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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o     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.  þ

 

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 Rule 12b-2 of the Act).  Yes o     No þ

 

 

DOCUMENTS INCORPORATED BY REFERENCE:

None

 

 

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

 

 

 

ENCORE ACQUISITION COMPANY

 

As used in this Report, references to “EAC,” “we,” “our,” “us,” or similar terms refer to Encore Acquisition Company and its subsidiaries, unless the context indicates otherwise. References to “ENP” refers to Encore Energy Partners LP and its subsidiaries. The financial position, results of operations, and cash flows of ENP are consolidated with those of EAC. This Report contains forward-looking statements, which give our current expectations or 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 under the caption “Glossary.” In addition, all production and reserve volumes disclosed in this Report represent amounts net to us, unless otherwise noted.

 

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 oil and natural gas reserves are located in four core areas:

 

 

In August 2009, we acquired certain oil and natural gas properties and related assets in the Mid-Continent and East Texas from EXCO Resources, Inc. (together with its affiliates, “EXCO”) for approximately $357.4 million in cash, substantially all of which are proved producing.

 

Merger with Denbury.  On October 31, 2009, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Denbury Resources Inc. (“Denbury”) pursuant to which we have agreed to merge with and into Denbury, with Denbury as the surviving entity (the “Merger”). The Merger Agreement, which was unanimously approved by our Board of Directors (the “Board”) and by Denbury’s Board of Directors, provides for Denbury’s acquisition of all of our issued and outstanding shares of common stock, par value $.01 per share, in a transaction valued at approximately $4.5 billion, including the assumption of debt and the value of our interest in ENP. We expect to complete the Merger during the first quarter of 2010, although completion by any particular date cannot be assured.

 

Proved Reserves.  Our estimated total proved reserves at December 31, 2009 were 147.1 MMBbls of oil and 439.1 Bcf of natural gas, based on 2009 average market prices of $61.18 per Bbl for oil and $3.83 per Mcf for natural gas. On a BOE basis, our proved reserves were 220.3 MMBOE at December 31, 2009, of which 67 percent was oil, 80 percent was proved developed, and 20 percent was proved undeveloped.

 

Most Valuable Asset.  The CCA represented approximately 32 percent of our total proved reserves as of December 31, 2009 and is our most valuable asset today and in the foreseeable future. A large portion of our future success revolves around current and future CCA exploitation and production through primary, secondary, and tertiary recovery techniques.

 

ENCORE ACQUISITION COMPANY

 

Drilling.  In 2009, we drilled 34 gross (27.5 net) operated productive wells and participated in drilling 78 gross (14.8 net) non-operated productive wells for a total of 112 gross (42.3 net) productive wells. In 2009, we drilled six gross (5.9 net) operated dry holes and participated in drilling another two gross (0.6 net) dry holes for a total of eight gross (6.6 net) dry holes. This represents a success rate of over 93 percent during 2009. We invested $286.9 million in development, exploitation, and exploration activities in 2009, of which $25.4 million related to dry holes.

 

ENP.  As of February 17, 2010, we owned 20,924,055 of ENP’s outstanding common units, representing an approximate 45.7 percent limited partner interest. Through our indirect ownership of ENP’s general partner, we also hold all 504,851 general partner units, representing a 1.1 percent general partner interest in ENP. As we control ENP’s general partner, ENP’s financial position, results of operations, and cash flows are consolidated with ours.

 

In February 2008, we sold certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota to ENP for approximately $125.0 million in cash and 6,884,776 ENP common units. In determining the total sales price, the common units were valued at $125.0 million. In January 2009, we sold certain oil and natural gas properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”), to ENP for approximately $46.4 million in cash. In June 2009, we sold certain oil and natural gas properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) to ENP for approximately $25.2 million in cash. In August 2009, we sold certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) to ENP for approximately $179.6 million in cash.

 

Financial Information About Operating 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 operating segment to revenues and operating income (loss), and the identifiable assets and liabilities attributable to each operating segment, are set forth in Note 16 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

 

Operations

 

Well Operations

 

In general, we seek to be the operator of wells in which we have a working interest. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oilfield service equipment used for drilling or maintaining wells on properties we operate. Independent contractors engaged by us provide all the equipment and personnel associated with these activities.

 

As of December 31, 2009, we operated properties representing approximately 79 percent of our proved reserves. As the operator, we are able to better control expenses, capital allocation, and the timing of exploitation and development activities on our properties. We also own working interests in properties that are operated by third parties for which we are required to pay our share of production, exploitation, and development costs. Please read “— Properties — Nature of Our Ownership Interests.” During 2009, 2008, and 2007, our development costs on non-operated properties were approximately 39 percent, 22 percent, and 40 percent, respectively, of our total development costs. We also own royalty interests in wells operated by third parties that are not burdened by production or capital costs; however, we have little or no control over the implementation of projects on these properties.

