-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, LRWoqJxa73oCSZDNU2Z00e1VXXeW4sEAVEGZaMluBsI3nIJUuJyHuDE3CnkHBeid NDA7YUCWit3K7n1Ia/FPnQ== 0000899243-02-000928.txt : 20020415 0000899243-02-000928.hdr.sgml : 20020415 ACCESSION NUMBER: 0000899243-02-000928 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 20011231 FILED AS OF DATE: 20020401 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-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-32261 FILM NUMBER: 02598124 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 10-K 1 d10k.txt FORM 10K ============================================================================== SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31, 2001 Commission file number: 000-32261 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 ATP OIL & GAS CORPORATION (Exact name of registrant as specified in its charter) Texas 76-0362774 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 4600 Post Oak Place, Suite 200 Houston, Texas 77027 (Address of principal executive offices) (Zip Code) (Registrant's telephone number, including area code): (713) 622-3311 Securities Registered Pursuant to Section 12 (b) of the Act: Title of each class Name of exchange on which registered - ----------------------------- ----------------------------------------- Common Stock, par NASDAQ value $.001 per share Securities Registered Pursuant to Section 12 (g) of the Act: None Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. On March 21, 2002, there were 20,312,648 shares of the Registrant's Common Stock outstanding. The aggregate value of the Common Stock held by non-affiliates of the Registrant (treating all executive officers and directors of the registrant, for this purpose, as if they are affiliates of the Registrant) was approximately $29,020,963 on March 21, 2002 (based on $4.80 per share, the last sale price of the Common Stock as reported on the NASDAQ National Market System on such date). DOCUMENTS INCORPORATED BY REFERENCE: The information required in Part III of the Annual Report on Form 10-K is incorporated by reference to the Registrant's definitive proxy statement to be filed pursuant to Regulation 14A for the Registrant's Annual Meeting of Stockholders. =============================================================================== ATP OIL & GAS CORPORATION AND SUBSIDIARIES 2001 FORM 10-K ANNUAL REPORT TABLE OF CONTENTS Page ---- Part I...................................................................... 6 Item 1. Business ....................................................... 6 Item 2. Properties...................................................... 14 Item 3. Legal Proceedings............................................... 17 Item 4. Submission of Matters to a Vote of Security Holders............. 18 Part II..................................................................... 20 Item 5. Market for Registrants Common Units and Related Security Holder Matters......................................... 20 Item 6. Selected Financial Data......................................... 21 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....................................... 23 Item 7a. Quantitative and Qualitative Disclosures about Market Risk...... 40 Item 8. Financial Statements and Supplementary Data..................... 41 Item 9. Disagreements on Accounting and Financial Disclosure............ 41 Part III.................................................................... 42 Item 10. Directors and Executive Officers of Registrant ................. 42 Item 11. Executive Compensation.......................................... 42 Item 12. Security Ownership of Certain Beneficial Owners and Management.. 42 Item 13. Certain Relationships and Related Transactions.................. 42 Part IV..................................................................... 43 Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................. 43 2 CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS This annual report on Form 10-K includes assumptions, expectations, projections, intentions or beliefs about future events. These statements are intended as "forward-looking statements" under the Private Securities Litigation Reform Act of 1995. We caution that assumptions, expectations, projections, intentions and beliefs about future events may and often do vary from actual results and the differences can be material. All statements in this document that are not statements of historical fact are forward looking statements. Forward looking statements include, but are not limited to: . projected operating or financial results; . budgeted or projected capital expenditures; . statements about pending or recent acquisitions, including the anticipated closing dates; . expectations regarding our planned expansions and the availability of acquisition opportunities; . statements about the expected drilling of wells and other planned development activities; . expectations regarding natural gas and oil markets in the United States and the United Kingdom; and . timing and amount of future production of natural gas and oil. When used in this document, the words "anticipate," "estimate," "project," "forecast," "may," "should," and "expect" reflect forward-looking statements. There can be no assurance that actual results will not differ materially from those expressed or implied in such forward looking statements. Some of the key factors which could cause actual results to vary from those expected include: . the timing and extent of changes in natural gas and oil prices; . the timing of planned capital expenditures and availability of acquisitions; . the inherent uncertainties in estimating proved reserves and forecasting production results; . operational factors affecting the commencement or maintenance of producing wells, including catastrophic weather related damage, unscheduled outages or repairs, or unanticipated changes in drilling equipment costs or rig availability; . the condition of the capital markets generally, which will be affected by interest rates, foreign currency fluctuations and general economic conditions; . cost and other effects of legal and administrative proceedings, settlements, investigations and claims, including environmental liabilities which may not be covered by indemnity or insurance; and . other United States or United Kingdom regulatory or legislative developments which affect the demand for natural gas or oil generally, increase the environmental compliance cost for our production wells or impose liabilities on the owners of such wells. 3 CERTAIN DEFINITIONS As used herein, the following terms have specific meanings as set forth below: Bbls Barrels of crude oil or other liquid hydrocarbons Bcfe Billion cubic feet equivalent MBbls Thousand barrels of crude oil or other liquid hydrocarbons Mcf Thousand cubic feet of natural gas Mcfe Thousand cubic feet equivalent MMBbls Million barrels of crude oil or other liquid hydrocarbons MMBtu Million British Thermal Units MMcf Million cubic feet of natural gas MMcfe Million cubic feet equivalent U.S. United States U.K. United Kingdom Crude oil and other liquid hydrocarbons are converted into cubic feet of gas equivalent based on six Mcf of gas to one barrel of crude oil or other liquid hydrocarbons. Development well is a well drilled within the proved area of an oil or natural gas field to the depth of a stratigraphic horizon known to be productive. Dry hole is a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Exploratory well is a well drilled to find and produce natural gas or oil reserves that is not a development well. Farm-in or farm-out is an agreement whereby the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in," while the interest transferred by the assignor is a "farm-out." Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition. Net feet of natural gas and condensate is the true vertical thickness of reservoir rock estimated to both contain hydrocarbons and be capable of contributing to producing rates. Pre-tax PV-10 is the estimated future net revenue to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future development costs, using prices and costs in effect as of a certain date, without escalation and without giving effect to non-property related expenses, such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion, and amortization. Productive well is a well that is producing or is capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Proved reserves are the estimated quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, can be recovered in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if shown to be economically producible by either actual production or conclusive formation tests. 4 Proved developed reserves are the portion of proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are the portion of proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Reserve life index is a measure of the productive life of a natural gas and oil property or a group of natural gas and oil properties, expressed in years. Reserve life equals the estimated net proved reserves attributable to property or group of properties divided by production from the property or group of properties for the four fiscal quarters preceding the date as of which the proved reserves were estimated. Shallow-deep waters are the waters in the Gulf of Mexico located between the continental shelf and water depths of up to approximately 3,000 feet. Working interest is the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production. Workover is operations on a producing well to restore or increase production. 5 PART I ITEM 1. BUSINESS GENERAL ATP Oil & Gas Corporation ("ATP") was incorporated in Texas in 1991. We are engaged in the acquisition, development and production of natural gas and oil properties in the outer continental shelf of the Gulf of Mexico, in the shallow-deep waters of the Gulf of Mexico and in the Southern Gas Basin of the North Sea. We primarily focus our efforts on natural gas and oil properties with proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies. We attempt to achieve a high return on our investment in these properties by limiting our up-front acquisition costs and by developing our acquisitions quickly. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties in both our current and planned areas of operation. At December 31, 2001, we had estimated net proved reserves of 235.0 Bcfe, an increase of 87% over the previous year-end, of which approximately 154.4 Bcfe (66%) was in the Gulf of Mexico and 80.6 Bcf (34%) was in the U.K. North Sea. Year-end reserves were comprised of 194.5 Bcf of natural gas and 6.8 MMBbls of oil. All of our oil reserves are located in the Gulf of Mexico and approximately 59% of our natural gas reserves are located in the Gulf of Mexico with the balance in the U.K. North Sea. The estimated pre-tax PV-10 of our reserves at December 31, 2001 was $264.3 million. Prices used in the U.S. reserve estimates were $2.65 per MMBtu of natural gas and $19.78 per barrel of oil with $3.88 per MMBtu of natural gas for the U.K reserve estimates. At December 31, 2001, natural gas accounted for 83% of our reserves, proved developed reserves comprised 32% of our total reserves and our reserve life index for total proved reserves was 9.1 years. At December 31, 2001, we had leasehold and other interests in 52 offshore blocks, 27 platforms and 74 wells, including seven subsea wells, in the federal waters of the Gulf of Mexico. We operate 56 of these 74 wells, including all of the subsea wells, and 67% of our offshore platforms. We also had interests in five foreign blocks in the U.K. sector of the North Sea. Our average working interest in our properties at December 31, 2001 was approximately 82%. We produced approximately 25.7 Bcfe in 2001, an increase of 5% over the previous year. For the five-year period since 1997, we have increased our annual production at a compounded annual growth rate of 74%. We increase our reserves and production exclusively through the acquisition and development of proved natural gas and oil properties. During 2001, we replaced 527% of 2001 production through our reserve replacement activities. OUR BUSINESS STRATEGY Our business strategy is to enhance shareholder value primarily through the acquisition, development and production of proved undeveloped natural gas and oil reserves in areas that have: . a substantial existing infrastructure of oil and natural gas pipelines and production/processing platforms; . geographic proximity to well-developed markets for natural gas and oil; . a large number of properties that major oil companies, exploration-oriented independents and others consider non-strategic; and . a relatively stable history of consistently applied governmental regulations for offshore natural gas and oil development and production. 6 We believe our strategy significantly reduces the risks associated with traditional natural gas and oil exploration. Unlike oil and gas companies that conduct exploration activities, our focus is to acquire properties that have been previously explored by others and found to contain proved reserves. During the life span of these properties, they may become non-core or non-strategic to their original owners. Reasons that a property may become non-core or non-strategic are varied. For example, companies may elect to concentrate their efforts elsewhere, to reduce their capital spending for development, or to pursue exploration projects as opposed to development projects. Also, a lease expiration date may be approaching and the owner may be unwilling to complete a development program. Companies pursuing exploration success may discover hydrocarbons which may not provide an acceptable economic return for them but which may prove attractive to us as we do not have the time or expense they do in the project. If such a project is economically attractive to us and is in our core areas, we will attempt to acquire the project. Each natural gas and oil discovery by another company in our core areas is a potential opportunity for the application of our approach. We focus on developing projects in the shortest time possible between initial investment and first revenue generated in order to maximize our rate of return. Since we usually operate the properties in which we acquire a working interest and begin a development program with proved reserves, we are able to expeditiously commence a project's development. We typically initiate new development projects by simultaneously obtaining the various required components such as the pipeline and the production platform or subsea well completion equipment. This strategy, combined with our ability to rapidly evaluate and implement a project's requirements, allows us to complete the development project and commence production as quickly and efficiently as possible. OUR STRENGTHS . Operating Control. As the operator of a property, we are afforded greater control of the selection of completion and production equipment, the timing and amount of capital expenditures and the operating parameters and costs of the project. As of December 31, 2001, we operated 67% of our offshore platforms, 100% of our subsea wells and 100% of our properties under development. . Low Cost Structure. We believe that our focus on a low cost structure with minimal cash investment for acquisitions allows us to pursue the acquisition, development and production of properties that may not be economically attractive to others. For the three-year period ended December 31, 2001, our total average cost incurred for finding and developing our net proved reserves was $0.96 per Mcfe. . Technical Expertise and Significant Experience. We have assembled a technical staff with an average of 19 years of industry experience. Our technical staff has specific expertise in offshore property development, including the implementation of subsea completion technology. . Employee Ownership. Through employee ownership, we have built a staff whose business decisions are aligned with our shareholders. Our employees own 70% of ATP on a fully diluted basis. . Operating Efficiency. We emphasize a low overhead and operating expense structure. For 2001, our lease operating expense was $0.58 per Mcfe of production and our general and administrative expense was $0.39 per Mcfe of production. INITIAL PUBLIC OFFERING On February 5, 2001, we successfully completed an initial public offering ("IPO") of 6.0 million shares of common stock and commenced trading the following day. After payment of the underwriting discount we received net proceeds of $78.3 million on February 9, 2001. We used the net proceeds from the IPO, together with the proceeds from a new credit facility, to repay all outstanding debt under a development program credit agreement and a prior bank credit facility and to acquire and develop additional natural gas and oil reserves. 7 MARKETING AND DELIVERY COMMITMENTS We sell our natural gas and oil production under price sensitive or market price contracts. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. The price received by us for our non-hedged natural gas and oil production can fluctuate widely. Changes in the prices of natural gas and oil will affect the carrying value of our proved reserves and our revenues, profitability and cash flow. Although we are not currently experiencing any significant involuntary curtailment of our natural gas or oil production, market, economic and regulatory factors may in the future materially affect our ability to sell our natural gas or oil production. We sell a portion of our natural gas and oil to end users through various gas marketing companies. We are not dependent upon, or confined to, any one purchaser or small group of purchasers. Due to the nature of natural gas and oil markets and because natural gas and oil are commodities and there are numerous purchasers in the areas in which we sell production, we do not believe the loss of a single purchaser, or a few purchasers, would materially affect our ability to sell our production. COMPETITION We compete with major and independent natural gas and oil companies for property acquisitions. We also compete for the equipment and labor required to operate and to develop these properties. Some of our competitors have substantially greater financial and other resources and may be able to sustain wide fluctuations in the economics of our industry easier than we can. Since we are in a highly regulated industry they may be able to absorb the burden of any changes in federal, state and local laws and regulations easier than we can. Our ability to acquire and develop additional properties in the future will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. REGULATION Federal Regulation of Sales and Transportation of Natural Gas. Historically, the transportation and sale for resale of natural gas in interstate commerce is regulated pursuant to the Natural Gas Act of 1938 ("the Natural Gas Act"), the Natural Gas Policy Act of 1978 and Federal Energy Regulatory Commission ("FERC") regulations. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of natural gas sales by producers began with the enactment of the Natural Gas Policy Act of 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act of 1938 and Natural Gas Policy Act of 1978 price and non-price controls affecting producer sales of natural gas effective January 1, 1993. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation are subject to extensive federal regulation. Beginning in April 1992, the FERC issued Order No. 636 and a series of related orders, which required interstate pipelines to provide open-access transportation on a not unduly discriminatory basis for all natural gas shippers. The FERC stated that Order No. 636 and the FERC's future restructuring activities are intended to foster increased competition within all phases of the natural gas industry. Although the regulations instituted by Order No. 636 do not directly apply to our production and marketing activities, they do affect how buyers and sellers gain access to the necessary transportation facilities and how we and our competitors sell natural gas in the marketplace. The courts have largely affirmed the significant features of Order No. 636 and the numerous related orders pertaining to individual pipelines. Subsequent to Order No. 636, the FERC continued to modify its regulations regarding the transportation of natural gas. 8 In February 2000, the FERC issued Order No. 637 which: . lifts the cost-based cap on pipeline transportation rates in the capacity release market until September 30, 2002, for short-term releases of pipeline capacity of less than one year; . permits pipelines to file for authority to charge different maximum cost-based rates for peak and off-peak periods; . encourages, but does not mandate, auctions for pipeline capacity; . requires pipelines to implement imbalance management services; . restricts the ability of pipelines to impose penalties for imbalances, overruns and non-compliance with operational flow orders; and . implements a number of new pipeline reporting requirements. Order No. 637 also requested that the FERC staff analyze whether the FERC should implement additional fundamental policy changes. These include whether to pursue performance-based or other non-cost based ratemaking techniques and whether the FERC should mandate greater standardization in terms and conditions of service across the interstate pipeline grid. Appeals of Order No. 637 remain pending. In April 1999, the FERC issued Order No. 603, which implemented new regulations governing the procedure for obtaining authorization to construct and operate new pipeline facilities or to abandon facilities under Section 7 of the Natural Gas Act. In September 1999 the FERC issued a related policy statement establishing a presumption in favor of requiring owners of new pipeline facilities to charge rates for service on new pipeline facilities based solely on the costs associated with such new pipeline facilities. We cannot predict what further action the FERC will take on these or related matters, nor can we accurately predict whether the FERC's actions will achieve the goal of increasing competition in markets in which our natural gas is sold. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers. The Outer Continental Shelf Lands Act, which the FERC implements with regard to transportation and pipeline issues, requires that all pipelines operating on or across the Outer Continental Shelf provide open-access, non-discriminatory service. Historically, the FERC has opted not to impose regulatory requirements under its Outer Continental Shelf Lands Act authority on gatherers and other entities outside the reach of its Natural Gas Act jurisdiction. However in April 2000, the FERC issued Order No. 639, requiring that virtually all non-proprietary pipeline transporters of natural gas on the Outer Continental Shelf report information on their affiliations, rates and terms and conditions of service. The reporting requirements established by the FERC in Order No. 639 may apply, in certain circumstances, to operators of production platforms and other facilities on the Outer Continental Shelf, with respect to gas movements across such facilities. Among FERC's stated purposes in issuing such rules was the desire to increase transparency in the market, to provide producers and shippers on the Outer Continental Shelf with greater assurance of (a) open-access services on pipelines located on the Outer Continental Shelf and (b) non-discriminatory rates and conditions of service on such pipelines. In January 2002, the U.S. District Court for the District of Columbia permanently enjoined the FERC from enforcing Order No. 639 and related orders; it is unclear whether this court order will be appealed. The FERC retains authority under the Outer Continental Shelf Lands Act to exercise jurisdiction over gatherers and other entities outside the reach of its Natural Gas Act jurisdiction if necessary to insure non-discriminatory access to service on the Outer Continental Shelf. We do not believe that any FERC action taken under its Outer Continental Shelf Lands Act jurisdiction will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue. 9 Federal Leases. A substantial portion of our operations is located on federal natural gas and oil leases, which are administered by the Minerals Management Service ("MMS") pursuant to the Outer Continental Shelf Lands Act. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed MMS regulations and orders that are subject to interpretation and change by the MMS. For offshore operations, lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the Outer Continental Shelf to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities. To cover the various obligations of lessees on the Outer Continental Shelf, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. We currently have several supplemental bonds in place. Under some circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations. The MMS also administers the collection of royalties under the terms of the Outer Continental Shelf Lands Act and the oil and gas leases issued under the Act. The amount of royalties due is based upon the terms of the oil and gas leases as well as of the regulations promulgated by the MMS. These regulations are amended from time to time, and the amendments can affect the amount of royalties that we are obligated to pay to the MMS. However, we do not believe that these regulations or any future amendments will affect us in a way that materially differs from the way it affects other oil and gas producers, gathers and marketers. Oil Price Controls and Transportation Rates. Sales of crude oil, condensate and natural gas liquids by us are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERC's regulation of gas pipelines under the Natural Gas Act. Regulated pipelines that transport crude oil, condensate, and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, issued in October 1993, pipeline rates are subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge market-based rates if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. As provided for in Order No. 561, in July 2000, the FERC issued a Notice of Inquiry seeking comment on whether to retain or to change the existing oil rate-indexing method. In 10 December 2000, the FERC issued an order concluding that the rate index reasonably estimated the actual cost changes in the pipeline industry and should be continued for another 5-year period, subject to review in July 2005. Appeals of the FERC's December 2000 order are pending. With respect to intrastate crude oil, condensate and natural gas liquids pipelines subject to the jurisdiction of state agencies, such state regulation is generally less rigorous than the regulation of interstate pipelines. State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests. Complaints or protests have been infrequent and are usually resolved informally. We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate, or natural gas liquids pipelines will affect us in a way that materially differs from the way it affects other crude oil, condensate, and natural gas liquids producers or marketers. Environmental Regulations. Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. Offshore drilling in some areas has been opposed by environmental groups and, in some areas, has been restricted. To the extent laws are enacted or other governmental action is taken that prohibits or restricts offshore drilling or imposes environmental protection requirements that result in increased costs to the natural gas and oil industry in general and the offshore drilling industry in particular, our business and prospects could be adversely affected. The Oil Pollution Act of 1990 and related regulations impose a variety of regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. A "responsible party" includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The Oil Pollution Act of 1990 assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75.0 million in other damages. Few defenses exist to the liability imposed by the Oil Pollution Act of 1990. The Oil Pollution Act of 1990 also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. As amended by the Coast Guard Authorization Act of 1996, the Oil Pollution Act of 1990 requires parties responsible for offshore facilities to provide financial assurance in the amount of $35.0 million to cover potential Oil Pollution Act of 1990 liabilities. This amount can be increased up to $150.0 million if a study by the MMS indicates that an amount higher than $35.0 million should be required. On August 11, 1998, the MMS adopted a rule implementing the Oil Pollution Act of 1990 financial responsibility requirements. We are in compliance with this rule. In addition, the Outer Continental Shelf Lands Act authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms and structures. Violations of lease conditions or regulations issued pursuant to the Outer Continental Shelf Lands Act can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or private prosecution. 