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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2002 Commission file number: 000-32261
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
ATP Oil & Gas Corporation
(Exact name of registrant as specified in its charter)
Texas 76-0362774
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
4600 Post Oak Place, Suite 200
Houston, Texas 77027
(Address of principal executive offices) (Zip Code)
(Registrant's telephone number, including area code): (713) 622-3311
Securities Registered Pursuant to Section 12 (b) of the Act:
Title of each class Name of exchange on which registered
------------------------------------------- --------------------------------------
Common Stock, par value $.001 per share NASDAQ
Securities Registered Pursuant to Section 12 (g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes[X] No__
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by Reference in Part III of this Form 10-K or any amendment to this
Form 10-K. Yes[X] No__
Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes__ No[X]
The aggregate market value of the voting and non-voting common stock held by
non-affiliates of the Registrant as of June 28, 2002 (the last business day of
the Registrant's most recently completed second fiscal quarter) was
approximately $18,271,364. The number of shares of the Registrant's common stock
outstanding as of March 21, 2003 was 20,338,753.
DOCUMENTS INCORPORATED BY REFERENCE: The information required in Part III of the
Annual Report on Form 10-K is incorporated by reference to the Registrant's
definitive proxy statement to be filed pursuant to Regulation 14A for the
Registrant's Annual Meeting of Stockholders.
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ATP OIL & GAS CORPORATION AND SUBSIDIARIES
2002 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
Page
----
Part I ...................................................................................... 6
Item 1. Business ...................................................................... 6
Item 2. Properties .................................................................... 14
Item 3. Legal Proceedings ............................................................. 17
Item 4. Submission of Matters to a Vote of Security Holders ........................... 17
Part II ..................................................................................... 19
Item 5. Market for Registrants Common Units and Related Security Holder Matters ....... 19
Item 6. Selected Financial Data ....................................................... 20
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations ..................................................... 21
Item 7a. Quantitative and Qualitative Disclosures about Market Risk .................... 39
Item 8. Financial Statements and Supplementary Data ................................... 40
Item 9. Disagreements on Accounting and Financial Disclosure .......................... 40
Part III .................................................................................... 41
Item 10. Directors and Executive Officers of Registrant ................................ 41
Item 11. Executive Compensation ........................................................ 41
Item 12. Security Ownership of Certain Beneficial Owners and Management ................ 41
Item 13. Certain Relationships and Related Transactions ................................ 41
Item 14. Controls and Procedures ....................................................... 41
Part IV ..................................................................................... 42
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K ............... 42
2
Cautionary Statement About Forward-Looking Statements
This annual report on Form 10-K includes assumptions, expectations,
projections, intentions or beliefs about future events. These statements are
intended as "forward-looking statements" under the Private Securities Litigation
Reform Act of 1995. We caution that assumptions, expectations, projections,
intentions and beliefs about future events may and often do vary from actual
results and the differences can be material.
All statements in this document that are not statements of historical fact
are forward looking statements. Forward looking statements include, but are not
limited to:
. projected operating or financial results;
. budgeted or projected capital expenditures;
. expectations regarding our planned expansions and the availability of
acquisition opportunities;
. statements about the expected drilling of wells and other planned
development activities;
. expectations regarding natural gas and oil markets in the United
States and the United Kingdom; and
. estimates of quantities of our proved reserves and the present value
thereof, and timing and amount of future production of natural gas and
oil.
When used in this document, the words "anticipate," "estimate," "project,"
"forecast," "may," "should," and "expect" reflect forward-looking statements.
There can be no assurance that actual results will not differ materially
from those expressed or implied in such forward looking statements. Some of the
key factors which could cause actual results to vary from those expected
include:
. the timing and extent of changes in natural gas and oil prices;
. the timing of planned capital expenditures;
. our ability to identify and acquire additional properties necessary to
implement our business strategy and our ability to finance such
acquisitions;
. the inherent uncertainties in estimating proved reserves and
forecasting production results;
. operational factors affecting the commencement or maintenance of
producing wells, including catastrophic weather related damage,
unscheduled outages or repairs, or unanticipated changes in drilling
equipment costs or rig availability;
. the condition of the capital markets generally, which will be affected
by interest rates, foreign currency fluctuations and general economic
conditions;
. cost and other effects of legal and administrative proceedings,
settlements, investigations and claims, including environmental
liabilities which may not be covered by indemnity or insurance;
. the political and economic climate in the foreign or domestic
jurisdictions in which we conduct oil and gas operations, including
risk of war or potential adverse results of military or terrorist
actions in those areas, and;
. other United States or United Kingdom regulatory or legislative
developments which affect the demand for natural gas or oil generally
increase the environmental compliance cost for our production wells or
impose liabilities on the owners of such wells.
3
CERTAIN DEFINITIONS
As used herein, the following terms have specific meanings as set forth
below:
Bbls Barrels of crude oil or other liquid hydrocarbons
Bcf Billion cubic feet
Bcfe Billion cubic feet equivalent
MBbls Thousand barrels of crude oil or other liquid hydrocarbons
Mcf Thousand cubic feet of natural gas
Mcfe Thousand cubic feet equivalent
MMBbls Million barrels of crude oil or other liquid hydrocarbons
MMBtu Million british thermal units
MMcf Million cubic feet of natural gas
MMcfe Million cubic feet equivalent
MMBoe Million barrels of crude oil or other liquid hydrocarbons equivalent
U.S. United States
U.K. United Kingdom of Great Britain and Northern Ireland
Crude oil and other liquid hydrocarbons are converted into cubic feet of gas
equivalent based on six Mcf of gas to one barrel of crude oil or other liquid
hydrocarbons.
Development well is a well drilled within the proved area of an oil or
natural gas field to the depth of a stratigraphic horizon known to be
productive.
Dry hole is a well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.
Exploratory well is a well drilled to find and produce natural gas or oil
reserves that is not a development well.
Farm-in or farm-out is an agreement whereby the owner of a working interest
in an oil and gas lease or license assigns the working interest or a portion
thereof to another party who desires to drill on the leased or licensed acreage.
Generally, the assignee is required to drill one or more wells in order to earn
its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The interest received by an assignee is a
"farm-in," while the interest transferred by the assignor is a "farm-out."
Field is an area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature or
stratigraphic condition.
Net feet of natural gas and condensate is the true vertical thickness of
reservoir rock estimated to both contain hydrocarbons and be capable of
contributing to producing rates.
PV-10 is the estimated future net revenue to be generated from the
production of proved reserves discounted to present value using an annual
discount rate of 10%. These amounts are calculated net of estimated production
costs and future development and abandonment costs, using prices and costs in
effect as of a certain date, without escalation and without giving effect to
non-production related expenses, such as general and administrative expenses,
debt service, future income tax expense, or depreciation, depletion, and
amortization.
Productive well is a well that is producing or is capable of production,
including natural gas wells awaiting pipeline connections to commence deliveries
and oil wells awaiting connection to production facilities.
4
Proved reserves are the estimated quantities of oil and gas which geological
and engineering data demonstrate, with reasonable certainty, can be recovered in
future years from known reservoirs under existing economic and operating
conditions. Reservoirs are considered proved if shown to be economically
producible by either actual production or conclusive formation tests.
Proved developed reserves are the portion of proved reserves that can be
expected to be recovered through existing wells with existing equipment and
operating methods.
Proved undeveloped reserves are the portion of proved reserves that are
expected to be recovered from new wells on undrilled acreage, or from existing
wells where a relatively major expenditure is required for completion.
Reserve life index is a measure of the productive life of a natural gas and
oil property or a group of natural gas and oil properties, expressed in years.
Reserve life equals the estimated net proved reserves attributable to property
or group of properties divided by production from the property or group of
properties for the four fiscal quarters preceding the date as of which the
proved reserves were estimated.
Working interest is the operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
Workover is operations on a producing well to restore or increase
production.
5
PART I
Item 1. Business
General
ATP Oil & Gas Corporation ("ATP") was incorporated in Texas in 1991. We are
engaged in the acquisition, development and production of natural gas and oil
properties in the Gulf of Mexico and the U.K. and Dutch Sectors of the North Sea
(the "North Sea"). We primarily focus our efforts on natural gas and oil
properties with proved undeveloped reserves that are economically attractive to
us but are not strategic to major or exploration-oriented independent oil and
gas companies. We attempt to achieve a high return on our investment in these
properties by limiting our up-front acquisition costs and by developing our
acquisitions quickly. Our management team has extensive engineering, geological,
geophysical, technical and operational expertise in successfully developing and
operating properties in both our current and planned areas of operation.
During 2002, we produced approximately 26.5 Bcfe, our seventh consecutive
annual increase in production. Natural gas accounted for 67% of our production
and all of our 2002 production was from the Gulf of Mexico. In December 2002, we
were near completion of our first well in the U.K. Sector - North Sea and, we
anticipate first production some time in the first half of 2003.
We increase our reserves and production primarily through acquisitions and
the subsequent development of proved reserves. During 2002 we added proved
reserves of approximately 38.5 Bcfe, of which 20.3 Bcf were through acquisitions
in the U.K. Sector - North Sea and 4.7 Bcf were through acquisitions in the Gulf
of Mexico. The remaining increase of 13.5 Bcfe came from an upward revision in
our previous reserve estimates. Also during 2002, we elected to sell an interest
in two of our U.K. Sector - North Sea properties which accounted for a
disposition of 17.1 Bcf in reserves.
At December 31, 2002, we had estimated net proved reserves of 230.0 Bcfe,
of which approximately 136.9 Bcfe (60%) was in the Gulf of Mexico and 93.1 Bcf
(40%) was in the U.K. Sector - North Sea. Year-end reserves were comprised of
195.5 Bcf of natural gas and 5.7 MMBbls of oil. All of our oil reserves are
located in the Gulf of Mexico and approximately 52% of our natural gas reserves
are located in the Gulf of Mexico with the balance in the U.K. Sector - North
Sea. The estimated pre-tax PV-10 of our reserves at December 31, 2002 was $355.3
million. Prices used in the U.S. reserve estimates were $4.74 per MMBtu of
natural gas and $31.23 per barrel of oil. For the U.K reserve estimates, we used
13.7 pence per thermal unit or approximately $2.20 per MMBtu of natural gas.
