ATP Oil & Gas 10-K 2005
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
AMENDMENT NO. 2
For the Fiscal Year Ended December 31, 2004
Commission file number: 000-32261
ATP Oil & Gas Corporation
(Exact name of registrant as specified in its charter)
4600 Post Oak Place, Suite 200
Houston, Texas 77027
(Address of principal executive offices) (Zip Code)
(Registrants telephone number, including area code): (713) 622-3311
Securities Registered Pursuant to Section 12 (b) of the Act:
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 Registrants 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. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.): Yes ¨ No x
Indicate by check mark whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes x No ¨
The aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2004 (the last business day of the Registrants most recently completed second fiscal quarter) was approximately $94,935,548. The number of shares of the Registrants common stock outstanding as of March 25, 2005 was 28,966,358.
This Amendment No. 2 to the Annual Report on Form 10-K of ATP Oil & Gas Corporation (the Company) for the fiscal year ended December 31, 2004 is the result of a staff review by the Division of Corporation Finance. The Company is filing with this amendment certifications that contain the required language referring to the certifying officers responsibility for establishing and maintaining internal controls over financial reporting for the Company. This form of certification became required once the Company filed Amendment No. 1 on April 29, 2005, which contained managements internal control report and the related attestation report of its independent accountants. These paragraphs were inadvertently not included. Additionally, the Staff requested expansion of the Companys description of its success converting proved undeveloped reserves into proved producing reserves.
The Company is filing this Amendment No. 2 to Annual Report on Form 10-K (the Amendment) to provide corrected certifications comprising Exhibits 31.1 and 31.2 of the Original Report, and to amend Item 1. Business and Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations to clarify the discussion of its success converting proved undeveloped reserves into proved producing reserves. Items 1 and 7 are presented herein in their entirety as amended, in accordance with Rule 12b-15 of the Securities Exchange Act of 1934. No other information in the original report is being amended by the Amendment and the Company has not updated disclosures in this Amendment to reflect any event subsequent to the Companys filing of the original report.
Item 1. Business
ATP Oil & Gas Corporation was incorporated in Texas in 1991. We are engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the North Sea. We primarily focus our efforts on oil and natural gas properties where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas. Many of these properties contain proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies. 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, 2004, we had estimated net proved reserves of 275.2 Bcfe, of which approximately 180.7 Bcfe (66%) was in the Gulf of Mexico and 94.5 Bcfe (34%) was in the North Sea. Year-end reserves were comprised of 205.2 Bcf of natural gas and 11.7 MMBbls of oil. The majority of our oil reserves are located in the Gulf of Mexico and approximately 54% of our natural gas reserves are located in the Gulf of Mexico with the balance located in the North Sea. The estimated pre-tax PV-10 of our proved reserves at December 31, 2004 was $732.8 million. See Item 2. Properties Oil and Natural Gas Reserves for a reconciliation to after-tax PV-10.
At December 31, 2004, we had leasehold and other interests in 52 offshore blocks, 26 platforms and 68 wells, including five subsea wells, in the Gulf of Mexico. We operate 56 of these 68 wells, including all of the subsea wells, and 85% of our offshore platforms. We also had interests in ten blocks and one company-operated subsea well in the North Sea. Our average working interest in our properties at
December 31, 2004 was approximately 79%. For more information regarding our operations and assets in the Gulf of Mexico and North Sea, see Note 14, Segment Information, to the Notes to Consolidated Financial Statements.
Our Business Strategy
Our business strategy is to enhance shareholder value primarily through the acquisition, development and production of properties that we believe contain oil and natural gas in commercial quantities in areas that have:
We believe our strategy significantly reduces the risks associated with traditional oil and natural gas exploration. Our focus is to acquire properties that have been explored by others and found to contain proved reserves. Occasionally we will acquire properties where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. From the inception of operations through March 25, 2005, we have successfully brought to production 37 out of 38 projects from previously undeveloped reservoirs, a 97% success ratio.
Our reserves estimates are prepared by independent reservoir engineers, who have had similar results in estimating the reserve quantities for those projects. Reserve estimates are inherently imprecise (see discussion regarding uncertainty of reserve estimates in Risk Factors). Our current post-drill ultimate reserves compared to the pre-drill PUD reserves for each of these reservoirs has a median success rate of 77% and has varied from zero percent of the original estimate on the single unsuccessful development to 560% of the original estimate on one of the 37 successful developments (at Brazos 544). We are unable to predict how our future results will compare to our current reserve estimates. While the results for the individual reservoirs has varied, we have accomplished an overall 98% success rate when comparing the total pre-drill PUD reserves to the current post-drill reserve estimates.
We focus on acquiring properties that contain proved undeveloped reserves that have become non-core or non-strategic to their original owners for various reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects with greater reserve potential. Some projects provide lower economic returns to a larger company due to its cost structure. Also, due to timing or budget constraints, a company may be unable or unwilling to develop a property before the expiration of the lease and desire to sell the property before it forfeits its lease rights. Because of our cost structure, expertise in our areas of focus and our ability to develop projects efficiently, these properties may be economically attractive to us.
By focusing on properties that are not strategic to other companies and properties that are primarily proved but as yet undeveloped, we are able to minimize up front acquisition costs and concentrate available capital on the development phase of these properties. Since our inception in 1991 through December 31, 2004, we have added 483.1 Bcfe of proved oil and natural gas reserves through acquisitions at a total cost of $78.7 million or $0.16 per Mcfe. Development costs for this same period were approximately $453.1 million.
We focus on developing projects in the shortest time possible between initial investment and first revenue generated in order to maximize our rate of return. Since we operate a significant number of the properties in which we acquire a working interest, we are able to significantly influence the time of a projects development. We typically initiate new development projects by simultaneously obtaining the various required components such as the pipeline and the production platform or subsea well completion equipment. We believe this strategy, combined with our ability to evaluate and implement a projects requirements, allows us to efficiently complete the development project and commence production quickly.
Marketing and Delivery Commitments
We sell our oil and natural gas production under price sensitive or market price contracts. Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. The price received by us for our oil and natural gas production can fluctuate widely. Changes in the prices of oil and natural gas will affect the carrying value of our proved reserves as well as our revenues, profitability and cash flow. Although we are not currently experiencing any significant involuntary curtailment of our natural gas or oil production, market, economic and regulatory factors may in the future materially affect our ability to sell our natural gas or oil production.
We sell a portion of our oil and natural gas to end users through various non-affiliated gas marketing companies. Historically, we have sold our oil and natural gas to a relatively few number of purchasers. However, we are not dependent upon, or confined to, any one purchaser or small group of purchasers. Due to the nature of oil and natural gas markets and because oil and natural gas 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.
We compete with major and independent oil and natural gas companies for property acquisitions. We also compete for the equipment and labor required to operate and to develop these properties. Some of our competitors have substantially greater financial and other resources and may be able to sustain
wide fluctuations in the economics of our industry more easily than we can. Since we are in a highly regulated industry, they may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can. Our ability to acquire and develop additional properties in the future will depend upon our ability to conduct operations, to evaluate and select suitable properties, to secure adequate financing and to consummate transactions in this highly competitive environment.
