<PAGE>

                                 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, 1999

                                       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 Identification No.)
     incorporation or organization)

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

      Registrant's telephone number, including area code: (713)  650-1025

       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 10, 2000 was approximately $92,691,653.

     As of March 10, 2000, the number of outstanding shares of the registrant's
common stock was 13,860,390

     Documents Incorporated by Reference: Portions of the registrant's annual
proxy statement, to be filed within 120 days after December 31, 1999, are
incorporated by reference into Part III.
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


                           ANNUAL REPORT ON FORM 10-K
                      For the Year Ended December 31, 1999

                               TABLE OF CONTENTS


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                              PAGE
                                                                                              Number
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<S>           <C>                                                                                <C>
PART I

 Item 1.  Business.............................................................................    3
 Item 2.  Properties...........................................................................    9
 Item 3.  Legal Proceedings....................................................................   19
 Item 4.  Submission of Matters to a Vote of Security Holders..................................   19

PART II

 Item 5.  Market for the Registrant's Common Equity and Related Stockholder Matters............   20
 Item 6.  Selected Financial Data..............................................................   21
 Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations   22
 Item 7a. Quantitative and Qualitative Disclosures About Market Risk...........................   29
 Item 8.  Financial Statements and Supplementary Data..........................................   31
 Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.   62

PART III

 Item 10. Directors and Executive Officers of the Registrant...................................   62
 Item 11. Executive Compensation...............................................................   62
 Item 12. Security Ownership of Certain Beneficial Owners and Management.......................   62
 Item 13. Certain Relationships and Related Transactions.......................................   62

PART IV

 Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K......................   62

   --                     Signatures
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<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 area of activity is southeastern New Mexico, west Texas, the
Texas/Louisiana Gulf Coast, both on and offshore, Latin America and the Ukraine.
At December 31, 1999, the Company's estimated net proved reserves, using
constant prices which were in effect at such date, totaled 14.7 MMBbl of oil,
2.1 MMBbl of natural gas liquids ("NGL"), and 130 Bcf of natural gas for a total
of 38.5 million barrels of oil equivalent ("MBOE").  On an equivalency basis,
approximately 56% of the Company's estimated net proved reserves were natural
gas and 79% were developed at such date.  In addition, the Company has interests
in natural gas processing plants in California and West Texas.

     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").

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 ("New Credit Facility" or
"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.

     Subsequent to the Partnership Transactions, the Company identified for
divestiture non-core properties including approximately 10% of the estimated net
proved reserves attributable to the Partnership Transactions.  These properties
were primarily small working interests in geographically diverse locations, with
generally lower operating margins and limited development potential.  Such
properties were sold in a series of transactions from May 1997 to December 1997
for aggregate consideration of $24 million.  The net proceeds from these
divestitures were used to repay indebtedness.

                                       3
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

     In December 1998 Bellwether was the successful bidder for the Charapa field
in Ecuador.  With the successful bid, the Company was awarded with a contract
for production and exploration of crude oil in the Charapa field.  The contract
provides the Company with approximately 50% 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 has committed to a $12
million work program over three years.

     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 Energy Advisors Incorporated.
("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 95.45 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 (approximately 43% of the Carpatsky's equity), do not carry a
preferential dividend and have majority voting rights over Carpatsky.  In
connection with this investment, Mr. J.P. Bryan, Chairman and Chief Executive
Officer of Bellwether became the Chairman and CEO of Carpatsky and three
Carpatsky directors retired and were replaced by three Bellwether appointees,
giving Bellwether five of the new eight directorships of Carpatsky.  Carpatsky
conducts oil and gas exploration and production activities in the Republic of
Ukraine.

Business Strategy

     The Company is committed to providing outstanding performance in all
categories of financial measurement in order to become a significant
international exploration and production company.  This vision is dictated by
the following business strategy:

     Acquire, Exploit and lastly, Explore.  The Company believes that acquiring
oil and gas reserves is the most effective way to increase shareholder value.
Once a property has been acquired, the Company immediately employs and
aggressive exploitation program to increase production, reduce operating costs
and develop low risk exploration opportunities.

     Emphasize Acquisition of International Properties with Significant
Development Upside.  The Company focuses on acquisition opportunities in the
international arena in an effort to realize significant value in areas that
other companies of Bellwether's size are not operating.  The Company reviews
acquisition opportunities spanning the globe, but focuses particularly in Latin
America and Eastern Europe.

     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 considers the Texas-Louisiana Gulf Coast, both on and offshore,
Latin America and Eastern Europe to be its core areas.  The Company may seek to
establish additional core areas in the future which 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,
whether operating, capital or overhead.  In this regard the Company outsources
certain non-strategic functions.  Additionally, the Company will regularly
review its property base

                                       4
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                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

aggressively exploiting identified opportunities and divesting non-core or lower
margin assets and redeploying capital to a higher use.

     Concentrate on High Value Operated Properties.  The Company will increase
efficiency, establish greater control and enhance economic impact with respect
to its activities through concentrating its holdings in a fewer number of higher
value properties, a majority of which it will seek to operate.  Achievement of
this objective will be a principal targeting criteria in the execution of its
acquisition and divestiture strategies.  Toward this end the Company's
exploration program will emphasize internal prospect generation as well as
strategic relationships with prospect generators having demonstrated expertise
within a particular play type or area of interest.

     Be Technology Driven.  The Company will seek to improve its success rates
and reduce its finding and operating costs by employing the latest 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.

     Use an Interdisciplinary Approach.  The Company utilizes interdisciplinary
teams comprised 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.  The Company
will target opportunities which offer multiple application of successful
concepts and are on trend with and extensions of existing applications of such
concepts.

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.

     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 22%, 28% and 22%
of fiscal year 1999, 1998 and transition period 1997 revenues, respectively.
Sales to Valero Industrial Gas, L.P. accounted for 18.0% of fiscal 1997
revenues.  Management of the Company does not believe that the loss of any
single customer or contract would materially affect the Company's business.
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.  While there is no 1999 production from
Bellwether's Ecuadorian or Ukrainian assets, the Ecuador crude oil will be
marketed by YPF and the Ukraine crude oil is sold on the spot market into the
domestic market.  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>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

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 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.  As required by the Energy
Policy Act of 1992, the FERC has revised its regulations governing the rates
that may be charged by oil pipelines.  The new rules, which were effective
January 1, 1995, provide a simplified, generally applicable method of regulating
such rates 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.  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 ("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

                                       6
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

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 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.

                                       7
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                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

     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 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.

                                       8
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                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

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 nine core areas: Central Gulf of Mexico; Western Gulf of Mexico;
West Texas; South Texas; Northwest Texas; Texas Coast; Southwest Louisiana;
Oregon; and New Mexico.

     Central Gulf of Mexico -  The primary fields in this area are East Cameron,
Eugene Island, Ship Shoal, South Marsh Island, West Cameron and South Timbalier
blocks in the Gulf of Mexico.  All of the blocks are operated by others except
East Cameron and Eugene Island 307 which are operated by the Company.  The
Central Gulf of Mexico core area represents approximately 15% of the Company's
total present value of reserves discounted at 10% (NPV10%).  The area is
comprised of approximately 550 wells of which 163 are producing and have an
average working interest of about 20%. The average reserve life is six and a
half years.

     Western Gulf of Mexico -  The primary fields in this area  are Cove, High
Island Blocks A-334, A-552 and 71/88 and Matagorda Island Block 605 in the Gulf
of Mexico.  The Cove field and High Island Block A-552 are Company operated
while the other fields are outside operated.  The Western Gulf of Mexico core
area represents approximately 9% of the Company's NPV10%.  The area is comprised
of approximately 35 wells of which 14 are producing and have an average working
interest of about 40%.  The average reserve life is six and a half years.

     West Texas -  The primary fields in this area are Waddell Ranch, Gomez,
Happy and Brooks/Zan-Zan.  All of the fields are outside operated, except the
Happy field which the Company operates.  The West Texas core area represents
approximately 19% of the Company's NPV10%.  The area is comprised of
approximately 2,200 wells of which 1,400 are producing and have an average
working interest of about 25%.  The Waddell Ranch field is primarily under
waterflood and represents 97% of total and producing wells in this core area.
The average working interest for the Waddell Ranch field is about 10% and the
field has a reserve life of 40 years.  The average reserve life for all the
fields in the West Texas core area thirty-five years.

     South Texas -  The primary fields in this area are Belle Pepper, La Rica
and McAllen Ranch.  The Company operates all the fields in this area except for
the McAllen Ranch field.  The South Texas core area represents approximately 1%
of the Company's total present value of 10% reserves.  The area is comprised of
approximately 30 wells of which 27 are producing.  The Belle Pepper and La Rica
fields have 100% working interest and the McAllen Ranch field has an average
working interest of about 20%.  The average reserve life for the South Texas
core area is ten years.

     Northwest Texas -  The primary fields in this area are Giddings, Rocky
Creek, Fort Trinidad and Matterhorn.  The Giddings and Matterhorn fields are
Company operated while the other fields are outside operated.  The Northwest
Texas core area represents approximately 6% of the Company's NPV10%.  The area
is comprised of approximately 200 wells of which 160 are producing and have an
average working interest of about 27%.  The average reserve life is twenty
years.

                                       9
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

     Texas Coast -  The primary fields in this area are Porter's Creek, which is
Company operated, and McFarlan, which is outside operated.  The Texas Coast core
area represents approximately 4% of the Company's NPV10%.  The area is comprised
of 18 wells of which 17 are producing and have an average working interest of
about 50%.  The average reserve life is thirteen years.

     Southwest Louisiana -  The primary fields in this area are Second Bayou,
which is Company operated, and West Chalkley, which is outside operated.  The
Southwest Louisiana core area represents approximately 6% of the Company's
NPV10%.  The area is comprised of 11 wells of which 10 are producing and have an
average working interest of about 12%.  The average reserve life is nine years.

     Oregon -  The only field in this area is the Mist field which is outside
operated and has a 50% working interest.  The Oregon core area  represents
approximately 3% of the Company's NPV10%.  The area is comprised of 32 wells of
which 11 are producing.  The average reserve life is fifteen years.

     New Mexico -  The primary fields in this area are Lusk, Turkey Track, Crow
Flats, Burton Flats and Empire. Currently five wells in the Lusk and Turkey
Track fields are operated by the Company and all other wells are outside
operated. As more wells are drilled in this core area, the Company will increase
its operated areas. The New Mexico core area represents approximately 6% of the
Company's NPV10%.  The area is comprised of approximately 240 wells of which 230
are producing and have an average working interest of about 38%.  The average
reserve life is thirty-two years.

     California -  The primary field in this area is Point Pedernales which is
operated by Nuevo Energy.  The California core area represents approximately 2%
of the Company's NPV10%.  The area is comprised of 22 wells of which 10 are
producing and have an average working interest of about 20%.  The average
reserve life is nine years.

International Properties

     Ecuador - In December 1998 Bellwether was the successful bidder for the
Charapa field in Ecuador.  Negotiations with the Ecuadorian government took
place throughout 1999 with Bellwether officially taking over operations of the
field in January of 2000.  Bellwether has committed to a $12 million work
program over a three year period.  Ecuador represents 8% of the Company's NPV
10%.  Beginning in 2000, one well will be producing with approximately a 50%
interest.

     Ukraine - Bellwether owns an interest in two projects in the Ukraine
through its ownership of Carpatsky Petroleum Inc.  Carpatsky is developing a
natural gas project in the Rudovsko-Chernozovodsky ("RC") field in central
Ukraine, and owns an interest in the Bitkov field in western Ukraine.  The RC
project includes the acquisition and documentation of ownership rights in the RC
field sufficient to support financing for development of the field.  In
addition, Carpatsky is seeking western purchasers for the gas reserves in the
field to reduce exposure to default in payment for reserves experienced when gas
was sold to Ukrainian purchasers.  Bellwether's interest in reserves in the
Ukraine were not material to Bellwether on  December 31, 1999.

                                       10
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

Reserves

     Estimated net proved oil and gas reserves at December 31, 1999 increased
approximately 34% from December 31, 1998.  This increase was primarily caused by
the acquisition of properties in New Mexico and the Gulf of Mexico and increased
oil and gas prices.  The Company has not filed oil or gas reserve information
with any foreign government or Federal authority or agency which contain
reserves materially different than those set forth herein.

