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                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

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

                                   FORM 10-K

                ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) of
                      THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2000        Commission File No. 000-32261

                           ATP Oil & Gas Corporation
             (Exact name of registrant as specified in its charter)

                 Texas                                 76-0362774
      (State or other jurisdiction                  (I.R.S. Employer
   of incorporation or organization)               Identification No.)

                         4600 Post Oak Place, Suite 200
                              Houston, Texas 77027
              (Address of Principal Executive Offices) (Zip Code)

       Registrant's telephone number, including area code: (713) 622-3311

          Securities Registered Pursuant to Section 12(b) of the Act:

          Title of each class             Name of Exchange on which registered


Common Stock, par value $.001 per share                  NASDAQ

        Securities Registered Pursuant to Section 12(g) of the Act: None

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

   Indicate by check mark if disclosure of delinquent filers pursuant to item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this form 10-K. [X]

   State the aggregate market value of the voting and non-voting common equity
held by non-affiliates of the registrant:

   Voting common stock (as of March 30, 2001)                  $73,045,781

   Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date:

As of March 30, 2001  Common Stock, par value $.001 per share  20,285,714 shares

                      DOCUMENTS INCORPORATED BY REFERENCE

                                      None

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                           ATP Oil & Gas Corporation

                 FORM 10-K for the Year Ended December 31, 2000

                               TABLE OF CONTENTS

<TABLE>
<S>                                                                         <C>
PART I.....................................................................   3
  Item 1 Business..........................................................   3
  Item 2. Properties.......................................................  12
  Item 3. Legal Proceedings................................................  15
  Item 4. Submission of Matters to a Vote of Security Holders..............  15
PART II....................................................................  15
  Item 5. Market for Registrant's Common Equity and Related Stockholder
   Matters.................................................................  15
  Item 6. Selected Financial Data..........................................  16
  Item 7. Management's Discussion and Analysis of Financial Condition and
   Results of Operations...................................................  18
  Item 7A. Quantitative and Qualitative Disclosures about Market Risk......  25
  Item 8. Financial Statements and Supplementary Data......................  26
  Item 9. Changes in and Disagreements With Accountants on Accounting and
   Financial Disclosure....................................................  26
PART III...................................................................  27
  Item 10. Directors and Executive Officers of Registrant..................  27
  Item 11. Executive Compensation..........................................  31
  Item 12. Security Ownership of Certain Beneficial Owners and Management..  34
  Item 13. Certain Relationships and Related Transactions..................  34
PART IV....................................................................  35
  Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-
   K.......................................................................  35
SIGNATURES.................................................................  62
INDEX OF EXHIBITS..........................................................  63
</TABLE>
<PAGE>

             Cautionary Statement About Forward-Looking Statements

   Some of the information included in this annual report include assumptions,
expectations, projections, intentions or beliefs about future events. These
statements are intended as "forward-looking statements" under the Private
Securities Litigation Reform Act of 1995. We caution that assumptions,
expectations, projections, intentions and beliefs about future events may and
often do vary from actual results and the differences can be material.

   All statements in this document that are not statements of historical fact
are forward looking statements. Forward looking statements include, but are not
limited to:

  . projected operating or financial results;

  . budgeted or projected capital expenditures;

  . statements about pending or recent acquisitions, including the
    anticipated closing dates;

  . expectations regarding our planned expansions and the availability of
    acquisition opportunities;

  . statements about the expected drilling of wells and other planned
    development activities;

  . expectations regarding natural gas and oil markets in the United States
    and the United Kingdom; and

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

   When used in this document, the words "anticipate," "estimate," "project,"
"forecast," "may," "should," and "expect" reflect forward-looking statements.

   There can be no assurance that actual results will not differ materially
from those expressed or implied in such forward looking statements. Some of the
key factors which could cause actual results to vary from those expected
include:

  . the timing and extent of changes in natural gas and oil prices;

   .the timing of planned capital expenditures and availability of
acquisitions;

  . the inherent uncertainties in estimating proved reserves and forecasting
    production results;

  . operational factors affecting the commencement or maintenance of
    producing wells, including catastrophic weather related damage,
    unscheduled outages or repairs, or unanticipated changes in drilling
    equipment costs or rig availability;

  . the condition of the capital markets generally, which will be affected by
    interest rates, foreign currency fluctuations and general economic
    conditions;

  . cost and other effects of legal and administrative proceedings,
    settlements, investigations and claims, including environmental
    liabilities which may not be covered by indemnity or insurance; and

  . other U.S. or United Kingdom regulatory or legislative developments which
    affect the demand for natural gas or oil generally, increase the
    environmental compliance cost for our production wells or impose
    liabilities on the owners of such wells.

                                       1
<PAGE>

                      WHERE YOU CAN FIND MORE INFORMATION

   This Annual Report on Form 10-K, including related exhibits and schedules,
can be inspected and copied at the Public Reference Room maintained by the SEC
at 450 Fifth Street, N.W., Washington, D.C. 20549. Copies of all or any portion
of this Annual Report can be obtained after payment of fees prescribed by the
SEC. You may obtain information on the operation of the Public Reference Room
by calling the SEC at (800) SEC-0330. The SEC maintains a web site that
contains reports, proxy and information statements and other information
regarding registrants, including us, that file electronically with the SEC. The
address of the site is www.sec.gov.

   We are required to comply with the informational requirements of the
Securities Exchange Act of 1934 and, accordingly, will file current reports on
Form 8-K, quarterly reports on Form 10-Q, annual reports on Form 10-K, proxy
statements and other information with the SEC. Those reports, proxy statements
and other information will be available for inspection and copying at the
Public Reference Room and internet site of the SEC referred to above. We intend
to furnish our shareholders with annual reports containing consolidated
financial statements certified by an independent public accounting firm.

                                       2
<PAGE>

                                     PART I

Item 1. Business

About ATP Oil & Gas Corporation

   ATP was incorporated in Texas in 1991. We are engaged in the acquisition,
development and production of natural gas and oil properties in the outer
continental shelf of the Gulf of Mexico, in the shallow-deep waters of the Gulf
of Mexico and in the Southern Gas Basin of the U.K. North Sea. We primarily
focus our efforts on natural gas and oil properties with proved undeveloped
reserves that are economically attractive to us but are not strategic to major
or exploration-oriented independent oil and gas companies. We attempt to
achieve a high return on our investment in these properties by limiting our up-
front acquisition costs and by developing our acquisitions quickly. Our
management team has extensive engineering, geological, geophysical, technical
and operational expertise in successfully developing and operating properties
in both our current and planned areas of operation.

   At December 31, 2000, we had estimated net proved reserves of 125.4 Bcfe, an
increase of 20% over the previous year end. The estimated pre-tax PV-10 of our
reserves at December 31, 2000 was $744.8 million. Prices used in these reserve
estimates were $9.52 per MMbtu of natural gas and $23.75 per barrel of oil. At
December 31, 2000, natural gas accounted for 81% of our reserves, proved
developed reserves comprised 38% of our total reserves and our reserve life
index for total proved reserves was 5.1 years. At December 31, 2000, we had
leasehold and other interests in 47 offshore blocks, 21 platforms and 56 wells,
including six subsea wells, in the federal waters of the Gulf of Mexico. We
operate 53 of these 56 wells, including all of the subsea wells, and 90% of our
offshore platforms. Our average working interest in our properties at December
31, 2000 was approximately 86%.

   We produced approximately 24.5 Bcfe in 2000, an increase of 41% over the
previous year. For the five-year period since 1996, we have increased our
annual production at a compounded annual growth rate (CAGR) of 115%. We
increase our reserves and production exclusively through the acquisition and
development of proved natural gas and oil properties. During 2000, we replaced
187% of 2000 production through these activities, and from 1997 to 2000 we
achieved an average annual reserve replacement ratio of 259%. We believe
substantial additional acquisition opportunities exist in the outer continental
shelf of the Gulf of Mexico, the shallow-deep waters of the Gulf of Mexico and
in the Southern Gas Basin of the U.K. North Sea.

   We were listed on the 2000 Inc. 500 as the 5th fastest growing privately
held company in the United States, an improvement from our ranking as 21st in
the 1999 Inc. 500. In both 1999 and 2000, we were the fastest growing energy
company in those surveys. During 2000, we received a Growing with Technology
Award from Inc./Cisco for innovative utilization of technology in offshore oil
and gas development. In October 2000, we were recognized as the only North
American finalist in the year 2000 Financial Times and Deloitte Touche Tohmatsu
Energy Award for Best Oil & Gas Company. Also in 2000, we received Blue Chip
Enterprise recognition from MassMutual, and our company president and founder,
T. Paul Bulmahn, was selected Entrepreneur Of The Year in Energy & Energy
Services by Ernst & Young.

Our Business Strategy

   Our business strategy is to enhance shareholder value primarily through the
acquisition, development and production of proved undeveloped natural gas and
oil reserves in areas that have:

  . a substantial existing infrastructure and geographic proximity to well-
    developed markets for natural gas and oil;

  . a large number of properties that major oil companies, exploration-
    oriented independents and others consider non-strategic; and

  . a relatively stable history of consistently applied governmental
    regulations for offshore natural gas and oil development and production.

                                       3
<PAGE>

   Prior to 2000, our area of concentration was the outer continental shelf of
the Gulf of Mexico, which exhibits each of the above characteristics. In 2000,
we expanded our efforts into the shallow-deep waters of the Gulf of Mexico and
into the Southern Gas Basin of the U.K. North Sea, each of which we believe
also exhibits these characteristics.

   We believe our strategy significantly reduces the risks associated with
traditional natural gas and oil exploration. Unlike oil and gas companies that
conduct exploration activities, our focus is to acquire properties that have
been previously explored by others and found to contain proved reserves. During
the life span of these properties, they may become non-core or non-strategic to
their original owners. Reasons that a property may become non-core or non-
strategic are varied. For example, companies may elect to concentrate their
efforts elsewhere, to reduce their capital spending for development, or to
pursue exploration projects as opposed to development projects. Also, a lease
expiration date may be approaching and the owner may be unwilling to complete a
development program. Companies pursuing exploration success may discover
hydrocarbons which may not provide an acceptable economic return for them but
which may prove attractive to us. If such a project is economically attractive
to us and is in our core areas, we will attempt to acquire the project. Each
natural gas and oil discovery by another company in our core areas is a
potential opportunity for the application of our approach.

   We focus on developing projects in the shortest time possible between
initial investment and first revenue generated in order to maximize our rate of
return. Since we usually operate the properties in which we acquire a working
interest and begin a development program with proved reserves, we are able to
expeditiously commence a project's development. We typically initiate new
development projects by simultaneously obtaining the various required
components such as the pipeline and the production platform or subsea well
completion equipment. This strategy, combined with our ability to rapidly
evaluate and implement a project's requirements, allows us to complete the
development project and commence production as quickly and efficiently as
possible.

Our Strengths

  . Operating Efficiency. We emphasize a low overhead and operating expense
    structure. For 2000, our lease operating expense was $0.47 per Mcfe of
    production and our general and administrative expense was $0.22 per Mcfe
    of production. We believe that our focus on a low cost structure allows
    us to pursue the acquisition, development and production of properties
    that may not be economically attractive to others. For the three year
    period ended December 31, 2000, our total average cost incurred for
    finding and developing our net proved reserves was $1.29 per Mcfe.

  . Operating Control. As of December 31, 2000, we operated 90% of our
    offshore platforms and 100% of our subsea wells. Being an operator allows
    us greater control of costs, the timing and amount of capital
    expenditures, and the selection of completion and production technology.

  . Technical Expertise and Significant Experience. We have assembled a
    management team and technical staff with an average of 17 years of
    industry experience. Our technical staff has specific expertise in
    offshore property development, including the implementation of subsea
    completion technology.

  . Employee Ownership. Through employee ownership, we have built a staff
    whose business decisions are aligned with our shareholders. Our employees
    own 71% of ATP on a fully diluted basis.

Marketing and Delivery Commitments

   We sell most of our natural gas and oil production under price sensitive or
market price contracts. Our revenues, profitability and future growth depend
substantially on prevailing prices for natural gas and oil. The price received
by us for our non-hedged natural gas and oil production fluctuates widely.
Changes in the prices of natural gas and oil will affect the carrying value of
our proved reserves and our revenues, profitability and cash flow. Although we
are not currently experiencing any significant involuntary curtailment of our
natural gas or oil production, market, economic and regulatory factors may in
the future materially affect our ability to sell our natural gas or oil
production.

                                       4
<PAGE>

   We sell a portion of our natural gas and oil to end users through various
gas marketing companies. We are not dependent upon, or confined to, any one
purchaser or small group of purchasers. Due to the nature of natural gas and
oil markets and because natural gas and oil are commodities and there are
numerous purchasers in the areas in which we sell production, we do not believe
the loss of a single purchaser, or a few purchasers, would materially affect
our ability to sell our production.

Competition

   We compete with major and independent natural gas and oil companies for
property acquisitions. We also compete for the equipment and labor required to
operate and to develop these properties. Some of our competitors have
substantially greater financial and other resources. In addition, larger
competitors may be able to absorb the burden of any changes in federal, state
and local laws and regulations more easily than we can, which would adversely
affect our competitive position. These competitors may be able to pay more for
natural gas and oil properties and may be able to define, evaluate, bid for and
acquire a greater number of properties than we can. Our ability to acquire and
develop additional properties in the future will depend upon our ability to
conduct operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment. In addition,
some of our competitors have been operating in the Gulf of Mexico or in the
Southern Gas Basin of the U.K. North Sea for a much longer time than we have
and have demonstrated the ability to operate through a number of industry
cycles.

Regulation

   Federal Regulation of Sales and Transportation of Natural Gas. Historically,
the transportation and sale for resale of natural gas in interstate commerce
have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas
Policy Act of 1978 and Federal Energy Regulatory Commission regulations. 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 of 1978. In 1989, Congress enacted the
Natural Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act
of 1938 and Natural Gas Policy Act of 1978 price and non-price controls
affecting producer sales of natural gas effective January 1, 1993. Congress
could, however, re-enact 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 are 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 not unduly discriminatory basis for all natural gas
shippers. The Federal Energy Regulatory Commission has stated that it intends
for Order No. 636 and its future restructuring activities 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 pertaining to individual pipelines. However,
some appeals remain pending and the Federal Energy Regulatory Commission
continues to review and modify its regulations regarding the transportation of
natural gas. For example, the Federal Energy Regulatory Commission issued Order
No. 637 which;

  . lifts the cost-based cap on pipeline transportation rates in the capacity
    release market until September 30, 2002, for short-term releases of
    pipeline capacity of less than one year,

  . permits pipelines to file for authority to charge different maximum cost-
    based rates for peak and off-peak periods,

  . encourages, but does not mandate, auctions for pipeline capacity,

  . requires pipelines to implement imbalance management services,

                                       5
<PAGE>

  . restricts the ability of pipelines to impose penalties for imbalances,
    overruns and non-compliance with operational flow orders, and

  . implements a number of new pipeline reporting requirements.

   Order No. 637 also requires the Federal Energy Regulatory Commission Staff
to analyze whether the Federal Energy Regulatory Commission should implement
additional fundamental policy changes. These include whether to pursue
performance-based or other non-cost based ratemaking techniques and whether the
Federal Energy Regulatory Commission should mandate greater standardization in
terms and conditions of service across the interstate pipeline grid.

   In April 1999 the Federal Energy Regulatory Commission issued Order No. 603,
which implemented new regulations governing the procedure for obtaining
authorization to construct new pipeline facilities. In September 1999, the
Federal Energy Regulatory Commission issued a related policy statement
establishing a presumption in favor of requiring owners of new pipeline
facilities to charge rates for service on new pipeline facilities based solely
on the costs associated with such new pipeline facilities.

   We cannot predict what further 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 natural gas producers, gatherers and
marketers.

   The Outer Continental Shelf Lands Act, which the Federal Energy Regulatory
Commission implements as to transportation and pipeline issues, requires that
all pipelines operating on or across the Outer Continental Shelf provide open-
access, non-discriminatory service. Historically, the Federal Energy Regulatory
Commission has opted not to impose regulatory requirements under its Outer
Continental Shelf Lands Act authority on gatherers and other entities outside
the reach of its Natural Gas Act jurisdiction. However, the Federal Energy
Regulatory Commission recently issued Order No. 639, requiring that virtually
all non-proprietary pipeline transporters of natural gas on the Outer
Continental Shelf report information on their affiliations, rates and
conditions of service. The reporting requirements established by the Federal
Energy Regulatory Commission in Order No. 639 may apply, in certain
circumstances, to operators of production platforms and other facilities on the
Outer Continental Shelf, with respect to gas movements across such facilities.
Among the Federal Energy Regulatory Commission's stated purposes in issuing
such rules was the desire to increase transparency in the market, to provide
producers and shippers on the Outer Continental Shelf with greater assurance of
(a) open-access services on pipelines located on the Outer Continental Shelf
and (b) non-discriminatory rates and conditions of service on such pipelines.

   The Federal Energy Regulatory Commission retains authority under the Outer
Continental Shelf Lands Act to exercise jurisdiction over gatherers and other
entities outside the reach of its Natural Gas Act jurisdiction if necessary to
ensure non-discriminatory access to service on the Outer Continental Shelf. We
do not believe that any Federal Energy Regulatory Commission action taken under
its Outer Continental Shelf Lands Act jurisdiction will affect us in a way that
materially differs from the way it affects other natural gas producers,
gatherers and marketers.

   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, there is no assurance that the less stringent regulatory
approach recently pursued by the Federal Energy Regulatory Commission and
Congress will continue.

   Federal Leases. A substantial portion of our operations is located on
federal natural gas and oil leases, which are administered by the Minerals
Management Service pursuant to the Outer Continental Shelf Lands Act. These
leases are issued through competitive bidding and contain relatively
standardized terms. These leases require compliance with detailed Minerals
Management Service regulations and orders that are subject to interpretation
and change by the Minerals Management Service.

                                       6
<PAGE>

   For offshore operations, lessees must obtain Minerals Management Service
approval for exploration, development and production plans prior to the
commencement of such operations. In addition to permits required from other
agencies such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency, lessees must obtain a permit from the Minerals
Management Service prior to the commencement of drilling. The Minerals
Management Service has promulgated regulations requiring offshore production
facilities located on the Outer Continental Shelf to meet stringent engineering
and construction specifications. The Minerals Management Service also has
regulations restricting the flaring or venting of natural gas, and has proposed
to amend such regulations to prohibit the flaring of liquid hydrocarbons and
oil without prior authorization. Similarly, the Minerals Management Service has
promulgated other regulations governing the plugging and abandonment of wells
located offshore and the installation and removal of all production facilities.

   To cover the various obligations of lessees on the Outer Continental Shelf,
the Minerals Management Service generally requires that lessees have
substantial net worth or post bonds or other acceptable assurances that such
obligations will be met. The cost of these bonds or assurances can be
substantial, and there is no assurance that they can be obtained in all cases.
We currently have several supplemental bonds in place. Under some
circumstances, the Minerals Management Service may require any of our
operations on federal leases to be suspended or terminated. Any such suspension
or termination could materially adversely affect our financial condition and
results of operations.

   The Minerals Management Service also administers the collection of royalties
under the terms of the Outer Continental Shelf Lands Act and the oil and gas
leases issued under the Act. The amount of royalties due is based upon the
terms of the oil and gas leases as well as of the regulations promulgated by
the Minerals Management Service. These regulations are amended from time to
time, and the amendments can affect the amount of royalties that we are
obligated to pay to the Minerals Management Service. However, we do not believe
that these regulations or any future amendments will affect us in a way that
materially differs from the way it affects other oil and gas producers, gathers
and marketers.

   Oil Price Controls and Transportation Rates. Sales of crude oil, condensate
and natural gas liquids by us are not currently regulated and are made at
market prices. In a number of instances, however, the ability to transport and
sell such products is dependent on pipelines whose rates, terms and conditions
of service are subject to Federal Energy Regulatory Commission jurisdiction
under the Interstate Commerce Act. In other instances, the ability to transport
and sell such products is dependent on pipelines whose rates, terms and
conditions of service are subject to regulation by state regulatory bodies
under state statutes.

   The regulation of pipelines that transport crude oil, condensate and natural
gas liquids is generally more light-handed than the Federal Energy Regulatory
Commission's regulation of gas pipelines under the Natural Gas Act. Regulated
pipelines that transport crude oil, condensate, and natural gas liquids are
subject to common carrier obligations that generally ensure non-discriminatory
access. With respect to interstate pipeline transportation subject to
regulation of the Federal Energy Regulatory Commission under the Interstate
Commerce Act, rates generally must be cost-based, although market-based rates
or negotiated settlement rates are permitted in certain circumstances. Pursuant
to Federal Energy Regulatory Commission Order No. 561, pipeline rates are
subject to an indexing methodology. Under this indexing methodology, pipeline
rates are subject to changes in the Producer Price Index for Finished Goods,
minus one percent. A pipeline can seek to increase its rates above index levels
provided that the pipeline can establish that there is a substantial divergence
between the actual costs experienced by the pipeline and the rate resulting
from application of the index. A pipeline can seek to charge market-based rates
if it establishes that it lacks significant market power. In addition, a
pipeline can establish rates pursuant to settlement if agreed upon by all
current shippers. A pipeline can seek to establish initial rates for new
services through a cost-of-service proceeding, a market-based rate proceeding,
or through an agreement between the pipeline and at least one shipper not
affiliated with the pipeline. The Federal Energy Regulatory Commission
indicated in Order No. 561 that it will assess in 2000 how the rate-indexing
method is operating. The Federal Energy Regulatory Commission issued a Notice
of Inquiry on July 27, 2000 seeking comment on whether to retain or to change
the existing index.