Gulf of Mexico
Federal Regulation of Sales and Transportation of Natural Gas. Historically, the transportation and sale for resale of natural gas in interstate commerce has been 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 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. The FERC requires interstate pipelines to provide open-access transportation on a not unduly discriminatory basis for all natural gas shippers. The FERC frequently reviews and modifies its regulations regarding the transportation of natural gas, with the stated goal of fostering competition within all phases of the natural gas industry. We cannot predict what further action the FERC will take with regard to its regulations and open-access policies, nor can we accurately predict whether the FERCs 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. There are currently no regulations implemented by FERC under its Outer Continental Shelf Lands Act authority on gatherers and other entities outside the reach of its Natural Gas Act jurisdiction. The Minerals Management Service, or MMS, has asked for comments on whether it should implement regulations under its Outer Continental Shelf Lands Act authority on gatherers and other entities to ensure open and non-discriminatory access on gathering systems and production facilities on the Outer Continental Shelf. Although we have no way of knowing whether the MMS will proceed with implementing regulations of this nature, 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.
The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the current regulatory approach by the FERC and Congress will continue. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts.
Federal Leases. A substantial portion of our operations is located on federal oil and natural gas leases, which are administered by the MMS pursuant to the Outer Continental Shelf Lands Act. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed MMS regulations and orders that are subject to interpretation and change by the MMS.
For offshore operations, lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the Outer Continental Shelf to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities.
To cover the various obligations of lessees on the Outer Continental Shelf, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. We currently have several supplemental bonds in place. Under some circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations.
The MMS also administers the collection of royalties under the terms of the Outer Continental Shelf Lands Act and the oil and gas leases issued under the Act. The amount of royalties due is based upon the terms of the oil and gas leases as well as of the regulations promulgated by the MMS. The MMS regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases currently rely on arms-length sales prices and spot market prices as indicators of value. On May 5, 2004, the MMS issued a final rule that changed certain components of its valuation procedures for the calculation of royalties owed for crude oil sales. The changes include changing the valuation basis for transactions not at arms-length from spot to NYMEX prices adjusted for locality and quality differentials, and clarifying the treatment of transactions under a joint operating agreement. We believe this rule will not have a material impact on our financial condition, liquidity or results of operations.
Oil Price Controls and Transportation Rates. Sales of crude oil, condensate and natural gas liquids by us are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.
The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERCs regulation of gas pipelines under the Natural Gas Act. Regulated pipelines that transport crude oil, condensate, and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, issued in October 1993, the FERC implemented regulations generally grandfathering all previously unchallenged interstate pipeline rates and made these rates subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods. 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, the FERCs indexing methodology is subject to review at five year intervals, with the next review scheduled for July 2005.
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 stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment, and impose substantial liabilities for pollution. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief. Offshore drilling in some areas has been opposed by environmental groups and, in some areas, has been restricted by governmental entities. Moreover, changes in environmental laws and regulations have increased in recent years. Any laws that are enacted or other governmental actions that are taken to prohibit or restrict offshore drilling or to impose more stringent or costly environmental protection requirements could have a material adverse affect on the natural gas and oil industry in general and our offshore operations in particular. While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, there is no assurance that this trend will continue in the future.
The Oil Pollution Act of 1990, also known as OPA, 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 OPA assigns liability to each responsible party for the costs of cleaning up an oil spill and for a variety of public and private damages resulting from a spill. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by a partys gross negligence or willful misconduct, a violation of a federal safety, construction or operating regulation, or a failure to report a spill or to cooperate fully in a cleanup. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages. Few defenses exist to the liability imposed by the Oil Pollution Act of 1990.
The OPA 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. Under this Act, parties responsible for offshore facilities must provide financial assurance of at least $35 million to address oil spills and associated damages, with this financial assurance amount increasing up to $150 million in certain limited circumstances if the MMS determines that a higher amount is warranted. The OPA also imposes other requirements, such as the preparation of an oil spill contingency plan, which we have in place.
We are also regulated by the Clean Water Act, which prohibits any discharge of pollutants into waters of the U.S. except in strict conformance with discharge permits issued by federal or state agencies. We have obtained, and are in material compliance with, the discharge permits necessary for
our operations. We are also subject to similar state and local water quality laws and regulations for any production or drilling activities that occur in state coastal waters. Failure to comply with the ongoing requirements of the Clean Water Act or analogous state laws may subject a responsible party to administrative, civil or criminal enforcement actions.
In addition, the Outer Continental Shelf Lands Act authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms and structures. Violations of lease conditions or regulations issued pursuant to the Outer Continental Shelf Lands Act can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or private prosecution
The 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 certain 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. Under CERCLA, responsible persons 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 may also incur liability under the Resource Conservation and Recovery Act, or RCRA, which imposes requirements relating to the management and disposal of solid and hazardous wastes. While there exists an exclusion from the definition of hazardous wastes for drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy, in the course of our operations, we may generate ordinary industrial wastes, including paint wastes, waste solvents, and waste compressor oils that may be regulated as hazardous substances or hazardous waste. Consequently, we may incur liability for such hazardous substances and hazardous waste under CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remediate previously disposed wastes or to perform remedial operations to prevent future contamination.
Our operations are also subject to regulation of air emissions under the Clean Air Act and the Outer Continental Shelf Lands Act. Implementation of these laws could lead to the gradual imposition of new air pollution control requirements on our operations. Therefore, we may incur capital expenditures over the next several years to upgrade our air pollution control equipment. We could also become subject to similar state and local air quality laws and regulations in the future if we conduct production or drilling activities in state coastal waters. However, we do not believe that our operations would be materially affected by any such requirements, nor do we expect such requirements to be anymore burdensome to us than to other companies our size involved in similar natural gas and oil development and production activities.
Regulation of Natural Gas and Oil Production. Pursuant to the Petroleum Act 1998, all natural gas and oil reserves contained in properties located in the U.K. are the property of the U.K. government. The development and production of natural gas and oil reserves in the U.K. Sector - North Sea requires a petroleum production license granted by the U.K. government. Prior to developing a field, we are required to obtain from the Secretary of State for Trade and Industry (the Secretary of State) a consent to develop that field. We would be required to obtain the consent of the Secretary of State prior to transferring an interest in a license.
The terms of the U.K. petroleum production licenses are based on model license clauses applicable at the time of the issuance of the license. Licenses frequently contain regulatory provisions governing matters such as working method, pollution and training, and reserve to the Secretary of State the power to direct some of the licensees activities. For example, a licensee may be precluded from carrying out development or production activities other than with the consent of the Secretary of State or in accordance with a development plan which the Secretary of State for Trade and Industry has approved. Breach of these requirements may result in the revocation of the license. In addition, licenses that we acquire may require us to pay fees and royalties on production and also impose certain other duties on us.