At December 31, 2002, we had leasehold and other interests in 50 offshore
blocks, 29 platforms and 70 wells, including six subsea wells, in the Gulf of
Mexico. We operate 55 of these 70 wells, including all of the subsea wells, and
76% of our offshore platforms. We also had interests in seven blocks and one
company-operated subsea well in the U.K. Sector - North Sea. Our average working
interest in our properties at December 31, 2002 was approximately 82%. For more
information regarding our operations in the Gulf of Mexico and North Sea, see
Note 15 to the Notes to Consolidated Financial Statements.
Our Business Strategy
Our business strategy is to enhance shareholder value primarily through the
acquisition, development and production of proved natural gas and oil reserves
in areas that have:
. an existing infrastructure of oil and natural gas pipelines and
production/processing platforms;
. geographic proximity to developed markets for natural gas and oil;
. a number of properties that major oil companies, exploration-oriented
independents and others consider non-strategic; and
. a relatively stable history of consistently applied governmental
regulations for offshore natural gas and oil development and
production.
6
We believe our strategy significantly reduces the risks associated with
traditional natural gas and oil exploration. Our focus is to acquire properties
that have been explored by others and found to contain proved reserves. From the
inception of operations in 1995 through March 20, 2003, we have successfully
brought to production 30 out of 31 projects from previously undeveloped
reserves, a 97% success ratio.
We focus on acquiring properties that contain proved undeveloped reserves
that have become non-core or non-strategic to their original owners for various
reasons. For example, larger oil companies from time to time adjust their
capital spending or shift their focus to exploration prospects with greater
reserve potential. Some projects provide lower economic returns to a larger
company due to its cost structure. Also, due to timing or budget constraints, a
company may be unable or unwilling to develop a property before the expiration
of the lease and desire to sell the property before they forfeit their lease
rights. Because of our cost structure, expertise in our areas of focus and our
ability to develop projects efficiently, these properties may be economically
attractive to us.
We focus on developing projects in the shortest time possible between
initial investment and first revenue generated in order to maximize our rate of
return. Since we operate a significant number of the properties in which we
acquire a working interest, we are able to significantly influence the time of a
project's development. We typically initiate new development projects by
simultaneously obtaining the various required components such as the pipeline
and the production platform or subsea well completion equipment. We believe this
strategy, combined with our ability to evaluate and implement a project's
requirements, allows us to efficiently complete the development project and
commence production quickly.
Our Strengths
. Low Acquisition Cost Structure. We believe that our focus on acquiring
properties with minimal cash investment allows us to pursue the
acquisition, development and production of properties that may not be
economically attractive to others. For the three-year period ended
December 31, 2002, our total average finding and development costs
(which do not include future development costs) incurred in the
acquisition and development of our net proved reserves was $1.09 per
Mcfe.
. Technical Expertise and Significant Experience. We have assembled a
technical staff with an average of over 20 years of industry
experience. Our technical staff has specific expertise in the Gulf of
Mexico and North Sea offshore property development, including the
implementation of subsea completion technology.
. Operating Control. As the operator of a property, we are afforded
greater control of the selection of completion and production
equipment, the timing and amount of capital expenditures and the
operating parameters and costs of the project. As of December 31,
2002, we operated 76% of our offshore platforms, all of our subsea
wells and all of our properties under development.
. Employee Ownership. Through employee ownership, we have built a staff
whose business decisions are aligned with the interests of our
shareholders. Our executive officers and directors own approximately
70% of our common stock on a fully diluted basis.
. Inventory of Projects. We have a substantial inventory of properties
to develop in both the Gulf of Mexico and in the North Sea. We
currently have three developments in the U.K. Sector - North Sea one
development at our 2003 acquisition in the Dutch Sector - North Sea
and seven developments in the Gulf of Mexico.
Marketing and Delivery Commitments
We sell our natural gas and oil production under price sensitive or market
price contracts. Our revenues, profitability and future growth depend
substantially on prevailing prices for natural gas and oil. The price received
by us for our non-hedged natural gas and oil production can fluctuate widely.
Changes in the prices of natural gas and oil will affect the carrying value of
our proved reserves as well as our revenues, profitability and cash flow.
Although we are not currently experiencing any significant involuntary
curtailment of our natural gas or oil production, market, economic and
regulatory factors may in the future materially affect our ability to sell our
natural gas or oil production.
7
We sell a portion of our natural gas and oil to end users through various
gas marketing companies. Historically, we have sold our natural gas and oil to a
relatively few number of purchasers. For instance, in 2002, four purchasers
accounted for 88% of our revenues. However, we are not dependent upon, or
confined to, any one purchaser or small group of purchasers. Due to the nature
of natural gas and oil markets and because natural gas and oil are commodities
and there are numerous purchasers in the areas in which we sell production, we
do not believe the loss of a single purchaser, or a few purchasers, would
materially affect our ability to sell our production.
Competition
We compete with major and independent natural gas and oil companies for
property acquisitions. We also compete for the equipment and labor required to
operate and to develop these properties. Some of our competitors have
substantially greater financial and other resources and may be able to sustain
wide fluctuations in the economics of our industry more easily than we can.
Since we are in a highly regulated industry, they may be able to absorb the
burden of any changes in federal, state and local laws and regulations more
easily than we can. Our ability to acquire and develop additional properties in
the future will depend upon our ability to conduct operations, to evaluate and
select suitable properties, to secure adequate financing and to consummate
transactions in this highly competitive environment.
Royalty Relief
In November 2001, we received notification from the U.S. Minerals
Management Service ("MMS") that our application for deepwater royalty relief for
the Garden Banks 409 property had been approved under a federal law that was
enacted in November 1995. The royalty relief provides for the abatement of
federal royalty on the first 52.5 MMBoe of oil and gas production from the
property. The royalty abatement continues in effect for each calendar year,
unless realized prices exceed certain prescribed thresholds. If the prescribed
threshold prices are exceeded during a calendar year, then royalty relief is
suspended and we would be required to pay royalties for that calendar year.
Regulation
Federal Regulation of Sales and Transportation of Natural Gas.
Historically, the transportation and sale for resale of natural gas in
interstate commerce is regulated pursuant to the Natural Gas Act of 1938 ("the
Natural Gas Act"), the Natural Gas Policy Act of 1978 and Federal Energy
Regulatory Commission ("FERC") regulations. In the past, the federal government
has regulated the prices at which natural gas could be sold. Deregulation of
natural gas sales by producers began with the enactment of the Natural Gas
Policy Act of 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol
Act, which removed all remaining Natural Gas Act of 1938 and Natural Gas Policy
Act of 1978 price and non-price controls affecting producer sales of natural gas
effective January 1, 1993.
Our sales of natural gas are affected by the availability, terms and cost
of pipeline transportation. The price and terms for access to pipeline
transportation are subject to extensive federal regulation. Beginning in April
1992, the FERC issued Order No. 636 and a series of related orders, which
required interstate pipelines to provide open-access transportation on a not
unduly discriminatory basis for all natural gas shippers. The FERC stated that
Order No. 636 and the FERC's future restructuring activities are intended to
foster increased competition within all phases of the natural gas industry.
Although the regulations instituted by Order No. 636 do not directly apply to
our production and marketing activities, they do affect how buyers and sellers
gain access to the necessary transportation facilities and how we and our
competitors sell natural gas in the marketplace. The courts have largely
affirmed the significant features of Order No. 636 and the numerous related
orders pertaining to individual pipelines. Subsequent to Order No. 636, the FERC
continued to modify its regulations regarding the transportation of natural gas.
8
In 2000, the FERC issued Order No. 637 and subsequent orders, which we
refer to collectively as "Order No. 637." Order No. 637 imposes a number of
additional reforms designed to enhance competition in natural gas markets. Among
other things, Order No. 637 revised the FERC pricing policy by waiving price
ceilings for short-term released capacity for a two-year period ending September
30, 2002, and effected changes in the FERC regulations relating to scheduling
procedures, capacity segmentation, pipeline penalties, rights of first refusal
("ROFR") and information reporting. Several parties subsequently filed appeals
in the Court of Appeals for the District of Columbia Circuit ("D.C. Circuit")
seeking court review of various aspects of Order 637, particularly (i) the right
of customers to segment their contractual capacity in a manner that allows a
forwardhaul/backhaul to a single point and (ii) the ROFR granted to existing
customers to extend contracts beyond the end of the contract's term. On April 5,
2002, the D.C. Circuit generally affirmed Order No. 637 but remanded certain
issues to FERC, including the forwardhaul/backhaul and ROFR issues. The FERC on
remand affirmed its position on the forwardhaul/backhaul issue but reversed
itself on the ROFR issue. Requests for rehearing of this order are currently
pending at FERC.
Order No. 637 also required interstate natural gas pipelines to
implement the policies mandated by the order through individual compliance
filings. The FERC has now ruled on a number of the individual compliance
filings, although its decisions in such proceedings remain subject to the
outcome of pending rehearing requests and possible court appeals.
In April 1999, the FERC issued Order No. 603, which implemented new
regulations governing the procedure for obtaining authorization to construct and
operate new pipeline facilities or to abandon facilities under Section 7 of the
Natural Gas Act. In September 1999, the FERC issued a related policy statement
establishing a presumption in favor of requiring owners of new pipeline
facilities to charge rates for service on new pipeline facilities based solely
on the costs associated with such new pipeline facilities.
We cannot predict what further action the FERC will take on these or
related matters, nor can we accurately predict whether the FERC's actions will
achieve the goal of increasing competition in markets in which our natural gas
is sold. However, we do not believe that any action taken will affect us in a
way that materially differs from the way it affects other natural gas producers,
gatherers and marketers.
The Outer Continental Shelf Lands Act, which the FERC implements with
regard to transportation and pipeline issues, requires that all pipelines
operating on or across the Outer Continental Shelf provide open-access,
non-discriminatory service. Historically, the FERC has opted not to impose
regulatory requirements under its Outer Continental Shelf Lands Act authority on
gatherers and other entities outside the reach of its Natural Gas Act
jurisdiction. However in April 2000, the FERC issued Order No. 639, requiring
that virtually all non-proprietary pipeline transporters of natural gas on the
Outer Continental Shelf report information on their affiliations, rates and
terms and conditions of service. The reporting requirements established by the
FERC in Order No. 639 may apply, in certain circumstances, to operators of
production platforms and other facilities on the Outer Continental Shelf, with
respect to gas movements across such facilities. Among FERC's stated purposes in
issuing such rules was the desire to increase transparency in the market and to
provide producers and shippers on the Outer Continental Shelf with greater
assurance of (a) open-access services on pipelines located on the Outer
Continental Shelf and (b) non-discriminatory rates and conditions of service on
such pipelines. In January 2002, the U.S. District Court for the District of
Columbia permanently enjoined the FERC from enforcing Order No. 639 and related
orders. FERC's appeal of the district court's decision is currently pending at
the D.C. Circuit.