                                       7
<PAGE>

   With respect to intrastate crude oil, condensate and natural gas liquids
pipelines subject to the jurisdiction of state agencies, regulation is
generally less rigorous than the regulation of interstate pipelines. State
agencies have generally not investigated or challenged existing or proposed
rates in the absence of shipper complaints or protests. Complaints or protests
have been infrequent and are usually resolved informally.

   We do not believe that the regulatory decisions or activities relating to
interstate or intrastate crude oil, condensate, or natural gas liquids
pipelines will affect us in a way that materially differs from the way it
affects other crude oil, condensate, and natural gas liquids producers or
marketers.

   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. Public interest in the
protection of the environment has increased dramatically in recent years.
Offshore drilling in some areas has been opposed by environmental groups and,
in some areas, has been restricted. To the extent laws are enacted or other
governmental action is taken that prohibits or restricts offshore drilling or
imposes environmental protection requirements that result in increased costs to
the natural gas and oil industry in general and the offshore drilling industry
in particular, our business and prospects could be adversely affected.

   The Oil Pollution Act of 1990 and related regulations impose a variety of
regulations on "responsible parties" related to the prevention of oil spills
and liability for damages resulting from such spills in United States waters. A
"responsible party" includes the owner or operator of a facility or vessel, or
the lessee or permittee of the area in which an offshore facility is located.
The Oil Pollution Act of 1990 assigns liability to each responsible party for
oil removal costs and a variety of public and private damages. While liability
limits apply in some circumstances, a party cannot take advantage of liability
limits if the spill was caused by gross negligence or willful misconduct or
resulted from violation of a federal safety, construction or operating
regulation. If the party fails to report a spill or to cooperate fully in the
cleanup, liability limits likewise do not apply. Even if applicable, the
liability limits for offshore facilities require the responsible party to pay
all removal costs, plus up to $75.0 million in other damages. Few defenses
exist to the liability imposed by the Oil Pollution Act of 1990.

   The Oil Pollution Act of 1990 also requires a responsible party to submit
proof of its financial responsibility to cover environmental cleanup and
restoration costs that could be incurred in connection with an oil spill. As
amended by the Coast Guard Authorization Act of 1996, the Oil Pollution Act of
1990 requires parties responsible for offshore facilities to provide financial
assurance in the amount of $35.0 million to cover potential Oil Pollution Act
of 1990 liabilities. This amount can be increased up to $150.0 million if a
study by the Minerals Management Service indicates that an amount higher than
$35.0 million should be required. On August 11, 1998, the Minerals Management
Service adopted a rule implementing these Oil Pollution Act of 1990 financial
responsibility requirements. We are in compliance with this rule.

   In addition, the Outer Continental Shelf Lands Act authorizes regulations
relating to safety and environmental protection applicable to lessees and
permittees operating on the Outer Continental Shelf. Specific design and
operational standards may apply to Outer Continental Shelf vessels, rigs,
platforms and structures. Violations of lease conditions or regulations issued
pursuant to the Outer Continental Shelf Lands Act can result in substantial
civil and criminal penalties, as well as potential court injunctions curtailing
operations and the cancellation of leases. Such enforcement liabilities can
result from either governmental or private prosecution.

   The Oil Pollution Act of 1990 also imposes other requirements, such as the
preparation of an oil spill contingency plan. We have such a plan in place. We
are also regulated by the Clean Water Act, which prohibits any discharge into
waters of the United States except in strict conformance with discharge permits
issued by federal or state agencies. We have obtained, and are in material
compliance with, the discharge permits necessary for our operations. We could
become subject to similar state and local water quality laws and regulations in
the future if we conduct production or drilling activities in state coastal
waters. Failure to comply with the ongoing requirements of the Clean Water Act
or inadequate cooperation during a spill event may subject a responsible party
to civil or criminal enforcement actions.

                                       8
<PAGE>

   The Comprehensive Environmental Response, Compensation, and Liability Act,
or 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 of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances 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. We could be subject to liability under CERCLA
because our drilling and production activities generate relatively small
amounts of liquid and solid wastes that may be subject to classification as
hazardous substances under CERCLA. These wastes must be brought to shore for
proper disposal under the Resource Conservation and Recovery Act. We minimize
this potential liability by selecting reputable contractors to dispose of our
wastes at government approved landfills or other types of disposal facilities.

   Our operations are also subject to regulation of air emissions under the
Clean Air Act and the Outer Continental Shelf Lands Act. Implementation of
these laws could lead to the gradual imposition of new air pollution control
requirements on our operations. Therefore, we may incur capital expenditures
over the next several years to upgrade our air pollution control equipment. We
could also become subject to similar state and local air quality laws and
regulations in the future if we conduct production or drilling activities in
state coastal waters. 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 development 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.

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

   U.K. Regulations of Natural Gas and Oil Production. Pursuant to the
Petroleum Act 1998, all natural gas and oil reserves contained in properties
located in Great Britain are the property of the U.K. government. The
development and production of natural gas and oil reserves in the U.K. North
Sea requires a petroleum production license granted by the U.K. government.
Prior to developing a field, we will be required to obtain from the Secretary
of State for Trade and Industry a consent to develop that field. We will also
be required to obtain the consent of the Secretary of State for Trade and
Industry in the event we wish to transfer an interest in a license.

   The terms of the petroleum production licenses are based on model license
clauses applicable at the time of the issuance of the license. Licenses
frequently contain regulatory provisions governing matters such as working
method, pollution and training, and reserve to the Secretary of State for Trade
and Industry the power to direct some of the licensee's activities. For
example, a licensee may be precluded from carrying out development or
production activities other than with the consent of the Secretary of State for
Trade and Industry or in accordance with a development plan which the Secretary
of State for Trade and Industry has approved. Breach of these requirements may
result in the revocation of the license. In addition, licenses that we acquire
may require us to pay fees and royalties on production and also impose certain
other duties on us.


                                       9
<PAGE>

   Our operations in the U.K. will be subject to the Petroleum Act 1998, which
imposes a health and safety regime on offshore natural gas and oil production
activities. The Petroleum Act 1998 also regulates the abandonment of facilities
by licensees. In addition, the Mineral Workings (Offshore Installations) Act
provides a framework in which the government can impose additional regulations
relating to health and safety. Since its enactment, a number of regulations
have been promulgated relating to offshore construction and operation of
offshore production facilities. Health and safety offshore is further governed
by the Health and Safety at Work Act 1974 and applicable regulations. Our
operations will also be subject to environmental laws and regulations imposed
by both the European Union and the U.K. Parliament.

   Petroleum production licenses require the approval of the Secretary of State
for Trade and Industry of a licensee to act as operator and who organizes or
supervises all or any of the development and production operations of natural
gas and oil properties subject thereto. As an operator we may obtain
operational services from third parties, but would remain fully responsible for
the operations as if we had conducted them ourself.

   Our operations in the U.K. may entail the construction of offshore pipelines
which are subject to the provisions of the Petroleum Act 1998 and other
legislation. The Petroleum Act 1998 requires a license to construct and operate
a pipeline in U.K. North Sea, including its continental shelf. Easements to
permit the laying of pipelines must be obtained from the Crown Estate
Commissioners prior to their construction. We plan to use capacity in existing
offshore pipelines in order to transport our gas. However, access to the
pipelines of a third party would need to be obtained on a negotiated basis, and
there is no assurance that we can obtain access to existing pipelines or, if
access is obtained, it may only be on terms that are not favorable to us.

   The natural gas we produce may be transported through the U.K.'s onshore
national gas transmission system, or NTS. The NTS is owned by a licensed gas
transporter, BG Transco plc. The terms on which Transco must transport gas are
governed by the Gas Acts 1986 and 1995, the gas transporter's license issued to
Transco under those Acts and a network code. For us to use the NTS, we must
obtain a shipper's license under the Gas Acts and arrange to have gas
transported by Transco within the NTS. We will therefore be subject to the
network code, which imposes obligations to payment, gas flow nominations,
capacity booking and system imbalance. Applying for and complying with a
shipper's license, and acting as a gas shipper, is expensive and
administratively burdensome. Alternatively, we may sell natural gas "at the
beach' before it enters the NTS or arrange with an existing gas shipper for
them to ship the gas through the NTS on our behalf.

Employees

   At December 31, 2000, we had 28 full-time employees and two contract
personnel in our Houston office and five full-time employees and three contract
personnel in our London office. None of our employees is 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
supervision, permitting and environmental assessment. Independent contractors
usually perform field and on-site production operation services for us,
including gauging, maintenance, dispatching, inspection and well testing.

                                       10
<PAGE>

                          GLOSSARY OF TECHNICAL TERMS

   Bbls. Barrels of crude oil or other liquid hydrocarbons.

   Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one bbl of crude oil, condensate or natural gas liquids.

   MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

   Mcf. Thousand cubic feet of natural gas.

   Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one bbl of crude oil, condensate or other liquid
hydrocarbons.

   MMBbls. Million barrels of crude oil or other liquid hydrocarbons.

   MMBtu. Million British Thermal Units.

   MMcf. Million cubic feet of natural gas.

   MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one bbl of crude oil, condensate or other liquid
hydrocarbons.

   Net feet of natural gas and condensate. The true vertical thickness of
reservoir rock estimated to both contain hydrocarbons and be capable of
contributing to producing rates.

   Pre-tax PV-10. 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.

   Proved developed reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery are included as "proved developed
reserves" only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.

   Proved undeveloped reserves. Reserves that are expected to be recovered from
new wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion. Reserves on undrilled acreage are
limited to those drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other undrilled units
are included only where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation. Estimates for
proved undeveloped reserves are not attributed to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.

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

   Shallow-deep waters. The waters in the Gulf of Mexico located between the
continental shelf and water depths of up to approximately 3,000 feet.

                                       11
<PAGE>

Item 2. Properties

General

   Since inception we have engaged in the acquisition, development and
production of natural gas and oil properties primarily in the outer continental
shelf of the Gulf of Mexico. During 2000 we entered into agreements to expand
our business to include the acquisition and development of properties in the
shallow-deep waters of the Gulf of Mexico and in the Southern Gas Basin of the
U.K. North Sea. At December 31, 2000, we had leasehold and other interests in
47 offshore blocks, 21 platforms and 56 wells, including six subsea wells, in
the federal waters of the Gulf of Mexico. We operate 53 of these 56 wells,
including all of the subsea wells, and 90% of our offshore platforms. Our
average working interest in our properties at December 31, 2000 was
approximately 86%. As of December 31, 2000, we had leasehold interests located
in the Gulf of Mexico covering approximately 177,000 gross and 157,000 net
acres.

Acquisitions During 2000

   Gulf of Mexico. During 2000 we acquired an interest in eleven lease blocks
covering nine separate properties in the Gulf of Mexico for total acquisition
costs of $7.5 million. Total proved reserves associated with these acquisitions
was 65.8 Bcfe net to our interest. Our working interest in these properties
range from 50% to 100%. We are the operator of all of the properties. Included
in these acquisitions were four blocks on three separate properties which
represent our first acquisitions in the shallow deep waters of the Gulf of
Mexico. Of the six properties in the outer continental shelf, two produced
during 2000 with the remainder scheduled to come on production during 2001. Two
of the three properties in the shallow deep waters are scheduled to begin
production in 2001. We intend to use the production and flow facilities of one
of these properties, after it ceases production, to develop the third of these
properties.

   Southern Gas Basin of the U.K. North Sea. In October 2000, we entered into a
letter of intent to acquire interests in three properties (five blocks) in the
Southern Gas Basin of the U.K. North Sea. Under the letter of intent, we would
acquire a 50% interest in one block, a 100% interest in one block and an 86%
interest in three blocks. The letter of intent provides that we would pay an
aggregate of (Pounds)2,500,000, approximately $3.6 million, for the three
properties at closing. We will make additional payments on a property by
property basis at first production and thereafter at designated production
levels. The aggregate payments at first production for all three fields would
total (Pounds)2,300,000, approximately $3.3 million. We do not expect first
production to occur until at least 2002. The aggregate payments for achieving
designated production levels for all three fields would total up to
(Pounds)1,650,000, approximately $2.4 million. Based on currently available
information we cannot reasonably estimate when such production levels may be
achieved.

Acquisitions During 2001

   Gulf of Mexico. In February 2001 we acquired three properties representing
13.5 Bcfe net to our interest. In March 2001 we acquired six additional
properties representing 7.8 Bcfe net to our interest. Total acquisition costs
for the above acquisitions was approximately $23.0 million. Eight of the above
properties were producing when acquired with additional development and
production planned during 2001.

   Southern Gas Basin of the U.K. North Sea. In March 2001 we acquired two of
the three properties covered by the October 2000 letter of intent. Total proved
reserves net to our interest in these two properties is approximately 40.0
Bcfe. Initial acquisition costs were (Pounds)1.6 million, approximately $2.3
million. Neither of the properties were producing when we acquired them. We
expect to begin development operations in 2001 with first production scheduled
for late 2002 or early 2003. The third property remains under the letter of
intent.

                                       12
<PAGE>

Natural Gas and Oil Reserves

   The following table presents our estimated net proved natural gas and oil
reserves and the net present value of our reserves at December 31, 2000 based
on reserve reports prepared by Ryder Scott Company, L.P. and Schlumberger
Holditch-Reservoir Technologies Consulting Services. The present values,
discounted at 10% per annum, of estimated future net cash flows before income
taxes shown in the table are not intended to represent the current market value
of the estimated natural gas and oil reserves we own.

   The present value of future net cash flows before income taxes as of
December 31, 2000 was determined by using the December 31, 2000 prices of $9.52
per MMBtu of natural gas and $23.75 per Bbl of oil.

<TABLE>
<CAPTION>
                                                        Proved Reserves
                                                 ------------------------------
                                                 Developed Undeveloped  Total
                                                 --------- ----------- --------
      <S>                                        <C>       <C>         <C>
      Natural gas (MMcf)........................   42,502     59,068    101,570
      Oil and condensate (MBbls)................      851      3,126      3,977
      Total proved reserves (MMcfe).............   47,610     77,823    125,433
      Pre-tax PV-10 (in thousands).............. $341,903   $402,923   $744,826
</TABLE>

   Our estimates of proved reserves in the table above do not differ from those
we have filed with other federal agencies. The process of estimating natural
gas and oil reserves is complex. It requires various assumptions, including
assumptions relating to natural gas and oil prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. We must
project production rates and timing of development expenditures. We analyze
available geological, geophysical, production and engineering data, and the
extent, quality and reliability of this data can vary. Therefore, estimates of
natural gas and oil reserves are inherently imprecise. Actual future
production, natural gas and oil prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable natural gas and
oil reserves most likely will vary from our estimates and these variances may
be material.

   You should not assume that the present value of future net cash flows
referred to in this annual report is the current market value of our estimated
natural gas and oil reserves. In accordance with SEC requirements, we generally
base the estimated discounted future net cash flows from proved reserves on
prices and costs on the date of the estimate. Actual future prices and costs
may differ materially from those used in the net present value estimate.

   Our business strategy is to acquire proved reserves, usually proved
undeveloped, and to bring those reserves on production as rapidly as possible.
At December 31, 2000, approximately 62% of our estimated equivalent net proved
reserves were undeveloped. Recovery of undeveloped reserves generally requires
significant capital expenditures and successful drilling and completion
operations. The reserve data assumes that we will make these expenditures.
Although we estimate our reserves and the costs associated with developing them
in accordance with industry standards, the estimated costs may be inaccurate,
development may not occur as scheduled and results may not be as estimated. The
following table highlights our history of bringing to production our proved
undeveloped reserves:

<TABLE>
<CAPTION>
                                              Year Ended December 31,
                         -----------------------------------------------------------------
                                 2000                  1999                  1998
                         --------------------- --------------------- ---------------------
                         Undeveloped Developed Undeveloped Developed Undeveloped Developed
                         ----------- --------- ----------- --------- ----------- ---------
<S>                      <C>         <C>       <C>         <C>       <C>         <C>
At January 1............       6         25         11         22          4         10
Acquisitions............      10          1          7          1         11          8
Divestitures............      --         (2)       (10)(1)     --         --         --
Undeveloped to
 productive                   (6)         6         (2)         2         (4)         4
Undeveloped to
 nonproductive..........      --         --         --         --         --         --
                             ---        ---        ---        ---        ---        ---
At end of period........      10         30          6         25         11         22
                             ===        ===        ===        ===        ===        ===
</TABLE>
--------
(1) Includes nine undeveloped exploration blocks that we sold. We retained a
    non-working future interest in seven of those blocks.

                                       13
<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 natural gas and oil for the periods indicated:

<TABLE>
<CAPTION>
                                                         Years Ended December
                                                                 31,
                                                         ----------------------
                                                          2000    1999    1998
                                                         ------  ------  ------
<S>                                                      <C>     <C>     <C>
Production:
  Natural gas (MMcf).................................... 22,410  16,533   9,026
  Oil and condensate (MBbls)............................    345     128     151
                                                         ------  ------  ------
    Total (MMcfe)....................................... 24,477  17,301   9,933
Average sales price per unit:
  Natural gas revenues from production (per Mcf)........ $ 4.20  $ 2.23    2.07
  Effects of hedging activities (per Mcf)...............  (1.19)  (0.23)     --
                                                         ------  ------  ------
    Average gas price................................... $ 3.01  $ 2.00  $ 2.07
  Oil and condensate revenues from production (per
   Bbl)................................................. $29.35  $15.37   11.50
  Effects of hedging activities (per Bbl)...............  (4.34)     --      --
                                                         ------  ------  ------
    Average oil price................................... $25.01  $15.37  $11.50
  Total revenues from production (per Mcfe)............. $ 4.26  $ 2.24  $ 2.05
  Effects of hedging activities (per Mcfe)..............  (1.16)  (0.22)     --
                                                         ------  ------  ------
    Total average price (per Mcfe)...................... $ 3.10  $ 2.02  $ 2.05
Expenses (per Mcfe):
  Lease operating....................................... $ 0.47  $ 0.32  $ 0.32
  General and administrative............................   0.22    0.20    0.26
  Depreciation, depletion and amortization--natural gas
   and
   oil properties.......................................   1.66    1.30    1.76
</TABLE>

Development and Acquisition Capital Expenditures

   The following table presents information regarding our net costs incurred in
the acquisition of proved properties and development activities (in thousands):

<TABLE>
<CAPTION>
                                                         Years Ended December
                                                                  31,
                                                        -----------------------
                                                         2000    1999    1998
                                                        ------- ------- -------
<S>                                                     <C>     <C>     <C>
Proved property acquisition costs...................... $ 7,534 $25,274 $12,070
Development costs......................................  68,982  30,777  23,866
                                                        ------- ------- -------
Total costs incurred................................... $76,516 $56,051 $35,936
                                                        ======= ======= =======
</TABLE>

Drilling Activity

   The following table shows our drilling and completion activity. 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 such
wells. We did not drill or complete any exploratory wells in any period
presented.

<TABLE>
<CAPTION>
                                                     Years Ended December 31,
                                                  ------------------------------
                                                     2000      1999      1998
                                                  ---------- --------- ---------
                                                  Gross Net  Gross Net Gross Net
                                                  ----- ---- ----- --- ----- ---
<S>                                               <C>   <C>  <C>   <C> <C>   <C>
Development Wells:
  Productive..................................... 12.0  11.0  3.0  2.2  5.0  5.0
  Nonproductive..................................  1.0   1.0   --   --   --   --
                                                  ----  ----  ---  ---  ---  ---
    Total........................................ 13.0  12.0  3.0  2.2  5.0  5.0
                                                  ====  ====  ===  ===  ===  ===
</TABLE>

                                       14
<PAGE>

   As of December 31, 2000, we were conducting completion activities on 1 gross
(1 net) well and drilling operations on 1 gross (1 net) well.

Productive Wells

   The following table presents the number of productive natural gas and oil
wells in which we owned an interest as of December 31, 2000. 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.

<TABLE>
<CAPTION>
                                                                        Total
                                                                      Productive
                                                                       Wells(1)
                                                                      ----------
                                                                      Gross Net
                                                                      ----- ----
      <S>                                                             <C>   <C>
      Natural gas.................................................... 36.0  32.1
      Oil............................................................  1.0   1.0
                                                                      ----  ----
        Total(1)..................................................... 37.0  33.1
                                                                      ====  ====
</TABLE>
--------
(1) Includes four gross and 3.2 net wells with multiple completions.

Acreage

   The following table presents information regarding our developed and
undeveloped acreage as of December 31, 2000.

<TABLE>
<CAPTION>
                                    Developed     Undeveloped
                                     Acreage        Acreage         Total
                                 --------------- ------------- ---------------
                                  Gross    Net   Gross   Net    Gross    Net
                                 ------- ------- ------ ------ ------- -------
<S>                              <C>     <C>     <C>    <C>    <C>     <C>
Gulf of Mexico-Shelf............ 133,245 116,125 22,620 22,620 155,865 138,745
Gulf of Mexico-Shallow Deep
 Waters.........................      --      -- 20,965 18,085  20,965  18,085
                                 ------- ------- ------ ------ ------- -------
  Total......................... 133,245 116,125 43,585 40,705 176,830 156,830
                                 ======= ======= ====== ====== ======= =======
</TABLE>

Item 3. Legal Proceedings

   From time to time, we may be a party to various legal proceedings. We
currently are not a party to any material litigation.

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

   No matters were submitted to a vote of security holders during the fourth
quarter of 2000.

                                    PART II

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

   Our authorized capital stock consists of 100,000,000 shares of common stock,
par value $0.001 per share, and 10,000,000 shares of preferred stock, par value
$0.001 per share. There were 20,285,714 shares of common stock and no shares of
preferred stock outstanding as of March 30, 2001. The number of record holders
of our common stock as of March 28, 2001 was seven. Our common stock is traded
on the Nasdaq National Market under the ticker symbol ATPG. There was no public
market for our common stock before February 6, 2001. The high sales price for
our common stock on the Nasdaq National Market for the period from February 6,
2001 (first trade after effective date) to March 30, 2001 was $14.563 per share
and the low sales price for the same period was $9.875 per share. The closing
price of our common stock on March 30, 2001 was $12.188 per share.

