<PAGE>
As filed with the Securities and Exchange Commission on September 18, 2000
Registration No. 333-
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------------
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. [_]
CALCULATION OF REGISTRATION FEE
<TABLE>
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-------------------------------------------------------------------------------------------------------
<CAPTION>
Title of each class of Proposed Maximum Amount of
securities to be registered Aggregate Offering Price (1) Registration Fee (2)
-------------------------------------------------------------------------------------------------------
<S> <C> <C>
Common Stock, par value $.001 per share............. $172,500,000 $45,540
-------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------
</TABLE>
(1) Estimated solely for purposes of calculating the registration fee pursuant
to Rule 457(o) under the Securities Act of 1933.
(2) Calculated pursuant to Rule 457(a) under the Securities Act of 1933 based
on an estimate of the proposed maximum offering price.
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.
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<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. +
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
Subject to Completion, dated September 18, 2000
PROSPECTUS
Shares
ATP OIL & GAS CORPORATION
Common Stock
--------------------------------------------------------------------------------
This is our initial public offering of common stock. We are offering up to
shares of common stock. No public market currently exists for our shares.
We propose to list our common stock on the Nasdaq National Market under the
symbol "ATPG." The anticipated price range is $ to $ per share.
Investing in the shares involves risks. "Risk Factors" begin on page 9.
<TABLE>
<CAPTION>
Per
Share Total
------ -----------
<S> <C> <C>
Public Offering Price....................................... $ $
Underwriting Discount....................................... $ $
Proceeds to ATP Oil & Gas Corporation....................... $ $
</TABLE>
We have granted the underwriters a 30-day option to purchase up to
additional shares of common stock on the same terms and conditions as set forth
above 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 , 2000.
--------------------------------------------------------------------------------
Lehman Brothers
CIBC World Markets
Dain Rauscher Wessels
Raymond James & Associates, Inc.
Fidelity Capital Markets
a division of National
Financial Services LLC
, 2000
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Prospectus Summary....................................................... 1
Risk Factors ............................................................ 9
Cautionary Statement About Forward-Looking Information................... 16
Use Of Proceeds.......................................................... 17
Dividend Policy.......................................................... 17
Dilution................................................................. 18
Capitalization........................................................... 19
Selected Historical and Pro Forma Financial Data......................... 20
Management's Discussion And Analysis Of Financial Condition And Results
Of Operations........................................................... 22
</TABLE>
<TABLE>
<CAPTION>
Page
----
<S> <C>
Business And Properties.................................................... 31
Management ................................................................ 47
Related Party Transactions ................................................ 53
Principal Shareholders .................................................... 54
Description Of Capital Stock .............................................. 55
Shares Eligible For Future Sale ........................................... 58
Underwriting .............................................................. 60
Legal Matters ............................................................. 62
Experts ................................................................... 62
Where You Can Find More Information ....................................... 63
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. You should not assume that the information contained in this
prospectus is accurate as of any date other than the date on the front cover of
this prospectus.
Until , 2000, 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.
We use some standard industry terms in this prospectus to describe our
operations:
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.
MMBls. 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.
Proved developed reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
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 completion or recompletion.
i
<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. Also, unless otherwise indicated, this
prospectus 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.
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 we have
achieved an average reserve replacement ratio of 318% for the past three years.
We have leasehold and other interests in 40 offshore blocks, 20 platforms and
50 wells, including five subsea wells, in the federal waters of the Gulf of
Mexico. We operate 45 of these 50 wells, including all of the subsea wells, and
90% of our offshore platforms. Based on our proved reserves at December 31,
1999, our average working interest in our properties is approximately 90%.
As of December 31, 1999, our estimated net proved reserves were 104.1 Bcfe,
90% of which was natural gas. At December 31, 1999, our net proved reserves had
an estimated pre-tax PV-10 of $156.3 million based on prices of $2.28 per MMbtu
of natural gas and $25.59 per barrel of oil. We produced approximately 17.3
Bcfe in 1999, an increase of 74% over the previous year. At December 31, 1999,
proved developed reserves comprised 69% of our total reserves and our reserve
life index for total proved reserves was six years.
As a result of our acquisition and development strategy, from 1995 to 1999,
we increased our net proved reserves at a compound annual growth rate of 262%,
production at a compound annual growth rate of 206%, oil and gas revenues at a
compound annual growth rate of 182% and EBITDA at a compound annual growth rate
of 371%. Since 1996, our EBITDA has consistently averaged 60% to 70% of total
revenues. 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, generally water depths of 600 to 3,000 feet, and
into the Southern Gas Basin of the U.K. North Sea.
We were listed on the 1999 Inc. 500 as the 21st fastest growing U.S.
privately held company and the fastest growing energy company. During 2000, we
received a Growing with Technology Award from Inc./Cisco for innovative
utilization of technology in offshore oil and gas development. In 1999, we
received the Best Field Improvement Award by Hart's Oil and Gas World for
utilizing a horizontal subsea wellhead with an 11 mile direct hydraulic
umbilical to develop a project in 520 feet of water. 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.
1
<PAGE>
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:
. substantial existing infrastructure and geographic proximity to well-
developed markets for natural gas and oil;
. a large number of properties that major oil companies, exploration-
oriented independents and others consider non-strategic; and
. a history of government stability with 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:
. Acquisition. 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.
. Development and Production. We focus on developing projects in the
shortest time possible between initial investment and first revenue
generated in order to maximize our rate of return. Since we usually
operate the properties in which we acquire a working interest and begin a
development program with proved reserves, we are able to expeditiously
commence a project's development. We typically initiate new development
projects by simultaneously obtaining the various required components such
as the pipeline and the production platform or subsea well completion
equipment. This strategy, combined with our ability to rapidly evaluate
and implement a project's requirements, allows us to complete the
development project and commence production as quickly and efficiently as
possible.
Our Strengths
. Operating Efficiency. We emphasize a low overhead and operating expense
structure. For the six months ended June 30, 2000, our lease operating
expense was $0.50 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.
. Technical Expertise and Significant Experience. We have assembled an
experienced management team and technical staff with specific expertise
in offshore property development, including the implementation of subsea
completion technology. Our staff has the following characteristics:
. 61% of our employees have over 20 years of industry experience,
2
<PAGE>
. 84% hold a bachelor's degree with 62% holding an advanced degree
and/or professional certification,
. 67% of those who hold masters degrees hold an MBA or MS in Finance.
. 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 % of ATP on a fully diluted basis.
Significant Properties
We have summarized our most significant properties in the tables below.
<TABLE>
<CAPTION>
As of 6/30/00 July 2000
ATP Net Proved Reserves (1)Average Daily
Significant ATP Net Revenue ---------------------- Production
Producing Properties Working Interest Interest Bcfe % Gas % Developed (MMcfe) (2)
-------------------- ---------------- ----------- ---- ----- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Gulf of Mexico-Shelf
High Island A-354....... 100% 76% 16.8 100 71 8.7
Eugene Island 30........ 100% 80% 16.1 68 36 8.7
Vermilion 410 Field..... 100% 77% 15.2 100 93 11.8
East Cameron 240........ 100% 82% 6.4 92 100 3.7
Brazos 544.............. 100% 62% 4.6 98 100 6.5
High Island A-253....... 100% 82% 3.5 92 100 9.6
Other properties........ 16.9
----
Total................. 65.9
====
</TABLE>
<TABLE>
<CAPTION>
As of 6/30/00
Net Proved Undeveloped
Reserves (3)
-----------------------
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
West Cameron 635........ 100% 80% 7.7 94 First quarter 2001
Vermilion 63............ 100% 76% 4.4 94 Fourth quarter 2000
Main Pass 282........... 100% 79% 3.9 92 First quarter 2001
Vermilion 260........... 100% 79% 3.8 97 Fourth quarter 2000
West Cameron 492........ 50% 36% 3.4 100 Fourth quarter 2000
Gulf of Mexico-Shallow-
Deep Waters
Garden Banks 409
(Ladybug).............. 50% 39% 19.4 35 Second quarter 2001
Southern Gas Basin-U.K.
North Sea
Block 49/12a (Venture)
(4).................... 50% 50% 18.1 99 First quarter 2002
</TABLE>
--------
(1) Estimates of net proved reserves are based on our third party independent
reserve reports as of December 31, 1999, mechanically adjusted to June 30,
2000 to account for projected production.
(2) Reflects our net revenue interest in each property.
(3) Estimates of net proved undeveloped reserves for our properties under
development are derived from our internal reserve reports.
(4) We have an executed letter of intent to acquire 50% of this property and
expect to close the acquisition in the fourth quarter of 2000.
3
<PAGE>
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 replace
our reserves may not be available, our reserve estimates are inherently
uncertain, 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 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.
4
<PAGE>
The Offering
<TABLE>
<C> <S>
Common stock offered by ATP........................ shares
Common stock to be outstanding after the offering.. shares
Use of proceeds.................................... We intend to use the net
proceeds of this offering
to repay all outstanding
indebtedness under our
credit agreements, to fund
our acquisition and
development program for
the remainder of 2000 and
a portion of 2001, and for
general corporate
purposes.
Proposed Nasdaq National Market symbol............. ATPG
</TABLE>
The number of shares of common stock outstanding after the offering does not
include outstanding options to purchase a total of 827,000 shares of common
stock as of August 31, 2000, at prices of either $1.00 or $2.75 per share. This
number also does not include options to purchase shares at the initial
public offering price that are expected to be granted concurrently with the
closing of this offering.
5
<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 Six Months Ended
December 31, June 30,
-------------------------------------------------- ------------------------
Pro Forma
1997 1998 1999 1999 1999 2000
----------- ----------- ----------- ----------- ----------- -----------
(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 $ 18,323 $ 36,252
Gas sold--marketing.... -- -- 7,703 7,703 3,423 2,919
----------- ----------- ----------- ---------- ----------- -----------
Total revenues........ 7,359 20,410 42,684 44,955 21,746 39,171
Costs and operating
expenses:
Lease operating........ 1,513 3,193 5,587 6,289 2,484 6,422
Gas purchased--
marketing............. -- -- 7,402 7,402 3,361 2,802
General and
administrative........ 1,170 2,591 3,541 3,541 1,550 2,738
Depreciation, depletion
and amortization...... 4,206 17,442 22,521 22,744 12,667 16,695
Impairment of oil and
gas properties........ 5,787 5,072 7,509 7,509 2,442 6,255
Other.................. -- -- -- -- -- 749
----------- ----------- ----------- ---------- ----------- -----------
Total operating
expenses............. 12,676 28,298 46,560 47,485 22,504 35,661
----------- ----------- ----------- ---------- ----------- -----------
Net income (loss) from
operations............. (5,317) (7,888) (3,876) (2,530) (758) 3,510
Other income (expense):
Gain on sale of oil and
gas properties........ 304 -- 287 287 -- 33
Interest income........ 207 141 202 202 48 255
Interest expense....... (1,212) (7,963) (9,399) (10,487) (6,078) (5,146)
----------- ----------- ----------- ---------- ----------- -----------
Income (loss) before
income taxes and
extraordinary item..... (6,018) (15,710) (12,786) (12,528) (6,788) (1,348)
Income tax benefit...... -- -- 1,829 1,739 (281) 474
----------- ----------- ----------- ---------- ----------- -----------
Income (loss) before
extraordinary item..... (6,018) (15,710) (10,957) $ (10,789) (7,069) (874)
==========
Gain on extinguishment
of debt, net of tax.... -- -- 29,185 29,185 --
----------- ----------- ----------- ----------- -----------
Net income (loss)....... $ (6,018) $ (15,710) $ 18,228 $ 22,116 $ (874)
=========== =========== =========== =========== ===========
Weighted average number
of common shares
outstanding:
Basic.................. 14,794,867 16,696,099 20,000,000 20,000,000 20,000,000 20,000,000
Diluted................ 14,794,867 16,696,099 20,000,000 20,000,000 20,000,000 20,000,000
Income (loss) per common
share before
extraordinary item:
Basic.................. $ (0.54)
Diluted................ $ (0.54)
Net income (loss) per
common share:
Basic.................. $ (0.41) $ (0.94) $ 0.91 $ 1.11 $ (0.04)
Diluted................ $ (0.41) $ (0.94) $ 0.91 $ 1.11 $ (0.04)
Other Financial Data:
EBITDA (1).............. $ 5,187 $ 14,767 $ 26,643 $ 28,212 $ 14,399 $ 26,748
EBITDA margin (2)....... 70% 72% 62% 63% 66% 68%
</TABLE>
6
<PAGE>
<TABLE>
<CAPTION>
As of
June 30, 2000
--------------
(in thousands)
<S> <C>
Balance Sheet Data:
Cash and cash equivalents........................................ $ 8,195
Working capital.................................................. 5,309
Net oil and gas properties....................................... 90,029
Total assets..................................................... 128,844
Total liabilities................................................ 132,499
Shareholders' deficit............................................ (3,655)
</TABLE>
--------
(1) EBITDA is defined as net income (loss) before interest expense, income
taxes, depreciation, depletion and amortization, and impairment of oil and
gas properties. 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 EBITDA calculation may not be comparable to other similarly
titled measures of other companies. We have presented EBITDA because of its
wide acceptance as a financial indicator.
(2) Represents EBITDA divided by total revenues.