11 The Oil Pollution Act of 1990 also imposes other requirements, such as the preparation of an oil spill contingency plan. We have such a plan in place. We are also regulated by the Clean Water Act, which prohibits any discharge into waters of the U.S. except in strict conformance with discharge permits issued by federal or state agencies. We have obtained, and are in material compliance with, the discharge permits necessary for our operations. We could become subject to similar state and local water quality laws and regulations in the future if we conduct production or drilling activities in state coastal waters. Failure to comply with the ongoing requirements of the Clean Water Act or inadequate cooperation during a spill event may subject a responsible party to civil or criminal enforcement actions. The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We could be subject to liability under CERCLA because our drilling and production activities generate relatively small amounts of liquid and solid wastes that may be subject to classification as hazardous substances under CERCLA. These wastes must be brought to shore for proper disposal under the Resource Conservation and Recovery Act. We minimize this potential liability by selecting reputable contractors to dispose of our wastes at government-approved landfills or other types of disposal facilities. Our operations are also subject to regulation of air emissions under the Clean Air Act and the Outer Continental Shelf Lands Act. Implementation of these laws could lead to the gradual imposition of new air pollution control requirements on our operations. Therefore, we may incur capital expenditures over the next several years to upgrade our air pollution control equipment. We could also become subject to similar state and local air quality laws and regulations in the future if we conduct production or drilling activities instate coastal waters. We do not believe that our operations would be materially affected by any such requirements, nor do we expect such requirements to be anymore burdensome to us than to other companies our size involved in natural gas and oil development and production activities. In addition, legislation has been proposed in Congress from time to time that would reclassify some natural gas and oil exploration and production wastes as "hazardous wastes," which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If Congress were to enact this legislation, it could increase our operating costs, as well as those of the natural gas and oil industry in general. Initiatives to further regulate the disposal of natural gas and oil wastes are also pending in some states, and these various initiatives could have a similar impact on us. Our management believes that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us. U.K. Regulations of Natural Gas and Oil Production. Pursuant to the Petroleum Act 1998, all natural gas and oil reserves contained in properties located in Great Britain are the property of the U.K. government. The development and production of natural gas and oil reserves in the U.K. North Sea requires a petroleum production license granted by the U.K. government. Prior to developing a field, we are required to obtain from the Secretary of State for Trade and Industry a consent to develop that field. We would be required to obtain the consent of the Secretary of State for Trade and Industry in the event we transfer an interest in a license. 12 The terms of the petroleum production licenses are based on model license clauses applicable at the time of the issuance of the license. Licenses frequently contain regulatory provisions governing matters such as working method, pollution and training, and reserve to the Secretary of State for Trade and Industry the power to direct some of the licensee's activities. For example, a licensee may be precluded from carrying out development or production activities other than with the consent of the Secretary of State for Trade and Industry or in accordance with a development plan which the Secretary of State for Trade and Industry has approved. Breach of these requirements may result in the revocation of the license. In addition, licenses that we acquire may require us to pay fees and royalties on production and also impose certain other duties on us. Our operations in the U.K. are subject to the Petroleum Act 1998, which imposes a health and safety regime on offshore natural gas and oil production activities. The Petroleum Act 1998 also regulates the abandonment of facilities by licensees. In addition, the Mineral Workings (Offshore Installations) Act provides a framework in which the government can impose additional regulations relating to health and safety. Since its enactment, a number of regulations have been promulgated relating to offshore construction and operation of offshore production facilities. Health and safety offshore is further governed by the Health and Safety at Work Act 1974 and applicable regulations. Our operations are also subject to environmental laws and regulations imposed by both the European Union and the U.K. Parliament. Petroleum production licenses require the approval of the Secretary of State for Trade and Industry of a licensee to act as operator and who organizes or supervises all or any of the development and production operations of natural gas and oil properties subject thereto. As an operator, we may obtain operational services from third parties, but will remain fully responsible for the operations as if we conduct them ourselves. Our operations in the U.K. may entail the construction of offshore pipelines, which are subject to the provisions of the Petroleum Act 1998 and other legislation. The Petroleum Act 1998 requires a license to construct and operate a pipeline in U.K. North Sea, including its continental shelf. Easements to permit the laying of pipelines must be obtained from the Crown Estate Commissioners prior to their construction. We plan to use capacity in existing offshore pipelines in order to transport our gas. However, access to the pipelines of a third party would need to be obtained on a negotiated basis, and there is no assurance that we can obtain access to existing pipelines or, if access is obtained, it may only be on terms that are not favorable to us. The natural gas we produce may be transported through the U.K.'s onshore national gas transmission system, or NTS. The NTS is owned by a licensed gas transporter, BG Transco plc ("Transco"). The terms on which Transco must transport gas are governed by the Gas Acts of 1986 and 1995, the gas transporter's license issued to Transco under those Acts and a network code. For us to use the NTS, we must obtain a shipper's license under the Gas Acts and arrange to have gas transported by Transco within the NTS. We will therefore be subject to the network code, which imposes obligations to payment, gas flow nominations, capacity booking and system imbalance. Applying for and complying with a shipper's license, and acting as a gas shipper, is expensive and administratively burdensome. Alternatively, we may sell natural gas 'at the beach' before it enters the NTS or arrange with an existing gas shipper for them to ship the gas through the NTS on our behalf. EMPLOYEES At December 31, 2001 we had 39 full-time employees in our Houston office and six full-time employees and seven contract personnel in our London office. None of our employees are covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well-site supervision, permitting and environmental assessment. Independent contractors usually perform field and on-site production operation services for us, including gauging, maintenance, dispatching, inspection and well testing. 13 ITEM 2. PROPERTIES GENERAL Since inception we have engaged in the acquisition, development and production of natural gas and oil properties primarily in the outer continental shelf of the Gulf of Mexico. In 2000 we expanded our business to include the acquisition and development of properties in the shallow-deep waters of the Gulf of Mexico and in the Southern Gas Basin of the North Sea. At December 31, 2001, we had leasehold and other interests in 52 offshore blocks, 27 platforms and 74 wells, including seven subsea wells, in the federal waters of the Gulf of Mexico. We operate 56 of these 74 wells, including all of the subsea wells, and 67% of our offshore platforms. We also held interests in five foreign blocks located in the U.K. sector of the North Sea. Our average working interest in our properties at December 31, 2001 was approximately 82%. As of December 31, 2001, we had leasehold interests located in the Gulf of Mexico and the U.K. covering approximately 246,000 gross and 196,000 net acres. ACQUISITIONS Gulf of Mexico During 2001, we acquired interests in 15 lease blocks covering 14 properties in six separate transactions. Total reserves associated with these transactions were approximately 60.6 Bcfe, based on third party reservoir engineering estimates at year-end, for total acquisition costs of approximately $22.7 million. Our working interests in these properties range from 25% to 100%. Ten of these properties produced in 2001 with additional development and production planned on the remaining four in 2002 and beyond. During 2000 we acquired an interest in 11 lease blocks covering nine separate properties for total acquisition costs of $7.5 million. Net proved reserves associated with these acquisitions were approximately 66.0 Bcfe based on third party reservoir engineering estimates. Our working interests in these properties range from 50% to 100%. We are the operator of all of the properties. Included in these acquisitions were four blocks on three separate properties which represent our first acquisitions in the shallow-deep waters of the Gulf of Mexico. Of these nine properties, five were producing in 2001, including "Ladybug", one of the properties in the shallow-deep waters of the Gulf of Mexico, and a sixth property commenced production in the first quarter of 2002. Two of the properties are scheduled for future development in 2002 and beyond and the remaining property was abandoned without commencing production in 2001. Southern Gas Basin of the North Sea In October 2000, we entered into a letter of intent to acquire interests in three properties (five blocks) in the Southern Gas Basin of the North Sea which included a 50% interest in one block, a 100% interest in one block and an 86% interest in three blocks. In 2001, we acquired all three properties for total acquisition costs of approximately $3.1 million. At December 31, 2001, net proved reserves were approximately 80.6 Bcfe, based on third party reservoir engineering estimates at year-end. None of the properties were producing when acquired and we expect to pursue development operations in 2002 through 2004. NATURAL GAS AND OIL RESERVES The following table presents our estimated net proved natural gas and oil reserves and the net present value of our reserves at December 31, 2001 based on reserve reports prepared by Ryder Scott Company, L.P. for our domestic reserves and Troy-Ikoda Limited for our U.K. reserves. 14 The present value of future net cash flows before income taxes as of December 31, 2001 was determined by using the December 31, 2001 prices of $2.65 per MMBtu and $3.88 per MMBtu of natural gas for the U.S. and U.K, respectively, and $19.78 per Bbl of oil for the U.S. The present values, discounted at 10% per annum, of estimated future net cash flows before income taxes shown in the table are not intended to represent the current market value of the estimated natural gas and oil reserves we own. Proved Reserves ------------------------------------- Developed Undeveloped Total ----------- ----------- ----------- Domestic Natural gas (MMcf).................. 56,704 57,176 113,880 Oil and condensate (MBbls).......... 3,115 3,638 6,753 Total proved reserves (MMcfe)....... 75,394 79,004 154,398 Pre-tax PV-10 (in thousands)........ $ 133,500 $ 66,513 $ 200,013 U.K. Natural gas (MMcf).................. - 80,629 80,629 Pre-tax PV-10 (in thousands)........ $ - $ 64,265 $ 64,265 Total Natural gas (MMcf).................. 56,704 137,805 194,509 Oil and condensate (MBbls).......... 3,115 3,638 6,753 Total proved reserves (MMcfe)....... 75,394 159,633 235,027 Pre-tax PV-10 (in thousands)........ $ 133,500 $ 130,778 $ 264,278 Our estimates of proved reserves in the table above do not differ from those we have filed with other federal agencies. The process of estimating natural gas and oil reserves is complex. It requires various assumptions, including assumptions relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. We must project production rates and timing of development expenditures. We analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. Therefore, estimates of natural gas and oil reserves are inherently imprecise. In accordance with the Securities and Exchange Commission ("SEC") requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the net present value estimate. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates and these variances may be material. Our business strategy is to acquire proved reserves, usually proved undeveloped, and to bring those reserves on production as rapidly as possible. At December 31, 2001, all of our reserves in the U.K. and approximately 51% of our estimated equivalent net proved reserves in the Gulf of Mexico were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling and completion operations. The reserve data assumes that we will make these expenditures. Although we estimate our reserves and the costs associated with developing them in accordance with industry standards, the estimated costs may be inaccurate, development may not occur as scheduled and results may not be as estimated. 15 The following table highlights our history of bringing our offshore blocks with proved undeveloped reserves to production:
2001 2000 1999 ------------------------ ------------------------ ------------------------- Undeveloped Developed Undeveloped Developed Undeveloped Developed ----------- ---------- ----------- ----------- ----------- ---------- At January 1........................ 10 30 7 24 11 22 Acquisitions........................ 11(1) 9 10 1 7 1 Divestitures and expirations........ (1) (8) - (2) (9)(2) (1) Undeveloped to productive........... (4) 4 (7) 7 (2) 2 Undeveloped to nonproductive........ (1) - - - - - ----------- ----------- ----------- ----------- ----------- ----------- At December 31...................... 15 35 10 30 7 24 =========== =========== =========== =========== =========== ===========
_______________________ (1) Includes interests in five blocks in the Southern Gas Basin of the North Sea. (2) These were undeveloped exploration blocks that we sold. We retained a future net profits interest in seven of those blocks. DRILLING ACTIVITY The following table shows our drilling and completion activity. In the table, "gross" refers to the total wells in which we have a working interest and "net" refers to gross wells multiplied by our working interest in such wells. We did not drill or complete any exploratory wells in any period presented.
Years Ended December 31, ---------------------------------------------------------------- 2001 2000 1999 -------------------- -------------------- -------------------- Gross Net Gross Net Gross Net --------- --------- --------- --------- --------- --------- Development Wells: Productive................................... 8.0 6.3 12.0 11.0 3.0 2.2 Nonproductive................................ 1.0 1.0 1.0 1.0 - - --------- --------- --------- --------- --------- --------- Total..................................... 9.0 7.3 13.0 12.0 3.0 2.2 ========= ========= ========= ======== ========= =========
As of December 31, 2001, there were no wells in the process of drilling or completing. PRODUCTIVE WELLS The following table presents the number of domestic productive natural gas and oil wells in which we owned an interest as of December 31, 2001. Total Productive Wells(1) ----------------------------- Gross Net ------------- ------------- Natural gas............................... 38.0 30.4 Oil .................................... 9.0 4.4 ------------- ------------- Total.................................. 47.0 34.8 ============= ============= (1) Includes eight gross and 6.8 net wells with multiple completions. We had no productive wells in the U.K. at December 31, 2001. 16 ACREAGE The following table summarizes our domestic and foreign developed and undeveloped acreage holdings at December 31, 2001. Acreage in which ownership interest is limited to royalty, overriding royalty and other similar interests is excluded (in acres):
Developed(1) Undeveloped(2) Total -------------------- -------------------- -------------------- Gross Net Gross Net Gross Net --------- --------- --------- --------- --------- --------- Domestic: Gulf of Mexico - Shelf....................... 157,128 122,979 17,500 16,250 174,628 139,229 Gulf of Mexico - Shallow-Deep Waters......... 5,760 2,880 15,189 15,189 20,949 18,069 --------- -------- -------- --------- --------- -------- 162,888 125,859 32,689 31,439 195,577 157,298 --------- -------- -------- --------- --------- -------- Foreign: Southern Gas Basin of the North Sea.......... - - 50,234 39,034 50,234 39,034 --------- -------- -------- --------- --------- -------- 162,888 125,859 82,923 70,473 245,811 196,332 ========= ======== ======== ========= ========= =======
________________ (1) Developed acres are acres spaced or assigned to productive wells. (2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil, regardless of whether such acreage contains proved reserves. PRODUCTION AND PRICING DATA Information on production and pricing data is contained in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations". ITEM 3. LEGAL PROCEEDINGS On August 28, 2001 ATP entered into a written agreement to acquire a property in the Gulf of Mexico during September 2001. On October 9, 2001 the agreement was amended to ultimately extend the closing date until October 31, 2001 in exchange for payments made by ATP totaling $3.0 million. This amendment also contained an arrangement whereby if ATP did not close on the property, and if sellers sold the property to a third party with a sale that met specific contract requirements, ATP would be required to execute a six month note for payment of the differential. Since ATP did not obtain the financing for the acquisition by October 31, 2001, the transaction did not close by that date; however, the parties' intensive work toward closing continued beyond that date without interruption. While working on the closing for the property with ATP, the sellers sold the property to a third party without informing ATP until after the closing had taken place. ATP filed an action in the District Court of Harris County, Texas against the sellers, generally alleging improper sale of the offshore property to a third party and breach of contract, and seeking unspecified damages from the sellers. The case is encaptioned ATP Oil & Gas Corporation vs. Legacy Resources Co., L.P. et al, No. 2001-63224 in the 269th Judicial District Court of Harris County, Texas. At the same time sellers notified ATP of their sale to a third party, the sellers had a demand made upon ATP for execution of a six month note for the amount of an alleged differential of approximately $12.3 million plus interest at 16%. Substantiation of the amount and validity of the demand could not be ascertained based on the content of the demand received. ATP contested the entire demand. The litigation is in its very early stages with written discovery propounded by ATP, but no answers received, and no depositions taken. The judge has abated the litigation, until arbitration pursuant to the underlying agreements between the sellers and ATP is completed. Since the legal proceedings have just begun, and a prediction of the outcome would be premature and uncertain, we have not accrued any amount related to this matter. And while we are seeking recovery of the amounts previously paid and discussed above, the $3.0 million has been charged to earnings along with certain other costs related to this matter. ATP intends to vigorously defend against the sellers' claims and forcefully pursue its own claims in this matter. 17 In August 2001, Burlington Resources Inc. filed suit against us alleging formation of a contract with us and our breach of the alleged contract. The complaint seeks compensatory damages of approximately $1.1 million. We believe that this claim is without merit, and we intend to defend it vigorously. We are, in the ordinary course of business, a claimant and/or defendant in various legal proceedings. Management does not believe that the outcome of these legal proceedings, individually, and in the aggregate will have a materially adverse effect on our financial condition, results of operations or cash flows. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the fourth quarter of 2001. EXECUTIVE OFFICERS OF THE COMPANY Set forth below are the names, ages (as of March 21, 2002) and titles of the persons currently serving as executive officers of the Company. All executive officers hold office until their successors are elected and qualified.
Name Age Position - ---- --- -------- T. Paul Bulmahn........................ 58 Chairman, President and Director Gerald W. Schlief...................... 54 Senior Vice President Albert L. Reese, Jr.................... 52 Senior Vice President and Chief Financial Officer Leland E. Tate......................... 54 Senior Vice President, Operations John E. Tschirhart..................... 51 Senior Vice President, General Counsel Carol E. Overbey....................... 50 Vice President, Corporate Secretary and Director
T. Paul Bulmahn has served as our Chairman and President since he founded the company in 1991. From 1988 to 1991, Mr. Bulmahn served as President and Director of Harbert Oil & Gas Corporation. From 1984 to 1988, Mr. Bulmahn served as Vice President, General Counsel of Plumb Oil Company. From 1978 to 1984, Mr. Bulmahn served as counsel for Tenneco's interstate gas pipelines and as regulatory counsel in Washington, D.C. From 1973 to 1978, he served the Railroad Commission of Texas, the Public Utility Commission and the Interstate Commerce Commission as an administrative law judge. Gerald W. Schlief has served as our Senior Vice President since 1993 and is primarily responsible for acquisitions. Between 1990 and 1993, Mr. Schlief acted as a consultant for the onshore and offshore independent oil and gas industry. From 1984 to 1990, Mr. Schlief served as Vice President, Offshore Land for Plumb Oil Company where he managed the acquisition of interests in over 35 offshore properties. From 1983 to 1984, Mr. Schlief served as Offshore Land Consultant for Huffco Petroleum Corporation. He served as Treasurer and Landman for Huthnance Energy Corporation from 1981 to 1983. In addition, from 1974 to 1978, Mr. Schlief conducted audits of oil and gas companies for Arthur Andersen & Co., and from 1978 to 1981, he conducted audits of oil and gas companies for Spicer & Oppenheim. Albert L. Reese, Jr. has served as our Chief Financial Officer since March 1999 and, in a consulting capacity, as our director of finance from 1991 until March 1999. He was also named Senior Vice President in August 2000. From 1986 to 1991, Mr. Reese was employed with the Harbert Corporation where he established a registered investment bank for the company to conduct project and corporate financings for energy, co-generation, and small power activities. From 1979 to 1986, Mr. Reese served as chief financial officer of Plumb Oil Company and its successor, Harbert Energy Corporation. Prior to 1979, Mr. Reese served in various capacities with Capital Bank in Houston, the independent accounting firm of Peat, Marwick & Mitchell, and as a partner in Arnold, Reese & Swenson, a Houston-based accounting firm specializing in energy clients. 18 Leland E. Tate has served as our Senior Vice President, Operations, since August 2000. Prior to joining ATP, Mr. Tate worked for over 30 years with Atlantic Richfield Company. From 1998 until July 2000, Mr. Tate served as the President of ARCO North Africa. He also was Director General of Joint Ventures at ARCO from 1996 to 1998. From 1994 to 1996, Mr. Tate served as ARCO's Vice President Operations & Engineering, where he led technical negotiations in field development. Prior to 1994, Mr. Tate's positions with ARCO included Director of Operations, ARCO British Ltd.; Vice President of Engineering, ARCO International; Senior Vice President Marketing and Operations, ARCO Indonesia; and for three years was Vice President and District Manager in Lafayette, Louisiana. John E. Tschirhart joined us in November 1997 and has served as our General Counsel since March 1998. Mr. Tschirhart was named Senior Vice President in July 2001 and served as Managing Director of ATP Oil & Gas (UK) Limited from May 2000 to May 2001. From 1993 to November 1997, Mr. Tschirhart worked as a partner at the law firm of Tschirhart and Daines, a partnership in Houston, Texas. From 1985 to 1993 Mr. Tschirhart was in private practice handling civil litigation matters including oil and gas and employment law. From 1979 to 1985, he was with Coastal Oil & Gas Corporation and from 1974 to 1979 he was with Shell Oil Company. Carol E. Overbey has served as a director and our Corporate Secretary since 1991 and has served as Vice President since August 2000. Ms. Overbey served as our Treasurer from 1991 to 1999. From 1985 to 1991, Ms. Overbey was Vice President/Controller of Continuity Corporation. 19 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.001 per share, and 10,000,000 shares of preferred stock, par value $0.001 per share. There were 20,312,648 shares of common stock and no shares of preferred stock outstanding as of March 21, 2002. There were 24 holders of record of our common stock as of March 21, 2002. Our common stock is traded on the Nasdaq National Market under the ticker symbol ATPG. There was no public market for our common stock before February 6, 2001. The following tables sets forth the range of high and low closing sales prices for the common stock as reported on the Nasdaq National Market for the periods indicated below: High Low ------------ ------------ 2001: - ----- 1st Quarter $ 14.5625 $ 9.8750 2nd Quarter 12.9600 8.7100 3rd Quarter 12.0000 6.6100 4th Quarter 7.1500 2.0000 We have never declared or paid any cash dividends on our common stock. We currently intend to retain future earnings and other cash resources, if any, for the operation and development of our business and do not anticipate paying any cash dividends on our common stock in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our current credit facility prohibits us from paying cash dividends on our common stock. Any future dividends may also be restricted by any loan agreements which we may enter into from time to time. 20 ITEM 6. SELECTED FINANCIAL DATA (in thousands, except per share data and percentages) The selected historical financial information was derived from, and is qualified by reference to our consolidated financial statements, including the notes thereto, appearing elsewhere in this report. The following data should be read in conjunction with "Item 7. - Management's Discussion and Analysis of Financial Condition and Results of Operations".