                                       15
<PAGE>

   We have never declared or paid any cash dividends on our common stock. We
currently intend to retain future earnings and other cash resources, 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. Payment of
any future dividends will be at the discretion of our board of directors after
taking into account many factors, including our financial condition, operating
results, current and anticipated cash needs and plans for expansion. In
addition, our current credit facility prohibits us from paying cash dividends
on our common stock. Any future dividends may also be restricted by any loan
agreements which we may enter into from time to time.

Item 6. Selected Financial Data

   The selected financial data on the following pages are as of and for the
years ended December 31, 2000, 1999, 1998, 1997 and 1996. The following data
should be read in conjunction with "Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the Company's
Consolidated Financial Statements, and related notes included in "Item 8,
Financial Statements and Supplementary Data" of this Annual Report on Form 10-
K.

                                       16
<PAGE>

<TABLE>
<CAPTION>
                                         Years Ended December 31,
                          -----------------------------------------------------------
                             2000        1999        1998        1997        1996
                          ----------  ----------  ----------  ----------  -----------
                                                                          (unaudited)
                                     (In thousands, except share data)
<S>                       <C>         <C>         <C>         <C>         <C>
Statement of Operations
 Data:
Revenues:
 Oil and gas
  production............  $   75,940  $   34,981  $   20,410  $    7,359   $   3,009
 Gas sold--marketing....       8,015       7,703          --          --          --
 Gain on sale of oil
  and gas properties....          33         287          --         304          --
                          ----------  ----------  ----------  ----------   ---------
   Total revenues.......      83,988      42,971      20,410       7,663       3,009
Costs and operating
 expenses:
 Lease operating........      11,559       5,587       3,193       1,513         308
 Gas purchased--
  marketing.............       7,788       7,402          --          --          --
 General and
  administrative........       5,409       3,541       2,591       1,170         505
 Depreciation,
  depletion and
  amortization..........      40,569      22,521      17,442       4,206       1,672
 Impairment of oil and
  gas properties........      10,838       7,509       5,072       5,787          --
 Realized loss on
  speculative
  position..............       4,662          --          --          --          --
 Unrealized loss on
  speculative
  position..............       7,249          --          --          --          --
 Other expense..........         450          --          --          --          --
                          ----------  ----------  ----------  ----------   ---------
 Total operating
  expenses..............      88,524      46,560      28,298      12,676       2,485
                          ----------  ----------  ----------  ----------   ---------
Net income (loss) from
 operations.............      (4,536)     (3,589)     (7,888)     (5,013)        524
Other income (expense):
Interest income.........         451         202         141         207          45
Interest expense........     (11,907)     (9,399)     (7,963)     (1,212)       (107)
                          ----------  ----------  ----------  ----------   ---------
Income (loss) before
 income taxes and
 extraordinary item.....     (15,992)    (12,786)    (15,710)     (6,018)        462
Income tax benefit
 (expense)..............       5,594       1,829          --          --          (1)
                          ----------  ----------  ----------  ----------   ---------
Income (loss) before
 extraordinary item.....  $  (10,398)    (10,957)    (15,710)     (6,018)        461
Gain on extinguishments
 of debt, net of tax....          --      29,185          --          --          --
                          ----------  ----------  ----------  ----------   ---------
Net income (loss).......  $  (10,398) $   18,228  $  (15,710) $   (6,018)  $     461
                          ==========  ==========  ==========  ==========   =========
Weighted average number
 of common shares
 outstanding:
 Basic..................  14,285,714  14,285,714  11,925,785  10,567,762   8,245,513
 Diluted................  14,285,714  14,285,714  11,925,785  10,567,762   8,245,513
Income (loss) per common
 share before
 extraordinary item:
 Basic..................  $    (0.73) $    (0.77) $    (1.32) $    (0.57)  $    0.06
 Diluted................  $    (0.73) $    (0.77) $    (1.32) $    (0.57)  $    0.06
Net income (loss) per
 common share:
 Basic..................  $    (0.73)       1.28  $    (1.32) $    (0.57)  $    0.06
 Diluted................  $    (0.73) $     1.28  $    (1.32) $    (0.57)  $    0.06
Other Financial Data:
Adjusted EBITDA(1)......  $   54,571  $   26,643  $   14,767  $    5,187   $   2,241
Adjusted EBITDA
 margin(2)..............          65%         62%         72%         68%         74%
<CAPTION>
                                            As of December 31,
                          -----------------------------------------------------------
                             2000        1999        1998        1997        1996
                          ----------  ----------  ----------  ----------  -----------
                                                                          (unaudited)
<S>                       <C>         <C>         <C>         <C>         <C>
Balance Sheet Data:
Cash and cash
 equivalents............  $   18,136  $   17,779  $    3,411  $    1,806   $   1,088
Working capital.........      (3,835)     14,115      (5,106)      3,340       2,574
Net oil and gas
 properties.............      98,725      72,278      47,612      33,355       5,201
Total assets............     161,993     107,054      61,354      48,906       9,074
Total long-term debt....     116,529      91,723      62,690      42,194          --
Total liabilities.......     175,172     109,835      82,363      54,217       8,369
Shareholders' equity
 (deficit)..............     (13,179)     (2,781)    (21,009)     (5,311)        705
</TABLE>
--------
(1) Net income (loss) before interest expense, income taxes, depreciation,
    depletion and amortization, impairment of natural gas and oil properties
    and unrealized gains and losses. Adjusted EBITDA is not a calculation based
    on generally accepted accounting principles and should not be considered as
    an alternative to net income (loss) or operating income (loss), as an
    indicator of a company's financial performance or to cash flow as a measure
    of liquidity. In addition, our Adjusted EBITDA calculation may not be
    comparable to other similarly titled measures of other companies. Adjusted
    EBITDA is included as a supplemental disclosure because it may provide
    useful information regarding our ability to service debt and to fund
    capital expenditures.
(2) Represents Adjusted EBITDA divided by total revenues.

                                       17
<PAGE>

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

   You should read the following discussion and analysis together with
"Selected Financial Data" and our Financial Statements and the notes to those
statements included elsewhere in this Form 10-K. This discussion contains
forward-looking statements based on our current expectations, assumptions,
estimates and projections about us and our industry. These forward-looking
statements involve risks and uncertainties. Our actual results could differ
materially from those indicated in these forward-looking statements as a result
of certain factors, as more fully described under "Cautionary Statement About
Forward-Looking Statements" and elsewhere in this annual report. We undertake
no obligation to update publicly any forward-looking statements, even if new
information becomes available or other events occur in the future.

Overview

   Our results of operations reflect rapid growth in natural gas and oil
production and revenues over the past three years driven primarily by our
strategy of acquiring and developing properties with proved undeveloped
reserves. We acquired 38 blocks from the beginning of 1998 through December
2000 and increased total proved reserves from 46.2 Bcfe at the beginning of
1998 to 125.4 Bcfe at the end of 2000, a compounded annual increase of 58%
during this three-year period. We increased production from 9,933 MMcfe in 1998
to 24,477 MMcfe in 2000, a compounded annual increase of 57% for these three
years. The acquisition and development of proved undeveloped natural gas and
oil properties has been the primary contributor to our oil and gas revenue
growth. During 2000, revenues have also reflected the positive effect of rising
prices for natural gas and oil, offset in part by our hedging activity. Our
revenues in future periods will reflect both our ability to continue to
identify, acquire and develop properties which are consistent with our
development strategy as well as commodity prices and hedging activity.

   Historically, we have financed our acquisitions and development activity
through a combination of borrowings and cash from operations. At December 31,
2000, we had $27.8 million outstanding under bank credit facility and $88.8
million outstanding under our development program credit agreement. In February
2001, we completed our initial public offering of 6,000,000 shares of common
stock resulting in proceeds net of underwriting discount of $78.3 million. We
will use the proceeds, together with cash on hand, to repay all of our
outstanding debt under our development program credit agreement. Future capital
requirements are expected to be met primarily through a combination of cash
from operations or borrowings.

   Our financial results are affected by hedging transactions we enter into
with respect to natural gas and oil prices. These hedging transactions
generally take the form of swaps or price collars with major financial or
commodities trading institutions. Our hedging activity during 2000 and 1999 was
significantly affected by the requirements of the lender under our development
program credit agreement. Our hedging activity was based on expected production
as required by our development program credit agreement. The details of our
current hedging positions are set forth under "Item 7A, Quantitative and
Qualitative Disclosures About Market Risk" below.

   We have hedges in place for 69,700 MMBtu/day of natural gas for the first
quarter of 2001 at an average price of $3.05 per MMBtu. We have lesser volumes
hedged after the end of the first quarter of 2001. Based on actual NYMEX
settlement prices for January through April of 2001 and NYMEX monthly
settlement prices on March 30, 2001 for the remainder of the year, our
operating income for 2001 as a result of hedging transactions would be
negatively affected by approximately $22.9 million in the first quarter and a
total of approximately $13.0 million in the remaining three quarters.

   In addition to the above financial hedges on natural gas, during 2000 we
entered into two written call option contracts that provide us a price for
natural gas above the then prevailing market price, but with a ceiling price.
For the period July 2000 through October 2000, we received NYMEX settlement
plus $0.15 with a ceiling price of $3.16 per MMBtu on 15,000 MMBtu per day. For
the period April 2001 through October 2001, we receive NYMEX settlement plus
$0.15 with a ceiling price of $3.50 per MMBtu on 10,000 MMBtu per day. We
recently determined that the above contracts do not qualify for hedge
accounting. As a result, we have revised previously reported amounts to account
for losses associated with these contracts on a mark-to-market

                                       18
<PAGE>

basis. See the Supplementary Quarterly Information Schedule (unaudited) on page
61 which incorporates the losses associated with these contracts. Because the
price of natural gas on March 31, 2001 was lower than the price at December 31,
2000, it is likely that we will recognize an unrealized gain for the first
quarter of 2001 on the contract that expires in October 2001.

   We use the successful efforts method of accounting for our investments in
natural gas and oil properties. Under this method, we capitalize lease
acquisition costs and intangible drilling and development costs on successful
wells and development nonproductive wells. Depreciation, depletion and
amortization of these capitalized costs are computed separately for each field
based on the unit of production method using only proved natural gas and oil
reserves.

   The successful efforts method of accounting requires us to review each of
our natural gas and oil properties on a field level for impairment when
circumstances indicate that the capitalized costs less accumulated
depreciation, depletion and amortization (also referred to as "carrying value")
of the property may not be recoverable. If the carrying value of the property
exceeds the expected future undiscounted cash flows, an amount equal to the
excess of the carrying value over the fair value of the property is charged as
an expense. An impairment results in a non-cash charge to earnings which
typically does not affect cash flow. Substantial impairment writedowns may
result in a reduction in our borrowing base under our bank credit facility
which would require us to use additional cash to reduce debt. Since 1998, we
have recorded impairments on       different properties. Impairment expense
totaled $10.8 million in 2000, $7.5 million in 1999 and $5.1 million in 1998.

   Since September 1999, we have granted options which are currently
outstanding to employees to purchase 23,752 shares of common stock at $1.40 per
share and 344,822 shares of common stock at $3.85 per share. One-third of the
options vest on each of April 10, 2001, February 9, 2002 and February 9, 2003.
We will recognize compensation expense based on the difference between the
exercise price for these options and the price of our stock offered to the
public in our initial public offering. The expense will be recognized in the
periods in which the options vest. Based upon the vesting schedule, we will
incur a non-cash compensation expense of approximately $3.2 million in 2001 and
approximately $0.6 million in 2002 relating to such option grants.

Results of Operations

Year Ended December 31, 2000 Compared to Year Ended December 31, 1999

   Oil and Gas Revenue. Our revenue from natural gas and oil production for
2000 increased over 1999 by 117%, from $35.0 million to $75.9 million. This
increase resulted from increases of 51% in realized natural gas prices and 63%
in realized oil prices as well as a 41% increase in production. The increase in
production volumes from 17,301 MMcfe to 24,477 MMcfe was attributable to ten
properties that were on production during 2000 that were not on production
during 1999. Hedging transactions reduced oil and natural gas revenues by $28.2
million, or $1.16 per Mcfe, in 2000 and $3.8 million, or $0.22 per Mcfe, in
1999.

   Marketing Revenue. During 2000, revenues from natural gas marketing
activities amounted to $8.0 million, an increase of $0.3 million from 1999. The
reason for the increase was a decrease in volumes offset by an increase in the
sales price per MMBtu. The daily natural gas contract decreased from 9,000
MMBtu per day in 1999 to 5,000 MMBtu per day in 2000. The decrease in volume
was offset by an average increase in the sales price per MMBtu from $2.34 in
1999 to $4.38 in 2000. For more information regarding this marketing activity,
please read "Subsidiary Activities" below.

   Lease Operating Expense. Our lease operating expense for 2000 increased 107%
from $5.6 million to $11.6 million. This increase was primarily the result of
an increase in the number of producing wells owned by us, an increase in their
total production volume and an increase in the level of workover activity.
During 1999, we held a working interest in 23 producing blocks (29 producing
wells/24.7 net wells). During 2000, we held a working interest in 27 producing
blocks (36 producing wells/31.6 net wells). For 1999, our net production from

                                       19
<PAGE>

these wells was 16,533 MMcf and 128,000 bbls. For 2000, our net production from
these wells was 22,410 MMcf and 345,000 bbls, an increase of 5,877 MMcf and
217,000 bbls. Workover spending increased from $0.4 million in 1999 to $2.6
million in 2000. The remaining increase in lease operating expense was
primarily attributable to transportation related costs. On a per Mcfe basis,
lease operating expense increased from $0.32 to $0.47.

   Gas Purchased-Marketing. Our cost of purchased gas was $7.8 million for 2000
compared to $7.4 million for 1999. The daily gas contract amount in our third
party marketing arrangement decreased from 9,000 MMBtu per day in 1999 to 5,000
MMBtu per day in 2000. Lower volumes were offset by an increase in the average
gas cost from $2.25 per MMbtu in 1999 to $4.26 per MMbtu in 2000.

   General and Administrative Expense. General and administrative expense
increased to $5.4 million for 2000 compared to $3.5 million for 1999. The
primary reason for the increase was the result of compensation and related
expenses increasing from $1.8 million to $3.3 million period to period. Our
total employees increased from 19 at December 31, 1999 to 33 at December 31,
2000. On an Mcfe basis, general and administrative expense was $0.22 in 2000
compared with $0.20 in 1999.

   Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense increased 80% during 2000 from $22.5 million to $40.6
million. The average depreciation, depletion and amortization rate was $1.66
per Mcfe during 2000 compared with $1.30 per Mcfe in 1999.

   Impairment Expense. As of December 31, 2000, the future undiscounted cash
flows for our properties were $931.2 million and the net book value for the
properties was $109.6 million before current year impairment expense. At
December 31, 1999, the future undiscounted cash flows for our properties were
$183.0 and the net book value for the properties was $79.8 million before
current year impairment expense. However, for three of our 33 properties in
2000 and four of our 26 properties in 1999, the future undiscounted cash flows
were less than their individual net book value. As a result, we recorded
impairments of $10.8 million in 2000 and $7.5 million in 1999. The impairments
in 2000 and 1999 were primarily the result of a reduction in recoverable
reserves individually attributable to the particular properties.

   Loss on Speculative Position. For 2000 we recorded an expense of $4.3
million ($1.7 million realized and $2.6 million unrealized) on a natural gas
derivative position as a result of our hedging position exceeding our expected
production in an upcoming period. In this situation, we are required to account
for the position using the mark-to-market method. In addition, we recorded an
expense of $7.6 million ($3.0 million realized and $4.6 million unrealized)
related to mark-to-market losses associated with our written call option
contracts.

   Other Expense. We recorded a charge of $0.5 million in 2000 relating to the
sale of a platform which was held for sale and included in other assets in
1999. There was no comparable expense for this account in 1999.

   Other Income (Expense). For 2000, interest expense was $11.9 million
compared to $9.4 million for 1999. Our borrowings increased from period to
period but were offset by a decrease in interest rates under our new
development program credit agreement. As required by applicable accounting
pronouncements, we capitalize interest while a property is being developed
until it is ready to commence production. During 2000 we capitalized $0.7
million of interest, and we capitalized $0.6 million of interest in 1999.

Year Ended December 31, 1999 Compared to Year Ended December 31, 1998

   Oil and Gas Revenue. Our revenue from natural gas and oil production for
1999 increased over 1998 revenues by 71.4%, from $20.4 million to $35.0 million
primarily as a result of increased production. Natural gas production increased
by 83.2% from 1998 to 1999 and realized natural gas prices fell by 3.4%. Oil
production decreased by 15.3% period to period but average realized prices for
oil increased by 33.7%. The increase in production volumes from 9,933 MMcfe to
17,301 MMcfe was attributable to new production resulting from development
activities on four properties which began production in the second half of
1998, new production resulting from development activities on four properties
that began producing in 1999, and

                                       20
<PAGE>

production from producing properties acquired in the fourth quarter of 1998.
Hedging transactions reduced oil and natural gas revenues by $3.8 million, or
$0.22 per Mcfe, in 1999. We had no hedging transactions in 1998.

   Marketing Revenue. During the year ended December 31, 1999, we recorded
revenues from gas marketing activities of $7.7 million. There were no
corresponding revenues for 1998. Gas marketing activities relate to the sale of
9,000 MMBtu per day to an unrelated entity. The average sales price during 1999
was $2.34 per MMBtu.

   Lease Operating Expense. Our lease operating expense for 1999 increased by
75.0%, from $3.2 million to $5.6 million. The increase in expense was primarily
the result of an increase in our number of producing wells and our total
production volume. During 1998, we held a working interest in 22 producing
blocks (27 producing wells/19.5 net wells). During 1999, we held a working
interest in 23 producing blocks (29 producing wells/24.7 net wells). For 1998,
our net production from these wells was 9,026 MMcf and 151,152 bbls. For 1999,
our net production from these wells was 16,533 MMcf and 127,986 bbls, an
increase of 7,507 MMcf and a decrease of 23,166 bbls. On a per Mcfe basis,
lease operating expense remained unchanged at $0.32 per Mcfe.

   Gas Purchased-Marketing. In 1999 we purchased 9,000 MMBtu per day for a
total cost of $7.4 million. The average cost of purchases in 1999 was $2.25 per
MMBtu. There was no corresponding expense in 1998.

   General and Administrative Expense. General and administrative expense
increased to $3.5 million in 1999 from $2.6 million in 1998. The primary reason
for the increase was the result of compensation and related expenses increasing
to $1.8 million in 1999 compared with $1.2 million in 1998. Our total number of
employees increased from 11 at January 1, 1998 to 15 at December 31, 1998 and
to 19 at December 31, 1999. On an Mcfe basis, general and administrative
expense decreased from $0.26 during 1998 to $0.20 during 1999.

   Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense increased 29.1% from $17.4 million in 1998 to $22.5
million in 1999. Our average depreciation, depletion and amortization rate was
$1.30 per Mcfe in 1999 and $1.76 per Mcfe in 1998. This decrease was
attributable to production in 1999 from properties that required a lower
relative development cost than the average cost of the producing properties in
1998.

   Impairment Expense. As of December 31, 1999, the future undiscounted cash
flows for our properties were $183.0 million and the net book value for the
properties was $79.8 million before current year impairment expense. At
December 31, 1998, the future undiscounted cash flows for our properties were
$69.6 million and the net book value for the properties was $52.7 million
before current year impairment expense. However, for four of our 26 properties
in 1999 and four of our 20 properties in 1998, the future undiscounted cash
flows were less than their individual net book value. As a result, we recorded
impairments of $7.5 million in 1999 and $5.1 million in 1998. The impairments
in 1998 and 1999 were primarily the result of depressed natural gas and oil
prices and a reduction in recoverable reserves individually attributable to the
particular properties.

   Other Income (Expense). Other income (expense) consists primarily of
interest income and interest expense. For the year ended December 31, 1999,
interest income was $0.2 million compared to $0.1 million for the same period
in 1998. This increase was primarily the result of the implementation of a new
cash management system in late 1999. For 1999, interest expense was $9.4
million compared to $8.0 million for 1998. This increase was primarily the
result of an increase in our non-recourse borrowings under our development
program credit agreement. During 1999, we capitalized $0.6 million of interest
incurred while developing properties. We capitalized $1.6 million during 1998
for the same purpose.

   Extraordinary Gain. In June 1999, we agreed with the lender under a prior
development program credit agreement to prepay the amount outstanding at a
discount. As a result, we recorded an extraordinary gain of $29.2 million.

                                       21
<PAGE>

Liquidity and Capital Resources

   We have financed our acquisition and development activity through a
combination of project-based development and bank borrowing as well as cash
from operations. At December 31, 2000, we had $88.8 million outstanding under
our development program credit agreement and $27.8 million outstanding under
our bank credit facility.

   Our operating activities contributed cash flow, including changes in working
capital, as follows:

<TABLE>
<CAPTION>
                                             Cash flow
            Period                        from operations
            ------                        ---------------
            <S>                           <C>
            1998.........................  $13.2 million
            1999.........................  $10.8 million
            2000.........................  $56.6 million
</TABLE>


 Development Program Credit Agreement

   We entered into our current development program credit agreement in April
1999. Loans outstanding under the agreement are secured only by the properties
financed and are non-recourse to us, meaning that, if we default in making loan
payments, the lender can seek repayment only from the properties.

