

<TABLE>
<CAPTION>
                                                      Year Ended   Year Ended
                                                     December 31, December 31,
                                                         2001         2000
                                                     ------------ ------------
   <S>                                               <C>          <C>
   Revenues.........................................   $182,252     $226,260
   Income before cumulative effective of change in
    accounting method...............................   $(26,054)    $ 40,936
   Net income (loss)................................   $(28,821)    $ 40,936
   Net income (loss) per share......................   $  (1.22)    $   1.75
   Net income (loss) per share-diluted..............   $  (1.22)    $   1.73
</TABLE>

                                      67
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


14. Segment Reporting

   Through mid-2001, the Company's operations are concentrated primarily in
three segments: exploration and production of oil and natural gas in the
United States, in Ecuador and gas plants. The assets in Ecuador and two gas
plants were sold in 2001.

<TABLE>
<CAPTION>
                                                   Year Ended December 31,
                                                  ---------------------------
                                                    2001      2000     1999
                                                  --------  -------- --------
<S>                                               <C>       <C>      <C>
Sales to unaffiliated customers:
  Oil and gas--US................................ $131,358  $107,938 $ 68,264
  Oil and gas--Ecuador...........................    1,877     4,315       --
  Gas plants.....................................    4,456     6,070    3,830
                                                  --------  -------- --------
    Total sales..................................  137,691   118,323   72,094
  Interest and other income......................    4,386       957    1,335
                                                  --------  -------- --------
    Total revenues...............................  142,077   119,280   73,429
                                                  ========  ======== ========
Operating profit (loss) before income taxes:
  Oil and gas--US................................ $38, 549  $ 40,983 $ 22,570
  Oil and gas--Ecuador...........................   (1,698)      719      (17)
  Gas plants.....................................    2,338     3,393    1,464
  Gain on gas plant sale.........................    1,124        --       --
                                                  --------  -------- --------
                                                  $ 40,313  $ 45,095 $ 24,017
  Unallocated corporate expenses.................   10,998     9,734    6,513
  Interest expense...............................   23,664    15,375   11,845
  Mining venture costs...........................      914        --       --
  Loss on sale of Ecuador interests..............   12,724        --       --
  Impairment expense.............................   27,057        --       --
  Uncollectible gas revenue...................... $  2,189
                                                  --------  -------- --------
  Operating profit (loss) before income taxes.... $(37,233) $ 19,986 $  5,659
                                                  ========  ======== ========
Identifiable assets:
  Oil and gas--US................................ $379,738  $125,586 $123,686
  Oil and gas--Ecuador...........................       --    12,243    1,246
  Gas plants.....................................       --    11,107   11,641
                                                  --------  -------- --------
                                                  $379,738  $148,936 $136,573
  Corporate assets and investments...............   68,026    72,609   35,188
                                                  --------  -------- --------
    Total........................................ $447,764  $221,545 $171,761
                                                  ========  ======== ========
Capital expenditures:
  Oil and gas--US................................ $ 68,048  $ 76,242 $ 56,793
  Oil and gas--Ecuador...........................    4,151    12,130       --
  Gas plants.....................................    1,047       677      369
                                                  --------  -------- --------
                                                  $ 73,246  $ 89,049 $ 57,162
                                                  ========  ======== ========
Depreciation, depletion amortization and
 impairments:
  Oil and gas--US................................ $ 41,895  $ 30,356 $ 22,643
  Oil and gas--Ecuador...........................      504       745       --
  Gas plants.....................................    1,025     1,211    1,159
                                                  --------  -------- --------
                                                  $ 43,424  $ 32,312 $ 23,802
                                                  ========  ======== ========
</TABLE>

                                      68
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


15. Supplemental Information--(Unaudited)

 Oil and Gas Producing Activities:

   Included herein is information with respect to oil and gas acquisition,
exploration, development and production activities, which is based on
estimates of year-end oil and gas reserve quantities and estimates of future
development costs and production schedules. Reserve quantities and future
production are based primarily upon reserve reports prepared by the
independent petroleum engineering firm Ryder Scott Company for the years ended
December 31, 2000 and 1999. The reserve reports for the year ended December
31, 2001 were prepared by Ryder Scott Company, Netherland Sewell & Associates,
Inc., and T. J. Smith & Company, Inc. These estimates are inherently imprecise
and subject to substantial revision.

   Estimates of future net cash flows from proved reserves of gas, oil,
condensate and natural gas liquids were made in accordance with Statement of
Financial Accounting Standards No. 69, "Disclosures about Oil and Gas
Producing Activities." The estimates are based on prices at year-end.
Estimated future cash inflows are reduced by estimated future development
costs (including future abandonment and dismantlement), and production costs
based on year-end cost levels, assuming continuation of existing economic
conditions, and by estimated future income tax expense. Tax expense is
calculated by applying the existing statutory tax rates, including any known
future changes, to the pre-tax net cash flows, less depreciation of the tax
basis of the properties and depletion allowances applicable to the gas, oil,
condensate and NGL production. The impact of the net operating loss is
considered in calculation of tax expense. The results of these disclosures
should not be construed to represent the fair market value of the Company's
oil and gas properties. A market value determination would include many
additional factors including:

    1) anticipated future increases or decreases in oil and gas prices and
       production and development costs;

    2) an allowance for return on investment;

    3) the value of additional reserves not considered proved at the
       present, which may be recovered as a result of further exploration
       and development activities; and

    4) other business risks.