7
<PAGE>
Summary Reserve and Operating Information
The table below presents our summary reserve information and our summary
operating data 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 Schlumberger Holditch-Reservoir Technologies
Consulting Services for the years 1998 and 1999. For additional information,
please read "Business and Properties--Natural Gas and Oil Reserves," "--
Volumes, Prices and Operating Expenses" and note 10 of the notes to our
consolidated financial statements.
Our PV-10 at December 31, 1999, 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 December 31, 1999, discounted at 10% per annum, was
determined by using prices of $2.28 per MMBtu of natural gas and $25.59 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 10 of the notes to our consolidated
financial statements.
<TABLE>
<CAPTION>
As of December 31,
--------------------------
1997 1998 1999
------- ------- --------
<S> <C> <C> <C>
Reserve Data:
Estimated proved reserves:
Natural gas (MMcf).............................. 40,526 46,424 93,997
Oil and condensate (MBbls)...................... 942 586 1,689
Total (MMcfe).................................. 46,181 49,940 104,128
Proved developed reserves as a percentage of
proved reserves.................................. 76.1% 86.5% 68.7%
Estimated future net revenues before income taxes
(in thousands)................................... $91,893 $69,610 $183,047
PV-10 (in thousands).............................. $78,406 $61,308 $156,315
Standardized measure of discounted future net cash
flows (in thousands)............................. $64,698 $61,308 $128,706
</TABLE>
<TABLE>
<CAPTION>
Years Ended Six Months
December 31, Ended June 30,
--------------------- ----------------
1997 1998 1999 1999 2000
------ ------ ------ ------- -------
<S> <C> <C> <C> <C> <C>
Operating Data:
Production:
Natural gas (MMcf).................. 2,713 9,026 16,533 8,848 11,804
Oil and condensate (MBbls).......... 16 151 128 89 178
------ ------ ------ ------- -------
Total (MMcfe)...................... 2,807 9,933 17,301 9,385 12,874
Average sales price per unit:
Natural gas revenues from production
(per Mcf).......................... $2.60 $ 2.07 $ 2.23 $ 1.99 $ 3.18
Effects of hedging activities (per
Mcf)............................... -- -- (0.23) (0.05) (0.47)
------ ------ ------ ------- -------
Average gas price.................. $ 2.60 $ 2.07 $ 2.00 $ 1.94 $ 2.71
Oil and condensate revenues from
production (per Bbl)............... $18.75 $11.50 $15.37 $ 12.93 $ 27.97
Effects of hedging activities (per
Bbl)............................... -- -- -- -- (4.10)
------ ------ ------ ------- -------
Average oil price.................. $18.75 $11.50 $15.37 $ 12.93 $ 23.87
Total revenues from production (per
Mcfe).............................. $ 2.62 $ 2.05 $ 2.24 $ 2.00 $ 3.30
Effects of hedging activities (per
Mcfe).............................. -- -- (0.22) (0.05) (0.48)
------ ------ ------ ------- -------
Total average price (per Mcfe)..... $ 2.62 $ 2.05 $ 2.02 $ 1.95 $ 2.82
Expenses (per Mcfe):
Lease operating..................... $ 0.54 $ 0.32 $ 0.32 $ 0.26 $ 0.50
General and administrative.......... 0.42 0.26 0.20 0.17 0.21
Depreciation, depletion and
amortization--
natural gas and oil properties..... 1.50 1.76 1.30 1.35 1.30
</TABLE>
8
<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 replace our reserves may not be available, which
would prevent us from continuing our business strategy and reduce our cash flow
and revenues.
Our natural gas and oil reserves decline as reserves are produced. Our
business strategy requires us to replace our reserves through acquisitions of
proved natural gas and oil properties and through further development of our
existing properties. However, properties may not be available for acquisition
in the future on terms we find attractive. 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. In addition, our
development activities may not be successful. If we fail to replace reserves,
our level of production and cash flows will be adversely impacted.
Estimating reserves and future net cash flow is difficult to do with any
certainty. Any material inaccuracies in reserve estimates or underlying
assumptions will materially affect the quantities and net present value of our
reserves.
This prospectus contains estimates of our proved natural gas and oil
reserves and the estimated future net revenues from such reserves. Our
estimates 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. The process of estimating our natural gas and oil reserves is
complex. 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.
Actual future production, oil and natural gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves will most likely vary from our estimates. 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.
At December 31, 1999, approximately 31% of our estimated proved reserves
were undeveloped. Recovery of undeveloped reserves requires significant capital
expenditures and successful drilling operations. The reserve data assumes that
we will make significant capital expenditures to develop our reserves. Although
we have prepared estimates of our oil and natural gas reserves and the costs
associated with these reserves in accordance with industry standards, the
estimated costs may not be accurate, development may not occur as scheduled and
the actual results may not be as estimated.
In addition, you should not construe PV-10 as the current market value of
the estimated oil and natural gas reserves attributable to our properties. We
have based the estimated discounted future net cash flows from
9
<PAGE>
proved reserves on prices and costs as of the date of the estimate, in
accordance with SEC regulations, whereas actual future prices and costs may be
materially higher or lower. Many factors will affect actual future net cash
flow, including:
. prices for oil and natural gas;
. the amount and timing of actual production;
. curtailments or increases in consumption by oil and natural gas
purchasers; and
. changes in governmental regulations or taxation.
The timing of the production of oil and natural gas properties and of the
related expenses affect the timing of actual future net cash flow from proved
reserves and, thus, their actual PV-10. In addition, the 10% discount factor,
which we are required to calculate PV-10 for reporting purposes, is not
necessarily the most appropriate discount factor given actual interest rates
and risks to which our business or the oil and natural gas industry in general
are subject.
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. 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. Because approximately 90% of our estimated proved
reserves as of December 31, 1999 were natural gas reserves, our financial
results are more sensitive to movements in natural gas prices.
10
<PAGE>
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 $5.3 million in 1997, $7.9 million in 1998 and $3.9 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.
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 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.
11
<PAGE>
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.
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. 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. In addition,
pollution and environmental risks generally are not fully insurable. If a
significant accident or other event occurs and is not fully covered by
insurance, it could adversely affect our operations.
We may be unable to identify liabilities associated with the properties that we
acquire or obtain protection from sellers against them.
Our growth is due largely to acquisitions of proved undeveloped properties
which we subsequently develop. The successful acquisition and development of
proved undeveloped properties require an assessment of a number of factors.
These factors include recoverable reserves, future natural gas and oil prices,
operating costs and potential environmental and other liabilities and other
factors. The assessments are inexact and their accuracy is 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 addition, the review does not always permit us to become
sufficiently familiar with the properties to fully assess their deficiencies
and capabilities. 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
12
<PAGE>
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.
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.
We may incur substantial impairment writedowns.
We review our proved oil and gas properties for impairment 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 carrying value and the fair value of the property on our
balance sheet. 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. Under the
successful efforts method of accounting we must review our properties on a
field by field basis. 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 half of 2000 of approximately $6.3 million. If natural
gas and oil prices decrease 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. Please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Overview."
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 August 31, 2000, we have 11
geologist/geophysicists, engineers and other technical personnel in our Houston
office. We have hired five geologist/geophysicists, engineers 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 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. 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;
13
<PAGE>
. 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 may have difficulty financing our planned growth.
We have experienced and expect to continue to experience substantial capital
expenditure and working capital needs, particularly as a result of our
acquisition and development program. Our capital expenditures on oil and gas
properties were $39.4 million during 1997, $35.9 million during 1998, $56.1
million during 1999 and $40.6 million through the first six months of 2000. We
expect to continue to require significant capital expenditures during the
remainder of 2000 and in 2001 to fund our anticipated reserve replacement needs
and our growth strategy. If low natural gas and oil prices, operating
difficulties or other factors, many of which are beyond our control, cause our
revenues or cash flows from operations to decrease, we may be limited in our
ability to spend the capital necessary to complete our development program. In
the event our resources or cash flows decrease, we may require additional
financing, in addition to cash generated from our operations, to fund our
planned growth. We cannot be certain that additional financing will be
available to us 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.
Our hedging decisions may impact our potential gains from changes in commodity
prices and may result in losses.
To reduce our exposure to fluctuations in the prices of natural gas and oil,
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 in some circumstances including the following:
. production is less than expected;
. 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.
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.
Furthermore, if we choose not to engage in hedging arrangements in the future,
we may be more adversely affected by changes in natural gas and oil prices than
had we engaged in hedging arrangements.
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
14
<PAGE>
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 % of our outstanding shares of common stock
and would own approximately % if they exercised all of their options to
purchase 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.
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 shares
of our common stock. This includes the shares we are selling in this
offering, all of which may be resold in the public market immediately unless
purchased in the offering by one of our affiliates. All of the remaining
20,000,000 shares are owned by our executive officers and directors. An
additional 158,333 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 20,158,333 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, 137,334 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 shareholder action by written consent, 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, the Texas Business Corporation Act imposes
restrictions on mergers and other business combinations between us and any
holder of 20% or more of our outstanding common stock.
15
<PAGE>
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.
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING INFORMATION
Some of the statements in this prospectus contains forward-looking
information. These statements express, or are based on, our expectations about
future events. These include such matters as:
. financial position;
. 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;
. budgets;
. amount, nature and timing of capital expenditures;
. drilling of wells and other planned development activities;
. natural gas and oil reserves;
. timing and amount of future production of natural gas and oil;
. operating costs and other expenses;
. future net cash flow and anticipated liquidity;
. property acquisitions; and
. marketing of natural gas and oil.
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 these forward-
looking statements, you should keep in mind these risk factors and the other
cautionary statements in this prospectus. Our forward-looking statements speak
only as of the date made.
16
<PAGE>
USE OF PROCEEDS
We estimate that we will receive net proceeds of $ million, or $
million if the underwriters exercise their over-allotment option in full, from
the sale of the 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 $ 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 $ million to repay all of our outstanding debt under
our credit facility and our development program credit agreement;
. approximately $ million to fund our acquisition and development
program for the remainder of 2000 and a portion of 2001; and
. approximately $ million for general corporate purposes.
Until we use the proceeds from this offering, we will deposit them in
short-term interest bearing accounts.
Our credit facility matures in September 2001. At June 30, 2000, the
average interest rate on borrowings outstanding under the credit facility was
10.125% 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.
Our development program credit agreement matures in November 2002. At June
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.
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.
17
<PAGE>
DILUTION
Our net tangible book value at June 30, 2000 was approximately $(3.7)
million, or $(0.18) 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 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 June
30, 2000 would have been $ per share of common stock. This represents an
immediate and substantial increase in the net tangible book value of $ per
share to existing shareholders and an immediate dilution of $ 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................. $
Net tangible book value per share at June 30, 2000............ (0.18)
Increase per share attributable to new investors..............
-----
Net tangible book value per share after this offering...........
--------
Dilution per share to new investors............................. $
========
</TABLE>
The following table sets forth, at June 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 $ per
share:
<TABLE>
<CAPTION>
Total Average
Shares Purchased Consideration Price
------------------ -------------- Per
Number Percent Amount Percent Share
---------- ------- ------ ------- -------
(in thousands)
<S> <C> <C> <C> <C> <C>
Existing shareholders................. 20,000,000 % $ 52 % $0.0026
New investors.........................
Total............................... 100% $ 100%
</TABLE>
These computations assume that no additional shares are issued upon exercise
of the underwriters' over-allotment option or outstanding stock options granted
under our stock option plans. As of August 31, 2000, options to purchase
422,500 shares of our common stock at $1.00 per share and 404,500 shares of our
common stock at $2.75 per share had been granted under our stock option plans
and we intend to grant options to purchase an additional shares of common
stock at the initial public offering price concurrently with the closing of
this offering. In the event the shares currently subject to the
underwriters' over-allotment option and options under our stock option plan
were included in the calculations above, the net tangible book value per share
before this offering would be $ , the net tangible book value per share
after this offering would be $ and the dilution per share to new investors
would be $ . In addition, the average price per share paid by existing
shareholders would increase to $ per share.
18
<PAGE>
CAPITALIZATION
The following table presents our cash, capitalization and other information
as of June 30, 2000 on two bases:
. on an actual basis; and
. on an as adjusted basis to reflect our sale of the shares of common
stock in this offering at an assumed offering price of $ 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
June 30, 2000
------------------
As
Actual Adjusted
-------- --------
(in thousands)
<S> <C> <C>
Cash........................................................ $ 8,195 $
======== ========
Long-term debt and non-recourse borrowings ................. $101,966 $
Shareholders' equity(1):
Preferred stock, $0.001 par value, 10,000,000 shares
authorized; no shares issued or outstanding................ --
Common stock, $0.001 par value, 100,000,000 shares
authorized; 20,000,000 shares issued and outstanding,
actual; shares issued and outstanding, as
adjusted................................................... 20
Additional paid-in capital.................................. 32
Accumulated deficit......................................... (3,707)
--------
Total shareholders' equity (deficit)...................... (3,655)
-------- --------
Total capitalization.................................... $ 98,311 $
======== ========
</TABLE>
--------
(1) The descriptions of our common and preferred stock reflect changes to our
capital structure that will occur prior to the closing of this offering.
19
<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 six-month periods ended June 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 six-month period ended June 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.
