ATP OIL & GAS CORP, S-1/A, 2001-01-12

ATP OIL & GAS CORP
S-1/A, 2001-01-12
CRUDE PETROLEUM & NATURAL GAS

Previous: WEALTHHOUND COM INC, 3, 2001-01-12

Next: ATP OIL & GAS CORP, S-1/A, EX-1.1, 2001-01-12

<PAGE>

As filed with the Securities and Exchange Commission on January 12, 2001
Registration No. 333-46034
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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

AMENDMENT NO. 3
TO
FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

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

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

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

Texas 1330 76-0362774
(State or other (Primary Standard (I.R.S. Employer
jurisdiction Industrial Identification No.)
of incorporation or Classification Code
organization) Number)

4600 Post Oak Place, Suite 200
Houston, Texas 77027
(713) 622-3311
(Address, including zip code, and telephone number, including area code, of
registrant's principal executive offices)

Albert L. Reese, Jr.
Senior Vice President and Chief Financial Officer
ATP Oil & Gas Corporation
4600 Post Oak Place, Suite 200
Houston, Texas 77027
(713) 622-3311
(Name, address, including zip code, and telephone number, including area code,
of agent for service)

----------------
Copies to:
Keith R. Fullenweider Darrell W. Taylor
Vinson & Elkins L.L.P. Baker Botts L.L.P.
2300 First City Tower 3000 One Shell Plaza
1001 Fannin 910 Louisiana
Houston, Houston, Texas 77002
Texas 77002-6760 (713) 229-1234
(713) 758-2222

Approximate date of commencement of proposed sale to the public: As soon as
practicable after this registration statement becomes effective.
If any of the securities registered on this form are being offered on a
delayed or continuous basis pursuant to Rule 415 under the Securities Act,
check the following box. [_]
If this form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering. [_]
If this form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]
If this form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [_]

The registrant hereby amends this registration statement on such date or
dates as may be necessary to delay its effective date until the registrant
shall file a further amendment which specifically states that this registration
statement shall thereafter become effective in accordance with section 8(a) of
the Securities Act of 1933 or until the registration statement shall become
effective on such date as the Commission, acting pursuant to said section 8(a),
may determine.
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>

++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
+ +
+The information in this prospectus is not complete and may be changed. We may +
+not sell these securities until the registration statement filed with the +
+Securities and Exchange Commission is effective. This prospectus is not an +
+offer to sell these securities and is not soliciting an offer to buy these +
+securities in any state where the offer or sale is not permitted. +
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++

PROSPECTUS Subject to Completion, dated January 12, 2001

7,500,000 Shares

[ATP LOGO]

ATP OIL & GAS CORPORATION

Common Stock

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

This is our initial public offering of common stock. We are offering up to
7,500,000 shares of common stock. No public market currently exists for our
shares.

Our common stock has been approved for quotation on the Nasdaq National
Market under the symbol "ATPG", subject to notice of issuance. The anticipated
price range is $15.00 to $18.00 per share.

Investing in the shares involves risks. "Risk Factors" begin on page 11.

<TABLE>
<CAPTION>
Per
Share Total
------ -----------
<S> <C> <C>
Public Offering Price....................................... $ $
Underwriting Discount....................................... $ $
Proceeds to ATP Oil & Gas Corporation....................... $ $
</TABLE>

Our selling shareholders have granted the underwriters a 30-day option to
purchase up to 1,125,000 additional shares of common stock to cover over-
allotments, if any.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if
this prospectus is accurate or complete. Any representation to the contrary is
a criminal offense.

Lehman Brothers, on behalf of the underwriters, expects to deliver the shares
on or about , 2001.

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

Lehman Brothers
CIBC World Markets
Dain Rauscher Wessels
Raymond James & Associates, Inc.
Fidelity Capital Markets

, 2001
<PAGE>

[ATP LOGO]

<PAGE>

TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Prospectus Summary....................................................... 2
Risk Factors ............................................................ 11
Cautionary Statement About Forward-Looking Information................... 18
Use Of Proceeds.......................................................... 19
Dividend Policy.......................................................... 19
Dilution................................................................. 20
Capitalization........................................................... 21
Selected Historical and Pro Forma Financial Data......................... 22
Additional Pro Forma Data................................................ 24
Management's Discussion And Analysis Of Financial Condition And Results
Of Operations........................................................... 25
</TABLE>
<TABLE>
<CAPTION>
Page
----
<S> <C>
Business And Properties.................................................... 34
Management ................................................................ 52
Related Party Transactions ................................................ 58
Principal and Selling Shareholders ........................................ 59
Description Of Capital Stock .............................................. 60
Shares Eligible For Future Sale ........................................... 63
Underwriting .............................................................. 65
Legal Matters ............................................................. 68
Experts ................................................................... 68
Where You Can Find More Information ....................................... 68
Glossary of Technical Terms................................................ 69
Index to Consolidated Financial Statements................................. F-1
</TABLE>

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

ABOUT THIS PROSPECTUS

You should rely only on the information contained in this prospectus. We
have not authorized anyone to provide you with different information. We are
not making an offer of these securities in any state where the offer is not
permitted.

Until , 2001, all dealers that effect transactions in these
securities, whether or not participating in this offering, may be required to
deliver a prospectus. This is in addition to the dealers' obligation to deliver
a prospectus when acting as underwriters and with respect to their unsold
allotments or subscriptions.

1
<PAGE>

PROSPECTUS SUMMARY

This summary highlights selected information from this prospectus, but does
not contain all information that may be important to you. This prospectus
includes specific terms of this offering, information about our business and
financial data. We encourage you to read this prospectus in its entirety before
making an investment decision. We have included definitions of technical terms
important to an understanding of our business under "Glossary of Technical
Terms" on page 69. Also, unless otherwise indicated, all information in this
prospectus gives effect to a 1.4-for-1 reverse split of our common stock
effected in December 2000 and assumes no exercise of the underwriters' over-
allotment option.

About ATP Oil & Gas Corporation

ATP is engaged in the acquisition, development and production of natural gas
and oil properties primarily in the outer continental shelf of the Gulf of
Mexico. We recently have 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. We 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 November 30, 2000, our estimated net proved reserves were 127.5 Bcfe, 81%
of which was natural gas, with an estimated pre-tax PV-10 of $492.3 million.
Our average daily net production for November 2000 was 61.7 MMcfe, increasing
to 67.7 MMcfe in December 2000. At December 31, 2000, we had leasehold and
other interests in 47 offshore blocks and operated 53 of our 56 wells. Our
average working interest in our properties is approximately 85%. At November
30, 2000, proved developed reserves comprised 44% of our total reserves and our
reserve life index for total proved reserves was 5.2 years.

From 1997 to 1999, we achieved an average reserve replacement ratio of 318%
through our acquisition and development activities. During the first eleven
months of 2000, we replaced approximately 200% of our production for that
period. We believe substantial additional acquisition opportunities exist in
the outer continental shelf of the Gulf of Mexico. We also believe that our
business model is well suited for our expansion into the shallow-deep waters of
the Gulf of Mexico and into the Southern Gas Basin of the U.K. North Sea.

From 1995 to 1999, we increased our net proved reserves at a compound annual
growth rate of 263%, production at a compound annual growth rate of 207%, oil
and gas revenues at a compound annual growth rate of 183% and Adjusted EBITDA
at a compound annual growth rate of 371%. Since 1996, our Adjusted EBITDA,
which we define as earnings before interest, income taxes, depreciation,
depletion and amortization and property impairment, has consistently averaged
60% to 75% of total revenues while our net income and loss has varied from a
loss of 79% of revenues to a profit of 42% of revenues. We were listed on the
2000 Inc. 500 as the fifth fastest growing privately held company in the United
States.

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;

2
<PAGE>

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

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

To date, our area of concentration has been on the outer continental shelf
of the Gulf of Mexico, which exhibits each of the above characteristics. We
believe these characteristics are also present in the shallow-deep waters of
the Gulf of Mexico and in the Southern Gas Basin of the U.K. North Sea, where
we are actively pursuing the acquisition and development of properties with
proved undeveloped reserves.

We implement our business strategy through the following two steps:

. Acquire Proved Undeveloped Reserves. We continually review opportunities
to acquire proved natural gas and oil reserves that are not strategic to
the companies from which we acquire them. Because we focus on undeveloped
properties, we are typically able to acquire our properties by granting
overriding royalty interests and for a minimal cash outlay.

. Efficiently Develop and Produce Reserves. 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.

Risks Related to Our Strategy

Prospective investors should carefully consider the matters set forth under
the caption "Risk Factors," as well as the other information set forth in this
prospectus, including that the market for attractive opportunities to acquire
properties with proved undeveloped reserves may not be available, our reserve
estimates may not be accurate, our results will be affected by the volatile
nature of oil and gas prices and we have incurred operating losses in recent
years. One or more of these matters could negatively affect our ability to
successfully implement our business strategy.

Our Strengths

. Operating Efficiency. We emphasize a low overhead and operating expense
structure. For the nine months ended September 30, 2000, our lease
operating expense was $0.44 per Mcfe of production and our general and
administrative expense was $0.21 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, 1999,
our total average cost incurred for finding and developing our net proved
reserves was $1.28 per Mcfe.

. Operating Control. We currently operate 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.

3
<PAGE>

. 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. Prior to the
offering, our employees own 100% of ATP. Following this offering, our
employees will own 67% of ATP on a fully diluted basis.

Significant Properties

We have summarized our most significant properties in the tables below.

<TABLE>
<CAPTION>
As of 11/30/00 November 2000
ATP Net Proved Reserves (1)Average Daily
Significant ATP Net Revenue ---------------------- Net Production
Producing Properties Working Interest Interest Bcfe % Gas % Developed (MMcfe)
-------------------- ---------------- ----------- ---- ----- ----------- --------------
<S> <C> <C> <C> <C> <C> <C>
Gulf of Mexico-Shelf
Eugene Island 30........ 100% 80% 11.6 76 41 3.9
High Island A-354....... 100% 72-76% 11.1 99 100 10.4
Vermilion 410 Field..... 100% 77% 9.3 100 88 8.3
Brazos 544.............. 100% 62-68% 6.4 97 100 6.3
East Cameron 240........ 100% 83% 5.8 55 100 1.7
West Cameron 492........ 50% 36% 4.1 69 65 1.5
West Cameron 461........ 100% 80% 3.8 100 70 1.3
Vermilion 260........... 100% 79% 3.5 97 100 6.6
</TABLE>

<TABLE>
<CAPTION>
As of 11/30/00
Net Proved Undeveloped
Reserves (1)
------------------------
ATP
Significant ATP Net Revenue Projected
Development Properties Working Interest Interest Bcfe % Gas Production Date
---------------------- ---------------- ----------- ----------- ----------- -------------------
<S> <C> <C> <C> <C> <C>
Gulf of Mexico-Shelf
South Marsh Island
189/190................ 100% 83% 20.4 84 Third quarter 2001
West Cameron 635........ 100% 80% 6.8 94 First quarter 2001
Main Pass 282........... 100% 79% 3.4 92 First quarter 2001
Gulf of Mexico-Shallow-
Deep Waters
Garden Banks 409
(Ladybug).............. 50% 39% 15.1 22 Second quarter 2001
Garden Banks 186/187
(Cabrito)(2)........... 100% 95% 6.9 100 Fourth quarter 2001
Garden Banks 142
(Matia)................ 100% 80% 2.4 100 Fourth quarter 2001
<CAPTION>
As of 11/30/00
Net Proved Undeveloped
Reserves (1)(4)
------------------------
Significant ATP
Acquisitions in ATP Net Revenue Projected
Progress(3) Working Interest Interest Bcfe % Gas Acquisition Date
--------------- ---------------- ----------- ----------- ----------- -------------------
<S> <C> <C> <C> <C> <C>
Southern Gas Basin-U.K.
North Sea
Block 49/12a (Venture)
(5).................... 50% 50% 14.7 100 First quarter 2001
Block 47/10b............ 100% 100% (6) (6) First quarter 2001
Blocks 43/22a, 43/22c
and 43/17c............. 86% 86% (6) (6) First quarter 2001
</TABLE>

4
<PAGE>

--------
(1) Estimates of net proved reserves are based on our third party independent
reserve reports as of November 30, 2000.

(2) The Minerals Management Service granted the Garden Banks 186 and 187
leases with the first 98.35 Bcfe produced free of any royalty. After 98.35
Bcfe are produced, each lease will be subject to a 16.67% royalty.

(3) We have executed a letter of intent dated October 27, 2000 with BP
Exploration Operating Company Limited to acquire the properties listed in
this table. Although we expect to acquire these properties in the first
quarter of 2001, we may not complete these acquisitions by that time or at
all.
(4) Our estimated net proved reserves as of November 30, 2000 included in this
prospectus do not include any reserves from these properties.
(5) Conoco, which owns the remaining 50% working interest in this property,
has a preferential right to purchase the interest subject to our letter of
intent on substantially similar terms. Conoco's right must be waived prior
to a closing of our acquisition. Based on conversations with the seller of
this property and Conoco, we believe that Conoco will waive its
preferential right, although we can give you no assurance that it will do
so.
(6) We are currently evaluating the property to determine proved reserves.

Our Executive Offices

Our principal executive offices are located at 4600 Post Oak Place, Suite
200, Houston, Texas 77027, and our telephone number is (713) 622-3311. Our
website is located at www.atpog.com. Information contained in our website is
not part of this prospectus.

5
<PAGE>

The Offering

<TABLE>
<C> <S>
Common stock offered by ATP........................ 7,500,000 shares
Common stock to be outstanding after the offering.. 21,785,714 shares
Use of proceeds.................................... We intend to use the net
proceeds of this offering
to repay all indebtedness
under our development
program credit agreement
and indebtedness under our
credit facility and for
general corporate
purposes.
Nasdaq National Market symbol...................... ATPG
</TABLE>

The number of shares of common stock outstanding after the offering does not
include currently outstanding options to purchase a total of 644,822 shares of
common stock at prices of either $1.40 or $3.85 per share.

6
<PAGE>

Summary Consolidated Financial Data

The following table presents a summary of our historical and pro forma
consolidated financial data. You should read the following data in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results
of Operations" and our consolidated financial statements and related notes
included elsewhere in this prospectus.

<TABLE>
<CAPTION>
Years Ended Nine Months Ended
December 31, September 30,
------------------------------------------------- ------------------------
Pro Forma
1997 1998 1999 1999(1) 1999 2000
----------- ----------- ---------- ----------- ----------- -----------
(unaudited) (unaudited) (unaudited)
Statement of Operations
Data:
(in thousands, except share and per share data)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil and gas
production............ $ 7,359 $ 20,410 $ 34,981 $ 37,252 $ 27,182 $ 54,290
Gas sold--marketing.... -- -- 7,703 7,703 5,602 5,024
Gain on sale of oil and
gas properties........ 304 -- 287 287 287 33
----------- ----------- ---------- ---------- ---------- ----------
Total revenues........ 7,663 20,410 42,971 45,242 33,071 59,347
Costs and operating
expenses:
Lease operating........ 1,513 3,193 5,587 6,289 3,321 8,363
Gas purchased--
marketing............. -- -- 7,402 7,402 5,431 4,856
General and
administrative........ 1,170 2,591 3,541 3,541 2,902 4,018
Depreciation, depletion
and amortization...... 4,206 17,442 22,521 23,253 18,452 30,686
Impairment of oil and
gas properties........ 5,787 5,072 7,509 7,509 6,382 7,038
Other.................. -- -- -- -- -- 2,947
----------- ----------- ---------- ---------- ---------- ----------
Total operating
expenses............. 12,676 28,298 46,560 47,994 36,488 57,908
----------- ----------- ---------- ---------- ---------- ----------
Net income (loss) from
operations............. (5,013) (7,888) (3,589) (2,752) (3,417) 1,439
Other income (expense):
Interest income........ 207 141 202 202 102 334
Interest expense....... (1,212) (7,963) (9,399) (10,621) (7,471) (8,445)
----------- ----------- ---------- ---------- ---------- ----------
Income (loss) before
income taxes and
extraordinary item..... (6,018) (15,710) (12,786) (13,171) (10,786) (6,672)
Income tax benefit...... -- -- 1,829 1,964 1,131 2,327
----------- ----------- ---------- ---------- ---------- ----------
Income (loss) before
extraordinary item..... (6,018) (15,710) (10,957) $ (11,207) (9,655) (4,345)
==========
Gain on extinguishment
of debt, net of tax.... -- -- 29,185 29,185 --
----------- ----------- ---------- ---------- ----------
Net income (loss)....... $ (6,018) $ (15,710) $ 18,228 $ 19,530 $ (4,345)
=========== =========== ========== ========== ==========
Weighted average number
of common shares
outstanding:
Basic.................. 10,567,762 11,925,785 14,285,714 14,285,714 14,285,714 14,285,714
Diluted................ 10,567,762 11,925,785 14,285,714 14,285,714 14,285,714 14,285,714
Income (loss) per common
share before
extraordinary item:
Basic.................. $ (0.57) $ (1.32) $ (0.77) $ (0.78) $ (0.68) $ (0.30)
Diluted................ $ (0.57) $ (1.32) $ (0.77) $ (0.78) $ (0.68) $ (0.30)
Net income (loss) per
common share:
Basic.................. $ (0.57) $ (1.32) $ 1.28 $ 1.37 $ (0.30)
Diluted................ $ (0.57) $ (1.32) $ 1.28 $ 1.37 $ (0.30)
Other Financial Data:
Adjusted EBITDA (2)..... $ 5,187 $ 14,767 $ 26,643 $ 28,212 $ 21,519 $ 39,497
Adjusted EBITDA margin
(3).................... 68% 72% 62% 62% 65% 67%
</TABLE>

7
<PAGE>

<TABLE>
<CAPTION>
As of
September 30,
2000
--------------
(in thousands)
<S> <C>
Balance Sheet Data:
Cash and cash equivalents........................................ $ 19,066
Working capital.................................................. 10,327
Net oil and gas properties....................................... 85,437
Total assets..................................................... 136,909
Total liabilities................................................ 144,035
Shareholders' deficit............................................ (7,126)
</TABLE>
--------
(1) The unaudited pro forma financial information gives effect to our purchase
of Eugene Island 30 as if the transaction occurred on January 1, 1999. We
completed the acquisition of a 100% working interest and an 82% net revenue
interest in the property in September 1999 for a purchase price of $16.3
million in cash. The total purchase price was recorded to oil and gas
properties and was accounted for using the purchase method.
(2) Net income (loss) before interest expense, income taxes, depreciation,
depletion and amortization, and impairment of natural gas and oil
properties. 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.
(3) Represents Adjusted EBITDA divided by total revenues.

Additional Pro Forma Data

The unaudited pro forma income (loss) data presented in the following table
adjusts our historical net income (loss) and our pro forma loss giving effect
to the following:

. the use of a portion of the net proceeds from this offering (using
proceeds from 5,272,403 of the shares being sold) to repay all
outstanding debt under our development program credit agreement, as if
the transaction occurred on January 1, 1999;

. the reduction of interest expense related to the above described debt
reduction of $8.8 million for 1999 and $7.3 million for the nine months
ended September 30, 2000; and

. the tax effect of the interest expense reduction calculated at the
statutory rate of 35%.

<TABLE>
<CAPTION>
Year Ended
December 31, 1999 Nine Months
----------------------- Ended
Pro Forma September 30,
As 2000
Pro Forma Adjusted(1) Pro Forma
---------- ----------- -------------
(in thousands, except per share
data)
<S> <C> <C> <C>
Pro forma income (loss) before
extraordinary item.................... $ (5,226) $ (5,475) $ 431
Pro forma income (loss) per common
share before extraordinary item:
Basic and diluted.................... (0.27) (0.28) 0.02
Pro forma weighted average number of
common shares outstanding:
Basic................................ 19,558,117 19,558,117 19,558,117
Diluted.............................. 19,558,117 19,558,117 20,081,820
</TABLE>
--------
(1) Adjusts the pro forma net loss to give effect to the Eugene Island 30
acquisition as if it occurred on January 1, 1999.

As described in "Use of Proceeds," we intend to use a portion of the
proceeds from this offering to repay amounts outstanding under our bank credit
facility. Because we expect to reborrow under the facility to finance our 2001
acquisition and development program, we have not eliminated such borrowings in
our pro forma and pro forma as adjusted financial data.

8
<PAGE>

Summary Operating Information

The table below presents our summary operating data for our natural gas and
oil properties.

Average sales price per unit:
Natural gas revenues from
production (per Mcf)............. $2.60 $ 2.07 $ 2.23 $ 2.16 $ 3.59
Effects of hedging activities (per
Mcf)............................. -- -- (0.23) (0.18) (0.85)
------ ------ ------ -------- --------
Average gas price................ $ 2.60 $ 2.07 $ 2.00 $ 1.98 $ 2.74

Oil and condensate revenues from
production (per Bbl)............. $18.75 $11.50 $15.37 $ 14.17 $ 28.89
Effects of hedging activities (per
Bbl)............................. -- -- -- -- (4.18)
------ ------ ------ -------- --------
Average oil price................ $18.75 $11.50 $15.37 $ 14.17 $ 24.71

Total revenues from production
(per Mcfe)....................... $ 2.62 $ 2.05 $ 2.24 $ 2.17 $ 3.70
Effects of hedging activities (per
Mcfe)............................ -- -- (0.22) (0.17) (0.84)
------ ------ ------ -------- --------
Total average price (per Mcfe)... $ 2.62 $ 2.05 $ 2.02 $ 2.00 $ 2.86

Expenses (per Mcfe):
Lease operating................... $ 0.54 $ 0.32 $ 0.32 $ 0.24 $ 0.44
General and administrative........ 0.42 0.26 0.20 0.21 0.21
Depreciation, depletion and
amortization--
natural gas and oil properties... 1.50 1.76 1.30 1.36 1.62
</TABLE>

9
<PAGE>

Summary Reserve Information

The table below presents our summary reserve information for our natural gas
and oil properties. Estimates of net proved natural gas and oil reserves are
based on the reserve reports prepared by our independent petroleum engineering
consultants, Ryder Scott Company, L.P. for the years 1997, 1998 and 1999 and as
of November 30, 2000 and Schlumberger Holditch-Reservoir Technologies
Consulting Services for the years 1998 and 1999 and as of November 30, 2000.
For additional information, please read "Business and Properties--Natural Gas
and Oil Reserves," "--Volumes, Prices and Operating Expenses," "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Liquidity and Capital Resources--Development Program Credit Agreement" and note
11 of the notes to our consolidated financial statements.

