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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2002 Commission file number: 000-32261
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
ATP Oil & Gas Corporation
(Exact name of registrant as specified in its charter)
Texas 76-0362774
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
4600 Post Oak Place, Suite 200
Houston, Texas 77027
(Address of principal executive offices) (Zip Code)
(Registrant's telephone number, including area code): (713) 622-3311
Securities Registered Pursuant to Section 12 (b) of the Act:
Title of each class Name of exchange on which registered
------------------------------------------- --------------------------------------
Common Stock, par value $.001 per share NASDAQ
Securities Registered Pursuant to Section 12 (g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes[X] No__
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by Reference in Part III of this Form 10-K or any amendment to this
Form 10-K. Yes[X] No__
Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes__ No[X]
The aggregate market value of the voting and non-voting common stock held by
non-affiliates of the Registrant as of June 28, 2002 (the last business day of
the Registrant's most recently completed second fiscal quarter) was
approximately $18,271,364. The number of shares of the Registrant's common stock
outstanding as of March 21, 2003 was 20,338,753.
DOCUMENTS INCORPORATED BY REFERENCE: The information required in Part III of the
Annual Report on Form 10-K is incorporated by reference to the Registrant's
definitive proxy statement to be filed pursuant to Regulation 14A for the
Registrant's Annual Meeting of Stockholders.
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ATP OIL & GAS CORPORATION AND SUBSIDIARIES
2002 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
Page
----
Part I ...................................................................................... 6
Item 1. Business ...................................................................... 6
Item 2. Properties .................................................................... 14
Item 3. Legal Proceedings ............................................................. 17
Item 4. Submission of Matters to a Vote of Security Holders ........................... 17
Part II ..................................................................................... 19
Item 5. Market for Registrants Common Units and Related Security Holder Matters ....... 19
Item 6. Selected Financial Data ....................................................... 20
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations ..................................................... 21
Item 7a. Quantitative and Qualitative Disclosures about Market Risk .................... 39
Item 8. Financial Statements and Supplementary Data ................................... 40
Item 9. Disagreements on Accounting and Financial Disclosure .......................... 40
Part III .................................................................................... 41
Item 10. Directors and Executive Officers of Registrant ................................ 41
Item 11. Executive Compensation ........................................................ 41
Item 12. Security Ownership of Certain Beneficial Owners and Management ................ 41
Item 13. Certain Relationships and Related Transactions ................................ 41
Item 14. Controls and Procedures ....................................................... 41
Part IV ..................................................................................... 42
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K ............... 42
2
Cautionary Statement About Forward-Looking Statements
This annual report on Form 10-K includes assumptions, expectations,
projections, intentions or beliefs about future events. These statements are
intended as "forward-looking statements" under the Private Securities Litigation
Reform Act of 1995. We caution that assumptions, expectations, projections,
intentions and beliefs about future events may and often do vary from actual
results and the differences can be material.
All statements in this document that are not statements of historical fact
are forward looking statements. Forward looking statements include, but are not
limited to:
. projected operating or financial results;
. budgeted or projected capital expenditures;
. expectations regarding our planned expansions and the availability of
acquisition opportunities;
. statements about the expected drilling of wells and other planned
development activities;
. expectations regarding natural gas and oil markets in the United
States and the United Kingdom; and
. estimates of quantities of our proved reserves and the present value
thereof, and timing and amount of future production of natural gas and
oil.
When used in this document, the words "anticipate," "estimate," "project,"
"forecast," "may," "should," and "expect" reflect forward-looking statements.
There can be no assurance that actual results will not differ materially
from those expressed or implied in such forward looking statements. Some of the
key factors which could cause actual results to vary from those expected
include:
. the timing and extent of changes in natural gas and oil prices;
. the timing of planned capital expenditures;
. our ability to identify and acquire additional properties necessary to
implement our business strategy and our ability to finance such
acquisitions;
. the inherent uncertainties in estimating proved reserves and
forecasting production results;
. operational factors affecting the commencement or maintenance of
producing wells, including catastrophic weather related damage,
unscheduled outages or repairs, or unanticipated changes in drilling
equipment costs or rig availability;
. the condition of the capital markets generally, which will be affected
by interest rates, foreign currency fluctuations and general economic
conditions;
. cost and other effects of legal and administrative proceedings,
settlements, investigations and claims, including environmental
liabilities which may not be covered by indemnity or insurance;
. the political and economic climate in the foreign or domestic
jurisdictions in which we conduct oil and gas operations, including
risk of war or potential adverse results of military or terrorist
actions in those areas, and;
. other United States or United Kingdom regulatory or legislative
developments which affect the demand for natural gas or oil generally
increase the environmental compliance cost for our production wells or
impose liabilities on the owners of such wells.
3
CERTAIN DEFINITIONS
As used herein, the following terms have specific meanings as set forth
below:
Bbls Barrels of crude oil or other liquid hydrocarbons
Bcf Billion cubic feet
Bcfe Billion cubic feet equivalent
MBbls Thousand barrels of crude oil or other liquid hydrocarbons
Mcf Thousand cubic feet of natural gas
Mcfe Thousand cubic feet equivalent
MMBbls Million barrels of crude oil or other liquid hydrocarbons
MMBtu Million british thermal units
MMcf Million cubic feet of natural gas
MMcfe Million cubic feet equivalent
MMBoe Million barrels of crude oil or other liquid hydrocarbons equivalent
U.S. United States
U.K. United Kingdom of Great Britain and Northern Ireland
Crude oil and other liquid hydrocarbons are converted into cubic feet of gas
equivalent based on six Mcf of gas to one barrel of crude oil or other liquid
hydrocarbons.
Development well is a well drilled within the proved area of an oil or
natural gas field to the depth of a stratigraphic horizon known to be
productive.
Dry hole is a well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.
Exploratory well is a well drilled to find and produce natural gas or oil
reserves that is not a development well.
Farm-in or farm-out is an agreement whereby the owner of a working interest
in an oil and gas lease or license assigns the working interest or a portion
thereof to another party who desires to drill on the leased or licensed acreage.
Generally, the assignee is required to drill one or more wells in order to earn
its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The interest received by an assignee is a
"farm-in," while the interest transferred by the assignor is a "farm-out."
Field is an area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature or
stratigraphic condition.
Net feet of natural gas and condensate is the true vertical thickness of
reservoir rock estimated to both contain hydrocarbons and be capable of
contributing to producing rates.
PV-10 is the estimated future net revenue to be generated from the
production of proved reserves discounted to present value using an annual
discount rate of 10%. These amounts are calculated net of estimated production
costs and future development and abandonment costs, using prices and costs in
effect as of a certain date, without escalation and without giving effect to
non-production related expenses, such as general and administrative expenses,
debt service, future income tax expense, or depreciation, depletion, and
amortization.
Productive well is a well that is producing or is capable of production,
including natural gas wells awaiting pipeline connections to commence deliveries
and oil wells awaiting connection to production facilities.
4
Proved reserves are the estimated quantities of oil and gas which geological
and engineering data demonstrate, with reasonable certainty, can be recovered in
future years from known reservoirs under existing economic and operating
conditions. Reservoirs are considered proved if shown to be economically
producible by either actual production or conclusive formation tests.
Proved developed reserves are the portion of proved reserves that can be
expected to be recovered through existing wells with existing equipment and
operating methods.
Proved undeveloped reserves are the portion of proved 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.
Reserve life index is a measure of the productive life of a natural gas and
oil property or a group of natural gas and oil properties, expressed in years.
Reserve life equals the estimated net proved reserves attributable to property
or group of properties divided by production from the property or group of
properties for the four fiscal quarters preceding the date as of which the
proved reserves were estimated.
Working interest is the operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
Workover is operations on a producing well to restore or increase
production.
5
PART I
Item 1. Business
General
ATP Oil & Gas Corporation ("ATP") was incorporated in Texas in 1991. We are
engaged in the acquisition, development and production of natural gas and oil
properties in the Gulf of Mexico and the U.K. and Dutch Sectors of the North Sea
(the "North Sea"). We primarily focus our efforts on natural gas and oil
properties with proved undeveloped reserves that are economically attractive to
us but are not strategic to major or exploration-oriented independent oil and
gas companies. We attempt to achieve a high return on our investment in these
properties by limiting our up-front acquisition costs and by developing our
acquisitions quickly. Our management team has extensive engineering, geological,
geophysical, technical and operational expertise in successfully developing and
operating properties in both our current and planned areas of operation.
During 2002, we produced approximately 26.5 Bcfe, our seventh consecutive
annual increase in production. Natural gas accounted for 67% of our production
and all of our 2002 production was from the Gulf of Mexico. In December 2002, we
were near completion of our first well in the U.K. Sector - North Sea and, we
anticipate first production some time in the first half of 2003.
We increase our reserves and production primarily through acquisitions and
the subsequent development of proved reserves. During 2002 we added proved
reserves of approximately 38.5 Bcfe, of which 20.3 Bcf were through acquisitions
in the U.K. Sector - North Sea and 4.7 Bcf were through acquisitions in the Gulf
of Mexico. The remaining increase of 13.5 Bcfe came from an upward revision in
our previous reserve estimates. Also during 2002, we elected to sell an interest
in two of our U.K. Sector - North Sea properties which accounted for a
disposition of 17.1 Bcf in reserves.
At December 31, 2002, we had estimated net proved reserves of 230.0 Bcfe,
of which approximately 136.9 Bcfe (60%) was in the Gulf of Mexico and 93.1 Bcf
(40%) was in the U.K. Sector - North Sea. Year-end reserves were comprised of
195.5 Bcf of natural gas and 5.7 MMBbls of oil. All of our oil reserves are
located in the Gulf of Mexico and approximately 52% of our natural gas reserves
are located in the Gulf of Mexico with the balance in the U.K. Sector - North
Sea. The estimated pre-tax PV-10 of our reserves at December 31, 2002 was $355.3
million. Prices used in the U.S. reserve estimates were $4.74 per MMBtu of
natural gas and $31.23 per barrel of oil. For the U.K reserve estimates, we used
13.7 pence per thermal unit or approximately $2.20 per MMBtu of natural gas.
At December 31, 2002, we had leasehold and other interests in 50 offshore
blocks, 29 platforms and 70 wells, including six subsea wells, in the Gulf of
Mexico. We operate 55 of these 70 wells, including all of the subsea wells, and
76% of our offshore platforms. We also had interests in seven blocks and one
company-operated subsea well in the U.K. Sector - North Sea. Our average working
interest in our properties at December 31, 2002 was approximately 82%. For more
information regarding our operations in the Gulf of Mexico and North Sea, see
Note 15 to the Notes to Consolidated Financial Statements.
Our Business Strategy
Our business strategy is to enhance shareholder value primarily through the
acquisition, development and production of proved natural gas and oil reserves
in areas that have:
. an existing infrastructure of oil and natural gas pipelines and
production/processing platforms;
. geographic proximity to developed markets for natural gas and oil;
. a number of properties that major oil companies, exploration-oriented
independents and others consider non-strategic; and
. a relatively stable history of consistently applied governmental
regulations for offshore natural gas and oil development and
production.
6
We believe our strategy significantly reduces the risks associated with
traditional natural gas and oil exploration. Our focus is to acquire properties
that have been explored by others and found to contain proved reserves. From the
inception of operations in 1995 through March 20, 2003, we have successfully
brought to production 30 out of 31 projects from previously undeveloped
reserves, a 97% success ratio.
We focus on acquiring properties that contain proved undeveloped reserves
that have become non-core or non-strategic to their original owners for various
reasons. For example, larger oil companies from time to time adjust their
capital spending or shift their focus to exploration prospects with greater
reserve potential. Some projects provide lower economic returns to a larger
company due to its cost structure. Also, due to timing or budget constraints, a
company may be unable or unwilling to develop a property before the expiration
of the lease and desire to sell the property before they forfeit their lease
rights. Because of our cost structure, expertise in our areas of focus and our
ability to develop projects efficiently, these properties may be economically
attractive to us.
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 operate a significant number of the properties in which we
acquire a working interest, we are able to significantly influence the time of 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. We believe this
strategy, combined with our ability to evaluate and implement a project's
requirements, allows us to efficiently complete the development project and
commence production quickly.
Our Strengths
. Low Acquisition Cost Structure. We believe that our focus on acquiring
properties with minimal cash investment 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, 2002, our total average finding and development costs
(which do not include future development costs) incurred in the
acquisition and development of our net proved reserves was $1.09 per
Mcfe.
. Technical Expertise and Significant Experience. We have assembled a
technical staff with an average of over 20 years of industry
experience. Our technical staff has specific expertise in the Gulf of
Mexico and North Sea offshore property development, including the
implementation of subsea completion technology.
. Operating Control. As the operator of a property, we are afforded
greater control of the selection of completion and production
equipment, the timing and amount of capital expenditures and the
operating parameters and costs of the project. As of December 31,
2002, we operated 76% of our offshore platforms, all of our subsea
wells and all of our properties under development.
. Employee Ownership. Through employee ownership, we have built a staff
whose business decisions are aligned with the interests of our
shareholders. Our executive officers and directors own approximately
70% of our common stock on a fully diluted basis.
. Inventory of Projects. We have a substantial inventory of properties
to develop in both the Gulf of Mexico and in the North Sea. We
currently have three developments in the U.K. Sector - North Sea one
development at our 2003 acquisition in the Dutch Sector - North Sea
and seven developments in the Gulf of Mexico.
Marketing and Delivery Commitments
We sell our natural gas and oil production under price sensitive or market
price contracts. Our revenues, profitability and future growth depend
substantially on prevailing prices for natural gas and oil. The price received
by us for our non-hedged natural gas and oil production can fluctuate widely.
Changes in the prices of natural gas and oil will affect the carrying value of
our proved reserves as well as 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.
7
We sell a portion of our natural gas and oil to end users through various
gas marketing companies. Historically, we have sold our natural gas and oil to a
relatively few number of purchasers. For instance, in 2002, four purchasers
accounted for 88% of our revenues. However, we are not dependent upon, or
confined to, any one purchaser or small group of purchasers. Due to the nature
of natural gas and oil markets and because natural gas and oil are commodities
and there are numerous purchasers in the areas in which we sell production, we
do not believe the loss of a single purchaser, or a few purchasers, would
materially affect our ability to sell our production.
Competition
We compete with major and independent natural gas and oil companies for
property acquisitions. We also compete for the equipment and labor required to
operate and to develop these properties. Some of our competitors have
substantially greater financial and other resources and may be able to sustain
wide fluctuations in the economics of our industry more easily than we can.
Since we are in a highly regulated industry, they may be able to absorb the
burden of any changes in federal, state and local laws and regulations more
easily 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, to secure adequate financing and to consummate
transactions in this highly competitive environment.
Royalty Relief
In November 2001, we received notification from the U.S. Minerals
Management Service ("MMS") that our application for deepwater royalty relief for
the Garden Banks 409 property had been approved under a federal law that was
enacted in November 1995. The royalty relief provides for the abatement of
federal royalty on the first 52.5 MMBoe of oil and gas production from the
property. The royalty abatement continues in effect for each calendar year,
unless realized prices exceed certain prescribed thresholds. If the prescribed
threshold prices are exceeded during a calendar year, then royalty relief is
suspended and we would be required to pay royalties for that calendar year.
Regulation
Federal Regulation of Sales and Transportation of Natural Gas.
Historically, the transportation and sale for resale of natural gas in
interstate commerce is regulated pursuant to the Natural Gas Act of 1938 ("the
Natural Gas Act"), the Natural Gas Policy Act of 1978 and Federal Energy
Regulatory Commission ("FERC") regulations. In the past, the federal government
has regulated the prices at which natural gas could be sold. Deregulation of
natural gas sales by producers began with the enactment of the Natural Gas
Policy Act of 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol
Act, which removed all remaining Natural Gas Act of 1938 and Natural Gas Policy
Act of 1978 price and non-price controls affecting producer sales of natural gas
effective January 1, 1993.
Our sales of natural gas are affected by the availability, terms and cost
of pipeline transportation. The price and terms for access to pipeline
transportation are subject to extensive federal regulation. Beginning in April
1992, the FERC issued Order No. 636 and a series of related orders, which
required interstate pipelines to provide open-access transportation on a not
unduly discriminatory basis for all natural gas shippers. The FERC stated that
Order No. 636 and the FERC's future restructuring activities are intended to
foster increased competition within all phases of the natural gas industry.
Although the regulations instituted by Order No. 636 do not directly apply to
our production and marketing activities, they do 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. Subsequent to Order No. 636, the FERC
continued to modify its regulations regarding the transportation of natural gas.
8
In 2000, the FERC issued Order No. 637 and subsequent orders, which we
refer to collectively as "Order No. 637." Order No. 637 imposes a number of
additional reforms designed to enhance competition in natural gas markets. Among
other things, Order No. 637 revised the FERC pricing policy by waiving price
ceilings for short-term released capacity for a two-year period ending September
30, 2002, and effected changes in the FERC regulations relating to scheduling
procedures, capacity segmentation, pipeline penalties, rights of first refusal
("ROFR") and information reporting. Several parties subsequently filed appeals
in the Court of Appeals for the District of Columbia Circuit ("D.C. Circuit")
seeking court review of various aspects of Order 637, particularly (i) the right
of customers to segment their contractual capacity in a manner that allows a
forwardhaul/backhaul to a single point and (ii) the ROFR granted to existing
customers to extend contracts beyond the end of the contract's term. On April 5,
2002, the D.C. Circuit generally affirmed Order No. 637 but remanded certain
issues to FERC, including the forwardhaul/backhaul and ROFR issues. The FERC on
remand affirmed its position on the forwardhaul/backhaul issue but reversed
itself on the ROFR issue. Requests for rehearing of this order are currently
pending at FERC.
Order No. 637 also required interstate natural gas pipelines to
implement the policies mandated by the order through individual compliance
filings. The FERC has now ruled on a number of the individual compliance
filings, although its decisions in such proceedings remain subject to the
outcome of pending rehearing requests and possible court appeals.
In April 1999, the FERC issued Order No. 603, which implemented new
regulations governing the procedure for obtaining authorization to construct and
operate new pipeline facilities or to abandon facilities under Section 7 of the
Natural Gas Act. In September 1999, the FERC issued a related policy statement
establishing a presumption in favor of requiring owners of new pipeline
facilities to charge rates for service on new pipeline facilities based solely
on the costs associated with such new pipeline facilities.
We cannot predict what further action the FERC will take on these or
related matters, nor can we accurately predict whether the FERC'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 FERC implements with
regard 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 FERC 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 in April 2000, the FERC 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
terms and conditions of service. The reporting requirements established by the
FERC in Order No. 639 may apply, in certain circumstances, to operators of
production platforms and other facilities on the Outer Continental Shelf, with
respect to gas movements across such facilities. Among FERC's stated purposes in
issuing such rules was the desire to increase transparency in the market and 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. In January 2002, the U.S. District Court for the District of
Columbia permanently enjoined the FERC from enforcing Order No. 639 and related
orders. FERC's appeal of the district court's decision is currently pending at
the D.C. Circuit.
The FERC retains authority under the Outer Continental Shelf Lands Act to
exercise jurisdiction over gatherers and other entities outside the reach of its
Natural Gas Act jurisdiction if necessary to insure non-discriminatory access to
service on the Outer Continental Shelf. We do not believe that any FERC 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.
9
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC 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
FERC 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 MMS pursuant
to the Outer Continental Shelf Lands Act. These leases are issued through
competitive bidding and contain relatively standardized terms. These leases
require compliance with detailed MMS regulations and orders that are subject to
interpretation and change by the MMS.
For offshore operations, lessees must obtain MMS 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 MMS prior to the commencement of drilling. The MMS has
promulgated regulations requiring offshore production facilities located on the
Outer Continental Shelf to meet stringent engineering and construction
specifications. The MMS 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 MMS 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 MMS generally requires that lessees have substantial net worth or post bonds
or other acceptable assurances that such obligations will be satisfied. The cost
of these bonds or assurances can be substantial, and there is no assurance that
they can be obtained in all cases. We currently have several supplemental bonds
in place. Under some circumstances, the MMS 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 MMS 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 MMS. The MMS has issued
a final rule that governs the calculation of royalties and the valuation of
crude oil produced from federal leases. This rule amends the way that the MMS
values crude oil produced from federal leases for determining royalties by
eliminating posted prices as a measure of value and relying instead on
arm's-length sales prices and spot market prices as indicators of value. The
lawfulness of the new rule has been challenged at the D.C. Circuit. We cannot
predict whether this new rule will be upheld, nor can we predict whether the MMS
will take further action on this matter. We believe this rule will not have a
material impact on our financial condition, liquidity or results of operations.
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 FERC jurisdiction under the Interstate Commerce Act. In
other instances, the ability to transport and sell such products is dependent on
pipelines whose rates, terms and conditions of service are subject to regulation
by state regulatory bodies under state statutes.
The regulation of pipelines that transport crude oil, condensate and
natural gas liquids is generally more light-handed than the FERC'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 FERC 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 FERC Order No. 561, issued in October 1993, the FERC
implemented regulations generally grandfathering all previously unchallenged
interstate pipeline rates and made these rates subject to an indexing
methodology. Under this indexing
10
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. As provided for in Order No. 561, in July 2000,
the FERC issued a Notice of Inquiry seeking comment on whether to retain or to
change the existing oil rate-indexing method. In December 2000, the FERC issued
an order concluding that the rate index reasonably estimated the actual cost
changes in the pipeline industry and should be continued for another 5-year
period, subject to review in July 2005. In February 2003, on remand of its
December 2000 order from the D.C. Circuit, the FERC changed the rate indexing
methodology to the Producer Price Index for Finished Goods, but without the
subtraction of 1% as had been done previously. The FERC made the change
prospective only, but did allow oil pipelines to recalculate their maximum
ceiling rates as though the new rate indexing methodology had been in effect
since July 1, 2001.
With respect to intrastate crude oil, condensate and natural gas liquids
pipelines subject to the jurisdiction of state agencies, such state regulation
is generally less rigorous than the regulation of interstate pipelines. State
agencies have generally not investigated or challenged existing or proposed
rates in the absence of shipper complaints or protests. Complaints or protests
have been infrequent and are usually resolved informally.
We do not believe that the regulatory decisions or activities relating to
interstate or intrastate crude oil, condensate, or natural gas liquids pipelines
will affect us in a way that materially differs from the way it affects other
crude oil, condensate, and natural gas liquids producers or marketers.
Environmental Regulations. Our operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Public interest in the
protection of the environment has increased dramatically in recent years.