     The following table sets forth certain information, as of December 31,
1999, which relates to fields which hold approximately 94% of the Company's
proved oil and gas reserves:

<TABLE>
<CAPTION>
                                                        Net Production                         Net Proved Reserves
                                           ------------------------------------  ---------------------------------------------
                                           Oil & NGL         Gas                   Oil & NGL         Gas        Oil Equivalent
FIELD                                       (MBBLS)         (MMCF)       MBOE        (MBBLS)        (MMCF)          (MBOE)
-----------------------------------------  ---------      --------      ------     ----------      --------     --------------

<S>                                          <C>             <C>          <C>          <C>             <C>           <C>
Central Gulf of Mexico                       407             3,566       1,002          1,248        25,490          5,496
Western Gulf of Mexico                        67             4,138         757            391        14,137          2,747
West Texas                                   556             1,110         741          6,066        15,419          8,636
South Texas                                    6               815         142             11         3,615            614
Northwest Texas                              232             1,389         464            477        10,255          2,186
Texas Coast                                   14               961         174             91         7,192          1,290
Southwest Louisiana                           64               618         167            394         4,353          1,120
Oregon                                        --               567          94             --         4,008            668
New Mexico                                     2                39           8            310        10,505          2,061
California                                    44                21          48          3,280         1,995          3,613
Ecuador*                                      --                --          --          3,884            --          3,884
Non-Core:
   Robinsons Bend /Blue Creek field           --             1,106         184             --        12,627          2,104
   Lirette field                              10               767         138             17         1,803            318
   Morganza field                              5               569         100             23         2,620            460
   Reddell field                              12               435          84             76         3,474            655
   Carpenter field                            --               291          49             --         2,745            458
   All others                                661             2,573       1,089            512         9,841          2,150
                                           -----------------------------------------------------------------------------------
                                           2,080            18,965       5,241         16,780       130,079         38,460
                                           ===================================================================================
</TABLE>

* Such 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 revenue.

   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 and future
operating costs and the assumed effects of regulation by governmental agencies,
all of which may vary considerably from actual results. All such estimates are
to some degree speculative, and classifications of reserves are only attempts to
define the degree of speculation involved. Estimates of the economically
recoverable oil and natural gas reserves attributable to any particular group of
properties, classifications of such reserves based on risk of recovery and
estimates of future net cash flows expected therefrom, prepared by different
engineers or by the same engineers at different times, may vary substantially.
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.

                                       11
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

     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 such prices or costs are contractually determined at such date.
Actual future prices and costs may be materially higher or lower. 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,
1999.  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 acreage is domestic.

                                           Gross       Net
                                         ---------   -------

      Developed Acreage...............     515,493    94,661
      Undeveloped Acreage.............   1,138,200   396,847
                                         ---------   -------
          Total.......................   1,653,693   491,508
                                         =========   =======

     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 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.

                                       12
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

Productive Wells

     The following table sets forth Bellwether's gross and net interests in
productive oil and gas wells as of December 31, 1999.  Productive wells are
defined as producing wells and wells capable of production.  All of the wells
listed are domestic.

                                   Gross   Net
                                   -----   ---

      Oil Wells.................   1,323   211
      Gas Wells.................     813   160
                                   -----   ---
          Total.................   2,136   371
                                   =====   ===

Production

     The Company's principal production volumes during the fiscal year ended
December 31, 1999 were from the states of Louisiana, Texas, Oregon and Alabama,
from federal waters in offshore California and from the Gulf of Mexico in
federal and state waters.

     Data relating to production volumes, average sales prices, average unit
production costs and oil and gas reserve information appear in Note 12 of the
Notes to Consolidated Financial Statements - Supplemental Information.

Drilling Activity and Present Activities

     During the last three fiscal years and the transition period ended December
31, 1997, the Company's principal drilling activities occurred in the
continental United States and offshore Texas, Louisiana and California in
federal and state waters.


     The following table sets forth the results of drilling activity for the
last three fiscal years and the transition period.  Gross wells, as it applies
to wells in the following tables, refers 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>
                                               Exploratory Wells
                                               -----------------
                                      Gross                            Net
                         --------------------------------  ----------------------------
                                          Dry                             Dry
                            Productive   Holes   Total      Productive   Holes   Total
                         --------------------------------  -----------------------------

<S>                                 <C>     <C>     <C>          <C>      <C>     <C>
Fiscal 1997                          3       4       7             .75     .74    1.49
Six Month Transition 1997            2       2       4             .28     .78    1.06
Fiscal 1998                         14       5      19            4.10    1.52    5.62
Fiscal 1999                          8       4      12            3.75    2.04    5.79
</TABLE>

                                       13
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


<TABLE>
<CAPTION>
                                                Development Wells
                                                -----------------
                                       Gross                            Net
                          -------------------------------  ----------------------------
                                           Dry                             Dry
                             Productive   Holes   Total      Productive   Holes   Total
                          -------------------------------  -----------------------------
<S>                             <C>       <C>     <C>          <C>         <C>      <C>
Fiscal 1997                       52       2      54            5.34        .63     5.97
Six Month Transition 1997         30       5      35            2.40       1.19     3.59
Fiscal 1998                       69       4      73            7.53        .52     8.05
Fiscal 1999                       13       2      15            4.39        .14     4.53
</TABLE>

The Company had 8 wells in progress as of December 31, 1999.
Gas Plants

     As of December 31, 1999 the Company owned interests in the following gas
plants:

<TABLE>
<CAPTION>
                                                                 Fiscal Year 1999
                                                    --------------------------------------
                                                       Capacity    Throughput    Ownership
Facility                State         Operator           MMCFD        MMCFD       Interest
--------               ------         --------      --------------------------------------

<S>                     <C>             <C>               <C>         <C>           <C>
                                Nuevo Energy Company
Point Pedernales Gas
 Plant                   CA                                13           4          19.7%

Snyder Gas                      Torch Energy
Plant                    TX     Marketing Inc.             60          14          11.9%

Diamond M-
Sharon Ridge                    Exxon Company,
Gas Plant(1)             TX     U.S.A.                     (1)         (1)           (1)

(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.
</TABLE>

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.  Oil prices were lower in 1998 than in previous years and hit historic
lows during the first quarter of 1999, but recovered significantly by year end
1999.  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 have

                                       14
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


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 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, without
successful exploration, development or acquisition activities, the Company's
revenues will decline rapidly. 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, to 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) exploration and exploitation potential, 3)
future oil and natural gas prices, 4) operating costs, 5) potential
environmental and other liabilities and 6) 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.

     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, Alabama, offshore
California, the Gulf of Mexico, Latin America and Ukraine there is no assurance
that the Company will not pursue acquisitions or properties located in other
geographic areas.

     In connection with the Partnership Transactions, Bellwether assumed or
otherwise became liable for all obligations with respect to operations of the
properties acquired in such transactions, including environmental and
operational liabilities, unknown liabilities, and liabilities arising prior to
the closing date.

                                       15
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


     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 flows 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. 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 lease in Ecuador in
1998. Contract negotiations with the Ecuadorian government were completed in
late 1999 with operations beginning January 2000. In addition, on December 30,
1999, the Company acquired an interest in Carpatsky, which has operations in
Ukraine. Ownership of property interests and production operations in Ecuador,
Ukraine and in any other areas outside of the United States in which the Company
may choose to do business, are subject to the various risks interest in 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 expropriations, nationalization, war, insurrection and
other political risks, risks of increase in taxes and governmental policies
governing operations of foreign-based companies
                                       16
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

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.

     Carpatsky's activities are focused in the RC field, which has substantial
gas reserves.  Carpatsky is seeking to acquire and fully document its ownership
interests in the RC field.  Currently, Carpatsky operates under a joint
activities agreement with a state majority owned oil company.  The joint
activities agreement gives Carpatsky the right to receive proceeds from a
portion of the production from the field in exchange for payment of a portion of
the costs.  The portions of production received and costs paid vary depending on
the amount paid by Carpatsky under the joint activities agreement.  The joint
activities agreement is not currently referred to in the RC field license
granted by the government of the Ukraine.  In addition, the current license
covers only production from a pilot project designed to determine the productive
boundaries of the field.  Carpatsky is seeking to have the RC field license
granted directly to it or to an entity in which it has an ownership interest,
and to have the license changed to a development license.  No assurances can be
made that Carpatsky will be successful in these activities.

     Administrative Services Agreement; Reliance on Torch

     The Company currently has 24 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, land, legal and technical support (See Note 4 to the Consolidated
Financial Statements).  The Company believes that its relationship with Torch
provides the Company with 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

     Director, Mr. J. P. Bryan, was elected Chairman and Chief Executive Officer
effective August 2, 1999.  Mr. Bryan is Senior Managing Director of and a holder
of common stock of the parent corporation of Torch.  Mr. Bryan has limited
involvement in the day to day operations of Torch.

     Torch also renders administrative 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 Master Services Agreement provides for procedures to reconcile
conflicts of interest between these other companies and the Company, 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 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

                                       17
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

prices and expenditures for future development and exploitation activities, and
3) of 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 gas equivalent basis, oil was converted to
gas 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 peculiar 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 liability for: 1) personal
injuries, 2) property damage, 3) oil spills, 4) discharge of hazardous
materials, 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 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 may lose substantial portions of its
properties in the event of certain environmental damages.

                                       18
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES



     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 require: 1) 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.  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.  The Company recently 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.

                                       19
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


                                    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 822 stockholders of record as of March 10,
2000.  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:
   September 30, 1996.................  $ 6.88         $4.38
   December 31, 1996..................  $ 9.00         $5.63
   March 31, 1997.....................  $11.50         $7.88
   June 30, 1997......................  $10.25         $7.25

   September 30, 1997.................  $15.38         $9.08
   December 31, 1997..................  $14.88         $9.75

   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
</TABLE>

Treasury Stock Repurchases

     In September 1998, the Board of Directors of the Company authorized the
open market repurchase of up to $5 million of the Company's common stock during
1998, at times and prices deemed attractive by management. As of December 31,
1999, the Company had repurchased 311,000 shares of common stock in open market
transactions, at an average purchase price of $6.13 per share.

                                       20
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


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
                            Year Ended          Year Ended       Transition Period
                              Dec.31,             Dec.31,          Ended Dec. 31            Fiscal Years Ended June 30,
                           -------------      --------------     ----------------    ----------------------------------------
                               1999               1998                 1997             1997(1)      1996         1995(2)
                           -------------      -------------      ----------------    ------------  ---------   --------------
<S>                           <C>                <C>                 <C>               <C>            <C>         <C>
Gas revenues..........       $ 41,380           $ 46,461             $ 26,755          $ 24,202       $ 9,856     $ 4,864
Oil revenues..........         26,568             26,756               17,408            14,865         5,810       3,643
Gas plant revenues,
 net..................          1,464              1,203                  804             3,330         3,534       4,627
Interest and other
 income...............          1,335              1,347                  609               363           116          97
                             --------           --------             --------          --------       -------     -------
 Total revenues.......         70,747             75,767               45,576            42,760        19,316      13,231

Production expenses...         21,532             25,381               13,836            11,437         5,317       2,856
General and
 administrative
 expenses.............          7,848              8,459                3,748             4,042         3,013       2,739
Depreciation,
 depletion and
 amortization.........         23,863             39,688               16,352            15,574         8,148       5,269
Impairment expenses...            ---             73,899                  ---               ---           ---         ---
Interest expense......         11,845             11,660                5,978             4,477         1,657       1,245
Provision (benefit)
 for income taxes              (3,154)            (6,069)               2,114             2,585            46           9
Other expenses........            ---                ---                  ---               ---           153         172
                             --------           --------             --------          --------       -------     -------
 Total expenses.......         61,934            153,018               42,028            38,115        18,334      12,290
                             --------          ---------             --------          --------       -------     -------
Net income (loss)            $  8,813          $ (77,251)            $  3,548          $  4,645       $   982     $   941
                             ========          =========             ========          =========      =======     =======
Earnings (loss) per
 commonshare..........       $    .64          $  (5.50)             $   0.26          $   0.46       $  0.11     $  0.12
Earnings (loss) per
 commonshare-diluted..       $    .63          $  (5.50)             $   0.25          $   0.45       $  0.11     $  0.12

Working capital.......       $  3,770          $  6,077              $ 13,964          $ 22,783       $ 5,168     $(1,246)
Long-term debt,
 net  of current             $130,000          $104,400              $100,000          $115,300       $13,048     $18,525
 maturities...........
Stockholders' equity..       $ 23,314          $ 14,489              $ 91,669          $ 87,924       $46,597     $45,447
Total assets..........       $171,761          $131,196              $214,757          $222,648       $67,225     $74,650
</TABLE>

(1)  Includes operations from the Partnership Transactions beginning April 1,
     1997.
(2)  Reflects operations from Odyssey and Hampton mergers beginning August 1994
     and February 1995, respectively.

