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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, 2000

                                      OR

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

                         Commission File Number 0-9498

                        BELLWETHER EXPLORATION COMPANY
            (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 14, 2001 was approximately $114,125,643.

   As of March 14, 2001, the number of outstanding shares of the registrant's
common stock was 14,046,233.

   Documents Incorporated by Reference: Portions of the registrant's annual
proxy statement, to be filed within 120 days after December 31, 2000, are
incorporated by reference into Part III.

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                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

                           Annual Report on Form 10-K
                      For the Year Ended December 31, 2000

                               TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                         Page
                                                                        Number
                                                                        ------
 <C>         <S>                                                        <C>
 PART I
    Item 1.  Business.................................................     3
    Item 2.  Properties...............................................     9
    Item 3.  Legal Proceedings........................................    18
    Item 4.  Submission of Matters to a Vote of Security Holders......    18
 PART II
    Item 5.  Market for the Registrant's Common Equity and Related
             Stockholder Matters......................................    19
    Item 6.  Selected Financial Data..................................    20
    Item 7.  Management's Discussion and Analysis of Financial
              Condition and Results of Operations.....................    20
    Item 7a. Quantitative and Qualitative Disclosures About Market
             Risk.....................................................    29
    Item 8.  Financial Statements and Supplementary Data..............    30
    Item 9.  Changes in and Disagreements with Accountants on
              Accounting and Financial Disclosure.....................    61
 PART III
    Item 10. Directors and Executive Officers of the Registrant.......    61
    Item 11. Executive Compensation...................................    61
    Item 12. Security Ownership of Certain Beneficial Owners and
             Management...............................................    61
    Item 13. Certain Relationships and Related Transactions...........    61
 PART IV
    Item 14. Exhibits, Financial Statement Schedules and Reports on
             Form 8-K.................................................    61
    Signatures.........................................................   64
</TABLE>

                                       2
<PAGE>

                BELLWETHER EXPLORATION COMPANY 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
included herein regarding the Company's financial position, estimated
quantities and net present values of reserves, business strategy, plans and
objectives for future operations and covenant compliance, are forward-looking
statements. The Company 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 Company's
expectations ("cautionary statements") are disclosed under Risk Factors and
elsewhere herein. All subsequent written and oral forward-looking statements
attributable to the Company or persons acting on its behalf are expressly
qualified by the cautionary statements.

General

   Bellwether Exploration Company ("Bellwether" or the "Company") is an
independent energy company engaged in the acquisition, exploitation,
development, exploration and production of oil and gas properties. The
Company's core areas of activity are the Texas/Louisiana Gulf Coast, both
onshore and offshore, southeastern New Mexico, and West Texas. At December 31,
2000, the Company's estimated net proved reserves, using constant prices which
were in effect at such date, totaled 17.5 MMBbl of oil, 1.7 MMBbl of natural
gas liquids ("NGL"), and 75 Bcf of natural gas for a total of 31.6 million
barrels of oil equivalent ("MBOE"). On an equivalency basis, approximately 39%
of the Company's estimated net proved reserves were natural gas and
approximately 77% of the reserves were developed at such date. In addition to
its leasehold interests, the Company has interests in natural gas processing
plants in California and West Texas.

   The Company is party to a Master Service Agreement dated October 1, 1999,
("Master Service Agreement") and six specific contracts ("Contracts") which
require Torch Energy Advisors, Inc ("Torch") to administer certain activities
of the Company including oil and gas marketing, operation of oil and gas
properties, land functions, accounting, risk management, legal and information
technology. 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 Contracts have initial terms ranging from two to five
years. Neither the Master Service Agreement nor the Contracts may be
terminated by Torch prior to the expiration of their initial terms. The
various Contracts have annual fees ranging from fixed and variable amounts of
$0.6 million to $3.0 million plus fees based upon percentages of production
ranging from 1/2% to 2%, depending on the product.

   In order to facilitate greater comparability with its peer group by the
financial community, the Company 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 ("transition period").

Proposed Merger

   On January 24, 2001, the Company entered into an Agreement and Plan of
Merger with Bargo Energy Company ("Bargo"). Pursuant to the agreement and plan
of merger Bargo will be merged with and into Bellwether, and Bellwether will
be renamed. Contemporaneously with the merger, Bellwether proposes to increase
its authorized common stock to 65.0 million shares and amend its 1996 Stock
Incentive Plan to increase the number of shares reserved for issuance under
the plan by 2.0 million shares. Bargo shareholders will receive a combination
of cash and Bellwether stock as consideration for the merger. The merger is
subject to the adoption

                                       3
<PAGE>

and approval of the agreement and plan of merger by the Bellwether
stockholders and the Bargo stockholders, and the absence of any law or court
order preventing the merger. It is anticipated that Bellwether's stockholder
meeting will be held in the second quarter of 2001. The merger will be
accounted for using the purchase method of accounting.

Oil and Gas Activities

   In 1987 and 1988, the Company merged with two independent oil and gas
companies owned by institutional investors and managed by Torch Energy
Advisors Incorporated ("Torch"). Since those mergers, the Company has operated
under agreements, pursuant to which the Company outsources certain
administrative functions to Torch.

   In April 1997, the Company acquired oil and gas properties and $13.9
million of working capital from affiliates of Torch ("Partnership
Transactions"), for $141.1 million after purchase price adjustments. The
Company financed the Partnership Transactions and related fees, with $34.1
million net proceeds of a common stock offering, $97.0 million net proceeds of
$100.0 million offering of 10 7/8% Senior Subordinated Notes due 2007 (the
"Offerings") and advances under a new credit facility ("Senior Credit
Facility"). In addition, as consideration for advisory services, Torch was
issued 150,000 shares of the Company's common stock and a warrant, expiring in
April 2002, to purchase 100,000 shares of common stock at $9.90 per share. The
warrant and shares were valued at $1.5 million and recorded as a cost of the
Partnership Transactions.

   In December 1998, Bellwether was the successful bidder for the Charapa
field in Ecuador and, as a result, 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. Bellwether is also entitled to recoup lease
operating expenses associated with the base production. Bellwether took over
operations of the field in January 2000. In February 2000, Bellwether took
over operations of another Ecuadorian field, the Tiguino field. The contract
with the government is similar for both fields. A Bellwether subsidiary
operates the field on behalf of Petroleos Colombianos ("Petrocol"), which had
been granted a 25% interest and operatorship by the Ecuadorian government.
Bellwether negotiated with Petrocol and other interest owners and by July 2000
had increased its interest to 70% and had been assigned the field
operatorship. Agreements transferring ownership and operatorship in the
Tiguino field have been signed by all parties, but the final government
approval of the transaction has not yet been obtained. Such approval is
necessary for the agreements to be accepted in Ecuador. Bellwether has
received a legal opinion that it is legally entitled to 70% of production from
the field and has also received confirmation that the government has never
failed to approve similar assignments.

   During 2000, after substantial analysis of its property portfolio in 1999,
Bellwether began divesting of several non-core properties. The high oil and
gas prices during 2000 created a favorable market for such properties. By
December 31, 2000, Bellwether had sold approximately 6.4 MMBOE, or 17%, of its
beginning of the year reserves, for gross proceeds of approximately $49
million.

Business Strategy

   The Company is committed to achieving outstanding performance in all areas
of the Company's business to maximize profits and shareholder return. This
goal will be pursued through the following business strategy:

   Pursue Attractive Company or Acquisition Opportunities in Core Areas. The
Company believes that acquiring oil and gas reserves using cash and/or stock
as the transaction currency is the most effective way to increase shareholder
value in the next one to two years. The Company believes that this strategy
will allow it to add attractively priced reserves, further improve the quality
of its property portfolio, and achieve economies of scale in production
operations, and improve exposure in the financial markets. Once a company or a
property has been acquired, the Company immediately employs an aggressive
exploitation program to increase production, reduce operating costs and
develop low risk exploration opportunities.

                                       4
<PAGE>

   Focus Activities in Core Areas. The Company will enhance its competitive
position by focusing its activities within core geographic areas where it has
significant existing assets and infrastructure, superior technical expertise
and experience, a technical/operational database and demonstrated business
know-how. The Company's current core areas are the Texas-Louisiana Gulf Coast,
both onshore and offshore, and southeastern New Mexico. The Company may seek
to establish additional core areas in the future that are complementary to its
strategy.

   Contain and Reduce Cost. In order to maintain a competitive cost structure
and to increase efficiency, the Company will continuously seek to reduce cost,
operating capital and overhead. In this regard, the Company outsources certain
non-strategic functions, and monitors the costs and benefits of those
outsourced activities to ensure that maximum value is being received.
Additionally, the Company will regularly review its property base to identify
non-core and lower margin assets. Those assets will be divested to allow
redeployment of capital to more profitable activities, or to reduce
outstanding debt.

   Increase Number of High Value Operated Properties. The Company will
increase efficiency, establish greater control and enhance economic impact by
increasing its holdings in higher value properties that are operated by the
Company. This objective will be a principal criteria in the execution of its
acquisition and divestiture strategies. Additionally, the Company's
exploration and exploitation programs will focus on internally generated
prospects.

   Utilize Technology Effectively. The Company will seek to improve its
success rates and reduce its finding and operating costs by employing state of
the art technology in its exploration, development and operating activities.
Its exploration and development program will utilize 3-D seismic evaluation,
sophisticated seismic processing and modeling tools and computer aided
exploration and development systems. Operationally, the Company will employ
horizontal drilling, enhanced recovery methods and advanced completion and
production techniques where they are cost effective.

   Use an Interdisciplinary Approach. The Company utilizes interdisciplinary
teams composed of geologists, geophysicists and engineers in the generation
and evaluation of acquisition, exploration and exploitation investment
opportunities. Through this approach the Company will maximize the
identification and quantification of opportunities and reduce risk through the
application of complementary experience, know-how and technology.

Markets

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

     1) the extent of domestic production and imports of oil and gas,

     2) the proximity of gas production to gas pipelines,

     3) the availability of capacity in such pipelines,

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

     5) the availability of alternate fuel sources,

     6) the effects of inclement weather,

     7) state, federal and international regulation of oil and gas
  production, and

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

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

                                       5
<PAGE>

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

   Sales to Torch Co-Energy LLC accounted for approximately 24%, 22% and 28%
of fiscal year 2000, 1999 and 1998 oil and gas revenues, respectively. The
contract with Torch Co-Energy is for an initial three year term from December
1996 and is renewable month to month after such term. It provides for payment
of index pricing (tied to Inside FERC postings) less gathering and
transportation charges to point of delivery. Sales to Valero Industrial Gas,
L.P. accounted for 18% of fiscal 1997 revenues and are based upon a month to
month contract (initial term of contract ended in May 1998 with month to month
renewals) which provides for index pricing less gathering, dehydration and
other transportation type fees. There are no other significant delivery
commitments and substantially all of the Company's U.S. oil and gas production
is sold at market responsive pricing through a marketing affiliate of Torch.
Bellwether's Ecuadorian crude oil was sold to YPF in the year 2000 and
accounted for approximately 4% of the total Company oil and gas revenue for
the year. Management of the Company does not believe that the loss of any
single customer or contract would materially affect the Company's business.

Regulation

 Federal Regulations

   Transportation of Gas. The Company'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.

   The 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
the Company at market prices and are not subject at this time to price
controls. The price that the Company receives from the sale of these products
will be affected by the cost of transporting the products to market. FERC
regulations governing 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 Company's operations.

   Federal, State or Indian Leases. In the event the Company 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

                                       6
<PAGE>

("MMS") or other appropriate federal or state agencies. The Company's OCS
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 the Company sells its production in the spot market and, therefore,
pays royalties on production from federal leases, it is not anticipated that
this final rule will have any substantial impact on the Company.

   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. The Company owns interests in numerous federal onshore
oil and gas leases. It is possible that the 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. Most states regulate the production and sale of oil and
gas, including: 1) requirements for obtaining drilling permits, 2) the method
of developing new fields, 3) the spacing and operation of wells and 4) 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.

   The Company 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.

   The Company may enter into agreements relating to the construction or
operation of a pipeline system for the transportation of gas. To the extent
that such gas is produced, transported and consumed wholly within one state,
such operations may, in certain instances, be subject to the jurisdiction of
such state's administrative authority charged with the responsibility of
regulating intrastate pipelines. In such event, the rates which the Company
could charge for gas, the transportation of gas, and the construction and
operation of such pipeline would be subject to the rules and regulations
governing such matters, if any, of such administrative authority.

Environmental Regulations

   General. The Company's activities are subject to existing federal, state
and local laws and regulations governing environmental quality and pollution
control. Activities of the Company 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. The Company cannot predict
what effect

                                       7
<PAGE>

future regulation or legislation, enforcement policies issued thereunder, and
claims for damages to property, employees, other persons and the environment
resulting from the Company's operations could have on its activities.

   Solid and Hazardous Waste. The Company 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 the Company
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
the Company or on or under locations where such wastes have been taken for
disposal. In addition, many of these properties have been owned or operated by
third parties. The Company 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
these new laws, the Company 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.

   The Company 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 approved
methods of disposal for certain hazardous and non-hazardous wastes.
Furthermore, it is possible that certain wastes generated by the Company'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 Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons with respect to the release of a "hazardous
substance" into the environment. These persons include the owner and operator
of a disposal site where a release occurred and any company that disposed or
arranged for the disposal of the hazardous substance 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 responsible classes of persons the costs of such
action. In the course of its operations, the Company has generated and will
generate wastes that may fall within CERCLA's definition of "hazardous
substances." The Company may also be an owner of sites on which "hazardous
substances" have been released. The Company may be responsible under CERCLA
for all or part of the costs to clean up sites at which such wastes have been
disposed.

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

   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
<PAGE>

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

   Air Emissions. The operations of the Company are subject to local, state
and federal laws and regulations for the control of emissions from sources of
air pollution. Administrative enforcement actions for failure to comply
strictly with air regulations or permits may result in the payment of civil
penalties and, in extreme cases, the shutdown of air emission sources. The
Company believes it is in compliance with all air emission regulations.

   OSHA and other Regulations. The Company is subject to the requirements of
the federal Occupational Safety and Health Act ("OSHA") and comparable state
statutes. The OSHA hazard communication standard, the EPA community right-to-
know regulations under Title III of CERCLA and similar state statutes require
the Company to organize and/or disclose information about hazardous materials
used or produced in the Company's operations. The Company 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.
Bellwether encounters competition from other oil and gas companies in all
areas of the Company's 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 Bellwether. Competition for
producing properties is affected by the amount of funds available to the
Company, information about a producing property available to the Company and
any standards established by the Company for the minimum projected return on
investment. Competition may also be presented by alternate fuel sources.