   From April 1999 through December 2000, we included 14 properties in this
financing and obtained total funding of $118.2 million. The lender receives 90%
of the monthly net revenues (after payment of operating costs) from the pledged
properties. From April 1999 through December 2000, we made payments to the
lender of $42.8 million, including interest, under the facility. The average
interest rate was 11.5% in 1999 and 12.7% during 2000. At December 31, 2000,
the amount outstanding was $88.8 million at an interest rate of 13.0%.

   The lender has overriding royalty interest rights in each of the 14
properties included in the collateral base for the development program credit
agreement. Ten of the 14 properties are subject to a 6.25% overriding royalty
interest which begins when the full amount of outstanding under the credit
agreement is repaid. The royalty interest is limited to the estimated proved
reserves attributable to the properties at the time the properties were added
to the collateral base less production after such date. Three of these ten
properties also are subject to a 3.125% overriding royalty on certain specified
levels of production above the proved reserves subject to the 6.25% interest.
The lender is not entitled to either of these interests unless the full amount
owed under the credit agreement has been repaid or the properties are removed
from the collateral base. Four of the 14 properties included in the collateral
base are subject to a 6.25% overriding royalty interest in all future
production when the full amount outstanding under the credit agreement is
repaid if the amounts outstanding under the credit agreement are not repaid in
full prior to May 1, 2001. This 6.25% interest is not limited to any specified
amount of reserves.

   Since the amount of reserves attributable to these overriding royalty
interests depend upon the timing of our repayment of the amounts borrowed,
these overriding royalty interests are not reflected in the reserve information
included in this annual report. We will repay the full amount borrowed under
the development program credit agreement with the proceeds of our initial
public offering and cash on hand. Based on our expected level of production for
January through March 2001, our lender will receive overriding royalty
interests of 1.3 Bcf in the group of ten properties described above and no
interest in the other four properties when we make the final payment.

 Bank Credit Agreement

   In September 1998, we entered into a revolving credit facility with Chase
Bank of Texas, N.A., as administrative agent. The amount available for
borrowing under the facility is limited to the loan value, as determined by the
bank, of certain oil and gas properties pledged under the facility. At December
31, 2000, the borrowing base was $27.8 million, all of which was outstanding.
Our borrowings under the credit facility have been repaid in full as of March
30, 2001.

                                       22
<PAGE>

   Advances under the credit facility can be in the form of either base rate
loans or Eurodollar loans. The interest on a base rate loan is a fluctuating
rate equal to the higher of the Federal funds rate plus 0.5% and the bank base
rate, plus a margin of either 0.625%, 0.875%, or 1.25% depending on the amount
outstanding under the credit agreement. The interest on a Eurodollar loan is
equal to the Eurodollar rate quoted by Chase Bank, plus a margin of 2.375%,
2.625%, or 3.00% depending on the amount outstanding under the credit facility.
The credit facility matures in January 2002. Prior to maturity, there are
scheduled reductions in the amount that may be outstanding. The average per
annum interest rate on borrowings under the credit facility was approximately
10.0% at December 31, 2000, 8.9% at December 31, 1999, and 8.1% at December 31,
1998.

   In connection with our credit facility, we are not permitted to:

  . enter into any arrangement to sell or transfer any of our material
    property;

  . merge into or consolidate with any other person or sell or dispose of all
    or substantially all of our assets;

  . allow the ratio of our current assets to our current liabilities to be
    less than 1:1 at any time.

  . allow our ratio of debt to our consolidated Adjusted EBITDA for four
    consecutive quarters to be greater than 3 to 1.

  . allow our ratio of Adjusted EBITDA for four consecutive quarters to
    interest payments made during those quarters to be less than 2.5 to 1.

  . declare or pay any cash dividend; purchase, redeem or otherwise acquire
    for value any of our outstanding stock; return capital to shareholders;
    or make any distribution of our assets to our shareholders.

   As of December 31, 2000, we were in compliance with all of the financial
covenants of our credit facility other than our covenant to maintain a current
ratio of at least 1:1 for which we have obtained a waiver from our lender.

 Capital Expenditures

   Our capital expenditures consist primarily of acquisition and development
costs related to our oil and gas properties. We invested the following amounts
in oil and gas properties:

<TABLE>
<CAPTION>
                                                                  Investments in
                                                                   Oil and Gas
                             Period                                 Properties
                             ------                               --------------
                                                                  (In millions)
                                                                  --------------
<S>                                                               <C>
1998:
  Acquisition costs (5 properties)...............................     $12.0
  Development costs (6 properties)...............................      23.9
                                                                      -----
                                                                      $35.9
1999:
  Acquisition costs (6 properties)(1)............................     $25.3
  Development costs (14 properties)..............................      30.8
                                                                      -----
                                                                      $56.1
2000:
  Acquisition costs (8 properties)(1)............................     $ 7.5
  Development costs (19 properties)..............................      69.0
                                                                      -----
                                                                      $76.5
</TABLE>
--------
(1) Acquisition costs include amounts paid to acquire additional working
    interests in properties in which we did not already own a 100% working
    interest.

                                       23
<PAGE>

   We estimate our capital expenditure requirements on a project by project
basis. At the beginning of the year, we estimate the development costs for our
projects in inventory for that year. During the year as properties are acquired
and scheduled for development, our actual level of capital spending may
increase significantly. For example, at the beginning of 1999, we identified
capital expenditures on projects then in inventory of $11.1 million. As a
result of acquisition opportunities and additional development spending on
newly acquired properties, our capital expenditures for the year totaled $56.1
million. At the beginning of 2000, we had identified capital expenditures of
$29.0 million for development projects in inventory. As a result of current
year acquisitions and additional development expenditures on newly acquired
projects, at December 31, 2000, we had incurred capital expenditures of $76.5
million. Based on our inventory of properties at December 31, 2000 we had
identified capital expenditures of $84.9 million for 2001 and $52.6 million in
future years. Included in these capital expenditures are $0.5 million in 2001
for dismantlement, restoration and abandonment costs and $17.5 million in
future years. In addition, we are constantly seeking new opportunities that fit
our business strategy. Thus far in 2001 we have closed on eleven new properties
for total acquisition costs of $25.3 million and have executed a letter of
intent to acquire another property for an acquisition cost of approximately
$1.3 million. See "Properties--Acquisitions During 2001". Our desire to
continue to acquire more natural gas and oil reserves in a year than we produce
will result in our incurring additional capital expenditures for properties
that we acquire in the future.

   We depend entirely on the acquisition and development of new properties to
replace our existing reserves. Therefore, we will continue to seek
opportunities for acquisitions of proved reserves with development potential.
The size and timing of capital requirements for acquisitions is inherently
unpredictable. Actual levels of future capital expenditures and their timing
may vary significantly due to a variety of factors, including:

  . drilling results;

  . product prices;

  . industry conditions and outlook; and

  . future acquisitions of properties.

   We believe that cash flow from operations and borrowings will be sufficient
to fund our operations through 2001.

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

Subsidiary Activities

   In December 1998, our wholly-owned subsidiary, ATP Energy, entered into an
agreement to purchase gas over a ten-year period commencing January 1999. The
amount of gas to be purchased was 9,000 MMBtu per day for the first year and
5,000 MMBtu per day for years two through ten. The contract requires ATP Energy
to purchase the gas on a monthly basis at a premium to the Gas Daily Henry Hub
Index. The seller is required to reimburse ATP Energy on a monthly basis for a
portion of this premium during the term of the contract. The terms of the
agreement provide for immediate termination upon non-performance by the seller.
ATP Energy entered into a contract in December 1998 to sell an identical
quantity of natural gas at the Gas Daily Henry Hub index price less $0.015
until December 2001.

   ATP Energy received $6.0 million in connection with these transactions of
which $2.0 million was recorded as deferred revenue and $4.0 million was
recorded as deferred obligations as of December 31, 1998. The deferred revenue
amount of $2.0 million is a non-refundable fee received by ATP Energy and is
recognized into income as earned over the life of the contract. The deferred
obligation amount of $4.0 million represented the difference between the
premium we agreed to pay for natural gas under the contract and the obligation
of

                                       24
<PAGE>

the seller to partially reimburse us for such premium. Any deferred obligation
amount not utilized is refundable if the contract is terminated. The remaining
balance of the deferred obligation was $0.1 million at December 31, 2000. The
premium we pay to the seller will be approximately the same as the
reimbursement obligation for the remainder of the contract. ATP Energy entered
into the transactions to earn the fee for agreeing to market the volumes of
natural gas specified in the contract. At the end of this agreement in December
2001, we may renew the agreement or enter into another marketing arrangement
having similar terms.

   We formed ATP Oil & Gas (UK) Limited on May 5, 2000 to conduct our
activities in the Southern Gas Basin of the U.K. North Sea. See "Item 2,
Properties--Significant Acquisitions in Progress" for a description of our
pending acquisitions in the U.K.

Recent Accounting Pronouncements

   In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for
Derivative Instruments and Hedging Activities, and in June 2000, the FASB
issued SFAS No. 138, Accounting for Certain Derivative Instruments and Certain
Hedging Activities, an amendment of FASB Statement No. 133. These statements
establish standards of accounting for and disclosures of derivative instruments
and hedging activities. We adopted this standard on January 1, 2001. We have
elected not to account for our hedging activities under the hedge accounting
provisions allowed in the standard. This will result in increased earnings
volatility associated with commodity price fluctuations as all of our
derivative financial instruments will be accounted for on a mark-to-market
basis beginning January 1, 2001. We estimate that effect of the transition
adjustment, after taxes, will be a non-cash reduction of approximately $35.0
million to other comprehensive income on January 1, 2001.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

 Interest Rate Risk

   We are exposed to changes in interest rates. Changes in interest rates
affect the interest earned on our cash and cash equivalents and the interest
rate paid on borrowings under the credit agreements. Under our current
policies, we do not use interest rate derivative instruments to manage exposure
to interest rate changes.

 Commodity Price Risk

   Our revenues, profitability and future growth depend substantially on
prevailing prices for natural gas and oil. Prices also affect the amount of
cash flow available for capital expenditures and our ability to borrow and
raise additional capital. The amount we can borrow under our bank credit
facility is subject to periodic re-determination based in part on changing
expectations of future prices. Lower prices may also reduce the amount of
natural gas and oil that we can economically produce. We currently sell most of
our natural gas and oil production under price sensitive or market price
contracts. To reduce exposure to fluctuations in natural gas and oil prices and
to achieve more predictable cash flow, we periodically enter into hedging
arrangements that usually consist of swaps or price collars that are settled in
cash. However, these contracts also limit the benefits we would realize if
commodity prices increase. Our internal hedging policy provides that we examine
the economic effect of entering into a commodity contract with respect to the
properties that we acquire. We generally acquire properties at prices that are
below the value of estimated reserves at the then current natural gas and oil
prices. We will enter into short term hedging arrangements if we are able to
obtain commodity contracts at prices sufficient to secure an acceptable
internal rate of return on a particular property or on a group of properties.
As of December 31, 2000, we had no oil hedges outstanding. All of our commodity
derivative financial instruments will be accounted for on a mark-to-market
basis beginning January 1, 2001.

                                       25
<PAGE>

   As of December 31, 2000, we had the following financial hedges on natural
gas outstanding:

<TABLE>
<CAPTION>
                                                                    SWAPS
                                                              -----------------
                                                               Average  Average
Period                                                        MMBtu/Day $/MMBtu
------                                                        --------- -------
<S>                                                           <C>       <C>
First quarter 2001...........................................  69,700    3.05
Second quarter 2001..........................................  29,000    2.83
Third quarter 2001...........................................  28,400    2.84
Fourth quarter 2001(1).......................................   9,300    2.87
</TABLE>
--------
(1) We have no gas hedges beyond October 2001.

   In addition to the above financial hedges on natural gas, during 2000 we
entered into a written call option contract that provides us a price for
natural gas above the then prevailing market price, but with a ceiling price.
For the period April 2001 through October 2001, we receive NYMEX settlement
plus $0.15 with a ceiling price of $3.50 per MMBtu on 10,000 MMBtu per day.

   On occasion, we may find ourselves in speculative positions as a result of
actual production being less than projected production when the derivative
products were consummated or as a result of entering into speculative
derivative instruments. Any speculative positions are accounted for using the
mark-to-market method. Under this methodology, contracts are adjusted to market
value, and the gains and losses are recognized in current period income.

Item 8. Financial Statements and Supplementary Data

   The consolidated financial statements and supplementary data of ATP appear
on pages 38 through 55 hereof and are incorporated by reference into this Item
8. Selected quarterly financial data is set forth in the Supplementary
Quarterly Information Schedule on page 61, which is incorporated herein by
reference.

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

   None.

                                       26
<PAGE>

                                    PART III

Item 10. Directors and Executive Officers of Registrant

Directors, Executive Officers and Other Key Employees

   The following table sets forth the names, ages and positions of our
executive officers, directors and other key employees as of March 30, 2001.

<TABLE>
<CAPTION>
Name                       Age Position
----                       --- --------
<S>                        <C> <C>
T. Paul Bulmahn...........  57 Chairman, President and Director
Gerald W. Schlief.........  53 Senior Vice President
Albert L. Reese, Jr.......  51 Senior Vice President and Chief Financial Officer
Leland E. Tate............  53 Senior Vice President, Operations
John E. Tschirhart........  50 Vice President, General Counsel
G. Ross Frazer............  45 Vice President, Engineering
Keith R. Godwin...........  33 Vice President and Controller
Carol E. Overbey..........  49 Vice President, Corporate Secretary and Director
Arthur H. Dilly...........  71 Director
Gerard J. Swonke..........  56 Director
Robert C. Thomas..........  72 Director
Walter Wendlandt..........  71 Director
</TABLE>

   The following biographies describe the business experience of our executive
officers, directors and other key employees.

   T. Paul Bulmahn (BA, JD, MBA) has served as our Chairman and President since
he founded the company in 1991. In 1991, he was elected Chairman, Houston Bar
Association Oil, Gas and Mineral Law Section, and in 1992 was elected to serve
for a three year term on the Oil & Gas Council of the State Bar of Texas. From
1988 to 1991, Mr. Bulmahn served as President and Director of Harbert Oil & Gas
Corporation. From 1984 to 1988, Mr. Bulmahn served as Vice President, General
Counsel of Plumb Oil Company. From 1978 to 1984, Mr. Bulmahn served as counsel
for Tenneco's interstate gas pipelines and as regulatory counsel in Washington,
D.C. From 1973 to 1978, Mr. Bulmahn served the Railroad Commission of Texas,
the Public Utility Commission and the Interstate Commerce Commission as an
administrative law judge. He has chaired various oil and gas industry seminars,
including "Marginal Offshore Field Development" in 1996 and the "Upstream Oil
and Gas E-Business Conference" in 2000, and has been a faculty lecturer in
natural gas regulations. In June 2000, Mr. Bulmahn was selected Entrepreneur Of
The Year 2000 in Energy & Energy Services by Ernst & Young LLP.

   Gerald W. Schlief (BBA, CPA, MBA) has served as our Senior Vice President
since 1993 and is primarily responsible for acquisitions. Between 1990 and
1993, Mr. Schlief acted as a consultant for the onshore and offshore
independent oil and gas industry. From 1984 to 1990, Mr. Schlief served as Vice
President, Offshore Land for Plumb Oil Company where he managed the acquisition
of interests in over 35 offshore properties. From 1983 to 1984, Mr. Schlief
served as Offshore Land Consultant for Huffco Petroleum Corporation. He served
as Treasurer and Landman for Huthnance Energy Corporation from 1981 to 1983. In
addition, from 1974 to 1978, Mr. Schlief conducted audits of oil and gas
companies for Arthur Andersen & Co., and from 1978 to 1981, he conducted audits
of oil and gas companies for Spicer & Oppenheim.

   Albert L. Reese, Jr. (BBA, CPA, MBA) has served as our Chief Financial
Officer since March 1999 and, in a consulting capacity, as our director of
finance from 1991 until March 1999. He was also named Senior Vice President in
August 2000. From 1986 to 1991, Mr. Reese was employed with the Harbert
Corporation where he established a registered investment bank for the company
to conduct project and corporate financings for energy, cogeneration, and small
power activities. From 1979 to 1986, Mr. Reese served as chief financial
officer of Plumb Oil Company and its successor, Harbert Energy Corporation.
Prior to 1979, Mr. Reese served

                                       27
<PAGE>

in various capacities with Capital Bank in Houston, the independent accounting
firm of Peat, Marwick & Mitchell, and as a partner in Arnold, Reese & Swenson,
a Houston-based accounting firm specializing in energy clients.

   Leland E. Tate (BS--Petroleum Engineering) has served as our Senior Vice
President, Operations, since August 2000. Prior to joining ATP, Mr. Tate worked
for over 30 years with Atlantic Richfield Company, a global energy company.
From 1998 until July 2000, Mr. Tate served as the President of ARCO North
Africa. He also was Director General of Joint Ventures at ARCO from 1996 to
1998. From 1994 to 1996, Mr. Tate served as ARCO's Vice President Operations &
Engineering, where he led technical negotiations in field development. Prior to
1994, Mr. Tate's positions with ARCO included Director of Operations, ARCO
British Ltd., where he was responsible for all operations in the North Sea;
Vice President of Engineering, ARCO International; Senior Vice President
Marketing and Operations, ARCO Indonesia; and for three years was Vice
President and District Manager in Lafayette, Louisiana, where he managed
operations on the Outer Continental Shelf and deep water of the Gulf of Mexico.

   John E. Tschirhart (BS--Marine Transportation, JD) joined us in November
1997 and has served as our Vice President, General Counsel since March 1998.
Mr. Tschirhart was named Managing Director of ATP Oil & Gas (UK) Limited in
July 2000. From 1993 to November 1997, Mr. Tschirhart worked as a partner at
the law firm of Tschirhart and Daines, a partnership in Houston, Texas where he
represented business clients in the energy industry. From 1985 to 1993 Mr.
Tschirhart was in private practice handling civil litigation matters including
oil and gas and employment law. From 1979 to 1985, he was with Coastal Oil &
Gas Corporation and from 1974 to 1979 he was with Shell Oil Company.

   G. Ross Frazer (BS Summa Cum Laude--Nuclear Engineering) joined us in August
2000 as Vice President, Engineering. From 1993 to August 2000, he was with
British-Borneo Exploration, Inc., an independent natural gas and oil company,
as operations manager, engineering manager, and engineering design verification
manager. This included responsibility for engineering and design verification
for the deep water Gulf of Mexico Morpeth field in 1,700 feet of water and the
Allegheny field in 3,300 feet of water. From 1997 to 1998, he was Chairman of
the American Petroleum Institute Houston Chapter Advisory Board and presently
serves on its Deep Water Operations Steering Committee.

   Keith R. Godwin (BBA, CPA) has served as our Controller since May 1997 and
was named a Vice President in August 2000. From 1995 to May 1997, Mr. Godwin
was in private industry as Corporate Accounting Manager with Champion
Healthcare Corporation, a publicly traded healthcare company. From 1990 to
1995, Mr. Godwin was employed as an accountant with the independent accounting
firm of Coopers & Lybrand L.L.P. where he conducted audits primarily in the
energy industry.

   Carol E. Overbey (BSW, AAS--RN) has served as a director and our Corporate
Secretary since 1991 and has served as Vice President since August 2000. Ms.
Overbey served as our Treasurer from 1991 to 1999. From 1985 to 1991, Ms.
Overbey was Vice President/Controller of Continuity Corporation. She also
served in 1991 as Assistant to the President at Harbert Oil & Gas Corporation
and assisted in developing gas marketing operations.

   Arthur H. Dilly (BA with honors, MA) has served as a director since January
2001. From 1981 to 1998, Mr. Dilly served as Executive Secretary of the Board
of Regents of the University of Texas System. He currently serves as Chairman
and Chief Executive Officer of Austin Geriatrics Center, Inc., a nonprofit
agency providing elderly support services, a post he has held since 1990. He
has served as Vice Chairman of the Board of Directors of the Shivers Cancer
Foundation, a nonprofit organization providing patient support services and
education, since 1998. From 1978 to 1981, he was Executive Director for
Development, The University of Texas System.

   Gerard J. Swonke (BA--Economics, JD) has served as a director since 1995.
Since 1985, he has been Of Counsel to the law firm of Greenberg, Peden,
Siegmyer & Oshman, P.C. representing domestic and international oil and gas
clients in contract drafting and negotiations, including in Indonesia, Africa
and the North Sea. From

                                       28
<PAGE>

1975 to 1985 he was Counsel for Aminoil, Inc. with responsibility for onshore
and offshore matters. From 1967 to 1974 when he received his law degree he was
Controller for Automated Systems Corporation with responsibility for corporate
accounting and preparation of financial statements and corporate tax returns.

   Robert C. Thomas (BS--Geological Engineering) has served as a director since
January 2001. Since 1994, Mr. Thomas has served as Chairman of the Board of The
Sarkeys Energy Center of the University of Oklahoma and as a Senior Associate
with Cambridge Energy Research Associates, an independent energy consulting
firm. Additionally, he has served as Vice Chairman of the Gas Research
Institute Advisory Council (now Gas Technology Institute), since 1998. In 1994,
Mr. Thomas stepped down as Chairman and Chief Executive Officer of Tenneco Gas
when he reached mandatory retirement age after thirty-eight years with Tenneco
beginning in 1956. He was elected president of Tenneco Gas in 1983 and chairman
and chief executive officer in 1990. He was with Tenneco's domestic exploration
and production operations until 1970 when he was elected Vice President of
Tenneco Oil Company's Canadian subsidiary with responsibility for all
engineering, drilling, processing plant and production operations. Mr. Thomas
is presently a member of the Board of Directors of Marine Drilling Companies,
Inc. and PetroCorp Incorporated. He is immediate past Chairman of the Board of
Directors of the YMCA of the Greater Houston Area and President of the Board of
Directors of Houston Hospice. He additionally has served on the Board of
Governors of The Houston Forum. Mr. Thomas has also served over 10 years on
each of the following Board of Directors: The Interstate Natural Gas
Association of America (INGAA), the American Gas Association (AGA), Gas
Research Institute (GRI), and the Institute of Gas Technology (IGT). From 1989
to 1994 he was a member of the National Petroleum Council (NPC) and served as a
Vice President of the International Association of LNG Importers (GIIGNL)
headquartered in Paris.