Years Ended December 31, --------------------------------------------------------------- 2001 2000 1999 1998 1997 ----------- ----------- ----------- ----------- ----------- Statement of Operations Data: Revenues: Oil and gas production...................... $ 105,757 $ 75,940 $ 34,981 $ 20,410 $ 7,359 Gas sold - marketing........................ 7,417 8,015 7,703 - - Gain on sale of oil and gas properties...... - 33 287 - 304 ----------- ----------- ----------- ----------- ----------- Total revenues............................ 113,174 83,988 42,971 20,410 7,663 ----------- ----------- ----------- ----------- ----------- Cost and operating expenses: Lease operating............................. 14,806 11,559 5,587 3,193 1,513 Gas purchased - marketing................... 7,218 7,788 7,402 - - Geological and geophysical expenses......... 1,068 - - - - General and administrative.................. 9,981 5,409 3,541 2,591 1,170 Non-cash compensation expense............... 3,364 - - - - Depreciation, depletion and amortization.... 53,428 40,569 22,521 17,442 4,206 Impairment of oil and gas properties........ 24,891 10,838 7,509 5,072 5,787 Loss on unsuccessful property acquisition... 3,147 - - - - Other expense............................... - 450 - - - ---------- ----------- ----------- ----------- ----------- Total operating expenses.................... 117,903 76,613 46,560 28,298 12,676 ---------- ----------- ----------- ----------- ----------- Income (loss) from operations................. (4,729) 7,375 (3,589) (7,888) (5,013) Other income (expense): Interest income............................. 884 451 202 141 207 Interest expense............................ (10,039) (11,907) (9,399) (7,963) (1,212) Realized loss on derivative instruments..... (19,348) (4,662) - - - Unrealized gain (loss) on derivative instruments 1,265 (7,249) - - - ---------- ---------- ---------- ---------- ----------- Loss before income taxes and extraordinary gain (loss) .................. (31,967) (15,992) (12,786) (15,710) (6,018) Income tax benefit............................ 11,186 5,594 1,829 - - ---------- ---------- ---------- ---------- ----------- Loss before extraordinary gain (loss)......... (20,781) (10,398) (10,957) (15,710) (6,018) Extraordinary gain (loss), net of tax......... (602) - 29,185 - - ---------- ---------- ---------- ---------- ----------- Net income (loss)............................. $ (21,383) $ (10,398) $ 18,228 $ (15,710) $ (6,018) ========== ========== ========== ========== =========== Weighted average number of common shares outstanding: Basic and diluted......................... 19,704 14,286 14,286 11,926 10,568 Loss per common share before extraordinary gain (loss): Basic and diluted......................... $ (1.06) $ (0.73) $ (0.77) $ (1.32) $ (0.57) Net income (loss) per common share: Basic and diluted......................... $ (1.09) $ (0.73) $ 1.28 $ (1.32) $ (0.57)
Table and footnotes continued on following page 21
Years Ended December 31, --------------------------------------------------------------- 2001 2000 1999 1998 1997 ----------- ----------- ----------- ----------- ----------- Other Financial Data: Adjusted EBITDA(1)............................. $ 58,490 $ 54,570 $ 26,643 $ 14,767 $ 5,187 Adjusted EBITDA margin(2)...................... 62% 65% 62% 72% 68% As of December 31, --------------------------------------------------------------- 2001 2000 1999 1998 1997 ----------- ----------- ----------- ----------- ----------- Balance Sheet Data: Cash and cash equivalents...................... $ 5,294 $ 18,136 $ 17,779 $ 3,411 $ 1,806 Working capital................................ (29,071) (3,835) 14,115 (5,106) 3,340 Net oil and gas properties..................... 133,033 98,725 72,278 47,612 33,355 Total assets................................... 177,564 161,993 107,054 61,354 48,906 Total debt..................................... 100,111 116,529 91,723 62,690 42,194 Total liabilities.............................. 132,572 175,172 109,835 82,363 54,217 Shareholders' equity (deficit)................. 44,992 (13,179) (2,781) (21,009) (5,311)
_________________ (1) Adjusted EBITDA means net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, impairment of natural gas and oil properties, non-cash compensation expense, unrealized gains and losses and extraordinary items. Adjusted EBITDA is not a calculation based on generally accepted accounting principles and should not be considered as an alternative to net income (loss) or operating income (loss), as an indicator of a company's financial performance or to cash flow as a measure of liquidity. In addition, our Adjusted EBITDA calculation may not be comparable to other similarly titled measures of other companies. Adjusted EBITDA is included as a supplemental disclosure because it may provide useful information regarding our ability to service debt and to fund capital expenditures. (2) Represents Adjusted EBITDA divided by total revenues for the years ended December 31, 1997 through 2000. For the year ended December 31, 2001, Adjusted EBITDA margin is Adjusted EBITDA divided by the sum of total revenues and realized loss on derivative instruments. 22 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW We are engaged in the acquisition, development and production of natural gas and oil properties in the outer continental shelf of the Gulf of Mexico, in the shallow-deep waters of the Gulf of Mexico and in the Southern Gas Basin of the North Sea. We primarily focus our efforts on natural gas and oil properties with proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies. We attempt to achieve a high return on our investment in these properties by limiting our up-front acquisition costs and by developing our acquisitions quickly. INITIAL PUBLIC OFFERING On February 5, 2001, we priced our IPO of 6.0 million shares of common stock and commenced trading the following day. After payment of the underwriting discount we received net proceeds of $78.3 million on February 9, 2001, excluding offering costs of approximately $1.5 million. We used the net proceeds from our IPO, together with the proceeds from our new credit facility, to repay all of our outstanding debt under our development program credit agreement and our prior bank credit facility and to acquire natural gas and oil properties. CRITICAL ACCOUNTING POLICIES Financial Reporting Release No. 60, which was recently released by the SEC, recommends that all companies include a discussion of critical accounting policies or methods used in the preparation of financial statements. Note 2 of the Notes to Consolidated Financial Statements includes a summary of the significant accounting policies and methods used in the preparation of our Consolidated Financial Statements. The following is a brief discussion of the more significant accounting policies and methods used by us. Oil and Gas Reserves The process of estimating quantities of natural gas and crude oil reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. We use the units-of-production method to amortize our oil and gas properties. This method requires us to amortize the capitalized costs incurred in developing a property in proportion to the amount of oil and gas produced as a percentage of the amount of proved reserves contained in the property. Accordingly, changes in reserve estimates as described above will cause corresponding changes in depletion expense recognized in periods subsequent to the reserve estimate revision. See the Supplemental Information for reserve data in our Consolidated Financial Statements. Oil and Gas Producing Activities We follow the "successful efforts" method of accounting for oil and gas properties. Under this method, lease acquisition costs and intangible drilling and development costs on successful wells and development dry holes are capitalized. Capitalized costs relating to producing properties are depleted on the unit- of-production method. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves for depletion rates of leasehold, platform and pipeline costs. Estimated dismantlement, restoration and abandonment costs and estimated residual salvage values are taken into account in determining amortization and depletion provisions. Expenditures for geological and geophysical are incurred for development purposes only. These costs are generally charged to expense unless the costs can be specifically attributed to determining the placement for a future well location. Expenditures for repairs and maintenance are charged to expense as incurred; renewals and betterments are capitalized. The costs and related accumulated depreciation, depletion, and amortization of properties sold or otherwise retired are eliminated from the accounts, and gains or losses on disposition are reflected in the statements of operations. We perform an impairment analysis whenever events or changes in circumstances indicate that our estimate of a particular asset's fair value, or carrying amount, may not be recoverable. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying published future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineer's estimate of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities For properties determined to be impaired, an impairment loss equal to the differences between the carrying value and the fair value of the impaired property will be recognized. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units' reserves, future cash flows and fair value. 23 Contingent Liabilities In preparing financial statements at any point in time, management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for prolonged periods of time. As discussed in Part I, Item 3. - "Legal Proceedings" and the Notes to Consolidated Financial Statements, we are involved in actions, which if determined adversely, could have a material negative impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of ATP's probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. Although it is difficult to predict the ultimate outcome of these matters, management believes that the recorded amounts, if any, are reasonable. Based on a critical assessment of our accounting policies and the underlying judgments and uncertainties affecting the application of those policies, management believes that our consolidated financial statements provide a meaningful and fair perspective of our company. RESULTS OF OPERATIONS Prior to the January 1, 2001 adoption of Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standard ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133") and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities ("SFAS 138"), an amendment to SFAS 133, we included the effects of our risk management activities as an offset to revenue. Upon adoption of the standard, any gains or losses from these activities are now included in other income (expense), as we did not account for our hedging activities under the hedge accounting provisions allowed in the standard. For comparative purposes though, the following table sets forth selected financial and operating information for our natural gas and oil operations inclusive of the effects of risk management activities:
Years Ended December 31, ------------------------------------------------ 2001 2000 1999 ------------- ------------- ------------- Production: Natural gas (MMcf).......................................... 20,957 22,410 16,533 Oil and condensate (MBbls).................................. 790 345 128 ------------- ------------- ------------- Total (MMcfe)............................................ 25,696 24,477 17,301 ============= ============= ============= Revenues (in thousands): Natural gas................................................. $ 88,908 $ 94,051 $ 36,856 Effects of risk management activities(1).................... (24,369) (26,729) (3,842) ------------- ------------- ------------- Total ................................................... $ 64,539 $ 67,322 $ 33,014 ============= ============= ============= Oil and condensate.......................................... $ 16,849 $ 10,112 $ 1,967 Effects of risk management activities....................... - (1,494) - ------------- ------------- ------------- Total ................................................... $ 16,849 $ 8,618 $ 1,967 ============= ============= ============= Natural gas, oil and condensate............................. $ 105,757 $ 104,163 $ 38,823 Effects of risk management activities....................... (24,369) (28,223) (3,842) ------------- ------------- ------------- Total ................................................... $ 81,388 $ 75,940 $ 34,981 ============= ============= =============
Table and footnote continued on following page 24
Years Ended December 31, ------------------------------------------------ 2001 2000 1999 ------------- ------------- ------------- Average sales price per unit: Natural gas (per Mcf).................................... $ 4.24 $ 4.20 $ 2.23 Effects of risk management activities (per Mcf).......... (1.16) (1.19) (0.23) ------------- ------------- ------------- Total (per Mcf).......................................... $ 3.08 $ 3.01 $ 2.00 ============= ============= ============= Oil and condensate (per Bbl)............................. $ 21.33 $ 29.35 $ 15.37 Effects of risk management activities (per Mcf).......... - (4.34) - ------------- ------------ ------------- Total (per Bbl).......................................... $ 21.33 $ 25.01 $ 15.37 ============= ============ ============= Natural gas, oil and condensate (per Mcfe)............... $ 4.12 $ 4.26 $ 2.24 Effects of risk management activities (per Mcfe)......... (0.95) (1.16) (0.22) ------------- ------------- -------------- Total (per Mcfe)......................................... $ 3.17 $ 3.10 $ 2.02 ============= ============= ============= Expenses (per Mcfe): Lease operating.......................................... $ 0.58 $ 0.47 $ 0.32 General and administrative............................... 0.39 0.22 0.20 Depreciation, depletion and amortization................. 2.08 1.66 1.30
________________ (1) For 2001, represents the net loss on the settlement of derivatives attributable to actual production. YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000 For the year ended December 31, 2001, we reported a net loss of $21.4 million, or $1.09 per share as compared to a net loss of $10.4 million, or $0.73 per share in 2000. For the year ended December 31, 1999, we reported net income of $18.2 million or $1.28 per share. Oil and Gas Revenue. Excluding the effects of risk management activities, our revenue from natural gas and oil production for 2001 increased 2% over 2000, from $104.2 million to $105.8 million. This increase resulted from a slight increase in the price of natural gas and a 5% increase in production, partially offset by a 27% decrease in the price of oil. The increase in production volumes from 24.4 Bcfe to 25.7 Bcfe was attributable to 13 properties that were on production during 2001 that were not on production during 2000. This increase in production was offset by the natural decline in our existing offshore properties. Risk management activities, which were included in oil and gas revenues in 2000 would have decreased oil and natural gas revenues by $24.4 million, or $0.95 per Mcfe in 2001 and $28.2 million, or $1.16 per Mcfe in 2000. Marketing Revenue. Revenues from natural gas marketing activities decreased to $7.4 million in 2001 as compared to $8.0 million in 2000. This decrease was due to a decrease in the sales price per MMBtu. The average sales price per MMBtu decreased from $4.38 in 2000 to $4.06 in 2001. For more information regarding this marketing activity, see Note 13 of Notes to Consolidated Financial Statements. Lease Operating Expense. Our lease operating expense for 2001 increased 28% from $11.6 million to $14.8 million. This increase was primarily the result of an increase in the number of producing wells we own and an increase in their total production volume. Additionally, the lease operating expense per Mcfe on those properties acquired in 2001 was higher due to cost structures and contract obligations in place at the time of acquisition. Transportation related costs increased ($0.6 million) and workover spending decreased ($0.9 million) as compared to 2000. Gas Purchased-Marketing. Our cost of purchased gas was $7.2 million for 2001 compared to $7.8 million for 2000. The average gas cost decreased from $4.26 per MMBtu in 2000 to $3.96 per MMBtu in 2001. 25 Geological and geophysical. In 2001, we recorded $1.1 million of costs related to the acquisition of 3-D seismic data purchased for development purposes on certain properties in the Gulf of Mexico and the U.K. General and Administrative Expense. General and administrative expense increased to $10.0 million for 2001 compared to $5.4 million for 2000. The primary reason for the increase was the result of compensation and related expenses due to an increase in the number of employees in our Houston office from 28 at the end of 2000 to 39 at the end of 2001 ($0.9 million) and the opening of our U.K. office in the third quarter of 2000 ($1.7 million). As a result of becoming a public company in 2001, we incurred costs such as insurance, filing fees, professional fees, investor relations expenses and other expenses related to public company requirements ($1.3 million). Non-Cash Compensation Expense. In 2001, we recorded a non-cash compensation expense of approximately $3.4 million. A portion of the expense ($2.9 million) is related to options granted from September 1999 to the date of our IPO and is based on the difference between the exercise price for those options and the fair market value of our stock as determined by the IPO price of $14.00 per share. The expense is recognized in the periods in which the options vest. Each option is divided into three equal portions corresponding to the three vesting dates, with the related compensation cost amortized straight-line over the period between the IPO date and the vesting date. The remaining expense ($0.5 million) was related to certain options granted prior to September 1999 and exercised in the current year. The expense was recorded on those exercises as the method in which those shares were exercised required us to account for the options under variable accounting. The remaining compensation expense to be recorded over 2002 and 2003 is approximately $0.5 million. Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense ("DD&A") increased 32% from $40.6 million in 2000 to $53.4 million in 2001. The average DD&A rate was $2.08 per Mcfe during 2001 compared to $1.66 per Mcfe during 2000. Impairment Expense. As of December 31, 2001, the future undiscounted cash flows for our properties were $354.2 million and the net book value for the properties was $157.9 million before current year impairment expense. At December 31, 2000, the future undiscounted cash flows for our properties were $931.2 million and the net book value for the properties was $109.6 million before current year impairment expense. However, on eight of our properties in 2001 and three of our properties in 2000, the future undiscounted cash flows were less than their individual net book value. As a result, we recorded impairments of $24.9 million in 2001 and $10.8 million in 2000. The impairments in 2001 were primarily the result of drilling a non-commercial development well at our Main Pass 282 property ($8.3 million), a decrease in expected future gas prices and reductions in recoverable reserves. In 2000, the impairments were primarily the result of a reduction in recoverable reserves individually attributable to the particular properties. Other Income (Expense). In 2001, we recorded a loss on derivative instruments of $18.1 million comprised of a realized loss of $19.3 million and an unrealized gain of $1.2 million. The realized loss represents derivative contracts settled in 2001, while the offsetting gain represents the fair market value of the open derivative positions at December 31, 2001. Prior to the adoption of SFAS 133, realized gains or losses were recorded as a component of revenue. For 2000 we recorded an expense of $4.3 million ($1.7 million realized and $2.6 million unrealized) on a natural gas derivative position as a result of our hedging position exceeding our expected production in an upcoming period. In addition, we recorded an expense of $7.6 million ($3.0 million realized and $4.6 million unrealized) related to losses associated with our written call option contracts. In both of these situations in 2000, we were required to account for the positions using the mark-to-market method. Interest expense decreased from $11.9 million in 2000 to $10.0 million in 2001 primarily due to lower debt levels following the use of proceeds from our IPO and as a result of lower interest rates. We capitalized none and $0.7 million of interest for the years ended December 31, 2001 and 2000, respectively. 26 YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999 Oil and Gas Revenue. Our revenue from natural gas and oil production for 2000 increased 117% over 1999 from $35.0 million to $75.9 million. This increase resulted from an increase in realized natural gas prices of 51% and realized oil prices of 63%, as well as a 41% increase in production. The increase in production volumes from 17.3 Bcfe to 24.5 Bcfe was attributable to ten properties that were on production during 2000 that were not on production during 1999. Hedging transactions reduced oil and natural gas revenues by $28.2 million, or $1.16 per Mcfe, in 2000 and $3.8 million, or $0.22 per Mcfe, in 1999. Marketing Revenue. Revenues from natural gas marketing activities increased to $8.0 million in 2000 as compared to $7.7 million in 1999. The reason for the increase was a decrease in volumes partially offset by an increase in the sales price per MMBtu. The daily natural gas contract decreased from 9,000 MMBtu per day in 1999 to 5,000 MMBtu per day in 2000. The average sales price increased from $2.34 per MMBtu in 1999 to $4.38 per MMBtu in 2000. Lease Operating Expense. Our lease operating expense for 2000 increased 107% from $5.6 million to $11.6 million. This increase was primarily the result of an increase in the number of producing wells owned by us, an increase in their total production volume and an increase in the level of workover activity. Workover spending increased from $0.4 million in 1999 to $2.6 million in 2000. The remaining increase in lease operating expense was primarily attributable to transportation related costs. Gas Purchased-Marketing. Our cost of purchased gas was $7.8 million for 2000 compared to $7.4 million for 1999. The daily gas contract amount in our third party marketing arrangement decreased from 9,000 MMBtu per day in 1999 to 5,000 MMBtu per day in 2000. Lower volumes were offset by an increase in the average gas cost from $2.25 per MMBtu in 1999 to $4.26 per MMBtu in 2000. General and Administrative Expense. General and administrative expense increased to $5.4 million for 2000 compared to $3.5 million for 1999. The primary reason for the increase was the result of compensation and related expenses increasing from $1.8 million to $3.3 million period to period. Our total employees increased from 19 at December 31, 1999 to 33 at December 31, 2000. Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense increased 80% from $22.5 million in 1999 to $40.6 million in 2000. The average DD&A rate was $1.66 per Mcfe during 2000 compared to $1.30 per Mcfe during 1999. Impairment Expense. As of December 31, 2000, the future undiscounted cash flows for our properties were $931.2 million and the net book value for the properties was $109.6 million before current year impairment expense. At December 31, 1999, the future undiscounted cash flows for our properties were $183.0 and the net book value for the properties was $79.8 million before current year impairment expense. However, for three of our 33 properties in 2000 and four of our 26 properties in 1999, the future undiscounted cash flows were less than their individual net book value. As a result, we recorded impairments of $10.8 million in 2000 and $7.5 million in 1999. The impairments in 2000 and 1999 were primarily the result of a reduction in recoverable reserves individually attributable to the particular properties. Other Expense. We recorded a charge of $0.5 million in 2000 relating to the sale of a platform which was held for sale and included in other assets in 1999. There was no comparable expense for this account in 1999. Other Income (Expense). For 2000 we recorded an expense of $4.3 million ($1.7 million realized and $2.6 million unrealized) on a natural gas derivative position as a result of our hedging position exceeding our expected production in an upcoming period. In this situation, we are required to account for the position using the mark-to-market method. In addition, we recorded an expense of $7.6 million ($3.0 million realized and $4.6 million unrealized) related to mark-to-market losses associated with our written call option contracts. 27 For 2000, interest expense was $11.9 million compared to $9.4 million for 1999. Our borrowings increased from period to period but were offset by a decrease in interest rates under our new development program credit agreement. We capitalized $0.7 million and $0.6 million of interest for the years ended December 31, 2000 and 1999, respectively. Extraordinary Gain. In June 1999, we agreed with the lender under a prior development program credit agreement to prepay the amount outstanding at a discount. As a result, we recorded an extraordinary gain of $29.2 million. LIQUIDITY AND CAPITAL RESOURCES General We have financed our acquisition and development activities through a combination of project-based development arrangements, bank borrowings and proceeds from our February 2001 IPO, as well as cash from operations. We believe the cash flows from operating activities combined with our ability to control the timing of substantially all of our future development and acquisition requirements will provide us with the flexibility and liquidity to meet our planned capital requirements during 2002. However, future cash flows are subject to a number of variables including the level of production and oil and natural gas prices. Future borrowings under credit facilities are subject to variables including the lenders' practices and policies, changes in the prices of oil and natural gas and changes in our oil and gas reserves. No assurance can be given that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of operations and capital expenditures. A reduction in the borrowing base or an increase in the monthly reduction amount by the lender would have a material negative impact on our cash flows and our ability to fund future obligations during 2002. As operator of all of our projects in development, we have the ability to significantly control the timing of many of our capital expenditures. In periods of reduced availability of funds from either cash flows or credit sources we would anticipate delaying planned capital expenditures, which could negatively impact our future revenues and cash flows. Cash Flows
Years Ended December 31, -------------------------------------------- 2001 2000 1999 ------------- ------------ ----------- (in thousands) Cash provided by (used in): Operating activities................ $ 41,356 $ 57,157 $ 10,707 Investing activities................ (110,810) (76,835) (55,120) Financing activities................ 56,612 20,035 58,781
Operating activities. Net cash provided by operating activities in 2001 was $41.4 million compared to $57.2 million in 2000. The decrease in 2001 was primarily due to an increase in working capital needs in addition to unfavorable settlements related to price risk derivative contracts. The decrease was partially offset by higher operating income, excluding non-cash items, as a result of higher natural gas prices and increased production volumes. Investing activities. Cash used in investing activities increased in 2001 to $110.8 million. The 2001 amount includes expenditures on oil and gas properties of $110.3 million, of which $25.9 million was used for the acquisition of 17 properties in the Gulf of Mexico and Southern Gas Basin area of the North Sea, $5.6 million was used to purchase the overriding royalty interests associated with our non-recourse debt and $78.8 million was used for development. Comparable expenditures for acquisition and development in 2000 were $7.5 million and $69.0 million, respectively. Financing activities. Cash provided from financing activities includes the proceeds from our IPO in February 2001 of $78.3 million net of the underwriters' discount. We also incurred costs of approximately $0.9 million in connection with the offering, which in addition to costs incurred in the fourth quarter of 2000, totaled approximately $1.5 million. Financing activities included repayments of $116.5 million of our credit facilities in place at December 31, 2000 and net proceeds of $100.0 million from our new credit facility and note payable (see "Credit Agreements"). Financing activities in 2000 included net proceeds of $7.6 million and $13.5 million from our credit facilities and non-recourse borrowings, respectively. 28 Amounts borrowed under our credit agreements were as follows for the dates indicated (in thousands):
December 31, ------------------------------ 2001 2000 ------------- -------------- Credit facility................................................... $ 70,000 $ 27,750 Note payable, net of unamortized discount of $1,139............... 30,111 - Non-recourse borrowings........................................... - 88,779 ------------- -------------- Total debt...................................................... $ 100,111 $ 116,529 ============= ==============