20
<PAGE>
<TABLE>
<CAPTION>
Six Months Ended
Years Ended December 31, June 30,
--------------------------------------------------------------------------------------------------
Pro Forma
1995 1996 1997 1998 1999 1999 1999 2000
---------- ---------- ----------- ----------- ----------- ----------------------- ----------
(unaudited) (unaudited) (unaudited)
(in thousands, except share and per share data)
<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 $ 18,323 $ 36,252
Gas sold--marketing... -- -- -- -- 7,703 7,703 3,423 2,919
---------- ---------- ----------- ----------- ----------- ----------- ---------- ----------
Total revenues...... 543 3,009 7,359 20,410 42,684 44,955 21,746 39,171
Costs and operating
expenses:
Lease operating....... 264 308 1,513 3,193 5,587 6,289 2,484 6,422
Gas purchased--
marketing............ -- -- -- -- 7,402 7,402 3,361 2,802
General and
administrative....... 233 505 1,170 2,591 3,541 3,541 1,550 2,738
Depreciation,
depletion and
amortization......... 5 1,672 4,206 17,442 22,521 22,744 12,667 16,695
Impairment of oil and
gas properties....... -- -- 5,787 5,072 7,509 7,509 2,442 6,255
Other................. -- -- -- -- -- -- -- 749
---------- ---------- ----------- ----------- ----------- ----------- ---------- ----------
Total operating
expenses............. 502 2,485 12,676 28,298 46,560 47,485 22,504 35,661
---------- ---------- ----------- ----------- ----------- ----------- ---------- ----------
Net income (loss) from
operations............ 41 524 (5,317) (7,888) (3,876) (2,530) (758) 3,510
Other income (expense):
Gain on sale of oil
and gas properties... -- -- 304 -- 287 287 -- 33
Interest income....... 8 45 207 141 202 202 48 255
Interest expense...... -- (107) (1,212) (7,963) (9,399) (10,487) (6,078) (5,146)
---------- ---------- ----------- ----------- ----------- ----------- ---------- ----------
Income (loss) before
income taxes and
extraordinary item.... 49 462 (6,018) (15,710) (12,786) (12,528) (6,788) (1,348)
Income tax benefit
(expense)............. (105) (1) -- -- 1,829 1,739 (281) 474
---------- ---------- ----------- ----------- ----------- ----------- ---------- ----------
Income (loss) before
extraordinary item.... (56) 461 (6,018) (15,710) (10,957) $ (10,789) (7,069) (874)
===========
Gain on extinguishment
of debt, net of tax... -- -- -- -- 29,185 29,185 --
---------- ---------- ----------- ----------- ----------- ---------- ----------
Net income (loss)...... $ (56) $ 461 $ (6,018) $ (15,710) $ 18,228 $ 22,116 $ (874)
========== ========== =========== =========== =========== ========== ==========
Weighted average number
of common shares
outstanding:
Basic................. 10,563,697 11,543,718 14,794,867 16,696,099 20,000,000 20,000,000 20,000,000 20,000,000
Diluted............... 10,563,697 11,543,718 14,794,867 16,696,099 20,000,000 20,000,000 20,000,000 20,000,000
Income (loss) per
common share before
extraordinary item:
Basic................. $ (0.54)
Diluted............... $ (0.54)
Net income (loss) per
common share:
Basic................. $ (0.01) $ 0.04 $ (0.41) $ (0.94) $ 0.91 $ 1.11 $ (0.04)
Diluted............... $ (0.01) $ 0.04 $ (0.41) $ (0.94) $ 0.91 $ 1.11 $ (0.04)
Other Financial Data:
EBITDA (1)............. $ 54 $ 2,241 $ 5,187 $ 14,767 $ 26,643 $ 28,212 $ 14,399 $ 26,748
EBITDA margin (2)...... 10% 74% 70% 72% 62% 63% 66% 68%
</TABLE>
<TABLE>
<CAPTION>
As of December 31, As of
---------------------------------------- June 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 $ 8,195
Working capital......... (71) 2,574 3,340 (4,853) 13,719 5,309
Net oil and gas
properties............. 360 5,201 34,073 47,612 72,278 90,029
Total assets............ 592 9,074 49,625 61,354 107,054 128,844
Total long-term debt.... -- -- 42,194 62,690 91,723 101,966
Total liabilities....... 359 8,369 54,936 82,363 109,835 132,499
Shareholders' equity
(deficit).............. 234 705 (5,311) (21,009) (2,781) (3,655)
</TABLE>
-------
(1) EBITDA is defined as net income (loss) before interest expense, income
taxes, depreciation, depletion and amortization, and impairment of oil and
gas properties. 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 EBITDA calculation may not be comparable to other
similarly titled measures of other companies. We have presented EBITDA
because of its wide acceptance as a financial indicator.
(2) Represents EBITDA divided by total revenues.
21
<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 have acquired 32 blocks since the beginning of 1997 and have
increased production from 2,807 MMcfe in 1997 to 17,301 MMcfe in 1999. Our
production in the first half of 2000 was 12,874 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 half 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 non-recourse to us and our other properties. At June
30, 2000, we had $80.0 million outstanding under our project-based development
facility and $22.0 million outstanding under our bank credit facility. We
expect to repay all of our outstanding indebtedness with the proceeds of this
offering. Future capital requirements will be met through a combination of
proceeds from this offering, cash from operations or borrowings under existing
or new debt facilities.
From time to time, we have utilized and may continue to utilize hedging
transactions with respect to a portion of our natural gas and oil production to
achieve a more predictable cash flow as well as to reduce our exposure to price
fluctuations. These transactions generally are swaps or price collars and are
entered into with major financial institutions or commodities trading
institutions. We entered into our first hedging transactions in January 1999 in
connection with our bank credit facility. Our development program credit
agreement requires us to hedge a portion of our expected production from the
properties financed through such facility. At June 30, 2000, we had hedged
approximately 14,303,000 MMbtu, or 92% of our expected remaining 2000 natural
gas production from our current portfolio of properties, and 14,527,000 MMbtu,
or 44% of our expected 2001 natural gas production from our current portfolio
of properties. The average price of hedged production is approximately $2.95
per MMbtu for 2000 and $3.03 per MMbtu for 2001. We had no natural gas hedges
in effect beyond October 2001. At June 30, 2000, we had hedged approximately
101,300 bbls of oil, or 47% of our expected remaining 2000 oil production from
our current portfolio of properties. The average price of hedged oil production
is $23.99 per bbl. We have no oil hedges in effect beyond December 2000. Based
on prices in effect at June 30, 2000, the above hedge positions would reduce
expected future net revenues by $21.4 million in the last six months of 2000
and $11.3 million in 2001.
We use the successful efforts method of accounting for our investments in
oil and natural gas properties. Under this method, we capitalize lease
acquisition costs and intangible drilling and development costs on successful
wells and development nonproductive wells. Depreciation, depletion and
amortization of these capitalized costs are computed separately for each field
based on the unit of production method using only proved natural gas and oil
reserves.
The successful efforts method of accounting requires us to review each of
our natural gas and oil properties on a field level for impairment when
circumstances indicate that the capitalized costs less accumulated
depreciation, depletion and amortization (also referred to as "carrying value")
of the property may
22
<PAGE>
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 $6.3 million in the first six
months of 2000.
Since June 30, 1999, we have granted options to employees to purchase 33,500
shares of common stock at $1.00 per share and 404,500 shares of common stock at
$2.75 per share. At August 31, 2000 we have outstanding options to purchase a
total of 827,000 shares. 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
a material amount of compensation expense following our initial public offering
relating to previous option grants. We will recognize as expense any difference
between the exercise price for certain of these options and the fair market
value of our stock as of the date of grant. Under applicable accounting
guidelines, the fair market value of our common stock will be measured based
upon our initial public offering price. 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 $ , we
estimate that we will incur a non-cash compensation expense of approximately
$ in 2000, approximately $ in 2001 and approximately $ 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
Six Months Ended June 30, 2000 Compared to Six Months Ended June 30, 1999
Oil and Gas Revenue. Our revenue from natural gas and oil production for the
six months ended June 30, 2000 increased over the first six months of 1999 by
97.8%, from $18.3 million to $36.3 million. This increase resulted from
increases of 39.7% in realized natural gas prices and 84.6% in realized oil
prices as well as a 37.2% increase in production. The increase in production
volumes from 9,385 MMcfe to 12,874 MMcfe was attributable to nine properties
that were on production during the first six months of 2000 that were not on
production during the same period in 1999. Hedging transactions reduced oil and
natural gas revenues by $6.3 million, or $0.48 per Mcfe, in the first half of
2000 and $0.4 million, or $0.05 per Mcfe, in the first half of 1999.
Marketing Revenue. During the six months ended June 30, 2000, revenues from
natural gas marketing activities amounted to $2.9 million, a decrease of $0.5
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 $2.10 in 1999 to $3.21 in
2000. For more information regarding this marketing arrangement, please read
"Subsidiary Activities" below.
Lease Operating Expense. Our lease operating expense for the six months
ended June 30, 2000 increased 158.5% from $2.5 million to $6.4 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 half of 1999, we held a
working interest in 20 producing blocks (24 producing wells/19.2 net wells).
During the first half of 2000, we held a working interest in 26 producing
blocks (33 producing wells/29.6 net wells). For the first six months of 1999,
our net production from these wells was 8,848 MMcf and 89,378 bbls. For the
first six months of 2000, our net production from these wells
23
<PAGE>
was 11,804 MMcf and 178,361 bbls, an increase of 2,956 MMcf and 88,983 bbls.
Workover spending increased from $0.3 million in the first half of 1999 to $2.0
million in the first half 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 $0.26 to $0.50.
Gas Purchased-Marketing. Our cost of purchased gas was $2.8 million the
first six months of 2000 compared to $3.4 million for the first six months in
1999. The daily gas contract amount in our third party marketing arrangement
decreased from 9,000 MMBtu/day in the first half of 1999 to 5,000 MMBtu/day in
the first half of 2000. Lower volumes were offset by an increase in the average
gas cost from $2.05 per MMbtu in the 1999 period to $3.08 per MMbtu in the 2000
period.
General and Administrative Expense. General and administrative expense
increased to $2.7 million for the first six months of 2000 compared to $1.6
million for the first half of 1999. The primary reason for the increase was the
result of compensation and related expenses increasing from $0.8 million to
$1.4 million period to period. Our total employees increased from 16 at June
30, 1999 to 23 at June 30, 2000. On an Mcfe basis, general and administrative
expense increased from $0.17 to $0.21 from period to period.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense increased 31.8% during the six months ended June 30,
2000 from $12.7 million to $16.7 million. The average depreciation, depletion
and amortization rate was $1.30 per Mcfe during the first half of 2000 compared
with $1.35 per Mcfe in the first half of 1999.
Impairment Expense. For the first half of 2000, we recorded an impairment of
$6.3 million related to one property. During the first half of 1999, we
recorded an impairment of $2.4 million related to two properties. The
impairment in 2000 was the result of a reduction in recoverable reserves from
the one property. The impairment in 1999 was primarily the result of depressed
oil and gas prices and a reduction in recoverable reserves for the two
properties.
Other Income (Expense). For the six months ended June 30, 2000, interest
expense was $5.1 million compared to $6.1 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 six months of 2000 we capitalized $0.7 million of interest. We
did not capitalize any interest in the first six months of 1999.
Other expense for the first six months of 2000 also includes an expense of
$0.8 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 charge in the first half of 2000 reflects such a position in excess
of expected production.
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.
24
<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 the properties in
1999 and four of the 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.
25
<PAGE>
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
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 properties and $5.8 million in 1997 for three 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.
26
<PAGE>
Liquidity and Capital Resources
We have financed our acquisition and development activity through a
combination of project-based development and bank borrowing as well as cash
from operations. At June 30, 2000, we had $80.0 million outstanding under our
current development program credit agreement and $22.0 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 Six Months 2000.......................................... 24.7 million
</TABLE>
Development Program Credit Agreement
We entered into our current non-recourse development program credit
agreement in April 1999. From April 1999 through August 2000, we included ten
projects in this financing and obtained total funding of $94.0 million. The
lender receives 90% of the monthly net revenues (after payment of operating
costs) from the pledged properties. From April 1999 through August 2000, we
made payments to the lender of $25.7 million under the facility. The average
interest rate was 11.5% in 1999 and 12.5% during the first six months of 2000.
At December 31, 1999, the amount outstanding was $75.3 million at an interest
rate of 12.0%. At June 30, 2000, the amount outstanding was $80.0 million at an
interest rate of 13.0%. The lender has a future specified overriding royalty
interest in the properties that serve as collateral under the facility. This
overriding royalty interest applies to each property that serves as collateral
and does not become effective until after all of the indebtedness has been paid
in full or when a property is removed from the collateral base. Each overriding
royalty is only for a specified volume of production from the property and is
contingent on the future performance of the property.
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 June 30, 2000 had increased to $39.0 million. As of
June 30, 2000, we had $22.0 million outstanding under the credit facility
resulting in $17.0 million in availability. Our borrowings under the credit
facility have increased to $34.5 million as of August 31, 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 10.1% at June 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;
. allow the ratio of our current assets to our current liabilities to be
less than 1:1 at any time.
27
<PAGE>
. allow our ratio of debt to our consolidated EBITDA for four consecutive
quarters to be greater than 3 to 1.