Item 2. Properties

Domestic Properties

   The Company's domestic exploration, development and acquisition activities
are focused in three core areas: Gulf Coast, Offshore Gulf of Mexico and
Permian Basin. The company primarily owns working interests in domestic wells.
Working interests are burdened by operating costs whereas royalty interests
receive a share of unburdened revenues. As used herein, "reserve life" is the
Company's estimated net proved at the end of year divided by production during
the year.

   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. Reserve life index
for the years ended December 31, 2000, 1999 and 1998 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.

   Gulf Coast--The fields in this area are located in Louisiana and Texas.
These fields produce gas as the primary product. Bellwether owns an interest
in approximately 140 wells and the reserves from these wells account for about
35% of the Company's discounted present value. The average reserve life is 6
years. The average working interest of the Company in the wells is
approximately 15 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. The Company owns an interest in approximately 120 wells and the
reserves from these wells account for about 35% of the Company's discounted
present value. The average reserve life is 4 years. The average working
interest of the Company in the wells is approximately 20 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. The Company owns an interest in

                                       9
<PAGE>

approximately 1,200 wells and the reserves from these wells account for about
15% of the Company's discounted present value. The average reserve life is 14
years. The average working interest of the Company in the wells is
approximately 10 percent.

   Other--Non-core fields are located in California, Oregon, Oklahoma and
Wyoming. The Company owns an interest in approximately 100 wells and the
reserves from these wells account for about 6% of the Company's discounted
present value.

International Properties

   Ecuador--Bellwether operates two concessions in Ecuador, each of which
contains one producing field. The working interest in the Charapa field is 90%
and the working interest in the Tiguino field is 70%. Oil is the only sales
product from both fields. Both fields are subject to contracts with the
Ecuador government, under which the company has a share of production above
specified base levels. Reserves from these wells account for about 9% of the
Company's discounted present value. The average reserve life is 7 years.

Reserves

   Estimated net proved oil and gas reserves at December 31, 2000 decreased
approximately 18% from December 31, 1999. Properties, with proved reserves
totaling 6.4 MMBOE, or about 17% of 1999 reserves, were sold during 2000. This
decrease was partially offset by the increased oil and gas prices and the
acquisition of a 70% working interest in the Tiguino field concession in
Ecuador. 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 set forth herein.

   The following table sets forth certain information as of December 31, 2000
for the Company's core areas.

<TABLE>
<CAPTION>
                                Net Production          Net Proved Reserves
                           -------------------------- --------------------------
                           Oil &              Oil     Oil &              Oil
                             NGL     Gas   Equivalent   NGL     Gas   Equivalent
Area                       (MBBLS) (MMCF)     MBOE    (MBBLS) (MMCF)    (MBOE)
----                       ------  ------  ---------- ------  ------  ----------
<S>                        <C>     <C>     <C>        <C>     <C>     <C>
Gulf Coast................   372    3,368      933       877  29,063     5,721
Gulf of Mexico............   708    7,678    1,988     1,759  25,269     5,971
Permian Basin.............   379    1,139      569     5,447  12,279     7,493
Ecuador*..................   174       --      174     7,813      --     7,813
Other**...................   747    8,293    2,129     3,241   8,118     4,594
                           -----   ------    -----    ------  ------    ------
                           2,380   20,478    5,793    19,137  74,729    31,592
                           =====   ======    =====    ======  ======    ======
</TABLE>
--------
 *  Such reserves are pursuant to a contract with the Ecuadorian government
    under which the Company does not own the reserves but where the Company
    has a contractual right to produce the reserves and receive revenue. The
    Ecuadorian government has not issued final approval for the assignment of
    4.9 MMBOE purchased by the Company; however, the Company has a legal
    opinion stating that it is legally entitled to the production of such
    reserves.
**  Net production includes nine to twelve months of production from fields
    that were sold in the year 2000. Such fields have been removed from
    December 31, 2000 proved reserves.

   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
variable 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

                                      10
<PAGE>

net cash flows expected therefrom, prepared by different engineers or by the
same engineers at different times, may vary substantially. The Company'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 acres of developed and undeveloped oil
and gas properties in which the Company held an interest as of December 31,
2000. 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 a working interest is owned directly by
the Company. The number of net acres is the sum of the fractional ownership of
working interests owned directly by the Company in the gross acres expressed
as a whole number and percentages thereof. A net acre is deemed to exist when
the sum of fractional ownership of working interests in gross acres equals
one. All of the undeveloped acreage is domestic.

<TABLE>
<CAPTION>
                                                                 Gross     Net
                                                               --------- -------
<S>                                                            <C>       <C>
Developed Acreage
  Domestic....................................................   404,141  75,124
  Ecuador.....................................................   123,674  98,951
Undeveloped Acreage........................................... 1,034,074 364,418
                                                               --------- -------
    Total..................................................... 1,561,889 538,493
                                                               ========= =======
</TABLE>

   Bellwether believes that the 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 the opinion of the Company,
are not so material as to detract substantially from the use or value of such
properties. The Company's properties are typically subject, in one degree or
another, to one or more of the following: 1) royalties and other burdens and
obligations, express or implied, under oil and gas leases; 2) overriding
royalties and other burdens created by the Company or its predecessors in
title; 3) 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; 4) back-ins and reversionary interests arising
under purchase agreements and leasehold assignments; 5) 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; 6) pooling, unitization and communitization
agreements, declarations and orders; and 7) 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 the Company's rights to

                                      11
<PAGE>

production revenues, they have been taken into account in calculating the
Company's net revenue interests and in estimating the size and value of the
Company's reserves. Bellwether believes that the burdens and obligations
affecting the Company's properties are conventional in the industry for
properties of the kind owned by the Company.

Productive Wells

   The following table sets forth Bellwether's gross and net interests in
productive oil and gas wells as of December 31, 2000. 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 a working interest is owned directly by the Company. 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 the Company in gross wells
expressed as whole numbers and percentages thereof.

<TABLE>
<CAPTION>
                                                                       Gross Net
                                                                       ----- ---
      <S>                                                              <C>   <C>
      Oil Wells
        Domestic...................................................... 1,138 150
        Ecuador.......................................................     7   5
      Gas Wells.......................................................   565 112
                                                                       ----- ---
          Total....................................................... 1,710 267
                                                                       ===== ===
</TABLE>

Production

   The Company's principal domestic production volumes during the fiscal year
ended December 31, 2000 were from the states of Louisiana, Texas, and Oregon
from federal waters in offshore California and from federal and state waters
in the Gulf of Mexico. The Charapa and Tiguino fields in Ecuador accounted for
about 8% of the Company's oil production.

   Data relating to production volumes, average sales prices, average unit
production costs and oil and gas reserve information appears in Note 12 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 in the Gulf Coast, the Gulf of Mexico, Oregon and
New Mexico. Development of the Charapa and Tiguino fields in Ecuador accounted
for all international activities.

   The following table sets 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>
1998--Domestic....................     14        5    19     4.10    1.52  5.62
1999--Domestic....................      8        4    12     3.75    2.04  5.79
2000--Domestic....................      7        6    13     3.98    1.96  5.94
2000--Ecuador.....................     --       --    --       --      --    --
</TABLE>

                                      12
<PAGE>

                               Development Wells

<TABLE>
<CAPTION>
                                           Gross                   Net
                                   ---------------------- ----------------------
                                               Dry                    Dry
                                   Productive Holes Total Productive Holes Total
                                   ---------- ----- ----- ---------- ----- -----
<S>                                <C>        <C>   <C>   <C>        <C>   <C>
1998--Domestic....................     69        4    73     7.53     .52   8.05
1999--Domestic....................     13        2    15     4.39     .14   4.53
2000--Domestic....................     46        8    54    15.01    2.70  17.71
2000--Ecuador.....................      1        3     4       .7     2.7    3.4
</TABLE>

   The Company had 6 domestic wells in progress as of December 31, 2000.

Gas Plants

   As of December 31, 2000, the Company owned interests in the following gas
plants:

<TABLE>
<CAPTION>
                                                                    Fiscal Year 2000
                                                              -----------------------------
                                                                       Throughput Ownership
 Facility                      State        Operator          Capacity   MMCFD    Interest
 --------                      -----        --------           MMCFD   ---------- ---------
 <C>                           <C>   <S>                      <C>      <C>        <C>
 Point Pedernales Gas Plant..   CA   Nuevo Energy Company        15         4       19.7%
                                     Torch Energy Marketing
 Snyder Gas Plant............   TX   Inc.                        60        15       11.9%
 Diamond M-Sharon Ridge Gas
  Plant(1)...................   TX   Exxon Company, U.S.A.       (1)       (1)        (1)
</TABLE>
--------
(1)  The Company has a 32.0% interest in the operations of the former Diamond
     M-Sharon Ridge Gas Plant. This plant was dismantled in December 1993 and
     the gas is being processed by Snyder Gas Plant pursuant to a processing
     agreement.

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 the control of the
Company. These factors include:

     1) weather conditions in the United States,

     2) the condition of the United States economy,

     3) the actions of the Organization of Petroleum Exporting Countries,

     4) governmental regulation,

     5) political stability in the Middle East and elsewhere,

     6) the foreign supply of oil and gas,

     7) the price of foreign imports, and

     8) the availability of alternate fuel sources.

   During 2000 oil prices were higher than in the three previous years and
natural gas prices were at record high levels. Any substantial and extended
decline in the price of oil or gas would have an adverse effect on the
Company's carrying value of its 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

                                      13
<PAGE>

have difficulty agreeing on such value. 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 the Company's 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

   The Company'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 Bellwether will generally decline as those reserves are
depleted. The Company therefore must locate and develop or acquire new oil and
gas reserves to replace those being depleted by production. Because the
Company's reserves are characterized by relatively rapid decline rates, the
Company's revenues will decline rapidly without successful exploration,
development or acquisition activities. No assurances can be given that the
Company will be able to find and develop or acquire additional reserves at an
acceptable cost.

 Acquisition Risks

   The Company's rapid growth in recent years has been attributable in
significant part to domestic and, to a less significant part, international
acquisitions of oil and gas properties. The Company expects to continue to
evaluate and, where appropriate, pursue acquisition opportunities on terms
management considers favorable to the Company. There can be no assurance that
suitable acquisition candidates will be identified in the future, or that the
Company will be able to finance such acquisitions on favorable terms. In
addition, the Company competes against other companies for acquisitions, and
there can be no assurances that the Company will be successful in the
acquisition of any material property interests. Further, there can be no
assurances that any future acquisitions made by the Company will be integrated
successfully into the Company's operations or will achieve desired
profitability objectives.

   The successful acquisition of producing properties requires an assessment
of:

     1) recoverable reserves,

     2) future production rates,

     3) exploration and exploitation potential and timing,

     4) future oil and natural gas prices,

     5) operating costs,

     6) infrastructure requirements,

     7) potential environmental and other liabilities and

     8) other factors beyond the Company's control.

   In connection with such an assessment, the Company performs 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 the Company 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 the Company for known or unknown
liabilities at the time of an acquisition.

                                      14
<PAGE>

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

   On January 24, 2001, Bellwether entered into an Agreement and Plan of
Merger with Bargo Energy Company. The merger is subject the adoption and
approval of the agreement by Bellwether shareholders, Bargo shareholders and
the absence of any law or court order preventing the merger. Bargo and
Bellwether filed a registration statement on Form S-4 (registration number
333-54798) with the SEC on February 1, 2001. A detailed discussion of risks
associated with the proposed merger may be found there.

 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 the Company will be productive or that the
Company 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
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. The Company's drilling operations may be curtailed, delayed or
canceled as a result of numerous factors, many of which are beyond the
Company's control, including:

     1) title problems,

     2) weather conditions,

     3) compliance with governmental requirements, and

     4) shortages or delays in the delivery of equipment and services.

 Substantial Capital Requirements

   The Company makes, and will continue to make, substantial capital
expenditures for the exploitation, exploration, acquisition and production of
oil and gas reserves. Historically, the Company 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.
The Company believes that it will have sufficient cash flow provided by
operating activities, the proceeds of equity offerings and borrowings under
the Senior Credit Facility to fund planned capital expenditures. If revenues
or the Company's borrowing base decrease as a result of lower oil and gas
prices, operating difficulties or declines in reserves, the Company 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

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

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

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

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


                                      15
<PAGE>

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

 Risks of Foreign Operations

   The Company was the successful bidder for a marginal field in Ecuador in
1998. Contract negotiations with the Ecuadorian government were completed in
late 1999 with operations beginning January 2000. Operatorship of a second
marginal field was acquired in July 2000. For these marginal fields,
Bellwether partners with other companies in consortiums which are then party
to the production sharing agreements with the Ecuadorian government.
Bellwether is 90% partner in the first consortium and 70% partner in the
second consortium. In addition, on December 30, 1999, the Company acquired an
interest in Carpatsky, which has operations in Ukraine. Operations in Ecuador,
Ukraine and other areas outside of the United States in which the Company may
choose to do business, are subject to the various risks inherent to foreign
operations. These risks may include, among other things, currency restrictions
and exchange rate fluctuations, loss of revenue, property and equipment as a
result of hazards such as expropriation, nationalization, war, insurrection
and other political risks, risks of an increase in taxes and governmental
policies governing operations of foreign-based companies, and other
uncertainties arising out of foreign government sovereignty over the Company's
international operations. The Company's international operations may also be
adversely affected by laws and policies of the United States affecting foreign
trade, taxation and investment. In addition, in the event of a dispute arising
from foreign operations, the Company may be subject to the exclusive
jurisdiction of foreign courts or may not be successful in subjecting foreign
persons to the jurisdiction of the courts of the United States.

 Outsourcing Agreement

   Bellwether currently has 34 employees. The Company is party to a Master
Services Agreement ("MSA") with Torch, pursuant to which Torch performs
certain administrative functions for the Company, including financial,
accounting, marketing, legal and technical support (See Note 4 to the
Consolidated Financial Statements). The Company believes that its relationship
with Torch provides the Company access to professional, technical and
administrative personnel not otherwise available to a company of its size.
Bellwether believes that if the MSA were terminated Bellwether could, over
time, hire experienced personnel and acquire the accounting and reporting
systems and other assets necessary to replace Torch. However, the
unanticipated termination of the MSA could have a material adverse effect upon
the Company.

 Conflicts of Interest

   Mr. J. P. Bryan served as Chief Executive Officer of Bellwether from August
1999 through May 2000. He remained as Chairman of the Board throughout the
year. 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 owns 1,061,750 shares of Bargo, and a subsidiary of Torch provides
outsourcing services to both Bellwether and Bargo.