Our pre-tax PV-10 at November 30, 2000, which is the present value of future
net cash flows attributable to our proved reserves on a pre-tax basis using
prices and costs in effect at November 30, 2000, discounted at 10% per annum,
was determined by using prices of $5.95 per MMBtu of natural gas and $31.45 per
barrel of oil. The standardized measure of discounted future net cash flows
represents the present value of estimated future net revenues after income
taxes discounted at 10%. Please read note 11 of the notes to our consolidated
financial statements.
<TABLE>
<CAPTION>
As of December 31, As of
-------------------------- November 30,
1997 1998 1999 2000
------- ------- -------- ------------
<S> <C> <C> <C> <C>
Reserve Data:
Estimated proved reserves:
Natural gas (MMcf)................. 40,526 46,424 93,997 102,726
Oil and condensate (MBbls)......... 942 586 1,689 4,129
Total (MMcfe)..................... 46,181 49,940 104,128 127,497
Proved developed reserves as a
percentage of proved reserves....... 76.1% 86.5% 68.7% 44.3%
Estimated future net revenues before
income taxes
(in thousands)...................... $91,893 $69,610 $183,045 $605,135
Pre-tax PV-10 (in thousands)......... $78,406 $61,308 $156,315 $492,286
Standardized measure of discounted
future net cash flows
(in thousands)...................... $64,698 $61,308 $128,706 $353,256
</TABLE>

10
<PAGE>

RISK FACTORS

Investing in our common stock will provide you with an equity ownership in
ATP. As one of our shareholders, you will be subject to risks inherent in our
business. The trading price of your shares will be affected by the performance
of our business relative to, among other things, competition, market conditions
and general economic and industry conditions. The value of your investment may
decrease, resulting in a loss. You should carefully consider the following
factors as well as other information contained in this prospectus before
deciding to invest in shares of our common stock.

Attractive opportunities to acquire properties with proved undeveloped reserves
may not be available, which would prevent us from continuing our business
strategy and reduce our cash flow and revenues.

We may not be able to identify or complete the acquisition of properties
with sufficient proved undeveloped reserves to implement our business strategy.
Our strategy is based on the acquisition and development of properties with
undeveloped discoveries. As we deplete our existing reserves we must identify,
acquire and develop properties through new acquisitions or our level of
production and cash flows will be adversely affected. The availability of
properties for acquisition depends largely on the divesting practices of other
natural gas and oil companies, commodity prices, general economic conditions
and other factors that we cannot control or influence. A substantial decrease
in the availability of proved oil and gas properties in our areas of operation,
or a substantial increase in their cost to acquire, would adversely affect our
ability to replace our reserves as they are depleted.

Our actual drilling results are likely to differ from our estimates of proved
reserves. We may experience production that is less than estimated in our
reserve reports and drilling costs that are greater than estimated in our
reserve reports. Such differences may be material.

Estimates of our natural gas and oil reserves and the costs associated with
developing these reserves may not be accurate. Development of our reserves may
not occur as scheduled and the actual results may not be as estimated. Drilling
activity may result in downward adjustments in reserves or higher than
estimated costs. For example, during the three year period ended December 31,
1999, we estimate that our proved undeveloped reserves after the completion of
our development activities were between 80 and 85% of our initial estimates of
such reserves, after taking into account production.

Amounts estimated for drilling costs on proved undeveloped properties in our
reserve reports have been less than those actually incurred. At December 31,
1997, our reserve report estimated development costs of $8.6 million for 1998
compared with actual spending of $11.8 million in that year on the proved
undeveloped properties reflected in the reserve report. At December 31, 1998,
our reserve report estimated development costs of $11.1 million for 1999
compared with actual spending for the year on such properties of $11.7 million.
At December 31, 1999, our reserve report estimate for development costs for the
entire year of 2000 was $29.0 million. Through September 30, 2000, we had spent
$37.8 million on developing such properties.

Our estimates of our proved natural gas and oil reserves and the estimated
future net revenues from such reserves are based upon various assumptions,
including assumptions required by the Securities and Exchange Commission
relating to natural gas and oil prices, drilling and operating expenses,
capital expenditures, taxes and availability of funds. This process requires
significant decisions and assumptions in the evaluation of available
geological, geophysical, engineering and economic data for each reservoir.
Therefore, these estimates are inherently imprecise and the quality and
reliability of this data can vary.

Any significant variance could materially affect the estimated quantities
and PV-10 of reserves set forth in this prospectus. Our properties may also be
susceptible to hydrocarbon drainage from production by other operators on
adjacent properties. In addition, we may adjust estimates of proved reserves to
reflect production history, results of development, prevailing oil and natural
gas prices and other factors, many of which are beyond our control. Actual
production, revenues, taxes, development expenditures and operating expenses
with respect to our reserves will likely vary from the estimates used. These
variances may be material.

11
<PAGE>

If we are not able to generate sufficient funds from our operations and other
financing sources, we will not be able to finance our development activity or
planned acquisitions.

We have experienced and expect to continue to experience substantial capital
expenditure and working capital needs to finance our acquisition and
development program. Our capital expenditures on natural gas and oil properties
were $39.4 million during 1997, $35.9 million during 1998, $56.1 million during
1999 and $50.6 million through the first nine months of 2000. Low commodity
prices, production problems, disappointing drilling results and other factors
beyond our control could reduce our funds from operations. We will also require
future financing transactions to support our planned strategy. Additional
financing may not be available to us in the future on acceptable terms or at
all. In the event additional capital resources are unavailable, we may curtail
our acquisition, drilling, development and other activities or be forced to
sell some of our assets on an untimely or unfavorable basis. For more
information on our capital spending and financing activities, see "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Liquidity and Capital Resources."

Natural gas and oil prices are volatile, and low prices have had in the past
and could have in the future a material adverse impact on our business.

Our revenues, profitability and future growth and the carrying value of our
properties depend substantially on the prices we realize for our natural gas
and oil production. Because approximately 81% of our estimated proved reserves
as of November 30, 2000 were natural gas reserves, our financial results are
more sensitive to movements in natural gas prices. Our realized prices also
affect the amount of cash flow available for capital expenditures and our
ability to borrow and raise additional capital.

Natural gas and oil are commodities and, therefore, their prices are subject
to wide fluctuations in response to relatively minor changes in supply and
demand. Historically, the markets for natural gas and oil have been volatile,
and they are likely to continue to be volatile in the future. For example,
natural gas and oil prices declined significantly in late 1997 and 1998 and,
for an extended period of time, remained substantially below prices obtained in
previous years. Among the factors that can cause this volatility are:

. worldwide or regional demand for energy, which is affected by economic
conditions;

. the domestic and foreign supply of natural gas and oil;

. weather conditions;

. domestic and foreign governmental regulations;

. political conditions in natural gas or oil producing regions;

. the ability of members of the Organization of Petroleum Exporting
Countries to agree upon and maintain oil prices and production levels;
and

. the price and availability of alternative fuels.

It is impossible to predict natural gas and oil price movements with
certainty. Lower natural gas and oil prices may not only decrease our revenues
on a per unit basis but also may reduce the amount of natural gas and oil that
we can produce economically. A substantial or extended decline in natural gas
and oil prices may materially and adversely affect our future business,
financial condition, results of operations, liquidity and ability to finance
planned capital expenditures. Further, oil prices and natural gas prices do not
necessarily move together.

Our hedging decisions may reduce our potential gains from increases in
commodity prices and may result in losses.

We have in the past and may in the future enter into hedging arrangements
with respect to a portion of our expected production. Hedging arrangements
expose us to risk of financial loss if:

. production is less than expected;

12
<PAGE>

. the other party to the hedging contract defaults on its contract
obligations; or

. there is a change in the expected differential between the underlying
price in the hedging agreement and actual prices received.

At December 31, 2000, we had hedged 14.5 Bcf of our expected 2001 natural
gas production. We have no hedges for oil production in 2001. These hedging
arrangements have limited and may continue to limit the benefit we would
receive from increases in the prices for natural gas and oil. Please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Overview" for volume and price information on our hedging
activities.

Because we have incurred losses from operations in recent years, our future
operating results are difficult to forecast. Our failure to achieve or sustain
profitability in the future could adversely affect the market price of our
common stock.

We have incurred operating losses in recent years. Our failure to achieve or
sustain profitability in the future could adversely affect the market price of
our common stock. In considering whether to invest in our common stock, you
should consider the historical financial and operating information available on
which to base your evaluation of our performance. We incurred operating losses
of $5.0 million in 1997, $7.9 million in 1998 and $3.6 million in 1999. We may
not be able to achieve or sustain profitability or positive cash flows from
operating activities in the future.

Relatively short production periods for Gulf of Mexico properties subject us to
high reserve replacement needs and require significant capital expenditures to
replace our reserves at a faster rate than companies whose reserves have longer
production periods.

Production of reserves from reservoirs in the Gulf of Mexico generally
declines more rapidly than from reservoirs in many other producing regions of
the world. This results in recovery of a relatively higher percentage of
reserves from properties in the Gulf of Mexico during the initial years of
production, and as a result, our reserve replacement needs from newly acquired
properties are greater. As our reserves decline from production, we are
required to incur significant capital expenditures to replace declining
production. Also, our revenues and return on capital will depend significantly
on prices prevailing during these relatively short production periods.

We may incur substantial impairment writedowns.

If management's estimates of natural gas and oil prices decline or if the
recoverable reserves on a property are revised downward, we may be required to
record additional impairment writedowns in the future, which would result in a
negative impact to our financial position. We review our proved oil and gas
properties for impairment on a depletable unit basis when circumstances suggest
there is a need for such a review. For each property determined to be impaired,
we recognize an impairment loss equal to the difference between the estimated
fair value and the carrying value of the property on a depletable unit basis.
Fair value 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 the estimated future production of oil and gas reserves over
the economic life of a property. Future cash flows are based upon our
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. We recorded an
impairment in 1997 of approximately $5.8 million, in 1998 of approximately $5.1
million, in 1999 of approximately $7.5 million and in the first nine months of
2000 of approximately $7.0 million.

The natural gas and oil business involves many uncertainties and operating
risks that can prevent us from realizing profits and can cause substantial
losses.

Our development activities may be unsuccessful for many reasons, including
weather, cost overruns, equipment shortages and mechanical difficulties.
Moreover, the successful drilling of a natural gas or oil well

13
<PAGE>

does not ensure a profit on investment. A variety of factors, both geological
and market-related, can cause a well to become uneconomical or only marginally
economic. In addition to their cost, unsuccessful wells can hurt our efforts to
replace reserves.

The natural gas and oil business involves a variety of operating risks,
including:

. fires;

. explosions;

. blow-outs and surface cratering;

. uncontrollable flows of natural gas, oil and formation water;

. natural disasters, such as hurricanes and other adverse weather
conditions;

. pipe, cement, subsea well or pipeline failures;

. casing collapses;

. embedded oil field drilling and service tools;

. abnormally pressured formations; and

. environmental hazards, such as natural gas leaks, oil spills, pipeline
ruptures and discharges of toxic gases.

If we experience any of these problems, it could affect well bores,
platforms, gathering systems and processing facilities, which could adversely
affect our ability to conduct operations. We could also incur substantial
losses as a result of:

. injury or loss of life;

. severe damage to and destruction of property, natural resources and
equipment;

. pollution and other environmental damage;

. clean-up responsibilities;

. regulatory investigation and penalties;

. suspension of our operations; and

. repairs to resume operations.

Offshore operations are also subject to a variety of operating risks
peculiar to the marine environment, such as capsizing, collisions and damage or
loss from hurricanes or other adverse weather conditions. These conditions can
cause substantial damage to facilities and interrupt production. As a result,
we could incur substantial liabilities that could reduce or eliminate the funds
available for development or leasehold acquisitions, or result in loss of
equipment and properties.

Our insurance coverage may not be sufficient to cover some liabilities or
losses which we may incur.

The occurrence of a significant accident or other event not fully covered by
our insurance could have a material adverse effect on our operations and
financial condition. Our insurance does not protect us against all operational
risks. We do not carry business interruption insurance at levels that would
provide enough funds for us to continue operating without access to other
funds. For some risks, we may not obtain insurance if we believe the cost of
available insurance is excessive relative to the risks presented. Because third
party drilling contractors are used to drill our wells, we may not realize the
full benefit of workmen's compensation laws in dealing with their employees. In
addition, pollution and environmental risks generally are not fully insurable.

14
<PAGE>

We may be unable to identify liabilities associated with the properties that we
acquire or obtain protection from sellers against them.

The acquisition of properties with proved undeveloped reserves requires us
to assess a number of factors, including recoverable reserves, development and
operating costs and potential environmental and other liabilities. Such
assessments are inexact and inherently uncertain. In connection with the
assessments, we perform a review of the subject properties, but such a review
will not reveal all existing or potential problems. In the course of our due
diligence, we may not inspect every well, platform or pipeline. We cannot
necessarily observe structural and environmental problems, such as pipeline
corrosion, when an inspection is made. We may not be able to obtain contractual
indemnities from the seller for liabilities that it created. We may be required
to assume the risk of the physical condition of the properties in addition to
the risk that the properties may not perform in accordance with our
expectations.

The unavailability or high cost of drilling rigs, equipment, supplies,
personnel and oilfield services could adversely affect our ability to execute
on a timely basis our development plans within our budget.

Shortages or an increase in cost of drilling rigs, equipment, supplies or
personnel could delay or adversely affect our operations, which could have a
material adverse effect on our business, financial condition and results of
operations. Recently, drilling activity in the Gulf of Mexico has increased,
and we have experienced increases in associated costs, including those related
to drilling rigs, equipment, supplies and personnel and the services and
products of other vendors to the industry. Increased drilling activity in the
Gulf of Mexico also decreases the availability of offshore rigs. These costs
may increase further and necessary equipment and services may not be available
to us at economical prices.

Competition in our industry is intense, and we are smaller and have a more
limited operating history than some of our competitors in the Gulf of Mexico
and in the Southern Gas Basis of the U.K. North Sea.

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 than us. 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 additional properties and develop new and existing properties in the
future will depend on 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 and 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
industry cycles.

Our success depends on our management team and other key personnel, the loss of
any of whom could disrupt our business operations.

Our success in the Gulf of Mexico area as well as the Southern Gas Basin of
the U.K. North Sea will depend on our ability to retain and attract experienced
geoscientists and other professional staff. As of December 31, 2000, we had 12
engineers, geologist/geophysicists and other technical personnel in our Houston
office. We have hired four engineers, geologist/geophysicists and other
technical personnel for our London location to focus on our U.K. activities. We
depend to a large extent on the efforts, technical expertise and continued
employment of these personnel and members of our management team. If a
significant number

15
<PAGE>

of them resigns or becomes unable to continue in their present role and if they
are not adequately replaced, our business operations could be adversely
affected. Please read "Management" for information regarding the members of our
management team.

Rapid growth may place significant demands on our resources.

We have experienced rapid growth in our operations and expect that
significant expansion of our operations will continue. From 1995 to 1999, we
increased our net proved reserves at a compound annual growth rate of 263%,
production at a compound annual growth rate of 207% and oil and gas revenues at
a compound annual growth rate of 183%. Our rapid growth has placed, and our
anticipated future growth will continue to place, a significant demand on our
managerial, operational and financial resources due to:

. the need to manage relationships with various strategic partners and
other third parties;

. difficulties in hiring and retaining skilled personnel necessary to
support our business;

. the need to train and manage a growing employee base; and

. pressures for the continued development of our financial and information
management systems.

If we have not made adequate allowances for the costs and risks associated
with this expansion or if our systems, procedures or controls are not adequate
to support our operations, our business could be harmed.

We are subject to complex laws and regulations, including environmental
regulations, that can adversely affect the cost, manner or feasibility of doing
business.

Development, production and sale of natural gas and oil in the U.S.,
especially in the Gulf of Mexico, and in the U.K., are subject to extensive
laws and regulations, including environmental laws and regulations. We may be
required to make large expenditures to comply with environmental and other
governmental regulations. Matters subject to regulation include:

. discharge permits for drilling operations;

. bonds for ownership, development and production of oil and gas properties;

. reports concerning operations; and

. taxation.

Under these laws and regulations, we could be liable for personal injuries,
property damage, oil spills, discharge of hazardous materials, remediation and
clean-up costs and other environmental damages. Failure to comply with these
laws and regulations also may result in the suspension or termination of our
operations and subject us to administrative, civil and criminal penalties.
Moreover, these laws and regulations could change in ways that substantially
increase our costs. Accordingly, any of these liabilities, penalties,
suspensions, terminations or regulatory changes could materially adversely
affect our financial condition and results of operations. In addition, we have
not yet received approval from the Department of Trade and Industry to operate
in the U.K. Failure to obtain this approval may adversely impact our growth
strategy.

Members of our management team own a significant amount of common stock, giving
them influence or control in corporate transactions and other matters, and the
interests of these individuals could differ from those of other shareholders.

On completion of this offering, members of our management team will
beneficially own approximately 65.6% of our outstanding shares of common stock.
As a result, these shareholders will continue to be in a position to
significantly influence or control the outcome of matters requiring a
shareholder vote, including the election of directors, the adoption of an
amendment to our articles of incorporation or bylaws and the approval of
mergers and other significant corporate transactions. Their control of ATP may
delay or prevent a change of control of ATP and may adversely affect the voting
and other rights of other shareholders.

16
<PAGE>

Future sales of our common stock may result in a decrease in the market price
of our common stock, even if our business is doing well.

The market price of our common stock could drop due to sales of a large
number of shares of our common stock in the market after the offering or the
perception that such sales could occur. This could make it more difficult to
raise funds through future offerings of common stock. Please read "Shares
Eligible for Future Sale."

On completion of this offering, we will have outstanding 21,785,714 shares
of our common stock. This includes the 7,500,000 shares we are selling in this
offering, all of which may be resold in the public market immediately. All of
the remaining 14,285,714 shares are owned by our executive officers and
directors. An additional 98,810 shares may be acquired by our directors,
executive officers and other key employees within 60 days after the closing of
this offering through the exercise of stock options. These persons have agreed
not to sell any shares of common stock for a period of 180 days from the date
of this prospectus without the consent of Lehman Brothers Inc. After expiration
of the lockup period, these 14,384,524 shares of common stock will be eligible
for resale, subject to the volume and other limitations of Rule 144 under the
Securities Act. In addition, 116,131 shares may be acquired by other employees
beginning 60 days after closing of the offering through the exercise of stock
options. These shares are not subject to a lockup agreement and may be sold
under Rule 701 under the Securities Act beginning 90 days after the date of
this prospectus.

Our articles of incorporation and bylaws and the Texas Business Corporation Act
contain provisions that could discourage an acquisition or change of control of
ATP.

Our articles of incorporation authorize our board of directors to issue
preferred stock without shareholder approval. If our board of directors elects
to issue preferred stock, it could be more difficult for a third party to
acquire control of us. In addition, provisions of the articles of incorporation
and bylaws, such as no cumulative voting rights, limitations on shareholder
proposals at meetings of shareholders and restrictions on the ability of our
shareholders to call special meetings, could also make it more difficult for a
third party to acquire control of us. Our bylaws provide that our board of
directors is divided into three classes, each elected for staggered three-year
terms. Thus, control of the board of directors cannot be changed in one year;
rather, at least two annual meetings must be held before a majority of the
members of the board of directors could be changed. In addition, upon
completion of the offering, the Texas Business Corporation Act will impose
restrictions on mergers and other business combinations between us and any
holder of 20% or more of our outstanding common stock.

These provisions of Texas law and our articles of incorporation and bylaws
may delay, defer or prevent a tender offer or takeover attempt that a
shareholder might consider in his or her best interest, including attempts that
might result in a premium over the market price for the common stock. Please
read "Description of Capital Stock" for additional details concerning the
provisions of Texas law and our articles of incorporation and bylaws.

17
<PAGE>

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING INFORMATION

All statements in this prospectus that are not statements of historical fact
are forward looking statements. These statements express or are based upon our
expectations about future events. We caution you that assumptions,
expectations, projections, intentions and beliefs about future events may and
often do vary from actual results and the differences can be material.

Forward looking statements in this prospectus include, but are not limited
to, such matters as:

. our future operating or financial results;

. budgeted capital expenditures;

. pending acquisitions, including the anticipated closing dates;

. our business strategy, including expansion into the shallow-deep waters
of the Gulf of Mexico and into the Southern Gas Basin of the U.K. North
Sea, and the availability of acquisition opportunities;

. drilling of wells and other planned development activities;

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

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

When used in this document, the words "anticipate," "estimate," "project,"
"may," "should," and "expect" reflect forward-looking statements. There are
many factors that could cause these forward-looking statements to be incorrect,
including the risks described under "Risk Factors" and "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and elsewhere in
this prospectus. When you consider the forward-looking statements, you should
keep in mind these factors and the other cautionary statements in this
prospectus.

18
<PAGE>

USE OF PROCEEDS

We estimate that we will receive net proceeds of $114.7 million from the
sale of the 7,500,000 shares of common stock offered by this prospectus, after
deducting underwriting discounts and estimated offering expenses. This estimate
assumes an initial public offering price of $16.50 per share, which is the mid-
point of the offering price range on the cover of this prospectus.

We intend to use the net proceeds as follows:

. approximately $84.0 million to repay all of our outstanding debt under
our development program credit agreement; and

. approximately $27.8 million to repay all of our outstanding debt under
our credit facility.

The remaining proceeds will be used in our acquisition and development
program and for other general corporate purposes. Until we use the proceeds
from this offering, we will deposit them in short-term interest bearing
accounts.

The selling shareholders will sell shares of common stock to the
underwriters if the underwriters exercise their over-allotment option. We will
not receive any proceeds from the sale of common stock by the selling
shareholders. See "Principal and Selling Shareholders."

Our development program credit agreement matures in November 2002. At
September 30, 2000, the interest rate on borrowings outstanding under the
development program credit agreement was 13.0% per annum. These borrowings have
been used for acquisition and development of natural gas and oil properties.

Our credit facility matures in January 2002. At September 30, 2000, the
average interest rate on borrowings outstanding under the credit facility was
10.0% per annum. These borrowings have been used primarily for acquisition and
development of our natural gas and oil properties, working capital and general
corporate purposes.

Please read "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Liquidity and Capital Resources" for additional
information about our credit facility and our development program credit
agreement.

DIVIDEND POLICY

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.

