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<SEC-DOCUMENT>0000899243-01-000854.txt : 20010410
<SEC-HEADER>0000899243-01-000854.hdr.sgml : 20010410
ACCESSION NUMBER: 0000899243-01-000854
CONFORMED SUBMISSION TYPE: 10-K405
PUBLIC DOCUMENT COUNT: 2
CONFORMED PERIOD OF REPORT: 20001231
FILED AS OF DATE: 20010405
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: ATP OIL & GAS CORP
CENTRAL INDEX KEY: 0001123647
STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311]
IRS NUMBER: 760362774
STATE OF INCORPORATION: TX
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K405
SEC ACT:
SEC FILE NUMBER: 000-32261
FILM NUMBER: 1595719
BUSINESS ADDRESS:
STREET 1: 4600 POST OAK PL
STREET 2: STE 200
CITY: HOUSTON
STATE: TX
ZIP: 77027
BUSINESS PHONE: 7136223311
MAIL ADDRESS:
STREET 1: 4600 POST OAK PLACE
STREET 2: SUITE 200
CITY: HOUSTON
STATE: TX
ZIP: 77027
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K405
<SEQUENCE>1
<FILENAME>0001.txt
<DESCRIPTION>FORM 10-K
<TEXT>
<PAGE>
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------------
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) of
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2000 Commission File No. 000-32261
ATP Oil & Gas Corporation
(Exact name of registrant as specified in its charter)
Texas 76-0362774
(State or other jurisdiction (I.R.S. Employer
of 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 [_] No [X]
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. [X]
State the aggregate market value of the voting and non-voting common equity
held by non-affiliates of the registrant:
Voting common stock (as of March 30, 2001) $73,045,781
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date:
As of March 30, 2001 Common Stock, par value $.001 per share 20,285,714 shares
DOCUMENTS INCORPORATED BY REFERENCE
None
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<PAGE>
ATP Oil & Gas Corporation
FORM 10-K for the Year Ended December 31, 2000
TABLE OF CONTENTS
<TABLE>
<S> <C>
PART I..................................................................... 3
Item 1 Business.......................................................... 3
Item 2. Properties....................................................... 12
Item 3. Legal Proceedings................................................ 15
Item 4. Submission of Matters to a Vote of Security Holders.............. 15
PART II.................................................................... 15
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters................................................................. 15
Item 6. Selected Financial Data.......................................... 16
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................... 18
Item 7A. Quantitative and Qualitative Disclosures about Market Risk...... 25
Item 8. Financial Statements and Supplementary Data...................... 26
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure.................................................... 26
PART III................................................................... 27
Item 10. Directors and Executive Officers of Registrant.................. 27
Item 11. Executive Compensation.......................................... 31
Item 12. Security Ownership of Certain Beneficial Owners and Management.. 34
Item 13. Certain Relationships and Related Transactions.................. 34
PART IV.................................................................... 35
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-
K....................................................................... 35
SIGNATURES................................................................. 62
INDEX OF EXHIBITS.......................................................... 63
</TABLE>
<PAGE>
Cautionary Statement About Forward-Looking Statements
Some of the information included in this annual report include assumptions,
expectations, projections, intentions or beliefs about future events. These
statements are intended as "forward-looking statements" under the Private
Securities Litigation Reform Act of 1995. We caution that assumptions,
expectations, projections, intentions and beliefs about future events may and
often do vary from actual results and the differences can be material.
All statements in this document that are not statements of historical fact
are forward looking statements. Forward looking statements include, but are not
limited to:
. projected operating or financial results;
. budgeted or projected capital expenditures;
. statements about pending or recent acquisitions, including the
anticipated closing dates;
. expectations regarding our planned expansions and the availability of
acquisition opportunities;
. statements about the expected drilling of wells and other planned
development activities;
. expectations regarding natural gas and oil markets in the United States
and the United Kingdom; and
. timing and amount of future production of natural gas and oil.
When used in this document, the words "anticipate," "estimate," "project,"
"forecast," "may," "should," and "expect" reflect forward-looking statements.
There can be no assurance that actual results will not differ materially
from those expressed or implied in such forward looking statements. Some of the
key factors which could cause actual results to vary from those expected
include:
. the timing and extent of changes in natural gas and oil prices;
.the timing of planned capital expenditures and availability of
acquisitions;
. the inherent uncertainties in estimating proved reserves and forecasting
production results;
. operational factors affecting the commencement or maintenance of
producing wells, including catastrophic weather related damage,
unscheduled outages or repairs, or unanticipated changes in drilling
equipment costs or rig availability;
. the condition of the capital markets generally, which will be affected by
interest rates, foreign currency fluctuations and general economic
conditions;
. cost and other effects of legal and administrative proceedings,
settlements, investigations and claims, including environmental
liabilities which may not be covered by indemnity or insurance; and
. other U.S. 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.
1
<PAGE>
WHERE YOU CAN FIND MORE INFORMATION
This Annual Report on Form 10-K, including related exhibits and schedules,
can be inspected and copied at the Public Reference Room maintained by the SEC
at 450 Fifth Street, N.W., Washington, D.C. 20549. Copies of all or any portion
of this Annual Report can be obtained after payment of fees prescribed by the
SEC. You may obtain information on the operation of the Public Reference Room
by calling the SEC at (800) SEC-0330. The SEC maintains a web site that
contains reports, proxy and information statements and other information
regarding registrants, including us, that file electronically with the SEC. The
address of the site is www.sec.gov.
We are required to comply with the informational requirements of the
Securities Exchange Act of 1934 and, accordingly, will file current reports on
Form 8-K, quarterly reports on Form 10-Q, annual reports on Form 10-K, proxy
statements and other information with the SEC. Those reports, proxy statements
and other information will be available for inspection and copying at the
Public Reference Room and internet site of the SEC referred to above. We intend
to furnish our shareholders with annual reports containing consolidated
financial statements certified by an independent public accounting firm.
2
<PAGE>
PART I
Item 1. Business
About ATP Oil & Gas Corporation
ATP was incorporated in Texas in 1991. We are engaged in the acquisition,
development and production of natural gas and oil properties in the outer
continental shelf of the Gulf of Mexico, in the shallow-deep waters of the Gulf
of Mexico and in the Southern Gas Basin of the U.K. North Sea. We primarily
focus our efforts on natural gas and oil properties with proved undeveloped
reserves that are economically attractive to us but are not strategic to major
or exploration-oriented independent oil and gas companies. We attempt to
achieve a high return on our investment in these properties by limiting our up-
front acquisition costs and by developing our acquisitions quickly. Our
management team has extensive engineering, geological, geophysical, technical
and operational expertise in successfully developing and operating properties
in both our current and planned areas of operation.
At December 31, 2000, we had estimated net proved reserves of 125.4 Bcfe, an
increase of 20% over the previous year end. The estimated pre-tax PV-10 of our
reserves at December 31, 2000 was $744.8 million. Prices used in these reserve
estimates were $9.52 per MMbtu of natural gas and $23.75 per barrel of oil. At
December 31, 2000, natural gas accounted for 81% of our reserves, proved
developed reserves comprised 38% of our total reserves and our reserve life
index for total proved reserves was 5.1 years. At December 31, 2000, we had
leasehold and other interests in 47 offshore blocks, 21 platforms and 56 wells,
including six subsea wells, in the federal waters of the Gulf of Mexico. We
operate 53 of these 56 wells, including all of the subsea wells, and 90% of our
offshore platforms. Our average working interest in our properties at December
31, 2000 was approximately 86%.
We produced approximately 24.5 Bcfe in 2000, an increase of 41% over the
previous year. For the five-year period since 1996, we have increased our
annual production at a compounded annual growth rate (CAGR) of 115%. We
increase our reserves and production exclusively through the acquisition and
development of proved natural gas and oil properties. During 2000, we replaced
187% of 2000 production through these activities, and from 1997 to 2000 we
achieved an average annual reserve replacement ratio of 259%. We believe
substantial additional acquisition opportunities exist in the outer continental
shelf of the Gulf of Mexico, the shallow-deep waters of the Gulf of Mexico and
in the Southern Gas Basin of the U.K. North Sea.
We were listed on the 2000 Inc. 500 as the 5th fastest growing privately
held company in the United States, an improvement from our ranking as 21st in
the 1999 Inc. 500. In both 1999 and 2000, we were the fastest growing energy
company in those surveys. During 2000, we received a Growing with Technology
Award from Inc./Cisco for innovative utilization of technology in offshore oil
and gas development. In October 2000, we were recognized as the only North
American finalist in the year 2000 Financial Times and Deloitte Touche Tohmatsu
Energy Award for Best Oil & Gas Company. Also in 2000, we received Blue Chip
Enterprise recognition from MassMutual, and our company president and founder,
T. Paul Bulmahn, was selected Entrepreneur Of The Year in Energy & Energy
Services by Ernst & Young.
Our Business Strategy
Our business strategy is to enhance shareholder value primarily through the
acquisition, development and production of proved undeveloped natural gas and
oil reserves in areas that have:
. a substantial existing infrastructure and geographic proximity to well-
developed markets for natural gas and oil;
. a large number of properties that major oil companies, exploration-
oriented independents and others consider non-strategic; and
. a relatively stable history of consistently applied governmental
regulations for offshore natural gas and oil development and production.
3
<PAGE>
Prior to 2000, our area of concentration was the outer continental shelf of
the Gulf of Mexico, which exhibits each of the above characteristics. In 2000,
we expanded our efforts into the shallow-deep waters of the Gulf of Mexico and
into the Southern Gas Basin of the U.K. North Sea, each of which we believe
also exhibits these characteristics.
We believe our strategy significantly reduces the risks associated with
traditional natural gas and oil exploration. Unlike oil and gas companies that
conduct exploration activities, our focus is to acquire properties that have
been previously explored by others and found to contain proved reserves. During
the life span of these properties, they may become non-core or non-strategic to
their original owners. Reasons that a property may become non-core or non-
strategic are varied. For example, companies may elect to concentrate their
efforts elsewhere, to reduce their capital spending for development, or to
pursue exploration projects as opposed to development projects. Also, a lease
expiration date may be approaching and the owner may be unwilling to complete a
development program. Companies pursuing exploration success may discover
hydrocarbons which may not provide an acceptable economic return for them but
which may prove attractive to us. If such a project is economically attractive
to us and is in our core areas, we will attempt to acquire the project. Each
natural gas and oil discovery by another company in our core areas is a
potential opportunity for the application of our approach.
We focus on developing projects in the shortest time possible between
initial investment and first revenue generated in order to maximize our rate of
return. Since we usually operate the properties in which we acquire a working
interest and begin a development program with proved reserves, we are able to
expeditiously commence a project's development. We typically initiate new
development projects by simultaneously obtaining the various required
components such as the pipeline and the production platform or subsea well
completion equipment. This strategy, combined with our ability to rapidly
evaluate and implement a project's requirements, allows us to complete the
development project and commence production as quickly and efficiently as
possible.
Our Strengths
. Operating Efficiency. We emphasize a low overhead and operating expense
structure. For 2000, our lease operating expense was $0.47 per Mcfe of
production and our general and administrative expense was $0.22 per Mcfe
of production. We believe that our focus on a low cost structure allows
us to pursue the acquisition, development and production of properties
that may not be economically attractive to others. For the three year
period ended December 31, 2000, our total average cost incurred for
finding and developing our net proved reserves was $1.29 per Mcfe.