The FERC retains authority under the Outer Continental Shelf Lands Act to
exercise jurisdiction over gatherers and other entities outside the reach of its
Natural Gas Act jurisdiction if necessary to insure non-discriminatory access to
service on the Outer Continental Shelf. We do not believe that any FERC action
taken under its Outer Continental Shelf Lands Act jurisdiction will affect us in
a way that materially differs from the way it affects other natural gas
producers, gatherers and marketers.
9
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC and the courts. The natural gas
industry historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue.
Federal Leases. A substantial portion of our operations is located on
federal natural gas and oil leases, which are administered by the MMS pursuant
to the Outer Continental Shelf Lands Act. These leases are issued through
competitive bidding and contain relatively standardized terms. These leases
require compliance with detailed MMS regulations and orders that are subject to
interpretation and change by the MMS.
For offshore operations, lessees must obtain MMS approval for exploration,
development and production plans prior to the commencement of such operations.
In addition to permits required from other agencies such as the Coast Guard, the
Army Corps of Engineers and the Environmental Protection Agency, lessees must
obtain a permit from the MMS prior to the commencement of drilling. The MMS has
promulgated regulations requiring offshore production facilities located on the
Outer Continental Shelf to meet stringent engineering and construction
specifications. The MMS also has regulations restricting the flaring or venting
of natural gas, and has proposed to amend such regulations to prohibit the
flaring of liquid hydrocarbons and oil without prior authorization. Similarly,
the MMS has promulgated other regulations governing the plugging and abandonment
of wells located offshore and the installation and removal of all production
facilities.
To cover the various obligations of lessees on the Outer Continental Shelf,
the MMS generally requires that lessees have substantial net worth or post bonds
or other acceptable assurances that such obligations will be satisfied. The cost
of these bonds or assurances can be substantial, and there is no assurance that
they can be obtained in all cases. We currently have several supplemental bonds
in place. Under some circumstances, the MMS may require any of our operations on
federal leases to be suspended or terminated. Any such suspension or termination
could materially adversely affect our financial condition and results of
operations.
The MMS also administers the collection of royalties under the terms of the
Outer Continental Shelf Lands Act and the oil and gas leases issued under the
Act. The amount of royalties due is based upon the terms of the oil and gas
leases as well as of the regulations promulgated by the MMS. The MMS has issued
a final rule that governs the calculation of royalties and the valuation of
crude oil produced from federal leases. This rule amends the way that the MMS
values crude oil produced from federal leases for determining royalties by
eliminating posted prices as a measure of value and relying instead on
arm's-length sales prices and spot market prices as indicators of value. The
lawfulness of the new rule has been challenged at the D.C. Circuit. We cannot
predict whether this new rule will be upheld, nor can we predict whether the MMS
will take further action on this matter. We believe this rule will not have a
material impact on our financial condition, liquidity or results of operations.
Oil Price Controls and Transportation Rates. Sales of crude oil, condensate
and natural gas liquids by us are not currently regulated and are made at market
prices. In a number of instances, however, the ability to transport and sell
such products is dependent on pipelines whose rates, terms and conditions of
service are subject to FERC jurisdiction under the Interstate Commerce Act. In
other instances, the ability to transport and sell such products is dependent on
pipelines whose rates, terms and conditions of service are subject to regulation
by state regulatory bodies under state statutes.
The regulation of pipelines that transport crude oil, condensate and
natural gas liquids is generally more light-handed than the FERC's regulation of
gas pipelines under the Natural Gas Act. Regulated pipelines that transport
crude oil, condensate, and natural gas liquids are subject to common carrier
obligations that generally ensure non-discriminatory access. With respect to
interstate pipeline transportation subject to regulation of the FERC under the
Interstate Commerce Act, rates generally must be cost-based, although
market-based rates or negotiated settlement rates are permitted in certain
circumstances. Pursuant to FERC Order No. 561, issued in October 1993, the FERC
implemented regulations generally grandfathering all previously unchallenged
interstate pipeline rates and made these rates subject to an indexing
methodology. Under this indexing
10
methodology, pipeline rates are subject to changes in the Producer Price Index
for Finished Goods, minus one percent. A pipeline can seek to increase its rates
above index levels provided that the pipeline can establish that there is a
substantial divergence between the actual costs experienced by the pipeline and
the rate resulting from application of the index. A pipeline can seek to charge
market-based rates if it establishes that it lacks significant market power. In
addition, a pipeline can establish rates pursuant to settlement if agreed upon
by all current shippers. A pipeline can seek to establish initial rates for new
services through a cost-of-service proceeding, a market-based rate proceeding,
or through an agreement between the pipeline and at least one shipper not
affiliated with the pipeline. As provided for in Order No. 561, in July 2000,
the FERC issued a Notice of Inquiry seeking comment on whether to retain or to
change the existing oil rate-indexing method. In December 2000, the FERC issued
an order concluding that the rate index reasonably estimated the actual cost
changes in the pipeline industry and should be continued for another 5-year
period, subject to review in July 2005. In February 2003, on remand of its
December 2000 order from the D.C. Circuit, the FERC changed the rate indexing
methodology to the Producer Price Index for Finished Goods, but without the
subtraction of 1% as had been done previously. The FERC made the change
prospective only, but did allow oil pipelines to recalculate their maximum
ceiling rates as though the new rate indexing methodology had been in effect
since July 1, 2001.
With respect to intrastate crude oil, condensate and natural gas liquids
pipelines subject to the jurisdiction of state agencies, such state regulation
is generally less rigorous than the regulation of interstate pipelines. State
agencies have generally not investigated or challenged existing or proposed
rates in the absence of shipper complaints or protests. Complaints or protests
have been infrequent and are usually resolved informally.
We do not believe that the regulatory decisions or activities relating to
interstate or intrastate crude oil, condensate, or natural gas liquids pipelines
will affect us in a way that materially differs from the way it affects other
crude oil, condensate, and natural gas liquids producers or marketers.
Environmental Regulations. Our operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Public interest in the
protection of the environment has increased dramatically in recent years.
Offshore drilling in some areas has been opposed by environmental groups and, in
some areas, has been restricted. To the extent laws are enacted or other
governmental action is taken that prohibits or restricts offshore drilling or
imposes environmental protection requirements that result in increased costs to
the natural gas and oil industry in general and the offshore drilling industry
in particular, our business and prospects could be adversely affected.
The Oil Pollution Act of 1990 and related regulations impose a variety of
regulations on "responsible parties" related to the prevention of oil spills and
liability for damages resulting from such spills in U.S. waters. A "responsible
party" includes the owner or operator of a facility or vessel, or the lessee or
permittee of the area in which an offshore facility is located. The Oil
Pollution Act of 1990 assigns liability to each responsible party for oil
removal costs and a variety of public and private damages. While liability
limits apply in some circumstances, a party cannot take advantage of liability
limits if the spill was caused by gross negligence or willful misconduct or
resulted from violation of a federal safety, construction or operating
regulation. If the party fails to report a spill or to cooperate fully in the
cleanup, liability limits likewise do not apply. Even if applicable, the
liability limits for offshore facilities require the responsible party to pay
all removal costs, plus up to $75.0 million in other damages. Few defenses exist
to the liability imposed by the Oil Pollution Act of 1990.
The Oil Pollution Act of 1990 also requires a responsible party to submit
proof of its financial responsibility to cover environmental cleanup and
restoration costs that could be incurred in connection with an oil spill. As
amended by the Coast Guard Authorization Act of 1996, the Oil Pollution Act of
1990 requires parties responsible for offshore facilities to provide financial
assurance in the amount of $35.0 million to cover potential Oil Pollution Act of
1990 liabilities. This amount can be increased up to $150.0 million if a study
by the MMS indicates that an amount higher than $35.0 million should be
required. On August 11, 1998, the
11
MMS adopted a rule implementing the Oil Pollution Act of 1990 financial
responsibility requirements. We are in compliance with this rule.
In addition, the Outer Continental Shelf Lands Act authorizes regulations
relating to safety and environmental protection applicable to lessees and
permittees operating on the Outer Continental Shelf. Specific design and
operational standards may apply to Outer Continental Shelf vessels, rigs,
platforms and structures. Violations of lease conditions or regulations issued
pursuant to the Outer Continental Shelf Lands Act can result in substantial
civil and criminal penalties, as well as potential court injunctions curtailing
operations and the cancellation of leases. Such enforcement liabilities can
result from either governmental or private prosecution.
The Oil Pollution Act of 1990 also imposes other requirements, such as the
preparation of an oil spill contingency plan. We have such a plan in place. We
are also regulated by the Clean Water Act, which prohibits any discharge into
waters of the U.S. except in strict conformance with discharge permits issued by
federal or state agencies. We have obtained, and are in material compliance
with, the discharge permits necessary for our operations. We are also
subject to similar state and local water quality laws and regulations
for any production or drilling activities that occur in state coastal waters.
Failure to comply with the ongoing requirements of the Clean Water Act or
inadequate cooperation during a spill event may subject a responsible party to
civil or criminal enforcement actions.
The Comprehensive Environmental Response, Compensation, and Liability Act,
or CERCLA, also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on some classes of persons
that are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment. We could be subject to liability under CERCLA because our
drilling and production activities generate relatively small amounts of liquid
and solid wastes that may be subject to classification as hazardous substances
under CERCLA. These wastes must be brought to shore for proper disposal under
the Resource Conservation and Recovery Act. We minimize this potential liability
by selecting reputable contractors to dispose of our wastes at
government-approved landfills or other types of disposal facilities.
Our operations are also subject to regulation of air emissions under the
Clean Air Act and the Outer Continental Shelf Lands Act. Implementation of these
laws could lead to the gradual imposition of new air pollution control
requirements on our operations. Therefore, we may incur capital expenditures
over the next several years to upgrade our air pollution control equipment. We
could also become subject to similar state and local air quality laws and
regulations in the future if we conduct production or drilling activities
instate coastal waters. We do not believe that our operations would be
materially affected by any such requirements, nor do we expect such requirements
to be anymore burdensome to us than to other companies our size involved in
similar natural gas and oil development and production activities.