Credit Facilities In March 2001, we repaid our then existing bank credit facility and in April 2001 we repaid the full amount borrowed under a non-recourse development program credit agreement which we had used as a source of financing for the acquisition of oil and gas properties. Concurrent with the repayment of our non-recourse agreement, we negotiated with the lender to terminate the overriding royalty interest retained by it on all properties previously financed by the lender in exchange for a lump-sum payment of approximately $5.6 million. Upon repayment of our former credit and non-recourse facilities, we entered into a new $100.0 million senior-secured revolving credit facility in April 2001. This facility is secured by substantially all of our oil and gas properties, as well as by approximately two-thirds of the capital stock of our U.K. subsidiary and is guaranteed by our wholly owned subsidiary, ATP Energy, Inc. As amended, the amount available for borrowing under the facility is limited to the loan value, as determined by the bank, of oil and gas properties pledged under the facility. At December 31, 2001, the borrowing base was $70.0 million and the monthly borrowing base reduction was set at $2.0 million a month beginning February 27, 2002 and remains in effect until there is a change, if any, at the next redetermination date. The redetermination dates are on or around the first business day of each calendar quarter at which time the lenders can increase or decrease the borrowing base and the monthly reduction amount. The next scheduled redetermination date is on or around the first business day of April 2002. Our lender has indicated this process will not be completed until mid to late April of 2002. The $2.0 million monthly reduction included in current maturities of long-term debt assumes there is no change in the monthly reduction amount or the borrowing base in 2002. If our outstanding balance exceeds our borrowing base at any time, we are required to repay such excess within 30 days and our interest rate during the time an excess exists is increased by 2.00%. A reduction in the borrowing base or an increase in the monthly reduction amount by the lender would have a material negative impact on our cash flows and our ability to fund future operations during 2002. As of December 31, 2001, all of our borrowing base under the agreement was outstanding. Advances under the credit facility can be in the form of either base rate loans or Eurodollar loans. The interest on a base rate loan is a fluctuating rate equal to the higher of the Federal funds rate plus 0.5% and the bank base rate, plus a margin of 0.25%, 0.50%, 0.75% or 1.00% depending on the amount outstanding under the credit agreement. The interest on a Eurodollar loan is equal to the Eurodollar rate, plus a margin of 2.25%, 2.50%, 2.875%, or 3.125% depending on the amount outstanding under the credit facility. The amended credit facility matures in November 2003. Our credit facility contains conditions and restrictive provisions, among other things, (1) prohibiting us to enter into any arrangement to sell or transfer any of our material property, (2) prohibiting a merger into or consolidation with any other person or sell or dispose of all or substantially all of our assets, and (3) maintaining certain financial ratios. 29 Note Payable Effective June 29, 2001, we issued a note payable to a purchaser for a face principal amount of $31.3 million which matures in June 2005 and bears interest at a fixed rate of 11.5% per annum. The note is secured by second priority liens on substantially all of our oil and gas properties and is subordinated in right of payment to our existing senior indebtedness. We executed an agreement in connection with the note which contains conditions and restrictive provisions and requires the maintenance of certain financial ratios. Upon consent of the purchaser, which shall not be unreasonably withheld, the note may be repaid prior to the maturity date with an additional repayment premium based on the percentage of the principal amount paid, ranging from 4.5% during the first year to 16.5% in the final year of payment. If the note is paid at maturity, the maximum payment premium of 16.5% is required. The expected repayment premium is being amortized to interest expense straight-line, over the term of the note which approximates the effective interest method. The resulting liability is included in other long-term liabilities on the consolidated balance sheet. In July 2001, we received proceeds of $30.0 million in consideration for the issuance of the note. The discount of $1.3 million is being amortized to interest expense using the effective interest method. The amount available for borrowing under the note is limited to the loan value of oil and gas properties pledged under the note, as determined by the purchaser. The purchaser has the right to make a redetermination of the borrowing base at least once every six months. We have assumed there is no change in the borrowing base in 2002. If our outstanding balance exceeds the borrowing base at any time, we are required to repay such excess within 10 days subject to the provisions of the agreement. A reduction in the borrowing base by the lender would have a material negative impact on our cash flows and our ability to fund future obligations during 2002. As of December 31, 2001, all of our borrowing base under the agreement was outstanding. As of December 31, 2001, we were in compliance with all of the financial covenants of our credit facility and note payable agreements other than our working capital covenant (as defined by the agreements) for which we have obtained amendments from our lenders. Both of the amendments require that our working capital at December 31, 2001 and March 31, 2002 shall not exceed deficits of $10.0 million and $5.0 million, respectively. Working Capital During the second half of 2001 we operated with a working capital deficit. In compliance with the definition of working capital in our credit facilities which excludes current maturities of long-term debt and the current portion of future commodity contracts and other derivatives, we ended the year with a deficit of approximately $9.0 million, an improvement over our deficits of $37.1 million at June 30, 2001 and $35.1 million at September 30, 2001. The improvement in our working capital was the result of the November 2001 increase in the borrowing base of our existing credit facility, the reduction of our current liabilities through cash flows from operations and the reduction of expenditures related to the curtailment of current development activity. We executed this improvement in working capital despite the devastating national and financial events in the U.S. that occurred during the third and fourth quarters of 2001. In efforts to preserve cash flow during this period of negative working capital, we reached agreement with several of our suppliers for extended payments. In response to lower gas prices received in the fourth quarter of 2001 and the early part of 2002 and our desire to completely eliminate our working capital deficit, we have reduced certain previously planned development activities for 2002. Four projects that can be developed in 2002 have been postponed until 2003. In addition to these measures, we are currently in discussions with potential investors to provide additional capital. These discussions involve increases to our current credit facilities, new credit facilities, sale of interests in selected properties and the potential sale and lease back of certain of our platforms and pipelines. We have also explored the possibility of the issuance of new debt or equity in both the public and private markets. Completion of any of these potential financings will expand our capabilities to further reduce our outstanding indebtedness, increase our working capital and expand our 2002 development and acquisition program. There can be no assurance however, that we will be successful in negotiating any of these transactions or that the form of the transaction will be acceptable to both the potential investor and our management or our board of 30 directors. If we are not successful in closing these transactions, our ability to reduce our debt below projected levels or to develop and produce our oil and gas properties as desired may be negatively impacted. Other items that could have a negative impact on our working capital include a significant decrease in oil or gas prices from expected levels, a redetermination by our lenders of our borrowing base or our monthly reduction amount in excess of the amounts forecasted in our cash flow projection, the increase in costs and expenses above projected levels or any significant payments related to the contingencies described below. Our planned development, acquisition and debt reduction programs are projected to be funded by available cash flow from our 2002 operations. We believe the cash flows from operating activities combined with our ability to control the timing of substantially all of our future development and acquisition requirements will provide us with the flexibility and liquidity to meet our future capital requirements. Realization of any of the aforementioned negative items could limit our ability to fund future operations during 2002. Commitments We have various commitments primarily related to leases for office space, other property and equipment and other agreements. We expect to fund these commitments with cash generated from operations. The following table summarizes our contractual obligations at December 31, 2001 (in thousands):
Payments Due By Period ----------------------------------------------------------------- Less Than After Contractual Obligation(1) Total 1 Year 1-2 Years 3-4 Years 4 Years - ------------------------------------------ ----------- ----------- ------------ ----------- ------------ Total debt................................. $ 101,250 $ 22,000 $ 48,000 $ 31,250 $ - Interest expense on credit facility(2)..... 4,787 3,145 1,642 - - Interest expense on note payable(3)........ 17,272 4,940 9,883 2,449 - Non-cancelable operating leases............ 2,545 375 688 368 1,114 Contractor commitment(4)................... 3,450 - 3,450 - - ------------ ----------- ----------- ----------- ----------- Total contractual obligations.......... $ 129,304 $ 30,460 $ 63,663 $ 34,067 $ 1,114 =========== =========== =========== =========== ===========
_______________ (1) Does not include any amounts related to contingencies discussed below. (2) Incudes interest based on rates and monthly reduction amounts in effect at December 31, 2001. (3) Includes 11.5% interest and repayment premium. (4) Does not include 7.5% interest due monthly. Contingencies On August 28, 2001 ATP entered into a written agreement to acquire a property in the Gulf of Mexico during September 2001. On October 9, 2001 the agreement was amended to ultimately extend the closing date until October 31, 2001 in exchange for payments made by ATP totaling $3.0 million. This amendment also contained an arrangement whereby if ATP did not close on the property, and if sellers sold the property to a third party with a sale that met specific contract requirements, ATP would be required to execute a six month note for payment of the differential. Since ATP did not obtain the financing for the acquisition by October 31, 2001,the transaction did not close by that date; however, the parties' intensive work toward closing continued beyond that date without interruption. While working on the closing for the property with ATP, the sellers sold the property to a third party without informing ATP until after the closing had taken place. ATP filed an action in the District Court of Harris County, Texas against the sellers, generally alleging improper sale of the offshore property to a third party and breach of contract, and seeking unspecified damages from the sellers. The case is encaptioned ATP Oil & Gas Corporation vs. Legacy Resources Co., L.P. et al, No. 2001-63224 in the 269th Judicial District Court of Harris County, Texas. At the same time sellers notified ATP of their sale to a third party, the sellers had a demand made upon ATP for execution of a six month note for the amount of an alleged differential of approximately $12.3 million plus interest at 16%. Substantiation of the amount and validity of the demand could not be ascertained based on the content of the demand received. ATP contested the entire demand. The litigation is in its very early stages with written discovery propounded by ATP, but no answers received, and no depositions taken. The judge has abated the litigation, until arbitration pursuant to the underlying 31 agreements between the sellers and ATP is completed. Since the legal proceedings have just begun, and a prediction of the outcome would be premature and uncertain, we have not accrued any amount related to this matter. And while we are seeking recovery of the amounts previously paid and discussed above, the $3.0 million has been charged to earnings along with certain other costs related to this matter. ATP intends to vigorously defend against the sellers' claims and forcefully pursue its own claims in this matter. In August 2001, Burlington Resources Inc. filed suit against us alleging formation of a contract with us and our breach of the alleged contract. The complaint seeks compensatory damages of approximately $1.1 million. We believe that this claim is without merit, and we intend to defend it vigorously. We are, in the ordinary course of business, a claimant and/or defendant in various legal proceedings. Management does not believe that the outcome of these legal proceedings, individually, and in the aggregate will have a materially adverse effect on our financial condition, results of operations or cash flows. RECENT ACCOUNTING PRONOUNCEMENTS In 2001, the FASB approved SFAS No. 141 "Business Combinations" ("SFAS 141"), No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142"), No. 143 "Accounting for Asset Retirement Obligations" ("SFAS 143") and No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 141 requires all business combinations completed after June 30, 2001, be accounted for under the purchase method. This standard also establishes for all business combinations made after June 30, 2001, specific criteria for the recognition of intangible assets separately from goodwill. SFAS 141 also requires that the excess of fair value of acquired assets over cost (negative goodwill) be recognized immediately as an extraordinary gain, rather than deferred and amortized. SFAS 142 addresses the accounting for goodwill and other intangible assets after an acquisition. The most significant changes made by SFAS 142 are: 1) goodwill and intangible assets with indefinite lives will no longer be amortized; 2) goodwill and intangible assets with indefinite lives must be tested for impairment at least annually; and 3) the amortization period for the intangible assets with finite lives will no longer be limited to forty years. We will adopt SFAS 142 effective January 1, 2002, as required. Additionally, SFAS 142 requires that unamortized negative goodwill associated with investments accounted for under the equity method and acquired before July 1, 2001, be recognized in income as a cumulative effect of change in accounting principle. SFAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets, including: 1) the timing of liability recognition; 2) initial measurement of the liability; 3) allocation of asset retirement cost to expense; 4) subsequent measurement of the liability; and 5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived asset and subsequently allocated to expense using a systematic and rational method. We will adopt the Statement effective January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. SFAS 144 provides that long-lived assets to be disposed of by sale be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations, and broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. SFAS 144 is effective for fiscal years beginning after December 15, 2001. SFAS 141 and SFAS 142 will not apply to us unless we enter into a future business combination. We are currently assessing the impact of SFAS 143 and SFAS 144 on our financial condition and results of operations. 32 FACTORS THAT MAY AFFECT FUTURE RESULTS You should carefully consider the risks described below in evaluating the other statements made herein. The risks described below are not the only ones facing our company. Additional risks not presently known to us, or that we currently deem immaterial, may also impair our business operations. Our business, financial condition, results of operations or the trading price of our common stock could be adversely affected by any of these risks. We have substantial debt, trade payables and related interest payment requirements that may restrict our future operations and impair our ability to meet our obligations. Our substantial debt, trade payables and related interest payment requirements may have important consequences. For instance, it could: . make it more difficult or render us unable to satisfy our financial obligations; . require us to dedicate a substantial portion of any cash flow from operations to the payment of interest and principal due under our debt, which will reduce funds available for other business purposes; . increase our vulnerability to general adverse economic and industry conditions; . limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate; . place us at a competitive disadvantage compared to some of our competitors that have less financial leverage; and . limit our ability to obtain additional financing required to fund working capital and capital expenditures and for other general corporate purposes. Our ability to satisfy our obligations and to reduce our total debt depends on our future operating performance and on economic, financial, competitive and other factors, many of which are beyond our control. We cannot provide assurance that our business will generate sufficient cash flow or that future financings will be available to provide sufficient proceeds to meet these obligations. The successful execution of our business strategy and the maintenance of our economic viability are also contingent upon our ability to meet our financial obligations. Our debt instruments impose restrictions on us that may affect our ability to successfully operate our business. Our bank credit facility and our 11.5% fixed rate note contain customary restrictions, including covenants limiting our ability to incur additional debt, grant liens, make investments, consolidate, merge or acquire other businesses, sell assets, pay dividends and other distributions, make capital expenditures and enter into transactions with affiliates. We also are required to meet specified financial ratios under the terms of our bank credit facilities. These restrictions may make it difficult for us to successfully execute our business strategy or to compete in our industry with companies not similarly restricted. Our bank credit facility matures in November 2003 and our 11.5% note matures in June 2005, at which time we will be required to repay or refinance those borrowings. We cannot provide assurance that we will be able to obtain replacement financing at that time or that any available replacement financing will be on terms acceptable to us. If we are unable to obtain acceptable replacement financing, we will not be able to satisfy our obligations under our bank credit facility or note due in 2005 and may be required to take other actions to avoid defaulting on those facilities, including selling assets or surrendering assets to our lenders, which would not otherwise be in our long-term economic interest. 33 Our properties are subject to rapid production declines and we require significant capital expenditures to replace our reserves at a faster rate than companies whose reserves have longer production periods. We may not be able to identify or complete the acquisition of properties with sufficient proved reserves to implement our business strategy. Production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than production from reservoirs in many other producing regions of the world. This results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial years of production. As our reserves decline from production, we must incur significant capital expenditures to replace declining production. As a result, in order to increase our reserves, we must replace our reserves with newly-acquired properties more quickly than companies whose reserves decline at a slower rate. Also, our return on capital for a particular property depends significantly on prices prevailing during the relatively short production period of that property. As of December 31, 2001 and 2000, our reserve life index was 9.1 years and 5.1 years, respectively. We may not be able to identify or complete the acquisition of properties with sufficient proved undeveloped reserves to implement our business strategy. As we deplete our existing reserves we must identify, acquire and develop properties through new acquisitions or our level of production and cash flows will be adversely affected. The availability of properties for acquisition depends largely on the divesting practices of other natural gas and oil companies, commodity prices, general economic conditions and other factors that we cannot control or influence. A substantial decrease in the availability of proved oil and gas properties in our areas of operation, or a substantial increase in the cost to acquire these properties, would adversely affect our ability to replace our reserves. Our actual drilling results are likely to differ from our estimates of proved reserves. We may experience production that is less than estimated in our reserve reports and drilling costs that are greater than estimated in our reserve reports. Such differences may be material. Estimates of our natural gas and oil reserves and the costs associated with developing these reserves may not be accurate. Development of our reserves may not occur as scheduled and the actual results may not be as estimated. Drilling activity may result in downward adjustments in reserves or higher than estimated costs. Our estimates of our proved natural gas and oil reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions required by the SEC relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise and the quality and reliability of this data can vary. Any significant variance could materially affect the estimated quantities and PV-10 of reserves set forth in this annual report. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we will likely adjust estimates of proved reserves to reflect production history, results of development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Actual production, revenues, taxes, development expenditures and operating expenses with respect to our reserves may vary materially from our estimates. If we are not able to generate sufficient funds from our operations and other financing sources, we may not be able to finance our planned development activity or acquisitions or service our debt. We have historically needed and will continue to need substantial amounts of cash to fund our capital expenditure and working capital requirements. Our ongoing capital requirements consist primarily of funding acquisition, development and abandonment of oil and gas reserves and to meet our debt service obligations. Our capital expenditures were $56.1 million during 1999, $76.5 million during 2000 and $110.3 million during 2001. 34 For 2002, we plan to finance anticipated expenses, debt service and acquisition and development requirements with funds generated from the following sources: . cash provided by operating activities; . funds available under new credit facilities; . the potential increased availability from our existing credit facilities; . extended financing arrangements with suppliers and service providers; . net cash proceeds from the sale of assets, debt or equity; and . the potential issuance of new debt or equity. Our projected cash flows provide the necessary funds for our debt service and our planned Gulf of Mexico developments and we intend to finance our planned North Sea development with projected cash flows and new financing. Low commodity prices, production problems, disappointing drilling results and other factors beyond our control could reduce our funds from operations and may restrict our ability to obtain additional financing. In addition, financing may not be available to us in the future on acceptable terms or at all. In the event additional capital is not available, we may curtail our acquisition, drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. In addition, we may not be able to pay interest and principal on our debt obligations. Natural gas and oil prices are volatile, and low prices have had in the past and could have in the future a material adverse impact on our business. Our revenues, profitability and future growth and the carrying value of our properties depend substantially on the prices we realize for our natural gas and oil production. Because approximately 83% of our estimated proved reserves as of December 31, 2001 were natural gas reserves, our financial results are more sensitive to movements in natural gas prices. Our realized prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Historically, the markets for natural gas and oil have been volatile, and they are likely to continue to be volatile in the future. For example, natural gas and oil prices increased significantly in late 2000 and steadily declined in 2001. Among the factors that can cause this volatility are: . worldwide or regional demand for energy, which is affected by economic conditions; . the domestic and foreign supply of natural gas and oil; . weather conditions; . domestic and foreign governmental regulations; . political conditions in natural gas or oil producing regions; . the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels; and . the price and availability of alternative fuels. It is impossible to predict natural gas and oil price movements with certainty. Lower natural gas and oil prices may not only decrease our revenues on a per unit basis but also may reduce the amount of natural gas and oil that we can produce economically. A substantial or extended decline in natural gas and oil prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures. Further, oil prices and natural gas prices do not necessarily move together. 35 Our hedging decisions may reduce our potential gains from increases in commodity prices and may result in losses. We periodically utilize derivative instruments respect to a portion of our expected production. These instruments expose us to risk of financial loss if: . production is less than expected; . the other party to the derivative instrument defaults on its contract obligations; or . there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received. Our results of operations may be negatively impacted by our hedges in the future and these instruments may limit any benefit we would receive from increases in the prices for natural gas and oil. For the years ended December 31, 2001 and 2000, we realized a loss on derivative instruments of $26.5 million and $32.7 million, respectively. See Item 7a. "Quantitative and Qualitative Disclosure about Market Risk" for volume and price information on our hedging activities. We may incur substantial impairment writedowns. If management's estimates of the recoverable reserves on a property are revised downward or if natural gas and oil prices decline, we may be required to record additional non-cash impairment writedowns in the future, which would result in a negative impact to our financial position. In addition, future writedowns to our properties could result in corresponding reductions of our borrowing base under our credit facility and promissory note. We review our proved oil and gas properties for impairment on a depletable unit basis when circumstances suggest there is a need for such a review. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying published future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineer's estimate of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis. Fair value is estimated to be the present value of aforementioned expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units' reserves, future cash flows and fair value. We recorded impairments of $24.9 million, $10.8 million and $7.5 million for the years ended December 31, 2001, 2000 and 1999, respectively. Management's assumptions used in calculating oil and gas reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Any change could cause impairment expense to be recorded, reducing our net income and our basis in the related asset. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the property's fair value. Additionally, as management's views related to future prices change, the change will affect the estimate of future net cash flows and the fair value estimates. Changes in either of these amounts will directly impact the calculation of impairment. The natural gas and oil business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses. Our development activities may be unsuccessful for many reasons, including cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economic. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves. The natural gas and oil business involves a variety of operating risks, including: . fires; . explosions; . blow-outs and surface cratering; . uncontrollable flows of natural gas, oil and formation water; . pipe, cement, subsea well or pipeline failures; . casing collapses; . embedded oil field drilling and service tools; . abnormally pressured formations; and . environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases. 36 If we experience any of these problems, it could affect well bores, platforms, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of: . injury or loss of life; . severe damage to and destruction of property, natural resources and equipment; . pollution and other environmental damage; . clean-up responsibilities; . regulatory investigation and penalties; . suspension of our operations; and . repairs to resume operations. Offshore operations are also subject to a variety of operating risks peculiar to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for development or leasehold acquisitions, or result in loss of equipment and properties. Our insurance coverage may not be sufficient to cover some liabilities or losses which we may incur. The occurrence of a significant accident or other event not fully covered by our insurance could have a material adverse effect on our operations and financial condition. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third party drilling contractors are used to drill our wells, we may not realize the full benefit of workmen's compensation laws in dealing with their employees. In addition, pollution and environmental risks generally are not fully insurable. We may be unable to identify liabilities associated with the properties that we acquire or obtain protection from sellers against them. The acquisition of properties with proved undeveloped reserves requires us to assess a number of factors, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well, platform or pipeline. We cannot necessarily observe structural and environmental problems, such as pipeline corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute on a timely basis our development plans within our budget. Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our operations, which could have a material adverse effect on our business, financial condition and results of operations. During 2000, drilling activity in the Gulf of Mexico increased, and we experienced increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in the Gulf of Mexico also decreases the availability of offshore rigs. These costs may increase further and necessary equipment and services may not be available to us at economical prices. 37 Competition in our industry is intense, and we are smaller and have a more limited operating history than some of our competitors in the Gulf of Mexico and in the Southern Gas Basin of the North Sea. We compete with major and independent natural gas and oil companies for property acquisitions. We also compete for the equipment and labor required to operate and to develop these properties. Some of our competitors have substantially greater financial and other resources than us. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for natural gas and oil properties and may be able to define, evaluate, bid for and acquire a greater number of properties than we can. Our ability to acquire additional properties and develop new and existing properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, some of our competitors have been operating in the Gulf of Mexico and in the Southern Gas Basin of the North Sea for a much longer time than we have and have demonstrated the ability to operate through industry cycles. Our success depends on our management team and other key personnel, the loss of any of whom could disrupt our business operations. Our success will depend on our ability to retain and attract experienced geoscientists and other professional staff. As of December 31, 2001, we had 16 engineers, geologist/geophysicists and other technical personnel in our Houston office and five engineers, geologist/geophysicists and other technical personnel in our London location. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected. Rapid growth may place significant demands on our resources. We have experienced rapid growth in our operations and expect that significant expansion of our operations will continue. Our rapid growth has placed, and our anticipated future growth will continue to place, a significant demand on our managerial, operational and financial resources due to: . the need to manage relationships with various strategic partners and other third parties; . difficulties in hiring and retaining skilled personnel necessary to support our business; . the need to train and manage a growing employee base; and . pressures for the continued development of our financial and information management systems. If we have not made adequate allowances for the costs and risks associated with this expansion or if our systems, procedures or controls are not adequate to support our operations, our business could be adversely impacted. We are subject to complex laws and regulations, including environmental regulations, that can adversely affect the cost, manner or feasibility of doing business. Development, production and sale of natural gas and oil in the U.S., especially in the Gulf of Mexico, and in the U.K., are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include: . discharge permits for drilling operations; . bonds for ownership, development and production of oil and gas properties; . reports concerning operations; and . taxation. 38 Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations. Members of our management team own a significant amount of common stock, giving them influence or control in corporate transactions and other matters, and the interests of these individuals could differ from those of other shareholders. Members of our management team beneficially own approximately 70% of our outstanding shares of common stock. As a result, these shareholders are in a position to significantly influence or control the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of an amendment to our articles of incorporation or bylaws and the approval of mergers and other significant corporate transactions. Their control of ATP may delay or prevent a change of control of ATP and may adversely affect the voting and other rights of other shareholders. 39 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Interest Rate Risk We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents and the interest rate paid on borrowings under the credit agreements. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes. Commodity Price Risk Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our bank credit facility is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas and oil that we can economically produce. We currently sell most of our natural gas and oil production under price sensitive or market price contracts. To reduce exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow, we periodically enter into hedging arrangements that usually consist of swaps or price collars that are settled in cash. However, these contracts also limit the benefits we would realize if commodity prices increase. Our internal hedging policy provides that we examine the economic effect of entering into a commodity contract with respect to the properties that we acquire. We generally acquire properties at prices that are below the management's estimated value of the estimated proved reserves at the then current natural gas and oil prices. We will enter into short term hedging arrangements if (1) we are able to obtain commodity contracts at prices sufficient to secure an acceptable internal rate of return on a particular property or on a group of properties or (2) if deemed necessary by the terms of our existing credit agreements. During 2001, we hedged approximately 82% of our natural gas production. Effective January 1, 2001, we adopted SFAS No. 133 and SFAS No. 138, an amendment to SFAS 133. SFAS 133 and 138 require that derivatives be reported on the balance sheet at fair value and, if the derivative is not designated as a hedging instrument, changes in fair value must be recognized in earnings in the period of change. If the derivative is designated as a hedge and to the extent such hedge is determined to be effective, changes in fair value are either (a) offset by the change in fair value of the hedged asset or liability (if applicable) or (b) reported as a component of other comprehensive income (loss) in the period of change, and subsequently recognized in earnings when the offsetting hedged transaction occurs. We use derivatives to hedge the price of crude oil and natural gas. Effective January 1, 2001, we did not attempt to qualify for the hedge provisions under SFAS 133 and thus have not designated our derivatives as hedging instruments. Accordingly, we account for the changes in market value of these derivatives through current earnings. This method will result in increased earnings volatility associated with commodity price fluctuations. Gains and losses on all derivative instruments related to accumulated other comprehensive income (loss) are included in other income (expense) on the consolidated financial statements. On January 1, 2001, in accordance with the transition provisions of SFAS 133, we recorded a non-cash loss of $52.7 million ($34.3 million after tax) in accumulated other comprehensive loss, representing the cumulative effect of an accounting change to recognize at fair value all cash flow type derivatives. Also on January 1, 2001, we recorded derivative liabilities of $52.7 million. During the year ended December 31, 2001, losses of $52.7 million ($34.3 million after tax) were reclassified from accumulated other comprehensive loss to earnings. Prior to the adoption of this standard, we included gains and losses on hedging instruments as a component of revenue. As of December 31, 2001, the fair market value of our derivatives consisted of a $1.9 million current asset and a $0.7 million long-term liability. As of December 31, 2001, all of our natural gas swap agreements were with one counterparty whose investment grade ratings were Baa2 from Moody's and BBB from Standard & Poor's. Those agreements outstanding were as follows:
Average Period MMBtu/Day $/MMBtu ------ ------------ ---------- January 2002 - October 2003........................................... 20,000 3.02