19
<PAGE>

DILUTION

Our net tangible book value at September 30, 2000 was approximately $(12.5)
million, or $(0.88) per share of common stock. Net tangible book value per
share is determined by dividing our tangible net worth, or tangible assets less
total liabilities, by the total number of outstanding shares of common stock.
After giving effect to the reverse split of our common stock, the sale of
common stock offered by this prospectus and the receipt of the estimated net
proceeds, after deducting underwriting discounts and estimated offering
expenses, our net tangible book value at September 30, 2000 would have been
$4.69 per share of common stock. This represents an immediate and substantial
increase in the net tangible book value of $5.57 per share to existing
shareholders and an immediate dilution of $11.81 per share, resulting from the
difference between the public offering price and the net tangible book value
after this offering, to new investors purchasing common stock in this offering.
The following table illustrates the per share dilution to new investors
purchasing common stock in this offering at an assumed offering price equal to
mid-point of the offering price range on the cover of this prospectus:

<TABLE>
<S> <C> <C>
Assumed initial public offering price per share................... $16.50
Net tangible book value per share at September 30, 2000......... (0.88)
Increase per share attributable to new investors................ 3.82
-----
Net tangible book value per share after this offering............. 4.69
------
Dilution per share to new investors............................... $11.81
======
</TABLE>

The following table sets forth, at September 30, 2000, the number of shares
of common stock purchased from us and the total consideration and average price
per share paid by existing shareholders and by the new investors before
deducting expenses payable by us, assuming an offering price of $16.50 per
share:

<TABLE>
<CAPTION>
Total Average
Shares Purchased Consideration Price
---------------- ---------------- Per
Number % Amount % Share
---------- ----- ---------- ----- -------
(in
thousands)
<S> <C> <C> <C> <C> <C>
Existing shareholders................. 14,285,714 65.6 $ 52 0.1 $ 0.01
New investors......................... 7,500,000 34.4 123,750 99.9 16.50
---------- ----- -------- ----- ------
Total............................... 21,785,714 100.0 $123,802 100.0 $ 5.68
========== ===== ======== ===== ======
</TABLE>

These computations assume that no additional shares are issued upon exercise
of the outstanding stock options. Options to purchase 301,786 shares of our
common stock at $1.40 per share and 343,036 shares of our common stock at $3.85
per share are currently outstanding under our stock option plan. In the event
the 644,822 shares subject to the options currently outstanding under our stock
option plan were included in the calculations above, the net tangible book
value per share before this offering would be $(0.72), the net tangible book
value per share after this offering would be $4.63 and the dilution per share
to new investors would be $11.87. In addition, the average price per share paid
by existing shareholders would increase to $0.12 per share.

20
<PAGE>

CAPITALIZATION

The following table presents our cash, capitalization and other information
as of September 30, 2000 on two bases:

. on an actual basis; and

. on an as adjusted basis to reflect changes to our authorized
capitalization, including a 1.4-to-1 reverse split of our common stock,
effected in December 2000, our sale of the shares of common stock in
this offering at an assumed offering price of $16.50 per share and the
anticipated use of the net proceeds.

You should read the table in conjunction with "Use of Proceeds,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and our consolidated financial statements and the related notes
included in this prospectus.

<TABLE>
<CAPTION>
As of
September 30,
2000
------------------
As
Actual Adjusted
-------- --------
(in thousands)
<S> <C> <C>
Cash...................................................... $ 19,066 $ 22,022
======== ========
Long-term debt and non-recourse borrowings ............... $112,590 $ 840
Shareholders' equity:
Preferred stock, $0.001 par value, no shares authorized,
actual, and 10,000,000 shares authorized, as adjusted; no
shares issued or outstanding actual and as adjusted...... -- --
Common stock, $0.001 par value, 50,000,000 shares
authorized, actual, and 100,000,000 shares authorized, as
adjusted; 14,285,714 shares issued and outstanding,
actual, and 21,785,714 shares issued and outstanding, as
adjusted................................................. 14 22
Additional paid-in capital................................ 38 114,736
Accumulated deficit....................................... (7,178) (7,178)
-------- --------
Total shareholders' equity (deficit).................... (7,126) 107,580
-------- --------
Total capitalization.................................. $105,464 $108,420
======== ========
</TABLE>

21
<PAGE>

SELECTED HISTORICAL AND UNAUDITED PRO FORMA
FINANCIAL INFORMATION

The following table sets forth some of our historical and unaudited pro
forma financial information. You should read the following data with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," our consolidated financial statements and the related notes and
our pro forma financial statements and the related notes included elsewhere in
this prospectus.

We derived the statement of operations data for the three-year period ended
December 31, 1999 and the balance sheet data as of December 31, 1997, 1998 and
1999 from our consolidated financial statements, which have been audited by
KPMG LLP, independent certified public accountants, and are included in this
prospectus. We derived the statement of operations data for the two-year period
ended December 31, 1996 and the balance sheet data as of December 31, 1995 and
1996 from our unaudited financial statements, which are not included in this
prospectus.

We derived the statement of operations data for the nine-month periods ended
September 30, 1999 and 2000 from our unaudited consolidated financial
statements, which are included in this prospectus. In the opinion of our
management, the unaudited financial information includes all adjustments,
consisting of only normal recurring adjustments, considered necessary for a
fair presentation of that information. Our results of operations for the nine-
month period ended September 30, 2000 are not necessarily indicative of the
results that we may achieve for the entire year.

The unaudited pro forma financial information for the periods reflected
below has been derived from the unaudited pro forma financial statements
included elsewhere in the prospectus. Pro forma information is based on
assumptions and include adjustments as explained in the notes to the unaudited
pro forma financial information included in this prospectus. The unaudited pro
forma financial information is not necessarily indicative of the results that
actually would have been achieved for these periods or that may be achieved in
the future. The unaudited pro forma financial information gives effect to our
purchase of Eugene Island 30 as if the transaction occurred on January 1, 1999.
We completed the acquisition of a 100% working interest and an 82% net revenue
interest in the property in September 1999 for a purchase price of $16.3
million in cash. The total purchase price was recorded to oil and gas
properties and was accounted for using the purchase method.

22
<PAGE>

<TABLE>
<CAPTION>
Nine Months Ended
Years Ended December 31, September 30,
-------------------------------------------------------------------- -----------------------
Pro Forma
1995 1996 1997 1998 1999 1999(1) 1999 2000
--------- --------- ---------- ---------- ---------- ---------- ---------- -----------
(unaudited) (unaudited) (unaudited) (unaudited)
(in thousands, except share and per share data and percentages)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Revenues:
Oil and gas
production............ $ 543 $ 3,009 $ 7,359 $ 20,410 $ 34,981 $ 37,252 $ 27,182 $ 54,290
Gas sold--marketing.... -- -- -- -- 7,703 7,703 5,602 5,024
Gain on sale of oil
and gas properties.... -- -- 304 -- 287 287 287 33
--------- --------- ---------- ---------- ---------- ---------- ---------- ----------
Total revenues....... 543 3,009 7,663 20,410 42,971 45,242 33,071 59,347
Costs and operating
expenses:
Lease operating........ 264 308 1,513 3,193 5,587 6,289 3,321 8,363
Gas purchased--
marketing............. -- -- -- -- 7,402 7,402 5,431 4,856
General and
administrative........ 233 505 1,170 2,591 3,541 3,541 2,902 4,018
Depreciation,
depletion and
amortization.......... 5 1,672 4,206 17,442 22,521 23,253 18,452 30,686
Impairment of oil and
gas properties........ -- -- 5,787 5,072 7,509 7,509 6,382 7,038
Other.................. -- -- -- -- -- -- -- 2,947
--------- --------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating
expenses.............. 502 2,485 12,676 28,298 46,560 47,994 36,488 57,908
--------- --------- ---------- ---------- ---------- ---------- ---------- ----------
Net income (loss) from
operations............. 41 524 (5,013) (7,888) (3,589) (2,752) (3,417) 1,439
Other income (expense):
Interest income........ 8 45 207 141 202 202 102 334
Interest expense....... -- (107) (1,212) (7,963) (9,399) (10,621) (7,471) (8,445)
--------- --------- ---------- ---------- ---------- ---------- ---------- ----------
Income (loss) before
income taxes and
extraordinary item..... 49 462 (6,018) (15,710) (12,786) (13,171) (10,786) (6,672)
Income tax benefit
(expense).............. (105) (1) -- -- 1,829 1,964 1,131 2,327
--------- --------- ---------- ---------- ---------- ---------- ---------- ----------
Income (loss) before
extraordinary item..... (56) 461 (6,018) (15,710) (10,957) $ (11,207) (9,655) (4,345)
==========
Gain on extinguishment
of debt, net of tax.... -- -- -- -- 29,185 29,185 --
--------- --------- ---------- ---------- ---------- ---------- ----------
Net income (loss)....... $ (56) $ 461 $ (6,018) $ (15,710) $ 18,228 $ 19,530 $ (4,345)
========= ========= ========== ========== ========== ========== ==========
Weighted average number
of common shares
outstanding:
Basic.................. 7,545,498 8,245,513 10,567,762 11,925,785 14,285,714 14,285,714 14,285,714 14,285,714
Diluted................ 7,545,498 8,245,513 10,567,762 11,925,785 14,285,714 14,285,714 14,285,714 14,285,714
Income (loss) per common
share before
extraordinary item:
Basic.................. $ (0.01) $ 0.06 $ (0.57) $ (1.32) $ (0.77) $ (0.78) $ (0.68) $ (0.30)
Diluted................ $ (0.01) $ 0.06 $ (0.57) $ (1.32) $ (0.77) $ (0.78) $ (0.68) $ (0.30)
Net income (loss) per
common share:
Basic.................. $ (0.01) $ 0.06 $ (0.57) $ (1.32) 1.28 $ 1.37 $ (0.30)
Diluted................ $ (0.01) $ 0.06 $ (0.57) $ (1.32) $ 1.28 $ 1.37 $ (0.30)
Other Financial Data:
Adjusted EBITDA(2)...... $ 54 $ 2,241 $ 5,187 $ 14,767 $ 26,643 $ 28,212 $ 21,519 $ 39,497
Adjusted EBITDA margin
(3).................... 10% 74% 68% 72% 62% 62% 65% 67%
</TABLE>

<TABLE>
<CAPTION>
As of December 31, As of
--------------------------------------------------------- September 30,
1995 1996 1997 1998 1999 2000
---------- ---------- ---------- ---------- ---------- -------------
(unaudited) (unaudited)
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Balance Sheet Data:
Cash and cash
equivalents............ $ 120 $ 1,088 $ 1,806 $ 3,411 $ 17,779 $ 19,066
Working capital......... (71) 2,574 3,340 (5,106) 14,115 10,327
Net oil and gas
properties............. 360 5,201 33,355 47,612 72,278 85,437
Total assets............ 592 9,074 48,906 61,354 107,054 136,909
Total long-term debt.... -- -- 42,194 62,690 91,723 108,090
Total liabilities....... 359 8,369 54,217 82,363 109,835 144,035
Shareholders' equity
(deficit).............. 234 705 (5,311) (21,009) (2,781) (7,126)

</TABLE>
--------
(1) The unaudited pro forma financial information gives effect to our purchase
of Eugene Island 30 as if the transaction occurred on January 1, 1999. We
completed the acquisition of a 100% working interest and an 82% net revenue
interest in the property in September 1999 for a purchase price of $16.3
million in cash. The total purchase price was recorded to oil and gas
properties and was accounted for using the purchase method.
(2) Net income (loss) before interest expense, income taxes, depreciation,
depletion and amortization, and impairment of natural gas and oil
properties. 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.
(3) Represents Adjusted EBITDA divided by total revenues.

23
<PAGE>

ADDITIONAL PRO FORMA DATA

The unaudited pro forma income (loss) data presented in the following table
adjusts our historical net income (loss) and our pro forma loss giving effect
to the following:

. the reduction of interest expense related to the above described debt
reduction of $8.8 million for 1999 and $7.3 million for the nine months
ended September 30, 2000; and

. the tax effect of the interest expense reduction calculated at the
statutory rate of 35%.

24
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 43 blocks from the beginning of 1997 through November
2000 and have increased production from 2,807 MMcfe in 1997 to 17,301 MMcfe in
1999. Our production in the first nine months of 2000 was 18,953 MMcfe. 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 1999 and the first nine months of 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.

We have financed our acquisitions and development activity through a
combination of project-based development financing, bank financing and cash
from operations. In project-based development financings, the lender is repaid
from a portion of the net revenues from particular properties. Such
transactions are typically secured only by those properties that are being
financed. At September 30, 2000, we had $80.3 million outstanding under our
project-based development facility and $32.3 million outstanding under our bank
credit facility. We expect to repay $111.8 million of indebtedness with
proceeds from this offering, including all of our outstanding indebtedness
under our project-based development program. Future capital requirements are
expected to be met through a combination of proceeds from this offering, cash
from operations or borrowings under existing or new debt facilities.

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 1999 and 2000 has
been significantly affected by the requirements of our development program
credit agreement lender. It is our policy not to enter into transactions for
speculative purposes. Accordingly, we base hedging activity on expected
production. If actual production is less than expected production we may be in
a position of having hedged a greater volume than actually produced.

The details of our current hedging positions are set forth under
"Quantitative and Qualitative Disclosures About Market Risk" below. We have
hedges in place for the fourth quarter of 2000 on 74,700 MMBtu/day at an
average price of $3.03 per MMBtu. Our average daily net production for November
2000 was approximately 60.7 MMBtu/day. Accordingly, we will be required to
account for a portion of our hedging position using the mark to market method
in the fourth quarter. We do not expect to hedge as great a percentage of
expected production after we repay amounts outstanding under our development
program credit agreement. We estimate the net effect of our hedges for the
fourth quarter will be to reduce operating income by approximately $14.4
million.

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 NYMEX monthly
settlement prices on January 3, 2001, our operating income for 2001 as a result
of hedging transactions would be negatively affected by $34.9 million in the
first quarter and a total of $18.6 million in the remaining three quarters.

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.

25
<PAGE>

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 1997, we
have recorded impairments on nine different properties. Impairment expense
totaled $5.8 million in 1997, $5.1 million in 1998, $7.5 million in 1999 and
$7.0 million in the first nine months of 2000.

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 343,036 shares of common stock at $3.85 per share. One-third of the
options vest 60 days after our initial public offering, and one-third of the
options vest on each of the first and second anniversaries of our initial
public offering. We expect to recognize compensation expense following our
initial public offering based on the difference between the exercise price for
these options and the fair market value of our stock as determined by our
initial public offering. The expense will be recognized in the periods in which
the options vest. Based upon the vesting schedule and the mid-point of the
initial public offering price range for our shares of $16.50, we estimate that
we will incur a non-cash compensation expense of approximately $3.9 million in
2001 and approximately $0.8 million in 2002 relating to such option grants.

We have two wholly owned subsidiaries, ATP Energy and ATP Oil & Gas (UK)
Limited. ATP Energy has entered into agreements to purchase and sell gas from
unrelated entities. ATP Oil & Gas (UK) Limited is responsible for our
activities in the Southern Gas Basin of the U.K. North Sea. Please read
"Subsidiary Activities" for a more complete discussion of these transactions.

Results of Operations

Nine Months Ended September 30, 2000 Compared to Nine Months Ended September
30, 1999

Oil and Gas Revenue. Our revenue from natural gas and oil production for the
nine months ended September 30, 2000 increased over the first nine months of
1999 by 99.7%, from $27.2 million to $54.3 million. This increase resulted from
increases of 38.3% in realized natural gas prices and 74.3% in realized oil
prices as well as a 39.6% increase in production. The increase in production
volumes from 13,575 MMcfe to 18,953 MMcfe was attributable to ten properties
that were on production during the first nine months of 2000 that were not on
production during the same period in 1999. Hedging transactions reduced oil and
natural gas revenues by $15.7 million, or $0.84 per Mcfe, in the first nine
months of 2000 and $2.2 million, or $0.17 per Mcfe, in the first nine months of
1999.

Marketing Revenue. During the nine months ended September 30, 2000, revenues
from natural gas marketing activities amounted to $5.0 million, a decrease of
$0.6 million from the same period in 1999. The reason for the decrease was a
reduction in the average daily natural gas contract amount from 9,000 MMBtu per
day in 1999 to 5,000 MMBtu per day in 2000. The decrease was offset in part by
an average increase in the sales price per MMBtu from $2.28 in 1999 to $3.67 in
2000. For more information regarding this marketing arrangement, please read
"Subsidiary Activities" below.

Lease Operating Expense. Our lease operating expense for the nine months
ended September 30, 2000 increased 151.8% from $3.3 million to $8.4 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 the first nine months of
1999, we held a working interest in 21 producing blocks (26 producing
wells/21.2 net wells). During the first nine months of 2000, we held a working
interest in 27 producing blocks (36 producing wells/31.6 net wells). For the
first nine months of 1999, our net production from these wells was 12,911 MMcf
and 110,581 bbls. For the first nine months of 2000, our net production from
these wells was 17,302 MMcf and 275,316 bbls, an increase of 4,391 MMcf and
164,735 bbls. Workover

26
<PAGE>

spending increased from $0.3 million in the first nine months of 1999 to $2.4
million in the first nine months of 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 $0.24 to $0.44.

Gas Purchased-Marketing. Our cost of purchased gas was $4.9 million the
first nine months of 2000 compared to $5.4 million for the first nine months in
1999. The daily gas contract amount in our third party marketing arrangement
decreased from 9,000 MMBtu/day in the first nine months of 1999 to 5,000
MMBtu/day in the first nine months of 2000. Lower volumes were offset by an
increase in the average gas cost from $2.21 per MMbtu in the 1999 period to
$3.54 per MMbtu in the 2000 period.

General and Administrative Expense. General and administrative expense
increased to $4.0 million for the first nine months of 2000 compared to $2.9
million for the first nine months of 1999. The primary reason for the increase
was the result of compensation and related expenses increasing from $1.4
million to $2.4 million period to period. Our total employees increased from 16
at September 30, 1999 to 34 at September 30, 2000. On an Mcfe basis, general
and administrative expense was $0.21 in both periods.

Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense increased 66.3% during the nine months ended September
30, 2000 from $18.5 million to $30.7 million. The average depreciation,
depletion and amortization rate was $1.62 per Mcfe during the first nine months
of 2000 compared with $1.36 per Mcfe in the first nine months of 1999.

Impairment Expense. For the first nine months of 2000, we recorded an
impairment of $7.0 million related to two of our 28 properties. During the
first nine months of 1999, we recorded an impairment of $6.4 million related to
four of our 26 properties. The impairment in 2000 was the result of a reduction
in recoverable reserves from the two properties. The impairment in 1999 was
primarily the result of depressed oil and gas prices and a reduction in
recoverable reserves for the four properties.

Other Expense. For the first nine months of 2000 we recorded an expense of
$2.9 million on a natural gas derivative position. It is our policy not to
acquire derivative products for the purpose of speculating on price changes.
However, if a hedging position exceeds our expected production in an upcoming
period, we are required to account for the position using the mark to market
method. The expense in the first nine months of 2000 reflects such a position
in excess of expected production.

Other Income (Expense). For the nine months ended September 30, 2000,
interest expense was $8.4 million compared to $7.5 million for the same period
in 1999. Our borrowings increased from period to period but were more than
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 the first nine months of 2000 we capitalized $0.7 million of
interest, and we capitalized $0.2 million of interest in the first nine months
of 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 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.

27
<PAGE>

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.

Year Ended December 31, 1998 Compared to Year Ended December 31, 1997

Oil and Gas Revenue. Our revenue from natural gas and oil production for
1998 increased over 1997 by 177.3%, from $7.4 million to $20.4 million
primarily as a result of substantially increased production. Natural gas
production increased by 232.7% from 1997 to 1998 while realized natural gas
prices fell by 20.4%. Oil production increased by 873.0% from year to year and
realized oil prices decreased by 38.7%. The increase in production volumes from
2,807 MMcfe to 9,933 MMcfe was attributable to new production resulting from

28
<PAGE>

development activities on four properties that began producing in the second
half of 1997 and new production resulting from development activities on five
properties that began production in 1998. We had no hedging transactions in
either 1998 or 1997.

Lease Operating Expense. Our lease operating expense for 1998 increased
111.0%, from $1.5 million to $3.2 million. The increase in these expenses was
primarily the result of an increase in our number of producing wells and total
production volume. During 1997, we held a working interest in nine producing
blocks (10 producing wells/7.8 net wells). During 1998, we held a working
interest in 22 producing blocks (27 producing wells/19.5 net wells). For 1997,
our net production was 2,713 MMcf and 15,535 bbls. For 1998, our net production
was 9,026 MMcf and 151,152 bbls, an increase of 6,313 MMcf and 135,617 bbls. On
a per Mcfe basis, lease operating expense decreased from $0.54 to $0.32,
primarily as a result of individual properties which produce at a higher rate
combined with mostly fixed lease operating cost.

General and Administrative Expense. General and administrative expense
increased from $1.2 million in 1997 to $2.6 million in 1998. The primary reason
for the increase was the result of compensation and related expenses increasing
from $0.6 million in 1997 to $1.2 million in 1998. Our total number of
employees increased from four at January 1, 1997 to 11 at December 31, 1997 and
to 15 at December 31, 1998. On a per Mcfe basis, general and administrative
expense decreased from $0.42 during 1997 to $0.26 during 1998.

Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense increased from $4.2 million in 1997 to $17.4 million
in 1998. The average depreciation, depletion and amortization rate was $1.50
per Mcfe during 1997 and $1.76 per Mcfe in 1998. This increase was attributable
to production in 1998 from properties that required a higher relative
development cost than the average cost of the producing properties in 1997.

Impairment Expense. As of 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. As of
December 31, 1997, the future undiscounted cash flows for our properties were
$91.9 million and the net book value for the properties was $39.9 million.
However, for four of the properties in 1998 and for three of the properties in
1997, the future undiscounted cash flows were less than their individual net
book value. As a result, we recorded impairments of $5.1 million in 1998 for
four of our 20 properties and $5.8 million in 1997 for three of our 13
properties. The impairments in 1998 and 1997 were primarily the result of
depressed oil and gas 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 1998, interest income was $0.1
million compared to $0.2 million for 1997. This decrease was primarily the
result of a decrease in cash required to be held in an escrow account. For
1998, interest expense was $8.0 million compared to $1.2 million for 1997. This
increase was primarily the result of an increase in non-recourse debt as well
as borrowings under our credit facility. During 1998, we capitalized $1.6
million of interest relating to the interest cost incurred while developing
properties. We capitalized $2.1 million during 1997.

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 September 30, 2000, we had $80.3 million outstanding under
our current development program credit agreement and $32.3 million outstanding
under our bank credit facility.