Our operations in the U.K. are subject to the Petroleum Act 1998, which imposes a health and safety regime on offshore natural gas and oil production activities. The Petroleum Act 1998 also regulates the abandonment of facilities by licensees. In addition, the Mineral Workings (Offshore Installations) Act provides a framework in which the government can impose additional regulations relating to health and safety. Since its enactment, a number of regulations have been promulgated relating to offshore construction and operation of offshore production facilities. Health and safety offshore is further governed by the Health and Safety at Work Act 1974 and applicable regulations.
Our operations are also subject to environmental laws and regulations imposed by both the European Union and the U.K. government. The offshore industry in the U.K. is regulated with regard to the environment both before activity commences and during the conduct of exploration and production activities. The licensing regime seeks to employ a preventive and precautionary approach. This is evident in the consultation which takes place before a U.K. licensing round begins, whereby the Secretary of State, acting through the Department of Trade and Industry (DTI), will consult with various public bodies having responsibility for the environment. Applicants for production licenses are required to submit a statement of the general environmental policy of the operator in respect of the contemplated license activities and a summary of its management systems for implementation of that policy and how those systems will be applied to the proposed work program. In addition, the Offshore Petroleum Production and Pipe-lines (Assessment of Environmental Effects) Regulations 1999, require the Secretary of State to exercise his licensing powers under the Petroleum Act 1998 in such a way to ensure that an environmental assessment is undertaken and considered before consent is given to certain projects.
We believe that our operations in the North Sea are in substantial compliance with current applicable environmental laws and regulations. While we expect that continued compliance with existing environmental requirements will not have a material adverse impact on us, there is no assurance that this trend will continue in the future.
Petroleum production licenses require the prior approval of the Secretary of State of a licensee to act as operator. The operator under a license organizes or supervises all or any of the development and production operations of natural gas and oil properties subject thereto. As an operator, we may obtain operational services from third parties, but will remain fully responsible for the operations as if we conduct them ourselves.
Our operations in the U.K. may entail the construction of offshore pipelines, which are subject to the provisions of the Petroleum Act 1998 and other legislation. The Petroleum Act 1998 requires a license to construct and operate a pipeline in U.K. North Sea, including its continental shelf. Easements to permit the laying of pipelines must be obtained from the Crown Estate Commissioners prior to their construction. We plan to use capacity in existing offshore pipelines in order to transport our gas. However, access to the pipelines of a third party would need to be obtained on a negotiated basis, and there is no assurance that we can obtain access to existing pipelines or, if access is obtained, it may only be on terms that are not favorable to us.
The natural gas we produce may be transported through the U.K.s onshore national gas transmission system, or NTS. The NTS is owned by a licensed gas transporter, BG Transco plc (Transco). The terms on which Transco must transport gas are governed by the Gas Acts of 1986 and 1995, the gas transporters license issued to Transco under those Acts and a network code. For us to use the NTS, we must obtain a shippers 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 shippers 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.
You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities.
Our actual development results are likely to differ from our estimates of our proved reserves. We may experience production that is less than estimated and development costs that are greater than estimated in our reserve reports. Such differences may be material.
Estimates of our oil and natural gas 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. Development activity may result in downward adjustments in reserves or higher than estimated costs.
Our estimates of our proved oil and natural gas reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas 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 that we disclose publicly. 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.
Delays in the development of or production curtailment at our material properties may adversely affect our financial position and results of operations.
The size of our operations and our capital expenditure budget limits the number of wells that we can develop in any given year. Complications in the development of any single material well may result in a material adverse affect on our financial condition and results of operations. For instance, during 2003, we experienced unforeseen production delays and increased development costs in connection with the development of our Helvellyn well in the North Sea which, combined with our significant capital requirements for the development of several of our Gulf of Mexico properties, contributed to our constrained liquidity position at the end of 2003.
In addition, a relatively few number of wells contribute to a substantial portion of our production. If we were to experience operational problems resulting in the curtailment of production in any of these wells, our total production levels would be adversely affected, which would have a material adverse affect on our financial condition and results of operations.
The unavailability or increased cost of drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute on a timely basis our development plans within our budget.
Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our operations, which could have a material adverse effect on our business, financial condition and results of operations. In periods of increased drilling activity in the Gulf of Mexico and the North Sea, we may experience increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in the Gulf of Mexico and the North Sea 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.
Our offshore properties are subject to rapid production declines. Therefore, we are required to replace our reserves at a faster rate than companies whose onshore 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.
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 produce 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 oil and natural gas 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.
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 for oil and gas properties were approximately $87.4 million, $83.8 million and $34.9 million for the years ended December 31, 2004, 2003 and 2002, respectively. Because we have experienced a negative working capital position in past years, we have depended on debt and equity financing to meet our working capital requirements that were not funded from operations.
For 2005, we plan to finance anticipated expenses, debt service and acquisition and development requirements with available cash, funds generated from cash provided by operating activities and net cash proceeds from the potential sale of assets, debt or equity.
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. Furthermore, we have incurred losses in the past that may affect our ability to obtain 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.
Our debt instruments impose restrictions on us that may affect our ability to successfully operate our business.
In March 2004, we entered into a new term loan, which was subsequently amended in September 2004 (the Term Loan), consisting of a $185.0 million Senior Secured First Lien Term Loan Facility and a $35.0 million Senior Secured Second Lien Term Loan Facility. The Term Loan matures in March 2009 and is secured by substantially all of our oil and gas assets in the Gulf of Mexico and the U.K. Sector North Sea and is guaranteed by our wholly owned subsidiaries ATP Energy and ATP Oil & Gas (U.K.) Limited. As of December 31, 2004, we had $218.4 million principal amount outstanding under the Term Loan. The Term Loan contains 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 and enter into transactions with affiliates. We also are required to maintain specified financial requirements under the terms of our Term Loan including the following, as defined in the Term Loan:
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. While we were in compliance with all of the financial covenants in our Term Loan at December 31, 2004, during 2003 and in February 2004, we were required to obtain waivers for certain of our financial covenants in our prior credit facility. If we are unable to meet the requirements of our Term Loan or any new financial transaction that we may enter into, we may be required to seek waivers from our lenders and there is no assurance that such waivers would be granted.
We have debt, trade payables and related interest payment requirements that may restrict our future operations and impair our ability to meet our obligations.
Our debt, trade payables and related interest payment requirements may have important consequences. For instance, it could:
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.
Oil and natural gas 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 oil and natural gas production. Because approximately 75% of our estimated proved reserves as of December 31, 2004 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 oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. For example, oil and natural gas prices increased significantly in late 2000 and early 2001 and then steadily declined in 2001, only to climb again in recent years to near all time highs. Among the factors that can cause this volatility are:
It is impossible to predict oil and natural gas price movements with certainty. Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil
and natural gas that we can produce economically. A substantial or extended decline in oil and natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures. Further, oil prices and natural gas prices do not necessarily move together.
Our price risk management decisions may reduce our potential gains from increases in commodity prices and may result in losses.
We periodically utilize financial derivative instruments and fixed price forward sales contracts with respect to a portion of our expected production. These instruments expose us to risk of financial loss if:
Our results of operations may be negatively impacted by our financial derivative instruments and fixed price forward sales contracts in the future and these instruments may limit any benefit we would receive from increases in the prices for oil and natural gas. For the years ended December 31, 2004, 2003 and 2002, we realized a loss on settled financial derivatives of $1.2 million, $16.6 million and $3.4 million, respectively.