                                       21
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


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. Prior to April 1997, the Company had grown and diversified its
operations primarily through acquisitions and subsequent development of the
acquired properties.  Subsequent to April 1997 the Company has employed a more
balanced growth strategy combining strategic acquisitions of producing
properties with technology driven exploration and development 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 exploitation 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 ("Partnership Transactions").  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
"Offerings") and borrowings under a new credit facility ("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. This resulted in a six-month transition period of
July 1, 1997 through December 31, 1997 ("transition period").

  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.  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.  No such write down was required for
the year ended December 31, 1999.

  The Company periodically uses derivative financial instruments to manage oil
and gas price risk. Settlements of gains and losses on price swap contracts are
generally based upon the difference between the contract price and the average
closing NYMEX or other floating index price and are reported as a component of
oil and gas revenue during the period in which the underlying commodity is
produced.  Gains or losses attributable to the termination of swap contracts are
deferred and recognized in revenue when the hedged oil and gas is sold.

Financing Activities

  The Company's outstanding indebtedness totals $130.0 million at December 31,
1999; $100 million is attributable to 10 7/8% Senior Subordinated Notes due in
2007 while $30.0 million is outstanding under a senior revolving unsecured
credit facility with an ultimate maturity date of November 2003.

  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 current borrowing base of $55.0 million, and a maturity date of November
5, 2003.
                                       22
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

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  1/2 of 1% plus the Federal Funds Rate.  For LIBOR borrowings, the
interest rate will vary from LIBOR plus 1.0% to LIBOR plus 1.75% based upon the
borrowing base usage.  In connection with the acquisition of oil and gas
properties, $30 million was drawn under this facility.  As of December 31, 1999,
$30.0 million was outstanding under the Senior Credit Facility.  The Senior
Credit Facility contains various covenants including certain required financial
measurements for current ratio, consolidated tangible net worth and interest
coverage ratio.  In addition, the Senior Credit Facility includes certain
limitations on restricted payments, dividends, incurrence of additional funded
indebtedness and asset sales.

     In October 1996, the Company entered into a syndicated credit facility
in an amount up to $50.0 million with an initial borrowing base of $27.0
million, to be re-determined semi-annually.  This credit facility was unsecured
and was retired in April 1997.  In February 1995, the Company entered into a
credit facility with a commercial bank providing an initial borrowing base of
$29.8 million.  The borrowings under the credit facility were secured by the
Company's interest in oil and gas properties, a gathering system and two gas
plants.  The Credit Facility was retired in October 1996.

     In April 1997, the Company issued $100.0 million of 10 7/8% senior
subordinated notes ("Notes") that mature April 1, 2007 for net proceeds of $97.0
million.  Interest on the Notes is payable semi-annually on April 1 and October
1 commencing on October 1, 1997.  The Notes contain certain covenants, including
limitations on: 1) the incurrence of debt, 2) on other senior subordinated
indebtedness, 3) on restricted payments and 4) on liens as well as restrictions
5) on the disposition of proceeds of asset sales and 6) on 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 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.  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.

     In April 1997, the Company issued 4.4 million common shares in a public
offering. The net proceeds of the offering were $34.1 million.

Liquidity and Capital Resources

     The Company's principal sources of capital for the last three years
and for the six month transition period have been the sale of Notes, borrowings
under bank credit facilities, the public sale of common stock and cash flow from
operations.  The Company sold $100 million in Notes in fiscal 1997.  Borrowings
from banks were 30.0 million, $4.9 million, $1.5 million and $57.3 million for
the fiscal years 1999 and 1998, the transition period 1997 and fiscal year ended
June 30, 1997 respectively.  The Company issued 4.4 million shares of common
stock in a public offering in April 1997 for net proceeds of $34.1 million. Cash
flow from operations before change in assets and liabilities totaled $30.8
million, $30.4 million, $21.8 million and $23.3 million for the fiscal years
1999 and 1998, the transition period 1997 and fiscal year 1997, respectively.
Cash flow from operations before changes in working capital for the fiscal year
1998 was adversely impacted by a 22% reduction in the average price received for
the Company's oil and gas production as compared to the average price received
during the transition period 1997.  In a series of transactions from May through
December 1997, the Company divested non-core assets representing approximately
10% of its estimated net proved reserves for $24.3 million.  Also, the Company
divested additional non-core assets in September and October 1999 for
approximately $4.9 million.

     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 $25.9 million, $10.3 million, $5.5 million and
$140 million for the fiscal years 1999 and 1998, the transition period 1997 and
fiscal 1997, respectively.  The Company's expenditures for exploration and
development of its oil and gas properties totaled $31.3 million, $30.6 million,
$13.7 million and $15.6 million for the fiscal years 1999 and 1998, the
transition period ended December 31, 1997 and the fiscal year ended June 30,
1997, respectively.

                                       23
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


Outlook

     The Company has adopted a $55.2 million capital budget for the year
ending December 31, 2000 primarily for development and exploratory drilling
activities.  The Company believes its working capital and net cash flows
provided by operating activities are sufficient to meet these capital
commitments.  Additionally, the Company currently has a $55.0 million borrowing
base under its Senior Credit Facility with $30.0 million outstanding borrowings
at December 31, 1999.  The Company is continuously reviewing acquisition
opportunities and expects to conclude one or more acquisitions during 2000.
Acquisitions are not included in the capital budget and will be funded through
additional borrowings and/or the issuance of securities.

     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 of 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.

Year 2000 Issues

     The Year 2000 problem ("Y2k") refers to the inability of computer and other
information technology systems to properly process date and time information.
The problem was caused, in part, by the outdated programming practice of using
two digits rather than four to represent the year in a date.  The consequence of
the Y2k problem is that information technology and embedded processing systems
are at risk of malfunction, particularly during the transition between 1999 to
2000.

     The estimated total costs for Y2k readiness were nominal. In addition,
there have been no material capital expenditures for Y2k and there is not
anticipated to be material capital expenditures because most major critical
field operations do not have date sensitive equipment. The Company has
experienced no material Y2k failures.

                                       24
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


Results of Operations

     For comparability with annual periods, amounts discussed in this section
regarding the six month transition period 1997 have been annualized.  These
amounts  may not be indicative of twelve month's operating results.  The table
below recaps the major components of financial and operating performance to be
discussed (amounts in thousands):
<TABLE>
<CAPTION>

                                             Year-ended December 31,              Annualized/(1)/
                                       ----------------------------------          Transition              Fiscal
                                           1999                  1998              Period 1997              1997
                                       --------------       -------------       -----------------       ----------------
<S>                                    <C>                      <C>                 <C>                      <C>
Oil and gas revenues                    $67,948               $ 73,217               $88,326                $39,067
Gas plant revenues, net                   1,464                  1,203                 1,608                  3,330
Interest and other                        1,335                  1,347                 1,218                    363
                                        -------               --------               -------                -------

Total revenue                            70,747                 75,767                91,152                 42,760

Production expenses                      21,532                 25,381                27,672                 11,437
Depreciation, depletion and
 amortization                            23,863                 39,688                32,704                 15,574
Impairment expense                          ---                 73,899                   ---                    ---
General and administrative
 expenses                                 7,848                  8,459                 7,496                  4,042
Income tax (benefit)
     and other                           (3,154)                (6,069)                4,228                  2,585
Interest expense                         11,845                 11,660                11,956                  4,477
                                        -------               --------               -------                -------
Net income (loss)                       $ 8,813               $(77,251)              $ 7,096                $ 4,645
                                       ========               ========               =======                =======

Production:
 Oil and                                  2,080                  2,298                 2,108                    854
 condensate(MBBLS)
 Natural gas (MMCF)                      18,965                 21,302                22,386                 10,552
 Gas equivalent (MMCFE)                  31,445                 35,090                35,034                 15,676

Average sales price/(2)/
 Oil and condensate (per
 barrel)                                $ 12.77               $  11.64               $ 16.52                $ 17.41
 Natural gas (per MCF)                  $  2.18               $   2.18               $  2.39                $  2.29

Average unit production
 costs per equivalent
 MCF (1 barrel equals 6
 MCF)                                   $   .68               $    .72               $   .79                $   .73

Average unit general and
 administrative expense
 per equivalent MCF/(3)/                $   .25               $    .24               $   .21                $   .23

Average unit depletion rate
 per equivalent MCF/(4)/                $   .72               $   1.10               $   .90                $   .94
</TABLE>

(1)  Annualized amounts were computed by multiplying Transition Period 1997
     components by 2

(2)  Average sales price is inclusive of the effect of natural gas and crude oil
     price hedges

(3)  Exclusive of general and administrative expenses allocated to gas plants

(4)  Exclusive of depreciation on gas plants

                                       25
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

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

<TABLE>
<CAPTION>
                                                                                                 Annualized
                                                             Year Ended      Year Ended      Transition Period       Fiscal
                                                                1999            1998                1997              1997
                                                           --------------   -------------   -------------------   ------------
<S>                                                          <C>               <C>                  <C>                <C>
Plant product sales volume (MBBLS).....................         241               254                218                319
Average product sales price per
  barrel...............................................      $12.93            $10.19              $14.45            $16.77
</TABLE>

     Year Ended 1999 Compared to Year Ended 1998:

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

     Oil and gas revenues were $67.9 million for the year ended 1999, as
compared to $73.2 million of oil and gas revenues for the year ended 1998.
While oil and gas volumes were down approximately 10% in 1999 compared to 1998,
oil prices were 10% higher in 1999.  Oil prices increased from $11.64 per barrel
in 1998 to $12.77 in 1999.  Gas prices remained flat at $2.18 for 1999 and 1998.
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.

     Gas plant net revenues were $1.5 million in 1999, as compared to $1.2
million in 1998.  Contributing to this increase were increases in plant liquid
prices of 27% over the prior year.

     Production expenses for fiscal 1999 totaled $21.5 million, as compared to
$25.4 million in fiscal 1998.  On an MCF basis, production expenses were $.68
per MCF in 1999 as compared to $.72 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, but high lease operating and workover expenses.  On an
equivalent MCF basis production expenses decreased from $.72 per equivalent MCF
in 1998 to $.68 per equivalent MCF in 1999.

     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 mentioned above.

     General and administrative expenses decreased in 1999 to $7.8 million from
$8.5 million in 1998.  A decrease in outsourcing costs from $4 million to $2.9
million was the major contribution to this decline. Until October 2000, 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 an equivalent MCF
basis increased from $.24 per equivalent MCF in 1998 to $.25 per equivalent MCF
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.

                                       26
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


     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.

     Year Ended 1998 Compared with Annualized Transition Period 1997:

     The year ended 1998 reflects a loss of $77.3 million as compared to net
income of $7.1 million for the annualized transition period 1997.  The loss in
1998 is directly attributable to oil and gas price declines of 31% and 20%,
respectively, and the full cost ceiling impairment of $73.9 million.  Such
impairment resulted from the price declines as well as the downward revision in
proved reserves.

     Oil and gas revenues were $73.2 million for the year ended December 31,
1998, a decrease of 17% over the annualized transition period 1997.  This
decrease is primarily due to the decline in oil and gas prices mentioned above.
Oil prices decreased from $16.52 per barrel in the annualized transition period
1997 to $11.64 in the year ended December 31, 1998.  Gas prices decreased from
$2.39 per Mcf in the annualized transition period 1997 to $2.18 per Mcf in the
year ended December 31, 1998.  The Company utilized various hedging transactions
to manage a portion of the risks associated with natural gas and crude oil price
volatility.  As a result of these hedges, oil and gas revenues were increased by
$3.6 million in the year ended December 31, 1998 and reduced by $1.6 million in
the transition period 1997.

     Gas plant revenues were $3.2 million in the year ended December 31, 1998, a
decrease of 22% from the transition period 1997 gas plant revenues of $4.1
million.  The decrease in average liquid prices of 30% is the primary reason gas
plant revenues have declined.  The average liquid price in the year ended 1998
was $10.19 per barrel while the annualized transition period 1997 average liquid
price was $14.45 per barrel.  Throughput volumes have remained steady at 14.3
MMcf per day in the year ended 1998 as compared to 14.9 MMcf per day in
annualized transition period 1997.  Plant shut-in days were less in the year
ended 1998 with 8 days downtime in 1998 resulting from an accident in an
adjacent plant and the tie-in of new equipment.  Downtime in 1997 totaled 24
days (48 days annualized) for installation of an amine unit in September 1997
and repairs to the insulation in the incinerator.  Gas plant expenses were $2.0
million in the year ended 1998 and $2.5 million in annualized transition period
1997.

     Interest and other income increased to $1.3 million in the year ended 1998
from $1.2 million in annualized transition period 1997.

     Production expenses for the year ended December 31, 1998 were $25.4
million, a decrease of 8% from the transition period amount.  On an MCF
equivalency basis, production expenses for the year decreased to $.72 per
equivalent MCF versus $.79 per equivalent MCF in the transition period 1997.

