<PAGE>

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

                      SECURITIES AND EXCHANGE COMMISSION
                            Washington, D.C. 20549

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

                                  FORM 10-KSB

(Mark One)

  [X] Annual report under Section 13 or 15(d) of the Securities Exchange Act
  of 1934
     For the fiscal year ended December 31, 2001

  [_] Transition report under Section 13 or 15(d) of the Securities Exchange
  Act of 1934
     For the transition period from      to

                       Commission file number: 001-14745

                            3TEC ENERGY CORPORATION
                (Name of Small Business Issuer in Its Charter)

               Delaware                               63-1081013
   (State or other jurisdiction of       (I.R.S. Employer Identification No.)
    incorporation or organization)

                                Pennzoil Plaza
                         700 Milam Street, Suite 1100
                             Houston, Texas 77002
                                (713) 821-7100
  (Address, including zip code, and telephone number, including area code, of
                   registrant's principal executive offices)

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

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

          Securities registered pursuant to Section 12(g) of the Act:
                         Common Stock, $.02 Par Value

   Check whether the Registrant (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such
shorter period that the Registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days. Yes [X]
 No [_]

   Check if disclosure of delinquent filers in response to Item 405 of
Regulation S-B is not contained in this form, and will not be contained, to
the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-KSB or any
amendment to this Form 10-KSB. [_]

   Revenues of Registrant for fiscal year ended December 31, 2001 are
$122,779,077.

   The aggregate market value as of March 7, 2002 of voting and nonvoting
stock held by nonaffiliates of the Registrant was $230,472,833.

   As of March 7, 2002 the Registrant had 16,504,503 shares of Common Stock,
$.02 par value outstanding.

   The Registrant's definitive proxy statement, to be filed pursuant to
Regulation 14A on or before May 1, 2002, is incorporated by reference for the
information set forth in Part III of this Form 10-KSB.

   Transitional Small Business Disclosure Format: Yes [_] No [X]

-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
<PAGE>

                               TABLE OF CONTENTS

                                     PART I

<TABLE>
<CAPTION>
                                                                           Page
                                                                           ----
 <C>      <S>                                                              <C>
 Item 1.  Business......................................................     4
          Background....................................................     4
          Recent Developments...........................................     4
          Business Strategy.............................................     5
          Marketing.....................................................     6
          Competition...................................................     6
          Regulation....................................................     6
          Employees.....................................................     8
          Our Executive Offices.........................................     8

 Item 2.  Properties....................................................     9
          Description of Our Properties.................................     9
          Natural Gas and Oil Reserves..................................    10
          Volumes, Prices and Operating Expenses........................    11
          Development, Exploration and Acquisition Capital
           Expenditures.................................................    11
          Drilling Activity.............................................    12
          Productive Wells..............................................    12
          Acreage Data..................................................    12
          Current Activities............................................    13

 Item 3.  Legal Proceedings.............................................    13

 Item 4.  Submission of Matters to Vote of Security Holders.............    13

                                    PART II

 Item 5.  Market for Registrant's Common Equity and Related Stockholder
           Matters......................................................    13

 Item 6.  Management's Discussion and Analysis of Financial Condition
           and Results of Operations....................................    14
          Overview......................................................    14
          Description of Critical Accounting Policies...................    14
          Liquidity and Capital Resources...............................    16
          Results of Operations.........................................    17
          Year Ended December 31, 2001, Compared With Year Ended
           December 31, 2000............................................    17
          Year Ended December 31, 2000, Compared With Year Ended
           December 31, 1999............................................    19

 Item 7.  Financial Statements..........................................    19

 Item 8.  Changes In and Disagreements with Accountants on Accounting
           and Financial Disclosure.....................................    19

                                    PART III

 Item 9.  Directors and Executive Officers of the Registrant............    20

 Item 10. Executive Compensation........................................    20

 Item 11. Security Ownership of Certain Beneficial Owners and
           Management...................................................    20

 Item 12. Certain Relationships and Related Transactions................    20

 Item 13. Exhibits, Financial Statement Schedules and Reports on Form 8-
           K............................................................    20
          Glossary of Certain Oil and Gas Terms.........................    24
          Signatures....................................................    26
          Power of Attorney.............................................    26
</TABLE>

 Item 13(a) includes the Index of Exhibits to be filed with the Securities
 and Exchange Commission relative to this Report.


                                       2
<PAGE>

             CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

   Some of the information in this Annual Report on Form 10-KSB, including
information incorporated by reference, contains forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933 and Section
21E of the Securities and Exchange Act of 1934. The forward-looking statements
speak only as of the date made and the Company undertakes no obligation to
update such forward-looking statements. These forward-looking statements may
be identified by the use of the words "believe," "expect," "anticipate,"
"will," "contemplate," "would" and similar expressions that contemplate future
events. These future events include the following matters:

  .financial position;

  . business strategy;

  . budgets;

  . amount, nature and timing of capital expenditures;

  . drilling of wells;

  . natural gas and oil reserves;

  . timing and amount of future production of natural gas and oil;

  . operating costs and other expenses;

  . cash flow and anticipated liquidity;

  . prospect development and property acquisitions; and

  . marketing of natural gas and oil.

   Numerous important factors, risks and uncertainties may affect the
Company's operating results, including:

  . the risks associated with exploration;

  . the ability to find, acquire, market, develop and produce new properties;

  . natural gas and oil price volatility;

  . uncertainties in the estimation of proved reserves and in the projection;

  . future rates of production and timing of development expenditures;

  . operating hazards attendant to the natural gas and oil business;

  . downhole drilling and completion risks that are generally not recoverable
    from third parties or insurance;

  . potential mechanical failure or under-performance of significant wells;

  . climactic conditions;

  . availability and cost of material and equipment;

  . delays in anticipated start-up dates;

  . actions or inactions of third-party operators of the Company's
    properties;

  . the ability to find and retain skilled personnel;

  . availability of capital;

  . the strength and financial resources of competitors;

  . regulatory developments;

  . environmental risks; and

  . general economic conditions.

   Any of the factors listed above and other factors contained in this Form
10-KSB could cause the Company's actual results to differ materially from the
results implied by these or any other forward-looking statements made by the
Company or on its behalf. The Company cannot assure you that future results
will meet its expectations.

                                       3
<PAGE>

                                    PART I

Item 1. Business

Background

   3TEC Energy Corporation ("3TEC", "the Company", "we", "our" and "us") is
the successor to Middle Bay Oil Company, Inc. ("Middle Bay"), an Alabama
corporation formed on November 30, 1992. 3TEC was incorporated in Delaware on
November 24, 1999, as a wholly owned subsidiary of Middle Bay for the sole
purpose of merging with Middle Bay to effect a change in domicile to Delaware
and to change our name to 3TEC Energy Corporation. Effective December 7, 1999,
Middle Bay was merged into us and each share of common stock of Middle Bay was
converted into one share of our common stock. Our common stock is quoted on
the Nasdaq National Market under the symbol "TTEN".

   We are engaged in the acquisition, development, production and exploration
of oil and natural gas reserves. Our properties are concentrated in East Texas
and the Gulf Coast region, both onshore and in the shallow waters of the Gulf
of Mexico. As of December 31, 2001, we had estimated total net proved reserves
of 263 Bcfe, of which approximately 88% were natural gas and approximately 204
Bcfe, or 77%, were proved developed, with an estimated SEC Case PV-10 value of
$212 million. We exited 2001 at a net daily production rate of approximately
85 Mmcfe.

   We have increased our reserves and production principally through
acquisitions. We focus on properties that have a substantial proved reserve
component and which management believes to have additional exploitation
opportunities. Additionally, we have also acquired a number of drilling
prospects covered by an extensive 3-D seismic database that we believe have
exploration potential. We have assembled an experienced management team and
technical staff with expertise in property acquisitions and development,
reservoir engineering, exploration and financial management.

   In August 1999, W/E Energy Company L.L.C. ("W/E LLC"), an entity which was
owned by affiliates of EnCap Investments L.L.C. ("EnCap") and Floyd C. Wilson,
purchased a controlling interest in us for approximately $20.5 million in cash
and $875,000 in producing properties. Concurrently with the investment by W/E
LLC, Mr. Wilson was named our Chairman and Chief Executive Officer. Following
the change in control in August 1999 discussed below, during the fourth
quarter of 1999 and the first half of 2000 we closed several transactions that
changed our senior management team, capital structure and our property base.
During the fourth quarter of 2001, W/E LLC was dissolved and its holdings of
3TEC common stock and warrants were distributed to its members. See discussion
in Note 3 of the Company's notes to consolidated financial statements.

   On June 30, 2000, the Company completed a public offering of 8.05 million
shares of the Company's common stock priced at $9.00 per share. The net
proceeds, approximately $66.6 million, were used primarily to repay a portion
of the outstanding debt under the Company's Credit Facility, hereafter
defined.

Recent Developments


  . On December 31, 2001, the shareholders of Enex Resources Corporation
    ("Enex") voted to approve the merger of Enex with a wholly-owned
    subsidiary of the Company. Each share of Enex common stock (other than
    shares owned by 3TEC) was converted into the right to receive $14.00 per
    share in cash. 3TEC owned 80% of the outstanding common stock of Enex. A
    cash payment of approximately $3.8 million was made by the Company to the
    Enex shareholders.

  . During 2001, the Company sent notices of an election to prepay to the
    holders or received notice of an election to convert the Company's $13.2
    million senior subordinated convertible notes. Pursuant to the terms of
    the convertible note agreements, the holders exercised their rights to
    convert the principal and accrued interest outstanding into common shares
    of the Company. Under the terms of the convertible

                                       4
<PAGE>

    note agreements, the balance of the note plus any accrued interest was to
    be converted at $9.00 per share. The conversion by the holders resulted
    in the retirement of the $13.2 million in senior subordinated debt and
    the issuance of an additional 1,487,806 shares of common stock of the
    Company.

  . During 2001, the Company completed the sale of certain non-strategic oil
    and gas properties for net cash proceeds of approximately $36.7 million.
    In order to defer the tax gain on the sales of certain properties, the
    Company successfully replaced a portion of these properties in accordance
    with the Like-Kind Exchange regulations of the Internal Revenue Service.
    At December 31, 2001, the Company had $13.9 million of cash in like-kind
    escrow accounts. In January 2002, the like-kind replacement term expired
    in accordance with the Internal Revenue Service regulations and the
    balance of the escrow accounts were used to reduce borrowings under the
    Company's Credit Facility.

  . On January 30, 2001, the Company acquired 100% of the issued and
    outstanding stock of Classic Resources Inc. ("Classic Acquisition") for
    cash consideration of approximately $53.5 million plus other acquisition
    costs. Classic was a privately-held exploration and production company
    with properties located in East Texas. The Company's estimate of total
    net proved reserves at the time of the acquisition for Classic's oil and
    gas properties was 47 Bcfe and net daily production of approximately 11
    Mmcfe. The Company financed the acquisition under its existing Credit
    Facility.

Business Strategy

   Our business strategy is focused on the following:

  . Pursuit of Strategic Acquisitions. We continually review opportunities to
    acquire producing properties, leasehold acreage and drilling prospects.
    We seek to acquire operational control of properties that we believe have
    significant exploitation and exploration potential. We are especially
    focused on increasing our holdings in fields and basins in which we
    already own an interest.

  . Further Development of Existing Properties. We intend to further develop
    our properties that have proved reserves. We seek to add proved reserves
    and increase production through the use of advanced technologies,
    including detailed technical analysis of our properties, and by drilling
    in-fill locations and selectively recompleting existing wells. We also
    plan to drill step-out wells to expand known field limits. We intend to
    enhance the efficiency and quality control of these activities by
    operating the majority of our properties.

  . Growth Through Exploration. We conduct an active technology-driven
    exploration program that is designed to complement our property
    acquisition and development drilling efforts with moderate to high risk
    exploration projects that have greater reserve potential. We generate
    exploration prospects through the analysis of geological and geophysical
    data and the interpretation of 3-D seismic data. We intend to manage our
    exploration expenditures through the optimal scheduling of our drilling
    program and by selectively reducing our participation in certain
    exploratory prospects through sales of interests to industry partners.

  . Rationalization of Property Portfolio. We intend to actively pursue
    opportunities to reduce and control operating costs of our existing
    properties and properties we may acquire in the future through the
    consolidation of overlapping operations, the sale of marginal properties
    and by increasing the number of fields we operate as a percentage of our
    total properties.

  . Maintenance of Financial Flexibility. We intend to maintain a substantial
    unused borrowing capacity under our bank Credit Facility by periodically
    refinancing our bank debt in the capital markets when conditions are
    favorable. We believe our expanded base of internally generated cash flow
    and other financial resources, including our existing financial partners,
    provide us with the financial flexibility to pursue additional
    acquisitions of producing properties and leasehold acreage and to develop
    our project inventory in an optimal fashion.

                                       5
<PAGE>

Marketing

   We have marketed the natural gas and oil produced from our properties
through typical channels for these products. We generally sell our oil at
local field prices paid by the principal purchasers of oil. The majority of
our natural gas production is sold at current market rates.

   Both natural gas and oil are purchased by marketing companies, pipelines,
major oil companies, public utilities, industrial customers and other users
and processors of petroleum products. We are not confined to, or dependent
upon, any one purchaser or small group of purchasers. Accordingly, the loss of
a single purchaser, or a few purchasers, would not have a long-term material
effect on our business because there are numerous purchasers in the areas in
which we sell our production.

   In order to manage our exposure to price risks in the marketing of our
natural gas and oil production, we have in the past and may in the future
enter into natural gas and oil price hedging arrangements with respect to a
portion of our expected production.

Competition

   We face competition from other oil and gas companies in all aspects of our
business, including acquisition of producing properties and oil and gas
leases, marketing of oil and gas, and obtaining goods, services and labor.
Many of our competitors have substantially larger financial and other
resources. Factors that affect our ability to acquire producing properties
include available funds, available information about the property and our
standards established for minimum projected return on investment. Competition
is also presented by alternative fuel sources, including heating oil and other
fossil fuels. We believe that we are competing and will compete effectively as
a result of our expertise in the acquisition, exploration, and development of
oil and gas reserves and our financial ability to take advantage of such
opportunities.

Regulation

   Federal Regulation of Transportation of Natural Gas. Historically, the
transportation and sale for resale of natural gas in interstate commerce have
been regulated by the Natural Gas Act of 1938, the Natural Gas Policy Act of
1978, and the regulations promulgated by the Federal Energy Regulatory
Commission. In the past, the federal government has regulated the prices at
which natural gas could be sold. Deregulation of natural gas sales by
producers began with the enactment of the Natural Gas Policy Act. In 1989,
Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all
remaining Natural Gas Act and Natural Gas Policy Act price and non-price
controls affecting producer sales of natural gas effective January 1, 1993.
Congress could, however, reenact price controls in the future.

   Our sales of natural gas are affected by the availability, terms and cost
of pipeline transportation. The price and terms for access to pipeline
transportation remain subject to extensive federal regulation. Beginning in
April 1992, the Federal Energy Regulatory Commission issued Order No. 636 and
a series of related orders, which required interstate pipelines to provide
open-access transportation on a basis that is equal for all natural gas
suppliers. The Federal Energy Regulatory Commission has stated that it intends
for Order No. 636 to foster increased competition within all phases of the
natural gas industry. Although Order No. 636 does not directly regulate our
production and marketing activities, it does affect how buyers and sellers
gain access to the necessary transportation facilities and how we and our
competitors sell natural gas in the marketplace. The courts have largely
affirmed the significant features of Order No. 636 and the numerous related
orders, although some appeals remain pending and the Federal Energy Regulatory
Commission continues to review and modify its regulations regarding the
transportation of natural gas. One broad and significant pending review
involves examination of several questions, including whether the
transportation regulations should be changed to better operate together with
changes in state law that are introducing competition in retail natural gas
markets, whether the historical method of setting transportation rates based
on cost should be changed for certain transportation, whether short term
transportation capacity should be allocated based only on auctions, and
whether additional changes need to be made to long term transportation
policies to prevent a market bias in favor of short term

                                       6
<PAGE>

transportation. We cannot predict what action the Federal Energy Regulatory
Commission will take on these matters, nor can we accurately predict whether
the Federal Energy Regulatory Commission's actions will achieve the goal of
increasing competition in markets in which our natural gas is sold. However,
we do not believe that any action taken will affect us in a way that
materially differs from the way it affects other oil and natural gas
producers.

   Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the Federal Energy Regulatory Commission
and the courts. The natural gas industry historically has been very heavily
regulated; therefore, we cannot assure you that the less stringent regulatory
approach recently pursued by the Federal Energy Regulatory Commission and
Congress will continue.

   Federal Regulation of Transportation of Oil. Oil and sales of oil,
condensate and natural gas liquids by us are not currently regulated and are
made at market prices. Effective as of January 1, 1995, the Federal Energy
Regulatory Commission implemented regulations establishing an indexing system
for transportation rates for interstate common carrier oil pipelines. These
rates are generally indexed to inflation, subject to conditions and
limitations. These regulations may, over time, tend to increase transportation
costs or reduce wellhead prices for oil. However, we do not believe that these
regulations affect us any differently than other oil and gas producers,
gatherers and marketers.

   State Regulation. Our oil and gas operations are subject to various types
of regulation at the state and local levels. These regulations require
drilling permits, regulate the methods for developing new fields and the
spacing and operating of wells and waste prevention, and sometimes impose
production limitations. These regulations may limit our production from wells
and the number of wells or locations we can drill.

   Some states have adopted regulations with respect to gathering systems.
These regulations have not had a material effect on the operation of our
gathering systems, but we cannot predict whether any future regulations in
this area may have a material impact on our gathering systems.