We may incur substantial impairment writedowns.
If managements estimates of the recoverable reserves on a property are revised downward, if development costs exceed previous estimates or if oil and natural gas 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. 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 managements estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineers estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions. For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis. Fair value is estimated to be the present value of the aforementioned expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units estimated reserves, future cash flows and fair value. We recorded no impairments in 2004 and impairments of $11.7 million and $6.8 million for the years ended December 31, 2003 and 2002, respectively.
Managements assumptions used in calculating oil and gas reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Any change could cause impairment expense to be recorded, impacting our net income or loss and our basis in the related asset. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the propertys fair value. Additionally, as managements 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 oil and natural gas 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 oil and natural gas business involves a variety of operating risks, including:
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 in excess of our insurance coverage as a result of:
Offshore operations are also subject to a variety of operating risks peculiar to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for development or leasehold acquisitions, or result in loss of equipment and properties.
Terrorist attacks or similar hostilities may adversely impact our results of operations.
The terrorist attacks that took place in the United States on September 11, 2001 were unprecedented events that have created many economic and political uncertainties, some of which may materially adversely impact our business. Uncertainty surrounding military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. The continuation of these developments may subject our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations, financial condition and prospects.
Our insurance coverage may not be sufficient to cover some liabilities or losses that 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 contractors and other service providers are used in our offshore operations, we may not realize the full benefit of workmens 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.
Competition in our industry is intense, and we are smaller and have a more limited operating history than some of our competitors in the Gulf of Mexico and in the North Sea.
We compete with major and independent oil and natural gas 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 oil and natural gas properties and may be able to define, evaluate, bid for and acquire a greater number of properties than we can. Our ability to acquire additional properties and develop new and existing properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, some of our competitors have been operating in the Gulf of Mexico and in the North Sea for a much longer time than we have and have demonstrated the ability to operate through industry cycles.
We may suffer losses as a result of foreign currency fluctuations.
The net assets, net earnings and cash flows from our wholly owned subsidiaries in the U.K. and the Netherlands are based on the U.S. dollar equivalent of such amounts measured in the applicable functional currency. These foreign operations have the potential to impact our financial position due to fluctuations in the local currency arising from the process of re-measuring the local functional currency in the U.S. dollar. Any increase in the value of the U.S. dollar in relation to the value of the local currency will adversely affect our revenues from our foreign operations when translated into U.S. dollars. Similarly, any decrease in the value of the U.S. dollar in relation to the value of the local currency will increase our development costs in our foreign operations, to the extent such costs are payable in foreign currency, when translated into U.S. dollars. We have not utilized derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies.
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, 2004, we had 18 engineers, geologist/geophysicists and other technical personnel in our Houston office, three engineers, geologist/geophysicists and other technical personnel in our London location and one engineer in our Netherlands office. 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:
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 oil and natural gas in the U.S., especially in the Gulf of Mexico and in the North Sea, are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:
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 37% 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.
At December 31, 2004 we had 43 full-time employees in our Houston office, five full-time employees in our London office and two full-time employees in our Netherlands office. None of our employees are covered by a collective bargaining agreement. We regularly 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.
Our Internet website is http://www.atpog.com and you may access, free of charge, through the Investor Relations portion of our website our annual reports on Form 10-K, current reports on Form 8-K and amendments to such reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on our website is not part of this report.
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
ATP Oil & Gas Corporation is engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the North Sea. We seek to acquire and develop properties with proved undeveloped reserves (PUD) that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. Occasionally we will acquire properties where previous drilling has encountered reservoirs that appear to us to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration.
We seek to create value and reduce operating risks through the acquisition and development of proved oil and natural gas reserves in areas that have:
Our focus is on acquiring properties that have become non-core or non-strategic to their original owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects which they believe offer greater reserve potential. Some projects provide lower economic returns to a company due to its cost structure within that company. Also, due to timing or budgetary constraints, a company may be unwilling or unable to develop a property before the expiration of the lease. Because of our cost structure, expertise in our areas of focus and ability to develop projects, the properties may be more financially attractive to us than the seller. Given our strategy of acquiring properties that contain proved reserves, our operations typically are lower risk than exploration-focused Gulf of Mexico and North Sea operators. As a result of this strategy, we have successfully brought 37 out of 38 (97%) projects with proved undeveloped reserves to production since our inception. Our reserves estimates are prepared by independent reservoir engineers, who have had similar results in estimating the reserve quantities for those projects. Reserve estimates are inherently imprecise (see discussion regarding uncertainty of reserve estimates in Risk Factors). Our current post-drill ultimate reserves compared to the pre-drill PUD reserves for each of these reservoirs has a median success rate of 77% and has varied from zero percent of the original estimate on the single unsuccessful development to 560% of the original estimate on one of the 37 successful developments (at Brazos 544). We are unable to predict how our future results will compare to our current reserve estimates. While the results for the individual reservoirs has varied, we have accomplished an overall 98% success rate when comparing the total pre-drill PUD reserves to the current post-drill reserve estimates.
We focus on developing projects in the shortest time possible between initial significant investment and first revenue generated in order to maximize our rate of return. Since we operate a significant number of the properties in which we acquire a working interest, we are able to significantly influence the development concept and timing of a projects development. We typically initiate new development projects by simultaneously obtaining the various required components such as the pipeline and the production platform or subsea well completion equipment. We believe this strategy, combined with our strong technical abilities to evaluate and implement a projects requirements, allows us to efficiently complete the development project and commence production.
To enhance the economics and return on investment of a project, we sometimes develop the project to a value creation point and either sell an interest or bring in partners on a promoted basis during the high capital development phase. In 2002, we sold a 50% interest in our Helvellyn project in the U.K. Sector North Sea after we had obtained field development approval for the project and finalized contractual commitments. In 2003, we sold interests in three projects in the Gulf of Mexico on a promoted basis to reduce the amount of capital employed. We continued this practice into 2004 whereupon we sold 25% of our interest in seven projects containing ten offshore blocks in the Gulf of Mexico for $19.5 million, approximately $1.85/Mcfe for proved reserves, of which 93.5% were proved undeveloped reserves.
Review of 2004
The year 2004 was a year of major financial improvement and development success for ATP. We completed three financing transactions, two debt and one equity, improved working capital by $114.8 million and ended 2004 with $102.8 million of cash and cash equivalents. These financing transactions and cash from operating activities provided us the liquidity to enjoy our most active development year since becoming a publicly traded company in February 2001.