In addition, legislation has been proposed in Congress from time to time
that would reclassify some natural gas and oil exploration and production wastes
as "hazardous wastes," which would make the reclassified wastes subject to much
more stringent handling, disposal and clean-up requirements. If Congress were to
enact this legislation, it could increase our operating costs, as well as those
of the natural gas and oil industry in general. Initiatives to further regulate
the disposal of natural gas and oil wastes are also pending in some states, and
these various initiatives could have a similar impact on us.
12
Our management believes that we are in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse impact on us.
U.K. Regulation of Natural Gas and Oil Production. Pursuant to the
Petroleum Act 1998, all natural gas and oil reserves contained in properties
located in the U.K. are the property of the U.K. government. The development and
production of natural gas and oil reserves in the U.K. Sector - North Sea
requires a petroleum production license granted by the U.K. government. Prior to
developing a field, we are required to obtain from the Secretary of State for
Trade and Industry (the "Secretary of State") a consent to develop that field.
We would be required to obtain the consent of the Secretary of State prior to
transferring an interest in a license.
The terms of the U.K. petroleum production licenses are based on model
license clauses applicable at the time of the issuance of the license. Licenses
frequently contain regulatory provisions governing matters such as working
method, pollution and training, and reserve to the Secretary of State the power
to direct some of the licensee's activities. For example, a licensee may be
precluded from carrying out development or production activities other than with
the consent of the Secretary of State or in accordance with a development plan
which the Secretary of State for Trade and Industry has approved. Breach of
these requirements may result in the revocation of the license. In addition,
licenses that we acquire may require us to pay fees and royalties on production
and also impose certain other duties on us.
Our operations in the U.K. are subject to the Petroleum Act 1998, which
imposes a health and safety regime on offshore natural gas and oil production
activities. The Petroleum Act 1998 also regulates the abandonment of facilities
by licensees. In addition, the Mineral Workings (Offshore Installations) Act
provides a framework in which the government can impose additional regulations
relating to health and safety. Since its enactment, a number of regulations have
been promulgated relating to offshore construction and operation of offshore
production facilities. Health and safety offshore is further governed by the
Health and Safety at Work Act 1974 and applicable regulations. Our operations
are also subject to environmental laws and regulations imposed by both the
European Union and the U.K. government.
Petroleum production licenses require the prior approval of the Secretary
of State of a licensee to act as operator. The operator under a license
organizes or supervises all or any of the development and production operations
of natural gas and oil properties subject thereto. As an operator, we may obtain
operational services from third parties, but will remain fully responsible for
the operations as if we conduct them ourselves.
Our operations in the U.K. may entail the construction of offshore
pipelines, which are subject to the provisions of the Petroleum Act 1998 and
other legislation. The Petroleum Act 1998 requires a license to construct and
operate a pipeline in U.K. North Sea, including its continental shelf. Easements
to permit the laying of pipelines must be obtained from the Crown Estate
Commissioners prior to their construction. We plan to use capacity in existing
offshore pipelines in order to transport our gas. However, access to the
pipelines of a third party would need to be obtained on a negotiated basis, and
there is no assurance that we can obtain access to existing pipelines or, if
access is obtained, it may only be on terms that are not favorable to us.
The natural gas we produce may be transported through the U.K.'s onshore
national gas transmission system, or NTS. The NTS is owned by a licensed gas
transporter, BG Transco plc ("Transco"). The terms on which Transco must
transport gas are governed by the Gas Acts of 1986 and 1995, the gas
transporter's license issued to Transco under those Acts and a network code. For
us to use the NTS, we must obtain a shipper's license under the Gas Acts and
arrange to have gas transported by Transco within the NTS. We will therefore be
subject to the network code, which imposes obligations to payment, gas flow
nominations, capacity booking and system imbalance. Applying for and complying
with a shipper's license, and acting as a gas shipper, is expensive and
administratively burdensome. Alternatively, we may sell natural gas `at the
beach' before it enters the NTS or arrange with an existing gas shipper for them
to ship the gas through the NTS on our behalf.
13
Employees
At December 31, 2002 we had 39 full-time employees in our Houston office
and seven full-time employees and seven contract personnel in our London office.
None of our employees are covered by a collective bargaining agreement. From
time to time, we use the services of independent consultants and contractors to
perform various professional services, particularly in the areas of
construction, design, well-site supervision, permitting and environmental
assessment. Independent contractors usually perform field and on-site production
operation services for us, including gauging, maintenance, dispatching,
inspection and well testing.
Item 2. Properties
General
We are engaged in the acquisition, development and production of natural
gas and oil properties primarily in the Gulf of Mexico and the North Sea. At
December 31, 2002, we had leasehold and other interests in 50 offshore blocks,
29 platforms and 70 wells, including six subsea wells, in the Gulf of Mexico. We
operate 55 of these 70 wells, including all of the subsea wells, and 76% of our
offshore platforms. We also held interests in seven blocks and one
company-operated subsea well located in the U.K. Sector - North Sea. Our average
working interest in our properties at December 31, 2002 was approximately 82%.
As of December 31, 2002, we had leasehold interests located in the Gulf of
Mexico and the U.K. Sector - North Sea covering approximately 250,000 gross and
196,000 net acres.
Acquisitions and Dispositions
Gulf of Mexico
During 2002, we entered into a farm-in agreement to acquire a 100% working
interest in one block with associated proved reserves of approximately 4.7 Bcf,
based on third party reservoir engineering estimates at year-end. We plan to
develop this block in 2003. In 2003, we entered into an agreement whereby a
third party received a 25% working interest in this block in exchange for paying
a disproportionate share of all costs prior to first production.
In addition, we acquired another block for approximately $1.0 million. This
block, along with the block immediately to the south which we did not acquire,
contains an accumulation of oil and gas. Since the well that identified proved
reserves is located on the southern block and due to the strict limitations to
declare reserves as proved, we are unable to record any proved reserves with
this acquisition.
U.K. Sector - North Sea
In 2001, we acquired interests in three properties (five blocks) in the
North Sea which included a 100% interest in one block ("Helvellyn"), a 50%
interest in one block ("Venture") and an 86% interest in three blocks ("Tors").
Helvellyn. In August 2002 we entered into an agreement, which was completed
on September 30, 2002, whereby we assigned 50% of our working interest in the
Helvellyn development in the U.K. Sector - North Sea to a joint venture partner.
The terms of the agreement required the other party to pay a disproportionate
share of the development costs on the project. The partner's share of
development costs totaled $28.9 million through December 31, 2002, of which
$17.3 million was paid to us in cash, $11.0 million is included in accounts
receivable and $0.6 million is included as a receivable in other long term
assets. We retained a 50% working interest and continued as the operator of the
field.
14
Tors. In February 2002 the U.K. Department of Trade and Industry directly
awarded us a 75% working interest in two lease blocks. The lease sale in the
U.K. is referred to as a "round" and the award is known as an "out of round"
award. We paid no acquisition costs and net proved reserves for these properties
at December 31, 2002, were approximately 20.3 Bcf, based on third party
reservoir engineering estimates at year-end. These two blocks will become a
component of our Tors development. Neither of the properties were producing when
acquired and we expect to pursue development operations in 2004 and 2005.
In October 2002 we entered into an earn-in agreement whereby we assigned an
11% interest in three blocks acquired in 2001 to a joint venture partner in
return for them funding part of the block's development costs. We retained a 75%
working interest and continued as the operator. As of December 31, 2002, these
blocks had not yet been developed.
Dutch Sector - North Sea
In February 2003, we acquired a 50% working interest in a block located in
the Dutch Sector - North Sea. First production is expected some time in 2004.
The remaining 50% interest is owned by a Dutch company who participates on
behalf of the Dutch state. This acquisition expands our offshore development
strategy and presents an extension of substantial opportunities for us.
Natural Gas and Oil Reserves
The following table presents our estimated net proved natural gas and oil
reserves and the net present value of our reserves at December 31, 2002 based on
reserve reports prepared by Ryder Scott Company, L.P. for our domestic reserves
and Troy-Ikoda Limited for our U.K. reserves.
Proved Reserves
-------------------------------------------------
Developed Undeveloped Total
------------- --------------- -----------
Gulf of Mexico
Natural gas (MMcf) .................................... 34,068 68,370 102,438
Oil and condensate (MBbls) ............................ 2,318 3,422 5,740
Total proved reserves (MMcfe) ......................... 47,976 88,903 136,879
U. K. Sector - North Sea
Natural gas (MMcf) .................................... - 93,100 93,100
Total
Natural gas (MMcf) .................................... 34,068 161,470 195,538
Oil and condensate (MBbls) ............................ 2,318 3,422 5,740
Total proved reserves (MMcfe) ......................... 47,976 182,003 229,979
15
Our estimates of proved reserves in the table above do not differ from
those we have filed with other federal agencies. The process of estimating
natural gas and oil reserves is complex. It requires various assumptions,
including assumptions relating to natural gas and oil prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds. We
must project production rates and timing of development expenditures. We analyze
available geological, geophysical, production and engineering data, and the
extent, quality and reliability of this data can vary. Therefore, estimates of
natural gas and oil reserves are inherently imprecise. In accordance with the
Securities and Exchange Commission ("SEC") requirements, we base the estimated
discounted future net cash flows from proved reserves on prices and costs on the
date of the estimate. Actual future prices and costs may differ materially from
those used in the net present value estimate. Actual future production, natural
gas and oil prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable natural gas and oil reserves most likely
will vary from our estimates and these variances may be material.
Our business strategy is to acquire proved reserves, usually proved
undeveloped, and to bring those reserves on production as rapidly as possible.
At December 31, 2002, all of our reserves in the U.K. Sector - North Sea and
approximately 65% of our estimated equivalent net proved reserves in the Gulf of
Mexico were undeveloped. Recovery of undeveloped reserves generally requires
significant capital expenditures and successful drilling and completion
operations. The reserve data assumes that we will make these expenditures.
Although we estimate our reserves and the costs associated with developing them
in accordance with industry standards, the estimated costs may be inaccurate,
development may not occur as scheduled and results may not be as estimated.
Drilling Activity
The following table shows our drilling and completion activity. In the
table, "gross" refers to the total wells in which we have a working interest and
"net" refers to gross wells multiplied by our working interest in such wells. We
did not drill or complete any exploratory wells in any period presented.