   Federal, State and Indian Leases. Our operations on federal, state or
Indian oil and gas leases are subject to numerous restrictions, including
nondiscrimination statutes. We must conduct our operations on these leases
pursuant to permits and authorization and other regulations issued by the
Bureau of Land Management, Minerals Management Service and other agencies. The
Minerals Management Service currently has under consideration a proposal to
change the manner in which crude oil is valued for purposes of calculating
royalty due the government. If adopted, these changes would decrease reliance
on historical valuation methods and instead adopt an indexing method intended
to better reflect market value, but which may not reflect the proceeds
actually received in the sale of the oil. We cannot predict what action the
Minerals Management Service may ultimately take or how it will affect royalty
payable on our production from federal leases, however, if adopted, the
changes may tend to increase costs of royalty payments.

   Environmental Regulations. Our operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Our exploration and production
operations and facilities for gathering, treating, processing and handling
hydrocarbons and related exploration and production wastes are subject to
stringent environmental regulation. These laws and regulations sometimes
require government approvals before activities occur, limit or prohibit
activities because of protected areas or species, impose substantial
liabilities for pollution and provide penalties for noncompliance. As with the
industry generally, compliance with existing and anticipated regulations
increases our overall cost of business. These regulations, however, generally
affect us and our competitors similarly. Environmental laws and regulations
are subject to frequent change, and we are not able to predict the costs or
other impacts of environmental regulation on our future operations.

   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 some classes of
persons that are considered to have contributed to the release or threat of
release of a "hazardous

                                       7
<PAGE>

substance" into the environment. These persons include the owner or operator
of the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances
released into the environment.

   Our operations are also subject to regulation of air emissions under the
Clean Air Act and comparable state and local requirements. Implementation of
these laws could lead to the gradual imposition of new air pollution control
requirements on our operations. As a result, we may incur capital expenditures
over the next several years to upgrade our air pollution control equipment. We
do not believe that our operations would be materially affected by any such
requirements, nor do we expect such requirements to be any more burdensome to
us than to other companies our size involved in natural gas and oil
exploration and production activities.

   In addition, legislation has been proposed in Congress from time to time
that would reclassify some natural gas and oil 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
Congress were to enact this legislation, it could increase our operating
costs, as well as those of the natural gas and oil industry in general.
Initiatives to further regulate the disposal of natural gas and oil wastes are
also pending in some states, and these various initiatives could have a
similar impact on us.

   The Clean Water Act imposes restrictions and controls on the discharge of
oil and gas wastes and other forms of pollutants into waters of the United
States. Federal law also imposes strict liability on owners of facilities for
consequences of an oil spill where the spill is in navigable waters or along
shorelines. These laws impose penalties for unauthorized discharges and
substantial liability for costs of removal and damages resulting from an
unauthorized discharge. State laws for the control of water pollution provide
similar penalties and liabilities. The cost of compliance with water pollution
laws has not historically been material to our operations. There can be no
assurance that changes in federal, state or local water pollution laws and
programs will not materially adversely affect our operations in the future.

   Our management believes that we are in substantial compliance with current
environmental laws and regulations that affect us and that continued
compliance with these requirements will not have a material adverse impact on
us.

Employees

   At December 31, 2001, we had 67 full-time employees. We believe that our
relationships with our employees are satisfactory. None of our employees are
covered by a collective bargaining agreement. From time to time, we use the
services of independent consultants and contractors to perform various
professional services, particularly in the areas of construction, design,
well-site surveillance, permitting and environmental assessment.

Our Executive Offices

   Our principal executive offices are located at 700 Milam Street, Suite
1100, Houston, Texas 77002, and our telephone number is 713.821.7100. Our
website is www.3tecenergy.com.

                                       8
<PAGE>

Item 2. Properties

Description of Our Properties

   We present information regarding our natural gas and oil reserves,
properties, and operating results below.

<TABLE>
<CAPTION>
                                               As of December 31, 2001
                         -------------------------------------------------------------------
                            Estimated Net Proved
                                  Reserves                  Percent   Proved      Budgeted
                         --------------------------  PV-10   Total  Undeveloped 2002 Capital
                           Gas      Oil      Total   Value   PV-10   Drilling   Expenditures
                         (Mmcf)  (MBbls)(1) (Mmcfe) ($000)   Value   Locations     ($000)
                         ------- ---------- ------- ------- ------- ----------- ------------
<S>                      <C>     <C>        <C>     <C>     <C>     <C>         <C>
East Texas.............. 150,934   1,322    158,866 110,546   52.1%     144        17,675
Gulf Coast Area.........  28,536   1,338     36,564  59,567   28.1%       2        13,170
South Texas.............  25,747       3     25,765  12,465    5.9%       7        15,774
Mid-Continent Area......  15,442     957     21,184  14,844    7.0%       2            --
Permian/San Juan Area...  10,607   1,700     20,807  14,033    6.6%      --            --
Other Areas.............      --      17        102     894    0.3%      --            --
                         -------   -----    ------- ------- -------     ---        ------
  Total................. 231,266   5,337    263,288 212,349 100.00%     155        46,619(2)
                         =======   =====    ======= ======= =======     ===        ======
</TABLE>
--------
(1) Includes oil, condensate and plant products barrels.
(2) As discussed in "Liquidity and Capital Resources" within Management's
    Discussion and Analysis, the Company's 2002 capital expenditure budget
    will range between $45-65 million and be dependant on the price of natural
    gas. The $46.6 million reflected in the table assumes a $2.50/Mmbtu
    average price for 2002. Natural gas prices in excess of $2.50/Mmbtu will
    allow the Company to expand its average capital expenditure program up to
    $65 million.

   East Texas. Our largest fields are located in the East Texas area. The
Rosewood, Glenwood, White Oak, Beckville, Carthage, East Henderson and Oak
Hill fields all produce from the Cotton Valley formation and have numerous
proved undeveloped drilling locations. Many of these development drilling
locations are based on a change in regulatory field rules that now permit
wells to be drilled on 80 acre spacing as opposed to 160 acre spacing. At
December 31, 2001 we have identified 144 proved undeveloped locations in this
area. For 2002, we have budgeted approximately $18 million for drilling of
development wells and exploitation activities in this area.

   Gulf Coast. We have established a substantial base of proved reserves and
undeveloped acreage with significant exploration potential along the Gulf
Coast of Texas and Louisiana. Through acquisitions, we acquired significant
interests in Breton Sound Block 34 in Louisiana state waters and the Garden
City and Bay de Chene fields in south Louisiana. During 2001, we participated
in one successful completion in the Breton Sound area, and at the end of the
year we were drilling ahead on exploratory wells in both Breton Sound and
Garden City. In 2002, we intend on drilling additional exploratory tests in
each of the previously mentioned three fields. Other significant fields in
south Louisiana include East Roanoke, Riceville and Raceland.

   Permian, San Juan and Mid-Continent Areas. We own interests in numerous
fields in the Anadarko, Permian, San Juan and Arkoma basins, Oklahoma, Texas
and New Mexico. Our largest fields in these areas are Puerto Chiquito and
Basin in the San Juan basin, and West Stigler in eastern Oklahoma. In 2002, we
have not budgeted any capital for development drilling and exploitation
activities in these areas.

   South Texas. In South Texas, we are active in two main areas, the Stuart
City field in the Edwards Reef Trend and the Segundo field in Webb County,
Texas. In 2002, we have budgeted approximately $16 million for development and
exploration drilling in this area.

                                       9
<PAGE>

Natural Gas and Oil Reserves

   The following table presents our estimated net proved natural gas and oil
reserves and the PV-10 value of our reserves as of December 31, 2001, 2000,
and 1999. The period end prices of oil and natural gas at December 31, 2001,
2000, and 1999, used in the PV-10 calculation were $19.84, $25.31 and $23.64
per barrel of oil and $2.57, $9.40 and $2.23 per thousand cubic feet of
natural gas, respectively. Our estimated net proved natural gas and oil
reserves and the PV-10 value of our reserves as of December 31, 2001, 2000,
and 1999, are based on a reserve report prepared by Ryder Scott Company for
our properties. The PV-10 values shown in the table are not intended to
represent the current market value of the estimated natural gas and oil
reserves we own. For further information concerning the PV-10 values of these
proved reserves, please read note 16 of the notes to our December 31, 2001
consolidated financial statements.

<TABLE>
<CAPTION>
                                                          December 31
                                                  ----------------------------
                                                    2001      2000      1999
                                                  -------- ---------- --------
   <S>                                            <C>      <C>        <C>
   Proved Reserves:
     Natural gas (Mmcf)..........................  231,266    237,693  159,699
     Oil (MBbls)(1)..............................    5,337     10,672    9,835
     Natural gas equivalents (Mmcfe).............  263,288    301,725  218,709

   Proved Developed Reserves:
     Natural gas (Mmcf)..........................  175,659    177,252  122,914
     Oil (MBbls)(1)..............................    4,705      9,895    9,358
     Natural gas equivalents (Mmcfe).............  203,889    236,622  179,062
     Estimated future net cash flows before
      income taxes, (in thousands)............... $385,335 $1,996,831 $370,258
     PV-10 value, (in thousands)................. $212,349 $1,047,364 $198,615
</TABLE>
--------
(1) Includes oil, condensate and plant product barrels

   There are numerous uncertainties in estimating quantities of proved
reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond our control. The
reserve data herein are only estimates. Although we believe these estimates to
be reasonable, reserve estimates are imprecise and may be expected to change
as additional information becomes available. Estimates of oil and natural gas
reserves, of necessity, are projections based on engineering data, and there
are uncertainties inherent in the interpretation of this data, as well as the
projection of future rates of production and the timing of development
expenditures. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be exactly
measured. Therefore, estimates of the economically recoverable quantities of
oil and natural gas attributable to any particular group of properties,
classifications of the reserves based on risk of recovery and the estimates
are a function of the quality of available data and of engineering and
geological interpretation and judgment and the future net cash flows expected
therefrom, prepared by different engineers or by the same engineers at
different times, may vary substantially. There also can be no assurance that
the reserves set forth herein will ultimately be produced or that the proved
undeveloped reserves will be developed within the periods anticipated. Actual
production, revenues and expenditures with respect to our reserves will likely
vary from estimates, and the variances may be material. In addition, the
estimates of future net revenues from our proved reserves and the present
value thereof are based upon certain assumptions about future production
levels, prices and costs that may not be correct. We emphasize with respect to
the estimates prepared by independent petroleum engineers that PV-10 value
should not be construed as representative of the fair market value of our
proved oil and natural gas properties since discounted future net cash flows
are based upon projected cash flows which do not provide for changes in oil
and natural gas prices or for escalation of expenses and capital costs. The
meaningfulness of such estimates is highly dependent upon the accuracy of the
assumptions upon which they are based. Actual future prices and costs may
differ materially from those estimated.

                                      10
<PAGE>

Volumes, Prices and Operating Expenses

   The following table presents information regarding the production volumes
of, average sales prices received for, and average production costs associated
with, our sales of oil and natural gas for the periods indicated.

<TABLE>
<CAPTION>
                                                          Years Ended
                                                         December 31,
                                                      -------------------------
                                                       2001      2000     1999
                                                      ------    ------    -----
   <S>                                                <C>       <C>       <C>
   Net Production Data:
     Natural gas (Mmcf).............................. 22,352    17,764    4,738
     Oil (MBbls).....................................    952     1,139      532
     Natural gas equivalents (Mmcfe)................. 28,065    24,598    7,930
   Average Sale Prices:
     Natural gas ($ per Mcf) (1)..................... $ 4.15(1) $ 4.12    $2.18
     Oil ($ per Bbl).................................  23.95     25.11(2) 16.88
     Natural gas equivalents ($ per Mcfe)............   4.12      4.20(2)  2.53
   Expenses: ($ per Mcfe)
     Lease operations................................ $ 0.60    $ 0.62    $0.80
     Production, severance and ad valorem taxes...... $ 0.27    $ 0.27    $0.17
     Gathering, transportation and other............. $ 0.14    $ 0.09    $0.02
     General and administrative...................... $ 0.25    $ 0.25    $0.52
     Depreciation, depletion and amortization........ $ 1.10    $ 0.80    $0.84
</TABLE>
--------
(1) Does not include the effect of our derivatives activities, which was
    approximately $162,000 of cash settlements during 2001.
(2) Includes the effect of our hedging activities.

Development, Exploration and Acquisition Capital Expenditures

   The following table presents information regarding our net costs incurred
in the purchase of properties and in exploration and development activities.

<TABLE>
<CAPTION>
                                        Years Ended December 31,
                                        ----------------------------
                                          2001        2000    1999
                                        --------    -------- -------
                                                   (in thousands)
<S>                                     <C>         <C>      <C>     <C> <C> <C>
Acquisition............................   84,325(1) $ 79,865 $91,424
Exploration............................   19,731         695     824
Development............................   63,358      25,346   2,154
                                        --------    -------- -------
  Total costs incurred................. $167,414    $105,906 $94,402
                                        ========    ======== =======
</TABLE>
--------
(1) Excludes approximately $29 million of deferred taxes recorded in
    connection with the Classic Acquisition.

                                      11
<PAGE>

Drilling Activity

   The following table shows our drilling activity for the years ended
December 31, 2001, 2000 and 1999. In the table, "gross" refers to the total
wells in which we have a working interest and "net" refers to gross wells
multiplied by our working interest in these wells.

<TABLE>
<CAPTION>
                                                   Year Ended December 31,
                                              ----------------------------------
                                                 2001        2000        1999
                                              ----------- ----------- ----------
                                              Gross  Net  Gross  Net  Gross Net
                                              ----- ----- ----- ----- ----- ----
   <S>                                        <C>   <C>   <C>   <C>   <C>   <C>
   Exploration Wells:
     Productive..............................    4   2.52   --     --   --    --
     Non-Productive..........................    5   1.93   --     --    5  0.90
                                               ---  -----  ---  -----  ---  ----
       Total.................................    9   4.45   --     --    5  0.90
                                               ===  =====  ===  =====  ===  ====
   Development Wells:
     Productive..............................   71  26.80   66  18.30   21  5.67
     Non-Productive..........................    2   1.30   --     --   --    --
                                               ---  -----  ---  -----  ---  ----
       Total.................................   73  28.10   66  18.30   21  5.67
                                               ===  =====  ===  =====  ===  ====
</TABLE>

Productive Wells

   The following table sets forth the number of productive natural gas and oil
wells in which we owned a working interest as of December 31, 2001.

<TABLE>
<CAPTION>
                                                                     Total
                                                               Productive Wells
                                                               -----------------
                                                                 Gross     Net
                                                               --------- -------
      <S>                                                      <C>       <C>
      Natural Gas.............................................       870     393
      Oil.....................................................       131      61
                                                               --------- -------
        Total.................................................     1,001     454
                                                               ========= =======
</TABLE>

   Productive wells consist of producing wells and wells capable of
production, including natural gas wells awaiting pipeline connections to
commence deliveries and oil wells awaiting connection to production
facilities. Additionally, the Company owns a royalty interest in 177 wells and
an overriding royalty interest in 826 wells. At December 31, 2001, we operated
approximately 344 wells.

Acreage Data

   The following table presents information regarding our developed and
undeveloped leasehold acreage as of December 31, 2001. Developed acreage
refers to acreage within producing units and undeveloped acreage refers to
acreage that has not been placed in producing units.

<TABLE>
<CAPTION>
                                      Developed     Undeveloped
                                       Acreage        Acreage         Total
                                   --------------- ------------- ---------------
                                    Gross    Net   Gross   Net    Gross    Net
                                   ------- ------- ------ ------ ------- -------
   <S>                             <C>     <C>     <C>    <C>    <C>     <C>
   Texas.......................... 130,720  63,767 17,089  7,150 147,809  70,917
   Louisiana......................  24,966   9,526 15,747  6,825  40,713  16,352
   Oklahoma.......................  23,764   8,947  1,040    865  24,804   9,812
   Other..........................  81,770  31,969  1,307    776  83,077  32,745
                                   ------- ------- ------ ------ ------- -------
     Total........................ 261,220 114,209 35,183 15,616 296,404 129,825
                                   ======= ======= ====== ====== ======= =======
</TABLE>

   Excluded from the acreage data are approximately 33,495 net mineral acres
owned by us, primarily in La Fourche, St. Mary and Terrebonne parishes of
Louisiana, all of which we believe have potential for oil and natural gas
exploration.

                                      12
<PAGE>

Current Activities

   As of March 8, 2002, 4 wells (1.4 net wells) were being drilled. Three
wells are in Texas and one is in Louisiana.

Item 3. Legal Proceedings

   From time to time, we are party to various routine litigation proceedings
incidental to our business. We currently are not a party to any material
litigation.

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

   None.

                                    PART II

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

Market Information

   Our common stock is currently quoted on the Nasdaq National Market under
the market symbol "TTEN."

   The following table sets forth the high and low closing prices per share of
our common stock for the periods indicated on the Nasdaq National Market.

<TABLE>
<CAPTION>
   Period                                                           High   Low
   ------                                                          ------ ------
   <S>                                                             <C>    <C>
   2001
    First Quarter................................................. $18.63 $15.69
    Second Quarter................................................ $20.40 $14.88
    Third Quarter................................................. $17.30 $12.27
    Fourth Quarter................................................ $15.10 $13.20

   2000
    First Quarter................................................. $11.44 $ 6.38
    Second Quarter................................................  13.50   7.00
    Third Quarter.................................................  17.25   9.63
    Fourth Quarter................................................  19.13  13.38
</TABLE>

   On March 7, 2002 the last reported sales price of our common stock on the
Nasdaq National Market was $17.70 per share.

   On March 7, 2002 there were 909 holders of record of our common stock.

   Our transfer agent is American Stock Transfer and Trust Company located at
59 Maiden Lane, New York, New York 10038. You may call them toll free at
800.937.5449 to answer any questions about transferring your stock.