Offshore drilling in some areas has been opposed by environmental groups and, in
some areas, has been restricted. To the extent laws are enacted or other
governmental action is taken that prohibits or restricts offshore drilling or
imposes environmental protection requirements that result in increased costs to
the natural gas and oil industry in general and the offshore drilling industry
in particular, our business and prospects could be adversely affected.
The Oil Pollution Act of 1990 and related regulations impose a variety of
regulations on "responsible parties" related to the prevention of oil spills and
liability for damages resulting from such spills in U.S. waters. A "responsible
party" includes the owner or operator of a facility or vessel, or the lessee or
permittee of the area in which an offshore facility is located. The Oil
Pollution Act of 1990 assigns liability to each responsible party for oil
removal costs and a variety of public and private damages. While liability
limits apply in some circumstances, a party cannot take advantage of liability
limits if the spill was caused by gross negligence or willful misconduct or
resulted from violation of a federal safety, construction or operating
regulation. If the party fails to report a spill or to cooperate fully in the
cleanup, liability limits likewise do not apply. Even if applicable, the
liability limits for offshore facilities require the responsible party to pay
all removal costs, plus up to $75.0 million in other damages. Few defenses exist
to the liability imposed by the Oil Pollution Act of 1990.
The Oil Pollution Act of 1990 also requires a responsible party to submit
proof of its financial responsibility to cover environmental cleanup and
restoration costs that could be incurred in connection with an oil spill. As
amended by the Coast Guard Authorization Act of 1996, the Oil Pollution Act of
1990 requires parties responsible for offshore facilities to provide financial
assurance in the amount of $35.0 million to cover potential Oil Pollution Act of
1990 liabilities. This amount can be increased up to $150.0 million if a study
by the MMS indicates that an amount higher than $35.0 million should be
required. On August 11, 1998, the
11
MMS adopted a rule implementing the 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 U.S. 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 are also
subject to similar state and local water quality laws and regulations
for any production or drilling activities that occur 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
instate 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 anymore burdensome to us than to other companies our size involved in
similar 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.
12
Our management believes that we are in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse impact on us.
U.K. Regulation of Natural Gas and Oil Production. Pursuant to the
Petroleum Act 1998, all natural gas and oil reserves contained in properties
located in the U.K. are the property of the U.K. government. The development and
production of natural gas and oil reserves in the U.K. Sector - North Sea
requires a petroleum production license granted by the U.K. government. Prior to
developing a field, we are required to obtain from the Secretary of State for
Trade and Industry (the "Secretary of State") a consent to develop that field.
We would be required to obtain the consent of the Secretary of State prior to
transferring an interest in a license.
The terms of the U.K. petroleum production licenses are based on model
license clauses applicable at the time of the issuance of the license. Licenses
frequently contain regulatory provisions governing matters such as working
method, pollution and training, and reserve to the Secretary of State the power
to direct some of the licensee's activities. For example, a licensee may be
precluded from carrying out development or production activities other than with
the consent of the Secretary of State or in accordance with a development plan
which the Secretary of State for Trade and Industry has approved. Breach of
these requirements may result in the revocation of the license. In addition,
licenses that we acquire may require us to pay fees and royalties on production
and also impose certain other duties on us.
Our operations in the U.K. are subject to the Petroleum Act 1998, which
imposes a health and safety regime on offshore natural gas and oil production
activities. The Petroleum Act 1998 also regulates the abandonment of facilities
by licensees. In addition, the Mineral Workings (Offshore Installations) Act
provides a framework in which the government can impose additional regulations
relating to health and safety. Since its enactment, a number of regulations have
been promulgated relating to offshore construction and operation of offshore
production facilities. Health and safety offshore is further governed by the
Health and Safety at Work Act 1974 and applicable regulations. Our operations
are also subject to environmental laws and regulations imposed by both the
European Union and the U.K. government.
Petroleum production licenses require the prior approval of the Secretary
of State of a licensee to act as operator. The operator under a license
organizes or supervises all or any of the development and production operations
of natural gas and oil properties subject thereto. As an operator, we may obtain
operational services from third parties, but will remain fully responsible for
the operations as if we conduct them ourselves.
Our operations in the U.K. may entail the construction of offshore
pipelines, which are subject to the provisions of the Petroleum Act 1998 and
other legislation. The Petroleum Act 1998 requires a license to construct and
operate a pipeline in U.K. North Sea, including its continental shelf. Easements
to permit the laying of pipelines must be obtained from the Crown Estate
Commissioners prior to their construction. We plan to use capacity in existing
offshore pipelines in order to transport our gas. However, access to the
pipelines of a third party would need to be obtained on a negotiated basis, and
there is no assurance that we can obtain access to existing pipelines or, if
access is obtained, it may only be on terms that are not favorable to us.
The natural gas we produce may be transported through the U.K.'s onshore
national gas transmission system, or NTS. The NTS is owned by a licensed gas
transporter, BG Transco plc ("Transco"). The terms on which Transco must
transport gas are governed by the Gas Acts of 1986 and 1995, the gas
transporter's license issued to Transco under those Acts and a network code. For
us to use the NTS, we must obtain a shipper's license under the Gas Acts and
arrange to have gas transported by Transco within the NTS. We will therefore be
subject to the network code, which imposes obligations to payment, gas flow
nominations, capacity booking and system imbalance. Applying for and complying
with a shipper's license, and acting as a gas shipper, is expensive and
administratively burdensome. Alternatively, we may sell natural gas `at the
beach' before it enters the NTS or arrange with an existing gas shipper for them
to ship the gas through the NTS on our behalf.
13
Employees
At December 31, 2002 we had 39 full-time employees in our Houston office
and seven full-time employees and seven contract personnel in our London office.
None of our employees are covered by a collective bargaining agreement. From
time to time, we use the services of independent consultants and contractors to
perform various professional services, particularly in the areas of
construction, design, well-site 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.
Item 2. Properties
General
We are engaged in the acquisition, development and production of natural
gas and oil properties primarily in the Gulf of Mexico and the North Sea. At
December 31, 2002, we had leasehold and other interests in 50 offshore blocks,
29 platforms and 70 wells, including six subsea wells, in the Gulf of Mexico. We
operate 55 of these 70 wells, including all of the subsea wells, and 76% of our
offshore platforms. We also held interests in seven blocks and one
company-operated subsea well located in the U.K. Sector - North Sea. Our average
working interest in our properties at December 31, 2002 was approximately 82%.
As of December 31, 2002, we had leasehold interests located in the Gulf of
Mexico and the U.K. Sector - North Sea covering approximately 250,000 gross and
196,000 net acres.
Acquisitions and Dispositions
Gulf of Mexico
During 2002, we entered into a farm-in agreement to acquire a 100% working
interest in one block with associated proved reserves of approximately 4.7 Bcf,
based on third party reservoir engineering estimates at year-end. We plan to
develop this block in 2003. In 2003, we entered into an agreement whereby a
third party received a 25% working interest in this block in exchange for paying
a disproportionate share of all costs prior to first production.
In addition, we acquired another block for approximately $1.0 million. This
block, along with the block immediately to the south which we did not acquire,
contains an accumulation of oil and gas. Since the well that identified proved
reserves is located on the southern block and due to the strict limitations to
declare reserves as proved, we are unable to record any proved reserves with
this acquisition.
U.K. Sector - North Sea
In 2001, we acquired interests in three properties (five blocks) in the
North Sea which included a 100% interest in one block ("Helvellyn"), a 50%
interest in one block ("Venture") and an 86% interest in three blocks ("Tors").
Helvellyn. In August 2002 we entered into an agreement, which was completed
on September 30, 2002, whereby we assigned 50% of our working interest in the
Helvellyn development in the U.K. Sector - North Sea to a joint venture partner.
The terms of the agreement required the other party to pay a disproportionate
share of the development costs on the project. The partner's share of
development costs totaled $28.9 million through December 31, 2002, of which
$17.3 million was paid to us in cash, $11.0 million is included in accounts
receivable and $0.6 million is included as a receivable in other long term
assets. We retained a 50% working interest and continued as the operator of the
field.
14
Tors. In February 2002 the U.K. Department of Trade and Industry directly
awarded us a 75% working interest in two lease blocks. The lease sale in the
U.K. is referred to as a "round" and the award is known as an "out of round"
award. We paid no acquisition costs and net proved reserves for these properties
at December 31, 2002, were approximately 20.3 Bcf, based on third party
reservoir engineering estimates at year-end. These two blocks will become a
component of our Tors development. Neither of the properties were producing when
acquired and we expect to pursue development operations in 2004 and 2005.
In October 2002 we entered into an earn-in agreement whereby we assigned an
11% interest in three blocks acquired in 2001 to a joint venture partner in
return for them funding part of the block's development costs. We retained a 75%
working interest and continued as the operator. As of December 31, 2002, these
blocks had not yet been developed.
Dutch Sector - North Sea
In February 2003, we acquired a 50% working interest in a block located in
the Dutch Sector - North Sea. First production is expected some time in 2004.
The remaining 50% interest is owned by a Dutch company who participates on
behalf of the Dutch state. This acquisition expands our offshore development
strategy and presents an extension of substantial opportunities for us.
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, 2002 based on
reserve reports prepared by Ryder Scott Company, L.P. for our domestic reserves
and Troy-Ikoda Limited for our U.K. reserves.
Proved Reserves
-------------------------------------------------
Developed Undeveloped Total
------------- --------------- -----------
Gulf of Mexico
Natural gas (MMcf) .................................... 34,068 68,370 102,438
Oil and condensate (MBbls) ............................ 2,318 3,422 5,740
Total proved reserves (MMcfe) ......................... 47,976 88,903 136,879
U. K. Sector - North Sea
Natural gas (MMcf) .................................... - 93,100 93,100
Total
Natural gas (MMcf) .................................... 34,068 161,470 195,538
Oil and condensate (MBbls) ............................ 2,318 3,422 5,740
Total proved reserves (MMcfe) ......................... 47,976 182,003 229,979
15
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. In accordance with the
Securities and Exchange Commission ("SEC") requirements, we 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. 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.
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, 2002, all of our reserves in the U.K. Sector - North Sea and
approximately 65% of our estimated equivalent net proved reserves in the Gulf of
Mexico were undeveloped. Recovery of undeveloped reserves generally requires
significant capital expenditures and successful drilling and completion
operations. The reserve data assumes that we will make these expenditures.
Although we estimate our reserves and the costs associated with developing them
in accordance with industry standards, the estimated costs may be inaccurate,
development may not occur as scheduled and results may not be as estimated.
Drilling Activity
The following table shows our drilling and completion activity. In the
table, "gross" refers to the total wells in which we have a working interest and
"net" refers to gross wells multiplied by our working interest in such wells. We
did not drill or complete any exploratory wells in any period presented.
Years Ended December 31,
---------------------------------------------------------------
2002 2001 2000
-------------------- -------------------- -------------------
Gross Net Gross Net Gross Net
--------- -------- --------- -------- --------- --------
Development Wells:
Productive - Gulf of Mexico .................. - - 8.0 6.3 12.0 11.0
Nonproductive - Gulf of Mexico ............... - - 1.0 1.0 1.0 1.0
Drilling at end of period - Gulf of Mexico ... 1.0 1.0 - - - -
Drilling at end of period - U.K. North Sea ... 1.0 0.5 - - - -
--------- --------- -------- ------- ------- -------
Total 2.0 1.5 9.0 7.3 13.0 12.0
========= ========= ======== ======= ======= =======
Productive Wells
The following table presents the number of productive natural gas and oil
wells in which we owned an interest as of December 31, 2002.
Natural Gas Wells Oil Wells
--------------------- -----------------
Gross Net Gross Net
--------- --------- -------- ------
Gulf of Mexico ............................................. 30.0 23.8 9.0 4.4
======== ========= ======== ======
Multiple completion wells included above ................... 9.0 7.5 - -
16
Acreage
The following table summarizes our developed and undeveloped acreage
holdings at December 31, 2002. Acreage in which ownership interest is limited to
royalty, overriding royalty and other similar interests is excluded (in acres):
Developed (1) Undeveloped (2) Total
------------------- ------------------ ------------------
Gross Net Gross Net Gross Net
------- -------- -------- ------- ------- --------
Gulf of Mexico .............................. 147,893 118,364 36,177 34,927 184,070 153,291
U.K. Sector - North Sea. .................... - - 66,148 42,524 66,148 42,524
--------- --------- --------- --------- --------- ---------
147,893 118,364 102,325 77,451 250,218 195,815
========= ========= ========= ========= ========= =========
- ------------------
(1) Developed acres are acres spaced or assigned to productive wells.
(2) Undeveloped acres are acres on which wells have not been drilled or
completed to a point that would permit the production of commercial
quantities of natural gas and oil, regardless of whether such acreage
contains proved reserves.
Production and Pricing Data
Information on production and pricing data is contained in Item 7. -
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Results of Operations".
Item 3. Legal Proceedings
On August 28, 2001 ATP entered into a written agreement to acquire a
property in the Gulf of Mexico during September 2001. On October 9, 2001 the
agreement was amended to ultimately extend the closing date until October 31,
2001 in exchange for payments made by ATP totaling $3.0 million. This amendment
also contained an arrangement whereby if ATP did not close on the property, and
if sellers sold the property to a third party with a sale that met specific
contract requirements, ATP would be required to execute a six month note for
payment of the differential. Since ATP did not obtain the financing for the
acquisition by October 31, 2001, the transaction did not close by that date;
however, the parties' intensive work toward closing continued beyond that date
without interruption.
While working on the closing for the property with ATP, the sellers sold
the property to a third party without informing ATP until after the closing had
taken place. ATP filed an action in the District Court of Harris County, Texas
against the sellers, generally alleging improper sale of the offshore property
to a third party and breach of contract, and seeking unspecified damages from
the sellers. The case is encaptioned ATP Oil & Gas Corporation vs. Legacy
Resources Co., L.P. et al, No. 2001-63224 in the 269th Judicial District Court
of Harris County, Texas. At the same time sellers notified ATP of their sale to
a third party, the sellers had a demand made upon ATP for execution of a six
month note for the amount of an alleged differential of approximately $12.3
million plus interest at 16%. Substantiation of the amount and validity of the
demand could not be ascertained based on the content of the demand received. ATP
contested the entire demand. The judge has abated the litigation, until
arbitration pursuant to the underlying agreements between the sellers and ATP is
completed. A tentative date of May 19, 2003 has been scheduled for the
arbitration with an alternative date in September 2003. Due to the inherent
uncertainties involving contested facts and legal issues a prediction as to the
likely outcome cannot be made with any degree of certainty, and we have not
accrued any amount related to this matter. While we are seeking recovery of the
amounts previously paid and discussed above, the $3.0 million has been charged
to earnings along with other costs related to this matter. ATP intends to
vigorously defend against the sellers' claims and forcefully pursue its own
claims in this matter.
In August 2001, Burlington Resources Inc. filed suit against ATP alleging
formation of a contract with ATP and our breach of the alleged contract. The
complaint seeks compensatory damages of approximately $1.1 million. We believe
that this claim is without merit, and we intend to defend it vigorously.
We are also, in the ordinary course of business, a claimant and/or
defendant in various legal proceedings. Management does not believe that the
outcome of these legal proceedings, individually, and in the aggregate will have
a materially adverse effect on our financial condition, results of operations or
cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of security holders during the fourth
quarter of 2002.
17
Executive Officers of the Company
Set forth below are the names, ages (as of March 21, 2003) and titles of
the persons currently serving as executive officers of the Company. All
executive officers hold office until their successors are elected and qualified.
Name Age Position
- ---- --- --------
T. Paul Bulmahn .......................... 59 Chairman and President
Gerald W. Schlief ........................ 55 Senior Vice President
Albert L. Reese, Jr. ..................... 53 Senior Vice President and Chief Financial Officer
Leland E. Tate. .......................... 55 Senior Vice President, Operations
John E. Tschirhart. ...................... 52 Senior Vice President, General Counsel
T. Paul Bulmahn has served as our Chairman and President since he founded
the company in 1991. 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, he served the Railroad
Commission of Texas, the Public Utility Commission and the Interstate Commerce
Commission as an administrative law judge.
Gerald W. Schlief 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. has served as our Chief Financial Officer since March
1999 and, in a consulting capacity, as our director of finance from 1991 until
March 1999. He was also named Senior Vice President in August 2000. From 1986 to
1991, Mr. Reese was employed with the Harbert Corporation where he established a
registered investment bank for the company to conduct project and corporate
financings for energy, co-generation, and small power activities. From 1979 to
1986, Mr. Reese served as chief financial officer of Plumb Oil Company and its
successor, Harbert Energy Corporation. Prior to 1979, Mr. Reese served in
various capacities with Capital Bank in Houston, the independent accounting firm
of Peat, Marwick & Mitchell, and as a partner in Arnold, Reese & Swenson, a
Houston-based accounting firm specializing in energy clients.
Leland E. Tate has served as our Senior Vice President, Operations, since
August 2000. Prior to joining ATP, Mr. Tate worked for over 30 years with
Atlantic Richfield Company ("ARCO"). From 1998 until July 2000, Mr. Tate served
as the President of ARCO North Africa. He also was Director General of Joint
Ventures at ARCO from 1996 to 1998. From 1994 to 1996, Mr. Tate served as ARCO's
Vice President Operations & Engineering, where he led technical negotiations in
field development. Prior to 1994, Mr. Tate's positions with ARCO included
Director of Operations, ARCO British Ltd.; Vice President of Engineering, ARCO
International; Senior Vice President Marketing and Operations, ARCO Indonesia;
and for three years was Vice President and District Manager in Lafayette,
Louisiana.
John E. Tschirhart joined us in November 1997 and has served as our General
Counsel since March 1998. Mr. Tschirhart was named Senior Vice President in July
2001 and served as Managing Director of ATP Oil & Gas (UK) Limited from May 2000
to May 2001. From 1993 to November 1997, Mr. Tschirhart worked as a partner at
the law firm of Tschirhart and Daines, a partnership in Houston, Texas. From
1985 to 1993 Mr. Tschirhart was in private practice handling civil litigation
matters including oil and gas and employment law. From 1979 to 1985, he was with
Coastal Oil & Gas Corporation and from 1974 to 1979 he was with Shell Oil
Company.
18
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Our authorized capital stock consists of 100,000,000 shares of common
stock, par value $0.001 per share, and 10,000,000 shares of preferred stock, par
value $0.001 per share. There were 20,338,753 shares of common stock and no
shares of preferred stock outstanding as of March 21, 2003. There were 61
holders of record of our common stock as of March 21, 2003. Our common stock is
traded on the Nasdaq National Market under the ticker symbol ATPG. There was no
public market for our common stock before February 6, 2001.
The following tables sets forth the range of high and low closing sales
prices for the common stock as reported on the Nasdaq National Market for the
periods indicated below:
High Low
---------- -----------
2002:
-----
4th Quarter $ 4.49 $ 2.78
3rd Quarter 3.40 2.51
2nd Quarter 4.77 2.50
1st Quarter 5.00 1.47
2001:
-----
4th Quarter $ 7.15 $ 2.00
3rd Quarter 12.00 6.61
2nd Quarter 12.96 8.71
1st Quarter 14.56 9.88
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.
Securities Authorized for Issuance under Equity Compensation Plans
The following table includes information regarding our equity compensation
plans as of the year ended December 31, 2002:
Number of
securities Weighted Number of
to be issued average securities remaining
upon exercise exercise price available for future
of outstanding of outstanding issuance under equity
Plan Category options options compensation plans
- ------------------------------------------- ---------------- --------------- ----------------------
Equity compensation plans
approved by security holders 1,685,147 $ 8.29 4,647,569
Equity compensation plans
not approved by security holders - - -
---------------- ----------------------
1,685,147 $ 8.29 4,647,569
================ ======================
19
Item 6. Selected Financial Data
(In thousands, except per share data)
The selected historical financial information was derived from, and is
qualified by reference to our consolidated financial statements, including the
notes thereto, appearing elsewhere in this report. The following data should be
read in conjunction with "Item 7. - Management's Discussion and Analysis of
Financial Condition and Results of Operations".
Years Ended December 31,
-------------------------------------------------------------------
2002 2001 2000 1999 1998
----------- ----------- ----------- ----------- -----------
Statement of Operations Data:
Revenues:
Oil and gas production ............................ $ 88,151 $ 105,757 $ 75,940 $ 34,981 $ 20,410
Gas sold - marketing .............................. 6,272 7,417 8,015 7,703 -
Gain on sale of oil and gas properties ............ - - 33 287 -
----------- ----------- ----------- ----------- -----------
Total revenues .................................. 94,423 113,174 83,988 42,971 20,410
----------- ----------- ----------- ----------- -----------
Cost and operating expenses:
Lease operating ................................... 16,764 14,806 11,559 5,587 3,193
Gas purchased - marketing ......................... 6,087 7,218 7,788 7,402 -
Geological and geophysical expenses ............... 154 1,068 - - -
General and administrative ....................... 10,287 9,981 5,409 3,541 2,591
Non-cash compensation expense
(general and administrative) .................... 595 3,364 - - -
Depreciation, depletion and amortization .......... 43,390 53,428 40,569 22,521 17,442
Impairment of oil and gas properties .............. 6,844 24,891 10,838 7,509 5,072
Loss on unsuccessful property acquisition ......... - 3,147 - - -
Other expense ..................................... - - 450 - -
----------- ----------- ----------- ----------- -----------
Total operating expenses .......................... 84,121 117,903 76,613 46,560 28,298
----------- ----------- ----------- ----------- -----------
Income (loss) from operations ........................ 10,302 (4,729) 7,375 (3,589) (7,888)
Other income (expense):
Interest income ................................... 73 884 451 202 141
Interest expense .................................. (10,418) (10,039) (11,907) (9,399) (7,963)
Other income ...................................... 1,081 - - - -
Realized loss on derivative instruments ........... (153) (19,348) (4,662) - -
Unrealized gain (loss) on derivative instruments... (8,166) 1,265 (7,249) - -
----------- ----------- ----------- ----------- -----------
Loss before income taxes and
extraordinary item ................................ (7,281) (31,967) (15,992) (12,786) (15,710)
Income tax benefit-deferred ....................... 2,581 11,186 5,594 1,829 -
----------- ----------- ----------- ----------- -----------
Loss before extraordinary item ....................... (4,700) (20,781) (10,398) (10,957) (15,710)
Extraordinary item, net of tax ....................... - (602) - 29,185 -
----------- ----------- ----------- ----------- -----------
Net income (loss) .................................... $ (4,700) $ (21,383) $ (10,398) $ 18,228 $ (15,710)
=========== =========== =========== =========== ===========
Weighted average number of common
shares outstanding - basic and diluted ............ 20,315 19,704 14,286 14,286 11,926
Loss per common share before extraordinary
item - basic and diluted .......................... $ (0.23) $ (1.06) $ (0.73) $ (0.77) $ (1.32)
Net income (loss) per common share:
Basic and diluted ............................... $ (0.23) $ (1.09) $ (0.73) $ 1.28 $ (1.32)
Balance Sheet Data:
Cash and cash equivalents ............................ $ 6,944 $ 5,294 $ 18,136 $ 17,779 $ 3,411
Working capital ...................................... (13,699) (29,071) (3,835) 14,115 (5,106)
Net oil and gas properties ........................... 119,036 133,033 98,725 72,278 47,612
Total assets ......................................... 182,055 177,564 161,993 107,054 61,354
Total debt ........................................... 86,387 100,111 116,529 91,723 62,690
Total liabilities .................................... 143,508 132,572 175,172 109,835 82,363
Shareholders' equity (deficit) ....................... 38,547 44,992 (13,179) (2,781) (21,009)
20
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Overview
We are engaged in the acquisition, development and production of natural
gas and oil properties in the Gulf of Mexico and in the North Sea. We primarily
focus our efforts on natural gas and oil properties with proved undeveloped
reserves that are economically attractive to us but are not strategic to major
or exploration-oriented independent oil and gas companies. We attempt to achieve
a high return on our investment in these properties by limiting our up-front
acquisition costs and by developing our acquisitions quickly.