 

ENCORE ACQUISITION COMPANY

 

Natural Gas Gathering

 

We own and operate a network of natural gas gathering systems in our Elk Basin area of operation. These systems gather and transport our natural gas and a small amount of third-party natural gas to larger gathering systems and intrastate, interstate, and local distribution pipelines. Our network of natural gas gathering systems permits us to transport production from our wells with fewer interruptions and also minimizes any delays associated with a gathering company extending its lines to our wells. Our ownership and control of these lines enables us to:

 

 

Seasonal Nature of Business

 

Oil and natural gas producing operations are generally not seasonal. However, demand for some of our products can fluctuate season to season, which impacts price. In particular, heavy oil is typically in higher demand in the summer for its use in road construction, and natural gas is generally in higher demand in the winter for heating.

 

ENCORE ACQUISITION COMPANY

 

Production and Price History

 

The following table sets forth information regarding our production volumes, average realized prices, and average costs per BOE for the periods indicated:

 

 

Productive Wells

 

The following table sets forth information relating to productive wells in which we owned a working interest at December 31, 2009. Wells are classified as oil or natural gas wells according to their predominant production stream. 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, 2009. 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, 2009, our undeveloped acreage in the Rockies represented approximately 40 percent of our total net undeveloped acreage. A portion of our oil and natural gas leases are held by production, which means that for as long as our wells continue to produce oil or natural gas, we will continue to own the lease. Leases which are not held by production expire at various dates between 2010 and 2020, with leases representing $28.9 million of cost set to expire in 2010 if not developed.

 

 

ENCORE ACQUISITION COMPANY

 

Development Results

 

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

 

 

Present Activities

 

As of December 31, 2009, we had 25 gross (10.3 net) wells that had begun drilling and were in varying stages of drilling operations, of which nine gross (1.9 net) were development wells. As of December 31, 2009, we had 15 gross (6.0 net) wells that had reached total depth and were in the process of being completed pending first production, of which six gross (1.2 net) were development wells.

 

Delivery Commitments and Marketing Arrangements

 

Our oil and natural gas production is generally sold to marketers, processors, refiners, and other purchasers that have access to nearby pipeline, processing, and gathering 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 and downstream purchasers. Our production sales agreements generally contain customary terms and conditions for the oil and natural gas industry, provide for sales based on prevailing market prices in the area, and generally have terms of one year or less.

 

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. 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 oversubscribed and subject to apportionment, we currently believe that we have been allocated sufficient pipeline capacity to move our crude oil production. However, there can be no assurance that we will be allocated sufficient pipeline capacity to move our crude oil production in the future. An expansion of the Enbridge Pipeline was completed in early 2008, which moved the total Rockies area pipeline takeaway closer to increasing production volumes and thereby provided greater stability to oil differentials in the area. An additional expansion of Enbridge Pipeline was completed in early

 

ENCORE ACQUISITION COMPANY

 

2010, bringing additional takeaway capacity to the region, but in spite of these increases in capacity, the Enbridge Pipeline continues to run at full capacity. The Enbridge pipeline is currently presenting a new proposal to further expand the line in anticipation of the continuing expected production increases from the Williston / Bakken region. However, any restrictions on available capacity to transport oil through any of the above-mentioned pipelines, 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 NYMEX market prices and the price received at the wellhead for oil and natural gas production is commonly referred to as a differential. 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 affected this differential. We cannot accurately predict future oil and natural gas differentials. Increases in the percentage 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. The following table shows the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices by quarter for 2009:

 

 

Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of liquids extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production resulting in a price we were paid per Mcf under certain contracts to be higher than the average NYMEX price.

 

Principal Customers

 

For 2009, our largest purchaser was Eighty-Eight Oil, which accounted for approximately 18 percent of our total sales of production. 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.

 

Competition

 

The oil and natural gas industry is highly competitive. We encounter strong competition from other oil and natural gas companies in acquiring properties, contracting for development equipment, and securing trained personnel. Many of these competitors have 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. 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.

 

ENCORE ACQUISITION COMPANY

 

Properties

 

Nature of Our Ownership Interests

 

The following table sets forth the production, average wellhead prices, and average LOE per BOE of our properties by principal area of operation for the periods indicated:

 

 

ENCORE ACQUISITION COMPANY

 

The following table sets forth the proved reserves of our properties by principal area of operation as of December 31, 2009:

 

 

The following table sets forth the PV-10 of our properties by principal area of operation as of December 31, 2009:

 

 

 

 

Recent SEC Rule-Making Activity.  In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and natural gas than would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 8.5 MBOE while the change in definition of proved

 

ENCORE ACQUISITION COMPANY

 

undeveloped reserves increased total proved reserves by 5.7 MMBOE. Therefore, the total impact of the new reserve rules resulted in negative reserves revisions of 2.8 MMBOE. Pursuant to the SEC’s final rule, prior period reserves were not restated.