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

<TABLE>
<CAPTION>
Cash flow
from
Period operations
------ -------------
<S> <C>
1997.......................................................... $ 3.6 million
1998.......................................................... 13.2 million
1999.......................................................... 10.8 million
First Nine Months 2000........................................ 35.2 million
</TABLE>

29
<PAGE>

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
being 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 November 2000, we included 14 properties in this
financing and obtained total funding of $111.5 million. The lender receives 90%
of the monthly net revenues (after payment of operating costs) from the pledged
properties. From April 1999 through November 2000, we made payments to the
lender of $42.9 million, including interest, under the facility. The average
interest rate was 11.5% in 1999 and 12.6% during the first nine months of 2000.
At September 30, 2000, the amount outstanding was $80.3 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 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.

Since the amount of reserves attributable to these overriding royalty
interests depends upon the timing of our repayment of the amounts borrowed,
these overriding royalty interests are not reflected in the reserve information
included in this Prospectus. We intend to repay the full amount borrowed under
the development program credit agreement with the proceeds of this offering.
Based on our expected level of production for January 2001, our lender will
receive overriding royalty interests of 2.3 Bcf in the group of ten properties
described above and no interest in the other four properties when we make these
repayments.

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
September 1998, the initial borrowing base was $6.5 million. The amount
available for borrowing at September 30, 2000 had increased to $32.3 million,
all of which was outstanding. Our borrowings under the credit facility have
decreased to $27.8 million as of November 30, 2000.

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 September 2001. 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
8.1% at December 31, 1998, 8.9% at December 31, 1999, and 10.0% at September
30, 2000.

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;

30
<PAGE>

. 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 September 30, 2000, we were in compliance with all of the financial
covenants of our credit facility.

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
Period Gas Properties
------ --------------
(In millions)
<S> <C>
1997:
Acquisition costs (4 properties)............................ $ 1.1
Development costs (9 properties)............................ 38.3
-----
$39.4
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
First Nine Months 2000:
Acquisition costs (4 properties)(1)......................... $ 2.6
Development costs (15 properties)........................... 48.0
-----
$50.6
</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.

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 this year, 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 September 30, 2000, we had
incurred capital expenditures of $50.6 million. Based on our current inventory
of properties at November 30, 2000 we have identified capital expenditures of
$11.3 million for the remainder of 2000 and $75.1 million for 2001. In
addition, we have executed letters of intent to acquire three new properties
that are expected to close in the first quarter of 2001. These properties, if
acquired, will require acquisition costs of approximately $3.6 million in
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.

31
<PAGE>

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.

In connection with our initial public offering, we intend to repay all
indebtedness under our development program credit agreement and indebtedness
under our credit facility. We believe that cash from our offering, cash flow
from operations and cash from borrowings under our existing or new credit
facilities will be sufficient to fund our operations at least 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.

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.

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

<TABLE>
<CAPTION>
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)....................................... 9,400 2.87
</TABLE>
--------
(1) We have no gas hedges beyond October 2001.

32
<PAGE>

In addition to the above financial hedges on natural gas we have entered
into two other financial hedges 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 $3.01 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 $3.35 per MMBtu on 10,000 MMBtu per day.

Subsidiary Activities

In December 1998, our wholly-owned subsidiary, ATP Energy, entered into an
agreement 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 the gas on a monthly basis at a
premium to the Gas Daily Henry Hub Index. American Citigas 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 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. 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 remaining balance of the deferred obligation was
$0.2 million at December 31, 1999, and $0.1 million at September 30, 2000. The
premium we pay to American Citigas 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 American Citigas contract. At the end of our
agreement with El Paso 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 "Business and
Properties--Significant Acquisitions in Progress" for a description of our
pending acquisitions in the U.K.

33
<PAGE>

BUSINESS AND PROPERTIES

About ATP Oil & Gas Corporation

At November 30, 2000, we had estimated net proved reserves of 127.5 Bcfe,
81% of which was natural gas, with an estimated pre-tax PV-10 of $492.3
million. Prices used in these reserve estimates were $5.95 per MMbtu of natural
gas and $31.45 per barrel of oil. At November 30, 2000, proved developed
reserves comprised 44% of our total reserves and our reserve life index for
total proved reserves was 5.2 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 85%. Our estimated future dismantlement, restoration and
abandonment costs for these properties is approximately $17.0 million.

We have increased our reserves and production exclusively through the
acquisition and development of proved natural gas and oil properties. During
1999, we replaced 413% of 1999 production through these activities, and from
1997 to 1999 we achieved an average annual reserve replacement ratio of 318%.
We have replaced approximately 200% of our production during the first eleven
months of 2000. We produced approximately 19.0 Bcfe in the nine month period
ended September 30, 2000, an increase of 40% over the same period in the
previous year. Our net average daily production for November 2000 was 61.7
MMcfe, increasing to 67.7 MMcfe in December 2000. We believe substantial
additional acquisition opportunities still exist in the outer continental shelf
of the Gulf of Mexico. We also believe that our business model is well suited
for our expansion into the shallow-deep waters of the Gulf of Mexico and into
the Southern Gas Basin of the U.K. North Sea.

We were listed on the 2000 Inc. 500 as the fifth 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 the surveys. In 1999, we received the Best Field Improvement Award
by Hart's Oil and Gas World for the technique we implemented in an 11 mile
underwater pipeline and production system for the development of a project in
520 feet of water. 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 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

34
<PAGE>

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

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. 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. Companies pursuing exploration success may
discover hydrocarbons which may not provide an acceptable economic return for
them but which may prove attractive to us.

We implement our business strategy through the following two steps:

. Acquire Proved Undeveloped Reserves. We continually review opportunities
to acquire proved natural gas and oil reserves that are not strategic to
the companies from which we acquire them. Because we focus on
undeveloped properties, we are typically able to acquire our properties
by granting overriding royalty interests and for a minimal cash outlay.

. Efficiently Develop and Produce Reserves. 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 Control. We currently operate 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.

35
<PAGE>

Significant Properties

We have summarized our most significant properties in the tables below.

<TABLE>
<CAPTION>
As of 11/30/00
Net Proved Reserves
(1)
----------------------
November 2000
Average Daily
ATP Net Net
Significant ATP Revenue Production
Producing Properties Working Interest Interest Bcfe % Gas % Developed (MMcfe)
-------------------- ---------------- -------- ---- ----- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Gulf of Mexico-Shelf
Eugene Island 30........ 100% 80% 11.6 76 41 3.9
High Island A-354....... 100% 72-76% 11.1 99 100 10.4
Vermilion 410 Field..... 100% 77% 9.3 100 88 8.3
Brazos 544.............. 100% 62-68% 6.4 97 100 6.3
East Cameron 240........ 100% 83% 5.8 55 100 1.7
West Cameron 492........ 50% 36% 4.1 69 65 1.5
West Cameron 461........ 100% 80% 3.8 100 70 1.3
Vermilion 260........... 100% 79% 3.5 97 100 6.6
</TABLE>
<TABLE>
<CAPTION>
As of 11/30/00
Net Proved Undeveloped
Reserves (1)
------------------------
ATP
Significant ATP Net Revenue Projected
Development Properties Working Interest Interest Bcfe % Gas Production Date
---------------------- ---------------- ----------- ----------- ----------- -------------------
<S> <C> <C> <C> <C> <C>
Gulf of Mexico-Shelf
South Marsh Island
189/190................ 100% 83% 20.4 84 Third quarter 2001
West Cameron 635........ 100% 80% 6.8 94 First quarter 2001
Main Pass 282........... 100% 79% 3.4 92 First quarter 2001
Gulf of Mexico-Shallow-
Deep Waters
Garden Banks 409
(Ladybug).............. 50% 39% 15.1 22 Second quarter 2001
Garden Banks 186/187
(Cabrito) (2).......... 100% 95% 6.9 100 Fourth quarter 2001
Garden Banks 142
(Matia)................ 100% 80% 2.4 100 Fourth quarter 2001
<CAPTION>
As of 11/30/00
Net Proved Undeveloped
Reserves (1)(4)
------------------------
Significant ATP
Acquisitions in Progress ATP Net Revenue Projected
(3) Working Interest Interest Bcfe % Gas Acquisition Date
------------------------ ---------------- ----------- ----------- ----------- -------------------
<S> <C> <C> <C> <C> <C>
Southern Gas Basin-U.K.
North Sea
Block 49/12a (Venture)
(5).................... 50% 50% 14.7 100 First quarter 2001
Block 47/10b............ 100% 100% (6) (6) First quarter 2001
Blocks 43/22a, 43/22c
and 43/17c............. 86% 86% (6) (6) First quarter 2001
</TABLE>
--------
(1) Estimates of net proved reserves are based on our third party independent
reserve reports as of November 30, 2000.

(3) We have executed a letter of intent dated October 27, 2000 with BP
Exploration Operating Company Limited to acquire the properties listed in
this table. Although we expect to acquire these properties in the first
quarter of 2001, we may not complete these acquisitions by that time or at
all.
(4) Our estimated net proved reserves as of November 30, 2000, included in
this prospectus do not include any reserves from these properties.
(5) Conoco, which owns the remaining 50% working interest in this property,
has a preferential right to purchase the interest subject to our letter of
intent on substantially similar terms. Conoco's right must be waived prior
to a closing of our acquisition. Based on conversations with the seller of
this property and Conoco, we believe that Conoco will waive its
preferential right, although we can give you no assurance that it will do
so.
(6) We are currently evaluating the property to determine proved reserves.

36
<PAGE>

Producing Properties

Eugene Island 30

We acquired Eugene Island 30 in September 1999 from a unit of Enron Capital
Corporation for $16.3 million. One well drilled on this property had previously
produced and two wells (the C-1 and C-2 wells) were shut-in awaiting pipeline
connections and an upgrade to the production facilities. At the date acquired,
one well was producing 2.3 MMcf per day and 112 bbls of condensate and oil per
day, net to our interest. We are the operator of this property.

We performed development operations to the C-1 and the C-2 wells. The C-1
well was brought on production in March 2000, and the C-2 well was brought on
production in April 2000. The development operations included laying two
pipelines and upgrading production equipment. Our total development cost was
$5.0 million.

Eugene Island 30 is located in approximately 15 feet of water and had
estimated proved reserves of approximately 8.8 Bcf and 460.0 MBbls of oil as of
November 30, 2000, net to our interest. During November 2000, the property
produced 3.2 MMcf per day and 128 bbls of oil and condensate per day, net to
our interest, from the C-1 and C-2 wells. As of November 2000, average flowing
tubing pressures were 4,025 psia for the B-1 well, 1,000 psia for the C-1 well
and 2,600 psia for the C-2 well.

High Island A-354

We acquired a 100% working interest in High Island A-354 from Seneca
Resources Corporation in January 1999 for an overriding royalty interest. There
was no production from this property as of the date acquired. We are the
operator of this property.

Prior to our acquisition, Seneca drilled two wells in approximately 300 feet
of water which encountered hydrocarbons, but did not develop these proved
reserves. One of those wells, Seneca HI A-354 #1, was temporarily abandoned.
This well contains approximately 180 net feet of natural gas and condensate in
five sands between 7,200 feet and 7,700 feet total vertical depth. We developed
this property by completing the A-354 #1 well, drilling and completing another
well, installing a platform with production facilities and laying a pipeline.
Production of this property commenced in March 2000. Our total development cost
was $17.9 million.

High Island A-354 had estimated proved reserves of approximately 11.0 Bcf
and 12.0 MBbls of oil as of November 30, 2000, net to our interest. During
November 2000, this property produced 10.4 MMcf per day and 7 bbls of
condensate per day, net to our interest.

Vermilion 410 Field

In December 1998, we purchased a 50% working interest in the Vermilion 410
Field from Statoil Exploration (US) Inc. for $9.8 million. The average
production during December 1998 was approximately 12.4 MMcf per day, net to our
interest. We are the operator of this field.

This four-block producing field was a part of Statoil's 17 block Gulf of
Mexico shelf divestment package. This package also included two other producing
fields covering three blocks along with ten blocks with exploration potential.
During 1999, we sold several of the exploratory blocks to Houston Exploration
Company for an aggregate cash payment of $750,000. We retained the right to
receive future payments based on production from those blocks if a certain
level of production is achieved. We have been informed by Houston Exploration
Company that three successful exploratory wells have been drilled on three of
the exploratory blocks and may result in future development.

In February 1999, we purchased McMoRan Oil & Gas LLC's 37.5% working
interest in the Vermilion 410 Field for $5.8 million. This was the first of
three separate acquisitions from McMoRan. In April 2000, we purchased the
remaining 12.5% working interest in this field from EEX Corporation for $1.0
million.

37
<PAGE>

The Vermilion 410 Field had estimated proved reserves of approximately 9.3
Bcf of natural gas as of November 30, 2000, net to our interest. The four
offshore blocks that comprise this field are East Cameron Block 362, Vermilion
Block 389, Vermilion Block 409 and Vermilion Block 410. The production platform
is located in Vermilion Block 410 in approximately 365 feet of water. During
November 2000, the Vermilion 410 Field produced 8.3 MMcf per day, net to our
interest.

Brazos 544

In May and June 1997, we acquired Brazos 544 from Newfield Exploration
Company and Cockrell Oil & Gas L.P. for $0.7 million and an overriding royalty
interest. We are the operator of this property. This property had an existing
"A" platform with two shut-in wells (the A-1 and A-2) and another well (the B-
1) that was drilled and temporarily abandoned. The temporarily abandoned B-1
well had approximately 20 net feet of natural gas in the Big Hum A sand with an
original bottom-hole pressure of 8,256 psia. There was no production from any
of these three wells on the date we acquired this property. Brazos 544 was the
first of two properties that we acquired from Newfield.

We developed this property by completing the temporarily abandoned B-1 well,
installing the "B" platform and laying a flowline from the "B" platform to the
"A" platform. Production of the B-1 well commenced in July 1998. Our total
development cost was $9.0 million. Brazos 544 is located in approximately 95
feet of water.

Brazos 544 had estimated proved reserves of approximately 6.2 Bcf and 34.0
MBbls of condensate as of November 30, 2000, net to our interest. During
November 2000, the B-1 well produced 6.0 MMcf per day and 41 bbls of oil and
condensate per day, net to our interest, with an average flowing tubing
pressure of 3,200 psia.

East Cameron 240

In August 1999, we acquired East Cameron 240 from Enron Oil & Gas Company
for $1.5 million. We are the operator of this property. One well had previously
been drilled and was temporarily abandoned. The well had approximately 30 net
feet of natural gas and condensate in the L-1 sand at approximately 11,500 feet
measured depth, and 43 net feet of natural gas and condensate in the JR-1 sand
at approximately 9,160 feet measured depth. There was no production from this
well on the date we acquired East Cameron 240.

We developed this property by completing the temporarily abandoned well,
installing a platform without production equipment and laying a flowline from
the platform to another platform approximately three miles away. Production
from the well commenced in March 2000. Our total development cost was $7.2
million. East Cameron 240 is located in approximately 140 feet of water.

East Cameron 240 had estimated proved reserves of approximately 3.2 Bcf and
436.0 MBbls of condensate as of November 30, 2000, net to our interest. During
November 2000, the well produced 0.2 MMcf per day and 252 bbls of oil per day,
net to our interest, with an average flowing tubing pressure of 1,600 psia.

West Cameron 492

In August 1999, we acquired a 50% working interest in West Cameron 492 from
McMoRan for $1.3 million and an overriding royalty interest. There was no
production from this property as of the date we acquired it. We are the
operator of this property.

In 1997, McMoRan drilled two wells (the #1 and #3 wells) and temporarily
abandoned both wells. The #1 well encountered five sands with hydrocarbons. The
#3 well encountered both natural gas and oil in one sand. We developed this
property by completing the #1 well, drilling and completing the #2 well,
installing a platform with production facilities and laying a 4,000 foot
flowline from the platform to connect with the

38
<PAGE>

Tennessee Gas pipeline. The total development cost net to our 50% working
interest was approximately $3.1 million. We plan to subsequently develop the #3
well.

West Cameron 492 had estimated proved reserves of approximately 2.8 Bcf of
natural gas and 214.0 MBbls of condensate as of November 30, 2000, net to our
interest. During November 2000, this property produced 1.5 MMcf of natural gas
per day and 2 bbls of oil and condensate per day, net to our interest.

West Cameron 461

In November 2000, we acquired a 100% working interest in West Cameron 461
from Petsec Energy Inc. for $1.5 million. When this property was acquired, the
A-2 well was producing approximately 1.3 MMcf per day, net to our interest. We
are the operator of this property. We plan to perform development operations
through 2004 at an estimated total cost of $2.3 million.

West Cameron 461 had estimated proved reserves of approximately 3.8 Bcf and
2.0 MBbls of oil as of November 30, 2000, net to our interest. During November
2000, this property produced approximately 1.3 MMcf of natural gas per day and
1 Bbls of oil and condensate per day, net to our interest.

Vermilion 260

In April 2000, we acquired Vermilion 260 from McMoRan for $125,000 and an
overriding royalty interest. This was the third property we have acquired from
McMoRan. There was no production from this property as of the date we acquired
it. We are the operator of this property.

We developed this property by completing the existing temporarily abandoned
Vermilion 260 #1 well, installing subsea completion equipment and installing a
flowline and umbilical from the subsea well to the "A" platform on Vermilion
Block 261. Our total development cost was approximately $5.7 million. This
property is located in approximately 160 feet of water.

This property had estimated proved reserves of approximately 3.4 Bcf of
natural gas and 19.0 MBbls of condensate as of November 30, 2000, net to our
interest. The reserves are located in three sands at approximately 9,000 feet
true vertical depth. During November 2000, this property produced approximately
6.4 MMcf of natural gas per day and 27 bbls of oil and condensate per day, net
to our interest.

Development Properties

South Marsh Island 189/190

In November 2000, we acquired a 100% working interest in South Marsh Island
189/190 from Petsec Energy Inc. for $3.1 million. There was no production from
this property as of the date we acquired it. We are the operator of this
property.

We plan to develop this property by drilling and completing two wells and
installing a production platform and a flowline to a pipeline connection. The
approximate water depth is 400 feet and the development costs are expected to
be approximately $20.4 million.

South Marsh Island 189/190 had estimated proved reserves of approximately
17.1 Bcf and 551.0 MBbls of oil as of November 30, 2000, net to our interest.
We expect to begin development activities on this property in the second
quarter of 2001 and we anticipate first production in the third quarter of
2001.

West Cameron 635

In May 2000, we acquired West Cameron 635, located in approximately 337 feet
of water, at the central Gulf of Mexico offshore federal lease sale for $1.1
million. There was no production from this property as of the date we acquired
it. We are the operator of this property.

39
<PAGE>

Meridian Oil drilled one well in December 1995 indicating 60 feet of natural
gas and condensate in the PL-18 sand, which was subsequently abandoned.
Meridian allowed the lease to expire, and the property returned to the Minerals
Management Service. We plan to develop this property by drilling and completing
a new well, installing subsea completion equipment and installing an umbilical
and flowline from the subsea well to another platform. On-site development
operations commenced in November 2000. The development costs are expected to be
approximately $7.5 million.

West Cameron 635 had estimated proved reserves of approximately 6.5 Bcf of
natural gas and 66.0 MBbls of condensate as of November 30, 2000, net to our
interest. We anticipate first production in the first quarter of 2001.

Main Pass 282

In July 2000, we acquired Main Pass 282, with less than 60 days until lease
expiration, from Dominion Exploration & Production, Inc. and Union Oil Company
of California for an overriding royalty interest. We subsequently obtained a
120 day extension of lease expiration from the Minerals Management Service. The
two companies that owned this property decided not to complete the temporarily
abandoned well. There was no production from this property as of the date we
acquired it. We are the operator of this property.

We plan to develop this property by completing the temporarily abandoned
well, installing subsea completion equipment and installing an umbilical and
flowline from the subsea well to another platform. The approximate water depth
for this property is 515 feet and the development costs are expected to be
approximately $6.5 million.

Main Pass Block 282 had estimated proved reserves of approximately 3.1 Bcf
of natural gas and 48.0 MBbls of condensate as of November 30, 2000, net to our
interest. We anticipate beginning on-site development of Main Pass Block 282 in
December 2000 with expected first production in the first quarter of 2001.

Garden Banks 409 (Ladybug)

In July 2000, we acquired Texaco Exploration and Production Inc.'s 50%
working interest in Garden Banks 409, also known as Ladybug, for an overriding
royalty interest. Union Oil Company of California owns the other 50% working
interest. There was no production from this property as of the date we acquired
it. We are the operator of this property.

Garden Banks 409 is located in the shallow-deep waters of the Gulf of Mexico
in approximately 1,360 feet of water. We plan to develop the property by
completing two wells, installing subsea completion equipment, installing
approximately 18 miles of umbilical and flowline from the subsea wells to the
Texaco and Unocal "Tick" Platform in Garden Banks Block 189 and performing
modifications to the Tick platform. We expect our 50% share of the development
costs to be approximately $20 million.

We anticipate first production from the property to be in the second quarter
of 2001. Garden Banks 409 had estimated proved reserves of approximately 3.3
Bcf of natural gas and 2.0 million bbls of oil as of November 30, 2000, net to
our interest.

Garden Banks 186 and 187 (Cabrito)

In November 2000, we acquired a 100% working interest in Garden Banks 186
and 187, also known as Cabrito, from Union Oil Company of California for
$250,000 and an overriding royalty interest. There was no production from this
property as of the date we acquired it. We are the operator of this property.

Garden Banks 186 and 187 is located in the shallow-deep waters of the Gulf
of Mexico in approximately 600 feet of water. We plan to develop this property
by drilling and completing one well, installing subsea completion equipment and
installing an umbilical and flowline from the subsea well to another platform.
The development costs are expected to be approximately $13.2 million.

40
<PAGE>

The Minerals Management Service granted both the Garden Banks 186 and 187
leases with the first 98.35 Bcfe produced free of any royalty. After 98.35 Bcfe
are produced, each lease will be subject to a 16.67% royalty.

Garden Banks 186 and 187 had estimated proved reserves of approximately 6.9
Bcf as of November 30, 2000, net to our interest. We expect to begin
development activities on this property in the second quarter of 2001 and we
anticipate first production to be in the fourth quarter of 2001.

Garden Banks 142 (Matia)

In November 2000, we acquired a 100% working interest in Garden Banks 142,
also known as Matia, from Union Oil Company of California for $100,000 and an
overriding royalty interest. There was no production from this property as of
the date we acquired it. We are the operator of this property.

Garden Banks 142 is located in the shallow-deep waters of the Gulf of Mexico
in approximately 550 feet of water. We plan to develop this property by
drilling and completing one well, installing subsea completion equipment and
installing an umbilical and flowline from the subsea well to another platform.
The development costs are expected to be approximately $6.7 million.