   Walter Wendlandt (BS--Mechanical Engineering, JD) has served as a director
since January 2001. He was Director, Railroad Commission of Texas for a total
of eighteen years during the period from 1961 to 1985. Mr. Wendlandt has been a
sole practitioner of law since 1984. He served as a Trustee of the Augustana
Annuity Trust from 1964 to 1992, a Director of the Georgetown Railroad from
1979 to 1982, and Director of Lamar Savings Association in 1989. He
additionally has served as President, National Conference of State
Transportation Specialists; Chairman, State Bar Committee on Public Utilities
Law; and was a member for six years of the Technical Pipeline Safety Standards
Committee of the U.S. Department of Transportation.

Board of Directors

   Our board of directors currently has six members divided into three classes.
The members of each class serve staggered, three-year terms. Upon the
expiration of the term of a class of directors, directors in that class are
elected for three-year terms at the annual meeting of shareholders in the year
in which their term expires. The classes are as follows:

  . Class I Directors. Mr. Bulmahn and Mr. Swonke are Class I Directors whose
    terms will expire at the 2004 annual meeting of shareholders;

  . Class II Directors. Ms. Overbey and Mr. Wendlandt are Class II Directors
    whose terms will expire at the 2002 annual meeting of shareholders; and

  . Class III Directors. Mr. Thomas and Mr. Dilly are Class III Directors
    whose terms will expire at the 2003 annual meeting of shareholders.

Committees of the Board of Directors

   Our board of directors has established an audit committee and a compensation
committee.

 Audit Committee

   The audit committee consists of Messrs. Swonke, Thomas and Wendlandt. The
audit committee is responsible for:

  . recommending annually to our board of directors the selection of our
    independent public accountants;

                                       29
<PAGE>

  . reviewing and approving the scope of our independent public accountants'
    audit activity and the extent of non-audit services;

  . reviewing with management and the independent public accountants the
    adequacy of our basic accounting systems and the effectiveness of our
    internal audit plan and activities;

  . reviewing our financial statements with management and the independent
    public accountants and exercising general oversight of our financial
    reporting process; and

  . reviewing our litigation and other legal matters that may affect our
    financial condition and monitoring compliance with our business ethics
    and other policies.

 Compensation Committee

   The compensation committee consists of Messrs. Thomas, Dilly and Swonke.
This committee's responsibilities include:

  . administering and granting awards under our 2000 Stock Plan;

  . reviewing the compensation of our President and recommendations of the
    President as to appropriate compensation for our other executive officers
    and key personnel;

  . examining periodically our general compensation structure; and

  . supervising our welfare and pension plans and compensation plans.

Compensation Committee Interlocks and Insider Participation

   None of our executive officers serves as a member of the board of directors
or compensation committee of any entity that has one or more of its executive
officers serving as a member of our board of directors or compensation
committee.

Compliance with Section 16(a) of the Securities Exchange Act

   Section 16(a) of the Securities Exchange Act of 1934 (the "Exchange Act")
requires our officers and directors, and persons who own more than ten percent
of a registered class of our equity securities, to file reports of ownership on
Form 3 and changes in ownership on Form 4 or Form 5 with the Securities and
Exchange Commission (the "SEC"). Such officers, directors and ten-percent
stockholders are also required by SEC rules to furnish us with copies of all
Section 16(a) forms they file. During fiscal year 2000, none of our equity
securities were registered under Section 12 of the Exchange Act, therefore,
none of our officers, directors or holders of more than ten percent of our
equity securities were required to file reports of ownership under Section
16(a) of the Exchange Act with respect to the ownership of our equity
securities.

                                       30
<PAGE>

Item 11. Executive Compensation

   The following table sets forth information regarding the compensation of our
President and each of our four other most highly compensated executive officers
for the year ended December 31, 2000. The annual compensation amounts in the
table exclude perquisites and other personal benefits because they did not
exceed the lesser of $50,000 or 10% of the total annual salary and bonus
reported for each executive officer:

                        2000 Summary Compensation Table

<TABLE>
<CAPTION>
                                                   Annual
                                                Compensation
                                              -----------------    All Other
Name and Principal Position                             Bonus   Compensation(1)
---------------------------                    Salary  -------- ---------------
<S>                                           <C>      <C>      <C>
T. Paul Bulmahn (2).......................... $155,600 $ 85,500     $5,300
 Chairman and President
Gerald W. Schlief (2)........................ $146,900 $ 31,400     $5,300
 Senior Vice President
Albert L. Reese, Jr.......................... $125,000 $123,800     $4,400
 Senior Vice President and Chief Financial
  Officer
John E. Tschirhart........................... $100,000 $ 31,268     $2,700
 Vice President, General Counsel
Keith R. Godwin.............................. $ 93,000 $ 37,200     $3,900
 Vice President and Controller
</TABLE>
--------
(1) Consists of matching contributions to our 401k savings plan.
(2) As described in "Item 13, Certain Relationships and Related Transactions,"
    during 2000 Mr. Bulmahn and Mr. Schlief each received an overriding royalty
    interest in a property at the time we acquired our interest in the
    property. We recorded a non-cash charge of $0.3 million in connection with
    their receiving such interests.

Stock Options

   The following table presents information concerning options granted to the
named executive officers during the year ended December 31, 2000:
<TABLE>
<CAPTION>
                                                                               Potential Realizable Value
                                                                                       at Assumed
                                                                                 Annual Rates of Stock
                                                                                 Price Appreciation for
                                     Individual Grants                               Option Term(3)
                         ------------------------------------------            --------------------------
                                             Percent of
                                            Total Options Exercise
                          Number of Shares   Granted to    or Base
                         Underlying Options Employees in    Price   Expiration
          Name               Granted(1)         2000      Per Share  Date(2)      0%       5%      10%
          ----           ------------------ ------------- --------- ---------- -------- -------- --------
<S>                      <C>                <C>           <C>       <C>        <C>      <C>      <C>
John E. Tschirhart......       35,714            9.7%       $3.85    8/1/2005  $362,497 $500,637 $667,750
Keith R. Godwin.........       14,286            3.9%       $3.85    8/1/2005  $145,003 $200,260 $267,107
</TABLE>
--------
(1) The options were granted on August 1, 2000. Under our 1998 Stock Option
    Plan, one third of the options vest on each of April 10, 2001, February 9,
    2002 and February 9, 2003.
(2) The expiration date is February 9, 2006.
(3) In accordance with the rules of the Securities and Exchange Commission,
    shown are the gains or "option spreads" that would exist for the respective
    options granted. These gains are based on the assumed rates of annual
    compound stock price appreciation of 0%, 5% and 10% from the date the
    option was granted over the full option term. We have assumed for these
    purposes that the stock price on the date of grant was equal to the initial
    public offering price for our shares of $14.00. These assumed annual
    compound rates of stock price appreciation are mandated by the rules of the
    Securities and Exchange Commission and do not represent our estimate or
    projection of our future common stock prices.

                                       31
<PAGE>

2000 Stock Plan

   Our board of directors and our shareholders have adopted the 2000 Stock
Plan. The purpose of the plan is to provide directors, employees and
consultants of ATP and its subsidiaries additional incentive and reward
opportunities designed to enhance the profitable growth of our company. The
plan provides for the granting of incentive stock options intended to qualify
under Section 422 of the Internal Revenue Code, options that do not constitute
incentive stock options and restricted stock awards. The plan is administered
by the compensation committee of our board of directors. In general, the
compensation committee is authorized to select the recipients of awards and the
terms and conditions of those awards.

   The number of shares of common stock that may be issued under the plan will
not exceed 4,000,000 shares, subject to adjustment to reflect stock dividends,
stock splits, recapitalizations and similar changes in our capital structure.
Shares of common stock which are attributable to awards which have expired,
terminated or been canceled or forfeited are available for issuance or use in
connection with future awards. The maximum number of shares of common stock
that may be subject to awards granted under the plan to any one individual
during the term of the plan will not exceed 50% of the aggregate number of
shares that may be issued under the plan. The price at which a share of common
stock may be purchased upon exercise of an option granted under the plan will
be determined by the compensation committee but (a) in the case of an incentive
stock option, such purchase price will not be less than the fair market value
of a share of common stock on the date such option is granted, and (b) in the
case of an option that does not constitute an incentive stock option, such
purchase price will not be less than 50% of the fair market value of a share of
common stock on the date such option is granted.

   Shares of common stock that are the subject of a restricted stock award
under the plan will be subject to restrictions on disposition by the holder of
such award and an obligation of such holder to forfeit and surrender the shares
to the under certain circumstances. The restrictions will be determined by the
compensation committee in its sole discretion, and the compensation committee
may provide that the restrictions will lapse upon (a) the attainment of one or
more performance targets established by the compensation committee, (b) the
award holder's continued employment with ATP or continued service as a
consultant or director for a specified period of time, (c) the occurrence of
any event or the satisfaction of any other condition specified by the
compensation committee in its sole discretion or (d) a combination of any of
the foregoing.

   No awards under the plan may be granted after ten years from the date the
plan is adopted by our board of directors. The plan will remain in effect until
all awards granted under the plan have been satisfied or expired. Our board of
directors in its discretion may terminate the plan at any time with respect to
any shares of common stock for which awards have not been granted. The plan may
be amended, other than to increase the maximum aggregate number of shares that
may be issued under the plan or to change the class of individuals eligible to
receive awards under the plan, by our board of directors without the consent of
our shareholders. No change in any award previously granted under the plan may
be made which would impair the rights of the holder of such award without the
approval of the holder.

                                       32
<PAGE>

1998 Stock Option Plan

   In December 1998, our board of directors and our shareholders adopted the
ATP Oil & Gas Corporation 1998 Stock Option Plan. Prior to our initial public
offering, the 1998 Stock Option Plan was amended to provide that the options
granted under the plan will remain outstanding until their termination dates;
however, no additional options will be granted.

   Options granted under the plan expire on February 9, 2006. Options granted
to an individual who, at the time of the grant, owned more than 10% of our
common stock expire five years from the date of the grant. Each option under
the 1998 Stock Option Plan may not be exercised for more than a percentage of
the aggregate number of shares offered by such option in accordance with the
following schedule:

<TABLE>
<CAPTION>
                                                                     % of shares
                                                                     vested and
                            Dates Exercisable                        exercisable
                            -----------------                        -----------
      <S>                                                            <C>
      April 10, 2001................................................      33
      February 9, 2002..............................................      66
      February 9, 2003..............................................     100
</TABLE>

   If there is a merger or consolidation of ATP that results in at least 40% of
the outstanding voting stock of ATP (or the successor of ATP) being owned by
persons or entities other than the shareholders of ATP prior to the merger or
consolidation, all outstanding options will become vested and fully exercisable
for the remainder of their terms. If there is a change in control other than as
described in the preceding sentence, then the compensation committee may effect
certain alternatives with respect to the options, including permitting exercise
of the options for a limited period of time, requiring surrender of the options
in exchange for cash payments, or providing for subsequent exercise for the
number and class of shares of stock or other securities or property in
accordance with the terms of the transaction.

401k Savings Plan

   Effective March 1, 1997, we adopted a 401k savings plan. This savings and
profit sharing plan covers all of our employees. The plan is subject to the
provisions of the Employee Retirement Income Security Act of 1974, as amended,
and Section 401(a) of the Internal Revenue Code.

   The assets of the plan are held and the related investments are executed by
the plan's trustee. Participants in the plan have investment alternatives in
which to direct their funds and may direct their funds in one or more of these
investment alternatives. We pay all administrative fees on behalf of the plan.
The plan provides for discretionary matching by ATP which is currently 50% of
each participant's contributions up to 6% of the participant's compensation. We
contributed $56,200 for the year ended December 31, 2000, $31,000 for the year
ended December 31, 1999 and $7,700 for the year ended December 31, 1998.

ATP All-Employee Bonus Program

   The ATP All-Employee Bonus Program is a bonus program designed to benefit
all employees based upon our overall performance. We have historically made
payments to employees through the All-Employee Bonus Program on a semi-annual
basis. The amount available for each employee under this program is based upon
a formula that considers length of service and base compensation. Each employee
is eligible to participate in the program allocations effective the first day
of the month following the employee's date of employment with ATP. There are
certain restrictions related to payment of an employee's allocation from the
program within their first year of employment. Those payments have represented
approximately 20% of average eligible compensation during the allocation
period.

Compensation of Directors

   Upon the closing of our initial public offering, we granted to each of our
non-employee directors options to purchase 5,000 shares of common stock at an
exercise price of $14.00 per share, the price paid by the public

                                       33
<PAGE>

in our initial public offering, for serving as a member of our board of
directors. In addition, each outside director receives $2,000 per board meeting
and $500 per committee meeting attended and is reimbursed for expenses
incurred. Directors who are our employees will not receive cash compensation
for their services as directors or members of committees of the board.

Item 12. Security Ownership of Certain Beneficial Owners and Management

   The following table presents information regarding beneficial ownership of
our common stock as of March 30, 2001, by:

  . each person who we know owns beneficially more than 5% of our common
    stock;

  . each of our directors;

  . the persons named in our 2000 Summary Compensation Table; and

  . all of our current officers and directors as a group.

<TABLE>
<CAPTION>
                                                            Shares    Percentage
                                                         Beneficially Beneficial
                       Beneficial Owner                     Owned     Ownership
                       ----------------                  ------------ ----------
      <S>                                                <C>          <C>
      T. Paul Bulmahn...................................   9,014,067     44.4%
      Gerald W. Schlief.................................   3,493,933     17.2%
      Carol E. Overbey..................................   1,164,738      5.7%
      Albert L. Reese, Jr...............................     612,976      3.0%
      John E. Tschirhart(1).............................      41,667        *
      Keith R. Godwin(1)................................      14,486        *
      Arthur H. Dilly(2)................................       5,000        *
      Gerard J. Swonke(2)...............................       5,000        *
      Robert C. Thomas(2)...............................       6,500        *
      Walter Wendlandt(2)...............................      10,000        *
      All officers and directors as a group
       (12 persons)(3)..................................  14,411,224     70.6%
</TABLE>
--------
 * Represents beneficial ownership of less than 1%.
(1) Includes shares that may be acquired as of April 10, 2001 through the
    exercise of stock options.
(2) Includes options to purchase 5,000 shares at an exercise price of $14.00
    per share, the price paid by the public in our initial public offering
    which we granted to our non-employee directors upon the close of our
    initial public offering.
(3) Includes 118,810 shares that may be acquired through the exercise of stock
    options.

Item 13. Certain Relationships and Related Transactions

   In 2000, Mr. Bulmahn, Mr. Schlief and Ms. Overbey each received overriding
royalty interests in one of our properties, ranging in amounts from 0.2% to
0.9%, at the time we acquired our interest in the property. In connection with
their receiving these interests, we recorded non-cash charges of $0.3 million
in 2000. These overriding royalty interests entitle the holder to receive a
designated percentage of the net revenue during the life of the property. Our
officers received these interests for their contributions to our growth during
our early years and in order to align their interests with the growth in our
operating revenues and cash flow. We do not expect our officers to receive such
interests in the future.

   We have entered into indemnification agreements with our officers and
directors containing provisions requiring us to, among other things, indemnify
our officers and directors against liabilities that may arise by reason of
their status or service as officers or directors, other than liabilities
arising from willful misconduct of a culpable nature, and to advance expenses
they incur as a result of any proceeding against them as to which they could be
indemnified.

                                       34
<PAGE>

                                    PART IV

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

   (a) Index to Financial Statements, Financial Statement Schedules and
Exhibits

     (1) and (2) Financial Statements and Schedules

      See "Index to Consolidated Financial Statements" on page 37.

     (3) Index of Exhibits

     See Index of Exhibits for a list of those exhibits filed herewith, which
  index also includes and identifies management contracts or compensatory
  plans or arrangements required to be filed as exhibits to this Form 10-K by
  Item 601(10)(iii) of Regulation S-K.

    (b) Reports on Form 8-K. No reports on Form 8-K were filed during the last
quarter of the period covered by this report.

   (c) Index of Exhibits

<TABLE>
<CAPTION>
 Exhibit No. Description
 ----------- -----------
 <C>         <S>
     3.1     Amended and Restated Articles of Incorporation (incorporated by
             reference to Exhibit 3.1 of ATP's registration statement No. 333-
             46034 on Form S-1)

     3.2     Restated Bylaws (incorporated by reference to Exhibit 3.2 of ATP's
             registration statement No. 333-46034 on Form S-1)

     4.1     Form of Common Stock Certificate (incorporated by reference to
             Exhibit 4.1 of ATP's registration statement No. 333-46034 on Form
             S-1)

    10.1     Amended and Restated Credit Agreement, dated as of September 21,
             1999, among ATP Oil & Gas Corporation, Chase Bank of Texas,
             National Association as Agent, and the Lenders Signatory thereto
             (incorporated by reference to Exhibit 10.1 of ATP's registration
             statement No. 333-46034 on Form S-1)

    10.2     First Amendment to Amended and Restated Credit Agreement, dated as
             of September 21, 1999, among ATP Oil & Gas Corporation, Chase Bank
             of Texas, National Association, as Agent, and the Lenders
             Signatory thereto, effective as of June 30, 2000 (incorporated by
             reference to Exhibit 10.2 of ATP's registration statement No. 333-
             46034 on Form S-1)

    10.3     Credit Agreement between ATP Oil & Gas Corporation and Aquila
             Energy Capital Corporation, dated April 9, 1999, effective as of
             March 31, 1999 (incorporated by reference to Exhibit 10.3 of ATP's
             registration statement No. 333-46034 on Form S-1)

    10.4     First Amendment to Credit Agreement, dated April 9, 1999, by and
             between ATP Oil & Gas Corporation and Aquila Energy Capital
             Corporation (incorporated by reference to Exhibit 10.4 of ATP's
             registration statement No. 333-46034 on Form S-1)

    10.5     Second Amendment to Credit Agreement, dated April 9, 1999, by and
             between ATP Oil & Gas Corporation and Aquila Energy Capital
             Corporation (incorporated by reference to Exhibit 10.5 of ATP's
             registration statement No. 333-46034 on Form S-1)
</TABLE>

                                       35
<PAGE>

<TABLE>
<CAPTION>
 Exhibit No. Description
 ----------- -----------

 <C>         <S>
    10.6     Gas Service Agreement, dated December 31, 1998, between American
             Citigas Company and ATP Energy, Inc. (incorporated by reference to
             Exhibit 10.6 of ATP's registration statement No. 333-46034 on Form
             S-1)

    10.7     Marketing & Natural Gas Purchase Agreement, dated December 1,
             1998, between ATP Energy, Inc. and El Paso Energy Marketing
             Company (incorporated by reference to Exhibit 10.7 of ATP's
             registration statement No. 333-46034 on Form S-1)

    10.8     Purchase and Sale Agreement, effective as of May 1, 1999, between
             Eugene Offshore Holdings, LLC and ATP Oil & Gas Corporation
             (incorporated by reference to Exhibit 10.8 of ATP's registration
             statement No. 333-46034 on Form S-1)

    10.9     ATP Oil & Gas Corporation 1998 Stock Option Plan (incorporated by
             reference to Exhibit 10.9 of ATP's registration statement No. 333-
             46034 on Form S-1)

    10.10    First Amendment to the ATP Oil & Gas Corporation 1998 Stock Option
             Plan (incorporated by reference to Exhibit 10.10 of ATP's
             registration statement No. 333-46034 on Form S-1)

    10.11    ATP Oil & Gas Corporation 2000 Stock Plan

    21.1     Subsidiaries of ATP Oil & Gas Corporation (incorporated by
             reference to Exhibit 21.1 of ATP's registration statement No. 333-
             46034 on Form S-1)

    24.1     Power of Attorney (included on the signature page to this
             Registration Statement)
</TABLE>

                                       36
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                          Page
                                                                          ----
<S>                                                                       <C>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
Independent Auditors' Report.............................................  38
Consolidated Balance Sheets as of December 31, 2000 and 1999.............  39
Consolidated Statements of Operations for the years ended December 31,
 2000, 1999 and 1998.....................................................  40
Consolidated Statements of Shareholders' Deficit for the years ended
 December 31, 2000, 1999 and 1998........................................  41
Consolidated Statements of Cash Flows for the years ended December 31,
 2000, 1999 and 1998.....................................................  42
Notes to Consolidated Financial Statements...............................  43
</TABLE>

                                       37
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

The Board of Directors
ATP Oil & Gas Corporation:

   We have audited the accompanying consolidated balance sheets of ATP Oil &
Gas Corporation and subsidiaries as of December 31, 2000 and 1999, and the
related consolidated statements of operations, shareholders' deficit, and cash
flows for each of the years in the three-year period ended December 31, 2000.
These consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.

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

   In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of ATP Oil &
Gas Corporation and subsidiaries as of December 31, 2000 and 1999, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2000, in conformity with accounting
principles generally accepted in the United States of America.