 

The SEC’s new rules expanded the technologies that a company can use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.

 

We used a combination of production and pressure performance, wireline wellbore measurements, simulation studies, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs, and core data to calculate our reserves estimates, including the material additions to the 2009 reserves estimates.

 

Proved Undeveloped Reserves (“PUDs”).  As of December 31, 2009, our PUDs totaled 25.7 MMBbls of crude oil and 116.7 Bcf of natural gas, for a total of 45.1 MMBOE or about 20.5 percent of our total proved reserves.

 

All of our PUDs as of December 31, 2009 are associated with drilling or improved recovery development projects that are scheduled to begin drilling or implementation within the next 5 years. Our major development areas include drilling locations in West Texas, Bakken, and Haynesville and PUDs booked for secondary recovery projects in CCA and West Texas. All of the drilling projects will have PUDs convert from undeveloped to developed as these projects begin production. All of the improved recovery projects will convert to proved developed reserves as, and to the extent, these projects achieve production response.

 

Changes in PUDs that occurred during 2009 were due to:

 

 

Drilling Plans.  All PUD drilling locations are scheduled to be drilled prior to the end of 2014. Initial production from these PUDs is expected to begin between 2010 to 2014.

 

Internal Controls Over Reserves Estimates.  Our policies regarding internal controls over the recording of reserves estimates requires reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. We engage a third-party petroleum consulting firm, Miller and Lents, to prepare our reserves. Responsibility for compliance in reserves bookings is delegated to the Reserves and Planning Engineering Manager and requires that reserves estimates be made by the regional reservoir engineering staff for our different geographical regions. These reserves estimates are reviewed and approved by regional management and senior engineering staff with final approval by the Reserves and Planning Engineering Manager and the Senior Vice President and Chief Operating Officer and certain members of senior management.

 

Our Reserves and Planning Engineering Manager is the technical person primarily responsible for overseeing the preparation of our reserves estimates. She has a Bachelor of Science degree in Petroleum Engineering, 15 years of industry experience, and 9 years experience managing our reserves with positions of increasing responsibility in engineering and evaluations. The Reserves and Planning Engineering Manager reports directly to our Senior Vice President and Chief Operating Officer.

 

The engineers and geologists of Miller and Lents have an average of 30 years of relevant industry experience in the estimation, assessment, and evaluation of oil and natural gas reserves. They have significant industry experience in virtually all petroleum-producing basins in the world and meet the requirements

 

ENCORE ACQUISITION COMPANY

 

regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Miller and Lents is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; it does not own an interest in our properties and is not employed on a contingent fee basis. Miller and Lents’ report on our reserves and future net revenues as of December 31, 2009, which details specific information regarding the scope of work undertaken and the results thereof, is filed as Exhibit 99.1 to this Report and incorporated herein by reference.

 

Guidelines established by the SEC were used to prepare these reserve estimates. Oil and natural gas reserve engineering is and must be recognized as 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 herein. 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, subject to change, 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.

 

Other Reserve Information.  During 2009, we filed the estimates of our oil and natural gas reserves as of December 31, 2008 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.

 

 

ENCORE ACQUISITION COMPANY

 

CCA Properties

 

Our initial purchase of interests in the CCA was in 1999, and we continue to acquire additional working interests. As of December 31, 2009, we operated virtually all of our CCA properties with an average working interest of approximately 89 percent in the oil wells and 27 percent in the natural gas wells.

 

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 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 waterfloods. Our average daily net production from the CCA decreased 15 percent to 10,360 BOE/D in the fourth quarter of 2009 as compared to 12,153 BOE/D in the fourth quarter of 2008. We invested $18.1 million, $37.3 million, and $41.6 million in capital projects in the CCA during 2009, 2008, and 2007, respectively.

 

The CCA represents approximately 32 percent of our total proved reserves as of December 31, 2009 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.

 

We pursued HPAI in the CCA beginning in 2002 because CO₂ was not readily available and HPAI was an attractive alternative. The initial project was successful and continues to be successful; however, the political environment is changing in favor of CO₂ sequestration. Therefore, we have made a strategic decision to move away from HPAI and focus on CO₂.

 

Existing HPAI project areas in the CCA are in Pennel and Cedar Creek fields. In both fields, HPAI wells will be converted to water injection in three to four phases over a period of approximately 18 months. Priority will be largely based on economics of incremental production uplift and air injection utilization. We anticipate that we will continue injecting air in a small number of HPAI patterns beyond the planned 18-month conversion period. We expect to realize significant LOE savings while achieving current production estimates.

 

Net Profits Interest.  A major portion of our acreage position in the CCA is subject to net profits interests ranging from one percent to 50 percent. The holders of these net profits interests 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 net profits interests are deducted from our reserves and production data, and our revenues are reported net of net profits interests. The reserves and production attributed to net profits interests are calculated by dividing estimated future net profits interests (in the case of reserves) or prior period actual net profits interests (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 attributable to the net profits interests and will have an inverse effect on our reported reserves and production. For 2009, 2008, and 2007, we reduced oil and natural gas revenues for net profits interests by $31.8 million, $56.5 million, and $32.5 million, respectively.

 

Permian Basin Properties

 

West Texas.  Our West Texas properties include 17 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.

 

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Production from the southern portion of the Permian Basin comes mainly from the Canyon, Devonian, Ellenberger, Mississippian, Montoya, Strawn, and Wolfcamp formations with multiple pay intervals.

 

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 have the opportunity to develop approximately 100,000 gross acres. We earn 30 percent of ExxonMobil’s working interest and 22.5 percent of ExxonMobil’s net revenue interest in each well drilled. We operate each well during the drilling and completion phase, after which ExxonMobil assumes operational control of the well. We also have the right to propose and drill wells for as long as we are engaged in continuous drilling operations.

 

We entered into a side letter agreement with ExxonMobil to: (1) combine a group of specified fields into one development area, and extend the period within which we must drill a well in this development area and one additional development area in order to be considered as conducting continuous drilling operations; (2) transfer ExxonMobil’s full working interest in a specified well along with a majority of its net royalty interest to us, while reserving its portion of an overriding royalty interest; (3) allow ExxonMobil to participate in any re-entry of the specified well under the original terms of a “subsequent well” (as defined in the joint development agreement), in which they will pay their proportional share of agreed costs incurred; and (4) reduce the non-consent penalty for 10 specified wells from 200 percent to 150 percent in exchange for ExxonMobil agreeing not to elect the carry for reduced working interest option for these wells.

 

Average daily production for our West Texas properties increased three percent from 8,497 BOE/D in the fourth quarter of 2008 to 8,777 BOE/D in the fourth quarter of 2009. We believe these properties will be an area of growth over the next several years. During 2009, we drilled 21 gross wells and invested approximately $64.3 million of capital to develop these properties.

 

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. Average daily production for these properties decreased 30 percent from 6,732 Mcfe/D in the fourth quarter of 2008 to 4,742 Mcfe/D in the fourth quarter of 2009. During 2009, we drilled two gross wells and invested approximately $3.3 million of capital to develop these properties.

 

Mid-Continent Properties

 

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 western Arkansas. Our average daily production for these properties nearly tripled from 8,159 Mcfe/D in the fourth quarter of 2008 to 24,420 Mcfe/D for the fourth quarter of 2009. The increase in production was primarily due to our acquisition of the Nogre Marchand Unit and other properties in the Anadarko basin from EXCO in 2009. During 2009, we invested $6.7 million of development and exploration capital in these properties.

 

North Louisiana Salt Basin and East Texas Basin.  Our North Louisiana Salt Basin and East Texas Basin properties consist of operated working interests, non-operated working interests, and undeveloped leases and development in the Stockman, Danville, Gladewater, and Overton fields in east Texas. We purchased interests in the Gladewater and Overton fields from EXCO in 2009. Our interests in the Elm Grove Field in Bossier Parish, Louisiana include non-operated working interests ranging from one percent to 47 percent across 1,800 net acres in 15 sections.

 

ENCORE ACQUISITION COMPANY

 

Our 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 from 8,000 to 11,500 feet.

 

In the fourth quarter of 2008, we began our Haynesville shale drilling program with the spudding of the first Haynesville shale well at the Greenwood Waskom field in Caddo Parish, Louisiana. This well reached total depth in January 2009 ahead of schedule and was completed with an 11-stage fracture stimulation. Since entering the Haynesville play, we have accumulated over 18,000 gross acres.

 

During 2009, we drilled four gross wells and invested approximately $93.7 million of capital to develop these properties. Average daily production for these properties increased 30 percent from 36,239 Mcfe/D in the fourth quarter of 2008 to 47,104 Mcfe/D for the fourth quarter of 2009.

 

Rockies Properties

 

Big Horn Basin.  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 is characterized by oil and natural gas fields with long production histories and multiple producing formations. The Big Horn Basin is a prolific basin and has produced over 1.8 billion Bbls of oil since its discovery in 1906.

 

ENP also owns and operates (1) the Elk Basin natural gas processing plant near Powell, Wyoming, (2) the Clearfork crude oil pipeline extending from the South Elk Basin Field to the Elk Basin Field in Wyoming, (3) 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 (4) a 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 decreased seven percent from 4,212 BOE/D in the fourth quarter of 2008 to 3,934 BOE/D in the fourth quarter of 2009. During 2009, we invested approximately $1.0 million of capital to develop these properties.

 

Williston Basin.  Our Williston Basin properties have historically consisted of working and overriding royalty interests in several geographically concentrated fields. The properties are located in western North Dakota and eastern Montana, near our CCA properties. In April 2007, we acquired additional properties in the Williston Basin including 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 300,000 acres. During 2009, we drilled and completed six wells in the Bakken and Sanish. The Almond prospect contains 70,000 net acres and is located near the northeast border of Mountrail County, North Dakota.

 

Average daily production for these properties increased 11 percent from 6,919 BOE/D in the fourth quarter of 2008 to 7,708 BOE/D in the fourth quarter of 2009. During 2009, we drilled seven gross wells and invested approximately $81.2 million of capital to develop our Rockies properties.

 

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

 

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We invested $12.3 million of capital to develop these properties in 2009. Average daily production from these properties increased nine percent from 890 BOE/D in the fourth quarter of 2008 to 969 BOE/D in the fourth quarter of 2009.

 

In July 2009, we acquired a private company for $24 million, which procured a CO₂ supply intended to be used for a tertiary oil recovery project in the Bell Creek Field. The initial term of the CO₂ supply contract is 15 years. The CO₂ purchasable is not transportable as capture and compression facilities and a related pipeline need to be built. Until the CO₂ can be transported to the field and the capture, compression, and injection of the CO₂ proves economic, the contract has an unknown useful life. During 2009, we invested approximately $5.0 million of capital related to a pipeline which is intended to be used to transport this CO₂ supply to our Bell Creek field.

 

Paradox Basin.  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. We believe these properties have additional potential in horizontal redevelopment, secondary development, and tertiary recovery potential.

 

Average daily production for these properties increased approximately four percent from 631 BOE/D in the fourth quarter of 2008 to 658 BOE/D in the fourth quarter of 2009. During 2009, we invested approximately $3.1 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 previously discussed, a major portion of our acreage position in the CCA, our primary asset, is subject to net profits interests.

 

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.

 

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:

 

 

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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 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.

 

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We 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 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 have been used for oil and natural gas exploration and production for many years. There have been known releases of hazardous substances, wastes, or hydrocarbons at the properties, and some of these sites are undergoing active remediation. The risks associated with these environmental conditions, and the cost of remediation, were assumed by ENP, subject only to limited indemnity from the seller of the Elk Basin assets. Releases may also have occurred in the past that have not yet been discovered, which could require costly future remediation. In addition, ENP assumed the risk of various other unknown or unasserted liabilities associated with the Elk Basin assets that relate to events that occurred prior to ENP’s acquisition. If a significant release or event occurred in the past, the liability for which was not retained by the seller or for which indemnification from the seller is not available, it could adversely affect our results of operations, financial position, and cash flows.

 

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. ENP does not anticipate ceasing operations at the Elk Basin natural gas processing plant in the near future nor a need to commence remedial activities at this time. However, a regulatory agency could require ENP to investigate and remediate any contamination even while the gas plant remains in operation. As of December 31, 2009, ENP has recorded $4.7 million as future abandonment liability for decommissioning the Elk Basin natural gas processing plant. Due to the significant 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. ENP’s estimates of the future abandonment liability and compliance costs are subject to change and the actual cost of these items could vary significantly from those estimates.

 

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

 

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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 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.

 

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 atmosphere. In response to such studies, Congress is considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 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 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 Supreme 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

 

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comment. Our current exploration and production activities and planned exploration and development activities on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of our 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 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 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 2009, and, as of the date of this Report, we are not aware of any environmental issues or claims that will require material capital expenditures in the future. 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, the passage of more stringent laws or regulations in the future may 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 the 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 in order to

 

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

 

Natural Gas Gathering.  Section 1(b) of the Natural Gas Act (“NGA”), exempts natural gas gathering facilities from the jurisdiction of the Federal Energy Regulatory Commission (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 since 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. Our gathering operations could be adversely affected should they become subject to the application of state or federal regulation of rates and services. Our 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 our 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 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.

 

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 NGA to prohibit market manipulation and also amended NGA and the Natural Gas Policy Act of 1978 (“NGPA”) to increase civil and criminal penalties for any violations of NGA, NGPA, and any rules, regulations, or orders of the FERC to up to $1,000,000 per day, per violation. In 2006, the FERC issued a rule 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 rule works together with the FERC’s enhanced penalty authority to provide increased oversight of the natural gas marketplace.

 

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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 or credits may apply to certain types of wells and production methods.

 

In addition to production taxes, Texas and Montana each impose ad valorem taxes on oil and natural gas properties and production equipment. Wyoming and New Mexico impose an ad valorem tax on the gross value of oil and natural gas production in lieu of an ad valorem tax on the underlying oil and natural gas properties. Wyoming also imposes an ad valorem tax on production equipment. North Dakota imposes an ad valorem tax on gross oil and natural gas production in lieu of an ad valorem tax on the underlying oil and gas leases or on production equipment used on oil and gas leases.

 

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 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 Federal 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

 

As of December 31, 2009, we had a staff of 421 persons, including 35 engineers, 18 geologists, and 13 landmen, 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.

 

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 its public reference room at

 

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100 F Street, N.E., Room 1580, Washington, D.C. 20549. Information concerning the operation of the public reference room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website (www.sec.gov) that contains reports, proxy 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 officer and principal financial officer. 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 NYSE require us to disclose, we intend to disclose these events on our website.

 

Our Board has four standing committees: (1) audit; (2) compensation; (3) nominating and corporate governance; and (4) special stock award. Our Board committee charters, code of business conduct and ethics, and corporate governance guidelines are available on our website.

 

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

 

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You should carefully consider each of the following risks and all of the information provided elsewhere in this Report. If any of the risks described below or elsewhere in this Report were actually to occur, our business, financial condition, results of operations, or cash flows could be materially and adversely affected. In that case, we may be unable to pay interest on, or the principal of, our debt securities, the trading price of our common stock could decline, and you could lose all or part of your investment.

 

Failure to complete the Merger or delays in completing the Merger could negatively affect our stock price and future business and operations.

 

There is no assurance that we will be able to consummate the Merger. If the Merger is not completed for any reason, we may be subject to a number of risks, including the following:

 

 

Delays in completing the Merger could exacerbate uncertainties concerning the effect of the Merger, which may have an adverse effect on the business following the Merger and could defer or detract from the realization of the benefits expected to result from the Merger.

 

There may be substantial disruption to our business and distraction of our management and employees as a result of the Merger.

 

There may be substantial disruption to our business and distraction of our management and employees from day-to-day operations because matters related to the Merger may require substantial commitments of time and resources, which could otherwise have been devoted to other opportunities that could have been beneficial to us.

 

Business uncertainties and contractual restrictions while the Merger is pending may have an adverse effect on us.

 

Uncertainty about the effect of the Merger on employees, suppliers, partners, regulators, and customers may have an adverse effect on us. These uncertainties may impair our ability to attract, retain, and motivate key personnel until the Merger is consummated and could cause suppliers, customers, and others that deal with us to defer purchases or other decisions concerning us or seek to change existing business relationships with us. In addition, the Merger Agreement restricts us from making certain acquisitions and taking other specified actions without Denbury’s approval. These restrictions could prevent us from pursuing attractive business opportunities that may arise prior to the completion of the Merger.

 

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

 

Because our oil and natural gas properties are a depleting asset, 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

 

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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.

 

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

 

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

 

The oil and natural gas markets are very volatile, and we cannot accurately 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:

 

 

The worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with substantial losses in worldwide equity markets led to an extended worldwide economic slowdown in 2008 and 2009, which is expected to continue into 2010. The slowdown in economic activity has reduced worldwide demand for energy and resulted in lower oil and natural gas prices.

 

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:

 

 

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An increase in the differential between benchmark prices of oil and natural gas and the wellhead price we receive could adversely 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. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials. For example, the oil production from our Elk Basin assets has historically sold at a higher discount to NYMEX as compared to our Permian Basin assets due to competition from Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, and corresponding deep pricing discounts by regional refiners. Increases in differentials could significantly reduce our cash available for development of our properties and adversely affect our financial condition, results of operations, and cash flows.

 

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 revisions to our estimated 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 and goodwill. If we incur such impairment charges, 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. In addition, any write-downs that result in a reduction in our borrowing base could require prepayments of indebtedness under our revolving credit facility.

 

Our commodity derivative contract activities could result in financial losses or could reduce our income and cash flows. Furthermore, in the future, our commodity derivative contract positions may not adequately protect us from changes in commodity prices.

 

To reduce our exposure to fluctuations in the price of oil and natural gas, we enter into derivative arrangements for a significant portion of our forecasted oil and natural gas production. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities, as well as to the ability of counterparties under our commodity derivative contracts to satisfy their obligations to us. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual prices we realize on our production. Changes in oil and natural gas prices could result in losses under our commodity derivative contracts.

 

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:

 

 

ENCORE ACQUISITION COMPANY

 

 

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

 

We have oil and natural gas commodity derivative contracts covering a significant portion of our forecasted production for 2010. These contracts are intended to reduce our exposure to fluctuations in the price of oil and natural gas. We have a much smaller commodity derivative contract portfolio covering our forecasted production in 2011 and 2012. After 2010, and unless we enter into new commodity derivative contracts, our exposure to oil and natural gas price volatility will increase significantly each year as our commodity derivative contracts expire. We may not be able to obtain additional commodity derivative contracts on acceptable terms, if at all. Our failure to mitigate our exposure to commodity price volatility through commodity derivative contracts could have a negative effect on our financial condition and results of operation and significantly reduce our cash flows.

 

The counterparties to our derivative contracts may not be able to perform their obligations to us, which could materially affect our cash flows and results of operations.