   We have never declared or paid any cash dividends on our common stock. We
currently intend to retain future earnings, if any, for the operation and
development of our business and do not anticipate paying any cash dividends on
our common stock in the foreseeable future. In addition, our Credit Facility
prohibits us from paying cash dividends on our common stock. Any future
dividends are also restricted by the terms of our outstanding preferred stock
and may be restricted by any debt agreements which we may enter into from time
to time.

                                      13
<PAGE>

   We are obligated to pay net cash dividends in the amount of approximately
$740,000 per year on our Series D Preferred Stock which may be paid, at our
option, in cash or in additional shares of Series D Preferred Stock during the
three years ending February 1, 2003. Our Credit Facility permits the payment
of dividends on our Series D Preferred Stock.

Item 6. Management's Discussion and Analysis of Financial Condition and
Results of Operations

   You should read the following discussion and analysis in conjunction with
our audited consolidated financial statements. The following information
contains forward-looking statements. See "Cautionary Statement About Forward
Looking Statements".

 Overview

   We are engaged in the acquisition, development, production and exploration
of oil and natural gas reserves. Our properties are concentrated in East Texas
and the Gulf Coast region, both onshore and in the shallow waters of the Gulf
of Mexico. As of December 31, 2001, we had estimated total net proved reserves
of 263 Bcfe, of which approximately 88% were natural gas and approximately 204
Bcfe, or 77%, were proved developed, with an estimated SEC case PV-10 value of
$212 million. We exited 2001 at a net daily production rate of approximately
85 Mmcfe.

   We have increased our reserves and production principally through
acquisitions. We focus on properties that have a substantial proved reserve
component and which management believes to have additional exploitation
opportunities. Recently, we have also acquired a number of drilling prospects
covered by an extensive 3-D seismic database that we believe have exploration
potential. We have assembled an experienced management team and technical
staff with expertise in property acquisitions and development, reservoir
engineering, exploration and financial management.

 Description Of Critical Accounting Policies

   Oil and Natural Gas Properties. We utilize the successful efforts method of
accounting for our oil and natural gas properties. Under this method, all
development and acquisition costs of proved properties are capitalized and
amortized on a unit-of-production basis over the remaining life of proved
developed reserves or proved reserves, as applicable. Exploration expenses,
including geological and geophysical expenses and delay rentals, are charged
to expense as incurred. Costs of drilling exploratory wells are initially
capitalized, but charged to expense if and when the well is determined to be
unsuccessful. Expenditures for repairs and maintenance to sustain or increase
production from the existing producing reservoir are charged to expense as
incurred. Expenditures to recomplete a current well in a different or
additional proven or unproven reservoir are capitalized pending determination
that economic reserves have been added. If the recompletion to an unproven
reservoir is not successful, the expenditures are charged to expense.
Expenditures for redrilling or directional drilling in a previously abandoned
well are classified as drilling costs to a proven or unproven reservoir for
determination of capital or expense. Significant tangible equipment added or
replaced is capitalized. Expenditures to construct facilities or increase the
productive capacity from existing reserves are capitalized. Internal costs
directly associated with the development and exploitation of properties are
capitalized as a cost of the property and are classified accordingly in the
Company's financial statements. Crude Oil volumes are converted to equivalent
Mcf's at the rate of one barrel to six Mcf.

   The Company is required to assess the need for an impairment of capitalized
costs of oil and natural gas properties and other long-lived assets whenever
events or circumstances indicate that the carrying value of those assets may
not be recoverable. If impairment is indicated based on a comparison of the
asset's carrying value to its undiscounted expected future net cash flows,
then it is recognized to the extent that the carrying value exceeds fair
value. Any impairment charge incurred is recorded in accumulated depletion,
depreciation, and amortization ("DD&A") to reduce our recorded basis in the
asset. Each part of this calculation is subject to a large degree of
management judgment, including the determination of property's reserves,
future cash flows, and fair value.

                                      14
<PAGE>

   Management's assumptions used in calculating oil and natural gas reserves
or regarding the future cash flows or fair value of our properties are subject
to change in the future. Any change could cause impairment expense to be
recorded, reducing our net income and our basis in the related asset. Future
prices received for production and future production costs may vary, perhaps
significantly, from the prices and costs assumed for purposes of calculating
reserve estimates. There can be no assurance that the proved reserves will be
developed within the periods estimated or that prices and costs will remain
constant. Actual production may not equal the estimated amounts used in the
preparation of reserve projections. As these estimates change, the amount of
calculated reserves change. Any change in reserves directly impacts our
estimate of future cash flows from the property, as well as the property's
fair value. Additionally, as management's views related to future prices
change, this changes the calculation of future net cash flows and also affects
fair value estimates. Changes in either of these amounts will directly impact
the calculation of impairment.

   DD&A expense is also directly affected by the Company's reserve estimates.
Any change in reserves directly impacts the amount of DD&A expense the Company
recognizes in a given period. Assuming no other changes, such as an increase
in depreciable base, as the Company's reserves increase, the amount of DD&A
expense in a given period decreases and vice versa. Changes in future
commodity prices would likely result in increases or decreases in estimated
recoverable reserves.

   The Company also uses estimates to record its accrual for oil and natural
gas revenues. The volume portion of the accrual of revenue for a given period
is based upon field production reports (both operated and non-operated),
estimates of production added via drilling or acquisitions, historical
production averages and natural production declines of the Company's
properties. The price component of the Company's accrual for revenue
incorporates historical averages of the Company's sales as compared to the
monthly closing NYMEX price for natural gas and the West Texas Intermediate
index price for crude oil.

   Several factors can impact the Company's ability to estimate its production
volume such as the fact that a significant portion of the Company's production
is operated by third parties. Reliance on accurate and timely data from the
operators of these properties can change the actual amounts of production for
which the Company receives payment. Additionally, production meters that are
manually read can be different than the volume metered at the Company's sales
points.

   Both the Company's estimate of sold volumes and the estimate of the price
received for these sales is adjusted on an on-going basis as the Company
receives payment for the accrued volumes. Changes in the estimates of the
accrual are adjusted for in the subsequent periods as payment is received or
additional supporting data is obtained.

   Bad Debt Expense. The Company routinely assesses the recoverability of all
material trade and other receivables to determine their collectibility. The
Company historically has not required collateral or other performance
guarantees from creditworthy counterparties. Many of our receivables are from
joint interest owners on property of which we are the operator. Thus, we may
have the ability to withhold future revenue disbursements to cover any non-
payment of joint interest billings. Our oil and natural gas receivables
quickly turnover, usually one month for oil and two months for gas; thus,
signaling any problem accounts in a timely manner. Counterparties to our
derivative commodity contracts are routinely reviewed for creditworthiness to
determine the realizability of any related derivative assets we might carry on
our books. This review of receivables and counterparties is heavily dependent
on the judgment of management. If it is determined that the carrying value of
a receivable or financial instrument might not be recoverable, we record an
allowance to the extent we believe the receivable or asset is not recoverable.
The determination as to what extent a receivable or asset might be impaired is
also heavily dependent on the judgment of management. As more information
becomes known related to a particular counterparty or customer, management
will continually reassess previous judgments and any resulting change in the
related allowance could have a material positive or negative effect on our
financial position and results of operations in the period of the change.

                                      15
<PAGE>

   Derivative Activities. We use various financial instruments in the normal
course of our business to manage and reduce price volatility and other market
risks associated with our crude oil and natural gas production. This activity
is referred to as risk management. These arrangements are structured to reduce
our exposure to commodity price decreases, but they can also limit the benefit
we might otherwise receive from commodity price increases. Our risk management
activity is generally accomplished through over-the-counter forward derivative
contracts executed with large financial institutions.

   Effective January 1, 2001, the Company adopted Statement of Financial
Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative
Instruments and Hedging Activities". This standard requires us to recognize
all of our derivative and hedging instruments in our consolidated balance
sheets as either assets or liabilities and measure them at fair value. If a
derivative does not qualify for hedge accounting, it must be adjusted to fair
value through earnings. However, if a derivative does qualify for hedge
accounting, depending on the nature of the hedge, changes in fair value can be
offset against the change in fair value of the hedged item through earnings or
recognized in other comprehensive income until such time as the hedged item is
recognized in earnings.

   To qualify for cash flow hedge accounting, the cash flows from the hedging
instrument must be highly effective in offsetting changes in cash flows due to
changes in the underlying items being hedged. In addition, all hedging
relationships must be designated, documented, and reassesed periodically. The
Company's natural gas derivative financial instruments were not designated as
hedges at the time the instruments were executed. According to the provisions
of SFAS 133, these instruments are marked-to-market through earnings each
period.

 Liquidity and Capital Resources

   Cash Flow. We believe that our cash flows from operations are adequate to
meet the requirements of operating our business. However, future cash flows
are subject to a number of variables, including our level of production and
prices, and we cannot assure you that operations and other capital resources
will provide cash in sufficient amounts to maintain planned levels of capital
expenditures. Our principal operating sources of cash include sales of natural
gas and oil.

   Our earnings before interest, taxes, minority interest, depletion and
exploration (impairment, dry hole and geological and geophysical) ("EBITDAX")
for the years ended December 31, 2001 and 2000, were $75.8 million and $74.4
million, respectively. For the year 2002, we have budgeted approximately $45-
65 million for capital expenditures depending on the price of natural gas and
drilling costs in 2002. The low-end of the range is based on an average
natural gas price of $2.50/Mmbtu. Pricing increases to $3.00/Mmbtu and above
will move the Company's capital expenditures into the higher end of the range.
We are obligated to pay dividends of approximately $740,000 per year on the
Series D Preferred Stock which we may pay in either cash or in additional
shares of Series D Preferred Stock during the three years ending February 1,
2003.

   Our activities in 2001 have been financed through operating cash flow and
bank borrowings. Our primary source of financing for acquisitions has been
borrowing under our Credit Facility described below.

   We believe we will have sufficient cash flow from operations and borrowings
under our Credit Facility to meet our obligations and operating needs for the
coming year. However, future cash flows are subject to a number of variables,
including our level of production and prices, and we cannot assure you that
operations and other capital resources will provide cash in sufficient amounts
to maintain planned levels of capital expenditures.

   Credit Facility. The Company has in place a $250 million credit facility
(the "Credit Facility") with Bank One, NA as agent and seven other banks. The
Credit Facility, as amended, matures May 31, 2003. On March 7, 2002, the
Company's borrowing base under its Credit Facility was set at $145 million.
The borrowing base is to be redetermined semi-annually on May 1 and November 1
and provides for interest as revised under the Credit Facility to accrue at a
rate calculated at the Company's option as either the bank's prime rate plus a
low of zero to a high of 50 basis points or LIBOR plus basis points increasing
from a low of 150 to a high of 212.5 as loans outstanding increase as a
percentage of the borrowing base. As of December 31, 2001, the borrowing base
was

                                      16
<PAGE>

set at $145 million. As of December 31, 2001, the Company was paying an
average of 3.68% per annum interest on the principal balance of $108 million
under the Credit Facility. Prior to maturity, no payments of principal are
required so long as the borrowing base exceeds the loan balance. The
borrowings under the Credit Facility are secured by substantially all of the
Company's oil and natural gas properties. At December 31, 2001, the amount
available to be borrowed under the Credit Facility was approximately $37
million. At December 31, 2001, the Company had approximately $13.9 million in
cash held in like-kind exchange escrow accounts. During January, 2002, the
Company repaid borrowings under the Credit Facility with the escrow funds. At
March 7, 2002, borrowings under the Credit Facility totaled $97 million.

   In connection with the Credit Facility we are required to adhere to certain
affirmative and negative covenants. The loan agreement contains a number of
dividend restrictions and restrictive covenants which, among other things,
require the maintenance of minimum current and interest coverage ratios.

   The following table illustrates the Company's contractual obligations
outstanding at December 31, 2001:

<TABLE>
<CAPTION>
                                                   Payments Due By Period
                                            ------------------------------------
      Contractual Obligations        Total  2002  2003-2004 2005-2006 Thereafter
      -----------------------       ------- ----- --------- --------- ----------
                                                   (in thousands)
<S>                                 <C>     <C>   <C>       <C>       <C>
Long-term debt..................... 108,000    --  108,000       --        --
Operating leases...................   7,298 1,142    2,650    1,737     1,769
                                    ------- -----  -------    -----     -----
  Totals........................... 115,298 1,142  110,650    1,737     1,769
                                    ======= =====  =======    =====     =====
</TABLE>

   Market Risk. We generally sell our oil at local field prices paid by the
principal purchasers of oil. The majority of our natural gas production is
sold at spot prices. Accordingly, we are generally subject to the commodity
prices for these resources as they vary from time to time.

   Inflation and Changes in Prices. Our revenues and the value of our oil and
gas properties have been and will be affected by changes in natural gas and
crude oil prices. Our ability to maintain current borrowing capacity and to
obtain additional capital on attractive terms is also substantially dependent
on natural gas and crude oil prices. These prices are subject to significant
seasonal and other fluctuations that are beyond our ability to control or
predict. During 2001, we received an average of $23.95 per barrel of crude oil
and $4.15 per Mcf of gas. Costs and expenses are affected by the level of
inflation, which has had a significant effect in 2001. Should current
conditions in the industry be sustained, increased competition resulting in a
relative shortage of oilfield supplies and/or services, inflationary cost
pressures may continue.

 Results of Operations

   Our revenue, profitability, and future rate of growth are dependent upon
prevailing prices for oil and gas, which, in turn, depend upon numerous
factors such as economic, political, and regulatory developments as well as
competition from other sources of energy. The energy markets historically have
been highly volatile, and future decreases in prices could have an adverse
effect on our financial position, results of operations, quantities of
reserves that may be economically produced, and access to capital.

   You should read the following discussion and analysis together with our
audited consolidated financial statements and the related notes for the fiscal
years ended December 31, 2001 and 2000.

 2001 Compared With 2000

   Revenue. Total revenue for the year ended December 31, 2001 was $122.8
million, an increase of $18.0 million (17%) over total revenue for 2000 of
$104.8 million. Oil, natural gas and plant income revenues for the 2001 period
were $117.9 million compared to $103.2 million in 2000, an increase of $14.7
million (14%). Realized prices for the Company's production was $4.12/Mcfe in
2001 compared to $4.20/Mcfe in 2000, while production volumes increased to
28,065 Mmcfe in 2001 compared to 24,598 Mmcfe in 2000. Realized price
increases for 2001 and 2000 were reflective of the continued strong commodity
price environment in the industry. Comparability of the Company's revenues and
volumes were both driven by an significant drilling program in

                                      17
<PAGE>

2001 and 2000 and the acquisitions of Magellan Properties in February 2000,
the CWR Properties in May 2000 and the Classic Properties in January 2001,
offset by the 2001 property divestments which were all significant
contributors to the year over year increases.

   Gain on Sale of Properties and Other Revenue. In 2001 vs. 2000, property
divestments resulted in the recognition of gains of $0.8 million and $0.8
million, respectively. The Company continues to actively review and manage its
property portfolio for divestiture of non-strategic properties. Other revenues
in 2001 were $1.0 million compared to $0.8 in 2000. Other revenue consists
primarily of interest, delay rental and lease bonus income.

   Gain on Derivative Fair Value. During the fourth quarter of 2001, the
Company entered into certain derivative transactions that were not designated
as hedges and therefore are required under generally accepted accounting
principals to be "marked-to-market." At December 31, 2001, these contracts had
a fair market value of $3.1 million. See further discussion in Note 13 of the
Company's Notes to Consolidated Financial Statements.

   Expenses. Total expenses for the year ended December 31, 2001 were $94.8
million, an increase of $36.4 million (62%) from total expenses in 2000 of
$58.4 million. Comparability of total expenses was impacted by the increase in
dry hole and impairment expenses, surrendered and expired acreage and the
increase in depreciation, depletion and amortization. On a per Mcfe basis, the
Company's lease operating expenses decreased by 3% to $0.60 in 2001 from $0.62
in 2000. Production, severance and ad valorem tax was flat at $0.27/Mcfe in
2001 vs. $0.27/Mcfe in 2000. General and administrative expense was $0.25/Mcfe
in 2001 compared to $0.25/Mcfe in 2000, interest expense $0.24/Mcfe vs.
$0.31/Mcfe in 2000, and DD&A $1.10/Mcfe in 2001 compared to $0.80/Mcfe in
2000. Lease operating expenses on a unit basis were impacted by the Company's
Classic Acquisition and 2001 divestiture program. The properties in the
Classic Acquisition were natural gas wells with lower lease operating costs as
compared to the divested properties that had higher lease operating costs
which were primarily oil producers.

   Production, severance and ad valorem taxes were comparable year over year
as expected with average sales prices on an mcfe basis being $4.12/Mcfe in
2001 vs. $4.20/Mcfe in 2000.

   The increase on a per unit basis to depreciation, depletion and
amortization ("DD&A") is attributed to the Classic Acquisition and the
Company's developmental drilling program. As the Company acquired the stock of
Classic Resources, Inc., the historical tax basis of the Classic Acquisition
properties were carried over to the Company's books. A corresponding deferred
tax liability was recorded in the Company's purchase price allocation for the
difference between the allocated value and the historical tax basis. This
"gross-up" to record the deferred tax liability, resulted in approximately $29
million being added to the depletable book basis of the Classic Acquisition
properties. The Company's development drilling activities during 2001 also
contributed to the increase in the Company's DD&A rate in 2001 due to a
majority of the proved undeveloped reserves associated with these capitalized
costs associated having been already included in the Company's December 31,
2000 reserve report estimate. Thus, additional costs were added to a
relatively static reserve figure, thereby increasing the per unit rate.

   Income Taxes. The Company recorded a $10.6 million income tax provision
during 2001 as compared to a $14.4 million income tax provision for 2000. The
results from the Company's operations generated pre-tax income of $28.0
million during 2001 vs. a pre-tax income of $46.4 million in 2000. During
2001, the Company's effective tax rate was approximately 38%. In 2001, the
Company expects to pay approximately $1.6 million in current taxes. The
Company paid $7.9 million in taxes for 2000.