                                          KPMG LLP

Houston, Texas
March 31, 2001

                                       38
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS

                       (In thousands, except share data)

<TABLE>
<CAPTION>
                                                              December 31,
                                                            ------------------
                          ASSETS                              2000      1999
                          ------                            --------  --------
<S>                                                         <C>       <C>
Current assets:
  Cash and cash equivalents................................ $ 18,136  $ 17,779
  Restricted cash..........................................      --        471
  Accounts receivable (net of allowance for doubtful ac-
   counts).................................................   32,542    11,119
  Other current assets.....................................    2,597     1,048
                                                            --------  --------
    Total current assets...................................   53,275    30,417
Oil and gas properties:
  Oil and gas properties using the successful efforts
   method of accounting....................................  209,548   135,609
  Less accumulated depreciation, depletion, impairment and
   amortization............................................ (110,823)  (63,331)
                                                            --------  --------
    Oil and gas properties, net............................   98,725    72,278
Furniture and fixtures (net of accumulated depreciation)...      487       250
Deferred tax assets........................................    7,652     2,058
Other assets...............................................    1,854     2,051
                                                            --------  --------
    Total assets........................................... $161,993  $107,054
                                                            ========  ========
<CAPTION>
           LIABILITIES AND SHAREHOLDERS' DEFICIT
           -------------------------------------
<S>                                                         <C>       <C>
Current liabilities:
  Accounts payable and accruals............................ $ 57,047  $ 12,477
  Current maturity of long-term debt.......................      --      3,750
  Other deferred obligations...............................       63        75
                                                            --------  --------
    Total current liabilities..............................   57,110    16,302
Long-term debt.............................................   27,750    16,450
Non-recourse borrowings....................................   88,779    75,273
Deferred revenue...........................................    1,481     1,667
Other deferred obligations.................................       52       143
                                                            --------  --------
    Total liabilities......................................  175,172   109,835
                                                            --------  --------
Shareholders' deficit:
  Preferred stock: $0.001 par value, authorized 10,000,000
   and none at December 31, 2000 and 1999, respectively,
   none issued and outstanding at December 31, 2000 and
   1999....................................................      --        --
  Common stock: $0.001 par value, authorized 100,000,000
   and 50,000,000 shares at December 31, 2000 and 1999,
   respectively; issued and outstanding 14,285,714 shares
   at December 31, 2000 and 1999...........................       14        14
  Additional paid in capital...............................       38        38
  Accumulated deficit......................................  (13,231)   (2,833)
                                                            --------  --------
    Total shareholders' deficit............................  (13,179)   (2,781)
                                                            --------  --------
Commitments and contingencies
    Total liabilities and shareholders' deficit............ $161,993  $107,054
                                                            ========  ========
</TABLE>

        See accompanying notes to the consolidated financial statements.

                                       39
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF OPERATIONS

                (In thousands, except share and per share data)

<TABLE>
<CAPTION>
                                                Years ended December 31,
                                            ----------------------------------
                                               2000        1999        1998
                                            ----------  ----------  ----------
<S>                                         <C>         <C>         <C>
Revenues:
  Oil and gas production................... $   75,940  $   34,981  $   20,410
  Gas sold--marketing......................      8,015       7,703         --
  Gain on sale of oil and gas properties...         33         287         --
                                            ----------  ----------  ----------
                                                83,988      42,971      20,410
                                            ----------  ----------  ----------
Costs and operating expenses:
  Lease operating expenses.................     11,559       5,587       3,193
  Gas purchased--marketing.................      7,788       7,402         --
  General and administrative expenses......      5,409       3,541       2,591
  Depreciation, depletion and
   amortization............................     40,569      22,521      17,442
  Impairment of oil and gas properties.....     10,838       7,509       5,072
  Loss on speculative position.............     11,911         --          --
  Other expense............................        450         --          --
                                            ----------  ----------  ----------
                                                88,524      46,560      28,298
                                            ----------  ----------  ----------
    Net loss from operations...............     (4,536)     (3,589)     (7,888)
                                            ----------  ----------  ----------
Other income (expense):
  Interest income..........................        451         202         141
  Interest expense.........................    (11,907)     (9,399)     (7,963)
                                            ----------  ----------  ----------
                                               (11,456)     (9,197)     (7,822)
                                            ----------  ----------  ----------
    Net loss before income taxes and
     extraordinary items...................    (15,992)    (12,786)    (15,710)
Income tax benefit.........................      5,594       1,829         --
                                            ----------  ----------  ----------
    Loss before extraordinary item.........    (10,398)    (10,957)    (15,710)
Gain on extinguishment of debt, net of
 tax.......................................        --       29,185         --
                                            ----------  ----------  ----------
    Net income (loss)...................... $  (10,398) $   18,228  $  (15,710)
                                            ==========  ==========  ==========
Basic and diluted earnings (loss) per
 common share:
  Loss before extraordinary item........... $    (0.73) $    (0.77) $    (1.32)
  Extraordinary gain, net of income taxes..        --         2.05         --
                                            ----------  ----------  ----------
    Net income (loss) per common share..... $    (0.73) $     1.28  $    (1.32)
                                            ==========  ==========  ==========
Weighted average number of common shares:
  Basic and diluted........................ 14,285,714  14,285,714  11,925,785
                                            ==========  ==========  ==========
</TABLE>

        See accompanying notes to the consolidated financial statements.

                                       40
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

                CONSOLIDATED STATEMENTS OF SHAREHOLDERS' DEFICIT

                  Years ended December 31, 2000, 1999 and 1998

                       (In thousands, except share data)

<TABLE>
<CAPTION>
                                    Common Additional                 Total
                           Common   share   paid-in   Accumulated shareholders'
                           shares   amount  capital     deficit      deficit
                         ---------- ------ ---------- ----------- -------------
<S>                      <C>        <C>    <C>        <C>         <C>
Balance, December 31,
 1997................... 11,069,899  $11      $28      $ (5,351)    $ (5,312)
  Exercise of options...  3,215,815    3       10           --            13
  Net loss..............        --   --       --        (15,710)     (15,710)
                         ----------  ---      ---      --------     --------
Balance, December 31,
 1998................... 14,285,714   14       38       (21,061)     (21,009)
  Net income............        --   --       --         18,228       18,228
                         ----------  ---      ---      --------     --------
Balance, December 31,
 1999................... 14,285,714   14       38        (2,833)      (2,781)
  Net loss..............        --   --       --        (10,398)     (10,398)
                         ----------  ---      ---      --------     --------
Balance, December 31,
 2000................... 14,285,714  $14      $38      $(13,231)    $(13,179)
                         ==========  ===      ===      ========     ========
</TABLE>



        See accompanying notes to the consolidated financial statements.

                                       41
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (In thousands)
<TABLE>
<CAPTION>
                                                   Years ended December 31,
                                                  ----------------------------
                                                    2000      1999      1998
                                                  --------  --------  --------
<S>                                               <C>       <C>       <C>
Cash flows from operating activities:
  Net income (loss).............................. $(10,398) $ 18,228  $(15,710)
  Adjustments to reconcile net income (loss) from
   operations to net cash provided by operating
   activities:
    Depreciation, depletion and amortization.....   40,569    22,521    17,442
    Amortization of deferred financing costs.....      384       280        45
    Impairment of oil and gas properties.........   10,838     7,509     5,072
    Assignment of overrides to related party.....      282       557       525
    Loss on speculative position.................    7,249       --        --
    Other expense................................      450       --        --
    Recognition of deferred revenue..............     (186)     (333)      --
    Gain on early extinguishment of debt.........       --   (29,185)      --
    Gain on sale of oil and gas properties.......      (33)     (287)      --
  Change in assets and liabilities:
    (Increase) decrease in accounts receivable...  (21,223)   (6,794)    7,205
    Decrease in cash held in escrow..............      --        439       981
    (Increase) in other current assets...........   (1,549)     (403)      (39)
    Decrease in restricted cash..................      471     3,529       --
    (Increase) in deferred tax assets............   (5,594)   (2,058)      --
    (Increase) in other assets...................     (436)     (714)      (96)
    Increase (decrease) in accounts payable and
     accruals....................................   35,864     1,304    (2,178)
    (Decrease) in deferred obligations...........     (103)   (3,782)      --
                                                  --------  --------  --------
      Cash provided by operating activities......   56,585    10,811    13,247
                                                  --------  --------  --------
Cash flows from investing activities:
  Additions and acquisitions of oil and gas
   properties....................................  (76,516)  (56,051)  (35,936)
  Proceeds from sale of oil and gas properties...      --      1,137       --
  Additions to furniture and fixtures............     (368)     (206)      (46)
                                                  --------  --------  --------
      Cash used by investing activities..........  (76,884)  (55,120)  (35,982)
                                                  --------  --------  --------
Cash flows from financing activities:
  Increase in long-term debt.....................   15,800    19,800    14,500
  Payments of long-term debt.....................   (8,250)  (14,100)      --
  Non-recourse borrowings........................   42,745    93,728    20,113
  Payments of non-recourse borrowings............  (29,239)  (39,420)  (11,617)
  Deferred financing costs incurred..............     (400)   (1,331)     (669)
  Receipt of deferred revenue....................      --        --      2,000
  Exercise of options to purchase common stock...      --        --         13
                                                  --------  --------  --------
      Cash provided by financing activities......   20,656    58,677    24,340
                                                  --------  --------  --------
  Increase in cash and cash equivalents..........      357    14,368     1,605
Cash and cash equivalents:
  At beginning of year...........................   17,779     3,411     1,806
                                                  --------  --------  --------
  At end of year................................. $ 18,136  $ 17,779  $  3,411
                                                  ========  ========  ========
</TABLE>

        See accompanying notes to the consolidated financial statements.

                                       42
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                        December 31, 2000, 1999 and 1998

(1) Organization

   ATP Oil & Gas Corporation (ATP or the Company), a Texas corporation, was
formed on August 8, 1991 and is engaged primarily in the acquisition,
development and operation of oil and gas properties. ATP owns and operates its
oil and gas properties utilizing financing arrangements with third parties and
shared working interest arrangements. The Company operates in one business
segment which is oil and gas operations.

(2) Summary of Significant Accounting Policies

 General

   The accompanying consolidated financial statements of the Company have been
prepared according to accounting principles generally accepted in the United
States of America and pursuant to the rules and regulations of the Securities
and Exchange Commission. These accounting principles require the use of
estimates, judgments and assumptions that affect the reported amounts of assets
and liabilities as of the date of the financial statements and revenues and
expenses during the reporting period. Actual results could differ from those
estimates. Certain reclassifications of amounts previously reported have been
made to conform to current period presentations.

 Basis of Presentation

   The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiaries, ATP Energy, Inc. (ATP Energy) and ATP Oil &
Gas (UK) Limited. All significant intercompany transactions are eliminated upon
consolidation.

 Cash and Cash Equivalents

   Cash and cash equivalents primarily consist of cash on deposit and
investments in money market funds with original maturities of three months or
less, stated at market value.

 Restricted Cash

   Restricted cash primarily consist of cash on deposit and investments in
money market funds and fixed income funds stated at the lower of cost or
current market value.

 Oil and Gas Producing Activities and Depreciation, Depletion and Amortization

   The Company follows the "successful efforts" method of accounting for oil
and gas properties. Under this method, lease acquisition costs and intangible
drilling and development costs on successful wells and development dry holes
are capitalized.

   Capitalized costs relating to producing properties are depleted on the unit-
of-production method. Proved developed reserves are used in computing unit
rates for drilling and development costs and total proved reserves for
depletion rates of leasehold, platform and pipeline costs. Estimated
dismantlement, restoration and abandonment costs and estimated residual salvage
values are taken into account in determining amortization and depletion
provisions.

   Expenditures for repairs and maintenance are charged to expense as incurred;
renewals and betterments are capitalized. The costs and related accumulated
depreciation, depletion, and amortization of properties sold or otherwise
retired are eliminated from the accounts, and gains or losses on disposition
are reflected in the statements of operations.

                                       43
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2000, 1999 and 1998


   The Company performs a review for impairment of proved oil and gas
properties on a depletable unit basis when circumstances suggest there is a
need for such a review. For properties determined to be impaired, an impairment
loss equal to the differences between the carrying value and the fair value of
the impaired property will be recognized. Fair value, on a depletable unit
basis, is estimated to be the present value of expected future net cash flows
computed by applying estimated future oil and gas prices, as determined by
management, to estimated future production of oil and gas reserves over the
economic lives of the reserves. Future net cash flows are based upon the
Company's independent engineer's estimate of proved reserves. In addition,
other factors such as probable and possible reserves are taken into
consideration when justified by economic conditions and actual or planned
drilling. The Company recorded the impairments during the years ended December
31, 2000, 1999 and 1998 of $10.8 million, $7.5 million and $5.1 million,
respectively, primarily due to depressed oil and natural gas prices,
unfavorable operating performance and a downward revision of recoverable
reserves.

 Furniture and Fixtures

   Furniture and fixtures consists of office furniture, computer hardware and
software and leasehold improvements. Depreciation of furniture and fixtures is
computed using the straight-line method over their estimated useful lives,
which vary from three to ten years. Depreciation of furniture and fixtures
included in depreciation, depletion and amortization expense was $131,000,
$52,000 and $33,000 for the periods ended December 31, 2000, 1999 and 1998,
respectively.

 Capitalized Interest

   The Company capitalizes interest costs associated with borrowed funds while
the property in a depletable unit is being developed. The Company ceases
capitalizing interest costs when the property begins its first production.
Interest costs capitalized for the periods ended December 31, 2000, 1999 and
1998 and were $0.7 million, $0.6 million and $1.6 million, respectively.

 Other Current Assets

   Other current assets for the periods ended December 31, 2000 and 1999
include prepaid expenses of $0.3 million and $0.2 million. Prepaid expenses are
amortized to production and operating expenses over the term of the related
agreements. Other current assets also include estimated royalty deposits
maintained with the Minerals Management Service of $2.3 million at December 31,
2000 and $0.8 million at December 31, 1999. These deposits represent an
estimate of one month's payment attributable to the Minerals Management Service
royalty interest in our properties.

 Other Assets

   Other assets include debt financing costs of $1.1 million and $1.2 million,
assets held for resale of none and $0.7 million, offering costs of $0.6 million
and none and spare parts inventory of $0.1 million and $0.2 million at December
31, 2000, and 1999, respectively. Debt financing costs relate to direct
financing fees incurred in establishing the Company's credit facility
agreements and non-recourse borrowing agreements, which are amortized to
interest expense straight-line, over the term of the related agreements, which
approximates the interest method. Amortization included in interest expense was
$0.4 million, $0.3 million and $45,000 for the periods ended December 31, 2000,
1999 and 1998, respectively. During the year ended December 31, 2000, the
Company realized a loss of $0.5 million from the sale of a platform. This
amount is reflected as other expense in the statement of operations.

                                       44
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2000, 1999 and 1998


 Environmental Liabilities

   Environmental expenditures that relate to current or future revenues are
expensed or capitalized as appropriate. Expenditures that relate to an existing
condition caused by past operations, and do not contribute to current or future
revenue generation, are expensed. The Company has never had an environmental
claim. If such a claim arose in the future, the liabilities would be recorded
when environmental assessments and/or clean-ups are probable, and the costs
could be reasonably estimated. Generally, the timing of these accruals
coincides with the Company's commitment to a formal plan of action.

 Revenue Recognition

   The Company records as revenue only that portion of production sold and
allocable to its ownership interest in the related property in the month the
production is sold. Imbalances arise when a purchaser takes delivery of more or
less volume from a property than the Company's actual interest in the
production from that property. Such imbalances are reduced either by subsequent
recoupment of over-and-under deliveries or by cash settlement, as required by
applicable contracts. Under-deliveries are included in accounts receivable and
over-deliveries are included in accounts payable. At December 31, 2000 and 1999
the Company had under-deliveries included in accounts receivable of $41,000 and
none, respectively. At December 31, 2000 and 1999, the Company had over-
deliveries included in accounts payable of $14,000 and $0.2 million,
respectively.

   The Company has allowance for doubtful accounts related to its trade
accounts receivable of $0.4 million and none at December 31, 2000 and 1999.

 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 that
enactment date.

 Financial Instruments

   The Company's financial instruments consist of cash and cash equivalents,
receivables, payables and debt. The carrying amount of cash and cash
equivalents, receivables and payables approximates fair value because of the
short-term nature of these items.

 Derivative Financial Instruments

   From time to time, the Company has utilized and may continue to utilize
hedging transactions with respect to a portion of its oil and gas production to
achieve a more predictable cash flow as well as to reduce its exposure to price
fluctuations. These transactions generally are swaps or price collars and are
entered into with major financial institutions or commodities trading
institutions. Derivative financial instruments are intended to reduce the
Company's exposure to declines in the market price of natural gas and crude
oil. These derivative financial instruments will limit the effect on the
Company's realized revenues if market prices fall below the contracted floor
price. As a result, gains and losses on derivative financial instruments are
generally offset in the Company's oil and gas revenues by similar changes in
the realized price of natural gas and crude oil.

                                       45
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2000, 1999 and 1998


   The Company uses the hedge or deferral method of accounting for these
instruments. To qualify as hedges, these instruments must highly correlate to
anticipated future production such that the Company's exposure to the effects
of price changes is reduced. Income and costs related to these hedging
activities are recognized in oil and gas revenues when the commodities are
produced. Income and costs on commodity derivative financial instruments that
are closed before the hedged production occurs are also deferred until the
production month originally hedged. In the event of a loss of correlation
between changes in oil and gas prices under a commodity derivative financial
instrument and actual oil and gas prices, income or costs are recognized
currently to the extent the financial instruments had not offset changes in
actual oil and gas prices.

   For the years ended December 31, 2000 and 1999 the Company recorded $28.2
million and $3.8 million, respectively, as a reduction of oil and gas revenues
related to hedging transactions. For the year ended December 31, 1998, the
Company had no hedge transactions.

   At December 31, 2000, the Company had hedged approximately 12,387 MMBtu of
its expected 2001 natural gas production. The average price of hedged natural
gas production is approximately $2.95 per MMBtu. The Company has no natural gas
hedges in effect beyond October 2001. The Company has no oil hedges in effect
beyond December 2000. All of the Company's commodity derivative financial
instruments will be accounted for on a mark-to-market basis beginning January
1, 2001. See New Accounting Policies.

   In addition to the above financial hedges on natural gas, during 2000 the
Company entered into two written call option contracts that provide it a price
for natural gas above the then prevailing market price, but with a ceiling
price. For the period July 2000 through October 2000, the Company received
NYMEX settlement plus $0.15 with a ceiling price of $3.16 per MMBtu on 15,000
MMBtu per day. For the period April 2001 through October 2001, the Company
receives NYMEX settlement plus $0.15 with a ceiling price of $3.50 per MMBtu on
10,000 MMBtu per day.

   On occasion, the Company may find itself in speculative positions as a
result of actual production being less than projected production when the
derivative products were consummated or as a result of entering into
speculative derivative instruments. Any speculative positions are accounted for
using the mark-to-market method. Under this methodology, contracts are adjusted
to market value, and the gains and losses are recognized in current period
income. As of December 31, 2000, the Company recognized a loss in the amount of
$11.9 million from certain speculative positions. This amount is reflected as
loss on speculative position in the statement of operations. At December 31,
2000, the Company has recorded $7.2 million in accounts payable and accruals
related to its estimated fair value of derivative financial instruments.

 Stock Options

   The Company accounts for stock-based compensation using the intrinsic value
method. Accordingly, compensation cost for stock options is measured as the
excess, if any, of the fair value of the Company's common stock at the date of
the grant over the amount an employee must pay to acquire the common stock (see
note 5).

 Use of Estimates

   The preparation of financial statements in accordance with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts
of assets, liabilities, revenues and expenses, and disclosure of contingent
assets and liabilities in the financial statements, including the use of
estimates for oil and gas reserve information and the valuation allowance for
deferred income taxes. Actual results could differ from those estimates.

                                       46
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2000, 1999 and 1998


 Supplemental Disclosure of Cash Flow Information

   For the years ended December 31, 2000, 1999, and 1998, the Company made cash
payments of interest of $2.5 million, $0.6 million and $32,000, respectively.
The Company made cash payments for income taxes during the years ended December
31, 2000, 1999 and 1998 of $0.5 million, none and none respectively.

 Concentration of Credit Risk

   Financial instruments that potentially subject the Company to concentration
of credit risk consist principally of trade accounts receivable. Management
believes that the credit risk posed by this concentration is offset by the
creditworthiness of the Company's customer base.

 Risk Factors

   The Company's revenue, profitability, cash flow and future rate of growth is
substantially dependent upon the price of and demand for oil and natural gas.
Prices for natural gas and oil are subject to wide fluctuations in response to
relatively minor changes in the supply of and demand for natural gas and crude
oil, market uncertainty and a variety of additional factors that are beyond the
control of the Company. Other factors that could affect the revenue,
profitability, cash flow and future growth of the Company include the Company's
incurrence of losses since formation, the inherent uncertainties in reserve
estimates, the concentration of production and reserves in a small number of
offshore properties, the ability to finance growth, and the ability to replace
reserves. The Company had a working capital surplus (deficit) at December 31,
2000 and 1999 totaling $(3.8) million and $13.7 million, respectively. The
Company has historically had significant amounts of net cash used in operating
and investing activities funded through short-term borrowings from financial
institutions. Management believes its access to cash through future borrowings
under new credit facilities and operations are sufficient to satisfy the
current cash requirements. (see note 3).

 New Accounting Policies

   In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for
Derivative Instruments and Hedging Activities, and in June 2000, the FASB
issued SFAS No. 138, Accounting for Certain Derivative Instruments and Certain
Hedging Activities, an amendment of FASB Statement No. 133. These statements
establish standards of accounting for and disclosures of derivative instruments
and hedging activities. The Company adopted this standard on January 1, 2001.
The Company has elected not to account for its hedging activities under the
hedge accounting provisions allowed in the standard. This will result in
increased earnings volatility associated with commodity price fluctuations as
all of the Company's derivative financial instruments will be accounted for on
a mark-to-market basis beginning January 1, 2001. The Company estimates that
effect of the transition adjustment, after taxes, will be a non-cash reduction
of approximately $35.0 million to other comprehensive income on January 1,
2001.