. Operating Control. As of December 31, 2000, we operated 90% of our
offshore platforms and 100% of our subsea wells. Being an operator allows
us greater control of costs, the timing and amount of capital
expenditures, and the selection of completion and production technology.
. Technical Expertise and Significant Experience. We have assembled a
management team and technical staff with an average of 17 years of
industry experience. Our technical staff has specific expertise in
offshore property development, including the implementation of subsea
completion technology.
. Employee Ownership. Through employee ownership, we have built a staff
whose business decisions are aligned with our shareholders. Our employees
own 71% of ATP on a fully diluted basis.
Marketing and Delivery Commitments
We sell most of our natural gas and oil production under price sensitive or
market price contracts. Our revenues, profitability and future growth depend
substantially on prevailing prices for natural gas and oil. The price received
by us for our non-hedged natural gas and oil production fluctuates widely.
Changes in the prices of natural gas and oil will affect the carrying value of
our proved reserves and our revenues, profitability and cash flow. Although we
are not currently experiencing any significant involuntary curtailment of our
natural gas or oil production, market, economic and regulatory factors may in
the future materially affect our ability to sell our natural gas or oil
production.
4
<PAGE>
We sell a portion of our natural gas and oil to end users through various
gas marketing companies. We are not dependent upon, or confined to, any one
purchaser or small group of purchasers. Due to the nature of natural gas and
oil markets and because natural gas and oil are commodities and there are
numerous purchasers in the areas in which we sell production, we do not believe
the loss of a single purchaser, or a few purchasers, would materially affect
our ability to sell our production.
Competition
We compete with major and independent natural gas and oil companies for
property acquisitions. We also compete for the equipment and labor required to
operate and to develop these properties. Some of our competitors have
substantially greater financial and other resources. In addition, larger
competitors may be able to absorb the burden of any changes in federal, state
and local laws and regulations more easily than we can, which would adversely
affect our competitive position. These competitors may be able to pay more for
natural gas and oil properties and may be able to define, evaluate, bid for and
acquire a greater number of properties than we can. Our ability to acquire and
develop additional properties in the future will depend upon our ability to
conduct operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment. In addition,
some of our competitors have been operating in the Gulf of Mexico or in the
Southern Gas Basin of the U.K. North Sea for a much longer time than we have
and have demonstrated the ability to operate through a number of industry
cycles.
Regulation
Federal Regulation of Sales and Transportation of Natural Gas. Historically,
the transportation and sale for resale of natural gas in interstate commerce
have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas
Policy Act of 1978 and Federal Energy Regulatory Commission regulations. In the
past, the federal government has regulated the prices at which natural gas
could be sold. Deregulation of natural gas sales by producers began with the
enactment of the Natural Gas Policy Act of 1978. In 1989, Congress enacted the
Natural Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act
of 1938 and Natural Gas Policy Act of 1978 price and non-price controls
affecting producer sales of natural gas effective January 1, 1993. Congress
could, however, re-enact price controls in the future.
Our sales of natural gas are affected by the availability, terms and cost of
pipeline transportation. The price and terms for access to pipeline
transportation are subject to extensive federal regulation. Beginning in April
1992, the Federal Energy Regulatory Commission issued Order No. 636 and a
series of related orders, which required interstate pipelines to provide open-
access transportation on a not unduly discriminatory basis for all natural gas
shippers. The Federal Energy Regulatory Commission has stated that it intends
for Order No. 636 and its future restructuring activities to foster increased
competition within all phases of the natural gas industry. Although Order No.
636 does not directly regulate our production and marketing activities, it does
affect how buyers and sellers gain access to the necessary transportation
facilities and how we and our competitors sell natural gas in the marketplace.
The courts have largely affirmed the significant features of Order No. 636
and the numerous related orders pertaining to individual pipelines. However,
some appeals remain pending and the Federal Energy Regulatory Commission
continues to review and modify its regulations regarding the transportation of
natural gas. For example, the Federal Energy Regulatory Commission issued Order
No. 637 which;
. lifts the cost-based cap on pipeline transportation rates in the capacity
release market until September 30, 2002, for short-term releases of
pipeline capacity of less than one year,
. permits pipelines to file for authority to charge different maximum cost-
based rates for peak and off-peak periods,
. encourages, but does not mandate, auctions for pipeline capacity,
. requires pipelines to implement imbalance management services,
5
<PAGE>
. restricts the ability of pipelines to impose penalties for imbalances,
overruns and non-compliance with operational flow orders, and
. implements a number of new pipeline reporting requirements.
Order No. 637 also requires the Federal Energy Regulatory Commission Staff
to analyze whether the Federal Energy Regulatory Commission should implement
additional fundamental policy changes. These include whether to pursue
performance-based or other non-cost based ratemaking techniques and whether the
Federal Energy Regulatory Commission should mandate greater standardization in
terms and conditions of service across the interstate pipeline grid.
In April 1999 the Federal Energy Regulatory Commission issued Order No. 603,
which implemented new regulations governing the procedure for obtaining
authorization to construct new pipeline facilities. In September 1999, the
Federal Energy Regulatory Commission issued a related policy statement
establishing a presumption in favor of requiring owners of new pipeline
facilities to charge rates for service on new pipeline facilities based solely
on the costs associated with such new pipeline facilities.
We cannot predict what further action the Federal Energy Regulatory
Commission will take on these matters, nor can we accurately predict whether
the Federal Energy Regulatory Commission's actions will achieve the goal of
increasing competition in markets in which our natural gas is sold. However, we
do not believe that any action taken will affect us in a way that materially
differs from the way it affects other natural gas producers, gatherers and
marketers.
The Outer Continental Shelf Lands Act, which the Federal Energy Regulatory
Commission implements as to transportation and pipeline issues, requires that
all pipelines operating on or across the Outer Continental Shelf provide open-
access, non-discriminatory service. Historically, the Federal Energy Regulatory
Commission has opted not to impose regulatory requirements under its Outer
Continental Shelf Lands Act authority on gatherers and other entities outside
the reach of its Natural Gas Act jurisdiction. However, the Federal Energy
Regulatory Commission recently issued Order No. 639, requiring that virtually
all non-proprietary pipeline transporters of natural gas on the Outer
Continental Shelf report information on their affiliations, rates and
conditions of service. The reporting requirements established by the Federal
Energy Regulatory Commission in Order No. 639 may apply, in certain
circumstances, to operators of production platforms and other facilities on the
Outer Continental Shelf, with respect to gas movements across such facilities.
Among the Federal Energy Regulatory Commission's stated purposes in issuing
such rules was the desire to increase transparency in the market, to provide
producers and shippers on the Outer Continental Shelf with greater assurance of
(a) open-access services on pipelines located on the Outer Continental Shelf
and (b) non-discriminatory rates and conditions of service on such pipelines.
The Federal Energy Regulatory Commission retains authority under the Outer
Continental Shelf Lands Act to exercise jurisdiction over gatherers and other
entities outside the reach of its Natural Gas Act jurisdiction if necessary to
ensure non-discriminatory access to service on the Outer Continental Shelf. We
do not believe that any Federal Energy Regulatory Commission action taken under
its Outer Continental Shelf Lands Act jurisdiction will affect us in a way that
materially differs from the way it affects other natural gas producers,
gatherers and marketers.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the Federal Energy Regulatory Commission
and the courts. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by the Federal Energy Regulatory Commission and
Congress will continue.
Federal Leases. A substantial portion of our operations is located on
federal natural gas and oil leases, which are administered by the Minerals
Management Service pursuant to the Outer Continental Shelf Lands Act. These
leases are issued through competitive bidding and contain relatively
standardized terms. These leases require compliance with detailed Minerals
Management Service regulations and orders that are subject to interpretation
and change by the Minerals Management Service.
6
<PAGE>
For offshore operations, lessees must obtain Minerals Management Service
approval for exploration, development and production plans prior to the
commencement of such operations. In addition to permits required from other
agencies such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency, lessees must obtain a permit from the Minerals
Management Service prior to the commencement of drilling. The Minerals
Management Service has promulgated regulations requiring offshore production
facilities located on the Outer Continental Shelf to meet stringent engineering
and construction specifications. The Minerals Management Service also has
regulations restricting the flaring or venting of natural gas, and has proposed
to amend such regulations to prohibit the flaring of liquid hydrocarbons and
oil without prior authorization. Similarly, the Minerals Management Service has
promulgated other regulations governing the plugging and abandonment of wells
located offshore and the installation and removal of all production facilities.
To cover the various obligations of lessees on the Outer Continental Shelf,
the Minerals Management Service generally requires that lessees have
substantial net worth or post bonds or other acceptable assurances that such
obligations will be met. The cost of these bonds or assurances can be
substantial, and there is no assurance that they can be obtained in all cases.
We currently have several supplemental bonds in place. Under some
circumstances, the Minerals Management Service may require any of our
operations on federal leases to be suspended or terminated. Any such suspension
or termination could materially adversely affect our financial condition and
results of operations.
The Minerals Management Service also administers the collection of royalties
under the terms of the Outer Continental Shelf Lands Act and the oil and gas
leases issued under the Act. The amount of royalties due is based upon the
terms of the oil and gas leases as well as of the regulations promulgated by
the Minerals Management Service. These regulations are amended from time to
time, and the amendments can affect the amount of royalties that we are
obligated to pay to the Minerals Management Service. However, we do not believe
that these regulations or any future amendments will affect us in a way that
materially differs from the way it affects other oil and gas producers, gathers
and marketers.
Oil Price Controls and Transportation Rates. Sales of crude oil, condensate
and natural gas liquids by us are not currently regulated and are made at
market prices. In a number of instances, however, the ability to transport and
sell such products is dependent on pipelines whose rates, terms and conditions
of service are subject to Federal Energy Regulatory Commission jurisdiction
under the Interstate Commerce Act. In other instances, the ability to transport
and sell such products is dependent on pipelines whose rates, terms and
conditions of service are subject to regulation by state regulatory bodies
under state statutes.
The regulation of pipelines that transport crude oil, condensate and natural
gas liquids is generally more light-handed than the Federal Energy Regulatory
Commission's regulation of gas pipelines under the Natural Gas Act. Regulated
pipelines that transport crude oil, condensate, and natural gas liquids are
subject to common carrier obligations that generally ensure non-discriminatory
access. With respect to interstate pipeline transportation subject to
regulation of the Federal Energy Regulatory Commission under the Interstate
Commerce Act, rates generally must be cost-based, although market-based rates
or negotiated settlement rates are permitted in certain circumstances. Pursuant
to Federal Energy Regulatory Commission Order No. 561, pipeline rates are
subject to an indexing methodology. Under this indexing methodology, pipeline
rates are subject to changes in the Producer Price Index for Finished Goods,
minus one percent. A pipeline can seek to increase its rates above index levels
provided that the pipeline can establish that there is a substantial divergence
between the actual costs experienced by the pipeline and the rate resulting
from application of the index. A pipeline can seek to charge market-based rates
if it establishes that it lacks significant market power. In addition, a
pipeline can establish rates pursuant to settlement if agreed upon by all
current shippers. A pipeline can seek to establish initial rates for new
services through a cost-of-service proceeding, a market-based rate proceeding,
or through an agreement between the pipeline and at least one shipper not
affiliated with the pipeline. The Federal Energy Regulatory Commission
indicated in Order No. 561 that it will assess in 2000 how the rate-indexing
method is operating. The Federal Energy Regulatory Commission issued a Notice
of Inquiry on July 27, 2000 seeking comment on whether to retain or to change
the existing index.