   Net Income. The Company's 2001 net income of $16.8 million is compared to
$31.7 million in 2000.

   Dividends to Preferred Shareholders. Dividends to preferred shareholders of
$0.7 million in 2001 is a $0.8 million decrease (53%) over 2000 dividends of
$1.5 million. The Company redeemed its Series C preferred stock in September,
2000 and recognized a non-cash charge to dividend expense of $0.5 million in
2000.

                                      18
<PAGE>

 2000 Compared With 1999

   Revenue. Total revenue for the year ended December 31, 2000 was $104.8
million, an increase of $82.6 million (372%) over total revenue for 1999 of
$22.2 million. Oil, natural gas and plant income revenues for the 2000 period
were $103.2 million compared to $20.0 million in 1999, an increase of $83.2
million (416%). Realized prices for the Company's production was $4.20/Mcfe in
2000 compared to $2.43/Mcfe in 1999, while production volumes increased to
24,598 Mmcfe in 2000 compared to 7,930 Mmcfe in 1999. Realized price increases
for 2000 over 1999 were reflective of the strong commodity price environment in
the industry, while being only minimally impacted by the Company's hedging
activities in both years ($2.1 million loss in 2000 on oil hedging, and $0.2
million loss on gas hedging in 1999). Comparability of the Company's revenues
and volumes were both driven by an aggressive developmental drilling program in
2000 and the acquisition of the Floyd Oil Properties in November 1999, the
Magellan Properties in February 2000 and the CWR Properties in May 2000, which
were all significant contributors to the year over year increases.

   Gain on Sale of Properties and Other Revenue. In 2000 vs. 1999, property
divestments resulted in the recognition of gains of $0.8 million and $1.0
million, respectively. The Company continues to actively review and manage its
property portfolio for divestiture of non-strategic properties. Other revenues
in 2000 were $0.8 million compared to $1.0 million in 1999. Other revenue
consists primarily of interest, delay rental and lease bonus income.

   Expenses. Total expenses for the year ended December 31, 2000 were $58.4
million, an increase of $31.4 million (116%) from total expenses in 1999 of
$27.0 million. Comparability of total expenses was significantly impacted by
the Company's aggressive developmental drilling program and the acquisition of
the Floyd Oil Properties in November 1999, the Magellan Properties in February
2000 and the CWR Properties in May 2000. On a per Mcfe basis, the Company's
lease operating expenses decreased by 23% to $0.62 in 2000 from $0.80 in 1999.
Production, severance and ad valorem tax increased by 59% to $0.27/Mcfe in 2000
from $0.17/Mcfe in 1999. Additionally, general and administrative, interest and
depreciation, depletion and amortization ("DD&A") expenses all rose on a dollar
basis in 2000 but decreased on a per Mcfe basis. General and administrative
expense was $0.25/Mcfe in 2000 compared to $0.52/Mcfe in 1999, interest expense
$0.31/Mcfe vs. $0.40/Mcfe in 1999, and DD&A $0.80/Mcfe in 2000 compared to
$0.84/Mcfe in 1999.

   Income Taxes. The Company recorded a $14.4 million income tax provision
during 2000 as compared to a $1.4 million income tax benefit for 1999. The
results from the Company's operations generated pre-tax income of $46.1 million
during 2000 vs. a pre-tax loss of $4.9 million in 1999. During 2000, the
Company's effective tax rate was approximately 32%. Also, the Company became a
cash taxpayer in 2000, with $8.0 million of the 2000 provision recorded as a
current tax payable.

   Net Income. The Company's 2000 net income of $31.7 million is compared to
the $3.4 million net loss in 1999. As discussed in the revenue and expenses
paragraphs above, the Company's significant drilling and acquisition success
during 2000, coupled with a very strong commodity price environment and cost
containment and improved efficiencies on a per unit basis, all attributed to
the current year net income result.

   Dividends to Preferred Shareholders. Dividends to preferred shareholders of
$1.5 million in 2000 is a $0.9 million increase (150%) over 1999 dividends of
$0.6 million. During 2000, the Company issued a new preferred stock series,
Series D, in connection with the Magellan Acquisition, which accounted for $0.6
million of the increase. Additionally, during the third quarter of 2000, the
Company redeemed its Series C preferred stock and recognized a non-cash charge
to dividend expense of $0.5 million.

Item 7. Financial Statements

   The Consolidated Financial Statements that constitute this item follow the
text of this report. An index to the Consolidated Financial Statements and
Schedules appears in Item 13 of this report.

Item 8. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure

   None.

                                       19
<PAGE>

                                    PART III

Item 9. Directors and Executive Officers of the Registrant; Compliance with
       Section 16(a) of the Exchange Act

   The Company's Definitive Proxy Statement for its 2002 Annual Meeting of
Stockholders, when filed pursuant to Regulation 14A under the Securities
Exchange Act of 1934, will be incorporated by reference into this Annual Report
on Form 10-KSB pursuant to General Instruction E(3) of Form 10-KSB and will
provide the information required for Items 9, 10, 11 and 12 under Part III.

Item 10. Executive Compensation

   The Company's Definitive Proxy Statement for its 2002 Annual Meeting of
Stockholders, when filed pursuant to Regulation 14A under the Securities
Exchange Act of 1934, will be incorporated by reference into this Annual Report
on Form 10-KSB pursuant to General Instruction E(3) of Form 10-KSB and will
provide the information required for Items 9, 10, 11 and 12 under Part III.

Item 11. Security Ownership of Certain Beneficial Owners and Management

   The Company's Definitive Proxy Statement for its 2002 Annual Meeting of
Stockholders, when filed pursuant to Regulation 14A under the Securities
Exchange Act of 1934, will be incorporated by reference into this Annual Report
on Form 10-KSB pursuant to General Instruction E(3) of Form 10-KSB and will
provide the information required for Items 9, 10, 11 and 12 under Part III.

Item 12. Certain Relationships and Related Transactions

   The Company's Definitive Proxy Statement for its 2002 Annual Meeting of
Stockholders, when filed pursuant to Regulation 14A under the Securities
Exchange Act of 1934, will be incorporated by reference into this Annual Report
on Form 10-KSB pursuant to General Instruction E(3) of Form 10-KSB and will
provide the information required for Items 9, 10, 11 and 12 under Part III.

Item 13. Exhibits, Financial Statement Schedules and Reports on Form 8-K

 (a)1. Consolidated Financial Statements: See Index to Consolidated Financial
 Statements on page F-1

    2. Exhibits: The following documents are filed as exhibits to this
 report:

<TABLE>
 <C>   <S>
  2.1  Agreement and Plan of Merger, dated December 21, 1999, by and between
       3TEC Energy Corporation, 3TM Acquisition L.L.C., Magellan Exploration,
       LLC and ECIC Corporation, EnCap Energy Capital Fund III, L.P., EnCap
       Energy Acquisition III-B, Inc., BOCP Energy Partners, L.P., and Pel-Tex
       Partners, L.L.C. (Incorporated by reference to Exhibit C to Form DEF14A,
       filed January 11, 2000.)

  2.2  Agreement and Plan of Merger, dated November 24, 1999, by and between
       3TEC Energy Corporation, a Delaware corporation, and Middle Bay Oil
       Company, Inc., an Alabama corporation. (Incorporated by reference to
       Exhibit A to Form DEF14A, filed October 25, 1999.)

  2.3  First Amendment to Agreement and Plan of Merger, effective as of January
       14, 2000, by and among 3TEC Energy Corporation, 3TM Acquisition L.L.C.,
       Magellan Exploration, LLC, ECIC Corporation, EnCap Energy Capital Fund
       III, L.P., EnCap Energy Acquisition III-B, Inc., BOCP Energy Partners,
       L.P., and Pel-Tex Partners, L.L.C. (Incorporated by reference to Exhibit
       2.1 to Form 8-K filed February 4, 2000.)

  2.4  Second Amendment to Agreement and Plan of Merger, effective as of
       February 2, 2000, by and among 3TEC Energy Corporation, 3TM Acquisition
       L.L.C., Magellan Exploration, LLC, ECIC Corporation, EnCap Energy
       Capital Fund III, L.P., EnCap Energy Acquisition III-B, Inc., BOCP
       Energy Partners, L.P., and Pel-Tex Partners, L.L.C. (Incorporated by
       reference to Exhibit 2.2 to Form 8-K filed February 4, 2000.)
</TABLE>

                                       20
<PAGE>

<TABLE>
 <C>   <S>
  2.5  Form of Agreement of Sale and Purchase by and between C.W. Resources,
       Inc., Westerman Royalty, Inc., and Carl A. Westerman and 3TEC Energy
       Corporation. (Incorporated by Reference to Exhibit 10.32 to Form S-2
       filed April 28, 2000.)

  2.6  Form of Stock Purchase Agreement by and between 3TEC Energy Corporation
       and Classic Resources, Inc., Natural Gas Partners IV, L.P., Natural Gas
       Partners V, L.P., and certain individual signatories. (Incorporated by
       reference to Exhibit 2.1 to Form 8-K filed February 13, 2001.)

  2.7  Merger Agreement, dated October 25, 2001, by and among 3TEC Energy
       Corporation, 3NEX Acquisition Corporation and Enex Resources
       Corporation.*

  2.8  Certificate of Ownership and Merger Merging Enex Resources Corporation
       into 3TEC Energy Corporation filed with the Delaware Secretary of State
       January 31, 2002.*

  3.1  Certificate of Incorporation of 3TEC Energy Corporation. (Incorporated
       by reference to Exhibit 3.1 of Form 8-K filed December 6, 1999.)

  3.2  Certificate of Amendment to the Certificate of Incorporation of 3TEC
       Energy Corporation. (Incorporated by reference to Exhibit 3.3 of Form
       10-KSB filed March 30, 2000.)

  3.3  Certificate of Amendment of the Certificate of Incorporation of 3TEC
       Energy Corporation, dated June 14, 2001 (Incorporated by reference to
       Exhibit 3.5 Form 10-QSB filed August 8, 2001.)
  3.4  Certificate of Merger of Middle Bay Oil Company, Inc. into 3TEC Energy
       Corporation. (Incorporated by reference to Exhibit 3.3 of Form 8-K/A
       filed December 16, 1999.)

  3.5  Bylaws of the Company. (Incorporated by reference to Exhibit C to Form
       DEF14A filed October 25, 1999.)

  3.6  Amendment No. 1 to Bylaws of the Company. (Incorporated by reference to
       Exhibit 4.5 Form S-8 filed October 26, 2001.)

  3.7  Amendment No. 2 to Bylaws of 3TEC Energy Corporation. (Incorporated by
       reference to Exhibit 3.6 to Form 10-QSB filed August 8, 2001.)

  4.1  Certificate of Designation of Series B Preferred Stock of 3TEC Energy
       Corporation. (Incorporated by reference to Exhibit 3.1 to Form 8-K/A
       filed December 16, 1999.)

  4.2  Certificate of Designation of Series D Preferred Stock of 3TEC Energy
       Corporation. (Incorporated by reference to Exhibit 4.3 to Form 10-QSB
       filed May 15, 2000.)

 10.1  Securities Purchase Agreement, dated July 1, 1999 by and between the
       Company and 3TEC Energy Corporation. (Incorporated by reference to
       Exhibit C Form DEF14A filed July 19, 1999.)

 10.2  Securities Purchase Agreement, dated August 27, 1999 by and between the
       Company and Shoemaker Family Partners, LP. (Incorporated by reference to
       Exhibit 10.2 to Form 10-QSB filed November 15, 1999.)

 10.3  Securities Purchase Agreement, dated August 27, 1999 by and between the
       Company and Shoeinvest II, LP. (Incorporated by reference to Exhibits to
       Exhibit 10.3 to Form 10-QSB filed November 15, 1999.)

 10.4  Securities Purchase Agreement, dated October 19, 1999 between The
       Prudential Insurance Company of America and the Company. (Incorporated
       by reference to Exhibit 10.1 to Form 8-K filed November 2, 1999.)

 10.5  Shareholders Agreement, dated August 27, 1999 by and among the Company,
       3TEC Energy Corporation and the Major Shareholders. (Incorporated by
       reference to Exhibit 10.5 to Form 10-QSB filed November 15, 1999.)

 10.6  Agreement to Terminate Shareholders' Agreement, dated April 30, 2001, by
       and among the Company and the Major Shareholders. (Incorporated by
       reference to Exhibit 10.6 to Form 10-QSB filed November 8, 2001.)
</TABLE>

                                      21
<PAGE>

<TABLE>
 <C>   <S>
 10.7  Registration Rights Agreement, dated August 27, 1999 by and among the
       Company, 3TEC Energy Corporation, the Major Shareholders, Shoemaker
       Family Partners, LP and Shoeinvest II, LP. (Incorporated by reference to
       Exhibit 10.6 to Form 10-QSB filed November 15, 1999.)

 10.8  Amendment to Registration Rights Agreement, dated October 19, 1999 by
       and among the Company, W/E Energy Company, L.L.C. f/k/a 3TEC Energy
       Company L.L.C., f/k/a 3TEC Energy Corporation, Shoemaker Family
       Partners, LP, Shoeinvest II, LP, and The Prudential Insurance Company of
       America. (Incorporated by reference to Exhibit 10.2 to Form 8-K filed
       November 2, 1999.)

 10.9  Participation Rights Agreement, dated October 19, 1999 by and among the
       Company, The Prudential Insurance Company of America and W/E Energy
       Company L.L.C. (Incorporated by reference to Exhibit 10.3 to Form 8-K
       filed November 2, 1999.)

 10.10 Employment Agreement, dated April 15, 2000 by and between Floyd C.
       Wilson and the Company. (Incorporated by reference to Exhibit 10.9 to
       Form S-2 filed April 28, 2000.)

 10.11 Employment Agreement, dated May 1, 2000, by and between R.A. Walker and
       the Company. (Incorporated by reference to Exhibit 10.9 to Form S-2
       filed April 28, 2000.)
 10.12 Restated Credit Agreement by and among Middle Bay Oil Company, Inc.,
       Enex Resources Corporation and Middle Bay Production Company, Inc. as
       borrowers, and Bank One, Texas, N.A. and other institutions as lenders.
       (Incorporated by reference to Exhibit 10.1 to Form 8-K/A filed December
       17, 1999.)

 10.13 Subordination Agreement, dated August 27, 1999 by and among Shoeinvest
       II, LP, Compass Bank, and Bank of Oklahoma, National Association.
       (Incorporated by reference to Exhibit 10.16 to Form 10-QSB filed
       November 15, 1999.)

 10.14 Subordination Agreement, dated August 27, 1999 by and among Shoeinvest
       II, LP, Compass Bank, and Bank of Oklahoma, National Association.
       (Incorporated by reference to Exhibit 10.16 to Form 10-QSB filed
       November 15, 1999.)

 10.15 Letter Amendment No. 1 to Middle Bay Oil Company, Inc. Securities
       Purchase Agreement, dated November 23, 1999, by and between Middle Bay
       Oil Company, Inc. (n/k/a 3TEC Energy Corporation) and The Prudential
       Insurance Company of America (Incorporated by reference to Exhibit 10.21
       to Form S-2 filed April 28, 2000 and replacing the unexecuted Exhibit
       10.17 of Form 10-QSB filed November 15, 1999.)

 10.16 Intercreditor Agreement, dated as of November 23, 1999, among Middle Bay
       Oil Company, Inc., Bank One Texas, N.A. and 3TEC Energy Company L.L.C.
       (Incorporated by reference to Exhibit 10.18 to Form S-2 filed April 28,
       2000.)

 10.17 Intercreditor Agreement, dated as of November 23, 1999, among Middle Bay
       Oil Company, Inc., Bank One Texas, N.A. and Shoemaker Family Partners,
       LP. (Incorporated by reference to Exhibit 10.19 to Form S-2 filed April
       28, 2000.)

 10.18 Intercreditor Agreement, dated as of November 23, 1999, among Middle Bay
       Oil Company, Inc., Bank One Texas, N.A. and Shoeinvest II, LP.
       (Incorporated by reference to Exhibit 10.20 to Form S-2 filed April 28,
       2000.)

 10.19 Amendment to Securities Purchase Agreement, dated as of November 23,
       1999, among Middle Bay Oil Company, Inc. and 3TEC Energy Company L.L.C.
       (Incorporated by reference to Exhibit 10.22 to Form S-2 filed April 28,
       2000.)

 10.20 Amendment to Securities Purchase Agreement, dated as of November 23,
       1999, among Middle Bay Oil Company, Inc. and Shoemaker Family Partners,
       LP. (Incorporated by reference to Exhibit 10.23 to Form S-2 filed April
       28, 2000.)

 10.21 Amendment to Securities Purchase Agreement, dated as of November 23,
       1999, among Middle Bay Oil Company, Inc. and Shoeinvest II, LP.
       (Incorporated by reference to Exhibit 10.24 to Form S-2 filed April 28,
       2000.)
</TABLE>

                                       22
<PAGE>

<TABLE>
 <C>   <S>
 10.22 Amended and Restated 1995 Stock Option and Stock Appreciation Rights
       Plan. (Incorporated by reference to Exhibit B to Form DEF 14A filed May
       5, 1997.)

 10.23 Amendment No. 1 to the Amended and Restated 1995 Stock Option and Stock
       Appreciation Rights Plan. (Incorporated by reference to Exhibit B to
       Form DEF 14A filed May 5, 1998.)

 10.24 Amendment No. 1 to Amended and Restated 1995 Stock Option and Stock
       Appreciation Rights Plan. (Incorporated by reference to Exhibit 99.7
       Form S-8 filed November 6, 2000.)

 10.25 Amendment No. 3 to Amended and Restated 1995 Stock Option and Stock
       Appreciation Rights Plan. (Incorporated by reference to Exhibit 99.8
       Form S-8 filed November 6, 2000.)