Thus far, in 2002, we have entered into the following swap agreements:
Period Volume/Day $/Unit ------ ---------- ---------- Natural gas (MMBtu): February 2002 - October 2002 ....................................... 6,000 2.41 April 2002 - July 2002 ............................................. 6,000 2.81 April 2002 - October 2002 .......................................... 2,000 3.31 Oil (Bbl): April 2002 - December 2002 ......................................... 500 23.50 April 2002 - December 2002 ......................................... 500 25.25
40 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required here is included in the report as set forth in the "Index to Financial Statements" on page F-1. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 41 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT Except for the information relating to Executive Officers of the Registrant, which is included in Part 1, Item 4 of this Report, the information required by Item 10 of Form 10-K is incorporated herein by reference to "Election of Directors" and "Section 16 Compliance" included in the definitive proxy statement for the Company's Annual Meeting of Shareholders to be held on June 14, 2002 (the "Proxy Statement"). ITEM 11. EXECUTIVE COMPENSATION The information required by Item 11 of Form 10-K is incorporated by reference to the information contained in the section captioned "Executive Compensation" of the Registrant's Proxy Statement. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by Item 12 of Form 10-K is incorporated by reference to the information contained in the section captioned "Securities Ownership by Principal Shareholders and Management" of the Registrant's Proxy Statement. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by Item 13 of Form 10-K is incorporated by reference to the information contained in the section captioned "Election of Directors - Certain Transactions" of the Registrant's Proxy Statement. 42 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) (1) and (2) Financial Statements and Financial Statement Schedules See "Index to Consolidated Financial Statements" on page F-1. (a) (3) Exhibit 3.1 Amended and Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 of ATP's registration statement No. 333- 46034 on Form S-1) 3.2 Restated Bylaws (incorporated by reference to Exhibit 3.2 of ATP's registration statement No. 333-46034 on Form S-1) 4.1 Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 of ATP's registration statement No. 333-46034 on Form S-1) 10.1 Amended and Restated Credit Agreement, dated as of September 21, 1999, among ATP Oil & Gas Corporation, Chase Bank of Texas, National Association as Agent, and the Lenders Signatory thereto (incorporated by reference to Exhibit 10.1 of ATP's registration statement No. 333-46034 on Form S-1) 10.2 First Amendment to Amended and Restated Credit Agreement, dated as of September 21, 1999, among ATP Oil & Gas Corporation, Chase Bank of Texas, National Association, as Agent, and the Lenders Signatory thereto, effective as of June 30, 2000 (incorporated by reference to Exhibit 10.2 of ATP's registration statement No. 333-46034 on Form S-1) 10.3 Credit Agreement between ATP Oil & Gas Corporation and Aquila Energy Capital Corporation, dated April 9, 1999, effective as of March 31, 1999 (incorporated by reference to Exhibit 10.3 of ATP's registration statement No. 333-46034 on Form S-1) 10.4 First Amendment to Credit Agreement, dated April 9, 1999, by and between ATP Oil & Gas Corporation and Aquila Energy Capital Corporation (incorporated by reference to Exhibit 10.4 of ATP's registration statement No. 333-46034 on Form S-1) 10.5 Second Amendment to Credit Agreement, dated April 9, 1999, by and between ATP Oil & Gas Corporation and Aquila Energy Capital Corporation (incorporated by reference to Exhibit 10.5 of ATP's registration statement No. 333-46034 on Form S-1) 10.6 Gas Service Agreement, dated December 31, 1998, between American Citigas Company and ATP Energy, Inc. (incorporated by reference to Exhibit 10.6 of ATP's registration statement No. 333-46034 on Form S-1) 10.7 Marketing & Natural Gas Purchase Agreement, dated December 1, 1998, between ATP Energy, Inc. and El Paso Energy Marketing Company (incorporated by reference to Exhibit 10.7 of ATP's registration statement No. 333-46034 on Form S-1) 10.8 Purchase and Sale Agreement, effective as of May 1, 1999, between Eugene Offshore Holdings, LLC and ATP Oil & Gas Corporation (incorporated by reference to Exhibit 10.8 of ATP's registration statement No. 333-46034 on Form S-1) 10.9 ATP Oil & Gas Corporation 1998 Stock Option Plan (incorporated by reference to Exhibit 10.9 of ATP's registration statement No. 333-46034 on Form S-1) 10.10 First Amendment to the ATP Oil & Gas Corporation 1998 Stock Option Plan (incorporated by reference to Exhibit 10.10 of ATP's registration statement No. 333-46034 on Form S-1) 10.11 ATP Oil & Gas Corporation 2000 Stock Plan (incorporated by reference to Exhibit 10.11 of ATP's Annual Report on Form 10-K for the year ended December 31, 2000) 10.12 Credit Agreement, dated as of April 27, 2001, among ATP Oil & Gas Corporation and BNP Paribas, as Agent and the Lenders Signatory thereto (incorporated by reference to Exhibit 10.1 of ATP's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2001) 43 10.13 First Amendment to Credit Agreement dated June 29, 2001, among ATP Oil & Gas Corporation and BNP Paribas, as Agent, and the Lenders Signatory thereto (incorporated by reference to Exhibit 10.1 of ATP's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001) 10.14 Second Amendment to Credit Agreement dated June 29, 2001, among ATP Oil & Gas Corporation and BNP Paribas, as Agent, and the Lenders Signatory thereto (incorporated by reference to Exhibit 10.2 of ATP's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001) 10.15 Note Purchase Agreement dated June 29, 2001 between ATP Oil & Gas Corporation and Aquila Energy Capital Corporation (incorporated by reference to Exhibit 10.3 of ATP's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001) 10.16 Intercreditor and Subordination Agreement dated June 29, 2001, among ATP Oil & Gas Corporation, Aquila Energy Capital Corporation, BNP Paribas, as Agent, and the Lenders Signatory thereto (incorporated by reference to Exhibit 10.4 of ATP's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001) 10.17 Third Amendment to Credit Agreement dated June 30, 2001, among ATP Oil & Gas Corporation and BNP Paribas, as Agent, and the Lenders Signatory thereto (incorporated by reference to Exhibit 10.5 of ATP's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001) 10.18 Fourth Amendment to Credit Agreement dated October 1, 2001, among ATP Oil & Gas Corporation and BNP Paribas, as Agent and the Lenders Signatory thereto (incorporated by reference to Exhibit 10.1 of ATP's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2001) 10.19 Fifth Amendment to Credit Agreement dated November 1, 2001, among ATP Oil & Gas Corporation and Union Bank of California, N.A., as Agent, and the Lenders Signatory thereto (incorporated by reference to Exhibit 10.2 of ATP's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2001) *10.20 Sixth Amendment to Credit Agreement dated January 31, 2002, among ATP Oil & Gas Corporation and Union Bank of California, N.A., as Agent, and the Lenders Signatory thereto *10.21 Seventh Amendment to Credit Agreement dated February 28, 2002, among ATP Oil & Gas Corporation and Union Bank of California, N.A., as Agent, and the Lenders Signatory thereto *10.22 Eighth Amendment to Credit Agreement dated March 27, 2002, among ATP Oil & Gas Corporation and Union Bank of California, as Agent, and the Lenders Signatory thereto *10.23 First Amendment to Note Purchase Agreement dated March 27, 2002 between ATP Oil & Gas Corporation and Aquila Energy Capital Corporation 21.1 Subsidiaries of ATP Oil & Gas Corporation (incorporated by reference to Exhibit 21.1 of ATP's registration statement No. 333-46034 on Form S-1) *23.1 Consent of KPMG LLP *23.2 Consent of Ryder Scott Company *23.3 Consent of Troy-Ikoda Limited _____________ * Filed herewith 44 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. ATP Oil & Gas Corporation By: /s/ Albert L. Reese, Jr. ------------------------------------ Albert L. Reese, Jr. Senior Vice President and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on April 1, 2002. Signature Title --------- ----- /s/ T. PAUL BULMAHN Chairman, President and Director - ------------------------------- (Principal Executive Officer) T. Paul Bulmahn /s/ ALBERT L. REESE, JR. Senior Vice President and Chief - ------------------------------- Financial Officer Albert L. Reese, Jr. (Principal Financial Officer and Principal Accounting Officer) /s/ CAROL E. OVERBEY Director - ------------------------------- Carol E. Overbey /s/ GERARD SWONKE Director - ------------------------------- Gerard Swonke /s/ ARTHUR H. DILLY Director - ------------------------------- Arthur H. Dilly /s/ ROBERT C. THOMAS Director - ------------------------------- Robert C. Thomas /s/ WALTER WENDLANDT Director - ------------------------------- Walter Wendlandt 45 ATP OIL & GAS CORPORATION AND SUBSIDIARIES INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page ---- ATP OIL & GAS CORPORATION AND SUBSIDIARIES Independent Auditors' Report............................................................. F-2 Consolidated Balance Sheets as of December 31, 2001 and 2000............................. F-3 Consolidated Statements of Operations for the years ended December 31, 2001, 2000 and 1999.................................................... F-4 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999.................................................... F-5 Consolidated Statements of Shareholders' Equity (Deficit) for the years ended December 31, 2001, 2000 and 1999.................................................... F-6 Notes to Consolidated Financial Statements............................................... F-7
F-1 INDEPENDENT AUDITORS' REPORT The Board of Directors ATP Oil & Gas Corporation: We have audited the accompanying consolidated balance sheets of ATP Oil & Gas Corporation and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, shareholders' equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2001. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ATP Oil & Gas Corporation and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 2 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative financial instruments. KPMG LLP Houston, Texas March 29, 2002 F-2 ATP OIL & GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Thousands, Except Share Amounts)
December 31, 2001 2000 ------------- -------------- Assets Current assets: Cash and cash equivalents....................................................... $ 5,294 $ 18,136 Accounts receivable (net of allowance of $1,423 and $443, respectively)......... 10,371 32,542 Commodity contracts and other derivatives....................................... 1,936 - Other current assets............................................................ 1,754 2,597 ------------- -------------- Total current assets......................................................... 19,355 53,275 ------------- -------------- Oil and gas properties: Oil and gas properties (using the successful efforts method of accounting)...... 319,506 209,548 Less: Accumulated depreciation, depletion, impairment and amortization.......... (186,473) (110,823) ------------- -------------- Oil and gas properties, net.................................................. 133,033 98,725 ------------- -------------- Furniture and fixtures (net of accumulated depreciation)............................ 794 487 Deferred tax asset.................................................................. 19,228 7,652 Other assets, net................................................................... 5,154 1,854 ------------- -------------- Total assets................................................................. $ 177,564 $ 161,993 ============= ============== Liabilities and Shareholders' Equity (Deficit) Current liabilities: Accounts payable and accruals................................................... $ 26,426 $ 49,799 Current maturities of long-term debt............................................ 22,000 - Commodity contracts and other derivatives....................................... - 7,248 Other deferred obligations...................................................... - 63 ------------- -------------- Total current liabilities.................................................... 48,426 57,110 Long-term debt...................................................................... 78,111 27,750 Non-recourse borrowings............................................................. - 88,779 Commodity contracts and other derivatives........................................... 671 - Deferred revenue.................................................................... 1,296 1,481 Other long-term liabilities and deferred obligations................................ 4,068 52 ------------- -------------- Total liabilities............................................................ 132,572 175,172 ------------- -------------- Commitments and Contingencies Shareholders' equity (deficit): Preferred stock: $0.001 par value, 10,000,000 shares authorized; none issued.................................................................. - - Common stock: $0.001 par value, 100,000,000 shares authorized in December 31, 2001 and 2000................................................ 20 14 Additional paid in capital...................................................... 80,478 38 Accumulated deficit............................................................. (34,614) (13,231) Accumulated other comprehensive income.......................................... 19 - Treasury stock, at cost......................................................... (911) - ------------- -------------- Total shareholders' equity (deficit)......................................... 44,992 (13,179) ------------- -------------- Total liabilities and shareholders' equity (deficit)......................... $ 177,564 $ 161,993 ============= ==============
See accompanying notes to the consolidated financial statements. F-3 ATP OIL & GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (In Thousands, Except Per Share Amounts)
Years Ended December 31, ------------------------------------------- 2001 2000 1999 ------------- ------------- ------------- Revenues: Oil and gas production......................................... $ 105,757 $ 75,940 $ 34,981 Gas sold - marketing........................................... 7,417 8,015 7,703 Gain on sale of oil and gas properties......................... - 33 287 ------------- ------------- ------------- 113,174 83,988 42,971 ------------- ------------- ------------- Costs and operating expenses: Lease operating expenses....................................... 14,806 11,559 5,587 Gas purchased - marketing...................................... 7,218 7,788 7,402 Geological and geophysical expenses............................ 1,068 - - General and administrative expenses............................ 9,981 5,409 3,541 Non-cash compensation expense (general and administrative)..... 3,364 - - Depreciation, depletion and amortization....................... 53,428 40,569 22,521 Impairment of oil and gas properties........................... 24,891 10,838 7,509 Loss on unsuccessful property acquisition...................... 3,147 - - Other expense.................................................. - 450 - ------------- -------------- ------------- 117,903 76,613 46,560 ------------- ------------- ------------- Income (loss) from operations..................................... (4,729) 7,375 (3,589) -------------- ------------- ------------- Other income (expense): Interest income................................................ 884 451 202 Interest expense............................................... (10,039) (11,907) (9,399) Loss on derivative instruments................................. (18,083) (11,911) - ------------- ------------- ------------ (27,238) (23,367) (9,197) ------------- ------------- ------------- Loss before income taxes and extraordinary gain (loss)............ (31,967) (15,992) (12,786) Income tax benefit................................................ 11,186 5,594 1,829 ------------- ------------- ------------- Loss before extraordinary gain (loss)............................. (20,781) (10,398) (10,957) Extraordinary gain (loss), net of tax............................. (602) - 29,185 ------------- ------------- ------------- Net income (loss)................................................. $ (21,383) $ (10,398) $ 18,228 ============= ============= ============= Basic and diluted earnings (loss) per common share: Loss before extraordinary gain (loss).......................... $ (1.06) $ (0.73) $ (0.77) Extraordinary gain (loss), net of tax.......................... (0.03) - 2.05 ------------ ------------- ------------- Net income (loss) per common share............................. $ (1.09) $ (0.73) $ 1.28 ============ ============= ============= Weighted average number of common shares: Basic and diluted.............................................. 19,704 14,286 14,286 ============= ============= =============
See accompanying notes to the consolidated financial statements. F-4 ATP OIL & GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Thousands)
Years Ended December 31, -------------------------------------------- 2001 2000 1999 ------------- ------------- -------------- Cash flows from operating activities: Net income (loss)................................................ $ (21,383) $ (10,398) $ 18,228 Adjustments to reconcile net income (loss) to net cash provided by operating activities - Depreciation, depletion and amortization.................... 53,428 40,569 22,521 Impairment of oil and gas properties........................ 24,891 10,838 7,509 Amortization of deferred financing costs.................... 797 376 256 Extraordinary item.......................................... 926 - (29,185) Deferred tax assets......................................... (11,576) (5,594) (2,058) Non-cash compensation expense............................... 3,364 - - Gain on sale of oil and gas properties...................... - (33) (287) Other expense............................................... - 450 - Other non-cash items........................................ 196 431 566 Changes in assets and liabilities - Accounts receivable and other................................. 23,014 (22,772) (7,197) Restricted cash............................................... - 471 3,529 Cash held in escrow........................................... - - 439 Net (assets) liabilities from risk management activities...... (8,513) 7,249 - Accounts payable and accruals................................. (23,436) 37,309 (2,403) Other long-term assets........................................ (4,183) (1,462) (803) Other long-term liabilities and deferred credits.............. 3,831 (277) (408) ------------- -------------- --------------- Net cash provided by operating activities............................ 41,356 57,157 10,707 ------------- ------------- -------------- Cash flows from investing activities: Additions and acquisitions of oil and gas properties............. (110,264) (76,474) (56,051) Proceeds from sale of oil and gas properties..................... - - 1,137 Additions to furniture and fixtures.............................. (546) (361) (206) ------------- ------------- -------------- Net cash used in investing activities................................ (110,810) (76,835) (55,120) ------------- ------------- -------------- Cash flows from financing activities: Proceeds of initial public offering.............................. 78,330 - - Payment of offering costs........................................ (893) (621) - Proceeds from long-term debt..................................... 119,000 15,800 19,800 Payments of long-term debt....................................... (46,750) (8,250) (14,100) Proceeds from non-recourse borrowings............................ 3,359 42,745 93,728 Payments of non-recourse borrowings.............................. (92,138) (29,239) (39,420) Deferred financing costs......................................... (3,586) (400) (1,227) Treasury stock purchases......................................... (911) - - Other............................................................ 201 - - ------------- ------------- -------------- Net cash provided by financing activities............................ 56,612 20,035 58,781 ------------- ------------- -------------- Increase (decrease) in cash and cash equivalents..................... (12,842) 357 14,368 Cash and cash equivalents, beginning of period....................... 18,136 17,779 3,411 ------------- ------------- -------------- Cash and cash equivalents, end of period............................. $ 5,294 $ 18,136 $ 17,779 ============= ============= ============== Supplemental disclosures of cash flow information: Cash paid during the period for interest......................... $ 4,177 $ 2,531 $ 600 ============= ============= ============== Cash paid during the period for taxes............................ $ - $ 497 $ - ============= ============= ==============
See accompanying notes to the consolidated financial statements. F-5 ATP OIL & GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT) (In Thousands)
2001 2000 1999 ------------------------ ------------------------ ------------------------- Shares Amount Shares Amount Shares Amount ----------- ----------- ----------- ----------- ----------- ----------- Common Stock Balance, beginning of year....... 14,286 $ 14 14,286 $ 14 14,286 $ 14 Issuances of common stock Public offering................ 6,000 6 - - - - Exercise of stock options...... 103 - - - - - Purchase of treasury stock....... (76) - - - - - ----------- ----------- ----------- ---------- ---------- ----------- Balance, end of year............. 20,313 $ 20 14,286 $ 14 14,286 $ 14 =========== ----------- =========== ---------- ========== ----------- Paid-in Capital Balance, beginning of year....... $ 38 $ 38 $ 38 Issuances of common stock Public offering................ 76,809 - - Exercise of stock options...... 267 - - Non-cash compensation expense.... 3,364 - - ----------- ---------- ----------- Balance, end of year............. $ 80,478 $ 38 $ 38 ----------- ---------- ----------- Accumulated Deficit Balance, beginning of year....... $ (13,231) $ (2,833) $ (21,061) Net income (loss)................ (21,383) (10,398) 18,228 ----------- ---------- ----------- Balance, end of year............. $ (34,614) $ (13,231) $ (2,833) ----------- ---------- ----------- Accumulated Other Comprehensive Income Balance, beginning of year..... $ - $ - $ - Other comprehensive income..... 19 - - ----------- ---------- ----------- Balance, end of year........... $ 19 $ - $ - ----------- ---------- ----------- Treasury Stock Balance, beginning of year....... - $ - - $ - - $ - Purchase of treasury stock....... 76 (911) - - - - ----------- ----------- ----------- ---------- ---------- ----------- Balance, end of year............. 76 $ (911) - $ - - $ - =========== ----------- =========== ---------- ========== ----------- Total Shareholders' Equity (Deficit)................. $ 44,992 $ (13,179) $ (2,781) =========== ========== ===========
See accompanying notes to the consolidated financial statements. F-6 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 -- ORGANIZATION AND BASIS OF PRESENTATION Organization ATP Oil & Gas Corporation ("ATP") was incorporated in Texas in 1991. We are engaged in the acquisition, development and production of natural gas and oil properties in the outer continental shelf of the Gulf of Mexico, in the shallow-deep waters of the Gulf of Mexico and in the Southern Gas Basin of the North Sea. We primarily focus our efforts on natural gas and oil properties with proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies. We attempt to achieve a high rate of return on our investment in these properties by limiting our up-front acquisition costs and by developing our acquisitions quickly. Basis of Presentation The consolidated financial statements include our accounts and our wholly-owned subsidiaries, ATP Energy, Inc. (ATP Energy) and ATP Oil & Gas (UK) Limited. All significant intercompany transactions are eliminated upon consolidation. Certain reclassifications have been made to the prior year statements to conform to the current year presentation. NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates. The preparation of financial statements in accordance with generally accepted accounting principles and pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosure of contingent assets and liabilities in the financial statements, including the use of estimates for oil and gas reserve information and the valuation allowance for deferred income taxes. Actual results could differ from those estimates. Cash and Cash Equivalents. Cash and cash equivalents primarily consist of cash on deposit and investments in money market funds with original maturities of three months or less, stated at market value. Oil and Gas Producing Activities. We follow the "successful efforts" method of accounting for oil and gas properties. Under this method, lease acquisition costs and intangible drilling and development costs on successful wells and development dry holes are capitalized. Capitalized costs relating to producing properties are depleted on the unit-of-production method. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves for depletion rates of leasehold, platform and pipeline costs. Estimated dismantlement, restoration and abandonment costs and estimated residual salvage values are taken into account in determining amortization and depletion provisions. Expenditures for geological and geophysical are incurred for development purposes only. These costs are generally charged to expense unless the costs can be specifically attributed to determining the placement for a future well location. Expenditures for repairs and maintenance are charged to expense as incurred; renewals and betterments are capitalized. The costs and related accumulated depreciation, depletion, and amortization of properties sold or otherwise retired are eliminated from the accounts, and gains or losses on disposition are reflected in the statements of operations. F-7 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS We perform a review for impairment of proved oil and gas properties on a depletable unit basis when circumstances suggest there is a need for such a review in accordance with Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standard ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" ("SFAS 121"). To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying published future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineer's estimate of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For properties determined to be impaired, an impairment loss equal to the differences between the carrying value and the fair value of the impaired property will be recognized. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units' reserves, future cash flows and fair value. We recorded impairments during the years ended December 31, 2001, 2000 and 1999 of $24.9 million, $10.8 million and $7.5 million, respectively, primarily due to depressed oil and natural gas prices, unfavorable operating performance and downward revisions of recoverable reserves. Furniture and Fixtures. Furniture and fixtures consists of office furniture, computer hardware and software and leasehold improvements. Depreciation of furniture and fixtures is computed using the straight-line method over their estimated useful lives, which vary from three to five years. Other Assets. Other assets consist of the following (in thousands):
December 31, ------------------------------ 2001 2000 ------------- -------------- Debt financing costs.......................................... $ 3,584 $ 1,794 Offering costs................................................ - 621 Spare parts inventory......................................... 2,138 77 Other......................................................... 9 10 ------------- -------------- 5,731 2,502 Accumulated amortization...................................... (577) (648) ------------- -------------- $ 5,154 $ 1,854 ============= ==============
Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense over the term of the related agreement, using the effective interest or straight-line method (which approximates the effective interest method). Environmental Liabilities. Environmental liabilities are recognized when the expenditures are considerable probable and can be reasonably estimated. Measurement of liabilities is based on currently enacted laws and regulations, existing technology and undiscounted site-specific costs. Generally, such recognition coincides with our commitment to a formal plan of action. We have never had an environmental claim. Revenue Recognition. We record as revenue only that portion of production sold and allocable to our ownership interest in the related property in the month the production is sold. Imbalances arise when a purchaser takes delivery of more or less volume from a property than our actual interest in the production from that property. Such imbalances are reduced either by subsequent recoupment of over-and-under deliveries or by cash settlement, as required by applicable contracts. Under-deliveries are included in accounts receivable and over-deliveries are included in accounts payable. F-8 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Major Customers. We sell a portion of our oil and gas to end users through various gas marketing companies. For the year ended December 31, 2001, revenues from three purchasers accounted for 53%, 17% and 10%, respectively, of oil and gas revenues. For the year ended December 31, 2000, revenues from two purchasers accounted for 41% each of oil and gas revenues and for the year ended December 31, 1999, revenues from three customers accounted for 48%, 19% and 12%, respectively, of oil and gas revenues. Percentages are calculated on oil and gas revenues before any effects of price risk management activities. Translation of Foreign Currencies. Financial statement amounts related to our U.K. subsidiary, which has a functional currency of the British pound sterling, are translated into the U.S. dollar equivalents at exchange rates as follows: (1) balance sheet accounts at year-end exchange rates and (2) statement of operations accounts at the weighted average exchange rate for the period. The gains or losses resulting from such translations are deferred and included in accumulated other comprehensive income as a separate component of shareholders' equity (deficit). Income Taxes. Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes that enactment date. Comprehensive Income (Loss). Comprehensive income (loss) is net income (loss), plus certain other items that are recorded directly to shareholders' equity. In 2001, comprehensive loss was $21.4 million. In 2000 and 1999, we had no comprehensive income (loss) other than net income (loss). Stock Options. We have elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25") and related interpretations in accounting for our employee stock options. Under APB 25, no compensation expense is recognized when the exercise price of options equals the fair value (market price) of the underlying stock on the date of grant. Fair Value of Financial Instruments. The following methods and assumptions were used in estimating the fair value of each class of financial instruments for which it is practicable to estimate fair value. For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments. On January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). Accordingly, natural gas and oil swaps and option contracts are recorded at fair value in our consolidated balance sheet. Information concerning our price risk management activities is included in Note 12. The following table provides information on other financial instruments (in thousands):
December 31, ----------------------------------------------------------- 2001 2000 ----------------------------- ---------------------------- Carrying Fair Carrying Fair Amount Value Amount Value Debt: Bank debt....................................... $ 70,000 $ 70,000 $ 27,750 $ 27,750 Note payable.................................... 30,111 33,400 - - Non-recourse borrowings......................... - - 88,779 88,779 ------------- ------------- -------------- ------------- Total......................................... 100,111 103,400 116,529 116,529 ============= ============= ============= =============
F-9 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Our bank debt and non-recourse borrowings are variable rate debt and as such, approximate their fair values, as interest rates are variable based on prevailing market rates. Our note payable is a fixed rate note and the fair value has been determined by discounting the future payments using our incremental borrowing rate, based on the differential between the fixed interest rate and interest rates of long-term treasury securities at the date of the borrowing and the balance sheet date. New Accounting Standards. In 2001, the FASB approved SFAS No. 141 "Business Combinations" ("SFAS 141"), No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142"), No. 143 "Accounting for Asset Retirement Obligations" ("SFAS 143") and No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 141 requires all business combinations completed after June 30, 2001, be accounted for under the purchase method. This standard also establishes for all business combinations made after June 30, 2001, specific criteria for the recognition of intangible assets separately from goodwill. SFAS 141 also requires that the excess of fair value of acquired assets over cost (negative goodwill) be recognized immediately as an extraordinary gain, rather than deferred and amortized. SFAS 142 addresses the accounting for goodwill and other intangible assets after an acquisition. The most significant changes made by SFAS 142 are: 1) goodwill and intangible assets with indefinite lives will no longer be amortized; 2) goodwill and intangible assets with indefinite lives must be tested for impairment at least annually; and 3) the amortization period for the intangible assets with finite lives will no longer be limited to forty years. We will adopt SFAS 142 effective January 1, 2002, as required. Additionally, SFAS 142 requires that unamortized negative goodwill associated with investments accounted for under the equity method and acquired before July 1, 2001, be recognized in income as a cumulative effect of change in accounting principle. SFAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets, including: 1) the timing of liability recognition; 2) initial measurement of the liability; 3) allocation of asset retirement cost to expense; 4) subsequent measurement of the liability; and 5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived asset and subsequently allocated to expense using a systematic and rational method. We will adopt the Statement effective January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. SFAS 144 provides that long-lived assets to be disposed of by sale be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations, and broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. SFAS 144 is effective for fiscal years beginning after December 15, 2001. SFAS 141 and SFAS 142 will not apply to us unless we enter into a future business combination. We are currently assessing the impact of SFAS 143 and SFAS 144 on our financial condition and results of operations. NOTE 3 -- ACQUISITIONS Gulf of Mexico During 2001, we acquired interests in 15 lease blocks covering 14 properties in six separate transactions. Total reserves associated with these transactions were approximately 60.6 Bcfe (unaudited), based on third party reservoir engineering estimates at year-end, for total acquisition costs of approximately $22.7 million. Our working interests in these properties range from 25% to 100%. Ten of these properties produced in 2001 with additional development and production planned on the remaining four in 2002 and beyond. F-10 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS During 2000 we acquired an interest in 11 lease blocks covering nine separate properties for total acquisition costs of $7.5 million. Total proved reserves associated with these acquisitions were approximately 66.0 Bcfe (unaudited) net to our interest. Our working interests in these properties range from 50% to 100%. We are the operator of all of the properties. Included in these acquisitions were four blocks on three separate properties which represent our first acquisitions in the shallow-deep waters of the Gulf of Mexico. Of these nine properties, five were producing in 2001, including "Ladybug", one of the properties in the shallow-deep waters of the Gulf of Mexico, and a sixth property commenced production in the first quarter of 2002. Two of the properties are scheduled for future development in 2002 and beyond and the remaining property was abandoned without commencing production in 2001. Southern Gas Basin of the North Sea In October 2000, we entered into a letter of intent to acquire interests in three properties (five blocks) in the Southern Gas Basin of the North Sea which included a 50% interest in one block, a 100% interest in one block and an 86% interest in three blocks. In 2001, we acquired all three properties for total acquisition costs of approximately $3.1 million. At December 31, 2001, net proved reserves were approximately 80.6 Bcfe (unaudited), based on third party reservoir engineering estimates at year-end. None of the properties were producing when acquired and we expect to pursue development operations in 2002 through 2004. NOTE 4 -- FINANCING AND DEBT Long-term debt at December 31, 2001 and 2000 consisted of the following balances (in thousands):
December 31, ------------------------------ 2001 2000 ------------- -------------- Credit facility, bearing interest at 5.26% and 10% at December 31, 2001 and 2000, respectively..................... $ 70,000 $ 27,750 11.5 % Note payable, net of unamortized discount of $1,139........ 30,111 - Non-recourse borrowings, bearing interest at 12.7%, at December 31, 2000............................................ - 88,779 ------------- -------------- Total debt........................................................ 100,111 116,529 Less current maturities........................................... (22,000) - ------------- -------------- Total long-term debt.............................................. $ 78,111 $ 116,529 ============= ==============
Credit Facilities In March 2001, we repaid our then existing bank credit facility and in April 2001 we repaid the full amount borrowed under a non-recourse development program credit agreement which we had used as a source of financing for the acquisition of oil and gas properties. Concurrent with the repayment of our non-recourse agreement, we negotiated with the lender to terminate the overriding royalty interest retained by it on all properties previously financed by the lender in exchange for a lump-sum payment of approximately $5.6 million. Upon repayment of our former credit and non-recourse facilities, we entered into a new $100.0 million senior-secured revolving credit facility in April 2001. This facility is secured by substantially all of our oil and gas properties, as well as by approximately two-thirds of the capital stock of our U.K. subsidiary and is guaranteed by our wholly owned subsidiary, ATP Energy, Inc. As amended, the amount available for borrowing under the facility is limited to the loan value, as determined by the bank, of oil and gas properties pledged under the facility. At December 31, 2001, the borrowing base was $70.0 million and the monthly borrowing base reduction was set at $2.0 million a month beginning February 27, 2002 and remains in effect until there is a change, if any, at the next redetermination date. The redetermination dates are on or around the first business day of each calendar quarter at which time the lenders can increase or decrease the borrowing base and the monthly reduction amount. The next scheduled redetermination date is on or around the first business day of April 2002. Our lender has indicated this process will not be completed until mid to late April of 2002. The $2.0 million monthly reduction included in F-11 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS current maturities of long-term debt assumes there is no change in the monthly reduction amount or the borrowing base in 2002. If our outstanding balance exceeds our borrowing base at any time, we are required to repay such excess within 30 days and our interest rate during the time an excess exists is increased by 2.00%. A reduction in the borrowing base or an increase in the monthly reduction amount by the lender would have a material negative impact on our cash flows and our ability to fund future operations during 2002. As of December 31, 2001, all of our borrowing base under the agreement was outstanding. Advances under the credit facility can be in the form of either base rate loans or Eurodollar loans. The interest on a base rate loan is a fluctuating rate equal to the higher of the Federal funds rate plus 0.5% and the bank base rate, plus a margin of 0.25%, 0.50%, 0.75% or 1.00% depending on the amount outstanding under the credit agreement. The interest on a Eurodollar loan is equal to the Eurodollar rate, plus a margin of 2.25%, 2.50%, 2.875%, or 3.125% depending on the amount outstanding under the credit facility. The amended credit facility matures in November 2003. Our credit facility contains conditions and restrictive provisions, among other things, (1) prohibiting us to enter into any arrangement to sell or transfer any of our material property, (2) prohibiting a merger into or consolidation with any other person or sell or dispose of all or substantially all of our assets, and (3) maintaining certain financial ratios. Note Payable Effective June 29, 2001, we issued a note payable to a purchaser for a face principal amount of $31.3 million which matures in June 2005 and bears interest at a fixed rate of 11.5% per annum. The note is secured by second priority liens on substantially all of our oil and gas properties and is subordinated in right of payment to our existing senior indebtedness. We executed an agreement in connection with the note which contains conditions and restrictive provisions and requires the maintenance of certain financial ratios. Upon consent of the purchaser, which shall not be unreasonably withheld, the note may be repaid prior to the maturity date with an additional repayment premium based on the percentage of the principal amount paid, ranging from 4.5% during the first year to 16.5% in the final year of payment. If the note is paid at maturity, the maximum payment premium of 16.5% is required. The expected repayment premium is being amortized to interest expense straight-line, over the term of the note which approximates the effective interest method. The resulting liability is included in other long-term liabilities on the consolidated balance sheet. In July 2001, we received proceeds of $30.0 million in consideration for the issuance of the note. The discount of $1.3 million is being amortized to interest expense using the effective interest method. The amount available for borrowing under the note is limited to the loan value of oil and gas properties pledged under the note, as determined by the purchaser. The purchaser has to right to make redetermination of the borrowing base at least once every six months. We have assumed there is no change in the borrowing base in 2002. If our outstanding balance exceeds the borrowing base at any time, we are required to repay such excess within 10 days subject to the provisions of the agreement. A reduction in the borrowing base by the lender would have a material negative impact on our cash flows and our ability to fund future obligations during 2002. As of December 31, 2001, all of our borrowing base under the agreement was outstanding. F-12 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS As of December 31, 2001, we were in compliance with all of the financial covenants of our credit facility and note payable agreements other than our working capital covenant (as defined by the agreements) for which we have obtained amendments from our lenders. Both of the amendments require that our working capital at December 31, 2001 and March 31, 2002 shall not exceed deficits of $10.0 million and $5.0 million, respectively. Maturities The aggregate amount of maturities of our long-term debt for the next five years is: 2002 - $22.0 million, 2003 - $48.0 million, 2004 - none, 2005 - $31.3 million, 2006 - none. NOTE 5 -- EQUITY Initial Public Offering On February 5, 2001, we priced our initial public offering ("IPO") of 6.0 million shares of common stock and commenced trading the following day. After payment of the underwriting discount we received net proceeds of $78.3 million on February 9, 2001. Common Stock At December 31, 2001, we had 100,000,000 shares authorized, 20,388,488 shares issued, 20,312,648 shares outstanding and 75,840 shares in treasury. At December 31, 2000, we had 100,000,000 shares authorized, 14,285,714 shares issued and outstanding. Treasury Stock During the second quarter, the first option vesting date occurred for certain options granted since September 1999 through the date of our IPO on February 5, 2001, as well as for certain options granted prior to September 1999. Of those options exercised during the second quarter, certain optionees elected to receive cash upon exercise of their options, whereby we purchased 75,840 shares for approximately $0.9 million and recorded such purchase as treasury stock using the cost method. Change in Authorized Capitalization On December 12, 2000, the Board of Directors approved an increase in the authorized common stock from 50,000,000 shares to 100,000,000 shares, the authorization of 10,000,000 shares of preferred stock and a 1.4-for-1 reverse split of the common stock. Par value of the common stock remained $.001 per share. The reverse stock split was effective December 12, 2000. NOTE 6 -- STOCK OPTION PLANS In May 1994, the Board of Directors approved the 1994 Stock Option Plan (the "1994 Plan") under which it was authorized to issue up to 55,902,930 shares of common stock. The exercise price of the options under the 1994 Plan was not less than the greater of par value per share or fair market value, at date of grant. These options had a maximum term of 10 years, subject to vesting requirements in the individual option agreements. In April 2000, the only outstanding option to purchase 18,937,397 shares under the 1994 Plan was amended to limit the number of shares that could be purchased pursuant to the option to such number that enables the holder to maintain ownership of a majority of the outstanding shares. Because the holder of this option owned a majority of the shares, the number of shares exercisable as of April 2000 was zero. Upon the closing of the IPO in February 2001, the 1994 Plan and all outstanding options under this plan were cancelled. F-13 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In December 1998, the Board of Directors approved the 1998 Stock Option Plan (the "1998 Plan") to provide increased incentive for its employees and directors. The 1998 Plan authorizes the granting of incentive and nonqualified stock options for up to 2,678,571 shares of common stock to eligible participants and expire five years after the closing date of our IPO. One third of the options were exercisable on April 10, 2001 with each remaining third exercisable on the first and second anniversaries of the IPO. Options granted under this plan remain exercisable by the employees owning such options, but no new options will be granted under this plan. In January 2001, the Board of Directors approved the 2000 Stock Option Plan (the "2000 Plan") to provide increased incentive for its employees and directors. The 2000 Plan authorizes the granting of options and awards for up to 4,000,000 shares of common stock. Generally, options are granted at prices equal to at least 100% of the fair value of the stock at the date of grant, expire not later than five years from the date of grant and vest ratably over a four-year period following the date of grant. From time to time, as approved by the Board of Directors, options with differing terms have also been granted. The following table is a summary of stock option activity:
2001 2000 1999 --------------------- ------------------- --------------------- Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price ----------- -------- ----------- ------- ----------- -------- Outstanding at beginning of year............ 646,608 $ 2.710 19,394,362 $ 0.040 19,378,111 $ 0.040 Granted..................................... 1,117,000 11.200 368,215 3.690 18,573 1.400 Exercised................................... (102,774) 1.960 - - - - Forfeited................................... (23,025) 4.000 (178,572) 1.400 (2,322) 1.400 Cancelled................................... - - (18,937,397) 0.004 - - ----------- ---------- ---------- Outstanding end of year..................... 1,637,809 $ 8.520 646,608 $ 2.710 19,394,362 $ 0.040 =========== =========== =========== Exercisable at end of period................ 112,760 $ 3.370 - $ - 18,937,397 $ 0.004 ============ ============ =========== Weighted average fair value of options granted during the year.......... $ 4.65 $ - $ -
The following table summarizes information about all stock options outstanding at December 31, 2001:
Options Outstanding Options Exercisable -------------------------------------- --------------------------- Weighted Average Weighted Weighted Remaining Average Average Number Contractual Exercise Number Exercise Range of Exercise Prices Outstanding Life Price Exercisable Price - -------------------------------------------- ------------ ----------- ----------- ------------ ---------- $ 1.40 - $ 3.85............................. 537,809 3.0 Years $ 2.82 112,760 $ 3.37 $ 6.95 - $ 6.95............................. 25,000 4.8 Years 6.95 - - $11.24 - $11.40............................. 1,055,000 4.4 Years 11.37 - - $14.00 - $14.00............................. 20,000 4.1 Years 14.00 - - ----------- ----------- $ 1.40 - $14.00............................. 1,637,809 3.9 Years $ 8.52 112,760 $ 3.37 =========== ===========
F-14 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS We have elected to follow APB 25 and related interpretations in accounting for our stock option plans. Accordingly, no compensation expense, except as specifically described below, has been recognized for employee stock option plans. Since options granted under the 1998 Plan did not vest nor were exercisable until 60 days after the date of our IPO, under the provisions of SFAS No. 123 "Accounting for Stock Based Compensation" ("SFAS 123"), our pro forma net loss and per share amounts would have been unchanged for the years ended December 31, 2000 and 1999. Had compensation expense been determined based on the fair value of the options at the date of or subsequent to the IPO, our loss and the related per share amount would have been reduced as is reflected by the pro forma amount indicated below (in thousands, except per share data):
As Reported Net loss before extraordinary item.................................. $ (20,781) Net loss per common share, basic and diluted........................ (1.06) Pro Forma Net loss before extraordinary item.................................. $ (20,934) Net loss per common share, basic and diluted........................ (1.06)
The fair value of these option grants were estimated on the latter of the date of grant or date of our IPO using a Black-Scholes option-pricing model with the following weighted-average assumptions: zero dividend yield; risk-free interest rate of 4.5% and volatility of 80.2% and an expected life of 2.4 years. Because the determination of the fair value of all options granted after we became a public entity includes an expected volatility factor, additional option grants are expected to be made and most options will vest over several years, the above effects of applying SFAS 123 in this pro forma disclosure are not likely to be representative of the effects on reported net income for future years. SFAS 123 does not apply to awards granted prior to fiscal year 1996. In 2001, we recorded a non-cash compensation expense of approximately $3.4 million. A portion of the expense ($2.9 million) is related to options granted from September 1999 to the date of our IPO and is based on the difference between the exercise price for those options and the fair market value of our stock as determined by the IPO price of $14.00 per share. The expense is recognized in the periods in which the options vest. Each option is divided into three equal portions corresponding to the three vesting dates, with the related compensation cost amortized straight-line over the period between the IPO date and the vesting date. The remaining expense ($0.5 million) was related to certain options granted prior to September 1999 and exercised in the current year. The expense was recorded on those exercises as the method in which those shares were exercised required us to account for the options under variable accounting. The remaining compensation expense to be recorded over 2002 and 2003 is approximately $0.5 million. We have a 401(k) Savings Plan which covers all domestic employees. At our discretion, we may match a certain percentage of the employees' contributions to the plan. The matching percentage is discretionary and is currently 50% of each participant's contributions up to 6% of the participant's compensation. Our matching contributions to the plan were approximately $70,000, $56,000 and $31,000, for the years ended December 31, 2001, 2000 and 1999, respectively. We also have a defined contribution plan for our U.K. employees. We currently contribute 3% to the plan and such contributions are subject to the Pensions Act 1999 (U.K.). For the year ended December 31, 2001, we contributed approximately $14,000. NOTE 7 -- EARNINGS PER SHARE Basic earnings per share is computed by dividing net income (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined on the assumption that outstanding stock options have been converted using the average price for the period. For purposes of computing earnings per share in a loss year, potential common shares have been excluded from the computation of weighted average common shares outstanding because their effect is antidilutive. F-15 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Basic and diluted net income (loss) per share is computed based on the following information (in thousands, except share and per share amounts):
For the Years Ended December 31, ------------------------------------------------ 2001 2000 1999 ------------- ------------- ------------- Net income (loss) available to common shareholders............ $ (21,383) $ (10,398) $ 18,228 ============= ============= ============= Weighted average shares-basic and diluted..................... 19,704 14,286 14,286 ============= ============= ============= Net income (loss) per share: Basic and diluted: Loss before extraordinary gain (loss).................. $ (1.06) $ (0.73) $ (0.77) Extraordinary gain (loss), net of income taxes......... (0.03) - 2.05 -------------- ------------- ------------- Net income (loss) per common share..................... $ (1.09) $ (0.73) $ 1.28 ============== ============= =============
NOTE 8 -- EXTRAORDINARY ITEMS For the year ended December 31, 2001, we recognized an extraordinary loss of $0.6 million, net of income taxes, related to the early extinguishment of our non-recourse borrowings. For the year ended December 31, 1999, we prepaid the amount outstanding under a development program credit agreement at a discount and recorded an extraordinary gain of $29.2 million, net of income taxes. NOTE 9 -- INCOME TAXES The benefit (provision) for income taxes before extraordinary gain (loss) consisted of the following:
For the Years Ended December 31, ------------------------------------------------ 2001 2000 1999 ------------- ------------- ------------- Current: State....................................................... $ - $ - $ - Federal..................................................... - - (229) ------------- ------------- -------------- - - (229) ------------- ------------- -------------- Deferred: State....................................................... - - (82) Federal..................................................... 11,186 5,594 2,140 ------------- ------------- ------------- 11,186 5,594 2,058 ------------- ------------- ------------- Benefit for income taxes before extraordinary gain (loss)..... $ 11,186 $ 5,594 $ 1,829 ============= ============= =============
Additionally, a tax benefit of $0.3 million and none was recognized related to the extraordinary gain (loss) for the years ended December 31, 2001 and 1999, respectively. The reconciliation of income tax computed at the U.S. federal statutory tax rates to the provision for income taxes is as follows:
For the Years Ended December 31, ------------------------------------------------ 2001 2000 1999 ------------- ------------- ------------- Before any valuation allowance: Statutory federal income tax rate........................ (35.00)% (35.00)% 35.00% State income taxes, net of federal benefit............... 0.00 0.00 0.32 Adjustment to valuation allowance........................ 0.00 0.00 (46.53) Nondeductible and other.................................. 0.01 0.02 0.05 -------------- ------------- ------------- (34.99)% (34.98)% (11.16)% ============== ============= =============
F-16 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS At December 31, 2001 we have determined that it is more likely than not the deferred tax assets will be realized based on current projections of future taxable income due to higher commodity prices at year-end. Significant components of our deferred tax assets (liabilities) as of December 31, 2001 and 2000 are as follows (in thousands):
December 31, ------------------------------ 2001 2000 ------------- ------------- Deferred tax assets: Net operating loss carryforwards........................................... $ 3,809 $ 3,826 Minimum tax credit carryforwards........................................... 229 229 Fixed asset basis differences.............................................. 11,367 554 State taxes................................................................ 17 17 Unrealized book (gains) losses............................................. (443) 2,537 Stock based compensation expense........................................... 1,177 - Litigation................................................................. 1,050 - Foreign equity in subsidiary............................................... 1,152 - Other...................................................................... 870 489 ------------- ------------- Net deferred tax assets......................................................... $ 19,228 $ 7,652 ============= =============
At December 31, 2001, 2000 and 1999, we had net operating loss carryforwards for federal income tax purposes of approximately $10.7 million, $11.0 million, and $11.0 million respectively, which are available to offset future federal taxable income through 2021. A tax benefit related to the exercise of employee stock options of approximately $0.1 million was allocated directly to additional paid-in capital in 2001. NOTE 10 -- COMPREHENSIVE LOSS Comprehensive loss consists of net loss, as reflected on the consolidated statement of operations, and other gains and losses affecting shareholders' equity that are excluded from net loss. We recorded other comprehensive income for the first time in 2001. Total comprehensive loss for the year ended December 31, 2001 is as follows (in thousands):
Net loss....................................................................... $ (21,383) ------------ Other comprehensive income, net of tax: Cumulative effect of change in accounting principle - January 1, 2001........ (34,252) Reclassification adjustment for settled contracts............................ 34,252 Foreign currency translation adjustment...................................... 19 -------------- Other comprehensive income................................................. 19 -------------- Comprehensive loss............................................................. $ (21,364) =============