Garden Banks 142 had estimated proved reserves of approximately 2.4 Bcf as
of November 30, 2000, net to our interest. We expect to begin development
activities on this property in the second quarter of 2001 and we anticipate
first production to be in the fourth quarter of 2001.

Significant Acquisitions in Progress

In October 2000, we entered into a letter of intent with BP Exploration
Operating Company Limited 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 Block 49/12a, including the Venture
Field, a 100% interest in Block 47/10b, and an 86% interest in Blocks 43/22a,
43/22c and 43/17c. The letter of intent provides that we would pay BP an
aggregate of (Pounds)2,500,000, approximately $3.6 million, for the three
properties at closing. We will make additional payments to BP 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.
Completion of these acquisitions from BP is conditioned upon, among other
things, obtaining all governmental and regulatory consents with regard to the
acquisitions and any necessary consents, approvals, and/or waivers from all
relevant co-venturers and entering into an acceptable sale and purchase
agreement.

Block 49/12a (Venture Field)

The Venture Field is our first potential development in the Southern Gas
Basin of the U.K. North Sea. This field is located offshore England about 80
miles northeast of Great Yarmouth. Our letter of intent provides that we will
acquire a 50% working interest in the field from BP. Conoco holds the other 50%
working interest and a preferential right to acquire BP's interest on the same
terms that we have agreed to purchase the interest. Conoco's right must be
waived prior to a closing of our acquisition. Based upon discussions with BP
and Conoco, we believe that Conoco will waive its preferential right, although
we can give you no assurance that it will do so. We believe that the
acquisition will close in the first quarter of 2001 and we expect to begin
development activities in the fourth quarter of 2001.

This field had estimated proved undeveloped reserves of 14.7 Bcf of natural
gas in three Rotliegendes sand layers as of November 30, 2000, net to our
interest. The project involves re-entering a temporarily abandoned well in 91
feet of water, installing subsea completion equipment and constructing a 10
kilometer flowline to an existing platform for entry into an existing
transportation system. The well designated for re-entry was

41
<PAGE>

originally drilled to a depth of 11,620 feet in 1989 and temporarily abandoned
for development at a later time. Facilities design is expected to commence in
the second half of 2001 with drilling operations commencing in the second
quarter of 2002. We expect that our 50% share of costs to develop this property
will be approximately $12 million. We expect first production to be in the
fourth quarter of 2002.

Block 47/10b

Our letter of intent with BP provides that we are to acquire a 100% working
interest in Block 47/10b. We intend to file an application with the Department
of Trade and Industry, the DTI, to be a licensed operator in the U.K. North
Sea. If approved by the DTI, we will be the operator of this property.

If we complete this acquisition, we plan to develop this block for a fourth
quarter 2002 startup. Facilities design is expected to commence in the second
half of 2001 with drilling operations commencing in the first half of 2002.
Development is expected to include drilling and completing one well, installing
subsea completion equipment and installing an umbilical and flowline from the
subsea well to an offset platform. The approximate water depth is 150 feet. We
are currently evaluating the property to determine proved reserves.

Block 43/22a, 43/22c and 43/17c

Our letter of intent with BP provides that we are to acquire an 86% working
interest in Blocks 43/22a, 43/22c and 43/17c. If our application to become an
operator is approved by the DTI, we will be the operator of this property.

If we complete this acquisition, we plan to develop this block for a fourth
quarter 2002 startup. Facilities design is expected to commence in the second
half of 2001 with drilling operations commencing in the second half of 2002.
Development is expected to include reentering and sidetracking two wells to
optimum development locations, installing subsea completion equipment and
installing an umbilical and flowline from the subsea wells to an offset
platform. The approximate water depth is 150 feet. We are currently evaluating
the property to determine proved reserves.

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 November 30, 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
November 30, 2000 was determined by using the November 30, 2000 prices of $5.95
per MMBtu of natural gas and $31.45 per Bbl of oil.

<TABLE>
<CAPTION>
Proved Reserves
------------------------------
Developed Undeveloped Total
--------- ----------- --------
<S> <C> <C> <C>
Natural gas (MMcf).............................. 50,359 52,367 102,726
Oil and condensate (MBbls)...................... 1,017 3,112 4,129
Total proved reserves (MMcfe)................... 56,462 71,035 127,497
Pre-tax PV-10 (in thousands).................... $251,184 $241,102 $492,286
</TABLE>

These reserve estimates do not reflect the contingent overriding royalty
interests held by the lender under our development program credit agreement.
When we repay amounts owed under this credit agreement with proceeds from this
offering, our lender will receive overriding royalty interests in certain of
our properties equal to an aggregate of 2.3 Bcf. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources--Development Program Credit Agreement."

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,

42
<PAGE>

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 prospectus 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 November 30, 2000, approximately 56% 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:

Gross Number of Blocks

<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------------------
Eleven Months Ended
1997 1998 1999 November 30, 2000
---------------------- ---------------------- --------------------------- ---------------------
Undeveloped Developed Undeveloped Developed Undeveloped Developed Undeveloped Developed
----------- --------- ----------- --------- ----------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
At January 1............ 4 5 4 10 11 22 6 25
Acquisitions............ 5 - 11 8 7 1 10 1
Divestitures............ - - - - (10)(/1/) - - (2)
Undeveloped to
productive............. (5) 5 (4) 4 (2) 2 (6) 6
Undeveloped to
nonproductive.......... - - - - - - - -
----- ----- ----- ----- ----- ----- ---- ----
At end of period........ 4 10 11 22 6 25 10 30
===== ===== ===== ===== ===== ===== ==== ====
</TABLE>
--------
(1) Includes nine undeveloped exploration blocks that we sold. We retained a
non-working future interest in seven of those blocks.

43
<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 Nine Months Ended
December 31, September 30,
-------------------- -------------------
1997 1998 1999 1999 2000
------ ------ ------ -------- ---------
<S> <C> <C> <C> <C> <C>
Production:
Natural gas (MMcf)................ 2,713 9,026 16,533 12,911 17,302
Oil and condensate (MBbls)........ 16 151 128 111 275
------ ------ ------ -------- ---------
Total (MMcfe)................... 2,807 9,933 17,301 13,575 18,953
Average sales price per unit:
Natural gas revenues from
production (per Mcf)............. $ 2.60 2.07 $ 2.23 $ 2.16 $ 3.59
Effects of hedging activities (per
Mcf)............................. -- -- (0.23) (0.18) (0.85)
------ ------ ------ -------- ---------
Average gas price............... $ 2.60 $ 2.07 $ 2.00 $ 1.98 $ 2.74
Oil and condensate revenues from
production (per Bbl)............. $18.75 11.50 $15.37 $ 14.17 $ 28.89
Effects of hedging activities (per
Bbl)............................. -- -- -- -- (4.18)
------ ------ ------ -------- ---------
Average oil price............... $18.75 $11.50 $15.37 $ 14.17 $ 24.71
Total revenues from production
(per Mcfe)....................... $ 2.62 $ 2.05 $ 2.24 $ 2.17 $ 3.70
Effects of hedging activities (per
Mcfe)............................ -- -- (0.22) (0.17) (0.84)
------ ------ ------ -------- ---------
Total average price (per Mcfe).. $ 2.62 $ 2.05 $ 2.02 $ 2.00 $ 2.86
Expenses (per Mcfe):
Lease operating................... $ 0.54 $ 0.32 $ 0.32 $ 0.24 $ 0.44
General and administrative........ 0.42 0.26 0.20 0.21 0.21
Depreciation, depletion and
amortization--natural gas and oil
properties....................... 1.50 1.76 1.30 1.36 1.62
</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 Nine Months
December 31, Ended
----------------------- September 30,
1997 1998 1999 2000
------- ------- ------- -------------
<S> <C> <C> <C> <C>
Proved property acquisition costs........ $ 1,105 $12,070 $25,274 $ 2,569
Development costs........................ 38,256 23,866 30,777 48,031
------- ------- ------- -------
Total costs incurred................... $39,361 $35,936 $56,051 $50,600
======= ======= ======= =======
</TABLE>

In addition, we acquired four properties (six blocks) in November 2000 for a
total acquisition cost of $5.0 million.

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>
Nine Months
Years Ended December 31, Ended
-------------------------------- September 30,
1997 1998 1999 2000
---------- ---------- ---------- --------------
Gross Net Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ---- ------- ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Development Wells:
Productive.................... 5.0 3.4 5.0 5.0 3.0 2.2 11.0 10.0
Nonproductive................. - - - - - - 1.0 1.0
---- ---- ---- ---- ---- ---- ------ ------
Total....................... 5.0 3.4 5.0 5.0 3.0 2.2 12.0 11.0
==== ==== ==== ==== ==== ==== ====== ======
</TABLE>

As of September 30, 2000, we were conducting completion activities on 1
gross (1 net) well.

44
<PAGE>

Productive Wells

The following table presents the number of productive natural gas and oil
wells in which we owned an interest as of September 30, 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 November 30, 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>

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 natural gas and oil production fluctuates widely. Decreases in
the prices of natural gas and oil could adversely 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.

We entered into a contract in 1998 with El Paso Energy Marketing to sell gas
for three years. The contract requires that we deliver 9,000 MMBtu per day
during 1999 and 5,000 MMBtu per day during 2000 and 2001. The price for the gas
is the Gas Daily Henry Hub Mid-Point which was $5.95 per MMBtu at November 30,
2000 less $0.015. Please read "Management's Discussion and Analysis of
Financial Condition and Results of Operation--Subsidiary Activities."

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

45
<PAGE>

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,

. 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.

46
<PAGE>

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.

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

47
<PAGE>

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.

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.

48
<PAGE>

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.

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

49
<PAGE>

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

In connection with our expansion of our business in the Southern Gas Basin
of the U.K. North Sea, we will be subject to various U.K. laws and regulations.

Licensing. 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.

Health and Safety, Environmental and Other Legislation. 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

50
<PAGE>

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.

Operatorship. 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.

Offshore Gas Transportation. 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.

Onshore Gas Transportation. 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.

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.

51
<PAGE>

MANAGEMENT

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.

<TABLE>
<CAPTION>
Name Age Position
---- --- --------
<C> <C> <S>
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........................... 71 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 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.

52
<PAGE>

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 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.

53
<PAGE>

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 2001 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;

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

54
<PAGE>

. 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.

Compensation of Directors

Upon the closing of this offering, we intend to grant to each of our non-
employee directors options to purchase 5,000 shares of common stock at an
exercise price equal to the price paid by the public in this 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.

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 Salary Bonus Compensation(1)
--------------------------- -------- -------- ---------------
<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>

55
<PAGE>

(1) Consists of matching contributions to our 401k savings plan.

(2) As described in "Related Party 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.

Each of the bonus amounts shown in the table was awarded by the board of
directors after consideration of the performance of each of the officers and
bonuses paid to similarly situated executives of companies of comparable size
in the natural gas and oil industry.

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
Individual Grants Price Appreciation for Option Term(3)
------------------------------------------------- -------------------------------------
Number of Shares Percent of Total Exercise or
Underlying Options Granted to Base Price Expiration
Name Options Granted(1) Employees in 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 $451,782 $614,590 $811,544
Keith R. Godwin....... 14,286 3.9% $3.85 8/1/2005 $ 180,718 $ 245,843 $ 324,627
</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 60 days, one year and two
years following the closing of this offering.
(2) The terms of these options provide that upon the closing of this offering,
the expiration date will be extended to the fifth anniversary of the
closing.

(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 $16.50, which is the
mid-point of the price range listed on the cover of this prospectus. 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.

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.

56
<PAGE>

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.

1998 Stock Option Plan

In December 1998, our board of directors and our shareholders adopted the
ATP Oil & Gas Corporation 1998 Stock Option Plan. Following this offering, 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 the later to occur of five years
from the date the 1998 Stock Option Plan was adopted or five years following an
underwritten public offering in a minimum amount of $5,000,000. 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 be exercised at any time after the grant,
subject to the limitation that these options shall not be exercisable for more
than a percentage of the aggregate number of shares offered by such option
determined by the occurrence of an initial public offering in accordance with
the following schedule:

<TABLE>
<CAPTION>
% of shares
Dates involving occurrence vested and
of initial public offering exercisable
-------------------------- -----------
<S> <C>
Prior to date of initial public offering...................... 0
Sixty days after date of initial public offering.............. 33 1/3
First anniversary of initial public offering.................. 66 2/3
Second anniversary of initial public offering................. 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.

57
<PAGE>

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 $7,695 for the year ended December 31, 1998, $30,966 for the year
ended December 31, 1999 and $44,063 for the nine months ended September 30,
2000.

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.

RELATED PARTY TRANSACTIONS

In 1997, 1998 and 2000, Mr. Bulmahn, Mr. Schlief and Ms. Overbey each
received overriding royalty interests in three of our properties, ranging in
amounts from 0.2% to 3.0%, at the time we acquired our interests in the
properties. In 1999, Mr. Bulmahn and Mr. Schlief each received an overriding
royalty interest of 1.0% in one of our properties at the time we acquired it.
In connection with their receiving these interests, we recorded no charges in
1997 and non-cash charges of $526,100 in 1998, $558,000 in 1999 and $281,500 in
the first nine months of 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 intend to enter 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.

58
<PAGE>

PRINCIPAL AND SELLING SHAREHOLDERS

The following table presents information regarding beneficial ownership of
our common stock as of December 31, 2000 and as adjusted to reflect the sale of
common stock in this offering, 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;

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

. the selling shareholders.

Unless otherwise indicated, each person listed has sole voting and
dispositive power over the shares indicated as owned by that person, and the
address of each shareholder is the same as our address. Furthermore, under the
regulations of the SEC, shares are deemed to be "beneficially owned" by a
person if the holder directly or indirectly has or shares the power to vote or
dispose of these shares, whether or not the holder has any pecuniary interest
in these shares, or if the holder has the right to acquire the power to vote or
dispose of these shares within 60 days following the closing of this offering,
including any right to acquire through the exercise of any option, warrant or
right.

<TABLE>
<CAPTION>
Percentage Beneficial Ownership
--------------------------------------
Maximum Number After Offering
of Shares to After Offering (Assuming
be Sold Upon (Assuming No Exercise of
Shares Exercise of Exercise of Over-Allotment
Beneficially Over-Allotment Before Over-Allotment Option in
Beneficial Owner Owned Option(1) Offering Option) Full)
---------------- ------------ -------------- -------- -------------- --------------
<S> <C> <C> <C> <C> <C>
T. Paul Bulmahn......... 9,014,067 709,852 63.1% 41.4% 38.1%
Gerald W. Schlief....... 3,493,933 275,153 24.5% 16.0% 14.8%
Carol E. Overbey........ 1,164,738 91,721 8.2% 5.3% 4.9%
Albert L. Reese, Jr..... 612,976 48,274 4.3% 2.8% 2.6%
John E. Tschirhart(2)... 41,667 -- * * *
Keith R. Godwin(2)...... 14,286 -- * * *
Arthur H. Dilly(3)...... 5,000 -- * * *
Gerard J. Swonke(3)..... 5,000 -- * * *
Robert C. Thomas(3)..... 5,000 -- * * *
Walter Wendlandt(3)..... 5,000 -- * * *
All current officers and
directors as a group
(12 persons)(4)........ 14,404,524 1,125,000 100% 65.5% 60.4%
</TABLE>
--------
* Represents beneficial ownership of less than 1%.
(1) If the over-allotment option is exercised in full, then the selling
shareholders will sell the number of shares of common stock indicated. If
the over-allotment option is exercised in part, then the number of shares
to be sold by each selling shareholder will be allocated pro rata, based
on the maximum number of shares to be sold by each selling shareholder
upon exercise of the over-allotment option.
(2) Consists of shares that may be acquired 60 days after the closing of this
offering through the exercise of stock options.
(3) Consists of options to purchase 5,000 shares at an exercise price equal to
the price paid by the public in this offering which we will grant to our
non-employee directors upon the close of this offering.
(4) Includes 118,810 shares that may be acquired after the closing of this
offering through the exercise of stock options.

59
<PAGE>

DESCRIPTION OF CAPITAL STOCK

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. We have 14,285,714 outstanding shares of common stock and no
outstanding shares of preferred stock. We have outstanding options to purchase
644,822 shares of common stock, none of which are currently exercisable. On
completion of this offering, we will have 21,785,714 outstanding shares of
common stock.

Common Stock

Subject to any special voting rights of any series of preferred stock that
we may issue in the future, each share of common stock has one vote on all
matters voted on by our shareholders, including the election of our directors.
Because holders of common stock do not have cumulative voting rights, the
holders of a majority of the shares of common stock can elect all of the
members of the board of directors standing for election, subject to the rights,
powers and preferences of any outstanding series of preferred stock.

No share of common stock affords any preemptive rights or is convertible,
redeemable, assessable or entitled to the benefits of any sinking or repurchase
fund. Holders of common stock will be entitled to dividends in the amounts and
at the times declared by our board of directors in its discretion out of funds
legally available for the payment of dividends.

Holders of common stock will share equally in our assets on liquidation
after payment or provision for all liabilities and any preferential liquidation
rights of any preferred stock then outstanding. All outstanding shares of
common stock are fully paid and non-assessable.

Preferred Stock

At the direction of our board, we may issue shares of preferred stock from
time to time. Our board of directors may, without any action by holders of the
common stock:

. adopt resolutions to issue preferred stock in one or more classes or
series;

. fix or change the number of shares constituting any class or series of
preferred stock; and

. establish or change the rights of the holders of any class or series of
preferred stock.

The rights of any class or series of preferred stock may include, among
others:

. general or special voting rights;

. preferential liquidation or preemptive rights;

. preferential cumulative or noncumulative dividend rights;

. redemption or put rights; and

. conversion or exchange rights.

We may issue shares of, or rights to purchase, preferred stock the terms of
which might:

. adversely affect voting or other rights evidenced by, or amounts
otherwise payable with respect to, the common stock;

. discourage an unsolicited proposal to acquire us; or

. facilitate a particular business combination involving us.

Any of these actions could discourage a transaction that some or a majority
of our shareholders might believe to be in their best interests or in which our
shareholders might receive a premium for their stock over its then market
price.

60
<PAGE>

Anti-Takeover Provisions of our Articles of Incorporation and Bylaws

The provisions of Texas law and our articles of incorporation and bylaws we
summarize below may have an anti-takeover effect and may delay, defer or
prevent a tender offer or takeover attempt that a shareholder might consider in
his or her best interest, including those attempts that might result in a
premium over the market price for the common stock.

Business Combinations Under Texas Law

We are a Texas corporation and, upon completion of the offering, will be
subject to Part Thirteen of the Texas Business Corporation Act, known as the
"Business Combination Law." In general, this law will prevent us from engaging
in a business combination with an affiliated shareholder, or any affiliate or
associate of an affiliated shareholder, for a three-year period after the date
such person became an affiliated shareholder, unless:

. our board of directors approves the acquisition of shares that causes
such person to become an affiliated shareholder before the date such
person becomes an affiliated shareholder,

. our board of directors approves the business combination before the date
such person becomes an affiliated shareholder, or

. holders of at least two-thirds of our outstanding voting shares not
beneficially owned by the affiliated shareholder or its affiliates or
associates approve the business combination within six months after the
date such person becomes an affiliated shareholder.

Under this law, any person that owns or has owned 20% or more of our voting
shares during the preceding three-year period is an "affiliated shareholder."
The law defines "business combination" generally as including:

. mergers, share exchanges or conversions involving an affiliated
shareholder,

. dispositions of assets involving an affiliated shareholder:

--having an aggregate value equal to 10% or more of the market value of
our assets,

--having an aggregate value equal to 10% or more of the market value of
our outstanding common stock, or

--representing 10% or more of our earning power or net income,

. issuances or transfers of securities by us to an affiliated shareholder
other than on a pro rata basis,

. plans or agreements relating to our liquidation or dissolution involving
an affiliated shareholder,

. reclassifications, recapitalizations, distributions or other transactions
that would have the effect of increasing an affiliated shareholder's
percentage ownership of our outstanding voting stock, and

. the receipt of tax, guarantee, pledge, loan or other financial benefits
by an affiliated shareholder other than proportionally as one of our
shareholders.

Written Consent of Shareholders

Our articles of incorporation provide that any action by our shareholders
must be taken at an annual or special meeting of shareholders. Special meetings
of the shareholders may be called only by holders of not less than 50% of all
the shares entitled to vote.

61
<PAGE>

Advance Notice Procedure for Shareholder Proposals

Our bylaws establish an advance notice procedure for the nomination of
candidates for election as directors as well as for shareholder proposals to be
considered at annual meetings of shareholders. In general, notice of intent to
nominate a director must contain specific information concerning the person to
be nominated and must be delivered to or mailed and received at our principal
executive offices as follows:

. With respect to an election to be held at the annual meeting of
shareholders, not less than 90 days nor more than 120 days prior to the
first anniversary date of the preceding year's annual meeting of
shareholders.

. With respect to an election to be held at a special meeting of
shareholders for the election of directors, not earlier than the close of
business on the 120th day prior to the special meeting and not later than
the close of business on the later of the 90th day prior to the special
meeting or the 10th day following the day on which public disclosure is
first made of the date of the special meeting.

Notice of shareholders' intent to raise business at an annual meeting must
be delivered to or mailed and received at our principal executive offices not
less than 90 days nor more than 120 days prior to the first anniversary date of
the preceding year's annual meeting of shareholders. These procedures may
operate to limit the ability of shareholders to bring business before a
shareholders meeting, including with respect to the nomination of directors or
considering any transaction that could result in a change of control.

Classified Board; Removal of Director

Our bylaws provide that the members of our board of directors are divided
into three classes as nearly equal as possible. Each class is elected for a
three-year term. At each annual meeting of shareholders, approximately one-
third of the members of the board of directors are elected for a three-year
term and the other directors remain in office until their three-year terms
expire. Furthermore, our bylaws provide that neither any director nor the board
of directors may be removed without cause, and that any removal for cause would
require the affirmative vote of the holders of at least a majority of the
voting power of the outstanding capital stock entitled to vote for the election
of directors. Thus, control of the board of directors cannot be changed in one
year without removing the directors for cause as described above; rather, at
least two annual meetings must be held before a majority of the members of the
board of directors could be changed.