 10.26 1999 Stock Option Plan. (Incorporated by reference to Exhibit E to Form
       DEF 14A filed October 25, 1999.)
 10.27 Amendment No. 1 to 3TEC Energy Corporation 1999 Stock Option Plan.
       (Incorporated by reference to Exhibit 99.4 Form S-8 filed November 6,
       2000.)

 10.28 2000 Stock Option Plan (Incorporated by reference to Exhibit A to Form
       DEF 14A filed on May 1, 2000.)

 10.29 Amendment No. 1 to 3TEC Energy Corporation 2000 Stock Option Plan.
       (Incorporated by reference to Exhibit 99.2 Form S-8 filed November 6,
       2000.)

 10.30 3TEC Energy Corporation 2001 Stock Option Plan. (Incorporated by
       reference to Exhibit 99.1 Form S-8 filed October 26, 2001.)

 10.31 3TEC Energy Corporation 2000 Non-Employee Directors Stock Option Plan.
       (Incorporated by reference to Exhibit 99.2 Form S-8 filed October 26,
       2001.)

 10.32 Second Restated Credit Agreement among 3TEC Energy Corporation, Enex
       Resources Corporation, Middle Bay Production Company, Inc., and Magellan
       Exploration, LLC, as Borrowers, and Bank One, Texas, N.A. and the
       Institutions named therein, as Lenders, Bank One, Texas, N.A., as
       Administrative Agent, Bank of Montreal as Syndication Agent and Banc One
       Capital Markets, Inc., as Arranger, dated May 31, 2000. (Incorporated by
       reference to Exhibit 10.28 to Form S-2/A filed June 6, 2000.)

 10.33 First Amendment to Shareholders' Agreement by and among 3TEC Energy
       Corporation, the W/E Shareholders and the Major Shareholders, dated May
       30, 2000. (Incorporated by reference to Exhibit 10.29 to Form S-2/A
       filed June 6, 2000.)

 10.34 Third Restated Credit Agreement among 3TEC Energy Corporation, Enex
       Resources Corporation and 3TEC/CRI Corporation, as Borrowers, and Bank
       One, N.A. and the Institutions named therein, as Lenders, Bank One,
       N.A., as Administrative Agent, Bank of Montreal as Syndication Agent and
       Banc One Capital Markets, Inc., as Arranger, dated March 12, 2001.
       (Incorporated by reference to Exhibit 10.27 to Form 10-QSB filed May 14,
       2001.)

 21.1  Subsidiaries of 3TEC Energy Corporation.*

 23.1  Consent of KPMG LLP, independent certified public accountants. *

 23.2  Consent of Ryder Scott Company, independent petroleum engineers. *
</TABLE>
--------
* Filed herewith

   (b) The following reports were filed on Form 8-K during the fourth quarter
of 2001:

   On October 26, 2001, the Company filed a Form 8-K under item 5 describing
the announcement of the definitive merger agreement entered into with Enex
Resources Corporation.

                                       23
<PAGE>

                     GLOSSARY OF CERTAIN OIL AND GAS TERMS

   The following are abbreviations and definitions of certain terms commonly
used in the oil and gas industry and herein:

   Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to oil or other liquid hydrocarbons.

   Bcf. One billion cubic feet of natural gas.

   Bcfe. One billion cubic feet of natural gas equivalent, determined using
the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural
gas liquids.

   Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.

   Completion. The installation of permanent equipment for the production of
natural gas or oil, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.

   Condensate. Liquid hydrocarbons associated with the production of a
primarily natural gas reserve.

   Developed acreage. The number of acres that are allocated or assignable to
productive wells or wells capable of production.

   Development well. A well drilled into a proved natural gas or oil reservoir
to the depth of a stratigraphic horizon known to be productive.

   Exploratory well. A well drilled to find and produce natural gas or oil
reserves that are not proved, to find a new reservoir in a field previously
found to be productive of natural gas or oil in another reservoir or to extend
a known reservoir.

   Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic level.

   MBbls. One thousand barrels of oil or other liquid hydrocarbons.

   Mcf. One thousand cubic feet of natural gas.

   Mcfe. One thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

   Mmbtu. One million British Thermal Units.

   Mmcf. One million cubic feet of natural gas.

   Mmcfe. One million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

   Productive well. A well that is found to be capable of producing sufficient
quantities of oil and gas so that proceeds from the sale of the production are
greater than production expenses and taxes.

   Prospect  A specific geographic area which, based on supporting geological,
geophysical or other data and also preliminary economic analysis using
reasonably anticipated prices and costs, is deemed to have potential for the
discovery of oil and natural gas.


                                      24
<PAGE>

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

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

   Proved undeveloped reserves. Reserves that are expected to be recovered
from new wells on developed acreage where the subject reserves cannot be
recovered without drilling additional wells.

   PV-10 value. The estimated future net revenue to be generated from the
production of proved reserves discounted to present value using an annual
discount rate of 10%. These amounts are calculated net of estimated production
costs and future development costs, using prices and costs in effect as of a
certain date, without escalation and without giving effect to non-property
related expenses, such as general and administrative expenses, debt service,
future income tax expense, or depreciation, depletion, and amortization.

   Recompletion. The completion of an existing well for production from a
formation that exists behind the casing of the well.

   Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible natural gas and/or oil that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.

   Royalty interest. An interest in a natural gas and oil property entitling
the owner to a share of natural gas and oil production free of costs of
production.

   Standardized measure. The estimated future net cash flows from proved
natural gas and oil reserves computed using prices and costs, at a specific
date, after income taxes and discounted at 10%.

   Tcfe. One trillion cubic feet of natural gas equivalent, determined using
the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural
gas liquids.

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

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

                                      25
<PAGE>

                                  SIGNATURES

   Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
by the undersigned, thereunto duly authorized, as of April 1, 2002.

                                                 3TEC Energy Corporation
                                                      (Registrant)

                                          By:       /s/ Floyd C. Wilson
                                             ----------------------------------
                                                     Floyd C. Wilson
                                          Chairman and Chief Executive Officer

                               POWER OF ATTORNEY

   KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints Floyd C. Wilson, his true and lawful
attorney-in-fact and agent, each with full power of substitution and
resubstitution, to sign any and all amendments (including post-effective
amendments) to this Annual Report on Form 10-KSB and to file the same, with
exhibits thereto and other documents in connection therewith, with the
Securities and Exchange Commission, granting unto said attorney-in-fact and
agents, and each of them, full power and authority to do and perform each and
every act and thing requisite and necessary to be done in connection
therewith, as fully to all intents and purposes as he or she might or could do
in person, hereby ratifying and confirming all that said attorneys-in-fact, or
their substitute or substitutes, or any of them, shall do or cause to be done
by virtue hereof.

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


<TABLE>
<CAPTION>
              Signature                          Title                   Date
              ---------                          -----                   ----

<S>                                    <C>                        <C>
       /s/ Floyd C. Wilson             Chairman and Chief            April 1, 2002
______________________________________  Executive Officer
           Floyd C. Wilson

         /s/ R.A. Walker               President, Chief Financial    April 1, 2002
______________________________________  Officer, Director
             R.A. Walker

       /s/ Shane M. Bayless            Vice President--Controller    April 1, 2002
______________________________________  & Treasurer Principal
           Shane M. Bayless             Accounting Officer

        /s/ Larry J. Bump              Director                      April 1, 2002
______________________________________
            Larry J. Bump

        /s/ Larry L. Helm              Director                      April 1, 2002
______________________________________
            Larry L. Helm

       /s/ David B. Miller             Director                      April 1, 2002
______________________________________
           David B. Miller

      /s/ D. Martin Phillips           Director                      April 1, 2002
______________________________________
          D. Martin Phillips

      /s/ James L. Irish III           Director                      April 1, 2002
______________________________________
          James L. Irish III
</TABLE>

                                      26
<PAGE>

                         INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                          Page
                                                                          ----
<S>                                                                       <C>
Independent Auditors' Report............................................. F-2
Consolidated Balance Sheets as of December 31, 2001 and 2000............. F-3
Consolidated Statements of Operations for the years ended December 31,
 2001 and 2000........................................................... F-4
Consolidated Statements of Cash Flows for the years ended December 31,
 2001 and 2000........................................................... F-5
Consolidated Statements of Changes in Stockholders' Equity for the years
 ended December 31, 2001 and 2000........................................ F-6
Notes to Consolidated Financial Statements............................... F-7
</TABLE>

                                      F-1
<PAGE>

                         INDEPENDENT AUDITORS' REPORT

The Board of Directors and Stockholders
3TEC Energy Corporation

   We have audited the accompanying consolidated balance sheets of 3TEC Energy
Corporation and subsidiaries as of December 31, 2001 and 2000 and the related
consolidated statements of operations, changes in stockholders' equity, and
cash flows for each of the years then ended. These consolidated financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.

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

   In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of 3TEC
Energy Corporation and subsidiaries as of December 31, 2001 and 2000, and the
results of their operations and their cash flows for each of the years then
ended in conformity with accounting principles generally accepted in the
United States of America.

   As explained in Note 1 to the Consolidated Financial Statements, the
Company changed its method of accounting for derivative instruments and
hedging activities in 2001.

KPMG LLP

Houston Texas
March 26, 2002

                                      F-2
<PAGE>

                    3TEC ENERGY CORPORATION AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS
                     (in thousands, except per share data)

<TABLE>
<CAPTION>
                                                      December 31, December 31,
                                                          2001         2000
                                                      ------------ ------------
                       ASSETS
<S>                                                   <C>          <C>
Current Assets:
 Cash and cash equivalents...........................   $ 17,762     $  4,436
 Accounts receivable.................................     16,835       26,138
 Income tax receivable...............................      4,464           --
 Other...............................................      4,473        5,390
                                                        --------     --------
   Total Current Assets..............................     43,534       35,964
Properties and Equipment, at cost:
 Oil and gas properties, successful efforts method...    385,264      269,531
 Other property and equipment........................      3,549        2,030
                                                        --------     --------
                                                         388,813      271,561
Accumulated depletion, depreciation and
 amortization........................................    (71,039)     (55,064)
                                                        --------     --------
Net Properties and Equipment.........................    317,774      216,497
                                                        --------     --------
Other Assets, net....................................      1,730        2,303
                                                        --------     --------
TOTAL ASSETS.........................................   $363,038     $254,764
                                                        ========     ========
<CAPTION>
        LIABILITIES AND STOCKHOLDERS' EQUITY
<S>                                                   <C>          <C>
Current Liabilities:
 Accounts payable....................................   $ 25,052     $ 10,746
 Accrued liabilities.................................      1,322        2,192
 Series C Preferred stock redemption payable.........      1,349        2,855
 Income taxes payable................................         --        4,462
 Other current liabilities...........................      1,468          467
                                                        --------     --------
   Total Current Liabilities.........................     29,191       20,722
Long-Term Liabilities:
 Bank Debt...........................................    108,000       63,000
 Senior Subordinated convertible notes...............         --       13,224
 Other long-term liabilities.........................         --           58
 Minority Interest...................................         --        1,394
                                                        --------     --------
   Total Long-Term Liabilities.......................    108,000       77,676
                                                        --------     --------
Deferred income taxes................................     45,135        6,771
                                                        --------     --------
TOTAL LIABILITIES....................................    182,326      105,169
                                                        --------     --------
Commitments and Contingencies........................         --           --
STOCKHOLDERS' EQUITY
 Preferred stock, $.02 par value, 20,000,000 shares
  authorized 266,667 designated Series B, 2,300,000
  shares designated Series C and 725,167 shares
  designated Series D, none other designated.........         --           --
 Convertible preferred stock Series B, $7.50 stated
  value, 266,667 shares issued and outstanding.
  $2,000 aggregate liquidation preference............      3,627        3,627
 Convertible preferred stock Series D, 5% $24.00
  stated value, 614,776 shares and 621,930 issued
  and outstanding at December 31, 2001 and December
  31,2000, respectively, $14,755 aggregate
  liquidation preference at December 31, 2001........      7,485        7,572
 Common stock, $.02 par value, 60,000,000 shares
  authorized, 16,547,595 and 14,687,906 shares
  issued at December 31, 2001 and December 31, 2000,
  respectively.......................................        331          294
 Additional paid-in capital..........................    151,412      136,383
 Retained earnings...................................     18,906        2,768
 Treasury stock; 69,807 shares at December 31, 2001
  and December 31, 2000..............................     (1,049)      (1,049)
                                                        --------     --------
   TOTAL STOCKHOLDERS' EQUITY........................    180,712      149,595
                                                        --------     --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...........   $363,038     $254,764
                                                        ========     ========
</TABLE>

          See accompanying notes to consolidated financial statements.

                                      F-3
<PAGE>

                    3TEC ENERGY CORPORATION AND SUBSIDIARIES

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

<TABLE>
<CAPTION>
                                                            Year Ended
                                                     -------------------------
                                                     December 31, December 31,
                                                         2001         2000
                                                     ------------ ------------
<S>                                                  <C>          <C>
REVENUES:
  Oil, natural gas and plant income.................  $  117,885   $  103,210
  Gain on sale of properties........................         815          800
  Gain on derivative fair value.....................       3,081           --
  Other.............................................         998          813
                                                      ----------   ----------
    TOTAL REVENUES..................................  $  122,779   $  104,823
EXPENSES:
  Production --
    Lease operations................................  $   16,935   $   15,326
    Production, severance and ad valorem tax........       7,711        6,692
    Gathering, transportation and other.............       3,829        2,223
  Geological and geophysical........................       1,172          666
  Dry hole and impairments..........................      12,261           29
  Surrendered and expired acreage...................       7,875           --
  General and administrative........................       6,991        6,141
  Interest..........................................       6,773        7,556
  Depreciation, depletion and amortization..........      30,983       19,779
  Other.............................................         250           --
                                                      ----------   ----------
    TOTAL EXPENSES..................................  $   94,780   $   58,412
INCOME BEFORE INCOME TAXES, MINORITY INTEREST AND
 DIVIDENDS TO PREFERRED STOCKHOLDERS................      27,999       46,411
Minority Interest...................................         511          305
Income Tax Expense..................................      10,640       14,442
                                                      ----------   ----------
NET INCOME..........................................      16,848       31,664
Dividends to preferred stockholders.................         710        1,488
                                                      ----------   ----------
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS......  $   16,138   $   30,176
                                                      ==========   ==========
EARNINGS PER COMMON SHARE:
  Basic.............................................  $     1.06   $     2.91
                                                      ==========   ==========
  Diluted...........................................  $     0.91   $     2.28
                                                      ==========   ==========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
  Basic.............................................  15,170,116   10,382,836
                                                      ==========   ==========
  Diluted...........................................  18,968,973   13,894,961
                                                      ==========   ==========
</TABLE>

          See accompanying notes to consolidated financial statements.

                                      F-4
<PAGE>

                    3TEC ENERGY CORPORATION AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (in thousands)
<TABLE>
<CAPTION>
                                                              Year Ended
                                                       -------------------------
                                                       December 31, December 31,
                                                           2001         2000
                                                       ------------ ------------
<S>                                                    <C>          <C>
OPERATING ACTIVITIES
Net income...........................................      16,848      31,664
Adjustments to reconcile net income to net cash
 provided by operating activities:
 Depreciation, depletion and amortization............      30,265      18,713
 Amortization of debt issue costs and other..........         967       1,066
 Dry hole and impairments............................      12,261          29
 Surrendered and expired leases......................       7,875          --
 Gain on derivative fair value.......................      (3,081)         --
 Gain on sale of properties..........................        (815)       (800)
 Deferred income taxes...............................       9,017       6,480
 Minority interest...................................         511         305
 Other changes.......................................         166          --
 Changes in operating assets and liabilities:
 Accounts receivable and other current assets........       9,961     (21,706)
 Account payable and accrued liabilities.............       5,805       8,717
                                                         --------     -------
CASH PROVIDED BY OPERATING ACTIVITIES................      89,780      44,468
INVESTING ACTIVITIES
 Proceeds from sales of oil and gas properties.......      36,818       5,840
 Acquisition of Magellan Exploration LLC, net of cash
  acquired...........................................          --         418
 Acquisition of Classic Resources, Inc. net of cash
  acquired...........................................     (58,670)         --
 Acquisition of Enex Resources Corporation...........      (3,803)         --
 Acquisition of oil and gas properties...............     (22,380)    (64,612)
 Development of oil and gas properties...............     (72,554)    (24,091)
 Additions of other assets...........................      (1,930)     (1,326)
                                                         --------     -------
CASH USED BY INVESTING ACTIVITIES....................    (122,519)    (83,771)
FINANCING ACTIVITIES
 Proceeds from long-term debt........................     130,000      66,100
 Proceeds from issuance of common stock..............          --      68,103
 Proceeds from exercise of stock options and
  warrants...........................................       1,590         705
 Payments on long-term debt..........................     (85,000)    (90,600)
 Preferred stock dividends...........................        (525)     (1,369)
 Treasury stock purchase--Alabama dissenters.........          --        (981)
 Redemption of Preferred Series C stock..............          --      (1,433)
 Debt, common stock and preferred stock issue and
  registration costs.................................          --      (2,927)
                                                         --------     -------
CASH PROVIDED BY FINANCING ACTIVITIES................      46,065      37,598
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS.....      13,326      (1,705)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD.......       4,436       6,141
                                                         --------     -------
CASH AND CASH EQUIVALENTS, END OF PERIOD.............    $ 17,762     $ 4,436
                                                         ========     =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for:
 Interest............................................    $  6,795     $ 7,539
 Income Taxes........................................      10,571       3,500
Non-cash investing and financing activities:
 Common stock and warrants issued in acquisition of
  Magellan Exploration LLC...........................          --      10,573
 Preferred Stock Series D issued in acquisition of
  Magellan Exploration LLC...........................          --       7,453
 Preferred Stock Series C conversions to common
  stock..............................................          --         362
 Preferred dividends incurred but not paid...........         185          --
 Common stock repurchase contingency accrual--Alabama
  dissenters.........................................          --         138
 Conversion of Preferred Series C into Common Stock..          --         910
 Preferred dividends paid in-kind....................          --         118
 Liability for redemption of Preferred Stock Series
  C..................................................          --       2,856
 Deferred taxes recorded in acquisition of Classic
  Resources, Inc.....................................      29,347          --
</TABLE>

          See accompanying notes to consolidated financial statements.