Critical Accounting Policies and Estimates
Our consolidated financial statements are prepared in conformity with
accounting principles generally accepted in the U.S., which require management
to make estimates and assumptions that affect the reported amounts of the assets
and liabilities and disclosures of contingent assets and liabilities as of the
date of the balance sheet as well as the reported amounts of revenues and
expenses during the reporting period. We routinely make estimates and judgments
about the carrying value of our assets and liabilities that are not readily
apparent from other sources. Such estimates and judgments are evaluated and
modified as necessary on an ongoing basis. We believe that of our significant
accounting policies (see Note 2, Summary of Significant Accounting Policies and
Estimates, to our Consolidated Financial Statements), the following may involve
a higher degree of judgment and complexity.
Oil and Gas Reserves
The process of estimating quantities of natural gas and crude oil reserves
is very complex, requiring significant decisions in the evaluation of all
available geological, geophysical, engineering and economic data. The data for a
given field may also change substantially over time as a result of numerous
factors including, but not limited to, additional development activity, evolving
production history and continual reassessment of the viability of production
under varying economic conditions. As a result, material revisions to existing
reserve estimates may occur from time to time. Although every reasonable effort
is made to ensure that reserve estimates reported represent the most accurate
assessments possible, the subjective decisions and variances in available data
for various fields make these estimates generally less precise than other
estimates included in the financial statement disclosures. We use the
units-of-production method to amortize our oil and gas properties. This method
requires us to amortize the capitalized costs incurred in developing a property
in proportion to the amount of oil and gas produced as a percentage of the
amount of proved reserves contained in the property. Accordingly, changes in
reserve estimates as described above will cause corresponding changes in
depletion expense recognized in periods subsequent to the reserve estimate
revision. See the Supplemental Information (unaudited) in our consolidated
financial statements for reserve data related to our properties.
Oil and Gas Producing Activities
We follow the "successful efforts" method of accounting for oil and gas
properties. Under this method, lease acquisition costs and intangible drilling
and development costs on successful wells and development dry holes are
capitalized.
Capitalized costs relating to producing properties are depleted on the
units-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 geological and geophysical testing are generally charged
to expense unless the costs can be specifically attributed to determining the
placement for a future developmental well location.
21
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.
We perform an impairment analysis whenever events or changes in
circumstances indicate that an asset's carrying amount may not be recoverable.
An impairment allowance is provided on an unproved property when we determine
that the property will not be developed. To determine if a depletable unit is
impaired, we compare the net carrying value of the depletable unit to the
undiscounted future net cash flows by applying management's estimates of future
oil and gas prices to the estimated future production of oil and gas reserves
over the economic life of the property. Future net cash flows are based upon our
independent reservoir 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 or other
development activities. For a property determined to be impaired, an impairment
loss equal to the difference between the carrying value and the estimated fair
value of the impaired property will be recognized. Fair value, on a depletable
unit basis, is estimated to be the present value of the aforementioned expected
future net cash flows. Any impairment charge incurred is recorded in accumulated
depreciation, depletion, impairment and amortization to reduce our recorded
basis in the asset. Each part of this calculation is subject to a large degree
of judgment, including the determination of the depletable units' estimated
reserves, future cash flows and fair value.
Contingent Liabilities
In preparing financial statements at any point in time, management is
periodically faced with uncertainties, the outcomes of which are not within its
control and will not be known for prolonged periods of time. As discussed in
Part I, Item 3. - "Legal Proceedings" and the Notes to Consolidated Financial
Statements, we are involved in actions, which if determined adversely, could
have a material negative impact on our financial position, results of operations
and cash flows. Management, with the assistance of counsel makes estimates, if
determinable, of ATP's probable liabilities and records such amounts in the
consolidated financial statements. Such estimates may be the minimum amount of a
range of probable loss when no single best estimate is determinable. Disclosure
is made, when determinable, of any additional possible amount of loss on these
claims, or if such estimate cannot be made, that fact is disclosed. Along with
our counsel, we monitor developments related to these legal matters and, when
appropriate, we make adjustments to recorded liabilities to reflect current
facts and circumstances. Although it is difficult to predict the ultimate
outcome of these matters, management believes that the recorded amounts, if any,
are reasonable.
Price Risk Management Activities
As of July 1, 2002, we performed the requisite steps to qualify our
derivative instruments for hedge accounting treatment under the provisions of
Financial Accounting Standards Board ("FASB") Statement of Financial Accounting
Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133"), as amended. Under SFAS 133 all derivative instruments
are recorded on the balance sheet at fair value. Changes in the derivative's
fair value are recognized currently in earnings unless specific hedge accounting
criteria are met. For qualifying cash flow hedges, the gain or loss on the
derivative is deferred in accumulated other comprehensive income (loss) to the
extent the hedge is effective. For qualifying fair value hedges, the gain or
loss on the derivative is offset by related results of the hedged item in the
statement of operations. Gains and losses on hedging instruments included in
accumulated other comprehensive income (loss) are reclassified to oil and gas
revenues in the period that the related production is delivered. Derivative
contracts that do not qualify for hedge accounting treatment are recorded as
derivative assets and liabilities at market value in the consolidated balance
sheet, and the associated unrealized gains and losses are recorded as current
expense or income in the consolidated statement of operations. Prior to July 1,
2002, gains or losses from our derivative instruments were included in other
income (expense).
22
Based on a critical assessment of our accounting policies and the
underlying judgments and uncertainties affecting the application of those
policies, management believes that our consolidated financial statements provide
a meaningful and fair perspective of our company.
Results of Operations
The following table sets forth selected financial and operating information
for our natural gas and oil operations inclusive of the effects of price risk
management activities:
Years Ended December 31,
------------------------------------------------
2002 2001 2000
------------- ------------- -------------
Production:
Natural gas (MMcf) .................................... 17,732 20,957 22,410
Oil and condensate (MBbls) ............................ 1,454 790 345
------------- ------------- -------------
Total (MMcfe) ...................................... 26,457 25,696 24,477
============= ============= =============
Revenues (in thousands):
Natural gas ........................................... $ 56,659 $ 88,908 $ 94,051
Effects of risk management activities (1) ............. (2,764) (19,751) (26,729)
------------- ------------- -------------
Total .............................................. $ 53,895 $ 69,157 $ 67,322
============= ============= =============
Oil and condensate .................................... $ 32,756 $ 16,849 $ 10,112
Effects of risk management activities (1).............. (615) - (1,494)
------------- ------------- -------------
Total .............................................. $ 32,141 $ 16,849 $ 8,618
============= ============= =============
Natural gas, oil and condensate ....................... $ 89,415 $ 105,757 $ 104,163
Effects of risk management activities (1).............. (3,379) (19,751) (28,223)
------------- ------------- -------------
Total .............................................. $ 86,036 $ 86,006 $ 75,940
============= ============= =============
Average sales price per unit:
Natural gas (per Mcf) ................................. $ 3.20 $ 4.24 $ 4.20
Effects of risk management activities (per Mcf) ....... (0.16) (0.94) (1.19)
------------- ------------- -------------
Total (per Mcf) .................................... $ 3.04 $ 3.30 $ 3.01
============= ============= =============
Oil and condensate (per Bbl) .......................... $ 22.53 $ 21.33 $ 29.35
Effects of risk management activities (per Mcf) ....... (0.42) - (4.34)
------------- ------------- -------------
Total (per Bbl) .................................... $ 22.11 $ 21.33 $ 25.01
============= ============= =============
Natural gas, oil and condensate (per Mcfe) ............ $ 3.38 $ 4.12 $ 4.26
Effects of risk management activities (per Mcfe) ...... (0.13) (0.77) (1.16)
------------- ------------- -------------
Total (per Mcfe) ................................... $ 3.25 $ 3.35 $ 3.10
============= ============= =============
Expenses (per Mcfe):
Lease operating ....................................... $ 0.63 $ 0.58 $ 0.47
General and administrative ............................ 0.39 0.39 0.22
Depreciation, depletion and amortization .............. 1.64 2.08 1.66
- ----------------
(1) Represents the net loss on the settlement of derivatives attributable
to actual production.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
For the year ended December 31, 2002, we reported a net loss of $4.7
million, or $0.23 per share as compared to a net loss of $21.4 million, or $1.09
per share in 2001.
Oil and Gas Revenue. Excluding the effects of settled derivatives, our
revenue from natural gas and oil production for 2002 decreased 16% compared to
2001, from $105.8 million to $89.4 million. This decrease was primarily due to
an approximate 18% decrease in our average sales price per Mcfe from $4.12 per
Mcfe in 2001 to $3.38 in 2002. This decrease was partially offset by a 3%
increase in production volumes from 25.7 Bcfe to 26.5 Bcfe due primarily to two
properties that were completed and began production in 2002. Additionally, one
property was completed in September 2001 but did not contribute a full year of
production until 2002.
23
Early in the fourth quarter, we were forced to shut-in a majority of our
Gulf of Mexico production when Hurricane Lili, a Category 4 storm, blew through
the central Gulf. Our current production continues to be hampered by the damage
wrought by Hurricane Lili and we estimated a fourth-quarter impact of
approximately 1.0 Bcfe. We carry insurance, subject to normal
deductibles, that covers both the physical damage and loss of production income,
which will partially mitigate the financial impact of this hurricane.
Marketing Revenue. Revenues from natural gas marketing activities decreased
to $6.3 million in 2002 as compared to $7.4 million in 2001. This decrease was
due to a decrease in the sales price per MMBtu. The average sales price per
MMBtu decreased from $4.06 in 2001 to $3.44 in 2002. For more information
regarding this marketing activity, see Note 13 to the Consolidated Financial
Statements.
Lease Operating Expense. Our lease operating expense for 2002 increased 13%
from $14.8 million ($0.58 per Mcfe) to $16.8 million ($0.63 per Mcfe). This
increase was primarily the result of an increase in the number of producing
wells we own and an increase in their total production volume. Lease operating
expense per Mcfe increased due to higher than expected repairs and maintenance
costs on our platforms and costs incurred related to the hurricane and tropical
storm.
Gas Purchased-Marketing. Our cost of purchased gas was $6.1 million for
2002 compared to $7.2 million for 2001. The average gas cost decreased from
$3.96 per MMBtu in 2001 to $3.34 per MMBtu in 2002. For more information
regarding this marketing activity, see Note 13 to the Consolidated Financial
Statements.
Geological and Geophysical. In 2002, we recorded approximately $0.2 million
of costs related to the acquisition of 3-D seismic data purchased for certain
properties in the U.K Sector - North Sea. In 2001, we recorded $1.1 million of
these same costs on properties in both the Gulf of Mexico and the U.K Sector -
North Sea.
General and Administrative Expense. General and administrative expense
increased to $10.3 million for 2002 compared to $10.0 million for 2001. The
primary reason for the increase was the result of higher compensation related
costs in 2002 which was substantially offset by a bad debt allowance recorded in
2001.
Non-Cash Compensation Expense. In 2002, we recorded a non-cash charge to
compensation expense of approximately $0.6 million for options granted since
September 1999 through the date of our initial public offering ("IPO") on
February 5, 2001 (the "measurement date"). The total expected expense as of the
measurement date is recognized in the periods in which the option vests. Each
option is divided into three equal portions corresponding to the three vesting
dates (April 10, 2001, February 9, 2002, and February 9, 2003), with the related
compensation cost for each portion amortized straight-line over the period to
the vesting date. In 2001, we recorded a non-cash compensation expense of $2.9
million for the above options and an additional non-cash compensation expense of
$0.5 million related to certain options granted prior to September 1999 and
exercised during 2001. The additional expense was recorded as a result of the
manner in which those shares were exercised.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense ("DD&A") decreased 19% from $53.4 million in 2001 to
$43.4 million in 2002. The average DD&A rate was $1.64 per Mcfe during 2002
compared to $2.08 per Mcfe during 2001. This decrease in the rate was
attributable to (1) impairments taken in 2001, (2) higher than expected costs of
an abandonment completed in 2001 and (3) a new property brought on line in 2002
with a lower average DD&A rate than those properties producing in 2001.
24
Impairment Expense. On two of our properties in 2002 and eight of our
properties in 2001, the future undiscounted cash flows were less than their
individual net book value. As a result, we recorded impairments of $6.8 million
in 2002 and $24.9 million in 2001. The impairments in 2002 were primarily the
result of reductions in recoverable reserves. The impairments in 2001 were
primarily the result of drilling a non-commercial development well ($8.3
million), a decrease in expected future gas prices and reductions in recoverable
reserves. The impairments were calculated as the difference between the carrying
value and the estimated fair value of the impaired depletable unit.
Other Income (Expense). Effective July 1, 2002, we qualified for hedge
accounting treatment under the provisions of SFAS 133 and began recording any
gains or losses on settled derivative instruments as a component of oil and gas
revenue. The effective portion of any changes in the fair market value of open
positions at the end of the period is recorded in other comprehensive income
(loss). The loss on derivative instruments of $8.3 million in 2002 represents
amounts recorded prior to July 1, 2002 and is comprised of a realized loss of
$0.1 million for derivative contracts settled in the first half of 2002 and an
unrealized loss of $8.2 million representing the change in fair market value of
the open derivative positions at June 30, 2002. In 2001, we recorded a loss on
derivative instruments of $18.1 million. The net loss in 2001 was comprised of a
realized loss of $19.3 million for derivative contracts settled in the period
and an unrealized gain of $1.2 million representing the change in fair market
value of the open derivative positions at December 31, 2001.
Interest expense increased by $0.4 million over 2001 due to amounts owed on
a long-term contract with a third party and we capitalized $0.3 million of
interest for the year ended December 31, 2002 related to one property in the
U.K. Sector - North Sea.
Other income includes $0.6 million of accrued insurance proceeds related to
the loss of production from Hurricane Lili in October 2002 and the forgiveness
of interest of $0.4 million related to amounts owed on a long-term contract with
a third party. We filed an insurance claim during the fourth quarter of 2002
covering the estimated damages and lost production from the Gulf of Mexico
region resulting from the effects of Hurricane Lili in October 2002. Our
financial statements reflect probable amounts recoverable, net of deductibles,
of approximately $1.5 million for damages to ten properties and lost production
on four properties through December 31, 2002. The total claim will be determined
when the final documentation is received and approved and any remaining payment
related to 2003 will be recorded when we have a firm settlement commitment from
the insurance company.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
For the year ended December 31, 2001, we reported a net loss of $21.4
million, or $1.09 per share as compared to a net loss of $10.4 million, or $0.73
per share in 2000.
Oil and Gas Revenue. Excluding the effects of settled derivatives, our
revenue from natural gas and oil production for 2001 increased 2% over 2000,
from $104.2 million to $105.8 million. This increase resulted from a slight
increase in the price of natural gas and a 5% increase in production, partially
offset by a 27% decrease in the price of oil. The increase in production volumes
from 24.4 Bcfe to 25.7 Bcfe was attributable to 13 properties that were on
production during 2001 that were not on production during 2000. This increase in
production was offset by the natural decline in our existing offshore
properties. Risk management activities, which were included in oil and gas
revenues in 2000 would have decreased oil and natural gas revenues by $24.4
million, or $0.95 per Mcfe in 2001 and decreased $28.2 million, or $1.16 per
Mcfe in 2000.
Marketing Revenue. Revenues from natural gas marketing activities decreased
to $7.4 million in 2001 as compared to $8.0 million in 2000. This decrease was
due to a decrease in the sales price per MMBtu. The average sales price per
MMBtu decreased from $4.38 in 2000 to $4.06 in 2001. For more information
regarding this marketing activity, see Note 13 to the Consolidated Financial
Statements.
25
Lease Operating Expense. Our lease operating expense for 2001 increased 28%
from $11.6 million to $14.8 million. This increase was primarily the result of
an increase in the number of producing wells we own and an increase in their
total production volume. Additionally, the lease operating expense per Mcfe on
those properties acquired in 2001 was higher due to cost structures and contract
obligations in place at the time of acquisition. Transportation related costs
increased ($0.6 million) and workover spending decreased ($0.9 million) as
compared to 2000.
Gas Purchased-Marketing. Our cost of purchased gas was $7.2 million for
2001 compared to $7.8 million for 2000. The average gas cost decreased from
$4.26 per MMBtu in 2000 to $3.96 per MMBtu in 2001. For more information
regarding this marketing activity, see Note 13 to the Consolidated Financial
Statements.
Geological and Geophysical. In 2001, we recorded $1.1 million of costs
related to the acquisition of 3-D seismic data purchased for certain properties
in the Gulf of Mexico and the U.K. Sector - North Sea.
General and Administrative Expense. General and administrative expense
increased to $10.0 million for 2001 compared to $5.4 million for 2000. The
primary reason for the increase was the result of compensation and related
expenses due to an increase in the number of employees in our Houston office
from 28 at the end of 2000 to 39 at the end of 2001 ($0.9 million) and the
opening of our U.K. office in the third quarter of 2000 ($1.7 million). As a
result of becoming a public company in 2001, we incurred costs such as
insurance, filing fees, professional fees, investor relations expenses and other
expenses related to public company requirements ($1.3 million).
Non-Cash Compensation Expense. In 2001, we recorded a non-cash compensation
expense of $3.4 million. A portion of the expense ($2.9 million) is related to
options granted from September 1999 to the date of our IPO and is based on the
difference between the exercise price for those options and the fair market
value of our stock as determined by the IPO price of $14.00 per share. The
expense is recognized in the periods in which the options vest. Each option is
divided into three equal portions corresponding to the three vesting dates, with
the related compensation cost amortized straight-line over the period between
the IPO date and the vesting date. The remaining expense ($0.5 million) was
related to certain options granted prior to September 1999 and exercised in the
current year. The expense was recorded on those exercises as the method in which
those shares were exercised required us to account for the options under
variable accounting.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense increased 32% from $40.6 million in 2000 to $53.4
million in 2001. The average DD&A rate was $2.08 per Mcfe during 2001 compared
to $1.66 per Mcfe during 2000.
Impairment Expense. As of December 31, 2001, the future undiscounted cash
flows for our properties were $354.2 million and the net book value for the
properties was $157.9 million before current year impairment expense. At
December 31, 2000, the future undiscounted cash flows for our properties were
$931.2 million and the net book value for the properties was $109.6 million
before current year impairment expense. However, on eight of our properties in
2001 and three of our properties in 2000, the future undiscounted cash flows
were less than their individual net book value. As a result, we recorded
impairments of $24.9 million in 2001 and $10.8 million in 2000. The impairments
in 2001 were primarily the result of drilling a non-commercial development well
at our Main Pass 282 property ($8.3 million), a decrease in expected future gas
prices and reductions in recoverable reserves. In 2000, the impairments were
primarily the result of a reduction in recoverable reserves individually
attributable to the particular properties.
Other Income (Expense). In 2001, we recorded a loss on derivative
instruments of $18.1 million comprised of a realized loss of $19.3 million and
an unrealized gain of $1.2 million. The realized loss represents derivative
contracts settled in 2001, while the offsetting gain represents the fair market
value of the open derivative positions at December 31, 2001. Prior to the
adoption of SFAS 133, realized gains or losses
26
were recorded as a component of revenue. For 2000 we recorded an expense of $4.3
million ($1.7 million realized and $2.6 million unrealized) on a natural gas
derivative position as a result of our hedging position exceeding our expected
production in an upcoming period. In addition, we recorded an expense of $7.6
million ($3.0 million realized and $4.6 million unrealized) related to losses
associated with our written call option contracts. In both of these situations
in 2000, we were required to account for the positions using the mark-to-market
method.
Interest expense decreased from $11.9 million in 2000 to $10.0 million in
2001 primarily due to lower debt levels following the use of proceeds from our
IPO and as a result of lower interest rates. We capitalized zero and $0.7
million of interest for the years ended December 31, 2001 and 2000,
respectively.
Liquidity and Capital Resources
General
We have financed our acquisition and development activities through a
combination of project-based development arrangements, bank borrowings and
proceeds from our February 2001 IPO, as well as cash from operations and the
sale on a promoted basis of interests in selected properties. We intend to
finance our near-term development projects in the Gulf of Mexico and North Sea
through available cash flows and the potential sell down of interests in the
development projects. As operator of all of our projects in development, we have
the ability to significantly control the timing of most of our capital
expenditures. We believe the cash flows from operating activities combined with
our ability to control the timing of substantially all of our future development
and acquisition requirements will provide us with the flexibility and liquidity
to meet our future planned capital requirements.
However, future cash flows are subject to a number of variables including
changes in the borrowing base, the level of production from our properties, oil
and natural gas prices and the impact, if any, of commitments and contingencies.
Future borrowings under credit facilities are subject to variables including the
lenders' practices and policies, changes in the prices of oil and natural gas
and changes in our oil and gas reserves. A material reduction in the borrowing
base or the institution of a monthly reduction amount by our lenders would have
a material negative impact on our cash flows and our ability to fund future
obligations. No assurance can be given that operations and other capital
resources will provide cash in sufficient amounts to maintain planned levels of
operations and capital expenditures. Historically, in periods of reduced
availability of funds from either cash flows or credit sources we have delayed
planned capital expenditures and will continue do to so when necessary. While
the delay decreases the amount of capital expenditures in the current period, it
could negatively impact our future revenues and cash flows.