The three financing transactions for ATP in 2004 were instrumental in providing the funds needed to complete our 2004 developments and provide us the initial financial resources for our 2005 program. In March 2004, we replaced our previous $110.0 million revolving credit facility with a new $185.0 million term loan comprised of a first lien of $150.0 million and a second lien of $35 million. The new five year term loan improved our liquidity position by $56.0 million and allowed us to aggressively begin our 2004 development program. In September 2004 we amended the term loan by adding $35.0 million to the first lien, reducing the interest rate on the first lien by 325 basis points and amending certain covenants of the facility to provide us more flexibility. As a result of putting in place a term facility and its subsequent amendment, interest expense increased to $22.3 million for 2004, compared to $9.7 million for 2003. After repurchasing 79% of outstanding warrants that were issued in conjunction with the March 2004 transaction, the amendment provided us with an additional $18.0 million of liquidity. By December 1, 2004, our share price had risen from $6.28 at the beginning of the year to approximately $14.00 per share, an increase of over 120%. As a result, we elected to issue four million shares of common stock for net proceeds of $53.1 million. The financing transactions net of costs and repayments of previously outstanding amounts provided us with approximately $123.0 million of liquidity and collectively were the catalysts in achieving such a productive year.
In the first quarter of 2004, we completed and placed on production Helvellyn, our first well in the North Sea. We initially drilled this well in late 2002, encountered delays beyond our control during early and mid 2003, and ultimately made the decision to side-track the well to achieve first production in February 2004. Total development costs related to Helvellyn in 2004 were $3.0 million and other North Sea properties accounted for $5.8 million. The impact of Helvellyn was a contributing factor to our 31% increase in production, the largest annual increase in production as a publicly traded company.
In the Gulf of Mexico we completed 13 wells at six different properties. At Garden Banks 186, adjacent to our Garden Banks 142 property and the host platform for Garden Banks 186, we placed on production one well. Development at these properties, together known as Matia/Cabrito, began in 2003 when the platform was installed and the well at Garden Banks 142 was placed on production. At Ship Shoal 358, four wells were drilled and placed on production during 2004. Like Matia/Cabrito, the platform was installed during 2003 and drilling was completed in 2004. Noteworthy with both the Ship Shoal 358 and the Matia/Cabrito developments was the reuse of platforms from other ATP locations. The significance was not that platforms were reused, which often happens in the Gulf of Mexico, but that the platforms were moved to deeper water depths than originally located. This required us to install plinths, or leg extensions, to accomplish the installations. In December 2004, ATP was awarded the Offshore Energy Achievement Award for Innovation/Technology for its innovative use of plinths. The Innovation/Technology award honors a new technology that has been field-proven or an innovative application of existing technology that resulted in a material improvement in safety, throughput or cost savings.
During 2004 the Company also completed three wells at West Cameron 237, two wells at Matagorda Island 704/709, one well at West Cameron 101 and two wells at Eugene Island 30/71. In the fourth quarter 2004, we tested a well at Mississippi Canyon 711, presently our largest property in terms of proved reserves. The Mississippi Canyon 711 #4 ST1 well which logged approximately 157 total net feet of oil and gas pay in Lower Pliocene sands tested at a rate of 13,610 BOPD and 52.7 MMcf/d or 134 MMcfe/d. The multiple day flow test recorded flowing tubing pressures exceeding 3500 psi. Additional development is scheduled at Mississippi Canyon 711 during 2005 with first production currently scheduled for early in the fourth quarter 2005. Total development and exploratory costs incurred in 2004 in the Gulf of Mexico was $77.3 million.
At the end of 2004, we were drilling two wells, one at West Cameron 432 and the other at High Island 74. The well at West Cameron 432 began production on January 31, 2005. The well at High Island 74 which was one of our properties not included in our reserve report as it did not meet the SEC definition of proved reserves is scheduled to begin production during the second quarter 2005.
As a result of the production from Helvellyn, a natural gas well, our natural gas component of production increased to 80% in 2004 from 63% in 2003. We also increased our average realized price in 2004 as a result of higher oil and natural gas prices and higher prices for those quantities we hedged. For 2004, we realized an average price including the effect of cash flow hedges for natural gas of $5.05 per Mcf, an increase of 48% over 2003, and $33.93 per barrel of oil, an increase of 25% over 2003.
At December 31, 2004, we had proved reserves of 275.2 Bcfe, of which 66% are located in the Gulf of Mexico and the remaining 34% in the North Sea. The pre-tax PV-10 of our proved reserves at December 31, 2004 was $732.8 million. See Item 2. Properties Oil and Natural Gas Reserves for a reconciliation to after- tax PV-10. We currently have 18 properties that have proved undeveloped reserves totaling 214.8 Bcfe scheduled for future development including 15 properties in the Gulf of Mexico, two in the U.K. Sector North Sea and one in the Dutch Sector North Sea. In addition, we have scheduled for drilling or completion, properties where previous drilling into the targeted reservoirs indicates to the Company the presence of commercially productive quantities of hydrocarbons even though the reservoirs do not meet the SEC definition of proved reserves. Five blocks acquired in 2004 in the Gulf of Mexico and Cheviot in the North Sea, potentially the largest property in the Companys portfolio, are not included in the reserve report as they did not meet the SEC definition of proved reserves at the end of 2004. Upon completion of plans which may include drilling, completion or testing of wells for these and similar properties in the Companys portfolio, the Company anticipates that it may be able to record proved reserves associated with several of these properties.
In 2004, we sold an undivided 25% interest in seven properties on ten blocks in the Gulf of Mexico. This sale accounted for a reduction in our proved reserves of 10.6 Bcfe of which 93.5% were classified as proved undeveloped at the time of the sale. We received $19.5 million for this sale or approximately $1.85 per Mcfe and recognized a gain of $6.0 million from the transaction. After adjusting for production and the sale of the interest in the seven properties, ATP recorded net upward revisions and extensions in proved reserves during 2004 of 5.5 Bcfe.
2005 Operational and Financial Objectives
We believe that 2005 production will exceed that of 2004 as a result of our 2003 and 2004 development programs and projects scheduled for development in 2005. Development activities scheduled at Mississippi Canyon 711 during 2005 include laying approximately 27 miles of oil and gas pipelines, converting a semi-submersible drilling rig to a floating production facility, completing a second well which was previously drilled in the Southern portion of the block and connecting for production both wells. First production is currently scheduled for early in the fourth quarter 2005. In addition to Mississippi Canyon 711, developments with proved undeveloped reserves at December 31, 2004 planned in 2005 include Block L-06d in the Dutch sector of the North Sea and additional properties in the Gulf of Mexico. We also have scheduled for drilling or completion properties in which previous drilling into targeted reservoirs indicates to the Company the presence of commercially productive quantities of hydrocarbons, although these reservoirs did not meet the SEC definition of proved reserves at the end of 2004. Other potential developments for 2005 in the Gulf of Mexico and North Sea are currently being evaluated.
ATP plans to devote considerable attention in 2005 to evaluating the potential of its Cheviot property in the North Sea. This property produced from 1992 1996 before it was taken off production by the previous owner. We completed a 3-D seismic survey in the fourth quarter of 2004 which is
currently being processed and interpreted. Once this work is completed, we will continue our evaluation utilizing not only the 3-D seismic, but also previous drilling and production information. We expect to complete a plan for the Cheviot property during 2005 with the goal of recording proved undeveloped reserves by the end of 2005. Additional locations within the Cheviot property but outside of the reservoirs that previously produced are also being evaluated for possible drilling, development or exploration.