. allow our ratio of 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 August 31, 2000, we were in compliance with all of the 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
Gas
Period Properties
------ -------------
<S> <C>
1997........................................................... $39.4 million
1998........................................................... 35.9 million
1999........................................................... 56.1 million
First Six Months 2000.......................................... 40.6 million
</TABLE>
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 budgeted $29.0 million for
development projects in inventory. At June 30, 2000, we had incurred capital
expenditures of $40.6 million.
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 of
our outstanding indebtedness. 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.
28
<PAGE>
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 August 31, 2000, we had the following financial hedges on natural gas
outstanding:
<TABLE>
<CAPTION>
Average Average
Period MMBtu/Day $/MMBtu
------ --------- -------
<S> <C> <C>
Fourth quarter 2000.......................................... 69,700 $3.02
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.
As of August 31, 2000, we have the following financial hedges on oil
outstanding:
<TABLE>
<CAPTION>
Average Average
Period Bbls/Day $/Bbl
------ -------- -------
<S> <C> <C>
Fourth quarter 2000(2)........................................ 500 24.39
</TABLE>
--------
(2) We have no oil hedges beyond December 2000.
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 receive 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.
These transactions are designated as hedges and accounted for on the accrual
basis with realized gains and losses recognized in revenues when the related
production occurs. The estimated fair value of the above listed open hedging
arrangements as of August 31, 2000 is an unrealized loss of approximately $22.2
million for the fourth quarter of 2000 and $11.3 million in 2001 using natural
gas and oil prices as of August 31, 2000.
29
<PAGE>
Subsidiary Activities
In 1998, our wholly-owned subsidiary, ATP Energy, entered into an agreement
with an unrelated entity to purchase gas over a ten-year period. 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 at a premium to the Gas Daily Henry Hub Index; however, the seller is
required to reimburse ATP Energy for this premium during the term of the
contract. In addition, ATP Energy received a non-refundable fee of $2.0 million
from the seller at the time of signing. ATP Energy recorded the fee as a long-
term deferred revenue at December 31, 1998. As the gas is purchased, ATP Energy
recognizes the fee over the life of the contract.
ATP Energy entered a transaction in 1998 with another unrelated entity to
sell gas for three years. The contract requires delivery of 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 Index less $0.015.
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. Since then we have
entered into a letter of intent to acquire a 50% interest in Block 49/12A, the
Venture Field, from BP Amoco. Conoco owns the other 50%. We expect to close the
acquisition transaction with BP Amoco in the fourth quarter of 2000 with
development activities on the block scheduled to begin in early 2001. We have
hired six employees for ATP Oil & Gas (UK) Limited.
30
<PAGE>
BUSINESS AND PROPERTIES
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.
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:
. substantial existing infrastructure and geographic proximity to well-
developed markets for natural gas and oil;
. a large number of properties that major oil companies, exploration-
oriented independents and others consider non-strategic; and
. a history of government stability with 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 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:
. Acquisition. 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.
. Development and Production. 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
31
<PAGE>
operate the properties in which we acquire a working interest and begin a
development program with proved reserves, we are able to expeditiously
commence a project's development. We typically initiate new development
projects by simultaneously obtaining the various required components such
as the pipeline and the production platform or subsea well completion
equipment. This strategy, combined with our ability to rapidly evaluate
and implement a project's requirements, allows us to complete the
development project and commence production as quickly and efficiently as
possible.
Our Strengths
. Operating Efficiency. We emphasize a low overhead and operating expense
structure. For the six months ended June 30, 2000, our lease operating
expense was $0.50 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.
. Technical Expertise and Significant Experience. We have assembled an
experienced management team and technical staff with specific expertise
in offshore property development, including the implementation of subsea
completion technology. Our staff has the following characteristics:
. 61% of our employees have over 20 years of industry experience,
. 84% hold a bachelor's degree with 62% holding an advanced degree
and/or professional certification,
. 67% of those who hold masters degrees hold an MBA or MS in Finance.
. 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 % of ATP on a fully diluted basis.
32
<PAGE>
Significant Properties
We have summarized our most significant properties in the tables below.
<TABLE>
<CAPTION>
As of 6/30/00 July 2000
ATP Net Proved Reserves (1)Average Daily
Significant ATP Net Revenue ---------------------- Production
Producing Properties Working Interest Interest Bcfe % Gas % Developed (MMcfe) (2)
-------------------- ---------------- ----------- ---- ----- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Gulf of Mexico-Shelf
High Island A-354....... 100% 76% 16.8 100 71 8.7
Eugene Island 30........ 100% 80% 16.1 68 36 8.7
Vermilion 410 Field..... 100% 77% 15.2 100 93 11.8
East Cameron 240........ 100% 82% 6.4 92 100 3.7
Brazos 544.............. 100% 62% 4.6 98 100 6.5
High Island A-253....... 100% 82% 3.5 92 100 9.6
Other properties........ 16.9
----
Total................. 65.9
====
</TABLE>
<TABLE>
<CAPTION>
As of 6/30/00
Net Proved Undeveloped
Reserves (3)
----------------------
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
West Cameron 635........ 100% 80% 7.7 94 First quarter 2001
Vermilion 63............ 100% 76% 4.4 94 Fourth quarter 2000
Main Pass 282........... 100% 79% 3.9 92 First quarter 2001
Vermilion 260........... 100% 79% 3.8 97 Fourth quarter 2000
West Cameron 492........ 50% 36% 3.4 100 Fourth quarter 2000
Gulf of Mexico-Shallow-
Deep Waters
Garden Banks 409
(Ladybug).............. 50% 39% 19.4 35 Second quarter 2001
Southern Gas Basin-U.K.
North Sea
Block 49/12a
(Venture) (4).......... 50% 50% 18.1 99 First quarter 2002
</TABLE>
--------
(1) Estimates of net proved reserves are based on our third party independent
reserve reports as of December 31, 1999, mechanically adjusted to June 30,
2000 to account for projected production.
(2) Reflects our net revenue interest in each property.
(3) Estimates of net proved undeveloped reserves for our properties under
development are derived from our internal reserve reports.
(4) We have an executed letter of intent to acquire 50% of this property and
expect to close the acquisition in the fourth quarter of 2000.
33
<PAGE>
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 16.8 Bcf as
of June 30, 2000, net to our interest. During July 2000, this well produced 8.5
MMcf per day and 27 bbls of condensate per day, net to our interest.
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 10.9 Bcf and 872,300 bbls of oil as
of June 30, 2000, net to our interest. During July 2000, the property produced
6.7 Mcf per day and 330 bbls of oil and condensate per day, net to our
interest, from the C-1 and C-2 wells. As of August 2000, average flowing tubing
pressures were 2,100 psia for the C-1 well and 3,450 psia for the C-2 well.
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 a cash payment plus a retained production payment in 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.
The Vermilion 410 Field had estimated proved reserves of approximately 15.2
Bcf of natural gas as of June 30, 2000, net to our interest. The four offshore
blocks that comprise this field are East Cameron Block 362, Vermilion Block
34
<PAGE>
389, Vermilion Block 409 and Vermilion Block 410. The production platform is
located in Vermilion Block 410 in approximately 365 feet of water. During July
2000, the Vermilion 410 Field produced 11.8 MMcf per day, net to our interest.
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 5.9 Bcf and
82,300 bbls of condensate as of June 30, 2000, net to our interest. During July
2000, the well produced 0.7 MMcf per day and 503 bbls of oil per day, net to
our interest, with an average flowing tubing pressure of 1,900 psia.
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 4.5 Bcf and 17,500
bbls of condensate as of June 30, 2000, net to our interest. Current proved
reserves in the Big Hum A sand exclude the attic volume of the reservoir and
the area and volume of the adjacent fault block. The well's performance
indicates that the B-1 well may drain some portion of these currently non-
proved reserves. During July 2000, the B-1 well produced 6.2 MMcf per day and
42 bbls of oil and condensate per day, net to our interest, with an average
flowing tubing pressure of 3,300 psia.
High Island A-253
In May and June 1999, we acquired High Island A-253, with less than 10 days
before its lease expired, from Vastar Resources, Inc. and two other companies.
We paid $35,000 and an overriding royalty interest for this property.
As operator of the property, we were able to obtain an extension of the
primary lease term from the Minerals Management Service. We proceeded to
develop the lease by completing the temporarily abandoned well, installing
subsea completion equipment and laying an umbilical and flowline from the
subsea well to an existing platform at High Island A-270.
35
<PAGE>
High Island A-253 began production in March 2000. It is located in
approximately 130 feet of water and had estimated proved reserves of
approximately 3.3 Bcf of natural gas and 47,300 bbls of condensate as of June
30, 2000, net to our interest.
During July 2000, this well produced 8.8 MMcf per day and 131 bbls of
condensate per day, net to our interest. In July 2000, we also acquired another
property, Main Pass 282, from one of the previous owners of High Island A-253.
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.
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. The development costs
are expected to be approximately $7.5 million.
West Cameron 635 had estimated proved reserves of approximately 7.3 Bcf of
natural gas and 72,700 bbls of condensate as of June 30, 2000, net to our
interest. We anticipate first production in the first quarter of 2001.
Vermilion 63
We acquired a 100% working interest in Vermilion 63 in July 2000 for an
overriding royalty interest. This property is located in approximately 40 feet
of water. The property was acquired pursuant to a farmout from El Paso
Production GOM Inc. There was no production from this property as of the date
we acquired it. We are the operator of this property.
Vermilion 63 had less than 60 days until its lease was to expire when we
acquired it. We were able to commence drilling operations in an expedited
fashion to maintain the lease and encountered two natural gas and condensate
sands in the well. We plan to develop this property by completing the well,
installing a small structure and installing a flowline from the structure to a
Unocal Corporation platform. Our total drilling and development cost is
estimated to be approximately $5.2 million.
Vermilion 63 had estimated proved reserves of approximately 4.1 Bcf of
natural gas and 41,200 bbls of condensate as of June 30, 2000, net to our
interest. We expect initial production to be in the fourth quarter of 2000.
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. 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 3.6 Bcf
of natural gas and 53,500 bbls of condensate as of June 30, 2000, net to our
interest. We anticipate first production in the first quarter of 2001.
36
<PAGE>
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 had 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 plan to develop 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 is estimated to be
approximately $5.7 million. This property is located in approximately 160 feet
of water.
This property had estimated proved reserves of approximately 3.7 Bcf of
natural gas and 19,300 bbls of condensate as of June 30, 2000, net to our
interest. The reserves are located in three sands at approximately 9,000 feet
true vertical depth. We anticipate first production to be in the fourth quarter
of 2000.
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 Tennessee
Gas pipeline. The total development cost net to our 50% working interest was
approximately $4.1 million. We plan to subsequently develop the #3 well.
West Cameron 492 had estimated proved reserves of approximately 3.4 Bcf of
natural gas as of June 30, 2000, net to our interest. This reserve estimate
does not include the reserves discovered in the #3 well. We expect first
production to be in the fourth quarter of 2000.
Garden Banks 409
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 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 6.8
Bcf of natural gas and 2.1 million bbls of oil as of June 30, 2000, net to our
interest.
Block 49/12a (Venture Field)
We have an executed letter of intent with BP Amoco to acquire a 50% working
interest in the Venture Field for three payments totaling $2.85 million. The
other 50% working interest is held by Conoco.
37
<PAGE>
We expect to close the transaction with BP Amoco in the fourth quarter of 2000
and to begin development activities in 2001. The Venture Field was selected as
our first development in the Southern Gas Basin of the U.K. North Sea. This
field is located offshore England in the UK Sector of the North Sea, about 80
miles northeast of Great Yarmouth.
This field had estimated proved undeveloped reserves of 17.9 Bcf of natural
gas and 35,800 bbls of condensate in three Rotliegendes sand layers as of June
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 originally
drilled to a depth of 11,620 feet in 1989 and temporarily abandoned for
development at a later time. 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 first quarter of 2002.
Natural Gas and Oil Reserves
The following table presents our estimated net proved natural gas and oil
reserves and the net present value of our reserves at December 31, 1999 based
on reserve reports prepared by Ryder Scott Company, L.P. and Schlumberger
Holditch-Reservoir Technologies Consulting Services. The present values,
discounted at 10% per annum, of estimated future net cash flows before income
taxes shown in the table are not intended to represent the current market value
of the estimated natural gas and oil reserves we own.
The present value of future net cash flows before income taxes as of
December 31, 1999 was determined by using the December 31, 1999 prices of $2.28
per MMBtu of natural gas and $25.59 per Bbl of oil.
<TABLE>
<CAPTION>
Proved Reserves
------------------------------
Developed Undeveloped Total
--------- ----------- --------
<S> <C> <C> <C>
Natural gas (MMcf)............................. 67,314 26,683 93,997
Oil and condensate (MBbls)..................... 710 979 1,689
Total proved reserves (MMcfe).................. 71,575 32,553 104,128
PV-10 (in thousands)........................... $111,866 $44,449 $156,315
</TABLE>
Our estimates of proved reserves in the table above do not differ from those
we have filed with other federal agencies. The process of estimating natural
gas and oil reserves is complex. It requires various assumptions, including
assumptions relating to natural gas and oil prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. We must
project production rates and timing of development expenditures. We analyze
available geological, geophysical, production and engineering data, and the
extent, quality and reliability of this data can vary. Therefore, estimates of
natural gas and oil reserves are inherently imprecise. Actual future
production, natural gas and oil prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable natural gas and
oil reserves most likely will vary from our estimates and these variances may
be material. Read "Risk Factors--Estimating reserves and future net cash flow
is difficult to do with any certainty."
