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10-K 1 d33392e10vk.htm FORM 10-K e10vk

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2005

Encore Acquisition Company

(Exact name of registrant as specified in its charter)


Delaware	001-16295	75-2759650
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

777 Main Street, Suite 1400, Fort Worth, Texas (Address of principal executive offices)		76102 (Zip Code)

Registrant’s telephone number, including area code:

(817) 877-9955

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered

Common Stock		New York Stock Exchange

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 of Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Exchange Act Rule 12b-2 of the Act).

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

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


Aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2005 (the last business day of Registrant’s most recently completed second fiscal quarter)	$	1,248,081,269
Number of shares of Common Stock, $0.01 par value, outstanding as of March 3, 2006		49,768,854

DOCUMENTS INCORPORATED BY REFERENCE

Parts of the definitive proxy statement for the Registrant’s 2006 annual meeting of stockholders are incorporated by reference into Part III of this report on Form 10-K.

ENCORE ACQUISITION COMPANY

2005 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS


		Page

PART I
Items 1 and 2.	Business and Properties		2
Item 1A.	Risk Factors		16
Item 1B.	Unresolved Staff Comments		24
Item 3.	Legal Proceedings		24
Item 4.	Submission of Matters to a Vote of Security Holders		24

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		25
Item 6.	Selected Financial Data		26
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		59
Item 8.	Financial Statements and Supplementary Data		64
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		97
Item 9A.	Controls and Procedures		97
Item 9B.	Other Information		99

PART III
Item 10.	Directors and Executive Officers of the Registrant		99
Item 11.	Executive Compensation		99
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		99
Item 13.	Certain Relationships and Related Transactions		100
Item 14.	Principal Accountant Fees and Services		100

PART IV
Item 15.	Exhibits and Financial Statement Schedules		101
Form of Restricted Stock Award - Executive
Form of Stock Option Agreement (Nonqualified)
Form of Stock Option Agreement (Incentive)
Table of 2006 Base Salaries for Executive Officers
Severance Agreement
Subsidiaries
Consent of Ernst & Young LLP
Consent of Miller & Lents, Ltd.
Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer)
Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer)
Section 1350 Certification (Principal Executive Officer)
Section 1350 Certification (Principal Financial Officer)

This annual report on Form 10-K (the “Report”) contains forward-looking statements, which give our current expectations and forecasts of future events. The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward-looking statements made by or on behalf of Encore Acquisition Company or its subsidiaries. See “Item 1A. Risk Factors” for a description of various factors that could materially affect the ability of Encore Acquisition Company 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 at the end of Item 7A, beginning on page 61, under the caption “Glossary of Oil and Natural Gas Terms.” In addition, all production and reserve volumes disclosed in this Report represent amounts net to Encore Acquisition Company.

PART I

Items 1 and 2. Business and Properties

General

Our Business. We are a growing independent energy company engaged in the acquisition, development, exploitation, exploration, and production of onshore North American oil and natural gas reserves. Since our inception in 1998, we have sought to acquire high quality assets with potential for upside through low-risk development drilling projects. Our properties — and our oil and natural gas reserves — are located in four core areas:


	•	the Cedar Creek Anticline (“CCA”) in the Williston Basin of Montana and North Dakota;

	•	the Permian Basin of West Texas and Southeastern New Mexico;

	•	the Mid-Continent area, which includes the Arkoma and Anadarko Basins of Oklahoma, the North Louisiana Salt Basin, the East Texas Basin, and the Barnett Shale of north Texas; and

	•	the Rockies, which includes non-CCA assets in the Williston and Powder River Basins of Montana and North Dakota, and the Paradox Basin of southeastern Utah.

Proved Reserves. Our estimated total proved reserves at December 31, 2005 were 148.4 MMBls of oil and 283.9 Bcf of natural gas, based on December 31, 2005 prices of $61.04 per Bbl for oil and $9.44 per Mcf of natural gas. On a barrel of oil equivalent basis, our proved reserves were 196 MMBOE at December 31, 2005, a 13% increase from proved reserves of 173 MMBOE at December 31, 2004.

Most Valuable Asset. The CCA represented 60% of our total proved reserves as of December 31, 2005. The CCA is our most valuable asset today and in the foreseeable future. A large portion of our future success revolves around future exploitation of and production from this property through primary, secondary, and tertiary recovery techniques.

Recent Acquisitions.

Mid-Continent and Permian Basin Acquisition. On November 30, 2005, we completed the acquisition of oil and natural gas producing properties from Kerr-McGee Corporation for a total purchase price of $101.4 million. The properties are located in the Levelland-Slaughter, Howard Glasscock, Nolley-McFarland, and Hutex fields in West Texas and the Oakdale, Calumet, and Rush Springs fields in western Oklahoma. Total proved reserves are estimated to be approximately 94% oil and 69% proved developed producing. Operating results for these properties are included in our Consolidated Statement of Operations for the month of December 2005.

Crusader Energy Corporation. On October 14, 2005, we purchased all of the outstanding capital stock of Crusader Energy Corporation (“Crusader”), a privately held, independent oil and natural gas company, for a total purchase price of $109.7 million, which includes cash paid to Crusader’s former shareholders of $79.2 million, the repayment of $29.7 million of Crusader’s debt, and transaction costs totaling $0.8 million.

The acquired properties are located primarily in the western Anadarko Basin and the Golden Trend area of Oklahoma. Total proved reserves are estimated to be approximately 78% natural gas and 72% proved developed producing. Crusader’s operating results are included in our Consolidated Statement of Operations for the period from October through December 2005.

Drilling. In 2005, we drilled 160 gross operated productive wells and participated in drilling another 116 gross non-operated productive wells for a total of 276 gross productive wells for the year. On a net basis, we drilled 151.9 operated productive wells and participated in 14.6 non-operated productive wells in 2005. We also drilled 51 (44.1 net) non-productive wells in 2005, of which 47 (41.9 net) were exploratory wells. We invested $326.5 million in development and exploration activities, of which $8.7 million related to non-productive wells.

Oil and Natural Gas Reserve Replacement During 2005, we added 33.0 MMBOE of oil and natural gas reserves, which replaced 318% of the 10.4 MMBOE we produced in 2005. Our three year average reserve replacement ratio is 345%. The following table sets forth our calculation of our 2005, 2004, 2003, and three year average reserve replacement ratios (in thousands of BOE except percentages):


			Year Ended December 31,
												Three Year
			2005			2004			2003			Average

Acquisition Reserve Replacement Ratio
Changes in Proved Reserves:
	Acquisitions of minerals-in-place			14,796			22,239			6,257			14,431
Divided by:
	Production			10,381			9,027			8,110			9,173

Acquisition reserve replacement ratio				142	%		246	%		77	%		157	%

Development Reserve Replacement Ratio
Changes in Proved Reserves:
	Extensions and discoveries			7,459			8,768			5,182			7,136
	Improved recovery			11,699			11,812			12,744			12,085
	Revisions of estimates			(928	)		(1,629	)		(3,493	)		(2,017	)

		Total development program		18,230			18,951			14,433			17,204
Divided by:
	Production			10,381			9,027			8,110			9,173

Development reserve replacement ratio				176	%		210	%		178	%		188	%

		Total Reserve Replacement Ratio
Changes in Proved Reserves:
	Acquisitions of minerals-in-place			14,796			22,239			6,257			14,431
	Extensions and discoveries			7,459			8,768			5,182			7,136
	Improved recovery			11,699			11,812			12,744			12,085
	Revisions of estimates			(928	)		(1,629	)		(3,493	)		(2,017	)

		Total reserve additions		33,026			41,190			20,690			31,635
Divided by:
	Production			10,381			9,027			8,110			9,173

Total reserve replacement ratio				318	%		456	%		255	%		345	%

For the three years ended December 31, 2005, we have invested $542.8 million in acquiring producing oil and natural gas properties, and we have invested an incremental $613.7 million on development, exploitation, and exploration of our properties.

Given the inherent decline of reserves resulting from production, it is important for an exploration and production company to demonstrate a long-term trend of more than offsetting produced volumes with new reserves that will provide for future production. Management uses the reserve replacement ratio, as defined above, as an indicator of our ability to replenish annual production volumes and grow our reserves, thereby providing some information on the sources of future production. Management believes that reserve replacement is relevant and useful information that is commonly used by analysts, investors and other interested parties in the oil and gas industry as a means of evaluating the operational performance and prospects of entities engaged in the production and sale of depleting natural resources. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not consider the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. The ratio does not distinguish between changes in reserve quantities that are developed and those that will require additional time and funding to develop.

Business Strategies

Our primary business objective is to maximize shareholder value by executing the following strategies:


	•	Maintain an active drilling and workover program. Our technological expertise, combined with our proficient field operations and reservoir engineering, has allowed us to increase production and reserves on our properties through development and exploitation drilling, workovers, and recompletions. Our plan is to maintain an inventory of low-risk exploitation and development projects that provide us ongoing drilling activity. Each year, we budget a portion of internally generated cash flow for secondary and tertiary recovery projects whose results will not be seen until future years.

	•	Maximize existing reserves and production through high-pressure air injection. In addition to conventional development programs, we utilize high-pressure air injection techniques on the CCA properties to enhance our growth. High-pressure air injection (“HPAI”) involves using compressors to inject air into producing oil and natural gas formations in order to displace remaining resident hydrocarbons and force them under pressure to a common lifting point for production. We believe that the HPAI programs on our CCA properties will generate a higher rate of return than other tertiary processes and can be applied throughout our CCA properties.

	•	Utilize other improved recovery techniques to maximize existing reserves and production. In addition to our HPAI programs, we use secondary and other tertiary recovery techniques to increase production and proved reserves on existing properties. Throughout our CCA properties and Permian Basin properties, we have successfully used waterflood enhancement programs to increase production. Waterflood enhancement is a secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells. In certain properties in the Rockies, a similar tertiary recovery technique involving CO₂ has added approximately 1.5 million BOE of proved reserves. We believe that these other improved recovery techniques will continue to be a significant growth area for us.

	•	Expand our reserves, production, and drilling inventory through a disciplined acquisition program. Using our experience, we have developed and refined an acquisition program designed to increase our reserves and to complement our core properties, while providing upside potential. We have a staff of engineering and geoscience professionals who manage our core properties and use their experience and expertise to target and evaluate attractive acquisition opportunities. Following an acquisition, our technical professionals seek to enhance the value of the new assets through a proven development and exploitation program. We will continue to evaluate acquisition opportunities in 2006 with the same disciplined commitment to acquire assets that fit our portfolio and create value for our shareholders.


	•	Explore for reserves. With the current commodity price environment, we believe exploration programs can provide a rate of return comparable to property acquisitions in certain areas. We seek to acquire undeveloped acreage and/or enter into drilling arrangements to explore in areas that complement our portfolio of properties. In keeping with our exploitation focus, the exploration projects are expected to set up multi-well exploitation projects if successful.

	•	Operate in a cost effective, efficient, and safe manner. As of December 31, 2005, we operated properties representing approximately 85% of our proved reserves, which allows us to control capital allocation, operate in a safe manner, and control timing of investments.

