Back to GetFilings.com
==============================================================================
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, 2001 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 NASDAQ
value $.001 per share
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.
On March 21, 2002, there were 20,312,648 shares of the Registrant's Common
Stock outstanding. The aggregate value of the Common Stock held by
non-affiliates of the Registrant (treating all executive officers and directors
of the registrant, for this purpose, as if they are affiliates of the
Registrant) was approximately $29,020,963 on March 21, 2002 (based on $4.80 per
share, the last sale price of the Common Stock as reported on the NASDAQ
National Market System on such date).
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.
===============================================================================
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
2001 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............. 18
Part II..................................................................... 20
Item 5. Market for Registrants Common Units and Related
Security Holder Matters......................................... 20
Item 6. Selected Financial Data......................................... 21
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations....................................... 23
Item 7a. Quantitative and Qualitative Disclosures about Market Risk...... 40
Item 8. Financial Statements and Supplementary Data..................... 41
Item 9. Disagreements on Accounting and Financial Disclosure............ 41
Part III.................................................................... 42
Item 10. Directors and Executive Officers of Registrant ................. 42
Item 11. Executive Compensation.......................................... 42
Item 12. Security Ownership of Certain Beneficial Owners and Management.. 42
Item 13. Certain Relationships and Related Transactions.................. 42
Part IV..................................................................... 43
Item 14. Exhibits, Financial Statement
Schedules and Reports on Form 8-K............................. 43
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;
. statements about pending or recent acquisitions, including the
anticipated closing dates;
. expectations regarding our planned expansions and the availability of
acquisition opportunities;
. statements about the expected drilling of wells and other planned
development activities;
. expectations regarding natural gas and oil markets in the United States
and the United Kingdom; and
. timing and amount of future production of natural gas and oil.
When used in this document, the words "anticipate," "estimate," "project,"
"forecast," "may," "should," and "expect" reflect forward-looking statements.
There can be no assurance that actual results will not differ materially
from those expressed or implied in such forward looking statements. Some of the
key factors which could cause actual results to vary from those expected
include:
. the timing and extent of changes in natural gas and oil prices;
. the timing of planned capital expenditures and availability of
acquisitions;
. the inherent uncertainties in estimating proved reserves and
forecasting production results;
. operational factors affecting the commencement or maintenance of
producing wells, including catastrophic weather related damage,
unscheduled outages or repairs, or unanticipated changes in drilling
equipment costs or rig availability;
. the condition of the capital markets generally, which will be
affected by interest rates, foreign currency fluctuations and general
economic conditions;
. cost and other effects of legal and administrative proceedings,
settlements, investigations and claims, including environmental
liabilities which may not be covered by indemnity or insurance; and
. other 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
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
U.S. United States
U.K. United Kingdom
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 assigns the working interest or a portion thereof to
another party who desires to drill on the leased 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.
Pre-tax 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 costs, using prices and costs in effect as of a
certain date, without escalation and without giving effect to non-property
related expenses, such as general and administrative expenses, debt service,
future income tax expense, or depreciation, depletion, and amortization.
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.
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.
4
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.
Shallow-deep waters are the waters in the Gulf of Mexico located between
the continental shelf and water depths of up to approximately 3,000 feet.
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 outer continental shelf of the Gulf of Mexico, in the
shallow-deep waters of the Gulf of Mexico and in the Southern Gas Basin of the
North Sea. We primarily focus our efforts on natural gas and oil properties
with proved undeveloped reserves that are economically attractive to us but are
not strategic to major or exploration-oriented independent oil and gas
companies. We attempt to achieve a high return on our investment in these
properties by limiting our up-front acquisition costs and by developing our
acquisitions quickly. Our management team has extensive engineering,
geological, geophysical, technical and operational expertise in successfully
developing and operating properties in both our current and planned areas of
operation.
At December 31, 2001, we had estimated net proved reserves of 235.0 Bcfe,
an increase of 87% over the previous year-end, of which approximately 154.4 Bcfe
(66%) was in the Gulf of Mexico and 80.6 Bcf (34%) was in the U.K. North Sea.
Year-end reserves were comprised of 194.5 Bcf of natural gas and 6.8 MMBbls of
oil. All of our oil reserves are located in the Gulf of Mexico and
approximately 59% of our natural gas reserves are located in the Gulf of Mexico
with the balance in the U.K. North Sea. The estimated pre-tax PV-10 of our
reserves at December 31, 2001 was $264.3 million. Prices used in the U.S.
reserve estimates were $2.65 per MMBtu of natural gas and $19.78 per barrel of
oil with $3.88 per MMBtu of natural gas for the U.K reserve estimates. At
December 31, 2001, natural gas accounted for 83% of our reserves, proved
developed reserves comprised 32% of our total reserves and our reserve life
index for total proved reserves was 9.1 years. At December 31, 2001, we had
leasehold and other interests in 52 offshore blocks, 27 platforms and 74 wells,
including seven subsea wells, in the federal waters of the Gulf of Mexico. We
operate 56 of these 74 wells, including all of the subsea wells, and 67% of our
offshore platforms. We also had interests in five foreign blocks in the U.K.
sector of the North Sea. Our average working interest in our properties at
December 31, 2001 was approximately 82%.
We produced approximately 25.7 Bcfe in 2001, an increase of 5% over the
previous year. For the five-year period since 1997, we have increased our
annual production at a compounded annual growth rate of 74%. We increase our
reserves and production exclusively through the acquisition and development of
proved natural gas and oil properties. During 2001, we replaced 527% of 2001
production through our reserve replacement activities.
OUR BUSINESS STRATEGY
Our business strategy is to enhance shareholder value primarily through
the acquisition, development and production of proved undeveloped natural gas
and oil reserves in areas that have:
. a substantial existing infrastructure of oil and natural gas pipelines
and production/processing platforms;
. geographic proximity to well-developed markets for natural gas and oil;
. a large number of properties that major oil companies,
exploration-oriented independents and others consider
non-strategic; and
. a relatively stable history of consistently applied governmental
regulations for offshore natural gas and oil development and
production.
6
We believe our strategy significantly reduces the risks associated with
traditional natural gas and oil exploration. Unlike oil and gas companies that
conduct exploration activities, our focus is to acquire properties that have
been previously explored by others and found to contain proved reserves. During
the life span of these properties, they may become non-core or non-strategic to
their original owners. Reasons that a property may become non-core or
non-strategic are varied. For example, companies may elect to concentrate their
efforts elsewhere, to reduce their capital spending for development, or to
pursue exploration projects as opposed to development projects. Also, a lease
expiration date may be approaching and the owner may be unwilling to complete a
development program. Companies pursuing exploration success may discover
hydrocarbons which may not provide an acceptable economic return for them but
which may prove attractive to us as we do not have the time or expense they do
in the project. If such a project is economically attractive to us and is in
our core areas, we will attempt to acquire the project. Each natural gas and
oil discovery by another company in our core areas is a potential opportunity
for the application of our approach.
We focus on developing projects in the shortest time possible between
initial investment and first revenue generated in order to maximize our rate of
return. Since we usually operate the properties in which we acquire a working
interest and begin a development program with proved reserves, we are able to
expeditiously commence a project's development. We typically initiate new
development projects by simultaneously obtaining the various required
components such as the pipeline and the production platform or subsea well
completion equipment. This strategy, combined with our ability to rapidly
evaluate and implement a project's requirements, allows us to complete the
development project and commence production as quickly and efficiently as
possible.
OUR STRENGTHS
. Operating 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, 2001,
we operated 67% of our offshore platforms, 100% of our subsea wells and
100% of our properties under development.
. Low Cost Structure. We believe that our focus on a low cost structure
with minimal cash investment for acquisitions 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, 2001, our total average cost incurred for finding and
developing our net proved reserves was $0.96 per Mcfe.
. Technical Expertise and Significant Experience. We have assembled a
technical staff with an average of 19 years of industry experience. Our
technical staff has specific expertise in offshore property
development, including the implementation of subsea completion
technology.
. Employee Ownership. Through employee ownership, we have built a staff
whose business decisions are aligned with our shareholders. Our
employees own 70% of ATP on a fully diluted basis.
. Operating Efficiency. We emphasize a low overhead and operating expense
structure. For 2001, our lease operating expense was $0.58 per Mcfe of
production and our general and administrative expense was $0.39 per
Mcfe of production.
INITIAL PUBLIC OFFERING
On February 5, 2001, we successfully completed an initial public offering
("IPO") of 6.0 million shares of common stock and commenced trading the
following day. After payment of the underwriting discount we received net
proceeds of $78.3 million on February 9, 2001. We used the net proceeds from
the IPO, together with the proceeds from a new credit facility, to repay all
outstanding debt under a development program credit agreement and a prior bank
credit facility and to acquire and develop additional natural gas and oil
reserves.
7
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 and our revenues, profitability and cash flow. Although we
are not currently experiencing any significant involuntary curtailment of our
natural gas or oil production, market, economic and regulatory factors may in
the future materially affect our ability to sell our natural gas or oil
production.
We sell a portion of our natural gas and oil to end users through various
gas marketing companies. We are not dependent upon, or confined to, any one
purchaser or small group of purchasers. Due to the nature of natural gas and
oil markets and because natural gas and oil are commodities and there are
numerous purchasers in the areas in which we sell production, we do not believe
the loss of a single purchaser, or a few purchasers, would materially affect
our ability to sell our production.
COMPETITION
We compete with major and independent natural gas and oil companies for
property acquisitions. We also compete for the equipment and labor required to
operate and to develop these properties. Some of our competitors have
substantially greater financial and other resources and may be able to sustain
wide fluctuations in the economics of our industry easier 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 easier than we can.
Our ability to acquire and develop additional properties in the future will
depend upon our ability to conduct operations, to evaluate and select suitable
properties and to consummate transactions in this highly competitive
environment.
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 February 2000, the FERC issued Order No. 637 which:
. lifts the cost-based cap on pipeline transportation rates in the
capacity release market until September 30, 2002, for short-term
releases of pipeline capacity of less than one year;
. permits pipelines to file for authority to charge different maximum
cost-based rates for peak and off-peak periods;
. encourages, but does not mandate, auctions for pipeline capacity;
. requires pipelines to implement imbalance management services;
. restricts the ability of pipelines to impose penalties for imbalances,
overruns and non-compliance with operational flow orders; and
. implements a number of new pipeline reporting requirements.
Order No. 637 also requested that the FERC staff analyze whether the FERC
should implement additional fundamental policy changes. These include whether
to pursue performance-based or other non-cost based ratemaking techniques and
whether the FERC should mandate greater standardization in terms and conditions
of service across the interstate pipeline grid. Appeals of Order No. 637
remain pending.
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, 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; it is unclear whether this court order will be appealed.
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.
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.
9
Federal Leases. A substantial portion of our operations is located on
federal natural gas and oil leases, which are administered by the Minerals
Management Service ("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 met.
The cost of these bonds or assurances can be substantial, and there is no
assurance that they can be obtained in all cases. We currently have several
supplemental bonds in place. Under some circumstances, the 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. These regulations
are amended from time to time, and the amendments can affect the amount of
royalties that we are obligated to pay to the MMS. However, we do not believe
that these regulations or any future amendments will affect us in a way that
materially differs from the way it affects other oil and gas producers, gathers
and marketers.
Oil Price Controls and Transportation Rates. Sales of crude oil,
condensate and natural gas liquids by us are not currently regulated and are
made at market prices. In a number of instances, however, the ability to
transport and sell such products is dependent on pipelines whose rates, terms
and conditions of service are subject to 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, pipeline
rates are subject to an indexing methodology. Under this indexing methodology,
pipeline rates are subject to changes in the Producer Price Index for Finished
Goods, minus one percent. A pipeline can seek to increase its rates above index
levels provided that the pipeline can establish that there is a substantial
divergence between the actual costs experienced by the pipeline and the rate
resulting from application of the index. A pipeline can seek to charge
market-based rates if it establishes that it lacks significant market power. In
addition, a pipeline can establish rates pursuant to settlement if agreed upon
by all current shippers. A pipeline can seek to establish initial rates for new
services through a cost-of-service proceeding, a market-based rate proceeding,
or through an agreement between the pipeline and at least one shipper not
affiliated with the pipeline. 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
10
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.
Appeals of the FERC's December 2000 order are pending.
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 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.
11
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 could become
subject to similar state and local water quality laws and regulations in the
future if we conduct production or drilling activities in state coastal waters.
Failure to comply with the ongoing requirements of the Clean Water Act or
inadequate cooperation during a spill event may subject a responsible party to
civil or criminal enforcement actions.