Our production may command higher realized oil and gas prices in 2005 than in recent years, based on our current hedge position and strong commodity prices. Our revenues, profitability and cash flows are highly dependent upon many factors, particularly our production results and the price of oil and natural gas. During the first quarter of 2005 we have been active in the futures market. We have hedged volumes for 2005-2006 of 6.0 Bcf of natural gas between $6.42 and $10.79 per MMBtu and 356 thousand barrels of crude oil between $45.35 and $51.05 per barrel. Including these recent hedges, we have hedged 12.4 Bcfe of our 2005 production at an average price of $6.34/MMBtue and 3.7 Bcfe of our 2006 production at an average price of $7.84/MMBtue. To mitigate future price volatility, we may hedge additional production, especially if commodity prices continue to rise.
In 2003, we recorded an income tax expense of $21.2 million primarily due to us recording a valuation allowance of $33.6 million against our deferred tax asset as required by SFAS No. 109 Accounting for Income Taxes (SFAS 109). See Note 10 Income Taxes to the Consolidated Financial Statements. SFAS 109 provides for the weighing of positive and negative evidence in determining whether a deferred tax asset is recoverable. While we recorded net income in 2004, we have incurred net operating losses in 2003 and prior consecutive years. Relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are overshadowed by such history of losses. Delays in bringing properties on to production and development cost overruns in 2003 were also significant factors considered in evaluating our deferred tax asset valuation allowance. If we achieve profitable operations in 2005, we expect to reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that period and may also reverse a portion or all of the remaining valuation allowance if we determine that it is more likely than not that we will utilize the remaining deferred tax asset.
Results of Operations
For the year ended December 31, 2004, we recorded net income of $1.4 million or $0.05 per share and for the years ended December 31, 2003 and 2002, we reported net losses $50.8 million or $2.21 per share and $4.7 million or $0.23 per share, respectively.
Oil and Gas Revenues
Revenues presented in the table and the discussion below represent revenue from sales of our oil and natural gas production volumes. Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts. Approximately 47%, 26% and 8% of our oil production was sold under these contracts for the years ended December 31, 2004, 2003 and 2002, respectively. Approximately 46%, 45% and 14% of our natural gas production was sold under these contracts for the comparable periods. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed price delivery contract was executed.
Oil and gas revenue increased 43% in 2004 compared to 2003 as the result of 12 properties brought on line during 2004, including our Helvellyn property, located in the U.K. Sector - North Sea. Another component of the increase was a 9% increase in our sales price per Mcfe in 2004 as compared to 2003. Due to the shut down of Helvellyn in September 2004 as a result of maintenance at the receiving terminal and the interruption of Gulf of Mexico production due to the hurricanes experienced during the third quarter of 2004, approximately 1.1 Bcfe of production was deferred into future periods.
The decrease in oil and gas revenue in 2003 compared to 2002 was the result of a decrease in production volumes as a result of natural decline, adverse weather conditions and repairs on pipelines and host platform facilities. The decrease was partially offset by an increase in our price realizations.
Lease Operating Expense
Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among others, workover expenses, operator fees, processing fees, insurance and transportation. Lease operating expense for the years ended December 31, 2004, 2003 and 2002 was as follows ($ in thousands):
The 13% decrease per Mcfe in 2004 compared to 2003 was primarily attributable to the aforementioned increase in production. Additionally, workover activities in 2004 were significantly lower than in 2003.
The 59% increase per Mcfe in 2003 compared to 2002 was primarily attributable to the aforementioned decrease in production while certain costs remained fixed. In addition, workover activities on eight properties and the effect of higher fixed costs on those properties with lower production rates in 2003 than in 2002 contributed to the increase.
General and Administrative Expense; Credit Facility Expenses
General and administrative expenses are overhead-related expenses, including among others, wages and benefits, legal and accounting fees, insurance, and investor relations expenses. General and administrative expense for the years ended December 31, 2004, 2003 and 2002 was as follows ($ in thousands):
The increase in 2004 compared to 2003, on an absolute basis was primarily due to higher compensation related costs and professional fees related to the implementation of the requirements of Section 404 of the Sarbanes-Oxley Act of 2002.
The increase in 2003 compared to 2002, on both an absolute and a per-unit basis was primarily due to higher professional fees and compensation related costs.
In 2004 and 2003, we recorded substantial non-recurring costs of $1.9 million and $2.0 million related to expenses incurred on behalf of waivers and amendments executed with our prior credit facilities.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization expense (DD&A) for the years ended December 31, 2004, 2003 and 2002 was as follows ($ in thousands):
DD&A expense increased 89% in 2004 as compared to 2003 primarily due to the 31% increase in production. The average DD&A per Mcfe increase was due primarily to the increased cost of development for those properties placed on production in 2003 and 2004 and to downward reserve revisions on six of our properties.
DD&A expense decreased 32% in 2003 as compared to 2002 primarily due to the 35% decrease in production. The average DD&A per Mcfe increase was due primarily to downward reserve revisions on two of our properties and impairments taken in 2002.
On two of our properties in 2003, the future undiscounted cash flows were less than their individual net book value, resulting in impairments of $10.7 million in 2003. These impairments were the result of
reductions in estimates of recoverable reserves. The impairments were calculated as the difference between the carrying value and the estimated fair value of the impaired depletable unit. We recorded an additional $1.0 million of impairment in 2003 related to SFAS 143. See Note 4, Asset Retirement Obligations, to the Consolidated Financial Statements.
On two of our properties in 2002, the future undiscounted cash flows were less than their individual net book value. As a result, we recorded impairments of $6.8 million in 2002. The impairments in 2002 were primarily the result of reductions in recoverable reserves. The impairments were calculated as the difference between the carrying value and the estimated fair value of the impaired depletable unit.
Loss on Abandonment
During 2003, we recognized a loss on abandonment of $5.0 million. Of this amount, approximately $4.4 million was attributable to actual costs exceeding the original estimates on two properties. These unforeseen overruns were a result of difficulties in abandoning one of our properties due to the condition of the wells received from the original owner and the collapse of a platform crane. In addition, we incurred significant standby time as a result of Hurricane Claudette.
Loss on Unsuccessful Property Acquisition
During 2002 and 2003, ATP was in a dispute over a contract for the sale of an oil and gas property. The dispute was subsequently resolved and the other party was awarded $8.2 million. We paid this amount in the first quarter of 2004 and the Court dismissed the lawsuit on April 16, 2004.
Loss on Extinguishment of Debt
In the first quarter of 2004, we recognized a non-cash loss of $3.3 million on the extinguishment of debt related to our prior credit facility agreement
In the third quarter of 2003, we recognized a $3.4 million loss on the extinguishment of debt related to our prior credit agreement and the repayment of our note payable. The portion of the loss attributable to the prior credit facility ($0.9 million) was related to non-cash deferred financing costs.