7
<PAGE>
With respect to intrastate crude oil, condensate and natural gas liquids
pipelines subject to the jurisdiction of state agencies, regulation is
generally less rigorous than the regulation of interstate pipelines. State
agencies have generally not investigated or challenged existing or proposed
rates in the absence of shipper complaints or protests. Complaints or protests
have been infrequent and are usually resolved informally.
We do not believe that the regulatory decisions or activities relating to
interstate or intrastate crude oil, condensate, or natural gas liquids
pipelines will affect us in a way that materially differs from the way it
affects other crude oil, condensate, and natural gas liquids producers or
marketers.
Environmental Regulations. Our operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Public interest in the
protection of the environment has increased dramatically in recent years.
Offshore drilling in some areas has been opposed by environmental groups and,
in some areas, has been restricted. To the extent laws are enacted or other
governmental action is taken that prohibits or restricts offshore drilling or
imposes environmental protection requirements that result in increased costs to
the natural gas and oil industry in general and the offshore drilling industry
in particular, our business and prospects could be adversely affected.
The Oil Pollution Act of 1990 and related regulations impose a variety of
regulations on "responsible parties" related to the prevention of oil spills
and liability for damages resulting from such spills in United States waters. A
"responsible party" includes the owner or operator of a facility or vessel, or
the lessee or permittee of the area in which an offshore facility is located.
The Oil Pollution Act of 1990 assigns liability to each responsible party for
oil removal costs and a variety of public and private damages. While liability
limits apply in some circumstances, a party cannot take advantage of liability
limits if the spill was caused by gross negligence or willful misconduct or
resulted from violation of a federal safety, construction or operating
regulation. If the party fails to report a spill or to cooperate fully in the
cleanup, liability limits likewise do not apply. Even if applicable, the
liability limits for offshore facilities require the responsible party to pay
all removal costs, plus up to $75.0 million in other damages. Few defenses
exist to the liability imposed by the Oil Pollution Act of 1990.
The Oil Pollution Act of 1990 also requires a responsible party to submit
proof of its financial responsibility to cover environmental cleanup and
restoration costs that could be incurred in connection with an oil spill. As
amended by the Coast Guard Authorization Act of 1996, the Oil Pollution Act of
1990 requires parties responsible for offshore facilities to provide financial
assurance in the amount of $35.0 million to cover potential Oil Pollution Act
of 1990 liabilities. This amount can be increased up to $150.0 million if a
study by the Minerals Management Service indicates that an amount higher than
$35.0 million should be required. On August 11, 1998, the Minerals Management
Service adopted a rule implementing these Oil Pollution Act of 1990 financial
responsibility requirements. We are in compliance with this rule.
In addition, the Outer Continental Shelf Lands Act authorizes regulations
relating to safety and environmental protection applicable to lessees and
permittees operating on the Outer Continental Shelf. Specific design and
operational standards may apply to Outer Continental Shelf vessels, rigs,
platforms and structures. Violations of lease conditions or regulations issued
pursuant to the Outer Continental Shelf Lands Act can result in substantial
civil and criminal penalties, as well as potential court injunctions curtailing
operations and the cancellation of leases. Such enforcement liabilities can
result from either governmental or private prosecution.
The Oil Pollution Act of 1990 also imposes other requirements, such as the
preparation of an oil spill contingency plan. We have such a plan in place. We
are also regulated by the Clean Water Act, which prohibits any discharge into
waters of the United States except in strict conformance with discharge permits
issued by federal or state agencies. We have obtained, and are in material
compliance with, the discharge permits necessary for our operations. We could
become subject to similar state and local water quality laws and regulations in
the future if we conduct production or drilling activities in state coastal
waters. Failure to comply with the ongoing requirements of the Clean Water Act
or inadequate cooperation during a spill event may subject a responsible party
to civil or criminal enforcement actions.
8
<PAGE>
The Comprehensive Environmental Response, Compensation, and Liability Act,
or CERCLA, also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on some classes of persons
that are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances
released into the environment. We could be subject to liability under CERCLA
because our drilling and production activities generate relatively small
amounts of liquid and solid wastes that may be subject to classification as
hazardous substances under CERCLA. These wastes must be brought to shore for
proper disposal under the Resource Conservation and Recovery Act. We minimize
this potential liability by selecting reputable contractors to dispose of our
wastes at government approved landfills or other types of disposal facilities.
Our operations are also subject to regulation of air emissions under the
Clean Air Act and the Outer Continental Shelf Lands Act. Implementation of
these laws could lead to the gradual imposition of new air pollution control
requirements on our operations. Therefore, we may incur capital expenditures
over the next several years to upgrade our air pollution control equipment. We
could also become subject to similar state and local air quality laws and
regulations in the future if we conduct production or drilling activities in
state coastal waters. We do not believe that our operations would be materially
affected by any such requirements, nor do we expect such requirements to be any
more burdensome to us than to other companies our size involved in natural gas
and oil development and production activities.
In addition, legislation has been proposed in Congress from time to time
that would reclassify some natural gas and oil exploration and production
wastes as "hazardous wastes," which would make the reclassified wastes subject
to much more stringent handling, disposal and clean-up requirements. If
Congress were to enact this legislation, it could increase our operating costs,
as well as those of the natural gas and oil industry in general. Initiatives to
further regulate the disposal of natural gas and oil wastes are also pending in
some states, and these various initiatives could have a similar impact on us.
Our management believes that we are in substantial compliance with current
applicable environmental laws and regulations and that continued compliance
with existing requirements will not have a material adverse impact on us.
U.K. Regulations of Natural Gas and Oil Production. Pursuant to the
Petroleum Act 1998, all natural gas and oil reserves contained in properties
located in Great Britain are the property of the U.K. government. The
development and production of natural gas and oil reserves in the U.K. North
Sea requires a petroleum production license granted by the U.K. government.
Prior to developing a field, we will be required to obtain from the Secretary
of State for Trade and Industry a consent to develop that field. We will also
be required to obtain the consent of the Secretary of State for Trade and
Industry in the event we wish to transfer an interest in a license.
The terms of the petroleum production licenses are based on model license
clauses applicable at the time of the issuance of the license. Licenses
frequently contain regulatory provisions governing matters such as working
method, pollution and training, and reserve to the Secretary of State for Trade
and Industry the power to direct some of the licensee's activities. For
example, a licensee may be precluded from carrying out development or
production activities other than with the consent of the Secretary of State for
Trade and Industry or in accordance with a development plan which the Secretary
of State for Trade and Industry has approved. Breach of these requirements may
result in the revocation of the license. In addition, licenses that we acquire
may require us to pay fees and royalties on production and also impose certain
other duties on us.
9
<PAGE>
Our operations in the U.K. will be subject to the Petroleum Act 1998, which
imposes a health and safety regime on offshore natural gas and oil production
activities. The Petroleum Act 1998 also regulates the abandonment of facilities
by licensees. In addition, the Mineral Workings (Offshore Installations) Act
provides a framework in which the government can impose additional regulations
relating to health and safety. Since its enactment, a number of regulations
have been promulgated relating to offshore construction and operation of
offshore production facilities. Health and safety offshore is further governed
by the Health and Safety at Work Act 1974 and applicable regulations. Our
operations will also be subject to environmental laws and regulations imposed
by both the European Union and the U.K. Parliament.
Petroleum production licenses require the approval of the Secretary of State
for Trade and Industry of a licensee to act as operator and who organizes or
supervises all or any of the development and production operations of natural
gas and oil properties subject thereto. As an operator we may obtain
operational services from third parties, but would remain fully responsible for
the operations as if we had conducted them ourself.
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. The terms on which Transco must transport gas are
governed by the Gas Acts 1986 and 1995, the gas transporter's license issued to
Transco under those Acts and a network code. For us to use the NTS, we must
obtain a shipper's license under the Gas Acts and arrange to have gas
transported by Transco within the NTS. We will therefore be subject to the
network code, which imposes obligations to payment, gas flow nominations,
capacity booking and system imbalance. Applying for and complying with a
shipper's license, and acting as a gas shipper, is expensive and
administratively burdensome. Alternatively, we may sell natural gas "at the
beach' before it enters the NTS or arrange with an existing gas shipper for
them to ship the gas through the NTS on our behalf.
Employees
At December 31, 2000, we had 28 full-time employees and two contract
personnel in our Houston office and five full-time employees and three contract
personnel in our London office. None of our employees is covered by a
collective bargaining agreement. From time to time, we use the services of
independent consultants and contractors to perform various professional
services, particularly in the areas of construction, design, well-site
supervision, permitting and environmental assessment. Independent contractors
usually perform field and on-site production operation services for us,
including gauging, maintenance, dispatching, inspection and well testing.
10
<PAGE>
GLOSSARY OF TECHNICAL TERMS
Bbls. Barrels of crude oil or other liquid hydrocarbons.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one bbl of crude oil, condensate or natural gas liquids.
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. Thousand cubic feet of natural gas.
Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one bbl of crude oil, condensate or other liquid
hydrocarbons.
MMBbls. Million barrels of crude oil or other liquid hydrocarbons.
MMBtu. Million British Thermal Units.
MMcf. Million cubic feet of natural gas.
MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one bbl of crude oil, condensate or other liquid
hydrocarbons.
Net feet of natural gas and condensate. The true vertical thickness of
reservoir rock estimated to both contain hydrocarbons and be capable of
contributing to producing rates.
Pre-tax PV-10. The estimated future net revenue to be generated from the
production of proved reserves discounted to present value using an annual
discount rate of 10%. These amounts are calculated net of estimated production
costs and future development costs, using prices and costs in effect as of a
certain date, without escalation and without giving effect to non-property
related expenses, such as general and administrative expenses, debt service,
future income tax expense, or depreciation, depletion, and amortization.
Proved developed reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery are included as "proved developed
reserves" only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.
Proved undeveloped reserves. Reserves that are expected to be recovered from
new wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion. Reserves on undrilled acreage are
limited to those drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other undrilled units
are included only where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation. Estimates for
proved undeveloped reserves are not attributed to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.
Reserve life index. A measure of the productive life of a natural gas and
oil property or a group of natural gas and oil properties, expressed in years.
Reserve life equals the estimated net proved reserves attributable to a
property or group of properties divided by production from the property or
group of properties for the four fiscal quarters preceding the date as of which
the proved reserves were estimated.
Shallow-deep waters. The waters in the Gulf of Mexico located between the
continental shelf and water depths of up to approximately 3,000 feet.