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.
38
<PAGE>
Our business strategy is to acquire proved reserves, usually proved
undeveloped, and to bring those reserves on production as rapidly as possible.
At December 31, 1999, approximately 31% of our estimated equivalent net proved
reserves were undeveloped. Recovery of undeveloped reserves generally requires
significant capital expenditures and successful drilling 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>
1997 1998 1999
--------------------- --------------------- ------------------------
Undeveloped Developed Undeveloped Developed Undeveloped Developed
----------- --------- ----------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C>
At January 1............ 4 5 4 10 11 22
Acquisitions............ 5 - 11 8 7 1
Divestitures............ - - - - (10)(/1/) -
Undeveloped to
productive............. (5) 5 (4) 4 (2) 2
Undeveloped to
nonproductive.......... - - - - - -
----- ----- ----- ----- ----- -----
At December 31.......... 4 10 11 22 6(/2/) 25
===== ===== ===== ===== ===== =====
</TABLE>
--------
(1) Includes nine undeveloped exploration blocks that we sold. We retained a
non-working future interest in seven of those blocks.
(2) Five of these blocks were brought to production in the six months ended
June 30, 2000.
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 Six Months
December 31, Ended June 30,
-------------------- ---------------
1997 1998 1999 1999 2000
------ ------ ------ ------ -------
<S> <C> <C> <C> <C> <C>
Production:
Natural gas (MMcf).................... 2,713 9,026 16,533 8,848 11,804
Oil and condensate (MBbls)............ 16 151 128 89 178
------ ------ ------ ------ -------
Total (MMcfe)....................... 2,807 9,933 17,301 9,385 12,874
Average sales price per unit:
Natural gas revenues from production
(per Mcf)............................ $ 2.60 2.07 $ 2.23 $ 1.99 $ 3.18
Effects of hedging activities (per
Mcf)................................. -- -- (0.23) (0.05) (0.47)
------ ------ ------ ------ -------
Average gas price................... $ 2.60 $ 2.07 $ 2.00 $ 1.94 $ 2.71
Oil and condensate revenues from
production (per Bbl)................. $18.75 11.50 $15.37 $12.93 $ 27.97
Effects of hedging activities (per
Bbl)................................. -- -- -- -- (4.10)
------ ------ ------ ------ -------
Average oil price................... $18.75 $11.50 $15.37 $12.93 $ 23.87
Total revenues from production (per
Mcfe)................................ $ 2.62 $ 2.05 $ 2.24 $ 2.00 $ 3.30
Effects of hedging activities (per
Mcfe)................................ -- -- (0.22) (0.05) (0.48)
------ ------ ------ ------ -------
Total average price (per Mcfe)...... $ 2.62 $ 2.05 $ 2.02 $ 1.95 $ 2.82
Expenses (per Mcfe):
Lease operating....................... $ 0.54 $ 0.32 $ 0.32 $ 0.26 $ 0.50
General and administrative............ 0.42 0.26 0.20 0.17 0.21
Depreciation, depletion and
amortization--natural gas and oil
properties........................... 1.50 1.76 1.30 1.35 1.30
</TABLE>
39
<PAGE>
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>
For the Years Ended For the Six
December 31, Months
----------------------- Ended June
1997 1998 1999 30, 2000
------- ------- ------- -----------
<S> <C> <C> <C> <C>
Proved property acquisition costs........... $ 1,105 $12,070 $25,274 $ 2,284
Development costs........................... 38,256 23,866 30,777 38,293
------- ------- ------- -------
Total costs incurred...................... $39,361 $35,936 $56,051 $40,577
======= ======= ======= =======
</TABLE>
Drilling Activity
The following table shows our drilling and completion activity. In the
table, "gross" refers to the total wells in which we have a working interest
and "net" refers to gross wells multiplied by our working interest in such
wells. We did not complete any exploratory wells in any period presented.
<TABLE>
<CAPTION>
For the
Six
Months
For the Years Ended December 31, Ended
-------------------------------- June 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 7.0 7.0
Nonproductive..................... - - - - - - - -
---- ---- ---- ---- ---- ---- ---- ----
Total........................... 5.0 3.4 5.0 5.0 3.0 2.2 7.0 7.0
==== ==== ==== ==== ==== ==== ==== ====
</TABLE>
As of June 30, 2000, we were conducting completion activities on four gross
(three net) wells.
Productive Wells
The following table presents the number of productive natural gas and oil
wells in which we owned an interest as of June 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......................................................... 29.0 26.6
Oil................................................................. 4.0 3.0
---- -----
Total(1).......................................................... 33.0 29.6
==== =====
</TABLE>
--------
(1) Includes four gross and 3.2 net wells with multiple completions.
40
<PAGE>
Acreage
The following table presents information regarding our developed and
undeveloped acreage as of June 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............ 128,245 111,125 14,995 14,995 143,240 126,120
Gulf of Mexico-Shallow Deep
Waters......................... -- -- 5,760 2,880 5,760 2,880
Southern Gas Basin-U.K. North
Sea(1)......................... -- -- 13,900 6,950 13,900 6,950
------- ------- ------ ------ ------- -------
Total....................... 128,245 111,125 34,655 24,825 162,900 135,950
======= ======= ====== ====== ======= =======
</TABLE>
--------
(1) We have an executed letter of intent to acquire 50% of this property and
expect to close the acquisition in the fourth quarter of 2000.
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 an unrelated entity 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 less $0.015 which was $4.595 per MMBtu at August
31, 2000. 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. Three of these gas marketing companies accounted for
52% of our natural gas and oil revenues for the period ended December 31, 1997,
58% for the period ended December 31, 1998, 70% for the period ended
December 31, 1999 and 73% for the period ended June 30, 2000. Due to the nature
of natural gas and oil markets, we do not believe the loss of any one of our
customers would have a material adverse effect on our financial condition or
results of operations.
Competition
We compete with major and independent natural gas and oil companies for
property acquisitions. We also compete for the equipment and labor required to
operate and to develop these properties. Some of our competitors have
substantially greater financial and other resources. In addition, larger
competitors may be able to absorb the burden of any changes in federal, state
and local laws and regulations more easily than we can, which would adversely
affect our competitive position. These competitors may be able to pay more for
natural gas and oil properties and may be able to define, evaluate, bid for and
acquire a greater number of properties than we can. Our ability to acquire and
develop additional properties in the future will depend upon our ability to
conduct operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment. In addition,
some of our competitors have been operating in the Gulf of Mexico or in the
Southern Gas Basin of the U.K. North Sea for a much longer time than we have
and have demonstrated the ability to operate through a number of industry
cycles.
41
<PAGE>
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 the regulations promulgated thereunder by the Federal
Energy Regulatory Commission. In the past, the federal government has regulated
the prices at which natural gas could be sold. Deregulation of natural gas
sales by producers began with the enactment of the Natural Gas Policy Act 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 remain subject to extensive federal regulation. Commencing in
April 1992, the Federal Energy Regulatory Commission issued Order No. 636 and a
series of related orders, which required interstate pipelines to provide open-
access transportation on a basis that is equal for all natural gas suppliers.
The Federal Energy Regulatory Commission has stated that it intends for Order
No. 636 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, although 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,
among other things, (1) 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, (2) permits pipelines to
charge different maximum cost-based rates for peak and off-peak periods, (3)
encourages, but does not mandate, auctions for pipeline capacity, (4) requires
pipelines to implement imbalance management services, (5) restricts the ability
of pipelines to impose penalties for imbalances, overruns and non-compliance
with operational flow orders, and (6) 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, including,
among other things, whether to pursue performance-based ratemaking or other
non-cost based ratemaking techniques and whether the Federal Energy Regulatory
Commission should mandate greater standardization in terms and conditions of
service across the interstate pipeline grid. In addition, 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 and, in September 1999, issued a policy
statement establishing a presumption in favor of requiring owners of new
pipeline facilities to charge rates 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. Among the Federal Energy Regulatory Commission's
purposes in issuing such rules was
42
<PAGE>
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. As to
gatherers and other entities outside the reach of its Natural Gas Act
jurisdiction, the Federal Energy Regulatory Commission retains authority under
the Outer Continental Shelf Lands Act to exercise jurisdiction over those
entities 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. Such
leases are issued through competitive bidding, contain relatively standardized
terms and 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 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 other surety can
be substantial, and there is no assurance that bonds or other surety 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.
43
<PAGE>
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.
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 regulations thereunder 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
44
<PAGE>
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 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.
45
<PAGE>
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.
Operating Hazards and Insurance
The natural gas and oil business involves a variety of operating risks,
which could result in severe property or environmental damages or injury to
personnel. Problems associated with those risks could affect well bores,
platforms, gathering systems and processing facilities, which could adversely
affect our ability to conduct operations. Offshore operations also are 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 our development or
leasehold acquisitions, or result in loss of properties. Please read "Risk
Factors--The natural gas and oil business involves many uncertainties and
operating risks that can prevent us from realizing profits and can cause
substantial losses."
In accordance with industry practice, we maintain insurance against some,
but not all, potential risks and losses. 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. 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. In addition, pollution and environmental risks
generally are not fully insurable. If a significant accident or other event
occurs and is not fully covered by insurance, it could adversely affect our
operations.
Employees
At August 31, 2000, we had 25 full-time employees and three contract
personnel in our Houston office and three full-time employees in our London
office. Three other individuals have agreed to accept employment with us and
will be joining our London office in September 2000. 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.
46
<PAGE>
MANAGEMENT
Directors, Executive Officers and Other Key Employees
The following table sets forth the names, ages and positions of our
executive officers, directors, nominees for 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......................... 49 Vice President, General
Counsel
G. Ross Frazer............................. 44 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 Nominee
Gerard J. Swonke........................... 55 Director
Robert C. Thomas........................... 71 Director Nominee
Walter Wendlandt........................... 71 Director Nominee
</TABLE>
The following biographies describe the business experience of our executive
officers, directors, nominees for 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 recently named Senior Vice
President. From 1979 to 1986, Mr. Reese served as chief financial officer of
Plumb Oil Company and its successor, Harbert Energy Corporation. 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. Prior to 1979,
Mr. Reese served in various capacities with Capital Bank in Houston, the firm
of Peat, Marwick & Mitchell, and as a partner in Arnold, Reese & Swenson, a
Houston-based accounting firm specializing in energy clients.
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<PAGE>
Leland E. Tate (BS--Petroleum Engineering) joined us in August 2000 as
Senior Vice President, Operations, to oversee evaluations, operations,
production and marketing functions. From 1969 to 2000, Mr. Tate worked in
various capacities for Atlantic Richfield Company in reservoir and operations
engineering and management, including two years as President, ARCO North
Africa, three years as Vice President and District Manager in Lafayette,
Louisiana, where he managed operations on the outer continental shelf of the
Gulf of Mexico and in deepwater, and three years as Director of Operations for
ARCO British Ltd., where he addressed operations in the North Sea.
John E. Tschirhart (BS--Marine Transportation, JD) has served as our Vice
President, General Counsel since 1997, and was named Managing Director of ATP
Oil & Gas (UK) Limited in July 2000. Prior to joining us, he was in private
practice from 1985 to 1997, and represented business, oilfield and maritime
clients. 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 2000, he served in various
operations and engineering managerial capacities for British-Borneo
Exploration, Inc., including responsibility for the deep water Gulf of Mexico
Morpeth development in 1,700 feet of water and the Allegheny development in
3,300 feet of water. Between 1981 and 1993, he was an operations and production
engineering consultant to the offshore oil and gas industry. From 1978 to 1981,
Mr. Frazer held positions of increasing engineering responsibility for Houston
Oil & Minerals Corporation, becoming Offshore Division Operations Engineer in
1980. 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 1997 and was
recently named a Vice President. From 1995 to 1997, Mr. Godwin was in private
industry as Corporate Accounting Manager with Champion Healthcare Corporation,
a publicly traded company. From 1990 to 1995, Mr. Godwin was employed as an
accountant with 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 since 1991 and
presently is Vice President and Corporate Secretary. Since 1991, she has served
as Corporate Secretary and was 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 been nominated as a director of
ATP. He currently serves as Chairman and Chief Executive Officer of Austin
Geriatrics Center, Inc. and as Vice Chairman of the Board of Directors of the
Shivers Cancer Foundation. From 1981 to 1998, Mr. Dilly served as Executive
Secretary of the Board of Regents of the University of Texas System. From 1978
to 1981, he was Executive Director for Development, The University of Texas
System. Prior to 1978, he was prominent in the field of hospital
administration.
Gerard J. Swonke (BA--Economics, JD) has served as a director since 1995.
Since 1985, he has been Of Counsel to 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.