Challenges to Implementing Our Strategy. We face a number of challenges to implementing our strategy and achieving our goals. Our primary challenge is to generate superior rates of return on our investments in a volatile commodity pricing environment, while replenishing our drilling inventory. Changing commodity prices affect the rate of return on a property acquisition, and the amount of our internally generated cash flow, and, in turn, can affect our capital budget. In addition to the changing commodity price risk, we face strong competition from independents and major oil companies. For more information on the challenges to implementing our strategy and achieving our goals, please read “Item 1A. Risk Factors” beginning on page 16.

Operations

We act as operator of properties representing approximately 85% of our proved reserves at December 31, 2005. As operator, we are able to better control expenses, capital allocation, and the timing of exploitation and development activities of these properties. We also own properties that are operated by third parties, and, as working interest owners in those properties, we are required to pay our share of operating, exploitation and development costs. See “— Properties — Nature of Our Ownership Interests” on page 11. During the years ended December 31, 2005, 2004, and 2003, our approximate costs for development activities on non-operated properties were $28.2 million, $10.9 million, and $5.4 million, respectively. We also own royalty interests in wells operated by third parties that are not burdened by lease operations expense or capital costs; however, we have little control over the implementation of projects on these properties.

Production and Price History

The following table sets forth information regarding net production of oil and natural gas, certain price information, including the effects of hedging, and average costs per BOE for each of the periods indicated:


		As of December 31,

		2005		2004		2003

Production:
	Oil (MBbls)		6,871		6,679		6,601
	Natural gas (MMcf)		21,059		14,089		9,051
	Combined (MBOE)		10,381		9,027		8,110
Average Daily Production:
	Oil (Bbls/day)		18,826		18,249		18,085
	Natural gas (Mcf/day)		57,696		38,493		24,798
	Combined (BOE/day)		28,442		24,665		22,218
Average Prices:
	Oil (per Bbl)	$	44.82	$	33.04	$	26.72
	Natural gas (per Mcf)		7.09		5.53		4.83
	Combined (per BOE)		44.05		33.07		27.14
Average Costs per BOE:
	Lease operations expense	$	6.59	$	5.22	$	4.67
	Production, ad valorem, and severance taxes		4.39		3.36		2.71
	Depletion, depreciation and amortization		8.25		5.38		4.13
	Exploration		1.39		0.43		—
	General and administrative (excluding non-cash stock based compensation)		1.42		1.22		1.07
	Other operating expense		0.91		0.56		0.43

Producing Wells

The following table sets forth information at December 31, 2005 relating to the producing wells in which we owned a working interest as of that date. We also held royalty interests in units and acreage beyond the wells in which we have a working interest. Wells are classified as oil or natural gas according to their predominant production stream. Gross wells are the total number of producing wells in which we have an interest, and net wells are determined by multiplying gross wells by our average working interest. As of December 31, 2005, we owned a working interest in 5,332 gross wells.


		Oil Wells							Natural Gas Wells

						Average							Average
		Gross		Net		Working			Gross		Net		Working
		Wells(1)		Wells		Interest			Wells(1)		Wells		Interest

Cedar Creek Anticline			756		673		89	%		18		6		31	%
Permian Basin			1,811		486		27	%		483		223		46	%
Rockies			605		319		53	%		15		14		91	%
Mid-Continent			366		174		48	%		1,278		315		25	%

	Total		3,538		1,652		47	%		1,794		558		31	%


(1)	Our total wells include 2,449 operated wells and 2,883 non-operated wells. At December 31, 2005, 26 of our wells have multiple completions.

Acreage

The following table sets forth information at December 31, 2005 relating to our acreage holdings. Developed acreage is assigned to producing wells. Undeveloped acreage is 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. Our undeveloped acreage is concentrated in the Rockies region, which represents 71% of our total undeveloped acreage. These leases expire at various dates ranging from 2006 to 2029, with leases representing $1.6 million of cost set to expire in 2006 if not developed.


		Gross		Net
		Acreage		Acreage

Cedar Creek Anticline:
	Developed		111,189		103,333
	Undeveloped		83,242		61,204

			194,431		164,537

West Texas and New Mexico:
	Developed		63,772		38,856
	Undeveloped		13,567		12,842

			77,339		51,698

Rockies:
	Developed		58,880		35,778
	Undeveloped		407,181		340,332

			466,061		376,110

Mid-Continent:
	Developed		379,148		96,895
	Undeveloped		70,641		20,378

			449,789		117,273

Total:
	Developed		612,989		274,862
	Undeveloped		574,631		434,756

			1,187,620		709,618

Drilling Results

The following table sets forth information with respect to wells drilled during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found, or economic value. Development wells are wells drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. Exploratory wells are wells drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir. Productive wells are those that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return.


		Year Ended December 31,

		2005				2004				2003

		Gross		Net		Gross		Net		Gross		Net

Development Wells:
Productive			242		145		203		135		137		103
Dry holes			4		2		1		1		1		1

			246		147		204		136		138		104

Exploratory Wells:
Productive			34		22		32		30		—		—
Dry holes			47		42		4		4		—		—

			81		64		36		34		—		—

All Wells Drilled:
Productive			276		167		235		165		137		103
Dry holes			51		44		5		5		1		1

	Total		327		211		240		170		138		104

Present Activities

As of December 31, 2005 we had a total of 14 gross (8.4 net) wells that had been spud and were in varying stages of drilling operations, of which 9 gross (4.4 net) wells were development wells. Also, there were 50 gross (33.9 net) wells that had reached total depth and were in varying stages of completion pending first production, of which 10 gross (8.0 net) wells were exploratory wells.

High-pressure air injection in the Little Beaver unit of the CCA was initiated in late 2003, and full implementation of the project was completed in the fourth quarter of 2004. We continue to see positive production response in line with expectations, with an increase of 800 barrels of oil per day over the expected production decline prior to the initiation of the project.

In the Pennel unit of the CCA, where we have been operating a successful HPAI appraisal project (Phase 1) for nearly three years, we completed the Phase 2 portion of the project and are currently expanding to Phase 3. In April 2005, we installed a new HPAI facility capable of injecting 60 million cubic feet per day of air into the Pennel and Coral Creek units of the CCA, giving us the capacity to complete the development of these units. The Pennel Field is responding to the air injection as expected, with an increase of 400 barrels of oil per day over the expected production decline prior to the initiation of the project.

Delivery Commitments and Marketing

Our oil and natural gas production is principally sold to end users, marketers, refiners, and other purchasers having access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities. While we typically market our oil and natural gas production for a term of a year or less, we entered into an agreement in 2004 to sell at least 2,500 barrels of oil per day at a floating market price through 2009.

For the fiscal year 2005, our largest purchasers included Shell, Eighty-Eight Oil, BP, and Chevron, which respectively accounted for 26%, 16%, 14%, and 10% of total oil and natural gas sales. Our marketing of oil and natural gas can be affected by factors beyond our control, the potential effects of which cannot be accurately predicted. Management believes that the loss of any one purchaser would not have a material adverse effect on our ability to market our oil and natural gas production.

The sale of our CCA oil production is dependent on transportation through Butte Pipeline to markets in the Guernsey, Wyoming area. To a lesser extent, our production also depends on transportation through Platte Pipeline to Wood River, Illinois as well as other pipelines connected to the Guernsey, Wyoming area. While shipments on Platte Pipeline are currently oversubscribed and subject to apportionment since December 2005, we have been able to move our produced volumes through Platte Pipeline. However, further restrictions on the available capacity to transport oil through Platte Pipeline or other pipelines could have a material adverse effect on price received, production volumes, and revenues.

We expect the differential between the NYMEX price of crude oil and the wellhead price we receive to widen in the first half of 2006 as compared to the fourth quarter of 2005. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited takeaway capacity from the Rocky Mountain area, have gradually widened this differential. A particularly active turnaround season on the part of Rocky Mountain area refiners in the first quarter of 2006 has led to a further widening of the differential. We cannot accurately predict crude oil differentials for subsequent quarters. Natural gas differentials are expected to remain approximately constant in the first half of 2006 as compared to the fourth quarter of 2005. Increases in the differential between the NYMEX price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial position, and cash flows.

Competition

We compete with major and independent oil and natural gas companies. Some of our competitors have substantially greater financial and other resources than we do. In addition, larger competitors may be able to absorb the burden of any changes in federal, state, provincial, and local laws and regulations more easily than we can, adversely affecting our competitive position. Our competitors may be able to pay more for productive oil and natural gas properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than we can. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to acquire additional properties in the future will depend upon our ability to conduct efficient operations, evaluate and select suitable properties, implement advanced technologies, and consummate transactions in this highly competitive environment.

Federal and State Regulations

Compliance with applicable federal and state regulations is often difficult and costly, and non-compliance may result in substantial penalties. The following are some specific regulations that may affect us. We cannot predict the impact of these or future legislative or regulatory initiatives.

Federal Regulation of Natural Gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation rates and various other matters, by the Federal Energy Regulatory Commission (“FERC”). Federal wellhead price controls on all domestic natural gas were terminated on January 1, 1993 and none of our natural gas sales are currently subject to FERC regulation. We cannot predict the impact of future government regulation on any natural gas operations.

Although FERC’s regulations should generally facilitate the transportation of natural gas produced from our properties and the direct access to end-user markets, the future impact of these regulations on marketing our production or on our natural gas transportation business cannot be predicted. We do not believe, however, that we will be affected differently than competing producers and marketers.

Federal Regulation of Oil. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The net price received from the sale of these products is affected by market transportation costs. A significant part of our oil production is transported by pipeline. Under rules adopted by FERC effective January 1995, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. The United States Court of Appeals upheld FERC’s orders in 1996. These rules have had little effect on our oil transportation cost.

State Regulation. Oil and natural gas operations are subject to various types of regulation at the state and local levels. Such regulation includes requirements for drilling permits, the method of developing new fields, the spacing and operations of wells, and waste prevention. The production rate may be regulated and the maximum daily production allowable from oil and natural gas wells may be established on a market demand or conservation basis. These regulations may limit production by well and the number of wells that can be drilled.

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

Environmental Regulations. Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and natural gas exploration, development and production operations, and consequently may impact our operations and costs. Management believes that we are in substantial compliance with applicable environmental laws and regulations. To date, we have not expended any material amounts to comply with such regulations, and we do not currently anticipate that future compliance will have a material adverse effect on our consolidated financial position, cash flows, or results of operations.

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 operations. Any of these problems could adversely affect our ability to conduct operations and cause us to incur substantial losses. Such losses could reduce or eliminate the funds available for exploration, exploitation, or leasehold acquisitions or result in loss of properties.

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

Employees

We had 205 employees as of December 31, 2005, 75 of which were field personnel. None of the employees are represented by any union. We consider our relations with our employees to be good.

Principal Executive Office

We are a Delaware corporation with our headquarters in Texas. Our principal executive offices are 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 items filed with the SEC pursuant to Section 13(a) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with or furnish such material to the SEC. In addition, the public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a

website (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers, like us, that file electronically with the SEC.

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

We have filed the required certifications under Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2 to this Report. In 2005, we submitted to the NYSE the CEO certification required by Section 303A.12(a) of the NYSE’s Listed Company Manual. In 2006, we expect to submit this certification to the NYSE after the annual meeting of stockholders.