   In March 2000, the FASB issued Interpretation No. 44, Accounting for Certain
Transactions Involving Stock Compensation: an Interpretation of APB Opinion No.
25. Among other issues, Interpretation No. 44 clarifies the application of
Accounting Principles Board Opinion No. 25 (APB No. 25) regarding (a) the
definition of employee for purposes of applying APB No. 25, (b) the criteria
for determining whether a plan qualifies as a non-compensatory plan, (c) the
accounting consequence of various modifications to the terms of a previously
fixed stock option or award, and (d) the accounting for an exchange of stock
options in a business combination.

                                       47
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2000, 1999 and 1998


(3) Acquisition of Oil & Gas Properties

   The Company has maintained its growth through the acquisition of proved
natural gas and oil properties. Because its focus is on undeveloped properties,
the Company is typically able to acquire properties with minimal cash
expenditures by granting overriding royalty interests (ORRI) in those
properties. The following table represents a list of our acquisitions during
2000 and 1999. For each of the acquisitions listed, the total purchase price
was allocated to oil and gas properties.

<TABLE>
<CAPTION>
                                            Working                  Purchase
                                            Interest                Price (in
                 Property                   Acquired      Date      thousands)
                 --------                   -------- -------------- ----------
<S>                                         <C>      <C>            <C>
High Island A-354..........................  100.0%  January 1999          0(a)
Vermilion 410 Field........................   37.5%  February 1999     5,800
East Cameron 240...........................  100.0%  August 1999       1,500
West Cameron 492...........................   50.0%  August 1999       1,300
Eugene Island 30...........................  100.0%  September 1999   16,318
Vermilion 410 Field........................   12.5%  April 2000          951
Vermilion 260..............................  100.0%  April 2000          125
West Cameron 635...........................  100.0%  May 2000          1,082
Main Pass 282..............................  100.0%  July 2000             0(a)
Garden Banks 409 (Ladybug).................   50.0%  July 2000             0(a)
West Cameron 461...........................  100.0%  November 2000     1,487
South Marsh Island 189/190.................  100.0%  November 2000     3,129
Garden Banks 186, 187 and 142..............  100.0%  November 2000       350
</TABLE>
--------
(a) Property was conveyed from seller who retained an overriding royalty
    interest.

   In 2001, the Company has acquired nine properties in the Gulf of Mexico for
a total acquisition cost of approximately $23.0 million. The Company has also
acquired two properties in the Southern Gas Basin of the U.K. North Sea for a
total acquisition cost of (Pounds)1.6 million, approximately $2.3 million.

   In September 1999, the Company completed an acquisition of a 100% working
interest and an 82% net revenue interest in Eugene Island 30 for a purchase
price of $16.3 million. The total purchase price was allocated to proved
property acquisition costs. Subsequent to the acquisition, the Company became
the operator of the property. The acquisition was financed through the
Company's credit facility.

   The following table sets forth summary unaudited pro forma financial data
which is presented to give effect to the Eugene Island 30 acquisition as if the
event had occurred as of January 1, 1998. The information does not purport to
be indicative of actual results, as if this transaction had been in effect for
the periods indicated, or of future results.

                        Unaudited Pro Forma Information

                  (Amounts in thousands except per share data)

<TABLE>
<CAPTION>
                                                                Years ended
                                                                December 31,
                                                              ----------------
                                                               1999     1998
                                                              ------- --------
    <S>                                                       <C>     <C>
    Revenues................................................. $45,242 $ 23,757
    Net income (loss)........................................ $17,978 $(15,660)
    Basic and diluted earnings (loss) per share.............. $  1.26 $  (1.31)
</TABLE>

                                       48
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2000, 1999 and 1998


(4) Long-term Debt and Non-Recourse Borrowings

 Credit facility

<TABLE>
<CAPTION>
                                                                  December 31,
                                                                 ---------------
                                                                  2000    1999
                                                                 ------- -------
                                                                 (In thousands)
   <S>                                                           <C>     <C>
   Credit facility.............................................. $27,750 $20,200
   Less current portion.........................................      --   3,750
                                                                 ------- -------
     Long-term debt............................................. $27,750 $16,450
                                                                 ======= =======
</TABLE>

   In September 1998, the Company entered into a revolving credit facility with
a national bank. The Company's maximum borrowing amount (its borrowing base) is
based on the loan value, as determined by the lender, of certain oil and gas
properties pledged to the credit facility. The initial borrowing base was
established at $6.5 million. Several amendments from September 1998 through
December 2000 adjusted the borrowing base to $27.8 million. Interest is
computed either at a base rate or at the Eurodollar loan rate plus a premium
(depending upon the percentage of the facility being used). Base rate loans
bear interest at the higher of Federal Funds plus a premium or the bank's prime
rate plus a premium. At December 31, 2000, 1999 and 1998 the average interest
rate was 10.0%, 8.9% and 8.1% respectively. The credit facility is
collateralized by a first mortgage on certain of the Company's oil and gas
properties. Commitment fees and facility fees are paid on the unused portion of
the loan. The loan agreement contains various restrictive non-financial
covenants including limitations on future debt, guarantees, liens, dividends,
mergers, and sale of assets. The loan agreement also contains various
restrictive financial covenants including ratio of debt (exclusive of non-
recourse debt and other permitted debt) to EBITDA as of the end of any fiscal
quarter (calculated on a rolling four quarter basis) shall not be greater than
3.00 to 1.00, current ratio of no less than 1.0 to 1.0 at any time, and
interest coverage ratio as of the end of any fiscal quarter to be less than
2.50 to 1.00. At December 31, 2000 and 1999, the Company was in compliance with
all terms of the agreement other than at December 31, 2000 the covenant to
maintain a current ratio of no less than 1.0 to 1.0 for which the Company
obtained a waiver from the lender.

 Non-Recourse Borrowing Agreements

   In November 1996, the Company entered into a dollar denominated, non-
recourse, production payment obligation. This obligation was subsequently
supplemented in a series of amendments that occurred between that date and
April 1998, in exchange for payments to the Company aggregating approximately
$53.7 million plus a designated return. Of this amount, approximately $6.4
million was received in 1996, $36.6 million in 1997 and $10.7 million in 1998.
These proceeds were received in exchange for the monthly obligation to provide
the lender with a designated interest in the net revenues attributable to
certain properties. This obligation was free of all costs of production and
operation prior to the delivery point as specified in the agreement.

   The payment obligations were based on the lender receiving a designated
return of the Company's net revenue from the properties until such time that
the sum of the net proceeds exceeded the amount advanced plus a designated
return. Several amendments during the life of the agreement adjusted the
percentage of net revenue allocated to repayment between 75% and 95%, the
implied rate of return between 20% and 40%, and continuing interest after
payout. At December 31, 1998, there was $50.7 million outstanding under this
agreement.

   In June 1999, the Company and the lender reached an agreement in a
negotiated transaction to terminate the obligation. The Company agreed to pay
in a lump sum an amount that would have been paid over the time from net
revenues from certain properties. The lump sum payment was less than the amount
outstanding at the

                                       49
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2000, 1999 and 1998

date of payment. As a result, the Company recognized a gain of $29.2 million on
the early extinguishments of the debt.

   In April 1999, the Company entered into a second non-recourse obligation.
This obligation was created in exchange for payments to the Company for up to
$47.0 million. These proceeds were received in exchange for an obligation to
provide the lender with 85% to 90% of the monthly net revenue received as
reflected in the Company's property operating statement for certain properties
as included in the agreement. In addition to the interest rate of prime plus 2
1/2% to 3 1/2% earned by the lender, it also has a future specified overriding
royalty interest in the properties that serve as collateral.

   Under the terms of this agreement, the payment obligation from the committed
properties commenced during April 1999. The agreement was subsequently amended
twice in 1999 to increase the amount of the lender's commitment to $91.2
million. Unless extended or further amended, the loan agreement will terminate
in January 2003. At December 31, 2000 and 1999, there was $88.8 million and
$75.3 million, respectively, outstanding under the agreement.

   The lender has overriding royalty interest rights in each of the 14
properties included in the collateral base for the development program credit
agreement. Ten of the 14 properties are subject to a 6.25% overriding royalty
interest which begins when the full amount outstanding under the credit
agreement is repaid. The royalty interest is limited to the estimated proved
reserves attributable to the properties at the time the properties were added
to the collateral base less production after such date. Three of these 10
properties also are subject to a 3.125% overriding royalty on certain specified
levels of production above the proved reserves subject to the 6.25% interest.
The lender is not entitled to either of these interests unless the full amount
owed under the credit agreement has been repaid or the properties are removed
from the collateral base. Four of the 14 properties included in the collateral
base are subject to a 6.25% overriding royalty interest in all future
production when the full amount outstanding under the credit agreement is
repaid if the amounts outstanding under the credit agreement are not repaid in
full prior to May 1, 2001. This 6.25% interest is not limited to any specified
amount of reserves.

(5) Equity

 Initial Public Offering

   On February 5, 2001, the Company priced its initial public offering of 6
million shares of common stock and commenced trading the following day. After
payment of the underwriting discount the Company received net proceeds of $78.3
million on February 9, 2001.

 Change in Authorized Capitalization

   On December 12, 2000, the Board of Directors approved an increase in the
authorized common stock from 50,000,000 shares to 100,000,000 shares, the
authorization of 10,000,000 shares of preferred stock and a 1.4-for-1 reverse
split of the common stock. Par value of the common stock will remain $.001 per
share. The reverse stock split was effective December 12, 2000.

   The effect of the stock split has been recognized retroactively in the
shareholders' equity accounts on the balance sheet as of December 31, 1999, and
in all share and per share data in the accompanying consolidated financial
statements, Notes to Financial Statements and supplemental financial data.
Shareholders' equity accounts have been restated to reflect the
reclassification of an amount equal to the par value of the decrease in

                                       50
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2000, 1999 and 1998

issued common shares from the capital in excess of par value and retained
earnings accounts to the common stock account.

 Stock Options

   SFAS No. 123, Accounting for Stock-based Compensation, defines a fair value
method of accounting for an employee stock option or similar equity instrument.
The Company has elected to account for its stock options using the intrinsic
value method, as prescribed in Accounting Principles Board (APB) Opinion No.
25, Accounting for Stock Issued to Employees, and related interpretations.
Accordingly, compensation cost for stock options is measured as the excess, if
any, of the fair value of the Company's common stock at the date of the grant
over the amount an employee must pay to acquire the common stock. Since the
Company was a private company whose shares did not trade in any market, there
was no established market value for the Company's common stock when options
were granted. The exercise price for the stock options was determined on the
basis of the formula price for stock repurchases in the Company's stockholders'
agreement. Had the Company determined its compensation cost based on the fair
value at the grant date for its stock options under the provisions of SFAS No.
123, the Company's pro forma net loss and profit for the years ended December
31, 2000, 1999 and 1998 would have been unchanged as the options do not vest
and are not exercisable until at least 60 days after an IPO or a corporate
change in control as defined by the 1998 Stock Option Plan.

 1998 Stock Option Plan

   In December 1998, the Board of Directors approved the 1998 Stock Option Plan
(the 1998 SOP) to provide increased incentive for its employees and directors.
The 1998 SOP is administered by the Compensation Committee of the Company's
Board of Directors and provides for up to 2,678,571 shares of common stock to
be granted to eligible participants. The stock options became exercisable upon
the closing of the initial public offering of Company Stock on February 9,
2001. These options expire five years after the date of the IPO. Each option
under the 1998 SOP may be exercised at any time after the grant in accordance
with the following schedule:
<TABLE>
<CAPTION>
                                                                     % of shares
                                                                     vested and
                           Dates Exercisable                         exercisable
                           -----------------                         -----------
   <S>                                                               <C>
   April 10, 2001...................................................      33
   February 9, 2002.................................................      66
   February 9, 2003.................................................     100
</TABLE>

   During the periods ended December 31, 2000, 1999 and 1998, the Company
granted options exercisable for 23,393, 18,571 and 440,714 shares of common
stock at $1.40 per share. During the period ended December 31, 2000, the
Company granted options exercisable for 344,822 shares of common stock at $3.85
per share.

   The Company will recognize compensation expense following its IPO based on
the difference between the exercise price for options granted since September
1999 and the fair market value of its stock as determined by the IPO price of
$14.00 per share. The expense will be recognized in the periods in which the
options vest. Each option is divided into three equal portions corresponding to
the three vesting dates, with the related compensation cost amortized straight-
line over the period between the IPO date and the vesting date. Based upon the
vesting schedule, the Company will incur a non-cash compensation expense of
approximately $3.2 million in 2001 and approximately $0.6 million in 2002
relating to such option grants.

                                       51
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2000, 1999 and 1998


   Information regarding the Company's 1998 SOP is summarized as follows:

<TABLE>
<CAPTION>
                            2000      2000    1999      1999    1998     1998
                          --------  -------- -------  -------- ------- --------
                                    Weighted          Weighted         Weighted
                                    average           average          average
                                    exercise          exercise         exercise
                           Shares    price   Shares    price   Shares   price
                          --------  -------- -------  -------- ------- --------
<S>                       <C>       <C>      <C>      <C>      <C>     <C>
Outstanding at beginning
 of year................   456,964   $1.40   440,714   $1.40       --
Granted.................   368,215   $3.69    18,571   $1.40   440,714  $1.40
Expired unexercised.....  (178,572)  $1.40    (2,321)  $1.40       --     --
Exercised...............       --      --        --                --     --
                          --------   -----   -------   -----   -------  -----
Outstanding at end of
 period.................   646,607   $2.71   456,964   $1.40   440,714  $1.40
                          ========   =====   =======   =====   =======  =====
Exercisable at end of
 period.................       --      --        --      --        --     --
                          ========   =====   =======   =====   =======  =====
Option Grant Price......   368,215   $3.69    18,571   $1.40   440,714  $1.40
                          ========   =====   =======   =====   =======  =====
</TABLE>

 1994 Stock Option Plan

   In May 1994, the Board of Directors approved the 1994 Stock Option Plan (the
1994 SOP) under which it was authorized to issue up to 55,902,930 shares of
common stock. The exercise price of the options under the 1994 SOP shall not be
less than the greater of par value per share or fair market value, at date of
grant. These options have a maximum term of 10 years, subject to vesting
requirements in the individual option agreements. During 1994, options to
purchase 26,235,244 shares were issued at $0.00358 per share immediately
exercisable after grant. As of December 31, 2000, 1999 and 1998, options to
purchase 18,937,397 shares of the 1994 options remain unexercised and
outstanding. In April 2000, the only outstanding option to purchase 18,937,397
shares under the 1994 SOP was amended to limit the number of shares that could
be purchased pursuant to the option to such number that enables the holder to
maintain ownership of a majority of the outstanding shares. Because the holder
of this option owned, and continues to own, a majority of the shares, the
number of shares exercisable as of April 2000 was zero. Prior to the closing of
the IPO, the 1994 Stock Option Plan and all outstanding options under the Plan
were cancelled.

   Information regarding the Company's 1994 SOP is summarized as follows:

<TABLE>
<CAPTION>
                             2000      2000      1999      1999      1998       1998
                          ---------- -------- ---------- -------- ----------  --------
                                     Weighted            Weighted             Weighted
                                     average             average              average
                                     exercise            exercise             exercise
                            Shares    price     Shares    price     Shares     price
                          ---------- -------- ---------- -------- ----------  --------
<S>                       <C>        <C>      <C>        <C>      <C>         <C>
Outstanding at beginning
 of year................  18,937,397  $0.004  18,937,397  $0.004  22,153,213   $0.004
Granted.................         --      --          --      --          --       --
Expired unexercised.....         --      --          --      --          --       --
Exercised...............         --      --          --      --   (3,215,816)   0.004
                          ----------  ------  ----------  ------  ----------   ------
Outstanding at end of
 period.................  18,937,397  $0.004  18,937,397  $0.004  18,937,397   $0.004
                          ==========  ======  ==========  ======  ==========   ======
Exercisable at end of
 period.................         --      --   18,937,397  $0.004  18,937,397   $0.004
                          ==========  ======  ==========  ======  ==========   ======
Fair value of options
 granted................         --      --          --      --          --       --
                          ==========  ======  ==========  ======  ==========   ======
</TABLE>

(6) Earnings Per Share

   Basic earnings per share is computed by dividing net income (loss) available
to common shareholders by the weighted average number of common shares
outstanding during the period. Diluted earnings per share is

                                       52
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2000, 1999 and 1998

determined on the assumption that outstanding stock options have been converted
using the average price for the period. For purposes of computing earnings per
share in a loss year, potential common shares have been excluded from the
computation of weighted average common shares outstanding because their effect
is antidilutive.

   Basic and diluted net income (loss) per share is computed based on the
following information (in thousands, except share and per share amounts):
<TABLE>
<CAPTION>
                                           For the years ended December 31,
                                           ----------------------------------
                                              2000        1999        1998
                                           ----------  ----------  ----------
<S>                                        <C>         <C>         <C>
Net income (loss) available to common
 shareholders............................. $  (10,398) $   18,228  $  (15,710)
                                           ==========  ==========  ==========
Basic--weighted average shares............ 14,285,714  14,285,714  11,925,785
                                           ==========  ==========  ==========
Diluted--weighted average shares           14,285,714  14,285,714  11,925,785
                                           ==========  ==========  ==========
Net income (loss) per share:
 Basic:
  Net loss before extraordinary item...... $    (0.73) $    (0.77) $    (1.32)
  Extraordinary gain, net of income
   taxes..................................         --        2.05          --
                                           ----------  ----------  ----------
Net income (loss) per common share........ $    (0.73) $     1.28  $    (1.32)
                                           ==========  ==========  ==========
Diluted:
  Net loss before extraordinary item...... $    (0.73) $    (0.77) $    (1.32)
  Extraordinary gain, net of income
   taxes.................................. $       --        2.05          --
                                           ----------  ----------  ----------
Net income (loss) per common share........ $    (0.73) $     1.28  $    (1.32)
                                           ==========  ==========  ==========
</TABLE>

 Major Customers

   The Company sells a portion of its oil and gas to end users through various
gas marketing companies. Three companies purchased oil and gas from the company
in excess of 10% of gross oil and gas revenues before giving effect to hedging
in each respective period. One of these company's purchases totaled $4.6
million and $12.4 million or 12% and 61% and for the periods ended December 31,
1999 and 1998 respectively. A second company's purchases totaled $42.7 million
and $18.6 million or 41% and 48% for the periods ended December 31, 2000 and
1999 respectively. The third company's purchases totaled $42.4 million and $7.3
million or 41% and 19% for the periods ended December 31, 2000 and 1999
respectively.

(7) Income Taxes

   The reconciliation of income tax computed at the U.S. federal statutory tax
rates to the provision for income taxes is as follows:
<TABLE>
<CAPTION>
                                                      Years ended December
                                                              31,
                                                      ------------------------
                                                       2000     1999     1998
                                                      ------   ------   ------
<S>                                                   <C>      <C>      <C>
Before any valuation allowance:
  Statutory federal income tax rate.................. (35.00)%  35.00 % (35.00)%
  State income taxes, net of federal benefit.........   0.00     0.32    (0.32)
  Adjustment to valuation allowance..................   0.00   (46.53)   35.31
  Nondeductible and other............................   0.02     0.05     0.01
                                                      ------   ------   ------
                                                      (34.98)% (11.16)%   0.00%
                                                      ======   ======   ======
</TABLE>


                                       53
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2000, 1999 and 1998

   At December 31, 1998, the Company had determined that it was more likely
than not the deferred tax assets would not be realized. During 1998, the
valuation allowance increased by $5.5 million. At December 31, 1999, however,
the Company determined that it was more likely than not the deferred tax assets
would be realized based on current projections of taxable income due to higher
commodity prices at year-end and the valuation allowance was decreased to zero.

   Significant components of the Company's deferred tax assets (liabilities) as
of December 31, 2000 and 1999 are as follows (in thousands):

<TABLE>
<CAPTION>
                                                                 December 31,
                                                                 --------------
                                                                  2000   1999
                                                                 ------ -------
<S>                                                              <C>    <C>
Deferred tax assets (liabilities):
  Net operating loss carryforwards.............................. $3,826 $ 3,800
  Minimum tax credit carryforwards..............................    229     229
  Fixed asset basis differences.................................    554  (2,379)
  State taxes...................................................     17      17
  Unrealized book losses........................................  2,537     --
  Other.........................................................    489     391
                                                                 ------ -------
    Total deferred tax assets...................................  7,652   2,058
Valuation allowance for deferred tax assets.....................    --      --
                                                                 ------ -------
    Net deferred tax assets..................................... $7,652 $ 2,058
                                                                 ====== =======
</TABLE>

   At December 31, 2000, 1999 and 1998 the Company had net operating loss
carryforwards for federal income tax purposes of approximately $11 million, $11
million, and $22 million respectively, which are available to offset future
federal taxable income through 2019.

(8) Commitments and Contingencies

   From time to time, the Company may be a party to various legal proceedings.
We currently are not a party to any material litigation.

   In October 2000, we entered into a letter of intent to acquire interests in
three properties (five blocks) in the Southern Gas Basin of the U.K. North Sea,
two of which we have since acquired. Under the letter of intent, we would
acquire a 50% interest in one block, a 100% interest in one block and an 86%
interest in three blocks. The letter of intent provides that we would pay an
aggregate of (Pounds)2,500,000, approximately $3.6 million, for the three
properties at closing. We will make additional payments on a property by
property basis at first production and thereafter at designated production
levels. The aggregate payments at first production for all three fields would
total (Pounds)2,300,000, approximately $3.3 million. We do not expect first
production to occur until at least 2002. The aggregate payments for achieving
designated production levels for all three fields would total up to
(Pounds)1,650,000, approximately $2.4 million. Based on currently available
information we cannot estimate when such production levels may be achieved.