Years Ended December 31,
---------------------------------------------------------------
2002 2001 2000
-------------------- -------------------- -------------------
Gross Net Gross Net Gross Net
--------- -------- --------- -------- --------- --------
Development Wells:
Productive - Gulf of Mexico .................. - - 8.0 6.3 12.0 11.0
Nonproductive - Gulf of Mexico ............... - - 1.0 1.0 1.0 1.0
Drilling at end of period - Gulf of Mexico ... 1.0 1.0 - - - -
Drilling at end of period - U.K. North Sea ... 1.0 0.5 - - - -
--------- --------- -------- ------- ------- -------
Total 2.0 1.5 9.0 7.3 13.0 12.0
========= ========= ======== ======= ======= =======
Productive Wells
The following table presents the number of productive natural gas and oil
wells in which we owned an interest as of December 31, 2002.
Natural Gas Wells Oil Wells
--------------------- -----------------
Gross Net Gross Net
--------- --------- -------- ------
Gulf of Mexico ............................................. 30.0 23.8 9.0 4.4
======== ========= ======== ======
Multiple completion wells included above ................... 9.0 7.5 - -
16
Acreage
The following table summarizes our developed and undeveloped acreage
holdings at December 31, 2002. Acreage in which ownership interest is limited to
royalty, overriding royalty and other similar interests is excluded (in acres):
Developed (1) Undeveloped (2) Total
------------------- ------------------ ------------------
Gross Net Gross Net Gross Net
------- -------- -------- ------- ------- --------
Gulf of Mexico .............................. 147,893 118,364 36,177 34,927 184,070 153,291
U.K. Sector - North Sea. .................... - - 66,148 42,524 66,148 42,524
--------- --------- --------- --------- --------- ---------
147,893 118,364 102,325 77,451 250,218 195,815
========= ========= ========= ========= ========= =========
- ------------------
(1) Developed acres are acres spaced or assigned to productive wells.
(2) Undeveloped acres are acres on which wells have not been drilled or
completed to a point that would permit the production of commercial
quantities of natural gas and oil, regardless of whether such acreage
contains proved reserves.
Production and Pricing Data
Information on production and pricing data is contained in Item 7. -
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Results of Operations".
Item 3. Legal Proceedings
On August 28, 2001 ATP entered into a written agreement to acquire a
property in the Gulf of Mexico during September 2001. On October 9, 2001 the
agreement was amended to ultimately extend the closing date until October 31,
2001 in exchange for payments made by ATP totaling $3.0 million. This amendment
also contained an arrangement whereby if ATP did not close on the property, and
if sellers sold the property to a third party with a sale that met specific
contract requirements, ATP would be required to execute a six month note for
payment of the differential. Since ATP did not obtain the financing for the
acquisition by October 31, 2001, the transaction did not close by that date;
however, the parties' intensive work toward closing continued beyond that date
without interruption.
While working on the closing for the property with ATP, the sellers sold
the property to a third party without informing ATP until after the closing had
taken place. ATP filed an action in the District Court of Harris County, Texas
against the sellers, generally alleging improper sale of the offshore property
to a third party and breach of contract, and seeking unspecified damages from
the sellers. The case is encaptioned ATP Oil & Gas Corporation vs. Legacy
Resources Co., L.P. et al, No. 2001-63224 in the 269th Judicial District Court
of Harris County, Texas. At the same time sellers notified ATP of their sale to
a third party, the sellers had a demand made upon ATP for execution of a six
month note for the amount of an alleged differential of approximately $12.3
million plus interest at 16%. Substantiation of the amount and validity of the
demand could not be ascertained based on the content of the demand received. ATP
contested the entire demand. The judge has abated the litigation, until
arbitration pursuant to the underlying agreements between the sellers and ATP is
completed. A tentative date of May 19, 2003 has been scheduled for the
arbitration with an alternative date in September 2003. Due to the inherent
uncertainties involving contested facts and legal issues a prediction as to the
likely outcome cannot be made with any degree of certainty, and we have not
accrued any amount related to this matter. While we are seeking recovery of the
amounts previously paid and discussed above, the $3.0 million has been charged
to earnings along with other costs related to this matter. ATP intends to
vigorously defend against the sellers' claims and forcefully pursue its own
claims in this matter.
In August 2001, Burlington Resources Inc. filed suit against ATP alleging
formation of a contract with ATP and our breach of the alleged contract. The
complaint seeks compensatory damages of approximately $1.1 million. We believe
that this claim is without merit, and we intend to defend it vigorously.
We are also, in the ordinary course of business, a claimant and/or
defendant in various legal proceedings. Management does not believe that the
outcome of these legal proceedings, individually, and in the aggregate will have
a materially adverse effect on our financial condition, results of operations or
cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of security holders during the fourth
quarter of 2002.
17
Executive Officers of the Company
Set forth below are the names, ages (as of March 21, 2003) and titles of
the persons currently serving as executive officers of the Company. All
executive officers hold office until their successors are elected and qualified.
Name Age Position
- ---- --- --------
T. Paul Bulmahn .......................... 59 Chairman and President
Gerald W. Schlief ........................ 55 Senior Vice President
Albert L. Reese, Jr. ..................... 53 Senior Vice President and Chief Financial Officer
Leland E. Tate. .......................... 55 Senior Vice President, Operations
John E. Tschirhart. ...................... 52 Senior Vice President, General Counsel
T. Paul Bulmahn has served as our Chairman and President since he founded
the company in 1991. From 1988 to 1991, Mr. Bulmahn served as President and
Director of Harbert Oil & Gas Corporation. From 1984 to 1988, Mr. Bulmahn served
as Vice President, General Counsel of Plumb Oil Company. From 1978 to 1984, Mr.
Bulmahn served as counsel for Tenneco's interstate gas pipelines and as
regulatory counsel in Washington, D.C. From 1973 to 1978, he served the Railroad
Commission of Texas, the Public Utility Commission and the Interstate Commerce
Commission as an administrative law judge.
Gerald W. Schlief has served as our Senior Vice President since 1993 and is
primarily responsible for acquisitions. Between 1990 and 1993, Mr. Schlief acted
as a consultant for the onshore and offshore independent oil and gas industry.
From 1984 to 1990, Mr. Schlief served as Vice President, Offshore Land for Plumb
Oil Company where he managed the acquisition of interests in over 35 offshore
properties. From 1983 to 1984, Mr. Schlief served as Offshore Land Consultant
for Huffco Petroleum Corporation. He served as Treasurer and Landman for
Huthnance Energy Corporation from 1981 to 1983. In addition, from 1974 to 1978,
Mr. Schlief conducted audits of oil and gas companies for Arthur Andersen & Co.,
and from 1978 to 1981, he conducted audits of oil and gas companies for Spicer &
Oppenheim.
Albert L. Reese, Jr. has served as our Chief Financial Officer since March
1999 and, in a consulting capacity, as our director of finance from 1991 until
March 1999. He was also named Senior Vice President in August 2000. From 1986 to
1991, Mr. Reese was employed with the Harbert Corporation where he established a
registered investment bank for the company to conduct project and corporate
financings for energy, co-generation, and small power activities. From 1979 to
1986, Mr. Reese served as chief financial officer of Plumb Oil Company and its
successor, Harbert Energy Corporation. Prior to 1979, Mr. Reese served in
various capacities with Capital Bank in Houston, the independent accounting firm
of Peat, Marwick & Mitchell, and as a partner in Arnold, Reese & Swenson, a
Houston-based accounting firm specializing in energy clients.
Leland E. Tate has served as our Senior Vice President, Operations, since
August 2000. Prior to joining ATP, Mr. Tate worked for over 30 years with
Atlantic Richfield Company ("ARCO"). From 1998 until July 2000, Mr. Tate served
as the President of ARCO North Africa. He also was Director General of Joint
Ventures at ARCO from 1996 to 1998. From 1994 to 1996, Mr. Tate served as ARCO's
Vice President Operations & Engineering, where he led technical negotiations in
field development. Prior to 1994, Mr. Tate's positions with ARCO included
Director of Operations, ARCO British Ltd.; Vice President of Engineering, ARCO
International; Senior Vice President Marketing and Operations, ARCO Indonesia;
and for three years was Vice President and District Manager in Lafayette,
Louisiana.
John E. Tschirhart joined us in November 1997 and has served as our General
Counsel since March 1998. Mr. Tschirhart was named Senior Vice President in July
2001 and served as Managing Director of ATP Oil & Gas (UK) Limited from May 2000
to May 2001. From 1993 to November 1997, Mr. Tschirhart worked as a partner at
the law firm of Tschirhart and Daines, a partnership in Houston, Texas. From
1985 to 1993 Mr. Tschirhart was in private practice handling civil litigation
matters including oil and gas and employment law. From 1979 to 1985, he was with
Coastal Oil & Gas Corporation and from 1974 to 1979 he was with Shell Oil
Company.
18
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Our authorized capital stock consists of 100,000,000 shares of common
stock, par value $0.001 per share, and 10,000,000 shares of preferred stock, par
value $0.001 per share. There were 20,338,753 shares of common stock and no
shares of preferred stock outstanding as of March 21, 2003. There were 61
holders of record of our common stock as of March 21, 2003. Our common stock is
traded on the Nasdaq National Market under the ticker symbol ATPG. There was no
public market for our common stock before February 6, 2001.
The following tables sets forth the range of high and low closing sales
prices for the common stock as reported on the Nasdaq National Market for the
periods indicated below:
High Low
---------- -----------
2002:
-----
4th Quarter $ 4.49 $ 2.78
3rd Quarter 3.40 2.51
2nd Quarter 4.77 2.50
1st Quarter 5.00 1.47
2001:
-----
4th Quarter $ 7.15 $ 2.00
3rd Quarter 12.00 6.61
2nd Quarter 12.96 8.71
1st Quarter 14.56 9.88
We have never declared or paid any cash dividends on our common stock. We
currently intend to retain future earnings and other cash resources, if any, for
the operation and development of our business and do not anticipate paying any
cash dividends on our common stock in the foreseeable future. Payment of any
future dividends will be at the discretion of our board of directors after
taking into account many factors, including our financial condition, operating
results, current and anticipated cash needs and plans for expansion. In
addition, our current credit facility prohibits us from paying cash dividends on
our common stock. Any future dividends may also be restricted by any loan
agreements which we may enter into from time to time.