   Torch also renders 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 may include the review
and recommendation of potential acquisitions. It is possible that conflicts
may occur between Bellwether 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 Bellwether, no assurances can be
made that such procedures will fully protect the Company from losses which may
occur if a conflict between the Company and these other companies arises.

 Estimates of Oil and Gas Reserves

   This document contains estimates of oil and gas reserves owned by the
Company, and the future net cash flows attributable to those reserves. There
are numerous uncertainties inherent in estimating quantities of proved

                                      16
<PAGE>

reserves and cash flows attributable to such reserves, including factors
beyond the control of the Company 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:

     1) the available data,

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

     3) 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 a oil
equivalent basis, gas was converted to 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 the Company 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

   The Company 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, the Company 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, the Company is
required to pay the counterparty this difference multiplied by the quantity
hedged. In such case, the Company is required to pay the difference regardless
of whether the Company has 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 the Company to make
payments under the hedge agreements even though such payments are not offset
by sales of production. Hedging will also prevent the Company 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

   Bellwether's operations are subject to risks inherent in the oil and gas
industry, such as: 1) blowouts, 2) cratering, 3) explosions, 4) uncontrollable
flows of oil, gas or well fluids, 5) fires, 6) pollution, 7) earthquakes and
8) environmental risks. These risks could result in substantial losses to the
Company 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 the Company'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.

   The Company's operations could result in a liability for: 1) personal
injuries, 2) property damage, 3) oil spills, 4) discharge of hazardous
materials and, 5) remediation and clean-up costs and other environmental
damages. The Company 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

                                      17
<PAGE>

have a material adverse effect on the Company's financial condition and
results of operations. The Company 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, the Company does
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, the Company 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

   The Company'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: 1) require
the acquisition of a permit before drilling commences, 2) restrict the types,
quantities and concentration of various substances that can be released into
the environment in connection with drilling and production activities, 3)
limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas, and 4) 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 the operating costs of the Company, as well as the oil
and gas industry in 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 the Company. Management believes
that the Company is in substantial compliance with current applicable
environmental laws and regulations.

   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 the Company.

 Competition

   The Company operates in the highly competitive areas of oil and gas
exploration, development and production. The Company's competitors include
major integrated oil and gas companies and substantial independent energy
companies, many of which possess greater financial and other resources than
the Company.

Item 3. Legal Proceedings

   The Company was a defendant in Cause No. C-4417-96-G; A.R. Guerra, et al.
v. Eastern Exploration, Inc., et al. in the 370th Judicial District Court of
Hidalgo County, Texas. The suit was filed with the Court on October 11, 1996.
On May 11, 1999, the trial court granted plaintiff's Motion of Summary
Judgement and denied defendants' Motion of Summary Judgement. The trial court
awarded plaintiffs in excess of $5.8 million in damages plus interest. In
early 2000, the Company settled the case for the sum of $353,500, net to its
interest.

   The Company 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 the Company.

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

     None.

                                      18
<PAGE>

                                    PART II

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

   The Company's common stock is traded on the NASDAQ National Market (Symbol:
BELW). There were approximately 760 stockholders of record as of March 14,
2001. The Company 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 in Company
operations. In addition, certain covenants contained in the Company'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 Bellwether common stock for the
periods indicated.

<TABLE>
<CAPTION>
                                                                    Sales Price
                                                                    ------------
                                                                     High   Low
                                                                    ------ -----
<S>                                                                 <C>    <C>
Quarter Ended:
  March 31,1998.................................................... $11.13 $7.88
  June 30, 1998.................................................... $ 9.88 $7.81
  September 30, 1998............................................... $ 8.88 $3.81
  December 31, 1998................................................ $ 7.69 $4.13
  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
</TABLE>

Treasury Stock Repurchases

   In September 1998, the Board of Directors of the Company authorized the
open market repurchase of up to $5.0 million of the Company's common stock
during 1998, at times and prices deemed attractive by management. As of
December 31, 2000, the Company had repurchased 311,000 shares of common stock
in open market transactions at an average purchase price of $6.13 per share.
No additional shares were purchased in 1999 and 2000.

                                      19
<PAGE>

Item 6. Selected Financial Data

   The following selected financial data with respect to the Company 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 Years
                          Year Ended Year Ended Year Ended   Period    Ended June 30,
                           Dec. 31,   Dec. 31,   Dec. 31,  Ended Dec. -----------------
                             2000       1999       1998     31, 1997    1997(1)  1996
                          ---------- ---------- ---------- ---------- --------  -------
<S>                       <C>        <C>        <C>        <C>        <C>       <C>
Gas revenues............   $ 62,652   $ 41,559   $ 46,661   $ 26,849  $ 24,323  $ 9,906
Oil revenues............     49,601     26,705     26,991     17,519    15,006    5,810
Gas plant revenues......      6,070      3,830      3,170      2,036     6,652    8,719
Interest and other
 income.................        957      1,335      1,347        609       363      116
                           --------   --------   --------   --------  --------  -------
  Total revenues........    119,280     73,429     78,169     47,013    46,344   24,551
Production expenses.....     30,509     21,532     25,381     13,836    11,437    5,317
Gas plant expenses......      2,677      2,366      1,967      1,232     3,322    5,185
Transportation costs....        270        316        435        205       262       50
Depreciation, depletion
 and amortization.......     32,654     23,863     39,688     16,352    15,574    8,148
Impairment expense......         --         --     73,899         --        --       --
Disposition of hedges...      8,671         --         --         --        --       --
General and
 administrative
 expenses...............      9,138      7,848      8,459      3,748     4,042    3,013
Interest expense........     15,375     11,845     11,660      5,978     4,477    1,657
Provision for income tax
 (benefit)..............    (12,222)    (3,154)    (6,069)     2,114     2,585       46
Other expenses..........         --         --         --         --        --      153
                           --------   --------   --------   --------  --------  -------
  Total expenses........     87,072     64,616    155,420     43,465    41,699   23,569
                           --------   --------   --------   --------  --------  -------
Net income (loss).......   $ 32,208   $  8,813   $(77,251)  $  3,548  $  4,645  $   982
                           ========   ========   ========   ========  ========  =======
Earnings (loss) per
 common share...........   $   2.32   $   0.64   $  (5.50)  $   0.26     $0.46  $  0.11
Earnings (loss) per
 common share--diluted..   $   2.27   $   0.63   $  (5.50)  $   0.25  $   0.45  $  0.11
Working capital.........   $  7,212   $  3,770   $  6,077   $ 13,964  $ 22,783  $ 5,168
Long-term debt, net of
 current maturities.....   $125,450   $130,000   $104,400   $100,000  $115,300  $13,048
Stockholders'equity.....   $ 56,960   $ 23,314   $ 14,489   $ 91,669  $ 87,924  $46,597
Total assets............   $221,545   $171,761   $131,196   $214,757  $222,648  $67,225
</TABLE>
--------
(1)  Includes operations from the Partnership Transactions beginning April 1,
     1997.

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

   Bellwether is an independent energy company primarily engaged in the
acquisition, exploitation and development of and exploration for oil and gas
properties. Since April 1997 the Company has employed a balanced growth
strategy combining strategic acquisitions of producing properties with
technology driven development and exploration drilling. As a result, the
Company's results of operations have been significantly affected by its
success in acquiring oil and gas properties and its ability to maintain or
increase production through its development activities.

   In April 1997, the Company purchased oil and gas properties and $13.9
million of working capital from affiliates of Torch for an adjusted purchase
price of $141.1 million. The acquisition was recorded effective April 1, 1997
and the operations of the Company include the Partnership Transactions from
that date. The Partnership Transactions were financed with $34.1 million of
net proceeds of a common stock offering, $97.0 million net proceeds of 10 7/8%
Senior Subordinated Notes due 2007 (the "Notes") and borrowings under a

                                      20
<PAGE>

new credit facility. In addition, as consideration for advisory services 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 the Partnership Transactions.
The warrant and shares were valued at $1.5 million and recorded as a cost of
the Partnership Transactions.

   In order to facilitate greater comparability with its peer group by the
financial community, the Company changed its fiscal year to the calendar year
beginning January 1, 1998.

   The Company 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. 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. To the
extent that such capitalized costs (net of depreciation, depletion and
amortization) exceed the discounted future net revenues on an after-tax basis
of estimated proved oil and gas reserves, such excess costs are charged to
operations. Once incurred, the writedown of oil and gas properties is not
reversible at a later date even if oil and gas prices increase. Sharp declines
in oil and gas prices, including further gas price decline subsequent to year
end, and to a lesser extent, downward revision in estimated proved reserves
resulted in a $73.9 million pretax impairment charge ($71.6 million after
tax), in the fiscal year ended December 31, 1998. Prices used in computing the
impairment were February 23, 1999 prices and were based on a NYMEX oil price
of $12.48 per barrel and a NYMEX gas price of $1.71 per MMBTU, adjusted to the
wellhead. No such write down was required for the years ended December 31,
1999 and 2000.

Financing Activities

   The Company's outstanding indebtedness totals $125.5 million at December
31, 2000, $100 million is attributable to the 10 7/8% Senior Subordinated
Notes due in 2007 while $25.5 million is outstanding under a senior revolving
credit facility with an ultimate maturity date of August 2002.

   In April 1997, the Company 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. Subsequent
amendments reflecting the impact of property sales in 2000 reduced the
borrowing base to $34.5 million at December 31, 2000. As of December 31, 2000,
$25.5 million was outstanding under the Senior Credit Facility. A February
2001 amendment reduced the credit facility to $40 million, increased the
borrowing base to $35 million, and changed the maturity date to August 2002.

   Bellwether may 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: 1) Bellwether and its
subsidiaries will not sell all or substantially all of their assets to another
person, 2) none of Bellwether or its subsidiaries will incur additional
indebtedness with the exception of permitted indebtedness, 3) the indebtedness
of Bellwether's subsidiaries will not exceed 10% of consolidated tangible net
worth (indebtedness from subsidiaries to Bellwether or guarantors is
permitted), 4) none of Bellwether 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.

                                      21
<PAGE>

   In April 1997, the Company issued $100.0 million of 10 7/8% Senior
Subordinated Notes that mature April 1, 2007. Interest on the Notes is payable
semi-annually on April 1 and October 1. The Notes contain certain covenants,
including limitations on: 1) incurrence of debt, 2) other senior subordinated
indebtedness, 3) restricted payments, 4) liens as well as restrictions 5)
disposition of proceeds of asset sales, 6) mergers, and 7) consolidations or
sales of assets. Additionally, the Notes require the Company to offer to
purchase the Notes in the event of a change of control.

   In order to reduce cash paid for interest costs, 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. 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, 2000 to April 1,
2001 is 10.875%. This interest swap is currently accounted for as a hedge.

Liquidity and Capital Resources

   The Company's principal sources of capital for the last three years been
the sale of non-core properties, borrowings under bank credit facilities and
cash flow from operations. Non-core property divestitures in the year 2000
realized net proceeds of approximately $46.0 million. Most sales were
completed during the fourth quarter of 2000. Borrowings from banks were $25.5
million, $30.0 million, and $4.9 million at the end of fiscal years 2000,
1999, and 1998, respectively. At December 31, 2000, available debt capacity
under the Senior Credit Facility, after netting $7.4 million in outstanding
letters of credit, was $1.6 million. As the Notes mature in November 2007 and
the Senior Credit Facility matures in August 2002, the Company has no debt
repayment obligation within the next twelve months. Cash flow from operations
before changes in assets and liabilities totaled $62.6 million, $30.8 million
and $30.4 million for the fiscal years 2000, 1999, and 1998, respectively.
Cash flow from operations before changes in working capital for the fiscal
year 2000 was significantly impacted by increases in the average prices
received for oil and gas production as compared to previous periods.

   The Company's primary uses of capital have been to fund acquisitions and to
fund its exploration and development projects. Acquisitions, net of working
capital acquired, totaled $7.1 million, $25.9 million, and $9.6 million for
the fiscal years 2000, 1999, and 1998, respectively. Approximately $2.0
million of acquisition costs in the year 2000 related to the Tiguino field in
Ecuador. The Company's expenditures for exploration, including unproved
property acquisitions, and development of its oil and gas properties totaled
$81.3 million, $30.9 million and $30.6 million, for the fiscal years 2000,
1999, and 1998, respectively. Development activities in Ecuador accounted for
approximately $10.0 million of expenditures in the year 2000. Under the
Company's contract for production of oil in the Charapa field of Ecuador, the
Company is required to execute a three year $12 million minimum investment
program.

Outlook

   The Company adopted an $82.9 million capital budget for the year ending
December 31, 2001 with $52.1 million for acquisitions, $20.0 million for
domestic exploration and development, and $10.7 million for development in
Ecuador. This budget is under review in conjunction with the proposed merger
with Bargo Energy Company. The Company believes its working capital and net
cash flows provided by operating activities are sufficient to meet the
exploration and development plans. At December 31, 2000, $1.6 million was
available for borrowing under the Senior Credit facility, as amended in
February 2001. The Company is continuously reviewing acquisition opportunities
and has the goal of concluding one or more acquisitions during 2001.
Acquisitions will be funded through additional borrowings under the Senior
Credit Facility, borrowings under a new facility and/or the issuance of
securities.

   On January 25, 2001, Bellwether announced plans to merge with Bargo Energy
Company. Contemporaneously with the merger, Bellwether proposes to increase
its authorized common stock to 65.0

                                      22
<PAGE>

million shares and amend 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, Bargo shareholders will receive a combination of cash
and Bellwether common stock. The merger is conditioned upon its receiving the
approval of Bellwether's shareholders and Bargo's shareholders. The merger
will be accounted for using the purchase method of accounting. Bellwether's
management believes the merger is, among other things, in accordance with
Bellwether's long-term strategy of growth through acquisitions, will create a
larger company with more liquidity in its common stock and more financial
flexibility, will strengthen Bellwether's management team, and will add
significantly to Bellwether's production. The Company anticipates the merger
will result in a cost savings of approximately $4.0 million per year. The
merging of the two companies into one office location will reduce costs
immediately. Key service providers, such as reserve engineers, information
systems and financial outsourcers, external auditors and tax providors,
attorneys and insurers, will be able to serve the larger combined company at
lower cost than the two smaller companies separately.

   The Company's results of operations and cash flow are affected by changing
oil and gas prices. Changes in oil and gas prices often result in changes in
the level of drilling activity, which in turn adjusts the demand for and cost
of exploration and development. Thus, increased prices may generate increased
revenue without necessarily a corresponding increase in profitability while
declining prices almost always have a negative impact on profitability. These
industry market conditions have been far more significant determinants of
Company earnings than have macroeconomic factors such as general inflation,
which has had only minimal impact on Company activities in recent years. It is
impossible to predict the precise effect of changing prices and inflation on
future Company operations, and no assurance can be given as to the Company's
future success at reducing the impact of price changes in the Company's
operating results.