Robert C. Thomas (BS--Geological Engineering) has been nominated as a
director of ATP. He currently serves as Chairman of the Board of The Energy
Center of the University of Oklahoma. Additionally he is Vice Chairman of the
Gas Research Institute Advisory Council, and also is a Senior Associate with
Cambridge Energy Research Associates. Mr. Thomas served as Chairman, President
and Chief Executive Officer of
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Tenneco Gas Company when he reached mandatory retirement age after thirty-eight
years with Tenneco beginning in 1956. 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. He was
elected president of Tenneco Gas in 1983 and chairman and chief executive
officer in 1990. Mr. Thomas is presently a member of the Board of Directors of
Marine Drilling Companies, Inc. and PetroCorp Incorporated. He is 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 serves on the Board
of Governors of The Houston Forum. Mr. Thomas has 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 been nominated as a
director of ATP. He was Director, Railroad Commission of Texas for eighteen
years, and was the Republican Nominee for the Railroad Commission of Texas in
1976. He presently is in the private practice of law, and has served as a
Trustee of the Augustana Annuity Trust, a Director of the Georgetown Railroad,
and Director of Lamar Savings Association. He additionally has served as
President, National Conference of State Transportation Specialists; Chairman,
State Bar Committee on Public Utilities Law; President, Capital City A&M Club;
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 three members. Prior to the closing of
this offering we plan to increase our board of directors to six members divided
into three classes. The members of each class will serve for a staggered,
three-year term. Upon the expiration of the term of a class of directors,
directors in that class will be elected for three-year terms at the annual
meeting of shareholders in the year in which their term expires. The classes
will be as follows:
. Class I Directors. Mr. Bulmahn and Mr. Swonke will be Class I Directors
whose terms will expire at the 2001 annual meeting of shareholders;
. Class II Directors. Mr. Wendlandt and Ms. Overbey will be Class II
Directors whose terms will expire at the 2002 annual meeting of
shareholders; and
. Class III Directors. Mr. Thomas and Mr. Dilly will be Class III Directors
whose terms will expire at the 2003 annual meeting of shareholders.
Committees of the Board of Directors
In connection with this initial public offering, our board of directors
intends to establish an audit committee and a compensation committee.
Audit Committee
The audit committee will consist of Messrs. Swonke, Thomas and Wendlandt.
The audit committee will be 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;
. 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
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<PAGE>
. 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 will consist of Messrs. Thomas, Dilly and Swonke.
This committee's responsibilities include:
. administering and granting awards under our 2000 Stock Option 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
Currently our directors receive no compensation. 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 will receive $2,000 per board
meeting, $500 per committee meeting attended and will be 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, 1999. 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:
1999 Summary Compensation Table
<TABLE>
<CAPTION>
Annual
Compensation
----------------- All Other
Name and Principal Position (1) Salary Bonus Compensation(2)
------------------------------- -------- -------- ---------------
<S> <C> <C> <C>
T. Paul Bulmahn (3).......................... $125,000 $ 32,700 $4,700
Chairman and President
Gerald W. Schlief (3)........................ $120,700 $ 53,800 $4,800
Senior Vice President
Albert L. Reese, Jr.......................... $ 87,100 $104,600 $ 800
Senior Vice President and Chief Financial
Officer
</TABLE>
--------
(1) On July 31, 2000, Mr. Ralph McBee, our former Vice-President of
Engineering, and Mr. Stephen R. Locke, our former Vice-President of
Operations, elected to leave the employment of ATP. In 1999, Mr. McBee
earned a salary of $122,000, a bonus of $55,800 and matching 401k
contributions of $4,800; Mr. Locke earned a salary of $106,700, a bonus of
$50,500 and matching 401k contributions of $4,700.
(2) Consists of matching contributions to our 401k savings plan.
(3) As described in "Related Party Transactions," during 1999 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 $0.6 million in connection with their receiving such interests.
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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
During 1999, we did not grant any stock options to the individuals named in
the previous table.
2000 Stock Option Plan
Prior to the closing of this offering, our board of directors and our
shareholders plan to adopt 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 will provide 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 will be administered by the compensation
committee of our board of directors. In general, the compensation committee
will be 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 shares, subject to adjustment to reflect stock dividends,
stock splits, recapitalizations and similar changes in our capital structure.
Shares of common stock which are attributable to awards which have expired,
terminated or been canceled or forfeited are available for issuance or use in
connection with future awards. The maximum number of shares of common stock
that may be subject to awards granted under the plan to any one individual
during the term of the plan will not exceed 50% of the aggregate number of
shares that may be issued under the plan. The price at which a share of common
stock may be purchased upon exercise of an option granted under the plan will
be determined by the compensation committee but (a) in the case of an incentive
stock option, such purchase price will not be less than the fair market value
of a share of common stock on the date such option is granted, and (b) in the
case of an option that does not constitute an incentive stock option, such
purchase price will not be less than 50% of the fair market value of a share of
common stock on the date such option is granted.
Shares of common stock that are the subject of a restricted stock award
under the plan will be subject to restrictions on disposition by the holder of
such award and an obligation of such holder to forfeit and surrender the shares
to the under certain circumstances. The restrictions will be determined by the
compensation committee in its sole discretion, and the compensation committee
may provide that the restrictions will lapse upon (a) the attainment of one or
more performance targets established by the compensation committee, (b) the
award holder's continued employment with ATP or continued service as a
consultant or director for a specified
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<PAGE>
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
date; 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 form 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. From November 1998 through June
2000, we granted options exercisable for 675,750 shares of common stock at
$1.00 each. In July and August 2000, we granted options exercisable for 404,500
shares of common stock at $2.75 per share. Please refer to note 4 in the
financial statements for a more detailed discussion of the options. At August
31, 2000, we had outstanding options to purchase a total of 827,000 shares of
common stock, of which options to purchase 422,500 shares will be exercisable
at $1.00 per share, and options to purchase 404,500 shares will be exercisable
at $2.75 per share.
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.
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<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 $29,146 for the six months ended June 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 six months of 2000.
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.
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<PAGE>
PRINCIPAL SHAREHOLDERS
The following table presents information regarding beneficial ownership of
our common stock as of August 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 and persons nominated to become directors;
. the persons named in our 1999 Summary Compensation Table; and
. all of our current executive officers and directors as a group.
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, including any right to acquire through
the exercise of any option, warrant or right.
<TABLE>
<CAPTION>
Beneficial Ownership
----------------------------
Percent
-----------------
Before After
Beneficial Owner Shares Offering Offering
---------------- ---------- -------- --------
<S> <C> <C> <C>
T. Paul Bulmahn................................... 12,619,695 63.1%
Gerard W. Schlief................................. 4,891,506 24.5%
Carol E. Overbey.................................. 1,630,633 8.2%
Albert L. Reese, Jr............................... 858,166 4.3%
Arthur H. Dilly(1)................................ 5,000 *
Gerard J. Swonke(1)............................... 5,000 *
Robert C. Thomas(1)............................... 5,000 *
Walter Wendlandt(1)............................... 5,000 *
All current executive officers, directors and
nominees for directors as a group (8
persons)(1)(2)................................... 20,020,000 100%
</TABLE>
--------
* Represents beneficial ownership of less than 1%.
(1) Includes 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.
(2) Excludes 138,333 shares that may be acquired by other key employees 60 days
after the closing of this offering through the exercise of stock options.
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<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. As of August 31, 2000, we had outstanding 20,000,000 shares
of common stock and no shares of preferred stock. As of August 31, 2000, there
were 827,000 shares of common stock subject to outstanding options, none of
which are currently exercisable. On completion of this offering, we will have
outstanding shares (or shares if the underwriters exercise
over-allotment option in full) of common stock and no shares of preferred
stock. The descriptions of our common stock and preferred stock reflect changes
to our capital structure that will occur prior to the closing of this offering.
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.
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<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
shares entitled to vote. Shareholders may not act by written consent.
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<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. Our bylaws provide that the provisions
related to the classified board and removal of directors cannot be altered,
amended or repealed without the approval of the holders of at least two-thirds
of the outstanding shares entitled to vote thereon.
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 unlawful distributions on ATP's capital stock; 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 .
57
<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 shares of
common stock. The shares of common stock sold in this offering, plus any shares
issued 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 shares of common stock outstanding 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."
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 approximately 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.
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, 137,334 shares
subject to outstanding options could be sold under Rule 701.
58
<PAGE>
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 Option Plan. Based on
the number of shares currently reserved for issuance under the plan, that
registration statement would cover up to shares issuable on exercise of
options, of which options to purchase shares will have been issued as of
the date of this offering. The registration statement on Form S-8 will
automatically become effective upon filing. 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.
59
<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..........................................................
==========
</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 in connection with this offering. These amounts are shown
assuming both no exercise and full exercise of the underwriters' option to
purchase additional shares described below. The underwriting fee is the
difference between the public offering price and the amount the underwriters
pay to us to purchase the shares from us. 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 $ .
We have granted to the underwriters an option to purchase up to
additional shares of common stock exercisable to cover over-allotments, if any,
at the initial public offering price less the underwriting discounts shown on
the cover page of this prospectus. The underwriters may exercise this option
any time until
60
<PAGE>
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 we will be obligated, under the over-allotment
option, to sell the shares of common stock to the underwriters.
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.
We have applied for quotation of our common stock on the Nasdaq National
Market under the symbol "ATPG."
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.
Until the distribution of the common stock is completed, rules of the
Securities and Exchange Commission may limit the ability of the underwriters
and selling group members to bid for and purchase shares of common stock. As an
exception to these rules, the representatives are permitted to engage in
transactions that stabilize the price of the common stock. These transactions
may consist of bids or purchases for the purpose of pegging, fixing or
maintaining the price of the common stock.
The underwriters may purchase and sell shares of common stock in the open
market. These transactions may include short sales, stabilizing transactions
and purchases to cover positions created by short sales. Short sales involve
the sale by the underwriters of a greater number of shares than they are
required to purchase in the offering. "Covered" short sales are sales made in
an amount not greater than the underwriters' option to purchase additional
shares from the issuer in the offering. The underwriters may close out any
covered short position by either exercising their option to purchase additional
shares or purchasing shares in the open market. In determining the source of
shares to close out the covered 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. "Naked" short sales are any sales in excess of such
option. The underwriters must close out any naked short position by purchasing
shares in the open market. A naked short position is more likely to be created
if the underwriters are concerned that there may be downward pressure on the
price of the common stock in the open market after pricing that could adversely
61
<PAGE>
affect investors who purchase in the offering. Stabilizing transactions consist
of various bids for or purchases of common stock made by the underwriters in
the open market prior to the completion of the offering.
The underwriters may also impose a penalty bid. This occurs when a
particular underwriter repays to the underwriters a portion of the underwriting
discount received by it because the representatives have repurchased shares
sold by or for the account of such underwriter in stabilizing or short covering
transactions.
Similar to other purchase transactions, the underwriters' purchases to cover
the syndicate short sales may have the effect of raising or maintaining the
market price of the common stock or preventing or retarding a decline in the
market price of the common stock. As a result, the price of the common stock
may be higher than the price that might otherwise exist in the open market.
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 selling shareholders or 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 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.
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. and Schlumberger Holditch-Reservoir Consulting Services Inc.,
independent petroleum engineering consultants, included in this prospectus have
been included in reliance on the authority of said firm as experts in petroleum
engineering.
62
<PAGE>
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.
63
<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 June 30,
2000 (unaudited)........................................................ F-3
Consolidated Statements of Operations for the periods ended December 31,
1997, 1998, and 1999 and June 30, 1999 (unaudited) and 2000
(unaudited)............................................................. F-4
Consolidated Statements of Shareholders' Deficit for the periods ended
December 31, 1997, 1998, and 1999 and June 30, 2000 (unaudited)......... F-5
Consolidated Statements of Cash Flows for the periods ended December 31,
1997, 1998, and 1999 and June 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-23
Statement of Revenues and Direct Operating Expenses for the nine-months
ended September 30, 1999................................................ F-24
Notes to Statement of Revenues and Direct Operating Expenses............. F-25
ATP OIL & GAS CORPORATION AND SUBSIDIARIES UNAUDITED PRO FORMA
CONSOLIDATED FINANCIAL INFORMATION
Unaudited Pro Forma Financial Information................................ F-27
Unaudited Pro Forma Consolidated Statement of Operations for the year
ended December 31, 1999................................................. F-28
Notes to Unaudited Pro Forma Consolidated Financial Statement............ F-29
</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 June 30, 2000 (unaudited)
(In thousands, except share data)
<TABLE>
<CAPTION>
June 30,
ASSETS 1998 1999 2000
------ -------- -------- -----------
(unaudited)
<S> <C> <C> <C>
Current assets:
Cash and cash equivalents........................ $ 3,411 $ 17,779 $ 8,195
Cash held in escrow.............................. 439 -- --
Accounts receivable.............................. 4,325 11,119 23,637
Other current assets............................. 645 1,048 2,269
-------- -------- --------
Total current assets........................... 8,820 29,946 34,101
Oil and gas properties:
Oil and gas properties using the successful
efforts method of accounting.................... 80,966 135,609 173,608
Less accumulated depreciation, depletion,
impairment and amortization..................... (33,354) (63,331) (83,579)
-------- -------- --------
Oil and gas properties, net.................... 47,612 72,278 90,029
Furniture and fixtures (net of accumulated
depreciation)..................................... 96 250 366
Restricted cash.................................... 4,000 471 --
Deferred tax assets................................ -- 2,058 2,532
Other assets....................................... 826 2,051 1,816
-------- -------- --------
Total assets................................... $ 61,354 $107,054 $128,844
======== ======== ========
<CAPTION>
LIABILITIES AND SHAREHOLDERS DEFICIT
------------------------------------
<S> <C> <C> <C>
Current liabilities:
Accounts payable and accruals.................... $ 11,155 $ 12,408 $ 27,782
Current maturity of long-term debt............... 2,500 3,750 --
Other current liabilities........................ 18 69 1,010
-------- -------- --------
Total current liabilities...................... 13,673 16,227 28,792
Long-term debt..................................... 12,000 16,450 22,000
Non-recourse borrowings............................ 50,690 75,273 79,966
Deferred revenue................................... 2,000 1,667 1,575
Other deferred obligations......................... 4,000 218 166
-------- -------- --------
Total liabilities.............................. 82,363 109,835 132,499
-------- -------- --------
Shareholders' deficit:
Common stock: $0.001 par value, authorized
50,000,000 shares; issued and outstanding
20,000,000 shares at December 31, 1998 and 1999
and June 30, 2000 .............................. 20 20 20
Additional paid in capital....................... 32 32 32
Accumulated deficit.............................. (21,061) (2,833) (3,707)
-------- -------- --------
Total shareholders' deficit.................... (21,009) (2,781) (3,655)
-------- -------- --------
Commitments and contingencies
Total liabilities and shareholders' deficit.... $ 61,354 $107,054 $128,844
======== ======== ========
</TABLE>
See accompanying notes to the consolidated financial statements.