In the fourth quarter of 2002, we filed an insurance claim covering the estimated damages and lost production from the Gulf of Mexico region resulting from the effects of Hurricane Lili in October 2002. At December 31, 2002, we recorded amounts recoverable, net of deductibles, of approximately $1.5 million for damages to ten properties and lost production on four properties through December 31, 2002. During 2003, we received an additional $2.2 million for damages incurred, based upon the final agreed upon claim with the underwriters.
Interest expense increased $12.6 million, to $22.3 million for 2004 from $9.7 million for 2003 primarily due to higher outstanding debt as a result of the replacement of our prior credit facility with the term loan.
During 2004, we provided a valuation allowance against all of our deferred tax assets recoded during the year. The income tax expense of $21.2 million in 2003 was primarily due to the Company recording a valuation allowance of $33.6 million against our deferred tax asset as required by SFAS 109. See Note 10 Income Taxes to the Consolidated Financial Statements
Liquidity and Capital Resources
At December 31, 2004, we had working capital of approximately $68.3 million, an increase of approximately $114.8 million from December 31, 2003. Our working capital position improved dramatically as a result of several events during 2004 including the following:
We have financed our acquisition and development activities through a combination of bank borrowings and proceeds from our equity offerings, as well as cash from operations and the sale on a promoted basis of interests in selected properties. We intend to finance our near-term development projects in the Gulf of Mexico and North Sea through available cash flows, remaining proceeds from our new term loan and the potential sell down of a portion of our interests in the development projects. As operator of all of our projects in development, we have the ability to significantly control the timing of most of our capital expenditures. We believe the cash flows from operating activities combined with our ability to control the timing of substantially all of our future development and acquisition requirements will provide us with the flexibility and liquidity to meet our future planned capital requirements.
Operating activities. Net cash provided by operating activities was $41.2 million for the year ended December 31, 2004 compared to $51.0 million for the year ended December 31, 2003. Cash flow from operations decreased primarily due to substantial drilling activity in the fourth quarter of 2004 and the subsequent increase in amounts due from partners for those capital costs incurred. In addition, we used available cash to reduce amounts owed to third parties in early 2004.
Investing activities. Cash used in investing activities in 2004 and 2003 was $68.7 million and $84.0 million, respectively. Developmental capital expenditures in the Gulf of Mexico and North Sea were approximately $77.3 million and $8.8 million, respectively, in 2004, offset by the receipt of $19.2 million in proceeds for the sale of certain interests in seven of our properties discussed below. We also acquired interests in five blocks in the Gulf of Mexico well for $1.2 million in 2004. In 2003, developmental capital expenditures in the Gulf of Mexico and the North Sea were approximately $57.2 million and $24.7 million, respectively. We also incurred acquisition costs of $1.9 million in the Gulf of Mexico in 2003.
In February 2004, we entered into an agreement to sell 25% of our working interests as of January 1, 2004 in seven Gulf of Mexico (GOM) properties for $19.5 million. This sale represents 10.6 Bcfe of proved reserves (5.2% of our GOM reserves), 94% of which were proved undeveloped at December 31, 2003. The sale was implemented in two stages. The first stage closed in February 2004 whereby we received $10.5 million for a 25% interest in one property and a 10% interest in six properties. The second stage closed on April 20, 2004 whereby we received $9.0 million for the remaining 15% interests in the six properties (see Note 5 to the Consolidated Financial Statements).
Financing activities. Cash provided by financing activities in 2004 consisted of net payments of $117.1 million related to our prior credit facility and net proceeds of $212.9 million related to our new term loan and warrants issued. We repurchased all 750,000 warrants related to our prior credit facility and 1,926,837 warrants related to our term loan for $12.3 million. We also incurred deferred financing costs of approximately $13.5 million related to the term loan and its amendment. In addition, we received net proceeds of $53.1 million from a private placement sale of four million shares of common stock to accredited investors. Cash provided by financing activities in 2003 included the private placement sale of four million shares of common stock to accredited investors for a total consideration of $11.8 million ($10.9 million net of placement fees and other expenses). In addition, we received net cash proceeds of $23.2 million from our prior and current term loan.
Amounts borrowed under our credit agreements were as follows for the dates indicated (in thousands):
On March 29, 2004, we entered into a new $185.0 million term loan (Term Loan) of which $150.0 million is a Senior Secured First Lien Term Loan Facility and $35.0 million is a Senior Secured Second Lien Term Loan Facility. The Term Loan matures in March 2009. It is secured by substantially all of our oil and gas assets in the Gulf of Mexico and the U.K. Sector North Sea and is guaranteed by our wholly owned subsidiaries ATP Energy and ATP Oil & Gas (U.K.) Limited. We used $116.2 million of the proceeds of the Term Loan to repay in full our previous credit facility in effect at December 31, 2003. At closing, we received net proceeds of $56.0 million after repaying our previous credit facility, the repurchase of 750,000 warrants associated with the previous credit facility described below, a 3% original issue discount of $5.6 million and fees associated with the transaction.
As consideration for an amendment and waivers of non-compliance with certain covenants under our previous credit facility, on February 16, 2004 we issued warrants to the lender to purchase 750,000 shares of our common stock. The warrants were issued with an exercise price of $6.75 per share, had an expiration of February 16, 2009 and were accounted for as additional paid-in-capital. The warrants also included the right, under certain conditions, for us to repurchase all of the outstanding warrants for $750,000 prior to May 17, 2004, when the warrants became exercisable. On March 29, 2004, these warrants were repurchased for $750,000 and retired with a decrease to additional paid-in-capital.
The Term Loan was issued on March 29, 2004 at an average annual interest rate of 10.8%. The $150.0 million term loan bore interest at the base rate plus a margin of 7.5% or LIBOR (with a 2% floor) plus a margin of 8.5% at the election of ATP. The $35.0 million term loan bore interest at the base rate plus a margin of 9.0% or LIBOR (with a 2% floor) plus a margin of 10.0% at our election.
In connection with the issuance of the Term Loan, we paid fees and expenses of $8.6 million and granted warrants to purchase 2,452,336 shares of common stock of ATP for $7.25 per share. The warrants have a term of six years and expire in March 2010. The fair value of the warrants, as determined by use of the Black-Scholes valuation model on March 29, 2004, was approximately $4.2 million and was accounted for as additional paid-in-capital and debt discount. The fair value was calculated with the following weighted-average assumptions: zero dividend yield; risk-free interest rate of 3.0%; volatility of 51.6% and an expected life of 6 years. The value was adjusted for liquidity issues associated with a potential sale of such a large volume of shares in relation to our public float. This amount and the original issue discount of $5.6 million are being accreted over the life of the loan as additional interest expense.
On September 24, 2004, the Term Loan was amended to effect the following:
In addition, under the first and second lien facilities, the lender consented to the repurchase by the borrower of 1,926,837 of the 2,432,336 outstanding second lien facility warrants for a price not to exceed $11,561,022. The warrants were repurchased on September 24, 2004 for $6.00 per warrant which, in managements estimation, represented the current fair value of the unregistered warrants as of that date. The $11.6 million partial repurchase was recorded as a decrease to additional paid in capital while the debt discount will continue to be amortized over the life of the loan.