                                      23
<PAGE>

Results of Operations

   The table below recaps 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,
                                                  ---------------------------
                                                    2000     1999      1998
                                                  --------  -------  --------
<S>                                               <C>       <C>      <C>
Oil and gas revenues--US......................... $107,938  $68,264  $ 73,652
Oil revenues--Ecuador............................    4,315       --        --
Gas plant revenues...............................    6,070    3,830     3,170
Interest and other...............................      957    1,335     1,347
                                                  --------  -------  --------
    Total revenue................................  119,280   73,429    78,169
Production expenses--US..........................   27,694   21,515    25,381
Production expenses--Ecuador.....................    2,815       17        --
Transportation costs.............................      270      316       435
Gas plant expenses...............................    2,677    2,366     1,967
Depreciation, depletion and amortization--US.....   31,909   23,863    39,688
Depreciation, depletion and amortization--
 Ecuador.........................................      745       --        --
Impairment expense...............................       --       --    73,899
Disposition of hedges............................    8,671       --        --
General and administrative expenses..............    9,138    7,848     8,459
Interest expense.................................   15,375   11,845    11,660
Income tax benefit...............................  (12,222)  (3,154)   (6,069)
                                                  --------  -------  --------
Net income (loss)................................ $ 32,208  $ 8,813  $(77,251)
                                                  ========  =======  ========
Production
  Oil and condensate (MBBLS)--US.................    2,206    2,080     2,297
  Oil and condensate (MBBLS)--Ecuador............      174       --        --
  Natural gas (MMCF).............................   20,478   18,965    21,302
  Gas equivalent (MMCFE).........................   34,758   31,445    35,084
  Oil equivalent (MBOE)..........................    5,793    5,241     5,847
Average sales price, including the effect of
 hedges
  Oil and condensate (per BBL)--US............... $  20.53  $ 12.84  $  11.75
  Oil and condensate (per BBL)--Ecuador.......... $  24.80  $    --  $     --
  Natural gas (per MCF).......................... $   3.06  $  2.19  $   2.19
Average sales price, excluding the effect of
 hedges
  Oil and condensate (per BBL)--US............... $  24.40  $ 14.48  $  11.44
  Oil and condensate (per BBL)--Ecuador.......... $  24.80  $    --  $     --
  Natural gas (per MCF).......................... $   3.84  $  2.22  $   2.06
Average production expenses per BOE--US.......... $   4.93  $  4.11  $   4.34
Average production expenses per BOE--Ecuador..... $  16.18       (1)       (1)
Average general and administrative expenses per
 BOE............................................. $   1.58  $  1.50  $   1.45
Average depletion rate per BOE--US............... $   5.46  $  4.32  $   6.59
Average depletion rate per BOE--Ecuador.......... $   4.28       (1)       (1)
</TABLE>
--------
(1)  There was no Ecuador production in 1999 and 1998.

   Operations of the gas plant and the gathering system are summarized as
follows:

<TABLE>
<CAPTION>
                                                           Year Ended December
                                                                   31,
                                                           --------------------
                                                            2000   1999   1998
                                                           ------ ------ ------
<S>                                                        <C>    <C>    <C>
Plant product sales volume (MBBLS)........................    257    241    254
Average product sales price per barrel.................... $20.31 $12.93 $10.19
</TABLE>

                                      24
<PAGE>

 Year Ended 2000 Compared to Year Ended 1999

   Net income for the year ended December 31, 2000 was $32.2 million, or $2.27
per share on a diluted basis, while net income for the year ended December 31,
1999 was $8.8 million, or $.63 per share on a diluted basis. Significant
increases in oil and gas prices are primarily responsible for the improvement,
but increased production has also played a role.

   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 prices from $12.84 in 1999 to $20.53 in 2000. Improved domestic oil
production was primarily due to new wells in the Big Island field in Southwest
Louisiana and Eugene Island 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 the Cove field
in Texas and some Gulf of Mexico fields. Additionally, the Big Island field in
Southwest Louisiana, an exploratory success in 2000, also contributed gas
production. The Company's Ecuador properties do 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.

   Bellwether 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 offsets the hedges
previously existing on forecast production that was sold in late 2000. 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 were $6.1 million in 2000, compared to $3.8 million in
1999. Contributing to this increase was a 53% increase in average realized
plant liquid prices. Gas plant expense 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.

   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 per BOE in 1999. Ecuadorian
operations, which started in late 1999, account for $2.9 million, or $.49 per
BOE, of this increase. Most of the Ecuadorian field expenses are 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 in this period of high prices. Transportation costs were not
significant in either 2000 or 1999.

                                      25
<PAGE>

   Depreciation, depletion and amortization 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 depreciation, depletion and
amortization, but accelerated capital expenditures caused a $.99 increase in
the per BOE rate. Total Company depreciation, depletion and amortization per
BOE was $5.37 and $4.32 for the years ended December 31, 2000 and 1999,
respectively.

   General and administrative expenses totaled $9.1 million in the year ended
December 31, 2000 as 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, Bellwether 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. The
new contracts have varying terms and fees, but under the contracts overall
management fees have increased to levels similar to 1998 management fee
levels.

   Other significant items in general and administrative expenses include 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 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
is 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.

   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. As of March 31, 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. At December 31, 2000, the Company
believes it is more likely than not that the entire deferred asset will be
realized.

 Year Ended 1999 Compared to Year Ended 1998

   Net income for the year ended December 31, 1999 was $8.8 million, or $0.63
per share on a diluted basis, while the year ended December 31, 1998 resulted
in a loss of $77.3 million, or $5.50 per share on a diluted basis. The loss in
1998 was due to a $73.9 million impairment charge resulting from the Company's
capitalized cost exceeding the discounted future net revenues on an after-tax
basis of estimated proved oil and gas reserves.

   Oil and gas revenues were $68.3 million for the year ended 1999, as
compared to $73.7 million of oil and gas revenues for the year ended 1998.
While oil and gas volumes were down approximately 9% in 1999 compared to 1998,
oil prices were 10% higher in 1999. Oil prices increased from $11.75 per
barrel in 1998 to $12.84 in 1999. While gas prices were weak in the first few
months in 1999, gas prices recovered in the fourth quarter of 1999. As a
result of natural gas and crude oil hedging activities, oil and gas revenues
were reduced by $4 million in 1999 and were increased by $3.6 million in 1998.

   The production declines were attributable to normal declines in the
Company's Gulf of Mexico properties. This decline was somewhat halted by the
acquisition of additional Gulf of Mexico properties in July and the November
acquisition of Southeast New Mexico properties.


                                      26
<PAGE>

   Gas plant revenues were $3.8 million in the year ended December 31, 1999,
an increase of 19% from $3.2 million of gas plant revenues reflected in the
year ended December 31, 1998. The increase is due to a 27% increase in plant
liquid prices. Gas plant expenses were $2.4 million in the year ended December
31, 1999 as compared to $2.0 million during the year ended December 31, 1998.
The increase in expenses is attributable to periodic plant maintenance.

   Production expenses for fiscal 1999 totaled $21.5 million, as compared to
$25.4 million in fiscal 1998. On an BOE basis, production expenses were $4.11
per BOE in 1999 as compared to $4.34 per BOE in 1998. The primary reason for
the decreased costs was the sale of $2.9 million of non-core assets. These
assets had minimal production expenses, but high lease operating and workover
expenses. Transportation costs were not significant in 1999 or 1998.

   Depreciation, depletion and amortization decreased 40% to $23.9 million in
1999 versus $39.7 million in 1998. Such decrease was attributable to the lower
book basis due to the 1998 impairment. To the extent that capitalized costs
(net of depreciation, depletion and amortization) exceed the discounted future
net revenues on an after-tax basis of estimated proved oil and gas reserves,
such excess costs are charged to operations as an impairment. Sharp declines
in oil and gas prices, including further gas price declines subsequent to year
end, and to a lesser extent, downward revision in estimated proved reserves
resulted in a $73.9 million pretax impairment charge ($71.6 million after
tax), in the fiscal year ended December 31, 1998. February 23, 1999 prices
used in computing the impairment were based on a NYMEX oil price of $12.48 per
barrel and a NYMEX gas price of $1.71 per MMBTU, adjusted to the wellhead.

   General and administrative expenses decreased in 1999 to $7.8 million from
$8.5 million in 1998. A decrease in outsourcing costs from $4.0 million to
$2.9 million was the major contribution to this decline. Until October 1999,
the Company was charged an outsourcing fee, which was based upon a specified
percentage of the average book value of the Company's total assets, excluding
cash, plus a percentage of operating cashflows. Due to the $73.9 million
impairment charge mentioned above, the Company's total assets and resulting
percentage of such assets was reduced. Additionally, the 1998 period included
costs related to the closing of the Company's Dallas exploration office in
March 1998 and certain transition costs related to the change of the Company's
1997 fiscal year. Partially offsetting such decreases was $1.7 million in
severance costs incurred in the third quarter of 1999 due to the Company's
recent management change. General and administrative expenses on a barrel of
oil equivalent basis increased from $1.45 per equivalent BOE in 1998 to $1.50
per equivalent BOE in 1999.

   A refund on 1998 taxes was received in 1999. The refund resulted from
higher than anticipated dry hole and expired lease charges in 1998. For the
year ended December 31, 1999, due to increased future net reserves, the
Company recognized a portion of the deferred tax asset previously offset by a
valuation allowance.

   Interest expense increased to $11.8 million for the year ended December 31,
1999 from $11.7 million in the year ended December 31, 1998.

Other Matters

 Dividends

   At present, there is no plan to pay dividends on the common stock. Certain
restrictions contained in the Company's outstanding Notes and Senior Credit
Facility limit the amount of dividends which may be declared. The Company
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.

 Gas Balancing Positions

   It is customary in the industry for various working interest partners to
sell more or less than their entitled share of natural gas production. The
Company uses the sales method of accounting for gas imbalances. Under

                                      27
<PAGE>

this method, gas sales are recorded when revenue checks are received or are
receivable on the accrual basis. The settlement or disposition of gas
balancing positions as of December 31, 2000 is not anticipated to adversely
impact the financial condition of the Company.

 Derivative Financial Instruments

   The Company periodically uses derivative financial instruments to manage
oil and gas price risk and interest rate risk. For purposes of its hedging
activities, the Company 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 the Company
for its production (referred to as "basis differential"). From time to time
the Company enters into swap transactions in which the Company 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 notational 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. 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,
2000 to April 1, 2001 is 10.875%, which is the cap. If rates were to drop
below the cap by 10%, Bellwether's interest costs in the next period would
decrease about $44,000.

 New Accounting Pronouncements

   In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This statement establishes standards of
accounting for and disclosures of derivative instruments and hedging
activities. As amended, this statement is effective for fiscal quarters
beginning after January 1, 2001. The Company has reviewed its operations for
and documented all hedge transactions in accordance with this pronouncement.
All of Bellwether's commodity derivative instruments, with the exception of
those causing the $8.7 million loss recognized in the fourth quarter of 2000,
qualify for treatment as hedges. Beginning January 1, 2001, Bellwether will
record the fair value of commodity hedges as current assets or liabilities,
with the offsetting amount of $33.1 million in Other Comprehensive Income.
Earnings will only be impacted as hedge transactions are satisfied or to the
extent that a hedge proves to be ineffective. The Company's interest rate
swap, however, will not be designated for hedge accounting under the new
pronouncement. At January 1, 2001, a long-term liability will be recorded for
$4.4 million, the fair value of the swap, with a corresponding charge to
income due to this change in accounting principle. Quarterly adjustments will
be made in order to reflect changes in the fair value of the swap.

                                      28
<PAGE>

Item 7a. Quantitative and Qualitative Disclosures About Market Risk

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

   Commodity Price Risk--The Company produces and sells crude oil, natural gas
and natural gas liquids. As a result, the Company's operating results can be
significantly affected by fluctuations in commodity prices caused by changing
market forces. The Company periodically seeks to reduce its exposure to price
volatility by hedging its productions through swaps, options and other
commodity derivative instruments. The Company uses hedge accounting for these
instruments, and settlements of gains or losses on these contracts are
reported as a component of oil and gas revenues and operating cash flows in
the period realized. These agreements expose the Company to counterparty
credit risk to the extent that the counterparty is unable to meet its
settlement commitments to the Company.

   Bellwether 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 offsets hedges
previously existing on forecast production that was sold in late 2000. A non-
cash loss of $8.7 million was recognized in the fourth quarter 2000 related to
the $4.60 swap, along with a related current liability. The liability will be
relieved monthly as the swap is settled. By December 31, 2000, the liability
had been reduced to $7.5 million.

   The following tables detail the Company's hedges of future production which
were in place at December 31, 2000. The oil hedge was transacted in August
2000. All gas hedges were entered into before March 2000.

Oil Hedges

<TABLE>
<CAPTION>
                                                                  NYMEX   NYMEX
                                            BBLS    Total         Price   Price
      Period                               Per Day  BBLS    Type  Floor  Ceiling
      ------                               ------- ------- ------ ------ -------
      <S>                                  <C>     <C>     <C>    <C>    <C>
      Jan. 2001-Dec. 2001.................  1,500  547,500 Collar $24.00 $30.00
</TABLE>

Gas Hedges

<TABLE>
<CAPTION>
                                                                   NYMEX  NYMEX
                                            MCF                    Price  Price
      Period                              Per Day Total MCF  Type  Floor Ceiling
      ------                              ------- --------- ------ ----- -------
      <S>                                 <C>     <C>       <C>    <C>   <C>
      Jan. 2001-March 2001............... 25,000  2,250,000 Collar $2.30  $3.37
      April 2001-Oct. 2001............... 35,000  7,490,000 Collar $2.30  $2.92
</TABLE>

   The fair value at December 31, 2000 of these swap agreements was a loss of
$33.1 million. A 10% increase or decrease in oil and gas prices would have a
$6 million impact in the fair value. These energy swap agreements expose the
Company to counterparty credit risk to the extent the counterparty is unable
to meet its monthly settlement commitment to the Company.

   Interest Rate Risk--The Company may enter into financial instruments such
as interest rate swaps to manage the impact of changes in interest rates.
Effective September 22, 1998, the Company entered into an eight and a 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, subject to a cap, 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. This agreement is not held for trading purposes. The swap
provider is a major financial institution, and the Company does not anticipate
non-performance by the provider.

   The Company's exposure to changes in interest rates primarily results from
short term changes in the LIBOR rates. A 10% decrease in the floating LIBOR
rates would have the effect of decreasing interest costs to the Company by
$872,500 per year. A 10% increase in the floating LIBOR rates would have no
impact since any increase at this time is capped at 10.875%.


                                      29
<PAGE>

Item 8. Financial Statements and Supplementary Data

                  INDEX TO FINANCIAL STATEMENTS AND SCHEDULES

<TABLE>
<CAPTION>
                                                                          Page
                                                                         Number
                                                                         ------
<S>                                                                      <C>
Independent Auditors' Report............................................   31
Financial Statements:
Consolidated Balance Sheets as of December 31, 2000 and 1999............   32
  Consolidated Statements of Operations for the Years Ended December 31,
   2000, 1999 and 1998..................................................   34
  Consolidated Statements of Changes in Stockholders' Equity for the
   Years Ended December 31, 2000, 1999 and 1998.........................   35
  Consolidated Statements of Cash Flows for the Years Ended December 31,
   2000, 1999 and 1998..................................................   36
  Notes to Consolidated Financial Statements............................   37
</TABLE>

                                       30
<PAGE>

                         INDEPENDENT AUDITORS' REPORT

The Board of Directors and Stockholders of
Bellwether Exploration Company and Subsidiaries:

   We have audited the accompanying consolidated balance sheets of Bellwether
Exploration Company and subsidiaries as of December 31, 2000 and 1999 and the
related consolidated statements of operations, changes in stockholders' equity
and cash flows for each of the years in the three-year period ended December
31, 2000. 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 present fairly, in
all material respects, the financial position of Bellwether Exploration
Company and subsidiaries as of December 31, 2000 and 1999 and the results of
their operations and their cash flows for each of the years in the three-year
period ended December 31, 2000 in conformity with accounting principles
generally accepted in the United States of America.

                                          KPMG LLP

Houston, Texas
March 9, 2001

                                      31
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                      December 31, December 31,
                                                          2000         1999
                       ASSETS                         ------------ ------------
                                                       (Amounts in thousands)
<S>                                                   <C>          <C>
CURRENT ASSETS:
  Cash and cash equivalents..........................  $  14,464    $   6,101
  Accounts receivable and accrued revenues...........     27,724       14,354
  Notes receivable-affiliate.........................      1,281           --
  Prepaid expenses and other.........................      1,189        1,562
                                                       ---------    ---------
    Total current assets.............................     44,658       22,017
                                                       ---------    ---------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties (full cost)
  United States--Unproved properties of $11,360 and
   $16,325 excluded from amortization as of December
   31, 2000 and 1999, respectively...................    421,408      344,778
  Ecuador--Unproved properties of $0 and $404
   excluded from amortization as of December 31, 2000
   and 1999, respectively............................     12,988        1,246
Gas plant facilities.................................     18,452       17,775
                                                       ---------    ---------
                                                         452,848      363,799
Accumulated depreciation, depletion and
 amortization--oil and gas...........................   (296,567)    (221,092)
Accumulated depreciation, depletion and
 amortization--gas plant.............................     (7,345)      (6,134)
                                                       ---------    ---------
Net property, plant and equipment....................    148,936      136,573
Leasehold, furniture and equipment...................      2,782          438
Accumulated depreciation.............................       (404)         (74)
                                                       ---------    ---------
                                                           2,378          364
                                                       ---------    ---------
INVESTMENT IN OUTSIDE COMPANY........................      4,554        4,554
DEFERRED INCOME TAXES................................     15,141        2,739
OTHER ASSETS.........................................      5,878        5,514
                                                       ---------    ---------
                                                       $ 221,545    $ 171,761
                                                       =========    =========
</TABLE>


                See Notes to Consolidated Financial Statements.

                                       32
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                      December 31, December 31,
                                                          2000         1999
        LIABILITIES AND STOCKHOLDERS' EQUITY          ------------ ------------
                                                       (Amounts in thousands,
                                                      except share information)
<S>                                                   <C>          <C>
CURRENT LIABILITIES:
  Accounts payable and accrued liabilities...........   $ 29,960     $ 18,247
  Commodity derivative liabilities...................      7,486           --
                                                        --------     --------
    Total current liabilities........................     37,446       18,247
                                                        --------     --------
LONG-TERM DEBT.......................................    125,450      130,000
OTHER LIABILITIES....................................      1,689          200
STOCKHOLDERS' EQUITY:
  Preferred stock, $0.01 par value, 1,000,000 shares
   authorized; none issued or outstanding at December
   31, 2000 and 1999.................................         --           --
  Common stock, $0.01 par value, 30,000,000 shares
   authorized, 14,259,626 and 14,168,791 shares
   issued at December 31, 2000 and December 31, 1999,
   respectively......................................        143          142
  Additional paid-in capital.........................     81,892       80,455
  Retained deficit...................................    (23,170)     (55,378)
  Treasury stock, at cost, 311,000 shares............     (1,905)      (1,905)
                                                        --------     --------
    Total stockholders' equity.......................     56,960       23,314
                                                        --------     --------
                                                        $221,545     $171,761
                                                        ========     ========
</TABLE>



                See Notes to Consolidated Financial Statements.

                                       33
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
                            Year Ended         Year Ended         Year Ended
                           December 31,       December 31,       December 31,
                               2000               1999               1998
                          ---------------    ---------------    ---------------
                           (Amounts in thousands, except per share data)
<S>                       <C>                <C>                <C>
REVENUES:
  Gas revenues..........           $ 62,652    $       41,559     $        46,661
  Oil revenues--United
   States...............             45,286            26,705              26,991
  Oil revenues--
   Ecuador..............              4,315                --                  --
  Gas plant revenues....              6,070             3,830               3,170
  Interest and other
   income...............                957             1,335               1,347
                            ---------------    --------------     ---------------
                                    119,280            73,429              78,169
                            ---------------    --------------     ---------------
COSTS AND EXPENSES:
  Production expenses--
   United States........             27,694            21,515              25,381
  Production expenses--
   Ecuador..............              2,815                17                  --
  Transportation costs..                270               316                 435
  Gas plant expenses....              2,677             2,366               1,967
  Depreciation,
   depletion and
   amortization--United
   States...............             31,909            23,863              39,688
  Depreciation,
   depletion and
   amortization--
   Ecuador..............                745                --                  --
  Impairment expense....                 --                --              73,899
  Disposition of
   hedges...............              8,671                --                  --
  General and
   administrative
   expenses.............              9,138             7,848               8,459
  Interest expense......             15,375            11,845              11,660
                            ---------------    --------------     ---------------
                                     99,294            67,770             161,489
                            ---------------    --------------     ---------------
Income (loss) before
 income tax benefit.....             19,986             5,659             (83,320)
Provision for income tax
 benefit................            (12,222)           (3,154)             (6,069)
                            ---------------    --------------     ---------------
Net income (loss).......    $        32,208    $        8,813     $       (77,251)
                            ===============    ==============     ===============
Net income (loss) per
 share..................    $          2.32    $          .64     $         (5.50)
                            ===============    ==============     ===============
Net income (loss) per
 share--diluted.........    $          2.27    $          .63     $         (5.50)
                            ===============    ==============     ===============
Weighted average common
 shares
 outstanding............             13,899            13,854              14,039
                            ===============    ==============     ===============
Weighted average common
 shares
 outstanding--diluted...             14,175            13,896              14,039
                            ===============    ==============     ===============
</TABLE>


                See Notes to Consolidated Financial Statements.

                                       34
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

           CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

<TABLE>
<CAPTION>
                                          Preferred
                          Common Stock      Stock     Additional Retained   Treasury Stock
                          ------------- -------------  Paid-In   Earnings   --------------
                          Shares Amount Shares Amount  Capital   (Deficit)  Shares Amount    Total
                          ------ ------ ------ ------ ---------- ---------  ------ -------  --------
                                                   (Amounts in thousands)
<S>                       <C>    <C>    <C>    <C>    <C>        <C>        <C>    <C>      <C>
Balance December 31,
 1997...................  13,892  $139    --    $--    $78,470   $ 13,060      --  $    --  $ 91,669
                          ======  ====   ===    ===    =======   ========    ====  =======  ========
Stock options exercised
 and related tax
 effects................     273     3    --     --      1,972         --      --       --     1,975
Treasury shares
 purchased..............      --    --    --     --         --         --    (311)  (1,904)   (1,904)
Net loss................      --    --    --     --         --    (77,251)     --       --   (77,251)
                          ------  ----   ---    ---    -------   --------    ----  -------  --------
Balance December 31,
 1998...................  14,165  $142    --    $--    $80,442   $(64,191)   (311) $(1,904) $ 14,489
                          ======  ====   ===    ===    =======   ========    ====  =======  ========
Stock options Exercised
 and related tax
 effects................       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) $(1,905) $ 23,314
                          ======  ====   ===    ===    =======   ========    ====  =======  ========
Stock options Exercised
 and related tax effects
 .......................      91     1    --     --        588         --      --       --       589
Compensation expense....      --    --    --     --        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
                          ======  ====   ===    ===    =======   ========    ====  =======  ========
</TABLE>



                See Notes to Consolidated Financial Statements.

                                       35
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                         Year Ended   Year Ended   Year Ended
                                        December 31, December 31, December 31,
                                            2000         1999         1998
                                        ------------ ------------ ------------
                                                (Amounts in thousands)
<S>                                     <C>          <C>          <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................   $ 32,208     $  8,813     $(77,251)
Adjustments to reconcile net income
 (loss) to net cash provided by
 operating activities:
  Depreciation, depletion and
   amortization........................     33,213       24,694       40,544
  Stock option expense amortization....        849           --           --
  Disposition of hedges................      8,671           --           --
  Impairment expense...................         --           --       73,899
  Deferred taxes.......................    (12,307)      (2,739)      (6,820)
                                          --------     --------     --------
                                            62,634       30,768       30,372
Changes in assets and liabilities, net
 of acquisition effects:
  Accounts receivable and accrued
   revenues............................    (13,370)       2,101        2,691
  Prepaid expenses and other...........        373          157        1,521
  Accounts payable and accrued
   liabilities.........................     12,217        6,265       (2,220)
  Due (to) from affiliates.............         --         (125)       3,245
  Other................................       (215)        (411)        (887)
                                          --------     --------     --------
NET CASH FLOWS PROVIDED BY OPERATING
 ACTIVITIES............................     61,639       38,755       34,722
                                          --------     --------     --------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Acquisitions of oil and gas
   properties..........................     (7,078)     (25,889)      (9,596)
  Investment in outside companies......         --       (4,426)        (128)
  Note receivable......................     (1,281)          --           --
  Additions to oil and gas properties..    (81,294)     (30,904)     (30,583)
  Proceeds from sales of properties....     45,906        5,139          421
  Abandonment costs....................     (1,531)        (136)        (757)
  Additions to leasehold, furniture and
   equipment...........................     (2,462)        (448)         (55)
  Additions to gas plant facilities....       (677)        (369)        (689)
  Other................................       (446)      (1,071)         (88)
                                          --------     --------     --------
NET CASH FLOWS USED IN INVESTING
 ACTIVITIES............................    (48,863)     (58,104)     (41,475)
                                          ========     ========     ========
CASH FLOWS FROM FINANCING ACTIVITIES:
  Proceeds from borrowings.............     31,400       42,000        4,900
  Net proceeds from issuance of common
   stock...............................        496           13        1,649
  Payments of long-term debt...........    (35,950)     (16,400)        (500)
  Credit facility costs................       (359)        (172)         (81)
  Purchase of treasury shares..........         --           (1)      (1,904)
                                          --------     --------     --------
NET CASH FLOWS (USED IN) PROVIDED BY
 FINANCING ACTIVITIES..................     (4,413)      25,440        4,064
                                          --------     --------     --------
Net increase (decrease) in cash and
 cash equivalents......................      8,363        6,091       (2,689)
Cash and cash equivalents at beginning
 of period.............................      6,101           10        2,699
                                          --------     --------     --------
Cash and cash equivalents at end of
 period................................   $ 14,464     $  6,101     $     10
                                          ========     ========     ========
</TABLE>

                See Notes to Consolidated Financial Statements.

                                       36
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

   Bellwether Exploration Company ("the Company") is an independent energy
company primarily engaged in the acquisition, exploitation and development of
and exploration for oil and gas properties. The Company is a Delaware
corporation. Since April 1997, the Company has employed a balanced growth
strategy combining strategic acquisitions of producing properties with
technology driven development and exploration drilling. As a result, the
Company's results of operations have been significantly affected by its
success in acquiring oil and gas properties and its ability to maintain or
increase production through its development activities.

   On January 25, 2001, Bellwether announced plans to merge with Bargo Energy
Company. Contemporaneously with the merger, Bellwether proposes to increase
its authorized common stock to 65.0 million shares and amend its 1996 Stock
Incentive Plan to increase the number of shares reserved for issuance under
the plan by 2.5 million shares. Under the merger agreement, Bargo shareholders
will receive a combination of cash and Bellwether common stock. The merger is
conditioned upon its receiving the approval of Bellwether's shareholders and
Bargo's shareholders. The merger will be accounted for using the purchase
method of accounting. Bellwether's management believes the merger is, among
other things, in accordance with Bellwether's long-term strategy of growth
through acquisitions, will create a larger company with more liquidity in its
common stock and more financial flexibility, will strengthen Bellwether's
management team, and will add significantly to Bellwether's production.

2. Summary of Significant Accounting Policies

 Principles of Consolidation

   The consolidated financial statements include the accounts of Bellwether
Exploration Company 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. The Company's investment in Carpatsky is reflected using the cost
method.

 Oil and Gas Properties

   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 incurred. Direct internal costs capitalized are primarily the
salary and benefits of geologists and engineers directly involved in
acquisition, exploration and development activities and amounted to $3.3
million, $1.7 million and $0.8 million in the years ended December 31, 2000,
1999 and 1998, respectively. The Company currently has two full cost pools:
United States and Ecuador. 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 $5.46
in 2000, $4.32 in 1999, and $6.59 in 1998. Depletion expense per equivalent
barrel of Ecuador production was $4.28 in 2000.

                                      37
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   Nothing was excluded from amortization in the Company's Ecuador full cost
pool as of December 31, 2000. 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        2000
                                --------- ----------- ----------- ------------
<S>                             <C>       <C>         <C>         <C>
Costs Incurred During Periods
 Ended:
  December 31, 2000............  $   948     $532         $--       $ 1,480
  December 31, 1999............    8,591       --          --         8,591
  December 31, 1998............    1,289       --          --         1,289
  Prior........................       --       --          --            --
                                 -------     ----         ---       -------
                                 $10,828     $532         $--       $11,360
                                 =======     ====         ===       =======
</TABLE>

   Land and seismic costs have been incurred in the current and prior years by
the Company and are still in the evaluation stage. Approximately $2.8 million
and $1.2 million was evaluated and moved to the full cost pool in 2000 and
1999, respectively.

   Such costs fall into four broad categories:

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

    2) Material projects currently being marketed to third parties;

    3) Leasehold and seismic costs for projects not yet evaluated at all;
      and

    4) Drilling and completion costs for projects in progress at year end
      which have not resulted in the recognition of reserves at December
      2000. This category of costs will transfer into the full cost pool in
      2001.

   Dispositions of oil and gas properties 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. 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 in 1998, with continued declines in
early 1999. As a result of such declines, the Company's capitalized costs were
in excess of future net revenues calculated using prices in effect in late
February 1999. The Company recorded an oil and gas property impairment of
$73.9 million in 1998. No such impairment in book value was required at
December 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

                                      38
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

satisfy requirements of the joint ventures. The result of this transfer of
interests was the dissolution of the joint ventures. Bellwether's interest in
the gas plants was reduced to 11.9% and 32.0% in the Snyder and Diamond M-
Sharon Ridge Gas Plants, respectively.

   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 when revenue checks are received or
are receivable on the accrual basis. Sales to Torch Co-Energy LLC accounted
for greater than 10% of oil and gas revenues in 2000, 1999, and 1998. The
sales amounts were $27.9 million, $14.4 million, and $13.6 million,
respectively, and were part of domestic revenues. Sales to Valero Industrial
Gas, L.P. of $7.0 million accounted for greater than 10% of the domestic
revenues in 1997.

   Gas imbalances are created, but not recorded, when the sales amount is not
equal to the Company's entitled share of production. The Company had a net
imbalance liability, at fair value, determined by applying average realized
prices for the year to the imbalance volumes of $2.3 million, $1.2 million and
$.5 million, at December 31, 2000, 1999 and 1998, 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 to extend the productive life of such reserves.

 Natural Gas and Crude Oil Hedging

   Commodity derivatives utilized as hedges include collar and swap contracts.
In order to qualify as a hedge, price movements in the underlying commodity
derivative must be sufficiently correlated with the hedged commodity. When a
commodity derivative ceases to qualify as a hedge, the change in its fair
value is recognized in income currently. Settlement of gains and losses on
price swap contracts are realized monthly, generally based upon the difference
between the contract price and the average closing New York Mercantile
Exchange ("NYMEX") price and are reported as a component of oil and gas
revenues and operating cash flows in the period realized. Gains and losses
attributable to the termination of a swap contract are deferred on the balance
sheet and recognized in revenue when the hedged crude oil and natural gas is
sold. There were no such deferred gains or losses at December 31, 2000, 1999
or 1998.

   Oil and gas revenues were decreased by $24.5 million and $4.0 million in
the years ended December 31, 2000 and 1999, respectively, and increased by
$3.6 million in the year ended December 31, 1998, as a result of such hedging
activity.

   In the fourth quarter of the year 2000, the Company recognized a non-cash
loss of $8.7 million related to a $4.60 per Mcf gas swap on 15,000 Mcf per day
over the period November 2000 through October 2001 and previously existing
swaps intended to hedge forecasted production. The swap was intended to limit
future losses by offsetting the previously existing hedges on forecasted
production from properties sold by the Company in late 2000.

 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.

                                      39
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 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, 2000, 1999 and 1998, was $13.8 million, $11.1 million, and $11.1
million, respectively. Income tax refunds received in cash for December 31,
1999 were $437,000. Income taxes paid in cash for the years ended December 31,
2000 and 1998 were $108,831 and $1,408,000, respectively. Certain non-cash
transactions were recorded in 2000: 1) A $849,000 non-cash general and
administrative charge in 2000 was required due to the difference between
exercise and grant date prices on options awarded to the Company president,
and 2) A non-cash loss of $8.7 million at December 31, 2000 related to a $4.60
gas swap not treated as a hedge.

 Benefit Plans

   During 1993, the Company adopted the Bellwether Corporation 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's matching
contributions are 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, 2000, 1999 and 1998 were $312,185, $191,176, and $123,952,
respectively.

 Deferred Compensation Plan

   In late 1997, the Company adopted the Bellwether 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.
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, 2000, 1999 and 1998 and was
approximately $25,000, $98,000 and $49,000, respectively.

 New Accounting Pronouncements

   In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This statement establishes standards of
accounting for and disclosures of derivative instruments and hedging
activities. As amended, this statement is effective for fiscal quarters
beginning after January 1, 2001. The Company has reviewed its operations for
and documented all hedge transactions in accordance with this pronouncement.
All of Bellwether's commodity derivative instruments, with the exception of
those causing the $8.7 million loss recognized in the fourth quarter of 2000,
qualify for treatment as hedges. Beginning January 1, 2001, Bellwether will
record the fair value of commodity hedges as current assets or liabilities,
with the offsetting amount of $33.1 million in Other Comprehensive Income.
Earnings will be impacted as hedge transactions are satisfied or to the extent
that a hedge proves to be ineffective. The Company's interest rate swap,
however, will not be designated for hedge accounting under the new
pronouncement. At January 1, 2001, a long-term liability will be recorded for
$4.4 million, the fair value of the swap, with a corresponding charge to
income due to this change in accounting principle. Quarterly adjustments will
be made in order to reflect changes in the fair value of the swap or collars.

                                      40
<PAGE>

                BELLWETHER EXPLORATION COMPANY 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 to current reporting practices.

3. Acquisitions and Investments

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

   During 1998, in connection with a possible transaction by the Company with
Carpatsky Petroleum Company ("Carpatsky"), the Company agreed to guarantee
$500,000 of indebtedness of Carpatsky to Torch. The Carpatsky note to Torch
went into default in June 1998. Under an agreement effective October 31, 1999,
Bellwether paid Torch $565,700 for the guaranty. The Company received in
exchange 4.5 million shares of Carpatsky and a warrant to acquire an
additional 967,296 common shares. On December 30, 1999, Bellwether purchased
95.5 million preferred shares of Carpatsky Petroleum, Inc. and warrants to
acquire 12.5 million common shares for $4 million. The preferred shares are
convertible into 50 million Carpatsky common shares. This investment does not
give the Company the ability to significantly influence Carpatsky's
operations.

   In December 1998, Bellwether 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. Bellwether is also entitled to recoup lease operating
expenses associated with the base production. Negotiations with the Ecuadorian
government took place throughout 1999 with Bellwether officially taking over
operations of the field in January of 2000. Bellwether committed to a
$12 million work program over three years. In February 2000, Bellwether took
over operations of another Ecuadorian field, the Tiguino field. The contract
with the government is similar for both fields. A Bellwether subsidiary
operated the field on behalf of Petroleos Colombianos ("Petrocol"), which had
been granted a 25% interest and operatorship by the Ecuadorian government.
Bellwether 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 have
been signed by all parties, but the final government approval of the
transaction has not yet been obtained. Such approval is necessary for the
agreements to be accepted in Ecuador. Bellwether has received a legal opinion
letter that it is legally entitled to the 70% of production from the field and
has also received confirmation that the government has never failed to approve
similar assignments.

4. Related Party Transactions

   The Company is a party to a master services agreement and six specific
outsourcing contracts which require Torch to administer certain business
activities of the Company. The various contracts have terms from two years to
five years in length and annual fees ranging from fixed and variable amounts
of $0.6 million to $3.0 million plus fees based upon percentages of production
ranging from 1/2% to 2% depending on the product. Prior to

                                      41
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

October 1999, the Company was party to an administrative services agreement
which required Torch to administer certain activities of the Company for
monthly fees equal to the sum of one-twelfth of 2% of the average of the book
value of the Company's total assets, excluding cash, plus 2% of annual
operating cash flows (as defined) during the period in which the services are
rendered plus reimbursement of certain costs incurred on behalf of the
Company. For the periods ended December 31, 2000, 1999, and 1998 related fees
paid to Torch amounted to $4.7 million, $2.9 million and $4.0 million,
respectively.

   In July 2000, Pan American Energy Finance, a wholly-owned subsidiary of
Bellwether entered into a $1 million revolving credit facility with Carpatsky.
The facility earns interest at 10% per annum and is due on November 30, 2001.
As of December 31, 2000 the full $1 million had been borrowed.

   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. Mr. Bryan is Senior
Managing Director of and a holder of common stock of the parent corporation of
Torch. Approximately $1.7 million of severance cost attributable to this
management change were incurred in August 1999. Mr. Bryan resigned his
position as CEO of Bellwether in May 2000 and his position as Chairman in
December 2000, but remains on the Board of Directors.

   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.

   Pursuant to a Separation Agreement between the Company and one of the
senior executives, the executive entered into a nonrecourse promissory note
with a principal amount of $332,872. The loan bears interest at an annual rate
of seven percent 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, 2000, the
outstanding loan balance of $332,872 was reflected in Other Assets on the
Balance Sheet, while accrued interest of $8,414 was reflected within Accounts
Receivable and Accrued Revenues on the Balance Sheet.

   Sales to Torch-Co Energy LLC accounted for approximately 24%, 22% and 28%
of fiscal year 2000, 1999 and 1998 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. The Company
generally pays fees of 1/2% to 2% of revenues for such marketing services.
Such charges were $563,369, $947,500 and $1,143,000, in periods ended December
31, 2000, 1999 and 1998, 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.

   Costs of the evaluation of potential property acquisitions and due
diligence conducted in conjunction with acquisitions closed are incurred by
Torch at the Company's request. The Company was charged $1.3 million,
$357,800, and $379,000 for these costs in periods ended December 31, 2000,
1999 and 1998, 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
Bellwether 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 periods ended December 31, 1999 and 1998 was
$1,153,000 and $1,349,000, respectively.

   Torch is the operator of the Snyder Gas Plant. In periods ended December
31, 2000, 1999 and 1998, the fees paid by the Company to Torch were $96,339,
$73,000 and $72,000, respectively.

                                      42
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


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
100,000 warrants is April 2002.

   A tax benefit related to the exercise of employee stock options of $95,000
in 2000 and $324,000 in 1998 was allocated directly to additional paid in
capital. Such benefit was not material in year 1999.

 Shareholder Rights Plan

   In September 1997, Bellwether adopted a shareholder rights plan to protect
Bellwether's shareholders from coercive or unfair takeover tactics. Under the
shareholder rights plan, each outstanding share of Bellwether common stock and
each share of subsequently issued Bellwether 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 Bellwether common stock without the prior consent of
Bellwether. 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 Bellwether which, at the time the rights become exercisable,
have a market price of two times the exercise price of the right. Bellwether
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
Bellwether.

 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
                                       2000                December 31, 1999
                             -------------------------- -----------------------
                              Income   Shares Per Share Income Shares Per Share
                             --------  ------ --------- ------ ------ ---------
<S>                          <C>       <C>    <C>       <C>    <C>    <C>
Net income.................  $ 32,208                   $8,813
                             --------  ------  ------   ------ ------   -----
Earnings per Common share..  $ 32,208  13,899  $ 2.32   $8,813 13,854   $0.64
Effect of Dilutive
 Securities:
 Options & Warrants........        --     276               --     42
                             --------  ------  ------   ------ ------   -----
Earnings per common share--
 diluted...................  $ 32,208  14,175  $ 2.27   $8,813 13,896   $0.63
                             ========  ======  ======   ====== ======   =====
<CAPTION>
                              Year Ended December 31,
                                       1998
                             --------------------------
                              Income   Shares Per Share
                             --------  ------ ---------
<S>                          <C>       <C>    <C>       <C>    <C>    <C>
Net Income (loss)..........  $(77,251)
                             --------  ------  ------
Earnings (loss) per Common
 share.....................  $(77,251) 14,039  $(5.50)
Effect of Dilutive
 Securities:
 Options & Warrants........        --      --      --
                             --------  ------  ------
Earnings (loss) per common
 share--diluted............  $(77,251) 14,039  $(5.50)
                             ========  ======  ======
</TABLE>


                                      43
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

   For the year ended December 31, 1998, 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 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 key employees of the
Company and Torch. 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 2000 the plans allow the Company 28,500
options.

   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 Bellwether's stock on the grant date. A charge of $536,070
was recorded in May 2000, when one-third of the options vested. The remaining
expense is charged ratably over the vesting period of two years. Relative to
these options, total compensation expense recognized for the year ended
December 31, 2000 was $849,000. At December 31, 2000, an unrecorded liability
of approximately $759,000 exists for the unvested cost of these options.

   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, 1997........................... 1,387,825  $3.00 $12.38
  Granted..............................................   300,000  $6.25 $10.94
  Surrendered..........................................  (146,000) $5.62 $12.38
  Exercised............................................  (273,325) $3.00 $ 7.75
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
                                                        =========  ===== ======
Exercisable at December 31, 2000....................... 1,732,502  $3.34 $12.38
                                                        =========  ===== ======
</TABLE>

                                      44
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   Detail of stock options outstanding and options exercisable at December 31,
2000 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 $ 7.63....   563,166     5.7       $5.21     447,001  $5.29
1996 Plan $3.34 to $12.38.... 1,739,500     9.2       $6.63   1,285,501  $6.78
                              ---------                       ---------
    Total.................... 2,302,666                       1,732,502
                              =========                       =========
</TABLE>

   The estimated weighted average fair value per share of options granted
during 2000, 1999, and 1998 was $12.75, $11.68 and $2.34, 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 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. For 1998, expected
stock price volatility of 40%; a risk free interest rate of 5.5%, an average
expected option life of 5 years. 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,
                                              2000         1999         1998
                                          ------------ ------------ ------------
<S>                                       <C>          <C>          <C>
Net income (loss)
  As reported............................   $32,208      $  8,813     $(77,251)
  Pro forma..............................   $24,955      $(19,516)    $(78,321)
Earnings (loss) per share
  As reported............................   $  2.32      $    .64     $  (5.50)
  Pro forma..............................   $  1.79      $  (1.41)    $  (5.58)
Diluted earnings (loss) per share
  As reported............................   $  2.27      $    .63     $  (5.50)
  Pro forma..............................   $  1.76      $  (1.41)    $  (5.58)
</TABLE>

6. Derivative Financial Instruments

   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. Gains and losses from these hedging activities are included
in oil and gas sales at the time the related production is delivered. Hedging
activities decreased revenues by $24.5 million and $4.0 million for the years
2000 and 1999, respectively. Revenues for the year 1998 were increased by $3.6
million due to hedging activities.

                                      45
<PAGE>

                BELLWETHER EXPLORATION COMPANY 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, 2000. The oil hedge was transacted in
August 2000. All gas hedges were entered into before March 2000.

Oil Hedges

<TABLE>
<CAPTION>
                                                                  NYMEX   NYMEX
                                            BBLS    Total         Price   Price
      Period                               Per Day  BBLS    Type  Floor  Ceiling
      ------                               ------- ------- ------ ------ -------
      <S>                                  <C>     <C>     <C>    <C>    <C>
      Jan. 2001-Dec. 2001.................  1,500  547,500 Collar $24.00 $30.00
</TABLE>

Gas Hedges

<TABLE>
<CAPTION>
                                                                   NYMEX  NYMEX
                                           MCF                     Price  Price
      Period                             Per Day Total MCF   Type  Floor Ceiling
      ------                             ------- ---------- ------ ----- -------
      <S>                                <C>     <C>        <C>    <C>   <C>
      Jan. 2001-March 2001.............. 25,000   2,250,000 Collar $2.30  $3.37
      April 2001-Oct. 2001.............. 35,000  97,490,000 Collar $2.30  $2.92
</TABLE>

   The fair value at December 31, 2000 of these swap agreements was a loss of
$33.1 million. These energy swap agreements expose the Company to counterparty
credit risk to the extent the counterparty is unable to meet its monthly
settlement commitment to the Company.

   Bellwether 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 offsets 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 2000
related to the $4.60 swap, along with a related current liability. The
liability will be relieved monthly as the swap is settled. By December 31,
2000, the liability had been reduced to $7.5 million.

   In order to reduce interest costs, effective September 22, 1998, the
Company entered into an eight and one-half year's 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 floating rate for the
period from October 1, 2000 to April 1, 2001 is 10.875%. Through April 1, 2002
the floating rate is capped at 10.875% and capped at 12.375% thereafter. The
Company's interest rate swap will not be designated for hedge accounting upon
implementation of SFAS 133, therefore, the interest rate swap will be recorded
at fair value with a corresponding charge to income.

Determination of Fair Values of Financial Instruments

   Fair value for cash, short-term investments, receivables and payables
approximates carrying value. The following table details the carrying values
and approximate fair values of the Company's other investments, derivative
financial instruments and long-term debt at December 31, 2000 and 1999 (in
thousands).

<TABLE>
<CAPTION>
                                   December 31, 2000      December 31, 1999
                                 ---------------------- ----------------------
                                 Carrying   Approximate Carrying   Approximate
                                   Value    Fair Value    Value    Fair Value
                                 ---------  ----------- ---------  -----------
<S>                              <C>        <C>         <C>        <C>
Assets (Liabilities):
Derivative instruments other
 than trading:
  Interest rate swap
   agreements................... $      --   $  (4,411) $      --   $   3,045
  Production swap agreements.... $      --   $ (33,133) $      --   $     862
Long-term debt (See Note 7)..... $(125,450)  $(114,890) $(130,000)  $(125,485)
</TABLE>


                                      46
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

7. Long-Term Debt

   Long-term debt is comprised of the following at December 31, 2000 and 1999
(in thousands):

<TABLE>
<CAPTION>
                                                       December 31, December 31,
                                                           2000         1999
                                                       ------------ ------------
      <S>                                              <C>          <C>
      Bank credit facility............................   $ 25,450     $ 30,000
      10 7/8% Senior Subordinated Notes...............    100,000      100,000
                                                         --------     --------
      Long-term debt..................................   $125,450     $130,000
                                                         ========     ========
</TABLE>

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

<TABLE>
      <S>                                                               <C>
      2000............................................................. $     --
      2001.............................................................       --
      2002.............................................................   25,450
      2003.............................................................       --
      2004.............................................................       --
      Thereafter.......................................................  100,000
                                                                        --------
                                                                        $125,450
                                                                        ========
</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 were $24.5 million in borrowings outstanding
under the Senior Credit Facility. In February 2001, the senior credit facility
was amended to reduce the facility amount to $40 million while increasing the
borrowing base to $35 million. The maturity date was changed to August 2002.

   Bellwether may 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: 1) Bellwether and its
subsidiaries will not sell all or substantially all of their assets to another
person, 2) none of Bellwether or its subsidiaries will incur additional
indebtedness with the exception of permitted indebtedness, 3) the indebtedness
of Bellwether's subsidiaries will not exceed 10% of consolidated tangible net
worth (indebtedness from subsidiaries to Bellwether or guarantors is
permitted), 4) none of Bellwether 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.

   In April 1997, the Company issued $100.0 million of 10 7/8% Senior
Subordinated Notes ("Notes") that mature April 1, 2007. 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%

                                      47
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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, 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.

   Effective September 22, 1998, the Company entered into an eight and one-
half year's 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 floating rate for the period from October 1, 1999 to April 1,
2000 is 9.64%. Through April 1, 2002 the floating rate is capped at 10.875%
and capped at 12.375% thereafter. This interest swap is accounted for as a
hedge.

8. 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,
                                            2000         1999         1998
                                        ------------ ------------ ------------
      <S>                               <C>          <C>          <C>
      Current
        Federal........................   $     67     $  (425)     $   658
        State..........................         18          10           93
      Deferred--Federal, Foreign and
       State...........................    (12,307)     (2,739)      (6,820)
                                          --------     -------      -------
      Total income tax benefit.........   $(12,222)    $(3,154)     $(6,069)
                                          ========     =======      =======
</TABLE>

   The tax effect of temporary differences that give rise to significant
portions of the deferred tax assets and liabilities at December 31, 2000 and
1999 is as follows:

<TABLE>
<CAPTION>
                                                      December 31, December 31,
                                                          2000         1999
                                                      ------------ ------------
   <S>                                                <C>          <C>
   Net operating loss carryforwards..................   $10,091      $10,296
   Percentage depletion carryforwards................       271          271
   Alternative minimum tax credit carryforwards......       752          725
   Property, plant and equipment.....................     3,087        9,551
   State income taxes................................     1,138        1,732
                                                        -------      -------
   Total deferred income tax assets..................    15,339       22,575
                                                        -------      -------
   Valuation allowances..............................        --      (19,836)
   Foreign income taxes..............................      (198)          --
                                                        -------      -------
   Total deferred income tax liability...............      (198)     (19,836)
                                                        -------      -------
   Net deferred income tax asset.....................   $15,141      $ 2,739
                                                        =======      =======
</TABLE>

   At December 31, 1999, the Company determined that it is more likely than
not that a portion of the deferred tax assets will not be realized and the
valuation allowance was adjusted by $5.2 million to a total valuation
allowance of $19.8 million. At December 31, 2000, however, the Company
determined that it was more likely

                                      48
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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.

   A tax benefit related to the exercise of employee stock options of
approximately $95,000 was allocated directly to additional paid-in capital in
2000. 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 and minority interest. The
reasons for the differences are as follows:

<TABLE>
<CAPTION>
                                          Year Ended   Year Ended   Year Ended
                                         December 31, December 31, December 31,
                                             2000         1999         1998
                                         ------------ ------------ ------------
   <S>                                   <C>          <C>          <C>
   Statutory Federal income tax rate...      34.0%        34.0%       (34.0)%
   Increase (decrease) in tax rate
    resulting from:
   State income taxes, net of federal
    benefit............................       3.0%         3.1%        (3.1)%
   Foreign income taxes, net of federal
    benefit............................       1.0%          --           --
   Non-deductible travel and
    entertainment......................       0.1%         0.2%         0.1%
   Other...............................        --          (.8)%         --
   Change in valuation allowance.......     (99.3)%      (92.2)%       29.7%
                                            -----        -----        -----
                                            (61.2)%      (55.7)%       (7.3)%
                                            =====        =====        =====
</TABLE>

   The Company issued 3,400,000 shares of its common stock on July 20, 1994.
As a result of the 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, 2000, the Company had net operating loss carryforwards of
approximately $29 million, which will expire in future years beginning in
2001.

9. Commitments and Contingencies

 Lease Commitments

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

<TABLE>
<CAPTION>
         Year Ended December 31                               ($ in thousands)
         ----------------------                               ---------------
         <S>                                                  <C>
                  2001                                              403
                  2002                                              415
                  2003                                              426
                  2004                                              430
                  2005                                              438
</TABLE>

   Rent expense was $509,000 in 2000, $16,023 in 1999 and zero in prior years.
Prior to October 1999, the Company was not responsible for office rental as
the administration services contract with Torch at the time included office
space. When the new Torch Master Service Agreement became effective in October
1999, Bellwether began paying office rent.


                                      49
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

 Other Commitments

   Under the Company's contract for production of oil in the Charapa field of
Ecuador, the Company is required to execute a three year $12 million minimum
investment program. Under a similar contract for production of oil in the
Tiguino field of Ecuador, a $25 million minimum investment program over three
years is required. The Ecuadorian national oil company requires guarantees for
a portion of each investment program. Such guarantees are backed by the
Company's letters of credit totaling $7.4 million. The letters of credit are
drawn on the Senior Credit Facility and are renewable annually.

 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.

   The Company was defendant in Cause No. C-4417-96-G; A.R. Guerra, et al. v.
Eastern Exploration, Inc., et al. in the 370th Judicial District Court of
Hidalgo County, Texas. On May 11, 1999, the trial court granted plaintiff's
Motion of Summary Judgement and denied defendants' Motion of Summary
Judgement. The trial court awarded plaintiffs in excess of $5.8 million on
damages plus interest. The Company settled the case in early 2000 for the sum
of $353,500, net to its interest.

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

<TABLE>
<CAPTION>
                                                 Quarter Ended
                                 ---------------------------------------------
                                 December 31, September 30, June 30, March 31,
                                     2000         2000        2000     2000
                                 ------------ ------------- -------- ---------
<S>                              <C>          <C>           <C>      <C>
Revenues........................   $35,229       $30,810    $25,953   $24,611
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 shares--
 diluted........................   $  0.03       $  0.37    $  0.21   $  1.67
</TABLE>

<TABLE>
<CAPTION>
                                                 Quarter Ended
                                 ---------------------------------------------
                                 December 31, September 30, June 30, March 31,
                                     1999         1999        1999     1999
                                 ------------ ------------- -------- ---------
<S>                              <C>          <C>           <C>      <C>
Revenues........................   $24,631       $17,771    $15,335   $13,326
Operating income (loss).........   $ 7,283       $  (463)   $   123   $(1,284)
Net income (loss)...............   $ 9,972       $     2    $   123   $(1,284)
Earnings (loss) per common
 share..........................   $  0.72       $  0.00    $  0.01   $ (0.09)
Earnings (loss) per common
 share--diluted.................   $  0.71       $  0.00    $  0.01   $ (0.09)
</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.

                                      50
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


11. Segment Reporting

   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.

<TABLE>
<CAPTION>
                                                   Year Ended December 31,
                                                  ---------------------------
                                                    2000     1999      1998
                                                  -------- --------  --------
<S>                                               <C>      <C>       <C>
Sales to unaffiliated customers:
  Oil and gas--US................................ $107,938 $ 68,264  $ 73,652
  Oil and gas--Ecuador...........................    4,315       --        --
  Gas plants.....................................    6,070    3,830     3,170
                                                  -------- --------  --------
    Total sales..................................  118,323   72,094    76,822
  Interest and other income......................      957    1,335     1,347
    Total revenues...............................  119,280   73,429    78,169
                                                  ======== ========  ========
Operating profit (loss) before income taxes:
  Oil and gas--US................................ $ 40,983 $ 22,570  $(65,751)
  Oil and gas--Ecuador...........................      719      (17)       --
  Gas plants.....................................    3,393    1,464     1,203
                                                  -------- --------  --------
                                                  $ 45,095 $ 24,017  $(64,548)
  Unallocated corporate expenses.................    9,734    6,513     7,112
  Interest expense...............................   15,375   11,845    11,660
                                                  -------- --------  --------
  Operating profit (loss) before income taxes.... $ 19,986 $  5,659  $(83,320)
                                                  ======== ========  ========
Identifiable assets:
  Oil and gas--US................................ $125,586 $123,686  $ 95,786
  Oil and gas--Ecuador...........................   12,243    1,246        --
  Gas plants.....................................   11,107   11,641    12,430
                                                  -------- --------  --------
                                                  $148,936 $136,573  $108,216
  Corporate assets and investments...............   72,609   35,188    22,980
                                                  -------- --------  --------
    Total........................................ $221,545 $171,761  $131,196
                                                  ======== ========  ========
Capital expenditures:
  Oil and gas--US................................ $ 76,242 $ 56,793  $ 40,179
  Oil and gas--Ecuador...........................   12,130       --        --
  Gas plants.....................................      677      369       689
                                                  -------- --------  --------
                                                  $ 89,049 $ 57,162  $ 40,868
                                                  ======== ========  ========
Depreciation, depletion amortization and
 impairments:
  Oil and gas--US................................ $ 30,356 $ 22,643  $112,447
  Oil and gas--Ecuador...........................      745       --        --
  Gas plants.....................................    1,211    1,159     1,140
                                                  -------- --------  --------
                                                  $ 32,312 $ 23,802  $113,587
                                                  ======== ========  ========
</TABLE>

                                       51
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


12. 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 the years ended
December 31, 2000, 1999 and 1998. 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.

                                      52
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Costs Incurred (in thousands)

<TABLE>
<CAPTION>
                                                        Year Ended December 31,
                                                        -----------------------
                                                         2000    1999    1998
                                                        ------- ------- -------
<S>                                                     <C>     <C>     <C>
United States:
  Property acquisition:
    Proved properties.................................. $ 5,065 $22,428 $   617
    Unproved properties................................      --   2,406   8,788
    Exploration........................................  13,139  14,052  16,186
  Development:
    Proved developed properties........................  41,615  15,500  10,755
    Proved undeveloped properties......................  16,423   1,352   3,642
                                                        ------- ------- -------
                                                        $76,242 $55,738 $39,988
                                                        ------- ------- -------
Ecuador:
  Property acquisition:
    Proved properties.................................. $ 2,013 $   651 $    --
    Unproved properties................................      --     404     191
  Development:
    Proved developed properties........................  10,117      --      --
    Proved undeveloped properties......................      --      --      --
                                                        ------- ------- -------
                                                        $12,130 $ 1,055 $   191
                                                        ------- ------- -------
Worldwide:
  Property acquisition:
    Proved properties.................................. $ 7,078 $23,079 $   617
    Unproved properties................................      --   2,810   8,979
    Exploration........................................  13,139  14,052  16,186
  Development:
    Proved developed properties........................  51,732  15,500  10,755
    Proved undeveloped properties......................  16,423   1,352   3,642
                                                        ------- ------- -------
                                                        $88,372 $56,793 $40,179
                                                        ======= ======= =======
</TABLE>

                                       53
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Capitalized costs (in thousands):

<TABLE>
<CAPTION>
                                                             Year Ended
                                                            December 31,
                                                         --------------------
                                                           2000       1999
                                                         ---------  ---------
<S>                                                      <C>        <C>
United States:
  Proved properties..................................... $ 410,048  $ 328,453
  Unproved properties...................................    11,360     16,325
                                                         ---------  ---------
    Total capitalized costs.............................   421,408    344,778
Accumulated depreciation, depletion, amortization and
 impairment.............................................  (295,822)  (221,092)
                                                         ---------  ---------
Net capitalized costs................................... $ 125,586  $ 123,686
                                                         ---------  ---------
Ecuador:
  Proved properties..................................... $  12,988  $     842
  Unproved properties...................................        --        404
                                                         ---------  ---------
    Total capitalized costs.............................    12,988      1,246
Accumulated depreciation, depletion, amortization and
 impairment.............................................      (745)        --
                                                         ---------  ---------
Net capitalized costs................................... $  12,243  $   1,246
                                                         ---------  ---------
Worldwide:
  Proved properties..................................... $ 423,036  $ 329,295
  Unproved properties...................................    11,360     16,729
                                                         ---------  ---------
    Total capitalized costs.............................   434,396    346,024
Accumulated depreciation, depletion, amortization and
 impairment.............................................  (296,567)  (221,092)
                                                         ---------  ---------
Net capitalized costs................................... $ 137,829  $ 124,932
                                                         =========  =========
</TABLE>

                                       54
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 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)   1998(1)
                                                  --------  --------
<S>                                               <C>       <C>       <C>
Revenues from oil and gas producing activities... $ 68,264  $ 73,652
Production costs.................................   21,532    25,381
Transportation costs.............................      316       435
Income tax.......................................    8,820        --
Impairment expense...............................       --    73,899
Depreciation, depletion and amortization.........   22,643    38,548
                                                  --------  --------
Results of operations from producing activities
 (excluding corporate overhead and interest
 costs).......................................... $ 14,953  $(64,611)
                                                  ========  ========
</TABLE>
--------
(1)  Ecuador activities did not commence production until 2000; therefore, no
     prior year information for international operations is disclosed.

 Per unit sales prices and costs

<TABLE>
<CAPTION>
                                                             Year Ended
                                                            December 31,
                                                        ----------------------
                                                         2000   1999(2)  1998(2)
                                                        ------ ------   ------
<S>                                                     <C>    <C>      <C>
Average sales price, including the effect of hedges
  Oil and condensate (per BBL)--US..................... $20.53 $12.84   $11.75
  Oil and condensate (per BBL)--Ecuador................ $24.80 $   --   $   --
  Natural gas (per MCF)................................ $ 3.06 $ 2.19   $ 2.19
Average sales price, excluding the effect of hedges
  Oil and condensate (per BBL)--US..................... $24.40 $14.48   $11.44
  Oil and condensate (per BBL)--Ecuador................ $24.80     (1)      (1)
  Natural gas (per MCF)................................ $ 3.84 $ 2.22   $ 2.06
Average production expenses per BOE--US................ $ 4.93 $ 4.11   $ 4.34
Average production expenses per BOE--Ecuador........... $16.18 $   (1)  $   (1)
Average depletion rate per BOE--US..................... $ 5.46 $ 4.32   $ 6.59
Average depletion rate per BOE--Ecuador................ $ 4.28     (1)      (1)
</TABLE>
--------
(1)  Ecuador activities commenced production in 2000; therefore, prior year
     price and cost information is not disclosed.

                                       55
<PAGE>

                BELLWETHER EXPLORATION COMPANY 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, 2000
                                                         ----------------------
                                                          Oil     NGL     Gas
Description                                              (MBBL)  (MBBL)  (MMCF)
-----------                                              ------  -----  -------
<S>                                                      <C>     <C>    <C>
United States:
Proved reserves at beginning of period.................. 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 period........................  9,669  1,655   74,729
                                                         ======  =====  =======
Proved developed reserves--
  Beginning of period...................................  9,990  2,032  108,491
                                                         ======  =====  =======
  End of period.........................................  9,073  1,508   68,757
                                                         ======  =====  =======
Ecuador: (1)
Proved reserves at beginning of period..................  3,884     --       --
Revisions of previous estimates.........................   (714)    --       --
Production..............................................   (174)    --       --
Purchase of reserves in-place...........................  4,817     --       --
                                                         ------  -----  -------
Proved reserves at end of period........................  7,813     --       --
                                                         ======  =====  =======
Proved developed reserves--
  Beginning of period...................................    245     --       --
                                                         ======  =====  =======
  End of period.........................................  2,135     --       --
                                                         ======  =====  =======
Worldwide:
Proved reserves at beginning of period.................. 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 period........................ 17,482  1,655   74,729
                                                         ======  =====  =======
Proved developed reserves--
  Beginning of period................................... 10,235  2,032  108,491
                                                         ======  =====  =======
  End of period......................................... 11,208  1,508   68,757
                                                         ======  =====  =======
</TABLE>

                                       56
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


<TABLE>
<CAPTION>
                                   Year Ended              Year Ended
                               December 31, 1999        December 31, 1998
                              ----------------------  -----------------------
                               Oil     NGL     Gas     Oil     NGL      Gas
Description                   (MBBL)  (MBBL)  (MMCF)  (MBBL)  (MBBL)   (MMCF)
-----------                   ------  -----  -------  ------  ------  -------
<S>                           <C>     <C>    <C>      <C>     <C>     <C>
United States:
Proved reserves at beginning
 of period...................  8,489  1,573  111,585  12,238   2,571  125,960
Revisions of previous
 estimates...................  2,671    798     (767) (2,473) (1,032)  (5,944)
Extensions and discoveries...    499     --   11,636     813     225    9,416
Production................... (1,831)  (249) (18,965) (2,106)   (191) (21,302)
Sales of reserves in-place...   (262)   (60)  (6,754)     (4)     --     (167)
Purchase of reserves in-
 place.......................  1,261      7   33,344      21      --    3,622
                              ------  -----  -------  ------  ------  -------
Proved reserves at end of
 period...................... 10,827  2,069  130,079   8,489   1,573  111,585
                              ======  =====  =======  ======  ======  =======
Proved developed reserves--
  Beginning of period........  8,021  1,554  106,253  11,153   2,460  119,270
                              ======  =====  =======  ======  ======  =======
  End of period..............  9,990  2,032  108,491   8,021   1,554  106,253
                              ======  =====  =======  ======  ======  =======
Ecuador: (1)
Purchase of reserves in-
 place.......................  3,884     --       --      --      --       --
                              ------  -----  -------  ------  ------  -------
Proved reserves at end of
 period......................  3,884     --       --      --      --       --
                              ======  =====  =======  ======  ======  =======
Proved developed reserves--
  Beginning of period........     --     --       --      --      --       --
                              ======  =====  =======  ======  ======  =======
  End of period..............    245     --       --      --      --       --
                              ======  =====  =======  ======  ======  =======
Worldwide:
Proved reserves at beginning
 of period...................  8,489  1,573  111,585  12,238   2,571  125,960
Revisions of previous
 estimates...................  2,671    798     (767) (2,473) (1,032)  (5,944)
Extensions and discoveries...    499     --   11,636     813     225    9,416
Production................... (1,831)  (249) (18,965) (2,106)   (191) (21,302)
Sales of reserves in-place...   (262)   (60)  (6,754)     (4)     --     (167)
Purchase of reserves in-
 place.......................  5,145      7   33,344      21      --    3,622
                              ------  -----  -------  ------  ------  -------
Proved reserves at end of
 period...................... 14,711  2,069  130,079   8,489   1,573  111,585
                              ======  =====  =======  ======  ======  =======
Proved developed reserves--
  Beginning of period........  8,021  1,554  106,253  11,153   2,460  119,270
                              ======  =====  =======  ======  ======  =======
  End of period.............. 10,235  2,032  108,491   8,021   1,554  106,253
                              ======  =====  =======  ======  ======  =======
</TABLE>
--------
(1)  The Company's Latin American 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.
     Relating to the reserves added in 2000, all documentation and agreements
     giving the Company the right to production from the field have been
     completed, but final approval from the Ecuadorian government has not yet
     been received. No similar assignments have ever been denied government
     approval.

                                      57
<PAGE>

                BELLWETHER EXPLORATION COMPANY 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,
                                                 ------------------------------
                                                    2000       1999      1998
                                                 ----------  --------  --------
<S>                                              <C>         <C>       <C>
United States:
Future cash flow................................ $  950,121  $535,605  $328,285
Future production costs.........................   (203,464) (202,800) (132,108)
Future income taxes.............................   (183,139)  (23,234)       --
Future development costs........................    (36,874)  (54,034)  (29,609)
                                                 ----------  --------  --------
Future net cash flows...........................    526,644   255,537   166,568
10% discount factor.............................   (133,062)  (63,933)  (50,588)
                                                 ----------  --------  --------
Standardized future net cash flows.............. $  393,582  $191,604  $115,980
                                                 ==========  ========  ========
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................................ $1,124,753  $623,694  $328,285
Future production costs.........................   (264,363) (237,334) (132,108)
Future income taxes.............................   (220,932)  (33,094)       --
Future development costs........................    (64,469)  (67,307)  (29,609)
                                                 ----------  --------  --------
Future net cash flows...........................    574,989   285,959   166,568
10% discount factor.............................   (151,897)  (81,071)  (50,588)
                                                 ----------  --------  --------
Standardized future net cash flows.............. $  423,092  $204,888  $115,980
                                                 ==========  ========  ========
</TABLE>

                                       58
<PAGE>

                BELLWETHER EXPLORATION COMPANY 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,
                                                             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>

<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>

                                      59
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


<TABLE>
<CAPTION>
                                                                   Year Ended
                                                                  December 31,
                                                                      1998
                                                                  ------------
   <S>                                                            <C>
   Standardized measure--beginning of year.......................   $185,715
   Sales, net of production costs................................    (44,264)
   Purchases of reserves in-place................................      3,379
   Net change in prices and production costs.....................    (55,408)
   Net change in income taxes....................................     14,517
   Extensions, discoveries and improved recovery, net of future
    production and development costs.............................      8,255
   Changes in estimated future development costs.................      4,542
   Development costs incurred during the period..................     11,244
   Revisions of quantity estimates...............................    (20,520)
   Accretion of discount.........................................     18,572
   Sales of reserves in-place....................................       (260)
   Changes in production rates and other.........................     (9,792)
                                                                    --------
   Standardized measure--end of year.............................   $115,980
                                                                    ========
</TABLE>

   The discounted future cash flows above were calculated using NYMEX
equivalent prices of $26.80, $25.60, and $12.05 per barrel and $9.52, $2.33,
and $2.15 per MMBTU, for December 31, 2000, 1999, and 1998, 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 $370,000 in 1999. 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 in 2000.

                                      60
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

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

   None

                                   PART III

Item 10. Directors and Executive Officers of the Registrant

   The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120
days after December 31, 2000. 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, 2000. 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, 2000. 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, 2000. 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 Financial Statements. See index to Consolidated Financial Statements
      2. 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 Bellwether Exploration Company
         (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.)

     3.4 By-laws of Bellwether Exploration Company (incorporated by reference
         to Exhibit 3.2 to the Company's Registration Statement No. 33-76570)
</TABLE>

                                      61
<PAGE>

<TABLE>
 <C>     <S>
     3.5 Amendment to Article II, Section 2.2 of Bellwether Exploration
         Company'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 Bellwether Exploration Company'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 herein 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)

    10.1 Administrative Services Agreement with Torch Energy Advisors
         Incorporated commencing January 1, 1994 (incorporated by reference to
         Exhibit 94-10-3 to the Company's Report on Form 10-Q for the quarter
         ended March 31, 1994)

    10.2 1994 Stock Incentive Plan (incorporated by reference to Exhibit 10.9
         to the Company's Registration Statement No. 33-76570)

    10.3 Registration Rights Agreement among the Company, Allstate Insurance
         Company and the former owners of Odyssey Partners, Ltd. (incorporated
         by reference to Exhibit 10.4 to the Company's Registration Statement
         No. 33-76570)

    10.4 Assignment of gas purchase contract from Texas Gas Transmission
         Corporation to Bellwether (incorporated by reference to Exhibit 96-
         10-4 to the Company's Report on Form 10-Q for the quarter ended March
         31, 1997)

    10.5 Acquisition Agreement dated March 31, 1997 among Bellwether
         Exploration Company, 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)

    10.6 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).

    10.7 Purchase and Sale Agreement dated June 9, 1997 among Bellwether
         Exploration Company, 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>

                                       62
<PAGE>

<TABLE>
 <C>     <S>
   10.8  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).

   10.9  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).

   10.10 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).

   10.11 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 10-Q for the quarter ended June 30, 1999).

   10.12 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).

   10.13 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).

   10.14 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).

   10.15 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).

   10.16 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).

   10.17 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).

   10.18 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).

   10.19 Separation agreement dated January 1, 2001 between the Company and
         Robert J. Bensh--included herewith.

   10.20 Employment contract dated January 15, 2001 between the Company and
         Kent Williamson--included herewith.

   11.22 Form of Voting Agreement (incorporated by reference to the Company's
         8-K dated January 26, 2001).

   21.1  Subsidiaries of Bellwether Exploration Company--Included herewith.

   23    Consents of experts:

   23.2  Consent of Ryder Scott Company

   23.3  Consent of KPMG LLP
</TABLE>

                                       63
<PAGE>

                                   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.

                                          BELLWETHER EXPLORATION COMPANY

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

Dated: March 29, 2001


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

<S>                                    <C>                        <C>
         /s/ J. P. Bryan               Director                     March 29, 2001
______________________________________
             J. P. Bryan

        /s/ Ann Kaesermann             Vice President--Chief        March 29, 2001
______________________________________  Accounting Officer
            Ann Kaesermann

        /s/ Dr. Jack Birks             Director                     March 29, 2001
______________________________________
            Dr. Jack Birks

        /s/ Judy Ley Allen             Director                     March 29, 2001
______________________________________
            Judy Ley Allen

      /s/ Vincent H. Buckley           Director                     March 29, 2001
______________________________________
          Vincent H. Buckley

        /s/ Habib Kairouz              Director                     March 29, 2001
______________________________________
            Habib Kairouz

       /s/ A. K. McLanahan             Director                     March 29, 2001
______________________________________
           A. K. McLanahan

      /s/ Townes G. Pressler           Director                     March 29, 2001
______________________________________
          Townes G. Pressler
</TABLE>

                                       64