UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

Commission File Number: 001-16295

 

ENCORE ACQUISITION COMPANY

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code: (817) 877-9955

 

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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

 

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 þ     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).  Yes o     No þ

 

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Parts of the definitive proxy statement for the registrant’s 2008 annual meeting of stockholders are incorporated by reference into Part III of this report on Form 10-K.

 

 

ENCORE ACQUISITION COMPANY

 

 

INDEX

 

 

ENCORE ACQUISITION COMPANY

 

GLOSSARY

 

The following are abbreviations and definitions of certain terms used in this annual report on Form 10-K (the “Report”). The definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

 

 

ENCORE ACQUISITION COMPANY

 

 

 

ENCORE ACQUISITION COMPANY

 

 

 

ENCORE ACQUISITION COMPANY

 

This Report contains forward-looking statements, which give our current expectations and forecasts of future events. The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward-looking statements made by us or on our behalf. Please read “Item 1A. Risk Factors” for a description of various factors that could materially affect our ability to achieve the anticipated results described in the forward-looking statements. Certain terms commonly used in the oil and natural gas industry and in this Report are defined above under the caption “Glossary”. In addition, all production and reserve volumes disclosed in this Report represent amounts net to us.

 

General

 

Our Business.  We are a Delaware corporation engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, we have acquired producing properties with proven reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring, reengineering or expanding existing waterflood projects, and applying tertiary recovery techniques. Our properties — and our oil and natural gas reserves — are located in four core areas:

 

 

On January 16, 2007, we entered into a purchase and sale agreement with certain subsidiaries of Anadarko Petroleum Corporation (“Anadarko”) to acquire oil and natural gas properties and related assets in the Big Horn Basin of Montana and Wyoming, which included oil and natural gas properties and related assets in or near the Elk Basin field in Park County, Wyoming and Carbon County, Montana and oil and natural gas properties and related assets in the Gooseberry field in Park County, Wyoming. Prior to closing, we assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin assets to Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP. The closing of the Big Horn Basin acquisition occurred on March 7, 2007. The total purchase price for the Big Horn Basin assets was approximately $393.6 million, including transaction costs of approximately $1.3 million.

 

On January 23, 2007, we entered into a purchase and sale agreement with certain subsidiaries of Anadarko to acquire oil and natural gas properties and related assets in the Williston Basin of Montana and Wyoming. The closing of the Williston Basin acquisition occurred on April 11, 2007. The total purchase price for the Williston Basin assets was approximately $392.1 million, including transaction costs of approximately $1.3 million. The properties are comprised of 50 different fields across Montana and North Dakota. As part of this acquisition, we also acquired approximately 70,000 net unproved acres in the Bakken play of Montana and North Dakota.

 

In February 2007, we formed ENP to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. In September 2007, ENP completed its initial public offering (“IPO”) of 9,000,000 common units at a price to the public of $21.00 per unit. In October 2007, the underwriters exercised their over-allotment option to purchase 1,148,400 additional ENP common units. The net proceeds from ENP’s issuance of common units was approximately $193.5 million, after deducting the underwriters’

 

ENCORE ACQUISITION COMPANY

 

discount and a structuring fee of approximately $14.9 million, in the aggregate, and offering expenses of approximately $4.7 million.

 

On June 29, 2007, we completed the sale of certain oil and natural gas properties in the Mid-Continent area, primarily in the Anadarko and Arkoma fields of Oklahoma. In July 2007, additional Mid-Continent properties that were subject to preferential rights were sold. We received total net proceeds of approximately $294.8 million, after deducting transaction costs of approximately $3.6 million, and recorded a loss on sale of approximately $7.4 million.

 

On December 27, 2007, we entered into a purchase and investment agreement with ENP, which provided for the sale of certain oil and natural gas producing properties and related assets in the Permian and Williston Basins to ENP. The transaction closed on February 7, 2008, but was effective as of January 1, 2008. The consideration for the sale consisted of approximately $125.4 million in cash and 6,884,776 common units representing limited partner interests in ENP. To fund the cash portion of the sales price, ENP borrowed under its revolving credit facility. As of February 20, 2008, we owned 20,924,055 of ENP’s outstanding common units, representing a 67.3 percent limited partner interest. Through our indirect ownership of ENP’s general partner, we also hold 504,851 general partner units, representing a 1.6 percent general partner interest in ENP.

 

Financial Information About Segments.  We have operations in only one industry segment: the oil and natural gas exploration and production industry in the United States. However, we are organizationally structured along two operating segments: EAC Standalone and ENP. The contribution of each segment to revenues and operating income (loss), and the identifiable assets attributable to each segment, are set forth in Note 17 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data”.

 

Proved Reserves.  Our estimated total proved reserves at December 31, 2007 were 189 MMbls of oil and 256 Bcf of natural gas, based on December 31, 2007 spot market prices of $96.01 per Bbl for oil and $7.47 per Mcf for natural gas. On a BOE basis, our proved reserves were 231 MMBOE at December 31, 2007.

 

Most Valuable Asset.  The CCA represented approximately 50 percent of our total proved reserves as of December 31, 2007 and is our most valuable asset today and in the foreseeable future. A large portion of our future success revolves around current and future exploitation of and production from this area through primary, secondary, and tertiary recovery techniques.

 

Drilling.  In 2007, we drilled 94 gross (67.3 net) operated productive wells and participated in drilling another 134 gross (15.2 net) non-operated productive wells for a total of 228 gross (82.5 net) productive wells. Also in 2007, we drilled 5 gross (3.2 net) operated non-productive wells and participated in drilling another 5 gross (2.7 net) non-operated non-productive wells for a total of 10 gross (5.9 net) non-productive wells. We invested $367.6 million in development and exploration activities in 2007, of which $14.7 million related to exploratory dry holes.

 

ENCORE ACQUISITION COMPANY

 

Oil and Natural Gas Reserve Replacement.  During 2007, we added 60.0 MMBOE of oil and natural gas reserves to our existing proved reserve base, which replaced 443 percent of the 13.5 MMBOE we produced in 2007. Our average reserve replacement for the three years ended December 31, 2007 was 322 percent. The following table sets forth the calculation of our reserve replacement for the periods indicated:

 

 

During the three years ended December 31, 2007, we invested $1.1 billion in acquiring proved oil and natural gas properties and leasehold acreage and $1.0 billion on development, exploitation, and exploration of these and our other properties.

 

Given the inherent decline of reserves resulting from production, we must more than offset produced volumes with new reserves in order to grow. Management uses reserve replacement as an indicator of our ability to replenish annual production volumes and grow our reserves. Management believes that reserve replacement is relevant and useful information as it is commonly used to evaluate the performance and prospects of entities engaged in the production and sale of depleting natural resources. It should be noted that reserve replacement is a statistical indicator that has limitations. As an annual measure, reserve replacement is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. The predictive and comparative value of reserve replacement is also limited for the same reasons. In addition, since reserve replacement does not consider the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. Reserve replacement does not distinguish between changes in reserve quantities that are developed and those that will require additional time and funding to develop.