Securities Authorized for Issuance under Equity Compensation Plans
The following table includes information regarding our equity compensation
plans as of the year ended December 31, 2002:
Number of
securities Weighted Number of
to be issued average securities remaining
upon exercise exercise price available for future
of outstanding of outstanding issuance under equity
Plan Category options options compensation plans
- ------------------------------------------- ---------------- --------------- ----------------------
Equity compensation plans
approved by security holders 1,685,147 $ 8.29 4,647,569
Equity compensation plans
not approved by security holders - - -
---------------- ----------------------
1,685,147 $ 8.29 4,647,569
================ ======================
19
Item 6. Selected Financial Data
(In thousands, except per share data)
The selected historical financial information was derived from, and is
qualified by reference to our consolidated financial statements, including the
notes thereto, appearing elsewhere in this report. The following data should be
read in conjunction with "Item 7. - Management's Discussion and Analysis of
Financial Condition and Results of Operations".
Years Ended December 31,
-------------------------------------------------------------------
2002 2001 2000 1999 1998
----------- ----------- ----------- ----------- -----------
Statement of Operations Data:
Revenues:
Oil and gas production ............................ $ 88,151 $ 105,757 $ 75,940 $ 34,981 $ 20,410
Gas sold - marketing .............................. 6,272 7,417 8,015 7,703 -
Gain on sale of oil and gas properties ............ - - 33 287 -
----------- ----------- ----------- ----------- -----------
Total revenues .................................. 94,423 113,174 83,988 42,971 20,410
----------- ----------- ----------- ----------- -----------
Cost and operating expenses:
Lease operating ................................... 16,764 14,806 11,559 5,587 3,193
Gas purchased - marketing ......................... 6,087 7,218 7,788 7,402 -
Geological and geophysical expenses ............... 154 1,068 - - -
General and administrative ....................... 10,287 9,981 5,409 3,541 2,591
Non-cash compensation expense
(general and administrative) .................... 595 3,364 - - -
Depreciation, depletion and amortization .......... 43,390 53,428 40,569 22,521 17,442
Impairment of oil and gas properties .............. 6,844 24,891 10,838 7,509 5,072
Loss on unsuccessful property acquisition ......... - 3,147 - - -
Other expense ..................................... - - 450 - -
----------- ----------- ----------- ----------- -----------
Total operating expenses .......................... 84,121 117,903 76,613 46,560 28,298
----------- ----------- ----------- ----------- -----------
Income (loss) from operations ........................ 10,302 (4,729) 7,375 (3,589) (7,888)
Other income (expense):
Interest income ................................... 73 884 451 202 141
Interest expense .................................. (10,418) (10,039) (11,907) (9,399) (7,963)
Other income ...................................... 1,081 - - - -
Realized loss on derivative instruments ........... (153) (19,348) (4,662) - -
Unrealized gain (loss) on derivative instruments... (8,166) 1,265 (7,249) - -
----------- ----------- ----------- ----------- -----------
Loss before income taxes and
extraordinary item ................................ (7,281) (31,967) (15,992) (12,786) (15,710)
Income tax benefit-deferred ....................... 2,581 11,186 5,594 1,829 -
----------- ----------- ----------- ----------- -----------
Loss before extraordinary item ....................... (4,700) (20,781) (10,398) (10,957) (15,710)
Extraordinary item, net of tax ....................... - (602) - 29,185 -
----------- ----------- ----------- ----------- -----------
Net income (loss) .................................... $ (4,700) $ (21,383) $ (10,398) $ 18,228 $ (15,710)
=========== =========== =========== =========== ===========
Weighted average number of common
shares outstanding - basic and diluted ............ 20,315 19,704 14,286 14,286 11,926
Loss per common share before extraordinary
item - basic and diluted .......................... $ (0.23) $ (1.06) $ (0.73) $ (0.77) $ (1.32)
Net income (loss) per common share:
Basic and diluted ............................... $ (0.23) $ (1.09) $ (0.73) $ 1.28 $ (1.32)
Balance Sheet Data:
Cash and cash equivalents ............................ $ 6,944 $ 5,294 $ 18,136 $ 17,779 $ 3,411
Working capital ...................................... (13,699) (29,071) (3,835) 14,115 (5,106)
Net oil and gas properties ........................... 119,036 133,033 98,725 72,278 47,612
Total assets ......................................... 182,055 177,564 161,993 107,054 61,354
Total debt ........................................... 86,387 100,111 116,529 91,723 62,690
Total liabilities .................................... 143,508 132,572 175,172 109,835 82,363
Shareholders' equity (deficit) ....................... 38,547 44,992 (13,179) (2,781) (21,009)
20
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Overview
We are engaged in the acquisition, development and production of natural
gas and oil properties in the Gulf of Mexico and in the North Sea. We primarily
focus our efforts on natural gas and oil properties with proved undeveloped
reserves that are economically attractive to us but are not strategic to major
or exploration-oriented independent oil and gas companies. We attempt to achieve
a high return on our investment in these properties by limiting our up-front
acquisition costs and by developing our acquisitions quickly.
Critical Accounting Policies and Estimates
Our consolidated financial statements are prepared in conformity with
accounting principles generally accepted in the U.S., which require management
to make estimates and assumptions that affect the reported amounts of the assets
and liabilities and disclosures of contingent assets and liabilities as of the
date of the balance sheet as well as the reported amounts of revenues and
expenses during the reporting period. We routinely make estimates and judgments
about the carrying value of our assets and liabilities that are not readily
apparent from other sources. Such estimates and judgments are evaluated and
modified as necessary on an ongoing basis. We believe that of our significant
accounting policies (see Note 2, Summary of Significant Accounting Policies and
Estimates, to our Consolidated Financial Statements), the following may involve
a higher degree of judgment and complexity.
Oil and Gas Reserves
The process of estimating quantities of natural gas and crude oil reserves
is very complex, requiring significant decisions in the evaluation of all
available geological, geophysical, engineering and economic data. The data for a
given field may also change substantially over time as a result of numerous
factors including, but not limited to, additional development activity, evolving
production history and continual reassessment of the viability of production
under varying economic conditions. As a result, material revisions to existing
reserve estimates may occur from time to time. Although every reasonable effort
is made to ensure that reserve estimates reported represent the most accurate
assessments possible, the subjective decisions and variances in available data
for various fields make these estimates generally less precise than other
estimates included in the financial statement disclosures. We use the
units-of-production method to amortize our oil and gas properties. This method
requires us to amortize the capitalized costs incurred in developing a property
in proportion to the amount of oil and gas produced as a percentage of the
amount of proved reserves contained in the property. Accordingly, changes in
reserve estimates as described above will cause corresponding changes in
depletion expense recognized in periods subsequent to the reserve estimate
revision. See the Supplemental Information (unaudited) in our consolidated
financial statements for reserve data related to our properties.
Oil and Gas Producing Activities
We follow the "successful efforts" method of accounting for oil and gas
properties. Under this method, lease acquisition costs and intangible drilling
and development costs on successful wells and development dry holes are
capitalized.
Capitalized costs relating to producing properties are depleted on the
units-of-production method. Proved developed reserves are used in computing unit
rates for drilling and development costs and total proved reserves for depletion
rates of leasehold, platform and pipeline costs. Estimated dismantlement,
restoration and abandonment costs and estimated residual salvage values are
taken into account in determining amortization and depletion provisions.
Expenditures for geological and geophysical testing are generally charged
to expense unless the costs can be specifically attributed to determining the
placement for a future developmental well location.
21
Expenditures for repairs and maintenance are charged to expense as incurred;
renewals and betterments are capitalized. The costs and related accumulated
depreciation, depletion, and amortization of properties sold or otherwise
retired are eliminated from the accounts, and gains or losses on disposition are
reflected in the statements of operations.
We perform an impairment analysis whenever events or changes in
circumstances indicate that an asset's carrying amount may not be recoverable.
An impairment allowance is provided on an unproved property when we determine
that the property will not be developed. To determine if a depletable unit is
impaired, we compare the net carrying value of the depletable unit to the
undiscounted future net cash flows by applying management's estimates of future
oil and gas prices to the estimated future production of oil and gas reserves
over the economic life of the property. Future net cash flows are based upon our
independent reservoir engineer's estimate of proved reserves. In addition, other
factors such as probable and possible reserves are taken into consideration when
justified by economic conditions and actual or planned drilling or other
development activities. For a property determined to be impaired, an impairment
loss equal to the difference between the carrying value and the estimated fair
value of the impaired property will be recognized. Fair value, on a depletable
unit basis, is estimated to be the present value of the aforementioned expected
future net cash flows. Any impairment charge incurred is recorded in accumulated
depreciation, depletion, impairment and amortization to reduce our recorded
basis in the asset. Each part of this calculation is subject to a large degree
of judgment, including the determination of the depletable units' estimated
reserves, future cash flows and fair value.
Contingent Liabilities
In preparing financial statements at any point in time, management is
periodically faced with uncertainties, the outcomes of which are not within its
control and will not be known for prolonged periods of time. As discussed in
Part I, Item 3. - "Legal Proceedings" and the Notes to Consolidated Financial
Statements, we are involved in actions, which if determined adversely, could
have a material negative impact on our financial position, results of operations
and cash flows. Management, with the assistance of counsel makes estimates, if
determinable, of ATP's probable liabilities and records such amounts in the
consolidated financial statements. Such estimates may be the minimum amount of a
range of probable loss when no single best estimate is determinable. Disclosure
is made, when determinable, of any additional possible amount of loss on these
claims, or if such estimate cannot be made, that fact is disclosed. Along with
our counsel, we monitor developments related to these legal matters and, when
appropriate, we make adjustments to recorded liabilities to reflect current
facts and circumstances. Although it is difficult to predict the ultimate
outcome of these matters, management believes that the recorded amounts, if any,
are reasonable.
Price Risk Management Activities
As of July 1, 2002, we performed the requisite steps to qualify our
derivative instruments for hedge accounting treatment under the provisions of
Financial Accounting Standards Board ("FASB") Statement of Financial Accounting
Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133"), as amended. Under SFAS 133 all derivative instruments
are recorded on the balance sheet at fair value. Changes in the derivative's
fair value are recognized currently in earnings unless specific hedge accounting
criteria are met. For qualifying cash flow hedges, the gain or loss on the
derivative is deferred in accumulated other comprehensive income (loss) to the
extent the hedge is effective. For qualifying fair value hedges, the gain or
loss on the derivative is offset by related results of the hedged item in the
statement of operations. Gains and losses on hedging instruments included in
accumulated other comprehensive income (loss) are reclassified to oil and gas
revenues in the period that the related production is delivered. Derivative
contracts that do not qualify for hedge accounting treatment are recorded as
derivative assets and liabilities at market value in the consolidated balance
sheet, and the associated unrealized gains and losses are recorded as current
expense or income in the consolidated statement of operations. Prior to July 1,
2002, gains or losses from our derivative instruments were included in other
income (expense).