11
<PAGE>
Item 2. Properties
General
Since inception we have engaged in the acquisition, development and
production of natural gas and oil properties primarily in the outer continental
shelf of the Gulf of Mexico. During 2000 we entered into agreements to expand
our business to include the acquisition and development of properties in the
shallow-deep waters of the Gulf of Mexico and in the Southern Gas Basin of the
U.K. North Sea. At December 31, 2000, we had leasehold and other interests in
47 offshore blocks, 21 platforms and 56 wells, including six subsea wells, in
the federal waters of the Gulf of Mexico. We operate 53 of these 56 wells,
including all of the subsea wells, and 90% of our offshore platforms. Our
average working interest in our properties at December 31, 2000 was
approximately 86%. As of December 31, 2000, we had leasehold interests located
in the Gulf of Mexico covering approximately 177,000 gross and 157,000 net
acres.
Acquisitions During 2000
Gulf of Mexico. During 2000 we acquired an interest in eleven lease blocks
covering nine separate properties in the Gulf of Mexico for total acquisition
costs of $7.5 million. Total proved reserves associated with these acquisitions
was 65.8 Bcfe net to our interest. Our working interest in these properties
range from 50% to 100%. We are the operator of all of the properties. Included
in these acquisitions were four blocks on three separate properties which
represent our first acquisitions in the shallow deep waters of the Gulf of
Mexico. Of the six properties in the outer continental shelf, two produced
during 2000 with the remainder scheduled to come on production during 2001. Two
of the three properties in the shallow deep waters are scheduled to begin
production in 2001. We intend to use the production and flow facilities of one
of these properties, after it ceases production, to develop the third of these
properties.
Southern Gas Basin of the U.K. North Sea. In October 2000, we entered into a
letter of intent to acquire interests in three properties (five blocks) in the
Southern Gas Basin of the U.K. North Sea. Under the letter of intent, we would
acquire a 50% interest in one block, a 100% interest in one block and an 86%
interest in three blocks. The letter of intent provides that we would pay an
aggregate of (Pounds)2,500,000, approximately $3.6 million, for the three
properties at closing. We will make additional payments on a property by
property basis at first production and thereafter at designated production
levels. The aggregate payments at first production for all three fields would
total (Pounds)2,300,000, approximately $3.3 million. We do not expect first
production to occur until at least 2002. The aggregate payments for achieving
designated production levels for all three fields would total up to
(Pounds)1,650,000, approximately $2.4 million. Based on currently available
information we cannot reasonably estimate when such production levels may be
achieved.
Acquisitions During 2001
Gulf of Mexico. In February 2001 we acquired three properties representing
13.5 Bcfe net to our interest. In March 2001 we acquired six additional
properties representing 7.8 Bcfe net to our interest. Total acquisition costs
for the above acquisitions was approximately $23.0 million. Eight of the above
properties were producing when acquired with additional development and
production planned during 2001.
Southern Gas Basin of the U.K. North Sea. In March 2001 we acquired two of
the three properties covered by the October 2000 letter of intent. Total proved
reserves net to our interest in these two properties is approximately 40.0
Bcfe. Initial acquisition costs were (Pounds)1.6 million, approximately $2.3
million. Neither of the properties were producing when we acquired them. We
expect to begin development operations in 2001 with first production scheduled
for late 2002 or early 2003. The third property remains under the letter of
intent.
12
<PAGE>
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, 2000 based
on reserve reports prepared by Ryder Scott Company, L.P. and Schlumberger
Holditch-Reservoir Technologies Consulting Services. The present values,
discounted at 10% per annum, of estimated future net cash flows before income
taxes shown in the table are not intended to represent the current market value
of the estimated natural gas and oil reserves we own.
The present value of future net cash flows before income taxes as of
December 31, 2000 was determined by using the December 31, 2000 prices of $9.52
per MMBtu of natural gas and $23.75 per Bbl of oil.
<TABLE>
<CAPTION>
Proved Reserves
------------------------------
Developed Undeveloped Total
--------- ----------- --------
<S> <C> <C> <C>
Natural gas (MMcf)........................ 42,502 59,068 101,570
Oil and condensate (MBbls)................ 851 3,126 3,977
Total proved reserves (MMcfe)............. 47,610 77,823 125,433
Pre-tax PV-10 (in thousands).............. $341,903 $402,923 $744,826
</TABLE>
Our estimates of proved reserves in the table above do not differ from those
we have filed with other federal agencies. The process of estimating natural
gas and oil reserves is complex. It requires various assumptions, including
assumptions relating to natural gas and oil prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. We must
project production rates and timing of development expenditures. We analyze
available geological, geophysical, production and engineering data, and the
extent, quality and reliability of this data can vary. Therefore, estimates of
natural gas and oil reserves are inherently imprecise. Actual future
production, natural gas and oil prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable natural gas and
oil reserves most likely will vary from our estimates and these variances may
be material.
You should not assume that the present value of future net cash flows
referred to in this annual report is the current market value of our estimated
natural gas and oil reserves. In accordance with SEC requirements, we generally
base the estimated discounted future net cash flows from proved reserves on
prices and costs on the date of the estimate. Actual future prices and costs
may differ materially from those used in the net present value estimate.
Our business strategy is to acquire proved reserves, usually proved
undeveloped, and to bring those reserves on production as rapidly as possible.
At December 31, 2000, approximately 62% of our estimated equivalent net proved
reserves were undeveloped. Recovery of undeveloped reserves generally requires
significant capital expenditures and successful drilling and completion
operations. The reserve data assumes that we will make these expenditures.
Although we estimate our reserves and the costs associated with developing them
in accordance with industry standards, the estimated costs may be inaccurate,
development may not occur as scheduled and results may not be as estimated. The
following table highlights our history of bringing to production our proved
undeveloped reserves:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------------
2000 1999 1998
--------------------- --------------------- ---------------------
Undeveloped Developed Undeveloped Developed Undeveloped Developed
----------- --------- ----------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C>
At January 1............ 6 25 11 22 4 10
Acquisitions............ 10 1 7 1 11 8
Divestitures............ -- (2) (10)(1) -- -- --
Undeveloped to
productive (6) 6 (2) 2 (4) 4
Undeveloped to
nonproductive.......... -- -- -- -- -- --
--- --- --- --- --- ---
At end of period........ 10 30 6 25 11 22
=== === === === === ===
</TABLE>
- --------
(1) Includes nine undeveloped exploration blocks that we sold. We retained a
non-working future interest in seven of those blocks.
13
<PAGE>
Volumes, Prices and Operating Expenses
The following table presents information regarding the production volumes
of, average sales prices received for and average production costs associated
with our sales of natural gas and oil for the periods indicated:
<TABLE>
<CAPTION>
Years Ended December
31,
----------------------
2000 1999 1998
------ ------ ------
<S> <C> <C> <C>
Production:
Natural gas (MMcf).................................... 22,410 16,533 9,026
Oil and condensate (MBbls)............................ 345 128 151
------ ------ ------
Total (MMcfe)....................................... 24,477 17,301 9,933
Average sales price per unit:
Natural gas revenues from production (per Mcf)........ $ 4.20 $ 2.23 2.07
Effects of hedging activities (per Mcf)............... (1.19) (0.23) --
------ ------ ------
Average gas price................................... $ 3.01 $ 2.00 $ 2.07
Oil and condensate revenues from production (per
Bbl)................................................. $29.35 $15.37 11.50
Effects of hedging activities (per Bbl)............... (4.34) -- --
------ ------ ------
Average oil price................................... $25.01 $15.37 $11.50
Total revenues from production (per Mcfe)............. $ 4.26 $ 2.24 $ 2.05
Effects of hedging activities (per Mcfe).............. (1.16) (0.22) --
------ ------ ------
Total average price (per Mcfe)...................... $ 3.10 $ 2.02 $ 2.05
Expenses (per Mcfe):
Lease operating....................................... $ 0.47 $ 0.32 $ 0.32
General and administrative............................ 0.22 0.20 0.26
Depreciation, depletion and amortization--natural gas
and
oil properties....................................... 1.66 1.30 1.76
</TABLE>
Development and Acquisition Capital Expenditures
The following table presents information regarding our net costs incurred in
the acquisition of proved properties and development activities (in thousands):
<TABLE>
<CAPTION>
Years Ended December
31,
-----------------------
2000 1999 1998
------- ------- -------
<S> <C> <C> <C>
Proved property acquisition costs...................... $ 7,534 $25,274 $12,070
Development costs...................................... 68,982 30,777 23,866
------- ------- -------
Total costs incurred................................... $76,516 $56,051 $35,936
======= ======= =======
</TABLE>
Drilling Activity
The following table shows our drilling and completion activity. In the
table, "gross" refers to the total wells in which we have a working interest
and "net" refers to gross wells multiplied by our working interest in such
wells. We did not drill or complete any exploratory wells in any period
presented.
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------------
2000 1999 1998
---------- --------- ---------
Gross Net Gross Net Gross Net
----- ---- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Development Wells:
Productive..................................... 12.0 11.0 3.0 2.2 5.0 5.0
Nonproductive.................................. 1.0 1.0 -- -- -- --
---- ---- --- --- --- ---
Total........................................ 13.0 12.0 3.0 2.2 5.0 5.0
==== ==== === === === ===
</TABLE>
14
<PAGE>
As of December 31, 2000, we were conducting completion activities on 1 gross
(1 net) well and drilling operations on 1 gross (1 net) well.
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, 2000. Productive wells
consist of producing wells and wells capable of production, including natural
gas wells awaiting pipeline connections to commence deliveries and oil wells
awaiting connection to production facilities.
<TABLE>
<CAPTION>
Total
Productive
Wells(1)
----------
Gross Net
----- ----
<S> <C> <C>
Natural gas.................................................... 36.0 32.1
Oil............................................................ 1.0 1.0
---- ----
Total(1)..................................................... 37.0 33.1
==== ====
</TABLE>
- --------
(1) Includes four gross and 3.2 net wells with multiple completions.
Acreage
The following table presents information regarding our developed and
undeveloped acreage as of December 31, 2000.
<TABLE>
<CAPTION>
Developed Undeveloped
Acreage Acreage Total
--------------- ------------- ---------------
Gross Net Gross Net Gross Net
------- ------- ------ ------ ------- -------
<S> <C> <C> <C> <C> <C> <C>
Gulf of Mexico-Shelf............ 133,245 116,125 22,620 22,620 155,865 138,745
Gulf of Mexico-Shallow Deep
Waters......................... -- -- 20,965 18,085 20,965 18,085
------- ------- ------ ------ ------- -------
Total......................... 133,245 116,125 43,585 40,705 176,830 156,830
======= ======= ====== ====== ======= =======
</TABLE>
Item 3. Legal Proceedings
From time to time, we may be a party to various legal proceedings. We
currently are not a party to any material litigation.
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 2000.
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 20,285,714 shares of common stock and no shares of
preferred stock outstanding as of March 30, 2001. The number of record holders
of our common stock as of March 28, 2001 was seven. 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 high sales price for
our common stock on the Nasdaq National Market for the period from February 6,
2001 (first trade after effective date) to March 30, 2001 was $14.563 per share
and the low sales price for the same period was $9.875 per share. The closing
price of our common stock on March 30, 2001 was $12.188 per share.
15
<PAGE>
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.