                                      69
<PAGE>

                 MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Costs Incurred (in thousands)

<TABLE>
<CAPTION>
                                                       Year Ended December 31,
                                                       ------------------------
                                                         2001    2000    1999
                                                       -------- ------- -------
<S>                                                    <C>      <C>     <C>
United States:
  Property acquisition:
    Proved properties*................................ $280,281 $ 5,065 $22,428
    Unproved properties...............................    4,100      --   2,406
    Exploration.......................................   12,489  13,139  14,052
  Development:
    Proved developed properties.......................   25,609  41,615  15,500
    Proved undeveloped properties.....................    6,462  16,423   1,352
                                                       -------- ------- -------
                                                       $328,941 $76,242 $55,738
                                                       -------- ------- -------
Ecuador:
  Property acquisition:
    Proved properties................................. $    249 $ 2,013 $   651
    Unproved properties...............................       --      --     404
  Development:
    Proved developed properties.......................    3,902  10,117      --
    Proved undeveloped properties.....................       --      --      --
                                                       -------- ------- -------
                                                       $  4,151 $12,130 $ 1,055
                                                       -------- ------- -------
Worldwide:
  Property acquisition:
    Proved properties................................. $280,530 $ 7,078 $23,079
    Unproved properties...............................    4,100      --   2,810
    Exploration.......................................   12,489  13,139  14,052
  Development:
    Proved developed properties.......................   29,511  51,732  15,500
    Proved undeveloped properties.....................    6,462  16,423   1,352
                                                       -------- ------- -------
                                                       $333,092 $88,372 $56,793
                                                       ======== ======= =======
</TABLE>
--------
* 2001 total includes $56.6 million of deferred taxes related to the Bargo
  merger.

                                       70
<PAGE>

                 MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Capitalized costs (in thousands):

<TABLE>
<CAPTION>
                                                              Year Ended
                                                             December 31,
                                                          --------------------
                                                            2001       2000
                                                          ---------  ---------
<S>                                                       <C>        <C>
United States:
Proved properties........................................ $ 738,375  $ 410,048
Unproved properties......................................    15,530     11,360
                                                          ---------  ---------
  Total capitalized costs................................   753,905    421,408
  Accumulated depreciation, depletion, Amortization and
   impairment............................................  (374,167)  (295,822)
                                                          ---------  ---------
    Net capitalized costs................................ $ 379,738  $ 125,586
                                                          ---------  ---------
Ecuador:
Proved properties........................................ $      --  $  12,988
Unproved properties......................................        --         --
                                                          ---------  ---------
  Total capitalized costs................................               12,988
  Accumulated depreciation, depletion, amortization and
   impairment............................................        --       (745)
                                                          ---------  ---------
    Net capitalized costs................................ $      --  $  12,243
                                                          ---------  ---------
Worldwide:
Proved properties........................................ $ 738,375  $ 423,036
Unproved properties......................................    15,530     11,360
                                                          ---------  ---------
  Total capitalized costs................................   753,905    434,396
  Accumulated depreciation, depletion, amortization and
   impairment............................................  (374,167)  (296,567)
                                                          ---------  ---------
    Net capitalized costs................................ $ 379,738  $ 137,829
                                                          =========  =========
</TABLE>

                                       71
<PAGE>

                 MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Results of operations for producing activities (in thousands):

<TABLE>
<CAPTION>
                                                     Year Ended December 31,
                                                               2001
                                                    ---------------------------
                                                      U.S.   Ecuador  Worldwide
                                                    -------- -------  ---------
<S>                                                 <C>      <C>      <C>
Revenues from oil and gas producing activities..... $131,358 $ 1,877  $133,235
Production expenses................................   48,134   3,071    51,205
Transportation costs...............................       73      --        73
Income tax.........................................    6,208      --     6,208
Impairment expense.................................   20,811      --    20,811
Depreciation, depletion and amortization...........   44,602     504    45,106
                                                    -------- -------  --------
Results of operations from producing activities
 (excluding corporate overhead and interest
 costs)............................................ $ 11,530 $(1,698) $  9,832
                                                    ======== =======  ========
</TABLE>

 Results of operations for producing activities (in thousands):

<TABLE>
<CAPTION>
                                                   Year Ended December 31, 2000
                                                  ------------------------------
                                                      U.S.     Ecuador Worldwide
                                                  ------------ ------- ---------
<S>                                               <C>          <C>     <C>
Revenues from oil and gas producing activities..    $107,938   $4,315  $112,253
Production expenses.............................      27,694    2,815    30,509
Disposition of hedges...........................       8,671       --     8,671
Transportation costs............................         234       36       270
Income tax......................................      15,574       --    15,574
Depreciation, depletion and amortization........      30,356      745    31,101
                                                    --------   ------  --------
Results of operations from producing activities
 (excluding corporate overhead and interest
 costs).........................................    $ 25,409   $  719  $ 26,128
                                                    ========   ======  ========

<CAPTION>
                                                   Year Ended
                                                  December 31,
                                                    1999(1)
                                                  ------------
<S>                                               <C>          <C>     <C>
Revenues from oil and gas producing activities..    $ 68,264
Production costs................................      21,532
Transportation costs............................         316
Income tax......................................       8,820
Depreciation, depletion and amortization........      22,643
                                                    --------
Results of operations from producing activities
 (excluding corporate overhead and interest
 costs).........................................    $ 14,953
                                                    ========
</TABLE>
--------
(1) Ecuador activities did not commence production until 2000; therefore, no
    prior year information for international operations is disclosed.