Limitation of Liability of Officers and Directors

Our articles of incorporation provide that no director shall be personally
liable to ATP or its shareholders for monetary damages for breach of fiduciary
duty as a director, except for liability as follows:

. for any breach of the director's duty of loyalty to ATP or its
shareholders;

. for acts or omissions not in good faith or which involve intentional
misconduct or a knowing violation of law;

. for an act or omission for which the liability of a director is expressly
provided by an applicable statute; and

. for any transaction from which the director derived an improper personal
benefit.

The effect of these provisions is to eliminate the rights of ATP and its
shareholders, through derivative suits on behalf of ATP, to recover monetary
damages against a director for a breach of fiduciary duty as a director,
including breaches resulting from grossly negligent behavior, except in the
situations described above.

Transfer Agent and Registrar

The transfer agent and registrar of our common stock is Mellon Investor
Services LLC.

62
<PAGE>

SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common
stock. Sales of substantial amounts of our common stock in the public market,
or the perception that such sales may occur, could cause the market price of
our common stock to fall and could affect our ability to raise capital on terms
favorable to us in the future.

Upon completion of this offering, we will have outstanding 21,785,714 shares
of common stock. The shares of common stock sold in this offering, plus any
shares sold upon exercise of the underwriters' over-allotment option, will be
freely tradable without restriction under the Securities Act unless purchased
by our affiliates as that term is defined in Rule 144 under the Securities Act.

The remaining 14,285,714 shares of common stock outstanding, or 13,160,714
shares if the underwriters exercise the over-allotment option in full, will be
restricted securities under Rule 144. Restricted securities may be sold in the
public market only if the sale is registered or if it qualifies for an
exemption from registration, such as under Rule 144 under the Securities Act,
which is summarized below. In addition, sales of these securities will be
subject to the restrictions on transfer contained in the lock-up agreements
described below.

All of our directors, executive officers and other key employees have agreed
that they will not, without the prior written consent of the representatives of
the underwriters, sell or otherwise dispose of any shares of common stock or
options to acquire shares of common stock during the 180-day period following
the closing of this offering. See "Underwriting." Lehman Brothers Inc., in its
sole discretion, may release the shares subject to the lock-up agreements in
whole or in part at any time with or without notice. When determining whether
to release shares from the lock-up agreements, Lehman Brothers Inc. will
consider, among other factors, the shareholders' reasons for requesting the
release, the number of shares for which the release is being requested and
market conditions at the time.

Rule 144

In general, under Rule 144 as currently in effect, beginning 90 days after
the date of this prospectus, a person, or persons whose shares are aggregated,
who has beneficially owned restricted shares for at least one year, including
the holding period of any prior owner except an affiliate, would be entitled to
sell within any three-month period a number of shares that does not exceed the
greater of:

. one percent of the number of shares of common stock then outstanding,
which will equal 217,857 shares immediately after this offering; or

. the average weekly trading volume of the common stock on the Nasdaq
National Market during the four calendar weeks preceding the filing with
the SEC of a notice on Form 144 with respect to the sale.

Sales under Rule 144 also are subject to manner of sale provisions and
notice requirements and to the availability of current public information about
us.

Under Rule 144(k), a person who is not deemed to have been one of our
affiliates at any time during the 90 days preceding a sale and who has
beneficially owned the shares proposed to be sold for at least two years,
including the holding period of any prior owner except an affiliate, is
entitled to sell those shares without complying with the manner of sale, public
information, volume limitation or notice provisions of Rule 144.

63
<PAGE>

Rule 701

Rule 701 permits resales of shares in reliance on Rule 144 but without
compliance with specified restrictions of Rule 144. Any employee, officer or
director of ATP who receives shares upon exercise of options granted prior to
the offering may be entitled to rely on the resale provisions of Rule 701. Rule
701 permits our affiliates to sell their Rule 701 shares under Rule 144 without
complying with the holding period requirements of Rule 144. Rule 701 further
provides that non-affiliates may sell those shares in reliance on Rule 144
without having to comply with the holding period, public information, volume
limitation or notice provisions of Rule 144. All holders of Rule 701 shares are
required to wait until 90 days after the date of this prospectus before selling
those shares. After the expiration of that 90-day period, 116,131 shares
subject to outstanding options could be sold under Rule 701.

Stock Options

Following the consummation of this offering, we intend to file a
registration statement on Form S-8 under the Securities Act covering shares of
common stock reserved for issuance under our 2000 Stock Plan. This registration
will permit the resale of these shares by nonaffiliates in the public market
without restriction under the Securities Act. Shares registered under the Form
S-8 registration statement held by affiliates will be subject to Rule 144
volume limitations and the lock-up period described above.

64
<PAGE>

UNDERWRITING

Under the underwriting agreement, which is filed as an exhibit to the
registration statement relating to this prospectus, Lehman Brothers Inc., CIBC
World Markets Corp., Dain Rauscher Incorporated, Raymond James & Associates,
Inc. and Fidelity Capital Markets, a division of National Financial Services
LLC, are acting as representatives of each of the underwriters named below.
Under the underwriting agreement, each of the underwriters has agreed to
purchase from us the respective number of shares of common stock shown opposite
its name below:
<TABLE>
<CAPTION>
Number of
Underwriter Shares
----------- ---------
<S> <C>
Lehman Brothers Inc. ...............................................
CIBC World Markets Corp. ...........................................
Dain Rauscher Incorporated..........................................
Raymond James & Associates, Inc. ...................................
Fidelity Capital Markets, a division of National Financial Services
LLC................................................................
---------
Total........................................................... 7,500,000
=========
</TABLE>

The underwriting agreement provides that the underwriters' obligations to
purchase shares of common stock depend on the satisfaction of the conditions
contained in the underwriting agreement and that, if any of the shares of
common stock are purchased by the underwriters under the underwriting
agreement, all of the shares of common stock that the underwriters have agreed
to purchase under the underwriting agreement must be purchased. The conditions
contained in the underwriting agreement include the requirement that the
representations and warranties made by us to the underwriters are true, that
there is no material change in the financial markets and that we deliver to the
underwriters customary closing documents.

The following table shows the underwriting fees to be paid to the
underwriters by us and the selling shareholders in connection with this
offering. These amounts are shown assuming both no exercise and full exercise
of the underwriters' option to purchase additional shares from the selling
shareholders described below. The underwriting fee is the difference between
the public offering price and the amount the underwriters pay to purchase the
shares from us and the selling shareholders. On a per share basis, the
underwriting fee is % of the initial public offering price.

<TABLE>
<CAPTION>
No Exercise Full Exercise
----------- -------------
<S> <C> <C>
Per share............................................. $ $
Total................................................. $ $
</TABLE>

The representatives have advised us that the underwriters propose to offer
the shares of common stock directly to the public at the initial public
offering price set forth on the cover page of this prospectus, and to dealers,
who may include the underwriters, at this public offering price less a selling
concession not in excess of $ per share. The underwriters may allow, and
the dealers may reallow, a concession not in excess of $ per share to
brokers and dealers. After the offering, the underwriters may change the
offering price and other selling terms.

We estimate that the total expenses of this offering, including
registration, filing and listing fees, printing fees and legal and accounting
expenses, but excluding underwriting discounts, will be approximately
$1,000,000.

The selling shareholders have granted to the underwriters an option to
purchase up to an aggregate of 1,125,000 of their shares of common stock
exercisable to cover over-allotments, if any, at the initial public

65
<PAGE>

offering price less the underwriting discounts shown on the cover page of this
prospectus. The underwriters may exercise this option any time until 30 days
after the date of the underwriting agreement. If this option is exercised, each
underwriter will be committed, so long as the conditions of the underwriting
agreement are satisfied, to purchase a number of additional shares of common
stock proportionate to the underwriter's initial commitment as indicated in the
table above and the selling shareholders will be obligated, under the over-
allotment option, to sell to the underwriters their shares of common stock.

We have agreed that, without the consent of Lehman Brothers Inc., we will
not, directly or indirectly, offer, sell or otherwise dispose of any shares of
common stock or any securities that may be converted into or exchanged for any
shares of common stock for a period of 180 days from the date of this
prospectus. All of our directors, executive officers and other key employees
have agreed under lock-up agreements that, without the prior written consent of
Lehman Brothers Inc., they will not, directly or indirectly, offer, sell or
otherwise dispose of any shares of common stock or any securities that may be
converted into or exchanged for any shares of common stock for the period
ending 180 days after the date of this prospectus. See "Shares Eligible for
Future Sale."

Prior to the offering, there has been no public market for the shares of our
common stock. The initial public offering price has been negotiated between the
representatives and us. The material factors considered in determining the
initial public offering price of the common stock, in addition to prevailing
market conditions, were:

. our historical performance and capital structure;

. estimates of our business potential and earning prospects;

. an overall assessment of our management; and

. the above factors in relation to market valuation of companies in related
businesses.

Fidelity Capital Markets, a division of National Financial Services LLC, is
acting as an underwriter of this offering and will be facilitating electronic
distribution through the Internet.

Our common stock has been approved for quotation on the Nasdaq National
Market under the symbol "ATPG", subject to notice of issuance.

We have agreed to indemnify the underwriters against liabilities under the
Securities Act and liabilities arising from breaches of the representations and
warranties contained in the underwriting agreement, and to contribute to
payments that the underwriters may be required to make for these liabilities.
We have further agreed to indemnify Lehman Brothers Inc. against liabilities
related to the directed share program referred to below, including liabilities
under the Securities Act.

The representatives may engage in over-allotment, stabilizing transactions,
syndicate covering transactions and penalty bids or purchases for the purpose
of pegging, fixing or maintaining the price of the common stock, in accordance
with Regulation M under the Securities Exchange Act of 1934:

. Over-allotment involves sales by the underwriters of shares in excess of
the number of shares the underwriters are obligated to purchase, which
creates a syndicate short position. The short position may be either a
covered short position or a naked short position. In a covered short
position, the number of shares over-alloted by the underwriters is not
greater than the number of shares that they may purchase in the over-
allotment option. In a naked short position, the number of shares
involved is greater than the number of shares in the over-allotment
option. The underwriters may close out any short position by exercising
their over-allotment option and/or purchasing shares in the open market.

. Stabilizing transactions permit bids to purchase the underlying security
so long as the stabilizing bids do not exceed a specified maximum.

. Syndicate covering transactions involve purchases of the common stock in
the open market after the distribution has been completed in order to
cover syndicate short positions. In determining the source of

66
<PAGE>

shares to close out the short position, the underwriters will consider,
among other things, the price of shares available for purchase in the
open market as compared to the price at which they may purchase shares
through the over-allotment option. If the underwriters sell more shares
than could be covered by the over-allotment option, a naked short
position, the position can only be closed out by buying shares in the
open market. A naked short position is more likely to be created if the
underwriters are concerned that there could be downward pressure on the
price of the shares in the open market after pricing that could adversely
affect investors who purchase in the offering.

. Penalty bids permit the representatives to reclaim a selling concession
from a syndicate member when the common stock originally sold by the
syndicate member is purchased in a stabilizing or syndicate covering
transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty
bids may have the effect of raising or maintaining the market price of our
common stock or preventing or retarding a decline in the market price of our
common stock. As a result, the price of our common stock may be higher than
the price that might otherwise exist in the open market. These transactions
may be effected on The Nasdaq National Market or otherwise and, if commenced,
may be discontinued at any time.

Neither we nor any of the underwriters makes any representation or
prediction as to the direction or magnitude of any effect that the
transactions described above may have on the price of the common stock. In
addition, neither we nor any of the underwriters makes any representation that
the representatives will engage in these transactions or that these
transactions, once commenced, will not be discontinued without notice.

Any offers in Canada will be made only under an exemption from the
requirements to file a prospectus in the relevant province of Canada in which
the sale is made.

Purchasers of the shares of common stock offered in this prospectus may be
required to pay stamp taxes and other charges under the laws and practices of
the country of purchase, in addition to the offering price listed on the cover
page of this prospectus.

The representatives have informed us that they do not intend to confirm the
sales of shares of common stock offered by this prospectus to any accounts
over which they exercise discretionary authority in excess of five percent of
the shares offered by them.

At our request, the underwriters have reserved up to 375,000 shares of the
common stock offered by this prospectus for sale to our officers, directors,
employees and their family members and to our business associates at the
initial public offering price set forth on the cover page of this prospectus.
These persons must commit to purchase no later than the close of business on
the day following the date of this prospectus. The number of shares available
for sale to the general public will be reduced to the extent these persons
purchase the reserved shares.

67
<PAGE>

LEGAL MATTERS

The validity of the issuance of the shares of common stock offered by this
prospectus will be passed on for us by Vinson & Elkins L.L.P., Houston, Texas.
Certain legal matters relating to the common stock offered by this prospectus
will be passed on by Baker Botts L.L.P., Houston, Texas, as counsel for the
underwriters.

EXPERTS

The audited consolidated financial statements as of December 31, 1998 and
1999, and for each of the years in the three-year period ended December 31,
1999 have been included in this prospectus and elsewhere in the registration
statement in reliance upon the report of KPMG LLP, independent certified public
accountants, appearing elsewhere herein, and upon the authority of said firm as
experts in accounting and auditing.

The statement of revenues and direct operating expenses of the Eugene Island
30 property for the nine months ended September 30, 1999 has been included
herein and in the registration statement in reliance upon the report of KPMG
LLP, independent certified public accountants, appearing elsewhere herein, and
upon the authority of said firm as experts in accounting and auditing.

The estimated reserve evaluations and related calculations of Ryder Scott
Company, L.P., Schlumberger Holditch-Reservoir Consulting Services Inc., and
Scott Pickford Group Limited, independent petroleum engineering consultants,
included in this prospectus have been included in reliance on the authority of
said firm as experts in petroleum engineering.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Securities and Exchange Commission a registration
statement on Form S-1 under the Securities Act, and the rules and regulations
promulgated thereunder, with respect to the common stock offered under this
prospectus. This prospectus, which constitutes a part of the registration
statement, does not contain all of the information included in the registration
statement and the attached exhibits and schedules. Statements contained in this
prospectus as to the contents of any contract or other document that is filed
as an exhibit to the registration statement are summaries of the material
provisions of those documents. These summaries are qualified in all respects by
reference to the full text of such contract or document.

The registration statement, 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 the
registration statement 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.

Upon completion of this offering, we will be 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.

68
<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.

69
<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............................................. F-2
Consolidated Balance Sheets as of December 31, 1998, 1999 and September
30, 2000 (unaudited).................................................... F-3
Consolidated Statements of Operations for the years ended December 31,
1997, 1998, and 1999 and nine months ended September 30, 1999
(unaudited) and 2000 (unaudited)........................................ F-4
Consolidated Statements of Shareholders' Deficit for the years ended
December 31, 1997, 1998, and 1999 and nine months ended September 30,
2000 (unaudited)........................................................ F-5
Consolidated Statements of Cash Flows for the years ended December 31,
1997, 1998, and 1999 and nine months ended September 30, 1999
(unaudited) and 2000 (unaudited)........................................ F-6
Notes to Consolidated Financial Statements............................... F-7
STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES FOR THE NINE MONTHS
ENDED SEPTEMBER 30, 1999 FOR THE EUGENE ISLAND 30 PROPERTY
Independent Auditors' Report............................................. F-24
Statement of Revenues and Direct Operating Expenses for the nine-months
ended September 30, 1999................................................ F-25
Notes to Statement of Revenues and Direct Operating Expenses............. F-26
ATP OIL & GAS CORPORATION AND SUBSIDIARIES UNAUDITED PRO FORMA
CONSOLIDATED FINANCIAL INFORMATION
Unaudited Pro Forma Financial Information................................ F-28
Unaudited Pro Forma Consolidated Statement of Operations for the year
ended December 31, 1999................................................. F-29
Notes to Unaudited Pro Forma Consolidated Financial Statement............ F-30
</TABLE>

F-1
<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 subsidiary as of December 31, 1998 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, 1999.
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 audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of ATP Oil &
Gas Corporation and subsidiary as of December 31, 1998 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, 1999, in conformity with generally
accepted accounting principles.

/s/ KPMG LLP

Houston, Texas
April 28, 2000

F-2
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 1998 and 1999 and September 30, 2000 (unaudited)
(In thousands, except share data)

<TABLE>
<CAPTION>
September 30,
ASSETS 1998 1999 2000
------ -------- -------- -------------
(unaudited)
<S> <C> <C> <C>
Current assets:
Cash and cash equivalents...................... $ 3,411 $ 17,779 $ 19,066
Restricted cash................................ 3,529 471 --
Cash held in escrow............................ 439 -- --
Accounts receivable (net of allowance for
doubtful accounts)............................ 4,325 11,119 23,356
Other current assets........................... 645 1,048 2,248
-------- -------- --------
Total current assets......................... 12,349 30,417 44,670
Oil and gas properties:
Oil and gas properties using the successful
efforts method of accounting.................. 80,966 135,609 183,632
Less accumulated depreciation, depletion,
impairment and amortization................... (33,354) (63,331) (98,195)
-------- -------- --------
Oil and gas properties, net.................. 47,612 72,278 85,437
Furniture and fixtures (net of accumulated
depreciation)................................... 96 250 492
Restricted cash.................................. 471 -- --
Deferred tax assets.............................. -- 2,058 4,385
Other assets..................................... 826 2,051 1,925
-------- -------- --------
Total assets................................. $ 61,354 $107,054 $136,909
======== ======== ========
<CAPTION>
LIABILITIES AND SHAREHOLDERS DEFICIT
------------------------------------
<S> <C> <C> <C>
Current liabilities:
Accounts payable and accruals.................. $ 11,155 $ 12,408 $ 26,359
Current maturity of long-term debt............. 2,500 3,750 4,500
Other deferred obligations..................... 3,782 75 67
Other current liabilities...................... 18 69 3,417
-------- -------- --------
Total current liabilities.................... 17,455 16,302 34,343
Long-term debt................................... 12,000 16,450 27,750
Non-recourse borrowings.......................... 50,690 75,273 80,340
Deferred revenue................................. 2,000 1,667 1,528
Other deferred obligations....................... 218 143 74
-------- -------- --------
Total liabilities............................ 82,363 109,835 144,035
-------- -------- --------
Shareholders' deficit:
Common stock: $0.001 par value, authorized
50,000,000 shares; issued and outstanding
14,285,714 shares at December 31, 1998 and
1999 and September 30, 2000 .................. 14 14 14
Additional paid in capital..................... 38 38 38
Accumulated deficit............................ (21,061) (2,833) (7,178)
-------- -------- --------
Total shareholders' deficit.................. (21,009) (2,781) (7,126)
-------- -------- --------
Commitments and contingencies
Total liabilities and shareholders' deficit.. $ 61,354 $107,054 $136,909
======== ======== ========
</TABLE>

See accompanying notes to the consolidated financial statements.

F-3
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

Years ended December 31, 1997, 1998 and 1999
and nine months ended September 30, 1999 (unaudited) and 2000 (unaudited)
(In thousands, except share and per share data)

<TABLE>
<CAPTION>
Nine months ended
Years ended December 31, September 30,
---------------------------------- ------------------------
1997 1998 1999 1999 2000
---------- ---------- ---------- ----------- -----------
(unaudited) (unaudited)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas
production........... $ 7,359 $ 20,410 $ 34,981 $ 27,182 $ 54,290
Gas sold--marketing... -- -- 7,703 5,602 5,024
Gain on sale of oil
and gas properties... 304 -- 287 287 33
---------- ---------- ---------- ---------- ----------
7,663 20,410 42,971 33,071 59,347
---------- ---------- ---------- ---------- ----------
Costs and operating
expenses:
Lease operating
expenses............. 1,513 3,193 5,587 3,321 8,363
Gas purchased--
marketing............ -- -- 7,402 5,431 4,856
General and
administrative
expenses............. 1,170 2,591 3,541 2,902 4,018
Depreciation,
depletion and
amortization......... 4,206 17,442 22,521 18,452 30,686
Impairment of oil and
gas properties....... 5,787 5,072 7,509 6,382 7,038
Other expense......... -- -- -- -- 2,947
---------- ---------- ---------- ---------- ----------
12,676 28,298 46,560 36,488 57,908
---------- ---------- ---------- ---------- ----------
Net income (loss)
from operations..... (5,013) (7,888) (3,589) (3,417) 1,439
---------- ---------- ---------- ---------- ----------
Other income (expense):
Interest income....... 207 141 202 102 334
Interest expense...... (1,212) (7,963) (9,399) (7,471) (8,445)
---------- ---------- ---------- ---------- ----------
(1,005) (7,822) (9,197) (7,369) (8,111)
---------- ---------- ---------- ---------- ----------
Net loss before
income taxes and
extraordinary
items............... (6,018) (15,710) (12,786) (10,786) (6,672)
Income tax benefit
(expense).............. -- -- 1,829 1,131 2,327
---------- ---------- ---------- ---------- ----------
Loss before
extraordinary item.. (6,018) (15,710) (10,957) (9,655) (4,345)
Gain on extinguishment
of debt, net of tax.... -- -- 29,185 29,185 --
---------- ---------- ---------- ---------- ----------
Net income (loss).... $ (6,018) $ (15,710) $ 18,228 $ 19,530 $ (4,345)
========== ========== ========== ========== ==========
Basic earnings (loss)
per common share:
Income (loss) before
extraordinary item... $ (0.57) $ (1.32) $ (0.77) $ (0.68) $ (0.30)
Extraordinary gain,
net of income taxes.. -- -- 2.05 2.05 --
---------- ---------- ---------- ---------- ----------
Net income (loss) per
common share........ $ (0.57) $ (1.32) $ 1.28 $ 1.37 $ (0.30)
========== ========== ========== ========== ==========
Diluted earnings (loss)
per common share:
Income (loss) before
extraordinary item... $ (0.57) $ (1.32) $ (0.77) $ (0.68) $ (0.30)
Extraordinary gain,
net of income taxes.. -- -- 2.05 2.05 --
---------- ---------- ---------- ---------- ----------
Net income (loss) per
common share........ $ (0.57) $ (1.32) $ 1.28 $ 1.37 $ (0.30)
========== ========== ========== ========== ==========
Weighted average number
of common shares:
Basic................. 10,567,762 11,925,785 14,285,714 14,285,714 14,285,714
========== ========== ========== ========== ==========
Diluted............... 10,567,762 11,925,785 14,285,714 14,285,714 14,285,714
========== ========== ========== ========== ==========
</TABLE>

See accompanying notes to the consolidated financial statements.

F-4
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' DEFICIT

Years ended December 31, 1997, 1998 and 1999 and nine months ended September
30, 2000 (unaudited)
(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,
1996................... 10,456,923 $10 $27 $ 667 $ 704
Exercise of options... 612,976 1 1 -- 2
Net loss.............. -- -- -- (6,018) (6,018)
---------- --- --- -------- --------
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.............. -- -- -- (4,345) (4,345)
---------- --- --- -------- --------
Balance, September 30,
2000................... 14,285,714 $14 $38 $ (7,178) $ (7,126)
========== === === ======== ========
</TABLE>

See accompanying notes to the consolidated financial statements.