 

ENCORE ACQUISITION COMPANY

 

Business Strategy

 

Our primary business objective is to maximize shareholder value by growing our asset base, prudently investing internally generated cash flows, efficiently operating our properties, and maximizing long-term profitability. Our strategy for achieving this objective is to:

 

 

Challenges to Implementing Our Strategy.  We face a number of challenges to implementing our strategy and achieving our goals. One challenge is to generate superior rates of return on our investments in a volatile commodity pricing environment, while replenishing our development inventory. Changing commodity prices and increased costs of goods and services affect the rate of return on property acquisitions, and the amount of our internally generated cash flows, and, in turn, can affect our capital budget. In addition to commodity price risk, we face strong competition from other independents and major oil and natural gas companies. Our views and the views of our competitors about future commodity prices affect our success in acquiring properties and the expected rate of return on each acquisition. For more information on the challenges to implementing our strategy and achieving our goals, please read “Item 1A. Risk Factors” below.

 

Operations

 

As of December 31, 2007, we operated properties representing approximately 86 percent of our proved reserves. As the operator, we are able to better control expenses, capital allocation, and the timing of

 

ENCORE ACQUISITION COMPANY

 

exploitation and development activities on our properties. We also own working interests in properties that are operated by third parties, and are required to pay our share of LOE, exploitation, and development costs. Please read “Properties — Nature of Our Ownership Interests” below. During 2007, 2006, and 2005, our costs for development activities on non-operated properties were approximately $67.0 million, $50.2 million, and $28.2 million, respectively. We also own royalty interests in wells operated by third parties that are not burdened by LOE or capital costs; however, we have little or no control over the implementation of projects on these properties.

 

Production and Price History

 

The following table sets forth information regarding our net production volumes, average realized prices, including the effects of commodity derivative contracts, and average costs per BOE for the periods indicated:

 

 

ENCORE ACQUISITION COMPANY

 

Productive Wells

 

The following table sets forth information relating to productive wells in which we owned a working interest at December 31, 2007. Wells are classified as oil or natural gas wells according to their predominant production stream. Gross wells are the total number of productive wells in which we have an interest, and net wells are determined by multiplying gross wells by our average working interest. As of December 31, 2007, we owned a working interest in 5,545 gross wells. We also hold royalty interests in units and acreage beyond the wells in which we own a working interest.

 

 

 

 

ENCORE ACQUISITION COMPANY

 

 

Acreage

 

The following table sets forth information relating to our leasehold acreage at December 31, 2007. Developed acreage is assigned to productive wells. Undeveloped acreage is acreage held under lease, permit, contract, or option that is not in a spacing unit for a producing well, including leasehold interests identified for exploitation or exploratory drilling. As of December 31, 2007, our undeveloped acreage in the Rockies represents 60 percent of our total net undeveloped acreage. Our current leases expire at various dates between 2008 and 2029, with leases representing $6.2 million of cost set to expire in 2008 if not developed.

 

 

ENCORE ACQUISITION COMPANY

 

Drilling Results

 

The following table sets forth information with respect to wells drilled during the periods indicated. This information should not be considered indicative of future performance, nor should a correlation be assumed among the number of productive wells drilled, quantities of reserves discovered, or economic value.

 

 

Present Activities

 

As of December 31, 2007, we had a total of 14 gross (6.2 net) wells that had begun drilling and were in varying stages of drilling operations, of which 5 gross (2.3 net) were development wells. Also as of December 31, 2007, there were 33 gross (11.9 net) wells that had reached total depth and were in varying stages of completion pending first production, of which 15 gross (6.7 net) were development wells.

 

Delivery Commitments and Marketing

 

Our oil and natural gas production is principally sold to end users, marketers, refiners, and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to central storage facilities where it is aggregated and sold to various markets. While we typically market our oil and natural gas production for a term of one year or less, we have entered into an agreement to sell at least 4,500 Bbls/D at a floating market price through 2009.

 

For 2007, our largest purchaser was Eighty-Eight Oil, which accounted for approximately 14 percent of our total sales volumes. Our marketing of oil and natural gas can be affected by factors beyond our control, the potential effects of which cannot be accurately predicted. Management believes that the loss of any one purchaser would not have a material adverse effect on our ability to market our oil and natural gas production.

 

The marketing of our CCA oil production is mainly dependent on transportation through the Bridger, Poplar, and Butte Pipelines to markets in the Guernsey, Wyoming area. Alternative transportation routes and markets have been developed by moving a portion of the crude oil production through the Enbridge Pipeline to the Clearbrook, Minnesota hub. In addition, new markets to the west have been identified and a portion of our crude oil is being moved that direction through the Rocky Mountain Pipeline. To a lesser extent, our production also depends on transportation through the Platte Pipeline to Wood River, Illinois as well as other pipelines connected to the Guernsey, Wyoming area. While shipments on the Platte Pipeline are currently oversubscribed and have been subject to apportionment since December 2005, we were allocated sufficient

 

ENCORE ACQUISITION COMPANY

 

pipeline capacity to move our equity crude oil production effective January 1, 2007. However, further restrictions on available capacity to transport oil through any of the above mentioned pipelines, or any other pipelines, or any refinery upsets could have a material adverse effect on our production volumes and the prices we receive for our production.

 

The difference between quoted NYMEX market prices and the price received at the wellhead for oil and natural gas production is commonly referred to as a differential. We expect the differential between the NYMEX price of crude oil and the wellhead price we receive to remain approximately constant in the first quarter of 2008 as compared to the $13.06 per Bbl differential we realized in the fourth quarter of 2007. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have gradually widened this differential. Natural gas differentials are expected to remain approximately constant or to widen slightly in the first quarter of 2008 as compared to the $0.55 per Mcf differential we realized in the fourth quarter of 2007. We cannot accurately predict future crude oil and natural gas differentials. Increases in the differential between the NYMEX price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial position, and cash flows.

 

Competition

 

The oil and natural gas industry is highly competitive. We encounter strong competition from other independents and major oil and natural gas companies in acquiring properties, contracting for development equipment, and securing trained personnel. Many of these competitors have financial, technical, and personnel resources substantially greater than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for, and purchase a greater number of properties or prospects than our resources will permit.

 

We are also affected by competition for rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of rigs, equipment, pipe, and personnel, which has delayed development and exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

 

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases, and development rights, and we may not be able to compete satisfactorily when attempting to acquire additional properties.

 

Environmental Matters and Regulation

 

General.  Our operations are subject to stringent and complex federal, state, and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges, and solid waste management. These laws and regulations may, among other things:

 

 

ENCORE ACQUISITION COMPANY

 

 

 

These laws, rules, and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes that result in indirect compliance costs or additional operating restrictions, including costly waste handling, disposal, and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

 

The following is a discussion of relevant environmental and safety laws and regulations that relate to our operations.

 

Waste Handling.  The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous solid wastes. Under the auspices of the federal Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils that may be regulated as hazardous wastes.