F-17 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 11 -- COMMITMENTS AND CONTINGENCIES Operating Leases We have commitments under an operating lease agreement for office space. Total rent expense for the years ended December 31, 2001, 2000 and 1999 was approximately $0.3 million, $0.2 million and $0.1 million respectively. At December 31, 2001, the future minimum rental payments due under the lease are as follows (in thousands amounts): 2002................................................................ $ 375 2003................................................................ 346 2004................................................................ 342 2005................................................................ 214 2006................................................................ 154 Later Years......................................................... 1,114 --------- Total........................................................... $ 2,545 ========= Litigation On August 28, 2001 ATP entered into a written agreement to acquire a property in the Gulf of Mexico during September 2001. On October 9, 2001 the agreement was amended to ultimately extend the closing date until October 31, 2001 in exchange for payments made by ATP totaling $3.0 million. This amendment also contained an arrangement whereby if ATP did not close on the property, and if sellers sold the property to a third party with a sale that met specific contract requirements, ATP would be required to execute a six month note for payment of the differential. Since ATP did not obtain the financing for the acquisition by October 31, 2001, the transaction did not close by that date; however, the parties' intensive work toward closing continued beyond that date without interruption. While working on the closing for the property with ATP, the sellers sold the property to a third party without informing ATP until after the closing had taken place. ATP filed an action in the District Court of Harris County, Texas against the sellers, generally alleging improper sale of the offshore property to a third party and breach of contract, and seeking unspecified damages from the sellers. The case is encaptioned ATP Oil & Gas Corporation vs. Legacy Resources Co., L.P. et al, No. 2001-63224 in the 269th Judicial District Court of Harris County, Texas. At the same time sellers notified ATP of their sale to a third party, the sellers had a demand made upon ATP for execution of a six month note for the amount of an alleged differential of approximately $12.3 million plus interest at 16%. Substantiation of the amount and validity of the demand could not be ascertained based on the content of the demand received. ATP contested the entire demand. The litigation is in its very early stages with written discovery propounded by ATP, but no answers received, and no depositions taken. The judge has abated the litigation, until arbitration pursuant to the underlying agreements between the sellers and ATP is completed. Since the legal proceedings have just begun, and a prediction of the outcome would be premature and uncertain, we have not accrued any amount related to this matter. And while we are seeking recovery of the amounts previously paid and discussed above, the $3.0 million has been charged to earnings along with certain other costs related to this matter. ATP intends to vigorously defend against the sellers' claims and forcefully pursue its own claims in this matter. In August 2001, Burlington Resources Inc. filed suit against us alleging formation of a contract with us and our breach of the alleged contract. The complaint seeks compensatory damages of approximately $1.1 million. We believe that this claim is without merit, and we intend to defend it vigorously. F-18 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS We are, in the ordinary course of business, a claimant and/or defendant in various legal proceedings. Management does not believe that the outcome of these legal proceedings, individually, and in the aggregate will have a materially adverse effect on our financial condition, results of operations or cash flows. NOTE 12 -- DERIVATIVE INSTRUMENTS We utilize various derivative instruments, for purposes other than trading, to hedge our exposure to price fluctuations on natural gas and oil sales. The derivative instruments consist primarily of swap contracts entered into with financial institutions. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes. Effective January 1, 2001, we adopted SFAS No. 133 and SFAS No. 138, an amendment to SFAS 133. SFAS 133 and 138 require that derivatives be reported on the balance sheet at fair value and, if the derivative is not designated as a hedging instrument, changes in fair value must be recognized in earnings in the period of change. If the derivative is designated as a hedge and to the extent such hedge is determined to be effective, changes in fair value are either (a) offset by the change in fair value of the hedged asset or liability (if applicable) or (b) reported as a component of other comprehensive income (loss) in the period of change, and subsequently recognized in earnings when the offsetting hedged transaction occurs. We use derivatives to hedge the price of crude oil and natural gas. Effective January 1, 2001, we did not attempt to qualify for the hedge provisions under SFAS 133 and thus have not designated our derivatives as hedging instruments. Accordingly, we account for the changes in market value of these derivatives through current earnings. This method will result in increased earnings volatility associated with commodity price fluctuations. Gains and losses on all derivative instruments related to accumulated other comprehensive income (loss) are included in other income (expense) on the consolidated financial statements. On January 1, 2001, in accordance with the transition provisions of SFAS 133, we recorded a non-cash loss of $52.7 million ($34.3 million after tax) in accumulated other comprehensive loss, representing the cumulative effect of an accounting change to recognize at fair value all cash flow type derivatives. Also on January 1, 2001, we recorded derivative liabilities of $52.7 million. During the year ended December 31, 2001, losses of $52.7 million ($34.3 million after tax) were reclassified from accumulated other comprehensive loss to earnings. Prior to the adoption of this standard, we included gains and losses on hedging instruments as a component of revenue. As of December 31, 2001, all of our natural gas swap agreements were with one counterparty whose investment grade ratings were Baa2 from Moody's and BBB from Standard & Poor's. Those agreements outstanding were as follows: Average Period MMBtu/Day $/MMBtu - ------ --------- ------------ January 2002 - October 2003...................... 20,000 3.02 At December 31, 2001, the fair value of our open derivative positions consisted of a $1.9 million current asset and a $0.7 million long-term liability. The $18.1 million loss on derivative instruments for the year ended December 31, 2001 includes the following items: . a $26.5 million loss related to contracts settled during 2001, . $7.2 million related to the reversal of a speculative position ($2.6 million) and settlement of a written call option ($4.6 million), both recorded at December 31, 2000 and settled during 2001; and . a $1.2 million gain on open positions at December 31, 2001. F-19 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS On occasion, we may find ourselves in speculative positions as a result of actual production being less than projected production when the derivative products were consummated or as a result of entering into speculative derivative instruments. Any speculative positions are accounted for using the mark-to-market method. For the year ended December 31, 2000, we recognized a loss on derivative instruments in the amount of $11.9 million from certain speculative positions. At December 31, 2000, the fair value of our derivative positions was a $7.2 million current liability. Thus far, in 2002 we have entered into the following swap agreements:
Period Volume/Day $/Unit - ------ ----------- ------------ Natural gas (MMBtu): February 2002 - October 2002 ......................... 6,000 2.41 April 2002 - July 2002 ............................... 6,000 2.81 April 2002 - October 2002 ............................ 2,000 3.31 Oil (Bbl): April 2002 - December 2002 ........................... 500 23.50 April 2002 - December 2002 ........................... 500 25.25
NOTE 13 -- ATP ENERGY GAS PURCHASE TRANSACTION ATP Energy entered an agreement in December 1998 with American Citigas Company ("American Citigas") to purchase gas over a ten-year period commencing January 1999. The amount of gas to be purchased was 9,000 MMBtu per day for the first year and 5,000 MMBtu per day for years two through ten. The contract requires ATP Energy to purchase on a monthly basis the gas at a premium of approximately $2.50 per MMBtu to the Gas Daily Henry Hub Index. American Citigas is required to reimburse ATP Energy on a monthly basis for a portion of this premium during the term of the contract. This portion of the reimbursement is accomplished by a note receivable in favor of ATP. The note receivable bears interest at 6% and has monthly payments of approximately $0.4 million until January 2009. The balance of the note receivable at December 31, 2001 and 2000 was $25.9 million and $28.8 million, respectively. At December 31, 2001 and 2000, the present value of the remaining premium payments to be made by ATP Energy, using a discount rate of 6%, was $25.8 million and $28.7 million, respectively. The note receivable and the premium payable to American Citigas have been offset in the consolidated financial statements in accordance with the prescribed accounting in FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts". The aggregate amount of premium payments to be paid by ATP Energy over the term of the contract is approximately $49.0 million and the aggregate amount of payments to be paid to ATP Energy over the term of the note is approximately $45.0 million. At December 31, 2001 the remaining premium to be paid was $31.7 million, which will be reimbursed by the monthly reimbursement from American Citigas and the remaining deferred obligation discussed below. The terms provide for the immediate termination of the agreement upon non-performance by American Citigas. ATP Energy entered into a contract with El Paso Energy Marketing in December 1998 to sell an identical quantity of natural gas at the Gas Daily Henry Hub index price less $0.015 until December 2001. This contract has been renewed on a month-to-month basis. ATP Energy received $6.0 million in connection with these transactions, of which $2.0 million was recorded as deferred revenue and $4.0 million was recorded as deferred obligations. The deferred revenue amount of $2.0 million is a non-refundable fee received by ATP Energy and is recognized into income as earned over the life of the contract. At December 31, 2001 and 2000, the deferred revenue amount was $1.3 million and $1.5 million, respectively. The deferred obligation amount of $4.0 million represented the difference between the premium we agreed to pay for natural gas under the American Citigas contract and the obligation of American Citigas to partially reimburse us for such premium. Any deferred obligation amount F-20 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS not utilized is refundable if the contract is terminated. The transaction is structured with American Citigas such that there is no financial impact to ATP Energy associated with the premium paid and reimbursement received other than the $2.0 million realized by ATP Energy. The remaining balance of the deferred obligation was $0.05 million and $0.1 million at December 31, 2001 and 2000, respectively. The premium we pay to American Citigas will be approximately the same as the reimbursement obligation for the remainder of the contract. ATP Energy entered into the transactions to earn the fee for agreeing to market the volumes of natural gas specified in the American Citigas contract. Our officers were paid $152,125 and $97,875 for the years ended December 31, 2000, and 1999, respectively, for negotiating and monitoring ATP Energy's gas supply contract. We have recognized these amounts in general and administrative expense in the respective periods. No amounts were paid in 2001 and we do not intend to pay any further amounts. NOTE 14 -- RELATED PARTY TRANSACTIONS We have granted to certain of our officers overriding royalty interests ranging in amounts from 0.2% to 3.0% in four of its oil and gas properties. The overriding royalty interest entitles the holder to a portion, 0.2% to 3.0%, of the future revenue for the life of each property. As a result, we recognized $0.3 million and $0.6 million in general and administrative expense for the years ended December 31, 2000 and 1999. No amounts were paid in 2001 and we do not intend to pay any further amounts. NOTE 15 -- SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)
First Second Third Fourth Quarter Quarter Quarter Quarter ----------- ----------- ----------- ----------- 2001 Revenues............................................ $ 41,443 $ 31,035 $ 20,883 $ 19,813 Costs and expenses.................................. 28,701(1) 29,694(1) 24,659(1) 34,849(1) Income (loss) from operations....................... 12,742 1,341 (3,776) (15,036) Income (loss) before extraordinary item............. (6,873) 3,813 (6,499) (11,222) Net income (loss)................................... (6,873) 3,211 (6,499) (11,222) Income (loss) per common share before extraordinary item, basic and diluted.............. $ (0.38) $ 0.19 $ (0.32) $ (0.55) Net income (loss) per common share: Basic and diluted................................. $ (0.38) $ 0.16 $ (0.32) $ (0.55) 2000 Revenues............................................ $ 15,127 $ 24,558 $ 20,462 $ 23,841 Costs and expenses.................................. 11,682 23,230(2) 20,049(2) 21,652(2) Income (loss) from operations....................... 3,445 (1,185) (3,316) (3,480) Net income (loss)................................... 1,029 (2,742) (4,251) (4,434) Net income (loss) per common share: Basic and diluted................................. $ 0.07 $ (0.19) $ (0.30) $ (0.31) - -------------------
(1) Includes impairment charges of $8.5 million, $5.7 million, $3.7 million and $7.0 million during the first, second, third and fourth quarters, respectively, for eight properties. (2) Includes impairment charges of $6.2 million, $0.8 million and $3.8 million during the second, third and fourth quarters, respectively, for three properties. F-21 ATP OIL & GAS CORPORATION SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS OIL AND GAS RESERVES AND RELATED FINANCIAL DATA (UNAUDITED) Costs Incurred The following table summarizes costs incurred in natural gas and oil property acquisition, exploration and development activities are summarized below (in thousands):
Years Ended December 31, --------------------------------------------------------------- 2001 2000 1999 ------------------------------------- ----------- ----------- U.S. U.K. Total U.S. U.S. ----------- ----------- ----------- ----------- ----------- Property costs: Acquisition costs.......................... $ 28,344 $ 3,112 $ 31,456 $ 7,534 $ 25,274 Development costs.......................... 77,783 719 78,502 68,982 30,777 ----------- ------------ ----------- ----------- ----------- Total costs incurred......................... $ 106,127 $ 3,831 $ 109,958 76,516 $ 56,051 =========== =========== =========== =========== ===========
Natural Gas and Oil Reserves Proved reserves are estimated quantities of natural gas and oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. Reserves quantities as well as certain information regarding future production and discounted cash flows were prepared by independent petroleum engineers Ryder Scott Company, L.P. for all years presented and Schlumberger Holditch-Reservoir Technologies Consulting Services for one property for 2000 and 1999. Our U.K. reserves at December 31, 2001 were prepared by independent petroleum consultants Troy Ikoda Limited. At December 31, 2001, our U.K. reserves included one property that was subject to an agreement with our joint venture partner to earn an additional 11% interest in that property upon their performance of future obligations. We expect the conditions of that agreement to be satisfied in the first half of 2002. At that time our ownership in the property will be reduced by 11%, resulting in a reduction of our net reserves of approximately 5.5 Bcfe. Our future revenues and costs in the project will be reduced accordingly. The reserves included in the tables below reflect our ownership interest in that property prior to the satisfaction of the conditions of the earn-in agreement. F-22 ATP OIL & GAS CORPORATION SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS The following table sets forth our net proved oil and gas reserves at December 31, 1998, 1999, 2000 and 2001 and the changes in net proved oil and gas reserves for the years ended December 31, 1999, 2000 and 2001:
Oil, Condensate and Natural Gas (MMcf) Natural Gas Liquids (MMBbls) -------------------------------------- -------------------------------------- U.S. U.K. Total U.S. U.K. Total ------------ ----------- ----------- ----------- ----------- ----------- Proved Reserves at December 31, 1998................ 46,424 - 46,424 586 - 586 Revisions of previous estimates..... 3,033 - 3,033 (131) - (131) Extensions and discoveries.......... 2,257 - 2,257 - - - Purchase of properties.............. 58,816 - 58,816 1,362 - 1,362 Production.......................... (16,533) - (16,533) (128) - (128) ----------- ----------- ----------- ----------- ----------- ------------ Proved Reserves at December 31, 1999................ 93,997 - 93,997 1,689 - 1,689 Revisions of previous estimates..... (19,423) - (19,423) (46) - (46) Extensions and discoveries.......... 7,239 - 7,239 77 - 77 Purchase of properties.............. 42,318 - 42,318 2,602 - 2,602 Disposition of properties........... (151) - (151) - - - Production.......................... (22,410) - (22,410) (345) - (345) ----------- ----------- ----------- ----------- ----------- ------------ Proved Reserves at December 31, 2000................ 101,570 - 101,570 3,977 - 3,977 Revisions of previous estimates..... (6,793) - (6,793) 134 - 134 Purchase of properties.............. 40,060 80,629 120,689 3,432 - 3,432 Production.......................... (20,957) - (20,957) (790) - (790) ----------- ----------- ----------- ----------- ----------- ----------- Proved Reserves at December 31, 2001................ 113,880 80,629 194,509 6,753 - 6,753 =========== =========== =========== =========== =========== ===========
Oil, Condensate and Natural Gas (MMcf) Natural Gas Liquids (MMBbls) -------------------------------------- -------------------------------------- U.S. U.K. Total U.S. U.K. Total ------------ ----------- ----------- ----------- ----------- ----------- Proved Developed Reserves at December 31, 1998................ 39,728 - 39,728 579 - 579 December 31, 1999................ 67,314 - 67,314 710 - 710 December 31, 2000................ 42,502 - 42,502 851 - 851 December 31, 2001................ 56,704 - 56,704 3,115 - 3,115
Standardized Measure The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves as of year-end is shown below (in thousands):
Years Ended December 31, ------------------------------------------------------------ 2001 2000 1999 ----------------------------------- ---------- ------- U.S. U.K. TOTAL U.S. U.S. --------- --------- --------- ---------- ------- Future cash inflows......................... $ 423,273 $ 302,894 $ 726,167 $1,139,404 $272,047 Future operating expenses................... (59,722) (100,330) (160,052) (70,719) (40,794) Future development costs.................... (100,919) (111,044) (211,963) (137,453) (48,204) --------- --------- --------- ---------- -------- Future net cash flows....................... 262,632 91,520 354,152 931,232 183,049 Future income taxes......................... (35,469) (26,188) (61,657) (285,587) (27,611) --------- --------- --------- ---------- -------- Future net cash flows, after income taxes... 227,163 65,332 292,495 645,645 155,438 10% annual discount per annum............... (54,247) (25,584) (79,831) (121,164) (26,732) --------- --------- --------- ---------- -------- Standardized measure of discounted future net cash flows..................... $ 172,916 $ 39,748 $ 212,664 $ 524,481 $128,706 ========= ========= ========= ========== ========
F-23 ATP OIL & GAS CORPORATION SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS Future cash inflows are computed by applying year-end prices of oil and gas to the year-end estimated future production of proved oil and gas reserves. The base prices used for the Pretax PV-10 calculation were public market prices on December 31 adjusted by differentials to those market prices. These price adjustments were done on a property-by-property basis for the quality of the oil and natural gas and for transportation to the appropriate location. The Henry Hub and West Texas Intermediate prices, before adjustment for quality and transportation, utilized in the Pretax PV-10 value at December 31, 2001 were $2.65 per MMBtu of natural gas and $19.78 per barrel of oil. The National Balancing Point, before adjustment for quality and transportation, utilized in the Pretax PV-10 value at December 31, 2001 was $3.88 per MMBtu of natural gas. Estimates of future development and production costs are based on year-end costs and assume continuation of existing economic conditions and year-end prices. We will incur significant capital in the development of our U.S. and U.K. oil and gas properties. We believe with reasonable certainty that we will be able to obtain such capital in the normal course of business. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. The standardized measure of discounted cash flows is the future net cash flows less the computed discount. Changes in Standardized Measure Changes in standardized measure of future net cash flows relating to proved natural gas and oil reserves are summarized below (in thousands):
Years Ended December 31, ----------------------------------------------------------- 2001 2000 1999 ---------------------------------- --------- -------- U.S. U.K. TOTAL U.S. U.S. --------- -------- --------- --------- -------- Beginning of year................................ $ 524,481 $ - $ 524,481 $ 128,706 $ 61,308 --------- -------- --------- --------- -------- Sales of oil and gas, net of production costs... (90,951) - (90,951) (64,381) (29,394) Net changes in income taxes..................... 193,247 (24,517) 168,730 (193,613) (27,611) Net changes in price and production costs....... (593,914) - (593,914) 416,738 9,931 Revisions of quantity estimates................. (11,220) - (11,220) (147,777) 4,176 Accretion of discount........................... 74,483 - 74,483 15,632 6,131 Development costs incurred...................... 57,119 - 57,119 18,134 15,550 Changes in estimated future development......... 22,413 - 22,413 (14,709) (15,664) Purchases of minerals-in-place.................. 64,322 64,265 128,587 300,706 105,514 Sales of minerals-in-place...................... - - - (525) - Extensions and discoveries...................... - - - 51,795 218 Changes in production rates, timing and other... (67,064) - (67,064) 13,775 (1,453) --------- -------- --------- --------- -------- (351,565) 39,748 (311,817) 395,775 67,398 --------- -------- --------- --------- -------- End of year...................................... $ 172,916 $ 39,748 $ 212,664 $ 524,481 $128,706 ========= ======== ========= ========= ========
Sales of natural gas and oil, net of natural gas and oil operating expenses, are based on historical pre-tax results. Sales of natural gas and oil properties, extensions and discoveries, purchases of minerals-in-place and the changes due to revisions in standardized variables are reported on a pre-tax discounted basis, while the accretion of discount is presented on an after-tax basis. F-24 EX-10.20 3 dex1020.txt SIXTH AMENDMENT TO CREDIT AGREEMENT EXHIBIT 10.20 SIXTH AMENDMENT TO CREDIT AGREEMENT This SIXTH AMENDMENT TO CREDIT AGREEMENT (this "Amendment") executed effective as of the 31st day of January, 2002 (the "Sixth Amendment Effective Date"), is by and among ATP OIL & GAS CORPORATION, a corporation formed under the laws of the State of Texas (the "Borrower"); each of the lenders that is a signatory hereto or which becomes a signatory hereto and to the hereinafter described Credit Agreement as provided in Section 12.06 of the Credit Agreement (individually, together with its successors and assigns, a "Lender" and collectively, the "Lenders"); and UNION BANK OF CALIFORNIA, N.A., a national banking association as agent for the Lenders (in such capacity, together with any successors in such capacity, the "Administrative Agent"). R E C I T A L S A. The Borrower, the Administrative Agent and the Lenders are parties to that certain Credit Agreement dated as of April 27, 2001 as amended and supplemented by that certain (i) First Amendment to Credit Agreement dated as of June 29, 2001, (ii) Second Amendment to Credit Agreement dated as of June 29, 2001, (iii) Third Amendment to Credit Agreement dated as of June 30, 2001, (iv) Fourth Amendment to Credit Agreement dated as of October 1, 2001, and (v) Fifth Amendment to Credit Agreement dated as of November 5, 2001 (as so amended, the "Credit Agreement"), pursuant to which the Lenders agreed to make loans to and extensions of credit on behalf of the Borrower. B. Subject to the terms and conditions of this Amendment, the Borrower, the Administrative Agent and the Lenders wish to amend the Credit Agreement and to provide for a guaranty by ATP Energy, Inc. (the "ATP Energy"). NOW THEREFORE, in consideration of the premises and the mutual covenants herein contained, the parties hereto agree as follows: SECTION 1. DEFINITIONS. As used in this Amendment, each of the terms defined in the opening paragraph and the Recitals above shall have the meanings assigned to such terms therein. Each term defined in the Credit Agreement and used herein without definition shall have the meaning assigned to such term in the Credit Agreement, unless expressly provided to the contrary. The words "hereby", "herein", "hereinafter", "hereof", "hereto" and "hereunder" when used in this Amendment shall refer to this Amendment as a whole and not to any particular Article, Section, subsection or provision of this Amendment. Section, subsection and Exhibit references herein are to such Sections, subsections and Exhibits to this Amendment unless otherwise specified. Whenever the context requires, reference herein made to the single number shall be understood to include the plural; and likewise, the plural shall be understood to include the singular. Words denoting sex shall be construed to include the masculine and feminine, when such construction is appropriate; and specific enumeration shall not exclude the general but shall be construed as cumulative. Definitions of terms defined in the singular or plural shall be equally applicable to the plural or singular, as the case may be, unless otherwise indicated. 1 SECTION 2. AMENDMENTS. The Borrower, the Administrative Agent and the Lenders agree that the Credit Agreement is hereby amended, effective as of the Sixth Amendment Effective Date, in the following particulars: (a) The following terms, which are defined in Section 1.02 of the Credit Agreement, are hereby amended in their entirety to read as follows: "Agreement" shall mean this Credit Agreement, as amended and supplemented by the First Amendment, the Second Amendment, the Third Amendment, the Fourth Amendment, the Fifth Amendment, the Sixth Amendment, and as the same may from time to time be further amended or supplemented. "Loan Documents" shall mean this Agreement, the Notes, the Fee Letter, all Letters of Credit, all Letter of Credit Agreements, the Security Instruments, the Guaranty, and any other document expressly indicating therein that such document is a "Loan Document" under this Agreement. (b) Section 1.02 of the Credit Agreement is hereby further amended and supplemented by adding the following new definitions where alphabetically appropriate, which read in their entirety as follows: "ATP Energy" means ATP Energy, Inc., a Texas corporation. "Guaranty" means the Guaranty dated as of the Sixth Amendment Effective Date made by ATP Energy in favor of the Administrative Agent for the benefit of the Credit Parties (as therein defined) as the same may be amended, supplemented or otherwise modified from time to time in the future. "Sixth Amendment" shall mean that certain Sixth Amendment to Credit Agreement dated as of January 31, 2002, by and among the Borrower, the Administrative Agent and the Lenders. "Sixth Amendment Effective Date" shall mean January 31, 2002. (c) Section 10.01(o) of the Credit Agreement is hereby amended is hereby amended in its entirety to read as follows: "(o) this Credit Agreement and the other Loan Documents shall not be amended and restated in their entirety, to the reasonable satisfaction of the Administrative Agent and the Lenders, on or before February 28, 2002; provided that neither the Administrative Agent nor any Lender shall be entitled to require any change in the economic terms of this Agreement or any Loan Document in connection with any such amendment and restatement other than those changes to the economic terms which are permitted in connection with the syndication of the credit facilities evidenced by the Credit Agreement in accordance with the Letter Agreement dated as of October 5, 2001 between Union Bank of California, N.A. and the Borrower; or". 2 (d) Section 10.01 of the Credit Agreement is hereby amended by adding a new Section 10.01(p) to read as follows: "(p) any of the provisions in the Guaranty shall for any reason cease to be in full force and effect, valid and binding on ATP Energy, or ATP Energy shall so state in writing." SECTION 3. REPRESENTATIONS AND WARRANTIES. The Borrower represents and warrants to the Administrative Agent and the Lenders that: (a) Except for such which are made only as of a prior date, the representations and warranties set forth in the Credit Agreement and in the other Loan Documents are true and correct in all material respects as of the Sixth Amendment Effective Date as if made on and as of such date. (b) The execution, delivery and performance of this Amendment are within the corporate power and authority of the Borrower and have been duly authorized by appropriate corporate proceedings, and the execution, delivery and performance of the Guaranty dated as of the date hereof by ATP Energy (the "Guaranty") are within the corporate power and authority of ATP Energy and have been duly authorized by appropriate corporate proceedings. (c) This Amendment constitutes a legal, valid, and binding obligation of the Borrower enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting the rights of creditors generally and general principles of equity. (d) No consent, order, authorization, or approval or other action by, and no notice to or filing with, any Governmental Authority or any other Person is required for the due execution, delivery, and performance by the Borrower of this Amendment or the other Loan Documents to which the Borrower is a party or by ATP Energy of the Guaranty or the other Loan Documents to which it is a party or the consummation of the transactions contemplated thereby. SECTION 4. CONDITIONS TO EFFECTIVENESS: This Amendment shall become effective and enforceable against the parties hereto and the Credit Agreement shall be amended as provided herein upon the occurrence of the following conditions precedent on or before the Sixth Amendment Effective Date: (a) Loan Documents. The Administrative Agent shall have received multiple original counterparts, as requested by the Administrative Agent, of (i) this Amendment duly and validly executed and delivered by duly authorized officers of the Borrower, the Administrative Agent and each Lender and (ii) the Guaranty duly and validly executed and delivered by a duly authorized officer of ATP Energy. (b) Corporate Proceedings of Loan Parties. The Administrative Agent shall have received multiple copies, as requested by the Administrative Agent, of the resolutions, in form and substance reasonably satisfactory to the Administrative Agent, of the Board of Directors of ATP Energy, authorizing the execution, delivery and performance of the Guaranty and the 3 transaction contemplated thereby, each such copy being attached to an original certificate of the Secretary or an Assistant Secretary of ATP Energy, dated the Sixth Amendment Effective Date, certifying (i) that the resolutions attached thereto are true, correct and complete copies of resolutions duly adopted by written consent or at a meeting of the Board of Directors of ATP Energy, (ii) that such resolutions constitute all resolutions adopted with respect to the transactions contemplated hereby, (iii) that such resolutions have not been amended, modified, revoked or rescinded as of the Sixth Amendment Effective Date, (iv) that the articles of incorporation and bylaws attached thereto are the true, correct and complete copies of such articles and bylaws and that such articles and bylaws have not been amended, supplemented or otherwise modified except pursuant to any amendments attached thereto, and (v) as to the incumbency and specimen signature of the officer of ATP Energy executing any Loan Documents (including, without limitation, the Guaranty). (c) No Default. No Default or Event of Default shall have occurred and be continuing as of the Sixth Amendment Effective Date. (d) Material Adverse Effect. No event shall have occurred or circumstance shall have arisen since September 30, 2001, which, in the reasonable opinion of the Lenders, could have a Material Adverse Effect. (e) Legal Fees of Administrative Agent's Counsel. The Borrower shall have paid all fees and expenses of the Administrative Agent's outside legal counsel and other consultants pursuant to all invoices presented for payment on or prior to the Sixth Amendment Effective Date. (f) Other Instruments or Documents. The Administrative Agent or any Lender or counsel to the Administrative Agent shall have received such other instruments or documents as any of them may reasonably request. SECTION 5. MISCELLANEOUS. (a) Effect on Loan Documents. Each of the Borrower, the Administrative Agent and the Lenders does hereby adopt, ratify, and confirm the Credit Agreement, as amended hereby, and acknowledges and agrees that the Credit Agreement, as amended hereby, is and remains in full force and effect. Nothing herein shall act as a waiver of any of the Administrative Agent's or Lender's rights under the Loan Documents, as amended, including the waiver of any Default or Event of Default, however denominated. From and after the Sixth Amendment Effective Date, all references to the Credit Agreement and the Loan Documents shall mean such Credit Agreement and such Loan Documents as amended by this Amendment. This Amendment is a Loan Document for the purposes of the provisions of the other Loan Documents. Without limiting the foregoing, any breach of representations, warranties, and covenants under this Amendment shall be a Default or Event of Default, as applicable, under the Credit Agreement. (b) Counterparts. This Amendment may be signed in any number of counterparts, each of which shall be an original and all of which, taken together, constitute a single instrument. 