                                       72
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The Company's estimated total proved and proved developed reserves of oil
and gas are as follows:

<TABLE>
<CAPTION>
                                                             Year Ended
                                                         December 31, 2001
                                                       ------------------------
                                                         Oil     NGL      Gas
Description                                            (MBBL)   (MBBL)  (MMCF)
-----------                                            -------  ------  -------
<S>                                                    <C>      <C>     <C>
United States:
Proved reserves at beginning of year..................   9,669  1,655    74,729
Revisions of previous estimates.......................  (1,134)   488    (3,302)
Extensions and discoveries............................   2,430     80    25,126
Production............................................  (3,140)  (163)  (17,597)
Sales of reserves in-place............................  (3,883)    --   (15,927)
Purchase of reserves in-- place.......................  35,596     --    91,053
                                                       -------  -----   -------
Proved reserves at end of year........................  39,538  2,060   154,082
                                                       =======  =====   =======
Proved developed reserves--
  Beginning of year...................................   9,073  1,508    68,757
                                                       =======  =====   =======
  End of year.........................................  31,902  1,924    97,984
                                                       =======  =====   =======
Ecuador:(1)
Proved reserves at beginning of year..................   7,812     --        --
Production............................................     (95)    --        --
Sales of reserves in-place............................  (7,717)    --        --
                                                       -------  -----   -------
Proved reserves at end of year........................      --     --        --
                                                       =======  =====   =======
Proved developed reserves--
  Beginning of year...................................   2,135     --        --
                                                       =======  =====   =======
  End of year.........................................      --     --        --
                                                       =======  =====   =======
Worldwide:
Proved reserves at beginning of year..................  17,481  1,655    74,729
Revisions of previous estimates.......................  (1,134)   488    (3,302)
Extensions and discoveries............................   2,430     80    25,126
Production............................................  (3,235)  (163)  (17,597)
Sales of reserves in-place............................ (11,600)    --   (15,927)
Purchase of reserves in-place.........................  35,596     --    91,053
                                                       -------  -----   -------
Proved reserves at end of year........................  39,538  2,060   154,082
                                                       =======  =====   =======
Proved developed reserves--
  Beginning of year...................................  11,208  1,508    68,757
                                                       =======  =====   =======
  End of year.........................................  31,902  1,924    97,984
                                                       =======  =====   =======
</TABLE>
--------
(1) The Company's Ecuador reserves are pursuant to a contract with the
    Ecuadorian government under which the Company does not own the reserves
    but has a contractual right to produce the reserves and receive revenues.

                                      73
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


<TABLE>
<CAPTION>
                                                         Year Ended December
                                                              31, 2000
                                                        -----------------------
                                                         Oil     NGL      Gas
Description                                             (MBBL)  (MBBL)  (MMCF)
-----------                                             ------  ------  -------
<S>                                                     <C>     <C>     <C>
United States:
Proved reserves at beginning of year................... 10,827  2,069   130,079
Revisions of previous estimates........................  1,033     93   (21,291)
Extensions and discoveries.............................    613      4    18,418
Production............................................. (1,987)  (219)  (20,478)
Sales of reserves in-place.............................   (817)  (292)  (31,999)
Purchase of reserves in-- place........................     --     --        --
                                                        ------  -----   -------
Proved reserves at end of year.........................  9,669  1,655    74,729
                                                        ======  =====   =======
Proved developed reserves--
  Beginning of year....................................  9,990  2,032   108,491
                                                        ======  =====   =======
  End of year..........................................  9,073  1,508    68,757
                                                        ======  =====   =======
Ecuador: (1)
Proved reserves at beginning of year...................  3,884     --        --
Revisions of previous estimates........................   (714)    --        --
Production.............................................   (174)    --        --
Purchase of reserves in-place..........................  4,817     --        --
Proved reserves at end of year.........................  7,813
                                                        ======  =====   =======
Proved developed reserves--
  Beginning of year....................................    245     --        --
                                                        ======  =====   =======
  End of year..........................................  2,135     --        --
                                                        ======  =====   =======
Worldwide:
Proved reserves at beginning of year................... 14,711  2,069   130,079
Revisions of previous estimates........................    319     93   (21,291)
Extensions and discoveries.............................    613      4    18,418
Production............................................. (2,161)  (219)  (20,478)
Sales of reserves in-place.............................   (817)  (292)  (31,999)
Purchase of reserves in-place..........................  4,817     --        --
                                                        ------  -----   -------
Proved reserves at end of year......................... 17,482  1,655    74,729
                                                        ======  =====   =======
Proved developed reserves--
  Beginning of year.................................... 10,235  2,032   108,491
                                                        ======  =====   =======
  End of year.......................................... 11,208  1,508    68,757
                                                        ======  =====   =======
</TABLE>
--------
(1) The Company's Ecuador reserves are pursuant to a contract with the
    Ecuadorian government under which the Company does not own the reserves
    but has a contractual right to produce the reserves and receive revenues.