Cash Flows
Years Ended December 31,
------------------------------------
2002 2001 2000
---------- ---------- ----------
(in thousands)
Cash provided by (used in):
Operating activities ......... $ 51,298 $ 41,356 $ 57,157
Investing activities ......... (35,167) (110,810) (76,835)
Financing activities ......... (14,481) 56,612 20,035
Operating activities. Net cash provided by operating activities in 2002 was
$51.3 million compared to $41.4 million in 2001. The change in accounts payable
reflects the primary reason for this increase as we utilized a substantial
portion of our operating cash flow in 2001 to reduce amounts owed to third
parties. This increase was partially offset by an 18% decrease in our average
sales price per Mcfe. Restricted cash of $0.4 million represents funds set aside
to satisfy payment conditions in our drilling contract for development in the
U.K.
27
Investing activities. Cash used in investing activities decreased in 2002
to $35.2 million of which $34.9 was for acquisition and development activities.
We incurred no costs for two acquisitions made in 2002 and approximately $1.0
million for the acquisition of an undeveloped block in the Gulf of Mexico.
Developmental capital expenditures in the Gulf of Mexico and the North Sea were
approximately $17.5 million and $16.4 million, respectively. In 2001, capital
expenditures for acquisition and development were $25.9 million and $78.8
million, respectively, and $5.6 million was used to purchase the overriding
royalty interests associated with the repayment of our non-recourse debt.
Financing activities. Cash used in financing activities in 2002 represents
net principal payments on our credit facility. Cash provided from financing
activities in 2001 included the proceeds from our initial public offering in
February 2001 of $78.3 million, repayment of prior credit facilities of $119.9
million and proceeds of $100.0 million from our credit facility and promissory
note.
Amounts borrowed under our credit agreements were as follows for the dates
indicated (in thousands):
December 31,
------------------------
2002 2001
---------- -----------
Credit facility .................................................... $ 56,000 $ 70,000
Note payable, net of unamortized discount of $863 and $1,139 ....... 30,387 30,111
---------- -----------
Total debt ....................................................... $ 86,387 $ 100,111
========== ===========
Credit Facility
We have a $100.0 million senior-secured revolving credit facility which is
secured by substantially all of our U.S. oil and gas properties, as well as by
approximately two-thirds of the capital stock of our foreign subsidiaries and is
guaranteed by our wholly owned subsidiary, ATP Energy, Inc. The amount available
for borrowing under the credit facility is limited to the loan value, as
determined by the bank, of oil and gas properties pledged under the facility. At
December 31, 2002, the borrowing base was $56.0 million with no further
scheduled borrowing base reduction. If our outstanding balance exceeds our
borrowing base at any time, we are required to repay such excess within 30 days
and our interest rate during the time an excess exists is increased by 2.00%.
On March 25, 2003, we entered into an agreement with our lenders to defer
our scheduled borrowing base redetermination until the next scheduled
redetermination in May 2003. This agreement reaffirmed the current borrowing
base of $56.0 million and the borrowing base reduction amount of zero. As part
of this agreement we committed to reduce the amount outstanding under our
borrowing base by $6.0 million between March 28, 2003 and May 31, 2003.
Additionally, if the aggregate principal amount of the loan exceeds the required
month-end reductions of $1.5 million, $2.5 million and $2.0 million during
the period from March 28, 2003 to May 31, 2003, such principal amounts in excess
of the applicable period limits shall bear interest at a per annum rate of
interest equal to the adjusted reference rate plus 2%. Further, the lenders
agreed to raise the limit of advances available to be made to our foreign
subsidiaries and specified certain future events which would require our foreign
subsidiaries to return the incremental advances to the parent. On March 28,
2003, we made a payment of $1.5 million reducing our outstanding principal to
$54.5 million. At the next scheduled redetermination in May 2003, the lenders
can increase or decrease the borrowing base and re-establish the monthly
reduction amount. A material reduction in the borrowing base or a material
increase in the monthly reduction amount by the lender would have a material
negative impact on our cash flows and our ability to fund future operations.
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 0.25%, 0.50%, 0.75% or 1.00% depending on the amount
outstanding under the credit agreement. The interest on a Eurodollar loan is
equal to the Eurodollar rate, plus a margin of 2.25%, 2.50%, 2.875%, or 3.125%
depending on the amount outstanding under the credit facility. The credit
facility matures in May 2004. Our credit facility contains conditions and
restrictive provisions, among other things, (1) limiting us to enter into any
arrangement to sell or transfer any of our material property, (2) prohibiting a
merger into or consolidation with any other person or sell or dispose of all or
substantially all of our assets, (3) maintaining certain financial ratios and
(4) limitations on advances to our foreign subsidiaries.
28
Note Payable
Effective June 29, 2001, we issued a note payable to a purchaser for a face
principal amount of $31.3 million which matures in June 2005 and bears interest
at a fixed rate of 11.5% per annum. The note is secured by second priority liens
on substantially all of our U.S. oil and gas properties and is subordinated in
right of payment to our existing senior indebtedness. We executed an agreement
in connection with the note which contains conditions and restrictive provisions
and requires the maintenance of certain financial ratios. Upon consent of the
purchaser, which shall not be unreasonably withheld, the note may be repaid
prior to the maturity date with an additional repayment premium based on the
percentage of the principal amount paid, ranging from 4.5% during the first year
to 16.5% in the final year of payment. If the note is paid at maturity, the
maximum payment premium of 16.5% is required. The expected repayment premium is
being amortized to interest expense straight-line, over the term of the note
which approximates the effective interest method. The resulting liability is
included in other long-term liabilities on the consolidated balance sheet. In
July 2001, we received proceeds of $30.0 million in consideration for the
issuance of the note. The discount of $1.3 million is being amortized to
interest expense using the effective interest method. The amount available for
borrowing under the note is limited to the loan value of oil and gas properties
pledged under the note, as determined by the purchaser. The purchaser has the
right to make a redetermination of the borrowing base at least once every six
months. We were not notified of any change in the borrowing base in 2002. If our
outstanding balance exceeds the borrowing base at any time, we are required to
repay such excess within 10 days subject to the provisions of the agreement. A
material reduction in the borrowing base by the lender would have a material
negative impact on our cash flows and our ability to fund future obligations. As
of December 31, 2002, all of our borrowing base under the agreement was
outstanding.
As of December 31, 2002, we were in compliance with all of the financial
covenants of our credit facility and note payable agreements.
Working Capital
At December 31, 2002, we had a working capital deficit of approximately
$13.7 million, an improvement over our working capital deficit of $29.1 million
at December 31, 2001. In compliance with the definition of working capital in
our credit facility, which excludes current maturities of long-term debt and the
current portion of assets and liabilities from derivatives, we had working
capital of approximately $0.3 million at December 31, 2002 as compared to a
deficit of approximately $9.0 million at December 31, 2001. We believe the cash
flows from operating activities combined with our ability to control the timing
of substantially all of our future development and acquisition requirements will
provide us with the flexibility and liquidity to meet our future planned capital
requirements.
Our 2003 planned development and acquisition programs are projected to be
funded substantially by available cash flow from our 2003 operations. We believe
the cash flows from operating activities combined with our ability to control
the timing of substantially all of our future development and acquisition
requirements will provide us with the flexibility and liquidity to meet our
future capital requirements. In addition to these measures, we are currently in
discussions with potential investors to provide additional capital. These
discussions involve increases to our current credit facilities, new credit
facilities and the sale of interests in selected properties. We have also
explored the possibility of the issuance of new debt or equity. Completion of
any of these potential financings would expand our capabilities to further
reduce our outstanding indebtedness, improve our working capital position and
may allow us to expand or accelerate our future development and acquisition
programs. There can be no assurance however, that we will be successful in
negotiating any of these transactions or that the form of the transaction will
be acceptable to both the potential investor and our management or our board of
directors.
29
Commitments
We have various commitments primarily related to leases for office space,
other property and equipment and other agreements. We expect to fund these
commitments with cash generated from operations.
The following table summarizes certain contractual obligations at December
31, 2002 (in thousands):
Payments Due By Period
-----------------------------------------------------------
Less Than After
Contractual Obligation (1) Total 1 Year 1-2 Years 3-4 Years 4 Years
--------------------------------------- ----------- ----------- --------- ----------- -------
Total debt .................................. $ 87,250 $ 6,000 $ 81,250 $ - $ -
Interest expense on credit facility (2) ..... 3,971 2,940 1,031 - -
Interest expense on promissory note (3) ..... 12,332 4,940 7,392 - -
Non-cancelable operating leases ............. 2,949 539 910 503 997
Contractor commitment (4) ................... 11,146 -- 11,146 - -
----------- ----------- --------- ----------- -------
Total contractual obligations ........... $ 117,648 $ 14,419 $ 101,729 $ 503 $ 997
=========== =========== ========= =========== =======
- -------------
(1) Does not include any amounts related to contingencies discussed below.
(2) Includes interest based on rates and monthly reduction amounts in
effect at December 31, 2002.
(3) Includes 11.5% interest and repayment premium.
(4) Includes 12% interest.
Contingencies
On August 28, 2001 ATP entered into a written agreement to acquire a
property in the Gulf of Mexico during September 2001. On October 9, 2001 the
agreement was amended to ultimately extend the closing date until October 31,
2001 in exchange for payments made by ATP totaling $3.0 million. This amendment
also contained an arrangement whereby if ATP did not close on the property, and
if sellers sold the property to a third party with a sale that met specific
contract requirements, ATP would be required to execute a six month note for
payment of the differential. Since ATP did not obtain the financing for the
acquisition by October 31, 2001, the transaction did not close by that date;
however, the parties' intensive work toward closing continued beyond that date
without interruption.
While working on the closing for the property with ATP, the sellers sold
the property to a third party without informing ATP until after the closing had
taken place. ATP filed an action in the District Court of Harris County, Texas
against the sellers, generally alleging improper sale of the offshore property
to a third party and breach of contract, and seeking unspecified damages from
the sellers. The case is encaptioned ATP Oil & Gas Corporation vs. Legacy
Resources Co., L.P. et al, No. 2001-63224 in the 269th Judicial District Court
of Harris County, Texas. At the same time sellers notified ATP of their sale to
a third party, the sellers had a demand made upon ATP for execution of a six
month note for the amount of an alleged differential of approximately $12.3
million plus interest at 16%. Substantiation of the amount and validity of the
demand could not be ascertained based on the content of the demand received. ATP
contested the entire demand. The judge has abated the litigation, until
arbitration pursuant to the underlying agreements between the sellers and ATP is
completed. A tentative date of May 19, 2003 has been scheduled for the
arbitration with an alternative date in September 2003. Due to the inherent
uncertainties involving contested facts and legal issues a prediction as to the
likely outcome cannot be made with any degree of certainty, and we have not
accrued any amount related to this matter. While we are seeking recovery of the
amounts previously paid and discussed above, the $3.0 million has been charged
to earnings along with other costs related to this matter. ATP intends to
vigorously defend against the sellers' claims and forcefully pursue its own
claims in this matter.
In August 2001, Burlington Resources Inc. filed suit against ATP alleging
formation of a contract with ATP and our breach of the alleged contract. The
complaint seeks compensatory damages of approximately $1.1 million. We believe
that this claim is without merit, and we intend to defend it vigorously.
In 2001 we purchased three properties in the U.K. Sector - North Sea for
approximately $3.1 million. In accordance with the purchase agreement, we also
committed to pay future consideration contingent upon the successful development
and operation of the properties. The contingent consideration for each property
includes amounts to be paid upon achieving first commercial production and upon
achieving designated cumulative production levels. Active development is in
progress on our Helvellyn property and future development is planned on the
other two properties. First commercial production from the Helvellyn property
may occur sometime in the first half of 2003. Although a significant portion
of the work required has been completed, there remains significant additional
work to be performed before this property can produce commercially. That work
includes completion, hook-up, and testing of the pipeline and production
facilities and final negotiation of certain terms in our transportation and
processing agreements. Accordingly, there can be no assurance of eventual
production from this development until the aforementioned activities are
completed successfully. At such time, the required amount will accrued for
payment to the seller and capitalized as acquisition costs.
30
We are also, in the ordinary course of business, a claimant and/or
defendant in various legal proceedings. Management does not believe that the
outcome of these legal proceedings, individually, and in the aggregate will have
a materially adverse effect on our financial condition, results of operations or
cash flows.
Recent Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 143 "Accounting for
Asset Retirement Obligations" ("SFAS 143"). SFAS 143 provides accounting
requirements for retirement obligations associated with tangible long-lived
assets, including: 1) the timing of liability recognition; 2) initial
measurement of the liability; 3) allocation of asset retirement cost to expense;
4) subsequent measurement of the liability; and 5) financial statement
disclosures. SFAS 143 requires that an asset retirement cost should be
capitalized as part of the cost of the related long- lived asset and
subsequently allocated to expense using a systematic and rational method. The
statement is effective for fiscal years beginning after June 15, 2002 and we
adopted the statement on January 1, 2003. The transition adjustment resulting
from the adoption of SFAS 143 will be reported as a cumulative effect of a
change in accounting principle. We have not yet completed our assessment of the
impact of SFAS 143 on our financial condition and results of operations.
However, we expect that adoption of the statement will result in increases in
the capitalized costs of our oil and properties and in the recognition of
additional liabilities related to asset retirement obligations.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, No. 44, and No. 64, Amendment of FASB Statement No. 13, and Technical
Corrections" ("SFAS 145"). Among other things, SFAS 145 requires gains and
losses from early extinguishment of debt to be included in income from
continuing operations instead of being classified as extraordinary items as
previously required by generally accepted accounting principles. SFAS 145 is
effective for fiscal years beginning after May 15, 2002 and we adopted the
statement on January 1, 2003. Any gain or loss on early extinguishment of debt
that was classified as an extraordinary item in periods prior to adoption must
be reclassified into income from continuing operations. The adoption of SFAS 145
will require the $0.6 million (net of tax) of extraordinary loss for the year
ended December 31, 2001 to be reclassified to interest expense and income tax
benefit.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" ("SFAS 146"). SFAS 146 addresses
financial accounting and reporting for costs associated with exit or disposal
activities and nullified Emerging Issues Task Force Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring". SFAS 146
requires that a liability for a cost associated with an exit or disposal
activity be recognized when the liability is incurred. SFAS 146 also establishes
that fair value is the objective for initial measurement of the liability. The
provisions of this statement are effective for exit or disposal activities that
are initiated after December 31, 2002. We adopted the provisions of SFAS 146 on
January 1, 2003 and the adoption did not have an effect on our financial
position or results of operations.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation -- Transition and Disclosure an amendment of FASB Statement No. 12"
("SFAS 148"). This statement amends SFAS No. 123, "Accounting for Stock-Based
Compensation" ("SFAS 123"), to provide alternative methods of transition for an
entity that voluntarily changes to the fair value based method of accounting for
stock-based employee compensation. It also amends the disclosure provisions of
that statement to require prominent disclosure about the effects on reported net
income of an entity's accounting policy decisions with respect to
31
stock-based employee compensation. Finally, this statement amends Accounting
Principles Board Opinion No. 28, "Interim Financial Reporting" ("APB 28"), to
require disclosure about those effects in interim financial information. We
intend to continue to account for stock-based compensation based on the
provisions of APB Opinion No. 25. The amended disclosure requirements have been
incorporated in Note 2 to the Consolidated Financial Statements.
In November 2002, the FASB issued FASB Interpretation No. 45 "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantee of Indebtedness of Others" ("FIN 45"). FIN 45 requires that upon
issuance of a guarantee, the guarantor must recognize a liability for the fair
value of the obligation it assumes under that guarantee. FIN 45's provisions for
initial recognition and measurement should be applied on a prospective basis to
guarantees issued or modified after December 31, 2002. The disclosure provisions
apply to financial statements for periods ending after December 15, 2002. We do
not currently have guarantees that require disclosure. We adopted the
measurement provisions of this statement in the first quarter of 2003 and the
adoption did not have an effect on our financial position or results of
operations.
In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation
of Variable Interest Entities" ("FIN 46"). FIN 46 requires a company to
consolidate a variable interest entity if it is designated as the primary
beneficiary of that entity even if the company does not have a majority of
voting interest. A variable interest entity is generally defined as an entity
where its equity is unable to finance its activities or where the owners of the
entity lack the risk and rewards of ownership. The provisions of FIN 46 apply
immediately to variable interest entities created after January 31, 2003 and to
variable interest entities in which an enterprise obtains an interest after that
date. The adoption of FIN 46 is not currently expected to have an effect on our
financial position or results of operations when adopted.
Emerging Issues Task Force ("EITF") Issue No. 02-03, "Recognition and
Reporting of Gains and Losses on Energy Trading Contracts" under EITF Issues No.
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" was issued in June 2002. EITF Issue No. 02-03 addresses certain
issues related to energy trading activities, including (a) gross versus net
presentation in the income statement, (b) whether the initial fair value of an
energy trading contract can be other than the price at which it was exchanged,
and (c) accounting for inventory utilized in energy trading activities. As of
January 1, 2003, we will present our gas sold and purchased activities in the
statement of operations for all periods on a net rather than a gross basis. The
change will decrease reported revenues and costs and operating expenses, but
will have no effect on operating income or cash flow. The remaining provisions
effective January 1, 2003 will have no impact on our financial statements. For
more information regarding this marketing activity, see Note 13 to the
Consolidated Financial Statements.
Factors That May Affect Future Results
You should carefully consider the risks described below in evaluating the
other statements made herein. The risks described below are not the only risks
of our company. Additional risks not presently known to us, or that we currently
deem immaterial, may also impair our business operations. Our business,
financial condition, results of operations or the trading price of our common
stock could be adversely affected by any of these risks.
We have debt, trade payables and related interest payment requirements that
may restrict our future operations and impair our ability to meet our
obligations.
Our debt, trade payables and related interest payment requirements may have
important consequences. For instance, it could:
. make it more difficult or render us unable to satisfy our financial
obligations;
. require us to dedicate a substantial portion of any cash flow from
operations to the payment of interest and principal due under our
debt, which will reduce funds available for other business purposes;
. increase our vulnerability to general adverse economic and industry
conditions;
. limit our flexibility in planning for or reacting to changes in our
business and the industry in which we operate;
. place us at a competitive disadvantage compared to some of our
competitors that have less financial leverage; and
. limit our ability to obtain additional financing required to fund
working capital and capital expenditures and for other general
corporate purposes.
32
Our ability to satisfy our obligations and to reduce our total debt depends
on our future operating performance and on economic, financial, competitive and
other factors, many of which are beyond our control. We cannot provide assurance
that our business will generate sufficient cash flow or that future financings
will be available to provide sufficient proceeds to meet these obligations. The
successful execution of our business strategy and the maintenance of our
economic viability are also contingent upon our ability me meet our financial
obligations.
Our debt instruments impose restrictions on us that may affect our ability
to successfully operate our business.
Our bank credit facility and our 11.5% fixed rate note contain customary
restrictions, including covenants limiting our ability to incur additional debt,
grant liens, make investments, consolidate, merge or acquire other businesses,
sell assets, pay dividends and other distributions, make capital expenditures
and enter into transactions with affiliates. We also are required to meet
specified financial ratios under the terms of our bank credit facilities. These
restrictions may make it difficult for us to successfully execute our business
strategy or to compete in our industry with companies not similarly restricted.
Our bank credit facility matures in May 2004 and our 11.5% note matures in
June 2005, at which time we will be required to repay or refinance those
borrowings. We cannot provide assurance that we will be able to obtain
replacement financing at that time or that any available replacement financing
will be on terms acceptable to us. If we are unable to obtain acceptable
replacement financing, we will not be able to satisfy our obligations under our
bank credit facility or note due in 2005 and may be required to take other
actions to avoid defaulting on those facilities, including selling assets or
surrendering assets to our lenders, which would not otherwise be in our
long-term economic interest.
Our properties are subject to rapid production declines and we require
significant capital expenditures to replace our reserves at a faster rate than
companies whose reserves have longer production periods. We may not be able to
identify or complete the acquisition of properties with sufficient proved
reserves to implement our business strategy.
Production of reserves from reservoirs in the Gulf of Mexico generally
declines more rapidly than production 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. As our reserves decline from production, we must incur significant
capital expenditures to replace declining production. As a result, in order to
increase our reserves, we must replace our reserves with newly-acquired
properties. Also, our return on capital for a particular property depends
significantly on prices prevailing during the relatively short production period
of that property. As of December 31, 2002 and 2001, our reserve life index was
8.7 years and 9.1 years, respectively.
We may not be able to identify or complete the acquisition of properties
with sufficient proved undeveloped reserves to implement our business strategy.
As we deplete our existing reserves we must identify, acquire and develop
properties through new acquisitions or our level of production and cash flows
will be adversely affected. The availability of properties for acquisition
depends largely on the divesting practices of other natural gas and oil
companies, commodity prices, general economic conditions and other factors that
we cannot control or influence. A substantial decrease in the availability of
proved oil and gas properties in our areas of operation, or a substantial
increase in the cost to acquire these properties, would adversely affect our
ability to replace our reserves.
33
Our actual drilling results are likely to differ from our estimates of
proved reserves. We may experience production that is less than estimated in our
reserve reports and drilling costs that are greater than estimated in our
reserve reports. Such differences may be material.
Estimates of our natural gas and oil reserves and the costs associated with
developing these reserves may not be accurate. Development of our reserves may
not occur as scheduled and the actual results may not be as estimated. Drilling
activity may result in downward adjustments in reserves or higher than estimated
costs.
Our estimates of our proved natural gas and oil reserves and the estimated
future net revenues from such reserves are based upon various assumptions,
including assumptions required by the SEC relating to natural gas and oil
prices, drilling and operating expenses, capital expenditures, taxes and
availability of funds. This process requires significant decisions and
assumptions in the evaluation of available geological, geophysical, engineering
and economic data for each reservoir. Therefore, these estimates are inherently
imprecise and the quality and reliability of this data can vary.
Any significant variance could materially affect the estimated quantities
and PV-10 of reserves set forth in this annual report. Our properties may also
be susceptible to hydrocarbon drainage from production by other operators on
adjacent properties. In addition, we will likely 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 may vary materially from our estimates.