Our board of directors currently has three standing committees: (1) audit, (2) compensation, and (3) nominating and corporate governance. The charters of our board committees are available on our website. Copies of the code of business conduct and ethics and board committee charters are also available in print upon written request to the Corporate Secretary, Encore Acquisition Company, 777 Main Street, Suite 1400, Fort Worth, Texas 76102.

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

Financial information about our business for the three years ended December 31, 2005 can be found in our consolidated financial statements and the accompanying notes included in Item 8 of this Report.

Properties


	*Nature of Our Ownership Interests*

The following table sets forth the net production, proved reserve quantities, and PV-10 values of our properties in our principal areas of operation:


											Proved Reserve Quantities at						PV-10 at
		Net Production 2005									December 31, 2005						December 31, 2005

				Natural									Natural
		Oil		Gas		Total					Oil		Gas		Total		Amount(1)
		(MBbls)		(MMcf)		(MBOE)		Percent			(MBbls)		(MMcf)		MBOE		(In thousands)		Percent

Cedar Creek Anticline			4,868		1,237		5,074		49	%		113,701		16,870		116,513	$	1,424,876		53	%
Permian Basin			1,138		6,261		2,182		21	%		21,958		85,921		36,278		573,476		22	%
Mid-Continent			179		13,127		2,367		23	%		3,938		177,698		33,554		536,668		20	%
Rockies			686		434		758		7	%		8,790		3,376		9,353		143,953		5	%

	Total		6,871		21,059		10,381		100	%		148,387		283,865		195,698	$	2,678,973		100	%

(1)

Calculated as the pretax present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs; using prices and costs as of the date of estimation without future escalation; without giving effect to hedging activities, and non-property related expenses such as general and administrative expenses, debt service, and depletion, depreciation, and amortization; and discounted using an annual discount rate of 10%. Giving effect to hedging transactions, our PV-10 value would have been decreased by $128.4 million at December 31, 2005. The Standardized Measure at December 31, 2005 is $1.9 billion. Standardized Measure differs from PV-10 by $760.5 million because Standardized Measure includes the effect of asset retirement obligations and future income taxes.

The estimates of our proved oil and natural gas reserves are based on estimates prepared by Miller and Lents, Ltd., independent petroleum engineers. Guidelines established by the SEC regarding the present value of future net revenues were used to prepare these reserve estimates. Reserve engineering is a

subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by petroleum engineers. In addition, the results of drilling, testing and production activities may require revisions of estimates that were made previously. Accordingly, estimates of reserves and their value are inherently imprecise and are subject to constant revision and change, and they should not be construed as representing the actual quantities of future production or cash flows to be realized from oil and natural gas properties or the fair market value of such properties.

During the calendar year 2005, we filed estimates of oil and natural gas reserves at December 31, 2004 with the U.S. Department of Energy on Form EIA-23. As required for the EIA-23, the filing reflected only production that comes from our operated wells at year end, and is reported on a gross basis. Those estimates came directly from our reserve report prepared by Miller and Lents, Ltd., who are independent petroleum engineers.


	*Cedar Creek Anticline Properties — Montana and North Dakota*

Our initial purchase of interests in the CCA was on June 1, 1999, and we have subsequently acquired additional working interests from various owners. Presently, we operate approximately 99.7% of our CCA properties with an average working interest of approximately 89.3%. The average daily production from our CCA properties during 2005 was 13,902 BOE per day.

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 feet and 9,000 feet.

Since taking over operations, along with subsequent additional acquired interests, we have increased production by 80.3% on the CCA from 7,807 BOE per day (average for June 1999) to 14,078 BOE per day (average for the fourth quarter of 2005). We have accomplished ongoing production growth through a combination of:


	•	additional acquisition of interests;

	•	effective management of the existing wellbores;

	•	the addition of strategically positioned new horizontal and vertical wellbores;

	•	the application of horizontal re-entry drilling in existing wellbores;

	•	waterflood enhancements; and

	•	implementation of our high-pressure air injection program.

In 2005, we drilled 63 gross wells on the CCA, of which 33 were horizontal re-entry wells that reestablished production from non-producing wells, added additional barrels from existing producing wells and serve as injection wells for secondary and tertiary recovery projects. Including our HPAI project, we invested $121.7 million, $116.5 million, and $77.6 million in capital projects on the CCA during 2005, 2004, and 2003, respectively.

Our outlook for sustained CCA production growth remains strong. We plan to continue the development of the reserve base through ongoing drilling and exploitation efforts on these properties. We believe that HPAI continues to be our most significant source of sustained production growth on the CCA.

The CCA represents 60% of our total proved reserves as of December 31, 2005. The CCA represents our most valuable asset today and in the foreseeable future. A large portion of our future success revolves around future conventional exploitation, production, and success of HPAI projects on these properties.

High-pressure air injection. In 2005, we continued our high-pressure air injection program at the CCA. High-pressure air injection is a tertiary recovery technique that involves using compressors to inject air into oil and natural gas formations in order to displace remaining resident hydrocarbons and force them under pressure to a common lifting point for production.

In 2002, we initiated a HPAI project that injects air into the Red River U4 zone in the Pennel unit of the CCA. The Red River U4 zone is the same zone where high-pressure air injection has been successfully implemented by other operators in adjacent areas on the CCA. We have seen positive results from this high-pressure air injection project at the Pennel and the Little Beaver units. Based on these results, we are in the process of expanding high pressure air injection to other areas in the CCA. We believe that high-pressure air injection technology can be applied throughout the CCA and that it may yield significant new reserves. We believe that the high-pressure air injection will generate a higher rate of return than other tertiary processes on the CCA.

In the Pennel unit, we have completed Phase 1 and Phase 2 of the HPAI project and are currently expanding to Phase 3. In April 2005, we installed a new HPAI facility capable of injecting 60 million cubic feet per day of air into the Pennel and Coral Creek units of the CCA, giving us the capacity to complete the development of these units. The Pennel unit is responding to the air injection as expected, with an increase of 400 barrels of oil per day over the forecasted production decline prior to the initiation of the project.

High-pressure air injection in the Little Beaver unit of the CCA was initiated in late 2003, and full implementation of the project was completed in the fourth quarter of 2004. Through 2005, the program has added proved reserves of approximately 15 million BOE to the Little Beaver unit. We continue to see positive production response in line with expectations, with an increase of 800 barrels of oil per day over the forecasted production decline prior to the initiation of the project.

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

Net Profits Interests. A major portion of our acreage position in the CCA is subject to net profits interests (“NPI”) ranging from 1% to 50%. 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 drilling costs. The amounts of reserves and production calculated to be attributable to these net profits interests are deducted from our reserves and production data, and our revenues are reported net of NPI payments. The reserves and production that are attributed to the NPIs are calculated by dividing estimated future NPI payments (in the case of reserves) or prior period actual NPI payments (in the case of production) by the commodity prices current at the determination date. Fluctuations in commodity prices and the levels of development activities in the CCA from period to period will impact the reserves and production attributed to the NPIs and will have an inverse effect on our reported reserves and production. For the years ended December 31, 2005, 2004, and 2003, we reduced revenue for the payments of the net profits interests by $21.2 million, $12.6 million, and $5.8 million, respectively.


	*Permian Basin Properties — West Texas and New Mexico*

Our Permian Basin properties include seventeen operated fields, including East Cowden Grayburg Unit, Furhman-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, Glorietta, Clearfork, Wolfcamp, and Pennsylvanian zones. Production from the southern portion of the Permian Basin comes mainly from the Canyon and Strawn Formations with multiple pay intervals.

Continued development opportunities remain on these properties. During 2005, we drilled 80 gross wells on the Permian properties primarily in the Sand Hills, Furhman-Mascho, and Crockett County fields. Average daily production in the fourth quarter of 2005 was 5,806 BOE per day. We believe these properties will be an area of growth over the next several years.

During 2005, we invested approximately $44.0 million of development capital on our Permian Basin properties. In the fourth quarter of 2005, we acquired additional oil and natural gas producing properties in the Permian Basin from Kerr-McGee Corporation.


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


	Oklahoma, Arkansas, North Texas, and Kansas

We own various interests, including operated, non-operated, royalty and mineral interests, on properties located in the Anadarko Basin of western Oklahoma and the Arkoma Basin of eastern Oklahoma, and eastern Arkansas. These properties produce primarily natural gas, and to a lesser extent oil, from various horizons. We also have operated interests in properties producing from the Barnett Shale in north Texas, and interests in properties in the Hugoton Basin in Kansas.

Average daily production for the Oklahoma, Arkansas, North Texas, and Kansas region increased 124% from 11,284 Mcfe per day in the fourth quarter of 2004 to 25,317 Mcfe per day for the fourth quarter of 2005.

During 2005, we invested $52.2 million of development and exploration capital in these properties. In the fourth quarter of 2005, we acquired additional Mid-Continent properties through the acquisition of

Crusader Energy Corporation and the purchase of oil and natural gas producing properties from Kerr-McGee Corporation.


	North Louisiana Salt Basin and East Texas Basin

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

The Overton Field assets are in the same core area as our interests in Elm Grove Field and have similar geology. The properties are producing primarily from multiple tight sandstone reservoirs in the Travis Peak and Lower Cotton Valley formations at depths ranging between 8,000 and 11,500 feet. Estimated proved reserves are approximately 94% natural gas and the properties are 100% operated by us.

During 2005, we drilled 72 gross wells in the Elm Grove and Overton fields and invested approximately $91.4 million of capital to develop these properties. Average daily production for this region increased 68% from 15,366 Mcfe per day in the fourth quarter of 2004 to 25,800 Mcfe per day for the fourth quarter of 2005. We believe these properties continue to be an area of growth for us.


	*Rocky Mountain Properties — North Dakota, Montana, and Utah*


	Williston Basin — North Dakota and Montana

The Williston Basin properties consist of working and overriding royalty interests in several geographically concentrated fields. The properties are located in the Williston Basin in western North Dakota and eastern Montana, near our CCA properties. The properties produce exclusively from the Mississippian-aged Lodgepole Formation, and the Eland Unit is the largest accumulation in the trend. The average daily production from the Williston Basin properties was 1,191 BOE for the fourth quarter of 2005.

In 2005, we acquired additional working interests in the Williston Basin for approximately $28.6 million. Production from the properties, which are concentrated primarily in the Crane Field in Montana and the Tracy Mountain Field in North Dakota, is approximately 94% oil and 77% operated.


	Bell Creek — Montana

The Bell Creek properties are located in the Powder River Basin of southeastern Montana. We operate the seven production units that comprise the Bell Creek properties, each with a 100% working interest. The shallow (less than 5,000 feet) Cretaceous-aged Muddy Sandstone reservoir produces 100% oil. We invested $7.5 million of capital in these properties in 2005. The average daily production from the Bell Creek properties was 386 BOE per day during the fourth quarter of 2005. In the fall of 2005, we initiated a small field test of new technology called Microbial Enhanced Oil Recovery (MEOR) in conjunction with the State of Montana, MSE Technology Applications Center for Innovations and Montana Tech. This process may enhance oil production by creating a natural Bio-film which diverts injected water towards un-swept oil. We have not yet been able to ascertain the performance of this project but continue to monitor its progress.


	Paradox Basin — Utah

The Paradox Basin properties, located in southeast Utah’s Paradox Basin, are divided between two prolific oil producing units: the Ratherford Unit operated by ExxonMobil and the Aneth Unit operated by Resolute Natural Resources Company. Our average net production from the properties for the fourth quarter of 2005 was approximately 660 BOE per day. We believe these properties have potential horizontal redevelopment, secondary development, and tertiary recovery potential. During 2005, we added proved

reserves of 1.5 MMBOE from a CO₂ flood tertiary recovery program in the Aneth Unit. Our development capital for these properties was $0.7 million during 2005.


	Shallow Gas — Montana

In 2004, we began a project to explore for natural gas in the shallow zones of our acreage in north central Montana. The primary producing horizon in this area is the Eagle Sandstone, which produces from reservoir depths between 800 feet and 1,200 feet. This Eagle Sandstone has produced large quantities of natural gas to date from numerous fields across northern Montana. We invested $5.2 million of capital during 2005 to drill a total of 37 exploratory wells, all of which were subsequently expensed as dry holes in 2005. In addition, 8 additional exploratory wells drilled in 2004 were expensed as dry holes in 2005. We have 365,954 undeveloped leasehold acres with an average lease term of approximately 7.5 years. We plan to continue to drill and analyze this acreage in 2006 and future years.

The success rate of any future exploratory wells that we may drill in this area will be lower than our historical company average. Additionally, there can be no guarantee that reserves will be found in a sufficient quantity as to make them economically producible. If reserves are not found in a quantity that would make them economically producible, all costs to drill the well, as well as any related undeveloped leasehold costs associated with the lease on which the well was drilled, would be expensed in the period in which the determination was made.

Title to Properties

We believe that our title to our oil and natural gas properties is good and defensible 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:


	•	royalties, overriding royalties, net profit interests, and other burdens under oil and natural gas leases;

	•	contractual obligations, including, in some cases, development obligations arising under operating agreements, farmout agreements, production sales contracts, and other agreements that may affect the properties or their titles;

	•	liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors, and contractual liens under operating agreements;

	•	pooling, unitization and communitization agreements, declarations, and orders; and

	•	easements, restrictions, rights-of-way, and other matters that commonly affect property.

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


Item 1A.	*Risk Factors*

You should read carefully the following factors and all other information contained in this Report. If any of the risks and uncertainties described below or elsewhere in this Report actually occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our common stock could decline, and an investor may lose all or part of his investment.


	*Oil and natural gas prices are volatile and sustained periods of low prices could materially and adversely affect our financial condition, results of operations, and cash flows.*

Historically, the markets for oil and natural gas have been volatile, and these markets are likely to continue to be volatile in the future. Our revenues, profitability and future growth depend substantially on prevailing oil and natural gas prices. Lower oil and natural gas prices may reduce the amount of oil and natural gas that we can economically produce. Prevailing oil and natural gas prices also affect the amount

of internally generated cash flow available for repayment of indebtedness and capital expenditures. In addition, the amount we can borrow under our revolving credit facility is subject to periodic redetermination based in part on changing expectations of future oil and natural gas prices.

The factors that can cause oil and natural gas price volatility include:


	•	the supply of domestic and foreign oil and natural gas;

	•	the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels;

	•	political instability or armed conflict in oil or natural gas producing regions;

	•	the level of consumer demand;

	•	the proximity and capacity of oil and natural gas pipelines and other transportation facilities;

	•	refinery demands and customer preferences for different grades of crude oil;

	•	weather conditions;

	•	the price and availability of alternative fuels and technological advances affecting energy consumption;

	•	domestic and foreign governmental regulations and taxes;

	•	domestic political developments; and

	•	worldwide economic conditions.

In addition, 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. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited takeaway capacity from the Rocky Mountain area, have gradually widened this differential. A particularly active turnaround season on the part of Rocky Mountain area refiners in the first quarter of 2006 has led to a further widening of the differential. We cannot accurately predict future differentials.

The volatile nature of markets for oil and natural gas makes it difficult to reliably estimate future prices. Any decline in oil and natural gas prices adversely affects our financial condition. If oil or natural gas prices decline significantly or if our wellhead price is lowered materially in comparison to the NYMEX price for a sustained period of time, we may, among other things, be unable to meet our financial obligations, make planned expenditures or raise additional capital.


	Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.

Estimating quantities of proved oil and natural gas reserves is a complex process that requires interpretations of available technical data and numerous assumptions, including certain economic assumptions. Any significant inaccuracies in these interpretations or assumptions or changes in conditions could cause the quantities and net present value of our reserves to be overstated.

To prepare estimates of economically recoverable oil and natural gas reserves and future net cash flows, we must analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs. Actual results most likely will vary from our estimates. Any significant variance could reduce the estimated quantities and present value of our reserves.

You should not assume that the present value of future net cash flows from our proved reserves referred to in this Report is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate.


	*The results of high pressure air injection techniques are uncertain.*

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


	*We may be required to take write downs.*

We may be required to write down the carrying value of our oil and natural gas properties if (1) future estimated oil and natural gas prices are low, (2) we have substantial downward adjustments to our estimated proved reserves, (3) our estimates of operating expenses or development costs increase substantially, or (4) we experience poor performance from our development and exploitation activities. We capitalize the costs to acquire, find and develop our oil and natural gas properties under the successful efforts accounting method. We review the carrying value of our properties quarterly, based on changes in expectations of future oil and natural gas prices, expenses and tax rates. Once incurred, a write down of oil and natural gas properties is not reversible at a later date even if oil or gas prices increase.


	*Our acquisition strategy subjects us to numerous risks that could adversely affect our results of operations.*

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. Depending on conditions in the acquisition market, it may be difficult or impossible for us to identify properties for acquisition or we may not be able to make acquisitions on terms that we consider economically acceptable. Even if we are able to identify suitable acquisition opportunities, our acquisition strategy depends upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals.

The successful acquisition of producing properties requires an assessment of several factors, including:


	•	recoverable reserves;

	•	future oil and natural gas prices;

	•	operating costs; and

	•	potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We are often not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Possible 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 operating results. Furthermore, our financial position and results of operations may fluctuate significantly from period to period based on whether significant acquisitions are completed in particular periods. Competition for acquisitions is intense and may increase the cost of, or cause us to refrain from, completing acquisitions.


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

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


	•	diversion of management attention from existing operations;

	•	unexpected losses of key employees, customers and suppliers of the acquired business;

	•	conforming the financial, technological and management standards, processes, procedures and controls of the acquired business with those of our existing operations; and

	•	increasing the scope, geographic diversity and complexity of our operations.

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


	*A substantial portion of our producing properties is located in one geographic area.*

We have extensive operations in the Williston Basin of Montana and North Dakota. As of December 31, 2005, our CCA properties in the Williston Basin represented approximately 60% of our proved reserves and 49% of our 2005 production. Any circumstance or event that negatively impacts production or marketing of oil and natural gas in the Williston Basin could materially reduce our earnings and cash flow.


	*Derivative instruments expose us to risks of financial loss in a variety of circumstances.*

We use derivative instruments in an effort to reduce our exposure to fluctuations in the prices of oil and natural gas and to reduce our cash outflows related to interest. Our derivative instruments expose us to risks of financial loss in a variety of circumstances, including when:


	•	a counterparty to our derivative instruments is unable to satisfy its obligations;

	•	production is less than expected; or

	•	there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

Derivative instruments may limit our ability to realize increased revenue from increases in the prices for oil and natural gas.

We adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), on January 1, 2001. SFAS 133 generally requires us to record each hedging transaction as an asset or liability measured at its fair value. Each quarter we must record changes in the fair value of our hedges, which could result in significant fluctuations in net income and stockholders’ equity from period to period.

Fluctuations in the NYMEX price for oil or natural gas that do not coincide with changes in our wellhead price may preclude the use of hedge accounting and cause earnings volatility.

Many of our commodity derivative contracts are based on the NYMEX price for oil and natural gas. We have experienced increased ineffectiveness in our cash flow hedges, particularly those designated on our Rocky Mountain production, due to increasing differentials between our average oil wellhead price and the average NYMEX oil price. We expect those differentials to widen at least through the first half of 2006. Increasing differentials will result in additional ineffectiveness on some of our cash flow hedges. Additionally, if the correlation between changes in our average wellhead price and the average NYMEX oil price drops below a certain level, we would no longer be allowed to use hedge accounting for these cash flow hedges and would be required, instead, to use mark-to-market accounting. In such circumstances, any change in the mark-to-market value of our hedges would be recognized immediately in earnings as a non-cash charge and could cause significant earnings volatility.


	*The failure to replace our reserves could adversely affect our financial condition.*

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploitation, development, or exploration activities or acquire properties containing proved reserves, or both. We may not be able to find, develop or acquire additional reserves on an economic basis.

Substantial capital is required to replace and grow reserves. If lower oil and natural gas prices or operating difficulties result in our cash flow from operations being less than expected or limit on our ability to borrow under our revolving credit facility, we may be unable to expend the capital necessary to find, develop or acquire new oil and natural gas reserves.


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

Other companies operate some of the properties in which we have an interest. 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 drilling or acquisition activities and lead to unexpected future costs.


	*Drilling oil and natural gas wells is a high-risk activity.*

Drilling oil and natural gas wells involves numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. We often are uncertain as to the future cost or timing of drilling, completing and producing wells. We may not recover all or any portion of our investment in drilling oil and natural gas wells.

Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions or miscalculations, title problems, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, compliance with environmental and other governmental requirements and cost of, or shortages or delays in the availability of, drilling rigs, equipment and field personnel.


	*Our business involves many operating risks that can cause substantial losses; insurance may be unavailable or inadequate to protect us against these risks.*

Our operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as:


	•	fires;

	•	natural disasters;

	•	explosions;

	•	formations with abnormal pressures;

	•	blowouts;

	•	collapses of wellbore, casing or other tubulars;

	•	failure of oilfield drilling and service tools;

	•	uncontrollable flows of oil, natural gas, formation water or drilling fluids;

	•	pressure forcing oil or natural gas out of the wellbore at a dangerous velocity coupled with the potential for fire or explosion;

	•	changes in below-ground pressure in a formation that causes surface collapse or cratering;

	•	pipeline ruptures or cement failures;

	•	environmental hazards, such as oil spills, natural gas leaks and discharges of toxic gases; and

	•	weather.

If any of these events occur, we could incur substantial losses as a result of injury or loss of life; damage to and destruction of property, natural resources and equipment; pollution and other environmental damage; regulatory investigations and penalties; suspension of our operations; and repair and remediation costs.

We do not maintain insurance against the loss of oil or natural gas reserves as a result of operating hazards, nor do we maintain business interruption insurance. In addition, pollution and environmental risks generally are not fully insurable. We may experience losses for uninsurable or uninsured risks or losses in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations.


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

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


	*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 a combination of cash flow from operations and external financing arrangements. Additional financing sources may be required in the future to fund our capital expenditures. Financing may not continue to be available under existing or new financing arrangements, or on acceptable terms, if at all. If additional capital resources are not available,

we may be forced to curtail our drilling 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.*

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

Our drilling 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 some other professionals is extremely intense and the cost of attracting and retaining technical personnel has increased significantly in recent months. 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 effect our results of operations and financial condition.


	Our business depends 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 to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity could reduce our ability to market our oil and natural gas production and harm our business.


	*Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do.*

We operate in the highly competitive areas of oil and natural gas acquisition, development, exploitation and production. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies in each of the following areas:


	•	acquiring desirable producing properties or new leases for future exploration;

	•	marketing our oil and natural gas production;

	•	integrating new technologies; and

	•	acquiring the equipment and expertise necessary to develop and operate our properties.

Many of our competitors have financial, technological and other resources substantially greater than ours, which may adversely affect our ability to compete with these companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to

successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.


	*We are subject to complex federal, state and local laws and regulations that could adversely affect our business.*

Exploration, development, production and sale of oil and natural gas in North America are subject to extensive federal, state, provincial and local laws and regulations, including complex tax and environmental laws and regulations. We may be required to make large expenditures to comply with applicable laws and regulations, which could adversely affect our results of operations and financial condition. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection, reports concerning operations and taxation. Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, reclamation costs, remediation and clean-up costs and other environmental damages.

We do not believe that full insurance coverage for all potential environmental damages is available at a reasonable cost, and we may need to expend significant financial and managerial resources to comply with environmental regulations and permitting requirements. We could incur substantial additional costs and liabilities in our oil and natural gas operations as a result of stricter environmental laws, regulations and enforcement policies.

Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Further, these laws and regulations could change in ways that substantially increase our costs. Any of these liabilities, penalties, suspensions, terminations or regulatory changes could make it more expensive for us to conduct our business or cause us to limit or curtail some of our operations.


	*We have entered into, and may in the future enter into, long-term drilling and service contracts that may not be economical if oil and natural gas prices decline significantly.*

The level of exploration and development activity in the oil and natural gas industry depends, in part, on prevailing commodity prices. In periods of comparatively high commodity prices, the level of exploration and development activity increases as projects that may have been uneconomical at lower commodity prices become financially more attractive at higher commodity prices. An increase in exploration and development activity results in increased demand for drilling rigs and other oilfield services, which often translates into higher costs and more stringent contract terms for oil and natural gas companies. In the current environment of comparatively high commodity prices, we have entered into, and may in the future enter into, long-term contracts for drilling rigs and other oilfield services. If commodity prices decline significantly, projects that may have been economical at higher prices may no longer provide satisfactory rates of return to warrant their continued development. Even if we elect to forgo certain projects, however, we may still be obligated under long-term contracts to pay for drilling rigs and other oilfield services at prices that do not justify their continued use or that significantly reduce our rates of return. In periods of declining commodity prices, long-term contracts for drilling rigs and oilfield services entered into during periods of comparatively high commodity prices could have a material adverse effect on our results of operations, financial condition, and cash flows.


	We could incur substantial additional indebtedness, which could negatively impact our financial condition, results of operations and business prospects and prevent us from fulfilling our obligations under our outstanding debt.

As of December 31, 2005, we had total debt of $673.2 million and stockholders’ equity of $546.8 million. Together with our subsidiaries, we may incur substantially more debt in the future. Although our revolving credit facility, the indentures governing our 6¹/4%, 6%, and 7¹/4% notes contain restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with

these restrictions could be substantial. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness. As of December 31, 2005, we had approximately $420.0 million of available borrowing capacity under our revolving credit facility, subject to specific requirements, including compliance with financial covenants.

Our debt level could have several important consequences to you, including:


	•	we may have difficulties borrowing money in the future for acquisitions, to meet our operating expenses or for other purposes;

	•	the amount of our interest expense may increase because certain of our borrowings are at variable rates of interest, which, if interest rates increase, could result in higher interest expense;

	•	we will need to use a portion of the money we earn to pay principal and interest on our debt which will reduce the amount of money we have to finance our operations and other business activities;

	•	we may be more vulnerable to economic downturns and adverse developments in our industry; and

	•	our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which are beyond our control. Our earnings may not be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough money, we may be required to refinance all or part of our existing debt, sell assets, borrow more money or raise equity, which we may not be able to do on terms acceptable to us, if at all. Further, failing to comply with the financial and other restrictive covenants in our indebtedness could result in an event of default under such indebtedness, which could adversely affect our business, financial condition and results of operations.


Item 1B.	*Unresolved Staff Comments*

There were no unresolved Securities and Exchange Commission staff comments as of December 31, 2005.


Item 3.	*Legal Proceedings*

We are not currently a party to any material legal proceeding of which we are aware.


Item 4.	*Submission of Matters to a Vote of Security Holders*

There were no matters submitted to stockholders during the quarter ended December 31, 2005.

PART II


Item 5.	*Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities*

Our common stock, $0.01 par value, is listed on the NYSE under the symbol “EAC.” The following table sets forth quarterly high and low sales prices of our common stock for each quarterly period of 2005 and 2004, as adjusted retroactively to reflect a 3-for-2 stock split that occurred on July 12, 2005:


	High		Low

2005
Quarter ended December 31	$	39.37	$	29.69
Quarter ended September 30		39.48		28.63
Quarter ended June 30		29.63		22.12
Quarter ended March 31		30.48		21.44
2004
Quarter ended December 31	$	24.59	$	20.37
Quarter ended September 30		23.17		16.99
Quarter ended June 30		21.00		16.54
Quarter ended March 31		19.23		15.77

On March 3, 2006, the closing sales price of our common stock as reported by the NYSE was $32.08 per share. On March 3, 2006, we had approximately 262 shareholders of record.

Issuer Purchases of Equity Securities

The following table summarizes purchases of our common stock during the fourth quarter of 2005:


						Total Number of		Maximum Number
						Shares Purchased		of Shares That May
		Total Number				as Part of Publicly		Yet Be Purchased
		of Shares		Average Price		Announced Plans		Under the Plans or
Month		Purchased		Paid per Share		or Programs		Programs

October			—	$	—		—		—
November(a)			11,169	$	33.56		—		—
December			—	$	—		—		—

	Total		11,169	$	33.56		—		—


(a)	We do not have a formal common stock repurchase program. During the quarter ended December 31, 2005, certain employees surrendered shares of common stock to pay income tax withholding obligations in conjunction with vesting of restricted shares under our 2000 Incentive Stock Plan.

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 our board of directors 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 credit agreement and the indentures governing our subordinated notes. Future debt agreements may also restrict our ability to pay dividends.


Item 6.	*Selected Financial Data*

The following selected consolidated financial 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” (in thousands except per share and per unit data):


		Year Ended December 31,

		2005			2004			2003			2002			2001

Consolidated Statement of Operations Data:
Revenues:(1)
	Oil	$	307,959		$	220,649		$	176,351		$	134,854		$	105,768
	Natural gas		149,365			77,884			43,745			25,838			30,149

Total revenues		$	457,324		$	298,533		$	220,096		$	160,692		$	135,917

Net income		$	103,425	(4)	$	82,147		$	63,641	(2)	$	37,685		$	16,179	(3)

Net income per common share:(5)
	Basic	$	2.12		$	1.74		$	1.41		$	0.84		$	0.38
	Diluted		2.09			1.72			1.40			0.83			0.38
Weighted average number of common shares outstanding:(5)
	Basic		48,682			47,090			45,153			45,047			43,077
	Diluted		49,522			47,738			45,500			45,242			43,085
Consolidated Statement of Cash Flows Data:
Cash provided by (used in):
	Operating activities	$	292,269		$	171,821		$	123,818		$	91,509		$	80,212
	Investing activities		(573,560	)		(433,470	)		(153,747	)		(159,316	)		(89,583	)
	Financing activities		281,842			262,321			17,303			80,749			8,610
Production:
	Oil (Bbls)		6,871			6,679			6,601			6,037			4,935
	Natural gas (Mcf)		21,059			14,089			9,051			8,175			8,078
	Combined (BOE)		10,381			9,027			8,110			7,399			6,281
Average Sales Price:
	Oil ($/Bbl)	$	44.82		$	33.04		$	26.72		$	22.34		$	21.43
	Natural gas ($/Mcf)		7.09			5.53			4.83			3.16			3.73
	Combined ($/BOE)		44.05			33.07			27.14			21.72			21.64
Cost per BOE:
	Lease operations	$	6.59		$	5.22		$	4.67		$	4.15		$	4.00
	Production, ad valorem, and severance taxes		4.39			3.36			2.71			2.12			2.20
	Depletion, depreciation, and amortization		8.25			5.38			4.13			4.67			5.05
	Exploration		1.39			0.43			—			—			—
	General and administrative (excluding non-cash stock based compensation)		1.42			1.22			1.07			0.83			0.80
	Other operating expense		0.91			0.56			0.43			0.28			0.15
Reserves:
	Oil (Bbls)		148,387			134,048			117,732			111,674			91,369
	Natural gas (Mcf)		283,865			234,030			138,950			99,818			75,687
	Combined (BOE)		195,698			173,053			140,890			128,310			103,983


		As of December 31,

		2005			2004			2003			2002		2001

Consolidated Balance Sheet Data:
	Working Capital	$	(56,838	)	$	(15,566	)	$	(52	)	$	12,489	$	1,107
	Total assets		1,705,705			1,123,400			672,138			549,896		402,000
	Long-term debt		673,189			379,000			179,000			166,000		79,107
	Stockholders’ equity		546,781			473,575			358,975			296,266		269,302


(1)	For the years ended December 31, 2005, 2004, 2003, 2002, and 2001 we reduced revenue for the payments of the net profits interests by $21.2 million, $12.6 million, $5.8 million, $2.0 million, and $2.8 million, respectively.

(2)	Net income for the year ended December 31, 2003 includes $0.9 million income from the cumulative effect of accounting change, which affects its comparability with other periods presented.

(3)	Net income for the year ended December 31, 2001 includes $9.6 million of non-cash compensation expense, $4.3 million of bad debt expense, $1.6 million of impairment of oil and natural gas properties, and a $0.9 million charge for the cumulative effect of accounting change, which affects its comparability with other periods presented.

(4)	Net income for the year ended December 31, 2005 includes a $12.2 million charge for the early redemption of debt, which affects its comparability with other periods presented.

(5)	Net income per common share and the weighted-average number of common shares outstanding have been revised for years prior to 2005 for the effects of the 3-for-2 stock split that occurred on July 12, 2005.


Item 7.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

The following discussion and analysis of our consolidated financial position and results of operations should be read in conjunction with our financial statements and notes and the supplemental oil and natural gas disclosures included elsewhere in this Report. The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. The words “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should” and similar expressions identify forward-looking statements. Actual results could differ materially from those stated in the forward-looking statements. We do not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under the headings: “Information Concerning Forward-Looking Statements” beginning on page 58 and “Item 1A. Risk Factors” beginning on page 16.