 

Site Remediation.  The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed of or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such 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, for damages to natural resources, and for the costs of certain health studies. CERCLA authorizes the EPA, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, 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 currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although petroleum, including crude oil, and natural gas are excluded from CERCLA’s definition of “hazardous substance”, in the course of our ordinary operations, we generate wastes that may fall within the definition of a “hazardous substance”. We believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, yet hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or

 

ENCORE ACQUISITION COMPANY

 

operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by us. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

 

ENP’s Elk Basin assets include a natural gas processing plant. Previous environmental investigations of the Elk Basin natural gas processing plant indicate historical soil and groundwater contamination by hydrocarbons and the presence of asbestos containing material at the site. Although the environmental investigations did not identify an immediate need for remediation of the suspected historical contamination, the extent of the contamination is not known and, therefore, the potential liability for remediating this contamination may be significant. In the event ENP ceased operating the gas plant, the cost of decommissioning it and addressing the previously identified environmental conditions and other conditions, such as waste disposal, could be significant. Due to the significant level of uncertainty associated with the known and unknown environmental liabilities at the gas plant, ENP’s estimates include a large contingency. ENP does not anticipate ceasing operations at the Elk Basin natural gas processing plant in the near future and do not anticipate a need to commence remedial activities at this time. However, a regulatory agency could require ENP to begin to investigate and remediate any contamination even while the gas plant remains in operation. As of December 31, 2007, ENP has recorded $4.4 million as future abandonment cost for decommissioning the Elk Basin natural gas processing plant, and ENP expects to continue reserving additional amounts based on its estimated timing to cease operations of the natural gas processing plant. Due to the significant level of uncertainty associated with the known and unknown environmental liabilities at the gas plant, ENP’s estimate of the future abandonment liability includes a large contingency. In addition to the future abandonment liability recorded for the Elk Basin plant, ENP has recorded an estimated liability of $1.0 million as of December 31, 2007 related to required environmental plant compliance costs.

 

In connection with ENP’s IPO, we agreed to indemnify ENP through September 17, 2008 against certain potential environmental claims, losses, and expenses associated with the operation of ENP’s assets in the Permian and Elk Basins. Our maximum liability for this indemnification obligation will not exceed $10 million. We will not have any obligation under this indemnification obligation until ENP’s aggregate losses exceed $500,000, and then only to the extent such aggregate losses exceed $500,000. We have no indemnification obligations with respect to environmental matters for claims made as a result of changes in environmental laws promulgated after September 17, 2007.

 

Water Discharges.  The Clean Water Act (“CWA”), and analogous state laws, impose strict controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. CWA regulates storm water run-off from oil and natural gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Spill prevention, control, and countermeasure requirements of CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of CWA and analogous state laws and regulations.

 

The primary federal law for oil spill liability is the Oil Pollution Act (“OPA”), which addresses three principal areas of oil pollution — prevention, containment, and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be

 

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subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

 

Air Emissions.  Oil and natural gas exploration and production operations are subject to the federal Clean Air Act (“CAA”), and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including oil and natural gas exploration and production facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions.

 

Permits and related compliance obligations under CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require oil and natural gas exploration and production operations to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some oil and natural gas facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations, and enforcement actions. Oil and natural gas exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

 

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 14 states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA must consider whether it is required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases fall under CAA’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under various CAA programs, including those used in oil and natural gas exploration and production operations. It is not possible to predict how legislation that may be enacted to address greenhouse gas emissions would impact the oil and natural gas exploration and production business. However, future laws and regulations could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, financial position, demand for our operations, results of operations, and cash flows.

 

Activities on Federal Lands.  Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

 

Occupational Safety and Health Act (“OSH Act”) and Other Laws and Regulation.  We are subject to the requirements of OSH Act and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The Occupational Safety and Health Administration’s hazard communication standard, EPA community right-to-know regulations under Title III of

 

ENCORE ACQUISITION COMPANY

 

CERCLA, and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSH Act and comparable requirements.

 

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities during 2007, and, as of the date of this Report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2008. However, accidental spills or releases may occur in the course of our operations, and we may incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our business, financial condition, or results of operations.

 

Other Regulation of the Oil and Natural Gas Industry

 

The oil and natural gas industry is extensively regulated by numerous federal, state, and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities, and locations of production.

 

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

 

Development and Production.  Our operations are subject to various types of regulation at federal, state, and local levels. These types of regulation include requiring permits for the development of wells, development bonds, and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

 

State laws regulate the size and shape of development and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally

 

ENCORE ACQUISITION COMPANY

 

imposes a production or severance tax with respect to the production and sale of oil, natural gas, and NGLs within its jurisdiction.

 

Interstate Crude Oil Transportation.  ENP’s Clearfork crude oil pipeline is an interstate common carrier pipeline, which is subject to regulation by the Federal Energy Regulatory Commission (the “FERC”) under the October 1977 version of the Interstate Commerce Act (“ICA”), and the Energy Policy Act of 1992 (“EP Act 1992”). ICA and its implementing regulations give the FERC authority to regulate the rates ENP charges for service on that interstate common carrier pipeline and generally require the rates and practices of interstate oil pipelines to be just and reasonable and nondiscriminatory. ICA also requires ENP to maintain tariffs on file with the FERC that set forth the rates ENP charges for providing transportation services on its interstate common carrier liquids pipeline as well as the rules and regulations governing these services. Shippers may protest, and the FERC may investigate, the lawfulness of new or changed tariff rates. The FERC can suspend those tariff rates for up to seven months. It can also require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful. The FERC and interested parties can also challenge tariff rates that have become final and effective. EP Act 1992 deemed certain rates in effect prior to its passage to be just and reasonable and limited the circumstances under which a complaint can be made against such “grandfathered” rates. EP Act 1992 and its implementing regulations also allow interstate common carrier oil pipelines to annually index their rates up to a prescribed ceiling level. In addition, the FERC retains cost-of-service ratemaking, market-based rates, and settlement rates as alternatives to the indexing approach.

 

Natural Gas Gathering.  Section 1(b) of the Natural Gas Act (“NGA”), exempts natural gas gathering facilities from the jurisdiction of the FERC. ENP owns a number of facilities that it believes would meet the traditional tests the FERC has used to establish a pipeline’s status as a gatherer not subject to the FERC’s jurisdiction. In the states in which ENP operates, regulation of gathering facilities and intrastate pipeline facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirement and complaint-based rate regulation.

 

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that the FERC has taken a less stringent approach to regulation of the offshore gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. ENP’s gathering operations could be adversely affected should they become subject to the application of state or federal regulation of rates and services. ENP’s gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on ENP’s operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

 

Sales of Natural Gas.  The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms, and cost of pipeline transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes on our natural gas marketing operations, and we note that some of the FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with which we compete.

 

ENCORE ACQUISITION COMPANY

 

The Energy Policy Act of 2005 (“EP Act 2005”) gave the FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended the NGA to prohibit market manipulation and also amended the NGA, and the Natural Gas Policy Act of 1978 (“NGPA”), to increase civil and criminal penalties for any violations of the NGA, NGPA, and any rules, regulations, or orders of the FERC to up to $1,000,000 per day, per violation. In addition, the FERC issued a final rule effective January 26, 2006 regarding market manipulation, which makes it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud. This final rule works together with the FERC’s enhanced penalty authority to provide increased oversight of the natural gas marketplace.

 

State Regulation.  The various states regulate the development, production, gathering, and sale of oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Reduced rates may apply to certain types of wells and production methods.

 

States also regulate the method of developing new fields, the spacing and operation of wells, and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but they may do so in the future. The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

 

Federal, State, or Native American Leases.  Our operations on federal, state, or Native American oil and natural gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, Minerals Management Service, and other agencies.

 

Operating Hazards and Insurance

 

The oil and natural gas business involves a variety of operating risks, including fires, explosions, blowouts, environmental hazards, and other potential events that can adversely affect our ability to conduct operations and cause us to incur substantial losses. Such losses could reduce or eliminate the funds available for exploration, exploitation, or leasehold acquisitions or result in loss of properties.

 

In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. We do not carry business interruption insurance. We may not obtain insurance for certain risks if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable at a reasonable cost. If a significant accident or other event occurs that is not fully covered by insurance, it could adversely affect us.

 

Employees

 

We had a staff of 364 persons, including 39 engineers, 16 geologists, and 15 landmen as of December 31, 2007, none of which are represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are satisfactory.