 

As of December 31, 2009, we were entitled to future payments of approximately $61.0 million from counterparties under our commodity derivative contracts. The worldwide financial and credit crisis may have adversely affected the ability of these counterparties to fulfill their obligations to us. If one or more of our counterparties is unable or unwilling to make required payments to us under our commodity derivative contracts, it could have a material adverse effect on our 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. In estimating our oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to oil and natural gas prices, 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 classification 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, net abandonment, 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. The Standardized Measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved 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. 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 timing of both our production and our incurrence of expenses in connection with the development, production, and abandonment 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 may not be the most appropriate discount factor based

 

ENCORE ACQUISITION COMPANY

 

on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

 

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. If commodity prices decline, the cost of developing, completing and operating a well may not decline in proportion to the prices that we receive for our production, resulting in higher operating and capital costs as a percentage of oil and natural gas revenues. 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 revenue and profitability.

 

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

 

A significant portion of our production and reserves rely on secondary and tertiary recovery techniques. If production response is less than forecasted for a particular project, then the project may be uneconomic or

 

ENCORE ACQUISITION COMPANY

 

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.

 

Shortages of rigs, equipment, and crews could delay our operations.

 

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 have planned. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues.

 

If we do not make acquisitions, our future growth could 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:

 

 

Competition for acquisitions is intense and may increase the cost of, or cause us to refrain from, completing acquisitions. If we are unable to acquire properties with proved reserves, our total proved reserves could decline as a result of our production. 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.

 

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

 

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

 

 

ENCORE ACQUISITION COMPANY

 

 

 

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 fully assess 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 32 percent of our proved reserves as of December 31, 2009 and accounted for 25 percent of our 2009 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.

 

We depend on certain customers for a substantial portion of our sales. If these customers reduce the volumes of oil and natural gas they purchase from us, our revenues and cash available for distribution will decline to the extent we are not able to find new customers for our production.

 

For 2009, our largest purchaser was Eighty-Eight Oil, which accounted for 18 percent of our total sales of production. If customer, or any other significant customer, were to reduce the production purchased from us, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production.

 

Competition in the oil and natural gas industry is intense and many of our competitors have greater 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 financial, technical, and personnel resources substantially greater than us. Those companies may be able to develop and acquire more prospects and productive properties than our resources permit. Our ability to acquire additional properties and to discover reserves in

 

ENCORE ACQUISITION COMPANY

 

the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Some of our 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 resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These 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 could have a material adverse impact on our business activities, financial condition, and results of operations.

 

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, 2009, we had total consolidated debt of $1.2 billion and $889.7 million of consolidated available borrowing capacity under our revolving credit facilities. We have the ability to incur additional debt under our revolving credit facilities, subject to borrowing base limitations. Our future indebtedness could have important consequences to us, including:

 

 

Our ability to service our indebtedness depends upon, among other things, our future financial and operating performance, which is 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 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.

 

In addition, we are not currently permitted to offset the value of our commodity derivative contracts with a counterparty against amounts that may be owing to such counterparty under our revolving credit facilities.

 

We are unable to predict the impact of the recent downturn in the credit markets and the resulting costs or constraints in obtaining financing on our business and financial results.

 

U.S. and global credit and equity markets have recently undergone significant disruption, making it difficult for many businesses to obtain financing on acceptable terms. In addition, equity markets are continuing to experience wide fluctuations in value. If these conditions continue or worsen, our cost of borrowing may increase, and it may be more difficult to obtain financing in the future. In addition, an increasing number of financial institutions have reported significant deterioration in their financial condition. If any of the financial institutions are unable to perform their obligations under our revolving credit agreements and other contracts, and we are unable to find suitable replacements on acceptable terms, our results of operations, liquidity, and cash flows could be adversely affected. We also face challenges relating to the

 

ENCORE ACQUISITION COMPANY

 

impact of the disruption in the global financial markets on other parties with which we do business, such as customers and suppliers. The inability of these parties to obtain financing on acceptable terms could impair their ability to perform under their agreements with us and lead to various negative effects on us, including business disruption, decreased revenues, and increases in bad debt write-offs. A sustained decline in the financial stability of these parties could have an adverse impact on our business, results of operations, and liquidity.

 

Our revolving credit facilities have substantial restrictions and financial covenants that may restrict our business and financing activities.

 

The operating and financial restrictions and covenants in our revolving credit facilities and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand, or pursue our business activities.

 

Our ability to comply with the restrictions and covenants in our revolving credit facilities in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, or financial ratios in our revolving credit facilities, a significant portion of our indebtedness may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, obligations under our revolving credit facilities are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facilities, the lenders could seek to foreclose on our assets.

 

Our revolving credit facilities limit the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. Outstanding borrowings in excess of the borrowing base will be required to be repaid immediately, or we will be required to pledge other oil and natural gas properties as additional collateral.

 

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 weather and adverse economic conditions 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.

 

ENCORE ACQUISITION COMPANY

 

 

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 available 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.