F-5
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years ended December 31, 1997, 1998 and 1999
and nine months ended September 30, 1999 (unaudited) and 2000 (unaudited)
(In thousands)

<TABLE>
<CAPTION>
Nine months ended
Years ended December 31, September 30,
---------------------------- -----------------------
1997 1998 1999 1999 2000
-------- -------- -------- ----------- -----------
(unaudited) (unaudited)
<S> <C> <C> <C> <C> <C>
Cash flows from
operating activities:
Net income (loss)..... $ (6,018) $(15,710) $ 18,228 $ 19,530 $ (4,345)
Adjustments to
reconcile net income
(loss) from
operations to net
cash provided by
operating activities:
Depreciation,
depletion and
amortization........ 4,206 17,442 22,521 18,452 30,686
Amortization of
deferred financing
costs............... 2 45 280 135 237
Impairment of oil and
gas properties...... 5,787 5,072 7,509 6,382 7,038
Assignment of
overrides to related
party............... -- 525 557 -- 282
Other expense........ -- -- -- -- 2,947
Recognition of
deferred revenue.... -- -- (333) (249) (139)
Gain on early
extinguishment of
debt................ -- -- (29,185) (29,185) --
Gain on sale of oil
and gas properties.. (304) -- (287) (287) (33)
Change in assets and
liabilities:
(Increase) decrease in
accounts receivable.. (9,967) 7,205 (6,794) (7,190) (12,237)
(Increase) decrease in
cash held in escrow.. (411) 981 439 426 --
(Increase) in other
current assets....... (482) (39) (403) (546) (1,200)
Decrease in restricted
cash................. -- -- 3,529 2,591 471
(Increase) in deferred
tax assets........... -- -- (2,058) (1,512) (2,327)
(Increase) decrease in
other assets......... 32 (96) (714) (724) 1
Increase (decrease) in
accounts payable..... 10,794 (2,156) 1,253 6,375 13,465
Increase (decrease) in
other current
liabilities.......... 19 (22) 51 760 401
(Decrease) in deferred
obligations.......... (86) -- (3,782) (2,777) (77)
-------- -------- -------- -------- --------
Cash provided by
operating
activities........ 3,572 13,247 10,811 12,181 35,170
-------- -------- -------- -------- --------
Cash flows from
investing activities:
Additions and
acquisitions of oil
and gas properties... (39,361) (35,936) (56,051) (43,624) (50,600)
Disposals of oil and
gas properties....... -- -- -- 113 --
Proceeds from sale of
oil and gas
properties........... 975 -- 1,137 300 --
Additions to furniture
and fixtures......... (84) (46) (206) (114) (288)
-------- -------- -------- -------- --------
Cash used by
investing
activities........ (38,470) (35,982) (55,120) (43,325) (50,888)
-------- -------- -------- -------- --------
Cash flows from
financing activities:
Increase in long-term
debt................. -- 14,500 19,800 16,800 15,800
Payments of long-term
debt................. -- -- (14,100) (11,100) (3,750)
Non-recourse
borrowings........... 39,924 20,113 93,728 67,107 24,925
Payments of non-
recourse borrowings.. (4,232) (11,617) (39,420) (32,772) (19,857)
Deferred financing
costs incurred....... (78) (669) (1,331) (993) (113)
Receipt of deferred
revenue.............. -- 2,000 -- -- --
Exercise of options to
purchase common
stock................ 2 13 -- -- --
-------- -------- -------- -------- --------
Cash provided by
financing
activities........ 35,616 24,340 58,677 39,042 17,005
-------- -------- -------- -------- --------
Increase in cash and
cash equivalents..... 718 1,605 14,368 7,898 1,287
Cash and cash
equivalents:
At beginning of year.. 1,088 1,806 3,411 3,411 17,779
-------- -------- -------- -------- --------
At end of year........ $ 1,806 $ 3,411 $ 17,779 $ 11,309 $ 19,066
======== ======== ======== ======== ========
</TABLE>

See accompanying notes to the consolidated financial statements.

F-6
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

(Amounts for interim periods are unaudited)

(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 generally accepted accounting principles 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.

Interim Financial Data

The unaudited consolidated financial statements as of September 30, 2000,
for the nine-month periods ended September 30, 1999 and 2000, and all related
footnote information for these periods have been prepared on the same basis as
the audited financial statements and, in the opinion of management, include all
adjustments, consisting of normal recurring adjustments, necessary for a fair
presentation of financial position, results of operations and cash flows in
accordance with generally accepted accounting principles.

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.

F-7
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

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.

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 an impairment during the years ended December
31, 1997, 1998 and 1999 and the nine-month periods ended September 30, 1999 and
2000 of $5.8 million, $5.1 million, $7.5 million, $6.4 million and $7.0
million, respectively, primarily due to depressed oil and natural gas prices,
unfavorable operating performance and a reduction 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 $27,000,
$33,000, $52,000, $36,000 and $46,000 for the periods ended December 31, 1997,
1998 and 1999 and September 30, 1999 and 2000, 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, 1997, 1998, and
1999 and September 30, 1999 and 2000 and were $2.1 million, $1.6 million, $0.6
million, $0.2 million and $0.7 million, respectively.

Other Current Assets

Other current assets for the periods ended December 31, 1998 and 1999 and
September 30, 2000 include prepaid expenses of $0.2 million, $0.2 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 $0.5 million at December 31, 1998, $0.8 million at December 31, 1999
and $2.0 million at September 30, 2000. These deposits represent an estimate of
one month's payment attributable to the Minerals Management Service royalty
interest in our properties.

F-8
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

Other Assets

Other assets include debt financing costs of $0.7 million, $1.2 million and
$1.0 million, assets held for resale of none, $0.7 million and none, offering
costs of none, none and $0.2 million and spare parts inventory of $0.1 million,
$0.2 million and $0.7 million at December 31, 1998, and 1999 and September 30,
2000, 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 $2,000, $45,000,
$0.3 million, $0.1 million and $0.2 million for the periods ended December 31,
1997, 1998 and 1999, and September 30, 1999 and 2000, respectively.

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, 1998 and 1999
and September 30, 2000, the Company had over-deliveries included in accounts
payable of $47,000, $0.2 million and $0.2 million, respectively.

The Company has allowance for doubtful accounts related to its trade
accounts receivable of none, none and $0.4 million at December 31, 1998 and
1999 and September 30, 2000.

Income Taxes

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

F-9
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

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.

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 year ended December 31, 1997 and 1998, the Company had no hedge
transactions. For the year ended December 31, 1999, the Company recorded $3.8
million as a reduction of oil and gas revenues related to hedging transactions.

At September 30, 2000, the Company had hedged approximately 6,875,000 MMBbtu
of its expected fourth quarter 2000 natural gas production from its current
portfolio of properties and 14,526,900 MMBbtu of its expected 2001 natural gas
production. The average price of hedged natural gas production is approximately
$3.03 per MMBbtu for fourth quarter 2000 and $3.03 per MMBbtu for 2001. The
Company has no natural gas hedges in effect beyond October 2001. At September
30, 2000, the Company had hedged 46,000 Bbls of oil of its expected remaining
fourth quarter 2000 oil production. The average price of hedged oil production
is $24.39 per barrel. The Company has no oil hedges in effect beyond December
2000. The Company estimates that the above hedge positions will result in a
reduction to operating income of approximately $14.4 million in the fourth
quarter of 2000. Based on NYMEX monthly settlement prices on January 3, 2001,
the Company anticipates that the above hedge positions will result in a
reduction to operating income of approximately $53.5 million for 2001.

It is the Company's general policy not to acquire derivative products for
the purpose of speculating on price changes, however, occasionally, the Company
may find itself in limited speculative positions as a result of actual
production being less than projected production when the derivative products
were consummated. 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. The
Company's derivative commodity instruments currently are comprised of swaps. As
of September 30, 2000, the Company recognized a loss in the amount of $2.9
million from certain speculative positions. This amount is reflected as other
expense in the statement of operations.

Stock Options

In October 1995, the Financial Accounting Standards Board (FASB) issued SFAS
No. 123, Accounting for Stock-Based Compensation. SFAS No. 123 encourages, but
does not require, companies to record compensation cost for stock-based
employee compensation plans at fair value. The Company has chosen to account
for stock-based compensation using the intrinsic value method prescribed in
Accounting Principles Board (APB) Opinion

F-10
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

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 (see note 5).

Use of Estimates

The preparation of financial statements in accordance with generally
accepted accounting principles 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.

Supplemental Disclosure of Cash Flow Information

For the years ended December 31, 1997, 1998, and 1999, the Company made cash
payments of interest of $0, $32,000 and $0.6 million, respectively and for the
nine months ended September 30, 1999 and 2000, the Company made cash payments
of interest of $0.5 million and $1.7 million, respectively. The Company made no
cash payments for income taxes during the three years ending December 31, 1999
or the nine months ended September 30, 1999 and the Company made cash payments
for income taxes during the nine months ended September 30, 2000 of $0.5
million.

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 working capital surpluses (deficits) at December 31,
1998 and 1999 and September 30, 2000 totaling ($4.9) million, $13.7 million and
$10.4 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 additional borrowings under its credit facility 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. These statements are effective for fiscal years
beginning after June 15, 2000. While the Company has not yet completed its
evaluation of the impact of these

F-11
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

statements, the Company does not believe the statements will have a significant
impact on its results of operations as it expects its current derivative
activities would continue to qualify under hedge accounting, if elected by the
Company. However if the Company decides not to elect hedge accounting for its
derivative activities there would be a significant impact on its results of
operations.

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. The provisions of Interpretation No. 44
affecting the Company are to be applied on a prospective basis effective July
1, 2000.

(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 recent acquisitions.
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>
Brazos 544................................. 100.0% May/June 1997 $ 700
Statoil Package............................ Varies December 1998 9,763
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.

F-12
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

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

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

Credit facility

<TABLE>
<CAPTION>
December 31,
---------------------- September 30,
1998 1999 2000
------- -------------- --------------
(In thousands) (unaudited)
<S> <C> <C> <C>
Credit facility........................ $14,500 $20,200 $32,250
Less current portion................... 2,500 3,750 4,500
------- ------- -------
Long-term debt....................... $12,000 $16,450 $27,750
======= ======= =======
</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
September 2000 adjusted the borrowing base to $39.0 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, 1998 and 1999, and September 30, 2000 the
average interest rate was 8.1%, 8.9% and 10.0% 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, 1999 and September 30, 2000, the
Company was in compliance with all terms of the agreement. At December 31, 1998
and 1999 and September 30, 2000, the amount outstanding under the credit
facility was $14.5 million, $20.2 million and $32.3 million, respectively.

F-13
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

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 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 November 2002. At December 31, 1999 and September 30, 2000, there was $75.3
million and $80.3 million, respectively, outstanding under the agreement.

F-14
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

(5) Equity

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 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 is a private company whose shares do not trade in any market, there is
no established market value for the Company's common stock. 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, 1997, 1998, and 1999 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 become exercisable upon
either the completion of an initial public offering of Company Stock in a
minimum amount of $5.0 million (an IPO) or a corporate change in control as
defined by the 1998 SOP. These options expire at the later of 5 years from the
date the 1998 SOP was adopted if no IPO is underwritten before such term or
five years after the date of an 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 involving occurrence of IPO exercisable
--------------------------------- -----------
<S> <C>
Prior to date of IPO............................................. 0
Sixty days after date of IPO..................................... 33 1/3
First anniversary of IPO......................................... 66 2/3
Second anniversary of IPO........................................ 100
</TABLE>

F-15
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

If there is a Corporate Change in Control as defined by the 1998 SOP prior
to an IPO, then, at the discretion of the Committee, the options may become
exercisable at a date other than that stated in the option, may be exchanged
for cash, or may be exchanged for options in another entity. During the periods
ended December 31, 1998 and 1999, and September 30, 2000, the Company granted
options exercisable for 440,714, 18,571 and 23,393 shares of common stock at
$1.40 per share. During the period ended September 30, 2000, the Company
granted options exercisable for 322,858 shares of common stock at $3.85 per
share.

The Company expects to 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.
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 and the mid-point of the IPO price range for its shares of $16.50, the
Company estimates that it will incur a non-cash compensation expense of
approximately $3.9 million in 2001 and approximately $0.8 million in 2002
relating to such option grants.

Information regarding the Company's 1998 SOP is summarized as follows:
<TABLE>
<CAPTION>
September 30, September 30,
2000 2000
1998 1998 1999 1999 (unaudited) (unaudited)
------- -------- ------- -------- ------------- -------------
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................ -- 440,714 $1.40 456,964 $1.40
Granted................. 440,714 $1.40 18,571 $1.40 346,251 $3.68
Expired unexercised..... -- -- (2,321) $1.40 (178,572) $1.40
Exercised............... -- -- -- -- --
------- ----- ------- ----- -------- -----
Outstanding at end of
period................. 440,714 $1.40 456,964 $1.40 624,643 $2.67
======= ===== ======= ===== ======== =====
Exercisable at end of
period................. -- -- -- -- -- --
======= ===== ======= ===== ======== =====
Option Grant Price...... 440,714 $1.40 18,571 $1.40 346,251 $3.68
======= ===== ======= ===== ======== =====
</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, 1997, 1998 and 1999 and September
30, 2000, options to purchase 22,766,189 shares, 18,937,397 shares, 18,937,397
shares and 18,937,397 shares, respectively, 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 the closing of this offering, no options can be exercised under
this plan unless the holder ceases to own a majority of the outstanding shares
of common stock. The Company does not expect the option to be exercised. In
conjunction with the Company's planned initial public offering, the 1994 SOP
will be terminated and the outstanding option will be cancelled. Thereafter, no
option under the 1994 SOP will ever be exercised.

F-16
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

Information regarding the Company's 1994 SOP is summarized as follows:
<TABLE>
<CAPTION>
September 30, September 30,
2000 2000
1997 1997 1998 1998 1999 1999 (unaudited) (unaudited)
---------- -------- ---------- -------- ---------- -------- ------------- -------------
Weighted Weighted Weighted Weighted
average average average average
exercise exercise exercise exercise
Shares price Shares price Shares price Shares price
---------- -------- ---------- -------- ---------- -------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Outstanding at beginning
of year................ 22,766,189 $0.004 22,153,213 $0.004 18,937,397 $0.004 18,937,397 $0.004
Granted................. -- -- -- -- -- -- -- --
Expired unexercised..... -- -- -- -- -- -- -- --
Exercised............... (612,976) 0.004 (3,215,816) 0.004 -- -- -- --
---------- ------ ---------- ------ ---------- ------ ---------- ------
Outstanding at end of
period................. 22,153,213 $0.004 18,937,397 $0.004 18,937,397 $0.004 18,937,397 $0.004
========== ====== ========== ====== ========== ====== ========== ======
Exercisable at end of
period................. 22,153,213 $0.004 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 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, common stock equivalents 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 nine months
For the years ended December 31, ended September 30,
----------------------------------- ----------------------
1997 1998 1999 1999 2000
----------- ---------- ---------- ---------- ----------
(unaudited)
<S> <C> <C> <C> <C> <C>
Net income (loss)
available to common
shareholders........... $ (6,018) $ (15,710) $ 18,228 $ 19,530 $ (4,345)
=========== ========== ========== ========== ==========
Basic--weighted average
shares................. 10,567,762 11,925,785 14,285,714 14,285,714 14,285,714
=========== ========== ========== ========== ==========
Diluted--weighted
average shares 10,567,762 11,925,785 14,285,714 14,285,714 14,285,714
=========== ========== ========== ========== ==========
Net income (loss) per
share:
Basic:
Net loss before
extraordinary item... $ (0.57) $ (1.32) $ (0.77) $ (0.68) $ (0.30)
Extraordinary gain,
net of income taxes.. -- -- 2.05 2.05 --
----------- ---------- ---------- ---------- ----------
Net income (loss) per
common share........... $ (0.57) $ (1.32) $ 1.28 $ 1.37 $ (0.30)
=========== ========== ========== ========== ==========
Diluted:
Net income (loss)
before extraordinary
item................. $ (0.57) $ (1.32) $ (0.77) $ (0.68) $ (0.30)
Extraordinary gain,
net of income taxes.. -- -- 2.05 2.05 --
----------- ---------- ---------- ---------- ----------
Net income (loss) per
common share........... $ (0.57) $ (1.32) $ 1.28 $ 1.37 $ (0.30)
=========== ========== ========== ========== ==========
</TABLE>

F-17
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

Major Customers

The Company sells a portion of its oil and gas to end users through various
gas marketing companies. Four 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 $4.8
million, $12.4 million, $4.6 million and $4.6 million or 66%, 61%, 12% and 16%
for the periods ended December 31, 1997, 1998, 1999 and September 30, 1999
respectively. A second company's purchases totaled $1.7 million or 23% for the
year ended December 31, 1997. The third company's purchases totaled $18.6
million, $14.0 million and $29.7 million or 48%, 48% and 42% for the periods
ended December 31, 1999 and September 30, 1999 and 2000 respectively. The
fourth company's purchases totaled $7.3 million, $4.3 million and $25.1 million
or 19%, 15% and 35% for the periods ended December 31, 1999 and September 30,
1999 and 2000 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>
Nine months
Years ended December ended
31, September 30,
------------------------ ---------------
1997 1998 1999 1999 2000
------ ------ ------ ------ ------
(unaudited)
<S> <C> <C> <C> <C> <C>
Before any valuation allowance:
Statutory federal income tax
rate........................... (35.00)% (35.00)% 35.00% 35.00% (35.00)%
State income taxes, net of
federal benefit................ (0.32) (0.32) 0.32 0.33 (0.32)
Adjustment to valuation
allowance...................... 35.31 35.31 (46.53) (41.48) 0.00
Nondeductible and other......... 0.01 0.01 0.05 0.00 0.07
------ ------ ------ ------ ------
0.00% 0.00% (11.16)% (6.15)% (35.25)%
====== ====== ====== ====== ======
</TABLE>

At December 31, 1997 and 1998, the Company had determined that it was more
likely than not the deferred tax assets would not be realized. During 1997 and
1998, the valuation allowance increased by $2.0 million and $5.5 million,
respectively. 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, 1998 and 1999 and September 30, 2000, are as follows (in
thousands):

<TABLE>
<CAPTION>
December 31,
---------------
1998 1999 September 30, 2000
------ ------- ------------------
(unaudited)
<S> <C> <C> <C>
Deferred tax assets (liabilities):
Net operating loss carryforwards........ $7,804 $ 3,800 $ 7,075
Minimum tax credit carryforwards........ -- 229 229
Fixed asset basis differences........... (439) (2,379) (3,709)
State taxes............................. 71 17 39
Other................................... 195 391 751
------ ------- -------
Total deferred tax assets............. 7,631 2,058 4,385
Valuation allowance for deferred tax
assets................................... (7,631) -- --
------ ------- -------
Net deferred tax assets............... $ -- $ 2,058 $ 4,385
====== ======= =======
</TABLE>

F-18
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

At December 31, 1997, 1998, and 1999, the Company had net operating loss
carryforwards for federal income tax purposes of approximately $1 million, $22
million and $11 million, respectively, which are available to offset future
federal taxable income through 2018.

(8) Commitments and Contingencies

The Company is subject to various legal proceedings and claims that arise in
the ordinary course of business. In the opinion of management, the amount of
liability, if any, with respect to these actions would not materially affect
the financial position, results of operation or cash flows of the Company.

In October 2000, we entered into a letter of intent with BP Exploration
Operating Company Limited 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 Block 49/12a, including the Venture
Field, a 100% interest in Block 47/10b, and an 86% interest in Blocks 43/22a,
43/22c and 43/17c. The letter of intent provides that we would pay BP an
aggregate of (Pounds)2,500,000, approximately $3.6 million, for the three
properties at closing. We will make additional payments to BP 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. The Company does 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 the Company cannot estimate when such production levels may be
achieved.

The Company has commitments under an operating lease agreement for office
space. Total rent expense for the year ended December 31, 1997, 1998 and 1999
was approximately $44,000, $0.1 million and $0.1 million, respectively. At
December 31, 1999, the future minimum rental payments due under the lease are
as follows (in thousands amounts):

<TABLE>
<S> <C>
2000.................................................................... $145
2001.................................................................... 179
2002.................................................................... 187
2003.................................................................... 194
2004 and beyond......................................................... 260
----
Total................................................................. $965
====
</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 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.
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

F-19
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

into income as earned over the life of the contract. At December 31, 1999 the
deferred revenue amount was $1.7 million. 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
remaining balance of the deferred obligation was $0.2 million at December 31,
1999, and $0.1 million at September 30, 2000. The premium we pay to American
Citigas 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 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 $97,875 and $152,125 for the periods ended
December 31, 1999 and September 30, 2000, 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 none, $0.5 million, $0.6 million and $0.3
million in general and administrative expense for the periods ended
December 31, 1997, 1998 and 1999 and September 30, 2000.

(11) Supplementary Financial Information on Natural Gas and Oil 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, 1997, 1998, and 1999.

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,
-----------------------
1997 1998 1999
------- ------- -------
<S> <C> <C> <C>
Property costs:
Acquisition costs.................................. $ 1,105 $12,070 $25,274
Development costs.................................. 38,256 23,866 30,777
------- ------- -------
Total costs incurred............................. $39,361 $35,936 $56,051
======= ======= =======
</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.

F-20
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (unaudited)

Proved natural gas and oil reserve quantities at December 31, 1997, 1998,
and 1999, 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.