If we are not able to generate sufficient funds from our operations and
other financing sources, we may not be able to finance our planned development
activity or acquisitions or service our debt.
We have historically needed and will continue to need substantial amounts of
cash to fund our capital expenditure and working capital requirements. Our
ongoing capital requirements consist primarily of funding acquisition,
development and abandonment of oil and gas reserves and to meet our debt service
obligations. Our capital expenditures were $34.9 million during 2002, $110.3
million during 2001 and $76.5 million during 2000.
For 2003, we plan to finance anticipated expenses, debt service and
acquisition and development requirements with funds generated from the following
sources:
. cash provided by operating activities;
. funds available under new credit facilities;
. the potential increased availability from our existing credit facilities;
. extended financing arrangements with suppliers and service providers;
. net cash proceeds from the sale of assets, debt or equity; and
. the potential issuance of new debt or equity.
Our projected cash flows provide the necessary funds for our debt service
and our planned Gulf of Mexico developments and we intend to finance our planned
North Sea development with projected cash flows and potential new financing
arrangements. Low commodity prices, production problems, disappointing drilling
results and other factors beyond our control could reduce our funds from
operations and may restrict our ability to obtain additional financing. In
addition, financing may not be available to us in the future on acceptable terms
or at all. In the event additional capital is not available, 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. In addition, we may not
be able to pay interest and principal on our debt obligations.
34
Natural gas and oil prices are volatile, and low prices have had in the past
and could have in the future a material adverse impact on our business.
Our revenues, profitability and future growth and the carrying value of our
properties depend substantially on the prices we realize for our natural gas and
oil production. Because approximately 85% of our estimated proved reserves as of
December 31, 2002 were natural gas reserves, our financial results are more
sensitive to movements in natural gas prices. Our realized prices also affect
the amount of cash flow available for capital expenditures and our ability to
borrow and raise additional capital.
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 increased significantly in late 2000 and steadily declined in
2001, only to climb again in 2002. Among the factors that can cause this
volatility are:
. worldwide or regional demand for energy, which is affected by economic
conditions;
. the domestic and foreign supply of natural gas and oil;
. weather conditions;
. domestic and foreign governmental regulations;
. political conditions in natural gas or oil producing regions;
. the ability of members of the Organization of Petroleum Exporting
Countries to agree upon and maintain oil prices and production levels;
and
. the price and availability of alternative fuels.
It is impossible to predict natural gas and oil price movements with
certainty. Lower natural gas and oil prices may not only decrease our revenues
on a per unit basis but also may reduce the amount of natural gas and oil that
we can produce economically. A substantial or extended decline in natural gas
and oil prices may materially and adversely affect our future business,
financial condition, results of operations, liquidity and ability to finance
planned capital expenditures. Further, oil prices and natural gas prices do not
necessarily move together.
Our price risk management decisions may reduce our potential gains from
increases in commodity prices and may result in losses.
We periodically utilize derivative instruments with respect to a portion of
our expected production. These instruments expose us to risk of financial loss
if:
. production is less than expected;
. the other party to the derivative instrument defaults on its contract
obligations; or
. there is an adverse change in the expected differential between the
underlying price in the derivative instrument and actual prices received.
Our results of operations may be negatively impacted by our derivative
instruments in the future and these instruments may limit any benefit we would
receive from increases in the prices for natural gas and oil. For the years
ended December 31, 2002, 2001 and 2000, we realized a loss of $3.4 million,
$19.7 million and $28.2 million, respectively. See Item 7a. "Quantitative and
Qualitative Disclosure about Market Risk" for volume and price information on
our price risk management activities.
35
We may incur substantial impairment writedowns.
If management's estimates of the recoverable reserves on a property are
revised downward or if natural gas and oil prices decline, we may be required to
record additional non-cash impairment writedowns in the future, which would
result in a negative impact to our financial position. In addition, future
writedowns to our properties could result in corresponding reductions of our
borrowing base under our credit facility and promissory note. We review our
proved oil and gas properties for impairment on a depletable unit basis when
circumstances suggest there is a need for such a review. To determine if a
depletable unit is impaired, we compare the carrying value of the depletable
unit to the undiscounted future net cash flows by applying management's
estimates of future oil and gas prices to the estimated future production of oil
and gas reserves over the economic life of the property. Future net cash flows
are based upon our independent reservoir 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. For each property
determined to be impaired, we recognize an impairment loss equal to the
difference between the estimated fair value and the carrying value of the
property on a depletable unit basis. Fair value is estimated to be the present
value of the aforementioned expected future net cash flows. Any impairment
charge incurred is recorded in accumulated depreciation, depletion, impairment
and amortization to reduce our recorded basis in the asset. Each part of this
calculation is subject to a large degree of judgment, including the
determination of the depletable units' estimated reserves, future cash flows and
fair value. We recorded impairments of $6.8 million, $24.9 million and $10.8
million for the years ended December 31, 2002, 2001 and 2000, respectively.
Management's assumptions used in calculating oil and gas reserves or
regarding the future cash flows or fair value of our properties are subject to
change in the future. Any change could cause impairment expense to be recorded,
impacting our net income or loss and our basis in the related asset. Any change
in reserves directly impacts our estimate of future cash flows from the
property, as well as the property's fair value. Additionally, as management's
views related to future prices change, the change will affect the estimate of
future net cash flows and the fair value estimates. Changes in either of these
amounts will directly impact the calculation of impairment.
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
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;
. 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.
36
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.
Terrorist Attacks or Similar Hostilities May Adversely Impact Our Results of
Operations.
The impact that future terrorist attacks or regional hostilities
(particularly in the Middle East) may have on the energy industry in general,
and on us in particular, is not known at the time. Uncertainty surrounding
military strikes or a sustained military campaign may affect our operations in
unpredictable ways, including disruptions of fuel supplies and markets,
particularly oil, and the possibility that infrastructure facilities, including
pipelines, production facilities, processing plants and refineries, could be
direct targets of, or indirect casualties of, an act of terror or war. Moreover,
we have incurred additional costs since the terrorist attacks of September 11,
2001 to safeguard certain of our assets and we may be required to incur
significant additional costs in the future.
The terrorist attacks on September 11, 2001 and the changes in the insurance
markets attributable to such attacks have made certain types of insurance more
difficult for us to obtain. There can be no assurance that insurance will be
available to us without significant additional costs. A lower level of economic
activity could also result in a decline in energy consumption which could
adversely affect our revenues or restrict our future growth. Instability in the
financial markets as a result of terrorism or war could also affect our ability
to raise capital.
Our insurance coverage may not be sufficient to cover some liabilities or
losses which we may incur.
The occurrence of a significant accident or other event not fully covered by
our insurance could have a material adverse effect on our operations and
financial condition. Our insurance does not protect us against all operational
risks. We do not carry business interruption insurance at levels that would
provide enough funds for us to continue operating without access to other funds.
For some risks, we may not obtain insurance if we believe the cost of available
insurance is excessive relative to the risks presented. Because third party
drilling contractors are used to drill our wells, we may not realize the full
benefit of workmen's compensation laws in dealing with their employees. In
addition, pollution and environmental risks generally are not fully insurable.
We may be unable to identify liabilities associated with the properties that
we acquire or obtain protection from sellers against them.
The acquisition of properties with proved undeveloped reserves requires us
to assess a number of factors, including recoverable reserves, development and
operating costs and potential environmental and other liabilities. Such
assessments are inexact and inherently uncertain. In connection with the
assessments, we perform a review of the subject properties, but such a review
will not reveal all existing or potential problems.
37
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. In periods of increased drilling activity in the Gulf of Mexico, we
may experience increases in associated costs, including those related to
drilling rigs, equipment, supplies and personnel and the services and products
of other vendors to the industry. Increased drilling activity in the Gulf of
Mexico also decreases the availability of offshore rigs. These costs may
increase further and necessary equipment and services may not be available to us
at economical prices.
Competition in our industry is intense, and we are smaller and have a more
limited operating history than some of our competitors in the Gulf of Mexico and
in the North Sea.
We compete with major and independent natural gas and oil companies for
property acquisitions. We also compete for the equipment and labor required to
operate and to develop these properties. Some of our competitors have
substantially greater financial and other resources than us. In addition, larger
competitors may be able to absorb the burden of any changes in federal, state
and local laws and regulations more easily than we can, which would adversely
affect our competitive position. These competitors may be able to pay more for
natural gas and oil properties and may be able to define, evaluate, bid for and
acquire a greater number of properties than we can. Our ability to acquire
additional properties and develop new and existing properties in the future will
depend on our ability to conduct operations, to evaluate and select suitable
properties and to consummate transactions in this highly competitive
environment. In addition, some of our competitors have been operating in the
Gulf of Mexico and in the North Sea for a much longer time than we have and have
demonstrated the ability to operate through industry cycles.
Our success depends on our management team and other key personnel, the loss
of any of whom could disrupt our business operations.
Our success will depend on our ability to retain and attract experienced
geoscientists and other professional staff. As of December 31, 2002, we had 13
engineers, geologist/geophysicists and other technical personnel in our Houston
office and five engineers, geologist/geophysicists and other technical personnel
in our London location. 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 resign or become unable to
continue in their present role and if they are not adequately replaced, our
business operations could be adversely affected.
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;
. 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.
38
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 adversely impacted.
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 North Sea, are subject to extensive
laws and regulations, including environmental laws and regulations. We may be
required to make large expenditures to comply with environmental and other
governmental regulations. Matters subject to regulation include:
. discharge permits for drilling operations;
. bonds for ownership, development and production of oil and gas
properties;
. reports concerning operations; and
. taxation.
Under these laws and regulations, we could be liable for personal injuries,
property damage, oil spills, discharge of hazardous materials, remediation and
clean-up costs and other environmental damages. Failure to comply with these
laws and regulations also may result in the suspension or termination of our
operations and subject us to administrative, civil and criminal penalties.
Moreover, these laws and regulations could change in ways that substantially
increase our costs. Accordingly, any of these liabilities, penalties,
suspensions, terminations or regulatory changes could materially adversely
affect our financial condition and results of operations.
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.
Members of our management team beneficially own approximately 70% of our
outstanding shares of common stock. As a result, these shareholders are 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.
Item 7a. Quantitative and Qualitative Disclosures about Market Risk
Interest Rate Risk
We are exposed to changes in interest rates. Changes in interest rates
affect the interest earned on our cash and cash equivalents and the interest
rate paid on borrowings under the credit facility. Under our current policies,
we do not use interest rate derivative instruments to manage exposure to
interest rate changes.
Foreign Currency Risk.
The net assets, net earnings and cash flows from our wholly owned
subsidiary in the U.K. are based on the U.S. dollar equivalent of such amounts
measured in the applicable functional currency. These foreign operations have
the potential to impact our financial position due to fluctuations in the local
currency arising from the process of re-measuring the local functional currency
in the U.S. dollar. We have not utilized derivatives or other financial
instruments to hedge the risk associated with the movement in foreign
currencies.
39
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 a portion of our natural gas
and oil production under price sensitive or market price contracts. We
periodically use derivative instruments to hedge our commodity price risk. We
hedge a portion of our projected natural gas and oil production through a
variety of financial and physical arrangements intended to support natural gas
and oil prices at targeted levels and to manage our exposure to price
fluctuations. We may use futures contracts, swaps and fixed price physical
contracts to hedge our commodity prices. Realized gains and losses from our
price risk management activities are recognized in oil and gas sales when the
associated production occurs. For derivatives designated as cash flow hedges,
the unrecognized gains and losses are included as a component of other
comprehensive income (loss) to the extent the hedge is effective. See Note 12 to
the Consolidated Financial Statements for additional information. We do not hold
or issue derivative instruments for trading purposes.
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
management's estimated value of the estimated proved reserves at the then
current natural gas and oil prices. We may enter into short-term hedging
arrangements if (1) 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 or (2) if deemed necessary by the terms of
our existing credit agreements. During 2002, we hedged approximately 51% of our
natural gas and oil production.
To calculate the potential effect of the derivative and fixed-price
contracts on future income (loss) before taxes, we applied the NYMEX oil and gas
strip prices as of December 31, 2002 to the quantity of our oil and gas
production covered by those contracts as of that date. The following table shows
the estimated potential effects of the derivative and fixed-price contracts on
future income (loss) before taxes (in thousands):
Estimated Increase (Decrease)
In Income (Loss)
Before Taxes Due to
------------------------------
10% 10%
Decrease Increase
Instrument in Prices in Prices
---------- ------------ -------------
Natural gas swaps ....................................... $ 2,772 $ (2,772)
Oil swaps ............................................... 504 (504)
Natural gas fixed price contracts ....................... 2,374 (2,374)
Oil fixed price contracts ............................... 642 (642)
Item 8. Financial Statements and Supplementary Data
The information required here is included in the report as set forth in the
"Index to the Consolidated Financial Statements" on page F-1.
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
None.
40
PART III
Item 10. Directors and Executive Officers of Registrant
Except for the information relating to Executive Officers of the Registrant,
which is included in Part 1, Item 4 of this Report, the information required by
Item 10 of Form 10-K is incorporated by reference to "Election of Directors" and
"Section 16 Compliance" included in the definitive proxy statement for the
Company's Annual Meeting of Shareholders to be held on May 28, 2003 (the "Proxy
Statement").
Item 11. Executive Compensation
The information required by Item 11 of Form 10-K is incorporated by
reference to the information contained in the section captioned "Executive
Compensation" of the Registrant's Proxy Statement.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required by Item 12 of Form 10-K is incorporated by
reference to the information contained in the section captioned "Securities
Ownership by Principal Shareholders and Management" of the Registrant's Proxy
Statement.
Item 13. Certain Relationships and Related Transactions
The information required by Item 13 of Form 10-K is incorporated by
reference to the information contained in the section captioned "Election of
Directors - Certain Transactions" of the Registrant's Proxy Statement.
Item 14. Controls and Procedures
a. Based on their evaluation of the Company's disclosure controls and
procedures as of a date within 90 days of the filing date of this Annual Report
on Form 10-K, the Company's chief executive officer and chief financial officer
have concluded that Company's disclosure controls and procedures were adequate
and designed to ensure that material information relating to the Company and the
Company's consolidated subsidiaries would be made known to them by others within
those entities.
b. There were no significant changes in the Company's internal controls or
in other factors that could significantly affect these controls subsequent to
the date of their evaluation.
41
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) (1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Consolidated Financial Statements" on page F-1.
(a) (3) Exhibit
3.1 Amended and Restated Articles of Incorporation (incorporated by
reference to Exhibit 3.1 of ATP's registration statement No.
333-46034 on Form S-1)
3.2 Restated Bylaws (incorporated by reference to Exhibit 3.2 of ATP's
registration statement No. 333-46034 on Form S-1)
4.1 Form of Common Stock Certificate (incorporated by reference to
Exhibit 4.1 of ATP's registration statement No. 333-46034 on
Form S-1)
10.1 Gas Service Agreement, dated December 31, 1998, between American
Citigas Company and ATP Energy, Inc. (incorporated by reference to
Exhibit 10.6 of ATP's registration statement No. 333-46034 on
Form S-1)
10.2 Marketing & Natural Gas Purchase Agreement, dated December 1, 1998,
between ATP Energy, Inc. and El Paso Energy Marketing Company
(incorporated by reference to Exhibit 10.7 of ATP's registration
statement No. 333-46034 on Form S-1)
10.3 Purchase and Sale Agreement, effective as of May 1, 1999, between
Eugene Offshore Holdings, LLC and ATP Oil & Gas Corporation
(incorporated by reference to Exhibit 10.8 of ATP's registration
statement No. 333-46034 on Form S-1)
10.4 ATP Oil & Gas Corporation 1998 Stock Option Plan (incorporated by
reference to Exhibit 10.9 of ATP's registration statement No.
333-46034 on Form S-1)
10.5 First Amendment to the ATP Oil & Gas Corporation 1998 Stock Option
Plan (incorporated by reference to Exhibit 10.10 of ATP's
registration statement No. 333-46034 on Form S-1)
10.6 ATP Oil & Gas Corporation 2000 Stock Plan (incorporated by reference
to Exhibit 10.11 of ATP's Annual Report on Form 10-K for the year
ended December 31, 2000)
10.7 Note Purchase Agreement dated June 29, 2001 between ATP Oil & Gas
Corporation and Aquila Energy Capital Corporation (incorporated by
reference to Exhibit 10.3 of ATP's Quarterly Report on Form 10-Q for
the quarterly period ended June 30, 2001)
10.8 Intercreditor and Subordination Agreement dated June 29, 2001, among
ATP Oil & Gas Corporation, Aquila Energy Capital Corporation, BNP
Paribas, as Agent, and the Lenders Signatory thereto (incorporated by
reference to Exhibit 10.4 of ATP's Quarterly Report on Form 10-Q for
the quarterly period ended June 30, 2001
10.9 First Amendment to Note Purchase Agreement dated March 27, 2002
between ATP Oil & Gas Corporation and Aquila Energy Capital
Corporation (incorporated by reference to Exhibit 10.23 of ATP's
Annual Report on Form 10-K for the year ended December 31, 2001)
10.10 Amended and Restated Credit Agreement dated July 31, 2002, among ATP
Oil & Gas Corporation, Union Bank of California, N.A., as agent,
Guaranty Bank, FSB, as Co-Agent and the Lenders Signatory thereto
(incorporated by reference to Exhibit 10.1 of ATP's Quarterly Report
on Form 10-Q for the quarterly period ended June 30, 2002)
*21.1 Subsidiaries of ATP Oil & Gas Corporation
*23.1 Consent of KPMG LLP
*23.2 Consent of Ryder Scott Company
*23.3 Consent of Troy-Ikoda Limited
*99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002
---------------
* Filed herewith
42
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
ATP Oil & Gas Corporation
By: /s/ Albert L. Reese, Jr.
---------------------------------
Albert L. Reese, Jr.
Senior Vice President
and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed by the following persons on behalf of the registrant in
the capacities indicated on March 28, 2003.
Signature Title
--------- -----
/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
Albert L. Reese, Jr. (Principal Financial Officer and
Principal Accounting Officer)
/s/ CHRIS A. BRISACK Director
- ----------------------------------
Chris A. Brisack
/s/ ARTHUR H. DILLY Director
- ----------------------------------
Arthur H. Dilly
/s/ GERARD J. SWONKE Director
- ----------------------------------
Gerard J. Swonke
/s/ ROBERT C. THOMAS Director
- ----------------------------------
Robert C. Thomas
/s/ WALTER WENDLANDT Director
- ----------------------------------
Walter Wendlandt
43
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
Independent Auditors' Report ............................................................ F-2
Consolidated Balance Sheets as of December 31, 2002 and 2001 ............................ F-3
Consolidated Statements of Operations for the years ended
December 31, 2002, 2001 and 2000 ................................................... F-4
Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001 and 2000 ................................................... F-5
Consolidated Statements of Shareholders' Equity (Deficit) for the years ended
December 31, 2002, 2001 and 2000 ................................................... F-6
Notes to Consolidated Financial Statements .............................................. F-7
F-1
INDEPENDENT AUDITORS' REPORT
The Board of Directors
ATP Oil & Gas Corporation:
We have audited the accompanying consolidated balance sheets of ATP Oil &
Gas Corporation and subsidiaries as of December 31, 2002 and 2001, and the
related consolidated statements of operations, shareholders' equity (deficit),
and cash flows for each of the years in the three-year period ended December 31,
2002. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of ATP Oil &
Gas Corporation and subsidiaries as of December 31, 2002 and 2001, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2002, in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
financial instruments.
KPMG LLP
Houston, Texas
March 26, 2003
F-2
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Amounts)
December 31,
------------------------
2002 2001
----------- -----------
Assets
Current assets:
Cash and cash equivalents ................................................. $ 6,944 $ 5,294
Restricted cash ........................................................... 414 -
Accounts receivable (net of allowance of $1,266 and $1,423, respectively).. 24,998 10,371
Deferred tax asset ........................................................ 1,628 -
Derivative asset .......................................................... - 1,936
Other current assets ...................................................... 3,245 1,754
----------- -----------
Total current assets ................................................... 37,229 19,355
----------- -----------
Oil and gas properties (using the successful efforts method of accounting)..... 355,088 319,506
Less: Accumulated depletion, impairment and amortization.................. (236,052) (186,473)
----------- -----------
Oil and gas properties, net............................................. 119,036 133,033
----------- -----------
Furniture and fixtures (net of accumulated depreciation)....................... 810 794
Deferred tax asset............................................................. 21,580 19,228
Other assets, net.............................................................. 3,400 5,154
----------- -----------
Total assets............................................................ $ 182,055 $ 177,564
=========== ===========
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable and accruals.............................................. $ 35,336 $ 26,426
Current maturities of long-term debt....................................... 6,000 22,000
Derivative liability....................................................... 9,592 -
----------- -----------
Total current liabilities............................................... 50,928 48,426
Long-term debt................................................................. 80,387 78,111
Long-term derivative liability................................................. - 671
Deferred revenue............................................................... 1,111 1,296
Other long-term liabilities and deferred obligations........................... 11,082 4,068
----------- -----------
Total liabilities....................................................... 143,508 132,572
----------- -----------
Shareholders' equity:
Preferred stock: $0.001 par value, 10,000,000 shares authorized;
none issued............................................................. - -
Common stock: $0.001 par value, 100,000,000 shares authorized
in December 31, 2002 and 2001........................................... 20 20
Additional paid in capital................................................. 81,087 80,478
Accumulated deficit........................................................ (39,314) (34,614)
Accumulated other comprehensive income (loss).............................. (2,335) 19
Treasury stock, at cost.................................................... (911) (911)
----------- -----------
Total shareholders' equity.............................................. 38,547 44,992
----------- -----------
Total liabilities and shareholders' equity.............................. $ 182,055 $ 177,564
=========== ===========
See accompanying notes to the consolidated financial statements.
F-3
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except Per Share Amounts)
Years Ended December 31,
----------------------------------
2002 2001 2000
---------- ---------- ----------
Revenues:
Oil and gas production........................................ $ 88,151 $ 105,757 $ 75,940
Gas sold - marketing.......................................... 6,272 7,417 8,015
Gain on sale of oil and gas properties........................ - - 33
---------- ---------- ----------
94,423 113,174 83,988
---------- ---------- ----------
Costs and operating expenses:
Lease operating expenses...................................... 16,764 14,806 11,559
Gas purchased - marketing..................................... 6,087 7,218 7,788
Geological and geophysical expenses........................... 154 1,068 -
General and administrative expenses........................... 10,287 9,981 5,409
Non-cash compensation expense (general and administrative).... 595 3,364 -
Depreciation, depletion and amortization...................... 43,390 53,428 40,569
Impairment of oil and gas properties.......................... 6,844 24,891 10,838
Loss on unsuccessful property acquisition..................... - 3,147 -
Other expense................................................. - - 450
---------- ---------- ----------
84,121 117,903 76,613
---------- ---------- ----------
Income (loss) from operations.................................... 10,302 (4,729) 7,375
---------- ---------- ----------
Other income (expense):
Interest income............................................... 73 884 451
Interest expense.............................................. (10,418) (10,039) (11,907)
Other......................................................... 1,081 - -
Loss on derivative instruments................................ (8,319) (18,083) (11,911)
----------- ---------- ----------
(17,583) (27,238) (23,367)
---------- ---------- ----------
Loss before income taxes and extraordinary item ................. (7,281) (31,967) (15,992)
Income tax benefit .............................................. 2,581 11,186 5,594
---------- ---------- ----------
Loss before extraordinary item................................... (4,700) (20,781) (10,398)
Extraordinary item, net of tax................................... - (602) -
---------- ---------- ----------
Net loss......................................................... (4,700) (21,383) (10,398)
Other comprehensive income (loss):
Cumulative effect of change in accounting principle - (34,252) -
Reclassification adjustment for settled contracts 627 34,252 -
Change in fair value of outstanding hedging positions (3,651) - -
Foreign currency translation adjustment 670 19 -
----------- ---------- ----------
Other comprehensive income (loss) (2,354) 19 -
----------- ---------- ----------
Comprehensive loss $ (7,054) $ (21,364) $ (10,398)
=========== ========== ==========
Basic and diluted loss per common share:
Loss before extraordinary item................................ $ (0.23) $ (1.06) $ (0.73)
Extraordinary item, net of tax................................ - (0.03) -
---------- ---------- ----------
Net loss per common share..................................... $ (0.23) $ (1.09) $ (0.73)
========== ========== ==========
Weighted average number of common shares:
Basic and diluted............................................. 20,315 19,704 14,286
========== ========== ==========
See accompanying notes to the consolidated financial statements.
F-4
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
Years Ended December 31,
-----------------------------------
2002 2001 2000
---------- ---------- -----------
Cash flows from operating activities:
Net loss ........................................................ $ (4,700) $ (21,383) $ (10,398)
Adjustments to reconcile net loss to net cash
provided by operating activities -
Depreciation, depletion and amortization ................... 43,390 53,428 40,569
Impairment of oil and gas properties ....................... 6,844 24,891 10,838
Amortization of deferred financing costs ................... 1,429 797 376
Extraordinary item ......................................... - 926 -
Other comprehensive loss ................................... (3,024) - -
Deferred tax assets ........................................ (2,352) (11,576) (5,594)
Non-cash compensation expense .............................. 595 3,364 -
Gain on sale of oil and gas properties ..................... - - (33)
Other expense .............................................. - - 450
Other non-cash items ....................................... 746 196 431
Changes in assets and liabilities -
Accounts receivable and other ................................ (14,659) 23,014 (22,772)
Restricted cash .............................................. (414) - 471
Net (assets) liabilities from risk management activities ..... 9,229 (8,513) 7,249
Accounts payable and accruals ................................ 8,910 (23,436) 37,309
Other long-term assets ....................................... (1,525) (4,183) (1,462)
Other long-term liabilities and deferred credits ............. 6,829 3,831 (277)
---------- ---------- ------------
Net cash provided by operating activities ........................... 51,298 41,356 57,157
---------- ---------- -----------
Cash flows from investing activities:
Additions and acquisitions of oil and gas properties ............ (34,873) (110,264) (76,474)
Additions to furniture and fixtures ............................. (294) (546) (361)
---------- ---------- -----------
Net cash used in investing activities ............................... (35,167) (110,810) (76,835)
---------- ---------- -----------
Cash flows from financing activities:
Proceeds of initial public offering ............................. - 78,330 -
Payment of offering costs ....................................... - (893) (621)
Proceeds from long-term debt .................................... 1,000 119,000 15,800
Payments of long-term debt ...................................... (15,000) (46,750) (8,250)
Proceeds from non-recourse borrowings ........................... - 3,359 42,745
Payments of non-recourse borrowings ............................. - (92,138) (29,239)
Deferred financing costs ........................................ (495) (3,586) (400)
Treasury stock purchases ........................................ - (911) -
Other ........................................................... 14 201 -
---------- ---------- -----------
Net cash provided by (used in) financing activities ................. (14,481) 56,612 20,035
---------- ---------- -----------
Increase (decrease) in cash and cash equivalents .................... 1,650 (12,842) 357
Cash and cash equivalents, beginning of period ...................... 5,294 18,136 17,779
---------- ---------- -----------
Cash and cash equivalents, end of period ............................ $ 6,944 $ 5,294 $ 18,136
========== ========== ===========
Supplemental disclosures of cash flow information:
Cash paid during the period for interest ........................ $ 7,361 $ 4,177 $ 2,531
========== ========== ===========
Cash paid during the period for taxes ........................... $ - $ - $ 497
========== ========== ===========
See accompanying notes to the consolidated financial statements.
F-5
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT)
(In Thousands)
2002 2001 2000
------------------- ------------------- --------------------
Shares Amount Shares Amount Shares Amount
------ ----------- ------ ---------- ------ ----------
Common Stock
Balance, beginning of year ........... 20,313 $ 20 14,286 $ 14 14,286 $ 14
Issuances of common stock
Public offering .................... - - 6,000 6 - -
Exercise of stock options .......... 9 - 103 - - -
Purchase of treasury stock ........... - - (76) - - -
------ ----------- ------ ---------- ------ ----------
Balance, end of year ................. 20,322 $ 20 20,313 $ 20 14,286 $ 14
====== ----------- ====== ---------- ====== ----------
Paid-in Capital
Balance, beginning of year ........... $ 80,478 $ 38 $ 38
Issuances of common stock
Public offering .................... - 76,809 -
Exercise of stock options .......... 14 267 -
Non-cash compensation expense ........ 595 3,364 -
----------- ----------- -----------
Balance, end of year ................. $ 81,087 $ 80,478 $ 38
----------- ---------- -----------
Accumulated Deficit
Balance, beginning of year ........... $ (34,614) $ (13,231) $ (2,833)
Net loss ............................. (4,700) (21,383) (10,398)
----------- ---------- ------------
Balance, end of year ................. $ (39,314) $ (34,614) $ (13,231)
----------- ---------- -----------
Accumulated Other
Comprehensive Income (Loss)
Balance, beginning of year ......... $ 19 $ - $ -
Other comprehensive
income (loss) .................... (2,354) 19 -
----------- ----------- -----------
Balance, end of year ............... $ (2,335) $ 19 $ -
----------- ---------- -----------
Treasury Stock
Balance, beginning of year ........... 76 $ (911) - $ - - $ -
Purchase of treasury stock ........... - - 76 (911) - -
------ ----------- ----------- ----------- ---------- -----------
Balance, end of year ................. 76 $ (911) 76 $ (911) - $ -
====== ----------- =========== ----------- ========== -----------
Total Shareholders'
Equity (Deficit) ..................... $ 38,547 $ 44,992 $ (13,179)
=========== ========== ===========
See accompanying notes to the consolidated financial statements.
F-6
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 -- Organization and Basis of Presentation
Organization
ATP Oil & Gas Corporation ("ATP") was incorporated in Texas in 1991. We are
engaged in the acquisition, development and production of natural gas and oil
properties in the Gulf of Mexico and the U.K. and Dutch Sectors of the North Sea
(the "North Sea"). We primarily focus our efforts on natural gas and oil
properties with proved undeveloped reserves that are economically attractive to
us but are not strategic to major or exploration-oriented independent oil and
gas companies. We attempt to achieve a high rate of return on our investment in
these properties by limiting our up-front acquisition costs and by developing
our acquisitions quickly.
Basis of Presentation
The consolidated financial statements include our accounts and our
wholly-owned subsidiaries, ATP Energy, Inc. (ATP Energy), ATP Oil & Gas (UK)
Limited and ATP Oil & Gas Netherlands (B.V.). All significant intercompany
transactions are eliminated upon consolidation. Certain reclassifications have
been made to the prior year statements to conform to the current year
presentation.
Note 2 -- Summary of Significant Accounting Policies and Estimates
Use of Estimates. The preparation of financial statements in accordance
with generally accepted accounting principles and pursuant to the rules and
regulations of the Securities and Exchange Commission ("SEC") 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.
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.
Oil and Gas Producing Activities. We follow the "successful efforts" method
of accounting for oil and gas properties. Under this method, lease acquisition
costs and intangible drilling and development costs on successful wells and
development dry holes are capitalized.
Capitalized costs relating to producing properties are depleted on the
unit-of-production method. Proved developed reserves are used in computing unit
rates for drilling and development costs and total proved reserves for depletion
rates of leasehold, platform and pipeline costs. Estimated dismantlement,
restoration and abandonment costs and estimated residual salvage values are
taken into account in determining amortization and depletion provisions.
Expenditures for geological and geophysical data are generally charged to
expense unless the costs can be specifically attributed to determining the
placement for a future developmental well location.
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.
F-7
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We perform 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 in accordance with Financial Accounting Standards Board ("FASB")
Statement of Financial Accounting Standard ("SFAS") No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). To determine if a
depletable unit is impaired, we compare the carrying value of the depletable
unit to the undiscounted future net cash flows by applying management's
estimates of future oil and gas prices to the estimated future production of oil
and gas reserves over the economic life of the property. Future net cash flows
are based upon our independent reservoir 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 or other development activities. For a property determined to be
impaired, an impairment loss equal to the difference between the carrying value
and the estimated fair value of the impaired property will be recognized. Fair
value, on a depletable unit basis, is estimated to be the present value of the
aforementioned expected future net cash flows. Any impairment charge incurred is
recorded in accumulated depreciation, depletion, impairment and amortization to
reduce our recorded basis in the asset. Each part of this calculation is subject
to a large degree of judgment, including the determination of the depletable
units' reserves, future cash flows and fair value. We recorded impairments
during the years ended December 31, 2002, 2001 and 2000 of $6.8 million, $24.9
million and $10.8 million, respectively, primarily due to either depressed oil
and natural gas prices, unfavorable operating performance or downward revisions
of recoverable reserves or a combination of these. The impairments were
calculated as the difference between the carrying value and the estimated fair
value of the impaired depletable unit.
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 five years.
Other Assets. Other assets consist of the following (in thousands):
December 31,
------------------------------
2002 2001
------------- --------------
Debt financing costs ............... $ 3,767 $ 3,584
Spare parts inventory .............. 1,000 2,138
Long-term portion of receivable .... 629 -
Other .............................. 10 9
------------- --------------
5,406 5,731
Accumulated amortization ........... (2,006) (577)
------------- --------------
$ 3,400 $ 5,154
============= ==============
Costs incurred in connection with the issuance of long-term debt are
capitalized and amortized to interest expense over the term of the related
agreement, using the effective interest or straight-line method (which
approximates the effective interest method).
Environmental Liabilities. Environmental liabilities are recognized when the
expenditures are considered probable and can be reasonably estimated.
Measurement of liabilities is based on currently enacted laws and regulations,
existing technology and undiscounted site-specific costs. Generally, such
recognition coincides with our commitment to a formal plan of action.
Revenue Recognition. We use the sales method of accounting for natural gas
and oil revenues. Under this method, revenues are recognized based on actual
volumes of gas and oil sold to purchasers. The volumes sold may differ from the
volumes to which we are entitled based on our interests in the properties.
Differences between volumes sold and entitled volumes create gas imbalances
which are generally reflected as adjustments to reported proved gas reserves and
future cash flows in the our supplemental oil and gas disclosures.
F-8
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Adjustments for gas imbalances totaled approximately 0.25 percent of our proved
gas reserves at December 31, 2002. If our excess takes of natural gas or oil
exceed our estimated remaining proved reserves for a property, a natural gas or
oil imbalance liability is recorded in the consolidated balance sheet.
No such amount was recorded in 2002.
Major Customers. We sell a portion of our oil and gas to end users through
various gas marketing companies. For the year ended December 31, 2002, revenues
from four purchasers accounted for 34%, 26%, 14% and 14%, respectively, for oil
and gas production revenues. For the year ended December 31, 2001, revenues from
three purchasers accounted for 53%, 17% and 10%, respectively, of oil and gas
production revenues. For the year ended December 31, 2000, revenues from two
purchasers accounted for 41% each of oil and gas production revenues.
Percentages are calculated on oil and gas revenues before any effects of price
risk management activities.
Translation of Foreign Currencies. Financial statement amounts related to
our U.K. subsidiary, which has a functional currency of the British pound
sterling, are translated into the U.S. dollar equivalents at exchange rates as
follows: (1) balance sheet accounts at year-end exchange rates and (2) statement
of operations accounts at the weighted average exchange rate for the period. The
gains or losses resulting from such translations are deferred and included in
accumulated other comprehensive income as a separate component of shareholders'
equity.
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 or benefits 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 carry forwards. 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.
Comprehensive Loss. Comprehensive loss is net loss, plus certain other items
that are recorded directly to shareholders' equity. In 2002 and 2001,
comprehensive loss was $7.1 million and $21.4 million, respectively. In 2000, we
had no comprehensive income (loss) other than net loss.
Stock Options. At December 31, 2002, we had stock-based compensation plans
which are more fully described in Note 6. We account for these plans under the
recognition and measurement principles of Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees" ("APB 25") and related
interpretations. Under APB 25, no compensation expense is recognized when the
exercise price of options equals the fair value (market price) of the underlying
stock on the date of grant. The following table illustrates the effect on net
income and earnings per share if we had applied the fair value recognition
provisions of SFAS No. 123 "Accounting for Stock Based Compensation" ("SFAS
123") to stock based compensation:
Year Ended December 31,
------------------------------
2002 2001
------------ ------------
Net loss before extraordinary item, as reported ............................ $ (4,700) $ (20,781)
Add: Stock based employee compensation expense included in
reported net loss, determined under APB 25, net of related tax effects ... 387 2,187
Deduct: Total stock based employee compensation expense
determined under fair value for all awards, net of related tax effects ... (2,673) (3,517)
------------- ------------
Pro forma net loss before extraordinary item ............................... $ (6,986) $ (22,111)
============ ============
Earnings per share:
Basic and diluted - as reported ........................................... $ (0.23) $ (1.06)
Basic and diluted - pro forma ............................................. $ (0.34) $ (1.12)
F-9
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair Value of Financial Instruments. The following methods and assumptions
were used in estimating the fair value of each class of financial instruments
for which it is practicable to estimate fair value.
For cash and cash equivalents, receivables and payables, the carrying
amounts approximate fair value because of the short maturity of these
instruments.
As of January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"), as amended. SFAS 133
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and
hedging activities. It requires the recognition of all derivative instruments as
assets or liabilities in our balance sheet and measurement of those instruments
at fair value. The accounting treatment of changes in fair value is dependent
upon whether or not a derivative instrument is designated as a hedge and if so,
the type of hedge. For derivatives designated as cash flow hedges, changes in
fair value are recognized in other comprehensive income (loss) to the extent
the hedge is effective, until the hedged item is recognized in earnings. Hedge
effectiveness is measured quarterly based on the relative changes in fair value
between the derivative instrument and the hedged item over time. Any change in
fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized
immediately in earnings.
The following table provides information our debt (in thousands):
December 31,
-----------------------------------------------------------
2002 2001
----------------------------- ----------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------------- ------------- ------------- -------------
Bank debt .......................... $ 56,000 $ 56,000 $ 70,000 $ 70,000
Note payable ....................... 30,387 34,376 30,111 33,400
------------- ------------- ------------- -------------
Total ............................ $ 86,387 $ 90,376 $ 100,111 $ 103,400
============= ============= ============= =============
Our bank debt is variable rate debt and as such, approximates fair value,
as interest rates are variable based on prevailing market rates. Our note
payable is a fixed rate note and the fair value has been determined by
discounting the future payments using our incremental borrowing rate, based on
the differential between the fixed interest rate and interest rates of long-term
treasury securities at the date of the borrowing and the balance sheet date.
New Accounting Standards. In June 2001, the Financial Accounting Standards
Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No.
143 "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 143
provides accounting requirements for retirement obligations associated with
tangible long-lived assets, including: 1) the timing of liability recognition;
2) initial measurement of the liability; 3) allocation of asset retirement cost
to expense; 4) subsequent measurement of the liability; and 5) financial
statement disclosures. SFAS 143 requires that an asset retirement cost should be
capitalized as part of the cost of the related long- lived asset and
subsequently allocated to expense using a systematic and rational method. The
statement is effective for fiscal years beginning after June 15, 2002 and we
adopted the statement on January 1, 2003. The transition adjustment resulting
from the adoption of SFAS 143 will be reported as a cumulative effect of a
change in accounting principle. We have not yet completed our assessment of the
impact of SFAS 143 on our financial condition and results of operations.
However, we expect that adoption of the statement will result in increases in
the capitalized costs of our oil and properties and in the recognition of
additional liabilities related to asset retirement obligations.
F-10
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, No. 44, and No. 64, Amendment of FASB Statement No. 13, and Technical
Corrections" ("SFAS 145"). Among other things, SFAS 145 requires gains and
losses from early extinguishment of debt to be included in income from
continuing operations instead of being classified as extraordinary items as
previously required by generally accepted accounting principles. SFAS 145 is
effective for fiscal years beginning after May 15, 2002 and we adopted the
statement on January 1, 2003. Any gain or loss on early extinguishment of debt
that was classified as an extraordinary item in periods prior to adoption must
be reclassified into income from continuing operations. The adoption of SFAS 145
will require the $0.6 million (net of tax) of extraordinary loss for the year
ended December 31, 2001 to be reclassified to interest expense and income tax
benefit.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" ("SFAS 146"). SFAS 146 addresses
financial accounting and reporting for costs associated with exit or disposal
activities and nullified Emerging Issues Task Force Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring". SFAS 146
requires that a liability for a cost associated with an exit or disposal
activity be recognized when the liability is incurred. SFAS 146 also establishes
that fair value is the objective for initial measurement of the liability. The
provisions of this statement are effective for exit or disposal activities that
are initiated after December 31, 2002. We adopted the provisions of SFAS 146 on
January 1, 2003 and the adoption did not have an effect on our financial
position or results of operations.
In November 2002, the FASB issued FASB Interpretation No. 45 "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantee of Indebtedness of Others" ("FIN 45"). FIN 45 requires that upon
issuance of a guarantee, the guarantor must recognize a liability for the fair
value of the obligation it assumes under that guarantee. FIN 45's provisions for
initial recognition and measurement should be applied on a prospective basis to
guarantees issued or modified after December 31, 2002. The disclosure provisions
apply to financial statements for periods ending after December 15, 2002. We do
not currently have guarantees that require disclosure. We adopted the
measurement provisions of this statement in the first quarter of 2003 and the
adoption did not have an effect on our financial position or results of
operations.
F-11
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation
of Variable Interest Entities" ("FIN 46"). FIN 46 requires a company to
consolidate a variable interest entity if it is designated as the primary
beneficiary of that entity even if the company does not have a majority of
voting interest. A variable interest entity is generally defined as an entity
where its equity is unable to finance its activities or where the owners of the
entity lack the risk and rewards of ownership. The provisions of FIN 46 apply
immediately to variable interest entities created after January 31, 2003 and to
variable interest entities in which an enterprise obtains an interest after that
date. The adoption of FIN 46 is not currently expected to have an effect on our
financial position or results of operations when adopted.
Emerging Issues Task Force ("EITF") Issue No. 02-03, "Recognition and
Reporting of Gains and Losses on Energy Trading Contracts" under EITF Issues No.
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" was issued in June 2002. EITF Issue No. 02-03 addresses certain
issues related to energy trading activities, including (a) gross versus net
presentation in the income statement, (b) whether the initial fair value of an
energy trading contract can be other than the price at which it was exchanged,
and (c) accounting for inventory utilized in energy trading activities. As of
January 1, 2003, we will present our gas sold and purchased activities in the
statement of operations for all periods on a net rather than a gross basis. The
change will decrease reported revenues and costs and operating expenses, but
will have no effect on operating income or cash flow. The remaining provisions
effective January 1, 2003 will have no impact on our financial statements. For
more information regarding this marketing activity, see Note 13.
Note 3 -- Acquisitions and Dispositions
Gulf of Mexico
During 2002, we entered into a farm-in agreement to acquire a 100% working
interest in one block with associated proved reserves of approximately 4.7 Bcf
(unaudited), based on third party reservoir engineering estimates at year-end.
We plan to develop this block in 2003.
In addition, we acquired another block for approximately $1.0 million. This
block, along with the block immediately to the south which we did not acquire,
contains an accumulation of oil and gas. Since the well that identified proved
reserves is located on the southern block and due to the strict limitations to
declare reserves as proved, we are unable to record any proved reserves with
this acquisition. The cost of this unproved property is included in oil and gas
properties.
U.K. Sector - North Sea
In 2001, we acquired interests in three properties (five blocks) in the
North Sea which included a 100% interest in one block ("Helvellyn"), a 50%
interest in one block ("Venture") and an 86% interest in three blocks ("Tors").
Helvellyn. In August 2002 we entered into an agreement, which was completed
on September 30, 2002, whereby we assigned 50% of our working interest in the
Helvellyn development in the U.K. Sector - North Sea to a joint venture partner.
The terms of the agreement required the other party to pay a disproportionate
share of the development costs on the project. The partner's share of
development costs totaled $28.9 million through December 31, 2002, of which
$17.3 million was paid to us in cash, $11.0 million is included in accounts
receivable and $0.6 million is included as a receivable in other long term
assets. We retained a 50% working interest and continued as the operator of the
field.
Tors. In February 2002 the U.K. Department of Trade and Industry directly
awarded us a 75% working interest in two lease blocks. The lease sale in the
U.K. is referred to as a "round" and the award is known as an "out of round"
award. We paid no acquisition costs and net proved reserves for these properties
at December 31, 2002, were approximately 20.3 Bcf (unaudited), based on third
party reservoir engineering estimates at year-end. These two blocks will become
a component of our Tors development.
In October 2002 we entered into an earn-in agreement whereby we assigned an
11% interest in three blocks acquired in 2001 to a joint venture partner in
return for them funding part of the block's development costs. We retained a 75%
working interest and continued as the operator. As of December 31, 2002, these
blocks had not yet been developed.
F-12
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Dutch Sector - North Sea
In February 2003, we acquired a 50% working interest in a block located in
the Dutch Sector - North Sea. The remaining 50% interest is owned by a Dutch
company who participates on behalf of the Dutch state.
Note 4 -- Financing and Debt
Long-term debt consisted of the following balances (in thousands):
December 31,
-------------------------
2002 2001
----------- -----------
Credit facility, bearing interest at 5.25% and 5.26%
at December 31, 2002 and 2001, respectively .............. $ 56,000 $ 70,000
11.5 % Note payable, net of unamortized discount of $863
and $1,139 at December 31, 2002 and 2001, respectively ... 30,387 30,111
----------- -----------
Total debt ................................................. 86,387 100,111
Less current maturities .................................... (6,000) (22,000)
----------- -----------
Total long-term debt ....................................... $ 80,387 $ 78,111
=========== ===========
Credit Facility
We have a $100.0 million senior-secured revolving credit facility which is
secured by substantially all of our U.S. oil and gas properties, as well as by
approximately two-thirds of the capital stock of our foreign subsidiaries and is
guaranteed by our wholly owned subsidiary, ATP Energy, Inc. The amount available
for borrowing under the credit facility is limited to the loan value, as
determined by the bank, of oil and gas properties pledged under the facility. At
December 31, 2002, the borrowing base was $56.0 million with no further
scheduled borrowing base reduction. If our outstanding balance exceeds our
borrowing base at any time, we are required to repay such excess within 30 days
and our interest rate during the time an excess exists is increased by 2.00%.
On March 25, 2003, we entered into an agreement with our lenders to defer
our scheduled borrowing base redetermination until the next scheduled
redetermination in May 2003. This agreement reaffirmed the current borrowing
base of $56.0 million and the borrowing base reduction amount of zero. As part
of this agreement we committed to reduce the amount outstanding under our
borrowing base by $6.0 million between March 28, 2003 and May 31, 2003.
Additionally, if the aggregate principal amount of the loan exceeds the required
month-end reductions of $1.5 million, $2.5 million and $2.0 million during the
period from March 28, 2003 to May 31, 2003, such principal amounts in excess of
the applicable period limits shall bear interest at a per annum rate of interest
equal to the adjusted reference rate plus 2%. Further, the lenders agreed to
raise the limit of advances available to be made to our foreign subsidiaries and
specified certain future events which would require our foreign subsidiaries to
return the incremental advances to the parent. At the next scheduled
redetermination in May 2003, the lenders can increase or decrease the borrowing
base and re-establish the monthly reduction amount. A material reduction in the
borrowing base or a material increase in the monthly reduction amount by the
lender would have a material negative impact on our cash flows and our ability
to fund future operations.
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 0.25%, 0.50%, 0.75% or 1.00% depending on the amount
outstanding under the credit agreement. The interest on a Eurodollar loan is
equal to the Eurodollar rate, plus a margin of 2.25%, 2.50%, 2.875%, or 3.125%
depending on the amount outstanding under the credit facility. The credit
facility matures in May 2004. Our credit facility contains conditions and
restrictive provisions, among other things, (1) limiting us to enter into any
arrangement to sell or transfer any of our material property, (2) prohibiting a
merger into or consolidation with any other person or sell or dispose of all or
substantially all of our assets, (3) maintaining certain financial ratios and
(4) limitations on advances to our foreign subsidiaries.
F-13
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note Payable
Effective June 29, 2001, we issued a note payable to a purchaser for a face
principal amount of $31.3 million which matures in June 2005 and bears interest
at a fixed rate of 11.5% per annum. The note is secured by second priority liens
on substantially all of our U.S. oil and gas properties and is subordinated in
right of payment to our existing senior indebtedness. We executed an agreement
in connection with the note which contains conditions and restrictive provisions
and requires the maintenance of certain financial ratios. Upon consent of the
purchaser, which shall not be unreasonably withheld, the note may be repaid
prior to the maturity date with an additional repayment premium based on the
percentage of the principal amount paid, ranging from 4.5% during the first year
to 16.5% in the final year of payment. If the note is paid at maturity, the
maximum payment premium of 16.5% is required. The expected repayment premium is
being amortized to interest expense straight-line, over the term of the note
which approximates the effective interest method. The resulting liability is
included in other long-term liabilities on the consolidated balance sheet. In
July 2001, we received proceeds of $30.0 million in consideration for the
issuance of the note. The discount of $1.3 million is being amortized to
interest expense using the effective interest method. The amount available for
borrowing under the note is limited to the loan value of oil and gas properties
pledged under the note, as determined by the purchaser. The purchaser has the
right to make a redetermination of the borrowing base at least once every six
months. We were not notified of any change in the borrowing base in 2002. If our
outstanding balance exceeds the borrowing base at any time, we are required to
repay such excess within 10 days subject to the provisions of the agreement. A
material reduction in the borrowing base by the lender would have a material
negative impact on our cash flows and our ability to fund future obligations. As
of December 31, 2002, all of our borrowing base under the agreement was
outstanding.
As of December 31, 2002, we were in compliance with all of the financial
covenants of our credit facility and note payable agreements.
Maturities
The aggregate amount of maturities of our long-term debt for the next five
years is: 2003 - $6.0 million, 2004 -$50.0 million and 2005 - $31.3 million.
Note 5 -- Equity
Common Stock
At December 31, 2002, we had 100,000,000 shares authorized, 20,398,007
shares issued, 20,322,167 shares outstanding and 75,840 shares in treasury. At
December 31, 2001, we had 100,000,000 shares authorized, 20,388,488 shares
issued, 20,312,648 shares outstanding and 75,840 shares in treasury.
Treasury Stock
During the second quarter 2001, the first option vesting date occurred for
certain options granted since September 1999 through the date of our initial
public offering ("IPO") on February 5, 2001, as well as for certain options
granted prior to September 1999. Of those options exercised during that period,
certain optionees elected to receive cash upon exercise of their options,
whereby we purchased 75,840 shares for approximately $0.9 million and recorded
such purchase as treasury stock using the cost method.
F-14
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6 -- Stock Option Plans
In May 1994, the Board of Directors approved the 1994 Stock Option Plan
(the "1994 Plan") under which it was authorized to issue up to 55,902,930 shares
of common stock. The exercise price of the options under the 1994 Plan was not
less than the greater of par value per share or fair market value, at date of
grant. These options had a maximum term of 10 years, subject to vesting
requirements in the individual option agreements. In April 2000, the only
outstanding option to purchase 18,937,397 shares under the 1994 Plan was amended
to limit the number of shares that could be purchased pursuant to the option to
such number that enables the holder to maintain ownership of a majority of the
outstanding shares. Because the holder of this option owned a majority of the
shares, the number of shares exercisable as of April 2000 was zero. Upon the
closing of the IPO in February 2001, the 1994 Plan and all outstanding options
under this plan were cancelled.
In December 1998, the Board of Directors approved the 1998 Stock Option
Plan (the "1998 Plan") to provide increased incentive for its employees and
directors. The 1998 Plan authorizes the granting of incentive and nonqualified
stock options for up to 2,678,571 shares of common stock to eligible
participants and expires five years after the closing date of our IPO. One third
of the options were exercisable on April 10, 2001 with each remaining third
exercisable on the first and second anniversaries of the IPO. Options granted
under this plan remain exercisable by the employees owning such options, but no
new options will be granted under this plan.
In January 2001, the Board of Directors approved the 2000 Stock Option Plan
(the "2000 Plan") to provide increased incentive for its employees and
directors. The 2000 Plan authorizes the granting of options and awards for up to
4,000,000 shares of common stock. Generally, options are granted at prices equal
to at least 100% of the fair value of the stock at the date of grant, expire not
later than five years from the date of grant and vest ratably over a four-year
period following the date of grant. From time to time, as approved by the Board
of Directors, options with differing terms have also been granted.
The following table is a summary of stock option activity:
2002 2001 2000
------------------------- ------------------------ -----------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
------------ -------- ----------- --------- ------------ ----------
Outstanding at beginning of year .. 1,637,809 $ 8.520 646,608 $ 2.710 19,394,362 $ 0.040
Granted ........................... 86,500 3.430 1,117,000 11.200 368,215 3.690
Exercised ......................... (9,519) 1.431 (102,774) 1.960 - -
Forfeited ......................... (29,643) 9.089 (23,025) 4.000 (178,572) 1.400
Cancelled ......................... - - - - (18,937,397) 0.004
------------ ----------- ------------
Outstanding at end of year ........ 1,685,147 $ 8.290 1,637,809 $ 8.520 646,608 $ 2.710
============ =========== ============
Exercisable at end of year ........ 563,344 $ 6.760 112,760 $ 3.370 - $ -
============ =========== ============
Weighted average fair value of
options granted during the year .. $ 1.74 $ 4.65 $ -
F-15
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information about all stock options
outstanding at December 31, 2002:
Options Outstanding Options Exercisable
-------------------------------------- -------------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Number Contractual Exercise Number Exercise
Range of Exercise Prices Outstanding Life Price Exercisable Price
- -------------------------------------------- ----------- ---------- -------- ----------- --------
$ 1.40 - $ 3.85 .......................... 607,647 2.4 Years $ 2.94 306,469 $ 3.37
$ 6.95 - $ 6.95 .......................... 25,000 3.8 Years 6.95 6,250 6.95
$11.24 - $ 11.40 .......................... 1,032,500 3.4 Years 11.37 245,625 11.37
$14.00 - $ 14.00 .......................... 20,000 3.1 Years 14.00 5,000 14.00
----------- -----------
$ 1.40 - $ 14.00 .......................... 1,685,147 3.0 Years $ 8.29 563,344 $ 6.76
=========== ===========
We have elected to follow APB 25 and related interpretations in accounting
for our stock option plans. Accordingly, no compensation expense, except as
specifically described below, has been recognized for employee stock option
plans. Since options granted under the 1998 Plan did not vest nor were
exercisable until 60 days after the date of our IPO, under the provisions of
SFAS No. 123 "Accounting for Stock Based Compensation" ("SFAS 123"), our pro
forma net loss and per share amounts would have been unchanged for the year
ended December 31, 2000. The pro forma effect on net income and earnings per
share in 2002 and 2001, had we applied the fair-value-recognition provisions of
SFAS 123, are shown in Note 2.
The fair value of options granted in 2002 was estimated at the date of
grant using a Black-Scholes option-pricing model with the following
weighted-average assumptions: zero dividend yield; risk-free interest rate of
2.8%, volatility of 92.8% and an expected life of 2.5 years.
The fair value of options granted prior to 2002 was estimated on the latter
of the date of grant or date of our IPO using a Black-Scholes option-pricing
model with the following weighted-average assumptions: zero dividend yield;
risk-free interest rate of 4.5% and volatility of 80.2% and an expected life of
2.4 years.
Non-Cash Compensation Expense. In 2002, we recorded a non-cash charge to
compensation expense of approximately $0.6 million for options granted since
September 1999 through the date of our initial public offering on February 5,
2001 (the "measurement date"). The total expected expense as of the measurement
date is recognized in the periods in which the option vests. Each option is
divided into three equal portions corresponding to the three vesting dates
(April 10, 2001, February 9, 2002, and February 9, 2003), with the related
compensation cost for each portion amortized straight-line over the period to
the vesting date. In 2001, we recorded a non-cash compensation expense of $2.9
million for the above options and an additional non-cash compensation expense of
$0.5 million related to certain options granted prior to September 1999 and
exercised during 2001. The additional expense was recorded as a result of the
manner in which those shares were exercised.
F-16
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We have a 401(k) Savings Plan which covers all domestic employees. At our
discretion, we may match a certain percentage of the employees' contributions to
the plan. The matching percentage is discretionary and is currently 50% of each
participant's contributions up to 6% of the participant's compensation. Our
matching contributions to the plan were approximately $97,000, $70,000 and
$56,000, for the years ended December 31, 2002, 2001 and 2000, respectively.
We also have a defined contribution plan for our U.K. employees. We
currently contribute 3% to the plan and such contributions are subject to the
Pensions Act 1999 (U.K.) and to U.K. rules on taxation. For the years ended
December 31, 2002 and 2001, we contributed approximately $15,500 and $14,000,
respectively.
Note 7 -- Earnings Per Share
Basic earnings per share is computed by dividing net 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,
potential common shares have been excluded from the computation of weighted
average common shares outstanding because their effect is antidilutive.
Basic and diluted net loss per share is computed based on the following
information (in thousands, except per share amounts):
Years Ended December 31,
------------------------------------------------
2002 2001 2000
------------- ------------- -------------
Net loss available to common shareholders .................. $ (4,700) $ (21,383) $ (10,398)
============= ============= =============
Weighted average shares - basic and diluted ................ 20,315 19,704 14,286
============= ============= =============
Net loss per share- basic and diluted:
Loss before extraordinary item ........................ $ (0.23) $ (1.06) $ (0.73)
Extraordinary item, net of income taxes ............... - (0.03) -
------------- ------------- -------------
Net loss per common share ........................... $ (0.23) $ (1.09) $ (0.73)
============= ============= =============
Note 8 -- Extraordinary Item
For the year ended December 31, 2001, we recognized an extraordinary loss
of $0.6 million, net of income taxes, related to the early extinguishment of our
non-recourse borrowings. This loss will be reclassified to interest expense and
income tax benefit upon the adoption of SFAS 145.
Note 9 -- Income Taxes
The benefit (provision) for income taxes before extraordinary item
consisted of the following (in thousands):
Years Ended December 31,
------------------------------------------------
2002 2001 2000
------------- ------------- -------------
Current:
State .................................................... $ - $ - $ -
Federal .................................................. 229 - -
------------- ------------- -------------
229 - -
------------- ------------- -------------
Deferred:
State .................................................... - - -
Federal .................................................. 2,352 11,186 5,594
------------- ------------- -------------
2,352 11,186 5,594
------------- ------------- -------------
Benefit for income taxes before extraordinary item ......... $ 2,581 $ 11,186 $ 5,594
============= ============= =============
F-17
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The reconciliation of income tax, before any valuation allowance, computed
at the U.S. federal statutory tax rates to the provision for income taxes is as
follows:
Years Ended December 31,
------------------------------------------------
2002 2001 2000
------------- ------------- -------------
Statutory federal income tax rate ..................... (35.00)% (35.00)% (35.00)%
Nondeductible and other ............................... (0.39) 0.01 0.02
------------- ------------- -------------
(35.39)% (34.99)% (34.98)%
============= ============= =============
Significant components of our deferred tax assets (liabilities) as of
December 31, 2002 and 2001 are as follows (in thousands):
December 31,
------------------------------
2002 2001
------------- -------------
Deferred tax assets:
Net operating loss carryforwards ....................................... $ 19,550 $ 3,809
Minimum tax credit carryforwards ....................................... - 229
Fixed asset basis differences .......................................... (5,427) 11,367
State taxes ............................................................ 17 17
Unrealized book (gains) losses ......................................... 2,415 (443)
Stock based compensation expense ....................................... 1,107 1,177
Litigation ............................................................. 1,101 1,050
Foreign equity in subsidiary ........................................... 1,989 1,152
Deferred taxes related to SFAS 133...................................... 1,628 -
Other .................................................................. 828 870
------------- -------------
Net deferred tax assets ..................................................... $ 23,208 $ 19,228
============= =============
At December 31, 2002, 2001 and 2000, we had net operating loss
carryforwards for federal income tax purposes of approximately $55.9 million,
$10.7 million, and $11.0 million respectively, which are available to offset
future federal taxable income through 2021.
At December 31, 2002 we have determined that it is more likely than not the
deferred tax assets will be realized based on current projections of future
taxable income due to higher commodity prices at year-end.
A tax benefit related to the exercise of employee stock options of
approximately $0.1 million was allocated directly to additional paid-in capital
in 2001.
Additionally, a tax benefit of $0.3 million was recognized related to the
extraordinary loss for the year ended December 31, 2001.
Note 10 -- Comprehensive Loss
Comprehensive loss consists of net loss, as reflected on the consolidated
statement of operations, and other gains and losses affecting shareholders'
equity that are excluded from net loss. We recorded other comprehensive income
for the first time in 2001.
F-18
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of comprehensive loss are as follows (in thousands):
Years Ended December 31,
------------------------------
2002 2001
------------- -------------
Net loss ......................................................................... $ (4,700) $ (21,383)
------------- -------------
Other comprehensive income (loss), net of tax:
Cumulative effect of change in accounting principle - January 1, 2001 .......... - (34,252)
Reclassification adjustment for settled contracts .............................. 627 34,252
Change in fair value of outstanding hedging positions .......................... (3,651) -
Foreign currency translation adjustment ........................................ 670 19
------------- -------------
Other comprehensive income (loss) ............................................ (2,354) 19
------------- -------------
Comprehensive loss ............................................................... $ (7,054) $ (21,364)
============= =============
Note 11 -- Commitments and Contingencies
Operating Leases
We have commitments under an operating lease agreement for office space.
Total rent expense for the years ended December 31, 2002, 2001 and 2000 was
approximately $0.5 million, $0.3 million and $0.2 million respectively. At
December 31, 2002, the future minimum rental payments due under the lease are as
follows (in thousands amounts):
2003 ......................................... $ 539
2004 ......................................... 539
2005 ......................................... 371
2006 ......................................... 289
2007 ......................................... 214
Later Years .................................. 997
---------
Total .................................... $ 2,949
=========
Contingencies
In 2001 we purchased three properties in the U.K. Sector - North Sea for
approximately $3.1 million. In accordance with the purchase agreement, we also
committed to pay future consideration contingent upon the successful development
and operation of the properties. The contingent consideration for each property
includes amounts to be paid upon achieving first commercial production and upon
achieving designated cumulative production levels. Active development is in
progress on our Helvellyn property and future development is planned on the
other two properties. First commercial production on the Helvellyn property may
occur sometime in the second quarter of 2003. Although a significant portion of
the work required has been completed, there remains significant additional work
to be performed before this property can produce commercially. That work
includes completion, hook-up, and testing of the pipeline and production
facilities and final negotiation of certain terms in our transportation and
processing agreements. Accordingly, there can be no assurance of eventual
production from this development until the aforementioned activities are
completed successfully. At such time, the required amount will be accrued for
payment to the seller and capitalized as acquisition costs.
Litigation
On August 28, 2001 ATP entered into a written agreement to acquire a
property in the Gulf of Mexico during September 2001. On October 9, 2001 the
agreement was amended to ultimately extend the closing date until October 31,
2001 in exchange for payments made by ATP totaling $3.0 million. This amendment
also contained an arrangement whereby if ATP did not close on the property, and
if sellers sold the property to a third party with a sale that met specific
contract requirements, ATP would be required to execute a six month note for
payment of the differential. Since ATP did not obtain the financing for the
acquisition by October 31, 2001, the transaction did not close by that date;
however, the parties' intensive work toward closing continued beyond that date
without interruption.
While working on the closing for the property with ATP, the sellers sold
the property to a third party without informing ATP until after the closing had
taken place. ATP filed an action in the District Court of Harris County, Texas
against the sellers, generally alleging improper sale of the offshore property
to a third party and breach of contract, and seeking unspecified damages from
the sellers. The case is encaptioned ATP Oil & Gas Corporation vs. Legacy
Resources Co., L.P. et al, No. 2001-63224 in the 269th Judicial District Court
of Harris County, Texas. At the same time sellers notified ATP of their sale to
a third party, the sellers had a demand made upon ATP for execution of a six
month note for the amount of an alleged differential of approximately $12.3
million plus interest at 16%. Substantiation of the amount and validity of the
demand could not be ascertained based on the content of the demand received. ATP
contested the entire demand. The judge has abated the litigation, until
arbitration pursuant to the underlying agreements between the sellers and ATP is
completed. A tentative date of May 19, 2003 has been scheduled for the
arbitration with an alternative date in September 2003. Due to the inherent
uncertainties involving contested facts and legal issues a prediction as to the
likely outcome cannot be made with any degree of certainty, and we have not
accrued any amount related to this matter. While we are seeking recovery of the
amounts previously paid and discussed above, the $3.0 million has been charged
to earnings along with other costs related to this matter. ATP intends to
vigorously defend against the sellers' claims and forcefully pursue its own
claims in this matter.
F-19
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In August 2001, Burlington Resources Inc. filed suit against ATP alleging
formation of a contract with ATP and our breach of the alleged contract. The
complaint seeks compensatory damages of approximately $1.1 million. We believe
that this claim is without merit, and we intend to defend it vigorously.
We are also, in the ordinary course of business, a claimant and/or
defendant in various legal proceedings. Management does not believe that the
outcome of these legal proceedings, individually, and in the aggregate will have
a materially adverse effect on our financial condition, results of operations or
cash flows.
Note 12 -- Derivative Instruments and Price Risk Management Activities
On January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"), as amended, and recorded a
cumulative transition loss of $34.3 million, net of tax, to accumulated other
comprehensive income (loss) to account for the effect of the change in
accounting principle. The standard requires that all derivatives be recorded on
the balance sheet at fair value and establishes criteria for documentation and
measurement of hedging activities.
We occasionally use derivative instruments with respect to a portion of our
oil and gas production to manage our exposure to price volatility. These
instruments may take the form of futures contracts, swaps or options.
Prior to July 1, 2002, we had not attempted to qualify our derivatives for
the hedge accounting provisions under SFAS 133. Accordingly, we accounted for
the changes in market value of these derivatives through current earnings. Gains
and losses on all derivative instruments prior to July 1, 2002 were included in
other income (expense) on the consolidated financial statements.
Loss on derivative instruments is comprised of the following components (in
thousands):
Years Ended December 31,
------------------------------------------------
2002 2001 2000
------------- ------------- -------------
Loss on settled contracts .................................. $ (153) $ (19,348) $ -
Loss on speculative positions (1) .......................... - - (4,662)
Loss on open speculative positions (1) ..................... - - (7,249)
Gain (loss) on open derivative positions ................... (8,166) 1,265 -
------------- ------------- -------------
$ (8,319) $ (18,083) $ (11,911)
============= ============= =============
- ---------------
(1) In 2000, we found ourselves in a speculative position as a result of actual
production being less than projected production when the derivative
products were consummated or as a result of entering into speculative
derivative instruments. This position was accounted for using the
mark-to-market method.
As of July 1, 2002, we performed the requisite steps to qualify our
existing derivative instruments for hedge accounting treatment under the
provisions of SFAS 133. Derivative instruments designated as cash flow hedges
are reflected at fair value on our consolidated balance sheets. Changes in fair
value, to the extent the hedge is effective, are recognized in other
comprehensive income (loss) until the hedged item is settled and is recognized
in earnings. Any ineffective portion of the derivative instrument's change in
fair value is recognized in revenues in the current period. Hedge effectiveness
is measured at least quarterly.
F-20
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Oil and gas revenues are comprised of the following components for the
periods indicated (in thousands):
Years Ended December 31,
---------------------------------------
2002 2001 2000
--------- --------- ---------
Oil and gas production ........................................ $ 89,415 $ 105,757 $ 104,163
Derivative settlements during the period ...................... (3,225) - (28,223)
--------- --------- ---------
86,190 105,757 75,940
Amounts previously recognized in earnings prior
to July 1, 2002 qualification for hedge accounting (1) ....... 3,225 - -
Change in fair value of derivative hedging positions (2) ...... (964) - -
Ineffective portion of derivative hedging instruments ......... (300) - -
--------- --------- ---------
$ 88,151 $ 105,757 $ 75,940
========= ========= =========
- ----------
(1) Represents the mark to market valuation of open positions at June 30, 2002
which were previously recognized in other income (expense).
(2) Represents the change in fair value of settled positions between the
beginning and end of the period.
At December 31, 2002, a $4.6 million loss ($3.0 million after tax) was
recorded to accumulated other comprehensive loss for the effective portion of
the change in fair market value during the last six months of 2002. All of this
deferred loss will be reversed during the next twelve months as the forecasted
transactions actually occur, assuming no further changes in fair market value.
All forecasted transactions currently being hedged are expected to occur by
December 2003. As of December 31, 2002, the fair value of the outstanding
derivative instruments was a current liability of $9.6 million. This amount
represents the difference between contract prices and future market prices on
contracted volumes of the commodities as of December 31, 2002.
As of December 31, 2002, we had derivative contracts in place for the
following natural gas and oil volumes:
Average
Fixed
Period Volumes Price
------ ----------- ---------
Natural gas (MMBtu):
2003 ....................................... 6,080,000 $ 3.02
Oil (Bbl):
2003 ....................................... 182,500 24.10
In addition to these derivative instruments, we also manage our exposure to
oil and gas price risks by periodically entering into fixed-price delivery
contracts. As of December 31, 2002, we had fixed-price contracts in place for
the following natural gas and oil volumes:
Average
Fixed
Period Volumes Price(1)
------ ----------- ----------
Natural gas (MMBtu):
2003 ....................................... 5,173,000 $ 3.83
Oil (Bbl):
2003 ....................................... 227,500 26.41
- ----------
(1) Includes the effect of basis differentials.
F-21
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes all derivative instruments and fixed-price
contracts as of December 31, 2002:
Average
Fixed
Period Volumes Price (1)
------ ----------- ----------
Natural gas (MMBtu):
2003 ...................................... 11,253,000 $ 3.39
Oil (Bbl):
2003 ...................................... 410,000 25.38
Thus far, in 2003 we have entered into the following fixed-price contracts:
Average
Fixed
Period Volumes Price (1)
------ ----------- ----------
Natural gas (MMBtu):
2004 ...................................... 3,403,000 $ 4.32
Oil (Bbl):
2003 ...................................... 44,500 31.61
-------------
(1) Includes the effect of basis differentials.
Additionally in 2003, we entered into a costless collar arrangement for
300,000 MMBtu of our natural gas production for the months of January through
March 2004 with a floor of $4.40 per MMBtu and a ceiling of $5.80 MMBtu. Collar
arrangements are put and call options used to establish floor and ceiling
commodity prices for a fixed volume of production during a certain time period.
They provide for payments to counterparties if the index price exceeds the
ceiling and payments from the counterparties if the index price is below the
floor.
Note 13 -- ATP Energy Gas Purchase Transaction
ATP Energy entered an agreement in December 1998 with American Citigas
Company ("American Citigas") to purchase gas over a ten-year period commencing
January 1999. The amount of gas to be purchased was 9,000 MMBtu per day for the
first year and 5,000 MMBtu per day for years two through ten. The contract
requires ATP Energy to purchase on a monthly basis the gas at a premium of
approximately $2.50 per MMBtu to the Gas Daily Henry Hub Index. American Citigas
is required to reimburse ATP Energy on a monthly basis for a portion of this
premium during the term of the contract. This portion of the reimbursement is
accomplished by a note receivable in favor of ATP. The note receivable bears
interest at 6% and has monthly payments of approximately $0.4 million until
January 2009. The balance of the note receivable at December 31, 2002 and 2001
was $22.9 million and $25.9 million, respectively. At December 31, 2002 and
2001, the present value of the remaining premium payments to be made by ATP
Energy, using a discount rate of 6%, was $22.7 million and $25.8 million,
respectively. The note receivable and the premium payable to American Citigas
have been offset in the consolidated financial statements in accordance with the
prescribed accounting in FASB Interpretation No. 39, "Offsetting of Amounts
Related to Certain Contracts". The aggregate amount of premium payments to be
paid by ATP Energy over the term of the contract is approximately $49.0 million
and the aggregate amount of payments to be paid to ATP Energy over the term of
the note is approximately $45.0 million. At December 31, 2002 the remaining
premium to be paid was $27.1 million, which will be reimbursed by the monthly
reimbursement from American Citigas and the remaining deferred obligation
discussed below. The terms provide for the immediate termination of the
agreement upon non-performance by American Citigas. ATP Energy entered into a
contract with El Paso Energy Marketing in December 1998 to sell an identical
quantity of natural gas at the Gas Daily Henry Hub index price less $0.015 until
December 2001 and has been renewed on a month-to-month basis since then.
F-22
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ATP Energy received $6.0 million in connection with these transactions, of
which $2.0 million was recorded as deferred revenue and $4.0 million was
recorded as deferred obligations. The deferred revenue amount of $2.0 million is
a non-refundable fee received by ATP Energy and is recognized into income as
earned over the life of the contract. At December 31, 2002 and 2001, the
deferred revenue amount was $1.1 million and $1.3 million, respectively. The
deferred obligation amount of $4.0 million represented the difference between
the premium we agreed to pay for natural gas under the American Citigas contract
and the obligation of American Citigas to partially reimburse us for such
premium. Any deferred obligation amount not utilized is refundable if the
contract is terminated. The transaction is structured with American Citigas such
that there is no financial impact to ATP Energy associated with the premium paid
and reimbursement received other than the $2.0 million realized by ATP Energy.
The premium we pay to American Citigas will be approximately the same
as the reimbursement obligation for the remainder of the contract. ATP Energy
entered into the transactions to earn the fee for agreeing to market the volumes
of natural gas specified in the American Citigas contract.
Our officers were paid $152,125 for the year ended December 31, 2000 for
negotiating and monitoring ATP Energy's gas supply contract. We have recognized
these amounts in general and administrative expense in the respective periods.
No amounts were paid in 2002 and 2001 and we do not intend to pay any further
amounts.
Note 14 -- Related Party Transactions
We have granted to certain of our officers overriding royalty interests
ranging in amounts from 0.2% to 3.0% in four of its oil and gas properties. The
overriding royalty interest entitles the holder to a portion, 0.2% to 3.0%, of
the future revenue for the life of each property. As a result, we recognized
$0.3 million in general and administrative expense for the year ended December
31, 2000. No amounts were paid in 2002 and 2001 and we do not intend to pay any
further amounts.
Note 15 -- Segment Information
We follow SFAS No. 131, "Disclosures About Segments of an Enterprise and
Related Information," which requires that companies disclose segment data based
on how management makes decisions about allocating resources to segments and
measuring their performance. We manage our business and identify our segments
based on geographic areas. We have two reportable segments: our operations in
the Gulf of Mexico and our operations in the North Sea. Both of these segments
involve oil and gas producing activities. Following is certain financial
information regarding our segments for 2002, 2001 and 2000 is as follows (in
thousands).
Gulf of
Mexico North Sea Total
------------ --------- ---------
2002
Revenues ....................................... $ 94,423 $ - $ 94,423
Depreciation, depletion and amortization ....... 43,292 98 43,390
Impairment of oil and gas properties ........... 6,844 - 6,844
Operating income (loss) ........................ 12,728 (2,426) 10,302
Total assets ................................... 144,069 37,986 182,055
Additions to oil and gas properties ............ 18,520 16,353 34,873
Table continued on following page
F-23
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Gulf of
Mexico North Sea Total
---------- ----------- -----------
2001
Revenues .................................................. $ 113,174 $ - $ 113,174
Depreciation, depletion and amortization .................. 53,376 52 53,428
Impairment of oil and gas properties ...................... 24,891 - 24,891
Operating loss ............................................ (1,825) (2,904) (4,729)
Total assets .............................................. 172,300 5,264 177,564
Additions to oil and gas properties ....................... 106,433 3,831 110,264
2000
Revenues .................................................. $ 83,988 $ - $ 83,988
Depreciation, depletion and amortization .................. 40,563 6 40,569
Impairment of oil and gas properties ...................... 10,838 - 10,838
Operating income (loss) ................................... 7,813 (438) 7,375
Total assets .............................................. 161,400 593 161,993
Additions to oil and gas properties ....................... 76,086 388 76,474
Note 16 -- Summarized Quarterly Financial Data (Unaudited)
(In Thousands, Except Per Share Amounts)
First Second Third Fourth
Quarter Quarter Quarter Quarter
------- ------- ------- -------
2002
Revenues ...................................... $ 19,790 $ 29,311 $ 24,668 $ 20,654
Costs and expenses ............................ 19,489 20,950 19,446 24,236(1)
Income (loss) from operations ................. 301 8,361 5,222 (3,582)
Net income (loss) ............................. (6,363) 3,171 1,665 (3,173)
Net income (loss) per common share:
Basic and diluted (3) ....................... $ (0.31) $ 0.16 $ 0.08 $ (0.16)
2001
Revenues ...................................... $ 41,443 $ 31,035 $ 20,883 $ 19,813
Costs and expenses ............................ 28,701(2) 29,694(2) 24,659(2) 34,849(2)
Income (loss) from operations ................. 12,742 1,341 (3,776) (15,036)
Income (loss) before extraordinary item ....... (6,873) 3,813 (6,499) (11,222)
Net income (loss) ............................. (6,873) 3,211 (6,499) (11,222)
Income (loss) per common share before
extraordinary item, basic and diluted ....... $ (0.38) $ 0.19 $ (0.32) $ (0.55)
Net income (loss) per common share:
Basic and diluted (3) ....................... $ (0.38) $ 0.16 $ (0.32) $ (0.55)
- ----------
(1) Includes impairment charges of $6.8 million during the fourth quarter for
two properties.
(2) Includes impairment charges of $8.5 million, $5.7 million, $3.7 million and
$7.0 million during the first, second, third and fourth quarters,
respectively, for eight properties.
(3) The sum of the per share amounts per quarter does not equal the year due to
the changes in the average number of common shares outstanding
F-24
ATP OIL & GAS CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
Oil and Gas Reserves and Related Financial Data (Unaudited)
Costs Incurred
The following table summarizes costs incurred in natural gas and oil
property acquisition, exploration and development activities are summarized
below (in thousands):
Gulf of
Mexico North Sea Total
------------- ------------- -------------
2002
Property acquisition costs:
Unproved ................................. $ 959 $ - $ 959
Proved ................................... - - -
Development costs ........................... 17,561 16,353 33,914
------------- ------------- -------------
$ 18,520 $ 16,353 $ 34,873
============= ============= =============
2001
Property acquisition costs:
Proved ................................... $ 28,344 $ 3,112 $ 31,456
Development costs ........................... 77,783 719 78,502
------------- ------------- -------------
$ 106,127 $ 3,831 $ 109,958
============= ============= =============
2000
Property acquisition costs:
Proved ................................... $ 7,534 $ - $ 7,534
Development costs ........................... 68,982 - 68,982
------------- ------------- -------------
$ 76,516 $ - $ 76,516
============= ============= =============
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.
Reserves quantities as well as certain information regarding future
production and discounted cash flows were prepared by independent petroleum
engineers Ryder Scott Company, L.P. for all years presented and Schlumberger
Holditch-Reservoir Technologies Consulting Services for one property for 2000.
Our U.K. reserves at December 31, 2002 and 2001 were prepared by independent
petroleum consultants Troy Ikoda Limited.
F-25
ATP OIL & GAS CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth our net proved oil and gas reserves at
December 31, 1999, 2000, 2001 and 2002 and the changes in net proved oil and gas
reserves for the years ended December 31, 2000, 2001 and 2002:
Oil, Condensate and
Natural Gas (MMcf) Natural Gas Liquids (MMBbls)
----------------------------------- -----------------------------------
Gulf of Gulf of
Mexico North Sea Total Mexico North Sea Total
---------- ------------- -------- ----------- ----------- -------
Proved Reserves at
December 31, 1999 ................. 93,997 - 93,997 1,689 - 1,689
Revisions of previous estimates ...... (19,423) - (19,423) (46) - (46)
Extensions and discoveries ........... 7,239 - 7,239 77 - 77
Purchase of properties ............... 42,318 - 42,318 2,602 - 2,602
Disposition of properties ............ (151) - (151) - - -
Production ........................... (22,410) - (22,410) (345) - (345)
----------- ----------- ----------- ----------- ----------- ------------
Proved Reserves at
December 31, 2000 ................. 101,570 - 101,570 3,977 - 3,977
Revisions of previous estimates ...... (6,793) - (6,793) 134 - 134
Purchase of properties ............... 40,060 80,629 120,689 3,432 - 3,432
Production ........................... (20,957) - (20,957) (790) - (790)
----------- ----------- ----------- ----------- ----------- -----------
Proved Reserves at
December 31, 2001 ................. 113,880 80,629 194,509 6,753 - 6,753
Revisions of previous estimates ...... 1,594 9,314 10,908 441 - 441
Purchase of properties ............... 4,696 20,272 24,968 - - -
Disposition of properties ............ - (17,115) (17,115) - - -
Production ........................... (17,732) - (17,732) (1,454) - (1,454)
----------- ----------- ----------- ----------- ----------- -----------
Proved Reserves at
December 31, 2002 ................. 102,438 93,100 195,538 5,740 - 5,740
=========== =========== =========== =========== =========== ===========
Oil, Condensate and
Natural Gas (MMcf) Natural Gas Liquids (MMBbls)
----------------------------------- -----------------------------------
Gulf of Gulf of
Mexico North Sea Total Mexico North Sea Total
---------- ----------- -------- ----------- ----------- -------
Proved Developed Reserves at
December 31, 1999 ................. 67,314 - 67,314 710 - 710
December 31, 2000 ................. 42,502 - 42,502 851 - 851
December 31, 2001 ................. 56,704 - 56,704 3,115 - 3,115
December 31, 2002 ................. 34,068 - 34,068 2,318 - 2,318
Standardized Measure
The standardized measure of discounted future net cash flows relating to
proved natural gas and oil reserves as of year-end is shown below (in
thousands):
Gulf of
Mexico North Sea Total
----------- ----------- ------------
2002
Future cash inflows............................................... $ 649,927 $ 205,629 $ 855,556
Future operating expenses......................................... (69,215) (78,131) (147,346)
Future development costs.......................................... (128,803) (109,510) (238,313)
---------- --------- ----------
Future net cash flows............................................. 451,909 17,988 469,897
Future income taxes............................................... (129,435) (929) (130,364)
---------- --------- ----------
Future net cash flows, after income taxes......................... 322,474 17,059 339,533
10% annual discount per annum..................................... (74,770) (5,870) (80,640)
---------- --------- ----------
Standardized measure of discounted future net cash flows $ 247,704 $ 11,189 $ 258,893
========== ========= ==========
Table continued on following page
F-26
ATP OIL & GAS CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
Gulf of
Mexico North Sea Total
------------- ------------- -------------
2001
Future cash inflows .............................................. $ 423,273 $ 302,894 $ 726,167
Future operating expenses ........................................ (59,722) (100,330) (160,052)
Future development costs ......................................... (100,919) (111,044) (211,963)
------------- ------------- -------------
Future net cash flows ............................................ 262,632 91,520 354,152
Future income taxes .............................................. (35,469) (26,188) (61,657)
------------- ------------- -------------
Future net cash flows, after income taxes ........................ 227,163 65,332 292,495
10% annual discount per annum .................................... (54,247) (25,584) (79,831)
------------- ------------- -------------
Standardized measure of discounted future net cash flows ......... $ 172,916 $ 39,748 $ 212,664
============= ============= =============
2000
Future cash inflows .............................................. $ 1,139,404 $ - $ 1,139,404
Future operating expenses ........................................ (70,719) - (70,719)
Future development costs ......................................... (137,453) - (137,453)
------------- ------------- -------------
Future net cash flows ............................................ 931,232 - 931,232
Future income taxes .............................................. (285,587) - (285,587)
------------- ------------- -------------
Future net cash flows, after income taxes ........................ 645,645 - 645,645
10% annual discount per annum .................................... (121,164) - (121,164)
------------- ------------- -------------
Standardized measure of discounted future net cash flows ......... $ 524,481 $ - $ 524,481
============= ============= =============
Future cash inflows are computed by applying year-end prices of oil and gas
to the year-end estimated future production of proved oil and gas reserves. The
base prices used for the Pretax PV-10 calculation were public market prices on
December 31 adjusted by differentials to those market prices. These price
adjustments were done on a property-by-property basis for the quality of the oil
and natural gas and for transportation to the appropriate location. The Henry
Hub and West Texas Intermediate prices, before adjustment for quality and
transportation, utilized in the PV-10 value at December 31, 2002 were $4.74 per
MMBtu of natural gas and $31.23 per barrel of oil. The National Balancing Point
(the U.K. natural gas benchmark), before adjustment for quality and
transportation, utilized in the PV-10 value at December 31, 2002 was $2.20 per
MMBtu of natural gas. Estimates of future development and production costs are
based on year-end costs and assume continuation of existing economic conditions
and year-end prices. We will incur significant capital in the development of our
Gulf of Mexico and North Sea oil and gas properties. We believe with reasonable
certainty that we will be able to obtain such capital in the normal course of
business. The estimated future net cash flows are then discounted using a rate
of 10 percent per year to reflect the estimated timing of the future cash flows.
The standardized measure of discounted cash flows is the future net cash flows
less the computed discount.
F-27
ATP OIL & GAS CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
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):
Gulf of
Mexico North Sea Total
-------------- ------------ ------------
2002
Beginning of year................................................. $ 172,916 $ 39,748 $ 212,664
------------- ------------- -------------
Sales of oil and gas, net of production costs.................. (72,658) - (72,658)
Net changes in income taxes.................................... (68,837) 24,007 (44,830)
Net changes in price and production costs...................... 192,111 (30,166) 161,945
Revisions of quantity estimates................................ 13,666 10,893 24,559
Accretion of discount.......................................... 20,001 6,427 26,428
Development costs incurred..................................... 13,163 14,413 27,576
Changes in estimated future development costs.................. (23,508) (10,670) (34,178)
Purchases of minerals-in-place................................. 8,252 662 8,914
Sales of minerals-in-place..................................... - (13,664) (13,664)
Changes in production rates, timing and other................... (7,402) (30,461) (37,863)
------------- ------------- -------------
74,788 (28,559) 46,229
------------- ------------- -------------
End of year ...................................................... $ 247,704 $ 11,189 $ 258,893
============= ============= =============
2001
Beginning of year ................................................ $ 524,481 $ - $ 524,481
------------- ------------- -------------
Sales of oil and gas, net of production costs ................. (90,951) - (90,591)
Net changes in income taxes ................................... 193,247 (24,517) 168,730
Net changes in price and production costs ..................... (593,914) - (593,914)
Revisions of quantity estimates ............................... (11,220) - (11,220)
Accretion of discount ......................................... 74,483 - 74,483
Development costs incurred .................................... 57,119 - 57,119
Changes in estimated future development costs ................. 22,413 - 22,413
Purchases of minerals-in-place ................................ 64,322 64,265 128,587
Changes in production rates, timing and other ................. (67,064) - (67,064)
------------- ------------- -------------
(351,565) 39,748 (311,817)
------------- ------------- -------------
End of year ...................................................... $ 172,916 $ 39,748 $ 212,664
============= ============= =============
2000
Beginning of year ................................................ $ 128,706 $ - $ 128,706
------------- ------------- -------------
Sales of oil and gas, net of production costs ................. (64,381) - (64,381)
Net changes in income taxes ................................... (193,613) - (193,613)
Net changes in price and production costs ..................... 416,738 - 416,738
Revisions of quantity estimates ............................... (147,777) - (147,777)
Accretion of discount ......................................... 15,632 - 15,632
Development costs incurred .................................... 18,134 - 18,134
Changes in estimated future development costs ................. (14,709) - (14,709)
Purchases of minerals-in-place ................................ 300,706 - 300,706
Sales of minerals-in-place .................................... (525) - (525)
Extensions and discoveries .................................... 51,795 - 51,795
Changes in production rates, timing and other ................. 13,775 - 13,775
------------- ------------- -------------
395,775 - 395,775
------------- ------------- -------------
End of year ...................................................... $ 524,481 $ - $ 524,481
============= ============= =============
F-28
ATP OIL & GAS CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Capitalized Costs Related to Oil and Gas Producing Activities
The following table summarizes capitalized costs related to our oil and gas
operations (in thousands):
Gulf of
Mexico North Sea Total
------- --------- -----
2002
Oil and gas properties:
Unproved $ 959 $ - $ 959
Proved 333,082 21,047 354,129
Accumulated depletion, impairment and amortization (236,052) - (236,052)
------------- ------------- -------------
$ 97,989 $ 21,047 $ 119,036
============= ============= =============
2001
Oil and gas properties:
Proved $ 315,287 $ 4,219 $ 319,506
Accumulated depletion, impairment and amortization (186,473) - (186,473)
------------- ------------- -------------
$ 128,814 $ 4,219 $ 133,033
============= ============= =============
F-29
CERTIFICATIONS
I, T. Paul Bulmahn, certify that:
1. I have reviewed this annual report on Form 10-K of ATP Oil & Gas Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 31, 2003 By: /s/ T. Paul Bulmahn
-------------------------------------
T. Paul Bulmahn
President and Chief Executive Officer
F-30
I, Albert L. Reese, Jr., certify that:
1. I have reviewed this annual report on Form 10-K of ATP Oil & Gas Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 31, 2003 By: /s/ Albert L. Reese, Jr.
--------------------------------
Albert L. Reese, Jr.
Senior Vice President and Chief
Financial Officer
F-31