                                      F-5
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

          CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

                    YEARS ENDED DECEMBER 31, 2001 AND 2000
                         (in thousands, except shares)

<TABLE>
<CAPTION>
                                  Preferred Stock
                  --------------------------------------------------
                     Series B        Series C           Series D       Common Stock              Accumulated Treasury
                  -------------- ------------------  ---------------  ----------------            Earnings    Stock
                  Shares   Par     Shares     Par    Shares    Par      Shares    Par  Paid-in    (Deficit)    Par
                  ------- ------ ----------  ------  -------  ------  ----------  ---- --------  ----------- --------
<S>               <C>     <C>    <C>         <C>     <C>      <C>     <C>         <C>  <C>       <C>         <C>
Balance January
1, 2000.........  266,667 $3,627  1,139,506  $5,198       --      --   5,338,771  $107 $ 57,775   $(27,408)  $(1,187)
Common stock
ussued in merger
with Magellan
Exploration
LLC.............                                                       1,085,934    22   10,251
Warrants issued
in merger with
Magellan
Exploration
LLC.............                                                                            300
Preferred Series
D issued in
merger with
Magellan
Exploration
LLC.............                                     617,009   7,453
Stockholder
dissenters
repurchase
contingency
adjustment......                                                                                                 138
Preferred Series
C conversions...                    (72,496)   (362)                      63,465     1      361
Common stock
issued..........                                                       8,050,000   161   67,943
Common stock
offering and
registration
costs...........                                                                         (1,497)
Preferred Series
C redemption....                 (1,067,010) (4,836)                      36,527     1      547
Reverse split
fractional
shares..........                                                            (314)
Employee stock
option
exercises.......                                                          95,190     2      648
Warrant
exercises.......                                                          18,333             55
Net Income......                                                                                    31,664
Preferred stock
dividends.......                                       4,921     119                                (1,488)
                  ------- ------ ----------  ------  -------  ------  ----------  ---- --------   --------   -------
Balance December
31, 2000........  266,667 $3,627         --      --  621,930  $7,572  14,687,906  $294 $136,383   $  2,768   $(1,049)
                  ======= ====== ==========  ======  =======  ======  ==========  ==== ========   ========   =======
Employee stock
option
exercises.......                                                          81,682     2      739
Preferred Series
D Conversions...                                      (7,154)    (87)      7,154             85
Warrant
exercises.......                                                         283,047     6      843
Senior
subordinated
debt
conversions.....                                                       1,487,806    29   13,362
Net Income......                                                                                    16,848
Preferred stock
dividends.......                                                                                      (710)
                  ------- ------ ----------  ------  -------  ------  ----------  ---- --------   --------   -------
Balance December
31, 2001........  266,667 $3,627         --  $   --  614,776  $7,485  16,547,595  $331 $151,412   $ 18,906   $(1,049)
                  ======= ====== ==========  ======  =======  ======  ==========  ==== ========   ========   =======
<CAPTION>
                  Stockholders'
                     Equity
                  -------------
<S>               <C>
Balance January
1, 2000.........    $ 38,112
Common stock
ussued in merger
with Magellan
Exploration
LLC.............      10,273
Warrants issued
in merger with
Magellan
Exploration
LLC.............         300
Preferred Series
D issued in
merger with
Magellan
Exploration
LLC.............       7,453
Stockholder
dissenters
repurchase
contingency
adjustment......         138
Preferred Series
C conversions...          --
Common stock
issued..........      68,104
Common stock
offering and
registration
costs...........      (1,497)
Preferred Series
C redemption....      (4,288)
Reverse split
fractional
shares..........          --
Employee stock
option
exercises.......         650
Warrant
exercises.......          55
Net Income......      31,664
Preferred stock
dividends.......      (1,369)
                  -------------
Balance December
31, 2000........    $149,595
                  =============
Employee stock
option
exercises.......         741
Preferred Series
D Conversions...          (2)
Warrant
exercises.......         849
Senior
subordinated
debt
conversions.....      13,391
Net Income......      16,848
Preferred stock
dividends.......        (710)
                  -------------
Balance December
31, 2001........    $180,712
                  =============
</TABLE>

          See accompanying notes to consolidated financial statements

                                      F-6
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                          December 31, 2001 and 2000

(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 Organization

   3TEC Energy Corporation, (formerly Middle Bay Oil Company, Inc.), was
incorporated under the laws of the state of Alabama on November 20, 1992. The
Company was reincorporated in Delaware on December 7, 1999 and changed its
name to 3TEC Energy Corporation. The reincorporation and name change were part
of a series of transactions related to a securities purchase agreement that
closed on August 27, 1999 between the Company and W/E Energy Company, LLC
("W/E LLC"), formerly known as 3TEC Energy Company, LLC, whereby the Company
received $21.4 million in cash and oil and natural gas properties for the sale
of common stock, warrants and debt securities (See Note 3).

   3TEC Energy Corporation and its subsidiaries (the "Company") are engaged in
the acquisition, development, production and exploration of oil and natural
gas in the contiguous United States. The Company considers its business to be
a single operating segment. Effective November 23, 1999, the Company acquired
oil and natural gas properties and interests managed by Floyd Oil Company from
a group of private sellers. Effective February 3, 2000, the Company acquired
oil and natural gas properties through a merger with Magellan Exploration,
LLC. Effective May 31, 2000, the Company acquired oil and natural gas
properties from C.W. Resources, Inc. Effective November 15, 2000, the Company
acquired oil and natural gas properties from H.G. Westerman and a group of
private sellers. Effective January 31, 2001, the Company acquired oil and
natural gas properties through the purchase of the stock of Classic Resources,
Inc.

 Significant Accounting Policies

   The Company's accounting policies reflect industry standards and conform to
generally accepted accounting principles. The more significant of such
policies are described below.

 Principles of Consolidation

   The consolidated financial statements include the accounts of the Company
and Enex Resources Corporation ("Enex") which prior to December 31, 2001 was
an 80% owned subsidiary. The equity of the minority interests in Enex is shown
in the consolidated financial statements as "minority interest". On December
31, 2001, the Company acquired the remaining 20% of Enex pursuant to the
merger of Enex into a wholly-owned subsidiary of the Company for cash
consideration of $14.00 per share. All significant intercompany balances and
transactions have been eliminated in consolidation.

 Reclassifications

   Certain prior-year amounts have been reclassified to conform with current
year presentation.

 Consolidated Statements of Cash Flows

   For the purpose of cash flows, the Company considers all highly liquid
investments with a maturity date of three months or less to be cash
equivalents. Significant transactions may occur which do not directly affect
cash balances and as such will not be disclosed in the Consolidated Statements
of Cash Flows. Certain of such non-cash transactions are disclosed in the
Consolidated Statements of Shareholders' Equity relating to shares issued as
compensation, and shares issued for stock and debt of an acquired company.

 Oil and Gas Properties

   The Company follows the successful efforts method of accounting for oil and
natural gas properties, and accordingly, capitalizes all direct costs incurred
in connection with the acquisition, drilling and development of

                                      F-7
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000

productive oil and natural gas properties. Costs associated with unsuccessful
exploration are charged to expense currently. Geological and geophysical costs
and costs of carrying and retaining unevaluated properties are charged to
expense. Depreciation, depletion and amortization of capitalized costs are
computed separately for each field based on the unit-of-production method
using only proved oil and natural gas reserves. In arriving at such rates,
commercially recoverable reserves have been estimated by an independent
petroleum engineering firm. The Company reviews its undeveloped properties
continually and charges them to expense on a property-by-property basis when
it is determined that they have been condemned by dry holes, or have otherwise
diminished in value. The Company recorded surrendered and expired acreage
expense on its undeveloped properties for the year ended December 31, 2001 of
approximately $7.9 million and no surrendered and expired acreage expense
during 2000. Gains and losses are recorded on sales of interests in proved
properties and on sales of entire interests in unproved properties. For the
years ended December 31, 2001 and 2000, the Company realized gains on sales of
properties of $0.8 million and $0.8 million, respectively.

   Proved oil and natural gas reserves are the estimated quantities of oil,
natural gas and natural gas liquids which are expected to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Reservoirs are considered proved if economic productability is
supported by either actual production or conclusive formation tests.

   The Company reviews long-lived assets for impairment when events or changes
in circumstances indicate that the carrying value of such an asset may not be
recoverable. This review consists of a comparison of the carrying value of the
asset to the asset's expected future undiscounted cash flows. Estimates of
expected future cash flows represent management's best estimate based on
reasonable and supportable assumptions and projections. If the expected future
cash flows, assuming escalated prices, are less than the carrying value of the
asset, an impairment exists and is measured as the excess of the carrying
value over the estimated fair value of the asset. The Company estimates
discounted future net cash flows to determine fair value. Any impairment
provisions recognized are permanent and may not be restored in the future. For
the years ended December 31, 2001 and 2000, the Company's proved properties
were assessed for impairment on an individual field basis and the Company
recorded impairment provisions on certain producing properties of $3.4 and $-
0- million, respectively.

 Revenue Recognition of Production Imbalances

   Oil and natural gas revenues are recorded using the sales method, whereby
the Company recognizes revenues based on the amount of oil and natural gas
sold to purchasers on its behalf not-withstanding its ownership percentage. At
December 31, 2001 and 2000, the Company's net imbalance position was
immaterial.

 Hedging

   In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities ("SFAS 133"). In June 2000, the FASB issued
SFAS 138, Accounting for Derivative Instruments and Hedging Activities, an
amendment of FASB Statement No. 133. SFAS 133, as amended, establishes
accounting and reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in other contracts) be
recorded in the balance sheet as either an asset or liability measured at its
fair market value. The statement requires that changes in the derivative's
fair value be recognized currently in earnings unless specific hedge criteria
are met. Special accounting for qualifying hedges allows a derivative's gains
and losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document, designate and
assess the effectiveness of transactions that receive hedge accounting. The
Company adopted SFAS 133 effective January 1, 2001. Based upon the historical
volatility of oil and gas commodity prices, the Company

                                      F-8
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000

expects that SFAS 133 could increase volatility in the Company's earnings and
other comprehensive income for periods where hedging activities are present.

   SFAS 133, in part, allows hedge accounting. SFAS 133 provides that the
effective portion of the gain or loss on a derivative instrument designated
and qualifying as a cash flow hedging instrument be reported as a component of
other comprehensive income and be reclassified into earnings in the same
period during which the hedged forecasted transaction affects earnings. The
remaining gain or loss on the derivative instrument, if any, must be
recognized currently in earnings.

   To qualify for cash flow hedge accounting, the cash flows from the hedging
instrument must be highly effective in offsetting changes in cash flows due to
changes in the underlying items being hedged. In addition, all hedging
relationships must be designated, documented, and reassessed periodically. The
Company's natural gas derivative instruments entered into during the period
were not designated as hedges at the time the instruments were executed. In
accordance with provisions of SFAS 133, these instruments have been marked-to-
market through earnings at December 31, 2001, resulting in an increase to
revenues of $3.1 million. There were no derivatives in place at December 31,
2000.

 Earnings Per Share

   Basic earnings and loss per common share are based on the weighted average
shares outstanding without any dilutive effects considered. Diluted earnings
and loss per share reflect dilution from all potential common shares,
including options, warrants and convertible preferred stock and convertible
notes. Diluted loss per share does not include the effect of any potential
common shares if the effect would be to decrease the loss per share.

   At December 31, 2001, the Company had a weighted average of 3,798,857,
combined stock options, warrants and convertible preferred stock outstanding
included in the Company's fully-diluted per share calculation. At December 31,
2000, the Company had a weighted average of 3,789,456, combined stock options,
warrants and convertible preferred stock and notes outstanding.

   All share and per share amounts have been retroactively adjusted for a one-
for-three reverse split that was approved by the Company's shareholders on
January 14, 2000.

 Income Taxes

   Income taxes are accounted for under the asset and liability method.
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases and operating loss and tax credit carryforwards. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected to be
recovered or settled. The effect on deferred tax assets and liabilities of a
change in tax rates is recognized in income in the period that includes the
enactment date.

 Concentrations of Market Risk

   The future results of the Company will be affected by the market prices of
oil and natural gas. The availability of a ready market for oil and natural
gas in the future will depend on numerous factors beyond the control of the
Company, including weather, production of other oil and natural gas, imports,
marketing of competitive fuels, proximity and capacity of oil and natural gas
pipelines and other transportation facilities, any

                                      F-9
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000

oversupply or undersupply of oil and natural gas, the regulatory environment,
and other regional and political events, none of which can be predicted with
certainty.

 Concentrations of Credit Risk

   Financial instruments which subject the Company to concentrations of credit
risk consist primarily of cash and accounts receivable. The Company places its
cash investments with high credit qualified financial institutions. Risk with
respect to receivables is concentrated primarily in the current production
revenue receivable from multiple oil and natural gas purchasers, and is
typical in the industry. For 2001, Calpine Producer Services, L.P. (formerly
Highland Energy Company) and Wagner & Brown, Ltd. accounted for approximately
22% and 19% of total oil and natural gas sales, respectively. No single
customer accounted for greater than 10% of the Company's total oil and natural
gas sales for the year ended December 31, 2000.

 Use of Estimates

   Management of the Company has made a number of estimates and assumptions
relating to the reporting of assets and liabilities to prepare the financial
statements in conformity with generally accepted accounting principles. Actual
results could differ from these estimates.

(2) ACQUISITIONS AND DIVESTITURES

   On January 30, 2001, the Company acquired 100% of the issued and
outstanding stock of Classic Resources Inc. (the "Classic Acquisition") for
cash consideration of approximately $53.5 million plus other acquisition
costs. The operating results of the Classic Acquisition have been included in
the consolidated financial statements since that date. Classic was a
privately-held exploration and production company with properties located in
East Texas. The Company's estimate of total net proved at the time of the
acquisition for Classic's oil and gas properties was 47 Bcfe and net daily
production of approximately 11 Mmcfe. The Company financed the acquisition
under its existing Credit Facility. The purchase price of the Classic
Acquisition was allocated principally to proved properties, with additional
amounts allocated to working capital related to amounts recorded for
production related receivables and payables in existence and accrued for at
January 20, 2001.

   On May 31, 2000, we completed the acquisition of the CWR Properties (the
"CWR Acquisition") located in East Texas for cash consideration of
approximately $51.7 million. The effective date of the acquisition was January
1, 2000, and the operations are included in the Company's consolidated
financial statements beginning June 1, 2000. The CWR Acquisition was financed
under our existing Credit Facility, which we amended prior to closing the
acquisition. The total purchase price was allocated principally to oil and
natural gas properties using the purchase method of accounting.

   On February 3, 2000, we completed the acquisition of Magellan Exploration
LLC (the "Magellan Acquisition"), from certain affiliates of EnCap Investments
L.L.C. ("EnCap"), a Delaware limited liability company and an investor in W/E
LLC, and other third parties for consideration consisting of (a) 1,085,934
shares of common stock, (b) four year warrants to purchase up to 333,333
shares of common stock at $30.00 per share, (c) 617,009 shares of 5% Series D
Convertible Preferred Stock with a redemption value of $24.00 per share and
(d) the assignment of a performance based "back-in" working interest of 5% of
Magellan's interest in 12 exploration prospects. The total purchase price of
approximately $19 million was allocated principally to proved undeveloped oil
and natural gas properties using the purchase method of accounting.

                                     F-10
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000


   The following pro forma data presents the results of the Company for the
year ended December 31, 2000, as if the Classic Acquisition and the CWR
Acquisition had occurred on January 1, 2000, and the results of the Company
for the year ended December 31, 2001 as if the Classic Acquisition had
occurred on January 1, 2001. The unaudited pro forma data assumes the
acquisition of the respective properties and the debt financing transactions
related to these acquisitions. The unaudited pro forma results are presented
for comparative purposes only and are not necessarily indicative of the
results which would have been obtained had the acquisitions been consummated
as presented. (in thousands, except per share amounts):

<TABLE>
<CAPTION>
                                                Pro Forma         Pro Forma
                                               Year Ended        Year Ended
                                            December 31, 2001 December 31, 2000
                                            ----------------- -----------------
                                               (unaudited)       (unaudited)
   <S>                                      <C>               <C>
   Total revenues.........................      $121,813          $121,724
   Net income attributable to common
    stockholders..........................        13,958            24,266
   Net income per basic share attributable
    to common stockholders................      $   0.92          $   2.34
</TABLE>

   During 2001, the Company completed the sale of certain non-strategic oil
and gas properties for net cash proceeds of approximately $36.7 million. In
order to defer the tax gain on the sales of the properties, the Company
successfully replaced a portion of these properties in accordance with the
Like-Kind Exchange regulations of the Internal Revenue Service. At December
31, 2001, the Company had $13.9 million of cash in like-kind escrow accounts.
In January 2002, the like-kind replacement term expired in accordance with the
Internal Revenue Service regulations and the balance of the escrow accounts
were used to reduce borrowings under the Company's Credit Facility.

(3) COMMON STOCK, WARRANT AND SENIOR SUBORDINATED CONVERTIBLE NOTE SALE TO W/E
ENERGY COMPANY, L.L.C. ("W/E LLC")

   On August 27, 1999, the Company closed a Securities Purchase Agreement (the
"Agreement") for a total of $21.4 million with W/E LLC. The Securities
Purchase Agreement and contemplated transactions were approved by the
stockholders at the Company's annual meeting on August 10, 1999.