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,
-----------------------
1997 1998 1999
------ ------ -------
<S> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of the year................................ 34,411 40,526 46,424
Revisions of previous estimates...................... (7,319) (8,411) 3,033
Extensions and discoveries........................... 291 -- 2,257
Purchase of properties............................... 20,491 24,059 58,816
Disposition of properties............................ (4,635) (724) --
Production........................................... (2,713) (9,026) (16,533)
------ ------ -------
Proved reserves at the end of the year............. 40,526 46,424 93,997
====== ====== =======
Proved developed reserves:
Beginning of year................................ 12,822 31,080 39,728
End of year...................................... 31,080 39,728 67,314
</TABLE>

<TABLE>
<CAPTION>
Barrels of oil,
condensate, and
natural
gas liquids at
December 31,
-----------------
1997 1998 1999
---- ---- -----
<S> <C> <C> <C>
Proved developed and undeveloped reserves (in thousands):
Beginning of the year..................................... 730 942 586
Revisions of previous estimates........................... (444) 29 (131)
Extensions and discoveries................................ 2 -- --
Purchase of properties.................................... 689 9 1,362
Disposition of properties................................. (19) (243) --
Production................................................ (16) (151) (128)
---- ---- -----
Proved reserves at the end of the year.................. 942 586 1,689
==== ==== =====
Proved developed reserves:
Beginning of year..................................... 14 678 579
End of year........................................... 678 579 710
</TABLE>

F-21
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (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,
--------------------------------
1997 1998 1999
-------- -------- --------
<S> <C> <C> <C>
Future cash inflows...................... $121,024 $106,772 $272,047
Future operating expenses................ (16,158) (18,730) (40,794)
Future development costs................. (12,973) (18,432) (48,204)
-------- -------- --------
Future net cash flows.................. 91,893 69,610 183,049(/2/)
Future income taxes...................... (13,708) -- (27,611)
-------- -------- --------
Future net cash flows after income
taxes................................. 78,185 69,610 155,438
10% annual discount per annum............ (13,487) (8,302) (26,732)
-------- -------- --------
Standardized measure of discounted
future net cash flows................. $ 64,698 $ 61,308(/1/) $128,706
======== ======== ========
</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 flows are computed by applying year-end prices of natural gas
and oil to year-end quantities of proved natural gas and oil reserves. Future
operating expenses and development costs are computed primarily by the
Company's petroleum engineers by estimating the expenditures to be incurred in
developing and producing the Company's proved natural gas and oil reserves at
the end of the year, based on the year-end costs and assuming continuation of
existing economic conditions. Future income taxes are based on year-end
statutory rates, adjusted for tax basis and applicable tax credits. A discount
factor of 10 percent was used to reflect the timing of future net cash flows.
The standardized measure of discounted future net cash flows is not intended to
represent the replacement cost or fair market value of the Company's natural
gas and oil properties. An estimate of fair value would also take into account,
among other things, the recovery of reserves not presently classified as
proved, anticipated future changes in prices and costs, and a discount factor
more representative of the time value of money and the risks inherent in
reserve estimates.

F-22
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 1997, 1998 and 1999 and September 30, 1999 and 2000 (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,
----------------------------
1997 1998 1999
-------- -------- --------
<S> <C> <C> <C>
Beginning of year................................ $ 36,460 $ 64,698 $ 61,308
Sales of oil and gas, net of production costs.... (5,846) (17,217) (29,394)
Net changes in income taxes...................... (13,708) 13,708 (27,611)
Net changes in price and production costs........ 7,374 (20,272) 9,931
Revisions of quantity estimates.................. (15,505) (12,318) 4,176
Accretion of discount............................ 3,646 7,841 6,131
Development costs incurred....................... 27,424 19,780 15,550
Changes in estimated future development.......... (7,154) (13,129) (15,664)
Purchases of minerals-in-place................... 40,604 25,136 105,514
Sales of minerals-in-place....................... (7,280) (4,886) --
Extensions and discoveries....................... 348 -- 218
Changes in production rates, timing and other.... (1,665) (2,033) (1,453)
-------- -------- --------
28,238 (3,390) 67,398
-------- -------- --------
End of year.................................... $ 64,698 $ 61,308 $128,706
======== ======== ========
</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.

F-23
<PAGE>

INDEPENDENT AUDITORS' REPORT

The Board of Directors:
ATP Oil & Gas Corporation:

We have audited the accompanying statement of revenues and direct operating
expenses for the nine months ended September 30, 1999 for the Eugene Island 30
Property (as described in note 1). This statement is the responsibility of ATP
Oil & Gas Corporation's management. Our responsibility is to express an opinion
on this statement based on our audit.

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

The accompanying statement was prepared as described in note 2 for the
purpose of complying with certain rules and regulations of the Securities and
Exchange Commission (SEC) for inclusion in certain SEC regulatory reports and
filings and is not intended to be a complete financial presentation.

In our opinion, the statement referred to above presents fairly, in all
material respects, the revenues and direct operating expenses of the Eugene
Island 30 property for the nine months ended September 30, 1999, in conformity
with generally accepted accounting principles.

/s/ KPMG LLP

September 11, 2000
Houston, Texas

F-24
<PAGE>

EUGENE ISLAND 30

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

For the nine months ended September 30, 1999

(In thousands)

<TABLE>
<S> <C>
Revenues:
Oil revenues........................................................... $ 493
Gas revenues........................................................... 1,623
Plant liquids revenues................................................. 155
------
2,271
------
Direct operating expenses................................................ 702
------
Revenues in excess of direct operating expenses...................... $1,569
======
</TABLE>

See accompanying notes to statement of revenues and direct operating expenses.

F-25
<PAGE>

EUGENE ISLAND 30

NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

September 30, 1999

(1) Basis of Presentation

The accompanying financial statement presents the revenues and direct
operating expenses of the Eugene Island 30 property (EI-30), an oil and gas
property acquired by ATP Oil & Gas Corporation from Eugene Offshore Holdings
LLC for $16.3 million. The acquisition, which closed on September 24, 1999,
resulted in the Company receiving a 100% working interest and a 82% net revenue
interest in EI-30. The EI-30 property is located in the offshore area of the
Louisiana gulf coast.

The accompanying financial statement was derived from the historical
accounting records of Eugene Offshore Holdings LLC. Direct operating expenses
include all costs associated with production, marketing and distribution,
including selling and direct overhead other than costs of general corporate
activities.

(2) Omitted Historical Financial Information

Full historical financial statements, including, depletion, depreciation and
amortization expense, general and administrative expense, income tax expense
and interest expense have not been presented herein.

(3) Commitments and Contingencies

Management is not aware of any legal, environmental or other commitments or
contingencies that would have a material adverse impact on the operations of
the property.

(4) Related Party Transactions

Magellan Exploration LLC operated EI-30 in exchange for a management fee
while Juniper Energy, LP, an affiliate of Eugene Offshore Holdings LLC, handled
fund disbursements. Fees incurred related to these services totalling $103,065
are reflected in direct operating expenses.

(5) Capital Expenditures

There were no capital expenditures related to EI-30 during the period.

(6) Supplemental Oil and Gas Reserve Information (Unaudited)

Estimated total proved oil and gas reserves of EI-30 at September 30, 1999
are based on reserve estimates included in the Company's reserve report
prepared by Ryder Scott Company, L.P. independent petroleum engineers as of
December 31, 1999. No comparable estimates were available for prior periods.
Therefore, reserves for September 30, 1999 have been calculated by adjusting
December 31, 1999 amounts for the year's activities and, consequently, no
revisions of previous estimates have been reflected. The future net cash flows
from production of these proved reserve quantities were computed by applying
September 30, 1999 prices of $24.04 per Bbl for oil and $2.89 per Mcf for gas
to estimated future production of proved oil and gas reserves less the
estimated future expenditures (based on current costs) as of September 30,
1999.

F-26
<PAGE>

EUGENE ISLAND 30

NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES--(Continued)

September 30, 1999

<TABLE>
<CAPTION>
Nine months
ended
September 30,
1999
--------------
Oil Gas
(Mbbl) (MMcf)
------ ------
<S> <C> <C>
Proved reserves(1):
Beginning of year........................................... 1,134 14,629
Production.................................................. (31) (775)
----- ------
End of period............................................. 1,103 13,854
Proved developed reserves:
Beginning of year........................................... 228 6,219
----- ------
End of period............................................... 197 5,444
===== ======
</TABLE>
--------
(1) As of November 30, 2000 proved reserves were 460 Mbbl and 8,808 MMcf. The
decline is a result of production of 100 Mbbl and 1,687 MMcf, an assignment
of an overriding royalty interest to certain key officers of 22 Mbbl and
277 MMcf, and a negative revision of approximately 521 Mbbl and 8,083 MMcf.
This negative revision is primarily a result of a steeper decline curve on
the wells than was originally expected.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Reserves as of September 30, 1999 (in thousands):

<TABLE>
<S> <C>
Future cash inflows.......................................... $66,517
Future production costs...................................... (9,030)
Future development costs..................................... (9,900)
-------
Future net inflows before income taxes..................... 47,587
Future income taxes.......................................... (10,880)(/1/)
-------
Future net inflows after income taxes...................... 36,707
10% discount factor.......................................... (6,686)
-------
Standardized measure of discounted future net cash flows
before income taxes....................................... $30,021
=======
</TABLE>

Changes to Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Reserves for the nine month period ended September 30, 1999 (in
thousands):

<TABLE>
<S> <C>
Standardized measure, beginning of year............................. $16,727
Sales, net of production costs.................................... (1,569)
Net changes in prices............................................. 21,214
Increase in income taxes.......................................... (8,231)
Accretion of discount............................................. 1,880
-------
Standardized measure, end of period................................. $30,021
=======
</TABLE>
--------
(1) Income taxes have been computed assuming estimated future net inflows
before income taxes less tax basis equal to the purchase price of EI-30 and
the statutory tax rate of 35%. This amount may not be indicative of actual
historical or future income taxes.

F-27
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

UNAUDITED PRO FORMA FINANCIAL INFORMATION

The unaudited pro forma financial information of the Company gives effect to
the purchase of Eugene Island 30 (EI-30). In September 1999, the Company
completed the acquisition of a 100% working interest and an 82% net revenue
interest in the property for a purchase price of $16.3 million. The total
purchase price was recorded to oil and gas properties and accounted for
pursuant to the purchase method. Subsequent to the acquisition, the Company
became the operator of the property. The acquisition was financed through the
Company's credit facility. The above transaction is reflected in the statement
of operations as if it occurred on January 1, 1999.

The following unaudited pro forma financial information is provided for
comparative purposes only and does not purport to be indicative of the results
which would actually have been obtained had the acquisition been effected on
the pro forma date, or of the results which may be obtained in the future. The
unaudited pro forma financial information in our opinion reflects all
adjustments necessary to present fairly the data for such period.

The unaudited pro forma financial information should be read in conjunction
with the historical financial statements appearing elsewhere in this
prospectus.

F-28
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

Year ended December 31, 1999
(In thousands amounts except share and per share data)

<TABLE>
<S> <C> <C> <C> <C>
<CAPTION>
Pro Forma
ATP Historical EI-30(A) adjustments Pro Forma
-------------- -------- ----------- ----------
<S> <C> <C> <C> <C>
Revenues:
Oil and gas production...... $ 34,981 2,271 -- 37,252
Gas sold--marketing......... 7,703 -- -- 7,703
Gain on sale of oil and gas
properties................. 287 -- -- 287
---------- ----- ------ ----------
42,971 2,271 -- 45,242
---------- ----- ------ ----------
Costs and operating expenses
Lease operating expenses.... 5,587 702 -- 6,289
Gas purchased--marketing.... 7,402 -- -- 7,402
General and administrative
expenses................... 3,541 -- -- 3,541
Depreciation, depletion and
amortization............... 22,521 -- 732 (B) 23,253
Impairment of oil and gas
properties................. 7,509 -- -- 7,509
---------- ----- ------ ----------
46,560 702 732 47,994
---------- ----- ------ ----------
Net income (loss) from
operations............... (3,589) 1,569 (732) (2,752)
---------- ----- ------ ----------
Other income (expense):
Interest income............. 202 -- -- 202
Interest expense............ (9,399) -- (1,222)(C) (10,621)
---------- ----- ------ ----------
(9,197) -- (1,222) (10,419)
---------- ----- ------ ----------
Net income (loss) before
extraordinary items...... (12,786) 1,569 (1,954) (13,171)
Income tax benefit (expense) 1,829 -- 135 (D) 1,964
---------- ----- ------ ----------
Net income (loss) before
extraordinary items...... (10,957) 1,569 (1,819) (11,207)
========== ===== ====== ==========
Basic loss per common share:
Loss before extraordinary
item....................... $ (0.77) (0.78)
========== ==========
Diluted loss per common share:
Loss before extraordinary
item....................... $ (0.77) (0.78)
========== ==========
Weighted average number of
common shares:
Basic....................... 14,285,714 14,285,714
========== ==========
Diluted..................... 14,285,714 14,285,714
========== ==========
</TABLE>

See accompanying notes to unaudited pro forma consolidated financial
statements.

F-29
<PAGE>

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENT

(A) To reflect the revenues and direct operating expenses related to the EI-30
property acquired on September 24, 1999.

(B) To adjust historical depreciation, depletion and amortization based on the
unit of production method to amounts that would have been included in the
financial statements effective January 1, 1999 had the acquisition of the
EI-30 property been consummated on such date.

(C) To adjust historical interest expense at the Company's current interest
rate of 10.0% based on a purchase price of $16.3 million to estimated
amounts that would have been included in the financial statements effective
January 1, 1999 had the acquisition of the EI-30 property been consummated
on such date. If the interest rate would have fluctuated 1/8%, the interest
would have increased/decreased by $15,281 for the year ended December 31,
1999.

(D) To reflect income tax expense related to the pro forma adjustments at the
statutory rate of 35%.

F-30
<PAGE>

7,500,000 Shares

[ATP LOGO]

ATP OIL & GAS CORPORATION

Common Stock

-----------
PROSPECTUS
, 2001
-----------

Lehman Brothers

CIBC World Markets

Dain Rauscher Wessels

Raymond James & Associates, Inc.

Fidelity Capital Markets
<PAGE>

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

The expenses of this offering, other than underwriting discount, are
estimated to be as follows:

<TABLE>
<S> <C>
Securities and Exchange Commission registration fee................. $ 45,540
NASD filing fee..................................................... 17,750
Nasdaq National Market listing fee.................................. 95,000
Legal fees and expenses............................................. 300,000
Accounting fees and expenses........................................ 300,000
Engineering fees and expenses....................................... 100,000
Printing expenses................................................... 100,000
Transfer agent fees................................................. 25,000
Miscellaneous....................................................... 16,710
----------
TOTAL........................................................... $1,000,000
==========
</TABLE>

Item 14. Indemnification of Directors and Officers

Article 2.02.A.(16) and Article 2.02-1 of the Texas Business Corporation Act
and Article IX of the Amended and Restated Bylaws of ATP Oil & Gas Corporation
(the "Company") provide the Company with broad powers and authority to
indemnify its directors and officers and to purchase and maintain insurance for
such purposes. Pursuant to such statutory and Bylaw provisions, the Company has
purchased insurance against certain costs of indemnification that may be
incurred by it and by its officers and directors.

Additionally, Article IX of the Company's Restated Articles of Incorporation
provides that a director of the Company is not liable to the Company for
monetary damages for any act or omission in the director's capacity as
director, except that Article IX does not eliminate or limit the liability of a
director for (i) breaches of such director's duty of loyalty to the Company and
its shareholders, (ii) acts or omissions not in good faith or which involve
intentional misconduct or knowing violation of law, (iii) transactions from
which a director receives an improper benefit, irrespective of whether the
benefit resulted from an action taken within the scope of the director's
office, (iv) acts or omissions for which liability is specifically provided by
statute and (v) acts relating to unlawful stock repurchases or payments of
dividends.

Article IX also provides that any subsequent amendments to Texas statutes
that further limit the liability of directors will inure to the benefit of the
directors, without any further action by shareholders. Any repeal or
modification of Article IX shall not adversely affect any right of protection
of a director of the Company existing at the time of the repeal or
modification.

The underwriting agreement to be entered into in connection with this
offering will provide that the Underwriters shall indemnify the Company, its
directors and certain officers of the Company against liabilities resulting
from information furnished by or on behalf of the Underwriters specifically for
use in the Registration Statement. See "Item 17. Undertakings" for a
description of the Commission's position regarding such indemnification
provisions.

II-1
<PAGE>

Item 15. Recent Sales of Unregistered Securities

The Company has sold and issued (without payment of any selling commission
to any person) the following securities in the past three years giving effect
to the reverse stock split of the Company's common stock. During the fiscal
years ended December 31, 1997 and 1998 the Company issued 612,976 and 3,215,815
shares of common stock, respectively, upon the exercise of options held by its
employees for an aggregate price of $2,000 in 1997 and $13,000 in 1998. During
the fiscal years ended December 31, 1998 and 1999 and through July 31, 2000,
the Company granted options to its employees to purchase at an exercise price
of $1.40, 440,714 shares of common stock, 18,571 shares of common stock and
23,393 shares of common stock, respectively. During August and September 2000,
we issued to our employees, options to purchase a total of 322,858 shares of
common stock at an exercise price of $3.85.

The sale of the above securities described in Item 15 were exempt from
registration under the Securities Act in reliance on Rule 701 under the
Securities Act.

Item 16. Exhibits and Financial Statement Schedules

(a) Exhibits:
<TABLE>
<C> <S>
1.1 --Form of Underwriting Agreement
+3.1 --Amended and Restated Articles of Incorporation
+3.2 --Restated Bylaws
+4.1 --Form of Common Stock Certificate
5.1 --Opinion of Vinson & Elkins L.L.P.
+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
+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
+10.3 --Credit Agreement between ATP Oil & Gas Corporation and Aquila
Energy Capital Corporation, dated April 9, 1999, effective as of
March 31, 1999
+10.4 --First Amendment to Credit Agreement, dated April 9, 1999, by and
between ATP Oil & Gas Corporation and Aquila Energy Capital
Corporation
+10.5 --Second Amendment to Credit Agreement, dated April 9, 1999, by and
between ATP Oil & Gas Corporation and Aquila Energy Capital
Corporation
+10.6 --Gas Service Agreement, dated December 31, 1998, between American
Citigas Company and ATP Energy, Inc.
+10.7 --Marketing & Natural Gas Purchase Agreement, dated December 1,
1998, between ATP Energy, Inc. and El Paso Energy Marketing
Company
+10.8 --Purchase and Sale Agreement, effective as of May 1, 1999, between
Eugene Offshore Holdings, LLC and ATP Oil & Gas Corporation
+10.9 --ATP Oil & Gas Corporation 1998 Stock Option Plan
+10.10 --First Amendment to the ATP Oil & Gas Corporation 1998 Stock
Option Plan
+21.1 --Subsidiaries of ATP Oil & Gas Corporation
23.1 --Consent of KPMG LLP
+23.2 --Consent of Ryder Scott Company, L.P.
+23.3 --Consent of Schlumberger Holditch-Reservoir Technologies
Consulting Services
+23.4 --Consent of Scott Pickford Group Limited
23.8 --Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1
hereto)
+24.1 --Power of Attorney (included on the signature page to this
Registration Statement)
27 --Financial Data Schedule
</TABLE>
--------

+ Previously filed.
(b) Consolidated Financial Statement Schedules:

All schedules are omitted because the required information is inapplicable
or the information is presented in the Consolidated Financial Statements or
related notes.

II-2
<PAGE>

Item 17. Undertakings

Insofar as indemnification for liabilities arising under the Securities Act
may be permitted to directors, officers and controlling persons of the
Registrant pursuant to the foregoing provisions, or otherwise, the Registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Securities
Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
Registrant of expenses incurred or paid by a director, officer or controlling
person of the Registrant in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, the Registrant will, unless in
the opinion of its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the question whether
such indemnification by it is against public policy as expressed in the
Securities Act and will be governed by the final adjudication of such issue.

The undersigned Registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the
information omitted from the form of prospectus filed as part of this
Registration Statement in reliance upon Rule 430A and contained in a form of
prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h)
under the Securities Act shall be deemed to be part of this Registration
Statement as of the time it was declared effective.

(2) For purposes of determining any liability under the Securities Act, each
post-effective amendment that contains a form of prospectus shall be deemed to
be a new registration statement relating to the securities offered therein, and
the offering of such securities at that time shall be deemed to be the initial
bona fide offering thereof.

The undersigned registrant hereby undertakes to provide to the underwriter
at the closing specified in the underwriting agreements, certificates in such
denominations and registered in such names and required by the underwriter to
permit prompt delivery to each purchaser.

II-3
<PAGE>

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the
Registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Houston,
State of Texas, on the 11th day of January, 2001.

ATP OIL & GAS CORPORATION

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

II-4
<PAGE>

POWER OF ATTORNEY

KNOW 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
(including post-effective amendments) to this Registration Statement and any
registration statement for the same offering filed pursuant to Rule 462 under
the Securities Act of 1933 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 hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this
Registration Statement has been signed below by the following persons in the
capacities indicated on the 11th day of January, 2001.

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

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

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

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

* Director
______________________________________
Carol E. Overbey

* Director
______________________________________
Gerard Swonke

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

Director
______________________________________
Robert C. Thomas

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

/s/ Albert L. Reese, Jr.
*By: ____________________________
Albert L. Reese, Jr.
Attorney-in-Fact

II-5
<PAGE>

INDEX TO EXHIBITS

<TABLE>
<C> <S>
1.1 --Form of Underwriting Agreement
+3.1 --Amended and Restated Articles of Incorporation
+3.2 --Restated Bylaws
+4.1 --Form of Common Stock Certificate
5.1 --Opinion of Vinson & Elkins L.L.P.
+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
+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
+10.3 --Credit Agreement between ATP Oil & Gas Corporation and Aquila
Energy Capital Corporation, dated April 9, 1999, effective as of
March 31, 1999
+10.4 --First Amendment to Credit Agreement, dated April 9, 1999, by and
between ATP Oil & Gas Corporation and Aquila Energy Capital
Corporation
+10.5 --Second Amendment to Credit Agreement, dated April 9, 1999, by and
between ATP Oil & Gas Corporation and Aquila Energy Capital
Corporation
+10.6 --Gas Service Agreement, dated December 31, 1998, between American
Citigas Company and ATP Energy, Inc.
+10.7 --Marketing & Natural Gas Purchase Agreement, dated December 1,
1998, between ATP Energy, Inc. and El Paso Energy Marketing
Company
+10.8 --Purchase and Sale Agreement, effective as of May 1, 1999, between
Eugene Offshore Holdings, LLC and ATP Oil & Gas Corporation
+10.9 --ATP Oil & Gas Corporation 1998 Stock Option Plan
+10.10 --First Amendment to the ATP Oil & Gas Corporation 1998 Stock
Option Plan
+21.1 --Subsidiaries of ATP Oil & Gas Corporation
23.1 --Consent of KPMG LLP
+23.2 --Consent of Ryder Scott Company, L.P.
+23.3 --Consent of Schlumberger Holditch-Reservoir Technologies
Consulting Services
+23.4 --Consent of Scott Pickford Group Limited
23.8 --Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1
hereto)
+24.1 --Power of Attorney (included on the signature page to this
Registration Statement)
27 --Financial Data Schedule
</TABLE>
--------

+ Previously filed.

II-6