                                      74
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


<TABLE>
<CAPTION>
                                                         Year Ended December
                                                              31, 1999
                                                        -----------------------
                                                         Oil     NGL      Gas
Description                                             (MBBL)  (MBBL)  (MMCF)
-----------                                             ------  ------  -------
<S>                                                     <C>     <C>     <C>
United States:
Proved reserves at beginning of year...................  8,489  1,573   111,585
Revisions of previous estimates........................  2,671    798      (767)
Extensions and discoveries.............................    499     --    11,636
Production............................................. (1,831)  (249)  (18,965)
Sales of reserves in-place.............................   (262)   (60)   (6,754)
Purchase of reserves in-place..........................  1,261      7    33,344
                                                        ------  -----   -------
Proved reserves at end of year......................... 10,827  2,069   130,079
                                                        ======  =====   =======
Proved developed reserves--
  Beginning of year....................................  8,021  1,554   106,253
                                                        ======  =====   =======
  End of year..........................................  9,990  2,032   108,491
                                                        ======  =====   =======
Ecuador: (1)
Purchase of reserves in-place..........................  3,884     --        --
                                                        ------  -----   -------
Proved reserves at end of year.........................  3,884     --        --
                                                        ======  =====   =======
Proved developed reserves--
  Beginning of year....................................     --     --        --
                                                        ======  =====   =======
  End of year..........................................    245     --        --
                                                        ======  =====   =======
Worldwide:
Proved reserves at beginning of year...................  8,489  1,573   111,585
Revisions of previous estimates........................  2,671    798      (767)
Extensions and discoveries.............................    499   ----    11,636
Production............................................. (1,831)  (249)  (18,965)
Sales of reserves in-place.............................   (262)   (60)   (6,754)
Purchase of reserves in-place..........................  5,145      7    33,344
                                                        ------  -----   -------
Proved reserves at end of year......................... 14,711  2,069   130,079
                                                        ======  =====   =======
Proved developed reserves--
  Beginning of year....................................  8,021  1,554   106,253
                                                        ======  =====   =======
  End of year.......................................... 10,235  2,032   108,491
                                                        ======  =====   =======
</TABLE>
--------
(1) The Company's Ecuador reserves are pursuant to a contract with the
    Ecuadorian government under which the Company does not own the reserves
    but has a contractual right to produce the reserves and receive revenues.

                                      75
<PAGE>

                 MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   Discounted future net cash flows (in thousands)

   The standardized measure of discounted future net cash flows and changes
therein related to proved oil and gas reserves are shown below:

<TABLE>
<CAPTION>
                                                  Year Ended December 31,
                                              ---------------------------------
                                                 2001        2000       1999
                                              ----------  ----------  ---------
<S>                                           <C>         <C>         <C>
United States:
Future cash flow............................. $1,200,145  $  950,121  $ 535,605
Future production costs......................   (502,083)   (203,464)  (202,800)
Future income taxes..........................   (112,364)   (183,139)   (23,234)
Future development costs.....................    (97,644)    (36,874)   (54,034)
                                              ----------  ----------  ---------
Future net cash flows........................    488,054     526,644    255,537
10% discount factor..........................   (192,483)   (133,062)   (63,933)
                                              ----------  ----------  ---------
Standardized future net cash flows........... $  295,571  $  393,582  $ 191,604
                                              ==========  ==========  =========
Ecuador:
Future cash flow............................. $       --  $  174,632  $  88,089
Future production costs......................         --     (60,899)   (34,534)
Future income taxes..........................         --     (37,793)    (9,860)
Future development costs.....................         --     (27,595)   (13,273)
                                              ----------  ----------  ---------
Future net cash flows........................         --      48,345     30,422
10% discount factor..........................         --     (18,835)   (17,138)
                                              ----------  ----------  ---------
Standardized future net cash flows........... $       --  $   29,510  $  13,284
                                              ==========  ==========  =========
Worldwide:
Future cash flow............................. $1,200,145  $1,124,753  $ 623,694
Future production costs......................   (502,083)   (264,363)  (237,334)
Future income taxes..........................   (112,364)   (220,932)   (33,094)
Future development costs.....................    (97,644)    (64,469)   (67,307)
                                              ----------  ----------  ---------
Future net cash flows........................    488,054     574,989    285,959
10% discount factor..........................   (192,483)   (151,897)   (81,071)
                                              ----------  ----------  ---------
Standardized future net cash flows........... $  295,571  $  423,092  $ 204,888
                                              ==========  ==========  =========
</TABLE>

                                       76
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands of dollars):

<TABLE>
<CAPTION>
                                                 Year Ended December 31, 2001
                                                 ------------------------------
                                                            United      World
                                                 Ecuador    States      Wide
                                                 --------  ---------  ---------
<S>                                              <C>       <C>        <C>
Standardized measure--beginning of year........  $ 29,510  $ 393,582  $ 423,092
Sales, net of production costs.................     1,194    (83,151)   (81,957)
Purchases of reserves in-place.................        --    618,442    618,442
Net change in prices and production costs......        --   (727,143)  (727,143)
Net change in income taxes.....................    18,577     30,994     49,571
Extensions, discoveries and improved recovery,
 net of future production and development
 costs.........................................        --     62,308     62,308
Changes in estimated future development costs..        --    (27,152)   (27,152)
Development costs incurred during the period...     3,736     21,584     25,320
Revisions of quantity estimates................        --     18,376     18,376
Accretion of discount..........................     2,950     39,358     42,308
Sales of reserves in-place.....................   (53,017)   (89,139)  (142,156)
Changes in production rates and other..........    (2,950)    37,512     34,562
                                                 --------  ---------  ---------
Standardized measure--end of year..............  $     --  $ 295,571  $ 295,571
                                                 ========  =========  =========

<CAPTION>
                                                 Year Ended December 31, 2000
                                                 ------------------------------
                                                            United      World
                                                 Ecuador    States      Wide
                                                 --------  ---------  ---------
<S>                                              <C>       <C>        <C>
Standardized measure--beginning of year........  $ 13,284  $ 191,604  $ 204,888
Sales, net of production costs.................    (1,500)   (80,244)   (81,744)
Purchases of reserves in-place.................    28,389         --     28,389
Net change in prices and production costs......   (23,174)   375,242    352,068
Net change in income taxes.....................   (14,430)  (113,444)  (127,874)
Extensions, discoveries and improved recovery,
 net of future production and development
 costs.........................................        --     56,283     56,283
Changes in estimated future development costs..    (1,990)    (4,942)    (6,932)
Development costs incurred during the period...     4,329     31,095     35,424
Revisions of quantity estimates................    (6,787)   (46,271)   (53,058)
Accretion of discount..........................     1,329     19,160     20,489
Sales of reserves in-place.....................        --    (34,697)   (34,697)
Changes in production rates and other..........    30,060       (204)    29,856
                                                 --------  ---------  ---------
Standardized measure--end of year..............  $ 29,510  $ 393,582  $ 423,092
                                                 ========  =========  =========
</TABLE>