Item 6. Selected Financial Data
The selected financial data on the following pages are as of and for the
years ended December 31, 2000, 1999, 1998, 1997 and 1996. The following data
should be read in conjunction with "Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the Company's
Consolidated Financial Statements, and related notes included in "Item 8,
Financial Statements and Supplementary Data" of this Annual Report on Form 10-
K.
16
<PAGE>
<TABLE>
<CAPTION>
Years Ended December 31,
-----------------------------------------------------------
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- -----------
(unaudited)
(In thousands, except share data)
<S> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Revenues:
Oil and gas
production............ $ 75,940 $ 34,981 $ 20,410 $ 7,359 $ 3,009
Gas sold--marketing.... 8,015 7,703 -- -- --
Gain on sale of oil
and gas properties.... 33 287 -- 304 --
---------- ---------- ---------- ---------- ---------
Total revenues....... 83,988 42,971 20,410 7,663 3,009
Costs and operating
expenses:
Lease operating........ 11,559 5,587 3,193 1,513 308
Gas purchased--
marketing............. 7,788 7,402 -- -- --
General and
administrative........ 5,409 3,541 2,591 1,170 505
Depreciation,
depletion and
amortization.......... 40,569 22,521 17,442 4,206 1,672
Impairment of oil and
gas properties........ 10,838 7,509 5,072 5,787 --
Realized loss on
speculative
position.............. 4,662 -- -- -- --
Unrealized loss on
speculative
position.............. 7,249 -- -- -- --
Other expense.......... 450 -- -- -- --
---------- ---------- ---------- ---------- ---------
Total operating
expenses.............. 88,524 46,560 28,298 12,676 2,485
---------- ---------- ---------- ---------- ---------
Net income (loss) from
operations............. (4,536) (3,589) (7,888) (5,013) 524
Other income (expense):
Interest income......... 451 202 141 207 45
Interest expense........ (11,907) (9,399) (7,963) (1,212) (107)
---------- ---------- ---------- ---------- ---------
Income (loss) before
income taxes and
extraordinary item..... (15,992) (12,786) (15,710) (6,018) 462
Income tax benefit
(expense).............. 5,594 1,829 -- -- (1)
---------- ---------- ---------- ---------- ---------
Income (loss) before
extraordinary item..... $ (10,398) (10,957) (15,710) (6,018) 461
Gain on extinguishments
of debt, net of tax.... -- 29,185 -- -- --
---------- ---------- ---------- ---------- ---------
Net income (loss)....... $ (10,398) $ 18,228 $ (15,710) $ (6,018) $ 461
========== ========== ========== ========== =========
Weighted average number
of common shares
outstanding:
Basic.................. 14,285,714 14,285,714 11,925,785 10,567,762 8,245,513
Diluted................ 14,285,714 14,285,714 11,925,785 10,567,762 8,245,513
Income (loss) per common
share before
extraordinary item:
Basic.................. $ (0.73) $ (0.77) $ (1.32) $ (0.57) $ 0.06
Diluted................ $ (0.73) $ (0.77) $ (1.32) $ (0.57) $ 0.06
Net income (loss) per
common share:
Basic.................. $ (0.73) 1.28 $ (1.32) $ (0.57) $ 0.06
Diluted................ $ (0.73) $ 1.28 $ (1.32) $ (0.57) $ 0.06
Other Financial Data:
Adjusted EBITDA(1)...... $ 54,571 $ 26,643 $ 14,767 $ 5,187 $ 2,241
Adjusted EBITDA
margin(2).............. 65% 62% 72% 68% 74%
<CAPTION>
As of December 31,
-----------------------------------------------------------
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- -----------
(unaudited)
<S> <C> <C> <C> <C> <C>
Balance Sheet Data:
Cash and cash
equivalents............ $ 18,136 $ 17,779 $ 3,411 $ 1,806 $ 1,088
Working capital......... (3,835) 14,115 (5,106) 3,340 2,574
Net oil and gas
properties............. 98,725 72,278 47,612 33,355 5,201
Total assets............ 161,993 107,054 61,354 48,906 9,074
Total long-term debt.... 116,529 91,723 62,690 42,194 --
Total liabilities....... 175,172 109,835 82,363 54,217 8,369
Shareholders' equity
(deficit).............. (13,179) (2,781) (21,009) (5,311) 705
</TABLE>
- --------
(1) Net income (loss) before interest expense, income taxes, depreciation,
depletion and amortization, impairment of natural gas and oil properties
and unrealized gains and losses. Adjusted EBITDA is not a calculation based
on generally accepted accounting principles and should not be considered as
an alternative to net income (loss) or operating income (loss), as an
indicator of a company's financial performance or to cash flow as a measure
of liquidity. In addition, our Adjusted EBITDA calculation may not be
comparable to other similarly titled measures of other companies. Adjusted
EBITDA is included as a supplemental disclosure because it may provide
useful information regarding our ability to service debt and to fund
capital expenditures.
(2) Represents Adjusted EBITDA divided by total revenues.
17
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
You should read the following discussion and analysis together with
"Selected Financial Data" and our Financial Statements and the notes to those
statements included elsewhere in this Form 10-K. This discussion contains
forward-looking statements based on our current expectations, assumptions,
estimates and projections about us and our industry. These forward-looking
statements involve risks and uncertainties. Our actual results could differ
materially from those indicated in these forward-looking statements as a result
of certain factors, as more fully described under "Cautionary Statement About
Forward-Looking Statements" and elsewhere in this annual report. We undertake
no obligation to update publicly any forward-looking statements, even if new
information becomes available or other events occur in the future.
Overview
Our results of operations reflect rapid growth in natural gas and oil
production and revenues over the past three years driven primarily by our
strategy of acquiring and developing properties with proved undeveloped
reserves. We acquired 38 blocks from the beginning of 1998 through December
2000 and increased total proved reserves from 46.2 Bcfe at the beginning of
1998 to 125.4 Bcfe at the end of 2000, a compounded annual increase of 58%
during this three-year period. We increased production from 9,933 MMcfe in 1998
to 24,477 MMcfe in 2000, a compounded annual increase of 57% for these three
years. The acquisition and development of proved undeveloped natural gas and
oil properties has been the primary contributor to our oil and gas revenue
growth. During 2000, revenues have also reflected the positive effect of rising
prices for natural gas and oil, offset in part by our hedging activity. Our
revenues in future periods will reflect both our ability to continue to
identify, acquire and develop properties which are consistent with our
development strategy as well as commodity prices and hedging activity.
Historically, we have financed our acquisitions and development activity
through a combination of borrowings and cash from operations. At December 31,
2000, we had $27.8 million outstanding under bank credit facility and $88.8
million outstanding under our development program credit agreement. In February
2001, we completed our initial public offering of 6,000,000 shares of common
stock resulting in proceeds net of underwriting discount of $78.3 million. We
will use the proceeds, together with cash on hand, to repay all of our
outstanding debt under our development program credit agreement. Future capital
requirements are expected to be met primarily through a combination of cash
from operations or borrowings.
Our financial results are affected by hedging transactions we enter into
with respect to natural gas and oil prices. These hedging transactions
generally take the form of swaps or price collars with major financial or
commodities trading institutions. Our hedging activity during 2000 and 1999 was
significantly affected by the requirements of the lender under our development
program credit agreement. Our hedging activity was based on expected production
as required by our development program credit agreement. The details of our
current hedging positions are set forth under "Item 7A, Quantitative and
Qualitative Disclosures About Market Risk" below.
We have hedges in place for 69,700 MMBtu/day of natural gas for the first
quarter of 2001 at an average price of $3.05 per MMBtu. We have lesser volumes
hedged after the end of the first quarter of 2001. Based on actual NYMEX
settlement prices for January through April of 2001 and NYMEX monthly
settlement prices on March 30, 2001 for the remainder of the year, our
operating income for 2001 as a result of hedging transactions would be
negatively affected by approximately $22.9 million in the first quarter and a
total of approximately $13.0 million in the remaining three quarters.
In addition to the above financial hedges on natural gas, during 2000 we
entered into two written call option contracts that provide us a price for
natural gas above the then prevailing market price, but with a ceiling price.
For the period July 2000 through October 2000, we received NYMEX settlement
plus $0.15 with a ceiling price of $3.16 per MMBtu on 15,000 MMBtu per day. For
the period April 2001 through October 2001, we receive NYMEX settlement plus
$0.15 with a ceiling price of $3.50 per MMBtu on 10,000 MMBtu per day. We
recently determined that the above contracts do not qualify for hedge
accounting. As a result, we have revised previously reported amounts to account
for losses associated with these contracts on a mark-to-market
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<PAGE>
basis. See the Supplementary Quarterly Information Schedule (unaudited) on page
61 which incorporates the losses associated with these contracts. Because the
price of natural gas on March 31, 2001 was lower than the price at December 31,
2000, it is likely that we will recognize an unrealized gain for the first
quarter of 2001 on the contract that expires in October 2001.
We use the successful efforts method of accounting for our investments in
natural gas and oil properties. Under this method, we capitalize lease
acquisition costs and intangible drilling and development costs on successful
wells and development nonproductive wells. Depreciation, depletion and
amortization of these capitalized costs are computed separately for each field
based on the unit of production method using only proved natural gas and oil
reserves.
The successful efforts method of accounting requires us to review each of
our natural gas and oil properties on a field level for impairment when
circumstances indicate that the capitalized costs less accumulated
depreciation, depletion and amortization (also referred to as "carrying value")
of the property may not be recoverable. If the carrying value of the property
exceeds the expected future undiscounted cash flows, an amount equal to the
excess of the carrying value over the fair value of the property is charged as
an expense. An impairment results in a non-cash charge to earnings which
typically does not affect cash flow. Substantial impairment writedowns may
result in a reduction in our borrowing base under our bank credit facility
which would require us to use additional cash to reduce debt. Since 1998, we
have recorded impairments on different properties. Impairment expense
totaled $10.8 million in 2000, $7.5 million in 1999 and $5.1 million in 1998.
Since September 1999, we have granted options which are currently
outstanding to employees to purchase 23,752 shares of common stock at $1.40 per
share and 344,822 shares of common stock at $3.85 per share. One-third of the
options vest on each of April 10, 2001, February 9, 2002 and February 9, 2003.
We will recognize compensation expense based on the difference between the
exercise price for these options and the price of our stock offered to the
public in our initial public offering. The expense will be recognized in the
periods in which the options vest. Based upon the vesting schedule, we will
incur a non-cash compensation expense of approximately $3.2 million in 2001 and
approximately $0.6 million in 2002 relating to such option grants.
Results of Operations
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
Oil and Gas Revenue. Our revenue from natural gas and oil production for
2000 increased over 1999 by 117%, from $35.0 million to $75.9 million. This
increase resulted from increases of 51% in realized natural gas prices and 63%
in realized oil prices as well as a 41% increase in production. The increase in
production volumes from 17,301 MMcfe to 24,477 MMcfe was attributable to ten
properties that were on production during 2000 that were not on production
during 1999. Hedging transactions reduced oil and natural gas revenues by $28.2
million, or $1.16 per Mcfe, in 2000 and $3.8 million, or $0.22 per Mcfe, in
1999.