F-3
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Periods ended December 31, 1997, 1998 and 1999
and June 30, 1999 (unaudited) and 2000 (unaudited)
(In thousands, except share and per share data)
<TABLE>
<CAPTION>
December 31, June 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 $ 18,323 $ 36,252
Gas sold--marketing... -- -- 7,703 3,423 2,919
---------- ---------- ---------- ---------- ----------
7,359 20,410 42,684 21,746 39,171
---------- ---------- ---------- ---------- ----------
Costs and operating
expenses:
Lease operating
expenses............. 1,513 3,193 5,587 2,484 6,422
Gas purchased--
marketing............ -- -- 7,402 3,361 2,802
General and
administrative
expenses............. 1,170 2,591 3,541 1,550 2,738
Depreciation,
depletion and
amortization......... 4,206 17,442 22,521 12,667 16,695
Impairment of oil and
gas properties....... 5,787 5,072 7,509 2,442 6,255
Other Expense......... -- -- -- -- 749
---------- ---------- ---------- ---------- ----------
12,676 28,298 46,560 22,504 35,661
---------- ---------- ---------- ---------- ----------
Net income (loss)
from operations..... (5,317) (7,888) (3,876) (758) 3,510
---------- ---------- ---------- ---------- ----------
Other income (expense):
Gain on sale of oil
and gas properties... 304 -- 287 -- 33
Interest income....... 207 141 202 48 255
Interest expense...... (1,212) (7,963) (9,399) (6,078) (5,146)
---------- ---------- ---------- ---------- ----------
(701) (7,822) (8,910) (6,030) (4,858)
---------- ---------- ---------- ---------- ----------
Net loss before
extraordinary
items............... (6,018) (15,710) (12,786) (6,788) (1,348)
Income tax benefit
(expense).............. -- -- 1,829 (281) 474
---------- ---------- ---------- ---------- ----------
Loss before
extraordinary item.. (6,018) (15,710) (10,957) (7,069) (874)
Gain on extinguishment
of debt, net of tax.... -- -- 29,185 29,185 --
---------- ---------- ---------- ---------- ----------
Net income (loss).... $ (6,018) $ (15,710) $ 18,228 $ 22,116 $ (874)
========== ========== ========== ========== ==========
Basic earnings (loss)
per common share:
Income (loss) before
extraordinary item... $ (0.41) $ (0.94) $ (0.55) $ (0.35) $ (0.04)
Extraordinary gain,
net of income taxes.. -- -- 1.46 1.46 --
---------- ---------- ---------- ---------- ----------
Net income (loss) per
common share........ $ (0.41) $ (0.94) $ 0.91 $ 1.11 $ (0.04)
========== ========== ========== ========== ==========
Diluted earnings (loss)
per common share:
Income (loss) before
extraordinary item... $ (0.41) $ (0.94) $ (0.55) $ (0.35) $ (0.04)
Extraordinary gain,
net of income taxes.. -- -- 1.46 1.46 --
---------- ---------- ---------- ---------- ----------
Net income (loss) per
common share........ $ (0.41) $ (0.94) $ 0.91 $ 1.11 $ (0.04)
========== ========== ========== ========== ==========
Weighted average number
of common shares:
Basic................. 14,794,867 16,696,099 20,000,000 20,000,000 20,000,000
========== ========== ========== ========== ==========
Diluted............... 14,794,867 16,696,099 20,000,000 20,000,000 20,000,000
========== ========== ========== ========== ==========
</TABLE>
See accompanying notes to the consolidated financial statements.
F-4
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' DEFICIT
Periods ended December 31, 1998 and 1999 and June 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,
1997................... 15,497,858 $15 $24 $(5,351) $(5,312)
Exercise of options... 4,502,142 5 8 -- 13
Net loss.............. -- -- -- (15,710) (15,710)
---------- --- --- ------- -------
Balance, December 31,
1998................... 20,000,000 20 32 (21,061) (21,009)
Net income............ -- -- -- 18,228 18,228
---------- --- --- ------- -------
Balance, December 31,
1999................... 20,000,000 20 32 (2,833) (2,781)
Net loss.............. -- -- -- (874) (874)
---------- --- --- ------- -------
Balance, June 30, 2000.. 20,000,000 $20 $32 $(3,707) $(3,655)
========== === === ======= =======
</TABLE>
See accompanying notes to the consolidated financial statements.
F-5
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Periods ended December 31, 1997, 1998 and 1999
and June 30, 1999 (unaudited) and 2000 (unaudited)
(In thousands)
<TABLE>
<CAPTION>
June 30, June 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 $22,116 $ (874)
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 12,667 16,695
Amortization of deferred
financing costs........ 2 45 280 67 157
Impairment of oil and
gas properties......... 5,787 5,072 7,509 2,442 6,255
Assignment of overrides
to related party....... -- 525 557 -- 282
Other expense........... -- -- -- -- 749
Recognition of deferred
revenue................ -- -- (333) (165) (92)
Gain on early
extinguishment of
debt................... -- -- (29,185) (29,185) --
Gain on sale of oil and
gas properties......... (304) -- (287) -- (33)
Change in assets and
liabilities:
(Increase) decrease in
accounts receivable..... (9,967) 7,205 (6,794) (6,619) (12,518)
(Increase) decrease in
cash held in escrow..... (411) 981 439 427 --
(Increase) in other
current assets.......... (482) (39) (403) (399) (1,221)
Decrease in restricted
cash.................... -- -- 3,529 1,657 471
(Increase) in deferred
tax assets.............. -- -- (2,058) (951) (474)
(Increase) decrease in
other assets............ 32 (96) (714) (649) 179
Increase (decrease) in
accounts payable........ 10,794 (2,156) 1,253 2,095 15,033
Increase (decrease) in
other current
liabilities............. 19 (22) 51 122 192
(Decrease) in deferred
obligations............. (86) -- (3,782) (1,815) (52)
------- -------- ------- ------- -------
Cash provided by
operating
activities........... 3,572 13,247 10,811 1,810 24,749
------- -------- ------- ------- -------
Cash flows from investing
activities:
Additions and
acquisitions of oil and
gas properties.......... (39,361) (35,936) (56,051) (13,544) (40,577)
Proceeds from sale of oil
and gas properties...... 975 -- 1,137 950 --
Additions to furniture
and fixtures............ (84) (46) (206) (79) (148)
------- -------- ------- ------- -------
Cash used by investing
activities........... (38,470) (35,982) (55,120) (12,673) (40,725)
------- -------- ------- ------- -------
Cash flows from financing
activities:
Increase in long-term
debt.................... -- 14,500 5,700 -- 3,300
Payments of long-term
debt.................... -- -- -- (9,900) (1,500)
Non-recourse borrowings.. 39,924 20,113 93,728 54,239 13,461
Payments of non-recourse
borrowings.............. (4,232) (11,617) (39,420) (27,819) (8,768)
Deferred financing costs
incurred................ (78) (669) (1,331) (824) (101)
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 15,696 6,392
------- -------- ------- ------- -------
Increase (decrease) in
cash and cash
equivalents............. 718 1,605 14,368 4,833 (9,584)
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 $ 8,244 $ 8,195
======= ======== ======= ======= =======
</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 June 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 June 30, 2000, for the
six-month periods ended June 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 June 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 six-month periods ended June 30, 1999 and 2000
of $5.8 million, $5.1 million, $7.5 million, $2.4 million and $6.3 million,
respectively, primarily due to depressed oil and natural gas prices,
unfavorable operating performance and a reduction of recoverable reserves.
Acquisition
In September 1999, the Company completed an acquisition of a 100% working
interest and a 82% net revenue interest in Eugene Island 30 for a purchase
price of $16.3 million. 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>
December 31,
-----------------
1998 1999
-------- -------
<S> <C> <C>
Revenues.................................................. $ 23,757 $44,955
Net income (loss)......................................... $(15,894) $18,396
Basic and diluted earnings (loss) per share............... $ (0.95) $ 0.92
</TABLE>
F-8
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
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, $22,000 and $32,000 for the periods ended December 31, 1997,
1998 and 1999 and June 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 June 30, 1999 and 2000 and were $2.1 million, $1.6 million, $0.6
million, none and $0.7 million, respectively.
Other Current Assets
Other current assets include prepaid expenses of $0.2 million, $0.2 million
and $0.1 million and estimated royalty deposits with the Mineral Management
Services of $0.5 million, $0.8 million and $2.2 million at December 31, 1998,
and 1999 and June 30, 2000, respectively. Prepaid expenses are amortized to
production and operating expenses over the term of the related agreements.
Other Assets
Other assets include debt financing costs of $0.7 million, $1.2 million and
$1.1 million, assets held for resale of none, $0.7 million and $0.7 million,
and spare parts inventory of $0.1 million, $0.2 million and $0.1 million at
December 31, 1998, and 1999 and June 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 June 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. 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 June 30, 2000, the Company had over-
deliveries included in accounts payable of $47,000, $0.2 million and $0.2
million, respectively.
F-9
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
The Company has no allowance for doubtful accounts related to its trade
accounts receivable for any period shown.
Income Taxes
Income taxes are accounted for under the asset and liability method.
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases and operating loss and tax credit carryforwards. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected to be
recovered or settled. The effect on deferred tax assets and liabilities of a
change in tax rates is recognized in income in the period that includes that
enactment date.
Financial Instruments
The Company's financial instruments consist of cash and cash equivalents,
receivables, payables and debt. The carrying amount of cash and cash
equivalents, receivables and payables approximates fair value because of the
short-term nature of these items.
Derivative Financial Instruments
From time to time, the Company has utilized and may continue to utilize
hedging transactions with respect to a portion of its oil and gas production to
achieve a more predictable cash flow as well as to reduce its exposure to price
fluctuations. These transactions generally are swaps or price collars and are
entered into with major financial institutions or commodities trading
institutions. Derivative financial instruments are intended to reduce the
Company's exposure to declines in the market price of natural gas and crude
oil. These derivative financial instruments will limit the effect on the
Company's realized revenues if market prices fall below the contracted floor
price. As a result, gains and losses on derivative financial instruments are
generally offset in the Company's oil and gas revenues by similar changes in
the realized price of natural gas and crude oil.
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 June 30, 2000, the Company had hedged approximately 14,303,000 MMbtu or
92% of its expected remaining 2000 natural gas production from its current
portfolio of properties and 14,527,000 MMbtu or 44% of its expected 2001
natural gas production from its current portfolio of properties. The average
price of hedged natural gas production is approximately $2.95 per MMbtu for
2000 and $3.03 per MMbtu for 2001. The Company has no natural gas hedges in
effect beyond October 2001. At June 30, 2000, the Company had hedged
approximately 101,300 barrels of oil or 47% of its expected remaining 2000 oil
production from its current portfolio of properties. The average price of
hedged oil production is estimated at $23.99 per barrel. The Company has no oil
hedges in effect beyond December 2000. Based on prices in effect at June 30,
2000 the above hedge positions would reduce expected future net revenues by
30%, or $21.4 million in the last six months of 2000 and 7%, or $11.3 million
in 2001.
F-10
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
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 June 30, 2000, the Company recognized a loss in the amount of $749,000 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 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 4).
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
six months ended June 30, 1999 and 2000, the Company made cash payments of
interest of $0.4 million and $0.7 million, respectively. The Company made no
cash payments for income taxes during the three years ending December 31, 1999
or the six months ended June 30, 1999 and the Company made cash payments for
income taxes during the six months ended June 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
F-11
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
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 June 30, 2000 totaling ($4.9) million, $13.7 million and $5.3
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 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.
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) Long-term Debt and Non-Recourse Borrowings
Credit facility
<TABLE>
<CAPTION>
December 31,
--------------- June 30,
1998 1999 2000
------- ------- -----------
(In thousands) (unaudited)
<S> <C> <C> <C>
Credit facility.................................. $14,500 $20,200 $22,000
Less current portion............................. 2,500 3,750 --
------- ------- -------
Long-term debt................................. $12,000 $16,450 $22,000
======= ======= =======
</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
June 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 June 30, 2000 the average interest
rate was 8.1%, 8.9% and 10.1% respectively. The credit facility is
collateralized by a first mortgage on certain of the Company's oil and gas
properties. Commitment fees and facility fees are paid
F-12
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
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 June 30, 2000, the Company was
in compliance with all terms of the agreement. At December 31, 1998 and 1999
and June 30, 2000, the amount outstanding under the credit facility was $14.5
million, $20.2 million and $22.0 million, respectively.