 

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

 

Other companies operated approximately 21 percent of our properties (measured by total reserves) and approximately 44 percent of our wells as of December 31, 2009. 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.

 

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 Regulation” 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.

 

Possible regulations related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.

 

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to the warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of refined oil products and natural gas, are examples of greenhouse gases. The U.S. Congress is considering climate-related legislation to reduce emissions of greenhouse gases. In addition, at least 20 states have developed measures to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs. The EPA has adopted regulations requiring reporting of greenhouse gas emissions from certain facilities and is considering additional regulation of greenhouse gases as “air pollutants” under the CAA. Passage of climate change legislation or other regulatory initiatives by

 

ENCORE ACQUISITION COMPANY

 

Congress or various states, or the adoption of regulations by the EPA or analogous state agencies, that regulate or restrict emissions of greenhouse gases (including methane or carbon dioxide) in areas in which we conduct business could have an adverse effect our operations and the demand for oil and natural gas.

 

Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.

 

We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas production activities. In addition, we often indemnify sellers of oil and natural gas properties for environmental liabilities they or their predecessors may have created. These costs and liabilities could arise under a wide range of federal, state, and local environmental and safety laws and regulations, which have become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, imposition of cleanup and site restoration costs, liens and, to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.

 

Strict, joint, and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations, or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our profitability could be adversely affected.

 

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 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 holes, 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 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.

 

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. We intend to finance these capital expenditures through operating cash flows. However,

 

ENCORE ACQUISITION COMPANY

 

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.

 

The loss of key personnel could adversely affect our business.

 

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.

 

 

There were no unresolved SEC staff comments as of December 31, 2009.

 

 

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 business, financial condition, results of operations, or liquidity.

 

Litigation Related to the Merger

 

Three shareholder lawsuits styled as class actions have been filed against us and our Board related to the Merger. The lawsuits are entitled:

 

(1) Sanjay Israni, Individually and On Behalf of All Others Similarly Situated vs. Encore Acquisition Company et al. (filed November 4, 2009 in the District Court of Tarrant County, Texas);

 

(2) Teamsters Allied Benefit Funds, Individually and On Behalf of All Others Similarly Situated vs. Encore Acquisition Company et al. (filed November 5, 2009 in the Court of Chancery in the State of Delaware); and

 

(3) Thomas W. Scott, Jr., individually and on behalf of all others similarly situated v. Encore Acquisition Company et al. (filed November 6, 2009 in the District Court of Tarrant County, Texas).

 

The Teamsters and Scott lawsuits also name Denbury as a defendant. The complaints generally allege that (1) our directors breached their fiduciary duties in negotiating and approving the Merger and by administering a sale process that failed to maximize shareholder value and (2) we, and, in the case of the Teamsters and Scott complaints, Denbury aided and abetted our directors in breaching their fiduciary duties. The Teamsters complaint also alleges that our directors and executives stand to receive substantial financial benefits if the Merger is consummated on its current terms. The plaintiffs in these lawsuits seek, among other things, to enjoin the Merger and to rescind the Merger Agreement. We and Denbury have entered into a Memorandum of Understanding with the plaintiffs in these lawsuits agreeing in principle to the settlement of the lawsuits based upon inclusion in the joint proxy statement/prospectus of additional disclosures requested by the plaintiffs, and agreeing that the parties to the lawsuits will use best efforts to enter into a definitive settlement agreement and seek court approval for the settlement which would be binding on all of our shareholders who do not opt-out of the settlement.

 

 

There were no matters submitted to a vote of stockholders during the fourth quarter of 2009.

 

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Our common stock, par value $0.01 per share, is listed on the NYSE under the symbol “EAC.” The following table sets forth high and low sales prices of our common stock for the periods indicated:

 

 

On February 17, 2010, the closing sales price of our common stock as reported by the NYSE was $50.03 per share and we had approximately 418 shareholders of record. This number does not include owners for whom common stock may be held in “street” name.

 

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

 

In October 2008, we announced that the Board authorized a share repurchase program of up to $40 million of our common stock. As of December 31, 2009, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the fourth quarter of 2009, we did not repurchase any shares of our outstanding common stock under the share repurchase program. As of December 31, 2009, approximately $22.8 million of our common stock remained authorized for repurchase.

 

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 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.

 

ENCORE ACQUISITION COMPANY

 

Stock Performance Graph

 

The following graph compares our cumulative total stockholder return during the period from January 1, 2005 to December 31, 2009 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, 2005 and that all dividends, if any, were reinvested. The following graph is being furnished pursuant to SEC rules and 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, 2005 Among Encore
Acquisition Company, the Standard & Poor’s 500 Index, and the
Independent Oil and Gas Index

 

 

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The following table shows selected historical financial data for the periods and as of the periods indicated. 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”:

 

 

ENCORE ACQUISITION COMPANY