Introduction

This management’s discussion and analysis of financial condition and results of operations is intended to provide investors with information regarding our financial condition and results of operations. The following will be discussed and analyzed:


	•	Overview of Business

	•	2005 Highlights

	•	Results of Operations


	•	Comparison of 2005 to 2004

	•	Comparison of 2004 to 2003


	•	Capital Resources

	•	Capital Commitments

	•	Liquidity

	•	Off-Balance Sheet Arrangements

	•	Inflation and Changes in Prices

	•	Critical Accounting Policies and Estimates

	•	New Accounting Standards

	•	Information Concerning Forward-Looking Statements

Overview of Business

We engage in the acquisition, development, exploitation, exploration, and production of onshore North American oil and natural gas reserves. Our business strategies include:


	•	Maintaining an active drilling and workover program;

	•	Maximizing existing reserves and programs through high-pressure air injection;

	•	Utilizing other improved recovery techniques to maximize existing reserves and production;

	•	Expanding our reserves, production, and drilling inventory through a disciplined acquisition program;

	•	Exploring for reserves; and

	•	Operating in a cost effective, efficient, and safe manner.

Our financial results and ability to generate cash depend upon many factors, particularly the price of oil and natural gas. Commodity prices continued to strengthen in 2005, with the average NYMEX prices increasing significantly in the past three years. The average oil price per barrel for the NYMEX futures market was $56.56, $41.26, and $31.04 for 2005, 2004, and 2003, respectively. The average natural gas price per MMBTU for the NYMEX futures market was $8.96, $6.11, and $5.50 for 2005, 2004, and 2003, respectively. Commodity prices are influenced by many factors that are outside of our control. We cannot predict future commodity benchmark or wellhead prices. For this reason, we attempt to mitigate the effect of commodity price risk by hedging a portion of our future production.

The significant increase in oil and natural gas prices over the past three years has continued to bid up the price of reserves to historically high levels. We closed two significant acquisitions during 2005. The purchase of Crusader Energy Corporation in October 2005 added substantial proved reserves to our Mid-Continent properties. The November 2005 acquisition of producing properties from Kerr-McGee Corporation also added substantial proved reserves to the Mid-Continent region and the Permian Basin in west Texas. Due to the rising cost of acquisitions, we are continuing to make significant investments within our core areas to develop proved undeveloped reserves and increase production from proved developed reserves through various secondary and tertiary recovery techniques, including our high-pressure air injection program in the CCA. We will, however, continue to evaluate acquisition opportunities as they arise and to the extent we believe we can realize a good rate of return to our shareholders.

We continue to believe that a portfolio of long-lived quality assets will position us for future success, and that reserve replacement is a key statistical measure of our success in growing our asset base. During 2005, we replaced 318% of our 2005 production. Our development program replaced 176% of production and acquisitions replaced 142% of production. See “Business and Properties — General — Oil and Natural Gas Production and Reserves” on page 3 for the calculation of our reserve replacement ratios.

Also in 2005, we continued to see positive results from our Phase I high-pressure air injection project at the Pennel unit and the Phase II implementation was completed in 2005. Pennel is the largest unit of the CCA units. In the Little Beaver unit at the southern end of the CCA, we continue to see positive production response in line with expectations with a 800 barrel per day increase over the forecast production decline prior to the initiation of the project. Our independent reserve engineers, Miller and Lents, Ltd. estimated that we added 3.2 million, 9.1 million and 12.5 million barrels, respectively, of proved undeveloped oil reserves associated with our high pressure air injection program at the end of 2005, 2004, and 2003. Over the long term, we believe that high-pressure air injection technology can be applied throughout the Cedar Creek Anticline.

2005 Highlights

Our financial and operating results for the year ended December 31, 2005 include the following:


	•	Oil and natural gas reserves increased 13% to 195.7 MMBOE. During 2005, we added 33.0 MMBOE, replacing 318% of the 10.4 MMBOE produced in 2005. See “Business and Properties — General — Oil and Natural Gas Production and Reserves” on page 3 for the calculation of our reserve replacement ratio. Oil reserves accounted for 76% of total proved reserves, and 71% of proved reserves are developed. The estimated pretax present value of our reserves increased by 65% to $2.7 billion (using a 10% discount rate and constant year end prices of $61.04 for oil and $9.44 for natural gas). The Standardized Measure at December 31, 2005 is $1.9 billion. Standardized Measure differs from PV-10 by $760.5 million, because Standardized Measure includes the effect of asset retirement obligations and future income taxes.

	•	During 2005, we had oil and natural gas revenues of $457.3 million. This represents a 53% increase over the $298.5 million of oil and natural gas revenues reported in 2004.

	•	We reported net income of $103.4 million, or $2.09 per diluted share, in 2005. This represents an increase of $21.3 million, or $0.37 per diluted share, over net income reported in 2004. Net income for 2005 was reduced due to a one-time $19.5 million loss on early redemption of debt related to

redemption premiums and the expensing of unamortized debt issuance costs related to our 8³/8% senior subordinated notes.

• Our realized average oil price for 2005, including the effects of hedging, increased $11.78 per Bbl to $44.82 per Bbl as compared to the 2004 average price of $33.04 per Bbl. Our realized average natural gas price for 2005, including the effects of hedging, increased $1.56 per Mcf to $7.09 per Mcf as compared to the 2004 average price of $5.53 per Mcf.

• Production volumes for 2005 increased 15% to 10,381 MBOE (28,442 BOE per day), compared with 2004 production volumes of 9,027 MBOE (24,665 BOE per day). The rise in production volumes was attributable to the continued success of our drilling program, uplift from our HPAI tertiary recovery project in the CCA, and acquisitions completed in 2004 and 2005. Oil represented 66% and 74% of our total production in 2005 and 2004, respectively.

• On July 13, 2005, we issued $300.0 million of 6% senior subordinated notes due 2015. We received net proceeds of approximately $294.5 million from the issuance and used approximately $165.9 million of the net proceeds to redeem all of the outstanding principal and related accrued interest of our 8³/8% senior subordinated notes. The remaining proceeds were used to reduce our indebtedness under our revolving credit facility.

• On November 23, 2005, we issued $150.0 million of 7¹/4% senior subordinated notes due 2017. We received net proceeds of approximately $148.5 million and used substantially all of the proceeds to reduce our indebtedness under our revolving credit facility.

• We invested $571.3 million in oil and natural gas activities during 2005 (excluding development-related asset retirement obligations). We invested $325.6 million in development, exploitation, HPAI expansion, and exploration activities, which yielded 327 gross (210.6 net) wells, and $245.7 million in acquiring proved properties and undeveloped leases during 2005 (excluding asset retirement obligations). In October 2005, we completed the acquisition of Crusader Energy Corporation, a privately held, independent oil and natural gas company for a purchase price of approximately $109.7 million. In November 2005, we acquired oil and natural gas properties from Kerr-McGee Corporation for approximately $101.4 million. In September 2005, we acquired oil and natural gas properties in the Williston Basin for approximately $28.6 million.

• During 2005, we improved our financial flexibility and liquidity by extending the maturity of our revolving credit facility to December 29, 2010 and increasing our borrowing base to $550.0 million. At December 31, 2005, we had $80.0 million outstanding under the revolving credit facility, $50.0 million in outstanding letters of credit, and available borrowing capacity of $420.0 million.

Results of Operations


	*Comparison of 2005 to 2004*

Below is a comparison of our results of operations for the year ended December 31, 2005 with the year ended December 31, 2004.

Revenues and Production. The following table illustrates the primary components of oil and natural gas revenue for the years ended December 31, 2005 and 2004, as well as each year’s respective oil and natural gas volumes (dollars in thousands except per unit and per day amounts):


			Year Ended December 31,
									*Increase/*
			2005			2004			(Decrease)

Revenues:
	Oil wellhead		$	350,837		$	255,394		$	95,443
	Oil hedges			(42,878	)		(34,745	)		(8,133	)

		Total Oil Revenues	$	307,959		$	220,649		$	87,310		40	%

	Natural gas wellhead		$	165,794		$	81,112		$	84,682
	Natural gas hedges			(16,429	)		(3,228	)		(13,201	)

		Total Natural Gas Revenues	$	149,365		$	77,884		$	71,481		92	%

	Combined wellhead		$	516,631		$	336,506		$	180,125
	Combined hedges			(59,307	)		(37,973	)		(21,334	)

		Total Combined Revenues	$	457,324		$	298,533		$	158,791		53	%

Revenues ($/Unit):
	Oil wellhead		$	51.06		$	38.24		$	12.82
	Oil hedges			(6.24	)		(5.20	)		(1.04	)

		Total Oil Revenues	$	44.82		$	33.04		$	11.78		36	%

	Natural gas wellhead		$	7.87		$	5.76		$	2.11
	Natural gas hedges			(0.78	)		(0.23	)		(0.55	)

		Total Natural Gas Revenues	$	7.09		$	5.53		$	1.56		28	%

	Combined wellhead		$	49.76		$	37.28		$	12.48
	Combined hedges			(5.71	)		(4.21	)		(1.50	)

		Total Combined Revenues	$	44.05		$	33.07		$	10.98		33	%

Total production volumes:
		Oil (Bbls)		6,871			6,679			192		3	%
		Natural gas (Mcf)		21,059			14,089			6,970		50	%
		Combined (BOE)		10,381			9,027			1,354		15	%
Daily production volumes:
		Oil (Bbls/day)		18,826			18,249			577		3	%
		Natural gas (Mcf/day)		57,696			38,493			19,203		50	%
		Combined (BOE/day)		28,442			24,665			3,777		15	%
Average NYMEX Prices:
		Oil (per Bbl)	$	56.56		$	41.26		$	15.30		37	%
		Natural gas (per Mcf)		8.96			6.11			2.85		47	%

Oil revenues increased $87.3 million from $220.6 million in 2004 to $308.0 million in 2005. The increase is due primarily to higher realized average oil prices which contributed approximately $80.0 million in additional revenues and an increase in oil production volumes of 192 MBbl which contributed approximately $7.3 million in additional revenues. The $80.0 million increase in revenues from higher realized average oil prices consists of an $88.1 million increase resulting from higher average wellhead oil prices, offset by increased hedging payments of $8.1 million, or $1.04 per Bbl. Our average wellhead oil price increased $12.82 per Bbl in 2005 over 2004 as a result of increases in the overall market price for oil as reflected in the increase in the average NYMEX price from $41.26 in 2004 to $56.56 in 2005.

Our oil wellhead revenue was reduced by $20.6 million and $12.3 million in 2005 and 2004, respectively, for the net profits interests payments related to our CCA properties.

Natural gas revenues increased $71.5 million from $77.9 million in 2004 to $149.4 million in 2005. The increase is due primarily to increased natural gas production volumes of 6,970 MMcf which contributed approximately $40.1 million in additional revenues and higher realized average natural gas prices which contributed approximately $31.4 million in additional revenues. The $31.4 million increase in revenues from higher realized average natural gas prices consists of a $44.6 million increase resulting from higher average wellhead natural gas prices, offset by increased hedging payments of $13.2 million, or $0.55 per Mcf. Our average wellhead natural gas price increased $2.11 per Mcf in 2005 over 2004 due to an increase in the overall market price of natural gas as reflected in the increase in the average NYMEX price from $6.11 in 2004 to $8.96 in 2005.

The prices we receive for our oil and natural gas production are largely based on current market prices, which are beyond our control. For comparability and accountability, we take a constant approach to budgeting commodity prices. We presently analyze our inventory of capital projects based on NYMEX prices of $55.00 per Bbl and $7.00 per Mcf. We do not assume any escalation of commodity prices when preparing our capital budget. If NYMEX prices trend downward below our base deck, we may reevaluate our capital projects. If commodity prices are significantly lower than our forecasted prices of $55.00 for oil and $7.00 for natural gas, it could have a material effect on our projected 2006 results. In this case, we would have to borrow additional money under our existing revolving credit facility, attempt to access the capital markets, or curtail the capital program. If drilling is curtailed or ended, future cash flows could be materially negatively impacted.

The table below illustrates the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices for the years ended December 31, 2005 and 2004. Management uses the wellhead to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.


		Year Ended
		December 31,

		2005			2004

Oil wellhead ($/Bbl)		$	51.06		$	38.24
Average NYMEX ($/Bbl)		$	56.56		$	41.26
	Differential to NYMEX	$	(5.50	)	$	(3.02	)
	Oil wellhead to NYMEX percentage		90	%		93	%

Natural gas wellhead ($/Mcf)		$	7.87		$	5.76
Average NYMEX ($/Mcf)		$	8.96		$	6.11
	Differential to NYMEX	$	(1.09	)	$	(0.35	)
	Natural gas wellhead to NYMEX percentage		88	%		94	%

In the fourth quarter of 2005, the oil wellhead to NYMEX price percentage decreased to as low as 88%. We expect this oil wellhead to NYMEX price percentage to decrease further in the first half of 2006 to approximately 75% to 80%. We attribute this widening to market conditions in the Rocky Mountain area, which is expected to adversely affect the wellhead price we receive in the CCA. In recent years,

production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited takeaway capacity from the Rocky Mountain area, have gradually widened the differential between our wellhead price and the benchmark NYMEX price at Cushing, Oklahoma. A particularly active turnaround season in the first quarter of 2006 on the part of the Rocky Mountain area refiners will lead to a further widening of the differential. We cannot accurately predict crude oil differentials for subsequent quarters.

In the fourth quarter of 2005, the natural gas wellhead to NYMEX price percentage decreased to as low as 75% due to pipeline capacity constraints. We expect that this natural gas wellhead to NYMEX price percentage will remain approximately constant in the first half of 2006.

Expenses. The following table summarizes our expenses for the years ended December 31, 2005 and 2004:


			Year Ended December 31,
							*Increase/*
			2005		2004		(Decrease)

Expenses (in thousands):
	Production —
		Lease operations	$	68,395	$	47,142	$	21,253
		Production, ad valorem, and severance taxes		45,601		30,313		15,288

	Total production expenses			113,996		77,455		36,541	47	%
	Other —
		Depletion, depreciation, and amortization		85,627		48,522		37,105
		Exploration		14,402		3,907		10,495
		General and administrative (excluding non-cash stock based compensation)		14,696		10,982		3,714
		Non-cash stock based compensation		3,962		1,770		2,192
		Derivative fair value loss		5,290		5,011		279
		Loss on early redemption of debt		19,477		—		19,477
		Other operating		9,485		5,028		4,457

	Total operating			266,935		152,675		114,260	75	%
	Interest			34,055		23,459		10,596
	Current and deferred income tax provision			53,948		40,492		13,456

Total expenses			$	354,938	$	216,626	$	138,312	64	%


			Year Ended December 31,
							*Increase/*
			2005		2004		(Decrease)

Expenses (per BOE):
	Production —
		Lease operations	$	6.59	$	5.22	$	1.37
		Production, ad valorem, and severance taxes		4.39		3.36		1.03

	Total production expenses			10.98		8.58		2.40		28	%
	Other —
		Depletion, depreciation, and amortization		8.25		5.38		2.87
		Exploration		1.39		0.43		0.96
		General and administrative (excluding non-cash stock based compensation)		1.42		1.22		0.20
		Non-cash stock based compensation		0.38		0.20		0.18
		Derivative fair value loss		0.51		0.56		(0.05	)
		Loss on early redemption of debt		1.88		—		1.88
		Other operating		0.91		0.56		0.35

	Total operating			25.72		16.93		8.79		52	%
	Interest			3.28		2.60		0.68
	Current and deferred income tax provision			5.20		4.49		0.71

Total expenses			$	34.20	$	24.02	$	10.18		42	%

Production expenses (Lease operations and production, ad valorem, and severance taxes). Total production expenses increased $36.5 million from $77.5 million in 2004 to $114.0 million in 2005. This increase resulted from an increase in total production volumes, as well as a $2.40 increase in production expenses per BOE. The 28% increase in total production expenses per BOE compares to a 33% increase in revenues per BOE due to a higher production margin (defined as revenues less production expenses) in 2005 as compared to 2004.

The production expense attributable to lease operations for 2005 increased as compared to 2004 by $21.3 million due to an increase in production volumes and an increase in the average per BOE rate. The increase in production volumes are the result of our 2005 drilling program; the 2005 and 2004 acquisitions, and our secondary and tertiary recovery programs, including the waterflood enhancement program and the high-pressure air injection program. These increased volumes resulted in approximately $7.1 million of additional lease operations expense. The increase in our average expense per BOE was attributable to increases in prices paid to oilfield service companies and suppliers due to a current higher price environment, increased operational activity to maximize production, and the operation of higher operating cost wells, which have become more attractive due to increases in oil and natural gas prices. This increased average per BOE rate resulted in approximately $14.2 million of additional lease operations expense for price escalation for services.

For 2006, we anticipate an increase in lease operations expense on both an aggregate and a per BOE basis. We anticipate the overall increase due to a full year of production at our properties acquired in 2005; further implementation of the high-pressure air injection program and a full year of production expenses related to the Little Beaver HPAI project; and the adoption of SFAS 123R. See “— Non-cash stock based compensation expense” below. In the third quarter of 2005, we began expensing HPAI production costs attributable to Little Beaver Phase I that previously were being capitalized during the pressurization phase.

The production expense attributable to production, ad valorem, and severance taxes (“production taxes”) for 2005 increased as compared to 2004 by $15.3 million due to an increase in production volumes and an increase in the average wellhead price we received for oil and natural gas production. The increase

in production volumes over 2004 resulted in approximately $4.5 million of additional production taxes. The average wellhead price we received for oil and natural gas revenues increased $12.48 per BOE, resulting in additional production taxes of approximately $10.8 million in 2005. As a percentage of oil and natural gas revenues (excluding the effect of hedges), production taxes for 2005 decreased slightly from 9.0% for 2004 to 8.8% for 2005. The effect of hedges is excluded from oil and natural gas revenues in the calculation of these percentages because this method more closely reflects the method used to calculate actual production taxes paid to taxing authorities.

For 2006, total production taxes will depend in a large part on prevailing oil and natural gas prices. However, the production tax rate should remain relatively constant at approximately 9.0% of wellhead revenues before hedging.

Depletion, depreciation, and amortization (“DD&A”) expense. DD&A expense increased $37.1 million from $48.5 million in 2004 to $85.6 million in 2005 due to a higher per BOE rate and increased production volumes. The per BOE rate increased $2.87 from 2004 due to the development of proved undeveloped reserves from the 2004 acquisitions, which do not increase total proved reserves, and higher drilling costs per BOE of reserves than our historical DD&A rate in certain areas. These factors resulted in additional DD&A expense of $29.8 million. The increase in production volumes of 1,352 MBOE over 2004 resulted in $7.3 million of additional DD&A expense.

We anticipate that total DD&A expense in 2006 will increase due to increased production and our planned 2006 capital expenditures of $320.0 million. We expect the invested capital to add barrels through the drill bit in 2006 at a cost higher than our historical DD&A rate. Assuming capital expenditures do not differ significantly from our budgeted amount, we expect our DD&A rate for 2006 to be higher per BOE. The DD&A rate could vary significantly based on actual capital expenditures, production rates, net profits interests, and any acquisitions that close in 2006. Additionally, changes in the market price for oil and natural gas could affect the level of our reserves.

Exploration expense. Exploration expense increased $10.5 million in 2005 as compared to 2004. During 2005, we expensed 47 exploratory dry holes totaling $8.6 million. Of the 47 exploratory dry holes expensed, 45 were drilled in the shallow gas area of Montana, 1 was drilled in the Permian Basin, and 1 was drilled in the CCA. In 2004, we expensed 4 exploratory dry holes at a cost of $2.0 million. In 2004, three of the exploratory dry holes were drilled in our Montana shallow gas area and one was drilled in the Barnett Shale in our Mid-Continent area. The following table details our exploration-related expenses (in thousands):


			Year Ended
			December 31,
							*Increase/*
			2005		2004		(Decrease)

Exploration expenses:
	Dry hole		$	8,632	$	2,050	$	6,582
	Geological and geophysical			1,247		425		822
	Seismic			1,849		553		1,296
	Delay rentals			635		204		431
	Impairment of unproved acreage			2,039		675		1,364

		Total	$	14,402	$	3,907	$	10,495

For 2006, we expect to continue to incur exploration expense as we continue our current exploration projects in the Mid-Continent and Montana shallow gas area. This amount could vary considerably, however, based on the success of these projects. Additionally, the adoption of SFAS 123R will increase exploration expense in 2006 for non-cash stock compensation both in total and per BOE. See “— Non-cash stock based compensation expense” below.

With the current commodity price environment, we believe exploration programs can provide a rate of return comparable or superior to property acquisitions in certain areas. We seek to acquire undeveloped

acreage and/or enter into drilling arrangements to explore in areas that complement our portfolio of properties. In keeping with our exploitation focus, the exploration projects are expected to set up multi-well exploitation projects if successful.

General and administrative (“G&A”) expense. G&A expense (excluding non-cash stock based compensation) increased $3.7 million from $11.0 million in 2004 to $14.7 million in 2005. The overall increase, as well as the $0.20 increase in the per BOE rate, is a result of increased staffing to manage our larger asset base, higher activity levels, and increased personnel costs due to intense competition for human resources within the industry.

We have forecast general and administrative expenses in 2006 to increase approximately 30% to 35% as compared to 2005. The increase from 2005 is expected to result from increased staffing to manage our larger asset base and continuing increases in the costs to hire and retain experienced industry personnel, as well as the effect of adoption of SFAS 123R, which will increase general and administrative expense in 2006 both in total and per BOE. See “— Non-cash stock based compensation expense” below.

Non-cash stock based compensation expense. Non-cash stock based compensation expense for 2005 increased $2.2 million from $1.8 million in 2004 to $4.0 million in 2005. This expense represents the amortization of deferred compensation recorded in equity related to restricted stock granted under our 2000 Incentive Stock Plan. Amortization of deferred compensation increased from 2004 primarily due to amortization recorded during 2005 related to 286,044 shares of restricted stock granted in 2005. In addition, certain restricted stock grants contain performance vesting provisions which require us to recognize periodic expense based on our current stock price, rather than the stock price at the day of grant. As a result, our higher stock price has also resulted in increased amortization expense.