                                      77
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


<TABLE>
<CAPTION>
                                                    Year Ended December 31,
                                                             1999
                                                   ---------------------------
                                                             United    World
                                                   Ecuador   States     Wide
                                                   -------  --------  --------
<S>                                                <C>      <C>       <C>
Standardized measure--beginning of year..........  $    --  $115,980  $115,980
Sales, net of production costs...................       --   (50,430)  (50,430)
Purchases of reserves in-place...................   17,431    40,488    57,919
Net change in prices and production costs........       --    40,736    40,736
Net change in income taxes.......................   (4,147)       --    (4,147)
Extensions, discoveries and improved recovery,
 net of future production and development costs..       --    23,497    23,497
Changes in estimated future development costs....       --    (3,304)   (3,304)
Development costs incurred during the period.....       --     8,930     8,930
Revisions of quantity estimates..................       --    20,565    20,565
Accretion of discount............................       --    11,598    11,598
Sales of reserves in-place.......................       --    (6,575)   (6,575)
Changes in production rates and other............       --    (9,881)   (9,881)
                                                   -------  --------  --------
Standardized measure--end of year................  $13,284  $191,604  $204,888
                                                   =======  ========  ========
</TABLE>

   The discounted future cash flows above were calculated using the NYMEX WTI
Cushing price for oil and the NYMEX Henry Hub price for gas that was posted
for the last trading day of each year presented. Those prices were $19.76,
$26.80, and $25.60 per barrel and $2.73, $9.52, and $2.33 per MMBTU, for
December 31, 2001, 2000, and 1999, respectively, adjusted to the wellhead to
reflect adjustments for transportation, quality and heating content. The
foregoing discounted future net cash flows do not include the effects of
hedging or other derivative contracts not specific to a property. Including
the tax effected impact of hedging on discounted future net cash flows would
have increased discounted future net cash flows by approximately $5.7 million
and $370,000 as of December 31, 2001 and 1999, respectively. Including the tax
effected impact of hedging on discounted future cash flows would have
decreased discounted future net cash flows by approximately $35.7 million as
of December 31, 2000.

                                      78
<PAGE>

                MISSION RESOURCES CORPORATION AND SUBSIDIARIES

                                   PART III

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

   None

Item 10. Directors and Executive Officers of the Registrant

   The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120
days after December 31, 2001. Such information is incorporated herein by
reference.

Item 11. Executive Compensation

   The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120
days after December 31, 2001. Such information is incorporated herein by
reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management

   The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120
days after December 31, 2001. Such information is incorporated herein by
reference.

Item 13. Certain Relationships and Related Transactions

   The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120
days after December 31, 2001. Such information is incorporated herein by
reference.

                                    PART IV

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

   (a)

<TABLE>
 <C>        <S>
 1. and 2.  Financial Statements. See index to Consolidated Financial
            Statements and Supplemental Information in Item 8, which
            information is incorporated herein by reference.

        2.1 Agreement and Plan of Merger dated January 24, 2001 between the
            Company and Bargo Energy Company (incorporated by reference to
            Exhibit 2.1 to the Company's 8-K dated January 26, 2001).

        3.  Exhibits

        3.1 Certificate of Incorporation of Mission Resources Corporation
            (incorporated by reference to Exhibit 3.1 to the Company's
            Registration Statement No. 33-76570)

        3.2 Certificate of Amendment to Certificate of Incorporation
            (incorporated by reference to Exhibit 3.2 to the Company's Annual
            Report on Form 10-K for the fiscal year ended June 30, 1997)

        3.3 Certificate of Designation, Preferences and Rights of Series A
            Preferred Stock (incorporated by reference to Exhibit 1 to the
            Company's Registration Statement on Form 8-A dated September 19,
            1997.)
</TABLE>


                                      79
<PAGE>

<TABLE>
 <C>  <S>
  3.4 By-laws of Mission Resources Corporation (incorporated by reference to
      Exhibit 3.2 to the Company's Registration Statement No. 33-76570)

  3.5 Amendment to Article II, Section 2.2 of Mission Resources Corporation's
      Bylaws (incorporated by reference to Exhibit 3.5 to the Company's Annual
      Report on Form 10-K for the transition period ended December 31, 1997)

  3.6 Amendment to Mission Resources Corporation's bylaws adopted on March 27,
      1998 (incorporated by reference to Exhibit 3.6 to the Company's Annual
      Report on Form 10-K for the transition period ended December 31, 1997)

  4.1 Specimen Stock Certificate (incorporated by reference to Exhibit 4.1 to
      the Company's Registration Statement on Form S-1, File No. 33-76570)

  4.2 The Company's 1996 Stock Incentive Plan (incorporated by reference to
      Exhibit 10.20 to the Company's Registration Statement on Form S-1, File
      No. 33-21813)

  4.3 Indenture dated April 9, 1997 among the Company, a Subsidiary Guarantor
      and Bank of Montreal Trust Company (incorporated by reference to Exhibit
      4.2 to the Company's Registration Statement on Form S-1, Registration No.
      33-21813)