 

Principal Executive Office

 

Our principal executive office is located at 777 Main Street, Suite 1400, Fort Worth, Texas 76102. Our main telephone number is (817) 877-9955.

 

ENCORE ACQUISITION COMPANY

 

Available Information

 

We make available electronically, free of charge through our website (www.encoreacq.com), our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and other filings with the SEC pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Exchange Act”) as soon as reasonably practicable after we electronically file such material with or furnish such material to the SEC. In addition, you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like us, that file electronically with the SEC.

 

We have adopted a code of business conduct and ethics that applies to all directors, officers, and employees, including our principal executive and financial officers. The code of business conduct and ethics is available on our website. In the event that we make changes in, or provide waivers from, the provisions of this code of business conduct and ethics that the SEC or the New York Stock Exchange (the “NYSE”) require us to disclose, we intend to disclose these events on our website.

 

We have filed the required certifications under Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2 to this Report. In 2007, we submitted to the NYSE the CEO certification required by Section 303A.12(a) of the NYSE’s Listed Company Manual. In 2008, we expect to submit this certification to the NYSE after our annual meeting of stockholders.

 

Our board of directors (the “Board”) currently has four standing committees: (i) audit, (ii) compensation, (iii) nominating and corporate governance, and (iv) special stock award. The charters of our audit, compensation, and nominating and corporate governance committees are available on our website. Copies of our code of business conduct and ethics and Board committee charters are also available in print upon written request to: Corporate Secretary, Encore Acquisition Company, 777 Main Street, Suite 1400, Fort Worth, Texas 76102.

 

The information on our website or any other website is not incorporated by reference into this Report.

 

Properties

 

Nature of Our Ownership Interests

 

The following table sets forth the net production, proved reserve quantities, and PV-10 values of our properties by principal area of operation as of and for the periods indicated:

 

 

 

 

ENCORE ACQUISITION COMPANY

 

 

The estimates of our proved oil and natural gas reserves are based on estimates prepared by Miller and Lents, Ltd. (“Miller and Lents”), independent petroleum engineers. Guidelines established by the SEC regarding the present value of future net revenues were used to prepare these reserve estimates. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those included in this Report. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions based on the results of drilling, testing, and production activities. Accordingly, reserve estimates and their PV-10 are inherently imprecise and should not be construed as representing the actual quantities of future production or cash flows to be realized from oil and natural gas properties or the fair market value of such properties.

 

During 2007, we filed estimates of oil and natural gas reserves as of December 31, 2006 with the U.S. Department of Energy on Form EIA-23. As required by Form EIA-23, the filing reflected only gross production that comes from our operated wells at year-end. Those estimates came directly from our reserve report prepared by Miller and Lents.

 

 

CCA Properties — Montana and North Dakota

 

Our initial purchase of interests in the CCA was in 1999, and we have subsequently acquired additional working interests from various owners. As of December 31, 2007, we operated virtually all of our CCA properties with an average working interest of approximately 89 percent in the oil wells and 26 percent in the natural gas wells. The average daily production from our CCA properties during 2007 was 12,640 BOE/D.

 

The CCA is a major structural feature of the Williston Basin in southeastern Montana and northwestern North Dakota. Our acreage is concentrated on the two- to six-mile-wide “crest” of the CCA, giving us access

 

ENCORE ACQUISITION COMPANY

 

to the greatest accumulation of oil in the structure. Our holdings extend for approximately 120 continuous miles along the crest of the CCA across five counties in two states. Primary producing reservoirs are the Red River, Stony Mountain, Interlake, and Lodgepole formations at depths of between 7,000 and 9,000 feet. Our fields in the CCA include the North Pine, South Pine, Cabin Creek, Coral Creek, Little Beaver, Monarch, Glendive North, Glendive, Gas City, and Pennel fields.

 

Our CCA reserves are primarily produced through a combination of waterfloods and HPAI. Since taking over operations, our net production from the CCA has increased by approximately 55 percent from 7,807 BOE/D (average for June 1999) to 12,080 BOE/D (average for the fourth quarter of 2007). We have accomplished ongoing production growth through a combination of:

 

 

In 2007, we drilled 20 gross wells in the CCA, of which 13 were horizontal re-entry wells that (i) reestablished production from non-producing wells, (ii) added additional production to existing producing wells, or (iii) served as injection wells for secondary and tertiary recovery projects. Including our HPAI project, we invested $41.6 million, $103.9 million, and $121.7 million in capital projects in the CCA during 2007, 2006, and 2005, respectively.

 

We plan to continue the development of the reserve base using the same strategies that gave rise to our past success in this area.

 

The CCA represents approximately 50 percent of our total proved reserves as of December 31, 2007 and is our most valuable asset today and in the foreseeable future. A large portion of our future success revolves around current and future exploitation of and production from this area through primary, secondary, and tertiary recovery techniques.

 

In 2006, we began implementation of two improved waterfloods in the CCA: one in South Pine Unit in the Red River U4 and one in the Coral Creek Unit in the Red River U4. In 2007, both units showed initial response for the waterflood. We believe these projects have added significant reserves in the Red River U4 and expect to see meaningful production uplift in 2008.

 

HPAI.  In 2002, we initiated a HPAI project on the CCA that injects air into the Red River U4 zone. The Red River U4 zone is the same zone where HPAI has been successfully implemented by other operators in adjacent areas on the CCA. We have seen positive results from this HPAI project at the Pennel and Little Beaver units.

 

We are currently injecting 55 MMcf/D of high pressure air in the Pennel and Little Beaver Units. The units are responding to the air injection with an increase of approximately 900 BOE/D over the expected production decline prior to the initiation of the project.

 

We believe that much of our acreage in the CCA has potential opportunities for utilizing HPAI recovery techniques at economic rates of return. We continue to evaluate and perform engineering studies on these projects. Over the next several years, we plan to study, engineer, and implement these development projects initially in the Red River U4 zone of the CCA. Additionally, we have other zones in the CCA that currently produce oil and may provide additional HPAI opportunities.

 

ENCORE ACQUISITION COMPANY

 

NPI.  A major portion of our acreage position in the CCA is subject to NPI ranging from one percent to 50 percent. The holders of these NPIs are entitled to receive a fixed percentage of the cash flow remaining after specified costs have been subtracted from net revenue. The net profits calculations are contractually defined. In general, net profits are determined after considering operating expense, overhead expense, interest expense, and development costs. The amounts of reserves and production attributable to NPIs are deducted from our reserves and production data, and our revenues are reported net of NPI payments. The reserves and production attributed to NPIs are calculated by dividing estimated future NPI payments (in the case of reserves) or prior period actual NPI payments (in the case of production) by commodity prices at the determination date. Fluctuations in commodity prices and the levels of development activities in the CCA from period to period will impact the reserves and production attributed to the NPIs and will have an inverse effect on our reported reserves and production. For 2007, 2006, and 2005, we reduced revenue for NPI payments by $32.5 million, $23.4 million, and $21.2 million, respectively.

 

Permian Basin Properties — West Texas and New Mexico

 

West Texas

 

Our West Texas properties include seventeen operated fields, including the East Cowden Grayburg Unit, Fuhrman-Mascho, Crockett County, Sand Hills, Howard Glasscock, Nolley, Deep Rock, and others; and seven non-operated fields. Production from the central portion of the Permian Basin comes from multiple reservoirs, including the Grayburg, San Andres, Glorieta, Clearfork, Wolfcamp, and Pennsylvanian zones. Production from the southern portion of the Permian Basin comes mainly from the Canyon, Devonian, Ellenberger, and Strawn formations with multiple pay intervals.