   The controlling person of W/E LLC was EnCap. The sole member of EnCap is El
Paso Field Services Company, a Delaware corporation ("El Paso Field
Services"). The controlling person of El Paso Field Services is El Paso
Corporation, a Delaware corporation. The Company received $9.8 million in cash
and properties valued at $875,000 for 1,585,185 shares of common stock and
1,200,000 warrants (the "Warrants") and $10.7 million for a 5-year senior
subordinated convertible note with a face value of $10.7 million (See Note 6).

   On November 28, 2001, W/E LLC was dissolved and all shares of common stock
and warrants of the Company held by W/E LLC were distributed to its members.

(4) RELATED PARTY TRANSACTIONS

   David B. Miller and D. Martin Phillips, directors of the Company, are
managing directors of EnCap, which was the controlling person of W/E LLC.
Floyd C. Wilson, Chairman and Chief Executive Officer of the Company, was also
a member of W/E LLC. Gary R. Christopher, a shareholder and director of the
Company until December 31, 2001, is employed by Kaiser-Francis Oil Co., which
owns approximately 7% of the common stock of the Company as of December 31,
2001.

   In 2000, the Company paid EnCap a fee of $500,000 in connection with a
private equity shelf facility related to the CWR Acquisition. As required by
the Company's Credit Facility, the private equity shelf facility would

                                     F-11
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000

have allowed the Company to require EnCap Investments to purchase up to $20
million of a new class of exchangeable preferred stock from the Company. Upon
completion of the Company's public offering of common stock on June 30, 2000,
the shelf facility expired.

   The Company has a $250 million credit facility (the "Credit Facility") with
Bank One, NA, as administrative agent, Bank of Montreal, as syndication agent,
and Union Bank of California, N.A., Wells Fargo Bank Texas, National
Association, CIBC, Inc., Comerica Bank, Fleet National Bank and The Bank of
Nova Scotia as participating lenders. The borrowing base is redetermined semi-
annually and as of December 31, 2001, was $145 million. In addition, the
Company is a party to certain derivative contracts that Bank One, NA is the
counter-party to. These derivative contracts cover a portion of the Company's
anticipated natural gas production for 2002. Larry L. Helm, a director of the
Company, is responsible for the nationwide Middle Market Banking Group of Bank
One Corporation.

(5) LONG-TERM DEBT

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

<TABLE>
<CAPTION>
                                                                 2001    2000
                                                               -------- -------
   <S>                                                         <C>      <C>
   $250 million Credit Facility............................... $108,000 $63,000
   Less current maturities....................................       --      --
                                                               -------- -------
   Long-term debt excluding current maturities................ $108,000 $63,000
                                                               ======== =======
</TABLE>

   The Company's Credit Facility with Bank One, NA as agent and seven other
banks. The Credit Facility as amended, matures May 31, 2003. As of December
31, 2001, the borrowing base was set at $145 million. The borrowing base is to
be redetermined semi-annually on May 1 and November 1 and provides for
interest as revised under the Credit Facility to accrue at a rate calculated
at the Company's option as either the bank's prime rate plus a low of zero to
a high of 50 basis points or LIBOR plus basis points increasing from a low of
150 to a high of 212.5 as loans outstanding increase as a percentage of the
borrowing base. As of December 31, 2001, the Company was paying an average of
3.68% per annum interest on the principal balance of $108 million under the
Credit Facility. Prior to maturity, no payments of principal are required so
long as the borrowing base exceeds the loan balance. The borrowings under the
Credit Facility are secured by substantially all of the Company's oil and
natural gas properties. At December 31, 2001, the amount available to be
borrowed under the Credit Facility was approximately $37 million.
Additionally, at December 31, 2001, the Company had approximately $13.9
million in cash held in like-kind exchange escrow accounts. The Company used
these funds to repay borrowings under the Credit Facility in January, 2002. At
March 7, 2002, borrowings under the Credit Facility totaled $97 million.

   The Credit Facility is governed by various financial and other covenants,
including requirements to maintain a current ratio of one to (1:1), and an
interest rate coverage ratio. Additionally, limitations on asset dispositions,
declaration and payment of cash dividends and the entering into hedge
transactions without the bank's consent are included. Aggregate amounts of
expected required repayments of long term debt at December 31, 2001 are as
follows (in thousands):

<TABLE>
   <S>                                                                  <C>
   2002................................................................ $     --
   2003................................................................  108,000
   2004................................................................       --
   Thereafter..........................................................       --
                                                                        --------
     Total............................................................. $108,000
                                                                        ========
</TABLE>

                                     F-12
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000


(6) SENIOR SUBORDINATED CONVERTIBLE NOTES

   On August 27, 1999, senior subordinated convertible promissory notes (the
"Senior Subordinated Notes") were sold to W/E LLC and affiliates of Alvin V.
Shoemaker ("Shoemaker"), a former director and significant shareholder, for
$10.7 million and $0.2 million, respectively. On October 19, 1999, $2.4
million of Senior Subordinated Notes were sold to The Prudential Insurance
Company of America ("Prudential"). The Senior Subordinated Notes bore interest
at an annual rate of 9%. Interest was payable beginning on December 31, 1999,
every March 31, June 30, September 30 and December 31, until maturity on
August 27, 2004. The Company may defer payment of fifty percent (50%) of the
first eight quarterly interest payments. The Senior Subordinated Notes could
be prepaid, without premium or penalty, in whole or in part, at any time after
August 27, 2001. The holders of the Senior Subordinated Notes could convert
all or any portion of outstanding principal and accrued interest at any time
into shares of Company common stock at a conversion price of $9.00 per common
share, a total of 1,469,316 common shares. The conversion price could be
adjusted from time to time based on the occurrence of certain events. In the
event of a change in control, the entire outstanding principal balance and all
accrued but unpaid interest is immediately due and payable.

   The Senior Subordinated Notes ranked senior in right of payment to all
Company notes and indebtedness other than the Credit Facility.

   During the second quarter of 2001, the Company received notice of an
election by Shoemaker to convert approximately $0.2 million of Senior
Subordinated Notes. The conversion resulted in the retirement of $0.2 million
in senior subordinated debt and the issuance of an additional 16,666 shares of
common stock of the Company.

   During the third quarter of 2001, the Company sent notice of an election to
W/E LLC to prepay the $10.7 million of Senior Subordinated Notes. Pursuant to
the terms of the convertible note agreement, W/E LLC elected instead to
exercise its right to convert the principal and accrued interest outstanding
into common shares of the Company. Under the terms of the convertible note
agreement, the balance of the note plus any accrued interest was to be
converted at $9.00 per share. The conversion by W/E LLC resulted in the
retirement of approximately $10.7 million in senior subordinated debt and the
issuance of an additional 1,206,127 shares of common stock of the Company.

   During the fourth quarter of 2001, the Company received notice of an
election by Prudential to convert approximately $2.4 million of Senior
Subordinated Notes. The conversion resulted in the retirement of $2.4MM in
senior subordinated debt and the issuance of an additional 265,013 shares of
common stock of the Company.

(7) INCOME TAXES

   The components of income tax expense for the years ended December 31, 2001
and 2000 consisted of the following (in thousands):

<TABLE>
<CAPTION>
                                            2001                   2000
                                   ---------------------- ----------------------
                                   Federal State   Total  Federal State   Total
                                   ------- ------ ------- ------- ------ -------
   <S>                             <C>     <C>    <C>     <C>     <C>    <C>
   Current........................ $1,143  $  479 $ 1,622 $ 6,120 $1,842 $ 7,962
   Deferred.......................  7,582   1,436   9,018   6,224    256   6,480
                                   ------  ------ ------- ------- ------ -------
     Total........................ $8,725  $1,915 $10,640 $12,344 $2,098 $14,442
                                   ======  ====== ======= ======= ====== =======
</TABLE>

                                     F-13
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000


   The reconciliation of income tax computed at the U.S. federal statutory tax
rates to the provision for income taxes is as follows (in thousands):

<TABLE>
<CAPTION>
                                                                December 31,
                                                               ----------------
                                                                2001     2000
                                                               -------  -------
   <S>                                                         <C>      <C>
   Income tax provision at statutory rate..................... $ 9,800  $16,137
   State income taxes, net of federal benefit.................   1,224    1,364
   Decrease in valuation allowance............................      --   (2,523)
   Utilization of Sec. 29 tax credits.........................    (500)    (400)
   Other......................................................     116     (136)
                                                               -------  -------
     Total.................................................... $10,640  $14,442
                                                               =======  =======

   The Company's net deferred tax liability at December 31, 2001 and 2000 is
as follows (in thousands):

<CAPTION>
                                                                2001     2000
                                                               -------  -------
   <S>                                                         <C>      <C>
   Deferred tax liability
     Oil and natural gas properties........................... $47,563  $ 9,547
                                                               -------  -------
   Deferred tax asset
     NOL carryforward.........................................  (5,237)  (5,812)
     AMT tax credit carryforward..............................    (327)     (36)
     Other....................................................    (430)    (495)
                                                               -------  -------
                                                                (5,994)  (6,343)
     Valuation allowance......................................   3,566    3,566
                                                               -------  -------
   Net deferred tax liability................................. $45,135  $ 6,770
                                                               =======  =======
</TABLE>

   In connection with the Classic Acquisition, the Company recorded $29.3
million in deferred taxes for the future tax impact of the difference between
the allocated book basis and the historical tax basis of the Classic
Properties.

   In assessing the realizability of deferred tax assets, management considers
whether it is more likely than not that some portion or all of the deferred
tax asset will not be realized. Management considers the scheduled reversal of
deferred tax liabilities, projected future taxable income, and tax planning
strategies in making this assessment. Based upon projections for future
taxable income over the periods in which the deferred tax assets are
deductible and the Section 382 limitation discussed below, management believes
it is more likely than not that the Company will realize the benefits of these
deductible differences, net of the existing valuation allowances at December
31, 2001 and 2000. The net change in the total valuation allowance for the
years ended December 31, 2001 and 2000 was $-0- and $2.5 million and the
amount remaining at December 31, 2001 is $3.6 million.

   The Enex acquisition caused an ownership change pursuant to Section 382 in
March 1998. As a result of this ownership change, the Company's use of its net
operating loss carryforwards subsequent to that date will be limited. The
Floyd Oil Acquisition in November 1999 also caused an ownership change
pursuant to Section 382. As a result of these changes, the Company's use of
its net operating loss carryforwards subsequent to that date will be limited.
In February 2000, Enex had an ownership change pursuant to Section 382 with
respect to its net operating losses.

   As of December 31, 2001, the Company had net operating loss carryforwards
of approximately $14.9 million, expiring beginning in 2009 through 2019.

                                     F-14
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000


(8) RETIREMENT PLAN AND EMPLOYEE INCENTIVE PLAN

   All of the employees of the Company are eligible to participate in a
defined contribution plan that provides for maximum employee contributions of
15% of total wages paid to employees for the year and Company contributions.
Company contributions made to the plan for the years ending December 31, 2001
and 2000 were $462,763 and $135,225, respectively.

(9) STOCK OPTION PLANS

   The Company's stock option plans authorize the granting of options to key
employees and non-employee directors at prices equivalent to the market value
at the date of grant. Options generally become exercisable in the following
manner: 50% upon the date of grant with the remaining 50% exercisable in three
annual installments commencing one year after the date of grant and, if not
exercised, expire 10 years from the date of grant. The Company accounts for
employee stock-based compensation using the intrinsic value method and since
the exercise price of the options granted is equal to the quoted market price
of the Company's stock at the grant date, no compensation costs have been
recognized for its stock option plans. Had compensation cost for the Company's
Plans been determined based on the fair value at the grant date for stock
options granted for the years ending December 31, 2001 and 2000, the Company's
net income and income per share would have been adjusted to the pro forma
amounts listed below (in thousands, except per share amounts):

<TABLE>
<CAPTION>
                                                     December 31, December 31,
                                                         2001         2000
                                                     ------------ ------------
   <S>                                               <C>          <C>
   Net Income attributable to Common Stockholders
     As Reported....................................   $16,137      $30,176
     Pro Forma......................................   $13,446      $21,889
   Net Income per common share, diluted
     As Reported....................................   $  0.91      $  2.28
     Pro Forma......................................   $  0.77      $  1.58
</TABLE>

   The fair value of grants was estimated on the date of grant using the Black
Scholes option pricing model with the following weighted-average assumptions
used in 2001 and 2000, respectively: risk free interest rates of 3.96% and
6.48%, expected volatility of 69% and 72%, no dividend yield, and an expected
life of the option of 3 years in 2001 and 2000. The weighted average fair
value of stock options granted in 2001 and 2000 was $7.02 and $5.72 per share,
respectively.

                                     F-15
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000


   A summary of the status of the Company's plans as of December 31, 2001 and
2000, and changes during the years ended on those dates is presented below:

<TABLE>
<CAPTION>
                                                               Average Exercise
                                                     Shares    Price Per Share
                                                    ---------  ----------------
<S>                                                 <C>        <C>
Options outstanding at January 1, 2000.............   335,922       $15.00
  Granted in 2000.................................. 2,898,500       $11.07
  Exercised in 2000................................   (95,190)      $ 6.83
  Forfeited in 2000................................  (248,160)      $16.39
                                                    ---------       ------
Options outstanding at December 31, 2000........... 2,891,072       $11.15
  Granted in 2001..................................   502,835       $14.67
  Exercised in 2001................................   (81,682)      $ 9.12
  Forfeited in 2001................................   (36,729)      $18.53
                                                    ---------       ------
Options outstanding at December 31, 2001........... 3,275,496       $11.66
Options outstanding at December 31, 2000........... 2,891,072       $11.15
Options exercisable at December 31, 2001........... 2,058,765        11.45
Options exercisable at December 31, 2000........... 1,442,995        11.16
Options available for grant at December 31, 2001... 1,012,527
Options available for grant at December 31, 2000...   275,298
</TABLE>
--------
   At December 31, 2001, the range of exercise prices and weighted average
remaining contractual life of options outstanding was $4.50 to $18.56 and 8.78
years, respectively.

   Warrants to purchase 1,216,822 shares and 266,226 shares of common stock at
$3.00 per share were issued on August 27, 1999 and October 19, 1999,
respectively, and warrants to purchase 333,333 shares of common stock at
$30.00 per share were issued on February 3, 2000, are excluded from the table
above because the warrants were issued in conjunction with the sales of stock
and are not stock-based compensation. During 2001, warrants to purchase
283,047 shares of common stock at $3.00 were exercised.

(10) STOCKHOLDERS' EQUITY

   Preferred Stock--Series B

   In connection with the merger of Shore Oil Company, effective June 30,
1997, the Company issued 266,667 shares of Series B Preferred Stock ("Series
B"). The Series B is nonvoting and pays no dividends. The Series B has a
liquidation value of $7.50 a share. Until December 31, 2002, any holder of the
Series B may convert all or any portion of Series B shares into shares of
Company Common Stock ("Common"). The number of shares of Common into which the
total number of Series B shares may be converted is 88,889 shares plus the
result of multiplying (i) (the value of approximately 40,000 net mineral acres
owned by the Company in South Louisiana (the "Mineral Acres") minus
$2,000,000) divided by $8,000,000 times (ii) 355,555. In no event shall the
aggregate total number of shares of Common into which the Series B are
converted exceed 444,444 shares. Unless the Company has given notice to redeem
the Series B shares, any outstanding shares of Series B shall be automatically
be converted on December 31, 2002.

   At December 31, 2001, the value of the Mineral Acres had increased to a
level that resulted in the 266,667 shares of Series B being convertible into
154,591 shares of Common. At December 31, 2001, none of the Series B had been
converted.

                                     F-16
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000


 Preferred Stock--Series C

   On August 31, 2000, the Company sent notices to the holders of its Series C
Preferred Stock (the "Series C") advising that the Series C would be redeemed
on September 30, 2000. The Series C had a redemption price of $5.00 per share
and the holders had the right to convert their Series C shares into Company
common stock at a ratio of one share of common for three shares of Series C
prior to September 30, 2000. A total of 2,101,827 shares of the Series C were
outstanding on September 30, 2000 with 1,293,521 (62%) held by the Company's
then 80% owned subsidiary, Enex. 109,580 Series C shares were converted to
36,527 shares of common stock and approximately 1,992,247 Series C shares were
redeemed. On a consolidated basis, the Company's initial liability for the
Series C redemption was approximately $4.8 million. As a result of the Series
C redemption, the Company recognized a charge to dividend expense in 2000 of
$498,706. At December 31, 2001, $1.3 million remained to be funded.

 Preferred Stock--Series D

   On February 3, 2000, we completed the Magellan Acquisition, from certain
affiliates of EnCap and an investor in W/E LLC, and other third parties for
consideration consisting of (a) 1,085,934 shares of common stock, (b) four
year warrants to purchase up to 333,333 shares of common stock at $30.00 per
share, (c) 617,009 shares of 5% Series D Convertible Preferred Stock with a
redemption value of $24.00 per share and (d) the assignment of a performance
based "back-in" working interest of 5% of Magellan's interest in 12
exploration prospects. The total purchase price of approximately $19 million
was allocated principally to proved undeveloped oil and natural gas
properties. During 2001, 7,154 shares of the Series D were converted to common
stock.

 Common Stock

   On June 30, 2000, the Company completed its public offering of 8.05 million
shares of the Company's common stock (priced at $9.00 per share). The net
proceeds, approximately $66.6 million, were used primarily to repay a portion
of the outstanding debt under the amended Credit Facility.

   On January 14, 2000, the Company's stockholders voted to affect a one-for-
three reverse split of the Company's common stock for the stockholders of
record on December 9, 1999. The par value of these shares was transferred to
additional paid-in capital. All common share and earnings per common share
amounts have been retroactively restated in the accompanying consolidated
financial statements to reflect the reverse stock split.