  4.4 First Supplemental Indenture dated April 21, 1997 among the Company,
      Odyssey Petroleum Company, Black Hawk Oil Company, 1989-I TEAI Limited
      Partnership and Bank of Montreal Trust Company, as Trustee (incorporated
      by reference to Exhibit 99.2 on the Company's Form 8-K Current Report
      filed on April 23, 1997)

  4.5 Shareholders Rights Agreement between the Company and American Stock
      Transfer & Trust Company (incorporated herein by reference to the
      Company's Registration Statement on Form 8-A as filed with the Securities
      and Exchange Commission on September 19, 1997)

  4.6 Warrant to Torch Energy Dated April 9. 1997 (incorporated by reference to
      Exhibit 4.6 to the Company's Annual Report on Form 10-K for the fiscal
      year ended June 30, 1997)

  4.7 Indenture dated May 29, 2001 among Mission Resources Corporation, the
      Subsidiary Guarantors named therein and the Bank of New York, as Trustee
      (incorporated by reference to Exhibit 4.1 of the Company's Registration
      Statement on Form S-4, filed on July 27, 2001)

  4.8 Exchange and Registration Rights Agreement dated as of May 29, 2001 among
      Mission Resources Corporation, the Subsidiary Guarantors listed on
      Schedule 1 thereto, JPMorgan Securities Inc and Merrill Lynch, Pierce,
      Fenner & Smith Incorporated (incorporated by reference to Exhibit 4.3 of
      the Company's Registration Statement on Form S-4, filed on July 27, 2001)

 10.1 1994 Stock Incentive Plan (incorporated by reference to Exhibit 10.9 to
      the Company's Registration Statement No. 33-76570)

 10.2 Acquisition Agreement dated March 31, 1997 among Mission Resources
      Corporation, Program Acquisition Company and the other parties thereto.
      (incorporated by reference to Exhibit 2.2 of the Company's Registration
      Statement on Form S-1 (Registration No. 333-21813) filed on April 3,
      1997)

 10.3 Credit Agreement dated April 21, 1997 among the Company, Odyssey
      Petroleum Company, Black Hawk Oil Company, 1989-I TEAI Limited
      Partnership, Morgan Guarantee Trust Company of New York, as
      administrative Agent, and certain banking institutions (incorporated by
      reference to the Company's Form 8-K Current Report as filed with the
      Commission on April 23, 1997).

 10.4 Purchase and Sale Agreement dated June 9, 1997 among Mission Resources
      Corporation, Black Hawk Oil Company, 1988-II TEAI Limited Partnership,
      1989-I TEAI Limited Partnership, TEAI Oil and Gas Company, and the other
      parties thereto as Sellers, and Jay Resources Corporation as Buyer
      (incorporated by reference to Exhibit 10.18 to the Company's Annual
      Report on Form 10-K for the fiscal year ended June 30, 1997)
</TABLE>


                                       80
<PAGE>

<TABLE>
 <C>   <S>
 10.5  Employment contract dated June 1, 1998 between the Company and J. Darby
       Sere' (incorporated by reference to Exhibit 10.1 to the Company's 10-Q
       for the quarter ended June 30, 1998)

 10.6  Employment contract dated June 1, 1998 between the Company and William
       C. Rankin (incorporated by reference to Exhibit 10.2 to the Company's
       Report on Form 10-Q for the quarter ended June 30, 1998)

 10.7  Purchase and Sale Agreement dated June 11, 1999 between Bellwether
       Exploration Company as Buyer and Energen Resources MAQ, Inc. as Seller
       (incorporated by reference to Exhibit 10.15 to the Company's Report on
       Form 10-Q for the quarter ended June 30, 1999)

 10.8  Separation contract dated August 9, 1999 between the Company and J.
       Darby Sere' (incorporated by reference to Exhibit 10.16 to the Company's
       Report on Form 10Q for the quarter ended June 30, 1999)

 10.9  Separation contract dated August 9, 1999 between the Company and William
       C. Rankin (incorporated herein by reference to Exhibit 10.17 to the
       Company's Report on Form 10-Q for the quarter ended June 30, 1999)

 10.10 Employment Contract dated August 1, 1999 between the Company and J.P.
       Bryan (incorporated herein by reference to Exhibit 10.18 to the
       Company's Report on Form 10-Q for the quarter ended September 30, 1999)

 10.11 Securities Purchase Agreement dated December 29, 1999 by and between the
       Company and Carpatsky Petroleum, Inc.--(incorporated by references to
       Exhibit 11.14 to the Company's Annual Report on Form 10-K for the year
       ended December 31,1999)

 10.12 Master Services Agreement dated October 1, 1999 between the Company and
       Torch Operating Company, Torch Energy Marketing, Inc., Torch Energy
       Advisors, Inc. and Novistar, Inc., -(incorporated by references to
       Exhibit 11.15 to the Company's Annual Report on Form 10-K for the year
       ended December 31,1999)

 10.13 Contract for the Production of Crude Oil and Additional Hydrocarbon
       Exploration in the Charapa Marginal Field of Petroecuador between the
       Company in Consortium with Tecnipetrol, Inc. and the Ecuadorian State
       Oil Company, Petroecuador --(incorporated by references to Exhibit 11.16
       to the Company's Annual Report on Form 10-K for the year ended December
       31,1999)

 10.14 Master Service Agreement between the Company and Tecnie S.A.C. dated
       November 1, 1999----(incorporated by references to Exhibit 10.17 to the
       company's annual report on form 10-K for the year ended December
       31,1999)