 

Average daily production for our West Texas properties increased approximately 27 percent from 5,626 BOE/D in the fourth quarter of 2006 to 7,122 BOE/D in the fourth quarter of 2007. We believe these properties will be an area of growth over the next several years. During 2007, we drilled 66 gross wells and invested approximately $120.8 million of capital to develop these properties.

 

In March 2006, we entered into a joint development agreement with ExxonMobil Corporation (“ExxonMobil”) to develop legacy natural gas fields in West Texas. The agreement covers certain formations in the Parks, Pegasus, and Wilshire Fields in Midland and Upton Counties, the Brown Bassett Field in Terrell County, and Block 16, Coyanosa, and Waha Fields in Ward, Pecos, and Reeves Counties. Targeted formations include the Barnett, Devonian, Ellenberger, Mississippian, Montoya, Silurian, Strawn, and Wolfcamp horizons.

 

Under the terms of the agreement, we will have the opportunity to develop approximately 100,000 gross acres. We will earn 30 percent of ExxonMobil’s working interest and 22.5 percent of ExxonMobil’s net revenue interest in each well drilled. We will operate each well during the drilling and completion phase, after which ExxonMobil will assume operational control of the well.

 

We will earn the right to participate in all fields by drilling a total of 24 commitment wells. During the commitment phase, ExxonMobil will have the option to receive non-recourse advanced funds from us attributable to ExxonMobil’s 70 percent working interest in each commitment well. Once a commitment well is producing, ExxonMobil will repay 95 percent of the advanced funds plus accrued interest assessed on the unpaid balance through our monthly receipt of proceeds of oil and natural gas sales. As an alternative to receiving advanced funds during the commitment phase, ExxonMobil can elect to pay their share of capital costs for each well. After we have fulfilled our obligations under the commitment phase, we will be entitled to a 30 percent working interest in future drilling locations. We will have the right to propose and drill wells for as long as we are engaged in continuous drilling operations. As of December 31, 2007, we had 6 wells to drill, at a minimum cost of $1.0 million per well, in order to fulfill our commitment under the joint development agreement.

 

ENCORE ACQUISITION COMPANY

 

In 2008, we intend to drill approximately 39 wells, including the 6 remaining commitment wells, and invest approximately $121.0 million of net capital in the development areas. We anticipate operating 5 rigs in West Texas by the end of 2008.

 

On December 27, 2007, we entered into a purchase and investment agreement with ENP, which provided for the sale of certain oil and natural gas producing properties and related assets in the Permian Basin to ENP. The transaction closed on February 7, 2008, but was effective as of January 1, 2008.

 

New Mexico

 

We began investing in New Mexico in May 2006 with the strategy of deploying capital to develop low- to medium-risk development projects in southeastern New Mexico where multiple reservoir targets are available. We expect to grow reserves in our New Mexico properties through:

 

 

Since May 2006, we have acquired or farmed-in approximately 10,500 gross acres and identified and secured approximately 30 low-risk infill locations.

 

Average daily production for these properties increased approximately 314 percent from 1,884 Mcfe/D in the fourth quarter of 2006 to 7,793 Mcfe/D in the fourth quarter of 2007. We believe these properties will be an area of growth over the next several years. During 2007, we drilled 4 operated wells, participated in 8 non-operated wells, and invested approximately $20.3 million of capital to develop these properties.

 

In 2008, we expect to increase production in New Mexico through conventional infill drilling opportunities.

 

Mid-Continent Properties — Oklahoma, Arkansas, East Texas, Kansas, and North Louisiana

 

Oklahoma, Arkansas, and Kansas

 

We own various interests, including operated, non-operated, royalty, and mineral interests, on properties located in the Anadarko Basin of western Oklahoma and the Arkoma Basin of eastern Oklahoma and eastern Arkansas.

 

As previously discussed, during 2007, we disposed of certain properties in the Anadarko and Arkoma fields. As a result, our average daily production for these properties decreased approximately 72 percent from 30,430 Mcfe/D in the fourth quarter of 2006 to 8,555 Mcfe/D for the fourth quarter of 2007. During 2007, we drilled 61 gross wells and invested $60.4 million of development and exploration capital in these properties.

 

North Louisiana Salt Basin and East Texas Basin

 

The North Louisiana Salt Basin and East Texas Basin properties consist of operated working interests, non-operated working interests, and undeveloped leases acquired primarily in the Elm Grove and Overton acquisitions in 2004 and grassroot development in the Stockman and Danville field in east Texas. Our interests acquired in the Elm Grove acquisition are located in the Elm Grove Field in Bossier Parish, Louisiana, and include non-operated working interests ranging from one percent to 47 percent across 1,800 net acres in 15 sections.

 

ENCORE ACQUISITION COMPANY

 

The East Texas and North Louisiana properties are in the same core area and have similar geology. The properties are producing primarily from multiple tight sandstone reservoirs in the Travis Peak and Lower Cotton Valley formations at depths ranging between 8,000 and 11,500 feet.

 

During 2007, we drilled 54 gross wells and invested approximately $59.4 million of capital to develop these properties. Average daily production for these properties decreased five percent from 21,092 Mcfe/D in the fourth quarter of 2006 to 20,038 Mcfe/D for the fourth quarter of 2007. We drilled 6 operated wells in the Stockman and Danville fields. Production from our Stockman field increased from 740 Mcfe/D in the fourth quarter of 2006 to 3,027 Mcfe/D for the fourth quarter of 2007.

 

Rockies Properties — Montana, North Dakota, Wyoming, and Utah

 

Big Horn Basin — Montana and Wyoming

 

In March 2007, ENP acquired the Big Horn Basin properties, which are located in the Big Horn Basin in northwestern Wyoming and south central Montana. The Big Horn Basin was formed by the Big Horn Mountains to the east, the Absaroka Mountains to the west, the Owl Creek Mountains to the south, and the Ny-Bowler Lineament to the north. The Big Horn Basin is located in Park County, Wyoming and Carbon County, Montana. The Big Horn Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations.

 

ENP also owns and operates (i) the Elk Basin natural gas processing plant near Powell, Wyoming, (ii) the Clearfork crude oil pipeline extending from the South Elk Basin Field to the Elk Basin Field in Wyoming, (iii) the Wildhorse natural gas gathering system that transports low sulfur natural gas from the Elk Basin and South Elk Basin fields to our Elk Basin natural gas processing plant, and (iv) a small natural gas gathering system that transports higher sulfur natural gas from the Elk Basin Field to our Elk Basin natural gas processing facility.

 

Average daily production for these properties was 4,255 BOE/D in the fourth quarter of 2007. During 2007, ENP drilled 6 gross wells and invested approximately $3.9 million of capital to develop these properties.

 

Williston Basin — Montana and North Dakota

 

Our Williston Basin properties have historically consisted of working and overriding royalty interests in several geographically concentrated fields. The properties are located in the Williston Basin in western North Dakota and eastern Montana, near our CCA properties. In April 2007, we acquired additional properties in the Williston Basin comprised of 50 different fields across Montana and North Dakota. As part of this acquisition, we also acquired approximately 70,000 net unproved acres in the Bakken play of Montana and North Dakota. Since the acquisition, we have increased our acreage position in the Bakken play to approximately 134,000 acres. We had one rig drilling on the Bakken acreage in 2007.