   On August 27, 1999, the Company sold to W/E LLC 1,585,185 shares of common
stock and five-year warrants to purchase 1,200,000 shares of common stock for
$9.8 million in cash and oil and natural gas properties valued at $0.9
million. On the same date, the Company sold 22,222 shares of common stock and
five-year warrants to purchase 16,822 shares of common stock to Shoemaker for
$0.2 million (See Notes 3 and 6).

   On October 19, 1999, the Company closed a private placement of securities
to Prudential. The economic terms and conditions of the private placement are
similar to those of the securities purchase agreement with W/E LLC and
Shoemaker entered into on July 1, 1999. The private placement consisted of the
sale of 351,681 shares of common stock and five-year warrants to purchase
266,226 shares at $3.00 per share of common stock for $2.4 million and a five-
year senior subordinated convertible note for $2.4 million (See Note 6).

   The warrants issued to W/E LLC, Shoemaker and Prudential are exercisable
for $3.00 per share and expire five years from the issue date. Sixty percent
of the warrants were immediately exercisable, in whole or in part at

                                     F-17
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000

any time until the expiration date. An additional 10% of the warrants may be
exercised at each anniversary of the grant date until expiration. At December
31, 2001, 1,200,000 warrants were exercisable. As a result of the conversion
of the entire principal balance of the Senior Subordinated Notes during 2001,
all of the warrants became immediately exercisable. During 2001, warrants to
purchase 283,047 shares of common stock at $3.00 were exercised.

(11) COMMITMENTS AND CONTINGENCIES

   On November 18, 1999, the Company's shareholders approved a reincorporation
of the Company from Alabama to Delaware (See Note 1). The Alabama Code has a
shareholder dissent provision that allows a shareholder to dissent from the
reincorporation and demand cash payment equal to the fair value of the common
stock owned at the date of the reincorporation. Before the November 18
meeting, the Company received shareholder dissents representing ownership of
99,438 shares of common stock. Over the period December 15, 1999 to January
25, 2000, the Company received formal demands for payment from the dissenting
shareholders (the "dissenters"). At December 31, 1999 the Company had accrued
the estimated cash payment to the dissenters of approximately $1.1 million.
The Company made an offer to the dissenters on March 14, 2000 and the
dissenters made a counteroffer in late March. On May 26, 2000, the Company
agreed to a settlement with the dissenters for them to surrender 62,549 shares
of common stock for a total of $980,800, including interest. The settlement
closed on June 30, 2000 and the shares are held by the Company as treasury
stock. A shareholder holding 36,889 shares of common stock agreed to withdraw
his dissent.

 Commitments and Contingencies

   The Company has commitments for operating leases (primarily for office
space) in Houston, Texas. Rental expense for office space was $670,842 in 2001
and $390,452 in 2000. Future minimum lease commitments at December 31, 2001
are $1,141,980 in 2002; $1,308,336 in 2003; $1,342,046 in 2004; $889,263 in
2005; $847,822 in 2006; and $1,769,192 in years thereafter.

   The Company is a defendant in various legal proceedings which are
considered routine litigation incidental to the Company's business, the
disposition of which management believes will not have a material effect on
the financial position or results of operations of the Company.

(12) ACCOUNTING PRONOUNCEMENTS

   In October, 2001, the FASB issued SFAS 144, Accounting for the Impairment
or Disposal of Long-Lived Assets, which addresses financial accounting and
reporting for the impairment or disposal of long-lived assets. While SFAS 144
supersedes SFAS 121, Accounting for the Impairment of Long-Lived Assets and
for Long Lived Assets to Be Disposed Of, it retains many of the fundamental
provisions of that Statement.

   SFAS 144 also supersedes the accounting and reporting provisions of APB
Opinion No. 30, Reporting the Results of Operations--Reporting the Effects of
Disposal of a Segment of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions, for the disposal of a segment
of business. However, it retains the requirement in Opinion 30 to report
separately discontinued operations and extends that reporting to a component
of an entity that either has been disposed of (by sale, abandonment, or in a
distribution to owners) or is classified as held for sale. By broadening the
presentation of discontinued operations to include more disposal transactions,
the FASB has enhanced managements ability to provide information that helps
financial statement users to assess the effects of a disposal transaction on
the ongoing operations of an entity.

                                     F-18
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000


   Statement No. 144 is effective for fiscal years beginning after December
15, 2001 and interim periods within those fiscal years. The Company does not
anticipate the adoption of SFAS 144 to have a material adverse impact on its
financial position or results of operations.

   In August, 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations". SFAS 143 addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and
the associated asset retirement costs. The standard applies to legal
obligations associated with the retirement of long-lived assets that result
from the acquisition, construction, development and (or) normal use of the
asset. SFAS 143 requires that the fair value of a liability for an asset
retirement obligation be recognized in the period in which it is incurred if a
reasonable estimate of fair value can be made. The fair value of the liability
is added to the carrying amount of the associated asset and this additional
carrying amount is depreciated over the life of the asset. The liability is
accreted at the end of each period through charges to operating expense. If
the obligation is settled for other than the carrying amount of the liability,
the Company will recognize a gain or loss on settlement.

   Implementation of SFAS 143 is required for fiscal year 2003. To accomplish
this, the Company must identify all legal obligations for asset retirement
obligations, if any, and determine the fair value of these obligations on the
date of adoption. The determination of fair value is complex and will require
the Company to gather market information and develop cash flow models.
Additionally, the Company will be required to develop processes to track and
monitor theses obligations. Due to the effort necessary to comply with the
adoption of SFAS 143, it is not practicable for management to estimate the
impact of adopting SFAS 143 at the date of this report.

   In July 2001, the FASB issued SFAS 141, "Business Combinations' and SFAS
142, "Goodwill and Other Intangible Assets". SFAS 141 requires that all
business combinations be accounted for under the purchase method and that
certain intangible assets in a business combination be recognized as assets
apart from goodwill. The company is required to implement SFAS 141 for all
business combinations for which the date of acquisition is July 1, 2001 or
later. SFAS 142 requires that ratable amortization of goodwill be replaced
with periodic tests of the impairment of goodwill and that intangible assets
other than goodwill should be amortized over their useful lives.
Implementation of SFAS 142 is required for fiscal year 2002. The Company does
not anticipate the adoption of SFAS 142 to have a material adverse impact on
its financial position or results of operations.

(13) FINANCIAL INSTRUMENTS

 Oil and Natural Gas Derivatives

   At December 31, 2001, the Company has a collar on 40,000 Mmbtu of daily
natural gas production for the NYMEX contract period of January through March
of 2002, with a floor of $2.67/Mmbtu and a ceiling of $3.15/Mmbtu.
Additionally, 3TEC has placed 56,000 Mmbtu of daily natural gas production
from April through October of 2002 into a collar with a floor of $2.90/Mmbtu
and an average ceiling of $3.38/Mmbtu. The fair value of these contracts at
December 31, 2001 was approximately $3.1 million. The Company did not
designate these derivative instruments as hedges as such these contracts have
been marked-to-market through earnings at December 31, 2001 and will be during
each quarter that the contract is outstanding.

   During February 2002, the Company unwound the April through October 2002
collar for net proceeds of approximately $5.8 million ($.48 per Mmbtu), and
then swapped 56,000 Mmbtu of daily natural gas production at $2.56/Mmbtu. Also
during February 2002, the Company put in place a collar on 20,000 Mmbtu of
daily gas production from November 2002 to March 2003 with a floor of
$3.20/Mmbtu and a weighted average ceiling of $3.53/Mmbtu.

                                     F-19
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000


   At December 31, 2000, the Company had no open derivative instruments.

   In February 2000, the Company entered into fixed swap agreements covering
2,000 barrels of oil per day for the period March through October 2000 at a
weighted average NYMEX West Texas Intermediate price of $25.96 per barrel.
During the year ended December 31, 2000, the Company's oil revenues were
reduced by the effect of the hedge by $2.1 million.

   Fair value of cash, receivables and payables approximates carrying value.
Fair value of long-term debt also approximates carrying value due to the
nature of the Credit Facility, whereby the interest rates are floating rates
which reflect market rates.

 Counterparty Risk

   The Company's couterparties to the derivative contracts open at December
31, 2001 are Bank One, NA and Bank of Montreal, both commercial banks who are
also participants in the Company's Credit Facility. We feel the credit-
worthiness of our current counterparties is sound and do not anticipate any
non-performance of contractual obligations.

(14) QUARTERLY FINANCIAL DATA (Unaudited)

   The following unaudited summarized quarterly financial data is presented in
thousands, except per share data.

<TABLE>
<CAPTION>
                                                         2001
                                           ----------------------------------
                                             1st     2nd
                                            Qtr.    Qtr.   3rd Qtr.  4th Qtr.
                                           ------- ------- --------  --------
<S>                                        <C>     <C>     <C>       <C>
Total Revenues............................ $44,731 $40,332 $ 17,995  $ 19,721
Operating Income (loss)...................  26,294  21,495     (766)  (19,024)
Net Income (loss).........................  16,177  13,209     (915)  (11,623)
Net Income (loss) per share (fully-
 diluted)................................. $  0.86 $  0.70 $  (0.07) $  (0.72)
<CAPTION>
                                                         2000
                                           ----------------------------------
                                             1st     2nd
                                            Qtr.    Qtr.   3rd Qtr.  4th Qtr.
                                           ------- ------- --------  --------
<S>                                        <C>     <C>     <C>       <C>
Total Revenues............................ $17,609 $22,130 $ 27,308  $ 37,776
Operating Income..........................   4,764   7,505   13,852    20,290
Net Income................................   3,116   4,914    9,085    14,549
Net Income per share (fully-diluted)...... $  0.35 $  0.50 $   0.50  $   0.93
</TABLE>

   The financial results of the Company have been restated for the first and
second quarters of 2001. The changes reflect adjustments to oil and natural
gas production and revenues as a result of the Company's overaccrual of
revenue related to these quarters. The impact of the adjustments decreased the
previously reported amounts as follows:

<TABLE>
<CAPTION>
                                                                      2001
                                                                 ---------------
                                                                  1st
                                                                  Qtr.  2nd Qtr.
                                                                 ------ --------
<S>                                                              <C>    <C>
Total Revenues.................................................. $4,345  $3,494
Cost and operating expenses.....................................    693     961
Operating Income................................................  3,652   2,533
Net Income......................................................  2,272   1,571
Net Income per share, (fully-diluted)...........................   0.12    0.08
</TABLE>

                                     F-20
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000


(15) SUBSEQUENT EVENTS

   During January 2002, the $13.9 million of cash being held in like-kind
escrow accounts was returned to the Company and used to pay down borrowings
under the Company's Credit Facility.

   During February 2002, the Company unwound the April through October 2002
collar for net proceeds of approximately $5.8 million ($.48 per Mmbtu), and
then swapped 56,000 Mmbtu of daily natural gas production at $2.56/Mmbtu. Also
during February 2002, the Company put in place a collar on 20,000 Mmbtu of
daily gas production from November 2002 to March 2003 with a floor of
$3.20/Mmbtu and a weighted average ceiling of $3.53/Mmbtu.

(16) SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)

 Capitalized Costs and Costs Incurred

   The following tables present the capitalized costs related to oil and
natural gas producing activities and the related depreciation, depletion,
amortization and impairment as of December 31, 2001 and 2000 and costs
incurred in oil and natural gas property acquisition, exploration and
development activities (in thousands) for the years ended December 31, 2001
and 2000.

<TABLE>
<CAPTION>
                                                              2001      2000
                                                            --------  --------
<S>                                                         <C>       <C>
Capitalized Costs
  Proved properties........................................ $374,449  $263,801
  Nonproducing leasehold...................................   10,974     6,477
  Accumulated depreciation, depletion, amortization and
   impairment..............................................  (70,299)  (54,260)
                                                            --------  --------
Net capitalized costs...................................... $315,124  $216,018
                                                            ========  ========
Costs Incurred
  Proved properties........................................ $ 75,765  $ 79,770
  Unproved properties......................................    8,560        95
  Exploration costs........................................   19,731       695
  Development costs........................................   63,358    25,346
                                                            --------  --------
    Total.................................................. $167,414  $105,906
                                                            ========  ========
Depletion, depreciation, amortization and impairment....... $ 32,982  $ 18,459
                                                            ========  ========
</TABLE>

 Estimated Quantities of Reserves

   The Company has interests in oil and natural gas properties that are
located principally in Texas, Louisiana, Oklahoma and New Mexico. The Company
does not own or lease any oil and natural gas properties outside the United
States. There are no quantities of oil and natural gas subject to long-term
supply or similar agreements with any governmental agencies.

   The Company retains independent engineering firms to provide year-end
estimates of the Company's future net recoverable oil, natural gas and natural
gas liquids reserves. In 2001 and 2000, such estimates were prepared by Ryder
Scott Company. The reserve information was prepared in accordance with
guidelines established by the Securities and Exchange Commission.

   Estimated proved net recoverable reserves as shown below include only those
quantities that can be expected to be commercially recoverable at prices and
costs in effect at the balance sheet dates under existing

                                     F-21
<PAGE>

                   3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                          December 31, 2001 and 2000

regulatory practices and with conventional equipment and operating methods.
Proved developed reserves represent only those reserves expected to be
recovered through existing wells. Proved undeveloped reserves include those
reserves expected to be recovered from new wells or on undrilled acreage or
from existing wells on which a relatively major expenditure is required for
recompletion.

   Net quantities of proved developed and undeveloped reserves of oil,
including condensate and natural gas liquids, for the years ended December 31,
2001 and 2000 are summarized as follows:

<TABLE>
<CAPTION>
                                             2001                 2000
                                      -------------------  -------------------
                                          Oil       Gas        Oil       Gas
                                      (MBbls) (1) (MMcf)   (MBbls) (1) (MMcf)
                                      ----------- -------  ----------- -------
<S>                                   <C>         <C>      <C>         <C>
Proved Reserves Beginning of year....   10,672    237,693     9,835    159,699
  Purchases of reserves in place.....      211     33,712     1,981     85,437
  Extensions and discoveries.........      308     11,547        51      2,699
  Revisions of previous estimates....   (1,520)   (18,822)      659      8,698
  Sales of reserves in place.........   (3,382)   (10,512)     (715)    (1,076)
  Production for the year............     (952)   (22,352)   (1,139)   (17,764)
                                        ------    -------    ------    -------
    End of year......................    5,337    231,266    10,672    237,693
                                        ======    =======    ======    =======
Proved Developed Reserves............
  Beginning of year..................    9,895    177,252     9,358    122,914
                                        ======    =======    ======    =======
  End of year........................    4,705    175,659     9,895    177,252
                                        ======    =======    ======    =======
</TABLE>
--------
(1) Includes oil, condensate and plant product barrels.

 Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves

   The following is a summary of the standardized measure of discounted future
net cash flows related to the Company's proved oil and natural gas reserves.
For these calculations, estimated future cash flows from estimated future
production of proved reserves are computed using oil and natural gas prices as
of the end of each period presented. Future development and production costs
attributable to the proved reserves were estimated assuming that existing
conditions would continue over the economic lives of the individual leases and
costs were not escalated for the future. Estimated future income taxes were
calculated by applying statutory tax rates (based on current law adjusted for
permanent differences and tax credits) to the estimated future pre-tax net
cash flows related to proved oil and natural gas reserves, less the tax basis
of the properties involved.

   The Company cautions against using this data to determine the value of its
oil and natural gas properties. To obtain the best estimate of the fair value
of the oil and natural gas properties, forecasts of future economic
conditions, varying discount rates, and consideration of other than proved
reserves would have to be incorporated into the calculation. In addition,
there are significant uncertainties inherent in estimating quantities of
proved reserves and in projecting rates of production that impair the
usefulness of the data.

                                     F-22
<PAGE>

                    3TEC ENERGY CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                           December 31, 2001 and 2000


   The standardized measure of discounted future net cash flows relating to
proved oil and natural gas reserves for the years ended December 31, 2001 and
2000 are summarized as follows (in thousands):

<TABLE>
<CAPTION>
                                                          2001        2000
                                                        ---------  ----------
<S>                                                     <C>        <C>
Future cash inflows.................................... $ 628,537  $2,349,534
Future production costs and development costs..........  (243,201)   (352,703)
Future income tax expenses.............................   (58,051)   (676,227)
                                                        ---------  ----------
Future net cash flows..................................   327,285   1,320,604
10% discount to reflect timing of cash flows...........  (145,686)   (627,930)
                                                        ---------  ----------
Standardized measure of discounted future net cash
 flows................................................. $ 181,599  $  692,674
                                                        =========  ==========
</TABLE>

   The following are the principal sources of changes in the standardized
measure of discounted future net cash flows for the years ended December 31,
2001 and 2000 (in thousands):

<TABLE>
<CAPTION>
                                                            2001       2000
                                                          ---------  ---------
<S>                                                       <C>        <C>
Sales of oil and natural gas, net of production cost..... $ (89,410) $ (78,969)
Net changes in prices and production cost................  (765,134)   467,920
Extensions and discoveries...............................    11,388     15,393
Purchases of reserves....................................    26,461    397,280
Sales of reserves........................................   (22,682)    (8,789)
Revisions of previous quantity estimates.................   (24,809)    39,442
Net change in income taxes...............................   322,700   (304,816)
Accretion of discount....................................   104,736     19,843
Changes in production rates (timing) and other...........   (74,325)    (3,371)
                                                          ---------  ---------
Change for year.......................................... $(511,075) $ 543,933
                                                          =========  =========
</TABLE>

   The period end prices of oil and natural gas at December 31, 2001 and 2000,
used in the above table were $19.84 and $25.31 per barrel of oil and $2.57 and
$9.40 per thousand cubic feet of natural gas, respectively.


                                      F-23