   In March 2001 we acquired two of the three properties covered by the October
2000 letter of intent. Total proved reserves net to our interest in these two
properties is approximately 40.0 Bcfe. Initial acquisition costs were
(Pounds)1.6 million, approximately $2.3 million. Neither of the properties were
producing when we acquired them. We expect to begin development operations in
2001 with first production scheduled for late 2002 or early 2003. The third
property remains under the letter of intent.

                                       54
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2000, 1999 and 1998


   The Company has commitments under an operating lease agreement for office
space. Total rent expense for the year ended December 31, 2000, 1999 and 1998
was approximately $0.2 million, $0.1 million and $0.1 million respectively. At
December 31, 2000, the future minimum rental payments due under the lease are
as follows (in thousands amounts):

<TABLE>
   <S>                                                                      <C>
   2001.................................................................... $234
   2002....................................................................  226
   2003....................................................................  230
   2004....................................................................  230
   2005 and beyond.........................................................   71
                                                                            ----
     Total................................................................. $991
                                                                            ====
</TABLE>

(9) ATP Energy Gas Purchase Transaction

   ATP Energy entered an agreement in December 1998 with American Citigas
Company to purchase gas over a ten-year period commencing January 1999. The
amount of gas to be purchased was 9,000 MMBtu per day for the first year and
5,000 MMBtu per day for years two through ten. The contract requires ATP Energy
to purchase on a monthly basis the gas at a premium of approximately $2.50 per
MMBtu to the Gas Daily Henry Hub Index. American Citigas Company is required to
reimburse ATP Energy on a monthly basis for a portion of this premium during
the term of the contract. This portion of the reimbursement is accomplished by
a note receivable in favor of the Company. The note receivable bears interest
at 6% and has monthly payments of $373,000 commencing January 1999 and ending
January 2009. The balance of the note receivable at December 31, 2000 was $28.8
million. At December 31, 2000, the present value of the remaining premium
payments to be made by ATP Energy, using a discount rate of 6%, was $28.7
million. The note receivable and the premium payable to American Citigas have
been offset in the consolidated financial statements in accordance with the
prescribed accounting in Financial Accounting Standards Board Interpretation
No. 39. The aggregate amount of premium payments to be paid by ATP Energy over
the term of the contract is approximately $49.0 million and the aggregate
amount of payments to be paid to ATP Energy over the term of the note is
approximately $45.0 million. At December 31, 2000, the remaining premium to be
paid was $     million which will be reimbursed by the monthly reimbursement
from American Citigas and the remaining deferred obligation discussed below.
The terms provide for the immediate termination of the agreement upon non-
performance by American Citigas. ATP Energy entered into a contract with El
Paso Energy Marketing in December 1998 to sell an identical quantity of natural
gas at the Gas Daily Henry Hub index price less $0.015 until December 2001.

   ATP Energy received $6.0 million in connection with these transactions, of
which $2.0 million was recorded as deferred revenue and $4.0 million was
recorded as deferred obligations as of December 31, 1998. The deferred revenue
amount of $2.0 million is a non-refundable fee received by ATP Energy and is
recognized into income as earned over the life of the contract. At December 31,
2000 and 1999 the deferred revenue amount was $1.5 million and $1.7 million,
respectively. The deferred obligation amount of $4.0 million represented the
difference between the premium we agreed to pay for natural gas under the
American Citigas contract and the obligation of American Citigas to partially
reimburse us for such premium. Any deferred obligation amount not utilized is
refundable if the contract is terminated. The transaction is structured with
American Citigas such that there is no financial impact to ATP Energy
associated with the premium paid and reimbursement received other than the $2.0
million realized by ATP Energy. The remaining balance of the deferred
obligation was $0.1 million and $0.2 million at December 31, 2000 and 1999,
respectively. The premium we pay to American Citigas will be approximately the
same as the reimbursement obligation for the

                                       55
<PAGE>

                   ATP OIL & GAS CORPORATION AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2000, 1999 and 1998

remainder of the contract. ATP Energy entered into the transactions to earn the
fee for agreeing to market the volumes of natural gas specified in the American
Citigas contract. At the end of its agreement with El Paso in December 2001 the
Company may renew the agreement or enter into another marketing arrangement
having similar terms.

   Officers of the Company were paid $152,125 and $97,875 for the periods ended
December 31, 2000 and 1999, respectively, for negotiating and monitoring ATP
Energy's gas supply contract. The Company has recognized these amounts in
general and administrative expense in the respective periods. The Company does
not intend to pay any further bonuses in connection with this transaction.

(10) Related Party Transactions

   The Company has granted to certain officers of the Company overriding
royalty interests ranging in amounts from 0.2% to 3.0% in four of its oil and
gas properties. The overriding royalty interest entitles the holder to a
portion, 0.2% to 3.0%, of the future revenue for the life of each property. As
a result, the Company has recognized $0.3 million, $0.6 million and $0.5
million in general and administrative expense for the periods ended
December 31, 2000, 1999 and 1998.

                                       56
<PAGE>

                           ATP OIL & GAS CORPORATION

              SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION,
                     DEVELOPMENT AND PRODUCTION ACTIVITIES

                                  (Unaudited)

   The following tables set forth certain historical costs and operating
information related to the Company's natural gas and oil producing activities
as of and for the periods ended December 31, 2000, 1999 and 1998.

Costs Incurred

   Costs incurred in natural gas and oil property acquisition, exploration and
development activities are summarized below (in thousands):
<TABLE>
<CAPTION>
                                                          Years ended December
                                                                   31,
                                                         -----------------------
                                                          2000    1999    1998
                                                         ------- ------- -------
   <S>                                                   <C>     <C>     <C>
   Property costs:
     Acquisition costs.................................. $ 7,534 $25,274 $12,070
     Development costs..................................  68,982  30,777  23,866
                                                         ------- ------- -------
       Total costs incurred............................. $76,516 $56,051 $35,936
                                                         ======= ======= =======
</TABLE>

Natural Gas and Oil Reserves

   Proved reserves are estimated quantities of natural gas and oil which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods.

   Proved natural gas and oil reserve quantities at December 31, 2000, 1999,
and 1998, and the related discounted future net cash flows before income taxes
are based on estimates prepared by Ryder Scott Company, L.P. and Schlumberger
Holditch-Reservoir Technologies Consulting Services, independent petroleum
engineers. Such estimates have been prepared in accordance with guidelines
established by the Securities and Exchange Commission.

                                       57
<PAGE>

                           ATP OIL & GAS CORPORATION

              SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION,
               DEVELOPMENT AND PRODUCTION ACTIVITIES--(Continued)

                                  (Unaudited)


   The Company's net ownership in estimated quantities of proved natural gas
and oil reserves and changes in net proved reserves, all of which are located
in the U.S. waters of the Gulf of Mexico, are summarized below:

<TABLE>
<CAPTION>
                                                       Millions of cubic feet
                                                         of natural gas at
                                                            December 31,
                                                       ------------------------
                                                        2000     1999     1998
                                                       -------  -------  ------
<S>                                                    <C>      <C>      <C>
Proved developed and undeveloped reserves:
  Beginning of the year...............................  93,997   46,424  40,526
  Revisions of previous estimates..................... (19,423)   3,033  (8,411)
  Extensions and discoveries..........................   7,239    2,257     --
  Purchase of properties..............................  42,318   58,816  24,059
  Disposition of properties...........................    (151)     --     (724)
  Production.......................................... (22,410) (16,533) (9,026)
                                                       -------  -------  ------
    Proved reserves at the end of the year............ 101,570   93,997  46,424
                                                       =======  =======  ======
    Proved developed reserves:
      Beginning of year...............................  67,314   39,728  31,080
      End of year.....................................  42,502   67,314  39,728
</TABLE>

<TABLE>
<CAPTION>
                                                            Barrels of oil,
                                                            condensate, and
                                                                natural
                                                             gas liquids at
                                                              December 31,
                                                            ------------------
                                                            2000   1999   1998
                                                            -----  -----  ----
<S>                                                         <C>    <C>    <C>
Proved developed and undeveloped reserves (in thousands):
  Beginning of the year.................................... 1,689    586   942
  Revisions of previous estimates..........................   (46)  (131)   29
  Extensions and discoveries...............................    77    --    --
  Purchase of properties................................... 2,602  1,362     9
  Disposition of properties................................   --     --   (243)
  Production...............................................  (345)  (128) (151)
                                                            -----  -----  ----
    Proved reserves at the end of the year................. 3,977  1,689   586
                                                            =====  =====  ====
    Proved developed reserves:
      Beginning of year....................................   710    579   678
      End of year..........................................   851    710   579
</TABLE>

                                       58
<PAGE>

                           ATP OIL & GAS CORPORATION

              SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION,
               DEVELOPMENT AND PRODUCTION ACTIVITIES--(Continued)

                                  (Unaudited)


Standardized Measure

   The standardized measure of discounted future net cash flows relating to the
Company's ownership interests in proved natural gas and oil reserves as of
year-end is shown below (in thousands):

<TABLE>
<CAPTION>
                                         Years ended  December 31,
                                        ----------------------------------
                                           2000       1999          1998
                                        ----------  --------      --------
<S>                                     <C>         <C>           <C>
Future cash inflows.................... $1,139,404  $272,047      $106,772
Future operating expenses..............    (70,719)  (40,794)      (18,730)
Future development costs...............   (137,453)  (48,204)      (18,432)
                                        ----------  --------      --------
  Future net cash flows................    931,232   183,049(/2/)   69,610
Future income taxes....................   (285,587)  (27,611)          --
                                        ----------  --------      --------
  Future net cash flows after income
   taxes...............................    645,645   155,438        69,610
10% annual discount per annum..........   (121,164)  (26,732)       (8,302)
                                        ----------  --------      --------
  Standardized measure of discounted
   future net cash flows............... $  524,481  $128,706      $ 61,308(/1/)
                                        ==========  ========      ========
</TABLE>
--------
(1) Net operating loss carryforwards and basis in natural gas and oil
    properties have eliminated the requirement for future income taxes.
(2) At December 31, 1999, future net cash flows totaling $112.5 million from
    ten properties, are committed to repayment of the Company's non-recourse
    borrowings.

   Future cash inflows are computed by applying year-end prices of oil and gas
to the year-end estimated future production of proved oil and gas reserves. The
base prices used for the Pretax PV-10 calculation were public market prices on
December 31 adjusted by differentials to those market prices. These price
adjustment were done on a property-by-property basis for the quality of the oil
and natural gas and for transportation to the appropriate location. The Henry
Hub and Koch West Texas New Mexico Intermediate prices, before adjustment for
quality and transportation, utilized in the Pretax PV-10 value at December 31,
2000 were $9.52 per mmbtu of natural gas and $23.75 per barrel of oil. At
February 28, 2001, the Henry Hub and Koch West Texas New Mexico Intermediate
prices were $5.10 per mmbtu of natural gas and $24.25 per barrel of oil.
Estimates of future development and production costs are based on year-end
costs and assume continuation of existing economic conditions and year-end
prices. The estimated future net cash flows are then discounted using a rate of
10 percent per year to reflect the estimated timing of the future cash flows.
The standardized measure of discounted cash flows is the future net cash flows
less the computed discount.

                                       59
<PAGE>

                           ATP OIL & GAS CORPORATION

              SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION,
               DEVELOPMENT AND PRODUCTION ACTIVITIES--(Continued)

                                  (Unaudited)


Changes in Standardized Measure

   Changes in standardized measure of future net cash flows relating to proved
natural gas and oil reserves are summarized below (in thousands):

<TABLE>
<CAPTION>
                                                   Years ended  December 31,
                                                   ----------------------------
                                                     2000      1999      1998
                                                   --------  --------  --------
<S>                                                <C>       <C>       <C>
Beginning of year................................. $128,706  $ 61,308  $ 64,698
  Sales of oil and gas, net of production costs...  (64,381)  (29,394)  (17,217)
  Net changes in income taxes..................... (193,613)  (27,611)   13,708
  Net changes in price and production costs.......  416,738     9,931   (20,272)
  Revisions of quantity estimates................. (147,777)    4,176   (12,318)
  Accretion of discount...........................   15,632     6,131     7,841
  Development costs incurred......................   18,134    15,550    19,780
  Changes in estimated future development.........  (14,709)  (15,664)  (13,129)
  Purchases of minerals-in-place..................  300,706   105,514    25,136
  Sales of minerals-in-place......................     (525)      --     (4,886)
  Extensions and discoveries......................   51,795       218       --
  Changes in production rates, timing and other...   13,775    (1,453)   (2,033)
                                                   --------  --------  --------
  Total changes in standardized increases.........  395,775    67,398    (3,390)
                                                   --------  --------  --------
End of year....................................... $524,481  $128,706  $ 61,308
                                                   ========  ========  ========
</TABLE>

   Sales of natural gas and oil, net of natural gas and oil operating expenses,
are based on historical pre-tax results. Sales of natural gas and oil
properties, extensions and discoveries, purchases of minerals-in-place and the
changes due to revisions in standardized variables are reported on a pre-tax
discounted basis, while the accretion of discount is presented on an after-tax
basis.

                                       60
<PAGE>

                           ATP OIL & GAS CORPORATION

                      SUPPLEMENTARY QUARTERLY INFORMATION
                                  (unaudited)

<TABLE>
<CAPTION>
                           First     Second           Third           Fourth
                          Quarter  Quarter(5)       Quarter(5)       Quarter
                          -------  ----------       ----------       --------
<S>                       <C>      <C>              <C>              <C>
2000
Revenues................  $15,127   $24,558          $20,462         $ 23,841
Costs and operating
 expenses...............   11,682    25,743 (1)(2)    23,778 (1)(2)    27,321 (1)(2)
Net income (loss) from
 operations.............    3,445    (1,185)          (3,316)          (3,480)
Net income (loss).......    1,029    (2,742)          (4,251)          (4,434)
Income (loss) per common
 share:
  Basic and diluted.....  $  0.07   $ (0.19)         $ (0.30)        $  (0.31)

1999
Revenues................  $10,498   $11,248          $11,325         $  9,900
Costs and operating
 expenses...............   10,649    11,855 (3)       13,984 (3)       10,072 (3)
Net income (loss) from
 operations.............     (151)     (607)          (2,659)            (172)
Income (loss) before
 extraordinary item.....   (2,050)   (5,019)          (2,586)          (1,302)
Net income (loss).......   (2,050)   24,166 (4)       (2,586)          (1,302)
Income (loss) per common
 share before
 extraordinary item:
  Basic and diluted.....  $ (0.14)  $ (0.35)         $ (0.18)        $  (0.09)
Income (loss) per common
 share:
  Basic and diluted.....  $ (0.14)  $  1.69          $ (0.18)        $  (0.09)
</TABLE>
--------
(1) Includes impairment charges of $6.2 million, $0.8 million and $3.8 million
    during the second, third and fourth quarters respectively for three
    properties.

(2) Includes loss on speculative derivative position of $2.5 million, $3.7
    million and $5.7 million during the second, third and fourth quarters
    respectively.

(3) Includes impairment charges of $2.5 million, $3.9 million and $1.1 million
    during the second, third and fourth quarters respectively for four
    properties.

(4) Includes extraordinary gain in the amount of $29.2 million recognized as a
    result of the discounted extinguishment of debt under our development
    program credit agreement.

(5) Results for the second and third quarters of 2000 have been revised to
    reflect the Company's written call option contracts on a mark-to-market
    basis. The Company recently determined that such contracts do not qualify
    for hedge accounting. The impact of the revision increased the previously
    reported amounts as follows:

<TABLE>
<CAPTION>
                                                                 Second   Third
                                                                 Quarter Quarter
                                                                 ------- -------
<S>                                                              <C>     <C>
Revenues........................................................ $  481  $  319
Cost and operating expenses.....................................  1,764   1,531
Net loss from operations........................................  1,283   1,212
Net loss........................................................    839     780
Basic and diluted loss per share................................   0.06    0.05
</TABLE>

                                       61
<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
on its behalf by the undersigned, thereunto duly authorized.

                                          ATP OIL & GAS CO.

                                                  /s/ Albert L. Reese, Jr.
                                          By: _________________________________
                                                    Albert L. Reese, Jr.
                                              Senior Vice President and Chief
                                                     Financial Officer

                               POWER OF ATTORNEY

   KNOWN ALL MEN BY THESE PRESENTS, that each person whose signature appears
below constitutes and appoints T. Paul Bulmahn and Albert L. Reese, Jr., and
each of them, his or her true and lawful attorneys-in-fact and agents with full
power of substitution and resubstitution for him or her and in his or her name,
place and stead, in any and all capacities, to sign any or all amendments to
this Form 10-K and to file the same, with all exhibits thereto, and other
documents in connection therewith, with the Securities and Exchange Commission
granting unto said attorneys-in-fact and agents and each of them full power and
authority to do and perform each and every act and thing requisite or necessary
to be done in and about the premises, to all intents and purposes and as fully
as he or she might or could do in person, hereby ratifying and confirming all
that said attorneys-in-fact and agents or their substitutes may lawfully do or
cause to be done by virtue thereof.

   Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed by the following persons on behalf of the registrant in
the capacities indicated on March 30, 2001.

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

<S>                                            <C>
        /s/ T. Paul Bulmahn                    Chairman, President and
______________________________________          Director (Principal Executive
           T. Paul Bulmahn                      Officer)

      /s/ Albert L. Reese, Jr.                 Senior Vice President and
______________________________________          Chief Financial Officer
         Albert L. Reese, Jr.                   (Principal Financial Officer)

        /s/ Keith R. Godwin                    Vice President and Controller
______________________________________          (Principal Accounting Officer)
           Keith R. Godwin

        /s/ Carol E. Overbey                   Director
______________________________________
           Carol E. Overbey

         /s/ Gerard Swonke                     Director
______________________________________
            Gerard Swonke

        /s/ Arthur H. Dilly                    Director
______________________________________
           Arthur H. Dilly

        /s/ Robert C. Thomas                   Director
______________________________________
           Robert C. Thomas

       /s/ Walter Wendlandt                    Director
______________________________________
           Walter Wendlandt
</TABLE>

                                       62
<PAGE>

                               INDEX OF EXHIBITS

<TABLE>
<CAPTION>
 Exhibit No. Description
 ----------- -----------
 <C>         <S>
     3.1     Amended and Restated Articles of Incorporation (incorporated by
             reference to Exhibit 3.1 of ATP's registration statement No. 333-
             46034 on Form S-1)

     3.2     Restated Bylaws (incorporated by reference to Exhibit 3.2 of ATP's
             registration statement No. 333-46034 on Form S-1)

     4.1     Form of Common Stock Certificate (incorporated by reference to
             Exhibit 4.1 of ATP's registration statement No. 333-46034 on Form
             S-1)

    10.1     Amended and Restated Credit Agreement, dated as of September 21,
             1999, among ATP Oil & Gas Corporation, Chase Bank of Texas,
             National Association as Agent, and the Lenders Signatory thereto
             (incorporated by reference to Exhibit 10.1 of ATP's registration
             statement No. 333-46034 on Form S-1)

    10.2     First Amendment to Amended and Restated Credit Agreement, dated as
             of September 21, 1999, among ATP Oil & Gas Corporation, Chase Bank
             of Texas, National Association, as Agent, and the Lenders
             Signatory thereto, effective as of June 30, 2000 (incorporated by
             reference to Exhibit 10.2 of ATP's registration statement No. 333-
             46034 on Form S-1)

    10.3     Credit Agreement between ATP Oil & Gas Corporation and Aquila
             Energy Capital Corporation, dated April 9, 1999, effective as of
             March 31, 1999 (incorporated by reference to Exhibit 10.3 of ATP's
             registration statement No. 333-46034 on Form S-1)

    10.4     First Amendment to Credit Agreement, dated April 9, 1999, by and
             between ATP Oil & Gas Corporation and Aquila Energy Capital
             Corporation (incorporated by reference to Exhibit 10.4 of ATP's
             registration statement No. 333-46034 on Form S-1)

    10.5     Second Amendment to Credit Agreement, dated April 9, 1999, by and
             between ATP Oil & Gas Corporation and Aquila Energy Capital
             Corporation (incorporated by reference to Exhibit 10.5 of ATP's
             registration statement No. 333-46034 on Form S-1)

    10.6     Gas Service Agreement, dated December 31, 1998, between American
             Citigas Company and ATP Energy, Inc. (incorporated by reference to
             Exhibit 10.6 of ATP's registration statement No. 333-46034 on Form
             S-1)

    10.7     Marketing & Natural Gas Purchase Agreement, dated December 1,
             1998, between ATP Energy, Inc. and El Paso Energy Marketing
             Company (incorporated by reference to Exhibit 10.7 of ATP's
             registration statement No. 333-46034 on Form S-1)

    10.8     Purchase and Sale Agreement, effective as of May 1, 1999, between
             Eugene Offshore Holdings, LLC and ATP Oil & Gas Corporation
             (incorporated by reference to Exhibit 10.8 of ATP's registration
             statement No. 333-46034 on Form S-1)

    10.9     ATP Oil & Gas Corporation 1998 Stock Option Plan (incorporated by
             reference to Exhibit 10.9 of ATP's registration statement No. 333-
             46034 on Form S-1)

    10.10    First Amendment to the ATP Oil & Gas Corporation 1998 Stock Option
             Plan (incorporated by reference to Exhibit 10.10 of ATP's
             registration statement No. 333-46034 on Form S-1)

    10.11    ATP Oil & Gas Corporation 2000 Stock Plan

    21.1     Subsidiaries of ATP Oil & Gas Corporation (incorporated by
             reference to Exhibit 21.1 of ATP's registration statement No. 333-
             46034 on Form S-1)

    24.1     Power of Attorney (included on the signature page to this
             Registration Statement)
</TABLE>

                                       63