Net proceeds from the additional borrowing were $18.4 million after the warrant repurchase and fees and expenses of $5.0 million. Of the $5.0 million, $4.9 million paid to the Lender was capitalized and is being amortized over the remaining life of the loan and $0.1 million of third party legal fees was expensed.
The terms of the Term Loan, as amended September 24, 2004, require us to maintain certain covenants. Capitalized terms are defined in the credit agreement for the Term Loan. The covenants include:
As of December 31, 2004, we were in compliance with all of the financial covenants of our Term Loan. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns could have a material adverse affect on our financial condition and results of operations and result in our non-compliance with these covenants. An event of non-compliance with any of the required covenants could result in a material mandatory repayment under the Term Loan.
Recently Issued Accounting Pronouncements
See Note 3, Recently Issued Accounting Pronouncements, to the Consolidated Financial Statements.
We have various commitments primarily related to leases for office space, other property and equipment and other agreements. The following table summarizes certain contractual obligations at December 31, 2004 (in thousands):
Our liabilities also include asset retirement obligations ($4.9 million current and $20.0 million long-term) that represent the estimated fair value at December 31, 2004 of our obligations with respect to the retirement/abandonment of our oil and gas properties. Each reporting period the liability is accreted to its then present value. The ultimate settlement amount and the timing of the settlement of such obligations is unknown because they are subject to, among other things, federal, state and local regulation and economic factors. See Note 4 to the Consolidated Financial Statements.
Critical Accounting Policies and Estimates
Our consolidated financial statements are prepared in conformity with generally accepted accounting principles (GAAP) in the U.S., which require management to make estimates and assumptions that affect the reported amounts of the assets and liabilities and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. We routinely make estimates and judgments about the carrying value of our assets and liabilities that are not readily apparent from other sources. Such estimates and judgments are evaluated and modified as necessary on an ongoing basis. Significant estimates include DD&A of proved oil and gas properties. Oil and gas reserve estimates, which are the basis for unit-of-production DD&A and the impairment analysis, are inherently imprecise and are expected to change as future information becomes available. In addition, alternatives may exist among various accounting methods. In such cases, the choice of accounting method may also have a significant impact on reported amounts.
Based on a critical assessment of our accounting policies discussed below 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.
Oil and Gas Property Accounting
Oil and gas exploration and production companies may elect to account for their property costs using either the successful efforts or full cost accounting method. Under the successful efforts method, lease acquisition costs and intangible drilling and development costs on successful wells and development dry holes are capitalized. Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. Selection of the oil and gas accounting method can have a significant impact on a companys financial results. We use the successful efforts method of accounting and generally pursue acquisitions and development of proved reserves as opposed to exploration activities.
Capitalized costs relating to producing properties are depleted on the units-of-production method. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves for depletion rates of leasehold, platform and pipeline costs. Estimated dismantlement, restoration and abandonment costs and estimated residual salvage values are taken into account in determining amortization and depletion provisions. Expenditures for geological and geophysical testing costs are generally charged to expense unless the costs can be specifically attributed to mapping a proved reservoir and determining the optimal placement for future developmental well locations. 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.
Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization base until the related properties are developed. Unproved properties are periodically assessed and any impairment in value is charged to impairment expense. The costs of unproved properties are transferred to proved oil and gas properties upon meeting SEC requirements and amortized on a unit of production.
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. Our Gulf of Mexico and Netherlands reserves quantities are prepared annually by independent petroleum engineers Ryder Scott Company, L.P. and our U.K. Sector North Sea reserves are prepared annually by independent petroleum consultants RPS Troy Ikoda Limited. See the Supplemental Information (unaudited) in our consolidated financial statements for reserve data related to our properties.
We perform an impairment analysis whenever events or changes in circumstances indicate that an assets 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 managements estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon reservoir engineers estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property will be recognized. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. An impairment allowance is provided on an unproved property when we determine that the property will not be developed. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units estimated reserves, future cash flows and fair value.
Asset Retirement Obligations
We have significant obligations related to the plugging and abandonment of our oil and gas wells, dismantling our offshore production platforms, and the removal of equipment and facilities from leased acreage and returning such land to its original condition. SFAS 143 requires that we estimate the future cost of this obligation, discount it to its present value, and record a corresponding asset and liability in our Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash payment, and interest and inflation rates. Revisions to these estimates may be required based on changes to cost estimates, the timing of settlement, and changes in legal requirements. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis. See Note 4, Asset Retirement Obligations, to the Consolidated Financial Statements.
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 from time to time, 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 ATPs probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. Although it is difficult to predict the ultimate outcome of these matters, management believes that the recorded amounts, if any, are reasonable.
Price Risk Management Activities
We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize fixed price physical contracts and price swaps, which are generally placed with major financial institutions or with counter-parties of high credit quality that we believe are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon oil and natural gas, which have a high degree of historical correlation with actual prices we receive. Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133), all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivatives fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded in oil and natural gas revenues. As of December 31, 2004, we had three derivative contracts in place that qualified as cash flow hedges.
Valuation of Deferred Tax Asset
We compute income taxes in accordance with SFAS 109. The standard requires an asset and liability approach which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of those assets and liabilities. SFAS 109 also requires the recording of a valuation allowance if it is more likely than not that some portion or all of a deferred tax asset will not be realized.
SFAS 109 provides for the weighing of positive and negative evidence in determining whether a deferred tax asset is recoverable. We have incurred net operating losses in 2003 and prior years. Relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are overshadowed by such history of losses. Delays in bringing properties on to production and development cost overruns in 2003 were also significant factors considered in evaluating our deferred tax asset valuation allowance. Accordingly, we established a valuation allowance of $33.6 million as of December 31, 2003. We achieved profitable operations in 2004; however the income generated in 2004 was not sufficient to overcome the negative evidence noted in the prior years.
Our valuation allowance decreased during 2004 by $2.7 million. This change was a result of an increase in deferred tax assets related to foreign operations of $1.6 million and a decrease in deferred tax assets related to domestic operations of $2.2 million. The change in the valuation allowance attributable to taxes recorded directly to shareholders equity was an increase of $0.3 million. Additionally, the gross deferred tax asset and valuation allowances have been changed by $2.4 million to reflect certain adjustments including those necessary to agree to tax returns as filed. See Note 10 Income Taxes to the Consolidated Financial Statements.
Stock Based Compensation
We account for our stock-based employee compensation plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees (APB 25), and related interpretations. Under APB 25, no compensation expense is recognized when the exercise price of options equals the fair value (market price) of the underlying stock on the date of grant. We have not yet adopted the recently issued SFAS No. 123R, Share-Based Payment: an Amendment of FASB Statements No 123 and 95 (SFAS 123R) and are currently evaluating the expected impact that the adoption of this pronouncement will have on our consolidated financial position, results of operations and cash flows. SFAS 123R is effective for all interim or annual periods beginning after June 15, 2005. See Note 3 Recently Issued Accounting Pronouncements to the Consolidated Financial Statements.
Item 15. Exhibits and Financial Statement Schedules
(a) (1) and (2) Financial Statements and Financial Statement Schedules
(a) (3) Exhibits
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.