4 This Amendment may be executed by facsimile signature and all such signatures shall be effective as originals. (c) Successors and Assigns. This Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted pursuant to the Credit Agreement. (d) Entire Agreement. This Amendment constitutes the entire agreement among the parties hereto with respect to the subject hereof. All prior understandings, statements and agreements, whether written or oral, relating to the subject hereof are superseded by this Amendment. (e) Invalidity. In the event that any one or more of the provisions contained in this Amendment shall for any reason be held invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Amendment. (f) Titles of Articles, Sections and Subsections. All titles or headings to Articles, Sections, subsections or other divisions of this Amendment or the exhibits hereto, if any, are only for the convenience of the parties and shall not be construed to have any effect or meaning with respect to the other content of such Articles, Sections, subsections, other divisions or exhibits, such other content being controlling as the agreement among the parties hereto. (g) Governing Law. This Amendment shall be deemed to be a contract made under and shall be governed by and construed in accordance with the internal laws of the State of Texas. THIS AMENDMENT, THE CREDIT AGREEMENT, AS AMENDED HEREBY, THE NOTES, AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. [SIGNATURES BEGIN ON NEXT PAGE] 5 IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorized officers as of the Sixth Amendment Effective Date. BORROWER: ATP OIL & GAS CORPORATION By: /s/ T. Paul Bulmahn ------------------- T. Paul Bulmahn President 6 LENDER AND ADMINISTRATIVE UNION BANK OF CALIFORNIA, N.A. AGENT as Lender and as Administrative Agent By: /s/ Damien Meiburger ---------------------------------------- Name: Damien Meiburger Title: Senior Vice President By: /s/ Ali Ahmed ---------------------------------------- Name: Ali Ahmed Title: Vice President 7 EX-10.21 4 dex1021.txt SEVENTH AMENDMENT TO CREDIT AGREEMENT EXHIBIT 10.21 SEVENTH AMENDMENT TO CREDIT AGREEMENT This SEVENTH AMENDMENT TO CREDIT AGREEMENT (this "Amendment") executed effective as of the 28th day of February, 2002 (the "Seventh Amendment Effective Date"), is by and among ATP OIL & GAS CORPORATION, a corporation formed under the laws of the State of Texas (the "Borrower"); each of the lenders that is a signatory hereto or which becomes a signatory hereto and to the hereinafter described Credit Agreement as provided in Section 12.06 of the Credit Agreement (individually, together with its successors and assigns, a "Lender" and collectively, the "Lenders"); and UNION BANK OF CALIFORNIA, N.A., a national banking association as agent for the Lenders (in such capacity, together with any successors in such capacity, the "Administrative Agent"). R E C I T A L S A. The Borrower, the Administrative Agent and the Lenders are parties to that certain Credit Agreement dated as of April 27, 2001 as amended and supplemented by that certain (i) First Amendment to Credit Agreement dated as of June 29, 2001, (ii) Second Amendment to Credit Agreement dated as of June 29, 2001, (iii) Third Amendment to Credit Agreement dated as of June 30, 2001, (iv) Fourth Amendment to Credit Agreement dated as of October 1, 2001, (v) Fifth Amendment to Credit Agreement dated as of November 5, 2001, and (vi) Sixth Amendment to Credit Agreement dated as of January 31, 2002 (as so amended, the "Credit Agreement"), pursuant to which the Lenders agreed to make loans to and extensions of credit on behalf of the Borrower. B. Subject to the terms and conditions of this Amendment, the Borrower, the Administrative Agent and the Lenders wish to amend the Credit Agreement as set forth herein. NOW THEREFORE, in consideration of the premises and the mutual covenants herein contained, the parties hereto agree as follows: SECTION 1. DEFINITIONS. As used in this Amendment, each of the terms defined in the opening paragraph and the Recitals above shall have the meanings assigned to such terms therein. Each term defined in the Credit Agreement and used herein without definition shall have the meaning assigned to such term in the Credit Agreement, unless expressly provided to the contrary. The words "hereby", "herein", "hereinafter", "hereof", "hereto" and "hereunder" when used in this Amendment shall refer to this Amendment as a whole and not to any particular Article, Section, subsection or provision of this Amendment. SECTION 2. AMENDMENTS. The Borrower, the Administrative Agent and the Lenders agree that the Credit Agreement is hereby amended, effective as of the Seventh Amendment Effective Date, in the following particulars: (a) The following term, which is defined in Section 1.02 of the Credit Agreement, is hereby amended in its entirety to read as follows: 1 "Agreement" shall mean this Credit Agreement, as amended and supplemented by the First Amendment, the Second Amendment, the Third Amendment, the Fourth Amendment, the Fifth Amendment, the Sixth Amendment, the Seventh Amendment, and as the same may from time to time be further amended or supplemented. (b) Section 1.02 of the Credit Agreement is hereby further amended and supplemented by adding the following new definition where alphabetically appropriate, which read in its entirety as follows: "Seventh Amendment" shall mean that certain Seventh Amendment to Credit Agreement dated as of February 28, 2002, by and among the Borrower, the Administrative Agent and the Lenders. (c) Section 10.01(o) of the Credit Agreement is hereby amended by replacing the reference to "February 28, 2002" stated therein with "March 31, 2002". SECTION 3. REPRESENTATIONS AND WARRANTIES. The Borrower represents and warrants to the Administrative Agent and the Lenders that: (a) Except for such which are made only as of a prior date, the representations and warranties set forth in the Credit Agreement and in the other Loan Documents are true and correct in all material respects as of the Seventh Amendment Effective Date as if made on and as of such date; (b) the execution, delivery and performance of this Amendment are within the corporate power and authority of the Borrower and have been duly authorized by appropriate corporate proceedings; (c) this Amendment constitutes a legal, valid, and binding obligation of the Borrower enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting the rights of creditors generally and general principles of equity; and (d) no consent, order, authorization, or approval or other action by, and no notice to or filing with, any Governmental Authority or any other Person is required for the due execution, delivery, and performance by the Borrower of this Amendment or the consummation of the transactions contemplated thereby. SECTION 4. CONDITIONS TO EFFECTIVENESS: This Amendment shall become effective and enforceable against the parties hereto and the Credit Agreement shall be amended as provided herein upon the occurrence of the following conditions precedent on or before the Seventh Amendment Effective Date: (a) the Administrative Agent shall have received multiple original counterparts, as requested by the Administrative Agent, of this Amendment duly and validly executed and delivered by duly authorized officers of the Borrower, the Administrative Agent and each Lender; (b) no Default or Event of Default shall have occurred and be continuing as of the Seventh Amendment Effective Date and no event shall have occurred or circumstance shall have arisen since September 30, 2001, which, in the reasonable opinion of the Lenders, could have a Material Adverse Effect; (c) the Borrower shall have paid all fees and expenses of the Administrative Agent's outside legal counsel and other consultants pursuant to all invoices presented for payment on or prior to the Seventh Amendment Effective Date, and (d) the Administrative Agent or any Lender or counsel to the Administrative Agent shall have received such other instruments or documents as any of them may reasonably request. 2 SECTION 5. EFFECT ON LOAN DOCUMENTS. Each of the Borrower, the Administrative Agent and the Lenders does hereby adopt, ratify, and confirm the Credit Agreement, as amended hereby, and acknowledges and agrees that the Credit Agreement, as amended hereby, is and remains in full force and effect. Nothing herein shall act as a waiver of any of the Administrative Agent's or Lender's rights under the Loan Documents, as amended, including the waiver of any Default or Event of Default, however denominated. From and after the Seventh Amendment Effective Date, all references to the Credit Agreement and the Loan Documents shall mean such Credit Agreement and such Loan Documents as amended by this Amendment. This Amendment is a Loan Document for the purposes of the provisions of the other Loan Documents. Without limiting the foregoing, any breach of representations, warranties, and covenants under this Amendment shall be a Default or Event of Default, as applicable, under the Credit Agreement. SECTION 6. COUNTERPARTS; ASSIGNS. This Amendment (a) may be signed in any number of counterparts, each of which shall be an original and all of which, taken together, constitute a single instrument; (b) may be executed by facsimile signature and all such signatures shall be effective as originals; and (c) shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted pursuant to the Credit Agreement. SECTION 7. INVALIDITY. In the event that any one or more of the provisions contained in this Amendment shall for any reason be held invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Amendment. SECTION 8. TITLES OF ARTICLES, SECTIONS AND SUBSECTIONS. All titles or headings to Articles, Sections, subsections or other divisions of this Amendment or the exhibits hereto, if any, are only for the convenience of the parties and shall not be construed to have any effect or meaning with respect to the other content of such Articles, Sections, subsections, other divisions or exhibits, such other content being controlling as the agreement among the parties hereto. SECTION 9. GOVERNING LAW. This Amendment shall be deemed to be a contract made under and shall be governed by and construed in accordance with the internal laws of the State of Texas. THIS AMENDMENT, THE CREDIT AGREEMENT, AS AMENDED HEREBY, THE NOTES, AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. [SIGNATURES BEGIN ON NEXT PAGE] 3 IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorized officers as of the Seventh Amendment Effective Date. BORROWER: ATP OIL & GAS CORPORATION By: /s/ T. Paul Bulmahn -------------------------------------------- T. Paul Bulmahn President LENDER AND ADMINISTRATIVE UNION BANK OF CALIFORNIA, N.A. AGENT as Lender and as Administrative Agent By: /s/ Damien Meiburger -------------------------------------------- Name: Damien Meiburger Title: Senior Vice President By: /s/ Ali Ahmed -------------------------------------------- Name: Ali Ahmed Title: Vice President 4 EX-10.22 5 dex1022.txt EIGTH AMENDMENT TO CREDIT AGREEMENT EXHIBIT 10.22 EIGHTH AMENDMENT TO CREDIT AGREEMENT This EIGHTH AMENDMENT TO CREDIT AGREEMENT (this "Amendment") executed effective as of the 27/th/ day of March, 2002 (the "Eighth Amendment Effective Date"), is by and among ATP OIL & GAS CORPORATION, a corporation formed under the laws of the State of Texas (the "Borrower"); each of the lenders that is a signatory hereto or which becomes a signatory hereto and to the hereinafter described Credit Agreement as provided in Section 12.06 of the Credit Agreement (individually, together with its successors and assigns, a "Lender" and collectively, the "Lenders"); and UNION BANK OF CALIFORNIA, N.A., a national banking association as agent for the Lenders (in such capacity, together with any successors in such capacity, the "Administrative Agent"). R E C I T A L S --------------- A. The Borrower, the Administrative Agent and the Lenders are parties to that certain Credit Agreement dated as of April 27, 2001 as amended and supplemented by that certain (i) First Amendment to Credit Agreement dated as of June 29, 2001, (ii) Second Amendment to Credit Agreement dated as of June 29, 2001, (iii) Third Amendment to Credit Agreement dated as of June 30, 2001, (iv) Fourth Amendment to Credit Agreement dated as of October 1, 2001, (v) Fifth Amendment to Credit Agreement dated as of November 5, 2001, (vi) Sixth Amendment to Credit Agreement dated as of January 31, 2002, and (vii) Seventh Amendment dated as of February 28, 2002 (as so amended, the "Credit Agreement"), pursuant to which the Lenders agreed to make loans to and extensions of credit on behalf of the Borrower. B. Subject to the terms and conditions of this Amendment, the Borrower, the Administrative Agent and the Lenders wish to amend the Credit Agreement as set forth herein. NOW THEREFORE, in consideration of the premises and the mutual covenants herein contained, the parties hereto agree as follows: Section 1. Definitions. As used in this Amendment, each of the terms ----------- defined in the opening paragraph and the Recitals above shall have the meanings assigned to such terms therein. Each term defined in the Credit Agreement and used herein without definition shall have the meaning assigned to such term in the Credit Agreement, unless expressly provided to the contrary. The words "hereby", "herein", "hereinafter", "hereof", "hereto" and "hereunder" when used in this Amendment shall refer to this Amendment as a whole and not to any particular Article, Section, subsection or provision of this Amendment. Section 2. Amendments. The Borrower, the Administrative Agent and the ---------- Lenders agree that the Credit Agreement is hereby amended, effective as of the Eighth Amendment Effective Date, in the following particulars: (a) The following term, which is defined in Section 1.02 of the Credit Agreement, is hereby amended in its entirety to read as follows: -1- "Agreement" shall mean this Credit Agreement, as amended and --------- supplemented by the First Amendment, the Second Amendment, the Third Amendment, the Fourth Amendment, the Fifth Amendment, the Sixth Amendment, the Seventh Amendment, Eighth Amendment, and as the same may from time to time be further amended or supplemented. (b) Section 1.02 of the Credit Agreement is hereby further amended and supplemented by adding the following new definition where alphabetically appropriate, which read in its entirety as follows: "Eighth Amendment" shall mean that certain Eighth Amendment to Credit ---------------- Agreement dated as of March 27, 2002, by and among the Borrower, the Administrative Agent and the Lenders. (c) Section 10.01(o) of the Credit Agreement is hereby amended by replacing the reference to "March 31, 2002" stated therein with "May 15, 2002". Section 3. Consents and Agreements Regarding Working Capital. The ------------------------------------------------- Borrower, the Administrative Agent and the Lenders hereby agree that the requirements of Section 9.13 shall not apply to the calendar months ending December 31, 2001, January 31, 2002, February 28, 2002, March 31, 2002, April 30, 2002 and May 31, 2002 and that such Section 9.13 shall first be tested as of the calendar month ending June 30, 2002 and shall continue for each calendar month thereafter in accordance with such Section. Additionally, the Borrower, the Administrative Agent and the Lenders agree that it shall constitute an Event of Default under the Credit Agreement if the Borrower's Working Capital Deficit shall exceed either (a) as of December 31, 2001, $10,000,000 or (b) as each of March 31, 2002, April 30, 2002, and May 31, 2002, $5,000,000. For purposes of the preceding sentence, "Working Capital Deficit" means the Borrower's consolidated current liabilities (excluding current maturities under the Notes) as of the relevant date minus its consolidated current assets (including any unused amounts under the Borrowing Base) as of such date. Section 4. Amendment Fee. In consideration of the Administrative Agent ------------- and the Lenders executing this Amendment, the Borrower hereby agrees to pay to the Administrative Agent for the account of the Lenders an amendment fee ("Amendment Fee") in an aggregate amount equal to $250,000. The entire Amendment Fee is deemed earned upon the execution and delivery by the Administrative Agent and the Lenders of this Amendment and shall be non-refundable. The Amendment Fee shall be paid in installments with $50,000 being due and payable concurrent with the execution of this Agreement and the $100,000 being due and payable on April 29, 2002 and the remaining $100,000 being due and payable on May 31, 2002. This Amendment shall not be effective unless the initial $50,000 is paid as per Section 6(c)(i) below. Additionally, failure to pay either the $100,000 on or before April 29, 2002 or the $100,000 installment on or before May 31, 2002 shall constitute an Event of Default under the Credit Agreement. Section 5. Representations and Warranties. The Borrower represents and ------------------------------ warrants to the Administrative Agent and the Lenders that: (a) after giving effect to this Amendment, except for such which are made only as of a prior date, the representations and warranties set forth in the Credit Agreement and in the other Loan Documents are true and correct in all -2- material respects as of the Eighth Amendment Effective Date as if made on and as of such date; (b) the execution, delivery and performance of this Amendment are within the corporate power and authority of the Borrower and have been duly authorized by appropriate corporate proceedings; (c) this Amendment constitutes a legal, valid, and binding obligation of the Borrower enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting the rights of creditors generally and general principles of equity; and (d) no consent, order, authorization, or approval or other action by, and no notice to or filing with, any Governmental Authority or any other Person is required for the due execution, delivery, and performance by the Borrower of this Amendment or the consummation of the transactions contemplated thereby. Section 6. Conditions to Effectiveness: This Amendment shall become --------------------------- effective and enforceable against the parties hereto and the Credit Agreement shall be amended as provided herein upon the occurrence of the following conditions precedent on or before the Eighth Amendment Effective Date: (a) the Administrative Agent shall have received multiple original counterparts, as requested by the Administrative Agent, of this Amendment duly and validly executed and delivered by duly authorized officers of the Borrower, the Administrative Agent and each Lender; (b) no Default or Event of Default shall have occurred and be continuing as of the Eighth Amendment Effective Date and no event shall have occurred or circumstance shall have arisen since September 30, 2001, which, in the reasonable opinion of the Lenders, could have a Material Adverse Effect; (c) the Borrower shall have paid (i) to the Lenders $50,000 of the Amendment Fee described above, and (ii) all fees and expenses of the Administrative Agent's outside legal counsel and other consultants pursuant to all invoices presented for payment on or prior to the Eighth Amendment Effective Date, and (d) the Administrative Agent or any Lender or counsel to the Administrative Agent shall have received such other instruments or documents as any of them may reasonably request. Section 7. Effect on Loan Documents. Each of the Borrower, the ------------------------ Administrative Agent and the Lenders does hereby adopt, ratify, and confirm the Credit Agreement, as amended hereby, and acknowledges and agrees that the Credit Agreement, as amended hereby, is and remains in full force and effect. Nothing herein shall act as a waiver of any of the Administrative Agent's or Lender's rights under the Loan Documents, as amended, including the waiver of any Default or Event of Default, however denominated. From and after the Eighth Amendment Effective Date, all references to the Credit Agreement and the Loan Documents shall mean such Credit Agreement and such Loan Documents as amended by this Amendment. This Amendment is a Loan Document for the purposes of the provisions of the other Loan Documents. Without limiting the foregoing, any breach of representations, warranties, and covenants under this Amendment shall be a Default or Event of Default, as applicable, under the Credit Agreement. -3- Section 8. Counterparts; Assigns. This Amendment (a) may be signed in --------------------- any number of counterparts, each of which shall be an original and all of which, taken together, constitute a single instrument; (b) may be executed by facsimile signature and all such signatures shall be effective as originals; and (c) shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted pursuant to the Credit Agreement. Section 9. Invalidity. In the event that any one or more of the ---------- provisions contained in this Amendment shall for any reason be held invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Amendment. Section 10. Titles of Articles, Sections and Subsections. All titles -------------------------------------------- or headings to Articles, Sections, subsections or other divisions of this Amendment or the exhibits hereto, if any, are only for the convenience of the parties and shall not be construed to have any effect or meaning with respect to the other content of such Articles, Sections, subsections, other divisions or exhibits, such other content being controlling as the agreement among the parties hereto. Section 11. Governing Law. This Amendment shall be deemed to be a ------------- contract made under and shall be governed by and construed in accordance with the internal laws of the State of Texas. THIS AMENDMENT, THE CREDIT AGREEMENT, AS AMENDED HEREBY, THE NOTES, AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. [SIGNATURES BEGIN ON NEXT PAGE] -4- IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorized officers as of the Eighth Amendment Effective Date. BORROWER: ATP OIL & GAS CORPORATION By: /s/ T. Paul Bulmahn ----------------------------- T. Paul Bulmahn President LENDER AND ADMINISTRATIVE UNION BANK OF CALIFORNIA, N.A. AGENT as Lender and as Administrative Agent By: /s/ Ali Ahmed ----------------------------- Name: Ali Ahmed ---------------------------- Title: Vice President --------------------------- By: Dustin Gaspari ------------------------------ Name: Dustin Gaspari ---------------------------- Title: Vice President --------------------------- -5- EX-10.23 6 dex1023.txt FIRST AMENDMENT TO CREDIT AGREEMENT EXHIBIT 10.23 FIRST AMENDMENT TO NOTE PURCHASE AGREEMENT DATED JUNE 29, 2001 BY AND BETWEEN ATP OIL & GAS CORPORATION AND AQUILA ENERGY CAPITAL CORPORATION This First Amendment ("First Amendment") to the Note Purchase Agreement dated June 29, 2001, by and between ATP OIL & GAS CORPORATION, a Texas corporation (the "Issuer") and AQUILA ENERGY CAPITAL CORPORATION, a Delaware corporation (the "Purchaser"), is entered into on this 26th day of March 2002. WITNESSETH: A. Issuer and Purchaser heretofore entered into a Note Purchase Agreement dated June 29, 2001 (the "Note Purchase Agreement"). B. Issuer and Purchaser hereby desire to amend the Note Purchase Agreement, subject to the terms and conditions contained herein. NOW, THEREFORE, in consideration of the mutual promises herein contained, and for other good and valuable consideration, the receipt and sufficiency of which are acknowledged by Issuer and Purchaser, and each intending to be legally bound hereby, Issuer and Purchaser agree as follows: I. Specific Amendments to Note Purchase Agreement ---------------------------------------------- Article I of the Note Purchase Agreement is hereby amended by adding --------- the following definition thereto: "First Amendment" means that certain First Amendment to the --------------- Note Purchase Agreement executed by Purchaser and Issuer effective on March 27, 2002. Section 7.1(v) of the Note Purchase Agreement is hereby amended by ------------- replacing the text of that Section in its entirety with: As of the end of each fiscal quarter beginning with the quarter ending June 30, 2002, Issuer shall have a positive working capital, as defined by GAAP, and no time during any fiscal quarter after March 31, 2002, shall the Issuer's working capital be less than a negative $5 million; provided that the working capital calculation shall include unused portions of the credit availability under the Senior Debt and exclude, for future periods, mark to market amounts under any Swap Agreements and current maturities of the Senior Debt. Any amount relating to litigation, either an asset or a liability of the Issuer, will be considered current at such time as either: (a) a judgement entered by a court of competent jurisdiction awarding such amount to the prevailing party has become final (a "Final Judgment"), or (b) Issuer and the other party(ies) to such litigation have entered into a binding agreement providing for the payment of such amount to or by Issuer; provided that if any Final Judgment is appealed by either party and execution of such Final Judgment is stayed by appellant's posting of a supersedeas bond, then so long as execution of such Final Judgment is stayed the amount of such judgement shall not be deemed a current asset or current liability. Notwithstanding the foregoing, the Issuer may have a negative working capital not in excess of $10 million at December 31, 2001 and $5 million at March 31, 2002 calculated as above. II. Reaffirmation of Representations and Warranties. To induce ----------------------------------------------- Purchaser to enter into this First Amendment, Issuer hereby reaffirms as of the date hereof its representations and warranties contained in Article IV of the Note Purchase Agreement and in all other documents executed pursuant thereto, and additionally represents and warrants as follows: A. The execution and delivery of this First Amendment and the performance by Issuer of its obligations under this First Amendment are within Issuer's power, have been duly authorized by all necessary corporate action, have received all necessary governmental approval (if any shall be required), and do not and will not contravene or conflict with any provision of law or of the Articles of Incorporation or Bylaws of Issuer or of any agreement binding upon Issuer. B. The Note Purchase Agreement as amended by this First Amendment, represents the legal, valid and binding obligations of Issuer, enforceable against Issuer in accordance with its terms, subject as to enforcement only to bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors' rights generally. C. No Event of Default has occurred and is continuing as of the date hereof. III. Defined Terms. Except as amended hereby, terms used herein ------------- that are defined in the Note Purchase Agreement shall have the same meanings herein. IV. Reaffirmation of Loan Agreement. This First Amendment shall be ------------------------------- deemed to be an amendment to the Note Purchase Agreement, and the Note Purchase Agreement, as further amended hereby, is hereby ratified, approved and confirmed in each and every respect. All references to the Note Purchase Agreement herein and in any other document, instrument, agreement or writing shall hereafter be deemed to refer to the Note Purchase Agreement as amended hereby. V. Entire Agreement. The Note Purchase Agreement, as hereby ---------------- amended, embodies the entire agreement between Issuer and Purchaser and supersedes all prior proposals, agreements and understandings relating to the subject matter hereof. Issuer certifies that it is relying on no representation, warranty, covenant or agreement except for those set forth in the Note Purchase Agreement as hereby further amended and the other documents previously executed or executed of even date herewith. 2 VI. Governing Law. THIS FIRST AMENDMENT SHALL BE GOVERNED BY AND ------------- CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS AND THE APPLICABLE LAWS OF THE UNITED STATES OF AMERICA. This First Amendment has been entered into in Harris County, Texas and shall be performable for all purposes in Harris County, Texas. Courts within the State of Texas shall have jurisdiction over any and all disputes between Issuer and Purchaser, whether in law or equity, including, but not limited to, any and all disputes arising out of or relating to this First Amendment or any other Transaction Document. VII. Severability. Whenever possible, each provision of this First ------------ Amendment shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this First Amendment shall be prohibited by or invalid under applicable law, such provision shall be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this First Amendment. VIII. Section Captions. Section captions used in this First ---------------- Amendment are for convenience of reference only, and shall not affect the construction of this First Amendment. IX. Successors and Assigns. This First Amendment shall be binding ---------------------- upon Issuer and Purchaser and their respective successors and assigns, and shall inure to the benefit of Issuer and Purchaser, and the respective successors and assigns of Purchaser. X. Non-Application of Chapter 346 of Texas Finance Code. In no ---------------------------------------------------- event shall Chapter 346 of the Texas Finance Code (which regulates certain revolving loan accounts and revolving tri-party accounts) apply to this Note Purchase Agreement as hereby further amended or any other Transaction Documents or the transactions contemplated hereby. XI. NOTICE. THIS FIRST AMENDMENT, TOGETHER WITH THE NOTE PURCHASE ------ AGREEMENT AND THE OTHER TRANSACTION DOCUMENTS, REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. [Signature page follows.] 3 IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to be duly executed as of the day and year first above written. PURCHASER ISSUER AQUILA ENERGY CAPITAL ATP OIL & GAS CORPORATION, CORPORATION, a Delaware corporation a Texas corporation By: /s/ Kenneth F. Wyatt By: /s/ T. Paul Bulmahn ------------------------------- ------------------------------ Kenneth F. Wyatt T. Paul Bulmahn Vice President President 4 EX-23.1 7 dex231.txt INDEPENDENT AUDITORS CONSENT EXHIBIT 23.1 INDEPENDENT AUDITORS' CONSENT The Board of Directors ATP Oil & Gas Corporation: We consent to the incorporation by reference in the registration statement (No. 333-60762) on Form S-8 of ATP Oil & Gas Corporation and subsidiaries of our report dated March 29, 2002, with respect to the consolidated balance sheets of ATP Oil & Gas Corporation and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, shareholders' equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2001, which report appears in the December 31, 2001, annual report on Form 10-K of ATP Oil & Gas Corporation and subsidiaries. Our report refers to a change in accounting for derivative financial instruments, effective January 1, 2001. KPMG LLP Houston, Texas April 1, 2002 EX-23.2 8 dex232.txt CONSENT OF INDEPENDENT PETROLEUM ENGINEERS - RYDER EXHIBIT 23.2 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS As independent petroleum engineers, we hereby consent to (i) the reference in this Form 10-K of ATP Oil & Gas Corporation (the "Company"), as well as in the Notes to the Consolidated Financial Statements included in such Form 10-K, to the report prepared by Ryder Scott Company, L.P. entitled "ATP Oil & Gas Corporation, Estimated Future Reserves and Income Attributable to Certain Leasehold and Royalty Interests, SEC Case, as of December 31, 2001", dated February 21, 2002, relating to the estimated quantities of future proved reserves and income attributable to the interests of the Company, and (ii) the incorporation by reference to the report prepared by Ryder Scott Company, L.P. into ATP Oil & Gas Corporation's previously filed Registration Statements on Form S-1 (No. 333-46034) and on Form S-8 (No. 333-60762). RYDER SCOTT COMPANY, L.P. Houston, Texas April 1, 2002 EX-23.3 9 dex233.txt CONSENT OF INDEPENDENT PETROLEUM ENGINEERS - TROY EXHIBIT 23.3 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS We hereby consent to the use of the name Troy-Ikoda Limited and of references to Troy-Ikoda Limited and to the inclusion of and references to our report, or information contained therein, dated 11th March 2002, prepared for ATP Oil & Gas (UK) Limited in the ATP Oil & Gas Corporation annual report on Form 10-K for the year ended 31st December 2001, and the incorporation by reference to the report prepared by Troy-Ikoda Limited into ATP Oil & Gas Corporation's previously filed Registration Statements on Form S-1 (No. 333-46034) and on Form S-8 (No. 333- 60762). Troy-Ikoda Limited 1st April 2002 -----END PRIVACY-ENHANCED MESSAGE-----