     Depreciation, depletion and amortization for the year ended December 31,
1998 increased 21% to $39.7 million.  The increase is due to the increase in the
depreciation, depletion and amortization rate per MCF to $1.10 per MCF.  This
represents a 21% increase over the annualized transition period 1997 rate of
$.90 per MCF.  The rate increase is primarily due to a downward revision to
proved reserves of 26 BCFE or 12% of the reserve quantities at the beginning of
the year.  Weak oil and gas prices  were the most significant contributor to the
reserve revision.  Production performance also contributed to the revision, but
to a lesser extent as the weak prices resulted in a shortened economic life for
certain of the Company's properties.

     An impairment expense of $73.9 million was required in the year ended 1998
because the Company's capitalized costs (net of depreciation, depletion and
amortization) exceeded the discounted future net reserves on an after-tax basis
of estimated proved oil and gas reserves.  The decline in oil and gas reserves
and discounted future net revenues is due largely to depressed oil and gas
prices.

     General and administrative expenses increased from $7.5 million in
annualized transition period 1997 to $8.5 million in the year ended December 31,
1998.  The closing of the Company's Dallas exploration office in March 1998
resulted in $.3 million of increased general and administrative expenses and
certain transition costs related to the change of the Company's fiscal year also
increased such expenses by approximately $.4 million.  On

                                       27
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


an equivalent MCF basis, general and administrative cost increased to $.24 per
MCF in fiscal 1998 as compared to $.21 per MCF in the transition period 1997.

     The large impairment mentioned above resulted in an increase in the
Company's tax valuation allowance for the benefit for the current period's net
loss from operations.

     Annualized interest expense decreased 2% to $11.7 million from $12.0
million in fiscal 1997.

     Annualized Transition Period 1997 Compared with Fiscal 1997:

     Net income for the annualized transition period 1997 was $7.1 million as
compared to net income of $4.6 million in the fiscal year 1997.  The primary
reason for the increase is the full year's production attributable to the
Partnership Transactions in the annualized transition period 1997.  The fiscal
1997 period reflects only 3 months of such activity.

     Oil and gas revenues were $88.3 million for the annualized transition
period 1997, an increase of 126% over the fiscal year ended June 30, 1997.  This
increase is due to a full year of production from the properties acquired in the
Partnership Transactions, which closed in the fourth quarter of fiscal 1997.
Annualized production on an equivalent MCFE basis increased 124% to 35,034
equivalent MCF in the transition period compared to 15,676 equivalent MCF of
production in fiscal 1997.

     During the period, the volatility of oil and gas prices also directly
impacted revenues.  Most significantly, natural gas prices increased in the
transition period 1997 to $2.55 per Mcf from $2.29 per Mcf in fiscal 1997.
During the transition period 1997 and fiscal 1997, the Company utilized various
hedging transactions to manage a portion of the risks associated with natural
gas and crude oil price volatility.  As a result of these hedges, oil and gas
revenues were reduced by $1.6 million in the transition period 1997 and by
$18,000 in fiscal 1997.

     Gas plant revenues were $4.1 million in the annualized transition period
1997, a decrease of 39% from fiscal 1997 gas plant revenues.  The decrease,
prior to annualization, was due to a 10 day shut-down of the plant in September
to install an amine unit and a two week shut-down in December to repair the
insulation in the incinerator (a total of 48 days on a annualized basis). Also,
contributing to the decline in the annualized transition period 1997 gas plant
revenues was a 14% decline from fiscal 1997 in plant liquids prices. Annualized
gas plant expenses were $2.5 million in the transition period 1997 as compared
to $3.3 million during fiscal 1997.  The decrease in expenses is attributable to
the plant shut-downs.

     Production expenses for the annualized transition period 1997 were $27.7
million, an increase of 142% over the fiscal 1997 amount.  The increase is
primarily due to inclusion of the Partnership Transactions for all of transition
1997, while fiscal 1997 amounts reflect only one quarter for the Partnership
Transactions.  On an MCF equivalency basis, production expenses for the
annualized transition period increased to $.79 per equivalent MCF versus $.73
per equivalent MCF in fiscal 1997.  The increase in the per unit rate results
from the suspension of production, but not production expenses, at the Point
Pedernales field for most of the last quarter of the transition period and from
out of period expenses recorded within the annualized 1997 transition period.

     Depreciation, depletion and amortization for the annualized transition
period 1997 increased 110% to $32.7 million.  The impact of increased production
in the transition period due to the Partnership Transactions was partially
offset by a $.04 per MCF decrease in the depletion rate.  Depreciation,
depletion and amortization was $.90 per MCF in the annualized transition period
1997 as compared to $.94 per MCF in fiscal 1997.

     General and administrative expenses increased from $4.0 million in fiscal
1997 to $7.5 million in annualized transition period 1997.  The increase is
primarily due to increased management fees resulting from the Partnership
Transactions.  Management fees are based on the Company's net assets and
operating cash flows.  On an MCF basis, general and administrative expenses
decreased to $.21 per MCF in transition 1997 from $.23 per MCF in fiscal 1997.

                                       28
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

     Annualized interest expense increased 167% to $12 million from $4.5 million
in fiscal 1997.  The increase is primarily due to interest attributable to the
$100 million of 10 7/8% Senior Subordinated Notes issued April 1997 to finance
the Partnership Transactions.

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 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, 1999 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.  The floating rate for the period from October 1, 1999 to April 1, 2000 is
9.64%.  Through April 2002 the floating rate is capped at 10.875% and capped at
12.375% thereafter.  A 10% increase in these floating rates would have the
effect of increasing interest costs to the Company by $216,800 per year.

     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 not yet determined the impact of this
statement on the Company's financial condition or results of operations.

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

                                       29
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


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.

    The following tables detail the Company's hedges of future production, which
were in place at December 31, 1999.

    OIL HEDGES

<TABLE>
<CAPTION>
                                                         NYMEX     NYMEX
       PERIOD            BBLS     TOTAL BBLS    TYPE     PRICE     PRICE
                        PER DAY                          FLOOR    CEILING
-------------------------------------------------------------------------
<S>                     <C>       <C>          <C>       <C>      <C>
Jan 2000-March 2000       2,000      182,000   Collar    $19.00    $21.75
-------------------------------------------------------------------------
Jan 2000-March 2000       2,000      182,000   Collar    $21.75    $25.60
-------------------------------------------------------------------------
April 2000-June 2000      4,000      364,000   Collar*   $22.00    $24.63
-------------------------------------------------------------------------
</TABLE>


    GAS HEDGES

<TABLE>
<CAPTION>
                                                           NYMEX    NYMEX
     PERIOD                 MCF     TOTAL MCF     TYPE     PRICE    PRICE
                          PER DAY                          FLOOR   CEILING
-------------------------------------------------------------------------------
<S>                        <C>      <C>          <C>       <C>      <C>
Jan 2000-Mar 2000          15,000   2,280,000    Floor     $2.40     N/A
-------------------------------------------------------------------------------
Jan 2000-Mar 2000          15,000   2,280,000   Collar**   $3.00     $3.55
-------------------------------------------------------------------------------
April 2000-Oct 2000        15,000   3,210,000    Collar    $2.30     $2.87
-------------------------------------------------------------------------------
Nov 2000-March 2001        20,000   3,020,000    Collar    $2.40     $3.40
-------------------------------------------------------------------------------
April 2001-Oct 2001        20,000   4,280,000    Collar    $2.20     $2.95
-------------------------------------------------------------------------------
</TABLE>

   *   This agreement includes a put at $17.00 per barrel
   **  This agreement includes a put at $2.40 per Mcf

     The fair value at December 31, 2000 of these swap agreements was a gain of
$862,000. these energy swap agreements expose the Company to counterparty credit
risk to the extent the counterparty is unable to meet its montly 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.  As the swap
provider is a major financial institution, 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% increase in the floating LIBOR
rates would have the effect of increasing interest costs to the Company by
$216,500 per year.

                                       30
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                  INDEX TO FINANCIAL STATEMENTS AND SCHEDULES

                                                                     Page Number
                                                                     -----------

Independent Auditors' Report..........................................   32

Financial Statements:

 Consolidated Balance Sheets as of December 31, 1999 and 1998,........   33

 Consolidated Statements of Operations for the Periods Ended
  December 31, 1999, 1998 and 1997, and June 30, 1997.................   35

 Consolidated Statements of Changes in Stockholders' Equity for the
  Periods Ended December 31, 1999, 1998, 1997, and June 30, 1997......   36

 Consolidated Statements of Cash Flows for the Periods Ended
  December 31, 1999, 1998, 1997, and June 30, 1997....................   37

 Notes to Consolidated Financial Statements...........................   39

                                       31
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

                         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, 1999 and 1998 and the
related consolidated statements of operations, changes in stockholders' equity
and cash flows for the years ended December 31, 1999 and 1998, the six month
period ended December 31, 1997 and the year ended June 30, 1997.  These
financial statements are the responsibility of the Company's management.  Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards.  Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the 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, such consolidated financial statements present fairly, in all
material respects, the financial position of Bellwether Exploration Company and
subsidiaries as of December 31, 1999 and 1998 and the results of their
operations and their cash flows for the years ended December 31, 1999, 1998, the
six month period ended December 31, 1997, and the year ended June 30, 1997 in
conformity with generally accepted accounting principles.



KPMG LLP
Houston, Texas
March 16, 2000

                                       32
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES



                          CONSOLIDATED BALANCE SHEETS
                                     ASSETS
                             (Amounts in thousands)

<TABLE>
<CAPTION>
                                                                          DECEMBER 31, 1999              DECEMBER 31, 1998
                                                                     -----------------------       -------------------------
CURRENT ASSETS:

<S>                                                                          <C>                           <C>
Cash and cash equivalents......................................              $   6,101                       $      10
Accounts receivable and accrued
       revenues................................................                 14,354                          15,602
Accounts receivable - related parties..........................                    ---                             853
Prepaid expenses...............................................                  1,562                           1,719
                                                                     ----------------------        -------------------------
  Total current assets.........................................                 22,017                          18,184
                                                                     -----------------------       -------------------------

PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas properties (full cost):
       United States - Unproved properties of $16,325 and
     $8,754 excluded from amortization as of December
     31, 1999 and 1998 respectively............................                344,778                         289,040
     Latin America - Unproved properties of  $404 and
     $191 excluded from amortization as of December
     31, 1999 and 1998, respectively...........................                  1,246                             191
Gas plant facilities...........................................                 17,775                          17,406
                                                                     -----------------------       -------------------------
                                                                               363,799                         306,637
Less accumulated depreciation,
       depletion and amortization..............................               (227,226)                       (198,421)
                                                                     -----------------------       -------------------------
                                                                               136,573                         108,216
                                                                     -----------------------       -------------------------

INVESTMENT IN OUTSIDE COMPANIES................................                  4,554                             ---

DEFERRED INCOME TAXES..........................................                  2,739                             ---

OTHER ASSETS...................................................                  5,878                           4,796
                                                                     -----------------------       -------------------------

                                                                             $ 171,761                       $ 131,196
                                                                     =======================       =========================
</TABLE>

                See Notes to Consolidated Financial Statements.

                                       33
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS
                      LIABILITIES AND STOCKHOLDERS' EQUITY
                (Amounts in thousands, except share information)

<TABLE>
<CAPTION>
                                                                          DECEMBER 31, 1999              DECEMBER 31, 1998
                                                                     -----------------------       -------------------------
CURRENT LIABILITIES:

<S>                                                                             <C>                           <C>
Accounts payable and accrued
       liabilities.............................................                $ 18,247                        $ 11,982
Accounts payable - related parties.............................                     ---                             125
                                                                               --------                        --------
  Total current liabilities....................................                  18,247                          12,107
                                                                               --------                        --------

LONG-TERM DEBT.................................................                 130,000                         104,400

OTHER LIABILITIES..............................................                     200                             200

CONTINGENCIES..................................................                     ---                             ---

STOCKHOLDERS' EQUITY:

Preferred stock, $0.01 par value, 1,000,000 shares
 authorized, none issued or outstanding........................                     ---                             ---

Common stock, $0.01 par value, 30,000,000 shares authorized
 14,168,791 and 14,164,791 shares issued  at December 31,
 1999, and 1998, respectively..................................                     142                             142


Additional paid-in capital.....................................                  80,455                          80,442
Retained earnings (deficit)....................................                 (55,378)                        (64,191)
Treasury stock, at cost, 311,000 and 310,800 shares                              (1,905)                         (1,904)
       at December 31, 1999 and 1998, respectively.............
                                                                               --------                        --------
Total stockholders' equity.....................................                  23,314                          14,489
                                                                               --------                        --------

                                                                               $171,761                        $131,196
                                                                               ========                        ========
</TABLE>


                See Notes to Consolidated Financial Statements.