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. Of this amount, approximately $39.9 million was received in 1997
and $20.1 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 an agreed upon
percentage 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, the implied rate of return,
and any 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 a designated percentage 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
earned by the lender, it also has a future specified overriding royalty
interest in the properties that serve as collateral. This overriding royalty
interest applies to each property that serves as collateral and does not become
effective until after all of the indebtedness has been paid in full or when a
property is removed from the collateral base. Each overriding royalty is only
for a specified volume of production from the property and is contingent on the
future performance of the related properties. 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 June 30, 2000, there was $75.3 million and $80.0
million, respectively, outstanding under the agreement.
F-13
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
(4) Equity
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 fair value of
each option granted was determined as the value using a standard option-pricing
model on the date of grant with industry average assumptions for valuations.
The fair value does not take into account the expected volatility of the
underlying stock if it were traded in an open market. 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.
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 3,750,000 shares of common stock to
be granted to eligible participants. Stock options are granted at the fair
market value of the Company's stock on the date of grant, determined by
Committee. These options expire 5 years from the date the 1998 SOP was adopted
if no initial public offering (IPO) of Company Stock, in a minimum amount of
$5.0 million, 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, 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 IPO 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>
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 June 30, 2000 the Company granted options
exercisable for 617,000, 26,000 and 32,750 shares of common stock at $1.00
each, the grant date fair market value as estimated by management.
Upon the occurrence of an IPO, the Company may recognize a material amount
of compensation expense depending on the fair market value of the Company's
common stock determined by an IPO. Compensation expense will be measured by the
Company at the IPO date as the difference between the grant price for certain
of its options granted prior to the IPO and the fair market value of the
Company's common stock. Any
F-14
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
determined compensation expense will be recognized in the Company's future
financial statements based on the above vesting schedule.
Information regarding the Company's 1998 SOP is summarized as follows:
<TABLE>
<CAPTION>
June 30, June 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................ -- $ -- 617,000 $1.00 639,750 $ 1.00
Granted................. 617,000 1.00 26,000 1.00 32,750 1.00
Expired unexercised..... -- -- (3,250) 1.00 -- --
Exercised............... -- -- -- -- --
------- ----- ------- ----- ------- ------
Outstanding at end of
period................. 617,000 $1.00 639,750 $1.00 672,500 $ 1.00
======= ===== ======= ===== ======= ======
Exercisable at end of
period................. -- $ -- -- $ -- -- $ --
======= ===== ======= ===== ======= ======
Fair value of options
granted................ 617,000 $1.00 26,000 $1.00 32,750 $ 1.00
======= ===== ======= ===== ======= ======
</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 78,264,102 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 36,729,342 shares were issued at $0.00256 per share immediately
exercisable after grant. As of December 31, 1997, 1998 and 1999 and June 30,
2000, options to purchase 31,872,664 shares, 26,512,356 shares, 26,512,356
shares and 26,512,356 shares, respectively, of the 1994 options remain
unexercised and outstanding. In April 2000, the only outstanding option under
the 1994 SOP was amended to place a limit on the number of shares that could be
purchased pursuant to the option. As a result, the number of shares exercisable
as of April 2000 was zero. In conjunction with the Company's planned initial
public offering, the 1994 SOP will be terminated and the only outstanding
option issued under that plan will be cancelled.
F-15
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
Information regarding the Company's 1994 SOP is summarized as follows:
<TABLE>
<CAPTION>
June 30, June 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................ 31,872,664 $0.002 31,014,498 $0.002 26,512,356 $0.002 26,512,356 $0.002
Granted................. -- -- -- -- --
Expired unexercised..... -- -- -- -- --
Exercised............... (858,166) 0.002 (4,502,142) 0.002 -- -- --
---------- ------ ---------- ------ ---------- ------ ---------- ------
Outstanding at end of
period................. 31,014,498 $0.002 26,512,356 $0.002 26,512,356 $0.002 26,512,356 $0.002
========== ====== ========== ====== ========== ====== ========== ======
Exercisable at end of
period................. 31,014,498 $0.002 26,512,356 $0.002 26,512,356 $0.002 -- $ --
========== ====== ========== ====== ========== ====== ========== ======
Fair value of options
granted................ -- $ -- -- $ -- -- $ -- -- $ --
========== ====== ========== ====== ========== ====== ========== ======
</TABLE>
(5) 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.
F-16
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
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 six months
For the years ended December 31, ended June 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 $ 22,116 $ (874)
=========== =========== =========== =========== ===========
Basic--weighted average
shares................. 14,794,867 16,696,099 20,000,000 20,000,000 20,000,000
=========== =========== =========== =========== ===========
Diluted--weighted
average shares 14,794,867 16,696,099 20,000,000 20,000,000 20,000,000
=========== =========== =========== =========== ===========
Net income (loss) per
share:
Basic:
Net loss before
extraordinary item... $ (0.41) $ (0.94) $ (0.55) $ (0.35) $ (0.04)
Extraordinary gain,
net of income taxes.. -- -- 1.46 1.46 --
----------- ----------- ----------- ----------- -----------
Net income (loss) per
common share........... $ (0.41) $ (0.94) $ 0.91 $ 1.11 $ (0.04)
=========== =========== =========== =========== ===========
Diluted:
Net income (loss)
before extraordinary
item................. $ (0.41) $ (0.94) $ (0.55) $ (0.35) $ (0.04)
Extraordinary gain,
net of income taxes.. -- -- 1.46 1.46 --
----------- ----------- ----------- ----------- -----------
Net income (loss) per
common share........... $ (0.41) $ (0.94) $ 0.91 $ 1.11 $ (0.04)
=========== =========== =========== =========== ===========
</TABLE>
Major Customers
The Company sells a portion of its oil and gas to end users through various
gas marketing companies. Three of these gas marketing companies accounted for
52%, 58%, 70%, 67%, and 73% of the Company's oil and gas revenues for the
periods ended December 31, 1997, 1998 and 1999, and June 30, 1999 and 2000,
respectively.
F-17
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
(6) 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>
December 31, June 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) (34.07) 0.00
Nondeductible and other.......... 0.01 0.01 0.05 0.00 0.14
------ ------ ------ ------ ------
0.00% 0.00% (11.16)% 1.26% (35.18)%
====== ====== ====== ====== ======
</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 June 30, 2000, are as follows (in thousands):
<TABLE>
<CAPTION>
December 31,
---------------
1998 1999 June 30, 2000
------ ------- -------------
(unaudited)
<S> <C> <C> <C>
Deferred tax assets (liabilities):
Net operating loss carryforwards.............. $7,804 $ 3,800 $ 4,787
Minimum tax credit carryforwards.............. -- 229 229
Fixed asset basis differences................. (439) (2,379) (3,256)
State taxes................................... 71 17 21
Other......................................... 195 391 751
------ ------- -------
Total deferred tax assets................... 7,631 2,058 2,532
Valuation allowance for deferred tax assets..... (7,631) -- --
------ ------- -------
Net deferred tax assets..................... $ -- $ 2,058 $ 2,532
====== ======= =======
</TABLE>
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.
(7) 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.
F-18
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
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>
(8) ATP Energy Gas Purchase Transaction
In December 31, 1998, ATP Energy entered an agreement to purchase gas over a
ten-year period from an unrelated third party. The purchase price of the gas is
in excess of the current Henry Hub index price, but is offset by amounts due
from the unrelated third party. The terms provide for the immediate termination
of the agreement upon non-performance by the unrelated third party.
Additionally, ATP Energy entered into a contract with another unrelated entity
to sell an identical quantity of gas at the current Henry Hub index price less
$0.015, until December 2001. In conjunction with these transactions, ATP Energy
received $6.0 million 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 balance is recognized into income as earned over the life
of the contract. The deferred obligations are utilized to offset the excess of
the purchase price of the gas over the current index and are amortized over the
expected life of the contract as the gas is purchased and the purchase
obligation of ATP Energy is reduced. During 1999, ATP Energy recognized $7.7
million of revenue related to the transaction and recorded expenses of $7.4
million. At December 31, 1999 the deferred revenue amount was $1.7 million and
deferred obligations was $0.2 million.
(9) 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. 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 June 30, 2000.
Officers of the Company were paid $97,875 and $152,125 for the periods ended
December 31, 1999 and June 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.
F-19
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
(10) 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>
For the years ended
December 31,
-----------------------
1997 1998 1999
------- ------- -------
<S> <C> <C> <C>
Property acquisition costs:
Proved............................................ $ 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.
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 and Holditch-Reservoir
Technologies, 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 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 at the end of the year... 31,080 39,728 67,314
====== ====== =======
</TABLE>
F-20
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
<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 at the end of the year........ 678 579 710
==== ==== =====
</TABLE>
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>
For the years ended at 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
F-21
<PAGE>
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1997, 1998 and 1999 and June 30, 1999 and 2000 (unaudited)
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.
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 at 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
Costs incurred which were previously
estimated................................... 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-22
<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-23
<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-24
<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 lease and well repairs, maintenance and other direct operating
expenses.
(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 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, 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-25
<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:
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>
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............................................. 17,020
Increase in income taxes.......................................... (4,037)
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-26
<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). The above transaction is reflected in
the statement of operations as if it occurred at the beginning of 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-27
<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
---------- ----- ------ ----------
42,684 2,271 -- 44,955
---------- ----- ------ ----------
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 -- 223 (B) 22,744
Impairment of oil and gas
properties................. 7,509 -- -- 7,509
---------- ----- ------ ----------
46,560 702 223 47,485
---------- ----- ------ ----------
Net income (loss) from
operations............... (3,876) 1,569 (223) (2,530)
---------- ----- ------ ----------
Other income (expense):
Gain on sale of oil and gas
properties................. 287 -- -- 287
Interest income............. 202 -- -- 202
Interest expense............ (9,399) -- (1,088)(C) (10,487)
---------- ----- ------ ----------
(8,910) -- (1,088) (9,998)
---------- ----- ------ ----------
Net (income) loss before
extraordinary items...... (12,786) 1,569 (1,311) (12,528)
Income tax benefit (expense) 1,829 -- (90)(D) 1,739
---------- ----- ------ ----------
Net (income) loss before
extraordinary items...... (10,957) 1,569 (1,401) (10,789)
========== ===== ====== ==========
Basic loss per common share:
Loss before extraordinary
item....................... $ (0.55) (0.54)
========== ==========
Diluted loss per common share:
Loss before extraordinary
item....................... $ (0.55) (0.54)
========== ==========
Weighted average number of
common shares:
Basic....................... 20,000,000 20,000,000
========== ==========
Diluted..................... 20,000,000 20,000,000
========== ==========
</TABLE>
See accompanying notes to unaudited pro forma consolidated financial
statements.
F-28
<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 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 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.
(D) To reflect income tax expense related to the pro forma adjustments.
F-29
<PAGE>
Shares
ATP OIL & GAS CORPORATION
Common Stock
-----------
PROSPECTUS
, 2000
-----------
Lehman Brothers
CIBC World Markets
Dain Rauscher Wessels
Raymond James & Associates, Inc.
Fidelity Capital Markets
a division of National Financial Services LLC
<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..................................... *
Legal fees and expenses................................................ *
Accounting fees and expenses........................................... *
Engineering fees and expenses.......................................... *
Blue Sky fees and expenses (including legal fees)...................... *
Printing expenses...................................................... *
Transfer agent fees.................................................... *
Miscellaneous.......................................................... *
-------
TOTAL.............................................................. $ *
=======
</TABLE>
--------
* To be provided by amendment.
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. During the
fiscal years ended December 31, 1997 and 1998 the Company issued 858,166 and
4,501,842 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 June
30, 2000, the Company granted options to its employees to purchase at an
exercise price of $1.00, 617,000 shares of common stock, 26,000 shares of
common stock and 32,750 shares of common stock, respectively. During July,
August and September 2000, we issued to our employees, options to purchase a
total of 457,000 shares of common stock at an exercise price of $2.75.
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 Arthur H. Dilly, Director Nominee
23.5 --Consent of Robert C. Thomas, Director Nominee
23.6 --Consent of Walter Wendlandt, Director Nominee
*23.7 --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>
--------
* To be filed by amendment.
(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 18th day of September, 2000.
ATP OIL & GAS CORPORATION
By: /s/ T. PAUL BULMAHN
----------------------------------
T. Paul Bulmahn
Chairman and President
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 18th day of September, 2000.
<TABLE>
<CAPTION>
Signature Title
--------- -----
<C> <S>
/s/ T. Paul Bulmahn 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.
/s/ Keith Godwin Vice President and Controller
______________________________________ (Principal Accounting Officer)
Keith Godwin
/s/ Carol E. Overbey Director
______________________________________
Carol E. Overbey
/s/ Gerard Swonke Director
______________________________________
Gerard Swonke
</TABLE>
II-4
<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 Arthur H. Dilly, Director Nominee
23.5 --Consent of Robert C. Thomas, Director Nominee
23.6 --Consent of Walter Wendlandt, Director Nominee
*23.7 --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>
--------
* To be filed by amendment.
II-5