22
Based on a critical assessment of our accounting policies and the
underlying judgments and uncertainties affecting the application of those
policies, management believes that our consolidated financial statements provide
a meaningful and fair perspective of our company.
Results of Operations
The following table sets forth selected financial and operating information
for our natural gas and oil operations inclusive of the effects of price risk
management activities:
Years Ended December 31,
------------------------------------------------
2002 2001 2000
------------- ------------- -------------
Production:
Natural gas (MMcf) .................................... 17,732 20,957 22,410
Oil and condensate (MBbls) ............................ 1,454 790 345
------------- ------------- -------------
Total (MMcfe) ...................................... 26,457 25,696 24,477
============= ============= =============
Revenues (in thousands):
Natural gas ........................................... $ 56,659 $ 88,908 $ 94,051
Effects of risk management activities (1) ............. (2,764) (19,751) (26,729)
------------- ------------- -------------
Total .............................................. $ 53,895 $ 69,157 $ 67,322
============= ============= =============
Oil and condensate .................................... $ 32,756 $ 16,849 $ 10,112
Effects of risk management activities (1).............. (615) - (1,494)
------------- ------------- -------------
Total .............................................. $ 32,141 $ 16,849 $ 8,618
============= ============= =============
Natural gas, oil and condensate ....................... $ 89,415 $ 105,757 $ 104,163
Effects of risk management activities (1).............. (3,379) (19,751) (28,223)
------------- ------------- -------------
Total .............................................. $ 86,036 $ 86,006 $ 75,940
============= ============= =============
Average sales price per unit:
Natural gas (per Mcf) ................................. $ 3.20 $ 4.24 $ 4.20
Effects of risk management activities (per Mcf) ....... (0.16) (0.94) (1.19)
------------- ------------- -------------
Total (per Mcf) .................................... $ 3.04 $ 3.30 $ 3.01
============= ============= =============
Oil and condensate (per Bbl) .......................... $ 22.53 $ 21.33 $ 29.35
Effects of risk management activities (per Mcf) ....... (0.42) - (4.34)
------------- ------------- -------------
Total (per Bbl) .................................... $ 22.11 $ 21.33 $ 25.01
============= ============= =============
Natural gas, oil and condensate (per Mcfe) ............ $ 3.38 $ 4.12 $ 4.26
Effects of risk management activities (per Mcfe) ...... (0.13) (0.77) (1.16)
------------- ------------- -------------
Total (per Mcfe) ................................... $ 3.25 $ 3.35 $ 3.10
============= ============= =============
Expenses (per Mcfe):
Lease operating ....................................... $ 0.63 $ 0.58 $ 0.47
General and administrative ............................ 0.39 0.39 0.22
Depreciation, depletion and amortization .............. 1.64 2.08 1.66
- ----------------
(1) Represents the net loss on the settlement of derivatives attributable
to actual production.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
For the year ended December 31, 2002, we reported a net loss of $4.7
million, or $0.23 per share as compared to a net loss of $21.4 million, or $1.09
per share in 2001.
Oil and Gas Revenue. Excluding the effects of settled derivatives, our
revenue from natural gas and oil production for 2002 decreased 16% compared to
2001, from $105.8 million to $89.4 million. This decrease was primarily due to
an approximate 18% decrease in our average sales price per Mcfe from $4.12 per
Mcfe in 2001 to $3.38 in 2002. This decrease was partially offset by a 3%
increase in production volumes from 25.7 Bcfe to 26.5 Bcfe due primarily to two
properties that were completed and began production in 2002. Additionally, one
property was completed in September 2001 but did not contribute a full year of
production until 2002.
23
Early in the fourth quarter, we were forced to shut-in a majority of our
Gulf of Mexico production when Hurricane Lili, a Category 4 storm, blew through
the central Gulf. Our current production continues to be hampered by the damage
wrought by Hurricane Lili and we estimated a fourth-quarter impact of
approximately 1.0 Bcfe. We carry insurance, subject to normal
deductibles, that covers both the physical damage and loss of production income,
which will partially mitigate the financial impact of this hurricane.
Marketing Revenue. Revenues from natural gas marketing activities decreased
to $6.3 million in 2002 as compared to $7.4 million in 2001. This decrease was
due to a decrease in the sales price per MMBtu. The average sales price per
MMBtu decreased from $4.06 in 2001 to $3.44 in 2002. For more information
regarding this marketing activity, see Note 13 to the Consolidated Financial
Statements.
Lease Operating Expense. Our lease operating expense for 2002 increased 13%
from $14.8 million ($0.58 per Mcfe) to $16.8 million ($0.63 per Mcfe). This
increase was primarily the result of an increase in the number of producing
wells we own and an increase in their total production volume. Lease operating
expense per Mcfe increased due to higher than expected repairs and maintenance
costs on our platforms and costs incurred related to the hurricane and tropical
storm.
Gas Purchased-Marketing. Our cost of purchased gas was $6.1 million for
2002 compared to $7.2 million for 2001. The average gas cost decreased from
$3.96 per MMBtu in 2001 to $3.34 per MMBtu in 2002. For more information
regarding this marketing activity, see Note 13 to the Consolidated Financial
Statements.
Geological and Geophysical. In 2002, we recorded approximately $0.2 million
of costs related to the acquisition of 3-D seismic data purchased for certain
properties in the U.K Sector - North Sea. In 2001, we recorded $1.1 million of
these same costs on properties in both the Gulf of Mexico and the U.K Sector -
North Sea.
General and Administrative Expense. General and administrative expense
increased to $10.3 million for 2002 compared to $10.0 million for 2001. The
primary reason for the increase was the result of higher compensation related
costs in 2002 which was substantially offset by a bad debt allowance recorded in
2001.
Non-Cash Compensation Expense. In 2002, we recorded a non-cash charge to
compensation expense of approximately $0.6 million for options granted since
September 1999 through the date of our initial public offering ("IPO") on
February 5, 2001 (the "measurement date"). The total expected expense as of the
measurement date is recognized in the periods in which the option vests. Each
option is divided into three equal portions corresponding to the three vesting
dates (April 10, 2001, February 9, 2002, and February 9, 2003), with the related
compensation cost for each portion amortized straight-line over the period to
the vesting date. In 2001, we recorded a non-cash compensation expense of $2.9
million for the above options and an additional non-cash compensation expense of
$0.5 million related to certain options granted prior to September 1999 and
exercised during 2001. The additional expense was recorded as a result of the
manner in which those shares were exercised.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense ("DD&A") decreased 19% from $53.4 million in 2001 to
$43.4 million in 2002. The average DD&A rate was $1.64 per Mcfe during 2002
compared to $2.08 per Mcfe during 2001. This decrease in the rate was
attributable to (1) impairments taken in 2001, (2) higher than expected costs of
an abandonment completed in 2001 and (3) a new property brought on line in 2002
with a lower average DD&A rate than those properties producing in 2001.
24
Impairment Expense. On two of our properties in 2002 and eight of our
properties in 2001, the future undiscounted cash flows were less than their
individual net book value. As a result, we recorded impairments of $6.8 million
in 2002 and $24.9 million in 2001. The impairments in 2002 were primarily the
result of reductions in recoverable reserves. The impairments in 2001 were
primarily the result of drilling a non-commercial development well ($8.3
million), a decrease in expected future gas prices and reductions in recoverable
reserves. The impairments were calculated as the difference between the carrying
value and the estimated fair value of the impaired depletable unit.
Other Income (Expense). Effective July 1, 2002, we qualified for hedge
accounting treatment under the provisions of SFAS 133 and began recording any
gains or losses on settled derivative instruments as a component of oil and gas
revenue. The effective portion of any changes in the fair market value of open
positions at the end of the period is recorded in other comprehensive income
(loss). The loss on derivative instruments of $8.3 million in 2002 represents
amounts recorded prior to July 1, 2002 and is comprised of a realized loss of
$0.1 million for derivative contracts settled in the first half of 2002 and an
unrealized loss of $8.2 million representing the change in fair market value of
the open derivative positions at June 30, 2002. In 2001, we recorded a loss on
derivative instruments of $18.1 million. The net loss in 2001 was comprised of a
realized loss of $19.3 million for derivative contracts settled in the period
and an unrealized gain of $1.2 million representing the change in fair market
value of the open derivative positions at December 31, 2001.
Interest expense increased by $0.4 million over 2001 due to amounts owed on
a long-term contract with a third party and we capitalized $0.3 million of
interest for the year ended December 31, 2002 related to one property in the
U.K. Sector - North Sea.
Other income includes $0.6 million of accrued insurance proceeds related to
the loss of production from Hurricane Lili in October 2002 and the forgiveness
of interest of $0.4 million related to amounts owed on a long-term contract with
a third party. We filed an insurance claim during the fourth quarter of 2002
covering the estimated damages and lost production from the Gulf of Mexico
region resulting from the effects of Hurricane Lili in October 2002. Our
financial statements reflect probable amounts recoverable, net of deductibles,
of approximately $1.5 million for damages to ten properties and lost production
on four properties through December 31, 2002. The total claim will be determined
when the final documentation is received and approved and any remaining payment
related to 2003 will be recorded when we have a firm settlement commitment from
the insurance company.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
For the year ended December 31, 2001, we reported a net loss of $21.4
million, or $1.09 per share as compared to a net loss of $10.4 million, or $0.73
per share in 2000.
Oil and Gas Revenue. Excluding the effects of settled derivatives, our
revenue from natural gas and oil production for 2001 increased 2% over 2000,
from $104.2 million to $105.8 million. This increase resulted from a slight
increase in the price of natural gas and a 5% increase in production, partially
offset by a 27% decrease in the price of oil. The increase in production volumes
from 24.4 Bcfe to 25.7 Bcfe was attributable to 13 properties that were on
production during 2001 that were not on production during 2000. This increase in
production was offset by the natural decline in our existing offshore
properties. Risk management activities, which were included in oil and gas
revenues in 2000 would have decreased oil and natural gas revenues by $24.4
million, or $0.95 per Mcfe in 2001 and decreased $28.2 million, or $1.16 per
Mcfe in 2000.