                                       34
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


                     CONSOLIDATED STATEMENTS OF OPERATIONS
                 (Amounts in thousands, except per share data)

<TABLE>
<CAPTION>

                                                                                  Six Month Transition
                                       Year Ended             Year Ended              Period Ended              Fiscal Year
                                       December 31,           December 31,             December 31,            Ended June 30,
                                      -------------          -------------        --------------------         --------------
REVENUES:                                 1999                   1998                     1997                     1997
                                      -------------          -------------        --------------------         --------------
<S>                                      <C>                    <C>                      <C>                      <C>
  Gas revenues........................   $ 41,380              $  46,461                $ 26,755                  $ 24,202
  Oil revenues........................     26,568                 26,756                  17,408                    14,865
  Gas plant revenues, net.............      1,464                  1,203                     804                     3,330
  Interest and other income...........      1,335                  1,347                     609                       363
                                         --------              ---------                --------                  --------
                                           70,747                 75,767                  45,576                    42,760
                                         --------              ---------                --------                  --------
COSTS AND EXPENSES:
  Production expenses.................     21,532                 25,381                  13,836                    11,437
  General and administrative
    expenses..........................      7,848                  8,459                   3,748                     4,042
  Depreciation, depletion and
    Amortization......................     23,863                 39,688                  16,352                    15,574
  Impairment expense..................        ---                 73,899                     ---                       ---
  Interest expense....................     11,845                 11,660                   5,978                     4,477
                                         --------               --------                --------                  --------
                                           65,088                159,087                  39,914                    35,530
                                         --------               --------                --------                  --------
  Income (loss) before income
   tax (benefit)......................      5,659                (83,320)                  5,662                     7,230
  Provision for income tax (benefit)..     (3,154)                (6,069)                  2,114                     2,585
                                         --------               --------                --------                  --------
  Net income (loss)...................   $  8,813               $(77,251)               $  3,548                  $  4,645
                                         ========               ========                ========                  ========
  Net income (loss) per share.........   $    .64               $  (5.50)               $    .26                  $   0.46
                                         ========               ========                ========                  ========
  Net income (loss) per share-
   diluted............................   $    .63               $  (5.50)               $    .25                  $   0.45
                                         ========               ========                ========                  ========
  Weighted average common shares
   outstanding........................     13,854                 14,039                  13,876                    10,201
                                         ========               ========                ========                  ========
  Weighted average common shares
   outstanding-diluted................     13,896                 14,039                  14,446                    10,261
                                         ========               ========                ========                  ========
</TABLE>


                 See Notes to Consolidated Financial Statements.


                                      35
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

                       CONSOLIDATED STATEMENTS OF CHANGES
                            IN STOCKHOLDERS' EQUITY
                             (Amounts in thousands)
<TABLE>
<CAPTION>

                                    Common Stock       Preferred Stock   Additional    Retained     Treasury Stock
                                   --------------     -----------------    Paid-In     Earnings     ---------------
                                  Shares   Amount    Shares     Amount     Capital     (Deficit)   Shares     Amount      Total
                                  ------  -------    ------    -------   -----------   ---------   -------    -------     -----
<S>                                <C>      <C>      <C>         <C>      <C>           <C>         <C>       <C>        <C>

Balance June 30, 1996..........    9,075     $ 91     ---       $  ---     $41,639    $  4,867       ---      $  ---     $ 46,597
Shares issued in public
 stock offering, net of
 offering costs................    4,687       47     ---          ---      36,169         ---       ---         ---       36,216
Stock options
 exercised and related
 tax effect...................        83        1     ---          ---         465         ---       ---         ---          466
Net income....................       ---      ---     ---          ---         ---       4,645       ---         ---        4,645
                                  ------    -----   -----       ------     -------      ------     -----      ------     --------

Balance June 30, 1997.........    13,845     $139     ---       $  ---     $78,273    $  9,512       ---      $  ---     $ 87,924
                                  ======    ======  =====       ======     =======    ========     =====      ======     ========
Offering costs................       ---      ---     ---          ---         (96)        ---       ---         ---          (96)
Stock options
 exercised and related
 tax effects..................        47      ---     ---          ---         293         ---       ---         ---          293
Net income....................       ---      ---     ---          ---         ---       3,548       ---         ---        3,548
                                  ------    -----   -----       ------     -------      ------     -----      ------     --------
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
                                  ======    ======  =====       ======     =======    ========     =====     =======     ========
</TABLE>
                See Notes to Consolidated Financial Statements.

                                       36
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                             (Amounts in Thousands)

<TABLE>
<CAPTION>
                                                                                                   Six Month
                                                                                               Transition Period          Fiscal
                                                         Year Ended         Year Ended               Ended              Year Ended
                                                        December 31,       December 31,           December 31,           June 30,
                                                       -------------      -------------        ------------------      ------------
                                                            1999               1998                     1997              1997
                                                       -------------      -------------        ------------------      ------------
<S>                                                         <C>                <C>                <C>                       <C>
CASH FLOWS FROM OPERATING ACTIVITIES:

Net income (loss)..............................          $  8,813           $(77,251)                 $  3,548         $  4,645
Adjustments to reconcile net income
  (loss) to net cash provided by
  operating activities:
  Depreciation, depletion and
  Amortization.................................            24,694             40,544                    16,708           16,044
  Impairment expense...........................               ---             73,899                       ---              ---
  Deferred taxes...............................            (2,739)            (6,820)                    1,585            2,562
                                                         --------           --------                   -------         --------
                                                           30,768             30,372                    21,841           23,251

Change in assets and liabilities,
  net of acquisition effects:
  Accounts receivable and accrued
    revenues...................................             2,101              2,691                    (1,498)           2,941
  Prepaid expenses.............................               157              1,521                    (1,481)            (638)
  Accounts payable and accrued expenses........             6,265             (2,220)                    1,502            4,438
  Due (to) from affiliates.....................              (125)             3,245                    (2,346)           5,738
  Other........................................            (1,837)            (1,908)                      (57)          (6,447)
                                                         --------           --------                   -------         --------
NET CASH FLOWS PROVIDED BY OPERATING
  ACTIVITIES...................................            37,329             33,701                    17,961           29,283
                                                         --------           --------                   -------         --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions of oil and gas properties,
  including working capital of $13,914
  in fiscal year ended June 30, 1997
  -Partnership Transactions....................               ---                ---                       ---         (147,909)
  -Other acquisitions..........................           (25,889)            (9,596)                   (5,486)          (2,005)
Investment in outside companies................            (4,554)               ---                       ---              ---
Additions to oil and gas properties............           (30,904)           (30,583)                  (13,727)         (20,811)
Proceeds from sales of properties..............             5,139                421                     5,362           18,775
Additions to gas plant facilities..............              (369)              (689)                   (1,632)             (84)
Other..........................................              (273)               (88)                      (17)             (88)
                                                         --------           --------                   -------         --------
NET CASH FLOWS  USED IN
  INVESTING ACTIVITIES.........................           (56,850)           (40,535)                  (15,500)        (152,122)
                                                         ========           ========                   =======         ========
</TABLE>


                See Notes to Consolidated Financial Statements.

                                       37
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


               CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
                            (Amounts in Thousands)

<TABLE>
<CAPTION>

                                                                                                Six Month
                                                                                                Transition          Fiscal Year
                                                        Year Ended         Year Ended          Period Ended            Ended
                                                        December 31,       December 31,         December 31,          June 30,
                                                       -------------      -------------       ---------------       ------------
                                                          1999               1998                   1997                1997
                                                       -------------      -------------       ---------------       ------------
<S>                                                       <C>                 <C>                     <C>                <C>
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings......................           42,000              4,900                     1,500           157,300
Net proceeds from issuance of
  common stock................................               13              1,649                       197            35,145
Payments of long-term debt....................          (16,400)              (500)                  (16,800)          (55,048)
Purchase of treasury shares...................               (1)            (1,904)                      ---               ---
                                                       --------           --------                 ---------          --------
NET CASH FLOWS PROVIDED BY
  (USED IN) FINANCING ACTIVITIES..............           25,612              4,145                   (15,103)          137,397
                                                       --------           --------                 ---------          --------
Net increase (decrease) in cash and
  cash equivalents............................            6,091             (2,689)                  (12,642)           14,558
Cash and cash equivalents at
  beginning of period.........................               10              2,699                    15,341               783
                                                       --------           --------                 ---------          --------
CASH AND CASH EQUIVALENTS AT END
  OF PERIOD...................................         $  6,101            $    10                  $  2,699          $ 15,341
                                                       ========           ========                 =========          ========
</TABLE>


                See Notes to Consolidated Financial Statements.

                                       38
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


1.   ORGANIZATION

     Bellwether Exploration Company ("the Company") was formed as a Delaware
corporation in 1994 to succeed to the business and properties of its predecessor
company pursuant to a merger, the primary purpose of which was to change the
predecessor company's state of incorporation from Colorado to Delaware.  The
predecessor company was formed in 1980 from the consolidation of the business
and properties of related oil and gas limited partnerships.  References to
Bellwether or the Company include the predecessor company, unless the context
requires otherwise.

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 Ukrainian interests are currently reflected using the equity method.
All significant intercompany accounts and transactions have been eliminated in
consolidation.

     Fiscal Year Change

     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").

     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.  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
MCF of production was approximately $ .72 in 1999, $1.10 in 1998, $.90 in
transition period 1997, and $.94 in fiscal 1997.

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

<TABLE>
<CAPTION>
                                           Leasehold            Exploration             Development              Total at
                                              Costs                Costs                    Cost             December 31, 1999
                                           ----------           ------------            -----------         -------------------
Costs Incurred During Periods Ended:
<S>                                          <C>                    <C>                     <C>                   <C>
    December 31, 1999                       $ 9,198                 $1,297                  $2,641                $13,136
    December 31, 1998                         3,016                    ---                     ---                  3,016
    December 31, 1997                           173                    ---                     ---                    173
    Prior                                       ---                    ---                     ---                    ---
                                            -------                 ------                  ------                -------
                                            $12,387                 $1,297                  $2,641                $16,325
                                            =======                 ======                  ======                =======
</TABLE>

                                       39
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

     The Latin American unproved property costs of $404,000 excluded from
amortization was incurred in 1999 and was for acquisition costs.

     Significant land and seismic costs have been incurred in the current and
prior years by the Company and are still in the evaluation stage. While
approximately $1.2 million has been evaluated and moved to the full cost pool in
1999, $16.3 million of such domestic costs remain to be evaluated.

          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
              1999. This category of costs will transfer into the full cost pool
              in 2000.

     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 1999, 1997 or
June 1997.

     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
Diamond M - NGL - Torch Gas Plant Venture, backed-in for a 16.5% working
interest in the Diamond M and Snyder gas plants. This resulted in the
dissolution of the joint venture and the Company's reduced interest in the
Diamond M and Snyder gas plants.

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

     Gas Imbalances

     The Company uses the sales method of accounting for gas imbalances.  Under
this method, gas sales are recorded when revenue checks are received or are
receivable on the accrual basis.  The Company had a net imbalance liability, at
fair value, of $1.2 million and $.5 million, at December 31, 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 has
taken steps to extend the productive life of such reserves.

                                       40
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


Natural Gas and Crude Oil Hedging

     Commodity derivatives utilized as hedges include 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, 1999 or 1998.

     Oil and gas revenues were decreased by $4.0 million in the year ended
December 31, 1999, increased by $3.6 million in the year ended December 31,
1998, decreased by $1.6 million in the six month transition period ended
December 1997 and decreased by $18,000 in the fiscal year ended June 1997, as a
result of such hedging activity.

Income Taxes

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

Statements of Cash Flows

     For cash flow presentation purposes, the Company considers all highly
liquid debt instruments purchased with an original maturity of three months or
less to be cash equivalents.  Interest paid in cash for the years ended December
31, 1999 and 1998, the six month transition period ended December 31, 1997, and
the fiscal year ended June 30, 1997, was $ 11.1 million, $11.1 million, $5.4
million and $1.5 million, respectively.  Income tax refunds received in cash for
December 31, 1999, were $437,000.  Income taxes paid in cash for the year ended
December 31, 1998, the transition period ended December 31, 1997 and the fiscal
year ended June 30, 1997, were $1,408,000, $41,000 and $198,000, respectively.
In April 1997, a portion of the purchase price of the Partnership Transactions
included the issuance to Torch Energy Advisors Inc. ("Torch"), as consideration
for advisory services, 150,000 shares of the Company's common stock valued at
$1.2 million and a warrant to purchase 100,000 shares of common stock at $9.90
per share valued at $300,000.