 10.15 Employment contract dated May 15, 2000 between the Company and Douglas
       G. Manner (incorporated by reference to Exhibit 10.20 to the Company's
       Report on Form 10-Q for the quarter ended June 30, 2000)

 10.16 Separation agreement dated January 1, 2001 between the Company and
       Robert J. Bensh--(incorporated by reference to Exhibit 10.19 to the
       Company's Annual Report on Form 10-K/A for the year ended December 2000)

 10.17 Employment contract dated January 15, 2001 between the Company and Kent
       Williamson--(incorporated by reference to Exhibit 10.20 to the Company's
       Annual Report on Form 10-K/A for the year ended December 2000)

 10.18 Contract for Crude Oil Production and Additional Exploration of
       Hydrocarbons in the Marginal Field Tiguino (incorporated by reference to
       Exhibit 10.19 to the Company's Proxy Statement filed April 24, 2001)

 10.19 Credit Agreement dated May 16, 2001 among Mission Resources Corporation
       as borrower, The Chase Manhattan Bank as administrative agent, BNP
       Paribas as syndication agent, First Union National Bank and Fleet
       National Bank as co-documentation agents--included herewith
</TABLE>

                                       81
<PAGE>

<TABLE>
<S>    <C>
11.22  Form of Voting Agreement (incorporated by reference to the Company's 8-K dated January 26, 2001)

21.1   Subsidiaries of Mission Resources Corporation--included herewith

  23   Consents of experts:

23.2   Consent of Ryder Scott Company--included herewith

23.3   Consent of KPMG LLP--included herewith

23.4   Consent of Netherland Sewell & Associates, Inc.--included herewith

23.5   Consent of T.J. Smith & Company, Inc.--included herewith
</TABLE>

                                       82
<PAGE>

                         GLOSSARY OF OIL AND GAS TERMS

Terms used to describe quantities of oil and natural gas

  .  Bbl--One stock tank barrel, or 42 US gallons liquid volume, of crude oil
     or other liquid hydrocarbons.

  .  Bcf--One billion cubic feet of natural gas.

  .  Bcfe--One billion cubic feet of natural gas equivalent.

  .  BOE--One barrel of oil equivalent, converting gas to oil at the ratio of
     6 Mcf of gas to 1 Bbl of oil.

  .  MBbl--One thousand Bbls.

  .  Mcf--One thousand cubic feet of natural gas.

  .  MMBbl--One million Bbls of oil or other liquid hydrocarbons.

  .  MMcf--One million cubic feet of natural gas.

  .  MBOE--One thousand BOE.

  .  MMBOE--One million BOE.

Terms used to describe the Company's interests in wells and acreage

  .  Gross oil and gas wells or acres--The Company's gross wells or gross
     acres represent the total number of wells or acres in which the Company
     owns a working interest.

  .  Net oil and gas wells or acres--Determined by multiplying "gross" oil
     and natural gas wells or acres by the working interest that the Company
     owns in such wells or acres represented by the underlying properties.

Terms used to assign a present value to the Company's reserves

  .  Standard measure of proved reserves--The present value, discounted at
     10%, of the pre-tax future net cash flows attributable to estimated net
     proved reserves. The Company calculates this amount by assuming that it
     will sell the oil and gas production attributable to the proved reserves
     estimated in its independent engineer's reserve report for the prices it
     received for the production on the date of the report, unless it had a
     contract to sell the production for a different price. The Company also
     assumes that the cost to produce the reserves will remain constant at
     the costs prevailing on the date of the report. The assumed costs are
     subtracted from the assumed revenues resulting in a stream of future net
     cash flows. Estimated future income taxes using rates in effect on the
     date of the report are deducted from the net cash flow stream. The
     after-tax cash flows are discounted at 10% to result in the standardized
     measure of the Company's proved reserves.

  .  Pre-tax discounted present value--The discounted present value of proved
     reserves is identical to the standardized measure, except that estimated
     future income taxes are not deducted in calculating future net cash
     flows. The Company discloses the discounted present value without
     deducting estimated income taxes to provide what it believes is a better
     basis for comparison of its reserves to the producers who may have
     different tax rates.

Terms used to classify our reserve quantities

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

                                      83
<PAGE>

   The SEC definition of proved oil and gas reserves, per Article 4-10(a)(2)
of Regulation S-X, is as follows:

     Proved oil and gas reserves. Proved oil and gas reserves are 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, i.e., prices and costs as of the date
  the estimate is made. Prices include consideration of changes in existing
  prices provided only by contractual arrangements, but not on escalations
  based upon future conditions.

     (a) Reservoirs are considered proved if economic producibility is
  supported by either actual production or conclusive formation test. The
  area of a reservoir considered proved includes (A) that portion delineated
  by drilling and defined by gas-oil and/or oil-water contacts, if any; and
  (B) the immediately adjoining portions not yet drilled, but which can be
  reasonably judged as economically productive on the basis of available
  geological and engineering data. In the absence of information on fluid
  contacts, the lowest known structural occurrence of hydrocarbons controls
  the lower proved limit of the reservoir.

     (b) Reserves which can be produced economically through application of
  improved recovery, techniques (such as fluid injection) are included in the
  "proved" classification when successful testing by a pilot project, or the
  operation of an installed program in the reservoir, provides support for
  the engineering analysis on which the project or program was based.