The Comprehensive Environmental Response, Compensation, and Liability Act,
or CERCLA, also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on some classes of persons
that are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances
released into the environment. We could be subject to liability under CERCLA
because our drilling and production activities generate relatively small
amounts of liquid and solid wastes that may be subject to classification as
hazardous substances under CERCLA. These wastes must be brought to shore for
proper disposal under the Resource Conservation and Recovery Act. We minimize
this potential liability by selecting reputable contractors to dispose of our
wastes at government-approved landfills or other types of disposal facilities.
Our operations are also subject to regulation of air emissions under the
Clean Air Act and the Outer Continental Shelf Lands Act. Implementation of
these laws could lead to the gradual imposition of new air pollution control
requirements on our operations. Therefore, we may incur capital expenditures
over the next several years to upgrade our air pollution control equipment. We
could also become subject to similar state and local air quality laws and
regulations in the future if we conduct production or drilling activities
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 natural gas and oil development and production activities.
In addition, legislation has been proposed in Congress from time to time
that would reclassify some natural gas and oil exploration and production
wastes as "hazardous wastes," which would make the reclassified wastes subject
to much more stringent handling, disposal and clean-up requirements. If
Congress were to enact this legislation, it could increase our operating costs,
as well as those of the natural gas and oil industry in general. Initiatives to
further regulate the disposal of natural gas and oil wastes are also pending in
some states, and these various initiatives could have a similar impact on us.
Our management believes that we are in substantial compliance with current
applicable environmental laws and regulations and that continued compliance
with existing requirements will not have a material adverse impact on us.
U.K. Regulations of Natural Gas and Oil Production. Pursuant to the
Petroleum Act 1998, all natural gas and oil reserves contained in properties
located in Great Britain are the property of the U.K. government. The
development and production of natural gas and oil reserves in the U.K. North
Sea requires a petroleum production license granted by the U.K. government.
Prior to developing a field, we are required to obtain from the Secretary of
State for Trade and Industry a consent to develop that field. We would be
required to obtain the consent of the Secretary of State for Trade and Industry
in the event we transfer an interest in a license.
12
The terms of the petroleum production licenses are based on model license
clauses applicable at the time of the issuance of the license. Licenses
frequently contain regulatory provisions governing matters such as working
method, pollution and training, and reserve to the Secretary of State for Trade
and Industry the power to direct some of the licensee's activities. For
example, a licensee may be precluded from carrying out development or
production activities other than with the consent of the Secretary of State for
Trade and Industry or in accordance with a development plan which the Secretary
of State for Trade and Industry has approved. Breach of these requirements may
result in the revocation of the license. In addition, licenses that we acquire
may require us to pay fees and royalties on production and also impose certain
other duties on us.
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. Parliament.
Petroleum production licenses require the approval of the Secretary of
State for Trade and Industry of a licensee to act as operator and who organizes
or supervises all or any of the development and production operations of
natural gas and oil properties subject thereto. As an operator, we may obtain
operational services from third parties, but 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.
EMPLOYEES
At December 31, 2001 we had 39 full-time employees in our Houston office
and six 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.
13
ITEM 2. PROPERTIES
GENERAL
Since inception we have engaged in the acquisition, development and
production of natural gas and oil properties primarily in the outer continental
shelf of the Gulf of Mexico. In 2000 we expanded our business to include the
acquisition and development of properties in the shallow-deep waters of the
Gulf of Mexico and in the Southern Gas Basin of the North Sea. At December 31,
2001, we had leasehold and other interests in 52 offshore blocks, 27 platforms
and 74 wells, including seven subsea wells, in the federal waters of the Gulf
of Mexico. We operate 56 of these 74 wells, including all of the subsea wells,
and 67% of our offshore platforms. We also held interests in five foreign
blocks located in the U.K. sector of the North Sea. Our average working
interest in our properties at December 31, 2001 was approximately 82%. As of
December 31, 2001, we had leasehold interests located in the Gulf of Mexico and
the U.K. covering approximately 246,000 gross and 196,000 net acres.
ACQUISITIONS
Gulf of Mexico
During 2001, we acquired interests in 15 lease blocks covering 14
properties in six separate transactions. Total reserves associated with these
transactions were approximately 60.6 Bcfe, based on third party reservoir
engineering estimates at year-end, for total acquisition costs of approximately
$22.7 million. Our working interests in these properties range from 25% to
100%. Ten of these properties produced in 2001 with additional development and
production planned on the remaining four in 2002 and beyond.
During 2000 we acquired an interest in 11 lease blocks covering nine
separate properties for total acquisition costs of $7.5 million. Net proved
reserves associated with these acquisitions were approximately 66.0 Bcfe based
on third party reservoir engineering estimates. Our working interests in these
properties range from 50% to 100%. We are the operator of all of the properties.
Included in these acquisitions were four blocks on three separate properties
which represent our first acquisitions in the shallow-deep waters of the Gulf of
Mexico. Of these nine properties, five were producing in 2001, including
"Ladybug", one of the properties in the shallow-deep waters of the Gulf of
Mexico, and a sixth property commenced production in the first quarter of 2002.
Two of the properties are scheduled for future development in 2002 and beyond
and the remaining property was abandoned without commencing production in 2001.
Southern Gas Basin of the North Sea
In October 2000, we entered into a letter of intent to acquire interests in
three properties (five blocks) in the Southern Gas Basin of the North Sea which
included a 50% interest in one block, a 100% interest in one block and an 86%
interest in three blocks. In 2001, we acquired all three properties for total
acquisition costs of approximately $3.1 million. At December 31, 2001, net
proved reserves were approximately 80.6 Bcfe, based on third party reservoir
engineering estimates at year-end. None of the properties were producing when
acquired and we expect to pursue development operations in 2002 through 2004.
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, 2001 based
on reserve reports prepared by Ryder Scott Company, L.P. for our domestic
reserves and Troy-Ikoda Limited for our U.K. reserves.
14
The present value of future net cash flows before income taxes as of
December 31, 2001 was determined by using the December 31, 2001 prices of $2.65
per MMBtu and $3.88 per MMBtu of natural gas for the U.S. and U.K,
respectively, and $19.78 per Bbl of oil for the U.S. The present values,
discounted at 10% per annum, of estimated future net cash flows before income
taxes shown in the table are not intended to represent the current market value
of the estimated natural gas and oil reserves we own.
Proved Reserves
-------------------------------------
Developed Undeveloped Total
----------- ----------- -----------
Domestic
Natural gas (MMcf).................. 56,704 57,176 113,880
Oil and condensate (MBbls).......... 3,115 3,638 6,753
Total proved reserves (MMcfe)....... 75,394 79,004 154,398
Pre-tax PV-10 (in thousands)........ $ 133,500 $ 66,513 $ 200,013
U.K.
Natural gas (MMcf).................. - 80,629 80,629
Pre-tax PV-10 (in thousands)........ $ - $ 64,265 $ 64,265
Total
Natural gas (MMcf).................. 56,704 137,805 194,509
Oil and condensate (MBbls).......... 3,115 3,638 6,753
Total proved reserves (MMcfe)....... 75,394 159,633 235,027
Pre-tax PV-10 (in thousands)........ $ 133,500 $ 130,778 $ 264,278
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, 2001, all of our reserves in the U.K. and approximately 51% 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.
15
The following table highlights our history of bringing our offshore blocks
with proved undeveloped reserves to production:
2001 2000 1999
------------------------ ------------------------ -------------------------
Undeveloped Developed Undeveloped Developed Undeveloped Developed
----------- ---------- ----------- ----------- ----------- ----------
At January 1........................ 10 30 7 24 11 22
Acquisitions........................ 11(1) 9 10 1 7 1
Divestitures and expirations........ (1) (8) - (2) (9)(2) (1)
Undeveloped to productive........... (4) 4 (7) 7 (2) 2
Undeveloped to nonproductive........ (1) - - - - -
----------- ----------- ----------- ----------- ----------- -----------
At December 31...................... 15 35 10 30 7 24
=========== =========== =========== =========== =========== ===========
_______________________
(1) Includes interests in five blocks in the Southern Gas Basin of the
North Sea.
(2) These were undeveloped exploration blocks that we sold. We retained a
future net profits interest in seven of those blocks.
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,
----------------------------------------------------------------
2001 2000 1999
-------------------- -------------------- --------------------
Gross Net Gross Net Gross Net
--------- --------- --------- --------- --------- ---------
Development Wells:
Productive................................... 8.0 6.3 12.0 11.0 3.0 2.2
Nonproductive................................ 1.0 1.0 1.0 1.0 - -
--------- --------- --------- --------- --------- ---------
Total..................................... 9.0 7.3 13.0 12.0 3.0 2.2
========= ========= ========= ======== ========= =========
As of December 31, 2001, there were no wells in the process of drilling or
completing.
PRODUCTIVE WELLS
The following table presents the number of domestic productive natural gas
and oil wells in which we owned an interest as of December 31, 2001.
Total Productive Wells(1)
-----------------------------
Gross Net
------------- -------------
Natural gas............................... 38.0 30.4
Oil .................................... 9.0 4.4
------------- -------------
Total.................................. 47.0 34.8
============= =============
(1) Includes eight gross and 6.8 net wells with multiple completions.
We had no productive wells in the U.K. at December 31, 2001.
16
ACREAGE
The following table summarizes our domestic and foreign developed and
undeveloped acreage holdings at December 31, 2001. 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
--------- --------- --------- --------- --------- ---------
Domestic:
Gulf of Mexico - Shelf....................... 157,128 122,979 17,500 16,250 174,628 139,229
Gulf of Mexico - Shallow-Deep Waters......... 5,760 2,880 15,189 15,189 20,949 18,069
--------- -------- -------- --------- --------- --------
162,888 125,859 32,689 31,439 195,577 157,298
--------- -------- -------- --------- --------- --------
Foreign:
Southern Gas Basin of the North Sea.......... - - 50,234 39,034 50,234 39,034
--------- -------- -------- --------- --------- --------
162,888 125,859 82,923 70,473 245,811 196,332
========= ======== ======== ========= ========= =======
________________
(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 litigation is in its very early stages
with written discovery propounded by ATP, but no answers received, and no
depositions taken. The judge has abated the litigation, until arbitration
pursuant to the underlying agreements between the sellers and ATP is completed.
Since the legal proceedings have just begun, and a prediction of the outcome
would be premature and uncertain, we have not accrued any amount related to
this matter. And while we are seeking recovery of the amounts previously paid
and discussed above, the $3.0 million has been charged to earnings along with
certain other costs related to this matter. ATP intends to vigorously defend
against the sellers' claims and forcefully pursue its own claims in this matter.
17
In August 2001, Burlington Resources Inc. filed suit against us alleging
formation of a contract with us 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, 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 2001.
EXECUTIVE OFFICERS OF THE COMPANY
Set forth below are the names, ages (as of March 21, 2002) 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........................ 58 Chairman, President and Director
Gerald W. Schlief...................... 54 Senior Vice President
Albert L. Reese, Jr.................... 52 Senior Vice President and Chief Financial Officer
Leland E. Tate......................... 54 Senior Vice President, Operations
John E. Tschirhart..................... 51 Senior Vice President, General Counsel
Carol E. Overbey....................... 50 Vice President, Corporate Secretary and Director
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.
18
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. 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.
Carol E. Overbey has served as a director and our Corporate Secretary
since 1991 and has served as Vice President since August 2000. Ms. Overbey
served as our Treasurer from 1991 to 1999. From 1985 to 1991, Ms. Overbey was
Vice President/Controller of Continuity Corporation.
19
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 20,312,648 shares of common stock and no
shares of preferred stock outstanding as of March 21, 2002. There were 24
holders of record of our common stock as of March 21, 2002. 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
------------ ------------
2001:
- -----
1st Quarter $ 14.5625 $ 9.8750
2nd Quarter 12.9600 8.7100
3rd Quarter 12.0000 6.6100
4th Quarter 7.1500 2.0000
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.