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 not yet determined the impact of this
statement on the Company's financial condition or results of operations.

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

                                       41
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

statements in conformity with generally accepted accounting principles. 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 MERGERS

     During the last three fiscal years, the Company has completed the following
mergers and acquisitions, all of which were recorded using the purchase method
of accounting:

     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 95.45 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 (approximately 43% of the Carpatsky's equity), do not carry a
preferential dividend and have majority voting rights over Carpatsky.  In
connection with this investment, Mr. J.P. Bryan, Chairman and Chief Executive
Officer of Bellwether became the Chairman and CEO of Carpatsky and three
Carpatsky directors retired and were replaced by three Bellwether appointees,
giving Bellwether five of the new eight directorships of Carpatsky.  Carpatsky
conducts oil and gas exploration and production activities in the Republic of
Ukraine.

     In December 1998 Bellwether was the successful bidder for the Charapa field
in Ecuador.  With the successful bid, the Company was awarded with a contract
for production and exploration of crude oil in the Charapa field.  The contract
provides the Company with approximately 50% 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 productions.  Negotiations with the Ecuadorian
government took place throughout 1999 with Bellwether officially taking over
operations of the field in January of 2000.  Bellwether has committed to a $12
million work program over three years.

     In April 1997, the Company closed acquisitions of oil and gas properties,
totaling $141.1 million, after purchase price adjustments, including working
capital of $13.9 million, from certain partnerships and other entities managed
or sponsored by Torch.  The acquisitions were financed by the sale of 4.4
million shares of common stock, the sale of $100.0 million of 10-7/8% senior
subordinated notes due in 2007 and the use of $33.3 million of a new $90.0
million senior unsecured credit facility (including the repayment of $22.0
million on a then existing credit facility).

4.   RELATED PARTY TRANSACTIONS

     The Company is a party to a master services agreement and six specific
contracts which requires 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 amounts of $.4 million to $2.8 million plus
fees based upon percentages of production ranging from  1/2% to 2% depending on
the product. Prior to 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

                                       42
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

December 31, 1999, 1998 and 1997, and June 30, 1997, related fees paid to Torch
amounted to $2.9 million, $4.0 million, $2.4 million and $2.3 million,
respectively.

     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 the Partnership
Transactions.  The Company's stock was valued at $1.2 million, and the warrant
was valued at $300,000. In December 1993, Torch was issued a warrant to purchase
187,500 shares of the Company's common stock at a price of $6.40 per share for
its advisory services in identifying and negotiating a merger; such warrants
were exercised in connection with the Partnership Transactions with total
proceeds to the Company of $684,000.

     Torch was also a selling partner in the Partnership Transactions through
its ownership of general partnership and working interests in the partnerships
programs.  As a result, Torch was paid $18.4 million for such interests.

     On August 2, 1999, Mr. J. Darby Sere, previously Chairman and CEO, and
Mr. William C. Rankin, previously Senior Vice President and Chief Financial
Officer, left the Company to pursue other opportunities. Director, Mr. J. P.
Bryan 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. Mr. Bryan has limited involvement in the day to day operations of Torch.
Approximately $1.7 million of severance cost attributable to this management
change were incurred in August 1999.

     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 $947,500, $1,143,000, $757,000 and $646,000 in periods ended
December 1999, 1998 and 1997, June 1997, respectively.

     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 $357,800, $379,000,
$217,000 and $650,000, for these costs in periods ended December 1999, 1998,
1997 and June 1997, 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.  Operator's
overhead charged for these activities for the periods ended December 31, 1999,
1998, 1997, and June 30, 1997 was $1,153,000, $1,349,000, $698,000 and $729,000,
respectively.

     Torch became the operator of the Snyder Gas Plant on December 1, 1993.  In
periods ended December 1999, 1998, 1997 and June 1997, the fees paid by the
Company to Torch were $73,000, $72,000, $42,000 and $49,000, respectively.

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 April 1997, the Company issued 4.4 million shares of common stock for
net proceeds to the Company of $34.1 million.  Such proceeds were used in
financing the Partnership Transactions.  Also included in the April Offering
were 719,264 shares sold by certain shareholders.  Additional shares issued
during fiscal 1997 included

                                       43
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


125,000 shares issued upon exercise of a warrant and 150,000 shares issued to
Torch for advisory services rendered in connection with the Partnership
Transactions.

     On September 12, 1997, the Company authorized and declared a dividend of
one preferred stock purchase right for each share of common stock, par value
$.01 per share, of the Company.  The dividend was payable on September 26, 1997
to the holders of record of Common Shares as of the close of business on such
date.

     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 at employee stock options was
immaterial in 1999 and approximately $324,000 was allocated directly to
additional paid in capital in 1998.  Such benefit was not material in prior
periods.

                                       44
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


Earnings Per Share

     SFAS No. 128 requires 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):
<TABLE>
<CAPTION>

                                                 Year Ended                                        Year Ended
                                              December 31, 1999                                 December 31, 1998
                               ----------------------------------------------     -------------------------------------------------
                                 Income         Shares         Per Share            Income           Shares          Per Share
                               ----------------------------------------------     -------------------------------------------------
<S>                               <C>            <C>             <C>                  <C>             <C>               <C>
Net income (loss)               $8,813                                              $(77,251)
                                ------          ------           ----               --------          ------           ------
Earnings (loss) per             $8,813          13,854           $.64               $(77,251)         14,039           $(5.50)
 Common share


Effect of Dilutive Securities:
 Options &  Warrants               ---              42             ---                   ---             ---
                                ------          ------            ----              --------          ------           ------

Earnings (loss) per
 Common share-diluted           $8,813          13,896            $.63              $(77,251)         14,039           $(5.50)
                                ======          ======           =====              ========          ======           ======
</TABLE>

<TABLE>
<CAPTION>
                                    Six Month Transition Period Ended                             Fiscal Year Ended
                                             December 31, 1997                                       June 30, 1997
                               ----------------------------------------------     -------------------------------------------------
                                 Income         Shares         Per Share            Income            Shares         Per Share
                               ----------------------------------------------     -------------------------------------------------
<S>                             <C>               <C>               <C>              <C>                   <C>             <C>
Net Income                      $3,548                                              $4,645
                                ------          ------            -----             ------            ------            -----
Earnings per
 Common share                   $3,548          13,876            $0.26             $4,645            10,201            $0.46

Effect of Dilutive
 Securities: Options &
 Warrants                          ---             570                                 ---                60
                                ------          ------            -----             ------            ------            -----
Earnings per common
 Share - diluted                $3,548          14,446            $0.25             $4,645            10,261            $0.45
                                ======          ======            =====             ======            ======            =====
</TABLE>

     Options and warrants on 203,000 of shares of common stock were not included
in computing diluted earnings per share for 1998 because their effects were
antidilutive.

                                       45
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


Treasury Stock

     In September 1998, the Company's Board of Directors authorized the
repurchase of up to $5 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. The plans currently allow the Company 1,825,000 options;
therefore, the remainder are subject to Shareholder approval of an amendment to
the Company's plan.

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

<TABLE>
<CAPTION>
                                                                         Number                            Option
                                                                        Of shares                       Price Range
                                                              -------------------------      -------------------------------
<S>                                                              <C>                            <C>
Balance at June 30, 1996.................................                908,325                    $3.00 -      $7.00
  Granted................................................                378,500                    $6.25 -     $10.19
  Surrendered............................................                (12,000)                   $7.63
  Exercised..............................................                (82,500)                   $5.63        $5.75
                                                              -------------------------      -------------------------------
Balance at June 30, 1997.................................              1,192,325                    $3.00 -     $10.19
  Granted................................................                242,000                    $1.31 -     $12.38
  Exercised..............................................                (46,500)                   $3.00 -     $10.00
                                                              -------------------------      -------------------------------
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
                                                              -------------------------      -------------------------------
Balance at December 31, 1999.............................              1,528,000                    $3.34 -     $12.38
                                                              =========================      ===============================
Exercisable at December 31, 1999.........................              1,210,000                    $3.34 -     $12.38
                                                              =========================      ===============================
</TABLE>

                                       46
<PAGE>

     Detail of stock options outstanding and options exercisable at December 31,
1999 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                   463,000               5.7           $5.27                 362,000           $5.47
1996 Plan $3.34 to $12.38                 1,065,000               8.6           $7.03                 848,000           $7.37
                                          ---------                                                 ---------
 Total                                    1,528,000                                                 1,210,000
                                          =========                                                 =========
</TABLE>

     The estimated weighted average fair value per share of options granted
during 1999, 1998, transition period 1997 and fiscal 1997 was $11.68, $2.34,
$1.78 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 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, transition period 1997 and fiscal 1997:
expected stock price volatility of 40%; and risk free interest rate of 5.5% and
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>

                                                                                       Six Month Transition
                                      Year Ended                Year Ended                 Period Ended           Fiscal Year
                                     December 31,              December 31,                December 31,          Ended June 30,
                                         1999                      1998                        1997                   1997
                                ------------------       --------------------       -----------------------    ------------------
<S>                                <C>                      <C>                        <C>                          <C>
Net income (loss)
     As Reported..........                $  8,813                   $(77,251)             $3,548                  $4,645
     Pro forma............                $(19,516)                  $(78,321)             $2,524                  $3,853
Earnings (loss) per share
     As reported..........                $    .64                   $  (5.50)             $ 0.26                  $ 0.46
     Pro forma............                $  (1.41)                  $  (5.58)             $ 0.18                  $ 0.38
Diluted earnings (loss) per
     share
     As reported..........                $    .63                   $  (5.42)             $ 0.25                  $ 0.45
     Pro forma............                $  (1.40)                  $  (5.50)             $ 0.17                  $ 0.38
</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
returns by $4 million for the year 1999, increased returns by $3.6 million for
the year 1998 and reduced revenues by $1.6 million and $18,000 for the
transition period 1997 and for the fiscal years ended June 30, 1997,
respectively.  At December 31, 1999 the Company had unrealized net hedging gains
of $862,000.

                                       47
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

    The following tables detail the Company's hedges of future production, which
were in place at December 31, 1999.

    OIL HEDGES

<TABLE>
<CAPTION>
                                                                                              NYMEX               NYMEX
          PERIOD                  BBLS           TOTAL BBLS             TYPE                  PRICE               PRICE
                                 PER DAY                                                      FLOOR              CEILING
-----------------------------------------------------------------------------------------------------------------------------
<S>                              <C>             <C>                   <C>                   <C>                 <C>
Jan 2000-March 2000              2,000            182,000              Collar                 $19.00             $21.75
-----------------------------------------------------------------------------------------------------------------------------
Jan 2000-March 2000              2,000            182,000              Collar                 $21.75             $25.60
-----------------------------------------------------------------------------------------------------------------------------
April 2000-June 2000             4,000            364,000              Collar*                $22.00             $24.63
-----------------------------------------------------------------------------------------------------------------------------
</TABLE>


    GAS HEDGES

<TABLE>
<CAPTION>
                                                                                             NYMEX             NYMEX
                 Period           MCF            TOTAL MCF            Type                   PRICE             PRICE
                                PER DAY                                                      FLOOR            CEILING
------------------------------------------------------------------------------------------------------------------------------
<S>                              <C>               <C>                <C>                    <C>                  <C>
Jan 2000-Mar 2000                15,000           2,280,000            Floor                  $2.40              N/A
------------------------------------------------------------------------------------------------------------------------------
Jan 2000-Mar 2000                15,000           2,280,000           Collar**                $3.00            $3.55
------------------------------------------------------------------------------------------------------------------------------
April 2000-Oct 2000              15,000           3,210,000           Collar                  $2.30            $2.87
------------------------------------------------------------------------------------------------------------------------------
Nov 2000-March 2001              20,000           3,020,000           Collar                  $2.40            $3.40
------------------------------------------------------------------------------------------------------------------------------
April 2001-Oct 2001              20,000           4,280,000           Collar                  $2.20            $2.95
------------------------------------------------------------------------------------------------------------------------------
</TABLE>

*   This agreement includes a put at $17.00 per barrel
**  This agreement includes a put at $2.40 per Mcf

     The fair value at December 31, 1999 of these swap agreements was a gain of
$862,000. 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.

     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, 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.

                                       48
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES



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, 1999 and 1998 (in
thousands).

<TABLE>
<CAPTION>
                                                       December 31, 1999                                  December 31, 1998
                                      -------------------------------------------------      --------------------------------------
                                                                    Approximate Fair                               Approximate Fair
                                         Carrying Value                  Value                 Carrying Value            Value
                                      ----------------------      ---------------------      --------------------  ----------------
Assets/ (Liabilities):
<S>                                         <C>                         <C>                        <C>                       <C>
Derivative instruments other than
 trading:
Interest swap agreements                 $   ---                      $   3,045                  $   ---                $   1,392
Production swap agreements               $   ---                      $     862                  $   ---                $     ---
Long-term debt (See Note 7)              $(130,000)                   $(125,485)                 $(104,400)             $(107,001)
</TABLE>

7.   LONG-TERM DEBT

     Long-term debt is comprised of the following at December 31, 1999 and 1998
(in thousands):

<TABLE>
<CAPTION>
                                                                   December 31,              December 31,
                                                                       1999                      1998
                                                             ---------------------     ---------------------

<S>                                                             <C>                       <C>
Bank credit facility....................................                  $ 30,000                  $  4,400

10-7/8% Senior Subordinated Notes.......................                   100,000                   100,000
                                                             ---------------------     ---------------------
Long-term debt..........................................                  $130,000                  $104,400
                                                             =====================     =====================
</TABLE>

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

          1999                     $    ---
          2000                          ---
          2001                          ---
          2002                          ---
          2003                       30,000
       Thereafter                   100,000
                                   --------
                                   $130,000
                                   ========

     In October 1996, the Company entered into a syndicated credit facility
("Syndicated Credit Facility") in an amount up to $50.0 million with an initial
borrowing base of $27.0 million, to be re-determined semi-annually.  At
Bellwether's option, the interest rate varied, based upon borrowing base usage,
from London Interbank Offered Rate ("LIBOR") plus 7/8% to LIBOR plus 1-1/4%, or
the greater of the prime rate or Federal Funds rate plus  1/2%.  The Syndicated
Credit Facility was unsecured and was retired in April 1997.

     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.  Bellwether may elect an interest rate based either on a margin
plus LIBOR or the higher of the prime rate or the sum of  1/2 of 1% plus the
Federal Funds Rate.  For LIBOR borrowings, the interest rate will vary from
LIBOR plus 0.875% to LIBOR

                                       49
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

plus 1.25% based upon borrowing base usage. In connection with the acquisition
of oil and gas properties, $33.3 million was drawn under this facility,
including $22 million used to retire outstandings under the Syndicated Credit
facility. At December 31, 1999, there were $30.0 million borrowings outstanding.

     The Senior Credit Facility contains various covenants including certain
required financial measurements for a current ratio, consolidated tangible net
worth and interest coverage ratio.  In addition, the Senior Credit Facility
includes certain limitations on restricted payments, dividends, incurrence of
additional funded indebtedness and asset sales.

     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% which decreases annually to 100.00% on April 1,
2005 and thereafter, plus accrued and unpaid interest.  In the event of 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.

8.   INCOME TAXES

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

<TABLE>
<CAPTION>
                                                                                   Six Month
                                        Year Ended            Year Ended        Transition Period          Year Ended
                                        December 31,          December 31,      Ended December 31,           June 30,
                                            1999                  1998                 1997                    1997
                                       -------------        --------------      ------------------         -----------
<S>                                       <C>                  <C>                  <C>                       <C>
Current
  Federal...........................      $ (425)               $   658               $  400                  $  (12)
  State.............................          10                     93                  129                      35
                                          ------                -------               ------                  ------
Deferred - Federal and State........      (2,739)                (6,820)               1,585                   2,562
                                          ------                -------               ------                  ------
Total income tax
  expense (benefit).................     $(3,154)               $(6,069)              $2,114                   2,585
                                         =======                =======               ======                  ======
</TABLE>

                                       50
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


     The tax effect of temporary differences that give rise to significant
portions of the deferred tax assets and liabilities at December 31, 1999 and
1998 is as follows:


<TABLE>
<CAPTION>

                                                                       December 31,                    December 31,
                                                                           1999                            1998
                                                              --------------------------       ------------------------
<S>                                                              <C>                              <C>
Net operating loss
  Carryforwards.........................................                        $ 10,296                       $ 11,085
Percentage depletion
  Carryforwards.........................................                             271                            271
Alternative minimum
   tax credit carryforwards.............................                             725                          1,150
Property, plant and
  equipment.............................................                           9,551                         10,646
State income taxes......................................                           1,732                          1,901
                                                              --------------------------       ------------------------
Total deferred income tax
   assets...............................................                          22,575                         25,053
                                                              --------------------------       ------------------------

Valuation allowances....................................                         (19,836)                       (25,053)
                                                              --------------------------       ------------------------
Net deferred income tax asset
  (liability)...........................................                        $  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.

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

                                       51
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


     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>
                                                                                                    Six Month
                                                                                                    Transition
                                                             Year Ended         Year Ended         Period Ended      Fiscal Year
                                                             December 31,       December 31,       December 31,     Ended June 30
                                                                1999               1998               1997               1997
                                                             -----------        -----------        -------------    -------------

<S>                                                              <C>                <C>                <C>               <C>
 Statutory Federal income tax rate.......................        34.0%              (34.0%)             34.0%            34.0%

 Increase (decrease) in tax rate
   resulting from:
   State income taxes, net of
   federal benefit.......................................         3.1%               (3.1%)              3.2%             1.3%

 Non-deductible travel and
   entertainment.........................................           .2%                0.1%              0.1%             0.5%
 Other...................................................          (.8%)               ---               ---              ---
 Change in valuation allowance...........................        (92.2%)              29.7%              ---              ---
                                                                 ------               ----             -----             ----
                                                                 (55.7%)              (7.3%)            37.3%            35.8%
                                                                 ======               ====             =====             ====
</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 has undergone 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, 1999, the Company had net operating loss carryforwards of
approximately $30.2 million, which will expire in future years beginning in
2000.

9.   COMMITMENTS AND CONTINGENCIES

          Lease Commitments

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

                  YEAR ENDED DECEMBER 31              ($ IN THOUSANDS)
                  ----------------------              ----------------
                           2000                             382
                           2001                             403
                           2002                             415
                           2003                             426
                           2004                             430

     Rent expense was $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.
Upon the new Torch Master Service Agreement in October 1999, Bellwether began
paying office rent.

                                       52
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

     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 $11.8 million minimum
investment program.  In 2000, the first year of the commitment, the Company is
budgeted to spend approximately $7.1 million in the Charapa field.

     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 recently settled  the case for the sum of $353,500 net to
its interest.

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

<TABLE>
<CAPTION>
                                                           Quarter Ended
                                   -----------------------------------------------------------------
                                      December 31,  September 30,    June 30,     March 31,
                                         1999          1999            1999          1999
                                   ------------------------------------------------------------------
<S>                                      <C>            <C>            <C>             <C>
Revenues                                  $24,556     $17,696         $15,264        $13,231
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 shares -
  diluted                                 $  0.71     $  0.00         $  0.01        $ (0.09)
</TABLE>

<TABLE>
<CAPTION>

                                                              Quarter Ended
                                   ------------------------------------------------------------------
                                      December 31,     September 30,      June 30,     March 31,
                                           1998            1998             1998          1998
                                   ------------------------------------------------------------------
<S>                                       <C>            <C>             <C>            <C>
Revenues                                 $ 15,943       $19,034           $20,953       $19,837
Operating income
  (loss)                                 $(82,812)      $  (283)          $   399       $  (624)
Net income (loss)                        $(76,919)      $  (187)          $   247       $  (392)
Earnings (loss) per
   common share                          $  (5.55)      $ (0.01)          $  0.02       $ (0.03)
Earnings (loss) per common share
   common share-
   diluted                               $  (5.55)      $ (0.01)          $  0.02       $ (0.03)
</TABLE>

     The quarter ended December 31, 1998 reflects a $73.9 million full cost
ceiling impairment, which resulted from low oil and gas prices at December 31,
1998.

                                       53
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

     The quarter ended December 31, 1999 reflects increased oil and gas prices
and increased production levels as result of increased drilling activities and
the acquisition of Gulf of Mexico and New Mexico properties in the last half of
1999. In addition, the Company recognized a $2.7 million tax asset based upon
increased future net reserves.

11.  SEGMENT REPORTING

     The Company has recently acquired interests in Ecuador and the Ukraine.
(See Note)  Relative to the Charapa field in Ecuador, capital expenditures as of
December 31, 1999 totaled $843,000 primarily incurred for contract negotiation,
development planning and accumulation of necessary tools, supplies and
equipment.  Field operations commenced in January of 2000.  A loss of $172,000
for the year ended December 31, 1999 is attributable to Ecuadorian operations
due to the recognition of start up costs and other administrative expenses.

     The Company's Ukrainian interests were acquired December 30, 1999 through
an acquisition of a controlling interest in the preferred stock of Carpatsky
Petroleum Inc.  At December 31, 1999 Bellwether's consolidated financial
statements reflected $4.6 million in Investment in Outside Companies  identified
to the Ukrainian interests.  No revenues or expenses related to the Ukrainian
operations were recognized by the Company for the year ended December 31, 1999.

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 for fiscal 1999 and 1998 and the transition
period 1997 and the year ended June 30, 1997.  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 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.

     There are no reserves associated with the Company's Ukrainian investments
as such amounts were immaterial at December 31, 1999.

                                       54
<PAGE>

     COSTS INCURRED (IN THOUSANDS)
<TABLE>
<CAPTION>



                                                                                        Six Month
                                      Year Ended December 31,                           Transition
                          ---------------------------------------------------          Period Ended
                                                                                       December 31,         Fiscal Year Ended
                                    1999                      1998                         1997               Junne 30, 1997
                          -------------------------    ----------------------    ----------------------     --------------------
<S>                              <C>                       <C>                          <C>                       <C>
United States:
--------------
Property acquisition:.....
  Proved properties.......        $22,428                   $   617                       $ 3,281                  $138,984
  Unproved properties.....          2,406                        52                           326                     1,002
Exploration...............          7,264                    16,186                         3,274                     1,576
  Unproved properties.....          6,788                     8,736                         1,879                       ---
Development...............         16,852                    14,397                        10,453                    14,032
                                  -------                   -------                       -------                  --------
                                  $55,738                   $39,988                       $19,213                  $155,594
                                  -------                   -------                       -------                  --------
Latin America:
---------------
Property acquisition:.....
  Proved properties.......        $   651                   $   ---                       $   ---                   $   ---
  Unproved properties.....            404                       191                           ---                       ---
Exploration...............            ---                       ---                           ---                       ---
Development...............            ---                       ---                           ---                       ---
                                  -------                   -------                       -------                   -------
                                  $ 1,055                   $   191                       $   ---                   $   ---
                                  -------                   -------                       -------                   -------
Worldwide:
----------
Property acquisition:
  Proved properties.......        $23,079                   $   617                       $ 3,281                   $138,984
  Unproved properties.....          2,810                       243                           326                      1,002
Exploration...............          7,264                    16,186                         3,274                      1,576
  Unproved properties.....          6,788                     8,736                         1,879                      1,002
                                  -------                   -------                       -------                   --------
Development...............         16,852                    14,397                        10,453                     14,032
                                  -------                   -------                       -------                   --------
                                  $56,793                   $40,179                       $19,213                   $155,594
                                  =======                   =======                       =======                   ========
</TABLE>

                                       55
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

     CAPITALIZED COSTS (IN THOUSANDS):
<TABLE>
<CAPTION>


                                                                               Year Ended December 31,
                                                         ----------------------------------------------------------------
                                                                       1999                               1998
                                                         -----------------------------      -----------------------------
<S>                                                         <C>                                <C>
United States:
--------------
Proved properties...................................                         $ 328,453                          $ 280,286
Unproved properties.................................                            16,325                              8,754
                                                         -----------------------------      -----------------------------

Total capitalized costs.............................                           344,778                            289,040
Accumulated depreciation, depletion,
amortization and impairment.........................                          (221,092)                          (193,445)
Net capitalized costs...............................                         $ 123,686                          $  95,595
                                                         -----------------------------      -----------------------------

Latin America:
--------------
Proved properties...................................                         $     842                          $     ---
Unproved properties.................................                               404                                191
                                                         -----------------------------      -----------------------------

Total capitalized costs.............................                             1,246                                191
Accumulated depreciation, depletion,
amortization and impairment.........................                               ---                                ---
Net capitalized costs...............................                         $   1,246                          $     191
                                                         -----------------------------      -----------------------------

Worldwide:
----------
Proved properties...................................                         $ 329,295                          $ 280,286
Unproved properties.................................                            16,729                              8,945
                                                         -----------------------------      -----------------------------

Total capitalized costs.............................                           346,024                            289,231
Accumulated depreciation, depletion,
amortization and impairment.........................                          (221,092)                          (193,445)
Net capitalized costs...............................                         $ 124,932                          $  95,786
                                                         =============================      =============================
</TABLE>

                                       56
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

Results of operations for producing activities (in thousands):
<TABLE>
<CAPTION>
                                                                                                 Six Month              Fiscal
                                                    Year Ended          Year Ended           Transition Period        Year Ended
                                                   December 31,         December 31,         Ended December 31,        June 30,
                                           -----------------------  -------------------   ----------------------  -----------------
                                                      1999 (1)              1998                   1997                   1997
                                          ------------------------  -------------------   ----------------------  -----------------
<S>                                             <C>                       <C>                     <C>                    <C>
Revenues from oil and gas
  producing activities....................       $ 67,948                  $ 73,217                $44,163               $39,067

Production costs..........................         21,532                    25,381                 13,836                11,437

Income tax................................          8,820                       ---                  5,379                 4,529

Impairment expense........................            ---                    73,899                    ---                   ---

Depreciation, depletion and
 amortization.............................         22,643                    38,548                 15,831                14,691
                                                ---------                 ---------               --------              --------
Results of operations from producing
  activities  (excluding corporate
  overhead and interest costs)............       $ 14,953                  $(64,611)               $ 9,117               $ 8,410
                                                 ========                  ========                =======               =======

</TABLE>

    1) Ecuador and Ukraine activities did not commence production until 2000;
therefore, no information for International operations is disclosed.