Marketing Revenue. During 2000, revenues from natural gas marketing
activities amounted to $8.0 million, an increase of $0.3 million from 1999. The
reason for the increase was a decrease in volumes offset by an increase in the
sales price per MMBtu. The daily natural gas contract decreased from 9,000
MMBtu per day in 1999 to 5,000 MMBtu per day in 2000. The decrease in volume
was offset by an average increase in the sales price per MMBtu from $2.34 in
1999 to $4.38 in 2000. For more information regarding this marketing activity,
please read "Subsidiary Activities" below.
Lease Operating Expense. Our lease operating expense for 2000 increased 107%
from $5.6 million to $11.6 million. This increase was primarily the result of
an increase in the number of producing wells owned by us, an increase in their
total production volume and an increase in the level of workover activity.
During 1999, we held a working interest in 23 producing blocks (29 producing
wells/24.7 net wells). During 2000, we held a working interest in 27 producing
blocks (36 producing wells/31.6 net wells). For 1999, our net production from
19
<PAGE>
these wells was 16,533 MMcf and 128,000 bbls. For 2000, our net production from
these wells was 22,410 MMcf and 345,000 bbls, an increase of 5,877 MMcf and
217,000 bbls. Workover spending increased from $0.4 million in 1999 to $2.6
million in 2000. The remaining increase in lease operating expense was
primarily attributable to transportation related costs. On a per Mcfe basis,
lease operating expense increased from $0.32 to $0.47.
Gas Purchased-Marketing. Our cost of purchased gas was $7.8 million for 2000
compared to $7.4 million for 1999. The daily gas contract amount in our third
party marketing arrangement decreased from 9,000 MMBtu per day in 1999 to 5,000
MMBtu per day in 2000. Lower volumes were offset by an increase in the average
gas cost from $2.25 per MMbtu in 1999 to $4.26 per MMbtu in 2000.
General and Administrative Expense. General and administrative expense
increased to $5.4 million for 2000 compared to $3.5 million for 1999. The
primary reason for the increase was the result of compensation and related
expenses increasing from $1.8 million to $3.3 million period to period. Our
total employees increased from 19 at December 31, 1999 to 33 at December 31,
2000. On an Mcfe basis, general and administrative expense was $0.22 in 2000
compared with $0.20 in 1999.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense increased 80% during 2000 from $22.5 million to $40.6
million. The average depreciation, depletion and amortization rate was $1.66
per Mcfe during 2000 compared with $1.30 per Mcfe in 1999.
Impairment Expense. As of December 31, 2000, the future undiscounted cash
flows for our properties were $931.2 million and the net book value for the
properties was $109.6 million before current year impairment expense. At
December 31, 1999, the future undiscounted cash flows for our properties were
$183.0 and the net book value for the properties was $79.8 million before
current year impairment expense. However, for three of our 33 properties in
2000 and four of our 26 properties in 1999, the future undiscounted cash flows
were less than their individual net book value. As a result, we recorded
impairments of $10.8 million in 2000 and $7.5 million in 1999. The impairments
in 2000 and 1999 were primarily the result of a reduction in recoverable
reserves individually attributable to the particular properties.
Loss on Speculative Position. For 2000 we recorded an expense of $4.3
million ($1.7 million realized and $2.6 million unrealized) on a natural gas
derivative position as a result of our hedging position exceeding our expected
production in an upcoming period. In this situation, we are required to account
for the position using the mark-to-market method. In addition, we recorded an
expense of $7.6 million ($3.0 million realized and $4.6 million unrealized)
related to mark-to-market losses associated with our written call option
contracts.
Other Expense. We recorded a charge of $0.5 million in 2000 relating to the
sale of a platform which was held for sale and included in other assets in
1999. There was no comparable expense for this account in 1999.
Other Income (Expense). For 2000, interest expense was $11.9 million
compared to $9.4 million for 1999. Our borrowings increased from period to
period but were offset by a decrease in interest rates under our new
development program credit agreement. As required by applicable accounting
pronouncements, we capitalize interest while a property is being developed
until it is ready to commence production. During 2000 we capitalized $0.7
million of interest, and we capitalized $0.6 million of interest in 1999.
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
Oil and Gas Revenue. Our revenue from natural gas and oil production for
1999 increased over 1998 revenues by 71.4%, from $20.4 million to $35.0 million
primarily as a result of increased production. Natural gas production increased
by 83.2% from 1998 to 1999 and realized natural gas prices fell by 3.4%. Oil
production decreased by 15.3% period to period but average realized prices for
oil increased by 33.7%. The increase in production volumes from 9,933 MMcfe to
17,301 MMcfe was attributable to new production resulting from development
activities on four properties which began production in the second half of
1998, new production resulting from development activities on four properties
that began producing in 1999, and
20
<PAGE>
production from producing properties acquired in the fourth quarter of 1998.
Hedging transactions reduced oil and natural gas revenues by $3.8 million, or
$0.22 per Mcfe, in 1999. We had no hedging transactions in 1998.
Marketing Revenue. During the year ended December 31, 1999, we recorded
revenues from gas marketing activities of $7.7 million. There were no
corresponding revenues for 1998. Gas marketing activities relate to the sale of
9,000 MMBtu per day to an unrelated entity. The average sales price during 1999
was $2.34 per MMBtu.
Lease Operating Expense. Our lease operating expense for 1999 increased by
75.0%, from $3.2 million to $5.6 million. The increase in expense was primarily
the result of an increase in our number of producing wells and our total
production volume. During 1998, we held a working interest in 22 producing
blocks (27 producing wells/19.5 net wells). During 1999, we held a working
interest in 23 producing blocks (29 producing wells/24.7 net wells). For 1998,
our net production from these wells was 9,026 MMcf and 151,152 bbls. For 1999,
our net production from these wells was 16,533 MMcf and 127,986 bbls, an
increase of 7,507 MMcf and a decrease of 23,166 bbls. On a per Mcfe basis,
lease operating expense remained unchanged at $0.32 per Mcfe.
Gas Purchased-Marketing. In 1999 we purchased 9,000 MMBtu per day for a
total cost of $7.4 million. The average cost of purchases in 1999 was $2.25 per
MMBtu. There was no corresponding expense in 1998.
General and Administrative Expense. General and administrative expense
increased to $3.5 million in 1999 from $2.6 million in 1998. The primary reason
for the increase was the result of compensation and related expenses increasing
to $1.8 million in 1999 compared with $1.2 million in 1998. Our total number of
employees increased from 11 at January 1, 1998 to 15 at December 31, 1998 and
to 19 at December 31, 1999. On an Mcfe basis, general and administrative
expense decreased from $0.26 during 1998 to $0.20 during 1999.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense increased 29.1% from $17.4 million in 1998 to $22.5
million in 1999. Our average depreciation, depletion and amortization rate was
$1.30 per Mcfe in 1999 and $1.76 per Mcfe in 1998. This decrease was
attributable to production in 1999 from properties that required a lower
relative development cost than the average cost of the producing properties in
1998.
Impairment Expense. As of December 31, 1999, the future undiscounted cash
flows for our properties were $183.0 million and the net book value for the
properties was $79.8 million before current year impairment expense. At
December 31, 1998, the future undiscounted cash flows for our properties were
$69.6 million and the net book value for the properties was $52.7 million
before current year impairment expense. However, for four of our 26 properties
in 1999 and four of our 20 properties in 1998, the future undiscounted cash
flows were less than their individual net book value. As a result, we recorded
impairments of $7.5 million in 1999 and $5.1 million in 1998. The impairments
in 1998 and 1999 were primarily the result of depressed natural gas and oil
prices and a reduction in recoverable reserves individually attributable to the
particular properties.
Other Income (Expense). Other income (expense) consists primarily of
interest income and interest expense. For the year ended December 31, 1999,
interest income was $0.2 million compared to $0.1 million for the same period
in 1998. This increase was primarily the result of the implementation of a new
cash management system in late 1999. For 1999, interest expense was $9.4
million compared to $8.0 million for 1998. This increase was primarily the
result of an increase in our non-recourse borrowings under our development
program credit agreement. During 1999, we capitalized $0.6 million of interest
incurred while developing properties. We capitalized $1.6 million during 1998
for the same purpose.
Extraordinary Gain. In June 1999, we agreed with the lender under a prior
development program credit agreement to prepay the amount outstanding at a
discount. As a result, we recorded an extraordinary gain of $29.2 million.
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<PAGE>
Liquidity and Capital Resources
We have financed our acquisition and development activity through a
combination of project-based development and bank borrowing as well as cash
from operations. At December 31, 2000, we had $88.8 million outstanding under
our development program credit agreement and $27.8 million outstanding under
our bank credit facility.
Our operating activities contributed cash flow, including changes in working
capital, as follows:
<TABLE>
<CAPTION>
Cash flow
Period from operations
------ ---------------
<S> <C>
1998......................... $13.2 million
1999......................... $10.8 million
2000......................... $56.6 million
</TABLE>
Development Program Credit Agreement
We entered into our current development program credit agreement in April
1999. Loans outstanding under the agreement are secured only by the properties
financed and are non-recourse to us, meaning that, if we default in making loan
payments, the lender can seek repayment only from the properties.
From April 1999 through December 2000, we included 14 properties in this
financing and obtained total funding of $118.2 million. The lender receives 90%
of the monthly net revenues (after payment of operating costs) from the pledged
properties. From April 1999 through December 2000, we made payments to the
lender of $42.8 million, including interest, under the facility. The average
interest rate was 11.5% in 1999 and 12.7% during 2000. At December 31, 2000,
the amount outstanding was $88.8 million at an interest rate of 13.0%.
The lender has overriding royalty interest rights in each of the 14
properties included in the collateral base for the development program credit
agreement. Ten of the 14 properties are subject to a 6.25% overriding royalty
interest which begins when the full amount of outstanding under the credit
agreement is repaid. The royalty interest is limited to the estimated proved
reserves attributable to the properties at the time the properties were added
to the collateral base less production after such date. Three of these ten
properties also are subject to a 3.125% overriding royalty on certain specified
levels of production above the proved reserves subject to the 6.25% interest.
The lender is not entitled to either of these interests unless the full amount
owed under the credit agreement has been repaid or the properties are removed
from the collateral base. Four of the 14 properties included in the collateral
base are subject to a 6.25% overriding royalty interest in all future
production when the full amount outstanding under the credit agreement is
repaid if the amounts outstanding under the credit agreement are not repaid in
full prior to May 1, 2001. This 6.25% interest is not limited to any specified
amount of reserves.
Since the amount of reserves attributable to these overriding royalty
interests depend upon the timing of our repayment of the amounts borrowed,
these overriding royalty interests are not reflected in the reserve information
included in this annual report. We will repay the full amount borrowed under
the development program credit agreement with the proceeds of our initial
public offering and cash on hand. Based on our expected level of production for
January through March 2001, our lender will receive overriding royalty
interests of 1.3 Bcf in the group of ten properties described above and no
interest in the other four properties when we make the final payment.
Bank Credit Agreement
In September 1998, we entered into a revolving credit facility with Chase
Bank of Texas, N.A., as administrative agent. The amount available for
borrowing under the facility is limited to the loan value, as determined by the
bank, of certain oil and gas properties pledged under the facility. At December
31, 2000, the borrowing base was $27.8 million, all of which was outstanding.
Our borrowings under the credit facility have been repaid in full as of March
30, 2001.
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<PAGE>
Advances under the credit facility can be in the form of either base rate
loans or Eurodollar loans. The interest on a base rate loan is a fluctuating
rate equal to the higher of the Federal funds rate plus 0.5% and the bank base
rate, plus a margin of either 0.625%, 0.875%, or 1.25% depending on the amount
outstanding under the credit agreement. The interest on a Eurodollar loan is
equal to the Eurodollar rate quoted by Chase Bank, plus a margin of 2.375%,
2.625%, or 3.00% depending on the amount outstanding under the credit facility.
The credit facility matures in January 2002. Prior to maturity, there are
scheduled reductions in the amount that may be outstanding. The average per
annum interest rate on borrowings under the credit facility was approximately
10.0% at December 31, 2000, 8.9% at December 31, 1999, and 8.1% at December 31,
1998.
In connection with our credit facility, we are not permitted to:
. enter into any arrangement to sell or transfer any of our material
property;
. merge into or consolidate with any other person or sell or dispose of all
or substantially all of our assets;
. allow the ratio of our current assets to our current liabilities to be
less than 1:1 at any time.
. allow our ratio of debt to our consolidated Adjusted EBITDA for four
consecutive quarters to be greater than 3 to 1.
. allow our ratio of Adjusted EBITDA for four consecutive quarters to
interest payments made during those quarters to be less than 2.5 to 1.
. declare or pay any cash dividend; purchase, redeem or otherwise acquire
for value any of our outstanding stock; return capital to shareholders;
or make any distribution of our assets to our shareholders.
As of December 31, 2000, we were in compliance with all of the financial
covenants of our credit facility other than our covenant to maintain a current
ratio of at least 1:1 for which we have obtained a waiver from our lender.
Capital Expenditures
Our capital expenditures consist primarily of acquisition and development
costs related to our oil and gas properties. We invested the following amounts
in oil and gas properties:
<TABLE>
<CAPTION>
Investments in
Oil and Gas
Period Properties
------ --------------
(In millions)
--------------
<S> <C>
1998:
Acquisition costs (5 properties)............................... $12.0
Development costs (6 properties)............................... 23.9
-----
$35.9
1999:
Acquisition costs (6 properties)(1)............................ $25.3
Development costs (14 properties).............................. 30.8
-----
$56.1
2000:
Acquisition costs (8 properties)(1)............................ $ 7.5
Development costs (19 properties).............................. 69.0
-----
$76.5
</TABLE>
- --------
(1) Acquisition costs include amounts paid to acquire additional working
interests in properties in which we did not already own a 100% working
interest.
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<PAGE>
We estimate our capital expenditure requirements on a project by project
basis. At the beginning of the year, we estimate the development costs for our
projects in inventory for that year. During the year as properties are acquired
and scheduled for development, our actual level of capital spending may
increase significantly. For example, at the beginning of 1999, we identified
capital expenditures on projects then in inventory of $11.1 million. As a
result of acquisition opportunities and additional development spending on
newly acquired properties, our capital expenditures for the year totaled $56.1
million. At the beginning of 2000, we had identified capital expenditures of
$29.0 million for development projects in inventory. As a result of current
year acquisitions and additional development expenditures on newly acquired
projects, at December 31, 2000, we had incurred capital expenditures of $76.5
million. Based on our inventory of properties at December 31, 2000 we had
identified capital expenditures of $84.9 million for 2001 and $52.6 million in
future years. Included in these capital expenditures are $0.5 million in 2001
for dismantlement, restoration and abandonment costs and $17.5 million in
future years. In addition, we are constantly seeking new opportunities that fit
our business strategy. Thus far in 2001 we have closed on eleven new properties
for total acquisition costs of $25.3 million and have executed a letter of
intent to acquire another property for an acquisition cost of approximately
$1.3 million. See "Properties--Acquisitions During 2001". Our desire to
continue to acquire more natural gas and oil reserves in a year than we produce
will result in our incurring additional capital expenditures for properties
that we acquire in the future.
We depend entirely on the acquisition and development of new properties to
replace our existing reserves. Therefore, we will continue to seek
opportunities for acquisitions of proved reserves with development potential.
The size and timing of capital requirements for acquisitions is inherently
unpredictable. Actual levels of future capital expenditures and their timing
may vary significantly due to a variety of factors, including:
. drilling results;
. product prices;
. industry conditions and outlook; and
. future acquisitions of properties.
We believe that cash flow from operations and borrowings will be sufficient
to fund our operations through 2001.
We believe that our capital resources are adequate to meet the requirements
of our business. However, future cash flows are subject to a number of
variables including the level of production and oil and natural gas prices. We
cannot assure you that operations and other capital resources will provide cash
in sufficient amounts to maintain planned levels of capital expenditures.
Subsidiary Activities
In December 1998, our wholly-owned subsidiary, ATP Energy, entered into an
agreement to purchase gas over a ten-year period commencing January 1999. The
amount of gas to be purchased was 9,000 MMBtu per day for the first year and
5,000 MMBtu per day for years two through ten. The contract requires ATP Energy
to purchase the gas on a monthly basis at a premium to the Gas Daily Henry Hub
Index. The seller is required to reimburse ATP Energy on a monthly basis for a
portion of this premium during the term of the contract. The terms of the
agreement provide for immediate termination upon non-performance by the seller.
ATP Energy entered into a contract in December 1998 to sell an identical
quantity of natural gas at the Gas Daily Henry Hub index price less $0.015
until December 2001.
ATP Energy received $6.0 million in connection with these transactions of
which $2.0 million was recorded as deferred revenue and $4.0 million was
recorded as deferred obligations as of December 31, 1998. The deferred revenue
amount of $2.0 million is a non-refundable fee received by ATP Energy and is
recognized into income as earned over the life of the contract. The deferred
obligation amount of $4.0 million represented the difference between the
premium we agreed to pay for natural gas under the contract and the obligation
of
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the seller to partially reimburse us for such premium. Any deferred obligation
amount not utilized is refundable if the contract is terminated. The remaining
balance of the deferred obligation was $0.1 million at December 31, 2000. The
premium we pay to the seller will be approximately the same as the
reimbursement obligation for the remainder of the contract. ATP Energy entered
into the transactions to earn the fee for agreeing to market the volumes of
natural gas specified in the contract. At the end of this agreement in December
2001, we may renew the agreement or enter into another marketing arrangement
having similar terms.
We formed ATP Oil & Gas (UK) Limited on May 5, 2000 to conduct our
activities in the Southern Gas Basin of the U.K. North Sea. See "Item 2,
Properties--Significant Acquisitions in Progress" for a description of our
pending acquisitions in the U.K.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for
Derivative Instruments and Hedging Activities, and in June 2000, the FASB
issued SFAS No. 138, Accounting for Certain Derivative Instruments and Certain
Hedging Activities, an amendment of FASB Statement No. 133. These statements
establish standards of accounting for and disclosures of derivative instruments
and hedging activities. We adopted this standard on January 1, 2001. We have
elected not to account for our hedging activities under the hedge accounting
provisions allowed in the standard. This will result in increased earnings
volatility associated with commodity price fluctuations as all of our
derivative financial instruments will be accounted for on a mark-to-market
basis beginning January 1, 2001. We estimate that effect of the transition
adjustment, after taxes, will be a non-cash reduction of approximately $35.0
million to other comprehensive income on January 1, 2001.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Interest Rate Risk
We are exposed to changes in interest rates. Changes in interest rates
affect the interest earned on our cash and cash equivalents and the interest
rate paid on borrowings under the credit agreements. Under our current
policies, we do not use interest rate derivative instruments to manage exposure
to interest rate changes.
Commodity Price Risk
Our revenues, profitability and future growth depend substantially on
prevailing prices for natural gas and oil. Prices also affect the amount of
cash flow available for capital expenditures and our ability to borrow and
raise additional capital. The amount we can borrow under our bank credit
facility is subject to periodic re-determination based in part on changing
expectations of future prices. Lower prices may also reduce the amount of
natural gas and oil that we can economically produce. We currently sell most of
our natural gas and oil production under price sensitive or market price
contracts. To reduce exposure to fluctuations in natural gas and oil prices and
to achieve more predictable cash flow, we periodically enter into hedging
arrangements that usually consist of swaps or price collars that are settled in
cash. However, these contracts also limit the benefits we would realize if
commodity prices increase. Our internal hedging policy provides that we examine
the economic effect of entering into a commodity contract with respect to the
properties that we acquire. We generally acquire properties at prices that are
below the value of estimated reserves at the then current natural gas and oil
prices. We will enter into short term hedging arrangements if we are able to
obtain commodity contracts at prices sufficient to secure an acceptable
internal rate of return on a particular property or on a group of properties.
As of December 31, 2000, we had no oil hedges outstanding. All of our commodity
derivative financial instruments will be accounted for on a mark-to-market
basis beginning January 1, 2001.
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<PAGE>
As of December 31, 2000, we had the following financial hedges on natural
gas outstanding:
<TABLE>
<CAPTION>
SWAPS
-----------------
Average Average
Period MMBtu/Day $/MMBtu
- ------ --------- -------
<S> <C> <C>
First quarter 2001........................................... 69,700 3.05
Second quarter 2001.......................................... 29,000 2.83
Third quarter 2001........................................... 28,400 2.84
Fourth quarter 2001(1)....................................... 9,300 2.87
</TABLE>
- --------
(1) We have no gas hedges beyond October 2001.
In addition to the above financial hedges on natural gas, during 2000 we
entered into a written call option contract that provides us a price for
natural gas above the then prevailing market price, but with a ceiling price.
For the period April 2001 through October 2001, we receive NYMEX settlement
plus $0.15 with a ceiling price of $3.50 per MMBtu on 10,000 MMBtu per day.
On occasion, we may find ourselves in speculative positions as a result of
actual production being less than projected production when the derivative
products were consummated or as a result of entering into speculative
derivative instruments. Any speculative positions are accounted for using the
mark-to-market method. Under this methodology, contracts are adjusted to market
value, and the gains and losses are recognized in current period income.
Item 8. Financial Statements and Supplementary Data
The consolidated financial statements and supplementary data of ATP appear
on pages 38 through 55 hereof and are incorporated by reference into this Item
8. Selected quarterly financial data is set forth in the Supplementary
Quarterly Information Schedule on page 61, which is incorporated herein by
reference.
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
None.
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PART III
Item 10. Directors and Executive Officers of Registrant
Directors, Executive Officers and Other Key Employees
The following table sets forth the names, ages and positions of our
executive officers, directors and other key employees as of March 30, 2001.
<TABLE>
<CAPTION>
Name Age Position
- ---- --- --------
<S> <C> <C>
T. Paul Bulmahn........... 57 Chairman, President and Director
Gerald W. Schlief......... 53 Senior Vice President
Albert L. Reese, Jr....... 51 Senior Vice President and Chief Financial Officer
Leland E. Tate............ 53 Senior Vice President, Operations
John E. Tschirhart........ 50 Vice President, General Counsel
G. Ross Frazer............ 45 Vice President, Engineering
Keith R. Godwin........... 33 Vice President and Controller
Carol E. Overbey.......... 49 Vice President, Corporate Secretary and Director
Arthur H. Dilly........... 71 Director
Gerard J. Swonke.......... 56 Director
Robert C. Thomas.......... 72 Director
Walter Wendlandt.......... 71 Director
</TABLE>
The following biographies describe the business experience of our executive
officers, directors and other key employees.
T. Paul Bulmahn (BA, JD, MBA) has served as our Chairman and President since
he founded the company in 1991. In 1991, he was elected Chairman, Houston Bar
Association Oil, Gas and Mineral Law Section, and in 1992 was elected to serve
for a three year term on the Oil & Gas Council of the State Bar of Texas. From
1988 to 1991, Mr. Bulmahn served as President and Director of Harbert Oil & Gas
Corporation. From 1984 to 1988, Mr. Bulmahn served as Vice President, General
Counsel of Plumb Oil Company. From 1978 to 1984, Mr. Bulmahn served as counsel
for Tenneco's interstate gas pipelines and as regulatory counsel in Washington,
D.C. From 1973 to 1978, Mr. Bulmahn served the Railroad Commission of Texas,
the Public Utility Commission and the Interstate Commerce Commission as an
administrative law judge. He has chaired various oil and gas industry seminars,
including "Marginal Offshore Field Development" in 1996 and the "Upstream Oil
and Gas E-Business Conference" in 2000, and has been a faculty lecturer in
natural gas regulations. In June 2000, Mr. Bulmahn was selected Entrepreneur Of
The Year 2000 in Energy & Energy Services by Ernst & Young LLP.
Gerald W. Schlief (BBA, CPA, MBA) has served as our Senior Vice President
since 1993 and is primarily responsible for acquisitions. Between 1990 and
1993, Mr. Schlief acted as a consultant for the onshore and offshore
independent oil and gas industry. From 1984 to 1990, Mr. Schlief served as Vice
President, Offshore Land for Plumb Oil Company where he managed the acquisition
of interests in over 35 offshore properties. From 1983 to 1984, Mr. Schlief
served as Offshore Land Consultant for Huffco Petroleum Corporation. He served
as Treasurer and Landman for Huthnance Energy Corporation from 1981 to 1983. In
addition, from 1974 to 1978, Mr. Schlief conducted audits of oil and gas
companies for Arthur Andersen & Co., and from 1978 to 1981, he conducted audits
of oil and gas companies for Spicer & Oppenheim.
Albert L. Reese, Jr. (BBA, CPA, MBA) has served as our Chief Financial
Officer since March 1999 and, in a consulting capacity, as our director of
finance from 1991 until March 1999. He was also named Senior Vice President in
August 2000. From 1986 to 1991, Mr. Reese was employed with the Harbert
Corporation where he established a registered investment bank for the company
to conduct project and corporate financings for energy, cogeneration, and small
power activities. From 1979 to 1986, Mr. Reese served as chief financial
officer of Plumb Oil Company and its successor, Harbert Energy Corporation.
Prior to 1979, Mr. Reese served
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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 (BS--Petroleum Engineering) has served as our Senior Vice
President, Operations, since August 2000. Prior to joining ATP, Mr. Tate worked
for over 30 years with Atlantic Richfield Company, a global energy company.
From 1998 until July 2000, Mr. Tate served as the President of ARCO North
Africa. He also was Director General of Joint Ventures at ARCO from 1996 to
1998. From 1994 to 1996, Mr. Tate served as ARCO's Vice President Operations &
Engineering, where he led technical negotiations in field development. Prior to
1994, Mr. Tate's positions with ARCO included Director of Operations, ARCO
British Ltd., where he was responsible for all operations in the North Sea;
Vice President of Engineering, ARCO International; Senior Vice President
Marketing and Operations, ARCO Indonesia; and for three years was Vice
President and District Manager in Lafayette, Louisiana, where he managed
operations on the Outer Continental Shelf and deep water of the Gulf of Mexico.
John E. Tschirhart (BS--Marine Transportation, JD) joined us in November
1997 and has served as our Vice President, General Counsel since March 1998.
Mr. Tschirhart was named Managing Director of ATP Oil & Gas (UK) Limited in
July 2000. From 1993 to November 1997, Mr. Tschirhart worked as a partner at
the law firm of Tschirhart and Daines, a partnership in Houston, Texas where he
represented business clients in the energy industry. From 1985 to 1993 Mr.
Tschirhart was in private practice handling civil litigation matters including
oil and gas and employment law. From 1979 to 1985, he was with Coastal Oil &
Gas Corporation and from 1974 to 1979 he was with Shell Oil Company.
G. Ross Frazer (BS Summa Cum Laude--Nuclear Engineering) joined us in August
2000 as Vice President, Engineering. From 1993 to August 2000, he was with
British-Borneo Exploration, Inc., an independent natural gas and oil company,
as operations manager, engineering manager, and engineering design verification
manager. This included responsibility for engineering and design verification
for the deep water Gulf of Mexico Morpeth field in 1,700 feet of water and the
Allegheny field in 3,300 feet of water. From 1997 to 1998, he was Chairman of
the American Petroleum Institute Houston Chapter Advisory Board and presently
serves on its Deep Water Operations Steering Committee.
Keith R. Godwin (BBA, CPA) has served as our Controller since May 1997 and
was named a Vice President in August 2000. From 1995 to May 1997, Mr. Godwin
was in private industry as Corporate Accounting Manager with Champion
Healthcare Corporation, a publicly traded healthcare company. From 1990 to
1995, Mr. Godwin was employed as an accountant with the independent accounting
firm of Coopers & Lybrand L.L.P. where he conducted audits primarily in the
energy industry.
Carol E. Overbey (BSW, AAS--RN) has served as a director and our Corporate
Secretary since 1991 and has served as Vice President since August 2000. Ms.
Overbey served as our Treasurer from 1991 to 1999. From 1985 to 1991, Ms.
Overbey was Vice President/Controller of Continuity Corporation. She also
served in 1991 as Assistant to the President at Harbert Oil & Gas Corporation
and assisted in developing gas marketing operations.
Arthur H. Dilly (BA with honors, MA) has served as a director since January
2001. From 1981 to 1998, Mr. Dilly served as Executive Secretary of the Board
of Regents of the University of Texas System. He currently serves as Chairman
and Chief Executive Officer of Austin Geriatrics Center, Inc., a nonprofit
agency providing elderly support services, a post he has held since 1990. He
has served as Vice Chairman of the Board of Directors of the Shivers Cancer
Foundation, a nonprofit organization providing patient support services and
education, since 1998. From 1978 to 1981, he was Executive Director for
Development, The University of Texas System.
Gerard J. Swonke (BA--Economics, JD) has served as a director since 1995.
Since 1985, he has been Of Counsel to the law firm of Greenberg, Peden,
Siegmyer & Oshman, P.C. representing domestic and international oil and gas
clients in contract drafting and negotiations, including in Indonesia, Africa
and the North Sea. From
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1975 to 1985 he was Counsel for Aminoil, Inc. with responsibility for onshore
and offshore matters. From 1967 to 1974 when he received his law degree he was
Controller for Automated Systems Corporation with responsibility for corporate
accounting and preparation of financial statements and corporate tax returns.
Robert C. Thomas (BS--Geological Engineering) has served as a director since
January 2001. Since 1994, Mr. Thomas has served as Chairman of the Board of The
Sarkeys Energy Center of the University of Oklahoma and as a Senior Associate
with Cambridge Energy Research Associates, an independent energy consulting
firm. Additionally, he has served as Vice Chairman of the Gas Research
Institute Advisory Council (now Gas Technology Institute), since 1998. In 1994,
Mr. Thomas stepped down as Chairman and Chief Executive Officer of Tenneco Gas
when he reached mandatory retirement age after thirty-eight years with Tenneco
beginning in 1956. He was elected president of Tenneco Gas in 1983 and chairman
and chief executive officer in 1990. He was with Tenneco's domestic exploration
and production operations until 1970 when he was elected Vice President of
Tenneco Oil Company's Canadian subsidiary with responsibility for all
engineering, drilling, processing plant and production operations. Mr. Thomas
is presently a member of the Board of Directors of Marine Drilling Companies,
Inc. and PetroCorp Incorporated. He is immediate past Chairman of the Board of
Directors of the YMCA of the Greater Houston Area and President of the Board of
Directors of Houston Hospice. He additionally has served on the Board of
Governors of The Houston Forum. Mr. Thomas has also served over 10 years on
each of the following Board of Directors: The Interstate Natural Gas
Association of America (INGAA), the American Gas Association (AGA), Gas
Research Institute (GRI), and the Institute of Gas Technology (IGT). From 1989
to 1994 he was a member of the National Petroleum Council (NPC) and served as a
Vice President of the International Association of LNG Importers (GIIGNL)
headquartered in Paris.
Walter Wendlandt (BS--Mechanical Engineering, JD) has served as a director
since January 2001. He was Director, Railroad Commission of Texas for a total
of eighteen years during the period from 1961 to 1985. Mr. Wendlandt has been a
sole practitioner of law since 1984. He served as a Trustee of the Augustana
Annuity Trust from 1964 to 1992, a Director of the Georgetown Railroad from
1979 to 1982, and Director of Lamar Savings Association in 1989. He
additionally has served as President, National Conference of State
Transportation Specialists; Chairman, State Bar Committee on Public Utilities
Law; and was a member for six years of the Technical Pipeline Safety Standards
Committee of the U.S. Department of Transportation.
Board of Directors
Our board of directors currently has six members divided into three classes.
The members of each class serve staggered, three-year terms. Upon the
expiration of the term of a class of directors, directors in that class are
elected for three-year terms at the annual meeting of shareholders in the year
in which their term expires. The classes are as follows:
. Class I Directors. Mr. Bulmahn and Mr. Swonke are Class I Directors whose
terms will expire at the 2004 annual meeting of shareholders;
. Class II Directors. Ms. Overbey and Mr. Wendlandt are Class II Directors
whose terms will expire at the 2002 annual meeting of shareholders; and
. Class III Directors. Mr. Thomas and Mr. Dilly are Class III Directors
whose terms will expire at the 2003 annual meeting of shareholders.
Committees of the Board of Directors
Our board of directors has established an audit committee and a compensation
committee.
Audit Committee
The audit committee consists of Messrs. Swonke, Thomas and Wendlandt. The
audit committee is responsible for:
. recommending annually to our board of directors the selection of our
independent public accountants;
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. reviewing and approving the scope of our independent public accountants'
audit activity and the extent of non-audit services;
. reviewing with management and the independent public accountants the
adequacy of our basic accounting systems and the effectiveness of our
internal audit plan and activities;
. reviewing our financial statements with management and the independent
public accountants and exercising general oversight of our financial
reporting process; and
. reviewing our litigation and other legal matters that may affect our
financial condition and monitoring compliance with our business ethics
and other policies.
Compensation Committee
The compensation committee consists of Messrs. Thomas, Dilly and Swonke.
This committee's responsibilities include:
. administering and granting awards under our 2000 Stock Plan;
. reviewing the compensation of our President and recommendations of the
President as to appropriate compensation for our other executive officers
and key personnel;
. examining periodically our general compensation structure; and