     (c) Estimates of proved reserves do not include the following: (1) oil
  that may become available from known reservoirs but is classified
  separately as "indicated additional reserves"; (2) crude oil, natural gas,
  and natural gas liquids, the recovery of which is subject to reasonable
  doubt because of uncertainty as to geology, reservoir characteristics, or
  economic factors; (3) crude oil, natural gas, and natural gas liquids, that
  may occur in undrilled prospects; and (4) crude oil, natural gas, and
  natural gas liquids, that may be recovered from oil shales, coal, gilsonite
  and other such sources.

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

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

Terms which describe the cost to acquire the Company's reserves

  .  Finding costs--The Company's finding costs compare the amount the
     Company spent to acquire, explore and develop its oil and gas
     properties, explore for oil and gas and to drill and complete wells
     during a period, with the increases in reserves during the period. This
     amount is calculated by dividing the net change in the Company's
     evaluated oil and property costs during a period by the change in proved
     reserves plus production over the same period. The Company's finding
     costs as of December 31 of any year represent the average finding costs
     over the three-year period ending December 31 of that year.

Terms which describe the productive life of a property or group of properties

  .  Reserve life--A measure of the productive life of an oil and gas
     property or a group of oil and gas properties, expressed in years.
     Reserve life for the years ended December 31, 2001, 2000 or 1999 equal
     the estimated net proved reserves attributable to a property or group of
     properties divided by production from the property or group of
     properties for the four fiscal quarters preceding the date as of which
     the proved reserves were estimated.

Terms used to describe the legal ownership of the Company's oil and gas
properties

  .  Royalty interest--A real property interest entitling the owner to
     receive a specified portion of the gross proceeds of the sale of oil and
     natural gas production or, if the conveyance creating the interest
     provides,

                                      84
<PAGE>

    a specific portion of oil and natural gas produced, without any deduction
    for the costs to explore for, develop or produce the oil and natural gas.
    A royalty interest owner has no right to consent to or approve the
    operation and development of the property, while the owners of the
    working interests have the exclusive right to exploit the mineral on the
    land.

  .  Working interest--A real property interest entitling the owner to
     receive a specified percentage of the proceeds of the sale of oil and
     natural gas production or a percentage of the production, but requiring
     the owner of the working interest to bear the cost to explore for,
     develop and produce such oil and natural gas. A working interest owner
     who owns a portion of the working interest may participate either as
     operator or by voting his percentage interest to approve or disapprove
     the appointment of an operator and drilling and other major activities
     in connection with the development and operation of a property.

Terms used to describe seismic operations

  .  Seismic data--Oil and gas companies use seismic data as their principal
     source of information to locate oil and gas deposits, both to aid in
     exploration for new deposits and to manage or enhance production from
     known reservoirs. To gather seismic data, an energy source is used to
     send sound waves into the subsurface strata. These waves are reflected
     back to the surface by underground formations, where they are detected
     by geophones which digitize and record the reflected waves. Computers
     are then used to process the raw data to develop an image of underground
     formations.

  .  2-D seismic data--2-D seismic survey data has been the standard
     acquisition technique used to image geologic formations over a broad
     area. 2-D seismic data is collected by a single line of energy sources
     which reflect seismic waves to a single line of geophones. When
     processed, 2-D seismic data produces an image of a single vertical plane
     of sub-surface data.

  .  3-D seismic--3-D seismic data is collected using a grid of energy
     sources, which are generally spread over several miles. A 3-D survey
     produces a three dimensional image of the subsurface geology by
     collecting seismic data along parallel lines and creating a cube of
     information that can be divided into various planes, thus improving
     visualization. Consequently, 3-D seismic data is a more reliable
     indicator of potential oil and natural gas reservoirs in the area
     evaluated.

The Company's miscellaneous definitions

  .  Infill drilling--Infill drilling is the drilling of an additional well
     or additional wells in excess of those provided for by a spacing order
     in order to more adequately drain a reservoir.

  .  No. 6 fuel oil (Bunker)--No. 6 fuel oil is a heavy residual fuel oil
     used by ships, industry, and for large-scale heating installations.

  .  Upstream oil and gas properties--Upstream is a term used in describing
     operations performed before those at a point of reference. Production is
     an upstream operation and marketing is a downstream operation when the
     refinery is used as a point of reference. On a gas pipeline, gathering
     activities are considered to have ended when gas reaches a central point
     for delivery into a single line, and facilities used before this point
     of reference are upstream facilities used in gathering, whereas
     facilities employed after commingling at the central point and employed
     to make ultimate delivery of the gas are downstream facilities.

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<PAGE>

                 MISSION RESOURCES CORPORATION AND SUBSIDIARIES

                                   SIGNATURES

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

                                          MISSION RESOURCES CORPORATION

                                                   /s/ Douglas Manner
                                          By: _________________________________
                                                    Douglas G. Manner
                                           Chief Executive Officer & Chairman

Dated March 28, 2002

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

<TABLE>
<CAPTION>
              Signatures                         Title                   Date
              ----------                         -----                   ----

<S>                                    <C>                        <C>
      /s/ Jonathon Clarkson            President--Chief Financial   March 28, 2002
______________________________________  Officer
          Jonathon Clarkson

        /s/ Ann Kaesermann             Vice President--Chief        March 28, 2002
______________________________________  Accounting Officer
            Ann Kaesermann

          /s/ July Allen               Director                     March 28, 2002
______________________________________
              July Allen

         /s/ J. P. Bryan               Director                     March 28, 2002
______________________________________
             J. P. Bryan

                                       Director
______________________________________
             Tim J. Goff

      /s/ D. Martin Phillips           Director                     March 28, 2002
______________________________________
          D. Martin Phillips

        /s/ Robert Rooney              Director                     March 28, 2002
______________________________________
           Robert R. Rooney
</TABLE>

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