20
ITEM 6. SELECTED FINANCIAL DATA
(in thousands, except per share data and percentages)
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,
---------------------------------------------------------------
2001 2000 1999 1998 1997
----------- ----------- ----------- ----------- -----------
Statement of Operations Data:
Revenues:
Oil and gas production...................... $ 105,757 $ 75,940 $ 34,981 $ 20,410 $ 7,359
Gas sold - marketing........................ 7,417 8,015 7,703 - -
Gain on sale of oil and gas properties...... - 33 287 - 304
----------- ----------- ----------- ----------- -----------
Total revenues............................ 113,174 83,988 42,971 20,410 7,663
----------- ----------- ----------- ----------- -----------
Cost and operating expenses:
Lease operating............................. 14,806 11,559 5,587 3,193 1,513
Gas purchased - marketing................... 7,218 7,788 7,402 - -
Geological and geophysical expenses......... 1,068 - - - -
General and administrative.................. 9,981 5,409 3,541 2,591 1,170
Non-cash compensation expense............... 3,364 - - - -
Depreciation, depletion and amortization.... 53,428 40,569 22,521 17,442 4,206
Impairment of oil and gas properties........ 24,891 10,838 7,509 5,072 5,787
Loss on unsuccessful property acquisition... 3,147 - - - -
Other expense............................... - 450 - - -
---------- ----------- ----------- ----------- -----------
Total operating expenses.................... 117,903 76,613 46,560 28,298 12,676
---------- ----------- ----------- ----------- -----------
Income (loss) from operations................. (4,729) 7,375 (3,589) (7,888) (5,013)
Other income (expense):
Interest income............................. 884 451 202 141 207
Interest expense............................ (10,039) (11,907) (9,399) (7,963) (1,212)
Realized loss on derivative instruments..... (19,348) (4,662) - - -
Unrealized gain (loss) on derivative instruments 1,265 (7,249) - - -
---------- ---------- ---------- ---------- -----------
Loss before income taxes and
extraordinary gain (loss) .................. (31,967) (15,992) (12,786) (15,710) (6,018)
Income tax benefit............................ 11,186 5,594 1,829 - -
---------- ---------- ---------- ---------- -----------
Loss before extraordinary gain (loss)......... (20,781) (10,398) (10,957) (15,710) (6,018)
Extraordinary gain (loss), net of tax......... (602) - 29,185 - -
---------- ---------- ---------- ---------- -----------
Net income (loss)............................. $ (21,383) $ (10,398) $ 18,228 $ (15,710) $ (6,018)
========== ========== ========== ========== ===========
Weighted average number of
common shares outstanding:
Basic and diluted......................... 19,704 14,286 14,286 11,926 10,568
Loss per common share
before extraordinary gain (loss):
Basic and diluted......................... $ (1.06) $ (0.73) $ (0.77) $ (1.32) $ (0.57)
Net income (loss) per common share:
Basic and diluted......................... $ (1.09) $ (0.73) $ 1.28 $ (1.32) $ (0.57)
Table and footnotes continued on following page
21
Years Ended December 31,
---------------------------------------------------------------
2001 2000 1999 1998 1997
----------- ----------- ----------- ----------- -----------
Other Financial Data:
Adjusted EBITDA(1)............................. $ 58,490 $ 54,570 $ 26,643 $ 14,767 $ 5,187
Adjusted EBITDA margin(2)...................... 62% 65% 62% 72% 68%
As of December 31,
---------------------------------------------------------------
2001 2000 1999 1998 1997
----------- ----------- ----------- ----------- -----------
Balance Sheet Data:
Cash and cash equivalents...................... $ 5,294 $ 18,136 $ 17,779 $ 3,411 $ 1,806
Working capital................................ (29,071) (3,835) 14,115 (5,106) 3,340
Net oil and gas properties..................... 133,033 98,725 72,278 47,612 33,355
Total assets................................... 177,564 161,993 107,054 61,354 48,906
Total debt..................................... 100,111 116,529 91,723 62,690 42,194
Total liabilities.............................. 132,572 175,172 109,835 82,363 54,217
Shareholders' equity (deficit)................. 44,992 (13,179) (2,781) (21,009) (5,311)
_________________
(1) Adjusted EBITDA means net income (loss) before interest expense, income
taxes, depreciation, depletion and amortization, impairment of natural
gas and oil properties, non-cash compensation expense, unrealized gains
and losses and extraordinary items. Adjusted EBITDA is not a calculation
based on generally accepted accounting principles and should not be
considered as an alternative to net income (loss) or operating income
(loss), as an indicator of a company's financial performance or to cash
flow as a measure of liquidity. In addition, our Adjusted EBITDA
calculation may not be comparable to other similarly titled measures of
other companies. Adjusted EBITDA is included as a supplemental
disclosure because it may provide useful information regarding our
ability to service debt and to fund capital expenditures.
(2) Represents Adjusted EBITDA divided by total revenues for the years ended
December 31, 1997 through 2000. For the year ended December 31, 2001,
Adjusted EBITDA margin is Adjusted EBITDA divided by the sum of total
revenues and realized loss on derivative instruments.
22
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 outer continental shelf of the Gulf of Mexico, in
the shallow-deep waters of the Gulf of Mexico and in the Southern Gas Basin of
the 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.
INITIAL PUBLIC OFFERING
On February 5, 2001, we priced our IPO of 6.0 million shares of common
stock and commenced trading the following day. After payment of the underwriting
discount we received net proceeds of $78.3 million on February 9, 2001,
excluding offering costs of approximately $1.5 million. We used the net proceeds
from our IPO, together with the proceeds from our new credit facility, to repay
all of our outstanding debt under our development program credit agreement and
our prior bank credit facility and to acquire natural gas and oil properties.
CRITICAL ACCOUNTING POLICIES
Financial Reporting Release No. 60, which was recently released by the SEC,
recommends that all companies include a discussion of critical accounting
policies or methods used in the preparation of financial statements. Note 2 of
the Notes to Consolidated Financial Statements includes a summary of the
significant accounting policies and methods used in the preparation of our
Consolidated Financial Statements. The following is a brief discussion of the
more significant accounting policies and methods used by us.
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 for reserve data in our Consolidated
Financial Statements.
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 are incurred for development
purposes only. These costs are generally charged to expense unless the costs can
be specifically attributed to determining the placement for a future 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.
We perform an impairment analysis whenever events or changes in
circumstances indicate that our estimate of a particular asset's fair value, or
carrying amount, may not be recoverable. 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 published 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 properties determined to be impaired, an impairment
loss equal to the differences between the carrying value and the fair value of
the impaired property will be recognized. Fair value, on a depletable unit
basis, is estimated to be the present value of 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.
23
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.
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
Prior to the January 1, 2001 adoption of Financial Accounting Standards
Board ("FASB") Statement of Financial Accounting Standard ("SFAS") No. 133,
Accounting for Derivative Instruments and Hedging Activities ("SFAS 133") and
SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities ("SFAS 138"), an amendment to SFAS 133, we included the effects of
our risk management activities as an offset to revenue. Upon adoption of the
standard, any gains or losses from these activities are now included in other
income (expense), as we did not account for our hedging activities under the
hedge accounting provisions allowed in the standard.
For comparative purposes though, the following table sets forth selected
financial and operating information for our natural gas and oil operations
inclusive of the effects of risk management activities:
Years Ended December 31,
------------------------------------------------
2001 2000 1999
------------- ------------- -------------
Production:
Natural gas (MMcf).......................................... 20,957 22,410 16,533
Oil and condensate (MBbls).................................. 790 345 128
------------- ------------- -------------
Total (MMcfe)............................................ 25,696 24,477 17,301
============= ============= =============
Revenues (in thousands):
Natural gas................................................. $ 88,908 $ 94,051 $ 36,856
Effects of risk management activities(1).................... (24,369) (26,729) (3,842)
------------- ------------- -------------
Total ................................................... $ 64,539 $ 67,322 $ 33,014
============= ============= =============
Oil and condensate.......................................... $ 16,849 $ 10,112 $ 1,967
Effects of risk management activities....................... - (1,494) -
------------- ------------- -------------
Total ................................................... $ 16,849 $ 8,618 $ 1,967
============= ============= =============
Natural gas, oil and condensate............................. $ 105,757 $ 104,163 $ 38,823
Effects of risk management activities....................... (24,369) (28,223) (3,842)
------------- ------------- -------------
Total ................................................... $ 81,388 $ 75,940 $ 34,981
============= ============= =============
Table and footnote continued on following page
24
Years Ended December 31,
------------------------------------------------
2001 2000 1999
------------- ------------- -------------
Average sales price per unit:
Natural gas (per Mcf).................................... $ 4.24 $ 4.20 $ 2.23
Effects of risk management activities (per Mcf).......... (1.16) (1.19) (0.23)
------------- ------------- -------------
Total (per Mcf).......................................... $ 3.08 $ 3.01 $ 2.00
============= ============= =============
Oil and condensate (per Bbl)............................. $ 21.33 $ 29.35 $ 15.37
Effects of risk management activities (per Mcf).......... - (4.34) -
------------- ------------ -------------
Total (per Bbl).......................................... $ 21.33 $ 25.01 $ 15.37
============= ============ =============
Natural gas, oil and condensate (per Mcfe)............... $ 4.12 $ 4.26 $ 2.24
Effects of risk management activities (per Mcfe)......... (0.95) (1.16) (0.22)
------------- ------------- --------------
Total (per Mcfe)......................................... $ 3.17 $ 3.10 $ 2.02
============= ============= =============
Expenses (per Mcfe):
Lease operating.......................................... $ 0.58 $ 0.47 $ 0.32
General and administrative............................... 0.39 0.22 0.20
Depreciation, depletion and amortization................. 2.08 1.66 1.30
________________
(1) For 2001, represents the net loss on the settlement of derivatives
attributable to actual production.
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. For the year ended December 31, 1999, we reported net income
of $18.2 million or $1.28 per share.
Oil and Gas Revenue. Excluding the effects of risk management activities,
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 $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 of Notes to Consolidated
Financial Statements.
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.
25
Geological and geophysical. In 2001, we recorded $1.1 million of costs
related to the acquisition of 3-D seismic data purchased for development
purposes on certain properties in the Gulf of Mexico and the U.K.
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 approximately $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. The remaining compensation expense to be
recorded over 2002 and 2003 is approximately $0.5 million.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense ("DD&A") 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 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 none and $0.7
million of interest for the years ended December 31, 2001 and 2000,
respectively.
26
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Oil and Gas Revenue. Our revenue from natural gas and oil production for
2000 increased 117% over 1999 from $35.0 million to $75.9 million. This increase
resulted from an increase in realized natural gas prices of 51% and realized oil
prices of 63%, as well as a 41% increase in production. The increase in
production volumes from 17.3 Bcfe to 24.5 Bcfe was attributable to ten
properties that were on production during 2000 that were not on production
during 1999. Hedging transactions reduced oil and natural gas revenues by $28.2
million, or $1.16 per Mcfe, in 2000 and $3.8 million, or $0.22 per Mcfe, in
1999.
Marketing Revenue. Revenues from natural gas marketing activities increased
to $8.0 million in 2000 as compared to $7.7 million in 1999. The reason for the
increase was a decrease in volumes partially offset by an increase in the sales
price per MMBtu. The daily natural gas contract decreased from 9,000 MMBtu per
day in 1999 to 5,000 MMBtu per day in 2000. The average sales price increased
from $2.34 per MMBtu in 1999 to $4.38 per MMBtu in 2000.
Lease Operating Expense. Our lease operating expense for 2000 increased
107% from $5.6 million to $11.6 million. This increase was primarily the result
of an increase in the number of producing wells owned by us, an increase in
their total production volume and an increase in the level of workover activity.
Workover spending increased from $0.4 million in 1999 to $2.6 million in 2000.
The remaining increase in lease operating expense was primarily attributable to
transportation related costs.
Gas Purchased-Marketing. Our cost of purchased gas was $7.8 million for
2000 compared to $7.4 million for 1999. The daily gas contract amount in our
third party marketing arrangement decreased from 9,000 MMBtu per day in 1999 to
5,000 MMBtu per day in 2000. Lower volumes were offset by an increase in the
average gas cost from $2.25 per MMBtu in 1999 to $4.26 per MMBtu in 2000.
General and Administrative Expense. General and administrative expense
increased to $5.4 million for 2000 compared to $3.5 million for 1999. The
primary reason for the increase was the result of compensation and related
expenses increasing from $1.8 million to $3.3 million period to period. Our
total employees increased from 19 at December 31, 1999 to 33 at December 31,
2000.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense increased 80% from $22.5 million in 1999 to $40.6
million in 2000. The average DD&A rate was $1.66 per Mcfe during 2000 compared
to $1.30 per Mcfe during 1999.
Impairment Expense. As of December 31, 2000, the future undiscounted cash
flows for our properties were $931.2 million and the net book value for the
properties was $109.6 million before current year impairment expense. At
December 31, 1999, the future undiscounted cash flows for our properties were
$183.0 and the net book value for the properties was $79.8 million before
current year impairment expense. However, for three of our 33 properties in 2000
and four of our 26 properties in 1999, the future undiscounted cash flows were
less than their individual net book value. As a result, we recorded impairments
of $10.8 million in 2000 and $7.5 million in 1999. The impairments in 2000 and
1999 were primarily the result of a reduction in recoverable reserves
individually attributable to the particular properties.
Other Expense. We recorded a charge of $0.5 million in 2000 relating to the
sale of a platform which was held for sale and included in other assets in 1999.