Marketing Revenue. Revenues from natural gas marketing activities decreased
to $7.4 million in 2001 as compared to $8.0 million in 2000. This decrease was
due to a decrease in the sales price per MMBtu. The average sales price per
MMBtu decreased from $4.38 in 2000 to $4.06 in 2001. For more information
regarding this marketing activity, see Note 13 to the Consolidated Financial
Statements.
25
Lease Operating Expense. Our lease operating expense for 2001 increased 28%
from $11.6 million to $14.8 million. This increase was primarily the result of
an increase in the number of producing wells we own and an increase in their
total production volume. Additionally, the lease operating expense per Mcfe on
those properties acquired in 2001 was higher due to cost structures and contract
obligations in place at the time of acquisition. Transportation related costs
increased ($0.6 million) and workover spending decreased ($0.9 million) as
compared to 2000.
Gas Purchased-Marketing. Our cost of purchased gas was $7.2 million for
2001 compared to $7.8 million for 2000. The average gas cost decreased from
$4.26 per MMBtu in 2000 to $3.96 per MMBtu in 2001. For more information
regarding this marketing activity, see Note 13 to the Consolidated Financial
Statements.
Geological and Geophysical. In 2001, we recorded $1.1 million of costs
related to the acquisition of 3-D seismic data purchased for certain properties
in the Gulf of Mexico and the U.K. Sector - North Sea.
General and Administrative Expense. General and administrative expense
increased to $10.0 million for 2001 compared to $5.4 million for 2000. The
primary reason for the increase was the result of compensation and related
expenses due to an increase in the number of employees in our Houston office
from 28 at the end of 2000 to 39 at the end of 2001 ($0.9 million) and the
opening of our U.K. office in the third quarter of 2000 ($1.7 million). As a
result of becoming a public company in 2001, we incurred costs such as
insurance, filing fees, professional fees, investor relations expenses and other
expenses related to public company requirements ($1.3 million).
Non-Cash Compensation Expense. In 2001, we recorded a non-cash compensation
expense of $3.4 million. A portion of the expense ($2.9 million) is related to
options granted from September 1999 to the date of our IPO and is based on the
difference between the exercise price for those options and the fair market
value of our stock as determined by the IPO price of $14.00 per share. The
expense is recognized in the periods in which the options vest. Each option is
divided into three equal portions corresponding to the three vesting dates, with
the related compensation cost amortized straight-line over the period between
the IPO date and the vesting date. The remaining expense ($0.5 million) was
related to certain options granted prior to September 1999 and exercised in the
current year. The expense was recorded on those exercises as the method in which
those shares were exercised required us to account for the options under
variable accounting.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense increased 32% from $40.6 million in 2000 to $53.4
million in 2001. The average DD&A rate was $2.08 per Mcfe during 2001 compared
to $1.66 per Mcfe during 2000.
Impairment Expense. As of December 31, 2001, the future undiscounted cash
flows for our properties were $354.2 million and the net book value for the
properties was $157.9 million before current year impairment expense. At
December 31, 2000, the future undiscounted cash flows for our properties were
$931.2 million and the net book value for the properties was $109.6 million
before current year impairment expense. However, on eight of our properties in
2001 and three of our properties in 2000, the future undiscounted cash flows
were less than their individual net book value. As a result, we recorded
impairments of $24.9 million in 2001 and $10.8 million in 2000. The impairments
in 2001 were primarily the result of drilling a non-commercial development well
at our Main Pass 282 property ($8.3 million), a decrease in expected future gas
prices and reductions in recoverable reserves. In 2000, the impairments were
primarily the result of a reduction in recoverable reserves individually
attributable to the particular properties.
Other Income (Expense). In 2001, we recorded a loss on derivative
instruments of $18.1 million comprised of a realized loss of $19.3 million and
an unrealized gain of $1.2 million. The realized loss represents derivative
contracts settled in 2001, while the offsetting gain represents the fair market
value of the open derivative positions at December 31, 2001. Prior to the
adoption of SFAS 133, realized gains or losses
26
were recorded as a component of revenue. For 2000 we recorded an expense of $4.3
million ($1.7 million realized and $2.6 million unrealized) on a natural gas
derivative position as a result of our hedging position exceeding our expected
production in an upcoming period. In addition, we recorded an expense of $7.6
million ($3.0 million realized and $4.6 million unrealized) related to losses
associated with our written call option contracts. In both of these situations
in 2000, we were required to account for the positions using the mark-to-market
method.
Interest expense decreased from $11.9 million in 2000 to $10.0 million in
2001 primarily due to lower debt levels following the use of proceeds from our
IPO and as a result of lower interest rates. We capitalized zero and $0.7
million of interest for the years ended December 31, 2001 and 2000,
respectively.
Liquidity and Capital Resources
General
We have financed our acquisition and development activities through a
combination of project-based development arrangements, bank borrowings and
proceeds from our February 2001 IPO, as well as cash from operations and the
sale on a promoted basis of interests in selected properties. We intend to
finance our near-term development projects in the Gulf of Mexico and North Sea
through available cash flows and the potential sell down of interests in the
development projects. As operator of all of our projects in development, we have
the ability to significantly control the timing of most of our capital
expenditures. We believe the cash flows from operating activities combined with
our ability to control the timing of substantially all of our future development
and acquisition requirements will provide us with the flexibility and liquidity
to meet our future planned capital requirements.
However, future cash flows are subject to a number of variables including
changes in the borrowing base, the level of production from our properties, oil
and natural gas prices and the impact, if any, of commitments and contingencies.
Future borrowings under credit facilities are subject to variables including the
lenders' practices and policies, changes in the prices of oil and natural gas
and changes in our oil and gas reserves. A material reduction in the borrowing
base or the institution of a monthly reduction amount by our lenders would have
a material negative impact on our cash flows and our ability to fund future
obligations. No assurance can be given that operations and other capital
resources will provide cash in sufficient amounts to maintain planned levels of
operations and capital expenditures. Historically, in periods of reduced
availability of funds from either cash flows or credit sources we have delayed
planned capital expenditures and will continue do to so when necessary. While
the delay decreases the amount of capital expenditures in the current period, it
could negatively impact our future revenues and cash flows.
Cash Flows
Years Ended December 31,
------------------------------------
2002 2001 2000
---------- ---------- ----------
(in thousands)
Cash provided by (used in):
Operating activities ......... $ 51,298 $ 41,356 $ 57,157
Investing activities ......... (35,167) (110,810) (76,835)
Financing activities ......... (14,481) 56,612 20,035
Operating activities. Net cash provided by operating activities in 2002 was
$51.3 million compared to $41.4 million in 2001. The change in accounts payable
reflects the primary reason for this increase as we utilized a substantial
portion of our operating cash flow in 2001 to reduce amounts owed to third
parties. This increase was partially offset by an 18% decrease in our average
sales price per Mcfe. Restricted cash of $0.4 million represents funds set aside
to satisfy payment conditions in our drilling contract for development in the
U.K.
27
Investing activities. Cash used in investing activities decreased in 2002
to $35.2 million of which $34.9 was for acquisition and development activities.
We incurred no costs for two acquisitions made in 2002 and approximately $1.0
million for the acquisition of an undeveloped block in the Gulf of Mexico.
Developmental capital expenditures in the Gulf of Mexico and the North Sea were
approximately $17.5 million and $16.4 million, respectively. In 2001, capital
expenditures for acquisition and development were $25.9 million and $78.8
million, respectively, and $5.6 million was used to purchase the overriding
royalty interests associated with the repayment of our non-recourse debt.
Financing activities. Cash used in financing activities in 2002 represents
net principal payments on our credit facility. Cash provided from financing
activities in 2001 included the proceeds from our initial public offering in
February 2001 of $78.3 million, repayment of prior credit facilities of $119.9
million and proceeds of $100.0 million from our credit facility and promissory
note.
Amounts borrowed under our credit agreements were as follows for the dates
indicated (in thousands):
December 31,
------------------------
2002 2001
---------- -----------
Credit facility .................................................... $ 56,000 $ 70,000
Note payable, net of unamortized discount of $863 and $1,139 ....... 30,387 30,111
---------- -----------
Total debt ....................................................... $ 86,387 $ 100,111
========== ===========
Credit Facility
We have a $100.0 million senior-secured revolving credit facility which is
secured by substantially all of our U.S. oil and gas properties, as well as by
approximately two-thirds of the capital stock of our foreign subsidiaries and is
guaranteed by our wholly owned subsidiary, ATP Energy, Inc. The amount available
for borrowing under the credit facility is limited to the loan value, as
determined by the bank, of oil and gas properties pledged under the facility. At
December 31, 2002, the borrowing base was $56.0 million with no further
scheduled borrowing base reduction. If our outstanding balance exceeds our
borrowing base at any time, we are required to repay such excess within 30 days
and our interest rate during the time an excess exists is increased by 2.00%.
On March 25, 2003, we entered into an agreement with our lenders to defer
our scheduled borrowing base redetermination until the next scheduled
redetermination in May 2003. This agreement reaffirmed the current borrowing
base of $56.0 million and the borrowing base reduction amount of zero. As part
of this agreement we committed to reduce the amount outstanding under our
borrowing base by $6.0 million between March 28, 2003 and May 31, 2003.
Additionally, if the aggregate principal amount of the loan exceeds the required
month-end reductions of $1.5 million, $2.5 million and $2.0 million during
the period from March 28, 2003 to May 31, 2003, such principal amounts in excess
of the applicable period limits shall bear interest at a per annum rate of
interest equal to the adjusted reference rate plus 2%. Further, the lenders
agreed to raise the limit of advances available to be made to our foreign
subsidiaries and specified certain future events which would require our foreign
subsidiaries to return the incremental advances to the parent. On March 28,
2003, we made a payment of $1.5 million reducing our outstanding principal to
$54.5 million. At the next scheduled redetermination in May 2003, the lenders
can increase or decrease the borrowing base and re-establish the monthly
reduction amount. A material reduction in the borrowing base or a material
increase in the monthly reduction amount by the lender would have a material
negative impact on our cash flows and our ability to fund future operations.
Advances under the credit facility can be in the form of either base rate
loans or Eurodollar loans. The interest on a base rate loan is a fluctuating
rate equal