During the years ended December 31, 2005, 2004, and 2003, we issued 130,854, 102,106, and 68,191 shares, respectively, of restricted stock to employees which depend only on continued employment for vesting. The following table illustrates by year of grant the vesting of these shares which remain outstanding at December 31, 2005:


		Year of Vesting

Year of Grant		2006		2007		2008		2009		2010		Total

2002			52,694		52,693		—		—		—		105,387
2003			19,569		19,522		19,522		—		—		58,613
2004			28,462		33,362		4,899		4,898		—		71,621
2005			5,511		5,511		42,367		36,793		36,793		126,975

	Total		106,236		111,088		66,788		41,691		36,793		362,596

During the years ended December 31, 2005, 2004, and 2003, we issued 155,190, 86,537, and zero shares of restricted stock to employees that not only depend on the passage of time and continued employment, but also on certain performance measures for their vesting. The following table illustrates by year of grant the vesting of these performance based shares which remain outstanding at December 31, 2005:


		Year of Vesting

Year of Grant		2006		2007		2008		2009		2010		Total

2004			—		25,832		25,828		25,828		—		77,488
2005			—		—		47,730		47,730		47,730		143,190

	Total		—		25,832		73,558		73,558		47,730		220,678

Total deferred compensation of $9.0 million was outstanding and included in Deferred Compensation in the accompanying Consolidated Balance Sheet as of December 31, 2005. Estimated amortization of deferred compensation is shown in the table below (in thousands) as of December 31, 2005:


		Estimated
		Amortization
Year Ended December 31,		Expense

2006		$	3,835
2007			2,918
2008			1,567
2009			617
2010			70

	Total	$	9,007

The estimated non-cash stock based compensation expense shown above is in part dependent on fluctuations in our stock price because, as noted above, certain awards are accounted for as variable awards as they are based on achievement of certain performance measures. Subsequent to December 31, 2005, we issued 389,922 shares of restricted stock to our employees as part of our annual incentive program.

Effective January 1, 2006, we adopted the provisions of Statement of Financial Accounting Standards No. 123R, “Share-Based Payment”, which requires that companies recognize in their financial statements the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. As a result, in 2006 we will recognize expense associated with stock options granted under our 2000 Incentive Stock Plan, which previously was only presented in pro forma disclosures. Total non-cash stock based compensation expense expected to be recorded in 2006, consisting of expense associated with both restricted stock and stock options, is approximately $10.0 million. This amount will not be reported separately on the Consolidated Statement of Operations but will be allocated to lease operations, exploration, and general and administrative expense.

Derivative fair value loss. During 2005, we recorded a $5.3 million derivative fair value loss as compared to a $5.0 million loss recorded in 2004. This derivative fair value loss represents the ineffective portion of the mark-to-market loss on our derivative hedging instruments, settlements received on our fixed-to-floating interest rate swaps, (gains) losses related to commodity derivatives not designated as hedges, and changes in the mark-to-market value of our fixed-to-floating interest rate swap. The components of the derivative fair value (gain) loss reported in 2005 and 2004 are as follows (in thousands):


			Year Ended
			December 31,
									*Increase/*
			2005			2004			(Decrease)

Designated cash flow hedges:
	Ineffectiveness — Commodity contracts		$	8,371		$	5,018		$	3,353
Undesignated derivative contracts:
	Mark-to-market (gain) loss — Interest rate swap			150			272			(122	)
	Mark-to-market (gain) loss — Commodity contracts			(3,231	)		(279	)		(2,952	)

		Total derivative fair value (gain) loss	$	5,290		$	5,011		$	279

Ineffectiveness loss related to our derivative commodity contracts designated as hedges increased $3.4 million due primarily to an increase in oil wellhead differentials on our production in the CCA. The interest rate swap loss decreased from 2004 due to the expiration of our fixed-to-floating interest rate swap in June 2005. The ineffectiveness loss is offset by a $3.2 million gain related to undesignated commodity contracts which increased due to changes in the fair value of certain natural gas basis swaps.

As we previously discussed, our oil wellhead differentials are expected to increase at least through the first half of 2006. For this reason, we expect derivative fair value loss to increase in 2006 from 2005 due to additional ineffectiveness on our designated cash flow hedges. Significant and sustained increases in our oil wellhead differential could preclude the application of hedge accounting to many of our derivative contracts, and should this occur, future mark-to-market gains or losses would be recognized as ‘Derivative fair value (gain) loss’ in the Consolidated Statements of Operations immediately. This could result in material fluctuations in net income and stockholders’ equity from period to period.

Loss on early redemption of debt. In 2005, we recorded a one-time $19.5 million loss on early redemption of debt related to the redemption premium and the write-off of unamortized debt issuance costs of our 8³/8% senior subordinated notes. We redeemed the 8³/8% notes with proceeds received from the issuance of our $300.0 million 6% senior subordinated notes in July 2005.

Other operating expense. Other operating expense increased $4.5 million from $5.0 million in 2004 to $9.5 million in 2005. This increase is mainly due to an increase in third party natural gas transportation costs attributable to higher production volumes for 2005 as compared to 2004.

For 2006, we anticipate other operating expense to increase over 2005, which reflects the increased transportation costs associated with higher expected production volumes.

Interest expense. Interest expense increased $10.6 million in 2005 as compared to 2004. The increase is primarily due to additional debt used to finance acquisitions and our capital program. We issued $150.0 million of 7¹/4% senior subordinated notes in November 2005, $300.0 million of 6% senior subordinated notes in July 2005, and $150.0 million of 6¹/4% senior subordinated notes in April 2004. We also redeemed $150.0 million of 8³/8% senior subordinated notes in August 2005. The weighted average interest rate, net of hedges, for 2005 was 6.8% as compared to 7.7% for 2004. This lower weighted average interest rate is the result of the debt issuances which have rates lower than our historical average rate.

The following table illustrates the components of interest expense for 2005 and 2004 (in thousands):


		Year Ended
		December 31,
						*Increase/*
		2005		2004		(Decrease)

8³/8 senior subordinated notes due 2012		$	7,852	$	12,563	$	(4,711	)
6¹/4% senior subordinated notes due 2014			9,375		7,005		2,370
6% senior subordinated notes due 2015			8,437		—		8,437
7¹/4% senior subordinated notes due 2017			1,145		—		1,145
Revolving credit facility			4,554		1,565		2,989
Letters of credit			615		170		445
Interest rate hedges			42		546		(504	)
Debt issuance costs amortization			979		969		10
Banking fees and other			847		641		206
Debt discount amortization			209		—		209

	Total	$	34,055	$	23,459	$	10,596

We have forecast interest expense to increase in 2006 as compared to 2005. The increase from 2005 is primarily due to higher levels of debt resulting from the senior subordinated note issuances in 2005. This forecast could vary considerably as future acquisitions may be funded with our revolving credit facility or new debt issuances.

Income taxes. Income tax expense for 2005 increased $13.5 million from 2004. This increase is due primarily to an increase of $34.7 million in income before income taxes. Our effective tax rate increased slightly in 2005 to 34.3% from 33.0% in 2004.

As of December 31, 2005, we had generated approximately $13.2 million of Section 43 credits related to our HPAI program. If unused, $2.0 million of the Section 43 credits will expire in 2023, $6.1 million in 2024, and $5.1 million in 2025.

To the extent our drilling and development activities continue to be greater than our cash flows for operating activities, we expect to pay immaterial amounts of current income taxes in 2006 with the largest percentage of our tax expense being deferred.


	*Comparison of 2004 to 2003*

Below is a comparison of our results of operations for the year ended December 31, 2004 with the year ended December 31, 2003.

Revenues and Production. The following table illustrates the primary components of oil and natural gas revenue for the years ended December 31, 2004 and 2003, as well as each year’s respective oil and natural gas volumes (dollars in thousands except per unit and per day amounts):


			Year Ended
			December 31,
									*Increase/*
			2004			2003			(Decrease)

Revenues:
	Oil wellhead		$	255,394		$	190,203		$	65,191
	Oil hedges			(34,745	)		(13,852	)		(20,893	)

		Total Oil Revenues	$	220,649		$	176,351		$	44,298		25	%

	Natural gas wellhead		$	81,112		$	45,218		$	35,894
	Natural gas hedges			(3,228	)		(1,473	)		(1,755	)

		Total Natural Gas Revenues	$	77,884		$	43,745		$	34,139		78	%

	Combined wellhead		$	336,506		$	235,421		$	101,085
	Combined hedges			(37,973	)		(15,325	)		(22,648	)

		Total Combined Revenues	$	298,533		$	220,096		$	78,437		36	%

Revenues ($/Unit):
	Oil wellhead		$	38.24		$	28.82		$	9.42
	Oil hedges			(5.20	)		(2.10	)		(3.10	)

		Total Oil Revenues	$	33.04		$	26.72		$	6.32		24

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		redemption premiums and the expensing of unamortized debt issuance costs related to our 8³/8% senior subordinated notes.

	•	Our realized average oil price for 2005, including the effects of hedging, increased $11.78 per Bbl to $44.82 per Bbl as compared to the 2004 average price of $33.04 per Bbl. Our realized average natural gas price for 2005, including the effects of hedging, increased $1.56 per Mcf to $7.09 per Mcf as compared to the 2004 average price of $5.53 per Mcf.

	•	Production volumes for 2005 increased 15% to 10,381 MBOE (28,442 BOE per day), compared with 2004 production volumes of 9,027 MBOE (24,665 BOE per day). The rise in production volumes was attributable to the continued success of our drilling program, uplift from our HPAI tertiary recovery project in the CCA, and acquisitions completed in 2004 and 2005. Oil represented 66% and 74% of our total production in 2005 and 2004, respectively.

	•	On July 13, 2005, we issued $300.0 million of 6% senior subordinated notes due 2015. We received net proceeds of approximately $294.5 million from the issuance and used approximately $165.9 million of the net proceeds to redeem all of the outstanding principal and related accrued interest of our 8³/8% senior subordinated notes. The remaining proceeds were used to reduce our indebtedness under our revolving credit facility.

	•	On November 23, 2005, we issued $150.0 million of 7¹/4% senior subordinated notes due 2017. We received net proceeds of approximately $148.5 million and used substantially all of the proceeds to reduce our indebtedness under our revolving credit facility.

	•	We invested $571.3 million in oil and natural gas activities during 2005 (excluding development-related asset retirement obligations). We invested $325.6 million in development, exploitation, HPAI expansion, and exploration activities, which yielded 327 gross (210.6 net) wells, and $245.7 million in acquiring proved properties and undeveloped leases during 2005 (excluding asset retirement obligations). In October 2005, we completed the acquisition of Crusader Energy Corporation, a privately held, independent oil and natural gas company for a purchase price of approximately $109.7 million. In November 2005, we acquired oil and natural gas properties from Kerr-McGee Corporation for approximately $101.4 million. In September 2005, we acquired oil and natural gas properties in the Williston Basin for approximately $28.6 million.

	•	During 2005, we improved our financial flexibility and liquidity by extending the maturity of our revolving credit facility to December 29, 2010 and increasing our borrowing base to $550.0 million. At December 31, 2005, we had $80.0 million outstanding under the revolving credit facility, $50.0 million in outstanding letters of credit, and available borrowing capacity of $420.0 million.