 

Average daily production for these properties increased from 978 BOE/D in the fourth quarter of 2006 to 6,363 BOE/D in the fourth quarter of 2007, largely due to the acquisition of additional interests in April 2007. During 2007, we drilled 19 gross wells and invested approximately $42.7 million of capital to develop these properties.

 

On December 27, 2007, we entered into a purchase and investment agreement with ENP, which provided for the sale of certain oil and natural gas producing properties and related assets in the Williston Basin to ENP. The transaction closed on February 7, 2008, but was effective as of January 1, 2008.

 

Bell Creek — Montana

 

Our Bell Creek properties are located in the Powder River Basin of southeastern Montana. We operate seven production units that comprise the Bell Creek properties, each with a 100 percent working interest. The shallow (less than 5,000 feet) Cretaceous-aged Muddy Sandstone reservoir produces oil. We have initiated a

 

ENCORE ACQUISITION COMPANY

 

polymer injection program on both injection and producing wells on our Bell Creek properties whereby a polymer is injected into a well to reduce the amount of water cycling in the higher permeability interval of the reservoir, reducing operating costs and increasing reservoir recovery. This process is generally more efficient than standard waterflooding. Initial encouraging results on the producing wells have resulted in an expansion of the program in 2008.

 

We invested $6.6 million of capital to develop these properties in 2007. Average daily production from these properties more than doubled from 453 BOE/D in the fourth quarter of 2006 to 958 BOE/D in the fourth quarter of 2007.

 

Paradox Basin — Utah

 

The Paradox Basin properties, located in southeast Utah’s Paradox Basin, are divided between two prolific oil producing units: the Ratherford Unit and the Aneth Unit both operated by Resolute Natural Resources Company. In 2007, the operator continued the implementation of a tertiary project in the Aneth Unit. We believe these properties have additional potential in horizontal redevelopment, secondary development, and tertiary recovery potential.

 

Average daily production for these properties decreased approximately two percent from 704 BOE/D in the fourth quarter of 2006 to 688 BOE/D in the fourth quarter of 2007. During 2007, we invested approximately $9.5 million of capital to develop these properties.

 

Title to Properties

 

We believe that we have satisfactory title to our oil and natural gas properties in accordance with standards generally accepted in the oil and natural gas industry.

 

Our properties are subject, in one degree or another, to one or more of the following:

 

 

We believe that the burdens and obligations affecting our properties do not in the aggregate materially interfere with the use of the properties. As indicated under “Net Profits Interests” above, a major portion of our acreage position in the CCA, our primary asset, is subject to NPIs.

 

We have granted mortgage liens on substantially all of our oil and natural gas properties in favor of Bank of America, N.A., as agent, to secure borrowings under our revolving credit facility. These mortgages and the revolving credit facility contain substantial restrictions and operating covenants that are customarily found in loan agreements of this type.

 

Please carefully consider the following factors together with all of the other information included in this Report. If any of the following risks and uncertainties were actually to occur, our business, financial condition, or results of operations could be materially adversely affected. In that case, the trading price of our common stock could decline and an investor could lose all or part of his/her investment.

 

ENCORE ACQUISITION COMPANY

 

Oil and natural gas prices are very volatile. A decline in commodity prices could materially and adversely affect our financial condition, results of operations, and cash flows.

 

The oil and natural gas markets are very volatile, and we cannot predict future oil and natural gas prices. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of additional factors that are beyond our control, such as:

 

 

Our revenue, profitability, and cash flow depend upon the prices of and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:

 

 

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive could significantly affect our financial condition, results of operations, and cash flows.

 

The prices that we receive for our oil and natural gas production sometimes trade at a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating commodity derivative settlements. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have gradually widened this differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could significantly reduce our cash available for development of our properties and adversely affect our financial condition. For information

 

ENCORE ACQUISITION COMPANY

 

regarding our expected differentials for 2008, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

 

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels, and operating and development costs. In estimating our level of oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to the level of oil and natural gas prices, future production levels, capital expenditures, operating and development costs, the effects of regulation, and availability of funds. If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and our estimates of the future net cash flows from our reserves could change significantly.

 

Our Standardized Measure is calculated using prices and costs in effect as of the date of estimation, less future development, production, and income tax expenses, and discounted at 10 percent per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.

 

The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates, and the timing of development expenditures.

 

The Standardized Measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate.

 

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows in compliance with the Financial Accounting Standards Board’s (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 69, “Disclosures about Oil and Gas Producing Activities”, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

 

Our oil and natural gas reserves naturally decline and the failure to replace our reserves could adversely affect our financial condition.

 

Our future oil and natural gas reserves, production volumes, and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find, or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition, and results of operations.

 

Because our oil and natural gas properties are a depleting asset, we will need to make substantial capital expenditures to maintain and grow our asset base. If lower oil and natural gas prices or operating difficulties result in our cash flows from operations being less than expected or limit our ability to borrow under our

 

ENCORE ACQUISITION COMPANY

 

revolving credit facility, we may be unable to expend the capital necessary to find, develop, or acquire additional reserves.

 

The results of HPAI techniques are uncertain.

 

We utilize HPAI techniques on some of our properties and plan to use the techniques in the future on a portion of our properties, including our CCA properties. The additional production and reserves attributable to our use of HPAI techniques, if any, are inherently difficult to predict. If our HPAI programs do not allow for the extraction of residual hydrocarbons in the manner or to the extent that we anticipate, or the cost of implementing these techniques increases beyond our expectations, our future results of operations and financial condition could be materially adversely affected.

 

Future price declines may result in a write-down of our asset carrying values, which could have a material adverse effect on our results of operations and limit our ability to borrow funds under our revolving credit facility.

 

Declines in oil and natural gas prices may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or development results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. If we incur such impairment charges in the future, it could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our revolving credit facility.

 

If we do not make acquisitions on economically acceptable terms, our future growth will be limited.

 

Acquisitions are an essential part of our growth strategy, and our ability to acquire additional properties on favorable terms is important to our long-term growth. We may be unable to make acquisitions because we are:

 

 

Future acquisitions could result in our incurring additional debt, contingent liabilities, and expenses, all of which could have a material adverse effect on our financial condition and results of operations. Furthermore, our financial position and results of operations may fluctuate significantly from period to period based on whether significant acquisitions are completed in particular periods. Competition for acquisitions is intense and may increase the cost of, or cause us to refrain from, completing acquisitions.

 

The failure to properly manage growth through acquisitions could adversely affect our results of operations.

 

Growing through acquisitions and managing that growth will require us to continue to invest in operational, financial, and management information systems and to attract, retain, motivate, and effectively manage our employees. Pursuing and integrating acquisitions involves a number of risks, including:

 

 

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The process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations.

 

Any acquisitions we complete are subject to substantial risks that would adversely affect our financial condition and results of operations.

 

Any acquisition involves potential risks, including, among other things:

 

 

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

 

Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.

 

A substantial portion of our producing properties is located in one geographic area and adverse developments in any of our operating areas would negatively affect our financial condition and results of operations.

 

We have extensive operations in the CCA. Our CCA properties represented approximately 50 percent of our proved reserves as of December 31, 2007 and 34 percent of our 2007 production. Any circumstance or event that negatively impacts production or marketing of oil and natural gas in the CCA would materially affect our results of operations and cash flows.

 

ENCORE ACQUISITION COMPANY

 

Our commodity derivative contract activities could result in financial losses or could reduce our income.