There was no comparable expense for this account in 1999.
Other Income (Expense). For 2000 we recorded an expense of $4.3 million
($1.7 million realized and $2.6 million unrealized) on a natural gas derivative
position as a result of our hedging position exceeding our expected production
in an upcoming period. In this situation, we are required to account for the
position using the mark-to-market method. In addition, we recorded an expense of
$7.6 million ($3.0 million realized and $4.6 million unrealized) related to
mark-to-market losses associated with our written call option contracts.
27
For 2000, interest expense was $11.9 million compared to $9.4 million for
1999. Our borrowings increased from period to period but were offset by a
decrease in interest rates under our new development program credit agreement.
We capitalized $0.7 million and $0.6 million of interest for the years ended
December 31, 2000 and 1999, respectively.
Extraordinary Gain. In June 1999, we agreed with the lender under a prior
development program credit agreement to prepay the amount outstanding at a
discount. As a result, we recorded an extraordinary gain of $29.2 million.
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. 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
planned capital requirements during 2002. However, future cash flows are subject
to a number of variables including the level of production and oil and natural
gas prices. 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. 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. A
reduction in the borrowing base or an 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 obligations during 2002. As operator of all of our
projects in development, we have the ability to significantly control the timing
of many of our capital expenditures. In periods of reduced availability of funds
from either cash flows or credit sources we would anticipate delaying planned
capital expenditures, which could negatively impact our future revenues and cash
flows.
Cash Flows
Years Ended December 31,
--------------------------------------------
2001 2000 1999
------------- ------------ -----------
(in thousands)
Cash provided by (used in):
Operating activities................ $ 41,356 $ 57,157 $ 10,707
Investing activities................ (110,810) (76,835) (55,120)
Financing activities................ 56,612 20,035 58,781
Operating activities. Net cash provided by operating activities in 2001 was
$41.4 million compared to $57.2 million in 2000. The decrease in 2001 was
primarily due to an increase in working capital needs in addition to unfavorable
settlements related to price risk derivative contracts. The decrease was
partially offset by higher operating income, excluding non-cash items, as a
result of higher natural gas prices and increased production volumes.
Investing activities. Cash used in investing activities increased in 2001
to $110.8 million. The 2001 amount includes expenditures on oil and gas
properties of $110.3 million, of which $25.9 million was used for the
acquisition of 17 properties in the Gulf of Mexico and Southern Gas Basin area
of the North Sea, $5.6 million was used to purchase the overriding royalty
interests associated with our non-recourse debt and $78.8 million was used for
development. Comparable expenditures for acquisition and development in 2000
were $7.5 million and $69.0 million, respectively.
Financing activities. Cash provided from financing activities includes the
proceeds from our IPO in February 2001 of $78.3 million net of the underwriters'
discount. We also incurred costs of approximately $0.9 million in connection
with the offering, which in addition to costs incurred in the fourth quarter of
2000, totaled approximately $1.5 million. Financing activities included
repayments of $116.5 million of our credit facilities in place at December 31,
2000 and net proceeds of $100.0 million from our new credit facility and
note payable (see "Credit Agreements"). Financing activities in 2000 included
net proceeds of $7.6 million and $13.5 million from our credit facilities and
non-recourse borrowings, respectively.
28
Amounts borrowed under our credit agreements were as follows for the dates
indicated (in thousands):
December 31,
------------------------------
2001 2000
------------- --------------
Credit facility................................................... $ 70,000 $ 27,750
Note payable, net of unamortized discount of $1,139............... 30,111 -
Non-recourse borrowings........................................... - 88,779
------------- --------------
Total debt...................................................... $ 100,111 $ 116,529
============= ==============
Credit Facilities
In March 2001, we repaid our then existing bank credit facility and in
April 2001 we repaid the full amount borrowed under a non-recourse development
program credit agreement which we had used as a source of financing for the
acquisition of oil and gas properties. Concurrent with the repayment of our
non-recourse agreement, we negotiated with the lender to terminate the
overriding royalty interest retained by it on all properties previously financed
by the lender in exchange for a lump-sum payment of approximately $5.6 million.
Upon repayment of our former credit and non-recourse facilities, we entered
into a new $100.0 million senior-secured revolving credit facility in April
2001. This facility is secured by substantially all of our oil and gas
properties, as well as by approximately two-thirds of the capital stock of our
U.K. subsidiary and is guaranteed by our wholly owned subsidiary, ATP Energy,
Inc. As amended, the amount available for borrowing under the facility is
limited to the loan value, as determined by the bank, of oil and gas properties
pledged under the facility. At December 31, 2001, the borrowing base was $70.0
million and the monthly borrowing base reduction was set at $2.0 million a month
beginning February 27, 2002 and remains in effect until there is a change, if
any, at the next redetermination date. The redetermination dates are on or
around the first business day of each calendar quarter at which time the lenders
can increase or decrease the borrowing base and the monthly reduction amount.
The next scheduled redetermination date is on or around the first business day
of April 2002. Our lender has indicated this process will not be completed until
mid to late April of 2002. The $2.0 million monthly reduction included in
current maturities of long-term debt assumes there is no change in the monthly
reduction amount or the borrowing base in 2002. 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%. A reduction in the borrowing base or an 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 during 2002. As of
December 31, 2001, all of our borrowing base under the agreement was
outstanding.
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 amended
credit facility matures in November 2003. Our credit facility contains
conditions and restrictive provisions, among other things, (1) prohibiting 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, and (3) maintaining certain
financial ratios.
29
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 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 have assumed there is no 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 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 during 2002.
As of December 31, 2001, all of our borrowing base under the agreement was
outstanding.
As of December 31, 2001, we were in compliance with all of the financial
covenants of our credit facility and note payable agreements other than our
working capital covenant (as defined by the agreements) for which we have
obtained amendments from our lenders. Both of the amendments require that our
working capital at December 31, 2001 and March 31, 2002 shall not exceed
deficits of $10.0 million and $5.0 million, respectively.
Working Capital
During the second half of 2001 we operated with a working capital deficit.
In compliance with the definition of working capital in our credit facilities
which excludes current maturities of long-term debt and the current portion of
future commodity contracts and other derivatives, we ended the year with a
deficit of approximately $9.0 million, an improvement over our deficits of $37.1
million at June 30, 2001 and $35.1 million at September 30, 2001. The
improvement in our working capital was the result of the November 2001 increase
in the borrowing base of our existing credit facility, the reduction of our
current liabilities through cash flows from operations and the reduction of
expenditures related to the curtailment of current development activity. We
executed this improvement in working capital despite the devastating national
and financial events in the U.S. that occurred during the third and fourth
quarters of 2001. In efforts to preserve cash flow during this period of
negative working capital, we reached agreement with several of our suppliers for
extended payments. In response to lower gas prices received in the fourth
quarter of 2001 and the early part of 2002 and our desire to completely
eliminate our working capital deficit, we have reduced certain previously
planned development activities for 2002. Four projects that can be developed in
2002 have been postponed until 2003.
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, sale of
interests in selected properties and the potential sale and lease back of
certain of our platforms and pipelines. We have also explored the possibility of
the issuance of new debt or equity in both the public and private markets.
Completion of any of these potential financings will expand our capabilities to
further reduce our outstanding indebtedness, increase our working capital and
expand our 2002 development and acquisition program. 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
30
directors. If we are not successful in closing these transactions, our ability
to reduce our debt below projected levels or to develop and produce our oil and
gas properties as desired may be negatively impacted. Other items that could
have a negative impact on our working capital include a significant decrease in
oil or gas prices from expected levels, a redetermination by our lenders of our
borrowing base or our monthly reduction amount in excess of the amounts
forecasted in our cash flow projection, the increase in costs and expenses above
projected levels or any significant payments related to the contingencies
described below. Our planned development, acquisition and debt reduction
programs are projected to be funded by available cash flow from our 2002
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. Realization of any of the
aforementioned negative items could limit our ability to fund future operations
during 2002.
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 our contractual obligations at December 31,
2001 (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................................. $ 101,250 $ 22,000 $ 48,000 $ 31,250 $ -
Interest expense on credit facility(2)..... 4,787 3,145 1,642 - -
Interest expense on note payable(3)........ 17,272 4,940 9,883 2,449 -
Non-cancelable operating leases............ 2,545 375 688 368 1,114
Contractor commitment(4)................... 3,450 - 3,450 - -
------------ ----------- ----------- ----------- -----------
Total contractual obligations.......... $ 129,304 $ 30,460 $ 63,663 $ 34,067 $ 1,114
=========== =========== =========== =========== ===========
_______________
(1) Does not include any amounts related to contingencies discussed below.
(2) Incudes interest based on rates and monthly reduction amounts in effect at
December 31, 2001.
(3) Includes 11.5% interest and repayment premium.
(4) Does not include 7.5% interest due monthly.
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 litigation is in its very early stages with
written discovery propounded by ATP, but no answers received, and no depositions
taken. The judge has abated the litigation, until arbitration pursuant to the
underlying
31
agreements between the sellers and ATP is completed. Since the legal proceedings
have just begun, and a prediction of the outcome would be premature and
uncertain, we have not accrued any amount related to this matter. And while we
are seeking recovery of the amounts previously paid and discussed above, the
$3.0 million has been charged to earnings along with certain 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 us alleging
formation of a contract with us 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, 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 2001, the FASB approved SFAS No. 141 "Business Combinations" ("SFAS
141"), No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142"), No. 143
"Accounting for Asset Retirement Obligations" ("SFAS 143") and No. 144
"Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144").
SFAS 141 requires all business combinations completed after June 30, 2001, be
accounted for under the purchase method. This standard also establishes for all
business combinations made after June 30, 2001, specific criteria for the
recognition of intangible assets separately from goodwill. SFAS 141 also
requires that the excess of fair value of acquired assets over cost (negative
goodwill) be recognized immediately as an extraordinary gain, rather than
deferred and amortized.
SFAS 142 addresses the accounting for goodwill and other intangible assets
after an acquisition. The most significant changes made by SFAS 142 are: 1)
goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for the
intangible assets with finite lives will no longer be limited to forty years. We
will adopt SFAS 142 effective January 1, 2002, as required. Additionally, SFAS
142 requires that unamortized negative goodwill associated with investments
accounted for under the equity method and acquired before July 1, 2001, be
recognized in income as a cumulative effect of change in accounting principle.
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. We will adopt the Statement effective 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.
SFAS 144 provides that long-lived assets to be disposed of by sale be
measured at the lower of carrying amount or fair value less cost to sell,
whether reported in continuing operations or in discontinued operations, and
broadens the reporting of discontinued operations to include all components of
an entity with operations that can be distinguished from the rest of the entity
and that will be eliminated from the ongoing operations of the entity in a
disposal transaction. SFAS 144 is effective for fiscal years beginning after
December 15, 2001.
SFAS 141 and SFAS 142 will not apply to us unless we enter into a future
business combination. We are currently assessing the impact of SFAS 143 and SFAS
144 on our financial condition and results of operations.
32
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 ones
facing 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 substantial debt, trade payables and related interest payment
requirements that may restrict our future operations and impair our ability to
meet our obligations.
Our substantial 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.
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 to 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 November 2003 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.
33
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 more quickly than companies whose reserves decline at a slower rate.
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, 2001 and 2000, our reserve life index was 9.1 years
and 5.1 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.
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 $56.1 million during 1999, $76.5
million during 2000 and $110.3 million during 2001.
34
For 2002, 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 new financing. 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.
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 83% of our estimated proved reserves as of
December 31, 2001 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. 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.
35
Our hedging decisions may reduce our potential gains from increases in
commodity prices and may result in losses.
We periodically utilize derivative instruments 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 hedges 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, 2001 and 2000, we realized a loss on derivative instruments of $26.5 million
and $32.7 million, respectively. See Item 7a. "Quantitative and Qualitative
Disclosure about Market Risk" for volume and price information on our hedging
activities.
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 published 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 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 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 of $24.9 million,
$10.8 million and $7.5 million for the years ended December 31, 2001, 2000 and
1999, 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,
reducing our net income 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.
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. 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. During 2000, drilling activity in the Gulf of Mexico increased, and
we experienced increases in associated costs, including those related to
drilling rigs, equipment, supplies and personnel and the services and products
of other vendors to the industry. Increased drilling activity in the Gulf of
Mexico also decreases the availability of offshore rigs. These costs may
increase further and necessary equipment and services may not be available to us
at economical prices.
37
Competition in our industry is intense, and we are smaller and have a more
limited operating history than some of our competitors in the Gulf of Mexico and
in the Southern Gas Basin of 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 Southern Gas Basin of 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, 2001, we had 16
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.