<TABLE>
<CAPTION>
Per unit sales prices and costs:                                                                 Six Month
                                                                                             Transition Period            Fiscal
                                                  Year Ended                Year Ended             Ended                Year Ended
                                                 December 31,              December 31,        December 31,              June 30,
                                              ------------------         -----------------   ------------------       -------------
                                                   1999 (2)                    1998                 1997                    1997
                                              ------------------         -----------------   -------------------      --------------
<S>                                               <C>                         <C>                   <C>                   <C>
Average sales price: (1)
  Oil (per barrel)........................        $  12.77                    $11.64                $16.52                $17.41
  Gas (per MCF)...........................        $   2.18                    $ 2.18                $ 2.39                $ 2.29

Average production cost per
  equivalent MCF..........................        $    .68                    $  .72                $  .79                $  .73

Average unit depletion rate
  per equivalent MCF......................        $    .72                    $ 1.10                $  .90                $  .94
</TABLE>

1)   Average sales price is inclusive of the effect of natural gas and crude oil
     price swaps, which decreased revenues $4 million in 1999, increased
     revenues $3.6 million in 1998, decreased revenues $1.6 million in
     transition period 1997 and decreased revenues $18,000 in fiscal year ended
     June 30, 1997.
2)   Ecuador and Ukraine activities commenced production in 2000; therefore,
     price and cost information is not disclosed.

                                       57
<PAGE>

The Company's estimated total proved and proved developed reserves of oil and
gas as follows:
<TABLE>
<CAPTION>

                                         Year Ended                              Year Ended
      Description                    December 31, 1999                        December 31, 1998
---------------------  -----------------------------------------   ----------------------------------
                               Oil          NGL          Gas           Oil      NGL          Gas
                             (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                  499          ---        11,636          813       225         9,416
 discoveries...........
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
                             ======        =====       =======       ======     =====       =======
Latin America (1)
-----------------
Purchase of reserves
 in-place...............      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
  year.................      14,711        2,069       130,079        8,489     1,573       111,585
                            =======       ======       =======       ======     =====       =======
  Proved developed
  reserves-
    Beginning of year..       8,021        1,554       106,253       11,153     2,460       119.270
                            =======       ======       =======       ======     =====       =======
    End of year........      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.

                                       58
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

Reserves continued:
<TABLE>
<CAPTION>
                                   Six Month Transition Period
                                        Ended December 31,                      Fiscal Year Ended June 30,
-----------------------      -----------------------------------------    ---------------------------------------
      Description                             1997                                        1997
-----------------------      -----------------------------------------    ---------------------------------------
                                 Oil          NGL          Gas               Oil            NGL           Gas
                                (MBBL)       (MBBL)        (MMCF)            (MBBL)        (MBBL)         (MMCF)
                             ------------------------------------------   ----------------------------------------
<S>                             <C>          <C>          <C>                  <C>           <C>           <C>

Worldwide:
-----------
Proved reserves at beginning
 of period..................     12,007        4,023       127,940             1,808           ---        33,194
Revisions of previous
 estimates..................      1,246       (1,417)        1,599            (1,187)         2,435       (2,773)
Extensions and discoveries..        641           52         4,869               658             52        4,202
Production..................       (967)         (87)      (11,193)             (854)           ---      (10,552)
Sales of reserves
 in-place...................       (694)         ---          (642)           (1,260)           ---      (16,194)
Purchase of reserves
 in-place...................          5          ---         3,387            12,842           1,536     120,063
                                -------       ------       -------            ------          ------     -------
Proved reserves at end
 of period..................     12,238        2,571       125,960            12,007           4,023     127,940
                                =======       ======       =======            ======          ======     =======
Proved developed reserves-
  Beginning of year.........     10,162        3,705       117,914             1,494             ---      22,696
                                =======       ======       =======            ======          ======     =======
  End of year...............     11,153        2,460       119,270            10,162           3,705     117,914
                                =======       ======       =======            ======          ======     =======
</TABLE>

                                       59
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


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 shown below:

<TABLE>
<CAPTION>

                                                                                   Six Month
                                                                                Transition Period          Fiscal
                                              Year Ended          Year Ended         Ended              Year Ended June
                                              December 31,        December 31,     December 31,               30,
                                            ----------------   ---------------- --------------------  --------------------
                                                 1999                 1998              1997                 1997
                                            -----------------  ---------------- --------------------  ---------------------
<S>                                            <C>                   <C>                <C>                <C>
United States
-------------
Future Cash Flow.......................         $ 535,605           $ 328,285           $ 517,323            $ 529,928
Future Future production costs.........          (202,800)           (132,108)           (191,988)            (183,479)
Future income taxes....................           (23,234)                ---             (48,594)             (59,419)
Future development costs...............           (54,034)            (29,609)            (33,197)             (32,237)
                                                ---------           ---------           ---------            ---------
Future net cash flows..................           255,537             166,568             243,544              254,793
10% discount factor....................           (63,933)            (50,588)            (57,829)             (67,300)
                                                ---------           ---------           ---------            ---------
Standardized future net cash flows.....         $ 191,604           $ 115,980           $ 185,715            $ 187,493
                                                =========           =========           =========            =========
Latin America
-------------
Future Cash Flow.......................         $  88,089           $     ---           $     ---            $     ---
Future production costs................           (34,534)                ---                 ---                  ---
Future income taxes....................            (9,860)                ---                 ---                  ---
Future development costs...............           (13,273)                ---                 ---                  ---
                                                ---------           ---------           ---------            ---------
Future net cash flows..................            30,422                 ---                 ---                  ---
10% discount factor....................           (17,138)                ---                 ---                  ---
                                                ---------           ---------           ---------            ----------
Standardized future net cash flows.....         $  13,284           $     ---           $     ---            $     ---
                                                =========           =========           ==========           ==========
Worldwide:
----------
Future Cash Flow.......................         $ 623,694           $ 328,285           $ 517,323            $ 529,928
Future production costs................          (237,334)           (132,108)           (191,988)            (183,479)
Future income taxes....................           (33,094)                ---             (48,594)             (59,419)
Future development costs...............           (67,307)            (29,609)            (33,197)             (32,237)
                                                ---------           ---------            --------            ---------
Future net cash flows..................           285,959             166,568             243,544              254,793
10% discount factor....................           (81,071)            (50,588)            (57,829)             (67,300)
                                                ---------           ---------           ---------            ---------
Standardized future net cash flows.....         $ 204,888           $ 115,980           $ 185,715            $ 187,493
                                                =========           =========           =========            =========
</TABLE>

                                       60
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


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

<TABLE>
<CAPTION>
                                                                                       Year Ended December 31, 1999
                                                            -----------------------------------------------------------------------
                                                                     Latin                    United                     World
                                                                    America                   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>

<TABLE>
<CAPTION>
                                                                                                                  Six Month
                                                                                                              Transition Period
                                                                                   Year Ended December              Ended
                                                                                            31                   December 31
                                                                                   ----------------------     --------------------
                                                                  1998                       1997                      1997
                                                          ---------------------     ----------------------     --------------------
<S>                                                             <C>                       <C>                        <C>
Standardized measure - beginning of year........                 $185,715                   $187,493                 $ 45,188
Sales, net of production costs..................                  (44,264)                   (30,327)                 (27,630)
Purchases of reserves in-place..................                    3,379                      4,117                  151,836
Net change in prices and production costs.......                  (55,408)                    (3,922)                  22,599
Net change in income taxes......................                   14,517                      8,706                  (20,265)
Extensions, discoveries and improved
  recovery, net of future production and
  development costs.............................                    8,255                     10,769                   12,555
Changes in estimated future development
  costs.........................................                    4,542                     (3,588)                  (3,034)
Development costs incurred during the
  period........................................                   11,244                      6,662                    9,124
Revisions of quantity estimates.................                  (20,520)                       569                   27,102
Accretion of discount...........................                   18,572                     18,749                    4,518
Sales of reserves in-place......................                     (260)                    (4,602)                 (16,140)
Changes in production rates and other...........                   (9,792)                    (8,911)                 (18,360)
                                                                 --------                   --------                 --------
Standardized measure - end of year..............                 $115,980                   $185,715                 $187,493
                                                                 ========                   ========                 ========
</TABLE>

     The discounted future cash flows above were calculated using NYMEX
equivalent prices of $25.60, $12.05, $18.32 and $19.80 per barrel and $2.33,
$2.15, $2.58 and $2.35 per MMBTU, for December 31, 1999, 1998 and 1997 and
June 30, 1997, respectively, adjusted to the wellhead to reflect adjustments for
transportation, quality and heating content.

                                       61
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


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

     On or about June 18, 1997 the Company replaced the firm of Deloitte and
Touche, LLP as its principal independent accountant and auditors to audit all
the Company's financial statements with the firm of KPMG LLP.  The decision to
make this change was influenced by the acquisition of Partnership properties and
interests, which were previously audited by KPMG LLP.  The Company does not and
has not during the past three years had disagreements with Deloitte and Touche
LLP or KPMG LLP concerning their audit or application of accounting principles
according to GAAP.

                                 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, 1999. 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, 1999. 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, 1999. 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, 1999. Such information is incorporated herein by reference.

                                 PART IV

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

(a)  1. and 2. Financial Statements.  See index to Consolidated Financial
               Statements and Supplemental Information in Item 8, which
               information is incorporated herein by reference.

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.)

                                       62
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES

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

3.5  Amendment to Article II, Section 2.2 of 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)

                                       63
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


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).

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).

11.10  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.)

11.11  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 10Q for the quarter ended June 30, 1999.

11.12  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 10-Q for the quarter ended June 30, 1999.

11.13  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 10-Q for the quarter ended September 30, 1999).

11.14  Securities Purchase Agreement dated December 29, 1999 by and between the
       Company and Carpatsky Petroleum, Inc. - included herewith.

11.15  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., - included herewith.

11.16  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 - included herewith.

11.17  Master Service Agreement between the Company and Tecnie S.A.C. dated
       November 1, 1999 - included herewith.

                                       64
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


16.1 Letter from predecessor auditors regarding change in certifying accountant
     (incorporated by reference to Exhibit 16-1 to the Company's Form 8K/A-1
     dated July 8, 1997)

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

27   Financial Data Schedule

                                       65
<PAGE>

                BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES


                                   SIGNATURES

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

                                        BELLWETHER EXPLORATION COMPANY


                                         /s/ J. P. Bryan
                                         -------------------
                                         J. P. BRYAN
                                         Chairman of Board of Directors and
                                         Chief Executive Officer


Dated March 24, 2000

   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.

          SIGNATURES            TITLE                     DATE


/s/ J. P. Bryan             Chairman of Board of      March 24, 2000
--------------------        Directors and Chief
J. P. Bryan                 Executive Officer


/s/ Robert Bensh            Senior Vice President -   March 24, 2000
--------------------        Finance
Robert Bensh


/s/ Dr. Jack Birks
--------------------        Director                  March 24, 2000
Dr. Jack Birks


/s/ Judith Allen
--------------------        Director                  March 24, 2000
Judith Allen


/s/ Vincent H. Buckley
-----------------------     Director                  March 24, 2000
Vincent H. Buckley


/s/ Habib Kairouz
--------------------        Director                  March 24, 2000
Habib Kairouz


/s/ A. K. McLanahan
--------------------        Director                  March 24, 2000
A. K. McLanahan


/s/ Townes G. Pressler
----------------------      Director                  March 24, 2000
Townes G. Pressler

                                       66