 

To reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently and may in the future enter into derivative arrangements for a significant portion of our oil and natural gas production that could result in commodity derivative losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual crude oil, natural gas, and NGL prices we realize in our operations.

 

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the notional amount of our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from the sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our derivative activities are subject to the following risks:

 

 

In addition, commodity derivative contracts may limit our ability to realize additional revenues from increases in the prices for oil and natural gas.

 

We have limited control over the activities on properties we do not operate.

 

Other companies operated approximately 14 percent of our properties (measured by total reserves) and approximately 45 percent of our wells as of December 31, 2007. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in development or acquisition activities and lead to unexpected future costs.

 

Our development and exploratory drilling efforts may not be profitable or achieve our targeted returns.

 

Development and exploratory drilling and production activities are subject to many risks, including the risk that we will not discover commercially productive oil or natural gas reserves. In order to further our development efforts, we acquire both producing and unproved properties as well as lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not be required to impair our initial investments.

 

In addition, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such unproved property or wells. The costs of drilling and completing wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions, and shortages or delays in the delivery of equipment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient commercial quantities to cover the development, operating, and other costs. In addition, wells that are profitable may not meet our internal return

 

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targets, which are dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas, and our ability to add reserves at an acceptable cost.

 

Seismic technology does not allow us to obtain conclusive evidence that oil or natural gas reserves are present or economically producible prior to spudding a well. We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects and in conducting our exploration activities. The use of seismic data and other technologies also requires greater up-front costs than development on proved properties.

 

Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations.

 

The cost of developing, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce as much oil and natural gas as we had estimated. Furthermore, our development and production operations may be curtailed, delayed, or canceled as a result of other factors, including:

 

 

If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our results of operations.

 

Secondary and tertiary recovery techniques may not be successful, which could adversely affect our financial condition or results of operations.

 

Approximately 65 percent of our production and 75 percent of our reserves rely on secondary and tertiary recovery techniques, which include waterfloods and injecting natural gases into producing formations to

 

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enhance hydrocarbon recovery. If production response is less than forecast for a particular project, then the project may be uneconomic or generate less cash flow and reserves than we had estimated prior to investing capital. Risks associated with secondary and tertiary recovery techniques include, but are not limited to, the following:

 

 

If any of these risks occur, it could adversely affect our financial condition or results of operations.

 

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

 

There are a variety of operating risks inherent in our wells, gathering systems, pipelines, and other facilities, such as leaks, explosions, mechanical problems, and natural disasters, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations, and substantial revenue losses. The location of our wells, gathering systems, pipelines, and other facilities near populated areas, including residential areas, commercial business centers, and industrial sites, could significantly increase the level of damages resulting from these risks.

 

We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets due to terrorist attacks and hurricanes have made it more difficult for us to obtain certain types of coverage. We may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and our insurance may contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, and results of operations.

 

Terrorist activities and the potential for military and other actions could adversely affect our business.

 

The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for oil and natural gas, all of which could adversely affect the markets for our production. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.

 

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Our development, exploitation, and exploration operations require substantial capital, and we may be unable to obtain needed financing on satisfactory terms.

 

We make and will continue to make substantial capital expenditures in development, exploitation, and exploration projects. For example, our Board recently approved a $445 million capital budget for 2008, excluding acquisitions. We intend to finance these capital expenditures through a combination operating cash flows and external financing arrangements. Additional financing sources may be required in the future to fund our capital expenditures. Financing may not continue to be available under existing or new financing arrangements, or on acceptable terms, if at all. If additional capital resources are not available, we may be forced to curtail our development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.

 

Shortages of rigs, equipment and crews could delay our operations and reduce our cash available for distribution.

 

Higher oil and natural gas prices generally increase the demand for rigs, equipment and crews and can lead to shortages of, and increasing costs for, development equipment, services, and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues.

 

The loss of key personnel could adversely affect our business.

 

We depend to a large extent on the efforts and continued employment of I. Jon Brumley, our Chairman of the Board, Jon S. Brumley, our Chief Executive Officer and President, and other key personnel. The loss of the services of any of these persons could adversely affect our business, and we do not have employment agreements with, and do not maintain key person insurance on the lives of, any of these persons.

 

Our development success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, and other professionals. Competition for experienced geologists, engineers, and other professionals is extremely intense and the cost of attracting and retaining technical personnel has increased significantly in recent years. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed. Furthermore, escalating personnel costs could adversely affect our results of operations and financial condition.

 

Our business depends in part on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production and could harm our business.

 

The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of pipelines, oil and natural gas gathering systems, and processing facilities. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity could reduce our ability to market our oil and natural gas production and harm our business.

 

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Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial, technological, and other resources than we do. As a result, we may be unable to effectively compete with larger competitors.

 

The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major and large independent oil and natural gas companies, and possess and employ financial, technical, and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national, or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for, and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local, and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

 

We are subject to complex federal, state, local, and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

 

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate, and abandon oil and natural gas wells and related pipeline and processing facilities. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals, and certificates from various federal, state, and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.

 

Our business is subject to federal, state, and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition and results of operations. Please read “Items 1 and 2. Business and Properties — Environmental Matters and Regulations” and “Items 1 and 2. Business and Properties — Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.

 

We have significant indebtedness and may incur significant additional indebtedness, which could negatively impact our financial condition, results of operations, and business prospects.

 

As of December 31, 2007, we had total debt of $1.1 billion and $371.5 million of available borrowing capacity under our revolving credit facility.

 

We have the ability to incur additional debt under our revolving credit facility, subject to borrowing base limitations of our revolving credit facility. Our future indebtedness could have important consequences to us, including:

 

 

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Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory, and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms or at all.

 

ITEM 1B.  UNRESOLVED STAFF COMMENTS

 

There were no unresolved SEC staff comments as of December 31, 2007.

 

 

We are a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the result of these legal proceedings will have a material adverse effect on our results of operations or financial position.

 

 

There were no matters submitted to stockholders during the fourth quarter of 2007.

 

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Our common stock, $0.01 par value, is listed on the NYSE under the symbol “EAC”. The following table sets forth high and low sales prices of our common stock for each quarterly period of 2007 and 2006:

 

 

On February 20, 2008, the closing sales price of our common stock as reported by the NYSE was $36.05 per share and we had approximately 406 shareholders of record. This number does not include owners for whom common stock may be held in “street” names.

 

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

 

The following table summarizes purchases of our common stock during the fourth quarter of 2007:

 

 

 

In December 2007, we announced that the Board had approved a new share repurchase program authorizing the purchase of up to $50 million of our common stock. As of December 31, 2007, we had not repurchased any of our common shares under this program. As of February 25, 2008, we had repurchased approximately 844,191 shares of our outstanding common stock for approximately $27.2 million, or an average price of $32.23 per share.

 

Dividends

 

No dividends have been declared or paid on our common stock. We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of the Board after taking into account many factors, including our operating results, financial condition, current and anticipated cash needs, and plans for expansion. The declaration and payment of dividends is

 

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restricted by our existing revolving credit facility and the indentures governing our senior subordinated notes. Future debt agreements may also restrict our ability to pay dividends.

 

Stock Performance Graph

 

The following graph compares our cumulative total stockholder return during the period from January 1, 2003 to December 31, 2007 with total stockholder return during the same period for the Independent Oil and Gas Index and the Standard & Poor’s 500 Index. The graph assumes that $100 was invested in our common stock and each index on January 1, 2003 and that all dividends, if any, were reinvested. The following graph is being furnished pursuant to SEC rules. It will not be incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act except to the extent we specifically incorporate it by reference.