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 U.K., are subject to extensive laws
and regulations, including environmental laws and regulations. We may be
required to make large expenditures to comply with environmental and other
governmental regulations. Matters subject to regulation include:
. discharge permits for drilling operations;
. bonds for ownership, development and production of oil and gas
properties;
. reports concerning operations; and
. taxation.
38
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.
39
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
We are exposed to changes in interest rates. Changes in interest rates
affect the interest earned on our cash and cash equivalents and the interest
rate paid on borrowings under the credit agreements. Under our current policies,
we do not use interest rate derivative instruments to manage exposure to
interest rate changes.
Commodity Price Risk
Our revenues, profitability and future growth depend substantially on
prevailing prices for natural gas and oil. Prices also affect the amount of cash
flow available for capital expenditures and our ability to borrow and raise
additional capital. The amount we can borrow under our bank credit facility is
subject to periodic redetermination based in part on changing expectations of
future prices. Lower prices may also reduce the amount of natural gas and oil
that we can economically produce. We currently sell most of our natural gas and
oil production under price sensitive or market price contracts. To reduce
exposure to fluctuations in natural gas and oil prices and to achieve more
predictable cash flow, we periodically enter into hedging arrangements that
usually consist of swaps or price collars that are settled in cash. However,
these contracts also limit the benefits we would realize if commodity prices
increase. Our internal hedging policy provides that we examine the economic
effect of entering into a commodity contract with respect to the properties that
we acquire. We generally acquire properties at prices that are below the
management's estimated value of the estimated proved reserves at the then
current natural gas and oil prices. We will 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 2001, we hedged approximately 82% of our
natural gas production.
Effective January 1, 2001, we adopted SFAS No. 133 and SFAS No. 138, an
amendment to SFAS 133. SFAS 133 and 138 require that derivatives be reported on
the balance sheet at fair value and, if the derivative is not designated as a
hedging instrument, changes in fair value must be recognized in earnings in the
period of change. If the derivative is designated as a hedge and to the extent
such hedge is determined to be effective, changes in fair value are either (a)
offset by the change in fair value of the hedged asset or liability (if
applicable) or (b) reported as a component of other comprehensive income (loss)
in the period of change, and subsequently recognized in earnings when the
offsetting hedged transaction occurs. We use derivatives to hedge the price of
crude oil and natural gas. Effective January 1, 2001, we did not attempt to
qualify for the hedge provisions under SFAS 133 and thus have not designated our
derivatives as hedging instruments. Accordingly, we account for the changes in
market value of these derivatives through current earnings. This method will
result in increased earnings volatility associated with commodity price
fluctuations. Gains and losses on all derivative instruments related to
accumulated other comprehensive income (loss) are included in other income
(expense) on the consolidated financial statements.
On January 1, 2001, in accordance with the transition provisions of SFAS
133, we recorded a non-cash loss of $52.7 million ($34.3 million after tax) in
accumulated other comprehensive loss, representing the cumulative effect of an
accounting change to recognize at fair value all cash flow type derivatives.
Also on January 1, 2001, we recorded derivative liabilities of $52.7 million.
During the year ended December 31, 2001, losses of $52.7 million ($34.3 million
after tax) were reclassified from accumulated other comprehensive loss to
earnings. Prior to the adoption of this standard, we included gains and losses
on hedging instruments as a component of revenue. As of December 31, 2001, the
fair market value of our derivatives consisted of a $1.9 million current asset
and a $0.7 million long-term liability.
As of December 31, 2001, all of our natural gas swap agreements were with
one counterparty whose investment grade ratings were Baa2 from Moody's and BBB
from Standard & Poor's. Those agreements outstanding were as follows:
Average
Period MMBtu/Day $/MMBtu
------ ------------ ----------
January 2002 - October 2003........................................... 20,000 3.02
Thus far, in 2002, we have entered into the following swap agreements:
Period Volume/Day $/Unit
------ ---------- ----------
Natural gas (MMBtu):
February 2002 - October 2002 ....................................... 6,000 2.41
April 2002 - July 2002 ............................................. 6,000 2.81
April 2002 - October 2002 .......................................... 2,000 3.31
Oil (Bbl):
April 2002 - December 2002 ......................................... 500 23.50
April 2002 - December 2002 ......................................... 500 25.25
40
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required here is included in the report as set forth in the
"Index to Financial Statements" on page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
41
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 herein 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 June
14, 2002 (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.
42
PART IV
ITEM 14. 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 Amended and Restated Credit Agreement, dated as of September 21,
1999, among ATP Oil & Gas Corporation, Chase Bank of Texas,
National Association as Agent, and the Lenders Signatory thereto
(incorporated by reference to Exhibit 10.1 of ATP's registration
statement No. 333-46034 on Form S-1)
10.2 First Amendment to Amended and Restated Credit Agreement, dated as
of September 21, 1999, among ATP Oil & Gas Corporation, Chase Bank
of Texas, National Association, as Agent, and the Lenders
Signatory thereto, effective as of June 30, 2000 (incorporated by
reference to Exhibit 10.2 of ATP's registration statement No.
333-46034 on Form S-1)
10.3 Credit Agreement between ATP Oil & Gas Corporation and Aquila
Energy Capital Corporation, dated April 9, 1999, effective as of
March 31, 1999 (incorporated by reference to Exhibit 10.3 of ATP's
registration statement No. 333-46034 on Form S-1)
10.4 First Amendment to Credit Agreement, dated April 9, 1999, by and
between ATP Oil & Gas Corporation and Aquila Energy Capital
Corporation (incorporated by reference to Exhibit 10.4 of ATP's
registration statement No. 333-46034 on Form S-1)
10.5 Second Amendment to Credit Agreement, dated April 9, 1999, by and
between ATP Oil & Gas Corporation and Aquila Energy Capital
Corporation (incorporated by reference to Exhibit 10.5 of ATP's
registration statement No. 333-46034 on Form S-1)
10.6 Gas Service Agreement, dated December 31, 1998, between American
Citigas Company and ATP Energy, Inc. (incorporated by reference
to Exhibit 10.6 of ATP's registration statement No. 333-46034
on Form S-1)
10.7 Marketing & Natural Gas Purchase Agreement, dated December 1,
1998, between ATP Energy, Inc. and El Paso Energy Marketing
Company (incorporated by reference to Exhibit 10.7 of ATP's
registration statement No. 333-46034 on Form S-1)
10.8 Purchase and Sale Agreement, effective as of May 1, 1999, between
Eugene Offshore Holdings, LLC and ATP Oil & Gas Corporation
(incorporated by reference to Exhibit 10.8 of ATP's registration
statement No. 333-46034 on Form S-1)
10.9 ATP Oil & Gas Corporation 1998 Stock Option Plan (incorporated
by reference to Exhibit 10.9 of ATP's registration statement
No. 333-46034 on Form S-1)
10.10 First Amendment to the ATP Oil & Gas Corporation 1998 Stock
Option Plan (incorporated by reference to Exhibit 10.10 of
ATP's registration statement No. 333-46034 on Form S-1)
10.11 ATP Oil & Gas Corporation 2000 Stock Plan (incorporated by
reference to Exhibit 10.11 of ATP's Annual Report on Form 10-K
for the year ended December 31, 2000)
10.12 Credit Agreement, dated as of April 27, 2001, among ATP Oil & Gas
Corporation and BNP Paribas, as 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 March
31, 2001)
43
10.13 First Amendment to Credit Agreement dated June 29, 2001, among
ATP Oil & Gas Corporation and BNP Paribas, as 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, 2001)
10.14 Second Amendment to Credit Agreement dated June 29, 2001, among
ATP Oil & Gas Corporation and BNP Paribas, as Agent, and the
Lenders Signatory thereto (incorporated by reference to Exhibit
10.2 of ATP's Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 2001)
10.15 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)
10.16 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)
10.17 Third Amendment to Credit Agreement dated June 30, 2001, among ATP
Oil & Gas Corporation and BNP Paribas, as Agent, and the Lenders
Signatory thereto (incorporated by reference to Exhibit 10.5 of
ATP's Quarterly Report on Form 10-Q for the quarterly period ended
June 30, 2001)
10.18 Fourth Amendment to Credit Agreement dated October 1, 2001, among
ATP Oil & Gas Corporation and BNP Paribas, as 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 September 30, 2001)
10.19 Fifth Amendment to Credit Agreement dated November 1, 2001, among
ATP Oil & Gas Corporation and Union Bank of California, N.A., as
Agent, and the Lenders Signatory thereto (incorporated by
reference to Exhibit 10.2 of ATP's Quarterly Report on Form 10-Q
for the quarterly period ended September 30, 2001)
*10.20 Sixth Amendment to Credit Agreement dated January 31, 2002, among
ATP Oil & Gas Corporation and Union Bank of California, N.A., as
Agent, and the Lenders Signatory thereto
*10.21 Seventh Amendment to Credit Agreement dated February 28, 2002,
among ATP Oil & Gas Corporation and Union Bank of California,
N.A., as Agent, and the Lenders Signatory thereto
*10.22 Eighth Amendment to Credit Agreement dated March 27, 2002, among
ATP Oil & Gas Corporation and Union Bank of California, as Agent,
and the Lenders Signatory thereto
*10.23 First Amendment to Note Purchase Agreement dated March 27, 2002
between ATP Oil & Gas Corporation and Aquila Energy Capital
Corporation
21.1 Subsidiaries of ATP Oil & Gas Corporation (incorporated by
reference to Exhibit 21.1 of ATP's registration statement No.
333-46034 on Form S-1)
*23.1 Consent of KPMG LLP
*23.2 Consent of Ryder Scott Company
*23.3 Consent of Troy-Ikoda Limited
_____________
* Filed herewith
44
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 April 1, 2002.
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/ CAROL E. OVERBEY Director
- -------------------------------
Carol E. Overbey
/s/ GERARD SWONKE Director
- -------------------------------
Gerard Swonke
/s/ ARTHUR H. DILLY Director
- -------------------------------
Arthur H. Dilly
/s/ ROBERT C. THOMAS Director
- -------------------------------
Robert C. Thomas
/s/ WALTER WENDLANDT Director
- -------------------------------
Walter Wendlandt
45
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, 2001 and 2000............................. F-3
Consolidated Statements of Operations for the years ended
December 31, 2001, 2000 and 1999.................................................... F-4
Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999.................................................... F-5
Consolidated Statements of Shareholders' Equity (Deficit) for the years ended
December 31, 2001, 2000 and 1999.................................................... 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, 2001 and 2000, 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,
2001. 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, 2001 and 2000, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2001, 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 29, 2002
F-2
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Amounts)
December 31,
2001 2000
------------- --------------
Assets
Current assets:
Cash and cash equivalents....................................................... $ 5,294 $ 18,136
Accounts receivable (net of allowance of $1,423 and $443, respectively)......... 10,371 32,542
Commodity contracts and other derivatives....................................... 1,936 -
Other current assets............................................................ 1,754 2,597
------------- --------------
Total current assets......................................................... 19,355 53,275
------------- --------------
Oil and gas properties:
Oil and gas properties (using the successful efforts method of accounting)...... 319,506 209,548
Less: Accumulated depreciation, depletion, impairment and amortization.......... (186,473) (110,823)
------------- --------------
Oil and gas properties, net.................................................. 133,033 98,725
------------- --------------
Furniture and fixtures (net of accumulated depreciation)............................ 794 487
Deferred tax asset.................................................................. 19,228 7,652
Other assets, net................................................................... 5,154 1,854
------------- --------------
Total assets................................................................. $ 177,564 $ 161,993
============= ==============
Liabilities and Shareholders' Equity (Deficit)
Current liabilities:
Accounts payable and accruals................................................... $ 26,426 $ 49,799
Current maturities of long-term debt............................................ 22,000 -
Commodity contracts and other derivatives....................................... - 7,248
Other deferred obligations...................................................... - 63
------------- --------------
Total current liabilities.................................................... 48,426 57,110
Long-term debt...................................................................... 78,111 27,750
Non-recourse borrowings............................................................. - 88,779
Commodity contracts and other derivatives........................................... 671 -
Deferred revenue.................................................................... 1,296 1,481
Other long-term liabilities and deferred obligations................................ 4,068 52
------------- --------------
Total liabilities............................................................ 132,572 175,172
------------- --------------
Commitments and Contingencies
Shareholders' equity (deficit):
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, 2001 and 2000................................................ 20 14
Additional paid in capital...................................................... 80,478 38
Accumulated deficit............................................................. (34,614) (13,231)
Accumulated other comprehensive income.......................................... 19 -
Treasury stock, at cost......................................................... (911) -
------------- --------------
Total shareholders' equity (deficit)......................................... 44,992 (13,179)
------------- --------------
Total liabilities and shareholders' equity (deficit)......................... $ 177,564 $ 161,993
============= ==============
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,
-------------------------------------------
2001 2000 1999
------------- ------------- -------------
Revenues:
Oil and gas production......................................... $ 105,757 $ 75,940 $ 34,981
Gas sold - marketing........................................... 7,417 8,015 7,703
Gain on sale of oil and gas properties......................... - 33 287
------------- ------------- -------------
113,174 83,988 42,971
------------- ------------- -------------
Costs and operating expenses:
Lease operating expenses....................................... 14,806 11,559 5,587
Gas purchased - marketing...................................... 7,218 7,788 7,402
Geological and geophysical expenses............................ 1,068 - -
General and administrative expenses............................ 9,981 5,409 3,541
Non-cash compensation expense (general and administrative)..... 3,364 - -
Depreciation, depletion and amortization....................... 53,428 40,569 22,521
Impairment of oil and gas properties........................... 24,891 10,838 7,509
Loss on unsuccessful property acquisition...................... 3,147 - -
Other expense.................................................. - 450 -
------------- -------------- -------------
117,903 76,613 46,560
------------- ------------- -------------
Income (loss) from operations..................................... (4,729) 7,375 (3,589)
-------------- ------------- -------------
Other income (expense):
Interest income................................................ 884 451 202
Interest expense............................................... (10,039) (11,907) (9,399)
Loss on derivative instruments................................. (18,083) (11,911) -
------------- ------------- ------------
(27,238) (23,367) (9,197)
------------- ------------- -------------
Loss before income taxes and extraordinary gain (loss)............ (31,967) (15,992) (12,786)
Income tax benefit................................................ 11,186 5,594 1,829
------------- ------------- -------------
Loss before extraordinary gain (loss)............................. (20,781) (10,398) (10,957)
Extraordinary gain (loss), net of tax............................. (602) - 29,185
------------- ------------- -------------
Net income (loss)................................................. $ (21,383) $ (10,398) $ 18,228
============= ============= =============
Basic and diluted earnings (loss) per common share:
Loss before extraordinary gain (loss).......................... $ (1.06) $ (0.73) $ (0.77)
Extraordinary gain (loss), net of tax.......................... (0.03) - 2.05
------------ ------------- -------------
Net income (loss) per common share............................. $ (1.09) $ (0.73) $ 1.28
============ ============= =============
Weighted average number of common shares:
Basic and diluted.............................................. 19,704 14,286 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,
--------------------------------------------
2001 2000 1999
------------- ------------- --------------
Cash flows from operating activities:
Net income (loss)................................................ $ (21,383) $ (10,398) $ 18,228
Adjustments to reconcile net income (loss) to net cash
provided by operating activities -
Depreciation, depletion and amortization.................... 53,428 40,569 22,521
Impairment of oil and gas properties........................ 24,891 10,838 7,509
Amortization of deferred financing costs.................... 797 376 256
Extraordinary item.......................................... 926 - (29,185)
Deferred tax assets......................................... (11,576) (5,594) (2,058)
Non-cash compensation expense............................... 3,364 - -
Gain on sale of oil and gas properties...................... - (33) (287)
Other expense............................................... - 450 -
Other non-cash items........................................ 196 431 566
Changes in assets and liabilities -
Accounts receivable and other................................. 23,014 (22,772) (7,197)
Restricted cash............................................... - 471 3,529
Cash held in escrow........................................... - - 439
Net (assets) liabilities from risk management activities...... (8,513) 7,249 -
Accounts payable and accruals................................. (23,436) 37,309 (2,403)
Other long-term assets........................................ (4,183) (1,462) (803)
Other long-term liabilities and deferred credits.............. 3,831 (277) (408)
------------- -------------- ---------------
Net cash provided by operating activities............................ 41,356 57,157 10,707
------------- ------------- --------------
Cash flows from investing activities:
Additions and acquisitions of oil and gas properties............. (110,264) (76,474) (56,051)
Proceeds from sale of oil and gas properties..................... - - 1,137
Additions to furniture and fixtures.............................. (546) (361) (206)
------------- ------------- --------------
Net cash used in investing activities................................ (110,810) (76,835) (55,120)
------------- ------------- --------------
Cash flows from financing activities:
Proceeds of initial public offering.............................. 78,330 - -
Payment of offering costs........................................ (893) (621) -
Proceeds from long-term debt..................................... 119,000 15,800 19,800
Payments of long-term debt....................................... (46,750) (8,250) (14,100)
Proceeds from non-recourse borrowings............................ 3,359 42,745 93,728
Payments of non-recourse borrowings.............................. (92,138) (29,239) (39,420)
Deferred financing costs......................................... (3,586) (400) (1,227)
Treasury stock purchases......................................... (911) - -
Other............................................................ 201 - -
------------- ------------- --------------
Net cash provided by financing activities............................ 56,612 20,035 58,781
------------- ------------- --------------
Increase (decrease) in cash and cash equivalents..................... (12,842) 357 14,368
Cash and cash equivalents, beginning of period....................... 18,136 17,779 3,411
------------- ------------- --------------
Cash and cash equivalents, end of period............................. $ 5,294 $ 18,136 $ 17,779
============= ============= ==============
Supplemental disclosures of cash flow information:
Cash paid during the period for interest......................... $ 4,177 $ 2,531 $ 600
============= ============= ==============
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)
2001 2000 1999
------------------------ ------------------------ -------------------------
Shares Amount Shares Amount Shares Amount
----------- ----------- ----------- ----------- ----------- -----------
Common Stock
Balance, beginning of year....... 14,286 $ 14 14,286 $ 14 14,286 $ 14
Issuances of common stock
Public offering................ 6,000 6 - - - -
Exercise of stock options...... 103 - - - - -
Purchase of treasury stock....... (76) - - - - -
----------- ----------- ----------- ---------- ---------- -----------
Balance, end of year............. 20,313 $ 20 14,286 $ 14 14,286 $ 14
=========== ----------- =========== ---------- ========== -----------
Paid-in Capital
Balance, beginning of year....... $ 38 $ 38 $ 38
Issuances of common stock
Public offering................ 76,809 - -
Exercise of stock options...... 267 - -
Non-cash compensation expense.... 3,364 - -
----------- ---------- -----------
Balance, end of year............. $ 80,478 $ 38 $ 38
----------- ---------- -----------
Accumulated Deficit
Balance, beginning of year....... $ (13,231) $ (2,833) $ (21,061)
Net income (loss)................ (21,383) (10,398) 18,228
----------- ---------- -----------
Balance, end of year............. $ (34,614) $ (13,231) $ (2,833)
----------- ---------- -----------
Accumulated Other
Comprehensive Income
Balance, beginning of year..... $ - $ - $ -
Other comprehensive income..... 19 - -
----------- ---------- -----------
Balance, end of year........... $ 19 $ - $ -
----------- ---------- -----------
Treasury Stock
Balance, beginning of year....... - $ - - $ - - $ -
Purchase of treasury stock....... 76 (911) - - - -
----------- ----------- ----------- ---------- ---------- -----------
Balance, end of year............. 76 $ (911) - $ - - $ -
=========== ----------- =========== ---------- ========== -----------
Total Shareholders'
Equity (Deficit)................. $ 44,992 $ (13,179) $ (2,781)
=========== ========== ===========
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 outer continental shelf of the Gulf of Mexico, in the
shallow-deep waters of the Gulf of Mexico and in the Southern Gas Basin of the
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) and ATP Oil & Gas (UK)
Limited. 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
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 are incurred for development
purposes only. These costs are generally charged to expense unless the costs can
be specifically attributed to determining the placement for a future 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. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of"
("SFAS 121"). 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 published 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
properties determined to be impaired, an impairment loss equal to the
differences between the carrying value and the fair value of the impaired
property will be recognized. Fair value, on a depletable unit basis, is
estimated to be the present value of 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,
2001, 2000 and 1999 of $24.9 million, $10.8 million and $7.5 million,
respectively, primarily due to depressed oil and natural gas prices, unfavorable
operating performance and downward revisions of recoverable reserves.
Furniture and Fixtures. Furniture and fixtures consists of office
furniture, computer hardware and software and leasehold improvements.
Depreciation of furniture and fixtures is computed using the straight-line
method over their estimated useful lives, which vary from three to five years.
Other Assets. Other assets consist of the following (in thousands):
December 31,
------------------------------
2001 2000
------------- --------------
Debt financing costs.......................................... $ 3,584 $ 1,794
Offering costs................................................ - 621
Spare parts inventory......................................... 2,138 77
Other......................................................... 9 10
------------- --------------
5,731 2,502
Accumulated amortization...................................... (577) (648)
------------- --------------
$ 5,154 $ 1,854
============= ==============
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 considerable 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. We have
never had an environmental claim.
Revenue Recognition. We record as revenue only that portion of production
sold and allocable to our ownership interest in the related property in the
month the production is sold. Imbalances arise when a purchaser takes delivery
of more or less volume from a property than our actual interest in the
production from that property. Such imbalances are reduced either by subsequent
recoupment of over-and-under deliveries or by cash settlement, as required by
applicable contracts. Under-deliveries are included in accounts receivable and
over-deliveries are included in accounts payable.
F-8
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2001, revenues
from three purchasers accounted for 53%, 17% and 10%, respectively, of oil and
gas revenues. For the year ended December 31, 2000, revenues from two
purchasers accounted for 41% each of oil and gas revenues and for the year
ended December 31, 1999, revenues from three customers accounted for 48%, 19%
and 12%, respectively, of oil and gas 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 (deficit).
Income Taxes. Income taxes are accounted for under the asset and liability
method. Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases and operating loss and tax credit 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 Income (Loss). Comprehensive income (loss) is net income
(loss), plus certain other items that are recorded directly to shareholders'
equity. In 2001, comprehensive loss was $21.4 million. In 2000 and 1999, we had
no comprehensive income (loss) other than net income (loss).
Stock Options. We have elected to follow Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25") and
related interpretations in accounting for our employee stock options. 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.
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.
On January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"). Accordingly, natural gas and
oil swaps and option contracts are recorded at fair value in our consolidated
balance sheet. Information concerning our price risk management activities is
included in Note 12.
The following table provides information on other financial instruments (in
thousands):
December 31,
-----------------------------------------------------------
2001 2000
----------------------------- ----------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
Debt:
Bank debt....................................... $ 70,000 $ 70,000 $ 27,750 $ 27,750
Note payable.................................... 30,111 33,400 - -
Non-recourse borrowings......................... - - 88,779 88,779
------------- ------------- -------------- -------------
Total......................................... 100,111 103,400 116,529 116,529
============= ============= ============= =============
F-9
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our bank debt and non-recourse borrowings are variable rate debt and as
such, approximate their fair values, 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 2001, the FASB approved SFAS No. 141 "Business
Combinations" ("SFAS 141"), No. 142 "Goodwill and Other Intangible Assets"
("SFAS 142"), No. 143 "Accounting for Asset Retirement Obligations" ("SFAS
143") and No. 144 "Accounting for the Impairment or Disposal of Long-Lived
Assets" ("SFAS 144"). SFAS 141 requires all business combinations completed
after June 30, 2001, be accounted for under the purchase method. This standard
also establishes for all business combinations made after June 30, 2001,
specific criteria for the recognition of intangible assets separately from
goodwill. SFAS 141 also requires that the excess of fair value of acquired
assets over cost (negative goodwill) be recognized immediately as an
extraordinary gain, rather than deferred and amortized.
SFAS 142 addresses the accounting for goodwill and other intangible assets
after an acquisition. The most significant changes made by SFAS 142 are: 1)
goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for the
intangible assets with finite lives will no longer be limited to forty years.
We will adopt SFAS 142 effective January 1, 2002, as required. Additionally,
SFAS 142 requires that unamortized negative goodwill associated with
investments accounted for under the equity method and acquired before July 1,
2001, be recognized in income as a cumulative effect of change in accounting
principle.
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. We will adopt the Statement effective 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.
SFAS 144 provides that long-lived assets to be disposed of by sale be
measured at the lower of carrying amount or fair value less cost to sell,
whether reported in continuing operations or in discontinued operations, and
broadens the reporting of discontinued operations to include all components of
an entity with operations that can be distinguished from the rest of the entity
and that will be eliminated from the ongoing operations of the entity in a
disposal transaction. SFAS 144 is effective for fiscal years beginning after
December 15, 2001.
SFAS 141 and SFAS 142 will not apply to us unless we enter into a future
business combination. We are currently assessing the impact of SFAS 143 and
SFAS 144 on our financial condition and results of operations.
NOTE 3 -- ACQUISITIONS
Gulf of Mexico
During 2001, we acquired interests in 15 lease blocks covering 14
properties in six separate transactions. Total reserves associated with these
transactions were approximately 60.6 Bcfe (unaudited), based on third party
reservoir engineering estimates at year-end, for total acquisition costs of
approximately $22.7 million. Our working interests in these properties range
from 25% to 100%. Ten of these properties produced in 2001 with additional
development and production planned on the remaining four in 2002 and beyond.
F-10
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During 2000 we acquired an interest in 11 lease blocks covering nine
separate properties for total acquisition costs of $7.5 million. Total proved
reserves associated with these acquisitions were approximately 66.0 Bcfe
(unaudited) net to our interest. Our working interests in these properties range
from 50% to 100%. We are the operator of all of the properties. Included in
these acquisitions were four blocks on three separate properties which represent
our first acquisitions in the shallow-deep waters of the Gulf of Mexico. Of
these nine properties, five were producing in 2001, including "Ladybug", one of
the properties in the shallow-deep waters of the Gulf of Mexico, and a sixth
property commenced production in the first quarter of 2002. Two of the
properties are scheduled for future development in 2002 and beyond and the
remaining property was abandoned without commencing production in 2001.
Southern Gas Basin of the North Sea
In October 2000, we entered into a letter of intent to acquire interests in
three properties (five blocks) in the Southern Gas Basin of the North Sea which
included a 50% interest in one block, a 100% interest in one block and an 86%
interest in three blocks. In 2001, we acquired all three properties for total
acquisition costs of approximately $3.1 million. At December 31, 2001, net
proved reserves were approximately 80.6 Bcfe (unaudited), based on third party
reservoir engineering estimates at year-end. None of the properties were
producing when acquired and we expect to pursue development operations in 2002
through 2004.
NOTE 4 -- FINANCING AND DEBT
Long-term debt at December 31, 2001 and 2000 consisted of the following
balances (in thousands):
December 31,
------------------------------
2001 2000
------------- --------------
Credit facility, bearing interest at 5.26% and 10%
at December 31, 2001 and 2000, respectively..................... $ 70,000 $ 27,750
11.5 % Note payable, net of unamortized discount of $1,139........ 30,111 -
Non-recourse borrowings, bearing interest at 12.7%,
at December 31, 2000............................................ - 88,779
------------- --------------
Total debt........................................................ 100,111 116,529
Less current maturities........................................... (22,000) -
------------- --------------
Total long-term debt.............................................. $ 78,111 $ 116,529
============= ==============
Credit Facilities
In March 2001, we repaid our then existing bank credit facility and in
April 2001 we repaid the full amount borrowed under a non-recourse development
program credit agreement which we had used as a source of financing for the
acquisition of oil and gas properties. Concurrent with the repayment of our
non-recourse agreement, we negotiated with the lender to terminate the
overriding royalty interest retained by it on all properties previously
financed by the lender in exchange for a lump-sum payment of approximately $5.6
million.
Upon repayment of our former credit and non-recourse facilities, we entered
into a new $100.0 million senior-secured revolving credit facility in April
2001. This facility is secured by substantially all of our oil and gas
properties, as well as by approximately two-thirds of the capital stock of our
U.K. subsidiary and is guaranteed by our wholly owned subsidiary, ATP Energy,
Inc. As amended, the amount available for borrowing under the facility is
limited to the loan value, as determined by the bank, of oil and gas properties
pledged under the facility. At December 31, 2001, the borrowing base was $70.0
million and the monthly borrowing base reduction was set at $2.0 million a month
beginning February 27, 2002 and remains in effect until there is a change, if
any, at the next redetermination date. The redetermination dates are on or
around the first business day of each calendar quarter at which time the lenders
can increase or decrease the borrowing base and the monthly reduction amount.
The next scheduled redetermination date is on or around the first business day
of April 2002. Our lender has indicated this process will not be completed until
mid to late April of 2002. The $2.0 million monthly reduction included in
F-11
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
current maturities of long-term debt assumes there is no change in the monthly
reduction amount or the borrowing base in 2002. 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%. A reduction in the borrowing base or an 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 during 2002. As of
December 31, 2001, all of our borrowing base under the agreement was
outstanding.
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 amended
credit facility matures in November 2003. Our credit facility contains
conditions and restrictive provisions, among other things, (1) prohibiting 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, and (3) maintaining certain
financial ratios.
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 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 to right to make redetermination
of the borrowing base at least once every six months. We have assumed there is
no 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 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 during 2002. As of December 31, 2001, all of
our borrowing base under the agreement was outstanding.
F-12
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2001, we were in compliance with all of the financial
covenants of our credit facility and note payable agreements other than our
working capital covenant (as defined by the agreements) for which we have
obtained amendments from our lenders. Both of the amendments require that our
working capital at December 31, 2001 and March 31, 2002 shall not exceed
deficits of $10.0 million and $5.0 million, respectively.
Maturities
The aggregate amount of maturities of our long-term debt for the
next five years is: 2002 - $22.0 million, 2003 - $48.0 million, 2004 - none,
2005 - $31.3 million, 2006 - none.
NOTE 5 -- EQUITY
Initial Public Offering
On February 5, 2001, we priced our initial public offering ("IPO") of 6.0
million shares of common stock and commenced trading the following day. After
payment of the underwriting discount we received net proceeds of $78.3 million
on February 9, 2001.
Common Stock
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. At
December 31, 2000, we had 100,000,000 shares authorized, 14,285,714 shares
issued and outstanding.
Treasury Stock
During the second quarter, the first option vesting date occurred for
certain options granted since September 1999 through the date of our IPO on
February 5, 2001, as well as for certain options granted prior to September
1999. Of those options exercised during the second quarter, 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.
Change in Authorized Capitalization
On December 12, 2000, the Board of Directors approved an increase in the
authorized common stock from 50,000,000 shares to 100,000,000 shares, the
authorization of 10,000,000 shares of preferred stock and a 1.4-for-1 reverse
split of the common stock. Par value of the common stock remained $.001 per
share. The reverse stock split was effective December 12, 2000.
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.
F-13
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 expire 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:
2001 2000 1999
--------------------- ------------------- ---------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
----------- -------- ----------- ------- ----------- --------
Outstanding at beginning of year............ 646,608 $ 2.710 19,394,362 $ 0.040 19,378,111 $ 0.040
Granted..................................... 1,117,000 11.200 368,215 3.690 18,573 1.400
Exercised................................... (102,774) 1.960 - - - -
Forfeited................................... (23,025) 4.000 (178,572) 1.400 (2,322) 1.400
Cancelled................................... - - (18,937,397) 0.004 - -
----------- ---------- ----------
Outstanding end of year..................... 1,637,809 $ 8.520 646,608 $ 2.710 19,394,362 $ 0.040
=========== =========== ===========
Exercisable at end of period................ 112,760 $ 3.370 - $ - 18,937,397 $ 0.004
============ ============ ===========
Weighted average fair value of
options granted during the year.......... $ 4.65 $ - $ -
The following table summarizes information about all stock options
outstanding at December 31, 2001:
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............................. 537,809 3.0 Years $ 2.82 112,760 $ 3.37
$ 6.95 - $ 6.95............................. 25,000 4.8 Years 6.95 - -
$11.24 - $11.40............................. 1,055,000 4.4 Years 11.37 - -
$14.00 - $14.00............................. 20,000 4.1 Years 14.00 - -
----------- -----------
$ 1.40 - $14.00............................. 1,637,809 3.9 Years $ 8.52 112,760 $ 3.37
=========== ===========
F-14
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 years
ended December 31, 2000 and 1999. Had compensation expense been determined based
on the fair value of the options at the date of or subsequent to the IPO, our
loss and the related per share amount would have been reduced as is reflected by
the pro forma amount indicated below (in thousands, except per share data):
As Reported
Net loss before extraordinary item.................................. $ (20,781)
Net loss per common share, basic and diluted........................ (1.06)
Pro Forma
Net loss before extraordinary item.................................. $ (20,934)
Net loss per common share, basic and diluted........................ (1.06)
The fair value of these option grants were 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.
Because the determination of the fair value of all options granted after we
became a public entity includes an expected volatility factor, additional option
grants are expected to be made and most options will vest over several years,
the above effects of applying SFAS 123 in this pro forma disclosure are not
likely to be representative of the effects on reported net income for future
years. SFAS 123 does not apply to awards granted prior to fiscal year 1996.
In 2001, we recorded a non-cash compensation expense of approximately $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. The remaining compensation expense to be recorded over 2002 and 2003
is approximately $0.5 million.
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 $70,000, $56,000 and
$31,000, for the years ended December 31, 2001, 2000 and 1999, 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.). For the year ended December 31, 2001, we contributed
approximately $14,000.
NOTE 7 -- EARNINGS PER SHARE
Basic earnings per share is computed by dividing net income (loss)
available to common shareholders by the weighted average number of common shares
outstanding during the period. Diluted earnings per share is determined on the
assumption that outstanding stock options have been converted using the average
price for the period. For purposes of computing earnings per share in a loss
year, potential common shares have been excluded from the computation of
weighted average common shares outstanding because their effect is antidilutive.
F-15
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Basic and diluted net income (loss) per share is computed based on the
following information (in thousands, except share and per share amounts):
For the Years Ended December 31,
------------------------------------------------
2001 2000 1999
------------- ------------- -------------
Net income (loss) available to common shareholders............ $ (21,383) $ (10,398) $ 18,228
============= ============= =============
Weighted average shares-basic and diluted..................... 19,704 14,286 14,286
============= ============= =============
Net income (loss) per share:
Basic and diluted:
Loss before extraordinary gain (loss).................. $ (1.06) $ (0.73) $ (0.77)
Extraordinary gain (loss), net of income taxes......... (0.03) - 2.05
-------------- ------------- -------------
Net income (loss) per common share..................... $ (1.09) $ (0.73) $ 1.28
============== ============= =============
NOTE 8 -- EXTRAORDINARY ITEMS
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. For the year ended December 31, 1999, we prepaid the
amount outstanding under a development program credit agreement at a discount
and recorded an extraordinary gain of $29.2 million, net of income taxes.
NOTE 9 -- INCOME TAXES
The benefit (provision) for income taxes before extraordinary gain (loss)
consisted of the following:
For the Years Ended December 31,
------------------------------------------------
2001 2000 1999
------------- ------------- -------------
Current:
State....................................................... $ - $ - $ -
Federal..................................................... - - (229)
------------- ------------- --------------
- - (229)
------------- ------------- --------------
Deferred:
State....................................................... - - (82)
Federal..................................................... 11,186 5,594 2,140
------------- ------------- -------------
11,186 5,594 2,058
------------- ------------- -------------
Benefit for income taxes before extraordinary gain (loss)..... $ 11,186 $ 5,594 $ 1,829
============= ============= =============
Additionally, a tax benefit of $0.3 million and none was recognized related
to the extraordinary gain (loss) for the years ended December 31, 2001 and 1999,
respectively.
The reconciliation of income tax computed at the U.S. federal statutory
tax rates to the provision for income taxes is as follows:
For the Years Ended December 31,
------------------------------------------------
2001 2000 1999
------------- ------------- -------------
Before any valuation allowance:
Statutory federal income tax rate........................ (35.00)% (35.00)% 35.00%
State income taxes, net of federal benefit............... 0.00 0.00 0.32
Adjustment to valuation allowance........................ 0.00 0.00 (46.53)
Nondeductible and other.................................. 0.01 0.02 0.05
-------------- ------------- -------------
(34.99)% (34.98)% (11.16)%
============== ============= =============
F-16
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At December 31, 2001 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.
Significant components of our deferred tax assets (liabilities) as of
December 31, 2001 and 2000 are as follows (in thousands):
December 31,
------------------------------
2001 2000
------------- -------------
Deferred tax assets:
Net operating loss carryforwards........................................... $ 3,809 $ 3,826
Minimum tax credit carryforwards........................................... 229 229
Fixed asset basis differences.............................................. 11,367 554
State taxes................................................................ 17 17
Unrealized book (gains) losses............................................. (443) 2,537
Stock based compensation expense........................................... 1,177 -
Litigation................................................................. 1,050 -
Foreign equity in subsidiary............................................... 1,152 -
Other...................................................................... 870 489
------------- -------------
Net deferred tax assets......................................................... $ 19,228 $ 7,652
============= =============
At December 31, 2001, 2000 and 1999, we had net operating loss
carryforwards for federal income tax purposes of approximately $10.7 million,
$11.0 million, and $11.0 million respectively, which are available to offset
future federal taxable income through 2021.
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.
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. Total comprehensive loss for the year ended December
31, 2001 is as follows (in thousands):
Net loss....................................................................... $ (21,383)
------------
Other comprehensive income, net of tax:
Cumulative effect of change in accounting principle - January 1, 2001........ (34,252)
Reclassification adjustment for settled contracts............................ 34,252
Foreign currency translation adjustment...................................... 19
--------------
Other comprehensive income................................................. 19
--------------
Comprehensive loss............................................................. $ (21,364)
=============
F-17
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2001, 2000 and 1999 was
approximately $0.3 million, $0.2 million and $0.1 million respectively. At
December 31, 2001, the future minimum rental payments due under the lease are
as follows (in thousands amounts):
2002................................................................ $ 375
2003................................................................ 346
2004................................................................ 342
2005................................................................ 214
2006................................................................ 154
Later Years......................................................... 1,114
---------
Total........................................................... $ 2,545
=========
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 litigation is in its very early stages
with written discovery propounded by ATP, but no answers received, and no
depositions taken. The judge has abated the litigation, until arbitration
pursuant to the underlying agreements between the sellers and ATP is completed.
Since the legal proceedings have just begun, and a prediction of the outcome
would be premature and uncertain, we have not accrued any amount related to
this matter. And while we are seeking recovery of the amounts previously paid
and discussed above, the $3.0 million has been charged to earnings along with
certain 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 us alleging
formation of a contract with us 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.
F-18
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We are, 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
We utilize various derivative instruments, for purposes other than
trading, to hedge our exposure to price fluctuations on natural gas and oil
sales. The derivative instruments consist primarily of swap contracts entered
into with financial institutions. Under our current policies, we do not use
interest rate derivative instruments to manage exposure to interest rate
changes.
Effective January 1, 2001, we adopted SFAS No. 133 and SFAS No. 138, an
amendment to SFAS 133. SFAS 133 and 138 require that derivatives be reported on
the balance sheet at fair value and, if the derivative is not designated as a
hedging instrument, changes in fair value must be recognized in earnings in the
period of change. If the derivative is designated as a hedge and to the extent
such hedge is determined to be effective, changes in fair value are either (a)
offset by the change in fair value of the hedged asset or liability (if
applicable) or (b) reported as a component of other comprehensive income (loss)
in the period of change, and subsequently recognized in earnings when the
offsetting hedged transaction occurs. We use derivatives to hedge the price of
crude oil and natural gas. Effective January 1, 2001, we did not attempt to
qualify for the hedge provisions under SFAS 133 and thus have not designated our
derivatives as hedging instruments. Accordingly, we account for the changes in
market value of these derivatives through current earnings. This method will
result in increased earnings volatility associated with commodity price
fluctuations. Gains and losses on all derivative instruments related to
accumulated other comprehensive income (loss) are included in other income
(expense) on the consolidated financial statements.
On January 1, 2001, in accordance with the transition provisions of SFAS
133, we recorded a non-cash loss of $52.7 million ($34.3 million after tax) in
accumulated other comprehensive loss, representing the cumulative effect of an
accounting change to recognize at fair value all cash flow type derivatives.
Also on January 1, 2001, we recorded derivative liabilities of $52.7 million.
During the year ended December 31, 2001, losses of $52.7 million ($34.3 million
after tax) were reclassified from accumulated other comprehensive loss to
earnings. Prior to the adoption of this standard, we included gains and losses
on hedging instruments as a component of revenue.
As of December 31, 2001, all of our natural gas swap agreements were with
one counterparty whose investment grade ratings were Baa2 from Moody's and BBB
from Standard & Poor's. Those agreements outstanding were as follows:
Average
Period MMBtu/Day $/MMBtu
- ------ --------- ------------
January 2002 - October 2003...................... 20,000 3.02
At December 31, 2001, the fair value of our open derivative positions
consisted of a $1.9 million current asset and a $0.7 million long-term
liability. The $18.1 million loss on derivative instruments for the year ended
December 31, 2001 includes the following items:
. a $26.5 million loss related to contracts settled during 2001,
. $7.2 million related to the reversal of a speculative position
($2.6 million) and settlement of a written call option
($4.6 million), both recorded at December 31, 2000 and settled during
2001; and
. a $1.2 million gain on open positions at December 31, 2001.
F-19
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On occasion, we may find ourselves in speculative positions as a result of
actual production being less than projected production when the derivative
products were consummated or as a result of entering into speculative
derivative instruments. Any speculative positions are accounted for using the
mark-to-market method. For the year ended December 31, 2000, we recognized a
loss on derivative instruments in the amount of $11.9 million from certain
speculative positions. At December 31, 2000, the fair value of our derivative
positions was a $7.2 million current liability.
Thus far, in 2002 we have entered into the following swap agreements:
Period Volume/Day $/Unit
- ------ ----------- ------------
Natural gas (MMBtu):
February 2002 - October 2002 ......................... 6,000 2.41
April 2002 - July 2002 ............................... 6,000 2.81
April 2002 - October 2002 ............................ 2,000 3.31
Oil (Bbl):
April 2002 - December 2002 ........................... 500 23.50
April 2002 - December 2002 ........................... 500 25.25
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, 2001 and 2000
was $25.9 million and $28.8 million, respectively. At December 31, 2001 and
2000, the present value of the remaining premium payments to be made by ATP
Energy, using a discount rate of 6%, was $25.8 million and $28.7 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, 2001 the remaining
premium to be paid was $31.7 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. This contract has been renewed on a month-to-month basis.
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, 2001 and 2000, the
deferred revenue amount was $1.3 million and $1.5 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
F-20
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
not utilized is refundable if the contract is terminated. The transaction is
structured with American Citigas such that there is no financial impact to ATP
Energy associated with the premium paid and reimbursement received other than
the $2.0 million realized by ATP Energy. The remaining balance of the deferred
obligation was $0.05 million and $0.1 million at December 31, 2001 and 2000,
respectively. 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 and $97,875 for the years ended December
31, 2000, and 1999, respectively, 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 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 and $0.6 million in general and administrative expense for the
years ended December 31, 2000 and 1999. No amounts were paid in 2001 and we do
not intend to pay any further amounts.
NOTE 15 -- SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)
First Second Third Fourth
Quarter Quarter Quarter Quarter
----------- ----------- ----------- -----------
2001
Revenues............................................ $ 41,443 $ 31,035 $ 20,883 $ 19,813
Costs and expenses.................................. 28,701(1) 29,694(1) 24,659(1) 34,849(1)
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................................. $ (0.38) $ 0.16 $ (0.32) $ (0.55)
2000
Revenues............................................ $ 15,127 $ 24,558 $ 20,462 $ 23,841
Costs and expenses.................................. 11,682 23,230(2) 20,049(2) 21,652(2)
Income (loss) from operations....................... 3,445 (1,185) (3,316) (3,480)
Net income (loss)................................... 1,029 (2,742) (4,251) (4,434)
Net income (loss) per common share:
Basic and diluted................................. $ 0.07 $ (0.19) $ (0.30) $ (0.31)
- -------------------
(1) 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.
(2) Includes impairment charges of $6.2 million, $0.8 million and $3.8
million during the second, third and fourth quarters, respectively,
for three properties.
F-21
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):
Years Ended December 31,
---------------------------------------------------------------
2001 2000 1999
------------------------------------- ----------- -----------
U.S. U.K. Total U.S. U.S.
----------- ----------- ----------- ----------- -----------
Property costs:
Acquisition costs.......................... $ 28,344 $ 3,112 $ 31,456 $ 7,534 $ 25,274
Development costs.......................... 77,783 719 78,502 68,982 30,777
----------- ------------ ----------- ----------- -----------
Total costs incurred......................... $ 106,127 $ 3,831 $ 109,958 76,516 $ 56,051
=========== =========== =========== =========== ===========
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
and 1999. Our U.K. reserves at December 31, 2001 were prepared by independent
petroleum consultants Troy Ikoda Limited.
At December 31, 2001, our U.K. reserves included one property that was subject
to an agreement with our joint venture partner to earn an additional 11%
interest in that property upon their performance of future obligations. We
expect the conditions of that agreement to be satisfied in the first half of
2002. At that time our ownership in the property will be reduced by 11%,
resulting in a reduction of our net reserves of approximately 5.5 Bcfe. Our
future revenues and costs in the project will be reduced accordingly. The
reserves included in the tables below reflect our ownership interest in that
property prior to the satisfaction of the conditions of the earn-in agreement.
F-22
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, 1998, 1999, 2000 and 2001 and the changes in net proved oil and
gas reserves for the years ended December 31, 1999, 2000 and 2001:
Oil, Condensate and
Natural Gas (MMcf) Natural Gas Liquids (MMBbls)
-------------------------------------- --------------------------------------
U.S. U.K. Total U.S. U.K. Total
------------ ----------- ----------- ----------- ----------- -----------
Proved Reserves at
December 31, 1998................ 46,424 - 46,424 586 - 586
Revisions of previous estimates..... 3,033 - 3,033 (131) - (131)
Extensions and discoveries.......... 2,257 - 2,257 - - -
Purchase of properties.............. 58,816 - 58,816 1,362 - 1,362
Production.......................... (16,533) - (16,533) (128) - (128)
----------- ----------- ----------- ----------- ----------- ------------
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
=========== =========== =========== =========== =========== ===========
Oil, Condensate and
Natural Gas (MMcf) Natural Gas Liquids (MMBbls)
-------------------------------------- --------------------------------------
U.S. U.K. Total U.S. U.K. Total
------------ ----------- ----------- ----------- ----------- -----------
Proved Developed Reserves at
December 31, 1998................ 39,728 - 39,728 579 - 579
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
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):
Years Ended December 31,
------------------------------------------------------------
2001 2000 1999
----------------------------------- ---------- -------
U.S. U.K. TOTAL U.S. U.S.
--------- --------- --------- ---------- -------
Future cash inflows......................... $ 423,273 $ 302,894 $ 726,167 $1,139,404 $272,047
Future operating expenses................... (59,722) (100,330) (160,052) (70,719) (40,794)
Future development costs.................... (100,919) (111,044) (211,963) (137,453) (48,204)
--------- --------- --------- ---------- --------
Future net cash flows....................... 262,632 91,520 354,152 931,232 183,049
Future income taxes......................... (35,469) (26,188) (61,657) (285,587) (27,611)
--------- --------- --------- ---------- --------
Future net cash flows, after income taxes... 227,163 65,332 292,495 645,645 155,438
10% annual discount per annum............... (54,247) (25,584) (79,831) (121,164) (26,732)
--------- --------- --------- ---------- --------
Standardized measure of discounted
future net cash flows..................... $ 172,916 $ 39,748 $ 212,664 $ 524,481 $128,706
========= ========= ========= ========== ========
F-23
ATP OIL & GAS CORPORATION
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
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 Pretax PV-10 value at December 31, 2001 were
$2.65 per MMBtu of natural gas and $19.78 per barrel of oil. The National
Balancing Point, before adjustment for quality and transportation, utilized in
the Pretax PV-10 value at December 31, 2001 was $3.88 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 U.S. and U.K. 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.
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):
Years Ended December 31,
-----------------------------------------------------------
2001 2000 1999
---------------------------------- --------- --------
U.S. U.K. TOTAL U.S. U.S.
--------- -------- --------- --------- --------
Beginning of year................................ $ 524,481 $ - $ 524,481 $ 128,706 $ 61,308
--------- -------- --------- --------- --------
Sales of oil and gas, net of production costs... (90,951) - (90,951) (64,381) (29,394)
Net changes in income taxes..................... 193,247 (24,517) 168,730 (193,613) (27,611)
Net changes in price and production costs....... (593,914) - (593,914) 416,738 9,931
Revisions of quantity estimates................. (11,220) - (11,220) (147,777) 4,176
Accretion of discount........................... 74,483 - 74,483 15,632 6,131
Development costs incurred...................... 57,119 - 57,119 18,134 15,550
Changes in estimated future development......... 22,413 - 22,413 (14,709) (15,664)
Purchases of minerals-in-place.................. 64,322 64,265 128,587 300,706 105,514
Sales of minerals-in-place...................... - - - (525) -
Extensions and discoveries...................... - - - 51,795 218
Changes in production rates, timing and other... (67,064) - (67,064) 13,775 (1,453)
--------- -------- --------- --------- --------
(351,565) 39,748 (311,817) 395,775 67,398
--------- -------- --------- --------- --------
End of year...................................... $ 172,916 $ 39,748 $ 212,664 $ 524,481 $128,706
========= ======== ========= ========= ========
Sales of natural gas and oil, net of natural gas and oil operating
expenses, are based on historical pre-tax results. Sales of natural gas and oil
properties, extensions and discoveries, purchases of minerals-in-place and the
changes due to revisions in standardized variables are reported on a pre-tax
discounted basis, while the accretion of discount is presented on an after-tax
basis.
F-24