 

Comparison of Total Return Since January 1, 2003 Among Encore
Acquisition Company, the Standard & Poor’s 500 Index, and the
Independent Oil and Gas Index

 

 

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The following selected consolidated financial and operating data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data”:

 

 

 

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The following discussion and analysis of our consolidated financial position and results of operations should be read in conjunction with our consolidated financial statements, the accompanying notes, and the supplemental oil and natural gas disclosures included in “Item 8. Financial Statements and Supplementary Data”. The following discussion and analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. Actual results could differ materially from those stated in the forward-looking statements. We do not undertake to update, revise, or correct any of the forward-looking information unless required to do so under federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under the headings: “Information Concerning Forward-Looking Statements” below and “Item 1A. Risk Factors”.

 

Introduction

 

In this management’s discussion and analysis of financial condition and results of operations, the following will be discussed and analyzed:

 

 

— Comparison of 2007 to 2006

 

— Comparison of 2006 to 2005

 

 

Overview of Business

 

We are engaged in the acquisition, development, exploitation, exploration, and production of oil and natural gas reserves from onshore fields in the United States. Our business strategies include:

 

 

In February 2007, we formed ENP to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. On September 17, 2007, ENP completed its IPO of 9,000,000 common units at a price to the public of $21.00 per unit. In October 2007, the underwriters exercised their over-allotment option to purchase 1,148,400 additional ENP common units. The net proceeds from ENP’s

 

ENCORE ACQUISITION COMPANY

 

issuance of common units was approximately $193.5 million, after deducting the underwriters’ discount and a structuring fee of approximately $14.9 million, in the aggregate, and offering expenses of approximately $4.7 million. The net proceeds were used to repay in full $126.4 million of outstanding indebtedness, including accrued interest, under ENP’s subordinated credit agreement with EAP Operating, Inc., an indirect wholly owned subsidiary of us, and $65.9 million of outstanding borrowings under its revolving credit facility. As of December 31, 2007, public unitholders in ENP had a limited partner interest of approximately 40.2 percent. We include ENP in our consolidated financial statements and show the ownership by the public as a minority interest.

 

On January 16, 2007, we entered into a purchase and sale agreement with certain subsidiaries of Anadarko to acquire oil and natural gas properties and related assets in the Big Horn Basin of Montana and Wyoming, which included oil and natural gas properties and related assets in or near the Elk Basin field in Park County, Wyoming and Carbon County, Montana and oil and natural gas properties and related assets in the Gooseberry field in Park County, Wyoming. Prior to closing, we assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin assets to OLLC. The closing of the Big Horn Basin acquisition occurred on March 7, 2007. The purchase price for the Big Horn Basin assets was approximately $393.6 million, including transaction costs of approximately $1.3 million.

 

On January 23, 2007, we entered into a purchase and sale agreement with certain subsidiaries of Anadarko to acquire oil and natural gas properties and related assets in the Williston Basin of Montana and Wyoming. The closing of the Williston Basin acquisition occurred on April 11, 2007. The purchase price for the Williston Basin assets was approximately $392.1 million, including transaction costs of approximately $1.3 million. The properties are comprised of 50 different fields across Montana and North Dakota. As part of this acquisition, we also acquired approximately 70,000 net unproved acres in the Bakken play of Montana and North Dakota.

 

As of December 31, 2006, estimated total proved reserves associated with the Big Horn Basin and Williston Basin acquisitions were 38,934 MBOE, 92 percent of which were oil and 90 percent of which were proved developed.

 

On June 29, 2007, we completed the sale of certain oil and natural gas properties in the Mid-Continent area. In July 2007, additional Mid-Continent properties that were subject to preferential rights were sold. We received total net proceeds of approximately $294.8 million, after deducting transaction costs of approximately $3.6 million, and recorded a loss on sale of approximately $7.4 million. The net proceeds were used to reduce outstanding borrowings under our revolving credit facility. As of December 31, 2006, estimated total proved reserves associated with the Mid-Continent disposition were 17,416 MBOE, 92 percent of which were natural gas and 75 percent of which were proved developed.

 

On December 27, 2007, we entered into a purchase and investment agreement with ENP, which provided for the sale of certain oil and natural gas producing properties and related assets in the Permian and Williston Basins to ENP. The transaction closed on February 7, 2008, but was effective as of January 1, 2008. The consideration for the sale consisted of approximately $125.4 million in cash and 6,884,776 common units representing limited partner interests in ENP. To fund the cash portion of the sales price, ENP borrowed under its revolving credit facility. As of February 20, 2008, we owned 20,924,055 of ENP’s outstanding common units, representing a 67.3 percent limited partner interest. Through our indirect ownership of ENP’s general partner, we also hold 504,851 general partner units, representing a 1.6 percent general partner interest in ENP.

 

Our financial results and ability to generate cash depend upon many factors, particularly the price of oil and natural gas. Oil prices continued to strengthen in 2007, with average NYMEX prices increasing in each of the past three years. In addition, our oil wellhead differentials to NYMEX tightened in 2007 as we realized 88 percent of the average NYMEX oil price, as compared to 82 percent in 2006. Natural gas prices continued to deteriorate in 2007 from an all-time high in 2005, but average NYMEX prices remain higher than historical averages. However, our natural gas wellhead differentials to NYMEX improved in 2007 as we realized 98 percent of the average NYMEX natural gas price, as compared to 92 percent in 2006. Commodity prices

 

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are influenced by many factors that are outside of our control. We cannot accurately predict future commodity benchmark or wellhead prices. For this reason, we attempt to mitigate the effect of commodity price risk by entering into commodity derivative contracts for a portion of our estimated future production.

 

We continue to believe that a portfolio of long-lived quality assets will position us for future success, and that reserve replacement is a key statistical measure of our success in growing our asset base. During 2007, we replaced 443 percent of our production. Our development program replaced 125 percent of our 2007 production and our acquisitions, primarily the Big Horn Basin and Williston Basin acquisitions, replaced 318 percent of our 2007 production. Please read “Items 1 and 2. Business and Properties — General — Oil and Natural Gas Reserve Replacement” for the calculation of our reserve replacement.

 

2007 Highlights

 

Our financial and operating results for 2007 included the following:

 

 

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2008 Outlook

 

For 2008, the Board has approved the following $445 million capital budget for oil and natural gas related activities, excluding proved property acquisitions (in thousands):

 

 

The prices we receive for our oil and natural gas production are largely based on current market prices, which are beyond our control. For comparability and accountability, we take a constant approach to budgeting commodity prices. We presently analyze our inventory of capital projects based on current NYMEX strip prices. If NYMEX prices trend downward for a sustained period of time, we may reevaluate our capital projects. If commodity prices are significantly lower than current NYMEX strip prices, it could have a material adverse effect on our results of operations in 2008. In this case, we would have to borrow additional money under our revolving credit facility, attempt to access the capital markets, or curtail our capital program. However, we currently believe that our 2008 capital budget will be within our anticipated operating cash flows as our current hedging program is expected to mitigate the effects of a significant decline in commodity prices. If development is curtailed or ended, future cash flows could be materially negatively impacted.

 

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Results of Operations

 

Comparison of 2007 to 2006

 

Oil and natural gas revenues and production.  The following table illustrates the primary components of oil and natural gas revenues for 2007 and 2006, as well as each year’s respective oil and natural gas production volumes and average prices: