10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________________________________________________

FORM 10-K

S Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2011

Commission file number 1-9735

BERRY PETROLEUM COMPANY

(Exact name of registrant as specified in its charter)

DELAWARE (State of incorporation or organization) 77-0079387 (I.R.S. Employer Identification Number)

1999 Broadway

Suite 3700

Denver, Colorado 80202

(Address of principal executive offices, including zip code)

Registrant's telephone number, including area code:

(303) 999-4400

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

Title of each class	Name of each exchange on which registered
Class A Common Stock, $0.01 par value (including associated stock purchase rights)	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 ý    NO o

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

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 ý    NO o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES ý    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. ý

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

Large accelerated filer ý Accelerated filer o Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES o NO ý

As of June 30, 2011, the aggregate market value of the voting and non-voting common stock held by non-affiliates was $2,583,421,226.

As of February 14, 2012, the registrant had 52,150,685 shares of Class A Common Stock outstanding. The registrant also had 1,797,784 shares of Class B Stock outstanding on February 14, 2012, all of which are held by an affiliate of the registrant.

DOCUMENTS INCORPORATED BY REFERENCE

Part III is incorporated by reference from the registrant's definitive Proxy Statement for its Annual Meeting of Shareholders to be filed, pursuant to Regulation 14A, no later than 120 days after the close of the registrant's fiscal year.

BERRY PETROLEUM COMPANY

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	1
	General	1
	Business Strategy and Strengths	1
	Acquisition and Divestiture Activities	2
	Properties	2
	Reserves	4
	Production, Average Sales Prices, and Production Costs	6
	Productive Wells and Acreage	6
	Future Acreage Expirations	6
	Drilling Activity	7
	Marketing and Customers	7
	Steaming Operations	8
	Electricity	10
	Competition	11
	Titles to Properties	11
	Employees	11
	Offices	12
	Available Information	12
	Environmental and Other Regulations	12
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	25
Item 2.	Properties	25
Item 3.	Legal Proceedings	25
Item 4.	Mine Safety Disclosure	25
	Executive Officers	26
PART II
Item 5.	Market for the Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	28
Item 6.	Selected Financial Data	30
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	31
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 8.	Financial Statements and Supplementary Data	52
	Report of Independent Registered Public Accounting Firm	53
	Balance Sheets	54
	Statements of Operations	55
	Statements of Shareholders' Equity	56
	Statements of Cash Flows	57
	Notes to Financial Statements	58
	Supplemental Information About Oil & Natural Gas Activities (unaudited)	86
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	90
Item 9A.	Controls and Procedures	90
Item 9B.	Other Information	91
PART III
Item 10.	Directors and Executive Officers and Corporate Governance	92
Item 11.	Executive Compensation	92
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	92
Item 13.	Certain Relationships and Related Transactions, and Director Independence	92
Item 14.	Principal Accounting Fees and Services	92
PART IV
Item 15.	Exhibits, Financial Statement Schedules	93

i

Forward Looking Statements

"Safe harbor under the Private Securities Litigation Reform Act of 1995:" Any statements in this Annual Report on Form 10-K that are not historical facts are forward-looking statements that involve risks and uncertainties. Words or forms of words such as "will," "might," "intend," "continue," "target," "expect," "achieve," "strategy," "future," "may," "could," "goal," "forecast," "anticipate," "estimate," or other comparable words or phrases, or the negative of those words, and other words of similar meaning, indicate forward-looking statements and important factors which could affect actual results. Forward-looking statements are made based on management's current expectations and beliefs concerning future developments and their potential effects upon Berry Petroleum Company. These items are discussed at length in Part I, Item 1A. in this Annual Report on Form 10-K, under the heading "Risk Factors."

PART I

Item 1.    Business

General

We are an independent energy company engaged in the production, development, exploitation and acquisition of oil and natural gas. We were incorporated in Delaware in 1985. We have been publicly traded since 1987 and trace our roots in California oil production back to 1909. Since 2002, we have expanded our portfolio of assets through selective acquisitions driven by a consistent focus on properties with proved reserves and significant growth potential through low risk development. Our principal reserves and producing properties are located in California, Texas (the Permian and E. Texas), Utah (Uinta) and Colorado (Piceance).

We operate in one industry segment, which is the production, development, exploitation and acquisition of oil and natural gas, and all of our operations are conducted in the United States. Consequently, we currently report a single industry segment. See Item 8. Financial Statements and Supplementary Data for financial information about this industry segment. Information contained in this Annual Report on Form 10-K reflects our business during the year ended December 31, 2011, unless noted otherwise.

Business Strategy

Our business strategy is to increase shareholder value by efficiently increasing production, reserves and cash flow, both through the drill bit and through acquisitions. We believe our inventory of drilling locations is ideally suited to growing production, reserves and cash flow due to predictable geology. Our strategy is based on the following:

• Pursuing the development of projects that we believe will generate attractive rates of return;

• Maintaining a balanced portfolio of long-lived oil and natural gas properties that provide stable cash flows;

• Maximizing production from our base oil assets;

• Selectively acquiring properties with an emphasis on oil; and

• Maintaining a strong financial position by investing our capital in a disciplined manner.

Business Strengths

We believe that the following strengths allow us to successfully execute our business strategy:

Low-Risk Multi-Year Drilling Inventory in Established Crude Oil Plays. We have a significant number of drilling locations in established crude oil plays that possess low geologic risk, leading to relatively predictable drilling results. Our complementary mix of primary development locations as well as heavy oil thermal projects provide high operating margins and the financial flexibility to respond to commodity price environments and localized operating environments.

Balanced High Quality Asset Portfolio. Since 2002, we have grown our asset base and diversified our portfolio through acquisitions in the Permian and Uinta. Our portfolio provides us with the flexibility to allocate capital among a diverse set of high return oil assets.

Long-Lived Proved Reserves with Stable Production Characteristics. Our properties generally have long reserve lives and reasonably stable and predictable well production characteristics, with a ratio of proved reserves to production of approximately 21 years as of December 31, 2011.

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Operational Control and Financial Flexibility. We exercise operating control over approximately 92% of our assets. We generally prefer to retain operating control over our properties, allowing us to more effectively control operating costs, timing of development activities and technological enhancements, marketing of production and allocation of our capital budget. In addition, the timing of most of our capital expenditures is discretionary, which allows us a significant degree of flexibility to adjust the size of our capital budget. We finance our drilling and development budget primarily through our internally generated operating cash flows.

Experienced Management and Operational Teams. Our core team of technical staff and operating managers has broad industry experience, including experience in heavy oil thermal recovery operations and unconventional reservoir development and completion. We continue to utilize technologies and steam practices that we believe will allow us to improve the ultimate recovery of crude oil on our California properties.

Acquisition and Divestiture Activities

The following sets forth our significant acquisitions and divestures over the last several years:

2011 Acquisitions. In 2011, we made multiple acquisitions, each of which involved interests in properties located primarily in the Permian, for an aggregate of approximately $158.1 million.

2010 Acquisitions. In 2010, we made multiple acquisitions, each of which involved interests in properties located primarily in the Permian, for an aggregate of approximately $334.4 million.

2009 Divestitures. In 2009, we sold all of our interest in our assets in the Denver-Julesburg basin in Colorado (DJ) for approximately $139.8 million.

Properties

The following table provides information regarding our operations by area as of December 31, 2011:

Name, State	Total Net Acres		Proved Reserves (MMBOE)(1)	Proved Developed Reserves (MMBOE)(1)	Proved Undeveloped Reserves (MMBOE)(1)	2011 Gross Wells(2)		2011 Net Wells(2)
S. Midway, CA	3,913		58.0	50.9	7.1	40		40
N. Midway, CA	2,657		62.4	34.0	28.4	208		208
Permian, TX	41,793		56.9	16.5	40.4	97	(4)	69
Uinta, UT	99,723	(3)	23.2	13.3	9.9	54		45
Piceance, CO	8,077		55.0	11.9	43.1	5		5
E. Texas	4,671		19.4	18.2	1.2	—		—
Totals	160,834		274.9	144.8	130.1	404		367

_______________________________________________________________________________

(1) MMBOE—Million BOEs.

(2) Represents gross and net productive wells drilled during 2011.

(3) Excludes 45,000 net acres subject to drill-to-earn agreements. Includes 4,768 net acres in Nevada.

(4) Includes 25 wells in which we have an average interest of approximately 0.7% each, or approximately 0.2 total net wells.

We currently have six asset teams as follows: South Midway-Sunset (SMWSS) – Steam Floods, North Midway-Sunset (NMWSS) – Diatomite, Permian, Uinta, Piceance and E. Texas.

SMWSS – Steam Floods. Our SMWSS – Steam Floods assets include our Homebase, Formax, Ethel D, Placerita, and Poso Creek properties. Production from our Homebase, Formax and Ethel D properties in the South Midway-Sunset Field relies on thermal enhanced oil recovery (EOR) methods, primarily cyclic steaming, to place steam effectively into the remaining oil column. These are some of our most thermally mature assets, with production from our Ethel D properties dating back to 1909. In 2011, we expanded our steam flood at our Homebase and Formax properties, drilling five horizontal wells, three vertical wells and six steam injection wells. At our Ethel D property, we expanded development of a new steam flood, drilling 17 producing wells and three steam injection wells. In 2012, we plan to continue development of the steam flood at our Ethel D property, adding additional steam generation capacity and drilling approximately 40 producing wells and five steam injection wells. In addition, we plan to drill eight horizontal wells and two vertical wells on our Homebase and Formax properties.

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In 2003, we acquired our Poso Creek properties in the San Joaquin Valley and have proceeded with a successful thermal EOR redevelopment. Average daily production from these properties increased from 50 BOE/D at acquisition in 2003 to 3,620 BOE/D in 2011. In 2012, we plan to expand the steam flood at our Poso Creek properties by drilling approximately 10 producing wells and six steam injection wells. Our Placerita field is located in Los Angeles County. In 2011, our efforts at Placerita were focused on the initiation of an Upper Kraft zone steam flood pilot and recompletion program. Average daily production at our Placerita properties increased to approximately 2,300 BOE/D in the fourth quarter of 2011 from less than 1,900 BOE/D in the third quarter of 2011. In 2012, we plan to drill six producing wells and continue our recompletion program in the Upper Kraft zone.

Average daily production from all SMWSS – Steam Floods assets was approximately 13,185 BOE/D in 2011 compared to 13,595 BOE/D in 2010.

NMWSS – Diatomite. Our NMWSS – Diatomite assets include our Diatomite and McKittrick properties and our North Midway-Sunset steam flood properties in the San Joaquin Valley. We received a new full-field development approval in late July 2011 from the California Department of Conservation, Division of Oil, Gas and Geothermal Resources (DOGGR) with respect to our Diatomite property. The approval contained operating requirements that were significantly more stringent than similar specifications contained in prior approvals from DOGGR. Implementation of these newer operating requirements negatively impacted the pace of drilling and steam injection in 2011, and this impact has continued into 2012. We are working constructively with DOGGR on the operating specifications to enable an increase in the pace of our development. On February 24, 2012, we received revisions to the July 2011 project approval letter, which, among other things, allow us to conduct mechanical integrity testing at least once every five years, rather than annually as provided in the original project approval letter. In addition, we are no longer required to cease cyclic steaming operations on wells located within 150 feet of a failed well bore, subject to demonstrating to DOGGR that steam injection into such surrounding wells will be confined to the Diatomite zone. Our estimates of well performance and ultimate recovery for the asset remain unchanged. We are currently assessing the impact of the revised project approval letter on the development and operations of our Diatomite properties. In 2011, we drilled 113 wells at our Diatomite property and expanded our infrastructure for the next phase of development. In 2012, we plan to drill approximately 70 new producing wells and 20 replacement wells at Diatomite. Average daily production from our Diatomite property was 3,154 BOE/D in 2011 compared to 2,721 BOE/D in 2010.

At our McKittrick property, we drilled 44 cyclic producing wells in 2011 in advance of a steam flood pilot expansion. We plan to steam cycle these new McKittrick wells and put them on production during the first quarter of 2012. We are currently in the final construction stages of our dehydration and steam generation facilities at our McKittrick property and plan to drill approximately 50 additional producing wells in 2012.

In 2011, we also drilled 51 wells at our North Midway-Sunset steam flood properties. In 2012, we plan to expand steam flood projects at our Fairfield, Pan and Main Camp properties, drilling approximately 35 producing wells and converting four wells to steam injection wells.

Average daily production from all NMWSS—Diatomite assets was approximately 4,210 BOE/D in 2011 compared to 3,527 BOE/D in 2010.

Permian. In 2010, we acquired approximately 20,000 net acres in the Wolfberry trend. In 2011, we acquired approximately 22,000 additional net acres in or adjacent to the Wolfberry trend, bringing our total Permian acreage to approximately 42,000 net acres. In 2011, we drilled 72 gross (69 net) wells and completed 80 gross (75 net) wells. Average daily production at our Permian properties was 5,600 BOE/D in the fourth quarter of 2011, despite a reduction of approximately 800 BOE/D related to natural gas curtailments in the fourth quarter. In 2012, we plan to operate a five rig drilling program and drill approximately 100 gross operated wells. Average daily production in our Permian properties was 4,420 BOE/D in 2011 compared to 1,225 BOE/D in 2010.

Uinta. In 2003, we established our initial acreage position in our Uinta properties near the Ashley National Forest, targeting the Green River formation that produces both light oil and natural gas. We acquired the Brundage Canyon leasehold in Duchesne County in Northeastern Utah, which consists of working interests in approximately 51,000 net acres on federal, tribal, and private leases. We have working interests in approximately 27,000 net acres and exploratory rights in approximately 45,000 net acres in the Lake Canyon project, which is located immediately west of our Brundage Canyon producing properties. In 2011, we drilled 54 gross (45 net) wells in our Uinta properties, which included 20 gross (20 net) wells in Brundage Canyon, 17 gross (17 net) wells in the Ashley National Forest and 17 gross (8 net) wells in Lake Canyon. Additionally, we deepened two existing wells in Brundage Canyon and one existing well in Lake Canyon. We participated in six non-operated Uteland Butte horizontal wells with our partner in Lake Canyon and drilled three Uteland Butte horizontal wells (two in Lake Canyon and one

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in Brundage Canyon). Of the 54 gross wells drilled in 2011, 12 tested the Wasatch formation. Results from the Wasatch test wells have been encouraging. We continue to monitor the progress of our initial water flood pilot in Brundage Canyon, which was implemented in the fourth quarter of 2009, and, in 2012, we plan to expand our second water flood pilot that was implemented in Brundage Canyon in the fourth quarter of 2010. Our Ashley National Forest Environmental Impact Study (EIS) continues to progress, although final approval continues to be delayed. We plan to run a three rig program in the Uinta in 2012, focused on developing areas of higher oil potential, including horizontal wells in the Uteland Butte and Brundage Canyon and commingled wells in the Green River and Wasatch formations. We estimate an inventory of 800-1,400 potential locations distributed across our entire Uinta leasehold. Average daily production in our Uinta properties was approximately 5,540 BOE/D in 2011 compared to 5,350 BOE/D in 2010.

Piceance. In 2006, we acquired two properties in the Piceance targeting the Williams Fork section of the Mesaverde formation. We have a 62.5% working interest in 6,300 gross acres on our Garden Gulch property, a 95% working interest in 4,300 gross acres and a 5% non-operating working interest in 89 wells on our North Parachute property. We have accumulated a sizable resource base, which should allow us to add significant proved reserves as we develop these assets. We have successfully drilled 111 gross wells (69 net) at our Garden Gulch property and 38 gross wells (36 net) on our North Parachute property since the acquisitions of those properties. During 2009, we began a 20 well completion program testing new completion designs and saw improved well performance in line with our expectations. During 2011, we completed nine wells utilizing these improved completion techniques, and results continue to meet our expectations. In January 2011, we renegotiated the agreement covering the North Parachute property such that we have until January 31, 2020 to complete our drilling obligations. See Note 10 to the Financial Statements. We are currently deferring drilling in the Piceance while we focus on higher return oil development opportunities in our portfolio. Average daily production in our Piceance properties was 24 MMcf/D in 2011 compared to 23 MMcf/D in 2010.

E. Texas. In 2008, we acquired certain interests in natural gas producing properties in Limestone and Harrison Counties in E. Texas. The Limestone County assets include seven productive horizons in the Cotton Valley and Bossier sands at depths between 8,000 and 13,000 feet. Additional potential exists in the Haynesville/Bossier shale. The Harrison County assets include five productive sands as well as the Haynesville/Bossier Shale, with average depths between 6,500 and 13,000 feet. In 2010, we completed an eight well Haynesville horizontal development program. We deferred drilling in E. Texas during 2011 and will defer drilling during 2012 while we focus on higher return oil development opportunities in our portfolio. Due to the impact of lower natural gas prices, we recorded an impairment of $625.0 million related to our E. Texas assets. See Notes 9 and 11 to the Financial Statements. Average daily production from the E. Texas assets was 26 MMcf/D in 2011 as compared to 31 MMcf/D in 2010.

Reserves

The following table presents our estimated quantities of proved reserves as of December 31, 2011:

	Estimated Proved Reserves(2)
	Oil (MBOE)	Natural Gas (MMcf)	Total (MBOE)(1)
Developed	107,849	221,606	144,783
Undeveloped	78,031	312,673	130,143
Total proved—December 31, 2011	185,880	534,279	274,926

___________________________________________

(1) Oil equivalents are determined using the ratio of six Mcf of natural gas to one barrel of oil.

(2) At December 31, 2011, all of our oil and natural gas reserves are attributable to properties within the United States.

At December 31, 2011, our estimated proved undeveloped reserves (PUDs) were 130.1 MMBOE, a decrease of 5% compared to 137.5 MMBOE at December 31, 2010. During 2011, approximately 26.8 MMBOE, or 19.5%, of our December 31, 2010 PUDs were converted into proved developed reserves as a result of investing approximately $345.4 million of drilling, completion and facilities capital. In addition, in 2011, we acquired 12.9 MMBOE of PUDs in the Wolfberry trend in the Permian. As a result of the SEC's five year development limitation on PUDs, we converted 20.5 MMBOE of PUDs to unproved reserves primarily due to changes in timing of our PUD development plans. Our drilling and completion activities in 2011, primarily related to our California, Permian and Utah assets, and engineering revisions, resulted in the addition of approximately 27.8 MMBOE of PUDs. We intend to convert the PUDs disclosed as of December 31, 2011 to proved developed reserves within five years of the date they were initially disclosed as proved undeveloped.

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Preparation of Reserves Estimates

Estimated proved reserves at December 31, 2011 were prepared by DeGolyer and MacNaughton (D&M), an independent petroleum engineering consulting firm that has provided consulting services throughout the world for over 70 years.See Exhibit 99.1—Report of DeGolyer and MacNaughton dated February 15, 2012.

Estimated proved reserves presented in the table above were calculated in accordance with the Securities and Exchange Commission's (SECs) "Modernization of Oil and Gas Reporting" rule which was first effective for December 31, 2009 reporting. These rules include calculating estimated proved reserves based on the average prices during the twelve-month period prior to the reporting date, with such prices determined as the unweighted arithmetic average of the first-day-of-the-month prices for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. In addition, the SEC generally requires that reserves classified as proved undeveloped be capable of conversion into proved developed within five years of classification unless specific circumstances justify a longer time.

We maintain adequate and effective internal controls over the reserve estimation process. The reserves estimation process begins with our reserves coordinators, who are senior petroleum engineers and who are part of each asset team. The reservoir coordinators prepare, update and assemble information provided to D&M. Once all the relevant technical and support information has been assembled, D&M meets with our technical personnel to review field performance and future development plans. Following these reviews, D&M prepares independent reserve estimates and a final report based on the information we furnish to them. Our senior reservoir engineer oversees the reserve estimation process and has over 21 years of industry experience in the estimation and evaluation of reserve information. She holds a B.S. degree in Mechanical Engineering from South Dakota School of Mines and Technology. Our reserve data and our reserve estimation process are reviewed by our senior management and a subcommittee of the Audit Committee of our Board of Directors.

The lead technical person at D&M primarily responsible for overseeing the audit of our reserves is a Registered Professional Engineer in the State of Texas, is a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists and has over 35 years of experience in oil and natural gas reservoir studies and reserves evaluations.

There are numerous uncertainties inherent in estimating quantities of reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. See Part I, Item 1A—"Risk Factors," for a description of some of the risks and uncertainties associated with our business and reserves.

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Production, Average Sales Prices and Operating Costs

The table below includes information for each of our assets that we consider a single field and which contained 15% or more of our total proved reserves at the dates shown. See Part II, Item 6. "Selected Financial Data" and Part II, Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information regarding our production, average sales price and operating costs.

	Net Production Volumes(1)		Average Sales Price(2)				Average Operating Cost
	Oil (BOE/D)	Natural Gas (Mcf/D)	Oil ($/BOE)		Natural Gas ($/Mcf)		$/BOE
Year Ended December 31, 2011
Total production—Continuing operations	24,771	65,498	$	92.35	$	4.09	$	18.23
Diatomite	3,154	—	106.20		—		38.40
Permian	3,741	4,083	82.94		4.10		9.38
Piceance	86	23,472	65.04		4.13		9.40
Year Ended December 31, 2010
Total production—Continuing operations	21,713	65,720	$	67.61	$	4.37	$	15.95
Diatomite	2,721	—	75.03		—		32.08
South Midway-Sunset(3)	6,889	—	63.96		—		12.77
Piceance	62	22,681	64.14		4.25		8.94
Year Ended December 31, 2009
Total production—Continuing operations	19,688	57,484	$	50.73	$	3.61	$	14.66
Diatomite	3,093	—	57.00		—		21.98
South Midway-Sunset(3)	7,214	—	48.68		—		10.18
Piceance	43	18,981	45.56		3.35		9.05

_____________________________________

(1) Net production represents that owned by us and produced to our interests.

(2) Excludes effects of derivative instruments.

(3) Includes only our Homebase and Formax properties, which we consider a single field and which contained 15% or more of our total proved reserves at the dates shown.

Productive Wells and Acreage

As of December 31, 2011, we had working interests in 3,038 gross (2,867 net) productive oil wells and 467 gross (282 net) productive natural gas wells. Productive wells include both producing wells and shut-in wells that are capable of producing.

The following table sets forth information with respect to our developed and undeveloped acreage as of December 31, 2011. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would permit production of oil and natural gas in economic quantities. Gross acreage represents acres in which we have a working interest, and net acreage represents our aggregate working interests in the gross acres.

	Developed Acres		Undeveloped Acres		Total
	Gross	Net	Gross	Net	Gross	Net
California	6,352	5,829	832	741	7,184	6,570
Colorado	1,600	1,121	9,062	6,956	10,662	8,077
Nevada	840	771	4,455	3,997	5,295	4,768
Texas	15,500	12,125	43,572	34,339	59,072	46,464
Utah(1)	22,160	21,373	123,810	73,582	145,970	94,955
Wyoming	3,640	522	—	—	3,640	522
Kansas	—	—	54,764	53,790	54,764	53,790
Other	40	4	—	—	40	4
Total	50,132	41,745	236,495	173,405	286,627	215,150

___________________________________________

(1) Excludes 45,000 net acres subject to drill-to-earn agreements.

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Future Acreage Expirations

If production is not established or we take no other action to extend the terms of the related leases, undeveloped acreage will expire over the next three years as follows:

	2012		2013		2014
	Gross	Net	Gross	Net	Gross	Net
Utah	4,293	3,298	14,553	2,201	1,940	1,517
Texas(1)	205	444	1,409	1,806	10,972	9,031
Kansas	54,764	53,790	—	—	—	—
Total	59,262	57,532	15,962	4,007	12,912	10,548

__________________________________________

(1) Expiring net acreage may be greater than expiring gross acreage when multiple undivided interests in the same gross acreage expire at different times.

The amounts in the table above represent the acreage that will expire if no further action is taken to extend. We currently intend to extend our acreage positions in Utah and Texas prior to expiration, either through development or through lease extensions. The expiring acreage in Kansas relates to a coalbed methane lease that will not be developed or renewed.

Drilling Activity

The following table sets forth our drilling activities for the following periods:

	Year Ended December 31,
	2011		2010		2009
	Gross	Net	Gross	Net	Gross	Net
Development wells drilled:
Productive	403	366	241	232	132	132
Dry	1	1	—	—	2	2
Exploratory wells drilled:
Productive	1	1	—	—	—	—
Dry	3	3	1	1	—	—
Total wells drilled:
Productive	404	367	241	232	132	132
Dry	4	4	1	1	2	2

We achieved a gross drilling success rate of 99.0%, 99.6% and 98.5% for the years ended December 31, 2011, 2010 and 2009. Gross drilling success represents the percentage of gross wells drilled that were not dry wells (defined as a well incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well).

As of December 31, 2011, we had 9 rigs drilling on our properties and we had 9 gross (8 net) wells in progress.

Marketing and Customers

We market the majority of the oil and natural gas production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our production to a variety of purchasers under oil and natural gas purchase contracts with daily, monthly, seasonal, annual or multi-year terms, all at market prices. The majority of our sales are to marketing companies or refiners. We typically sell production to a relatively small number of customers.

For the year ended December 31, 2011, sales to ExxonMobil Oil Corporation and Shell Trading (US) Company accounted for approximately 43% and 14%, respectively, of our revenue. Based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition, results of operations, or operating cash flows. However, due to possible refinery constraints in the Utah region, it is possible that the loss of a single refining customer in Utah could materially and adversely affect the marketability of a portion of our Utah crude oil volumes.

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Oil. Our oil production is collected in tanks and sold via pipeline or truck. Our oil contracts are priced either on local area oil postings or are based upon the NYMEX WTI, with location or transportation differentials. A substantial portion of our oil reserves are located in California, and approximately 49% of our production is attributable to heavy crude (generally 21 degree API gravity crude oil or lower). The market price for California crude differs from the established market indices in the U.S. due primarily to the higher refining costs associated with heavy crude and differences in supply origin at domestic refineries. As of December 31, 2011, over 87% of our California oil production was under contract with Shell Trading (US) Company and ExxonMobil Oil Corporation. Our contract with Shell Trading (US) Company continues through June 30, 2013, and our contract with ExxonMobil Oil Corporation renews automatically on a month-to-month basis, unless either party to the contract terminates upon 90 days' notice. Our remaining California production is under contract through December 2012 with a refiner in the Los Angeles basin.

In Utah, we are a party to a crude oil sales contract through June 30, 2013 with a refiner for the purchase of a minimum amount of Uinta light crude oil. Pricing under the contract, which includes transportation and gravity adjustments, is at a fixed percentage of WTI. See Item 1A. Risk Factors—"We may not be able to deliver minimum crude oil volumes required by our sales contract."

Natural Gas. Our natural gas is transported through our own and third party gathering systems and pipelines. We incur processing, gathering and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped and the fee charged by the third-party processor or transporter. In certain instances, we enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our natural gas volumes. During 2011, our Rocky Mountain natural gas production was sold into the eastern markets in Lebanon and Clarington, Ohio, while our natural gas production in Utah is generally priced relative to a Rocky Mountain Northwest Pipeline (NWPL) or Questar index price. Our natural gas produced in E. Texas is generally priced based on the Florida Zone 1 or the Natural Gas Pipeline Co. of America-Texok zone (NGPL Texok) index. Our natural gas produced in the Permian is priced based on the El Paso Permian index.

We enter into firm transportation contracts on interstate and intrastate pipelines to assure the delivery of our natural gas to market. These commitments generally require a minimum monthly charge regardless of whether the contracted capacity

is used or not. Currently, our natural gas production is insufficient to fully utilize our contracted capacity on the Rockies Express, Wyoming Interstate, and Ruby pipelines. In California, we have firm transportation contracts to assure our ability to purchase a portion of our consumed natural gas outside of the California markets. The following table sets forth information about material long-term firm transportation contracts for pipeline capacity as of December 31, 2011:

Pipeline	From	To	Quantity (Avg. MMBtu/D)	Term	Demand charge per MMBtu			Remaining contractual obligation (in thousands)
Kern River Pipeline	Opal, WY	Kern County, CA	12,000	5/2003 to 4/2013	$	0.58		$	3,413
Rockies Express Pipeline	Meeker, CO	Clarington, OH	25,000	2/2008 to 1/2018	1.13		(1)	62,949
Rockies Express Pipeline	Meeker, CO	Clarington, OH	10,000	6/2009 to 11/2019	1.09		(1)	31,400
Questar Pipeline	Brundage Canyon, UT	Salt Lake City, UT	2,500	9/2003 to 6/2012	0.17		(2)	79
Questar Pipeline	Brundage Canyon, UT	Salt Lake City, UT	2,859	9/2003 to 6/2012	0.17		(2)	91
Questar Pipeline	Brundage Canyon, UT	Goshen, UT	5,000	9/2003 to 10/2022	0.26			5,087
Questar Pipeline	Chipeta Plant, UT	Various UT locations	6,200	7/2012 to 6/2020	0.17		(2)	3,165
Enbridge Pipeline	Limestone and Harrison Counties, TX	Orange, TX	Up to 55,000	4/2009 to 3/2012	0.22			277
Wyoming Interstate Company Pipeline	Meeker, CO	Opal, WY	35,000	8/2011 to 7/2021	0.31			38,335
Ruby Pipeline	Opal, WY	Malin, OR	35,000	8/2011 to 7/2021	0.95			118,741
Total			188,559					$	263,537

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(1) Based on weighted average cost.

(2) Subject to completion of planned expansion of the Chipeta Processing LLC natural gas plant. The expansion is expected to be completed and transportation will begin under the contract on July 1, 2012.

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Steaming Operations

Our California assets consist of heavy crude oil, which requires heat, supplied in the form of steam, injected into the oil producing formations to reduce the oil viscosity, thereby allowing the oil to flow to the wellbore for production. We utilize cyclic steam and/or steam flood recovery methods on such assets.

Cogeneration Steam Supply. In pursuing our goal of being a cost-efficient heavy oil producer in California, we have consistently focused on minimizing our steam cost. We believe one of the main methods to keep steam costs low is through the ownership and efficient operation of three cogeneration facilities located on our properties. Two of these cogeneration facilities, a 38 megawatt (MW) and an 18 MW facility, are located on our SMWSS properties. We also own a 42 MW cogeneration facility, which is located on our Placerita property. Cogeneration, also called combined heat and power (CHP), extracts energy from the exhaust of a turbine that would otherwise be wasted, to produce steam. This increases the efficiency of the combined process and consumes less fuel than would be required to produce the steam and electricity separately.

Conventional Steam Generation. We also own 39 fully permitted conventional steam generators. The quantity of generators operated at any point in time is dependent on (i) the steam volume required to achieve our targeted production and (ii) the price of natural gas compared to the realized price of crude oil sold. In 2011, we added five additional steam generators, four for use in our ongoing development of our Diatomite property and one for use at our McKittrick property. In 2010, we added four additional steam generators for use in our ongoing development of our Diatomite assets. In 2009, we added three additional generators at our Diatomite property and one steam generator at our Poso Creek property.

Ownership of these varied steam generation facilities and sources allows for maximum operational control over the steam supply, location, and to some extent, over the aggregated cost of steam generation. Our steam supply and flexibility are crucial for the maximization of California thermally enhanced heavy oil production, cost control and ultimate oil recovery.

Total BSPD capacity as of December 31, 2011 was as follows:

Steam generation capacity of conventional steam generators	133,429
Steam generation capacity of cogeneration plants	42,789
Additional steam purchased under contract with a third party	1,870
Total steam capacity	178,088

The average gross volume of steam injected in our operations for the years ended December 31, 2011 and 2010 was 133,404 BSPD and 116,956 BSPD, respectively.

During December 2011, approximately 80% of the natural gas we purchased to generate steam and electricity was based upon California indices. We pay distribution/transportation charges for the delivery of natural gas to our various locations where we use the natural gas for steam generation purposes. In some cases, this transportation cost is embedded in the price of the natural gas we purchase. Approximately 20% of the volume of natural gas purchased to generate steam and electricity was purchased in the Rockies and moved to the Midway-Sunset field using our firm transportation capacity on the Kern River Pipeline. This natural gas has historically been purchased based upon the Rocky Mountain NWPL index.

	2011		2010		2009
Average SoCal Border Monthly Index Price per MMBtu	$	4.10	$	4.34	$	3.59
Average PG&E Citygate Monthly Index Price per MMBtu	4.29		4.66		4.17
Average Rocky Mountain NWPL Monthly Index Price per MMBtu	3.80		3.94		3.09

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Historically we have been a net producer of natural gas and have benefited operationally when natural gas prices increase. Our production of natural gas has, in the past, provided a form of natural hedge against rising steam costs. As our natural gas production continues to decrease and our use of natural gas for steaming operations increase, we may become a net consumer of natural gas and would no longer benefit operationally when natural gas prices increase. The following table shows our average and estimated average amount of production, consumption and hedged volumes (in average MMBtu/D) for the following years:

	Estimated 2012		2011		2010
Natural gas produced	51,190		65,500		65,720
Natural gas consumed in operations
Cogeneration operations	26,500		25,087		27,083
Conventional steam generators	49,000		34,377		27,108
Total natural gas consumed in operations	75,500		59,464		54,191
Less: Estimated natural gas volumes consumed to produce electricity(1)	(16,000	)	(15,229	)	(18,171	)
Net estimated natural gas consumed in steam generation	59,500		44,235		36,020
Natural gas volumes hedged	15,000		15,000		19,000
Estimated net (deficit) excess of natural gas produced, consumed, and hedged	(23,310	)	6,265		10,700

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(1) Estimate is based on the historical allocation of fuel costs to electricity.

Electricity

Generation. The total net electrical generation capacity of our three cogeneration facilities during 2011 was approximately 93 MW, of which we consumed approximately 7 MW for use in our operations. Each facility is centrally located on certain of our oil producing properties. Thus the steam generated by each facility is capable of being delivered to numerous wells that require steam for the EOR process. Our investment in our cogeneration facilities has been for the express purpose of lowering the steam costs in our heavy oil operations and securing operating control of the respective steam generation. Expenses of operating the cogeneration plants are analyzed regularly to determine whether they are advantageous versus conventional steam generators. Cogeneration costs are allocated between electricity generation and oil and natural gas operations based on the conversion efficiency (of fuel to electricity and steam) of each cogeneration facility and certain direct costs to produce steam. Cogeneration costs allocated to electricity will vary based on, among other factors, the thermal efficiency of our cogeneration plants, the price of natural gas used for fuel in generating electricity and steam and the terms of our power contracts. Although we account for cogeneration costs as described above, economically we view any profit or loss from the generation of electricity as a decrease or increase, respectively, to our total cost of producing heavy oil in California. Depreciation, depletion and amortization (DD&A) related to our cogeneration facilities is allocated between electricity operations and oil and natural gas operations using a similar allocation method.

Sales Contracts. We sell electricity produced by our cogeneration facilities to two California public utilities: Southern California Edison Company (Edison) and Pacific Gas and Electric Company (PG&E), under long-term contracts approved by the California Public Utilities Commission (CPUC). These contracts are referred to as standard offer (SO) power purchase agreement (PPA) contracts under which we are paid an energy payment that reflects the utility's Short Run Avoided Cost (SRAC) of energy plus a capacity payment that reflects a recovery of capital expenditures that would otherwise have been made by the utility. We currently sell energy and capacity to PG&E and Edison under interim extensions of legacy PPAs with those utilities. These legacy PPAs were originally ordered by the CPUC in the 1980s in its implementation of the Public Utilities Regulatory Policy Act of 1978, as amended (PURPA). As these legacy PPAs expired over the last 10 years, there has been considerable pressure by the investor owned utilities (IOUs) to require qualifying facilities (QFs), such as our cogeneration plants, to bid for new contracts against other resources in competitive solicitations. The administratively determined energy and capacity prices under these standard offer contracts have also been the subject of litigation in various regulatory and legal proceedings for more than 10 years. In an effort to resolve a broad range of issues, the various parties involved, including us, entered into settlement discussions resulting in a Global Settlement that became effective on November 23, 2011. Among other things, the Global Settlement resolved all claims by the IOUs for retroactive payment adjustments against QFs, including claims against us, made available new standard form contracts, revised SRAC energy prices and established a transition period to allow QFs to secure new long-term agreements through competitive solicitations. Our current legacy extension PPAs with Edison for our Placerita Units 1 and 2 are scheduled to terminate on or about March 22, 2012, at which time we intend to enter into a Transition Contract for the combined output of the two units. The Transition Contract is

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intended to be a bridge agreement to allow QFs to bid against other CHP facilities for long-term contracts with the IOUs and is similar to our current SO contracts, but with updated regulatory requirements and more stringent scheduling and performance requirements. All Transition Contracts will terminate no later than June 30, 2015, but may be terminated earlier if we elect to bid into a competitive CHP solicitation and are awarded a contract based on our bid. There is no assurance that we will be successful in bidding for long-term replacement contracts prior to the termination of our Transition Contract.

Our current PPAs with PG&E for our Cogen 18 facility and our Cogen 38 facility are scheduled to terminate on March 31, 2012. Because the rated capacity of our Cogen 18 facility is less than 20 MW, it will continue to be eligible for a PURPA contract under which it will be paid the prevailing CPUC-determined SRAC price and either a firm or as-available capacity payment at our discretion. In addition, we will have the option to competitively bid the energy and capacity from our Cogen 18 facility into various competitive solicitations that will be open only to CHP facilities. Upon the termination of the PPA for Cogen 18, we anticipate that we will enter into a new contract with PG&E pursuant to PURPA with a term of up to seven years. Upon the termination of the PPA for our Cogen 38 facility, we anticipate that we will enter into a Transition Contract with PG&E that will terminate no later than June 30, 2015. We also intend to bid into one or more of the CHP only solicitations that were issued by Edison and PG&E in December 2011. For existing facilities, such as ours, the maximum term of a PPA awarded in a competitive IOU solicitation is seven years. Beginning in 2015, the energy prices we will be paid will be based on market prices for electricity. See Item 1A. Risk Factors-"We are dependent on our cogeneration facilities and deteriorations in the electricity market and regulatory changes in California may materially and adversely affect our financial condition, results of operations and operating cash flows."

Facility and Contract Summary

Location and Facility	Type of Contract (4)	Purchaser	Contract Expiration		Approximate Megawatts Available for Sale(1)	Approximate Megawatts Consumed in Operations(1)	Approximate Barrels of Steam Per Day
Placerita
Placerita Unit 1	SO2	Edison	Mar-12	(2)	20	—	6,500
Placerita Unit 2	SO1	Edison	Mar-12	(2)	17	4	6,500
S. Midway
Cogen 18	SO1	PG&E	Mar-12	(3)	11	4	6,600
Cogen 38	SO1	PG&E	Mar-12	(2)	37	—	18,500

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(1) Assumes operations at full capacity with no interruptions.

(2) We anticipate the current contract will be replaced by a transition contract expiring June 30, 2015.

(3) We anticipate the current contract will be replaced by a PURPA contract with a term of up to 7 years.

(4) SO1 contracts pay only "as available" capacity rates and SO2 contracts pay firm capacity rates.

Competition

The oil and natural gas industry is highly competitive. As an independent producer, we have little control over the price we receive for our oil and natural gas. As such, higher costs, fees and taxes assessed at the producer level cannot necessarily be passed on to our customers. In acquisition activities, competition is intense as integrated and independent companies and individual producers are active bidders for desirable oil and natural gas properties and prospective acreage. Although many of these competitors have greater financial and other resources than we have, we are in a position to compete effectively due to our business strengths.

Title to Properties

Prior to the time we acquire undeveloped properties, we conduct a title investigation consistent with industry custom and practice. Most developed properties we acquire have existing title opinions. In addition, prior to commencement of drilling operations we obtain a drilling title opinion which, in the event production is achieved, is supplemented with a division order title opinion or its equivalent. To date, we have obtained or commissioned title opinions on virtually all of our producing properties and have satisfactory title to those properties in accordance with industry standards. A majority of our oil and natural gas properties are subject to a mortgage or deed of trust under our senior secured revolving credit facility, as well as to customary royalty interests, liens incidental to operating agreements, tax liens, and other minor burdens, encumbrances, easements and restrictions which do not materially interfere with the use of or affect the value of such properties.

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Employees

As of December 31, 2011, we had 317 full-time employees. We also contract for the services of independent consultants involved with land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by a collective bargaining agreement. Our relations with our employees are good.

Offices

Our corporate headquarters are located in Denver, Colorado, and we have regional offices in Bakersfield, California, Plano, Texas and Midland, Texas.

Available Information

Our website, located at http://www.bry.com, can be used to access recent news releases and Securities and Exchange Commission (SEC) filings, crude oil price postings, hedging summaries, our Annual Report, Proxy Statement, Board Committee Charters, Corporate Governance Guidelines, Code of Business Conduct and Ethics, the Code of Ethics for Senior Financial Officers, and other items of interest. Information on our website is not incorporated into this report. SEC filings, including supplemental schedules and exhibits, can also be accessed free of charge through the SEC website at http://www.sec.gov.

Environmental Matters and Other Regulations

General. Our operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Our operations are subject to the same environmental laws and regulations as other companies in the oil and natural gas exploration and production industry. These laws and regulations:

• require the acquisition of various permits before drilling commences;

• require the installation of expensive pollution control equipment;

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

• limit or prohibit drilling activities on lands lying within environmentally sensitive areas, wilderness, wetlands and other protected areas;

• require measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;

• impose substantial liabilities for pollution resulting from our operations; and

• with respect to operations affecting federal lands or leases, require time-consuming environmental analysis with uncertain outcomes.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost and timing of doing business and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in delay of oil and natural gas operations or more stringent and costly permitting, well drilling, construction, completions and water management activities, or waste handling, disposal and clean-up requirements for the oil and natural gas industry could have a significant impact on our operating costs.

We believe that, in all material respects, we are in compliance with, and have complied with, all applicable environmental laws and regulations. We have made and will continue to make expenditures in our efforts to comply with all environmental regulations and requirements. We consider these a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with governmental regulations. We believe that our continued compliance with existing requirements has been accounted for and will not have a material and adverse impact on our financial condition, results of operations and operating cash flows. However, we cannot predict the passage of or quantify the potential impact of any more stringent future laws and regulations at this time. For the year ended December 31, 2011, we did not incur any material capital expenditures for remediation or retrofit of pollution control equipment at any of our facilities.

Some of the more significant environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry and our business are as follows:

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (NEPA). NEPA requires federal agencies, including the Departments of Interior and

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Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an environmental assessment prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed EIS that is made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that may trigger the requirements of NEPA. This process has the potential to delay or limit the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Waste Handling. The Resource Conservation and Recovery Act (RCRA) and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the Environmental Protection Agency (EPA), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil, natural gas, or geothermal energy constitute “solid wastes,” which are regulated under the less stringent, non-hazardous waste provisions, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration and production wastes as “hazardous wastes.” In September 2010, an environmental organization petitioned the EPA to reconsider certain RCRA exemptions for exploration and production wastes but, to date, the EPA has not taken action on the petition.

We believe that we are in compliance in all material respects with the requirements of RCRA and related state and local laws and regulations, and that we have held, and continue to hold, all necessary approvals, permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we believe that the current costs of managing waste as presently classified are reflected in our budget, any more stringent legislative or regulatory reclassification of oil and natural gas exploration and production waste could increase our costs to manage and dispose of such waste.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as the “Superfund” law, imposes strict, joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for a release or threatened release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site, or site where the release or threatened release of a “hazardous substance” occurred, and companies that disposed or arranged for the disposal of the hazardous substance. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, could be subject to CERCLA. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

Water Discharges. The federal Water Pollution Control Act (Clean Water Act) and comparable state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Air Emissions. The federal Clean Air Act (CAA) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs. These laws and the implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” (GHGs) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of

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the CAA. The EPA recently adopted two sets of rules regulating GHG emissions under the CAA, one that requires a reduction in emissions of GHGs from motor vehicles and the other that regulates emissions of GHGs from certain large stationary sources under the Clean Air Act's Prevention of Significant Deterioration and Title V permitting programs. The EPA's rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among other things, certain onshore oil and natural gas production facilities, on an annual basis.

In addition, legislation has from time to time been introduced in the United States Congress that would establish measures restricting GHG emissions in the United States. At the state level, almost one half of the states, including California, have begun taking actions to control and/or reduce emissions of GHGs. The State of California has adopted legislation that caps California's GHG emissions at 1990 levels by 2020, and the California Air Resources Board (CARB) has implemented mandatory reporting regulations and instituted early action measures in an effort to reduce GHG emissions prior to January 1, 2012. On October 20, 2011, California became the first state to adopt a cap and trade program to reduce GHG emissions. The new regulations, which will take effect in 2013, will require us to continue to report our GHG emissions and will set maximum limits or caps on total emissions of GHGs from all industrial sectors, including the oil and natural gas extraction sector of which we are a part, that are subject to the cap and trade regulation. The cap will decline annually thereafter through 2020. We will be required to obtain compliance instruments for each metric tonne of GHG that we emit, in the form of allowances (each the equivalent of one ton of carbon dioxide) or qualifying offset credits. The availability of allowances will decline over time in accordance with the declining cap, and the cost to acquire such allowances may increase over time. We are currently assessing the impact of these regulations on our operations, including the costs to acquire allowances and to reduce emissions. Our early estimates indicate that, based on our understanding of the current market price of allowances, the manner in which cost-free allowances are to be distributed by CARB to the oil and natural gas extraction industry and our current production and emissions estimates, among other factors, our cost of acquiring allowances beginning in 2013 may be in the range of $2.00-3.00 per barrel. The actual cost to acquire allowances will depend on the market price for such allowances at the time they are purchased, the distribution of allowances among various industry sectors and our ability to limit our GHG emissions and implement cost-containment measures. The cap and trade program is currently scheduled to be in effect through 2020.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition, results of operations and operating cash flows.

Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act (SDWA) and is developing guidance documents related to this newly asserted regulatory authority. In addition, on November 23, 2011, the EPA announced that it was granting in part a petition to initiate a rulemaking under the Toxic Substances Control Act relating to chemical substances and mixtures used in oil and natural gas exploration and production. Moreover, legislation has been introduced before Congress to repeal an exemption in the federal SDWA for the underground injection of hydraulic fracturing fluids near drinking water sources. If adopted, the legislation would require the reporting and public disclosure of chemicals used in the fracturing process. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Further, if enacted, the FRAC Act could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements.

Certain states in which we operate, including Texas and Colorado have adopted, and other states are considering adopting, regulations that could impose increased regulatory oversight of hydraulic fracturing through additional permit requirements, public disclosure, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. For example, the Railroad Commission of Texas adopted rules in December 2011 requiring disclosure of certain information regarding the components used in the hydraulic fracturing process. In addition to state laws,

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local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, the EPA announced on October 20, 2011 that it is launching a study of wastewater resulting from hydraulic fracturing activities and currently plans to propose pretreatment regulations by 2014. The U.S. Department of Energy is also conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Moreover, the U.S. Department of the Interior is considering public disclosure, well testing and monitoring requirements for hydraulic fracturing on federal lands. Also, certain members of the Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or otherwise.

Further, on July 28, 2011, the EPA issued proposed rules that would subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs. The EPA proposed rules also include NSPS standards for completions of hydraulically fractured natural gas wells. These standards include the reduced emission completion (REC) techniques developed in the EPA's Natural Gas STAR program along with the pit flaring of natural gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (MACT) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. We are currently evaluating the effect these proposed rules could have on our business. Final action on the proposed rules is expected no later than April 3, 2012.

The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to perform hydraulic fracturing, complete natural gas wells in shale formations, and obtain permits, and could increase our costs of compliance and doing business.

Endangered Species. The Endangered Species Act (ESA) may restrict activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Federal Energy Regulation. The enactment of the PURPA and the adoption of regulations thereunder by the Federal Energy Regulatory Commission (FERC) provided incentives for the development of cogeneration facilities such as ours. A domestic electricity generating project must be a QF under FERC regulations in order to benefit from certain rate and regulatory incentives provided by PURPA.

PURPA provides two primary benefits to QFs. First, QFs generally are relieved of compliance with extensive federal and state regulations that control the financial structure of an electricity generating plant. Second, FERC's regulations promulgated under PURPA require that electric utilities purchase electricity generated by QFs at a price based on the purchasing utility's avoided cost and that the utility sell back-up power to the QF on a non-discriminatory basis. The term “avoided cost” is defined as the incremental cost to an electric utility of electric energy or capacity, or both, which, but for the purchase from QFs, such utility would generate for itself or purchase from another source. The Energy Policy Act of 2005 amended PURPA to allow a utility to petition FERC to be relieved of its obligation to enter into any new contracts with QFs if FERC determines that a competitive wholesale electricity market is available to QFs in the service territory. Upon the effectiveness of the Global

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Settlement on November 23, 2011, the California utilities have been relieved of their PURPA obligation to enter into new contracts with cogeneration QFs larger than 20 MW. However, under the Global Settlement those utilities will be required to offer standard form Transition contracts pursuant to CPUC jurisdiction to facilities larger than 20 MW, for a term ending no later than June 30, 2015.

State Energy Regulation. The CPUC has broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in California and to promulgate regulation for implementation of PURPA. Since a power sales agreement becomes a part of a utility's cost structure (generally reflected in its retail rates), power sales agreements with independent electricity producers, such as us, are potentially under the regulatory purview of the CPUC and in particular the process by which the utility has entered into the power sales agreements. While we are not subject to regulation by the CPUC, the CPUC's implementation of PURPA is important to us, as is other regulatory oversight provided by the CPUC to the electricity market in California.

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

Drilling and Production. Our operations are subject to various types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribes also regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

• the rates of production or “allowables;”

• the surface use and restoration of properties upon which wells are drilled and other third parties;

• wildlife management and protection;

• the protection of archaeological and paleontological resources;

• property mitigation measures;

• the plugging and abandoning of wells; and

• notice to, and consultation with, surface owners and other third parties.

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

Natural Gas Sales and Transportation. Section 1(b) of the Natural Gas Act (NGA) exempts natural gas gathering facilities from regulation by the FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to regulation as a natural gas company, but the status of these lines has never been challenged before FERC. The distinction between FERC-regulated transmission services and federally unregulated gathering services is subject to change based on future determinations by FERC, the courts, or Congress, and application of existing FERC policies to individual factual circumstances. Accordingly, the classification and regulation of some of our natural gas gathering facilities may be subject to challenge before FERC or subject to change based on future determinations by FERC, the courts, or Congress. In the event our gathering facilities are reclassified to FERC-regulated transmission services, we may be required to charge lower rates and our revenues could thereby be reduced.

FERC requires certain participants in the natural gas market, including natural gas gatherers and marketers, which engage in a minimum level of natural gas sales or purchases to submit annual reports regarding those transactions to FERC. Should we

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fail to comply with this requirement or any other applicable FERC-administered statute, rule, regulation or order, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation.

Operations on Native American Reservations. A portion of our leases and drill-to-earn arrangements in the Uinta are, and some of our future leases in this and other areas may be, regulated by Native American tribes. In addition to regulation by various federal, state and local agencies and authorities, an entirely separate and distinct set of laws and regulations applies to lessees, operators and other parties within the boundaries of Native American reservations. Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service and the Bureau of Indian Affairs, as well as the EPA, together with each Native American tribe, promulgate and enforce regulations pertaining to oil and natural gas operations on Native American reservations. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, Tribal employment and contractor preferences and numerous other matters.

Native American tribes are subject to various federal statutes and oversight by the Bureau of Indian Affairs and Bureau of Land Management. However, each Native American tribe is a sovereign nation and has the right to enact and enforce certain other laws and regulations entirely independent from federal, state and local statutes and regulations, as long as they do not supersede or conflict with such federal statutes. These tribal laws and regulations include various fees, taxes, requirements to employ Native American tribal members and numerous other conditions that apply to lessees, operators and contractors conducting operations within the boundaries of a Native American reservation. Further, lessees and operators within a Native American reservation are subject to the Native American tribal court system, unless there is a specific waiver of sovereign immunity by the Native American tribe allowing resolution of disputes between the Native American tribe and those lessees or operators to occur in federal or state court.

Therefore, we are subject to various laws and regulations pertaining to Native American tribal surface ownership. In addition, we are subject to the terms and conditions of Native American oil and natural gas leases, as well as fees, taxes, obligations and other issues unique to oil and natural gas ownership and operations within Native American reservations. These laws, regulations and other issues present unique risks which may impose additional requirements on our operations, cause delays in obtaining necessary approvals or permits, or result in losses or cancellations of our oil and natural gas leases, which in turn may materially and adversely affect our operations on Native American tribal lands.

Item 1A.    Risk Factors

Oil and natural gas prices are volatile, and declines in prices could materially and adversely affect our business, financial condition, results of operations and operating cash flow. Our future financial condition, revenues, results of operations, rate of growth and the carrying amount of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production and the prices prevailing from time to time for oil and natural gas. Oil and natural gas prices historically have been volatile, and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the amount of cash flow we have available for capital expenditures and our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of factors beyond our control, including:

• the level of consumer demand for oil and natural gas;

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

• commodity processing, gathering and transportation availability, and the availability of refining capacity;

• the price and level of imports of foreign oil and natural gas;

• the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• domestic and foreign governmental regulations and taxes;

• the price and availability of alternative fuel sources;

• weather conditions;

• political conditions or hostilities in oil and natural gas producing regions, including the Middle East, Africa and South America;

• technological advances affecting energy consumption;

• variations between product prices at sales points and applicable index prices; and

• worldwide economic conditions.

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These factors and the volatility of oil and natural gas markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices would reduce our revenues and could also reduce the amount of oil and natural gas that we can produce economically, which could materially and adversely affect our financial condition, results of operations, and operating cash flow.

Future oil and natural gas price declines may result in write-downs of the carrying amount of our assets, which could materially and adversely affect our results of operations and limit our ability to borrow funds. The value of our assets depends on oil and natural gas prices. Declines in these prices as well as increases in development costs, changes in well performance, delays in asset development or deterioration of drilling results may result in our having to make material downward adjustments to our estimated proved reserves, and accounting rules may require us to write down, and incur a corresponding non-cash charge to earnings, the carrying amount of our oil and natural gas properties for impairments.

Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis, annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of our oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows.Due to the impact of lower natural gas prices, we recorded an impairment of $625.0 million related to our E. Texas natural gas assets. See Notes 9 and 11 to the Financial Statements.

The U.S. natural gas price environment remained depressed and volatile in 2011 as NYMEX Henry Hub (HH) spot prices declined 32% from $4.41 per MMBtu at December 31, 2010 to $2.99 per MMBtu at December 31, 2011. In the fourth quarter of 2011, the NYMEX HH five-year future strip (the average of the settlement prices of the next 60 months' futures contracts) decreased approximately 15% from $4.97 at September 30, 2011 to $4.23 at December 31, 2011. If the price of natural gas futures continues to decrease during 2012, the estimated undiscounted future cash flows for our natural gas properties may fall below the carrying amount for such assets, and, in such case, we would be required to reduce the carrying amount our natural gas properties to estimated fair value.

The borrowing base of our senior secured revolving credit facility is subject to semi-annual redeterminations in April and October of each year, based on the value of our oil and natural gas properties, in accordance with the lenders' customary procedures and practices. We and the lenders each have a right to one additional redetermination each year. As of December 31, 2011, the borrowing base under our credit facility was $1.4 billion and total lender commitments were $1.2 billion. Declines in oil or natural gas prices in the future could limit our borrowing base and reduce our ability to borrow under our credit facility. Additionally, divestitures of properties could result in a reduction of our borrowing base.

We require substantial capital expenditures to conduct our operations, engage in acquisition activities, replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to execute our operating strategy. The oil and natural gas industry is capital intensive. We require substantial capital expenditures to conduct our exploration, development, and production operations, engage in acquisition activities, and replace our production. Historically, we have funded our capital expenditures through a combination of our cash flows from operations, borrowings under our senior secured revolving credit facility and the capital markets. Our cash flow from operations and access to capital are subject to a number of factors, some of which are outside our control. These factors include, among others:

• the value and performance of our debt and equity securities;

• the credit ratings assigned to our debt by independent rating agencies;

• domestic and global economic conditions; and

• conditions in the domestic and global financial markets.

If our revenues or the borrowing base under our credit facility decreases as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, seek additional financing. However, our credit facility places certain restrictions on our ability to obtain new financing, and we may not be able to obtain new financing on terms favorable to us, or at all. If cash generated by operations or borrowings under our credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our exploration and development activities, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves as well as our financial condition, results of operations and operating cash flows.

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The actual quantities and present values of our proved oil and natural gas reserves may be less than we have estimated. It is not possible to measure underground accumulations of oil or natural gas in an exact way. Estimating accumulations of oil and natural gas is a complex process that relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions, such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds, some of which are mandated by the SEC.

Actual future production, oil and natural gas prices, revenues, production taxes, development expenditures, operating expenses, and quantities of producible oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially and adversely affect the estimated quantities of and present values related to our proved reserves, and the actual quantities and present values may be less than we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development activity, prevailing oil and natural gas prices, costs to develop and operate properties, and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production on adjacent properties.

Further, it should not be assumed that any present value of future net cash flows from our estimated proved reserves represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on first-day-of-month average oil and natural gas prices for the twelve-month period preceding the estimate and on costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations and, or taxes.

Approximately 47% of our total estimated proved reserves at December 31, 2011, were undeveloped, and those reserves may not ultimately be developed. At December 31, 2011, approximately 47% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these undeveloped reserves and the actual costs, development schedule, and results associated with these properties may not be as estimated. Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could materially and adversely affect our financial condition, results of operations and operating cash flows.

In addition, the SEC generally requires that reserves classified as proved undeveloped be capable of conversion into proved developed within five years of classification unless specific circumstances justify a longer time. Proved undeveloped reserves that are not timely developed are subject to possible reclassification as non-proved reserves. These requirements may limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Material downward adjustments to our estimated proved reserves could materially and adversely affect our financial condition, results of operations, and operating cash flows.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated. Our future oil and natural gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves and efficiently developing and exploiting our current reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

Recent regulatory changes in California have and may continue to materially and adversely impact our production and operating costs related to our Diatomite assets. Recent regulatory changes in California have impacted our Diatomite production. In 2010, Diatomite production decreased significantly due to the inability to drill new wells pending the receipt of permits from DOGGR. We received a new full-field development approval in late July 2011 from the DOGGR with respect to our Diatomite assets. The approval contained operating requirements that were significantly more stringent than similar specifications contained in prior approvals from DOGGR, including operating, response and preventative requirements relating to mechanical integrity testing and responses to integrity issues and surface expressions, among others. Implementation of these new operating requirements negatively impacted the pace of drilling and steam injection in 2011, and increased our operating

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costs for our Diatomite assets. The new requirements have continued to affect our operations into 2012, and may have lasting impacts on our operations in the future. On February 24, 2012, we received revisions to the July 2011 project approval letter amending certain requirements in such letter. For a description of the February 2012 revisions, see Item 1., "Business—Properties— NMWSS – Diatomite." We are currently assessing the impact of the revised project approval letter on the development and operations of our Diatomite properties. We may not be successful in streamlining the review process with DOGGR or in taking additional steps to more efficiently manage our operations to avoid additional delays. In addition, DOGGR may impose additional operational restrictions or requirements. In such case, we may experience additional delays in production and increased operating costs related to our Diatomite assets. Average daily production for our Diatomite assets was 3,154 BOE/D during 2011.

Our heavy crude oil in California may be less economic than lighter crude oil. As of December 31, 2011, approximately 44% of our proved reserves, or 120.5 million barrels, consisted of heavy oil, and light crude oil represented 24% of our proved reserves. Heavy crude oil historically sells for a discount to light crude oil, as more complex refining equipment is required to convert heavy oil into high value products. Additionally, most of our crude oil in California is produced using steam injection. This process is generally more costly than primary and secondary recovery methods.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results. We have significant concentrations of credit risk with the purchasers of our oil and natural gas. For example, all of our oil produced in the Utah region is sold under a long-term contract to a single refiner. Due to the terms of supply agreements with our customers, we may not know that a customer is unable to make payment to us until months after production has been delivered. If the purchasers of our oil and natural gas become insolvent, we may be unable to collect amounts owed to us. Due to refinery constraints in the Utah region, it is possible that the loss of a single refining customer in Utah could impact the marketability of a portion of our Utah crude oil volumes.

Drilling is a high-risk activity and, as a result we may not be able to adhere to our proposed drilling schedule, or our drilling program may not result in commercially productive reserves. Our future success will partly depend on the success of our drilling program. The future cost or timing of drilling, completing and producing wells is inherently uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

• unexpected drilling conditions;

• well integrity issues and surface expressions;

• pressure or irregularities in formations;

• equipment failures or accidents;

• adverse weather conditions;

• changes in regulations;

• compliance with governmental or landowner requirements;

• availability, costs and terms of contractual arrangements with respect to leases, pipelines and related facilities to gather, process and compress, transport and market oil and natural gas; and

• shortages or delays in the availability of drilling rigs and the delivery of equipment and/or services, including experienced labor.

In addition, our drilling plans require drilling permits from state, local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays which jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a material and adverse effect on our ability to explore on or develop our properties.

Shortages of oilfield equipment, services and qualified personnel could delay our drilling program and increase the prices we pay to obtain such equipment, services and personnel. The demand for qualified and experienced field personnel to drill wells and conduct field operations such as geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling and workover rigs, crews and associated supplies, equipment and services. It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results, or restrict our ability to drill the wells and conduct the operations which we currently have planned and budgeted or which we may plan in the future. In addition, the availability of drilling rigs can vary significantly from region to region at any particular time. Although

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land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region.

We may be unable to make attractive acquisitions or successfully integrate acquired operations, and any inability to do so may disrupt our business and hinder our ability to grow. Our business strategy has emphasized growth through strategic acquisitions. We may not be able to continue to identify properties for acquisition or we may not be able to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. If we are unable to achieve strategic acquisitions, our growth may be impaired, thus impacting earnings, cash from operations and reserves. In addition, we may have difficulty integrating the operations, systems, management and other personnel and technology of acquired assets or businesses with our own. These difficulties could disrupt our ongoing business, distract our management and employees, increase our expenses and adversely affect our results of operations. In addition, we may incur additional debt or issue additional equity to pay for any future acquisitions, subject to the limitations described above.

Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential liabilities. Our recent growth is due in part to acquisitions of properties with additional development potential and properties with minimal production at acquisition but significant growth potential, and we expect acquisitions will continue to contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include: recoverable reserves, exploration potential, future oil and natural gas prices, operating costs, production taxes, access rights and potential environmental and other liabilities. Such assessments are inexact, and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties, which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not allow us to become sufficiently familiar with the properties, and we do not always discover structural, subsurface, environmental and access problems that may exist or arise. Our review prior to signing a definitive purchase agreement may be even more limited.

There may be threatened or contemplated claims against the assets or businesses we acquire related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, on acquisitions. We may acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. If material breaches are discovered by us prior to closing, we could require adjustments to the purchase price or if the claims are significant, we or the seller may have a right to terminate the agreement. If we fail to discover breaches or defects prior to closing, we may incur significant unknown liabilities, including environmental liabilities, for which we would have limited or no contractual remedies or insurance coverage.

We may incur losses as a result of title deficiencies. We acquire working and revenue interests in the oil and natural gas leaseholds and estates upon which we will perform our exploration activities from third parties, or directly from the mineral fee owners. The existence of a material title deficiency can reduce the value or render a property worthless, thus materially and adversely affecting our financial condition, results of operations and operating cash flow. Title insurance covering mineral leaseholds is not always available, and when available is not always obtained. As is customary in our industry, we rely upon the judgment of staff and independent landmen who perform the field work of examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and/or undertake drilling activities. We, in some cases, perform curative work to correct deficiencies in the marketability of the title to us. In cases involving material title problems, the amount paid for affected oil and natural gas leases or estates can be generally lost, and a prospect can become undrillable.

We may incur material losses and be subject to material liability claims as a result of our oil and natural gas operations. In addition, we may not be insured for, or our insurance may be inadequate to protect us against, these risks. Oil and natural gas operations are subject to many risks, including fires, explosions, well blowouts, uncontrollable flows of oil and natural gas, formation water or drilling fluids, adverse weather, freezing conditions in our various regions, natural disasters, pipe or cement failures, casing collapse, embedded oilfield drilling and service tools, formations with abnormal pressures, major equipment failures, including cogeneration facilities and, pollution, releases of toxic gas, and other environmental risks and hazards. If any of these types of events occurs, we could sustain material losses.

Under certain circumstances, we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease, or operate. As a result, we may incur material liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or acquisitions, or cause us to incur losses.

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We maintain insurance against some, but not all, of these potential risks and losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. We currently have insurance policies covering our operations that include coverage for general liability, excess liability, physical damage to our oil and natural gas properties, operational control of wells, oil pollution, third-party liability, workers' compensation and employers' liability and other coverages. While we intend to obtain and maintain insurance coverage we deem appropriate for these risks, there can be no assurance that our operations will not expose us to liabilities exceeding such insurance coverage or to liabilities not covered by insurance. The occurrence of an event not fully covered by insurance could materially and adversely affect our financial condition, results of operations and operating cash flows.

Our use of hedging transactions could result in financial losses or reduce our earnings. To reduce our exposure to fluctuations in oil and natural gas prices, we have entered into and expect in the future to enter into derivative instruments (or hedging contracts) for a portion of our anticipated oil and natural gas production or natural gas consumption. Our hedging transactions expose us to certain risks and financial losses, including, among others the risk that we may be limited in receiving the full benefit of increases in oil and natural gas prices as a result of these transactions, and that we may hedge too much or too little production or consumption depending on how oil and natural gas prices fluctuate in the future.

Due to the volatility of oil and natural gas prices, we may be required to recognize unrealized gains and losses (non-cash changes in fair value) on derivative instruments as the estimated fair value of our commodity derivative instruments is subject to significant fluctuations from period to period. The amount of any actual gains or losses recognized will likely differ from our period to period estimates and will be a function of the actual price of the commodities on the settlement date of the derivative instrument. We expect that commodity prices will continue to fluctuate in the future and, as a result, our periodic financial results will continue to be subject to fluctuations related to our derivative instruments.

Our financial counterparties may be unable to satisfy their obligations. We rely on financial institutions to fund their obligations under our credit facility and make payments to us under our commodity hedging contracts. Currently, all of our outstanding commodity derivative instruments are with lenders or affiliates of the lenders under our credit facility. If one or more of our financial counterparties becomes insolvent, they may not be able to meet their commitment to fund future borrowings under our credit facility which would reduce our liquidity and materially and adversely affect our ability to fund capital expenditures and make acquisitions. If our financial counterparties are unable to make payments under our commodity hedging contracts, our cash flow will be reduced.

A widening of commodity differentials may materially and adversely impact our revenues and our economics. The oil and natural gas we produce are priced in the local markets where production occurs based on local or regional supply and demand factors as well as other local market dynamics such as regional storage capacity and transportation. The prices that we receive for our oil and natural gas production are generally lower than the relevant benchmark prices, such as NYMEX or Brent, that are used for calculating commodity derivative positions. The difference between the benchmark price and the price we receive is called a differential.

We may be unable to accurately predict oil and natural gas differentials, which may widen significantly in the future. Numerous factors may influence local commodity pricing, such as refinery capacity, pipeline takeaway capacity and specifications, localized storage capacity, upsets in the mid-stream or downstream sectors of the industry, trade restrictions and governmental regulations. We may be materially and adversely impacted by a widening differential on the products we sell. Our commodity hedging contracts are typically based on West Texas intermediate (WTI) or natural gas index prices. As a result, we may be subject to “basis risk” if the differential on products we sell widens from the benchmarks used in our commodity hedging contracts. Additionally, regional capacity and storage issues may cause benchmark prices to become disconnected from regional oil and natural gas prices which may materially and adversely affect the effectiveness of our hedges based on such indices. Insufficient pipeline capacity, storage capacity or trucking capability and the lack of demand in any given operating area may cause the differential to widen in that area compared to other oil and natural gas producing areas. Increases in the differential between benchmark prices for oil and natural gas and the wellhead price we receive could materially and adversely affect our financial condition, results of operation, and operating cash flows.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production. Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities, trucking capability and refineries owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to

22

shut in wells for a lack of a market or because of inadequacy or unavailability of oil and natural gas pipelines, gathering system capacity, processing facilities or refineries. If we experience interruptions or loss of pipeline or access to gathering systems that impact a substantial amount of our production, it could have a material and adverse impact on our financial condition, results of operation, and operating cash flows.

We may not be able to deliver minimum crude oil volumes required by our sales contract. Production volumes from our Uinta properties over the next several years are uncertain, and there is no assurance that we will be able to consistently meet the minimum required volume under our refining contract relating to our production from these properties. During the term of the contract, the minimum number of delivered barrels is 5,000 Bbl/d. In the event that we cannot produce the necessary volume, we may need to purchase crude to meet our contract requirements. Gross oil production from our Uinta properties averaged approximately 3,390 Bbl/d during 2011.

A shortage of natural gas in California could materially and adversely affect our business. We may be subject to the risks associated with a shortage of natural gas and/or the transportation of natural gas into and within California. We are highly dependent on sufficient volumes of natural gas necessary to use for fuel in generating steam in our heavy oil operations in California. If the required volume of natural gas for use in our operations were to be unavailable or too highly priced to produce heavy oil economically, our production could be materially and adversely impacted.

We are dependent on our cogeneration facilities and deteriorations in the electricity market and regulatory changes in California may materially and adversely affect our financial condition, results of operations and operating cash flows. We are dependent on several cogeneration facilities that, combined, provide approximately 24% of our steam capacity as of December 31, 2011. These facilities are dependent on reasonable contracts for the sale of electricity. Market fluctuations in electricity prices and regulatory changes in California could adversely affect the economics of our cogeneration facilities and the corresponding increase in the price of steam could significantly impact our operating costs. If we are unable to enter into new or replacement contracts or were to lose existing contracts, we may be unable to meet our steam requirements necessary to maximize production from our heavy oil assets. An additional investment in various steam sources may be necessary to replace such steam, and there may be risks and delays in being able to install conventional steam equipment due to permitting requirements and availability of equipment. The financial cost and timing of such new investment could materially and adversely affect our financial condition, results of operations and operating cash flows. For a more detailed discussion of our electricity sales contracts, see Part I, Item 1, "Business-Electricity."

Changes to current income tax laws may affect our ability to take certain deductions. Substantive changes to the existing federal income tax laws have been proposed that, if adopted, would affect, among other things, our ability to take certain deductions related to our operations, including depletion deductions, deductions for intangible drilling and development costs and deductions for United States production activities. These changes, if enacted into law, could materially and adversely affect our financial condition, results of operations and operating cash flow.

Derivatives legislation enacted in 2010 could materially and adversely impact on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. New comprehensive financial reform legislation was signed into law by the President on July 21, 2010. The legislation calls for the Commodities Futures Trading Commission (the CFTC) to regulate certain markets for over-the-counter (OTC) derivative products. Currently, final rules to be adopted by the CFTC implementing the mandates of the new legislation are pending. Such rules would require certain derivatives to clear through clearinghouses. The effect on our business will depend in part on whether we are determined to be a major swap participant or swap dealer or a qualifying end-user, as those terms are defined in the final rules. We may be required to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities. The CFTC has proposed regulations that, if adopted, may exempt us from margin and clearing requirements, but the timing of adoption of such regulations, and their scope, is uncertain. Even if we are not deemed a major swap participant or swap dealer, the rules could impose burdens on market participants to such an extent that liquidity in the bilateral OTC derivative market decreases substantially. The legislation may also require counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The legislation and any new regulations, including determinations with respect to the applicability of margin requirements and other trading structures, could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could limit our ability to plan for and fund capital expenditures. Any of these consequences could materially and adversely affect our financial condition, results of operations and operating cash flows.

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Competition within our industry is intense and may materially and adversely affect our operations. We operate in a highly competitive environment. We compete with major and independent oil and natural gas companies in acquiring desirable oil and natural gas properties and in obtaining the equipment and labor required to develop and operate such properties. We also compete with major and independent oil and natural gas companies in the marketing and sale of oil and natural gas. Many of our competitors are larger, fully integrated energy companies that have financial, staff, and other resources substantially greater than ours, may be less leveraged than we are and have a lower cost of capital. As a result, these companies may have greater access to capital and may be able to pay more for development prospects and producing properties, or evaluate and bid for a greater number of properties and prospects than our financial and staffing resources permit. These larger companies may also have a greater ability to continue drilling activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. From time to time, we have to compete with financial investors in the property acquisition market, including private equity sponsors with more funds and access to additional liquidity. Many of these competitors have financial and other resources substantially greater than ours.

In addition, oil and natural gas producers are increasingly facing competition from providers of alternative energy, and government policy may favor those competitors in the future. We can give no assurance that we will be able to compete effectively in the future which could materially and adversely affect our financial condition, results of operations and operating cash flows.

Our oil and natural gas operations are subject to various environmental and other governmental laws and regulations that may materially affect our operations. Our oil and natural gas operations are subject to various U.S. federal, state, local and Tribal laws and regulations. These laws and regulations may be changed in response to economic, political or other conditions. There can be no assurance that present or future regulations will not materially and adversely affect our business and operations.

Many of the laws and regulations to which our operations are subject include those relating to the protection of the environment, including those governing the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes and the clean-up of contaminated sites. We could incur material costs, including clean-up costs, fines and civil and criminal sanctions and third-party claims for property damage and personal injury as a result of violations of, or liabilities under, environmental laws and regulations. Such laws and regulations not only expose us to liability for our own activities, but may also expose us to liability for the conduct of others or for actions by us that were in compliance with all applicable laws at the time those actions were taken. In particular, regulation of GHG emissions by Congress, the EPA, or various other legislative or regulatory bodies in the United States could have an adverse effect on our operations and demand for the oil and natural gas that we produce. In addition, we could incur material expenditures complying with environmental laws and regulations, including future environmental laws and regulations which may be more stringent including, for example, the regulation of GHG emissions under new federal legislation, the federal Clean Air Act, or state or regional regulatory programs. In addition, changes in interpretations of or enforcement of existing laws may cause us to incur substantial expenditures. Operating in densely populated regions may expose us to additional risk of regulation, as well as claims by property owners and others affected by such operations. See Part I, Item 1, “Business—Environmental Matters and Other Regulations” for more detail on both current and potential governmental regulation.

Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and operating restrictions or delays. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the Federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. For example, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel under the SDWA's Underground Injection Control Program and is developing guidance documents related to this newly asserted regulatory authority. In addition, both Texas and Colorado have adopted public disclosure regulations requiring varying degrees of disclosure of the constituents in hydraulic fracturing fluids. The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to perform hydraulic fracturing, complete oil and natural gas wells in shale formations, and obtain permits, and could increase our costs of compliance and doing business. For a more detailed discussion of hydraulic fracturing matters impacting our business, see Part I, Item 1, “Business—Environmental Matters and Other Regulations.”

The loss of key personnel could materially and adversely affect our business. We depend to a large extent on the efforts and continued employment of our executive management team and other key personnel. The loss of the services of these or other key personnel could materially and adversely affect our business, and we 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, landmen and other professionals. Competition for many of

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these professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed.

We may not adhere to our proposed drilling schedule. Our final determination of whether to drill any scheduled or budgeted wells will depend on a number of factors, including:

• results of our exploration efforts and the acquisition, review and analysis of our seismic data, if any;

• availability of sufficient capital resources to us and any other participants for the drilling of the prospects;

• approval of the prospects by other participants after additional data has been compiled;

• economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability and prices of drilling rigs and crews; and

• availability of leases, license options, farm-outs, other rights to explore and permits on reasonable terms for the prospects.

Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame, or at all. For instance, our drilling schedule may vary from our expectations because of future uncertainties and rig availability and access to our drilling locations utilizing available roads. In addition, we will not necessarily drill wells on all of our identified drilling locations on our acreage.

Restrictions in our existing and future debt agreements could limit our growth and our ability to respond to changing conditions. Agreements governing our outstanding debt restrict our ability to, among other things:

• incur, assume or guarantee additional indebtedness or issue redeemable stock;

• pay dividends or distributions or redeem or repurchase capital stock;

• prepay, redeem or repurchase debt that is junior in right of payment to our senior and subordinated notes;

• make loans and other types of investments;

• incur liens;

• sell or otherwise dispose of assets;

• consolidate or merge with or into, or sell substantially all of our assets to, another person;

• make capital expenditures or acquire assets or businesses;

• enter into transactions with affiliates; and

• enter into new lines of business.

In addition, our credit facility contains certain covenants, which, among other things, require the maintenance of (i) an interest coverage ratio of 2.75 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0. Our ability to borrow under our credit facility is dependent upon the quantity of proved reserves attributable to our oil and natural gas properties and the respective projected commodity prices as determined by the lenders under our credit facility. Our ability to meet these covenants or requirements may be affected by events beyond our control, and we cannot assure you that we will satisfy such covenants and requirements.

A downgrade in our credit rating could materially and adversely impact our cost of and ability to access capital. Our access to credit and capital markets also depends on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access capital or financial markets in the future, increase our borrowing costs and potentially require us to post letters of credit for certain obligations.

Item 1B.    Unresolved Staff Comments

None.

Item 2.    Properties

Information required by Item 2. Properties is included under Part I, Item 1, “Business—Properties.”

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Item 3.    Legal Proceedings

While we are, from time to time, a party to certain lawsuits in the ordinary course of business, we do not believe any of such existing lawsuits will have a material adverse effect on our operations, financial condition, or operating cash flows. For a description of legal matters see "Legal Matters" in Note 10 to the Financial Statements, which descriptions are incorporated by reference herein.

Item 4. Mine Safety Disclosure.

Not applicable.

Executive Officers

Presented below is information about our executive officers as of December 31, 2011. There are no family relationships between any of the executive officers and members of the Board of Directors.

ROBERT F. HEINEMANN, 58, has been President and Chief Executive Officer since June 2004. Mr. Heinemann was Chairman of the Board and interim President and Chief Executive Officer from April 2004 to June 2004. From December 2003 to March 2004, Mr. Heinemann acted as the director designated to serve as the presiding director at executive sessions of the Board in the absences of the Chairman and as liaison between the independent directors and the CEO. Mr. Heinemann joined the Board in March of 2002. From 2000 until 2002, Mr. Heinemann served as the Senior Vice President and Chief Technology Officer of Halliburton Company and as the Chairman of the Halliburton Technology Advisory Committee. He was previously with Mobil Oil Corporation (Mobil) where he served in a variety of positions for Mobil and its various affiliate companies in the energy and technical fields from 1981 to 1999, with his last responsibilities as Vice President of Mobil Technology Company and General Manager of the Mobil Exploration and Producing Technical Center.

DAVID D. WOLF, 41, has been Executive Vice President and Chief Financial Officer since August 2008. Mr. Wolf was previously employed by JPMorgan from 1995 to 2008 where he served as a Managing Director in JPMorgan's Oil and Gas Group and advised on numerous equity, debt and M&A transactions in the energy industry.

MICHAEL DUGINSKI, 45, has been Executive Vice President and Chief Operating Officer since September 2007. Mr. Duginski served as Executive Vice President of Corporate Development and California from October 2005 to August 2007; he acted as Senior Vice President of Corporate Development from June 2004 through October 2005 and as Vice President of Corporate Development from February 2002 through June 2004. Mr. Duginski, a mechanical engineer, was previously employed by Texaco, Inc. from 1988 to 2002 where his positions included Director of New Business Development, Production Manager and Gas and Power Operations Manager. Mr. Duginski is also an Assistant Secretary.

GEORGE T. CRAWFORD, 51, has been Senior Vice President of California Production since May 2009. Mr. Crawford served as Vice President of California Production from October 2005 until May 2009, Vice President of Production from December 2000 through October 2005 and as Manager of Production from January 1999 to December 2000. Mr. Crawford, a petroleum engineer, previously served as the Production Engineering Supervisor for Atlantic Richfield Corp. from 1989 to 1998, with numerous engineering and operational assignments, including Production Engineering Supervisor, Planning and Evaluation Consultant and Operations Superintendent.

GEORGE W. CIOTTI, 48, was promoted to Vice President of Rocky Mountain Production effective January 1, 2012. Mr. Ciotti was Vice President, Corporate Development from January 2010 until December 2011. Mr. Ciotti was Manager of Business Development from January 2009 through December 2009 and Senior Financial Analyst from December 2007 until December 2008. Immediately prior to joining Berry, Mr. Ciotti was President and Founder of a consulting company focused on financial and business services. He also had ten years of experience with Texaco in positions such as Assistant Controller and Senior Project Economist.

WALTER B. AYERS, 68, has held the position of Vice President of Human Resources since May 2006. Mr. Ayers was previously a private consultant to the energy industry from January 2002 until his employment with the Company. Mr. Ayers served as a Manager of Human Resources for Mobil Oil Corporation from June 1965 until December 2000.

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SHAWN M. CANADAY, 36, has held the position of Vice President of Finance and Treasurer since August 2009. Mr. Canaday was Vice President and Controller from June 2008 until July 2009 and was Interim Chief Financial Officer from June 2008 until August 2008. Mr. Canaday served as Controller from February 2007 to July 2009, as Treasurer from December 2004 to February 2007 and as Senior Financial Analyst from November 2003 until December 2004. Mr. Canaday has worked in the oil and natural gas industry since 1998 in various finance functions at Chevron and in public accounting. Mr. Canaday is also an Assistant Secretary.

DAVIS O. O'CONNOR, 57, has been the Vice President, General Counsel, and Secretary since October 2010. He previously served as a partner and an associate with the Denver law firm of Holland and Hart LLP since 1979 where he practiced in the areas of domestic and international business transactions including mergers, acquisitions, divestitures, joint ventures and related transactions, primarily in the oil and natural gas industry.

JAMIE L. WHEAT, 41, has held the position of Principal Accounting Officer since March 2010, and Controller since August 2009. Ms. Wheat was the Accounting Manager from August 2008 until August 2009. Prior to joining the Company, Ms. Wheat was a Senior Manager in the assurance practice group of KPMG, where she worked from 2001 to 2008.

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PART II

Item 5.    Market for the Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Shares of our Class A Common Stock and Class B Stock are each entitled to one vote and 95% of one vote, respectively. Each share of Class B Stock is entitled to a $0.50 per share preference in the event of liquidation or dissolution. Further, each share of Class B Stock is convertible into one share of Class A Common Stock at the option of the holder.

Our Class A Common Stock is listed on the New York Stock Exchange under the symbol BRY. The Class B Stock is not publicly traded. The market data and dividends for 2011 and 2010 are shown below:

	2011						2010
	Price Range				Dividends Per Share		Price Range				Dividends Per Share
	High		Low				High		Low
First Quarter	$	52.32	$	42.61	$	.075	$	31.27	$	25.62	$	.075
Second Quarter	53.76		44.13		.075		34.30		25.57		.075
Third Quarter	61.17		36.53		.080		32.23		24.30		.075
Fourth Quarter	47.92		30.62		.080		44.80		30.65		.075
Total Dividends Paid					$	.310					$	.300

There were 489 holders of record of our Class A Common Stock and one holder of record of our Class B Stock as of February 14, 2012.

Dividends

Our regular quarterly dividend is payable in March, June, September and December. In the third quarter of 2011, the regular quarterly dividend was increased from $0.075 per share to $0.08 per share, resulting in a regular annual dividend of $0.31 per share for 2011.

Since our formation in 1985 through December 31, 2011, we have paid dividends on our Common Stock for 89 consecutive quarters, and previous to that for eight consecutive semi-annual periods. We intend to continue the payment of dividends, although future dividend payments will depend upon our level of earnings, operating cash flow, capital commitments, financial covenants and other relevant factors. Dividend payments are limited by covenants in (i) our credit facility to the greater of $35 million or 75% of net earnings for any four quarter period, and (ii) the indentures governing our senior and subordinated notes to up to $0.36 per share annually (but in no event in excess of $20 million annually) in the event that we are not in default under such indentures, and up to $10 million in the event we are in a non-payment default under such indentures.

Equity Compensation Plan Information

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance
Equity compensation plans approved by security holders (1)	1,520,690	$	30.32	886,893
Equity compensation plans not approved by security holders	—	—		—

_______________________________________________________________________________

(1) Excludes 400,570 shares of restricted stock units for which the vesting period has not lapsed.

Issuer Purchases of Equity Securities

None.

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Performance Graph

This graph shall not be deemed "filed" for purposes of Section 18 of the Securities and Exchange Act of 1934 (the Exchange Act) or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933 or the Exchange Act, regardless of any general incorporation language in such filing.

Total returns assume $100 invested on December 31, 2006 in shares of Berry Petroleum Company, the Russell 2000, the Standard & Poors 500 Index and a Peer Group, assuming reinvestment of dividends for each measurement period. The information shown is historical and is not necessarily indicative of future performance. The 14 companies which make up the "Peer Group" are as follows: Bill Barrett Corp., Cabot Oil & Gas Corp., Cimarex Energy Co., Comstock Resources Inc., Denbury Resources Inc., Forest Oil Corp., Penn Virginia Corp., Plains Exploration & Production Co., Quicksilver Resources Inc., Sandridge Energy Inc., SM Energy Co., Stone Energy Corp., Swift Energy Co. and Whiting Petroleum Corp.

	12/06	12/07	12/08	12/09	12/10	12/11
Berry Petroleum Company	100.00	144.57	24.93	98.18	148.59	143.88
S&P 500	100.00	105.49	66.46	84.05	96.71	98.75
Russell 2000	100.00	98.43	65.18	82.89	105.14	100.75
Peer Group	100.00	138.37	60.49	91.69	116.56	106.44

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Item 6.    Selected Financial Data

The following table sets forth certain financial information and is qualified in its entirety by reference to the historical financial statements and notes thereto included in Item 8. Financial Statements and Supplementary Data. The financial information at December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009 was derived from our audited financial statements and the accompanying notes to those financial statements included in Item 8. Financial Statements and Supplementary Data in this Annual Report on Form 10-K. The financial information at December 31, 2009, 2008 and 2007 and for the years ended December 31, 2008 and 2007 was derived from unaudited financial data not included in the report.

	Year Ended December 31,
(in thousands, except per share, production, and per BOE data)	2011			2010		2009		2008		2007
Statements of Operations Data:
Operating Revenues (continuing operations)	$	919,558		$	676,510	$	559,403	$	746,632	$	478,099
Net (loss) earnings from continuing operations	(228,063		)	82,524		47,224		120,577		120,666
Basic net (loss) earnings per share from continuing operations	(4.21		)	1.54		1.03		2.67		2.71
Diluted net (loss) earnings per share from continuing operations	$	(4.21	)	$	1.52	$	1.02	$	2.64	$	2.67
Production Data (continuing operations):
Oil production (MBOE)	9,041			7,925		7,186		7,441		7,210
Natural gas production (MMcf)	23,907			23,988		20,982		18,323		8,817
Operating Data (continuing operations) (per BOE):
Average sales price(1)	$	71.59		$	53.69	$	41.23	$	73.64	$	52.30
Average operating costs—oil and natural gas production	18.23			15.95		14.66		17.99		15.09
Production taxes	2.58			1.93		1.70		2.56		1.69
G&A	4.74			4.43		4.61		5.17		4.57
DD&A—oil and natural gas production	$	16.42		$	15.05	$	13.10	$	11.97	$	9.55
Balance Sheet and Other Data (at period end):
Total assets	$	2,734,952		$	2,838,616	$	2,240,135	$	2,542,383	1,452,106
Long-term debt	1,380,192			1,108,965		1,008,544		1,131,800		445,000
Dividends per share	$	0.31		$	0.30	$	0.30	0.30		$	0.30
Cash Flow Data:
Cash flow from operations	$	455,899		$	367,237	$	212,576	409,569		$	238,879
Exploration and development of oil and natural gas properties	527,112			310,139		134,946		397,601		285,267
Property acquisitions	$	158,090		334,409		$	13,497	667,996		$	56,247

__________________________________________

(1) Excludes all effects of derivatives. See Part II, Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information regarding the effect of derivatives on our average realized price.

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

The following discussion and analysis should be read in conjunction with Item 6. Selected Financial Data and the accompanying financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The following discussion contains forward looking statements that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially because of a number of risks and uncertainties. Some of these risks and uncertainties are detailed in Part I, Item 1A. Risk Factors, and elsewhere in this Annual Report on Form 10-K.

Overview

Our results are directly related to the realized prices of oil, natural gas and electricity sold, the type and volume of oil and natural gas produced and electricity generated and the results of development, exploitation, acquisition and hedging activities. The realized prices for natural gas and electricity will fluctuate from one period to another due to regional market conditions and other factors, while oil prices are predominantly influenced by global supply and demand. Beginning in the second half of 2009 and through 2011, oil prices rebounded from the lows seen during the recent recession and financial crises. Natural gas prices have fallen significantly since their peak in the third quarter of 2008 and have remained low through 2011. The aggregate amount of oil and natural gas we produce may fluctuate based on the success of development and exploitation of oil and natural gas reserves pursuant to current reservoir management.

The principal influences on our operating costs include the cost of natural gas used in our steam operations and electrical generation, production rates, labor and equipment costs, maintenance expenses and production taxes. We have historically been a net producer of natural gas and have benefited operationally when natural gas prices increase. Our production of natural gas has, in the past, provided a form of natural hedge against rising steam costs. As our natural gas production continues to decrease and our use of natural gas for steaming operations increase, we may become a net consumer of natural gas and would no longer benefit operationally when natural gas prices increase.

Diatomite

We received a new full-field development approval in late July 2011 from the California Department of Conservation, Division of Oil, Gas and Geothermal Resources (DOGGR) with respect to our Diatomite assets. The approval contained operating requirements that were significantly more stringent than similar specifications contained in prior approvals from DOGGR. The development of our Diatomite assets and associated production growth were on track in 2011, but the implementation of these newer operating requirements negatively impacted the pace of drilling and steam injection, and this impact has continued into 2012. We are working constructively with DOGGR on the operating specifications for our Diatomite assets to enable an increase in the pace of our development.

On February 24, 2012, we received revisions to the July 2011 project approval letter, which, among other things, allow us to conduct mechanical integrity testing at least once every five years, rather than annually as provided in the original project approval letter. In addition, we are longer required to cease cyclic steaming operations on wells located within 150 feet of a failed well bore, subject to demonstrating to DOGGR that steam injection into such surrounding wells will be confined to the Diatomite zone. Our estimates of well performance and ultimate recovery for the asset remain unchanged. We are currently assessing the impact of the revised project approval letter on the development and operations of our Diatomite properties.

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Notable Items in 2011

• Generated an operating margin of $44.87 per BOE and discretionary cash flow of $461.9 million⁽¹⁾ 

• Increased oil production 14% and total production 9% to 35,687 BOE/D

• Increased our pre-tax PV10 value by 50% to $5.7 billion as a result of strong oil pricing, favorable heavy oil differentials and a 12% BOE increase in oil reserves⁽¹⁾ 

• Increased oil reserves to 68% of total proved reserves

• Acquired approximately 22,000 additional net acres in the Permian for $150.9 million, bringing our total Permian position to 42,000 net acres

• Drilled 69 net wells in the Permian and exited 2011 at 5,700 BOE/D

• Drilled 45 net wells in Uinta, including nine Uteland Butte horizontal wells

• Sold our California heavy oil at a $7.81 average premium to WTI

• Increased Diatomite production by 16% to 3,154 BOE/D

• Increased our borrowing base under our credit facility from $875 million to $1.4 billion and lender commitments from $875 million to $1.2 billion

• Repurchased $94.7 million aggregate principal amount of our 10.25% senior notes due 2014 (2014 Notes)

• Recorded an impairment of $625.0 million on our E. Texas properties due to low natural gas prices

Expectations for 2012

• Anticipating average production between 38,000 BOE/D and 39,000 BOE/D, a 6% to 9% increase over 2011, overcoming an expected 22% decrease in natural gas production

• Planning to invest our 2012 capital budget in our oil assets, targeting oil production growth of approximately 20% to over 75% of total production

• Expecting to drill approximately 100 Permian wells, increasing average production to approximately 7,500 BOE/D

• Expecting to drill over 70 Utah wells, including Green River/Wasatch commingled wells and Uteland Butte horizontal wells, increasing average production to approximately 6,000 BOE/D

• Continuing to work with DOGGR on Diatomite operating specifications to increase the pace of development

• Continuing to evaluate acquisition opportunities that fit into our core areas of operation

___________________________________________

(1) Discretionary cash flow, operating margin and pre-tax PV10 are non-GAAP measures and reference should be made to "Reconciliation of Non-GAAP Measures" in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations for further explanation as well as reconciliations to the most directly comparable GAAP measures.

2012 Capital Budget

We expect our 2012 capital budget, excluding acquisitions to range between $600 million and $650 million assuming an average commodity price of $90 WTI, which we expect to fund with net cash provided by our operating activities. To the extent net cash provided by operating activities is higher or lower than currently anticipated, we may adjust our capital budget accordingly or adjust borrowings under our credit facility, as needed.

Results of Operations

We experienced a net loss of $228.1 million, or $4.21 per diluted share, for the year ended December 31, 2011. The net loss included a charge of $385.3 million related to the impairment of our E. Texas natural gas properties, a charge of $38.0 million resulting from amortization of accumulated other comprehensive loss (AOCL) related to discontinuing hedge accounting, a charge of $9.2 million associated with repurchasing $94.7 million principal amount of our 2014 Notes and a charge of $2.6 million related to the impairment of our drilling rigs, partially offset by a gain of $56.0 million resulting from non-cash changes in fair value of derivative instruments and a gain of $2.6 million related to a retroactive payment adjustment for capacity from one of our electricity customers, in each case net of income taxes. Net cash provided by operating activities was $455.9 million and capital expenditures, excluding capitalized interest and property acquisitions, totaled $527.1 million. We drilled 367 net wells during 2011 and achieved average daily production of 35,687 BOE/D in 2011, an increase of 9% from 2010.

We experienced a net loss of $414.7 million, or $7.62 per diluted share, for the fourth quarter of 2011. The net loss included a charge of $387.6 million related to the impairment of our E. Texas natural gas properties, a charge of $58.9 million resulting from non-cash changes in the fair value of derivative instruments, a charge of $9.6 million resulting from amortization of AOCL related to discontinuing hedge accounting and a charge of $2.6 million related to the impairment of our drilling rigs, partially offset by a gain of $2.6 million related to a retroactive payment adjustment for capacity from one of

32

our electricity customers, in each case net of income taxes. Net cash provided by operating activities was $84.0 million and capital expenditures, excluding capitalized interest and property acquisitions, totaled $103.0 million. We drilled 94 net wells during the quarter and achieved average daily production of 35,790 BOE/D, a decrease of 3% from the third quarter of 2011, primarily due to more stringent operating regulations with respect to our Diatomite assets, imposed curtailments by our third-party processors in the Permian and the natural production declines at our Piceance and E. Texas properties.

33

Operating Data

The following table sets forth selected operating data for the years ended:

	December 31, 2011			%	December 31, 2010			%	December 31, 2009			%
Oil and Natural Gas
Heavy oil production (BOE/D)	17,397			49	17,124			52	16,842			56
Light oil production (BOE/D)	7,374			21	4,589			14	2,846			10
Total oil production (BOE/D)	24,771			70	21,713			66	19,688			66
Natural gas production (Mcf/D)	65,498			30	65,720			34	62,074			34
Total production (BOE/D)(1)	35,687			100	32,666			100	30,034			100
Less DJ production	—				—				765
Production—continuing operations (BOE/D)(1)	35,687				32,666				29,269
Oil and natural gas, per BOE, from continuing operations:
Average realized sales price	$	66.91			$	52.14			$	46.72
Average sales price including cash derivative settlements	$	65.68			$	53.84			$	46.02
Oil, per BOE, from continuing operations:
Average WTI price	$	95.11			$	79.59			$	62.09
Price sensitive royalties(2)	(3.60		)		(3.06		)		(2.04		)
Quality differential and other(3)	0.84				(8.92		)		(9.08		)
Oil derivatives non-cash amortization(4)	(6.77		)		(2.59		)		—
Oil derivatives cash settlements(5)	—				—				7.47
Correction to royalties payable(6)	—				—				(0.24		)
Oil revenue	$	85.58			$	65.02			$	58.20
Oil derivatives non-cash amortization(4)	6.77				2.59				—
Oil derivatives cash settlements(7)	(9.72		)		(0.90		)		(0.92		)
Average realized oil price	$	82.63			$	66.71			$	57.28
Natural gas, per Mcf, from continuing operations:
Average Henry Hub price per MMBtu	$	4.04			$	4.39			$	4.00
Conversion to Mcf	0.28				0.22				0.20
Natural gas derivatives non-cash amortization(4)	0.01				0.08				—
Natural gas derivative cash settlements(5)	—				—				0.23
Location, quality differentials and other	(0.23		)		(0.24		)		(0.59		)
Natural gas revenue	$	4.10			$	4.45			$	3.84
Natural gas derivatives non-cash amortization(4)	(0.01		)		(0.08		)		—
Natural gas derivative cash settlements(7)	0.46				0.37				(0.04		)
Average realized natural gas price	$	4.55			$	4.74			$	3.80

___________________________________________

(1) Oil equivalents are determined using the ratio of six Mcf of natural gas to one barrel of oil.

(2) Our Formax property in S. Midway is subject to a price-sensitive royalty burden. The royalty is 53% of the amount of the heavy oil posted price above a base price which was $17.09 per barrel in 2011 as long as we maintain a minimum steam injection level. We met the steam injection level in 2011 and expect to meet the requirement going forward. This base price escalates at 2% annually and will be $17.43 per barrel in 2012.

(3) In California, the differential at December 31, 2011, was $2.48 and ranged from a low of ($6.43) to a high of $22.77 per barrel during the year. In Utah, the differential at December 31, 2011,was ($13.75) and averaged ($14.10) during 2011.

(4) Non-cash amortization of AOCL resulting from discontinuing hedge accounting effective January 1, 2010. Recorded in sales of oil and natural gas.

(5) Includes cash settlements on hedges prior to January 1, 2010, for which we had elected hedge accounting. Recorded in sales of oil and natural gas.

(6) 2009 includes a correction to one of our royalties payable in the amount of $1.9 million, which resulted in decreasing our sales of oil and natural gas and increasing our royalties payable.

(7) Includes cash settlements on derivative instruments recorded in realized and unrealized (gain) loss on derivatives, net.

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The following table sets forth selected operating data for the three months ended:

	December 31, 2011			%	December 31, 2010			%	September 30, 2011			%
Oil and Natural Gas
Heavy oil production (BOE/D)	17,497			49	16,548			48	18,173			49
Light oil production (BOE/D)	8,166			23	6,131			18	7,918			22
Total oil production (BOE/D)	25,663			72	22,679			66	26,091			71
Natural gas production (Mcf/D)	60,759			28	70,828			34	64,950			29
Total production—continuing operations (BOE/D)(1)	35,790			100	34,484			100	36,916			100
Oil and natural gas, per BOE, from continuing operations:
Average realized sales price	$	69.29			$	53.55			$	66.74
Average sales price including cash derivative settlements	$	68.80			$	53.75			$	67.62
Oil, per BOE, from continuing operations:
Average WTI price	$	94.06			$	85.20			$	89.48
Price sensitive royalties(2)	(3.63		)		(3.37		)		(3.37		)
Quality differential and other(3)	4.75				(9.16		)		4.45
Oil derivatives non-cash amortization(4)	(6.76		)		(3.22		)		(6.56		)
Oil revenue	$	88.42			$	69.45			$	84.00
Oil derivatives non-cash amortization(4)	6.76				3.22				6.56
Oil derivative cash settlements(5)	(8.89		)		(4.35		)		(6.32		)
Average realized oil price	$	86.29			$	68.32			$	84.24
Natural gas, per Mcf, from continuing operations:
Average Henry Hub price per MMBtu	$	3.54			$	3.80			$	4.20
Conversion to Mcf	0.21				0.19				0.21
Natural gas derivatives non-cash amortization(4)	—				0.05				0.02
Location, quality differentials and other	(0.24		)		(0.14		)		(0.18		)
Natural gas revenue	$	3.51			$	3.90			$	4.25
Natural gas derivatives non-cash amortization(4)	—				(0.05		)		(0.02		)
Natural gas derivative cash settlements(5)	0.61				0.50				0.42
Average realized natural gas price	$	4.12			$	4.35			$	4.65

___________________________________________

(1) Oil equivalents are determined using the ratio of six Mcf of natural gas to one barrel of oil.

(2) Our Formax property in S. Midway is subject to a price-sensitive royalty burden. The royalty is 53% of the amount of the heavy oil posted price above a base price which was $17.09 per barrel in 2011 as long as we maintain a minimum steam injection level. We met the steam injection level in 2011 and expect to meet the requirement going forward. This base price escalates at 2% annually and will be $17.43 per barrel in 2012.

(3) In California, the differential at December 31, 2011, was $2.48 and ranged from a low of $2.48 to a high of $22.43 per barrel during the fourth quarter of 2011. In Utah, the differential at December 31, 2011, was ($13.75) and averaged ($13.13) during the fourth quarter of 2011.

(4) Non-cash amortization of AOCL resulting from discontinuing hedge accounting effective January 1, 2010. Recorded in sales of oil and natural gas.

(5) Includes cash settlements on derivatives recorded in realized and unrealized (gain) loss on derivatives, net.

35

The following table reflects our results from continuing operations (in thousands, except per share data):

	Twelve months ended,							Three months ended,
	December 31, 2011			December 31, 2010		December 31, 2009		December 31, 2011			December 31, 2010			September 30, 2011
Sales of oil	$	772,685		$	512,699	$	419,991	$	207,689		$	143,246		$	199,930
Sales of natural gas	98,088			106,909		80,541		19,609			25,359			25,395
Sales of oil and natural gas	$	870,773		$	619,608	$	500,532	$	227,298		$	168,605		$	225,325
Sales of electricity	34,953			34,740		36,065		10,750			7,427			9,826
Natural gas marketing	13,832			22,162		22,806		2,550			3,968			3,612
Settlement on Flying J bankruptcy claim	—			21,992		—		—			—			—
Gain (loss) on sale of assets	—			—		826		—			—			—
Interest and other income, net	1,784			3,300		1,810		390			980			463
Total revenues and other income	$	921,342		$	701,802	$	562,039	$	240,988		$	180,980		$	239,226
Net (loss) earnings from continuing operations	$	(228,063	)	$	82,524	$	47,224	$	(414,733	)	$	(21,145	)	$	134,001
Diluted net (loss) earnings per share from continuing operations	$	(4.21	)	$	1.52	$	1.02	$	(7.62	)	$	(0.40	)	$	2.42

Sales of Oil and Natural Gas

Sales of oil and natural gas increased $251.2 million, or 41%, to $870.8 million in 2011 from $619.6 million in 2010. The increase was primarily due to a 10% increase in sales volumes and an increase in the average sales price to $66.91 per BOE in 2011 from $52.14 per BOE in 2010, which includes an increase in the non-cash amortization of AOCL related to discontinuing hedge accounting to $60.9 million, or $4.68 per BOE, for 2011, compared to $18.4 million, or $1.55 per BOE, for 2010. Sales of oil and natural gas increased $119.1 million, or 24%, to $619.6 million for 2010 from $500.5 million for 2009. The increase was primarily due to a 11% increase in sales volumes and an increase in the average realized sales price to $52.14 per BOE in 2010 from $46.72 per BOE in 2009, which includes an increase in the non-cash amortization of AOCL related to discontinuing hedge accounting to $18.4 million, or $1.55 per BOE, for 2010. There was no non-cash amortization of AOCL related to discontinuing hedge accounting in 2009.

Total production from continuing operations in 2011 increased 3,021 BOE/D, or 9%, to 35,687 BOE/D, from 32,666 BOE/D in 2010, primarily due to development activities and the contribution of our acquisitions in the Permian, and partially offset by more stringent operating regulations with respect to our Diatomite assets, imposed curtailments by our third-party processors in the Permian and planned production declines at our Piceance and E. Texas properties. In 2011, we drilled a total of 367 net wells compared to 232 net wells in 2010. Total production from continuing operations increased 3,397 BOE/D, or 12%, to 32,666 BOE/D in 2010 from 29,269 BOE/D in 2009, primarily due to our development activities and the contribution of our acquisitions in the Permian. In 2010, we drilled a total of 232 net wells compared to 132 net wells in 2009.

Sales of Electricity

Sales of electricity increased $0.2 million, or 1%, to $34.9 million in 2011 from $34.7 million in 2010, primarily due to the refund of $4.1 million received in December 2011 from one of our electricity customers associated with a retroactive payment adjustment for capacity. As a result of the Global Settlement, we received retroactive payments for firm capacity that had been originally paid at "as available" capacity rates, and the payment received in December 2011 represents the difference in rates over the disputed period. This increase was offset by a 6% decrease in the average sales price of electricity and a 6% decrease in electric power sold associated with an increase in cogeneration unit downtime in 2011. Operating costs—electricity generation decreased $5.6 million, or 18%, to $25.7 million in 2011 from $31.3 million in 2010 primarily due to a 6% decrease in fuel gas cost and a 6% decrease in electric power produced related to increased cogeneration unit downtime in 2011.

Sales of electricity decreased $1.3 million, or 4%, to $34.7 million in 2010 from $36.1 million in 2009, primarily due to a $1.7 million adjustment received in 2009 relating to a retroactive revision to payments received from PG&E. Operating cost—electricity generation remained relatively unchanged in 2010 compared to 2009.

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	Year Ended December 31,
	2011		2010		2009
Electricity
Sales of electricity (in thousands)	$	34,953	$	34,740	$	36,065
Operating costs (in thousands)	$	25,690	$	31,295	$	31,400
Electric power produced—MWh/D	1,968		2,088		2,098
Electric power sold—MWh/D	1,806		1,925		1,907
Average sales price/MWh	$	47.00	$	50.06	$	60.99
Fuel gas cost/MMBtu (including transportation)	$	4.20	$	4.49	$	3.86

We purchased approximately 25,000 MMBtu/D, 27,000 MMBtu/D and 27,000 MMBtu/D of natural gas as fuel in our cogeneration facilities for the years ended December 31, 2011, 2010 and 2009, respectively. We purchase and transport, on average, 12,000 MMBtu/D on the Kern River Pipeline under our firm transportation contract

Natural Gas Marketing

We have long-term firm transportation contracts on the Rockies Express, Wyoming Interstate Company (WIC), and Ruby pipelines, each with total average capacities of 35,000 MMBtu/D. Demand charges for our capacity are reflected in operating costs-oil and natural gas production in our Statements of Operations. Our current production is insufficient to fully utilize this capacity. To optimize our remaining capacity, we purchase third-party natural gas at the market rate in our producing areas utilizing FERC-approved asset management agreements. Sales and purchases of third-party natural gas are recorded under natural gas marketing in the revenues and expenses section of the Statement of Operations, respectively.

The pre-tax net of our natural gas marketing revenue and our natural gas marketing expense for the years ended December 31, 2011, 2010 and 2009 was $0.8 million, $2.3 million and $1.6 million, respectively.

Realized and Unrealized (Gain) Loss on Derivatives, Net

Realized and unrealized (gain) loss on derivatives, net is primarily related to derivative instruments for which we did not elect hedge accounting or derivatives which did not qualify for hedge accounting either at the inception of the derivative instrument or where hedge accounting was discontinued during the term of the derivative instrument. When the criteria for hedge accounting is not met or when hedge accounting is not elected, realized gains and losses (e.g., cash settlements) and unrealized gains and losses (e.g., non-cash changes in fair value) are recorded in realized and unrealized (gain) loss on derivatives, net in our Statements of Operations. Conversely, cash settlements of derivative instruments accounted for under hedge accounting are recorded as additions to or reductions of sales of oil and natural gas or interest expense, while changes in fair value of derivative instruments are recognized, to the extent the hedge is effective, in AOCL until the hedged item is recognized in earnings. Realized and unrealized (gain) loss on derivatives, net also includes any hedge ineffectiveness on cash flow hedges accounted for under hedge accounting.

During 2009, we entered into commodity derivative instruments for which we did not elect hedge accounting. In addition, effective January 1, 2010, we elected to discontinue hedge accounting for all of our commodity and interest rate derivative instruments for which we had previously elected hedge accounting, and have elected to discontinue all hedge accounting prospectively. Accordingly, beginning January 1, 2010, changes in the fair value of derivative instruments are recognized immediately in net earnings in our Statements of Operations. Cash flows from operating activities are impacted to the extent that actual cash settlements under our derivative instruments result in making or receiving a payment to or from a counterparty, and such cash settlement gains and losses are recorded under the caption realized and unrealized (gain) loss on derivatives, net in our Statements of Operations. See Notes 8 and 9 to the Financial Statements. Also, See Part II, Item 7A. "Quantitative and Qualitative Disclosures About Market Risk" for further details concerning our hedging activities.

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The following table sets forth the cash settlements and non-cash fair value gains and losses recorded in realized and unrealized (gain) loss on derivatives, net:

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Cash receipts payments (receipts):
Commodity derivatives—oil	$	87,747		$	7,078		$	6,671
Commodity derivatives—natural gas	(10,806		)	(8,889		)	888
Financial derivatives—interest(1)	—			17,499			—
Total cash payments	$	76,941		$	15,688		$	7,559
Non-cash fair value (gain) loss:
Commodity derivatives—oil	$	(89,478	)	$	37,440		$	—
Commodity derivatives—natural gas	(1,371		)	(12,424		)	(355		)
Financial derivatives—interest(1)	—			(8,857		)	—
Total fair value (gain) loss	$	(90,849	)	$	16,159		$	(355	)
Realized and unrealized (gain) loss on derivatives, net	$	(13,908	)	$	31,847		$	7,204

_______________________________________

(1) In the fourth quarter of 2010, we terminated certain interest rate derivative instruments for which we had previously elected hedge accounting. The termination resulted in a cash settlement of $10.8 million, offset by a fair value gain of $8.9 million.

During the year ended December 31, 2009, we recorded $0.6 million under the caption realized and unrealized (gain) loss on derivatives, net as a result of ineffectiveness on cash flow hedges.

Settlement of Flying J Bankruptcy

On July 6, 2010, the Joint Plan of Reorganization of Flying J, Inc., Big West of California, LLC, Big West Oil, LLC, Big West Transportation, LLC and Longhorn Partners Pipeline, L.P. was confirmed under Chapter 11 of the United State Bankruptcy Code. Additionally, the United States Bankruptcy Court approved and confirmed the June 15, 2010 Stipulation and Agreed Order (the Stipulation) with Flying J Inc. and certain of its affiliates (collectively Flying J), regarding the resolution of our claim in Flying J's pending bankruptcy. Pursuant to the Stipulation, we and Flying J agreed that the total amount owed to us by Flying J for the purchases of our California production and other damages was $60.5 million and, as a result, we received $60.5 million in cash on July 23, 2010.

Oil and Natural Gas Operating and Other Expenses

The following table presents information about our oil and natural gas operating and other expenses from continuing operations for each of the years ended December 31:

	Amount per BOE						Amount (in thousands)
	2011		2010		2009		2011		2010		2009
Operating costs—oil and natural gas production	$	18.23	$	15.95	$	14.66	$	237,476	$	190,218	$	156,612
Production taxes	2.58		1.93		1.70		33,617		22,999		18,144
DD&A—oil and natural gas production	16.42		15.05		13.10		213,859		179,432		139,919
G&A	4.74		4.43		4.61		61,727		52,846		49,237
Interest	5.59		5.58		4.67		72,807		66,541		49,923
Total	$	47.56	$	42.94	$	38.74	$	619,486	$	512,036	$	413,835

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• Operating costs—oil and natural gas production were $237.5 million in 2011, an increase of $47.3 million, or 25%, from $190.2 million in 2010. On a per BOE basis, operating costs—oil and natural gas production were $18.23 per BOE in 2011, an increase of $2.28 per BOE, or 14%, from $15.95 per BOE in 2010. The increase primarily results from higher steam costs resulting from higher volumes of injected steam, partially offset by a decrease in natural gas fuel cost and increases in water hauling and disposal costs, well maintenance and workover costs, contract labor costs and transportation costs. Operating costs—oil and natural gas production were $190.2 million in 2010, an increase of $33.6 million, or 21%, compared to $156.6 million in 2009. On a per BOE basis, operating costs—oil and natural gas production were $15.95 per BOE in 2010, an increase of $1.29 per BOE, or 9%, from $14.66 per BOE in 2009. The increase was primarily due to higher steam costs resulting from higher volumes of injected steam and higher natural gas fuel costs, higher expenditures for well workovers and higher compression, gathering, and dehydration costs.

Firm transportation costs totaled $21.4 million, $16.2 million and $16.1 million for the years ended December 31, 2011, 2010 and 2009, respectively. The increase in firm transportation costs in 2011 was due primarily to the commencement of Ruby Pipeline operations in July 2011.

The following table presents steam information:

	Year Ended December 31,
	2011		2010		2009
Average volume of steam injected (Bbl/D)	133,404		116,956		109,153
Fuel gas cost/MMBtu (including transportation)	$	4.20	$	4.49	$	3.86
Approximate net fuel gas volume consumed in steam generation (MMBtu/D)	44,235		36,020		30,462

• Production taxes were $33.6 million in 2011, an increase of $10.6 million, or 46%, from $23.0 million in 2010. On a per BOE basis, production taxes were $2.58 per BOE in 2011, an increase of $0.65, or 34%, from $1.93 per BOE in 2010. The increase in production taxes was primarily due to an increase in the assessed ad valorem values attributed to our California properties and an increase in the number of wells outside California, where property taxes are based largely on assessed value per well. Additionally, our severance taxes increased in 2011, largely due to increased commodity prices. Production taxes were $23.0 million in 2010, an increase of $4.9 million, or 27%, from $18.1 million in 2009. On a per BOE basis, production taxes were $1.93 per BOE in 2010, an increase of $0.23 per BOE, or 14%, from $1.70 per BOE in 2009. The increase in production taxes was primarily due to an increase in the assessed ad valorem values attributed to our California properties. In addition, our West Texas and Utah properties contributed to a higher cost per BOE due to severance taxes tied to the field sales price of the commodity.

• Depreciation, depletion and amortization—oil and natural gas production (DD&A—oil and natural gas production) was $213.9 million in 2011, an increase of $34.4 million, or 19%, from $179.4 million in 2010. On a per BOE basis, DD&A—oil and natural gas production was $16.42 per BOE in 2011, an increase of $1.37 per BOE, or 9%, from $15.05 per BOE in 2010. The increase in DD&A—oil and natural gas production per BOE is primarily due to an overall shift in production volumes to our assets outside of California, which have higher drilling and leasehold acquisition costs than our California properties. In 2011, 49% of our production volumes were heavy oil produced in California, compared to 52% of our production volumes in 2010. DD&A—oil and natural gas production was $179.4 million in 2010, an increase of $39.5 million, or 28%, from $139.9 million in 2009. On a per BOE basis, DD&A—oil and natural gas production was $15.05 per BOE in 2010, an increase of $1.95, or 15%, from $13.10 per BOE in 2009. The increase in DD&A—oil and natural gas production per BOE was primarily due to the contribution of our development properties with higher drilling and leasehold acquisition costs than our California properties, including our recent acquisitions in the Permian and a shift in production volumes to assets outside of California.

• General and administrative expense (G&A) was $61.7 million in 2011, an increase of $8.9 million, or 17%, from $52.8 million in 2010. On a per BOE basis, G&A was $4.74 per BOE in 2011, an increase of $0.31 per BOE, or 7%, from $4.43 per BOE in 2010. The increase is due in part to higher employee salary and benefit costs. As of December 31, 2011, we had 317 full-time employees compared to 270 as of December 31, 2010. The increase in employees was primarily due to our acquisitions in the Permian and additional personnel required for our growing capital program and production levels. Additionally, G&A increased due to higher consulting costs directly attributable to our efforts to comply with new regulations in California, as well as our growing capital program and production levels. G&A was $52.8 million in 2010, an increase of $3.6 million, or 7%, from $49.2 million in 2009. On a per BOE basis, G&A was $4.43 per BOE in 2010, a decreased of $0.18 per BOE, or 4%, from $4.61 per BOE in 2009. The increase was largely

39

due to increases in employee compensation, including bonuses, related to increased employees in the Permian and to support increasing production. The decrease in G&A on a per BOE basis was due to increased production.

• Interest was $72.8 million in 2011, an increase of $6.3 million, or 9%, from $66.5 million in 2010. The increase in interest is a result the issuance of our 6.75% senior notes due 2020 (2020 Notes) in November 2010 and an increase in the average amount of borrowings outstanding under our credit facility. These increases were partially offset by a decrease in non-cash derivative losses of $7.5 million related to the de-designated interest rate hedges reclassified from AOCL into interest expense and a decrease in interest payments related to the repurchase of $94.7 million aggregate principal amount of our 2014 Notes in September and October of 2011. Interest was $66.5 million in 2010, an increase of $16.6 million, or 33%, compared to $49.9 million in 2009. Interest in 2010 included non-cash derivative losses of $8.3 million related to the de-designated interest rate hedges reclassified from AOCL into interest . In addition, interest increased due to the issuances of our 2014 Notes in May and August of 2009 and our 2020 Notes in November 2010, partially offset by a decrease in the average amount of borrowings outstanding under our credit facility.

Extinguishment of Debt. We recorded debt extinguishment costs of $15.5 million, $0.6 million and $10.8 million in 2011, 2010 and 2009, respectively. In 2011, we wrote off $15.0 million in conjunction with the repurchase of $94.7 million aggregate principal amount of our 2014 Notes, consisting of $11.5 million in premium paid over par and $3.5 million in write-offs of net discount and deferred financing costs. We also wrote off $0.5 million associated with one lender that did not renew its commitment under our credit facility in October 2011. In 2010, we wrote off $0.6 million associated with borrowing base changes under our credit facility. In 2009, we wrote off costs associated with borrowing base changes under our credit facility and fees associated with the extinguishment of our second lien term loan.

Transaction Costs on Acquisitions. In 2010, we incurred $2.6 million of acquisition related expenses for the acquisition of certain properties in the Permian. See Note 2 to the Financial Statements.

Impairment of Oil and Natural Gas Properties. We recorded non-cash impairments of oil and natural gas properties in continuing operations of $625.6 million, $0.0 million, and $1.0 million, in 2011, 2010 and 2009, respectively.

In the fourth quarter of 2011, we recorded a non-cash impairment of $625.0 million related our E. Texas natural gas properties. The impairment was due to decreases in natural gas prices and, as a result, changes in our development plans. In the fourth quarter of 2011, the NYMEX HH five-year future strip (the average of the settlement prices of the next 60 months' futures contracts) decreased approximately 15%. The assets were written down to their estimated fair value. Further, in 2011, 2010 and 2009, we recorded non-cash impairments in continuing operations of $0.6 million, $0 million and $1.0 million related to the expiration of acreage primarily in the Uinta. See Notes 9 and 11 to the Financial Statements.

In 2009, we recorded a non-cash impairment in discontinued operations of $9.6 million related to the sale of our DJ assets. See Note 2 to the Financial Statements.

Dry Hole, Abandonment, Impairment and Exploration. We recorded dry hole, abandonment and impairment charges of $5.2 million, $1.5 million and $4.2 million in 2011, 2010 and 2009, respectively. In 2011, we recorded a $4.3 million impairment charge related to the write-down of three rigs to their fair value. In 2010, we recorded dry hole expense due to a mechanical failure encountered on one well in the Piceance. In 2009, we recorded a $4.2 million impairment charge related to the write-down of a rig to its fair value. See Notes 9 and 11 to the Financial Statements.

We incurred exploration costs in 2011, 2010 and 2009, of $0.1 million, $0.8 million and $0.2 million, respectively. These costs consist primarily of geological and geophysical costs.

Bad Debt (Recovery) Expense. On July 6, 2010, the Joint Plan of Reorganization of Flying J was confirmed under Chapter 11 of the United States Bankruptcy Code. Additionally, the United States Bankruptcy Court approved and confirmed the Stipulation, pursuant to which Flying J agreed that the total amount owed to us by Flying J was $60.5 million and, as a result, we received $60.5 million in cash on July 23, 2010. In 2010, we recorded a settlement of our Flying J bankruptcy claim of $22.0 million and a bad debt recovery of $38.5 million.

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Income Tax (Benefit) Expense. Our effective income tax rates for the years ended December 31, 2011, 2010, and 2009 were 38%, 40% and 30%, respectively. In 2011, we recorded an income tax benefit due to a pre-tax loss as a result of the impairment of our E. Texas natural gas properties. In 2009, the effective income tax rate was impacted by reduced state rates and a decrease in our liability related to uncertain income tax positions. Our estimated annual effective income tax rate varies from the 35% federal statutory rate due to the effects of state income taxes and estimated permanent differences (i.e., differences between book earnings and taxable income that are not expected to reverse in future periods). See Note 5 to the Financial Statements.

Estimated 2012 Oil and Natural Gas Operating, G&A and Interest Expense. We estimate our 2012 production volume will range between 38,000 BOE/D and 39,000 BOE/D. Based on WTI of $90.00 and NYMEX HH of $3.00 MMBtu, we expect our oil and natural gas operating and other expenses to be within the following ranges:

	Amount per BOE
	Anticipated range in 2012	2011		2010
Operating costs—oil and natural gas production	$17.00 - 19.50	$	18.23	$	15.95
Production taxes	2.50 - 3.25	2.58		1.93
DD&A	15.00 - 18.00	16.42		15.05
G&A	4.25 - 5.50	4.74		4.43
Interest expense	5.50 - 6.25	5.59		5.58
Total	$44.25 - 52.50	$	47.56	$	42.94

Financial Condition, Liquidity and Capital Resources

Our development, exploitation and acquisition activities require us to make significant operating and capital expenditures. Historically, we have used cash flow from operations and borrowings under our credit facility as our primary sources of liquidity. The debt and equity capital markets have served as our primary source of financing to fund large acquisitions and other transactions. Our ability to access the debt and equity capital markets on economical terms is affected by general economic conditions, the financial markets, the credit ratings assigned to our debt by independent credit rating agencies, our operational and financial performance, the value and performance of equity and debt securities, prevailing commodity prices, and other macroeconomic factors outside of our control. We have also engaged in asset monetization transactions as a source of financing, as market conditions have permitted. In April 2009, we sold our assets in the DJ for $139.8 million, and in July 2009 we completed the sale of our E. Texas natural gas gathering system for $18.4 million. As we pursue profitable reserves and production growth, we continually monitor the capital resources, including the issuance of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activity and liquidity.

At December 31, 2011, we had a working capital deficit of approximately $63.5 million. We generally maintain a working capital deficit because we use excess cash to reduce outstanding borrowings under our credit facility. Our working capital fluctuates for various reasons, including changes in the fair value of our commodity derivative instruments.

Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations. We employ derivative instruments in our risk management strategy in an attempt to minimize the adverse effects of wide fluctuations in the commodity prices on our cash flows. As of December 31, 2011, we had hedged approximately 70% and 40% of our expected oil production in 2012 and 2013 in the form of swaps and collars. This level of derivatives is expected to provide a measure of certainty of the cash flows that we will receive for a portion of our production in 2012 and 2013. In the future, we may increase or decrease our derivative positions. At December 31, 2011, all of our derivatives counterparties were commercial banks that are parties, or affiliates of parties, to our credit facility. See Part II, Item 7A. "Quantitative and Qualitative Disclosures About Market Risk" for further details concerning our hedging activities.

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Revolving Credit Facility. Our senior secured revolving credit facility, which matures in May 2016, has a current borrowing base of $1.4 billion, subject to lender commitments. On October 26, 2011, as part of the semi-annual borrowing base redetermination process, we entered into an amendment to the credit facility which, among other things, increased total lender commitments to $1.2 billion. Borrowings under our credit facility bear interest at either (i) LIBOR plus a margin between 1.50% and 2.50% or (ii) the prime rate plus a margin between 0.50% and 1.50%, in each case, based on the amount utilized. The annual commitment fee on the unused portion of the credit facility ranges between 0.35% to 0.50% based on the amount utilized.

As of December 31, 2011, outstanding borrowings under the facility were $531.5 million (excluding $23.2 million of outstanding letters of credit), leaving $645.3 million in borrowing capacity available under the credit facility. The maximum amount available under the credit facility is subject to semi-annual redeterminations of the borrowing base in April and October of each year, based on the value of our proved oil and natural gas reserves, in accordance with the lenders' customary procedures and practices. We and the lenders each of a right to one additional redetermination each year.

The credit facility contains certain covenants, which, among other things, require the maintenance of (i) an interest coverage ratio of 2.75 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0. The facility also contains other customary covenants, subject to certain agreed exceptions, including covenants restricting our ability to, among other things, owe or be liable for indebtedness; create, assume or permit to exist liens; be a party to or be liable on any hedging contract; engage in mergers or consolidations; transfer, lease, exchange, alienate or dispose of our material assets or properties; declare dividends on or redeem or repurchase our capital stock; make any acquisitions of, capital contributions to or other investments in any entity or property; extend credit or make advances or loans; engage in transactions with affiliates; and enter into, create or allow to exist contractual obligations limiting our ability to grant liens on our assets to the lenders under the senior secured revolving credit facility. We are currently in compliance with all financial covenants and have complied with all financial covenants for each of the years ended December 31, 2010 and 2009.

Subject to certain agreed limitations, we granted first priority security interests over substantially all of our assets in favor of the lenders under the senior secured revolving credit facility.

Money Market Line of Credit. Our senior secured uncommitted money market line of credit has a borrowing capacity of up to $40 million for a maximum of 30 days. As of December 31, 2011, there were no borrowings outstanding under the money market line of credit. Amounts borrowed under the money market line of credit bear interest at LIBOR plus a margin of approximately 1.4%. The line of credit is not currently unavailable to us and we do not know when or if the line of credit will be available in the future.

Other Outstanding Indebtedness. As of December 31, 2011, in addition to our credit facility, we had the following long-term debt outstanding:

• $200 million aggregate principal amount of our 8.25% senior subordinated notes due 2016 (2016 Notes);

• $355.3 million aggregate principal amount of our 2014 Notes; and

• $300 million aggregate principal amount of our 2020 Notes.

The indentures governing our senior and subordinated notes contain provisions that limit our ability to incur, assume or guarantee additional indebtedness; issue redeemable stock and preferred stock; pay dividends or distributions or redeem or repurchase capital stock; prepay, redeem or repurchase debt that is junior in right of payment to our senior and subordinated notes; make loans and other types of investments; incur liens; restrict dividends, loans or asset transfers from our subsidiaries; sell or otherwise dispose of assets, including capital stock of subsidiaries; consolidate or merge with or into, or sell substantially all of our assets to, another person; enter into transactions with affiliates; and enter into new lines of business. Upon specified change in control events, we will be required to make offers to repurchase our senior and subordinated notes at amounts specified in the indentures governing such notes.

From August to October 2011, we repurchased $94.7 million aggregate principal amount of our 2014 Notes for an aggregate purchase price of $108.8 million, including accrued and unpaid interest. These notes were repurchased using available borrowings under our credit facility. We may from time to time seek to repurchase our outstanding notes, including additional 2014 Notes, through open market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts repurchased may be material.

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Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody's Investor Services and Standard & Poor's Rating Services currently rate our outstanding notes and have assigned us a credit rating. We do not have any provisions that are linked to our credit ratings, nor do we have any credit rating triggers that would accelerate the maturity of amounts due under our currently outstanding debt. However, our ability to raise funds and the costs of any financing activities will be affected by our credit rating at the time any such financing activities are conducted.

Historical Cash Flows. Cash flows provided by operating activities are primarily affected by the price of oil and natural gas, sales volumes and changes in working capital. The increase in net cash provided by operating activities of $88.7 million in 2011 compared to 2010 is primarily due to a 28% increase in average commodity sales prices and a 10% increase in sales volume. The increase in net cash provided by operating activities of $154.7 million in 2010 compared to 2009 is primarily due to a 12% increase in average commodity sales prices and a 11% increase in sales volume.

Cash flows used by investing activities are primarily comprised of development, exploitation and acquisition of oil and natural gas properties net of dispositions of oil and natural gas properties. The increase in net cash used in investing activities of $38.2 million in 2011 compared to 2010 is due to an increase in development expenditures offset by a decrease in expenditures for property acquisitions in 2011 as compared with 2010. The increase in net cash used in investing activities of $634.1 million in 2010 compared to 2009 is due to an increase in development expenditures and an increase in acquisition activities in 2010 compared with 2009.

Net cash provided by financing activities in 2011 includes net borrowings under our credit facility of $361.5 million, partially offset by the repurchase of $94.7 million aggregate principal amount of our 2014 Notes. Net cash provided by financing activities in 2010 included net proceeds of $224.0 million from the issuance of 8 million shares of our Class A Common Stock and $300.0 million aggregate principal amount of our 2020 Notes, partially offset by debt issuance costs of $15.2 million and net repayment of our outstanding borrowings under our credit facility and our money market line of credit of $196.7 million. Net cash used in financing activities in 2009 included $585.1 million net repayment on our outstanding borrowings under our credit facility and money market line of credit and $24.0 million of debt issuance costs, partially offset by the issuance of $450.0 million aggregate principal amount of our 2014 Notes for net proceeds of $435.0 million after underwriting discounts and estimated offering expenses.

Capital Expenditures. The following is a summary of the drilling and development capital expenditures:

(in thousands)	Year Ended December 31,
Asset Team	2011		2010		2009
S. Midway	$	47,000	$	35,000	$	24,000
N. Midway	156,000		67,000		32,000
Permian	218,000		42,000		—
Uinta	63,000		50,000		6,000
E. Texas	11,000		71,000		47,000
Piceance	31,000		45,000		26,000
Corporate	1,000		—		—
Total	$	527,000	$	310,000	$	135,000

We continually evaluate our capital needs and compare them to our capital resources. We establish a capital budget for each calendar year based on our development opportunities and the expected cash flow from operations for that year. We may revise our capital budget during the year as a result of acquisitions and/or drilling outcomes or significant changes in cash flows. We expect our 2012 capital budget to be between $600 million and $650 million, assuming an average commodity price of $90 WTI, and we expect to fund our 2012 capital budget largely with net cash provided by our operating activities. To the extent net cash provided by operating activities is higher or lower than currently anticipated, we may adjust our capital budget accordingly or adjust borrowings under our credit facility, as needed. Substantially all of our 2012 capital expenditure budget is directed towards our oil assets, targeting oil production growth of approximately 20%.

Although we have no specific budget for property acquisitions in 2012, we will continue to selectively pursue property acquisitions that complement our existing core property base. We believe that, should attractive acquisition opportunities be presented, we will be able to finance additional capital expenditures with cash flows from operating activities, borrowings under our credit facility, issuances of additional debt or equity, or agreements with industry partners.

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Contractual Obligations

Our contractual obligations as of December 31, 2011 are as follows:

(in millions)	Total		2012		2013		2014		2015		2016		Thereafter
Long-term debt and interest(1)	$	1,780.2	$	83.9	$	83.9	$	417.9	$	47.5	$	769.4	$	377.6
Asset retirement obligations(2)	64.0		4.7		3.8		3.6		3.6		3.6		44.7
Operating leases(3)	11.8		2.8		2.8		2.6		2.2		1.4		—
Other commitments (4)	31.3		14.2		11.4		1.8		1.9		2.0		—
Drilling rig commitments(5)	7.0		7.0		—		—		—		—		—
Firm natural gas transportation contracts(6)	263.5		29.7		30.2		32.7		32.6		32.5		105.8
Derivative liabilities(7)	35.9		20.4		15.5		—		—		—		—
Total	$	2,193.7	$	162.7	$	147.6	$	458.6	$	87.8	$	808.9	$	528.1

___________________________________________

(1) Long-term debt consists of our 2016 Notes, 2014 Notes, 2020 Notes and outstanding debt under our credit facility, and assumes no principal repayment until the due date of the instruments. Cash interest expense on our credit facility is estimated assuming no principal repayment until the instrument due date and is estimated at a constant interest rate of 2.018%.

(2) The ultimate settlement amounts and the timing of the settlement of such obligations are unknown because they are subject to, among other things, federal, state, local, and tribal regulation and economic factors. See Part II, Item 7A. "Critical Accounting Policies and Estimates" for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(3) Operating leases relate primarily to obligations associated with our office facilities, equipment, vehicles and aircraft.

(4) Other commitments relate primarily to natural gas purchases, cogeneration facility management services and equipment rentals.

(5) We currently have four drilling rigs under contract that require minimum payments for the full contract term or penalties upon early termination. All these drilling rig contracts expire in 2012. Contracts for all other rigs performing work for us at December 31, 2011 were on a well-by-well basis and could be released without penalty at the conclusion of drilling on the current well, and therefore have not been included in the table above.

(6) We enter into certain firm commitments to transport natural gas production to market and to transport natural gas for use in our cogeneration and conventional steam generation facilities. These commitments generally require a minimum monthly charge regardless of whether the contracted capacity is used or not. These commitments include a transportation agreement with Questar Pipeline Company for an average of 6,200 MMBtu/D of firm transportation over a period of eight years, based on the expectation that the expansion of the Chipeta Processing LLC natural gas plant will be completed and transportation under this contract will begin July 1, 2012.

(7) Derivative liabilities represent the fair value of our derivatives presented as net liabilities in our Balance Sheets as of December 31, 2011. These amounts represent open commodity derivative instruments that were in a net liability position with the counterparty at December 31, 2011. Our remaining commodity derivative instruments were in a net asset position with the counterparty at December 31, 2011. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See Notes 8 and 9 to the Financial Statements. Also, See Part II, Item 7A. "Quantitative and Qualitative Disclosures About Market Risk" for further details concerning our hedging activities.

Based on current oil and natural gas prices and anticipated levels of production, we believe that we have sufficient liquidity and capital resources to execute our business plans over the next 12 months and for the foreseeable future. In addition, with our expected cash flow streams, commodity price hedging strategies, current liquidity levels, access to debt and equity markets and flexibility to modify future capital expenditure programs, we expect to be able to fund all planned capital programs, dividend distributions and debt repayments; while complying with our debt covenants and meeting any other obligations that may arise from our oil and natural gas operations. However, if our revenue and cash flow decrease in the future as a result of a deterioration in domestic and global economic conditions or a significant decline in commodity prices, we may elect to reduce our planned capital expenditures. We believe that this financial flexibility to adjust our spending levels will provide us with sufficient liquidity to meet our financial obligations. See Part I, Item 1A—"Risk Factors," for a discussion of the risks and uncertainties that affect our financial condition, results of operation, and operating cash flows.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make certain assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses and to disclose contingent assets and liabilities at the date of our financial statements. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. A summary of our significant accounting policies is detailed in Note 1 to our Financial Statements. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management.

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Successful Efforts Method of Accounting. We account for our oil and natural gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion. Exploratory wells that discover potentially economic reserves that are in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized as long as the additional exploratory work is under way or firmly planned. The costs of development wells are capitalized whether productive or nonproductive.

Impairment of Oil and Natural Gas Properties. Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis, annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of our oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows.Due to the impact of lower natural gas prices, we recorded an impairment of $625.0 million related to our E. Texas natural gas assets. See Notes 9 and 11 to the Financial Statements.

Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, we will recognize an impairment loss at that time.

Oil and Natural Gas Reserves. Estimated proved reserves included in this Annual Report on Form 10-K were prepared by DeGolyer and MacNaughton (D&M), an independent petroleum engineering consulting firm that has provided consulting services throughout the world for over 70 years. Estimated proved reserves presented in this report are calculated in accordance with the SEC's "Modernization of Oil and Gas Reporting" rule which was first effective for December 31, 2009 reporting. These rules include calculating estimated proved reserves based on the average prices during the twelve-month period prior to the reporting date, with such prices determined as the unweighted arithmetic average of the first-day-of-the month prices for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition to the physical factors such as the results of drilling, testing, and production subsequent to the date of an estimate, economic factors such as changes in commodity prices or development and production expenses, may require revision of such estimates. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserve estimates. See Part I, Item 1A—"Risk Factors," for a description of some of the risks and uncertainties associated with our business and reserves.

Depreciation, Depletion and Amortization (DD&A-oil and natural gas production). The provision for DD&A-oil and natural gas production is calculated on a field-by-field basis using the unit-of-production method. Projected future production rates, the timing of future capital expenditures as well as changes in commodity prices, may significantly impact estimated reserve quantities. DD&A—oil and natural gas production is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. These estimates are subject to change as additional information and technologies become available. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different than projected. Reduction in reserve estimates may result in increased DD&A oil and natural gas production, which in turn reduces net earnings. Changes in reserve estimates are applied on a prospective basis. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher costs fields.

Capitalized Interest. Acquisition costs of proved undeveloped and unproved properties qualify for interest capitalization during a period if interest cost is incurred and activities necessary to bring the properties into a productive state are in progress. As wells are drilled in a field with proved undeveloped or unproved reserves, a portion of the acquisition costs are either re-

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designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, we determine the amount of the acquisition cost to re-designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field.

Purchase Price Allocations. We occasionally acquire assets and assume liabilities in transactions accounted for as business combinations. In connection with a purchase business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess of the purchase price over amounts assigned to assets and liabilities is recorded as goodwill. Any excess of amounts assigned to assets and liabilities over the purchase price is recorded as a gain on bargain purchase. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the value attributed to assets acquired and liabilities assumed.

In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method estimates future cash flows based on management’s expectations of future recoverable proved and risk-adjusted probable reserves, commodity prices based on commodity futures price strips, production timing, drilling and production costs and a risk-adjusted discount rate.

Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in higher DD&A-oil and natural gas production, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value.

Derivatives and Hedging. We periodically enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility. We also enter into derivative contracts to mitigate the risk of interest rate fluctuations. The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in accumulated other comprehensive loss until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the statements of operations because changes in fair value of the derivative offsets changes in the fair value of the hedged item. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings. The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, whether or not the forecasted hedged transaction will occur, option pricing models, futures prices, volatility, and time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. Effective January 1, 2010, we elected to de-designate all of our commodity and interest rate contracts that had previously been designated as cash flow hedges as of December 31, 2009 and have elected to discontinue hedge accounting prospectively.

Due to the volatility of oil and natural gas prices and interest rates, the estimated fair values of our derivative instruments are subject to large fluctuations from period to period. See Part II, Item 7A—"Quantitative and Qualitative Disclosures about Market Risk" for a sensitivity analysis of the change in net fair values of our commodity and interest rate derivatives based on a hypothetical change in commodity prices and interest rates.

Income Taxes and Uncertain Tax Positions. Income taxes are recorded for the income tax effects of transactions reported in the financial statements and consist of income taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income taxes are also recognized for income tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted income tax rates to the differences between the financial statements and income tax reporting. We routinely assess the realizability of our deferred income tax assets, and a valuation allowance is recognized if it is determined that deferred income tax assets may not be fully utilized in future periods. We consider future taxable earnings in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable earnings, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). There can be no assurance that facts and circumstances will not materially change and require us to establish deferred income tax asset

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valuation allowances in a future period. We are subject to taxation in many jurisdictions, and the calculation of our income tax liabilities involves dealing with uncertainties in the application of complex income tax laws and regulations in various taxing jurisdictions. We recognize certain income tax positions that meet a more-likely-than not recognition threshold. If we ultimately determine that the payment of these liabilities will be unnecessary, we will reverse the liability and recognize an income tax benefit during the period in which we determine the liability no longer applies.

Asset Retirement Obligations. Our asset retirement obligations (AROs) consist primarily of estimated future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment facilities from leased acreage, and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of the ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted-risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net earnings as accretion expense. The related capital cost, including revisions thereto, is charged to expense through DD&A-oil and natural gas over the life of the oil and natural gas field.

Environmental Remediation Liability. We review, on a quarterly basis, our estimates of costs of the cleanup of various sites including sites in which governmental agencies have designated us as a potentially responsible party. When it is probable that obligations have been incurred and where a minimum cost or a reasonable estimate of the cost of remediation can be determined, the applicable amount is accrued. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is an estimation process that includes the judgment of management. In many cases, management's judgment is based on the advice and opinions of legal counsel and other advisers, and the interpretation of laws and regulations, which can be interpreted differently by regulators or courts of law. Our experience and the experience of other companies in dealing with similar matters influence the decision of management as to how it intends to respond to a particular matter. A change in estimate could impact our oil and natural gas operating costs and the liability, if applicable, recorded on our Balance Sheets.

Electricity Cost Allocation. Our investment in our cogeneration facilities has been for the express purpose of lowering steam costs in our California heavy oil operations and securing operating control of the respective steam generation. Such cogeneration operations produce electricity and steam and use natural gas as fuel. We allocate steam costs to our oil and natural gas operating costs based on the conversion efficiency (of fuel to electricity and steam) of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to the utilities. A portion of the capital costs of the cogeneration facilities is allocated to DD&A—oil and natural gas production.

Impact of Recently Issued Accounting Standard Updates

For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, see Note 1 to the Financial Statements.

47

Reconciliation of Non-GAAP Measures

Discretionary Cash Flow.  Discretionary cash flow consists of cash provided by operating activities before changes in working capital items. Management uses discretionary cash flow as a measure of liquidity and believes it provides useful information to investors because it assesses cash flow from operations for each period before changes in working capital, which fluctuates due to the timing of collections of receivables and the settlements of liabilities. The following table provides a reconciliation of discretionary cash flow to cash provided by operating activities, the most directly comparable GAAP measure, for the period presented.

	Year Ended December 31:
(in millions)	2011			2010			2009
Net cash provided by operating activities	$	455.9		$	367.2		$	212.6
Add back: Net increase (decrease) in current assets	26.3			(12.5		)	10.1
Add back: Net decrease (increase) in current liabilities including book overdraft	(20.3		)	(12.7		)	33.6
Add back: Unwind interest swap payments	—			10.8			—
Add back: Recovery of Flying J bad debt	—			38.5			—
Discretionary cash flow	$	461.9		$	391.3		$	256.3

Operating Margin per BOE.  Operating margin per barrel consists of oil and natural gas revenues less oil and natural gas operating expenses and production taxes divided by the total barrels sold during the period. Management uses operating margin per barrel as a measure of profitability and believes it provides useful information to investors because it relates our oil and natural gas revenue and oil and natural gas operating expenses to our total units of production providing a gross margin per unit of production, allowing investors to evaluate how our profitability varies on a per unit basis each period.

	Year Ended December 31:
(per BOE)	2011		2010		2009
Average sales price including cash derivative settlements	$	65.68	$	53.84	$	46.02
Average operating costs—oil and natural gas production	18.23		15.95		14.66
Average production taxes	2.58		1.93		1.70
Average operating margin	$	44.87	$	35.96	$	29.66

Pre-Tax PV10. Pre-tax PV10 is defined as standardized measure of discounted future net cash flows before the effect of income taxes. We present pre-tax PV-10 because it is a widely used industry standard which management believes is useful when comparing our asset base and performance to other comparable oil and natural gas exploration and production companies. The following table reconciles pre-tax PV-10 to the standardized measure of discounted future net cash flows:

	Year Ended December 31,
(in thousands)	2011		2010
Standardized measure of oil and gas	$	4,035,279	$	2,799,156
Discounted future cash flow from income taxes	1,669,768		1,035,021
Discounted future net cash flow before income taxes	$	5,705,047	$	3,834,177

48

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

Our primary market risk relates to the prices we receive for our oil and natural gas production. Historically the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. We use various derivative instruments to manage our exposure to commodity price risk. All derivative instruments are recorded on the balance sheet at fair value. If a derivative instrument does not qualify for hedge accounting or we do not elect to use hedge accounting, the changes in fair value, both realized and unrealized, are recorded as unrealized gains or losses in realized and unrealized (gain) loss on derivatives, net in our Statements of Operations. Cash flows from operating activities are impacted to the extent that actual cash settlements under these derivative instruments result in payments to or from the counterparty, and such cash settlement gains and losses are recorded under realized and unrealized (gain) loss on derivatives, net in our Statements of Operations. See Notes 8 and 9 to the Financial Statements. We do not have any current derivative instruments for which we have elected hedge accounting.

Currently, our derivative instruments are in the form of swaps and collars. However, we may use a variety of derivative instruments in the future to hedge WTI or other index prices. A two-way collar is a combination of options, a sold call and purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (the ceiling) we will receive for the volumes under contract. We utilize costless collars which are options positions by which the proceeds from the sale of the call option fund the purchase of a put option. A hypothetical $10 increase in the oil prices used and $1 increase in the natural gas prices used to calculate the fair values of our derivative instruments at December 31, 2011 would decrease the respective fair value of crude oil and natural gas derivative instruments at December 31, 2011 by $96.9 million and $3.3 million, respectively. A hypothetical $10 decrease in oil prices and a $1 decrease in natural gas prices used to calculate the fair values of our derivative instruments at December 31, 2011 would increase the respective fair value of oil and natural gas derivative instruments at December 31, 2011 by $83.1 million and $3.3 million, respectively. As our natural gas production continues to decrease and our use of natural gas for steaming operations increase, we may become a net consumer of natural gas and may enter into derivative instruments to limit our exposure to future increases in natural gas prices.

49

The following table summarizes our commodity hedge positions as of December 31, 2011:

Term	Average Barrels Per Day	Average Prices	Term	Average MMBtu Per Day	Average Prices
Crude Oil Sales (NYMEX WTI) Three-Way Collars			Natural Gas Sales (NYMEX HH) Swaps
Full year 2012	1,000	$65.00/$85.00/$97.25	Full year 2012	5,000		$7.16
Full year 2012	1,000	$70.00/$87.00/$105.00	Full year 2012	5,000		$5.75
Full year 2012	1,000	$70.00/$88.00/$106.00
Full year 2012	1,000	$60.00/$80.00/$96.92	Natural Gas Sales (NYMEX HH) Collars
Full year 2012	1,000	$60.00/$80.00/$120.00	Full year 2012	5,000	$6.00/$7.70
Full year 2012	1,000	$70.00/$88.15/$100.00
Full year 2012	1,000	$70.00/$86.85/$100.00	Natural Gas Sales (NYMEX HH to NGPL-Tex OK) Basis Swaps
Full year 2012	1,000	$69.70/$85.00/$100.00	Full year 2012	2,500		$0.44
Full year 2012	1,000	$70.00/$87.00/$108.50
Full year 2012	1,000	$70.00/$90.00/$116.50	Natural Gas Sales (NYMEX HH TO HSC) Basis Swaps
Full year 2012	1,000	$70.00/$90.00/$120.00	Full year 2012	2,500		$0.32
Full year 2012	1,000	$70.00/$95.00/$120.10
Full year 2012	1,000	$77.95/$105.00/$115.00
Full year 2012	1,000	$80.00/$107.00/$119.60
Full year 2012	500	$70.00/$90.00/$100.00
Full year 2012	500	$70.00/$90.00/$100.00
Full year 2012	1,000	$75.00/$90.00/$101.85
Full year 2012 (1)	1,000	$70.00/$85.00/$92.00
Full year 2012 (1)	2,000	$70.00/$80.00/$83.00
Full year 2012 (1)	1,500	$75.00/$90.00/$97.50
Full year 2012 (1)	500	$75.00/$90.00/$106.90
Full year 2013	1,000	$65.00/$85.00/$97.25
Full year 2013	1,000	$70.00/$87.00/$105.00
Full year 2013	1,000	$70.00/$88.00/$106.00
Full year 2013	1,000	$60.00/$80.00/$103.30
Full year 2013	1,000	$70.00/$88.15/$100.00
Full year 2013	1,000	$70.00/$86.85/$100.00
Full year 2013	1,000	$69.70/$85.00/$100.00
Full year 2013	1,000	$70.00/$87.00/$108.50
Full year 2013	1,000	$70.00/$90.00/$116.50
Full year 2013	1,000	$70.00/$90.00/$120.00
Full year 2013	1,000	$70.00/$95.00/$120.10
Full year 2013	1,000	$77.95/$105.00/$115.00
Full year 2013	1,000	$80.00/$107.00/$119.60
Full year 2013	500	$70.00/$90.00/$100.00
Full year 2013	500	$70.00/$90.00/$100.00
Full year 2013	1,000	$75.00/$90.00/$101.85
Full year 2014	1,000	$77.95/$105.00/$115.00
Full year 2014	1,000	$80.00/$107.00/$119.60

_______________________________________

(1) In the third quarter of 2011, we converted several of our two-way oil collars to three-way oil collars. There were no payments made or received as a result of these transactions.

Excluded from the table above are our calendar month average swaps, which protect us from variances in market pricing conditions of certain of our sales contracts. These derivative contracts protect 5,000 BOE/D of our Permian sales volumes and have differentials of $0.075 to $0.080 during 2012 and $0.070 to $0.075 during 2013.

50

Interest Rate Risk

Market risk is estimated as the change in fair value resulting from a hypothetical 100 basis point change in the interest rate on the outstanding balance under our credit facility. Our credit facility allows us to fix the interest rate for all or a portion of the principal balance for a period up to 12 months. To the extent the interest rate is fixed, interest rate changes affect the instrument's fair market value but do not impact results of operations or cash flows. Conversely, for the portion of the credit facility that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate debt. At December 31, 2011, our outstanding principal balance under our credit facility was $531.5 million and the weighted average interest rate on the outstanding principal balance was 2.018%. At December 31, 2011, the carrying amount approximated fair market value. Assuming a constant debt level of $1.4 billion, the cash flow impact resulting from a 100 basis point change in interest rates during periods when the interest rate is not fixed would be $3.3 million over a 12-month time period.

51

Item 8.    Financial Statements and Supplementary Data

	Page
Report of Independent Registered Public Accounting Firm	53
Balance Sheets at December 31, 2011 and 2010	54
Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009	55
Statements of Shareholders' Equity for the Years Ended December 31, 2011, 2010 and 2009	56
Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009	57
Notes to the Financial Statements	58
Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited)	86

Financial statement schedules have been omitted since they are either not required, are not applicable, or the required information is shown in the financial statements and related notes.

52

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Berry Petroleum Company:

In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Berry Petroleum Company at December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 8 to the financial statements, the Company discontinued hedge accounting effective January 1, 2010.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

February 28, 2012

53

BERRY PETROLEUM COMPANY

Balance Sheets

December 31, 2011 and 2010

(In Thousands, Except Share Information)

	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	298		$	278
Short-term investments	65			65
Accounts receivable	115,952			93,406
Deferred income taxes	13,779			32,342
Derivative instruments	6,117			2,742
Assets held for sale	14,622			—
Prepaid expenses and other	16,801			14,033
Total current assets	167,634			142,866
Oil and natural gas properties (successful efforts basis), buildings and equipment, net	2,531,393			2,655,792
Derivative instruments	7,027			2,054
Other assets	28,898			37,904
	$	2,734,952		$	2,838,616
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	126,489		$	106,459
Revenue and royalties payable	49,253			37,812
Accrued liabilities	35,066			36,234
Line of credit	—			5,300
Derivative instruments	20,365			84,846
Total current liabilities	231,173			270,651
Long-term liabilities:
Deferred income taxes	185,450			329,207
Senior secured revolving credit facility	531,500			170,000
8.25% Senior subordinated notes due 2016	200,000			200,000
10.25% Senior notes due 2014, net of unamortized discount of $6,564 and $11,035, respectively	348,692			438,965
6.75% Senior notes due 2020	300,000			300,000
Asset retirement obligations	64,019			53,443
Derivative instruments	15,505			33,526
Other long-term liabilities	17,884			18,271
	1,663,050			1,543,412
Commitments and contingencies (Note 10)
Shareholders' equity:
Preferred stock, $0.01 par value, 2,000,000 shares authorized; no shares outstanding	—			—
Capital stock, $0.01 par value:
Class A Common Stock, 100,000,000 shares authorized; 52,067,994 and 51,426,232 shares issued and outstanding, respectively	521			514
Class B Stock, 3,000,000 shares authorized; 1,797,784 shares issued and outstanding (liquidation preference of $0.50 per share)	18			18
Capital in excess of par value	350,158			327,369
Accumulated other comprehensive loss	(5,517		)	(43,806		)
Retained earnings	495,549			740,458
Total shareholders' equity	840,729			1,024,553
	$	2,734,952		$	2,838,616

The accompanying notes are an integral part of these financial statements.

54

BERRY PETROLEUM COMPANY

Statements of Operations

Years ended December 31, 2011, 2010 and 2009

(In Thousands, Except Per Share Data)

	2011			2010			2009
REVENUES
Sales of oil and natural gas	$	870,773		$	619,608		$	500,532
Sales of electricity	34,953			34,740			36,065
Natural gas marketing	13,832			22,162			22,806
Settlement of Flying J bankruptcy claim	—			21,992			—
Gain on sale of assets	—			—			826
Interest and other income, net	1,784			3,300			1,810
	921,342			701,802			562,039
EXPENSES
Operating costs—oil and natural gas production	237,476			190,218			156,612
Operating costs—electricity generation	25,690			31,295			31,400
Production taxes	33,617			22,999			18,144
Depreciation, depletion & amortization—oil and natural gas production	213,859			179,432			139,919
Depreciation, depletion & amortization—electricity generation	1,963			3,225			3,681
Natural gas marketing	13,038			19,896			21,231
General and administrative	61,727			52,846			49,237
Interest	72,807			66,541			49,923
Extinguishment of debt	15,544			573			10,823
Realized and unrealized (gain) loss on derivatives, net	(13,908		)	31,847			7,756
Gain on purchase	(1,046		)	—			—
Transaction costs on acquisitions	—			2,635			—
Impairment of oil and natural gas properties	625,564			—			1,017
Dry hole, abandonment, impairment and exploration	5,302			2,311			4,408
Bad debt recovery	—			(38,508		)	—
	1,291,633			565,310			494,151
(Loss) earnings from continuing operations before income taxes	(370,291		)	136,492			67,888
Income tax (benefit) provision	(142,228		)	53,968			20,664
Net (loss) earnings from continuing operations	(228,063		)	82,524			47,224
Net earnings from discontinued operations	—			—			6,806
Net (loss) earnings	$	(228,063	)	$	82,524		$	54,030
Basic net (loss) earnings per share from continuing operations	(4.21		)	1.54			1.03
Basic net earnings per share from discontinued operations	—			—			0.15
Basic net (loss) earnings per share	$	(4.21	)	$	1.54		$	1.18
Diluted net (loss) earnings per share from continuing operations	(4.21		)	1.52			1.02
Diluted net earnings per share from discontinued operations	—			—			0.15
Diluted net (loss) earnings per share	$	(4.21	)	$	1.52		$	1.17
Dividends per share	$	0.31		$	0.30		$	0.30

The accompanying notes are an integral part of these financial statements.

55

BERRY PETROLEUM COMPANY

Statements of Shareholders' Equity

Years Ended December 31, 2011, 2010 and 2009

(In Thousands)

	Class A		Class B		Capital in Excess of Par Value			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders' Equity
Balances at January 1, 2009	$	427	$	18	$	79,653		$	633,749		$	113,697		$	827,544
Stock options and restricted stock issued	3		—		890			—			—			893
Stock based compensation expense	—		—		8,623			—			—			8,623
Income tax effect of stock option exercises	—		—		(98		)	—			—			(98		)
Dividends ($0.30 per share)	—		—		—			(13,664		)	—			(13,664		)
Comprehensive earnings:
Net earnings	—		—		—			54,030			—			54,030
Effect of derivative instruments, net of income taxes	—		—		—			—			(174,069		)	(174,069		)
Total comprehensive loss	—		—		—			—			—			(120,039		)
Balances at December 31, 2009	430		18		89,068			674,115			(60,372		)	703,259
Issuance of stock	80				224,233									224,313
Stock options and restricted stock issued	4		—		4,398			—			—			4,402
Stock based compensation expense	—		—		9,386			—			—			9,386
Income tax effect of stock option exercises	—		—		284			—			—			284
Dividends ($0.30 per share)	—		—		—			(16,181		)	—			(16,181		)
Comprehensive earnings:
Net earnings	—		—		—			82,524			—			82,524
Amortization of Accumulated other comprehensive loss related to de-designated hedges, net of income taxes	—		—		—			—			16,566			16,566
Total comprehensive earnings	—		—		—			—			—			99,090
Balances at December 31, 2010	514		18		327,369			740,458			(43,806		)	1,024,553
Stock options and restricted stock issued	7		—		10,106			—			—			10,113
Stock based compensation expense	—		—		9,636			—			—			9,636
Income tax effect of stock option exercises	—		—		3,047			—			—			3,047
Dividends ($0.31 per share)	—		—		—			(16,846		)	—			(16,846		)
Comprehensive earnings:														—
Net (loss)	—		—		—			(228,063		)	—			(228,063		)
Amortization of Accumulated other comprehensive loss related to de-designated hedges, net of income taxes	—		—		—			—			38,289			38,289
Total comprehensive loss	—		—		—			—			—			(189,774		)
Balances at December 31, 2011	$	521	$	18	$	350,158		$	495,549		$	(5,517	)	$	840,729

The accompanying notes are an integral part of these financial statements.

56

BERRY PETROLEUM COMPANY

Statements of Cash Flows

Years Ended December 31, 2011, 2010 and 2009

(In Thousands)

	2011			2010			2009
Cash flows from operating activities:
Net (loss) earnings	$	(228,063	)	$	82,524		$	54,030
Depreciation, depletion and amortization	215,822			182,657			145,788
Gain on purchase	(1,046		)	—			—
Extinguishment of debt	4,072			573			10,823
Amortization of debt issuance costs and net discount	8,243			8,481			6,827
Impairment of oil and natural gas properties	625,564			—			10,654
Dry hole and impairment	4,616			1,478			4,205
Derivatives	(29,094		)	42,609			247
Stock-based compensation expense	9,636			9,386			8,626
Deferred income taxes	(149,279		)	54,698			19,998
Loss on sale of asset	—			—			79
Other, net	3,223			(12		)	(4,016		)
Cash paid for abandonment	(1,803		)	(1,832		)	(1,030		)
Bad debt recovery	—			(38,508		)	—
Change in book overdraft	(156		)	528			(16,018		)
Changes in operating assets and liabilities:
Accounts receivable	(23,526		)	20,055			(11,816		)
Inventories, prepaid expenses, and other current assets	(2,768		)	(7,553		)	1,761
Accounts payable and revenue and royalties payable	25,019			5,273			(49,119		)
Accrued interest and other accrued liabilities	(4,561		)	6,880			31,537
Net cash provided by operating activities	455,899			367,237			212,576
Cash flows from investing activities:
Exploration and development of oil and natural gas properties	(527,112		)	(310,139		)	(134,946		)
Property acquisitions	(158,090		)	(334,409		)	(13,497		)
Capitalized interest	(29,117		)	(28,321		)	(30,107		)
Proceeds from sale of assets	—			—			139,796
Deposits on asset sales	3,300			—			—
Net cash used in investing activities	(711,019		)	(672,869		)	(38,754		)
Cash flows from financing activities:
Proceeds from issuances on line of credit	406,600			316,000			387,700
Payments on line of credit	(411,900		)	(310,700		)	(413,000		)
Proceeds from issuance of 10.25% senior notes due 2014	—			—			434,962
Proceeds from issuance of 6.75% senior notes due 2020	—			300,000			—
Repurchase of 10.25% senior notes due 2014	(94,744		)	—			—
Proceeds from long-term borrowings under credit facility	719,700			363,000			655,300
Repayments of long-term borrowings under credit facility	(358,200		)	(565,000		)	(1,215,100		)
Financing obligation	(380		)	(346		)	18,214
Debt issuance costs	(2,250		)	(15,173		)	(23,955		)
Dividends paid	(16,846		)	(16,181		)	(13,664		)
Proceeds from issuance of stock	—			224,313			—
Proceeds from stock option exercises	10,113			4,402			890
Excess income tax benefit (expense)	3,047			284			(98		)
Net cash provided by (used in) financing activities	255,140			300,599			(168,751		)
Net increase (decrease) in cash and cash equivalents	20			(5,033		)	5,071
Cash and cash equivalents at beginning of year	278			5,311			240
Cash and cash equivalents at end of year	$	298		$	278		$	5,311
Supplemental disclosures of cash flow information:
Interest paid, net of capitalized interest	$	59,853		40,773			36,854
Income taxes paid (refunded)	7,914			(285		)	8,769
Noncash investing activities:
Accrued capital expenditures	$	61,098		$	51,095		$	5,059
Asset retirement obligations	7,448			3,721			1,407

The accompanying notes are an integral part of these financial statements.

57

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

1. Summary of Significant Accounting Policies

Description of the Business

Berry Petroleum Company (the Company) is an independent energy company engaged in the production, development, exploitation and acquisition of oil and natural gas. The Company has invested in cogeneration facilities, which provide steam required for the extraction of heavy oil and which generate electricity for sale.

Basis of Presentation

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). Certain amounts in prior years' financial statements have been reclassified to conform to the 2011 financial statement presentation.

Assumptions, Judgments, and Estimates

In the course of preparing the financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.

The more significant areas requiring the use of assumptions, judgments, and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) income taxes; (7) valuation of derivative instruments; and (8) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with a remaining maturity of three months or less to be cash equivalents. The Company's cash management process provides for the daily funding of checks as they are presented to the bank. Included in accounts payable at December 31, 2011 and 2010 is $16.1 million and $16.3 million, respectively, representing outstanding checks in excess of the bank balance (book overdraft).

Accounts Receivable

Trade accounts receivable consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, oil and natural gas receivables are collected within two months.

Bad Debt Recovery

The Company recognized $38.5 million in bad debt expense in the year ended December 31, 2008 related to the Flying J bankruptcy. On July 6, 2010, the Joint Plan of Reorganization of Flying J was confirmed under Chapter 11 of the United States Bankruptcy Code. Additionally, the United States Bankruptcy Court approved and confirmed the June 15, 2010 Stipulation and Agreed Order (the Stipulation) with Flying J regarding the resolution of the Company's claim in Flying J's pending bankruptcy. Pursuant to the Stipulation, Flying J agreed that the total amount owed to the Company by Flying J was $60.5 million and, as a result, the Company received $60.5 million in cash on July 23, 2010. In the quarter ended September 30, 2010, the Company recorded a settlement of the Company's Flying J bankruptcy claim of $22.0 million and a bad debt recovery of $38.5 million.

58

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

1. Summary of Significant Accounting Policies (Continued)

Discontinued Operations

In 2009, the Company sold its DJ assets, the results of operations of which are reported as discontinued operations in the 2009 Statements of Operations. See Note 2 to the Financial Statements.

Income Taxes and Uncertain Tax Positions

The Company recognizes deferred income tax liabilities and assets for the expected future income tax consequences of temporary differences between financial accounting bases and income tax bases of assets and liabilities. Deferred income taxes are measured by applying currently enacted income tax rates. The Company accounts for uncertainty in income taxes for income tax positions taken or expected to be taken in an income tax return. Only income tax positions that meet the more-likely-than-not recognition threshold will be recognized.

Derivative Instruments

The Company enters into derivative contracts, primarily swaps and collars, to manage its exposure to commodity price risk. All derivative instruments, other than those that meet the "normal purchases normal sales" exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. The Company is required to formally document, at the inception of a hedge, the hedging relationship and the risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment. Effective January 1, 2010, the Company elected to discontinue all hedge accounting prospectively. As a result, subsequent to December 31, 2009, the Company records all derivative instruments as either assets or liabilities at fair value and recognizes all gains and losses from changes in derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive loss (AOCL). See Notes 8 and 9 to the Financial Statements. Cash settlements of derivative instruments used to manage commodity price risk are classified as cash flows from operating activities in the Statements of Cash Flows along with the cash flows from the related oil and natural gas production activities. The Company nets derivative assets and liabilities of a given counterparty whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The Company uses these agreements to manage and reduce its potential counterparty credit risk. The Company does not enter into derivative instruments for speculative or trading purposes.

Oil and Natural Gas Properties, Buildings and Equipment

The Company accounts for its oil and natural gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The costs of development wells are capitalized whether productive or nonproductive.

The provision for depletion of oil and natural gas properties is calculated on a field-by-field basis using the unit-of-production method. If the estimates of total proved or proved developed reserves decline, the rate at which the Company records depreciation, depletion and amortization (DD&A) expense increases, which in turn reduces net earnings. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. The Company is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of its development program, as well as future economic conditions. Changes in reserves are applied on a prospective basis.

Buildings and equipment are recorded at cost. Depreciation is calculated on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment.

59

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

1. Summary of Significant Accounting Policies (Continued)

Capitalized Interest

Acquisition costs of proved undeveloped and unproved properties qualify for interest capitalization during a period if interest cost is incurred and activities necessary to bring the properties into a productive state are in progress. As wells are drilled in a field with proved undeveloped reserves or unproved reserves, a portion of the acquisition costs are either re-designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re-designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field.

Impairment of Proved and Unproved Properties

Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis, annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows.Due to the impact of lower natural gas prices, the Company recorded an impairment of $625.0 million related to its E. Texas natural gas assets. See Notes 9 and 11 to the Financial Statements.

Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time.

Assets Held for Sale

Any properties held for sale as of the date of presentation of the balance sheets have been classified as assets held for sale and are separately presented on the balance sheets at the lower of net book value or fair value less the cost to sell. See Note 3 to the Financial Statements.

Asset Retirement Obligations

The Company's asset retirement obligations (AROs) relate to future costs associated with plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability.

Deferred Financing Costs

Costs incurred in connection with the execution or modification of the Company’s credit facility, and in connection with the Company's senior and subordinated notes, are capitalized and amortized over the life, or expected life, of the debt using the effective interest method.

60

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

1. Summary of Significant Accounting Policies (Continued)

Prepaid Expenses and Other

The components of prepaid expenses and other are as follows:

	Year Ended December 31,
(in thousands)	2011	2010
Prepaid expenses	5,275	9,590
Inventory	11,526	4,443
Total prepaid expenses and other	16,801	14,033

Accrued Liabilities

The components of accrued liabilities are as follows:

	Year Ended December 31,
(in thousands)	2011		2010
Property taxes	$	10,430	$	11,245
Accrued interest	9,205		10,074
Accrued payroll	9,953		10,225
Other accrued liabilities	5,478		4,690
Total accrued liabilities	$	35,066	$	36,234

Revenue Recognition

Revenues associated with sales of oil, natural gas, electricity and natural gas marketing are recognized when delivery has occurred and title has transferred, and if the collectability of the revenue is probable. The electricity and natural gas the Company produces and uses in its operations are not included in revenues. Revenues from oil and natural gas production from properties in which the Company has an interest with other producers are recognized on the basis of its net working interest. Revenues are also derived from natural gas marketing sales, which represent excess capacity on the Rockies Express, Wyoming Interstate, and Ruby pipelines used by the Company to market natural gas for its working interest partners and other third parties.

Significant Customers

The Company sells oil and natural gas to various types of customers, including pipelines, refineries and other oil and natural gas companies, and electricity to utility companies. Credit is extended based on an evaluation of the customer's financial condition and historical payment record. The Company does not believe that the loss of any one customer would impact the marketability of its products, but it may impact the profitability of its oil, natural gas or electricity sold. Due to the possibility of refinery constraints in the Utah region, it is possible that the loss of the Company's crude oil sales customer in Utah could impact the marketability of a portion of the Company's Utah crude oil volumes.

In 2011, sales to ExxonMobil Oil Corporation and Shell Trading (US) Company accounted for approximately 43% and 14%, respectively, of the Company's revenue. In 2010, sales to two purchasers were approximately 44% and 14%, respectively, of the Company's revenue. In 2009, sales to three purchasers were approximately 25%, 16% and 12%, respectively, of the Company's revenue.

61

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

1. Summary of Significant Accounting Policies (Continued)

Concentrations of Market Risk

The results of the Company's oil and natural gas operations are impacted by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future depends on numerous factors beyond the Company's control, including weather, imports, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil and natural gas products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

During 2011, 2010 and 2009, the Company did not incur any credit losses with respect to counterparties to contracts for the sale of oil and natural gas or under the Company's derivative instruments. As of December 31, 2011, over 87% of the Company's California oil production is under contract with Shell Trading (US) Company and ExxonMobil Oil Corporation. The Company's contract with Shell Trading (US) Company continues through June 30, 2013 and the Company's contract with ExxonMobil Oil Corporation renews automatically on a month-to-month basis, unless either party to the contract terminates upon 90 days' notice.

The Company places its temporary cash investments with high-quality financial institutions and does not limit the amount of credit exposure to any one financial institution. For the three years ended December 31, 2011, the Company has not incurred losses related to these investments.

Electricity Cost Allocation

The Company owns three cogeneration facilities. Its investment in cogeneration facilities has been for the express purpose of lowering steam costs in its heavy oil operations and securing operating control of the respective steam generation. Cogeneration, also called combined heat and power (CHP), extracts energy from the exhaust of a turbine, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. The Company allocates steam costs to its oil and natural gas operating costs based on the conversion efficiency of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to utility companies. A portion of the capital costs of the cogeneration facilities is allocated to DD&A—oil and natural gas production. Electricity production used in oil and natural gas operations is allocated to operating costs—oil and natural gas production, and totaled $2.3 million, $2.8 million and $2.8 million for the years ended December 31, 2011, 2010 and 2009 respectively.

Transportation Costs

Natural gas transportation costs are included in either operating costs—oil and natural gas production or operating costs—electricity generation, as applicable. Natural gas transportation costs included in operating costs—oil and natural gas production were $21.4 million, $16.2 million and $16.1 million for 2011, 2010 and 2009, respectively. Costs for transporting natural gas used in electricity generation were $5.0 million, $4.7 million and $2.8 million for 2011, 2010 and 2009, respectively; a portion of these costs are allocated to operating costs—oil and natural gas production, as described above, and the remainder are included in operating costs—electricity generation.

Stock-Based Compensation

The Company recognizes the grant date fair value of stock options and other stock based compensation issued in the Statements of Operations. Expense is recognized on a straight-line basis over the employee's requisite service period (generally the vesting period of the award).

62

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

1. Summary of Significant Accounting Policies (Continued)

(Loss) Earnings Per Share

The two-class method of computing earnings per share is required for entities that have participating securities. The two-class method is an earnings allocation formula that determines earnings per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. Unvested restricted stock issued prior to January 1, 2010, under the Company's equity incentive plans, has the right to receive non-forfeitable dividends, participating on an equal basis with common stock, and thus these securities are classified as participating securities. Participating securities do not have a contractual obligation to share in the Company's losses. Therefore, in periods of net loss, no portion of the loss is allocated to participating securities. Unvested restricted stock issued subsequent to January 1, 2010, under the Company's equity incentive plans does not participate in dividends. Stock options issued under the Company's equity incentive plans do not participate in dividends.

Basic (loss) earnings per share is calculated by dividing (loss) earnings available to common shareholders by the weighted average shares-basic during each period. Under the treasury stock method, diluted (loss) earnings per share is calculated by dividing (loss) earnings available to common shareholders by the weighted average shares-dilutive, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of non-participating unvested restricted stock awards and outstanding stock options. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted (loss) earnings per share.

The following table shows the computation of basic and diluted net earnings per share from continuing and discontinued operations:

	Year Ended December 31,
	2011			2010		2009
	(in thousands, except per share amounts)
Net (loss) earnings from continuing operations	$	(228,063	)	$	82,524	$	47,224
Less: earnings allocable to participating securities	—			1,199		1,134
Net earnings from continuing operations available for common shareholders	$	(228,063	)	$	81,325	$	46,090
Net earnings from discontinued operations	$	—		$	—	$	6,806
Less: earnings allocable to participating securities	—			—		174
Net earnings from discontinued operations available for common shareholders	$	—		$	—	$	6,632
Basic (loss) earnings per share from continuing operations	$	(4.21	)	$	1.54	$	1.03
Basic earnings per share from discontinued operations	—			—		0.15
Basic (loss) earnings per share	$	(4.21	)	$	1.54	$	1.18
Dilutive (loss) earnings per share from continuing operations	$	(4.21	)	$	1.52	$	1.02
Dilutive earnings per share from discontinued operations	—			—		0.15
Dilutive (loss) earnings per share	$	(4.21	)	$	1.52	$	1.17
Basic weighted average shares	54,133			52,969		44,625
Add: dilutive effects of stock options	—			460		221
Diluted weighted average shares	54,133			53,429		44,846

Options of 1.5 million, 0.7 million and 1.6 million shares were not included in the weighted average shares-dilutive calculation for the years ended December 31, 2011, 2010 and 2009, respectively, because their effect would have been anti-dilutive.

63

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

1. Summary of Significant Accounting Policies (Continued)

Equity Method Investments

The Company owns interests in two entities that gather and transport natural gas in the Company's Lake Canyon and Brundage Canyon fields. The Company owns less than a 50% interest in both of these entities and such interests are accounted for using the equity method. The Company's net investment in these entities is included under the caption other assets on its Balance Sheets.

Comprehensive (Loss) Earnings

Comprehensive (loss) earnings is a term used to refer to net (loss) earnings plus other comprehensive earnings (loss). Other comprehensive (loss) earnings is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of shareholders' equity instead of net (loss) earnings. The components of other comprehensive (loss) earnings were as follows:

	Year Ended December 31,
(in thousands)	2011			2010		2009
Net (loss) earnings	$	(228,063	)	$	82,524	$	54,030
Unrealized gain (loss) on derivatives, net of income taxes of $0, $0, and ($79,240), respectively	—			—		(129,287		)
Reclassification of realized (gain) loss on derivatives included in net earnings, net of income taxes of $0, $0, ($27,447)	—			—		(44,782		)
Amortization of Accumulated other comprehensive loss related to de-designated hedges, net of income taxes of $23,467, $10,153, and $0, respectively	38,289			16,566		—
Comprehensive (loss) earnings	$	(189,774	)	$	99,090	$	(120,039	)

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development, and production of oil and natural gas, and all of the Company's operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment.

Impact of Recently Issued Accounting Standard Updates

In December 2011, the FASB issued ASU No. 2011-11 Disclosures about Offsetting Assets and Liabilities. The ASU requires additional disclosures about the impact of offsetting, or netting, on a company's financial position, and is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods, and retrospectively for all comparative periods presented. Under US GAAP, derivative assets and liabilities can be offset under certain conditions. The ASU requires disclosures showing both gross information and net information about instruments eligible for offset in the balance sheet. The Company is currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on the Company's financial position or results of operations.

In June 2011, the FASB issued ASU No. 2011-05 Presentation of Comprehensive Income. The ASU amends previously issued authoritative guidance and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. These amendments remove the option under current U.S. GAAP to present the components of other comprehensive income as part of the statements of changes in stockholder's equity. In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-12 Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards. The ASU supersedes pending paragraphs in ASU 2011-05 related to presenting reclassifications out of accumulated other comprehensive income by component in the financial statements. The adoption of this authoritative guidance will not have an impact on the Company's financial position or results of operations, but will require the Company to present the Statements of Comprehensive Income separately from its Statements of Shareholders' Equity, as these statements are currently presented on a combined basis.

64

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

1. Summary of Significant Accounting Policies (Continued)

In May 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-04 Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRSs. The ASU amends previously issued authoritative guidance and requires new disclosures, clarifies existing disclosures and is effective for interim and annual periods beginning after December 15, 2011. The amendments change requirements for measuring fair value and disclosing information about those measurements. Additionally, the ASU clarifies the FASB's intent regarding the application of existing fair value measurement requirements and changes certain principles or requirements for measuring fair value or disclosing information about its measurements. For many of the requirements, the FASB does not intend the amendments to change the application of the existing Fair Value Measurements guidance. The Company is currently evaluating the provisions of ASU 2011-04 and assessing the impact, if any, it may have on the Company's financial position or results of operations.

2. Acquisitions and Divestitures

On May 25, 2011, the Company acquired interests in producing properties on approximately 6,000 net acres in the Wolfberry trend in the Permian for an aggregate purchase price of $128.4 million (the Wolfberry Acquisition). The Wolfberry Acquisition had an effective date of March 1, 2011, with operations from March 1, 2011 through May 24, 2011 resulting in purchase price adjustments. The acquisition was financed using the Company's senior secured revolving credit facility. The Company operates 98% of and has an average 93% working interest (70% net revenue interest) in the properties acquired in the Wolfberry Acquisition.

The Company has not presented pro forma information for the properties acquired in the Wolfberry Acquisition, as the impact of the acquisition was insignificant to the Company's Statements of Operations for the year ended December 31, 2011. Revenues of $7.8 million from properties acquired in the Wolfberry Acquisition have been included in the accompanying Statements of Operations for the year ended December 31, 2011, and earnings from the acquired properties were insignificant. 

The following table summarizes the consideration paid to the sellers and the amounts of the assets acquired and liabilities assumed in the Wolfberry Acquisition:

	(in thousands)
Consideration paid to sellers:
Cash consideration	$	128,398
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed and undeveloped properties	128,697
Asset retirement obligation	(119		)
Other liabilities assumed	(180		)
Total identifiable net assets	$	128,398

In March, April and November 2010, the Company completed three separate acquisitions of producing properties located in the Wolfberry trend in the Permian for an aggregate purchase price of approximately $327.0 million (the Permian Acquisitions). The Permian Acquisitions were financed with net proceeds from the issuance in January 2010 of 8 million shares of the Company's Class A Common Stock, cash generated from operations and net proceeds from the issuance in November 2010 of $300 million aggregate principal amount of the Company's 6.75% senior notes due 2020 (2020 Notes).

In the first quarter of 2011, the Company recorded a $1.0 million gain (net of deferred income taxes of $0.7 million) in conjunction with usual and customary post-closing adjustments to the purchase price of the November 2010 Permian acquisition. The gain was recorded in the Statements of Operations under the caption gain on purchase.

Acquisition costs of $2.6 million were recorded for the Permian Acquisitions in the Statements of Operations under the caption transaction costs on acquisitions for the year ended December 31, 2010. Revenues of $28.7 million were included in the accompanying Statements of Operations for the year ended December 31, 2010, and earnings from the acquired properties in 2010 were insignificant.  

65

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

2. Acquisitions and Divestiture (Continued)

The following table summarizes the consideration paid to the sellers and the amounts of the assets acquired and liabilities assumed in the Permian Acquisitions:

	(in thousands)
Consideration paid to sellers:
Cash consideration	$	327,032
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed and undeveloped properties	332,214
Other assets acquired	342
Asset retirement obligation	(3,498		)
Deferred income tax liability	(647		)
Other liabilities assumed	(333		)
Total identifiable net assets	$	328,078

The Wolfberry Acquisition and the Permian Acquisitions qualify as business combinations and, as such, the Company estimated the fair value of each property as of each acquisition date (the date on which the Company obtained control of the properties). The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model based on an income approach and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. Given the unobservable nature of the inputs, nonrecurring measurements of business combinations are deemed to use Level 3 inputs.

In March 2009, the Company entered into an agreement to sell its assets in the Denver-Julesburg basin in Colorado. The transaction closed in April 2009. The Company recorded a pre-tax impairment loss of $9.6 million related to the sale, which is included in net earnings from discontinued operations in its Statements of Operations for the year ended December 31, 2009.

Earnings from discontinued operations, net of income tax, on the accompanying Statements of Operations for the year ended December 31, 2009 is comprised of the following (in thousands):

	Year Ended December 31, 2009
Sales of oil and natural gas(1)	$	11,555
Loss on sale of asset	(908		)
Other revenue	623
Total revenues	11,270
Realized and unrealized (gain) on derivatives, net	(13,786		)
Other expenses(2)	15,799
Total expenses	2,013
Earnings from discontinued operations, before income taxes	9,257
Provision for income taxes	2,451
Net earnings from discontinued operations	$	6,806

________________________________________

(1) A $6.2 million realized gain included in sales of oil and natural gas was reclassified to discontinued operations for the year ended December 31, 2009.

(2) Includes $9.6 million of impairment charges related to the sale of the Company's assets in the DJ and $0.8 million of interest allocated to discontinued operations based on the ratio of net assets to the sum of total net assets.

66

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

2. Acquisitions and Divestiture (Continued)

At the time of the DJ asset sale, the Company had designated derivative instruments as cash flow hedges from the forecasted sale of natural gas produced by the DJ assets. As such, all recurring impacts on the Company's Statements of Operations were classified as discontinued operations. Additionally, the Company determined that as a result of the sale of the DJ assets, the forecasted transactions were no longer probable of occurring. Accordingly, the Company discontinued hedge accounting for such derivative instruments and reclassified a gain of $14.3 million from AOCL to net earnings from discontinued operations in its Statements of Operations.

During the first quarter of 2009, the Company entered into natural gas derivative instruments on behalf of the purchaser of its DJ assets. The Company did not elect hedge accounting for these derivative instruments and recorded an unrealized net loss of $0.5 million which is included in net earnings from discontinue operations in its Company's Statements of Operations.

3. Assets Held For Sale

At December 31, 2011, the Company's assets held for sale had a balance of $14.6 million related to proved developed properties in Elko, Eureka, and Nye Counties, Nevada (Nevada Assets). On December 21, 2011, the Company entered into an agreement to sell its Nevada Assets to a group of private buyers for $16.5 million, subject to customary closing adjustments. The sale of the Nevada Assets was effective January 1, 2012 and closed January 31, 2012. The Company received a deposit of $3.3 million on December 22, 2011 for the sale of these assets, which is recorded under accrued liabilities on the Balance Sheets at December 31, 2011.The asset retirement obligation related to the Nevada Assets was $0.7 million at December 31, 2011 and is included in the asset retirement obligations liability on the December 31, 2011 Balance Sheets.

4. Debt

Revolving Credit Facility

The Company's senior secured revolving credit facility, which matures on May 13, 2016, has a current borrowing base of $1.4 billion, subject to lender commitments. On October 26, 2011, as part of the semi-annual borrowing base redetermination process, the Company entered into an amendment to the credit facility which, among other things, increased total lender commitments to $1.2 billion. Borrowings under the credit facility bear interest at either (i) LIBOR plus a margin between 1.50% and 2.50% or (ii) the prime rate plus a margin between 0.50% and 1.50%, in each case, based on the amount utilized. The annual commitment fee on the unused portion of the credit facility ranges between 0.35% and 0.50% based on the amount utilized. Total fees paid during 2011 to increase the borrowing base and lender commitments were approximately $2.2 million, and will be amortized over the remaining term of the credit facility. The Company wrote off debt issuance costs of $0.5 million during the fourth quarter associated with one lender that did not renew its commitment to the credit facility.

As of December 31, 2011, outstanding borrowings under the facility were $531.5 million (excluding $23.2 million of outstanding letters of credit), leaving $645.3 million in borrowing capacity available under the credit facility. As of December 31, 2010, there were $170.0 million in outstanding borrowings under the credit facility. The maximum amount available under the credit facility is subject to semi-annual redeterminations of the borrowing base in April and October of each year, based on the value of the Company's proved oil and natural gas reserves, in accordance with the lenders' customary procedures and practices. The Company and the lenders each have a right to one additional redetermination each year.

The credit facility contains certain covenants, which, among other things, require the maintenance of (i) an interest coverage ratio of 2.75 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0. The senior secured revolving credit facility contains other customary covenants, subject to certain agreed exceptions, including covenants restricting the Company's ability to, among other things, owe or be liable for indebtedness; create, assume or permit to exist liens; be a party to or be liable on any hedging contract; engage in mergers or consolidations; transfer, lease, exchange, alienate or dispose of the Company's material assets or properties; declare dividends on or redeem or repurchase the Company's capital stock; make any acquisitions of, capital contributions to or other investments in any entity or property; extend credit or make advances or loans; engage in transactions with affiliates; and enter into, create or allow to exist contractual obligations limiting the Company's ability to grant liens on the Company's assets to the lenders under the senior secured revolving credit facility. The Company are currently in compliance with all financial covenants and have complied with all financial covenants for all prior periods presented

67

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

4. Debt (Continued)

Subject to certain agreed limitations, the Company granted first priority security interests over substantially all of its assets in favor of the lenders under the credit facility.

Money Market Line of Credit

The Company's senior secured uncommitted money market line of credit has a borrowing capacity of up to $40 million for a maximum of 30 days. As of December 31, 2011, there were no borrowings outstanding under the money market line of credit. Amounts borrowed under the money market line of credit bear interest at LIBOR plus a margin of approximately 1.4%. The line of credit is currently unavailable to the Company and the Company does not know when or if the line of credit will be available in the future. As of December 31, 2010 there was $5.3 million in outstanding borrowings under the line of credit. The outstanding borrowings under the line of credit at December 31, 2010 had a weighted average interest rate of 1.7%.

6.75% Senior Notes Due 2020

On November 1, 2010, the Company issued $300 million in principal amount of 2020 Notes. Interest is payable in arrears semi-annually in May and November of each year, beginning May 2011. The Company received net proceeds of $294.0 million, which were used in part to finance a November 2010 acquisition of producing properties in the Permian and the remainder was used to reduce outstanding borrowings under the credit facility. The 2020 Notes are senior unsecured obligations of the Company and rank effectively junior to all of the Company's existing and any future secured debt, to the extent of the value of the collateral securing that debt, rank equally in right of payment with the 2014 Notes and any future senior unsecured debt, and rank senior in right of payment to the Company's 8.25% senior subordinated notes due 2016 (2016 Notes) and the Company's other future subordinated debt.

The Company may redeem up to 35% of the 2020 Notes at any time prior to November 1, 2013, on one or more occasions, with the proceeds of certain equity offerings at a redemption price of 106.75%. The Company may redeem all or any part of the 2020 Notes at any time beginning on or after November 1, 2015 at the prices set forth below, expressed as percentages of the principal amount redeemed, plus accrued and unpaid interest:

2015	103.375	%
2016	102.250	%
2017	101.125	%
2018 and thereafter	100.000	%

The Company may also redeem the 2020 Notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a "make-whole" premium, plus accrued and unpaid interest to the redemption date.

10.25% Senior Notes Due 2014

On May 27, 2009, the Company issued $325 million in principal amount of its 10.25% senior notes due 2014 (2014 Notes) at 93.546% of par resulting in a discount of $21.0 million. Interest is payable in arrears semi-annually on June 1 and December 1 of each year. The Company received net proceeds of $295.1 million, which were used to repay the $140 million second lien term loan in full and reduce outstanding borrowings under the credit facility.

On August 13, 2009, the Company issued an additional $125 million principal amount of 2014 Notes at 104.75% of par resulting in a premium of $6 million. Interest is payable in arrears semi-annually on June 1 and December 1 of each year. The Company received net proceeds of $129.1 million, which were used to reduce outstanding borrowings under the credit facility.

The 2014 Notes are treated as a single series of debt securities and are carried on the balance sheet at their combined amortized cost. The 2014 Notes are senior unsecured obligations of the Company, which rank effectively junior to all of the Company's existing and any future secured debt, to the extent of the value of the collateral securing that debt, rank equally in right of payment with the 2020 Notes and any future senior unsecured debt, and rank senior in right of payment to the 2016 Notes and the Company's other future subordinated debt.

68

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

4. Debt (Continued)

The 2014 Notes are redeemable at the Company's option, in whole or in part, at any time at a price equal to 100% of the principal amount of the 2014 Notes plus accrued and unpaid interest, if any, plus a "make-whole" premium.

From August to October 2011, the Company repurchased $94.7 million aggregate principal amount of its 2014 Notes for an aggregate purchase price of $108.8 million, including accrued and unpaid interest. The related loss of $15.0 million recorded in extinguishment of debt consists of $11.5 million in premium paid over par and $3.5 million in write-offs of net discount and deferred financing costs. These notes were repurchased using available borrowings under the credit facility. The Company may from time to time seek to repurchase its outstanding debt, including additional 10.25% Notes, through open market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts repurchased may be material.

8.25% Senior Subordinated Notes Due 2016

In 2006, the Company issued $200 million of 2016 Notes at par for proceeds of $196.0 million. Interest on the 2016 Notes is paid semiannually in May 1 and November 1 of each year. The 2016 Notes rank junior to all of the Company's existing and any future secured debt, to the extent of the value of the collateral securing that debt, junior in right of payment to the 2014 and 2020 Notes and any future senior unsecured debt, and equally in right of payment with any future senior subordinated indebtedness.

The Company may redeem the 2016 Notes at any time beginning on or after November 1, 2011 at the prices set forth below, expressed as percentages of the principal amount redeemed, plus accrued but unpaid interest:

2011	104.125	%
2012	102.750	%
2013	101.375	%
2014 and thereafter	100.000	%

The Company may also redeem the 2016 Sub Notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus accrued and unpaid interest plus a "make-whole" premium.

5. Income Taxes

The (benefit) provision for income taxes from continuing operations consists of the following (in thousands):

	Year Ended December 31,
	2011			2010		2009
Current:
Federal	$	4,115		$	363	$	3,148
State	2,936			1,870		782
	7,051			2,233		3,930
Deferred:
Federal	(125,261		)	47,709		20,885
State	(24,018		)	4,026		(4,151		)
	(149,279		)	51,735		16,734
Total	$	(142,228	)	$	53,968	$	20,664

69

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

5. Income Taxes (Continued)

The components of the net deferred income tax liabilities consist of the following:

(in thousands)	Year Ended December 31,
	2011			2010
Deferred income tax assets:
Federal benefit of state income taxes	$	(2,479	)	$	6,862
Credit carryforwards	28,783			28,808
Equity and deferred compensation	12,620			11,229
Derivatives	8,669			26,838
Net operating loss	412			14,545
Other, net	29			1,293
	48,034			89,575
Deferred income tax liabilities:
Depreciation and depletion	(219,705		)	(386,440		)
	(219,705		)	(386,440		)
Net deferred income tax liabilities	$	(171,671	)	$	(296,865	)

At December 31, 2011, the Company's net deferred income tax assets and liabilities were recorded as a current asset of $13.8 million and a long-term liability of $185.5 million. At December 31, 2010, the Company's net deferred income tax assets and liabilities were recorded as a current asset of $32.3 million and a long-term liability of $329.2 million.

Reconciliation of the statutory federal income tax rate to the Company's effective income tax rate follows:

	Year Ended December 31,
	2011		2010		2009
Income tax computed at statutory federal rate	35	%	35	%	35	%
State income taxes, net of federal benefit	3		4		4
Deferred state rate impact	—		(1	)	(5	)
Net impact to uncertain income tax positions	1		—		(2	)
Other	(1	)	2		(2	)
Effective income tax rate	38	%	40	%	30	%

As of December 31, 2011, the Company had approximately $11.1 million of federal and $13.5 million of state (California) EOR tax credit carryforwards available to reduce future income taxes. The EOR credits will begin to expire, if unused, in 2025 and 2016 for federal and California purposes, respectively. The Company has federal alternative minimum income tax (AMT) credit carryforwards of $0.8 million and California AMT credits of $0.7 million that do not expire and can be used to offset regular income taxes in future years to the extent that regular income taxes exceed the AMT in any such year. The Company also has Colorado enterprise zone income tax credits of $2.5 million that will begin to expire in 2018 if not used.

In 2011, the Company executed a final audit settlement that reduced unrecognized income tax benefits by $2.3 million, which resulted in a reduction of the effective income tax rate. As of December 31, 2011, the Company had a gross liability for uncertain income tax benefits of $2.9 million which, if recognized, would affect the effective income tax rate. The Company estimates that it is reasonably possible that the balance of unrecognized income tax benefits as of December 31, 2011 could decrease by a maximum of $2.7 million in the next 12 months due to the expiration of statutes of limitations. The Company recognizes potential accrued interest and penalties related to unrecognized income tax benefits in income tax expense, which is consistent with the recognition of these items in prior reporting periods. The Company had accrued approximately $0.8 million of interest related to its uncertain income tax positions as of December 31, 2011 and 2010.

70

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

5. Income Taxes (Continued)

The Company recognized a net benefit of $2.3 million, $0.0 million and $3.6 million due to the closure of certain federal and state income tax years, offset by additional uncertain income tax position accruals net of interest expense of $0.5 million, $0.1 million and $0.8 million for the years ended December 31, 2011, 2010 and 2009, respectively.

The following table illustrates changes in the gross unrecognized income tax benefits:

(in millions)	Year Ended December 31,
	2011			2010			2009
Unrecognized income tax benefits at January 1	$	5.2		$	6.1		$	12.0
Decreases for positions taken in current year	—			—			(0.1		)
Decreases for positions taken in a prior year	—			(0.8		)	(1.3		)
Decreases for settlements with taxing authorities	(2.3		)	—			(3.6		)
Decreases for lapses in the applicable statute of limitations	—			(0.1		)	(0.9		)
Unrecognized income tax benefits at December 31	$	2.9		$	5.2		$	6.1

As of December 31, 2011, the Company remains subject to examination in the following major tax jurisdictions for the tax years indicated below:

Jurisdiction:	Tax Years Subject to Exam:
Federal	2007 - 2010
California	2007 - 2010
Colorado	2007 - 2010
Texas	2007 - 2010
Utah	2008 - 2010

6. Shareholders' Equity

Shares of Class A Common Stock (Common Stock) and Class B Stock, referred to collectively as the "Capital Stock," are entitled to one vote and 95% of one vote, respectively. Each share of Class B Stock is entitled to a $0.50 per share preference in the event of liquidation or dissolution. Further, each share of Class B Stock is convertible into one share of Common Stock at the option of the holder.

Common Stock Offering

In January 2010, the Company issued 8.0 million shares of Class A Common Stock at a price of $29.25 per share. Net proceeds from this offering were $224.3 million. The Company used the net proceeds from the offering to fund a March 2010 acquisition in the Permian and to repay a portion of the outstanding borrowings under the credit facility. See Note 2 to the Financial Statements.

Dividends

The regular annual dividend for 2011 was $0.31 per share. On August 23, 2011, the Company’s Board of Directors approved an increase in the Company’s quarterly dividend of one-half cent per share from $0.075 to $0.08 per share, beginning with the September 2011 dividend. The Company's dividend is payable quarterly in March, June, September and December. Dividend payments are limited by covenants in the (i) credit facility to the greater of $35 million or 75% of net earnings for any four quarter period, and (ii) indentures governing the Company's senior and subordinated indentures to up to $0.36 per share annually (but in no event in excess of $20 million annually) in the event that the Company is not in default, and up to $10 million in the event that the Company is in a non-payment default.

71

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

7. Equity Incentive Compensation Plans and Other Benefit Plans

The Company's 2010 Equity Incentive Plan (the 2010 Plan), approved by the Company's shareholders in May 2010, provides for granting of equity compensation up to an aggregate of 1,000,000 shares of Common Stock. The purpose of the 2010 Plan is to encourage ownership in the Company by key personnel whose long-term service is considered essential to the Company's continued progress and, thereby, align participants' and shareholders' interests. Stock options, stock appreciation rights (SARs), cash awards and stock awards, including restricted shares and stock units, may be granted under the 2010 Plan. The exercise price of an option may not be less than the fair market value of one share of Common Stock on the date of grant. Stock options and restricted stock awards granted under the 2010 Plan have historically vested either in increments of 25% on each of the first four anniversary dates of the date of grant or 100% after three years. Stock options and restricted stock units (RSUs) granted to non-employee directors have historically vested immediately. Options granted under the 2010 Plan have a term of 10 years. As of December 31, 2011, the Company had 697,596 shares available to be issued under the 2010 Plan.

The 2005 Equity Incentive Plan (the 2005 Plan), approved by the Company's shareholders in May 2005, provides for granting of equity compensation up to an aggregate of 2,900,000 shares of Common Stock. The purpose of the 2005 Plan is to encourage ownership in the Company by key personnel whose long-term service is considered essential to the Company's continued progress and, thereby, align participants' and shareholders' interests. Stock options, stock appreciation rights (SARs), cash awards and stock awards, including restricted shares and stock units, may be granted under the 2005 Plan. The exercise price of an option shall not be less than the fair market value of one share of Common Stock on the date of grant. Stock options and restricted stock awards granted under the 2005 Plan have historically vested in increments of 25% on each of the first four anniversary dates of the date of grant or 100% after three years. Stock options and RSUs granted to non-employee directors have historically vested immediately. Options granted under the 2005 Plan have a term of 10 years. As of December 31, 2011, the Company had 189,297 shares available to be issued under the 2005 Plan.

Total compensation expense recognized in the Statements of Operations for grants under the Company's equity incentive plans was $9.0 million, $8.3 million and $7.7 million in 2011, 2010 and 2009, respectively.

Stock Options

The following table summarizes stock option activity for the years ended December 31, 2011, 2010 and 2009:

	Number of Shares		Weighted Average Exercise Price		Aggregate Intrinsic Value (in thousands)(1)		Number of Shares Exercisable
Outstanding at January 1, 2009	2,421,650		$	25.16	$	—	1,842,532
Granted	—		—
Exercised	(62,050	)	13.52		560
Cancelled/expired	(83,580	)	28.48
Outstanding as of December 31, 2009	2,276,020		25.36		15,296		2,008,325
Granted	—		—
Exercised	(227,100	)	19.40		3,570
Cancelled/expired	(31,695	)	35.51
Outstanding at December 31, 2010	2,017,225		25.87		35,974		1,884,937
Granted	89,865		48.50
Exercised	(579,635	)	17.47		17,746
Cancelled/expired	(6,765	)	45.92
Outstanding at December 31, 2011	1,520,690		$	30.32	$	17,798	1,434,020

_________________________________________

(1) The intrinsic value of a stock option is the amount by which the market value of the underlying stock at the end of the related period exceeds the exercise price of the option.

72

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

7. Equity Incentive Compensation Plans and Other Benefit Plans (Continued)

In March 2011, 89,865 stock options were granted under the 2010 Plan to certain executive officers and other officers of the Company with exercise prices equal to the closing market price of the Company's Common Stock on the grant date. These stock options generally vest ratably over a four-year service period from the grant date and are exercisable immediately upon vesting through the tenth anniversary of the grant date.

The fair value of each option granted was estimated using the Black-Scholes option pricing model. Expected volatility was calculated based on the historical volatility of the Company's Common Stock, and the risk-free interest rate was based on U.S. treasury yield curve rates with maturities consistent with the expected life of each stock option. The key assumptions used in computing the weighted average fair market value of stock options granted were as follows:

	2011
Expected volatility	45.00	%
Risk-free rate	2.54	%
Dividend yield	0.62	%
Expected term (in years)	6.0

The following table summarizes information about stock options outstanding at December 31, 2011:

	Stock Options Outstanding					Stock Options Exercisable
Range of Exercise Prices	Number of Options	Weighted Average Remaining Contractual Life (Years)	Weighed Average Exercise Price		Aggregate Intrinsic Value (in thousands)	Number of Options	Weighted Average Remaining Contractual Life (Years)	Weighed Average Exercise Price		Aggregate Intrinsic Value (in thousands)
$7.00-$15.00	199,000	2.13	$	12.36	5,902	199,000	2.13	$	12.36	$	5,902
$15.01-$25.00	287,000	2.90	21.60		5,861	287,000	2.90	21.60		5,861
$25.01-$35.00	655,001	4.51	31.65		6,792	655,001	4.51	31.65		6,792
$35.01-$48.50	379,689	6.79	44.01		—	293,019	6.09	42.68		—
	1,520,690	4.47	$	30.32	17,798	1,434,020	4.18	$	29.22	$	18,360

As of December 31, 2011, there was $1.3 million of total unrecognized compensation expense related to outstanding stock options, which is expected to be recognized over the next 3.25 years.

73

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

7. Equity Incentive Compensation Plans and Other Benefit Plans (Continued)

Restricted Stock Units

The following table summarizes RSU activity for the years ended December 31, 2011, 2010 and 2009:

	RSUs		Weighted Average Intrinsic Value at Grant Date		Vest Date Fair Value (in thousands)
Outstanding at January 1, 2009	966,198		$	20.83
Granted	294,504		26.72
Issued	(107,375	)	28.98		$	2,574
Canceled/expired	(46,034	)	25.08
Outstanding at December 31, 2009(1)(2)	1,107,293		$	22.14
Granted	34,529		30.94
Issued	(246,633	)	28.98		$	7,813
Canceled/expired	(37,829	)	22.20
Outstanding at December 31, 2010(1)(2)	857,360		$	19.67
Granted	159,333		47.98
Issued	(62,127	)	26.18		$	2,588
Canceled/expired	(39,544	)	25.12
Outstanding at December 31, 2011(1)(2)	915,022		$	23.88

__________________________________

(1) The balance outstanding includes RSUs granted to the non-employee directors that 100% vested at date of grant but are subject to a deferral election before the corresponding shares of Common Stock are issued. For the years ended December 31, 2011, 2010 and 2009, 30,544, 10,522 and 10,522 RSUs have vested, but the corresponding shares of Common Stock have not been issued.

(2) The balance outstanding includes RSUs granted to executive officers and other officers that have vested in accordance with the RSU agreement, but are subject to a deferral election before the corresponding shares of Common Stock are issued. For the years ended December 31, 2011, 2010 and 2009, 483,908, 289,335, and 124,799 RSUs have vested, but the corresponding shares of Common Stock have not been issued.

The grant date fair value of RSUs issued under the 2005 Plan was determined by reference to the average high and low stock price of a share of Common Stock on the date of grant. The grant date fair value of RSUs issued under the 2010 Plan was determined by reference to the closing price of a share of Common Stock on the date of grant. The Company uses historical data and projections to estimate expected restricted stock forfeitures. The expected forfeitures are then included as part of the grant date estimate of compensation cost.

As of December 31, 2011, there was $7.9 million of total unrecognized compensation expense related to RSUs granted. That cost is expected to be recognized over 3.25 years.

74

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

7. Equity Incentive Compensation Plans and Other Benefit Plans (Continued)

Performance Share Program

The following table summarizes performance share award activity for the years ended December 31, 2011, 2010 and 2009:    

	Performance Share Awards		Weighted Average Grant Date Fair Value		Vest Date Fair Value (in thousands)
Outstanding at January 1, 2009	—		$	—
Granted	—		—
Issued	—		—		$	—
Canceled/expired	—		—
Outstanding at December 31, 2009	—		$	—
Granted	103,794		31.20
Issued	—		—		$	—
Canceled/expired	—		—
Outstanding at December 31, 2010	103,794		$	31.20
Granted	65,620		51.86
Issued	—		—		$	—
Canceled/expired	(6,565	)	44.20
Outstanding at December 31, 2011	162,849		$	39.00

In March 2011, 65,620 RSUs that are subject to internal performance metrics and market based vesting criteria in addition to a three-year service condition (performance share awards), were granted to executive officers and other officers. The ultimate vesting of performance share awards is contingent upon meeting the established criteria. From January 1, 2011 to December 31, 2013, the Company must maintain an interest coverage ratio of at least 2.5 to 1.0. The number of performance share awards that ultimately vest is based on two equally weighted performance factors: (i) average daily production growth with respect to certain of the Company's assets on an annual basis and (ii) total shareholder return as compared to the Company's defined peer group for years 2011-2013.

For the portion of the performance share awards subject to internal performance metrics, the grant date fair value was determined by reference to the closing price of a share of Common Stock on the date of grant. The Company recognizes compensation expense when it becomes probable that these conditions will be achieved. However, any such compensation expense recognized is reversed if vesting does not actually occur.

For the portion of the performance share awards subject to market based vesting criteria, the grant date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Company's Common Stock, and the risk-free interest rate is based on U.S. treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in valuing the market-based portion of the performance share awards were as follows:

	2011		2010
Number of simulations	100,000		100,000
Expected volatility	44	%	79	%
Risk-free rate	1.15	%	1.36	%

The total grant date fair value of the market-based portion of the performance share awards issued in 2011 and 2010, as determined by the Monte Carlo valuation model, was $1.1 million and $1.0 million, respectively, and is being recognized ratably over the respective three-year vesting period. Compensation expense for the market-based portion of the performance share awards is not reversed if vesting does not actually occur.

75

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

7. Equity Incentive Compensation Plans and Other Benefit Plans (Continued)

As of December 31, 2011, there was $1.4 million of total unrecognized compensation cost related to performance share awards granted. This cost is expected to be recognized over 2 years.

Director Fees

The Company's directors may elect to receive their annual retainer and meeting fees in the form of the Company's Common Stock issued pursuant to the Company's Non-Employee Director Deferred Stock and Compensation Plan (the Deferred Plan). The plan permits eligible directors, in recognition of their contributions to the Company, to receive compensation for service and to defer recognition of their compensation in whole or in part to a stock unit account or an interest account. When the eligible director ceases to be a director, the distribution from the stock unit account is made in shares of Common Stock. The distribution from the interest account is made in cash. Shares of Common Stock earned and deferred in accordance with the Deferred Plan as of December 31, 2011, 2010 and 2009 were 13,647, 38,462, and 124,686, respectively.

Amounts allocated to the stock unit account have the right to receive a "dividend equivalent" equal to the dividends declared and paid by the Company. The dividend equivalent is treated as reinvested in an additional number of units and credited to the director's account using an established market value. Amounts allocated to the interest account are credited with interest at an established interest rate.

Other Employee Benefits—401(k) Plan

The Company sponsors a defined contribution thrift plan under section 401(k) of the Internal Revenue Code to assist all employees in providing for retirement or other future financial needs. The Company currently matches 100% of each employee's contribution up to 8% of an employee's eligible compensation. The Company's contributions to the 401(k) Plan, net of forfeitures, for the years ended December 31, 2011, 2010 and 2009 were $1.8 million, $1.5 million and $1.4 million, respectively. Employees are eligible to participate in the 401(k) Plan on their date of hire and approximately 98% of the Company's employees participated in the 401(k) Plan in 2011.

8. Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable, economic cash flow from its oil and natural gas production by reducing its exposure to price fluctuations. The Company has entered into financial commodity swap and collar contracts to fix the floor and ceiling prices received for a portion of the Company's oil and natural gas production. The terms of the contracts depend on various factors, including management's view of future crude oil and natural gas prices, acquisition economics on purchased assets and future financial commitments. The Company periodically enters into interest rate derivative contracts to protect against changes in interest rates on its floating rate debt. For further discussion related to the fair value of the Company's derivatives see Note 9 to the Financial Statements.

As of December 31, 2011, the Company had commodity derivatives associated with the following volumes:

	2012	2013	2014
Oil Bbl/D:	21,000	15,000	2,000
Natural Gas MMBtu/D:	15,000	—	—

Based on NYMEX strip pricing as of December 31, 2011, the Company would receive payments under existing derivative contracts of $5.3 million during the next twelve months.

Discontinuance of Hedge Accounting

Effective January 1, 2010, the Company elected to de-designate all of its commodity and interest rate derivative contracts that had been previously designated as cash flow hedges as of December 31, 2009. As a result, subsequent to December 31, 2009, the Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings

76

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

8. Derivative Instruments (Continued)

rather than deferring any such amounts in AOCL. As a result of discontinuing hedge accounting on January 1, 2010, the fair values of the Company's open derivative instruments designated as cash flow hedges as of December 31, 2009, less any ineffectiveness recognized, were frozen in AOCL and are reclassified into earnings as the original hedge transactions settle.

At December 31, 2011, AOCL consisted of $8.9 million ($5.5 million net of income tax) of unrealized losses on commodity and interest rate contracts that had been previously designated as cash flow hedges. At December 31, 2010, AOCL consisted of $70.7 million ($43.8 million net of income tax) of unrealized losses on commodity and interest rate contracts that had been previously designated as cash flow hedges. During the years ended December 31, 2011 and December 31, 2010, $61.8 million ($38.3 million, net of income tax) and $26.7 million ($16.6 million, net of income tax), respectively, of non-cash amortization of AOCL related to discontinuing hedge accounting was reclassified from AOCL into earnings. The Company expects to reclassify into earnings from AOCL pre-tax net losses of $8.9 million related to de-designated commodity and interest rate derivative contracts during the next 12 months.

In the fourth quarter of 2010, the Company terminated interest rate derivative instruments that were previously designated as cash flow hedges. The termination resulted in a cash settlement of $10.8 million, offset by a fair value gain of $8.9 million. The net loss of $1.9 million is included in realized and unrealized (gain) loss on derivatives, net.

The following tables detail the fair value of derivatives recorded on the Company's Balance Sheets, by category:

	December 31, 2011
	Derivative Assets			Derivative Liabilities
(in millions)	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Current:
Commodity	Derivative assets	$	6.1	Derivative liabilities	$	20.4
Long-term:
Commodity	Derivative assets	7.0		Derivative liabilities	15.5
Total derivatives		$	13.1		$	35.9

	December 31, 2010
	Derivative Assets			Derivative Liabilities
(in millions)	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Current:
Commodity	Derivative assets	$	2.7	Derivative liabilities	$	84.9
Long-term:
Commodity	Derivative assets	2.1		Derivative liabilities	33.5
Total derivatives		$	4.8		$	118.4

77

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

8. Derivative Instruments (Continued)

The tables below summarize the location and the amount of derivative instrument (gains) losses before income taxes reported in the Statements of Operations for the periods indicated:

(in millions)		Year Ended December 31,
Derivatives cash flow hedging relationships	Location of (Gain) Loss Recognized in Earnings	2011	2010	2009
Commodity
Loss recognized in AOCL (effective portion)	Accumulated other comprehensive loss	—	—	206.4
(Gain) reclassified from AOCL into earnings (effective portion)	Sales of oil and natural gas	—	—	(58.8	)
(Gain) reclassified from AOCL into earnings (effective portion)	Earnings from discontinued operations	—	—	(20.5	)
Loss recognized in earnings (ineffective portion)	Realized and unrealized (gain) loss on derivatives, net	—	—	0.6
Loss reclassified from AOCL into earnings (amortization of frozen amounts)	Sales of oil and natural gas	60.9	18.4	—
Interest rate
Loss recognized in AOCL (effective portion)	Accumulated other comprehensive loss	—	—	2.7
Loss reclassified from AOCL into earnings (effective portion)	Interest	—	—	7.0
Loss reclassified from AOCL into earnings (amortization of frozen amounts)	Interest	0.8	8.3	—

(in millions)		Year Ended December 31,
Derivatives not designated as hedging instruments under authoritative guidance	Location of (Gain) Loss Recognized in Earnings	2011		2010	2009
Commodity
(Gain) loss recognized in earnings (cash settlements and mark-to-market movements)	Realized and unrealized (gain) loss on derivatives, net	(13.9	)	23.2	7.2
(Gain) loss recognized in earnings (cash settlements and mark-to-market movements)	Earnings from discontinued operations	—		—	0.5
Interest rate
(Gain) loss reclassified from AOCL into earnings (amortization of frozen amounts)	Realized and unrealized (gain) loss on derivatives, net	—		8.6	—

Credit Risk

The Company does not require collateral or other security from counterparties to support derivative instruments. However, the contracts with those counterparties typically contain netting provisions such that if a default occurs, the non-defaulting party can offset the amount payable to the defaulting party under the derivative contract with the amount due from the defaulting party. As a result of the netting provisions, the Company's maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. The maximum amount of loss due to credit risk that the Company would have incurred if all counterparties to its derivative contracts failed to perform at December 31, 2011 was $7.5 million.

As of December 31, 2011, the counterparties to the Company's commodity derivative contracts consist of seven financial institutions. The Company's counterparties or their affiliates are generally lenders, or affiliates of lenders, under the Company's credit facility. As a result, the counterparties to the Company's derivative contracts share in the collateral supporting the Company's credit facility. The Company is not generally required to post additional collateral under derivative contracts.

78

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

8. Derivative Instruments (Continued)

Certain of the Company's derivative contracts contain cross default provisions that accelerate of amounts due under such contract if the Company defaults on its obligations under its material debt agreements. In addition, if the Company defaults on certain of its material debt agreements, including, potentially, its derivative contracts, the Company would be in default under the credit facility. As of December 31, 2011, the Company was in a net liability position with four of its counterparties, the fair value of which was $30.2 million. As of December 31, 2011, the Company's largest two counterparties accounted for 84% of the value of its total derivative positions.

9. Fair Value Measurement

The authoritative guidance for fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers include: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

A financial instrument's categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy. The fair value of all derivative instruments is estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The fair value of all derivative instruments is estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services, and the Company has made no adjustments to the obtained prices. The independent pricing services publish observable market information from multiple brokers and exchanges. All valuations were compared against counterparty valuations to verify the reasonableness of prices. The Company also considers counterparty credit risk and its own credit risk in its determination of all estimated fair values. The Company has consistently applied these valuation techniques in all periods presented and believes it has obtained the most accurate information available for the types of derivative contracts it holds. The Company recognizes transfers between levels at the end of the reporting period for which the transfer has occurred.

Liabilities Measured at Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy the Company's net derivative liabilities that were measured at fair value on a recurring basis as of December 31, 2011 and 2010:

(in millions)	Total		Level 1		Level 2		Level 3
Commodity derivatives liability, net
December 31, 2011	$	22.7	$	—	$	22.7	$	—
December 31, 2010	$	113.6	$	—	$	11.8	$	101.8

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BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

9. Fair Value Measurement (Continued)

Changes in Level 3 Fair Value Measurements

The table below includes a rollforward of amounts included in the Company's Balance Sheet (including the change in fair value) for financial instruments classified by the Company within Level 3 of the fair value hierarchy. When a determination is made to classify a financial instrument within Level 3 of the fair value hierarchy, the determination is based upon the significance of the unobservable factors to the overall fair value measurement. Level 3 financial instruments typically include, in addition to the unobservable or Level 3 components, observable components (that is, components that are actively quoted and can be validated to external sources).

	Year Ended December 31,
(in millions)	2011			2010		2009
Fair value liability (asset), beginning of period	$	101.8		$	26.0	$	(172.5	)
Transfer out of Level 3(1)	(101.8		)	—		(3.4		)
Realized and unrealized (gain) loss included in earnings	—			37.4		(71.0		)
Unrealized loss included in accumulated other comprehensive loss	—			—		201.9
Settlements	—			38.4		71.0
Fair value liability, end of period	$	—		$	101.8	$	26.0
Total unrealized (gain) loss included in earnings related to financial assets and liabilities still on the Balance Sheets	$	—		$	75.8	$	(0.4	)

___________________________

(1) During the first quarter of 2011, the inputs used to value oil collars, natural gas collars and natural gas basis swaps were directly or indirectly observable, and these instruments were transferred to level 2.

The $3.4 million of transfers out of Level 3 for the year ended December 31, 2009 represent crude oil collars that were converted to crude oil swaps during the first quarter of 2009.

For further discussion related to the Company's derivatives, see Note 8 to the Financial Statements.

Fair Market Value of Financial Instruments

The Company uses various assumptions and methods in estimating the fair values of its financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of the Company's credit facility and line of credit approximated fair value because the interest rates are variable and could be at similar rates today. The fair values of the 2016 Notes, the 2014 Notes, and the 2020 Notes were estimated based on quoted market prices. The fair values of the Company's derivative instruments are discussed above.

	December 31, 2011				December 31, 2010
(in millions)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Line of credit	$	—	$	—	$	5	$	5
Senior secured revolving credit facility	532		532		170		170
8.25% Senior subordinated notes due 2016	200		209		200		210
10.25% Senior notes due 2014, net of unamortized discount of $6,564 and $11,035, respectively	349		402		439		518
6.75% Senior notes due 2020	300		302		300		303
	$	1,381	$	1,445	$	1,114	$	1,206

80

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

9. Fair Value Measurement (Continued)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The Company applies the provisions of the fair value measurement standard to its non-recurring, non-financial measurements including business combinations, oil and natural gas property impairments and other long-lived asset impairments. These items are not measured at fair value on a recurring basis but are subject to fair value adjustments only in certain circumstances.

In 2011, the Company recognized impairment losses of $625.0 million and $4.3 million related to natural gas properties and other long-lived assets (drilling rigs), respectively. In 2009, the Company recognized an impairment loss of $4.2 million related to other long-lived assets. The following tables present information about the Company's non-financial assets measured at fair value on a non-recurring basis as of December 31, 2011 and 2009 and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values:

			Fair Value Measurements (in millions) Using
Description	Carrying Value at 12/31/2011		Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)	Losses Recognized in 2011
Natural Gas Properties	$	114.3	—	—	114.3	$	625.0
Other Long-Lived Assets	1.4		—	—	1.4	4.3
						$	629.3

			Fair Value Measurements (in millions) Using
Description	Carrying Value at 12/31/2009		Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)	Losses Recognized in 2009
Other Long-Lived Assets	$	3.3	—	—	3.3	$	4.2

See Notes 2 and 11 to the Financial Statements for additional information on the methods and assumptions used to estimate the fair values of the Company's assets measured at fair value on a nonrecurring basis.

10. Commitments and Contingencies

Operating Leases and Other Commitments

The Company leases corporate and field offices in California, Colorado and Texas under agreements expiring over the next five years. In 2006, the Company purchased an airplane for business travel which was subsequently sold and contracted under a ten year operating lease beginning December 2006. The Company also finances vehicles under operating leases, which expire over the next three years. Rent expense with respect to these lease commitments was $2.6 million for each of the years ended December 31, 2011, 2010 and 2009. The Company currently has four drilling rigs under contracts that require minimum payments for the full contract term or penalties upon early termination. All of these contracts expire during 2012. All other rigs currently performing work for the Company are on a well-by-well basis and can be released without penalty at the conclusion of drilling on the current well. The Company also has other commitments relating primarily to natural gas purchases, cogeneration facility management services and equipment rentals. Additionally, the Company enters into certain firm commitments to transport natural gas production to market and to transport natural gas to its cogeneration and conventional steam generation facilities. These commitments generally require a minimum monthly charge regardless of whether the contracted capacity is used or not.

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BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

10. Commitments and Contingencies (Continued)

The table below shows the Company's future minimum payments under non-cancelable operating leases and other commitments as of December 31, 2011:

(in millions)	Total		2012		2013		2014		2015		2016		Thereafter
Operating leases(1)	$	11.8	$	2.8	$	2.8	$	2.6	$	2.2	$	1.4	$	—
Drilling rig commitments(2)	7.0		7.0		—		—		—		—		—
Other commitments(3)	31.3		14.2		11.4		1.8		1.9		2.0		—
Firm natural gas transportation contracts(4)	263.5		29.7		30.2		32.7		32.6		32.5		105.8
Total	$	313.6	$	53.7	$	44.4	$	37.1	$	36.7	$	35.9	$	105.8

___________________________________

(1) Includes operating leases related to office facilities, vehicles and aircraft.

(2) Excludes obligations related to rigs drilling on a well-by-well basis that can be released after drilling the current well without penalty.

(3) Includes primarily obligations related to natural gas purchases, cogeneration facility management services and equipment rentals.

(4) Includes a transportation agreement with Questar Pipeline Company for an average of 6,200 MMBtu/D of firm transportation over a period of eight years, based on the expectation that the expansion of the Chipeta Processing LLC natural gas plant expansion will be completed and transportation under this contract will begin July 1, 2012.

Uinta Crude Oil Sales Contract

The Company is a party to a crude oil sales contract through June 30, 2013 with a refiner for the purchase of a minimum of 5,000 Bbl/D of its Uinta light crude oil. Pricing under the contract, which includes transportation and gravity adjustments, is at a fixed percentage of WTI. While the contractual differentials under this contract may be less favorable at times than the posted differential, demand for the Company's 40 degree black wax (light) crude oil can vary seasonally and this contract provides a stable outlet for the Company's crude oil. Gross oil production from the Company's Uinta properties averaged approximately 3,390 Bbl/D in 2011. Due to the possibility of refinery constraints in the Utah region, it is possible that the loss of the Company's crude oil sales customer in Utah could impact the marketability of a portion of the Company's Utah crude oil volumes. Please see Item 1A. Risk Factors—"We may not be able to deliver minimum crude oil volumes required by our sales contract."

E. Texas Gathering System

In July 2009, the Company closed on the financing of its E. Texas natural gas gathering system for $18.4 million in cash. The Company entered into concurrent long-term natural gas gathering agreements for the E. Texas production which contained an embedded lease. The transaction was treated as a financing obligation. Accordingly, the $16.7 million net book value of the property is being depreciated over the remaining useful life of the asset and the cash received of $18.4 million was recorded as a financing obligation. A portion of payments under the agreements are recorded as gathering expense and a portion as interest expense, with the balance being recorded as a reduction to the financing obligation. There are no minimum payments required under these agreements. For the years ended December 31, 2011, 2010 and 2009 the Company incurred $5.3 million, $6.7 million and $2.0 million, respectively, under the agreements.

82

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

10. Commitments and Contingencies (Continued)

Carry and Earning Agreement

On January 14, 2011, the Company entered into an amendment relating to certain contractual obligations to a third party co-owner of certain Piceance assets in Colorado. The amendment waives the $0.2 million penalty for each well not spud by February 2011 and requires the Company to reassign to such co-owner, by January 31, 2020, all of the interest acquired by the Company from the co-owner in each 160-acre tract in which the Company has not drilled and completed a well that is producing or capable of producing from a designated formation, or deeper formation, on January 1, 2020. The amendment also requires the Company to pay the first $9.0 million of costs incurred in connection with the construction of either an extension of the existing access road or a new access road, including the third party's 50% share. If by June 30, 2013 (which date may be extended until December 31, 2014 if road construction has commenced by June 30, 2013), the Company has not expended $9.0 million ($4.5 million of which would otherwise be such third party's responsibility) in road construction costs, then it will be obligated to pay the third party 50% of the difference between $12 million and the actual amount expended on road construction as of such date. Due to the need to obtain regulatory approvals, the Company has not yet commenced construction of either an extension of the existing access road or a new access road and may be unable to do so by June 30, 2013, thus triggering the payment obligation to the third party.

Environmental Matters

The Company has no material accrued environmental liabilities for its sites, including sites in which governmental agencies have designated the Company as a potentially responsible party, because it is not probable that a loss will be incurred and the minimum cost and/or amount of loss cannot be reasonably estimated. However, because of the uncertainties associated with environmental assessment and remediation activities, future expense to remediate the currently identified sites, and sites identified in the future, if any, could be incurred. Management believes, based upon current site assessments, that the ultimate resolution of any matters will not result in material costs incurred.

Legal Matters

COGCC Order — On April 21, 2011, the Company received a proposed Order Finding Violation from the Colorado Oil and Gas Conservation Commission (COGCC) alleging that certain releases in late 2007 from a lined reserve pit located on a well pad in western Colorado violated COGCC regulations. Shortly thereafter, the Company entered into negotiations with the COGCC. While the Company denies that it violated any COGCC regulations in connection with the releases, on June 27, 2011, the COGCC approved and the Company later signed an Administrative Order on Consent under which the Company would pay $100,000, and fund a mutually acceptable public project in the amount of $73,000, in full satisfaction of the matter. The Company recorded these amounts in the second quarter of 2011 and paid $100,000 in July 2011. The Company expects to fund the mutually acceptable project during the first half of 2012.

BLM Settlement — On March 28, 2011, the Company entered into a settlement agreement with the Bureau of Land Management (BLM) resolving all claims by the BLM that the Company did not comply with BLM regulations relating to the operation and position of certain valves, and the submission of related site facility diagrams, in its Uinta operations. The settlement agreement confirmed that the Company promptly remediated the alleged noncompliance upon learning of it, and cooperated with the BLM's investigation, and that there is no evidence of any senior Company management knowledge of the alleged noncompliance, or of any environmental harm or loss of oil or royalty revenue resulting from such alleged noncompliance. The Company paid a $2.1 million civil penalty to the BLM under the settlement agreement in April 2011.

Royalty Payments — Certain of the Company's royalty payment calculations are being disputed. The Company believes that its royalty calculations are in accordance with applicable leases and other agreements, as well as applicable law. However, the disputed amounts that the Company may be required to pay are up to approximately $7.1 million.

Other —The Company is involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of management, the resolution of these matters will not have a material effect on its financial position, results of operations or operating cash flows.

83

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

11. Oil and Natural Gas Properties, Buildings and Equipment

Oil and natural gas properties, buildings and equipment consist of the following:

	Year Ended December 31,
(in thousands)	2011			2010
Oil and natural gas:
Proved properties(1)	$	3,257,321		$	3,182,305
Unproved properties(2)	228,486			217,253
	3,485,807			3,399,558
Less accumulated depreciation, depletion and amortization	(962,154		)	(757,264		)
	2,523,653			2,642,294
Commercial and other:
Machinery, drilling rigs, and equipment	22,509			24,988
Buildings and improvements	6,894			7,434
Vehicles	7,806			6,849
	37,209			39,271
Less accumulated depreciation	(29,469		)	(25,773		)
	7,740			13,498
	$	2,531,393		$	2,655,792

________________________________________

(1) Includes cogeneration facilities.

(2) Unproved properties includes acquisition costs for properties to which proved developed producing and proved undeveloped reserves are also attributed. At December 31, 2011, unproved properties included $14.8 million of acquisition costs for unevaluated properties. The Company assesses these properties annually and recorded impairments of $0.6 million, $0.0 million and $1.0 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Impairment of Oil and Natural Gas Properties

The Company reviews its oil and natural gas properties for impairment whenever events or circumstances indicate that their carry values may not be recoverable. During the years ended December 31, 2011, 2010 and 2009, the Company recorded impairments of oil and natural gas properties in continuing operations of $625.6 million, $0.0 million, and $1.0 million, respectively. Additionally, during the year ended December 31, 2009, the Company recorded an impairment of $9.6 million, which is recorded in discontinued operations.

In the fourth quarter of 2011, the Company recorded a non-cash impairment of $625.0 million related its E. Texas natural gas properties. The impairment was due to decreases in natural gas prices and, as a result, changes in the Company's development plans. In the fourth quarter of 2011, the NYMEX Henry Hub (HH) five-year future strip (the average of the settlement prices of the next 60 months' futures contracts) decreased approximately 15%. The carrying value of the Company's E. Texas assets prior to the impairment was $739.3 million. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows. Given the unobservable nature of these inputs, the nonrecurring fair value measurement of the E. Texas properties is deemed to use Level 3 inputs.

In March 2009, the Company entered into an agreement to sell its assets in the DJ. The transaction closed in April 2009. The Company recorded a non-cash impairment of $9.6 million related to the sale, which is aggregated within the $6.8 million earnings from discontinued operations, net of income tax, on its Statements of Operations for the year ended December 31, 2009.

84

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

11. Oil and Natural Gas Properties, Buildings and Equipment (Continued)

If natural gas prices continue to decrease during 2012, the estimated undiscounted future cash flows of the Company's proved natural gas properties may not exceed the carry value and a non-cash impairment charge may be required to be recognized in future periods.

Dry Hole, Abandonment, and Impairment

During the years ended December 31, 2011, 2010, and 2009, the Company recorded an impairment of its drilling rigs in continuing operations of $4.3 million, $0 million, and $4.2 million, respectively. In the fourth quarter of 2011, the Company decided to sell and is actively marketing its three drilling rigs. As a result, the Company reduced the rigs' carrying value of $5.7 million to $1.4 million, consisting of the rigs' fair value less costs to sell. The fair value of the rigs is included in oil and natural gas properties (successful efforts basis), buildings and equipment, net on the Company's Balance Sheets at December 31, 2011. The fair value of the drilling rigs was determined using a market approach, considering comparative market data. Given the unobservable nature of these inputs, the nonrecurring fair value measurement of the drilling rigs is deemed to use Level 3 inputs. In the fourth quarter of 2009, subsequent to the approval of the Company's capital budget, the Company recorded a non-cash impairment to reduce the carrying value of a drilling rig to fair value. The carrying value of $7.5 million was written down to its fair value of $3.3 million. The fair value of the rig was determined using the present value of estimated cash flows. This model considered internal estimates of drilling and operating costs, technical and economic conditions, and a risk adjusted discount rate. Given the unobservable nature of these inputs, the nonrecurring fair value measurement of this rig is deemed to use Level 3 inputs.

In 2010, the Company recorded dry hole, abandonment, and impairment expense primarily due to a mechanical failure encountered on one well in the Piceance. The well was abandoned in favor of drilling a replacement well from the same well pad.

Capitalized Interest

Acquisition costs of proved undeveloped and unproved properties qualify for interest capitalization during a period if interest cost is incurred and activities necessary to bring the properties into a productive state are in progress. As wells are drilled in a field with proved undeveloped or unproved reserves, a portion of the acquisition costs are either re-designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re-designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field.

During 2011, the Company capitalized interest on its Piceance asset for the first half of 2011 and on its Permian asset for all of 2011, as development activities were ongoing. During 2010, the Company capitalized interest on its Piceance and Permian assets as development activities were ongoing. During 2009, the Company capitalized interest on its Piceance and E. Texas assets as development activities were ongoing. In the future, interest capitalization on acquisition costs will depend on whether or not development activities are ongoing. Development activities consist primarily of drilling wells and installing the necessary equipment for production to commence. Interest capitalization ceases when the wells have been completed. Interest cost is capitalized as a component of property cost for development projects that require greater than six months to be readied for their intended use.

85

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

12. Asset Retirement Obligations (AROs)

The following table summarizes the summarizes the activity for the Company's abandonment obligations:

	Year Ended December 31,
(in thousands)	2011			2010
Beginning balance at January 1	$	53,443		$	43,487
Liabilities incurred	2,983			3,721
Liabilities settled	(1,803		)	(1,832		)
Liabilities assumed	119			3,498
Accretion expense	4,812			4,569
Revisions in estimated cash flows	4,465			—
Ending balance at December 31(1)	$	64,019		$	53,443

____________________

(1) The asset retirement obligation related to the Nevada Assets, which were held for sale as of December 31, 2011, was $0.7 million at December 31, 2011 and is included in the asset retirement obligations liability on the December 31, 2011 Balance Sheets. See Note 3 to the Financial Statements.

AROs reflect the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company's oil and natural gas properties. Inherent in the fair value calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance.

13. Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited)

The reserve estimates were made in accordance with oil and natural gas reserve estimation and disclosure authoritative accounting guidance issued by the Financial Accounting Standards Board effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and natural gas reserve estimation and disclosure requirements with the requirements in the SEC's "Modernization of Oil and Gas Reporting" rule, which was also effective for annual reports for fiscal years ending on or after December 31, 2009.

The above-mentioned rules include updated definitions of proved oil and natural gas reserves, proved undeveloped oil and natural gas reserves, oil and natural gas producing activities, and other terms used in estimating proved oil and natural gas reserves. Proved oil and natural gas reserves were calculated based on the prices for oil and natural gas during the twelve month period before the reporting date, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. In addition, the SEC generally requires that reserves classified as proved undeveloped be capable of conversion into proved developed within five years of classification unless specific circumstances justify a longer time.

86

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

13. Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited) (Continued)

Changes in Estimated Reserve Quantities

The following table sets forth the Company's estimates of its net proved, net proved developed, and net proved undeveloped oil and natural gas reserves as of December 31, 2011, 2010 and 2009, and changes in its net proved oil and natural gas reserves for the years then ended. For the years presented, the estimates of proved reserves and related valuations were based 100% on reports prepared by the Company's independent petroleum engineers, DeGolyer and MacNaughton (D&M).

	2011						2010						2009
	Oil MBOE		Natural Gas MMcf		MBOE		Oil MBOE		Natural Gas MMcf		MBOE		Oil MBOE		Natural Gas MMcf		MBOE
Proved developed  and undeveloped reserves:
Beginning of year	166,181		630,192		271,213		129,940		632,178		235,303		125,251		724,135		245,940
Revision of previous estimates	(4,054	)	(146,349	)	(28,446	)	4,288		(46,860	)	(3,522	)	2,786		(34,564	)	(2,975	)
Improved recovery	—		—		—		1,700		—		1,700		—		—		—
Extensions and  discoveries	19,601		65,992		30,600		12,774		43,469		20,019		8,989		54,664		18,100
Property sales	—		—		—		—		—		—		—		(126,600	)	(21,100	)
Production	(9,041	)	(23,907	)	(13,025	)	(7,925	)	(23,989	)	(11,923	)	(7,186	)	(22,657	)	(10,962	)
Purchase of reserves in place	13,193		8,351		14,584		25,404		25,394		29,636		100		37,200		6,300
End of year	185,880		534,279		274,926		166,181		630,192		271,213		129,940		632,178		235,303
Proved developed  reserves:
Beginning of year	88,917		268,566		133,678		82,870		255,520		125,456		74,616		361,575		134,879
End of year	107,849		221,606		144,783		88,917		268,566		133,678		82,870		255,520		125,456

Notable changes in proved reserves for the years ended December 31, 2011, 2010, 2009 included:

• Purchase of Reserves in Place. In 2011 and 2010 the Company acquired reserves of 14,584 MBOE, 29,636 MBOE and primarily in the Wolfberry trend in the Permian. See Note 2 to the Financial Statements. In 2009, the Company acquired reserves of 6,300 MBOE primarily in the Piceance.

• Extensions and Discoveries. In 2011, the Company had a total of 30,600 MBOE of extensions and discoveries, which were primarily due to successful drilling and completion activities in the Diatomite, McKittrick, Utah, Piceance and Permian assets. In 2010, the Company had a total of 20,019 MBOE of extensions and discoveries, which were primarily due to the successful drilling and completion activities in the Diatomite, Permian, Utah and E. Texas assets. In 2009, the Company had a total of 18,100 MBOE of extensions and discoveries, which were primarily due to the successful drilling and completion activities in the Diatomite and Piceance assets.

• Revisions to Previous Estimates. In 2011, the Company had negative revisions of 28,446 MBOE, which were primarily due to removing proved undeveloped reserves related to assets that reached aging limitations, as mandated by the SEC and negative performance revisions. Specifically, the decrease is due to a 19,632 MBOE decrease in E. Texas, a 5,779 MBOE decrease in Piceance and a 2,576 MBOE decrease in Utah. In 2010, the Company had negative revisions 3,522 MBOE, which were primarily due to negative performance revisions and the Company's future development plans.

87

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

13. Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited) (Continued)

Specifically, the decrease is due to a 3,666 MBOE decrease in E. Texas, a 3,890 MBOE decrease in the Piceance, and a 840 MBOE decrease in Uinta, offset by a 971 MBOE increase in the Permian and a 3,903 MBOE increase in California. In 2009, the Company had negative revisions of 2,975 MBOE, which were primarily due to negative performance revisions. Specifically, the decrease is due to a 9,108 MBOE decrease in E. Texas, offset by a 398 MBOE increase in California and 5,735 MBOE increase in Utah and Piceance.

• Property Sales. In 2009, the Company had total reserve sales of 21,100 MBOE from sale of its DJ assets. See Note 2 to the Financial Statements.

Standardized Measure of Discounted Future Net Cash Flows

Future oil and natural gas sales are calculated applying the prices used in estimating the Company's proved oil and natural gas reserves to the year-end quantities of those reserves. Future production and development costs, which include costs related to plugging of wells, removal of facilities and equipment, and site restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved oil and natural gas reserves at the end of each year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory income tax rates to the estimated future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax bases of the properties involved. The future income tax expenses give effect to income tax deductions, credits, and allowances relating to the proved oil and natural gas reserves. All cash flow amounts, including income taxes, are discounted at 10%.

The following table presents the standardized measure of discounted future net cash flows related to proved oil and natural gas reserves:

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Future cash inflows	$	19,568,628		$	14,354,627		$	9,028,991
Future production costs	(5,226,044		)	(4,446,183		)	(3,826,832		)
Future development costs	(1,975,429		)	(1,789,001		)	(1,159,465		)
Future income tax expense	(3,770,512		)	(2,272,184		)	(969,771		)
Future net cash flows	8,596,643			5,847,259			3,072,923
10% annual discount for estimated timing of cash flows	(4,561,364		)	(3,048,103		)	(1,627,176		)
Standardized measure of discounted future net cash flows	$	4,035,279		$	2,799,156		$	1,445,747
Average price during the 12-month period: (1)
Oil ($/BOE)	$	93.72		$	69.04		$	52.06
Natural gas ($/Mcf)	4.02			4.57			3.58
BOE ($/BOE)	$	71.18		$	52.93		$	38.37

______________________________     

(1) Differences between the average benchmark prices and the average prices used in the calculation of the standardized measure are attributable to adjustments made for transportation, quality and basis differentials.

The present value (at a 10% annual discount) of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of its estimated oil and natural gas reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on prices and costs in effect on the day of estimate in accordance with the applicable accounting guidance. However, actual future net cash flows from its oil and natural gas properties will also be affected by factors such as actual prices the Company receives for oil and natural gas, the amount and timing of actual production, supply of and demand for oil and natural gas and changes in governmental regulations or taxation.

88

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

13. Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited) (Continued)

The timing of both the Company’s production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor the Company uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general.

A summary of changes in the standardized measure of discounted future net cash flows is as follows:

	Year ended December 31,
	2011			2010			2009
	(in thousands)
Standardized measure—beginning of year	$	2,799,156		$	1,445,747		$	1,135,581
Sales of oil and natural gas produced, net of production costs	(599,679		)	(406,390		)	(353,052		)
Revisions to estimates of proved reserves:
Net changes in sales prices and production costs	1,473,454			1,724,212			637,882
Revisions of previous quantity estimates	(281,765		)	(49,784		)	(33,943		)
Improved recovery	—			24,033			—
Extensions and discoveries	601,313			283,011			206,542
Change in estimated future development costs	(274,122		)	(152,096		)	(52,824		)
Purchases of reserves in place	164,383			307,205			29,348
Sales of reserves in place	—			—			(138,265		)
Development costs incurred during the period	433,660			144,086			110,200
Accretion of discount	383,418			184,917			131,745
Income taxes	(634,747		)	(593,272		)	(190,727		)
Other	(29,792		)	(112,513		)	(36,740		)
Net increase	1,236,123			1,353,409			310,166
Standardized measure—end of year	$	4,035,279		$	2,799,156		$	1,445,747

The following table presents costs incurred in oil and natural gas property acquisition, exploration, and development activities:

	Year ended December 31,
	2011		2010		2009
	(in thousands)
Property acquisitions
Proved properties	$	149,158	$	334,409	$	13,497
Unproved properties	6,632		—		—
Development	544,114		320,927		138,168
Exploration	627		2,310		209
Total(1)	$	700,531	$	657,646	$	151,874

__________________________________________

(1)The total above does not reflect $29.1 million, $28.3 million, and $30.1 million of capitalized interest incurred in 2011, 2010, and 2009, respectively.

89

BERRY PETROLEUM COMPANY

Notes to the Financial Statements (Continued)

14. Selected Quarterly Financial Data (Unaudited)

	Operating Revenues		Net (Loss) Earnings			Basic Net (Loss) Earnings Per Share(1)			Diluted Net (Loss) Earnings Per  Share(1)
2011
First Quarter	$	197,486	$	(52,497	)	$	(0.98	)	$	(0.98	)
Second Quarter	242,709		105,166			1.93			1.90
Third Quarter	238,763		134,001			2.45			2.42
Fourth Quarter	240,600		(414,733		)	(7.62		)	(7.62		)
	$	919,558	$	(228,063	)	$	(4.21	)	$	(4.21	)
2010
First Quarter	$	166,012	$	17,669		$	0.34		$	0.34
Second Quarter	164,457		89,023			1.65			1.64
Third Quarter	166,040		(3,023		)	(0.06		)	(0.06		)
Fourth Quarter	180,001		(21,145		)	(0.40		)	(0.40		)
	$	676,510	$	82,524		$	1.54		$	1.52

_______________________________________________________________________________

(1) The sum of the individual quarterly net (loss) earnings per common share amounts may not agree with year-to-date net (loss) earnings per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period. Potentially dilutive securities were included in the computation of diluted net (loss) earnings per common share for each quarter in which the Company reported net earnings.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of December 31, 2011, we have carried out an evaluation under the supervision of, and with the participation of, our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934, as amended (the Exchange Act).

Our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2011, our disclosure controls and procedures are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Management's Report on Internal Control Over Financial Reporting

Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, our principal executive and principal financial officers, or persons performing similar functions, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles and includes those policies and procedures that:

• pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in

90

accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of our management and Directors; and

• provide reasonable assurance regarding prevention or the timely detection of unauthorized acquisition, or the use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control—Integrated Framework, management concluded that our internal control over financial reporting was effective as of December 31, 2011. The effectiveness of our internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.    Other Information

None.

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PART III

Item 10.    Directors and Executive Officers and Corporate Governance

The information called for by Item 10 is incorporated by reference from information under the captions "Corporate Governance," "Meetings and Committees of our Board" and "Compliance with Section 16(a) of the Securities Exchange Act of 1934" to be included in our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year. Information regarding our executive officers is contained in Part I, Item 1. "Business" of this Annual Report on Form 10-K.

Item 11.    Executive Compensation

The information called for by Item 11 is incorporated by reference from information under the caption "Executive Compensation" to be included in our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information called for by Item 12 is incorporated by reference from information under the captions "Security Ownership" and "Principal Shareholders" in our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year and Part II, Item 5. "Market for the Registrant's Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities" of this Annual Report Form 10-K.

Item 13.    Certain Relationships and Related Transactions, and Director Independence

The information called for by Item 13 is incorporated by reference from information under the caption "Certain Relationships and Related Transactions" in our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year.

Item 14.    Principal Accounting Fees and Services

The information called for by Item 14 is incorporated by reference from the information under the caption "Fees to Independent Registered Public Accounting Firms for 2011 and 2010" to be included in our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year.

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PART IV

Item 15.    Exhibits, Financial Statement Schedules

(a) The following documents are filed as part of this annual report:

(1)    Financial Statements               

All financial statements of the Registrant are set forth under Part II, Item 8 of this Annual Report on Form 10-K.

(2)     Financial Statement Schedules

All financial statement schedules have been omitted because they are not applicable or not required, or the information required thereby is included in the Financial Statements or the notes thereto included in this Annual Report on Form 10-K.

    (3)     Exhibits

3.1	Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, File No. 1-09735).
3.2	Restated Bylaws dated December 11, 2009 (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed on December 11, 2009, File No. 1-09735).
4.1	Certificate of Designation, Preferences and Rights of Series B Junior Participating Preferred Stock (incorporated by reference to Exhibit A to the Registrant's Registration Statement on Form 8-A12B on December 7, 1999, File No. 001-09735).
4.2	Indenture, dated June 15, 2006, between Berry Petroleum Company and Wells Fargo Bank, National Association, as trustee, relating to subordinated debt securities (incorporated by reference to Exhibit 4.3 to the Registrant's Registration Statement on Form S-3 on June 15, 2006, File No. 1-9735).
4.3	First Supplemental Indenture, dated October 24, 2006, between Berry Petroleum Company and Wells Fargo Bank, National Association, as trustee, including the form of 8.25% senior subordinated note due 2016 (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on October 25, 2006, File No. 1-9735).
4.4	Indenture, dated June 15, 2006, between Berry Petroleum Company and Wells Fargo Bank, National Association, as trustee, relating to senior debt securities (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on May 29, 2009, File No. 1-09735).
4.5	First Supplemental Indenture, dated May 27, 2009, between Berry Petroleum Company and Wells Fargo Bank, National Association, as Trustee, including the form of 10.25% senior note due 2014 (incorporated by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K filed on May 29, 2009, File No. 1-09735).
4.6	Second Supplemental Indenture, dated November 1, 2010, between Berry Petroleum Company and Wells Fargo Bank, National Association, as trustee, including the form of 6.75% senior note due 2020 (incorporated by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K filed on November 1, 2010, File No. 1-09735).
4.7	Second Amended and Restated Credit Agreement, dated November 15, 2010, by and among Berry Petroleum Company, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 99.1 to the Registrant's Current Report on Form 8-K filed on November 17, 2010, File No. 1-9735).
4.8	First Amendment to the Second Amended and Restated Credit Agreement, dated April 13, 2011, by and among Berry Petroleum Company, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on April 13, 2011, File No. 1-9735).
4.9	Second Amendment to the Second Amended and Restated Credit Agreement, dated June 17, 2011, by and among Berry Petroleum Company, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto. (incorporated by reference to Exhibit 4.1 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011, File No. 1-9735).
4.10	Third Amendment to the Second Amended and Restated Credit Agreement, dated October 26, 2011, by and among Berry Petroleum Company, Wells Fargo Bank, N.A. and the other lenders party thereto (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on October 27, 2011, File No. 1-9735).
	The Registrant and its subsidiaries are party to other debt instruments not filed herewith under which the total amount of securities authorized does not exceed 10% of the total assets of Berry and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, Berry agrees to furnish a copy of such instruments to the SEC upon request.

93

10.1*	Carry and Earning Agreement, dated June 7, 2006, between Registrant and EnCana Oil & Gas (USA), Inc. (incorporated by reference to Exhibit 99.2 to the Registrant's Current Report on Form 8-K filed on June 19, 2006, File No. 1-9735).
10.2*	Crude Oil Supply Agreement between the Registrant and Holly Refining and Marketing Company - Woods Cross (incorporated by reference to Exhibit 10.22 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-0735).
10.3*	Crude Oil Purchase Contract dated March 20, 2009, between the Registrant and Tesoro Corporation (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-09735).
10.4*	Crude Oil Purchase Contract dated September 24, 2009 between the Registrant and ExxonMobil Oil Corporation (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-9735).
10.5*	Crude Oil Purchase Contract dated October 5, 2010 between the Registrant and ExxonMobil Oil Corporation (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-9735).
10.6†	Amended and Restated 1994 Stock Option Plan (incorporated by reference to Exhibit 4.1 to the Registrant's Registration Statement on Form S-8 filed on August 20, 2002, File No. 333-98379).
10.7†	First Amendment to the Registrant's Amended and Restated 1994 Stock Option Plan dated as of June 23, 2006 (incorporated by reference to Exhibit 99.3 to the Registrant's Current Report on Form 8-K June 26, 2006, File No. 1-9735).
10.8†	Berry Petroleum Company 2005 Equity Incentive Plan (incorporated by reference to Exhibit 4.2 to the Registrant's Registration Statement on Form S-8 filed on July 29, 2005, File No. 333-127018).
10.9†	Form of Stock Option Agreement under the 2005 Equity Incentive Plan (incorporated by reference to Exhibit 4.3 to the Registrant's Registration Statement on Form S-8 filed on July 29, 2005, File No. 333-127018).
10.10†	Form of the Stock Appreciation Rights Agreement under the 2005 Equity Incentive Plan (incorporated by reference to Exhibit 4.4 to the Registrant's Registration Statement on Form S-8 filed on July 29, 2005, File No. 333-127018).
10.11†	Form of Stock Award Agreement under the 2005 Equity Incentive Plan (incorporated by reference to Exhibit 99.4 to the Registrant's Current Report on Form 8-K June 26, 2006, File No. 1-9735).
10.12†	Form of Amended and Restated Restricted Stock Award Agreement for directors under the 2005 Equity Incentive Plan (incorporated by reference to Exhibit 99.1 to the Registrant's Current Report on Form 8-K filed on December 17, 2007, File No. 1-9735).
10.13†	Form of Amended and Restated Restricted Stock Award Agreement for officers under the 2005 Equity Incentive Plan (incorporated by reference to Exhibit 99.2 to the Registrant's Current Report on Form 8-K December 17, 2007, File No. 1-9735).
10.14†	Form of Award Grant under the Performance Share Award Program for select officers of the Company (incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on March 18, 2010, File No. 1-9735).
10.15†	Performance-based Restricted Stock Unit Award Agreement for Robert H. Heinemann under the 2005 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on March 18, 2010, File No. 1-9735).
10.16†	Performance-based Restricted Stock Unit Award Agreement for David D. Wolf under the 2005 Equity Incentive Plan (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on March 18, 2010, File No. 1-9735).
10.17†	Performance-based Restricted Stock Unit Award Agreement for Michael Duginski under the 2005 Equity Incentive Plan (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on March 18, 2010, File No. 1-9735).
10.18†	Berry Petroleum Company 2010 Equity Incentive Plan (incorporated by reference to Exhibit 4.3 to the Registrant's Registration Statement on Form S-8 filed on June 23, 2010, File No. 333-167698).
10.19†	Form of Restricted Stock Unit Award Agreement under the 2010 Equity Incentive Plan (incorporated by reference to Exhibit 4.4 to the Registrant's Registration Statement on Form S-8 filed on June 23, 2010, File No. 333-167698).
10.20†	Form of Restricted Stock Unit Award Agreement for officers under the 2010 Equity Incentive Plan (incorporated by reference to Exhibit 4.5 to the Registrant's Registration Statement on Form S-8 filed on June 23, 2010, File No. 333-167698).

94

10.21†	Form of Restricted Stock Unit Award Agreement for directors under the 2010 Equity Incentive Plan (incorporated by reference to Exhibit 4.6 to the Registrant's Registration Statement on Form S-8 filed on June 23, 2010, File No. 333-167698).
10.22†	Form of Stock Option Agreement under the 2010 Equity Incentive Plan (incorporated by reference to Exhibit 4.7 to the Registrant's Registration Statement on Form S-8 filed on June 23, 2010, File No. 333-167698).
10.23†	Form of Stock Appreciation Rights Agreement under the 2010 Equity Incentive Plan (incorporated by reference to Exhibit 4.8 to the Registrant's Registration Statement on Form S-8 filed on June 23, 2010, File No. 333-167698).
10.24†	Form of Amended and Restated Restricted Stock Unit Award Agreement for officers under the 2010 Equity Incentive Plan (incorporated by reference to Exhibit 99.2 to the Registrant's Current Report on Form 8-K filed on November 17, 2010, File No. 1-9735).
10.25†	Description of Short-Term Cash Incentive Plan of Registrant (incorporated by reference to Exhibit 10.1 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-9735).
10.26†	Non-Employee Director Deferred Stock and Compensation Plan (as amended and restated effective November 19, 2008) (incorporated by reference to exhibit 10.12 to Registrant's Annual Report on Form 10-K for the year ended December 31, 2009, File No. 1-9735).
10.27†	Form of Change in Control Severance Protection Agreement dated August 24, 2006, by and between Registrant and selected employees of the Company (incorporated by reference to Exhibit 99.1 to the Registrant's Current Report on Form 8-K filed on August 24, 2006, File No. 1-9735).
10.28†	Amended and Restated Employment Contract dated as of June 23, 2006 by and between the Registrant and Robert F. Heinemann (incorporated by reference to Exhibit 99.1 to the Registrant's Current Report on Form 8-K June 26, 2006, File No. 1-9735).
10.29†	Stock Award Agreement dated as of June 23, 2006 by and between the Registrant and Robert F. Heinemann (incorporated by reference to Exhibit 99.2 to the Registrant's Current Report on Form 8-K June 26, 2006, File No. 1-9735).
10.30†	Employment Agreement dated November 19, 2008 by and between Berry Petroleum Company and David D. Wolf (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K/A filed on November 21, 2008, File No. 1-9735).
10.31†	Employment Agreement dated November 19, 2008 by and between Berry Petroleum Company and Michael Duginski (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on November 21, 2008, File No. 1-9735).
10.32†	Form of Indemnity Agreement (incorporated by reference to Exhibit 99.1 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2004, File No. 1-9735).
12.1	Ratio of Earnings to Fixed Charges.
23.1	Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
23.2	Consent of DeGolyer and MacNaughton.
31.1	Certification of Chief Executive Officer pursuant to SEC Rule 13(a)-14(a).
31.2	Certification of Chief Financial Officer pursuant to SEC Rule 13(a)-14(a).
32.1	Certification of Chief Executive Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code.
32.2	Certification of Chief Financial Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code.
99.1	Report of DeGolyer and MacNaughton dated February 15, 2012 regarding the Registrant's reserves estimates.
99.2	Form of "B" Group Trust (incorporated by reference to Exhibit 28.3 to Amendment No. 1 to the Registrant's Registration Statement on Form S-4 filed on May 22, 1987, File No. 33-13240).
101	Interactive Data Files.

_______________________________________________

*     Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

†    Management contract or compensatory plan or arrangement.

95

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on February 28, 2012.

BERRY PETROLEUM COMPANY
/s/ ROBERT F. HEINEMANN	/s/ DAVID D. WOLF	/s/ JAMIE L. WHEAT
ROBERT F. HEINEMANN President, Chief Executive Officer and Director	DAVID D. WOLF Executive Vice President and Chief Financial Officer (Principal Financial Officer)	JAMIE L. WHEAT Controller (Principal Accounting Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the dates indicated.

Name	Office	Date
/s/ MARTIN H. YOUNG, JR.	Chairman of the Board, Director	February 28, 2012
Martin H. Young, Jr.
/s/ ROBERT F. HEINEMANN	President, Chief Executive Officer and Director	February 28, 2012
Robert F. Heinemann
/s/ RALPH B. BUSCH, III
Ralph B. Busch, III	Director	February 28, 2012
/s/ WILLIAM E. BUSH, JR.
William E. Bush, Jr.	Director	February 28, 2012
/s/ STEPHEN L. CROPPER
Stephen L. Cropper	Director	February 28, 2012
/s/ J. HERBERT GAUL, JR.
J. Herbert Gaul, Jr.	Director	February 28, 2012
/s/ STEPHEN J. HADDEN
Stephen J. Hadden	Director	February 28, 2012
/s/ THOMAS J. JAMIESON
Thomas J. Jamieson	Director	February 28, 2012
/s/ J. FRANK KELLER
J. Frank Keller	Director	February 28, 2012
/s/ MICHAEL S. REDDIN
Michael S. Reddin	Director	February 28, 2012

96

EX-12.1

Exhibit 12.1

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(in thousands, except ratios)

	12/31/2011				12/31/2010			12/31/2009			12/31/2008			12/31/2007
Pre-tax income from continuing operations	$	(370,291	)		$	136,492		$	67,888		$	190,193		$	195,616
Interest expense	72,807				66,541			50,738			26,209			17,287
Amortization of capitalized interest	1,813
Capitalized interest	29,117				28,321			30,107			23,209			18,104
Earnings	$	(295,671	)		$	203,033		$	118,626		$	216,402		$	212,903
Ratio of earnings to fixed charges	—			(1)	2.1		x	1.5		x	4.4		x	6.0		x

___________________________

(1) For the year ended December 31, 2011, earnings were deficient by $397.6 million, which was due primarily to a pre-tax, non-cash charge to earnings of $625.0 million related to the impairment of our E. Texas natural gas properties.

For purposes of this table, “earnings” consists of income before income taxes from continuing operations plus fixed charges (excluding capitalized interest).  “Fixed charges” consists of interest expense and capitalized interest (for both continuing and discontinued operations).

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-135055, 333-157507, 333-161243  and 333-163743) and Form S-8 (Nos. 333-98379, 333-127018 and 333-167698) of Berry Petroleum Company of our report dated February 28, 2012 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

February 28, 2012

EX-23.2

Exhibit 23.2

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 27, 2012

Berry Petroleum Company

1999 Broadway Street, Suite 3700

Denver, CO 80202

Gentlemen:

We hereby consent to (i) the inclusion of our third party letter report dated February 15, 2012, containing our opinion on the proved reserves attributable to certain properties owned by Berry Petroleum Company, as of December 31, 2011, (ii) the use of and reference to our third party letter report dated February 15, 2011, containing our opinion on the proved reserves attributable to certain properties owned by Berry Petroleum Company, as of December 31, 2010, and the use of and reference to our third party letter report dated February 19, 2010, containing our opinion on the proved reserves attributable to certain properties owned by Berry Petroleum Company, as of December 31, 2009, (the Reports) under the captions “Properties” and “Oil and Gas Reserves” in Item 1, “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Item 7, and “Supplemental Information About Oil & Gas Producing Activities (Unaudited)” in Item 8 of the Annual Report on Form 10-K for the fiscal year ended December 31, 2011, of Berry Petroleum Company (the Annual Report); and (iii) the use of and reference to the name DeGolyer and MacNaughton as the independent petroleum engineering firm that prepared the Reports under such items; provided, however, that since the cash-flow calculations in the Annual Report include estimated income taxes not included in the Reports, we are unable to verify the accuracy of the cash‑flow values in the Annual Report.

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

EX-31.1

Exhibit 31.1

Certification of Chief Executive Officer

Pursuant to Section 302 of Sarbanes Oxley Act of 2002

I, Robert F. Heinemann, certify that:

1. I have reviewed this report on Form 10-K of Berry Petroleum Company (the Company);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;

4. The Company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a - 15(e) and 15d - (e) and internal control over financial reporting (as defined in Exchange Act Rules 13a - 15(f) and 15d - 15(f)) for the Company and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, and its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designated under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter that has materially affected or is reasonably likely to materially affect the Company’s internal control over financial reporting.

5. The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company’s auditors and the audit committee of the Company’s board of directors:

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal controls over financial reporting.

	/s/ Robert F. Heinemann
	Robert F. Heinemann
February 28, 2012	President, Chief Executive Officer and Director

EX-31.2

Exhibit 31.2

Certification of Chief Financial Officer

Pursuant to Section 302 of Sarbanes Oxley Act of 2002

I, David D. Wolf, certify that:

1. I have reviewed this report on Form 10-K of Berry Petroleum Company (the Company);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;

4. The Company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a - 15(e) and 15d - (e) and internal control over financial reporting (as defined in Exchange Act Rules 13a - 15(f) and 15d - 15(f)) for the Company and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designated under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter that has materially affected or is reasonably likely to materially affect the Company’s internal control over financial reporting;

5. The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting to the Company’s auditors and the audit committee of the Company’s board of directors:

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal controls over financial reporting.

	/s/ David D. Wolf
	David D. Wolf
February 28, 2012	Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification of Chief Executive Officer

Pursuant to Section 906 of Sarbanes Oxley Act of 2002

In Connection with the Annual Report of Berry Petroleum Company (the “Company”) on Form 10-K for the period ending December 31, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert F. Heinemann, President, Chief Executive Officer and Director of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-Oxley Act of 2002, that:

1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Robert F. Heinemann
	Robert F. Heinemann
February 28, 2012	President, Chief Executive Officer and Director

EX-32.2

Exhibit 32.2

Certification of Chief Financial Officer

Pursuant to Section 906 of Sarbanes Oxley Act of 2002

In Connection with the Annual Report of Berry Petroleum Company (the “Company”) on Form 10-K for the period ending December 31, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David D. Wolf, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-Oxley Act of 2002, that:

1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ David D. Wolf
	David D. Wolf
February 28, 2012	Executive Vice President and Chief Financial Officer

EX-99.1

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 15, 2012

Berry Petroleum Company

1999 Broadway

Suite 3700

Denver, Colorado 80202

Gentlemen:

Pursuant to your request, we have prepared estimates of the extent and value of the net proved crude oil, condensate, natural gas liquids (NGL), and natural gas reserves, as of December 31, 2011, of certain properties owned by Berry Petroleum Company (Berry). This evaluation was completed on February 15, 2012. Berry has represented that these properties account for 100 percent on a net equivalent barrel basis of Berry's net proved reserves as of December 31, 2011. The net proved reserves estimates prepared by us have been prepared in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Berry.

Reserves included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2011. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Berry after deducting all interests owned by others. Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as that portion of the total gas to be delivered into a gas pipeline for sale after separation, processing, fuel use, and flare. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the legal pressure base of the state in which the interest is located. Condensate reserves estimated herein are those to be recovered by conventional lease separation. NGL reserves are those attributed to the leasehold interests according to processing agreements.

Values shown herein are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, and capital costs from the future gross revenue. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization.

Estimates of oil, condensate, NGL, and natural gas should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this evaluation were obtained from reviews with Berry personnel, Berry files, from records on file with the appropriate regulatory agencies, and from public sources. Additionally, this information includes data supplied by Petroleum Information/Dwights LLC; Copyright 2011 Petroleum Information/Dwights LLC. In the preparation of this report we have relied, without independent verification, upon such information furnished by Berry with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principals and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production‑decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.  

Definition of Reserves

Petroleum reserves estimated by us included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by us in this report are in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves - Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves - Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves - Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4-10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs:

Oil, Condensate, and NGL Prices

Berry has represented that the oil, condensate, and NGL prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Berry supplied differentials by certain geographic producing areas to a NYMEX Light Crude Oil reference price of $96.19 per barrel and the prices were held constant thereafter. The volume-weighted average oil and condensate price was $97.89 per barrel and the volume-weighted average NGL price was $54.62 per barrel.

Natural Gas Prices

Berry has represented that the natural gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Berry supplied differentials by certain geographic producing areas to the NYMEX Natural Gas reference price of $4.16 per million British thermal units. The prices were held constant thereafter. The volume-weighted average price was $4.02 per Mcf.

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by Berry, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. For certain leases in the Midway Sunset field in California, future gas supply costs to generate steam were determined based on contractual arrangements, which resulted in below spot market gas purchase pricing until October 2013.

These costs were not escalated for inflation.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant's ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2011, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

Our estimates of Berry's net proved reserves attributable to the reviewed properties are based on the definitions of proved reserves of the SEC and are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Net Proved Reserves as of December 31, 2011
	Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
Proved Developed
California	84,946	—	—	84,946
Colorado	239	—	70,085	11,920
Nevada	556	—	—	556
Texas	9,869	5,767	114,191	34,668
Utah	5,648	813	37,291	12,676
Wyoming	—	—	38	6
Various (LA, NV, OK)	11	—	—	11
Total Proved Developed	101,269	6,580	221,605	144,783
Proved Undeveloped
California	35,568	—	—	35,568
Colorado	896	—	253,298	43,112
Nevada	—	—	—	—
Texas	23,278	11,081	43,111	41,544
Utah	6,941	267	16,264	9,919
Wyoming	—	—	—	—
Various (LA, NV, OK)	—	—	—	—
Total Proved Undeveloped	66,683	11,348	312,673	130,143
Total Proved	167,952	17,928	534,278	274,926

Note: Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent

The estimated future revenue attributable to Berry's interests in the proved reserves, as of December 31, 2011, of the properties appraised is summarized as follows, expressed in thousands of dollars (M$):

	Developed Producing	Developed Nonproducing	Undeveloped	Total
Future Gross Revenue, M$	8,265,497	2,957,256	8,345,875	19,568,628
Production and Ad Valorem Taxes, M$	274,231	104,073	382,300	760,604
Operating Expenses, M$	2,375,610	635,370	1,454,460	4,465,440
Capital Costs, M$	177,740	75,205	1,722,484	1,975,429
Future Net Revenue*, M$	5,437,916	2,142,608	4,786,631	12,367,155
Present Worth at 10 Percent*, M$	2,968,517	781,757	1,954,773	5,705,047

* Future income tax expenses were not taken into account in the preparation of these estimates.

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries - Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4-10(a) (1)-(32) of Regulation S-X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S-K of the SEC; provided, however, future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Berry. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Berry. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

	Submitted,
	/s/ DeGolyer and MacNaughton
	DeGOLYER and MacNAUGHTON
	Texas Registered Engineering Firm F-716
	/s/ Paul J. Szatkowski, P.E.
	Paul J. Szatkowski, P.E.
[SEAL]	Senior Vice President
	DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Paul J. Szatkowski, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1. That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Berry dated February 15, 2012, and that I, as Senior Vice President, was responsible for the preparation of this report.

2. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists; and that I have in excess of 37 years of experience in oil and gas reservoir studies and reserves evaluations.

	/s/ Paul J. Szatkowski, P.E.
	Paul J. Szatkowski, P.E.
[SEAL]	Senior Vice President
	DeGolyer and MacNaughton

XML

Summary of Significant Accounting Policies (Comprehensive (Loss) Earnings) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Comprehensive earnings (loss):
Net (loss) earnings	$ (414,733)	$ 134,001	$ 105,166	$ (52,497)	$ (21,145)	$ (3,023)	$ 89,023	$ 17,669	$ (228,063)	$ 82,524	$ 54,030
Unrealized gain (loss) on derivatives, net of income taxes of $0, $0, and ($79,240), respectively									0	0	(129,287)
Reclassification of realized (gain) loss on derivatives included in net income, net of income taxes of $0, $0, ($27,447)									0	0	(44,782)
Amortization of Accumulated other comprehensive loss related to de-designated hedges, net of taxes of $23,467, $10,153, and $0, respectively									38,289	16,566
Total comprehensive (loss) earnings									(189,774)	99,090	(120,039)
Unrealized gains (losses) on derivatives, income tax expense (benefit)									0	0	(79,240)
Reclassifications of realized (gain) loss on derivatives included in Net (loss) earnings, income tax expense (benefit)									0	0	(27,447)
Amortization of Accumulated other comprehensive loss related to de-designated hedges, income tax benefit									$ 23,467	$ 10,153	$ 0

XML

Equity Incentive Compensation Plans (Stock Options) (Details) (USD $)	12 Months Ended						1 Months Ended
	Dec. 31, 2011 year		Dec. 31, 2010		Dec. 31, 2009		Mar. 31, 2011 Executive officers and other officers
Stock options activity
Outstanding at the beginning of the period (in shares)	2,017,225		2,276,020		2,421,650
Granted (in shares)	89,865		0		0		89,865
Exercised (in shares)	(579,635)		(227,100)		(62,050)
Cancelled/expired (in shares)	(6,765)		(31,695)		(83,580)
Outstanding at the end of the period (in shares)	1,520,690		2,017,225		2,276,020
Stock options, Weighted Average Exercise Price
Outstanding at the beginning of the period (in dollars per share)	$ 25.87		$ 25.36		$ 25.16
Granted (in dollars per share)	$ 48.50		$ 0.00		$ 0.00
Exercised (in dollars per share)	$ 17.47		$ 19.40		$ 13.52
Cancelled/expired (in dollars per share)	$ 45.92		$ 35.51		$ 28.48
Outstanding at the end of the period (in dollars per share)	$ 30.32		$ 25.87		$ 25.36
Stock options, Aggregate Intrinsic Value
Outstanding at the beginning of the period	$ 35,974,000	[1]	$ 15,296,000	[1]	$ 0	[1]
Exercised	17,746,000	[1]	3,570,000	[1]	560,000	[1]
Outstanding at the end of the period	17,798,000	[1]	35,974,000	[1]	15,296,000	[1]
Stock options, Number of Shares Exercisable
Options outstanding at the beginning of the period (in shares)	1,884,937		2,008,325		1,842,532
Options outstanding at the end of the period (in shares)	1,434,020		1,884,937		2,008,325
Vesting period (in years)	4 years
Anniversary date through which options are exercisable from grant date	Tenth
Fair value assumptions
Expected volatility (as a percent)	45.00%
Risk-free interest rate (as a percent)	2.54%
Dividend yield (as a percent)	0.62%
Expected term (in years)	6.0
Total unrecognized compensation cost	$ 1,300,000
Period of recognition of unrecognized compensation cost (in years)	3.25

[1] The intrinsic value of a stock option is the amount by which the market value of the underlying stock at the end of the related period exceeds the exercise price of the option.

XML

Income Taxes (Schedule of Components of Income Tax Expense (Benefit)) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Current:
Federal	$ 4,115	$ 363	$ 3,148
State	2,936	1,870	782
Current Income Tax Expense (Benefit)	7,051	2,233	3,930
Deferred:
Federal	(125,261)	47,709	20,885
State	(24,018)	4,026	(4,151)
Deferred Income Tax Expense (Benefit)	(149,279)	51,735	16,734
Total	$ (142,228)	$ 53,968	$ 20,664

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Supplemental Information about Oil & Gas Producing Activities (Unaudited) (Reserve Quantities) (Details)	12 Months Ended
	Dec. 31, 2011 mboe	Dec. 31, 2010 mboe	Dec. 31, 2009 mboe
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved developed and undeveloped reserves, Beginning of year	271,213	235,303	245,940
Revision of previous estimates	(28,446)	(3,522)	(2,975)
Improved recovery	0	1,700	0
Extensions and discoveries	30,600	20,019	18,100
Property sales	0	0	(21,100)
Production	(13,025)	(11,923)	(10,962)
Purchase of reserves in place	14,584	29,636	6,300
Proved developed and undeveloped reserves, End of year	274,926	271,213	235,303
Proved developed reserves, Beginning of year	133,678	125,456	134,879
Proved developed reserves, End of year	144,783	133,678	125,456
East Texas
Proved Developed and Undeveloped Reserves [Roll Forward]
Revision of previous estimates	(19,632)	(3,666)	(9,108)
Piceance
Proved Developed and Undeveloped Reserves [Roll Forward]
Revision of previous estimates	(5,779)	(3,890)
Uinta
Proved Developed and Undeveloped Reserves [Roll Forward]
Revision of previous estimates		(840)
Permian
Proved Developed and Undeveloped Reserves [Roll Forward]
Revision of previous estimates		971
California
Proved Developed and Undeveloped Reserves [Roll Forward]
Revision of previous estimates		3,903	398
Utah and Piceance
Proved Developed and Undeveloped Reserves [Roll Forward]
Revision of previous estimates			5,735
Utah
Proved Developed and Undeveloped Reserves [Roll Forward]
Revision of previous estimates	(2,576)
Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved developed and undeveloped reserves, Beginning of year	166,181	129,940	125,251
Revision of previous estimates	(4,054)	4,288	2,786
Improved recovery	0	1,700	0
Extensions and discoveries	19,601	12,774	8,989
Property sales	0	0	0
Production	(9,041)	(7,925)	(7,186)
Purchase of reserves in place	13,193	25,404	100
Proved developed and undeveloped reserves, End of year	185,880	166,181	129,940
Proved developed reserves, Beginning of year	88,917	82,870	74,616
Proved developed reserves, End of year	107,849	88,917	82,870
Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved developed and undeveloped reserves, Beginning of year	630,192	632,178	724,135
Revision of previous estimates	(146,349)	(46,860)	(34,564)
Improved recovery	0	0	0
Extensions and discoveries	65,992	43,469	54,664
Property sales	0	0	(126,600)
Production	(23,907)	(23,989)	(22,657)
Purchase of reserves in place	8,351	25,394	37,200
Proved developed and undeveloped reserves, End of year	534,279	630,192	632,178
Proved developed reserves (volume), Beginning of year	268,566	255,520	361,575
Proved developed reserves (volume), End of year	221,606	268,566	255,520

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Equity Incentive Compensation Plans (Range of Exercise Prices) (Details) (USD $) In Thousands, except Share data, unless otherwise specified									12 Months Ended
	Dec. 31, 2011 year		Dec. 31, 2010		Dec. 31, 2009		Dec. 31, 2008		Dec. 31, 2011 $7.00-$15.00 year	Dec. 31, 2011 $15.01-$25.00 year	Dec. 31, 2011 $25.01-$35.00 year	Dec. 31, 2011 $35.01-$48.50 year
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Range of Exercise Prices, Lower Range Limit (in dollars)									$ 7.00	$ 15.01	$ 25.01	$ 35.01
Range of Exercise Prices, Upper Range Limit (in dollars)									$ 15.00	$ 25.00	$ 35.00	$ 48.50
Stock Options Outstanding, Number of Options	1,520,690								199,000	287,000	655,001	379,689
Stock Options Outstanding, Weighted Average Remaining Contractual Life (Years)	4.47								2.13	2.90	4.51	6.79
Stock Options Outstanding, Weighted Average Exercise Price (in dollars per share)	$ 30.32		$ 25.87		$ 25.36		$ 25.16		$ 12.36	$ 21.60	$ 31.65	$ 44.01
Stock Options Outstanding, Aggregate Intrinsic Value (in dollars)	$ 17,798	[1]	$ 35,974	[1]	$ 15,296	[1]	$ 0	[1]	$ 5,902	$ 5,861	$ 6,792	$ 0
Stock Options Exercisable, Number of Options	1,434,020								199,000	287,000	655,001	293,019
Stock Options Exercisable, Weighted Average Remaining Contractual Life (Years)	4.18								2.13	2.90	4.51	6.09
Stock Options Exercisable, Weighted Average Exercise Price (in dollars per share)	$ 29.22								$ 12.36	$ 21.60	$ 31.65	$ 42.68
Stock Options Exercisable, Aggregate Intrinsic Value (in dollars)	$ 18,360								$ 5,902	$ 5,861	$ 6,792	$ 0

[1] The intrinsic value of a stock option is the amount by which the market value of the underlying stock at the end of the related period exceeds the exercise price of the option.

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Debt (8.25% Senior Suborinated Notes Due 2016) (Details) (8.25% Senior subordinated notes due 2016, USD $)			12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2011 Unsecured Debt	Dec. 31, 2006 Unsecured Debt	Dec. 31, 2011 Unsecured Debt November 1, 2011 through October 31, 2012	Dec. 31, 2011 Unsecured Debt November 1, 2012 through October 31, 2013	Dec. 31, 2011 Unsecured Debt November 1, 2013 through October 31, 2014	Dec. 31, 2011 Unsecured Debt November 1, 2014 and thereafter
Debt Instrument
Principal amount of debt issued				$ 200,000,000
Interest rate on debt instrument (as a percent)	8.25%	8.25%		8.25%
Net proceeds from issuance senior subordinated debt				$ 196,000,000
Senior Notes, Expressed As Percentage Of Principal Amount Redeemed, Plus Accured and Unpaid Interest
Redemption price, as a percentage of the principal or face amount of the given debt instrument, that the Company must pay upon redemption					104.125%	102.75%	101.375%	100.00%
Debt Instrument redemption price percentage of principal amount plus make whole premium, plus accrued and unpaid interest (as a percent)			100.00%

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Supplemental Information about Oil & Gas Producing Activities (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities

	2011						2010						2009
	Oil MBOE		Natural Gas MMcf		MBOE		Oil MBOE		Natural Gas MMcf		MBOE		Oil MBOE		Natural Gas MMcf		MBOE
Proved developed  and undeveloped reserves:
Beginning of year	166,181		630,192		271,213		129,940		632,178		235,303		125,251		724,135		245,940
Revision of previous estimates	(4,054	)	(146,349	)	(28,446	)	4,288		(46,860	)	(3,522	)	2,786		(34,564	)	(2,975	)
Improved recovery	—		—		—		1,700		—		1,700		—		—		—
Extensions and  discoveries	19,601		65,992		30,600		12,774		43,469		20,019		8,989		54,664		18,100
Property sales	—		—		—		—		—		—		—		(126,600	)	(21,100	)
Production	(9,041	)	(23,907	)	(13,025	)	(7,925	)	(23,989	)	(11,923	)	(7,186	)	(22,657	)	(10,962	)
Purchase of reserves in place	13,193		8,351		14,584		25,404		25,394		29,636		100		37,200		6,300
End of year	185,880		534,279		274,926		166,181		630,192		271,213		129,940		632,178		235,303
Proved developed  reserves:
Beginning of year	88,917		268,566		133,678		82,870		255,520		125,456		74,616		361,575		134,879
End of year	107,849		221,606		144,783		88,917		268,566		133,678		82,870		255,520		125,456

Schedule of Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Future cash inflows	$	19,568,628		$	14,354,627		$	9,028,991
Future production costs	(5,226,044		)	(4,446,183		)	(3,826,832		)
Future development costs	(1,975,429		)	(1,789,001		)	(1,159,465		)
Future income tax expense	(3,770,512		)	(2,272,184		)	(969,771		)
Future net cash flows	8,596,643			5,847,259			3,072,923
10% annual discount for estimated timing of cash flows	(4,561,364		)	(3,048,103		)	(1,627,176		)
Standardized measure of discounted future net cash flows	$	4,035,279		$	2,799,156		$	1,445,747
Average price during the 12-month period: (1)
Oil ($/BOE)	$	93.72		$	69.04		$	52.06
Natural gas ($/Mcf)	4.02			4.57			3.58
BOE ($/BOE)	$	71.18		$	52.93		$	38.37

______________________________     

(1) Differences between the average benchmark prices and the average prices used in the calculation of the standardized measure are attributable to adjustments made for transportation, quality and basis differentials.

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows

	Year ended December 31,
	2011			2010			2009
	(in thousands)
Standardized measure—beginning of year	$	2,799,156		$	1,445,747		$	1,135,581
Sales of oil and natural gas produced, net of production costs	(599,679		)	(406,390		)	(353,052		)
Revisions to estimates of proved reserves:
Net changes in sales prices and production costs	1,473,454			1,724,212			637,882
Revisions of previous quantity estimates	(281,765		)	(49,784		)	(33,943		)
Improved recovery	—			24,033			—
Extensions and discoveries	601,313			283,011			206,542
Change in estimated future development costs	(274,122		)	(152,096		)	(52,824		)
Purchases of reserves in place	164,383			307,205			29,348
Sales of reserves in place	—			—			(138,265		)
Development costs incurred during the period	433,660			144,086			110,200
Accretion of discount	383,418			184,917			131,745
Income taxes	(634,747		)	(593,272		)	(190,727		)
Other	(29,792		)	(112,513		)	(36,740		)
Net increase	1,236,123			1,353,409			310,166
Standardized measure—end of year	$	4,035,279		$	2,799,156		$	1,445,747

Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities

The following table presents costs incurred in oil and natural gas property acquisition, exploration, and development activities:

	Year ended December 31,
	2011		2010		2009
	(in thousands)
Property acquisitions
Proved properties	$	149,158	$	334,409	$	13,497
Unproved properties	6,632		—		—
Development	544,114		320,927		138,168
Exploration	627		2,310		209
Total(1)	$	700,531	$	657,646	$	151,874

__________________________________________

(1)The total above does not reflect $29.1 million, $28.3 million, and $30.1 million of capitalized interest incurred in 2011, 2010, and 2009, respectively.

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Selected Quarterly Financial Data (Unaudited) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2011		Sep. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Dec. 31, 2010		Sep. 30, 2010		Jun. 30, 2010		Mar. 31, 2010		Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Quarterly Financial Information Disclosure [Abstract]
Operating Revenues	$ 240,600		$ 238,763		$ 242,709		$ 197,486		$ 180,001		$ 166,040		$ 164,457		$ 166,012		$ 919,558		$ 676,510
Net (Loss) Earnings	$ (414,733)		$ 134,001		$ 105,166		$ (52,497)		$ (21,145)		$ (3,023)		$ 89,023		$ 17,669		$ (228,063)		$ 82,524		$ 54,030
Basic Net (Loss) Earnings Per Share (in dollars per share)	$ (7.62)	[1]	$ 2.45	[1]	$ 1.93	[1]	$ (0.98)	[1]	$ (0.40)	[1]	$ (0.06)	[1]	$ 1.65	[1]	$ 0.34	[1]	$ (4.21)	[1]	$ 1.54	[1]	$ 1.18
Dilutive Net (Loss) Earnings Per Share (in dollars per share)	$ (7.62)	[1]	$ 2.42	[1]	$ 1.90	[1]	$ (0.98)	[1]	$ (0.40)	[1]	$ (0.06)	[1]	$ 1.64	[1]	$ 0.34	[1]	$ (4.21)	[1]	$ 1.52	[1]	$ 1.17

[1] The sum of the individual quarterly net (loss) earnings per common share amounts may not agree with year-to-date net (loss) earnings per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period. Potentially dilutive securities were included in the computation of diluted net (loss) earnings per common share for each quarter in which the Company reported net

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Equity Incentive Compensation Plans (Restricted Stock Units and Performance Share Program Parenthetical) (Details) (USD $)	1 Months Ended		12 Months Ended
	Mar. 31, 2011 ratio performancefactor simulation	Mar. 31, 2010 simulation	Dec. 31, 2011 performancefactor year	Dec. 31, 2010	Dec. 31, 2009
Equity Incentive Compensation Plans
Total unrecognized compensation cost			$ 1,300,000
Period of recognition of unrecognized compensation cost (in years)			3.25
Vesting period (in years)			4 years
Fair value assumptions used in market-based portion of performance shares valuation model (Monte Carlo model)
Expected volatility (as a percent)			45.00%
Risk-free interest rate (as a percent)			2.54%
Restricted Stock Units
Equity Incentive Compensation Plans
Total unrecognized compensation cost			7,900,000
Period of recognition of unrecognized compensation cost (in years)			3.25
Granted (in shares)			159,333	34,529	294,504
Restricted Stock Units | Executive officers and other officers
Equity Incentive Compensation Plans
Fully Vested Shares Outstanding Subject to Deferral Election by Executive Officers or Other Officers (in shares)			483,908	289,335	124,799
Restricted Stock Units | Non-employee directors
Equity Incentive Compensation Plans
Percentage of stock units vested at date of grant (as a percent)			100.00%
Fully Vested Shares Outstanding Subject to Non-Employee Director Deferral Election (in shares)			30,544	10,522	10,522
Performance-Based RSUs
Equity Incentive Compensation Plans
Total unrecognized compensation cost			1,400,000
Period of recognition of unrecognized compensation cost (in years)			2
Granted (in shares)			65,620	103,794	0
Number of years of service to be completed to participate in the program (in years)	3 years
Minimum interest coverage ratio, numerator	2.5
Minimum interest coverage ratio, denominator	1.0
Number of equally weighted performance factors	2		2
Vesting period (in years)	3 years		3 years
Grant date fair value determined by Monte Carlo valuation model	$ 1,100,000	$ 1,000,000
Fair value assumptions used in market-based portion of performance shares valuation model (Monte Carlo model)
Number of simulations	100,000	100,000
Expected volatility (as a percent)	44.00%	79.00%
Risk-free interest rate (as a percent)	1.15%	1.36%
Performance-Based RSUs | Executive officers and other officers
Equity Incentive Compensation Plans
Granted (in shares)	65,620

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Supplemental Information about Oil & Gas Producing Activities (Unaudited) (Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
Standardized measure used for discounted future net cash flows to determine average price (in months)	12 months
Future cash inflows	$ 19,568,628		$ 14,354,627		$ 9,028,991
Future production costs	(5,226,044)		(4,446,183)		(3,826,832)
Future development costs	(1,975,429)		(1,789,001)		(1,159,465)
Future income tax expense	(3,770,512)		(2,272,184)		(969,771)
Future net cash flows	8,596,643		5,847,259		3,072,923
10% annual discount for estimated timing of cash flows	(4,561,364)		(3,048,103)		(1,627,176)
Standardized measure of discounted future net cash flows	4,035,279		2,799,156		1,445,747
BOE (average sales price in dollars)	71.18	[1]	52.93	[1]	38.37	[1]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure—beginning of year	2,799,156		1,445,747		1,135,581
Sales of oil and natural gas produced, net of production costs	(599,679)		(406,390)		(353,052)
Net changes in sales prices and production costs	1,473,454		1,724,212		637,882
Revisions of previous quantity estimates	(281,765)		(49,784)		(33,943)
Improved recovery	0		24,033		0
Extensions and discoveries	601,313		283,011		206,542
Change in estimated future development costs	(274,122)		(152,096)		(52,824)
Purchases of reserves in place	164,383		307,205		29,348
Sales of reserves in place	0		0		(138,265)
Development costs incurred during the period	433,660		144,086		110,200
Accretion of discount	383,418		184,917		131,745
Income taxes	(634,747)		(593,272)		(190,727)
Other	(29,792)		(112,513)		(36,740)
Net increase (decrease)	1,236,123		1,353,409		310,166
Standardized measure—end of year	$ 4,035,279		$ 2,799,156		$ 1,445,747
Oil ($/Bbl)
Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
Average sales prices (in dollars per production type)	93.72	[1]	69.04	[1]	52.06	[1]
Natural Gas ($/Mcf)
Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
Average sales prices (in dollars per production type)	4.02	[1]	4.57	[1]	3.58	[1]

[1] Differences between the average benchmark prices and the average prices used in the calculation of the standardized measure are attributable to adjustments made for transportation, quality and basis differentials.

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Debt (Tables)

12 Months Ended

Dec. 31, 2011

Senior Notes 6.75 Percent Due 2020

Debt Instrument

Senior notes, expressed as percentage of principal amount redeemed, plus accured and unpaid interest, by maturity

2015	103.375	%
2016	102.250	%
2017	101.125	%
2018 and thereafter	100.000	%

Senior Subordinated Notes 8.25 Percent Due 2016

Debt Instrument

Senior notes, expressed as percentage of principal amount redeemed, plus accured and unpaid interest, by maturity

2011	104.125	%
2012	102.750	%
2013	101.375	%
2014 and thereafter	100.000	%

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Income Taxes (Schedule of Effective Income Tax Rate Reconciliation) (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Effective Income Tax Rate, Continuing Operations, Tax Rate Reconciliation
Income tax computed at statutory federal rate	35.00%	35.00%	35.00%
State income taxes, net of federal benefit	3.00%	4.00%	4.00%
Deferred state rate impact	0.00%	(1.00%)	(5.00%)
Net impact to uncertain income tax positions	1.00%	0.00%	(2.00%)
Other	(1.00%)	2.00%	(2.00%)
Effective income tax rate	38.00%	40.00%	30.00%

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Assets Held For Sale (Details) (USD $)	12 Months Ended				0 Months Ended
	Dec. 31, 2011		Dec. 31, 2010	Dec. 31, 2009	Dec. 21, 2011 Nevada Assets	Dec. 22, 2011 Nevada Assets	Dec. 31, 2011 Nevada Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Assets held-for-sale related to proved developed properties	$ 14,622,000		$ 0
Subsequent event, amount					16,500,000
Deposits on asset sales	(3,300,000)		0	0		(3,300,000)
Asset retirement obligations	$ 64,019,000	[1]	$ 53,443,000	$ 43,487,000			$ 700,000

[1] The asset retirement obligation related to the Nevada Assets, which were held for sale as of December 31, 2011, was $0.7 million at December 31, 2011 and is included in the asset retirement obligations liability on the December 31, 2011 Balance Sheets. See Note 3 to the Financial Statements.

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Summary of Significant Accounting Policies (Accrued Liabilities) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Accrued liabilities
Property taxes	$ 10,430	$ 11,245
Accrued interest	9,205	10,074
Accrued payroll	9,953	10,225
Other accrued liabilities	5,478	4,690
Total accrued liabilities	$ 35,066	$ 36,234

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Shareholder's Equity (Details) (USD $)	5 Months Ended	7 Months Ended	12 Months Ended				1 Months Ended	12 Months Ended			12 Months Ended
	Dec. 31, 2011	Jul. 31, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Aug. 23, 2011	Jan. 31, 2010 Class A	Dec. 31, 2011 Class A	Dec. 31, 2011 Class B	Dec. 31, 2010 Class B	Dec. 31, 2011 Dividend payments limited by covenants by Credit Agreement
Shareholder's Equity
Common Stock, voting rights (votes per share)								1
Common Stock, voting rights (percent of vote per share)									95.00%
Per share liquidation preference (or restrictions) of common stock that has a preference in involuntary liquidation in excess of the par or stated value of the shares (in dollars per share)									$ 0.50	$ 0.50
Convertible at the option of the holder (shares per share converted)									1
Issuance of Class A common stock (in shares)							8,000,000
Common stock, shares issued price per share (in dollars per share)							$ 29.25
Proceeds from issuance of common stock			$ 0	$ 224,313,000	$ 0		$ 224,300,000
Dividends per share (in dollars per share)			$ 0.31	$ 0.30	$ 0.30
Quarterly dividend, amount of increase in quarterly dividend (in dollars per share)						$ 0.05
Quarterly dividend, previous before Board of Directors approved increase (in dollars per share)		$ 0.075
Quarterly dividend, increase (in dollars per share)	$ 0.08
Dividends payment covenant credit agreement based on net earnings											35,000,000
Dividends payment covenant credit agreement based on net earnings, (as a percent)											75.00%
Dividends payment covenant credit agreement based on net earnings, (Number of quarters)											4
Dividends payment covenant credit agreement based on indentures governing senior and subordinated indentures per share annually (in dollars per share)											$ 0.36
Dividends payments credit agreement bond indentures annually without consideration of coverage ratio or exhausted restricted payments baskets											20,000,000
Dividends payments credit agreement on debt in event it is in a non-payment default											$ 10,000,000

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Commitments and Contingencies (Details 2) (USD $)	12 Months Ended		1 Months Ended			3 Months Ended
	Dec. 31, 2011 acre	Jan. 31, 2011 Carry and Earning Agreement	Apr. 30, 2011 Bureau of Land Management	Jul. 31, 2011 Order of Violation from Colorado Oil and Gas Conservative Commission	Dec. 31, 2011 Royalty payment disputes	Jun. 30, 2011 Cash Settlement Order of Violation from Colorado Oil and Gas Conservative Commission	Jun. 30, 2011 Mutually Acceptable Project Order of Violation from Colorado Oil and Gas Conservative Commission
Commitments
Amount of penalty waived for each well not spud		$ 200,000
Number of acres within each tract party to the earning and carrying agreement	160
Cumulative contingent construction expenditure required by December 31, 2012		9,000,000
Percentage of difference in connection with construction shared with third-party (as a percent)	50.00%
Construction expenditure otherwise payable by third party		4,500,000
Penalty payable as a percentage of difference between specified amount and actual expended (as a percent)		50.00%
Specified amount for penalty calculation		12,000,000
Litigation settlement expense			2,100,000	100,000
Funding to mutually acceptable public project to be made as per Administrative Order						100,000	73,000
Disputed royalty amounts the company may be required to pay					$ 7,100,000

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Derivative Instruments (Details 3) (USD $)	12 Months Ended			3 Months Ended	12 Months Ended
	Dec. 31, 2011 counterparty	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2010 Interest rate contract	Dec. 31, 2011 Designated as Hedging Instrument Accumulated other comprehensive loss Commodity contract	Dec. 31, 2010 Designated as Hedging Instrument Accumulated other comprehensive loss Commodity contract	Dec. 31, 2009 Designated as Hedging Instrument Accumulated other comprehensive loss Commodity contract	Dec. 31, 2011 Designated as Hedging Instrument Accumulated other comprehensive loss Interest rate contract	Dec. 31, 2010 Designated as Hedging Instrument Accumulated other comprehensive loss Interest rate contract	Dec. 31, 2009 Designated as Hedging Instrument Accumulated other comprehensive loss Interest rate contract	Dec. 31, 2011 Designated as Hedging Instrument Sales of oil and natural gas Commodity contract	Dec. 31, 2010 Designated as Hedging Instrument Sales of oil and natural gas Commodity contract	Dec. 31, 2009 Designated as Hedging Instrument Sales of oil and natural gas Commodity contract	Dec. 31, 2011 Designated as Hedging Instrument Earnings from discontinued operations Commodity contract	Dec. 31, 2010 Designated as Hedging Instrument Earnings from discontinued operations Commodity contract	Dec. 31, 2009 Designated as Hedging Instrument Earnings from discontinued operations Commodity contract	Dec. 31, 2011 Designated as Hedging Instrument Interest Interest rate contract	Dec. 31, 2010 Designated as Hedging Instrument Interest Interest rate contract	Dec. 31, 2009 Designated as Hedging Instrument Interest Interest rate contract	Dec. 31, 2011 Designated as Hedging Instrument Realized and unrealized (gain) loss on derivatives, net Commodity contract	Dec. 31, 2010 Designated as Hedging Instrument Realized and unrealized (gain) loss on derivatives, net Commodity contract	Dec. 31, 2009 Designated as Hedging Instrument Realized and unrealized (gain) loss on derivatives, net Commodity contract
Location and amount of derivative instrument (gains) losses before income taxes recognized in the condensed statements of income
Derivative Instruments, (Gain) Loss Reclassified from AOCL into Income, Effective Portion, Net											$ 0	$ 0	$ (58,800,000)	$ 0	$ 0	$ (20,500,000)	$ 0	$ 0	$ 7,000,000
Derivative Instruments, (Gain) Loss Reclassified from AOCL into Income, Effective Portion, Amortization of Frozen Amounts											60,900,000	18,400,000	0				800,000	8,300,000	0
Derivative Instruments, Loss Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing																				0	0	600,000
(Gain) loss recognized in earnings	(13,908,000)	31,847,000	7,756,000	1,900,000	0	0	206,400,000	0	0	2,700,000
Credit risk
Maximum loss if all counterparties to derivative contracts failed to perform	7,500,000
Number of counterparties to the Company's commodity derivative contracts (in counterparties)	7
Number of counterparties with net liability position (in counterparties)	4
Derivative instruments, net liability position	$ 30,200,000
Derivative instruments, number of largest counterparties (in counterparties)	2
Derivative value held by largest counterparties (as a percent)	84.00%

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Income Taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Tax Contingency
Deferred income taxes	$ 13,779,000	$ 32,342,000
Deferred income taxes, noncurrent	185,450,000	329,207,000
Unrecognized Tax Benefits Maximum Estimated Reductions Resulting from Expiration of Applicable Statute of Limitations in Next 12 Months	2,700,000
Uncertain income tax position accruals net of interest expense	500,000	100,000	800,000
Accrued interest recognized due to uncertain tax positions	800,000	800,000
Federal
Income Tax Contingency
Tax credit carryforwards, alternative minimum tax	800,000
EOR tax credit | Federal
Income Tax Contingency
Tax credit carryforwards	11,100,000
California | State
Income Tax Contingency
Tax credit carryforwards, alternative minimum tax	700,000
California | EOR tax credit | State
Income Tax Contingency
Tax credit carryforwards	13,500,000
Colorado | Enterprise zone income tax credits | State
Income Tax Contingency
Tax credit carryforwards	$ 2,500,000

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2011

Business Combinations [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

On May 25, 2011, the Company acquired interests in producing properties on approximately 6,000 net acres in the Wolfberry trend in the Permian for an aggregate purchase price of $128.4 million (the Wolfberry Acquisition). The Wolfberry Acquisition had an effective date of March 1, 2011, with operations from March 1, 2011 through May 24, 2011 resulting in purchase price adjustments. The acquisition was financed using the Company's senior secured revolving credit facility. The Company operates 98% of and has an average 93% working interest (70% net revenue interest) in the properties acquired in the Wolfberry Acquisition.

The Company has not presented pro forma information for the properties acquired in the Wolfberry Acquisition, as the impact of the acquisition was insignificant to the Company's Statements of Operations for the year ended December 31, 2011. Revenues of $7.8 million from properties acquired in the Wolfberry Acquisition have been included in the accompanying Statements of Operations for the year ended December 31, 2011, and earnings from the acquired properties were insignificant. 

The following table summarizes the consideration paid to the sellers and the amounts of the assets acquired and liabilities assumed in the Wolfberry Acquisition:

	(in thousands)
Consideration paid to sellers:
Cash consideration	$	128,398
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed and undeveloped properties	128,697
Asset retirement obligation	(119		)
Other liabilities assumed	(180		)
Total identifiable net assets	$	128,398

In March, April and November 2010, the Company completed three separate acquisitions of producing properties located in the Wolfberry trend in the Permian for an aggregate purchase price of approximately $327.0 million (the Permian Acquisitions). The Permian Acquisitions were financed with net proceeds from the issuance in January 2010 of 8 million shares of the Company's Class A Common Stock, cash generated from operations and net proceeds from the issuance in November 2010 of $300 million aggregate principal amount of the Company's 6.75% senior notes due 2020 (2020 Notes).

In the first quarter of 2011, the Company recorded a $1.0 million gain (net of deferred income taxes of $0.7 million) in conjunction with usual and customary post-closing adjustments to the purchase price of the November 2010 Permian acquisition. The gain was recorded in the Statements of Operations under the caption gain on purchase.

Acquisition costs of $2.6 million were recorded for the Permian Acquisitions in the Statements of Operations under the caption transaction costs on acquisitions for the year ended December 31, 2010. Revenues of $28.7 million were included in the accompanying Statements of Operations for the year ended December 31, 2010, and earnings from the acquired properties in 2010 were insignificant.  

The following table summarizes the consideration paid to the sellers and the amounts of the assets acquired and liabilities assumed in the Permian Acquisitions:

	(in thousands)
Consideration paid to sellers:
Cash consideration	$	327,032
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed and undeveloped properties	332,214
Other assets acquired	342
Asset retirement obligation	(3,498		)
Deferred income tax liability	(647		)
Other liabilities assumed	(333		)
Total identifiable net assets	$	328,078

The Wolfberry Acquisition and the Permian Acquisitions qualify as business combinations and, as such, the Company estimated the fair value of each property as of each acquisition date (the date on which the Company obtained control of the properties). The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model based on an income approach and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. Given the unobservable nature of the inputs, nonrecurring measurements of business combinations are deemed to use Level 3 inputs.

In March 2009, the Company entered into an agreement to sell its assets in the Denver-Julesburg basin in Colorado. The transaction closed in April 2009. The Company recorded a pre-tax impairment loss of $9.6 million related to the sale, which is included in net earnings from discontinued operations in its Statements of Operations for the year ended December 31, 2009.

Earnings from discontinued operations, net of income tax, on the accompanying Statements of Operations for the year ended December 31, 2009 is comprised of the following (in thousands):

	Year Ended December 31, 2009
Sales of oil and natural gas(1)	$	11,555
Loss on sale of asset	(908		)
Other revenue	623
Total revenues	11,270
Realized and unrealized (gain) on derivatives, net	(13,786		)
Other expenses(2)	15,799
Total expenses	2,013
Earnings from discontinued operations, before income taxes	9,257
Provision for income taxes	2,451
Net earnings from discontinued operations	$	6,806

________________________________________

(1) A $6.2 million realized gain included in sales of oil and natural gas was reclassified to discontinued operations for the year ended December 31, 2009.

(2) Includes $9.6 million of impairment charges related to the sale of the Company's assets in the DJ and $0.8 million of interest allocated to discontinued operations based on the ratio of net assets to the sum of total net assets.

At the time of the DJ asset sale, the Company had designated derivative instruments as cash flow hedges from the forecasted sale of natural gas produced by the DJ assets. As such, all recurring impacts on the Company's Statements of Operations were classified as discontinued operations. Additionally, the Company determined that as a result of the sale of the DJ assets, the forecasted transactions were no longer probable of occurring. Accordingly, the Company discontinued hedge accounting for such derivative instruments and reclassified a gain of $14.3 million from AOCL to net earnings from discontinued operations in its Statements of Operations.

During the first quarter of 2009, the Company entered into natural gas derivative instruments on behalf of the purchaser of its DJ assets. The Company did not elect hedge accounting for these derivative instruments and recorded an unrealized net loss of $0.5 million which is included in net earnings from discontinue operations in its Company's Statements of Operations.

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Derivative Instruments (Details 4) (Details) (USD $)	12 Months Ended			3 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2010 Interest rate contract	Dec. 31, 2011 Not Designated as Hedging Instrument Commodity contract Realized and unrealized (gain) loss on derivatives, net	Dec. 31, 2010 Not Designated as Hedging Instrument Commodity contract Realized and unrealized (gain) loss on derivatives, net	Dec. 31, 2009 Not Designated as Hedging Instrument Commodity contract Realized and unrealized (gain) loss on derivatives, net	Dec. 31, 2011 Not Designated as Hedging Instrument Commodity contract Earnings from discontinued operations	Dec. 31, 2010 Not Designated as Hedging Instrument Commodity contract Earnings from discontinued operations	Dec. 31, 2009 Not Designated as Hedging Instrument Commodity contract Earnings from discontinued operations	Dec. 31, 2011 Not Designated as Hedging Instrument Interest rate contract Realized and unrealized (gain) loss on derivatives, net	Dec. 31, 2010 Not Designated as Hedging Instrument Interest rate contract Realized and unrealized (gain) loss on derivatives, net	Dec. 31, 2009 Not Designated as Hedging Instrument Interest rate contract Realized and unrealized (gain) loss on derivatives, net
Derivative Instruments, (gain) loss
(Gain) loss recognized in earnings	$ (13,908,000)	$ 31,847,000	$ 7,756,000	$ 1,900,000	$ (13,900,000)	$ 23,200,000	$ 7,200,000	$ 0	$ 0	$ 500,000
Derivative Instruments, (Gain) Loss Reclassified from AOCL into Income, Effective Portion, Amortization of Frozen Amounts											$ 0	$ 8,600,000	$ 0

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Debt (Details) (USD $)	12 Months Ended		12 Months Ended		0 Months Ended	3 Months Ended	12 Months Ended		12 Months Ended
	Dec. 31, 2011 Redetermination	Dec. 31, 2010	Dec. 31, 2011 Line of Credit-short term day	Dec. 31, 2010 Line of Credit-short term day	Dec. 31, 2011 Senior secured revolving credit agreement (Credit Agreement - long term) ratio Lenders	Dec. 31, 2011 Senior secured revolving credit agreement (Credit Agreement - long term) Lenders	Dec. 31, 2011 Senior secured revolving credit agreement (Credit Agreement - long term) Lenders	Dec. 31, 2010 Senior secured revolving credit agreement (Credit Agreement - long term)	Dec. 31, 2011 Senior secured revolving credit agreement (Credit Agreement - long term) LIBOR	Dec. 31, 2011 Senior secured revolving credit agreement (Credit Agreement - long term) Prime
Debt obligations
Line of credit, current borrowing capacity			$ 40,000,000	$ 40,000,000
Line of credit, maximum number of days which borrowings may be outstanding (in days)			30	30
Short-term Bank Loans and Notes Payable	0	5,300,000	0	5,300,000
Line of credit, margin rate over LIBOR (as a percent)			1.40%
Weighted average interest rate on outstanding borrowings (as a percent)				1.70%
Credit agreement maximum borrowing base after amendment					1,400,000,000	1,400,000,000	1,400,000,000
Lender commitments					1,200,000,000	1,200,000,000	1,200,000,000
Debt instrument basis spread on variable rate low end of range (as a percent)									1.50%	0.50%
Debt Instrument basis spread on variable rate high end of range (as a percent)									2.50%	1.50%
Annual commitment fee on the unused portion of the credit agreement low end of range (as a percent)							0.35%
Annual commitment fee on the unused portion of the credit agreement high end of range (as a percent)							0.50%
Fee paid for additional lender commitments							2,200,000
Write-off of debt issuance costs						500,000
Number of lenders that did not renew commitment to credit agreement (in lenders)					1	1	1
Outstanding borrowing under credit facility	531,500,000	170,000,000						170,000,000
Line of credit facility, borrowing base number of additional redeterminations	1
Letters of credit that have been issued under the facility	23,200,000
Remaining borrowing capacity available under the agreement	$ 645,300,000
Debt instrument covenant consolidated interest coverage ratio numerator (as a ratio)					2.75
Debt instrument covenant consolidated interest coverage ratio denominator (as a ratio)					1.00
Debt instrument covenant consolidated minimum current ratio numerator (as a ratio)					1.0
Debt instrument covenant consolidated minimum current ratio denominator (as a ratio)					1.0

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Fair Value Measurement (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value Disclosures [Abstract]

Net derivative liabilities measured at fair value on a recurring basis

(in millions)	Total		Level 1		Level 2		Level 3
Commodity derivatives liability, net
December 31, 2011	$	22.7	$	—	$	22.7	$	—
December 31, 2010	$	113.6	$	—	$	11.8	$	101.8

Changes in Level 3 fair value measurements

	Year Ended December 31,
(in millions)	2011			2010		2009
Fair value liability (asset), beginning of period	$	101.8		$	26.0	$	(172.5	)
Transfer out of Level 3(1)	(101.8		)	—		(3.4		)
Realized and unrealized (gain) loss included in earnings	—			37.4		(71.0		)
Unrealized loss included in accumulated other comprehensive loss	—			—		201.9
Settlements	—			38.4		71.0
Fair value liability, end of period	$	—		$	101.8	$	26.0
Total unrealized (gain) loss included in earnings related to financial assets and liabilities still on the Balance Sheets	$	—		$	75.8	$	(0.4	)

___________________________

(1) During the first quarter of 2011, the inputs used to value oil collars, natural gas collars and natural gas basis swaps were directly or indirectly observable, and these instruments were transferred to level 2.

Schedule of fair values and carrying amounts of debt instruments

	December 31, 2011				December 31, 2010
(in millions)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Line of credit	$	—	$	—	$	5	$	5
Senior secured revolving credit facility	532		532		170		170
8.25% Senior subordinated notes due 2016	200		209		200		210
10.25% Senior notes due 2014, net of unamortized discount of $6,564 and $11,035, respectively	349		402		439		518
6.75% Senior notes due 2020	300		302		300		303
	$	1,381	$	1,445	$	1,114	$	1,206

Fair value, assets measured on recurring and nonrecurring basis

			Fair Value Measurements (in millions) Using
Description	Carrying Value at 12/31/2011		Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)	Losses Recognized in 2011
Natural Gas Properties	$	114.3	—	—	114.3	$	625.0
Other Long-Lived Assets	1.4		—	—	1.4	4.3
						$	629.3

			Fair Value Measurements (in millions) Using
Description	Carrying Value at 12/31/2009		Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)	Losses Recognized in 2009
Other Long-Lived Assets	$	3.3	—	—	3.3	$	4.2

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of commodity derivatives

	2012	2013	2014
Oil Bbl/D:	21,000	15,000	2,000
Natural Gas MMBtu/D:	15,000	—	—

Schedule of derivative assets and liabilities

	December 31, 2011
	Derivative Assets			Derivative Liabilities
(in millions)	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Current:
Commodity	Derivative assets	$	6.1	Derivative liabilities	$	20.4
Long-term:
Commodity	Derivative assets	7.0		Derivative liabilities	15.5
Total derivatives		$	13.1		$	35.9

	December 31, 2010
	Derivative Assets			Derivative Liabilities
(in millions)	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Current:
Commodity	Derivative assets	$	2.7	Derivative liabilities	$	84.9
Long-term:
Commodity	Derivative assets	2.1		Derivative liabilities	33.5
Total derivatives		$	4.8		$	118.4

Summary of (gains) losses before income taxes of derivative instruments recognized in the condensed statements of income (loss)

(in millions)		Year Ended December 31,
Derivatives cash flow hedging relationships	Location of (Gain) Loss Recognized in Earnings	2011	2010	2009
Commodity
Loss recognized in AOCL (effective portion)	Accumulated other comprehensive loss	—	—	206.4
(Gain) reclassified from AOCL into earnings (effective portion)	Sales of oil and natural gas	—	—	(58.8	)
(Gain) reclassified from AOCL into earnings (effective portion)	Earnings from discontinued operations	—	—	(20.5	)
Loss recognized in earnings (ineffective portion)	Realized and unrealized (gain) loss on derivatives, net	—	—	0.6
Loss reclassified from AOCL into earnings (amortization of frozen amounts)	Sales of oil and natural gas	60.9	18.4	—
Interest rate
Loss recognized in AOCL (effective portion)	Accumulated other comprehensive loss	—	—	2.7
Loss reclassified from AOCL into earnings (effective portion)	Interest	—	—	7.0
Loss reclassified from AOCL into earnings (amortization of frozen amounts)	Interest	0.8	8.3	—

(in millions)		Year Ended December 31,
Derivatives not designated as hedging instruments under authoritative guidance	Location of (Gain) Loss Recognized in Earnings	2011		2010	2009
Commodity
(Gain) loss recognized in earnings (cash settlements and mark-to-market movements)	Realized and unrealized (gain) loss on derivatives, net	(13.9	)	23.2	7.2
(Gain) loss recognized in earnings (cash settlements and mark-to-market movements)	Earnings from discontinued operations	—		—	0.5
Interest rate
(Gain) loss reclassified from AOCL into earnings (amortization of frozen amounts)	Realized and unrealized (gain) loss on derivatives, net	—		8.6	—

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Equity Incentive Compensation Plans (Restricted Stock Units and Performance Share Program) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Restricted Stock Units
Other than stock options activity
Outstanding at the beginning of the period (in shares)	857,360	[1],[2]	1,107,293	[1],[2]	966,198
Granted (in shares)	159,333		34,529		294,504
Issued (in shares)	(62,127)		(246,633)		(107,375)
Canceled/expired (in shares)	(39,544)		(37,829)		(46,034)
Outstanding at the end of the period (in shares)	915,022	[1],[2]	857,360	[1],[2]	1,107,293	[1],[2]
Weighted-average intrinsic value at grant-date
Outstanding at the beginning of the period (in dollars per share)	$ 19.67	[1],[2]	$ 22.14	[1],[2]	$ 20.83
Granted (in dollars per share)	$ 47.98		$ 30.94		$ 26.72
Issued (in dollars per share)	$ 26.18		$ 28.98		$ 28.98
Canceled/expired (in dollars per share)	$ 25.12		$ 22.20		$ 25.08
Outstanding at the end of the period (in dollars per share)	$ 23.88	[1],[2]	$ 19.67	[1],[2]	$ 22.14	[1],[2]
Vest Date Fair Value - Issued (in dollars)	$ 2,588		$ 7,813		$ 2,574
Performance-Based RSUs
Other than stock options activity
Outstanding at the beginning of the period (in shares)	103,794		0		0
Granted (in shares)	65,620		103,794		0
Issued (in shares)	0		0		0
Canceled/expired (in shares)	(6,565)		0		0
Outstanding at the end of the period (in shares)	162,849		103,794		0
Weighted-average intrinsic value at grant-date
Outstanding at the beginning of the period (in dollars per share)	$ 31.20		$ 0.00		$ 0.00
Granted (in dollars per share)	$ 51.86		$ 31.20		$ 0.00
Issued (in dollars per share)	$ 0.00		$ 0.00		$ 0.00
Canceled/expired (in dollars per share)	$ 44.20		$ 0.00		$ 0.00
Outstanding at the end of the period (in dollars per share)	$ 39.00		$ 31.20		$ 0.00
Vest Date Fair Value - Issued (in dollars)	$ 0		$ 0		$ 0

[1] The balance outstanding includes RSUs granted to executive officers and other officers that have vested in accordance with the RSU agreement, but are subject to a deferral election before the corresponding shares of Common Stock are issued. For the years ended December 31, 2011, 2010 and 2009, 483,908, 289,335, and 124,799 RSUs have vested, but the corresponding shares of Common Stock have not been issued.

[2] The balance outstanding includes RSUs granted to the non-employee directors that 100% vested at date of grant but are subject to a deferral election before the corresponding shares of Common Stock are issued. For the years ended December 31, 2011, 2010 and 2009, 30,544, 10,522 and 10,522 RSUs have vested, but the corresponding shares of Common Stock have not been issued.

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Debt (6.75% Senior Notes Due 2020) (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Nov. 01, 2010
Debt Instrument
6.75% Senior notes due 2020	300,000,000	$ 300,000,000
6.75% Senior notes due 2020
Debt Instrument
Interest rate on debt instrument (as a percent)	6.75%	6.75%
Unsecured Debt | 6.75% Senior notes due 2020
Debt Instrument
Interest rate on debt instrument (as a percent)			6.75%
Net proceeds from Issuance long-term debt		294,000,000
Redemption percentage, maximum (as a percent)	35.00%
Senior notes redemption price percentage of principal (as a percent)	106.75%
Senior Notes, Expressed As Percentage Of Principal Amount Redeemed, Plus Accured and Unpaid Interest
Debt Instrument redemption price percentage of principal amount plus make whole premium, plus accrued and unpaid interest (as a percent)	100.00%
Permian Basin | Unsecured Debt | 6.75% Senior notes due 2020
Debt Instrument
6.75% Senior notes due 2020			300,000,000
November 1, 2015 Through October 31, 2016 | Unsecured Debt | 6.75% Senior notes due 2020
Senior Notes, Expressed As Percentage Of Principal Amount Redeemed, Plus Accured and Unpaid Interest
Redemption price, as a percentage of the principal or face amount of the given debt instrument, that the Company must pay upon redemption	103.375%
November 1, 2016 through October 31, 2017 | Unsecured Debt | 6.75% Senior notes due 2020
Senior Notes, Expressed As Percentage Of Principal Amount Redeemed, Plus Accured and Unpaid Interest
Redemption price, as a percentage of the principal or face amount of the given debt instrument, that the Company must pay upon redemption	102.25%
November 1, 2017 through October 31, 2018 | Unsecured Debt | 6.75% Senior notes due 2020
Senior Notes, Expressed As Percentage Of Principal Amount Redeemed, Plus Accured and Unpaid Interest
Redemption price, as a percentage of the principal or face amount of the given debt instrument, that the Company must pay upon redemption	101.125%
November 1, 2018 and thereafter | Unsecured Debt | 6.75% Senior notes due 2020
Senior Notes, Expressed As Percentage Of Principal Amount Redeemed, Plus Accured and Unpaid Interest
Redemption price, as a percentage of the principal or face amount of the given debt instrument, that the Company must pay upon redemption	100.00%

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure [Abstract]

Schedule of future minimum rental payments for operating leases

(in millions)	Total		2012		2013		2014		2015		2016		Thereafter
Operating leases(1)	$	11.8	$	2.8	$	2.8	$	2.6	$	2.2	$	1.4	$	—
Drilling rig commitments(2)	7.0		7.0		—		—		—		—		—
Other commitments(3)	31.3		14.2		11.4		1.8		1.9		2.0		—
Firm natural gas transportation contracts(4)	263.5		29.7		30.2		32.7		32.6		32.5		105.8
Total	$	313.6	$	53.7	$	44.4	$	37.1	$	36.7	$	35.9	$	105.8

___________________________________

(1) Includes operating leases related to office facilities, vehicles and aircraft.

(2) Excludes obligations related to rigs drilling on a well-by-well basis that can be released after drilling the current well without penalty.

(3) Includes primarily obligations related to natural gas purchases, cogeneration facility management services and equipment rentals.

(4) Includes a transportation agreement with Questar Pipeline Company for an average of 6,200 MMBtu/D of firm transportation over a period of eight years, based on the expectation that the expansion of the Chipeta Processing LLC natural gas plant expansion will be completed and transportation under this contract will begin July 1, 2012.

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Oil and Gas Properties, Buildings and Equipment (Tables)

12 Months Ended

Dec. 31, 2011

Oil and Gas Properties, Buildings and Equipment [Abstract]

Schedule of Oil and Gas Properties, Building and Equipment Activities

	Year Ended December 31,
(in thousands)	2011			2010
Oil and natural gas:
Proved properties(1)	$	3,257,321		$	3,182,305
Unproved properties(2)	228,486			217,253
	3,485,807			3,399,558
Less accumulated depreciation, depletion and amortization	(962,154		)	(757,264		)
	2,523,653			2,642,294
Commercial and other:
Machinery, drilling rigs, and equipment	22,509			24,988
Buildings and improvements	6,894			7,434
Vehicles	7,806			6,849
	37,209			39,271
Less accumulated depreciation	(29,469		)	(25,773		)
	7,740			13,498
	$	2,531,393		$	2,655,792

________________________________________

(1) Includes cogeneration facilities.

(2) Unproved properties includes acquisition costs for properties to which proved developed producing and proved undeveloped reserves are also attributed. At December 31, 2011, unproved properties included $14.8 million of acquisition costs for unevaluated properties. The Company assesses these properties annually and recorded impairments of $0.6 million, $0.0 million and $1.0 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Description of the Business

Berry Petroleum Company (the Company) is an independent energy company engaged in the production, development, exploitation and acquisition of oil and natural gas. The Company has invested in cogeneration facilities, which provide steam required for the extraction of heavy oil and which generate electricity for sale.

Basis of Presentation

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). Certain amounts in prior years' financial statements have been reclassified to conform to the 2011 financial statement presentation.

Assumptions, Judgments, and Estimates

In the course of preparing the financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.

The more significant areas requiring the use of assumptions, judgments, and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) income taxes; (7) valuation of derivative instruments; and (8) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with a remaining maturity of three months or less to be cash equivalents. The Company's cash management process provides for the daily funding of checks as they are presented to the bank. Included in accounts payable at December 31, 2011 and 2010 is $16.1 million and $16.3 million, respectively, representing outstanding checks in excess of the bank balance (book overdraft).

Accounts Receivable

Trade accounts receivable consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, oil and natural gas receivables are collected within two months.

Bad Debt Recovery

The Company recognized $38.5 million in bad debt expense in the year ended December 31, 2008 related to the Flying J bankruptcy. On July 6, 2010, the Joint Plan of Reorganization of Flying J was confirmed under Chapter 11 of the United States Bankruptcy Code. Additionally, the United States Bankruptcy Court approved and confirmed the June 15, 2010 Stipulation and Agreed Order (the Stipulation) with Flying J regarding the resolution of the Company's claim in Flying J's pending bankruptcy. Pursuant to the Stipulation, Flying J agreed that the total amount owed to the Company by Flying J was $60.5 million and, as a result, the Company received $60.5 million in cash on July 23, 2010. In the quarter ended September 30, 2010, the Company recorded a settlement of the Company's Flying J bankruptcy claim of $22.0 million and a bad debt recovery of $38.5 million.

Discontinued Operations

In 2009, the Company sold its DJ assets, the results of operations of which are reported as discontinued operations in the 2009 Statements of Operations. See Note 2 to the Financial Statements.

Income Taxes and Uncertain Tax Positions

The Company recognizes deferred income tax liabilities and assets for the expected future income tax consequences of temporary differences between financial accounting bases and income tax bases of assets and liabilities. Deferred income taxes are measured by applying currently enacted income tax rates. The Company accounts for uncertainty in income taxes for income tax positions taken or expected to be taken in an income tax return. Only income tax positions that meet the more-likely-than-not recognition threshold will be recognized.

Derivative Instruments

The Company enters into derivative contracts, primarily swaps and collars, to manage its exposure to commodity price risk. All derivative instruments, other than those that meet the "normal purchases normal sales" exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. The Company is required to formally document, at the inception of a hedge, the hedging relationship and the risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment. Effective January 1, 2010, the Company elected to discontinue all hedge accounting prospectively. As a result, subsequent to December 31, 2009, the Company records all derivative instruments as either assets or liabilities at fair value and recognizes all gains and losses from changes in derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive loss (AOCL). See Notes 8 and 9 to the Financial Statements. Cash settlements of derivative instruments used to manage commodity price risk are classified as cash flows from operating activities in the Statements of Cash Flows along with the cash flows from the related oil and natural gas production activities. The Company nets derivative assets and liabilities of a given counterparty whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The Company uses these agreements to manage and reduce its potential counterparty credit risk. The Company does not enter into derivative instruments for speculative or trading purposes.

Oil and Natural Gas Properties, Buildings and Equipment

The Company accounts for its oil and natural gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The costs of development wells are capitalized whether productive or nonproductive.

The provision for depletion of oil and natural gas properties is calculated on a field-by-field basis using the unit-of-production method. If the estimates of total proved or proved developed reserves decline, the rate at which the Company records depreciation, depletion and amortization (DD&A) expense increases, which in turn reduces net earnings. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. The Company is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of its development program, as well as future economic conditions. Changes in reserves are applied on a prospective basis.

Buildings and equipment are recorded at cost. Depreciation is calculated on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment.

Capitalized Interest

Acquisition costs of proved undeveloped and unproved properties qualify for interest capitalization during a period if interest cost is incurred and activities necessary to bring the properties into a productive state are in progress. As wells are drilled in a field with proved undeveloped reserves or unproved reserves, a portion of the acquisition costs are either re-designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re-designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field.

Impairment of Proved and Unproved Properties

Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis, annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows.Due to the impact of lower natural gas prices, the Company recorded an impairment of $625.0 million related to its E. Texas natural gas assets. See Notes 9 and 11 to the Financial Statements.

Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time.

Assets Held for Sale

Any properties held for sale as of the date of presentation of the balance sheets have been classified as assets held for sale and are separately presented on the balance sheets at the lower of net book value or fair value less the cost to sell. See Note 3 to the Financial Statements.

Asset Retirement Obligations

The Company's asset retirement obligations (AROs) relate to future costs associated with plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability.

Deferred Financing Costs

Costs incurred in connection with the execution or modification of the Company’s credit facility, and in connection with the Company's senior and subordinated notes, are capitalized and amortized over the life, or expected life, of the debt using the effective interest method.

Prepaid Expenses and Other

The components of prepaid expenses and other are as follows:

	Year Ended December 31,
(in thousands)	2011	2010
Prepaid expenses	5,275	9,590
Inventory	11,526	4,443
Total prepaid expenses and other	16,801	14,033

Accrued Liabilities

The components of accrued liabilities are as follows:

	Year Ended December 31,
(in thousands)	2011		2010
Property taxes	$	10,430	$	11,245
Accrued interest	9,205		10,074
Accrued payroll	9,953		10,225
Other accrued liabilities	5,478		4,690
Total accrued liabilities	$	35,066	$	36,234

Revenue Recognition

Revenues associated with sales of oil, natural gas, electricity and natural gas marketing are recognized when delivery has occurred and title has transferred, and if the collectability of the revenue is probable. The electricity and natural gas the Company produces and uses in its operations are not included in revenues. Revenues from oil and natural gas production from properties in which the Company has an interest with other producers are recognized on the basis of its net working interest. Revenues are also derived from natural gas marketing sales, which represent excess capacity on the Rockies Express, Wyoming Interstate, and Ruby pipelines used by the Company to market natural gas for its working interest partners and other third parties.

Significant Customers

The Company sells oil and natural gas to various types of customers, including pipelines, refineries and other oil and natural gas companies, and electricity to utility companies. Credit is extended based on an evaluation of the customer's financial condition and historical payment record. The Company does not believe that the loss of any one customer would impact the marketability of its products, but it may impact the profitability of its oil, natural gas or electricity sold. Due to the possibility of refinery constraints in the Utah region, it is possible that the loss of the Company's crude oil sales customer in Utah could impact the marketability of a portion of the Company's Utah crude oil volumes.

In 2011, sales to ExxonMobil Oil Corporation and Shell Trading (US) Company accounted for approximately 43% and 14%, respectively, of the Company's revenue. In 2010, sales to two purchasers were approximately 44% and 14%, respectively, of the Company's revenue. In 2009, sales to three purchasers were approximately 25%, 16% and 12%, respectively, of the Company's revenue.

Concentrations of Market Risk

The results of the Company's oil and natural gas operations are impacted by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future depends on numerous factors beyond the Company's control, including weather, imports, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil and natural gas products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

During 2011, 2010 and 2009, the Company did not incur any credit losses with respect to counterparties to contracts for the sale of oil and natural gas or under the Company's derivative instruments. As of December 31, 2011, over 87% of the Company's California oil production is under contract with Shell Trading (US) Company and ExxonMobil Oil Corporation. The Company's contract with Shell Trading (US) Company continues through June 30, 2013 and the Company's contract with ExxonMobil Oil Corporation renews automatically on a month-to-month basis, unless either party to the contract terminates upon 90 days' notice.

The Company places its temporary cash investments with high-quality financial institutions and does not limit the amount of credit exposure to any one financial institution. For the three years ended December 31, 2011, the Company has not incurred losses related to these investments.

Electricity Cost Allocation

The Company owns three cogeneration facilities. Its investment in cogeneration facilities has been for the express purpose of lowering steam costs in its heavy oil operations and securing operating control of the respective steam generation. Cogeneration, also called combined heat and power (CHP), extracts energy from the exhaust of a turbine, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. The Company allocates steam costs to its oil and natural gas operating costs based on the conversion efficiency of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to utility companies. A portion of the capital costs of the cogeneration facilities is allocated to DD&A—oil and natural gas production. Electricity production used in oil and natural gas operations is allocated to operating costs—oil and natural gas production, and totaled $2.3 million, $2.8 million and $2.8 million for the years ended December 31, 2011, 2010 and 2009 respectively.

Transportation Costs

Natural gas transportation costs are included in either operating costs—oil and natural gas production or operating costs—electricity generation, as applicable. Natural gas transportation costs included in operating costs—oil and natural gas production were $21.4 million, $16.2 million and $16.1 million for 2011, 2010 and 2009, respectively. Costs for transporting natural gas used in electricity generation were $5.0 million, $4.7 million and $2.8 million for 2011, 2010 and 2009, respectively; a portion of these costs are allocated to operating costs—oil and natural gas production, as described above, and the remainder are included in operating costs—electricity generation.

Stock-Based Compensation

The Company recognizes the grant date fair value of stock options and other stock based compensation issued in the Statements of Operations. Expense is recognized on a straight-line basis over the employee's requisite service period (generally the vesting period of the award).

(Loss) Earnings Per Share

The two-class method of computing earnings per share is required for entities that have participating securities. The two-class method is an earnings allocation formula that determines earnings per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. Unvested restricted stock issued prior to January 1, 2010, under the Company's equity incentive plans, has the right to receive non-forfeitable dividends, participating on an equal basis with common stock, and thus these securities are classified as participating securities. Participating securities do not have a contractual obligation to share in the Company's losses. Therefore, in periods of net loss, no portion of the loss is allocated to participating securities. Unvested restricted stock issued subsequent to January 1, 2010, under the Company's equity incentive plans does not participate in dividends. Stock options issued under the Company's equity incentive plans do not participate in dividends.

Basic (loss) earnings per share is calculated by dividing (loss) earnings available to common shareholders by the weighted average shares-basic during each period. Under the treasury stock method, diluted (loss) earnings per share is calculated by dividing (loss) earnings available to common shareholders by the weighted average shares-dilutive, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of non-participating unvested restricted stock awards and outstanding stock options. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted (loss) earnings per share.

The following table shows the computation of basic and diluted net earnings per share from continuing and discontinued operations:

	Year Ended December 31,
	2011			2010		2009
	(in thousands, except per share amounts)
Net (loss) earnings from continuing operations	$	(228,063	)	$	82,524	$	47,224
Less: earnings allocable to participating securities	—			1,199		1,134
Net earnings from continuing operations available for common shareholders	$	(228,063	)	$	81,325	$	46,090
Net earnings from discontinued operations	$	—		$	—	$	6,806
Less: earnings allocable to participating securities	—			—		174
Net earnings from discontinued operations available for common shareholders	$	—		$	—	$	6,632
Basic (loss) earnings per share from continuing operations	$	(4.21	)	$	1.54	$	1.03
Basic earnings per share from discontinued operations	—			—		0.15
Basic (loss) earnings per share	$	(4.21	)	$	1.54	$	1.18
Dilutive (loss) earnings per share from continuing operations	$	(4.21	)	$	1.52	$	1.02
Dilutive earnings per share from discontinued operations	—			—		0.15
Dilutive (loss) earnings per share	$	(4.21	)	$	1.52	$	1.17
Basic weighted average shares	54,133			52,969		44,625
Add: dilutive effects of stock options	—			460		221
Diluted weighted average shares	54,133			53,429		44,846

Options of 1.5 million, 0.7 million and 1.6 million shares were not included in the weighted average shares-dilutive calculation for the years ended December 31, 2011, 2010 and 2009, respectively, because their effect would have been anti-dilutive.

Equity Method Investments

The Company owns interests in two entities that gather and transport natural gas in the Company's Lake Canyon and Brundage Canyon fields. The Company owns less than a 50% interest in both of these entities and such interests are accounted for using the equity method. The Company's net investment in these entities is included under the caption other assets on its Balance Sheets.

Comprehensive (Loss) Earnings

Comprehensive (loss) earnings is a term used to refer to net (loss) earnings plus other comprehensive earnings (loss). Other comprehensive (loss) earnings is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of shareholders' equity instead of net (loss) earnings. The components of other comprehensive (loss) earnings were as follows:

	Year Ended December 31,
(in thousands)	2011			2010		2009
Net (loss) earnings	$	(228,063	)	$	82,524	$	54,030
Unrealized gain (loss) on derivatives, net of income taxes of $0, $0, and ($79,240), respectively	—			—		(129,287		)
Reclassification of realized (gain) loss on derivatives included in net earnings, net of income taxes of $0, $0, ($27,447)	—			—		(44,782		)
Amortization of Accumulated other comprehensive loss related to de-designated hedges, net of income taxes of $23,467, $10,153, and $0, respectively	38,289			16,566		—
Comprehensive (loss) earnings	$	(189,774	)	$	99,090	$	(120,039	)

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development, and production of oil and natural gas, and all of the Company's operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment.

Impact of Recently Issued Accounting Standard Updates

In December 2011, the FASB issued ASU No. 2011-11 Disclosures about Offsetting Assets and Liabilities. The ASU requires additional disclosures about the impact of offsetting, or netting, on a company's financial position, and is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods, and retrospectively for all comparative periods presented. Under US GAAP, derivative assets and liabilities can be offset under certain conditions. The ASU requires disclosures showing both gross information and net information about instruments eligible for offset in the balance sheet. The Company is currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on the Company's financial position or results of operations.

In June 2011, the FASB issued ASU No. 2011-05 Presentation of Comprehensive Income. The ASU amends previously issued authoritative guidance and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. These amendments remove the option under current U.S. GAAP to present the components of other comprehensive income as part of the statements of changes in stockholder's equity. In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-12 Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards. The ASU supersedes pending paragraphs in ASU 2011-05 related to presenting reclassifications out of accumulated other comprehensive income by component in the financial statements. The adoption of this authoritative guidance will not have an impact on the Company's financial position or results of operations, but will require the Company to present the Statements of Comprehensive Income separately from its Statements of Shareholders' Equity, as these statements are currently presented on a combined basis.

In May 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-04 Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRSs. The ASU amends previously issued authoritative guidance and requires new disclosures, clarifies existing disclosures and is effective for interim and annual periods beginning after December 15, 2011. The amendments change requirements for measuring fair value and disclosing information about those measurements. Additionally, the ASU clarifies the FASB's intent regarding the application of existing fair value measurement requirements and changes certain principles or requirements for measuring fair value or disclosing information about its measurements. For many of the requirements, the FASB does not intend the amendments to change the application of the existing Fair Value Measurements guidance. The Company is currently evaluating the provisions of ASU 2011-04 and assessing the impact, if any, it may have on the Company's financial position or results of operations.

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Asset Retirement Obligation (ARO) (Tables)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation Disclosure [Abstract]

Summary of change in asset retirement obligation

	Year Ended December 31,
(in thousands)	2011			2010
Beginning balance at January 1	$	53,443		$	43,487
Liabilities incurred	2,983			3,721
Liabilities settled	(1,803		)	(1,832		)
Liabilities assumed	119			3,498
Accretion expense	4,812			4,569
Revisions in estimated cash flows	4,465			—
Ending balance at December 31(1)	$	64,019		$	53,443

____________________

(1) The asset retirement obligation related to the Nevada Assets, which were held for sale as of December 31, 2011, was $0.7 million at December 31, 2011 and is included in the asset retirement obligations liability on the December 31, 2011 Balance Sheets. See Note 3 to the Financial Statements.

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Acquisitions and Divestitures (Details) (USD $)	12 Months Ended					3 Months Ended	12 Months Ended		1 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 Class A	Dec. 31, 2010 Class A	Mar. 31, 2011 Permian Basin Acquisitions	Dec. 31, 2010 Permian Basin Acquisitions property	Jan. 31, 2010 Permian Basin Acquisitions Class A	May 31, 2011 Wolfberry Acquisition acre	Dec. 31, 2011 Wolfberry Acquisition	Dec. 31, 2009 Denver Julesburg	Dec. 31, 2011 Senior Notes 6.75 Percent Due 2020	Dec. 31, 2010 Senior Notes 6.75 Percent Due 2020	Nov. 01, 2010 Senior Notes 6.75 Percent Due 2020 Unsecured Debt	Nov. 01, 2010 Senior Notes 6.75 Percent Due 2020 Unsecured Debt Permian Basin Acquisitions
Acquisitions
Interests acquired in producing properties (in net acres)									6,000
Purchase price paid, net of customary post-closing adjustments	$ 158,090,000	$ 334,409,000	$ 13,497,000				$ 327,032,000		$ 128,398,000
Percentage of operation of acquired properties (as a percent)										98.00%
Percentage of average working interest (as a percent)										93.00%
Percentage of net revenue interest (as a percent)										70.00%
Revenues generated by acquired properties	870,773,000	619,608,000	500,532,000				28,700,000			7,800,000
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed and undeveloped properties							332,214,000		128,697,000
Other assets acquired							342,000
Asset retirement obligation							(3,498,000)		(119,000)
Deferred income tax liability							(647,000)
Other liabilities assumed							(333,000)		(180,000)
Total identifiable net assets							328,078,000		128,398,000
Number of separate acquisitions (in properties)							3
Common stock shares issued for financing acquisitions (in shares)				52,067,994	51,426,232			8,000,000
Aggregate principal amount of senior notes due in November 2020 issued for financing acquisitions	300,000,000	300,000,000													300,000,000
Interest rate of senior notes due in November 2020 (as a percent)												6.75%	6.75%	6.75%
Gain on purchase of oil and natural gas properties						1,000,000
Deferred income taxes	(149,279,000)	51,735,000	16,734,000			700,000
Transaction Costs on Acquisitions	0	2,635,000	0				2,600,000
Net earnings from discontinued operations	$ 0	$ 0	$ 6,806,000								$ 6,806,000

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Equity Incentive Compensation Plans and Other Benefit Plans (Equity Incentive Plans) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 2010 Equity Incentive Plan	Dec. 31, 2011 2005 Equity Incentive Plan	Dec. 31, 2011 Scenerio One 2010 Equity Incentive Plan	Dec. 31, 2011 Scenerio One 2005 Equity Incentive Plan	Dec. 31, 2011 Scenerio Two 2010 Equity Incentive Plan	Dec. 31, 2011 Scenerio Two 2005 Equity Incentive Plan	May 31, 2010 Class A 2010 Equity Incentive Plan	May 31, 2005 Class A 2005 Equity Incentive Plan	Dec. 31, 2011 Class A Minimum 2010 Equity Incentive Plan	Dec. 31, 2011 Class A Minimum 2005 Equity Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award
Number of Common Stock shares available for grant										1,000,000	2,900,000
Options may not be less than fair market value of Common Stock on the date of grant (in shares)												1	1
Vesting rate based on Plan (as a percent)						25.00%	25.00%	100.00%	100.00%
Options granted under plan, term (in years)				10 years	10 years
Shares available to be issued in period				697,596	189,297
Vesting period based on plan (in years)	4 years					4 years	4 years	3 years	3 years
Total compensation cost (in dollars)	$ 9.0	$ 8.3	$ 7.7

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Supplemental Information about Oil & Gas Producing Activities (Unaudited) (Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities) (Details) (USD $)	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Costs Incurred, Acquisition of Oil and Natural Gas Properties
Proved properties	$ 149,158,000		$ 334,409,000		$ 13,497,000
Unproved properties	6,632,000		0		0
Development	544,114,000		320,927,000		138,168,000
Exploration	627,000		2,310,000		209,000
Total	700,531,000	[1]	657,646,000	[1]	151,874,000	[1]
Capitalized interest incurred	$ 29,100,000		$ 28,300,000		$ 30,100,000

[1] The total above does not reflect $29.1 million, $28.3 million, and $30.1 million of capitalized interest incurred in 2011, 2010, and 2009, respectively.

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Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 298		$ 278
Short-term investments	65		65
Accounts receivable	115,952		93,406
Deferred income taxes	13,779		32,342
Derivative instruments	6,117		2,742
Assets held for sale	14,622		0
Prepaid expenses and other	16,801		14,033
Total current assets	167,634		142,866
Oil and natural gas properties (successful efforts basis), buildings and equipment, net	2,531,393		2,655,792
Derivative instruments	7,027		2,054
Other assets	28,898		37,904
TOTAL ASSETS	2,734,952		2,838,616
Current liabilities:
Accounts payable	126,489		106,459
Revenue and royalties payable	49,253		37,812
Accrued liabilities	35,066		36,234
Line of credit	0		5,300
Derivative instruments	20,365		84,846
Total current liabilities	231,173		270,651
Long-term liabilities:
Deferred income taxes	185,450		329,207
Senior secured revolving credit facility	531,500		170,000
8.25% Senior subordinated notes due 2016	200,000		200,000
10.25% Senior notes due 2014, net of unamortized discount of $6,564 and $11,035, respectively	348,692		438,965
6.75% Senior notes due 2020	300,000		300,000
Asset retirement obligations	64,019	[1]	53,443
Derivative instruments	15,505		33,526
Other long-term liabilities	17,884		18,271
Total long-term liabilities	1,663,050		1,543,412
Commitments and contingencies (Note 10)
Shareholders' equity:
Preferred stock, $0.01 par value, 2,000,000 shares authorized; no shares outstanding	0		0
Capital stock, $0.01 par value:
Capital in excess of par value	350,158		327,369
Accumulated other comprehensive loss	(5,517)		(43,806)
Retained earnings	495,549		740,458
Total shareholders' equity	840,729		1,024,553
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	2,734,952		2,838,616
Class A
Capital stock, $0.01 par value:
Common Stock	521		514
Class B
Capital stock, $0.01 par value:
Common Stock	$ 18		$ 18

[1] The asset retirement obligation related to the Nevada Assets, which were held for sale as of December 31, 2011, was $0.7 million at December 31, 2011 and is included in the asset retirement obligations liability on the December 31, 2011 Balance Sheets. See Note 3 to the Financial Statements.

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Debt (10.25% Senior Notes Due 2014) (Details) (USD $)	12 Months Ended					0 Months Ended		12 Months Ended		2 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 10.25% Senior notes due 2014	Dec. 31, 2010 10.25% Senior notes due 2014	Aug. 13, 2009 Unsecured Debt 10.25% Senior notes due 2014	May 27, 2009 Unsecured Debt 10.25% Senior notes due 2014	Dec. 31, 2011 Unsecured Debt 10.25% Senior notes due 2014	Sep. 30, 2011 Unsecured Debt 10.25% Senior notes due 2014	Sep. 30, 2011 Unsecured Debt Buy back of notes 10.25% Bond Repurchases	Dec. 31, 2011 Unsecured Debt Buy back of notes 10.25% Bond Repurchases	Oct. 31, 2011 Unsecured Debt Buy back of notes 10.25% Bond Repurchases
Debt Instrument
Interest rate on debt instrument (as a percent)				10.25%	10.25%			10.25%	10.25%			10.25%
Principal amount of debt issued						$ 125,000,000	$ 325,000,000
Discount on issuance (as a percent)							93.546%
Unamortized discount				6,564,000	11,035,000		21,000,000
Net proceeds from Issuance long-term debt						129,100,000	295,100,000
Aggregate purchase price for repurchase of notes							140,000,000	108,800,000
Premium on issuance (as a percent)						104.75%
Unamortized premium						6,000,000
Debt Instrument redemption price percentage of principal amount plus make whole premium, plus accrued and unpaid interest (as a percent)								100.00%
Aggregate principal amount of notes repurchased										94,700,000
Loss on repurchase of notes	15,544,000	573,000	10,823,000					15,000,000
Premium paid on debt extinguishment								11,500,000
Extinguishment of debt	$ 4,072,000	$ 573,000	$ 10,823,000								$ 3,500,000

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Statement of Shareholders' Equity (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Dividends per share (in dollars per share)	$ 0.31	$ 0.30	$ 0.30

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Derivative Instruments (Details) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accumulated Other Comprehensive Loss
Expected derivative payments during next twelve months		$ 5,300,000
Unrealized losses, before tax, on contracts previously designated as cash flow hedges	(70,700,000)	(8,900,000)	(70,700,000)
Unrealized losses, net of tax, on contracts previously designated as cash flow hedges	(43,806,000)	(5,517,000)	(43,806,000)
Reclassified unrealized losses, before tax from AOCL into earnings		(61,800,000)	(26,700,000)
Reclassified unrealized losses, after tax from AOCL into earnings		(38,289,000)	(16,566,000)
Termination of Interest Rate Derivatives
Cash paid to counterparties to unwind or terminate interest rate derivative contracts during the period	10,800,000
Fair value gain related to interest rate derivative contracts that were terminated during the period	8,900,000
Realized and unrealized (gain) loss on derivatives, net		13,908,000	(31,847,000)	(7,756,000)
2012 | Oil Bbl/D
Notional amount of derivative instruments
Notional amount of derivatives (Bbl/MMBtu)		21,000
2012 | Natural Gas MMBtu/D
Notional amount of derivative instruments
Notional amount of derivatives (Bbl/MMBtu)		15,000
2013 | Oil Bbl/D
Notional amount of derivative instruments
Notional amount of derivatives (Bbl/MMBtu)		15,000
2013 | Natural Gas MMBtu/D
Notional amount of derivative instruments
Notional amount of derivatives (Bbl/MMBtu)		0
2014 | Oil Bbl/D
Notional amount of derivative instruments
Notional amount of derivatives (Bbl/MMBtu)		2,000
2014 | Natural Gas MMBtu/D
Notional amount of derivative instruments
Notional amount of derivatives (Bbl/MMBtu)		0
Interest rate contracts
Termination of Interest Rate Derivatives
Realized and unrealized (gain) loss on derivatives, net	$ (1,900,000)

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Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended			0 Months Ended	3 Months Ended	12 Months Ended																	12 Months Ended
	Dec. 31, 2011 Purchasers Cogeneration_facilities Industry_Segments	Dec. 31, 2010 Purchasers	Dec. 31, 2009 Purchasers	Jul. 23, 2010 Flying J	Sep. 30, 2010 Flying J	Dec. 31, 2008 Flying J	Dec. 31, 2011 Building and Building Improvements year	Dec. 31, 2011 Machinery and Equipment year	Dec. 31, 2011 California Shell Trading (US) and Exxon Mobil Oil Corporation	Dec. 31, 2011 Electricity Cost Allocation	Dec. 31, 2010 Electricity Cost Allocation	Dec. 31, 2009 Electricity Cost Allocation	Dec. 31, 2011 Costs of Transporting Natural Gas	Dec. 31, 2010 Costs of Transporting Natural Gas	Dec. 31, 2009 Costs of Transporting Natural Gas	Dec. 31, 2011 Sales Shell Trading (US) Company	Dec. 31, 2011 Sales ExxonMobil Oil Corporation	Dec. 31, 2010 Sales Purchaser One	Dec. 31, 2009 Sales Purchaser One	Dec. 31, 2010 Sales Purchaser Two	Dec. 31, 2009 Sales Purchaser Two	Dec. 31, 2009 Sales Purchaser Three	Dec. 31, 2011 East Texas Oil and Gas Properties Assets measured on nonrecurring basis
Accounting Policies
Electricity Consumption Included in Operating Costs-Oil and Natural Gas Production										$ 2,300,000	$ 2,800,000	$ 2,800,000
Outstanding checks in excess of the bank balance, included in accounts payable	16,100,000	16,300,000
Oil and natural gas receivables generally collected (in months)	2 months
Bad debt expense						38,500,000
Litigation settlement, gross				60,500,000
Proceeds received from bankruptcy claim				60,500,000
Settlement of Flying J bankruptcy claim	0	21,992,000	0		22,000,000
Allowance for doubtful accounts recoveries of bad debts	0	38,508,000	0		38,500,000
Property, plant and equipment, useful lives, minimum (in years)							5	3
Property, plant and equipment, useful lives, maximum (in years)							30	10
Significant customer, amount (in ones)	2	2	3
Concentration risk (as a percent)																14.00%	43.00%	44.00%	25.00%	14.00%	16.00%	12.00%
Oil production under contract (as a percent)									87.00%
Contract renewal automatic on month-to-month basis unless either party to contract gives termination notice (number of days in advance)	90 days
Natural Gas Transportation Costs Included in Operating Costs-Oil and Natural Gas Production													21,400,000	16,200,000	16,100,000
Costs of Natural Gas Transportation Used in Electricity Generation													5,000,000	4,700,000	2,800,000
Number of companies owned under equity method investments (in ones)	2
Equity method investment, ownership is less than (as a percent)	50.00%
Exploratory wells are evaluated for economic viability after well completion, length of time (in years)	1 year
Impairment of oil and natural gas properties	$ 625,564,000	$ 0	$ 1,017,000																				$ 625,000,000
Number of Cogeneration facilities (in ones)	3
Number of industry segments (in ones)	1

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Fair Value Measurement (Details 3) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
8.25% Senior subordinated notes due 2016
Fair value and carrying value of debt instruments
Interest rate on debt instrument (as a percent)	8.25%	8.25%
10.25% Senior notes due 2014, net of unamortized discount of $6,564 and $11,035, respectively
Fair value and carrying value of debt instruments
Interest rate on debt instrument (as a percent)	10.25%	10.25%
Unamortized discount	6,564	11,035
6.75% Senior notes due 2020
Fair value and carrying value of debt instruments
Interest rate on debt instrument (as a percent)	6.75%	6.75%
Carrying Amount
Fair value and carrying value of debt instruments
Debt Instrument, Fair Value Disclosure	1,381,000	1,114,000
Carrying Amount | Line of Credit
Fair value and carrying value of debt instruments
Debt Instrument, Fair Value Disclosure	0
Carrying Amount | Senior secured revolving credit facility
Fair value and carrying value of debt instruments
Debt Instrument, Fair Value Disclosure	531,500	170,000
Carrying Amount | 8.25% Senior subordinated notes due 2016
Fair value and carrying value of debt instruments
Debt Instrument, Fair Value Disclosure	200,000	200,000
Carrying Amount | 10.25% Senior notes due 2014, net of unamortized discount of $6,564 and $11,035, respectively
Fair value and carrying value of debt instruments
Debt Instrument, Fair Value Disclosure	348,692	439,000
Carrying Amount | 6.75% Senior notes due 2020
Fair value and carrying value of debt instruments
Debt Instrument, Fair Value Disclosure	300,000	300,000
Estimated Fair Value
Fair value and carrying value of debt instruments
Debt Instrument, Fair Value Disclosure	1,445,000	1,206,000
Estimated Fair Value | Senior secured revolving credit facility
Fair value and carrying value of debt instruments
Debt Instrument, Fair Value Disclosure		170,000
Estimated Fair Value | 8.25% Senior subordinated notes due 2016
Fair value and carrying value of debt instruments
Debt Instrument, Fair Value Disclosure	209,000	210,000
Estimated Fair Value | 10.25% Senior notes due 2014, net of unamortized discount of $6,564 and $11,035, respectively
Fair value and carrying value of debt instruments
Debt Instrument, Fair Value Disclosure	402,000	518,000
Estimated Fair Value | 6.75% Senior notes due 2020
Fair value and carrying value of debt instruments
Debt Instrument, Fair Value Disclosure	302,000	303,000

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Basis of Presentation

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). Certain amounts in prior years' financial statements have been reclassified to conform to the 2011 financial statement presentation.

Assumptions, Judgements, and Estimates

In the course of preparing the financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.

The more significant areas requiring the use of assumptions, judgments, and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) income taxes; (7) valuation of derivative instruments; and (8) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with a remaining maturity of three months or less to be cash equivalents. The Company's cash management process provides for the daily funding of checks as they are presented to the bank.

Accounts Receivable

Trade accounts receivable consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, oil and natural gas receivables are collected within two months.

Bad debt recovery

The Company recognized $38.5 million in bad debt expense in the year ended December 31, 2008 related to the Flying J bankruptcy. On July 6, 2010, the Joint Plan of Reorganization of Flying J was confirmed under Chapter 11 of the United States Bankruptcy Code. Additionally, the United States Bankruptcy Court approved and confirmed the June 15, 2010 Stipulation and Agreed Order (the Stipulation) with Flying J regarding the resolution of the Company's claim in Flying J's pending bankruptcy. Pursuant to the Stipulation, Flying J agreed that the total amount owed to the Company by Flying J was $60.5 million and, as a result, the Company received $60.5 million in cash on July 23, 2010. In the quarter ended September 30, 2010, the Company recorded a settlement of the Company's Flying J bankruptcy claim of $22.0 million and a bad debt recovery of $38.5 million.

Discontinued operations

In 2009, the Company sold its DJ assets, the results of operations of which are reported as discontinued operations in the 2009 Statements of Operations. See Note 2 to the Financial Statements.

Income Taxes and Uncertain Tax Positions

The Company recognizes deferred income tax liabilities and assets for the expected future income tax consequences of temporary differences between financial accounting bases and income tax bases of assets and liabilities. Deferred income taxes are measured by applying currently enacted income tax rates. The Company accounts for uncertainty in income taxes for income tax positions taken or expected to be taken in an income tax return. Only income tax positions that meet the more-likely-than-not recognition threshold will be recognized.

Derivatives Instruments

The Company enters into derivative contracts, primarily swaps and collars, to manage its exposure to commodity price risk. All derivative instruments, other than those that meet the "normal purchases normal sales" exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. The Company is required to formally document, at the inception of a hedge, the hedging relationship and the risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment. Effective January 1, 2010, the Company elected to discontinue all hedge accounting prospectively. As a result, subsequent to December 31, 2009, the Company records all derivative instruments as either assets or liabilities at fair value and recognizes all gains and losses from changes in derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive loss (AOCL). See Notes 8 and 9 to the Financial Statements. Cash settlements of derivative instruments used to manage commodity price risk are classified as cash flows from operating activities in the Statements of Cash Flows along with the cash flows from the related oil and natural gas production activities. The Company nets derivative assets and liabilities of a given counterparty whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The Company uses these agreements to manage and reduce its potential counterparty credit risk. The Company does not enter into derivative instruments for speculative or trading purposes.

Oil and Gas Properties, Building and Equipment

The Company accounts for its oil and natural gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The costs of development wells are capitalized whether productive or nonproductive.

The provision for depletion of oil and natural gas properties is calculated on a field-by-field basis using the unit-of-production method. If the estimates of total proved or proved developed reserves decline, the rate at which the Company records depreciation, depletion and amortization (DD&A) expense increases, which in turn reduces net earnings. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. The Company is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of its development program, as well as future economic conditions. Changes in reserves are applied on a prospective basis.

Buildings and equipment are recorded at cost. Depreciation is calculated on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment.

Capitalized Interest

Acquisition costs of proved undeveloped and unproved properties qualify for interest capitalization during a period if interest cost is incurred and activities necessary to bring the properties into a productive state are in progress. As wells are drilled in a field with proved undeveloped reserves or unproved reserves, a portion of the acquisition costs are either re-designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re-designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field.

Impairment of Proved and Unproved Properties

Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis, annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows.Due to the impact of lower natural gas prices, the Company recorded an impairment of $625.0 million related to its E. Texas natural gas assets. See Notes 9 and 11 to the Financial Statements.

Assets Held for Sale

Any properties held for sale as of the date of presentation of the balance sheets have been classified as assets held for sale and are separately presented on the balance sheets at the lower of net book value or fair value less the cost to sell

Asset Retirement Obligations

The Company's asset retirement obligations (AROs) relate to future costs associated with plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability

Deferred Financing Costs

Costs incurred in connection with the execution or modification of the Company’s credit facility, and in connection with the Company's senior and subordinated notes, are capitalized and amortized over the life, or expected life, of the debt using the effective interest method.

Revenue Recognition

Revenues associated with sales of oil, natural gas, electricity and natural gas marketing are recognized when delivery has occurred and title has transferred, and if the collectability of the revenue is probable. The electricity and natural gas the Company produces and uses in its operations are not included in revenues. Revenues from oil and natural gas production from properties in which the Company has an interest with other producers are recognized on the basis of its net working interest. Revenues are also derived from natural gas marketing sales, which represent excess capacity on the Rockies Express, Wyoming Interstate, and Ruby pipelines used by the Company to market natural gas for its working interest partners and other third parties.

Significant Customers

The Company sells oil and natural gas to various types of customers, including pipelines, refineries and other oil and natural gas companies, and electricity to utility companies. Credit is extended based on an evaluation of the customer's financial condition and historical payment record. The Company does not believe that the loss of any one customer would impact the marketability of its products, but it may impact the profitability of its oil, natural gas or electricity sold. Due to the possibility of refinery constraints in the Utah region, it is possible that the loss of the Company's crude oil sales customer in Utah could impact the marketability of a portion of the Company's Utah crude oil volumes.

Concentrations of Market Risk

The results of the Company's oil and natural gas operations are impacted by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future depends on numerous factors beyond the Company's control, including weather, imports, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil and natural gas products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

The Company places its temporary cash investments with high-quality financial institutions and does not limit the amount of credit exposure to any one financial institution.

Electricity Cost Allocation

The Company owns three cogeneration facilities. Its investment in cogeneration facilities has been for the express purpose of lowering steam costs in its heavy oil operations and securing operating control of the respective steam generation. Cogeneration, also called combined heat and power (CHP), extracts energy from the exhaust of a turbine, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. The Company allocates steam costs to its oil and natural gas operating costs based on the conversion efficiency of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to utility companies. A portion of the capital costs of the cogeneration facilities is allocated to DD&A—oil and natural gas production. Electricity production used in oil and natural gas operations is allocated to operating costs

Transportation Costs

Natural gas transportation costs are included in either operating costs—oil and natural gas production or operating costs—electricity generation, as applicable.

Share-based Compensation

The Company recognizes the grant date fair value of stock options and other stock based compensation issued in the Statements of Operations. Expense is recognized on a straight-line basis over the employee's requisite service period (generally the vesting period of the award).

(Loss) Earnings Per Share

The two-class method of computing earnings per share is required for entities that have participating securities. The two-class method is an earnings allocation formula that determines earnings per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. Unvested restricted stock issued prior to January 1, 2010, under the Company's equity incentive plans, has the right to receive non-forfeitable dividends, participating on an equal basis with common stock, and thus these securities are classified as participating securities. Participating securities do not have a contractual obligation to share in the Company's losses. Therefore, in periods of net loss, no portion of the loss is allocated to participating securities. Unvested restricted stock issued subsequent to January 1, 2010, under the Company's equity incentive plans does not participate in dividends. Stock options issued under the Company's equity incentive plans do not participate in dividends.

Basic (loss) earnings per share is calculated by dividing (loss) earnings available to common shareholders by the weighted average shares-basic during each period. Under the treasury stock method, diluted (loss) earnings per share is calculated by dividing (loss) earnings available to common shareholders by the weighted average shares-dilutive, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of non-participating unvested restricted stock awards and outstanding stock options. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted (loss) earnings per share.

Equity Method Investments

The Company's net investment in these entities is included under the caption other assets on its Balance Sheets.

Comprehensive (Loss) Earnings

Comprehensive (loss) earnings is a term used to refer to net (loss) earnings plus other comprehensive earnings (loss). Other comprehensive (loss) earnings is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of shareholders' equity instead of net (loss) earnings.

Industy Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development, and production of oil and natural gas, and all of the Company's operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment

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Summary of Significant Accounting Policies (Prepaid Expenses and Other) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Prepaid expense
Prepaid expenses	$ 5,275	$ 9,590
Inventory	11,526	4,443
Total prepaid expenses and other	$ 16,801	$ 14,033

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Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2011

Business Combinations [Abstract]

Consideration paid to sellers and recognized amounts of identifiable assets acquired and liabilities assumed

	(in thousands)
Consideration paid to sellers:
Cash consideration	$	128,398
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed and undeveloped properties	128,697
Asset retirement obligation	(119		)
Other liabilities assumed	(180		)
Total identifiable net assets	$	128,398

	(in thousands)
Consideration paid to sellers:
Cash consideration	$	327,032
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed and undeveloped properties	332,214
Other assets acquired	342
Asset retirement obligation	(3,498		)
Deferred income tax liability	(647		)
Other liabilities assumed	(333		)
Total identifiable net assets	$	328,078

Schedule of Earnings from discontinued operations, net of tax on the accompanying Statement of Operations

	Year Ended December 31, 2009
Sales of oil and natural gas(1)	$	11,555
Loss on sale of asset	(908		)
Other revenue	623
Total revenues	11,270
Realized and unrealized (gain) on derivatives, net	(13,786		)
Other expenses(2)	15,799
Total expenses	2,013
Earnings from discontinued operations, before income taxes	9,257
Provision for income taxes	2,451
Net earnings from discontinued operations	$	6,806

________________________________________

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Oil and Gas Properties, Buildings and Equipment (Details) (USD $)	12 Months Ended											12 Months Ended							12 Months Ended			3 Months Ended
	Dec. 31, 2011		Dec. 31, 2010 Wells		Dec. 31, 2009	Dec. 31, 2011 Machinery, drilling rigs, and equipment	Dec. 31, 2010 Machinery, drilling rigs, and equipment	Dec. 31, 2011 Building and improvements	Dec. 31, 2010 Building and improvements	Dec. 31, 2011 Vehicles	Dec. 31, 2010 Vehicles	Dec. 31, 2009 Denver Julesburg	Dec. 31, 2011 Assets measured on nonrecurring basis Other Long-Lived Assets	Dec. 31, 2010 Assets measured on nonrecurring basis Other Long-Lived Assets	Dec. 31, 2009 Assets measured on nonrecurring basis Other Long-Lived Assets	Dec. 31, 2011 East Texas Assets measured on nonrecurring basis Oil and Gas Properties	Dec. 31, 2011 3 Drilling Rigs Drilling_rigs	Dec. 31, 2009 1 Drilling Rig	Dec. 31, 2011 Unevaluated properties	Dec. 31, 2010 Unevaluated properties	Dec. 31, 2009 Unevaluated properties	Dec. 31, 2011 NYMEX HH
Oil and natural gas:
Proved properties	$ 3,257,321,000	[1]	$ 3,182,305,000	[1]
Unproved properties	228,486,000	[2]	217,253,000	[2]															14,800,000
Oil and natural gas: Proved properties and Unproved properties, gross	3,485,807,000		3,399,558,000
Less accumulated depreciation, depletion and amortization	(962,154,000)		(757,264,000)
Oil and natural gas: Proved and Unproved properties, Net	2,523,653,000		2,642,294,000
Oil and natural gas properties (successful efforts basis), buildings and equipment, net	2,531,393,000		2,655,792,000
Capitalized interest costs as component of property costs for development projects (in months)	6 months
Number of wells encountering mechanical failure			1
Impairment charge related to the write-down of a rig to its fair market value					4,200,000								4,300,000	0	4,200,000
Drilling rigs																	3
Carrying amount before impairment of equipment																	5,700,000	7,500,000
Property, Plant and Equipment, Fair Value Disclosure																	1,400,000	3,300,000
Future strip, average of the daily settlement prices of futures contracts (in years)																						5 years
Future strip, average of the daily settlement prices of futures contracts (in months)																						60 months
Future strip, average of the daily settlement prices of futures contracts, percentage decrease																						15.00%
E. Texas Carrying Amount Prior to Impairment	739,300,000
Impairment of oil and natural gas properties	625,564,000		0		1,017,000											625,000,000			600,000	0	1,017,000
Impairment of Oil and Gas Properties from discontinued operations, before tax												9,600,000
Net earnings from discontinued operations	0		0		6,806,000							6,806,000
Commerical and other:
Commerical and other, gross	37,209,000		39,271,000			22,509,000	24,988,000	6,894,000	7,434,000	7,806,000	6,849,000
Less accumulated depreciation	(29,469,000)		(25,773,000)
Commercial and other, net	$ 7,740,000		$ 13,498,000

[1] Includes cogeneration facilities.

[2] Unproved properties includes acquisition costs for properties to which proved developed producing and proved undeveloped reserves are also attributed. At December 31, 2011, unproved properties included $14.8 million of acquisition costs for unevaluated properties. The Company assesses these properties annually and recorded impairments of $0.6 million, $0.0 million and $1.0 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash flows from operating activities:
Net (loss) earnings	$ (228,063)	$ 82,524	$ 54,030
Depreciation, depletion and amortization	215,822	182,657	145,788
Gain on purchase	(1,046)	0	0
Extinguishment of debt	4,072	573	10,823
Amortization of debt issuance costs and net discount	8,243	8,481	6,827
Impairment of oil and natural gas properties	625,564	0	10,654
Dry hole and impairment	4,616	1,478	4,205
Derivatives	(29,094)	42,609	247
Stock-based compensation expense	9,636	9,386	8,626
Deferred income taxes	(149,279)	54,698	19,998
Loss on sale of asset	0	0	79
Other, net	3,223	(12)	(4,016)
Cash paid for abandonment	(1,803)	(1,832)	(1,030)
Bad debt recovery	0	(38,508)	0
Change in book overdraft	(156)	528	(16,018)
Changes in operating assets and liabilities:
Accounts receivable	(23,526)	20,055	(11,816)
Inventories, prepaid expenses, and other current assets	(2,768)	(7,553)	1,761
Accounts payable and revenue and royalties payable	25,019	5,273	(49,119)
Accrued interest and other accrued liabilities	(4,561)	6,880	31,537
Net cash provided by operating activities	455,899	367,237	212,576
Cash flows from investing activities:
Exploration and development of oil and natural gas properties	(527,112)	(310,139)	(134,946)
Property acquisitions	(158,090)	(334,409)	(13,497)
Capitalized interest	(29,117)	(28,321)	(30,107)
Proceeds from sale of assets	0	0	139,796
Deposits on asset sales	3,300	0	0
Net cash used in investing activities	(711,019)	(672,869)	(38,754)
Cash flows from financing activities:
Proceeds from issuances on line of credit	406,600	316,000	387,700
Payments on line of credit	(411,900)	(310,700)	(413,000)
Proceeds from issuance of 10.25% senior notes due 2014	0	0	434,962
Proceeds from issuance of 6.75% senior notes due 2020	0	300,000	0
Repurchase of 10.25% Senior notes due 2014	(94,744)	0	0
Proceeds from long-term borrowings under credit facility	719,700	363,000	655,300
Repayments of long-term borrowings under credit facility	(358,200)	(565,000)	(1,215,100)
Financing obligation	(380)	(346)	18,214
Debt issuance costs	(2,250)	(15,173)	(23,955)
Dividends paid	(16,846)	(16,181)	(13,664)
Proceeds from issuance of stock	0	224,313	0
Proceeds from stock option exercises	10,113	4,402	890
Excess income tax benefit (expense)	3,047	284	(98)
Net cash provided by (used in) financing activities	255,140	300,599	(168,751)
Net increase (decrease) in cash and cash equivalents	20	(5,033)	5,071
Cash and cash equivalents at beginning of year	278	5,311	240
Cash and cash equivalents at end of year	298	278	5,311
Supplemental disclosures of cash flow information:
Interest paid, net of capitalized interest	59,853	40,773	36,854
Incomes taxes paid (refunded)	7,914	(285)	8,769
Noncash investing activities:
Accrued capital expenditures	61,098	51,095	5,059
Asset retirement obligations	$ 7,448	$ 3,721	$ 1,407

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Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	2,000,000	2,000,000
Preferred stock, shares outstanding	0	0
Class A
Capital stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common Stock, shares authorized	100,000,000	100,000,000
Common Stock, shares issued	52,067,994	51,426,232
Common Stock, shares outstanding	52,067,994	51,426,232
Class B
Capital stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common Stock, shares authorized	3,000,000	3,000,000
Common Stock, shares issued	1,797,784	1,797,784
Common Stock, shares outstanding	1,797,784	1,797,784
Common Stock, liquidation preference (in dollars per share)	$ 0.50	$ 0.50
8.25% Senior subordinated notes due 2016
Interest rate on debt instrument (as a percent)	8.25%	8.25%
10.25% Senior notes due 2014
Interest rate on debt instrument (as a percent)	10.25%	10.25%
10.25% Senior notes due 2014, unamortized discount (in dollars)	$ 6,564	$ 11,035
6.75% Senior notes due 2020
Interest rate on debt instrument (as a percent)	6.75%	6.75%

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Operating Leases and Other Commitments

The Company leases corporate and field offices in California, Colorado and Texas under agreements expiring over the next five years. In 2006, the Company purchased an airplane for business travel which was subsequently sold and contracted under a ten year operating lease beginning December 2006. The Company also finances vehicles under operating leases, which expire over the next three years. Rent expense with respect to these lease commitments was $2.6 million for each of the years ended December 31, 2011, 2010 and 2009. The Company currently has four drilling rigs under contracts that require minimum payments for the full contract term or penalties upon early termination. All of these contracts expire during 2012. All other rigs currently performing work for the Company are on a well-by-well basis and can be released without penalty at the conclusion of drilling on the current well. The Company also has other commitments relating primarily to natural gas purchases, cogeneration facility management services and equipment rentals. Additionally, the Company enters into certain firm commitments to transport natural gas production to market and to transport natural gas to its cogeneration and conventional steam generation facilities. These commitments generally require a minimum monthly charge regardless of whether the contracted capacity is used or not.

The table below shows the Company's future minimum payments under non-cancelable operating leases and other commitments as of December 31, 2011:

(in millions)	Total		2012		2013		2014		2015		2016		Thereafter
Operating leases(1)	$	11.8	$	2.8	$	2.8	$	2.6	$	2.2	$	1.4	$	—
Drilling rig commitments(2)	7.0		7.0		—		—		—		—		—
Other commitments(3)	31.3		14.2		11.4		1.8		1.9		2.0		—
Firm natural gas transportation contracts(4)	263.5		29.7		30.2		32.7		32.6		32.5		105.8
Total	$	313.6	$	53.7	$	44.4	$	37.1	$	36.7	$	35.9	$	105.8

___________________________________

(1) Includes operating leases related to office facilities, vehicles and aircraft.

(2) Excludes obligations related to rigs drilling on a well-by-well basis that can be released after drilling the current well without penalty.

(3) Includes primarily obligations related to natural gas purchases, cogeneration facility management services and equipment rentals.

(4) Includes a transportation agreement with Questar Pipeline Company for an average of 6,200 MMBtu/D of firm transportation over a period of eight years, based on the expectation that the expansion of the Chipeta Processing LLC natural gas plant expansion will be completed and transportation under this contract will begin July 1, 2012.

Uinta Crude Oil Sales Contract

The Company is a party to a crude oil sales contract through June 30, 2013 with a refiner for the purchase of a minimum of 5,000 Bbl/D of its Uinta light crude oil. Pricing under the contract, which includes transportation and gravity adjustments, is at a fixed percentage of WTI. While the contractual differentials under this contract may be less favorable at times than the posted differential, demand for the Company's 40 degree black wax (light) crude oil can vary seasonally and this contract provides a stable outlet for the Company's crude oil. Gross oil production from the Company's Uinta properties averaged approximately 3,390 Bbl/D in 2011. Due to the possibility of refinery constraints in the Utah region, it is possible that the loss of the Company's crude oil sales customer in Utah could impact the marketability of a portion of the Company's Utah crude oil volumes. Please see Item 1A. Risk Factors—"We may not be able to deliver minimum crude oil volumes required by our sales contract."

E. Texas Gathering System

In July 2009, the Company closed on the financing of its E. Texas natural gas gathering system for $18.4 million in cash. The Company entered into concurrent long-term natural gas gathering agreements for the E. Texas production which contained an embedded lease. The transaction was treated as a financing obligation. Accordingly, the $16.7 million net book value of the property is being depreciated over the remaining useful life of the asset and the cash received of $18.4 million was recorded as a financing obligation. A portion of payments under the agreements are recorded as gathering expense and a portion as interest expense, with the balance being recorded as a reduction to the financing obligation. There are no minimum payments required under these agreements. For the years ended December 31, 2011, 2010 and 2009 the Company incurred $5.3 million, $6.7 million and $2.0 million, respectively, under the agreements.

Carry and Earning Agreement

On January 14, 2011, the Company entered into an amendment relating to certain contractual obligations to a third party co-owner of certain Piceance assets in Colorado. The amendment waives the $0.2 million penalty for each well not spud by February 2011 and requires the Company to reassign to such co-owner, by January 31, 2020, all of the interest acquired by the Company from the co-owner in each 160-acre tract in which the Company has not drilled and completed a well that is producing or capable of producing from a designated formation, or deeper formation, on January 1, 2020. The amendment also requires the Company to pay the first $9.0 million of costs incurred in connection with the construction of either an extension of the existing access road or a new access road, including the third party's 50% share. If by June 30, 2013 (which date may be extended until December 31, 2014 if road construction has commenced by June 30, 2013), the Company has not expended $9.0 million ($4.5 million of which would otherwise be such third party's responsibility) in road construction costs, then it will be obligated to pay the third party 50% of the difference between $12 million and the actual amount expended on road construction as of such date. Due to the need to obtain regulatory approvals, the Company has not yet commenced construction of either an extension of the existing access road or a new access road and may be unable to do so by June 30, 2013, thus triggering the payment obligation to the third party.

Environmental Matters

The Company has no material accrued environmental liabilities for its sites, including sites in which governmental agencies have designated the Company as a potentially responsible party, because it is not probable that a loss will be incurred and the minimum cost and/or amount of loss cannot be reasonably estimated. However, because of the uncertainties associated with environmental assessment and remediation activities, future expense to remediate the currently identified sites, and sites identified in the future, if any, could be incurred. Management believes, based upon current site assessments, that the ultimate resolution of any matters will not result in material costs incurred.

Legal Matters

COGCC Order — On April 21, 2011, the Company received a proposed Order Finding Violation from the Colorado Oil and Gas Conservation Commission (COGCC) alleging that certain releases in late 2007 from a lined reserve pit located on a well pad in western Colorado violated COGCC regulations. Shortly thereafter, the Company entered into negotiations with the COGCC. While the Company denies that it violated any COGCC regulations in connection with the releases, on June 27, 2011, the COGCC approved and the Company later signed an Administrative Order on Consent under which the Company would pay $100,000, and fund a mutually acceptable public project in the amount of $73,000, in full satisfaction of the matter. The Company recorded these amounts in the second quarter of 2011 and paid $100,000 in July 2011. The Company expects to fund the mutually acceptable project during the first half of 2012.

BLM Settlement — On March 28, 2011, the Company entered into a settlement agreement with the Bureau of Land Management (BLM) resolving all claims by the BLM that the Company did not comply with BLM regulations relating to the operation and position of certain valves, and the submission of related site facility diagrams, in its Uinta operations. The settlement agreement confirmed that the Company promptly remediated the alleged noncompliance upon learning of it, and cooperated with the BLM's investigation, and that there is no evidence of any senior Company management knowledge of the alleged noncompliance, or of any environmental harm or loss of oil or royalty revenue resulting from such alleged noncompliance. The Company paid a $2.1 million civil penalty to the BLM under the settlement agreement in April 2011.

Royalty Payments — Certain of the Company's royalty payment calculations are being disputed. The Company believes that its royalty calculations are in accordance with applicable leases and other agreements, as well as applicable law. However, the disputed amounts that the Company may be required to pay are up to approximately $7.1 million.

Other —The Company is involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of management, the resolution of these matters will not have a material effect on its financial position, results of operations or operating cash flows.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2011	Jun. 30, 2011	Feb. 14, 2012 Class A	Feb. 14, 2012 Class B
Entity Registrant Name	BERRY PETROLEUM CO
Entity Central Index Key	0000778438
Document Type	10-K
Document Period End Date	Dec. 31, 2011
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float		$ 2,583,421,226
Entity Common Stock, Shares Outstanding			52,150,685	1,797,784
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY

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Oil and Gas Properties, Buildings and Equipment

12 Months Ended

Dec. 31, 2011

Oil and Gas Properties, Buildings and Equipment [Abstract]

Oil and Gas Properties, Buildings and Equipment

Oil and Natural Gas Properties, Buildings and Equipment

Oil and natural gas properties, buildings and equipment consist of the following:

	Year Ended December 31,
(in thousands)	2011			2010
Oil and natural gas:
Proved properties(1)	$	3,257,321		$	3,182,305
Unproved properties(2)	228,486			217,253
	3,485,807			3,399,558
Less accumulated depreciation, depletion and amortization	(962,154		)	(757,264		)
	2,523,653			2,642,294
Commercial and other:
Machinery, drilling rigs, and equipment	22,509			24,988
Buildings and improvements	6,894			7,434
Vehicles	7,806			6,849
	37,209			39,271
Less accumulated depreciation	(29,469		)	(25,773		)
	7,740			13,498
	$	2,531,393		$	2,655,792

________________________________________

(1) Includes cogeneration facilities.

(2) Unproved properties includes acquisition costs for properties to which proved developed producing and proved undeveloped reserves are also attributed. At December 31, 2011, unproved properties included $14.8 million of acquisition costs for unevaluated properties. The Company assesses these properties annually and recorded impairments of $0.6 million, $0.0 million and $1.0 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Impairment of Oil and Natural Gas Properties

The Company reviews its oil and natural gas properties for impairment whenever events or circumstances indicate that their carry values may not be recoverable. During the years ended December 31, 2011, 2010 and 2009, the Company recorded impairments of oil and natural gas properties in continuing operations of $625.6 million, $0.0 million, and $1.0 million, respectively. Additionally, during the year ended December 31, 2009, the Company recorded an impairment of $9.6 million, which is recorded in discontinued operations.

In the fourth quarter of 2011, the Company recorded a non-cash impairment of $625.0 million related its E. Texas natural gas properties. The impairment was due to decreases in natural gas prices and, as a result, changes in the Company's development plans. In the fourth quarter of 2011, the NYMEX Henry Hub (HH) five-year future strip (the average of the settlement prices of the next 60 months' futures contracts) decreased approximately 15%. The carrying value of the Company's E. Texas assets prior to the impairment was $739.3 million. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows. Given the unobservable nature of these inputs, the nonrecurring fair value measurement of the E. Texas properties is deemed to use Level 3 inputs.

In March 2009, the Company entered into an agreement to sell its assets in the DJ. The transaction closed in April 2009. The Company recorded a non-cash impairment of $9.6 million related to the sale, which is aggregated within the $6.8 million earnings from discontinued operations, net of income tax, on its Statements of Operations for the year ended December 31, 2009.

If natural gas prices continue to decrease during 2012, the estimated undiscounted future cash flows of the Company's proved natural gas properties may not exceed the carry value and a non-cash impairment charge may be required to be recognized in future periods.

Dry Hole, Abandonment, and Impairment

During the years ended December 31, 2011, 2010, and 2009, the Company recorded an impairment of its drilling rigs in continuing operations of $4.3 million, $0 million, and $4.2 million, respectively. In the fourth quarter of 2011, the Company decided to sell and is actively marketing its three drilling rigs. As a result, the Company reduced the rigs' carrying value of $5.7 million to $1.4 million, consisting of the rigs' fair value less costs to sell. The fair value of the rigs is included in oil and natural gas properties (successful efforts basis), buildings and equipment, net on the Company's Balance Sheets at December 31, 2011. The fair value of the drilling rigs was determined using a market approach, considering comparative market data. Given the unobservable nature of these inputs, the nonrecurring fair value measurement of the drilling rigs is deemed to use Level 3 inputs. In the fourth quarter of 2009, subsequent to the approval of the Company's capital budget, the Company recorded a non-cash impairment to reduce the carrying value of a drilling rig to fair value. The carrying value of $7.5 million was written down to its fair value of $3.3 million. The fair value of the rig was determined using the present value of estimated cash flows. This model considered internal estimates of drilling and operating costs, technical and economic conditions, and a risk adjusted discount rate. Given the unobservable nature of these inputs, the nonrecurring fair value measurement of this rig is deemed to use Level 3 inputs.

In 2010, the Company recorded dry hole, abandonment, and impairment expense primarily due to a mechanical failure encountered on one well in the Piceance. The well was abandoned in favor of drilling a replacement well from the same well pad.

Capitalized Interest

Acquisition costs of proved undeveloped and unproved properties qualify for interest capitalization during a period if interest cost is incurred and activities necessary to bring the properties into a productive state are in progress. As wells are drilled in a field with proved undeveloped or unproved reserves, a portion of the acquisition costs are either re-designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re-designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field.

During 2011, the Company capitalized interest on its Piceance asset for the first half of 2011 and on its Permian asset for all of 2011, as development activities were ongoing. During 2010, the Company capitalized interest on its Piceance and Permian assets as development activities were ongoing. During 2009, the Company capitalized interest on its Piceance and E. Texas assets as development activities were ongoing. In the future, interest capitalization on acquisition costs will depend on whether or not development activities are ongoing. Development activities consist primarily of drilling wells and installing the necessary equipment for production to commence. Interest capitalization ceases when the wells have been completed. Interest cost is capitalized as a component of property cost for development projects that require greater than six months to be readied for their intended use.

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Statements of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
REVENUES
Sales of oil and natural gas	$ 870,773		$ 619,608		$ 500,532
Sales of electricity	34,953		34,740		36,065
Natural gas marketing	13,832		22,162		22,806
Settlement of Flying J bankruptcy claim	0		21,992		0
Gain on sale of assets	0		0		826
Interest and other income, net	1,784		3,300		1,810
TOTAL REVENUES	921,342		701,802		562,039
EXPENSES
Operating costs- oil and natural gas production	237,476		190,218		156,612
Operating costs- electricity generation	25,690		31,295		31,400
Production taxes	33,617		22,999		18,144
Depreciation, depletion & amortization- oil and natural gas production	213,859		179,432		139,919
Depreciation, depletion & amortization- electricity generation	1,963		3,225		3,681
Natural gas marketing	13,038		19,896		21,231
General and administrative	61,727		52,846		49,237
Interest	72,807		66,541		49,923
Extinguishment of debt	15,544		573		10,823
Realized and unrealized (gain) loss on derivatives, net	(13,908)		31,847		7,756
Gain on purchase	(1,046)		0		0
Transaction costs on acquisitions	0		2,635		0
Impairment of oil and natural gas properties	625,564		0		1,017
Dry hole, abandonment, impairment and exploration	5,302		2,311		4,408
Bad debt recovery	0		(38,508)		0
TOTAL EXPENSES	1,291,633		565,310		494,151
(Loss) earnings from continuing operations before income taxes	(370,291)		136,492		67,888
Income tax (benefit) provision	(142,228)		53,968		20,664
Net (loss) earnings from continuing operations	(228,063)		82,524		47,224
Net earnings from discontinued operations	0		0		6,806
Net (loss) earnings	$ (228,063)		$ 82,524		$ 54,030
Basic net (loss) earnings per share from continuing operations (in dollars per share)	$ (4.21)		$ 1.54		$ 1.03
Basic net earnings per share from discontinued operations (in dollars per share)	$ 0.00		$ 0.00		$ 0.15
Basic net (loss) earnings per share (in dollars per share)	$ (4.21)	[1]	$ 1.54	[1]	$ 1.18
Diluted net (loss) earnings per share from continuing operations (in dollars per share)	$ (4.21)		$ 1.52		$ 1.02
Diluted net earnings per share from discontinued operations (in dollars per share)	$ 0.00		$ 0.00		$ 0.15
Diluted net (loss) earnings per share (in dollars per share)	$ (4.21)	[1]	$ 1.52	[1]	$ 1.17
Dividends per share (in dollars per share)	$ 0.31		$ 0.30		$ 0.30

[1] The sum of the individual quarterly net (loss) earnings per common share amounts may not agree with year-to-date net (loss) earnings per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period. Potentially dilutive securities were included in the computation of diluted net (loss) earnings per common share for each quarter in which the Company reported net

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The (benefit) provision for income taxes from continuing operations consists of the following (in thousands):

	Year Ended December 31,
	2011			2010		2009
Current:
Federal	$	4,115		$	363	$	3,148
State	2,936			1,870		782
	7,051			2,233		3,930
Deferred:
Federal	(125,261		)	47,709		20,885
State	(24,018		)	4,026		(4,151		)
	(149,279		)	51,735		16,734
Total	$	(142,228	)	$	53,968	$	20,664

The components of the net deferred income tax liabilities consist of the following:

(in thousands)	Year Ended December 31,
	2011			2010
Deferred income tax assets:
Federal benefit of state income taxes	$	(2,479	)	$	6,862
Credit carryforwards	28,783			28,808
Equity and deferred compensation	12,620			11,229
Derivatives	8,669			26,838
Net operating loss	412			14,545
Other, net	29			1,293
	48,034			89,575
Deferred income tax liabilities:
Depreciation and depletion	(219,705		)	(386,440		)
	(219,705		)	(386,440		)
Net deferred income tax liabilities	$	(171,671	)	$	(296,865	)

At December 31, 2011, the Company's net deferred income tax assets and liabilities were recorded as a current asset of $13.8 million and a long-term liability of $185.5 million. At December 31, 2010, the Company's net deferred income tax assets and liabilities were recorded as a current asset of $32.3 million and a long-term liability of $329.2 million.

Reconciliation of the statutory federal income tax rate to the Company's effective income tax rate follows:

	Year Ended December 31,
	2011		2010		2009
Income tax computed at statutory federal rate	35	%	35	%	35	%
State income taxes, net of federal benefit	3		4		4
Deferred state rate impact	—		(1	)	(5	)
Net impact to uncertain income tax positions	1		—		(2	)
Other	(1	)	2		(2	)
Effective income tax rate	38	%	40	%	30	%

As of December 31, 2011, the Company had approximately $11.1 million of federal and $13.5 million of state (California) EOR tax credit carryforwards available to reduce future income taxes. The EOR credits will begin to expire, if unused, in 2025 and 2016 for federal and California purposes, respectively. The Company has federal alternative minimum income tax (AMT) credit carryforwards of $0.8 million and California AMT credits of $0.7 million that do not expire and can be used to offset regular income taxes in future years to the extent that regular income taxes exceed the AMT in any such year. The Company also has Colorado enterprise zone income tax credits of $2.5 million that will begin to expire in 2018 if not used.

In 2011, the Company executed a final audit settlement that reduced unrecognized income tax benefits by $2.3 million, which resulted in a reduction of the effective income tax rate. As of December 31, 2011, the Company had a gross liability for uncertain income tax benefits of $2.9 million which, if recognized, would affect the effective income tax rate. The Company estimates that it is reasonably possible that the balance of unrecognized income tax benefits as of December 31, 2011 could decrease by a maximum of $2.7 million in the next 12 months due to the expiration of statutes of limitations. The Company recognizes potential accrued interest and penalties related to unrecognized income tax benefits in income tax expense, which is consistent with the recognition of these items in prior reporting periods. The Company had accrued approximately $0.8 million of interest related to its uncertain income tax positions as of December 31, 2011 and 2010.

The Company recognized a net benefit of $2.3 million, $0.0 million and $3.6 million due to the closure of certain federal and state income tax years, offset by additional uncertain income tax position accruals net of interest expense of $0.5 million, $0.1 million and $0.8 million for the years ended December 31, 2011, 2010 and 2009, respectively.

The following table illustrates changes in the gross unrecognized income tax benefits:

(in millions)	Year Ended December 31,
	2011			2010			2009
Unrecognized income tax benefits at January 1	$	5.2		$	6.1		$	12.0
Decreases for positions taken in current year	—			—			(0.1		)
Decreases for positions taken in a prior year	—			(0.8		)	(1.3		)
Decreases for settlements with taxing authorities	(2.3		)	—			(3.6		)
Decreases for lapses in the applicable statute of limitations	—			(0.1		)	(0.9		)
Unrecognized income tax benefits at December 31	$	2.9		$	5.2		$	6.1

As of December 31, 2011, the Company remains subject to examination in the following major tax jurisdictions for the tax years indicated below:

Jurisdiction:	Tax Years Subject to Exam:
Federal	2007 - 2010
California	2007 - 2010
Colorado	2007 - 2010
Texas	2007 - 2010
Utah	2008 - 2010

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Debt

12 Months Ended

Dec. 31, 2011

Debt Disclosure [Abstract]

Debt

Debt

Revolving Credit Facility

The Company's senior secured revolving credit facility, which matures on May 13, 2016, has a current borrowing base of $1.4 billion, subject to lender commitments. On October 26, 2011, as part of the semi-annual borrowing base redetermination process, the Company entered into an amendment to the credit facility which, among other things, increased total lender commitments to $1.2 billion. Borrowings under the credit facility bear interest at either (i) LIBOR plus a margin between 1.50% and 2.50% or (ii) the prime rate plus a margin between 0.50% and 1.50%, in each case, based on the amount utilized. The annual commitment fee on the unused portion of the credit facility ranges between 0.35% and 0.50% based on the amount utilized. Total fees paid during 2011 to increase the borrowing base and lender commitments were approximately $2.2 million, and will be amortized over the remaining term of the credit facility. The Company wrote off debt issuance costs of $0.5 million during the fourth quarter associated with one lender that did not renew its commitment to the credit facility.

As of December 31, 2011, outstanding borrowings under the facility were $531.5 million (excluding $23.2 million of outstanding letters of credit), leaving $645.3 million in borrowing capacity available under the credit facility. As of December 31, 2010, there were $170.0 million in outstanding borrowings under the credit facility. The maximum amount available under the credit facility is subject to semi-annual redeterminations of the borrowing base in April and October of each year, based on the value of the Company's proved oil and natural gas reserves, in accordance with the lenders' customary procedures and practices. The Company and the lenders each have a right to one additional redetermination each year.

The credit facility contains certain covenants, which, among other things, require the maintenance of (i) an interest coverage ratio of 2.75 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0. The senior secured revolving credit facility contains other customary covenants, subject to certain agreed exceptions, including covenants restricting the Company's ability to, among other things, owe or be liable for indebtedness; create, assume or permit to exist liens; be a party to or be liable on any hedging contract; engage in mergers or consolidations; transfer, lease, exchange, alienate or dispose of the Company's material assets or properties; declare dividends on or redeem or repurchase the Company's capital stock; make any acquisitions of, capital contributions to or other investments in any entity or property; extend credit or make advances or loans; engage in transactions with affiliates; and enter into, create or allow to exist contractual obligations limiting the Company's ability to grant liens on the Company's assets to the lenders under the senior secured revolving credit facility. The Company are currently in compliance with all financial covenants and have complied with all financial covenants for all prior periods presented

Subject to certain agreed limitations, the Company granted first priority security interests over substantially all of its assets in favor of the lenders under the credit facility.

Money Market Line of Credit

The Company's senior secured uncommitted money market line of credit has a borrowing capacity of up to $40 million for a maximum of 30 days. As of December 31, 2011, there were no borrowings outstanding under the money market line of credit. Amounts borrowed under the money market line of credit bear interest at LIBOR plus a margin of approximately 1.4%. The line of credit is currently unavailable to the Company and the Company does not know when or if the line of credit will be available in the future. As of December 31, 2010 there was $5.3 million in outstanding borrowings under the line of credit. The outstanding borrowings under the line of credit at December 31, 2010 had a weighted average interest rate of 1.7%.

6.75% Senior Notes Due 2020

On November 1, 2010, the Company issued $300 million in principal amount of 2020 Notes. Interest is payable in arrears semi-annually in May and November of each year, beginning May 2011. The Company received net proceeds of $294.0 million, which were used in part to finance a November 2010 acquisition of producing properties in the Permian and the remainder was used to reduce outstanding borrowings under the credit facility. The 2020 Notes are senior unsecured obligations of the Company and rank effectively junior to all of the Company's existing and any future secured debt, to the extent of the value of the collateral securing that debt, rank equally in right of payment with the 2014 Notes and any future senior unsecured debt, and rank senior in right of payment to the Company's 8.25% senior subordinated notes due 2016 (2016 Notes) and the Company's other future subordinated debt.

The Company may redeem up to 35% of the 2020 Notes at any time prior to November 1, 2013, on one or more occasions, with the proceeds of certain equity offerings at a redemption price of 106.75%. The Company may redeem all or any part of the 2020 Notes at any time beginning on or after November 1, 2015 at the prices set forth below, expressed as percentages of the principal amount redeemed, plus accrued and unpaid interest:

2015	103.375	%
2016	102.250	%
2017	101.125	%
2018 and thereafter	100.000	%

The Company may also redeem the 2020 Notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a "make-whole" premium, plus accrued and unpaid interest to the redemption date.

10.25% Senior Notes Due 2014

On May 27, 2009, the Company issued $325 million in principal amount of its 10.25% senior notes due 2014 (2014 Notes) at 93.546% of par resulting in a discount of $21.0 million. Interest is payable in arrears semi-annually on June 1 and December 1 of each year. The Company received net proceeds of $295.1 million, which were used to repay the $140 million second lien term loan in full and reduce outstanding borrowings under the credit facility.

On August 13, 2009, the Company issued an additional $125 million principal amount of 2014 Notes at 104.75% of par resulting in a premium of $6 million. Interest is payable in arrears semi-annually on June 1 and December 1 of each year. The Company received net proceeds of $129.1 million, which were used to reduce outstanding borrowings under the credit facility.

The 2014 Notes are treated as a single series of debt securities and are carried on the balance sheet at their combined amortized cost. The 2014 Notes are senior unsecured obligations of the Company, which rank effectively junior to all of the Company's existing and any future secured debt, to the extent of the value of the collateral securing that debt, rank equally in right of payment with the 2020 Notes and any future senior unsecured debt, and rank senior in right of payment to the 2016 Notes and the Company's other future subordinated debt.

The 2014 Notes are redeemable at the Company's option, in whole or in part, at any time at a price equal to 100% of the principal amount of the 2014 Notes plus accrued and unpaid interest, if any, plus a "make-whole" premium.

From August to October 2011, the Company repurchased $94.7 million aggregate principal amount of its 2014 Notes for an aggregate purchase price of $108.8 million, including accrued and unpaid interest. The related loss of $15.0 million recorded in extinguishment of debt consists of $11.5 million in premium paid over par and $3.5 million in write-offs of net discount and deferred financing costs. These notes were repurchased using available borrowings under the credit facility. The Company may from time to time seek to repurchase its outstanding debt, including additional 10.25% Notes, through open market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts repurchased may be material.

8.25% Senior Subordinated Notes Due 2016

In 2006, the Company issued $200 million of 2016 Notes at par for proceeds of $196.0 million. Interest on the 2016 Notes is paid semiannually in May 1 and November 1 of each year. The 2016 Notes rank junior to all of the Company's existing and any future secured debt, to the extent of the value of the collateral securing that debt, junior in right of payment to the 2014 and 2020 Notes and any future senior unsecured debt, and equally in right of payment with any future senior subordinated indebtedness.

The Company may redeem the 2016 Notes at any time beginning on or after November 1, 2011 at the prices set forth below, expressed as percentages of the principal amount redeemed, plus accrued but unpaid interest:

2011	104.125	%
2012	102.750	%
2013	101.375	%
2014 and thereafter	100.000	%

The Company may also redeem the 2016 Sub Notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus accrued and unpaid interest plus a "make-whole" premium.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Prepaid Expenses and Other

	Year Ended December 31,
(in thousands)	2011	2010
Prepaid expenses	5,275	9,590
Inventory	11,526	4,443
Total prepaid expenses and other	16,801	14,033

Schedule of Accrued Liabilities

	Year Ended December 31,
(in thousands)	2011		2010
Property taxes	$	10,430	$	11,245
Accrued interest	9,205		10,074
Accrued payroll	9,953		10,225
Other accrued liabilities	5,478		4,690
Total accrued liabilities	$	35,066	$	36,234

Computation of Basic and Diluted Earnings (Loss) Per Share

	Year Ended December 31,
	2011			2010		2009
	(in thousands, except per share amounts)
Net (loss) earnings from continuing operations	$	(228,063	)	$	82,524	$	47,224
Less: earnings allocable to participating securities	—			1,199		1,134
Net earnings from continuing operations available for common shareholders	$	(228,063	)	$	81,325	$	46,090
Net earnings from discontinued operations	$	—		$	—	$	6,806
Less: earnings allocable to participating securities	—			—		174
Net earnings from discontinued operations available for common shareholders	$	—		$	—	$	6,632
Basic (loss) earnings per share from continuing operations	$	(4.21	)	$	1.54	$	1.03
Basic earnings per share from discontinued operations	—			—		0.15
Basic (loss) earnings per share	$	(4.21	)	$	1.54	$	1.18
Dilutive (loss) earnings per share from continuing operations	$	(4.21	)	$	1.52	$	1.02
Dilutive earnings per share from discontinued operations	—			—		0.15
Dilutive (loss) earnings per share	$	(4.21	)	$	1.52	$	1.17
Basic weighted average shares	54,133			52,969		44,625
Add: dilutive effects of stock options	—			460		221
Diluted weighted average shares	54,133			53,429		44,846

Components of Other Comprehensive Earnings (Loss)

	Year Ended December 31,
(in thousands)	2011			2010		2009
Net (loss) earnings	$	(228,063	)	$	82,524	$	54,030
Unrealized gain (loss) on derivatives, net of income taxes of $0, $0, and ($79,240), respectively	—			—		(129,287		)
Reclassification of realized (gain) loss on derivatives included in net earnings, net of income taxes of $0, $0, ($27,447)	—			—		(44,782		)
Amortization of Accumulated other comprehensive loss related to de-designated hedges, net of income taxes of $23,467, $10,153, and $0, respectively	38,289			16,566		—
Comprehensive (loss) earnings	$	(189,774	)	$	99,090	$	(120,039	)

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Asset Retirement Obligation (ARO)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation (ARO)

Asset Retirement Obligations (AROs)

The following table summarizes the summarizes the activity for the Company's abandonment obligations:

	Year Ended December 31,
(in thousands)	2011			2010
Beginning balance at January 1	$	53,443		$	43,487
Liabilities incurred	2,983			3,721
Liabilities settled	(1,803		)	(1,832		)
Liabilities assumed	119			3,498
Accretion expense	4,812			4,569
Revisions in estimated cash flows	4,465			—
Ending balance at December 31(1)	$	64,019		$	53,443

____________________

(1) The asset retirement obligation related to the Nevada Assets, which were held for sale as of December 31, 2011, was $0.7 million at December 31, 2011 and is included in the asset retirement obligations liability on the December 31, 2011 Balance Sheets. See Note 3 to the Financial Statements.

AROs reflect the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company's oil and natural gas properties. Inherent in the fair value calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance.

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Derivative Instruments

12 Months Ended

Dec. 31, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable, economic cash flow from its oil and natural gas production by reducing its exposure to price fluctuations. The Company has entered into financial commodity swap and collar contracts to fix the floor and ceiling prices received for a portion of the Company's oil and natural gas production. The terms of the contracts depend on various factors, including management's view of future crude oil and natural gas prices, acquisition economics on purchased assets and future financial commitments. The Company periodically enters into interest rate derivative contracts to protect against changes in interest rates on its floating rate debt. For further discussion related to the fair value of the Company's derivatives see Note 9 to the Financial Statements.

As of December 31, 2011, the Company had commodity derivatives associated with the following volumes:

	2012	2013	2014
Oil Bbl/D:	21,000	15,000	2,000
Natural Gas MMBtu/D:	15,000	—	—

Based on NYMEX strip pricing as of December 31, 2011, the Company would receive payments under existing derivative contracts of $5.3 million during the next twelve months.

Discontinuance of Hedge Accounting

Effective January 1, 2010, the Company elected to de-designate all of its commodity and interest rate derivative contracts that had been previously designated as cash flow hedges as of December 31, 2009. As a result, subsequent to December 31, 2009, the Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in AOCL. As a result of discontinuing hedge accounting on January 1, 2010, the fair values of the Company's open derivative instruments designated as cash flow hedges as of December 31, 2009, less any ineffectiveness recognized, were frozen in AOCL and are reclassified into earnings as the original hedge transactions settle.

At December 31, 2011, AOCL consisted of $8.9 million ($5.5 million net of income tax) of unrealized losses on commodity and interest rate contracts that had been previously designated as cash flow hedges. At December 31, 2010, AOCL consisted of $70.7 million ($43.8 million net of income tax) of unrealized losses on commodity and interest rate contracts that had been previously designated as cash flow hedges. During the years ended December 31, 2011 and December 31, 2010, $61.8 million ($38.3 million, net of income tax) and $26.7 million ($16.6 million, net of income tax), respectively, of non-cash amortization of AOCL related to discontinuing hedge accounting was reclassified from AOCL into earnings. The Company expects to reclassify into earnings from AOCL pre-tax net losses of $8.9 million related to de-designated commodity and interest rate derivative contracts during the next 12 months.

In the fourth quarter of 2010, the Company terminated interest rate derivative instruments that were previously designated as cash flow hedges. The termination resulted in a cash settlement of $10.8 million, offset by a fair value gain of $8.9 million. The net loss of $1.9 million is included in realized and unrealized (gain) loss on derivatives, net.

The following tables detail the fair value of derivatives recorded on the Company's Balance Sheets, by category:

	December 31, 2011
	Derivative Assets			Derivative Liabilities
(in millions)	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Current:
Commodity	Derivative assets	$	6.1	Derivative liabilities	$	20.4
Long-term:
Commodity	Derivative assets	7.0		Derivative liabilities	15.5
Total derivatives		$	13.1		$	35.9

	December 31, 2010
	Derivative Assets			Derivative Liabilities
(in millions)	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Current:
Commodity	Derivative assets	$	2.7	Derivative liabilities	$	84.9
Long-term:
Commodity	Derivative assets	2.1		Derivative liabilities	33.5
Total derivatives		$	4.8		$	118.4

The tables below summarize the location and the amount of derivative instrument (gains) losses before income taxes reported in the Statements of Operations for the periods indicated:

(in millions)		Year Ended December 31,
Derivatives cash flow hedging relationships	Location of (Gain) Loss Recognized in Earnings	2011	2010	2009
Commodity
Loss recognized in AOCL (effective portion)	Accumulated other comprehensive loss	—	—	206.4
(Gain) reclassified from AOCL into earnings (effective portion)	Sales of oil and natural gas	—	—	(58.8	)
(Gain) reclassified from AOCL into earnings (effective portion)	Earnings from discontinued operations	—	—	(20.5	)
Loss recognized in earnings (ineffective portion)	Realized and unrealized (gain) loss on derivatives, net	—	—	0.6
Loss reclassified from AOCL into earnings (amortization of frozen amounts)	Sales of oil and natural gas	60.9	18.4	—
Interest rate
Loss recognized in AOCL (effective portion)	Accumulated other comprehensive loss	—	—	2.7
Loss reclassified from AOCL into earnings (effective portion)	Interest	—	—	7.0
Loss reclassified from AOCL into earnings (amortization of frozen amounts)	Interest	0.8	8.3	—

(in millions)		Year Ended December 31,
Derivatives not designated as hedging instruments under authoritative guidance	Location of (Gain) Loss Recognized in Earnings	2011		2010	2009
Commodity
(Gain) loss recognized in earnings (cash settlements and mark-to-market movements)	Realized and unrealized (gain) loss on derivatives, net	(13.9	)	23.2	7.2
(Gain) loss recognized in earnings (cash settlements and mark-to-market movements)	Earnings from discontinued operations	—		—	0.5
Interest rate
(Gain) loss reclassified from AOCL into earnings (amortization of frozen amounts)	Realized and unrealized (gain) loss on derivatives, net	—		8.6	—

Credit Risk

The Company does not require collateral or other security from counterparties to support derivative instruments. However, the contracts with those counterparties typically contain netting provisions such that if a default occurs, the non-defaulting party can offset the amount payable to the defaulting party under the derivative contract with the amount due from the defaulting party. As a result of the netting provisions, the Company's maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. The maximum amount of loss due to credit risk that the Company would have incurred if all counterparties to its derivative contracts failed to perform at December 31, 2011 was $7.5 million.

As of December 31, 2011, the counterparties to the Company's commodity derivative contracts consist of seven financial institutions. The Company's counterparties or their affiliates are generally lenders, or affiliates of lenders, under the Company's credit facility. As a result, the counterparties to the Company's derivative contracts share in the collateral supporting the Company's credit facility. The Company is not generally required to post additional collateral under derivative contracts.

Certain of the Company's derivative contracts contain cross default provisions that accelerate of amounts due under such contract if the Company defaults on its obligations under its material debt agreements. In addition, if the Company defaults on certain of its material debt agreements, including, potentially, its derivative contracts, the Company would be in default under the credit facility. As of December 31, 2011, the Company was in a net liability position with four of its counterparties, the fair value of which was $30.2 million. As of December 31, 2011, the Company's largest two counterparties accounted for 84% of the value of its total derivative positions.

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Derivative Instruments (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Fair value derivative assets and liabilities classified in condensed balance sheets
Total Derivative Assets	$ 13.1	$ 4.8
Total Derivative Liabilities	35.9	118.4
Commodity contract | Current assets
Fair value derivative assets and liabilities classified in condensed balance sheets
Total Derivative Assets	6.1	2.7
Commodity contract | Long term assets
Fair value derivative assets and liabilities classified in condensed balance sheets
Total Derivative Assets	7.0	2.1
Commodity contract | Current liability
Fair value derivative assets and liabilities classified in condensed balance sheets
Total Derivative Liabilities	20.4	84.9
Commodity contract | Long term liabilities
Fair value derivative assets and liabilities classified in condensed balance sheets
Total Derivative Liabilities	$ 15.5	$ 33.5

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Shareholder's Equity

12 Months Ended

Dec. 31, 2011

Equity [Abstract]

Shareholder's Equity

Shareholders' Equity

Shares of Class A Common Stock (Common Stock) and Class B Stock, referred to collectively as the "Capital Stock," are entitled to one vote and 95% of one vote, respectively. Each share of Class B Stock is entitled to a $0.50 per share preference in the event of liquidation or dissolution. Further, each share of Class B Stock is convertible into one share of Common Stock at the option of the holder.

Common Stock Offering

In January 2010, the Company issued 8.0 million shares of Class A Common Stock at a price of $29.25 per share. Net proceeds from this offering were $224.3 million. The Company used the net proceeds from the offering to fund a March 2010 acquisition in the Permian and to repay a portion of the outstanding borrowings under the credit facility. See Note 2 to the Financial Statements.

Dividends

The regular annual dividend for 2011 was $0.31 per share. On August 23, 2011, the Company’s Board of Directors approved an increase in the Company’s quarterly dividend of one-half cent per share from $0.075 to $0.08 per share, beginning with the September 2011 dividend. The Company's dividend is payable quarterly in March, June, September and December. Dividend payments are limited by covenants in the (i) credit facility to the greater of $35 million or 75% of net earnings for any four quarter period, and (ii) indentures governing the Company's senior and subordinated indentures to up to $0.36 per share annually (but in no event in excess of $20 million annually) in the event that the Company is not in default, and up to $10 million in the event that the Company is in a non-payment default.

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Equity Incentive Compensation Plans and Other Benefit Plans

12 Months Ended

Dec. 31, 2011

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity Incentive Compensation Plans and Other Benefit Plans

Equity Incentive Compensation Plans and Other Benefit Plans

The Company's 2010 Equity Incentive Plan (the 2010 Plan), approved by the Company's shareholders in May 2010, provides for granting of equity compensation up to an aggregate of 1,000,000 shares of Common Stock. The purpose of the 2010 Plan is to encourage ownership in the Company by key personnel whose long-term service is considered essential to the Company's continued progress and, thereby, align participants' and shareholders' interests. Stock options, stock appreciation rights (SARs), cash awards and stock awards, including restricted shares and stock units, may be granted under the 2010 Plan. The exercise price of an option may not be less than the fair market value of one share of Common Stock on the date of grant. Stock options and restricted stock awards granted under the 2010 Plan have historically vested either in increments of 25% on each of the first four anniversary dates of the date of grant or 100% after three years. Stock options and restricted stock units (RSUs) granted to non-employee directors have historically vested immediately. Options granted under the 2010 Plan have a term of 10 years. As of December 31, 2011, the Company had 697,596 shares available to be issued under the 2010 Plan.

The 2005 Equity Incentive Plan (the 2005 Plan), approved by the Company's shareholders in May 2005, provides for granting of equity compensation up to an aggregate of 2,900,000 shares of Common Stock. The purpose of the 2005 Plan is to encourage ownership in the Company by key personnel whose long-term service is considered essential to the Company's continued progress and, thereby, align participants' and shareholders' interests. Stock options, stock appreciation rights (SARs), cash awards and stock awards, including restricted shares and stock units, may be granted under the 2005 Plan. The exercise price of an option shall not be less than the fair market value of one share of Common Stock on the date of grant. Stock options and restricted stock awards granted under the 2005 Plan have historically vested in increments of 25% on each of the first four anniversary dates of the date of grant or 100% after three years. Stock options and RSUs granted to non-employee directors have historically vested immediately. Options granted under the 2005 Plan have a term of 10 years. As of December 31, 2011, the Company had 189,297 shares available to be issued under the 2005 Plan.

Total compensation expense recognized in the Statements of Operations for grants under the Company's equity incentive plans was $9.0 million, $8.3 million and $7.7 million in 2011, 2010 and 2009, respectively.

Stock Options

The following table summarizes stock option activity for the years ended December 31, 2011, 2010 and 2009:

	Number of Shares		Weighted Average Exercise Price		Aggregate Intrinsic Value (in thousands)(1)		Number of Shares Exercisable
Outstanding at January 1, 2009	2,421,650		$	25.16	$	—	1,842,532
Granted	—		—
Exercised	(62,050	)	13.52		560
Cancelled/expired	(83,580	)	28.48
Outstanding as of December 31, 2009	2,276,020		25.36		15,296		2,008,325
Granted	—		—
Exercised	(227,100	)	19.40		3,570
Cancelled/expired	(31,695	)	35.51
Outstanding at December 31, 2010	2,017,225		25.87		35,974		1,884,937
Granted	89,865		48.50
Exercised	(579,635	)	17.47		17,746
Cancelled/expired	(6,765	)	45.92
Outstanding at December 31, 2011	1,520,690		$	30.32	$	17,798	1,434,020

_________________________________________

(1) The intrinsic value of a stock option is the amount by which the market value of the underlying stock at the end of the related period exceeds the exercise price of the option.

In March 2011, 89,865 stock options were granted under the 2010 Plan to certain executive officers and other officers of the Company with exercise prices equal to the closing market price of the Company's Common Stock on the grant date. These stock options generally vest ratably over a four-year service period from the grant date and are exercisable immediately upon vesting through the tenth anniversary of the grant date.

The fair value of each option granted was estimated using the Black-Scholes option pricing model. Expected volatility was calculated based on the historical volatility of the Company's Common Stock, and the risk-free interest rate was based on U.S. treasury yield curve rates with maturities consistent with the expected life of each stock option. The key assumptions used in computing the weighted average fair market value of stock options granted were as follows:

	2011
Expected volatility	45.00	%
Risk-free rate	2.54	%
Dividend yield	0.62	%
Expected term (in years)	6.0

The following table summarizes information about stock options outstanding at December 31, 2011:

	Stock Options Outstanding					Stock Options Exercisable
Range of Exercise Prices	Number of Options	Weighted Average Remaining Contractual Life (Years)	Weighed Average Exercise Price		Aggregate Intrinsic Value (in thousands)	Number of Options	Weighted Average Remaining Contractual Life (Years)	Weighed Average Exercise Price		Aggregate Intrinsic Value (in thousands)
$7.00-$15.00	199,000	2.13	$	12.36	5,902	199,000	2.13	$	12.36	$	5,902
$15.01-$25.00	287,000	2.90	21.60		5,861	287,000	2.90	21.60		5,861
$25.01-$35.00	655,001	4.51	31.65		6,792	655,001	4.51	31.65		6,792
$35.01-$48.50	379,689	6.79	44.01		—	293,019	6.09	42.68		—
	1,520,690	4.47	$	30.32	17,798	1,434,020	4.18	$	29.22	$	18,360

As of December 31, 2011, there was $1.3 million of total unrecognized compensation expense related to outstanding stock options, which is expected to be recognized over the next 3.25 years.

Restricted Stock Units

The following table summarizes RSU activity for the years ended December 31, 2011, 2010 and 2009:

	RSUs		Weighted Average Intrinsic Value at Grant Date		Vest Date Fair Value (in thousands)
Outstanding at January 1, 2009	966,198		$	20.83
Granted	294,504		26.72
Issued	(107,375	)	28.98		$	2,574
Canceled/expired	(46,034	)	25.08
Outstanding at December 31, 2009(1)(2)	1,107,293		$	22.14
Granted	34,529		30.94
Issued	(246,633	)	28.98		$	7,813
Canceled/expired	(37,829	)	22.20
Outstanding at December 31, 2010(1)(2)	857,360		$	19.67
Granted	159,333		47.98
Issued	(62,127	)	26.18		$	2,588
Canceled/expired	(39,544	)	25.12
Outstanding at December 31, 2011(1)(2)	915,022		$	23.88

__________________________________

(1) The balance outstanding includes RSUs granted to the non-employee directors that 100% vested at date of grant but are subject to a deferral election before the corresponding shares of Common Stock are issued. For the years ended December 31, 2011, 2010 and 2009, 30,544, 10,522 and 10,522 RSUs have vested, but the corresponding shares of Common Stock have not been issued.

(2) The balance outstanding includes RSUs granted to executive officers and other officers that have vested in accordance with the RSU agreement, but are subject to a deferral election before the corresponding shares of Common Stock are issued. For the years ended December 31, 2011, 2010 and 2009, 483,908, 289,335, and 124,799 RSUs have vested, but the corresponding shares of Common Stock have not been issued.

The grant date fair value of RSUs issued under the 2005 Plan was determined by reference to the average high and low stock price of a share of Common Stock on the date of grant. The grant date fair value of RSUs issued under the 2010 Plan was determined by reference to the closing price of a share of Common Stock on the date of grant. The Company uses historical data and projections to estimate expected restricted stock forfeitures. The expected forfeitures are then included as part of the grant date estimate of compensation cost.

As of December 31, 2011, there was $7.9 million of total unrecognized compensation expense related to RSUs granted. That cost is expected to be recognized over 3.25 years.

Performance Share Program

The following table summarizes performance share award activity for the years ended December 31, 2011, 2010 and 2009:    

	Performance Share Awards		Weighted Average Grant Date Fair Value		Vest Date Fair Value (in thousands)
Outstanding at January 1, 2009	—		$	—
Granted	—		—
Issued	—		—		$	—
Canceled/expired	—		—
Outstanding at December 31, 2009	—		$	—
Granted	103,794		31.20
Issued	—		—		$	—
Canceled/expired	—		—
Outstanding at December 31, 2010	103,794		$	31.20
Granted	65,620		51.86
Issued	—		—		$	—
Canceled/expired	(6,565	)	44.20
Outstanding at December 31, 2011	162,849		$	39.00

In March 2011, 65,620 RSUs that are subject to internal performance metrics and market based vesting criteria in addition to a three-year service condition (performance share awards), were granted to executive officers and other officers. The ultimate vesting of performance share awards is contingent upon meeting the established criteria. From January 1, 2011 to December 31, 2013, the Company must maintain an interest coverage ratio of at least 2.5 to 1.0. The number of performance share awards that ultimately vest is based on two equally weighted performance factors: (i) average daily production growth with respect to certain of the Company's assets on an annual basis and (ii) total shareholder return as compared to the Company's defined peer group for years 2011-2013.

For the portion of the performance share awards subject to internal performance metrics, the grant date fair value was determined by reference to the closing price of a share of Common Stock on the date of grant. The Company recognizes compensation expense when it becomes probable that these conditions will be achieved. However, any such compensation expense recognized is reversed if vesting does not actually occur.

For the portion of the performance share awards subject to market based vesting criteria, the grant date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Company's Common Stock, and the risk-free interest rate is based on U.S. treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in valuing the market-based portion of the performance share awards were as follows:

	2011		2010
Number of simulations	100,000		100,000
Expected volatility	44	%	79	%
Risk-free rate	1.15	%	1.36	%

The total grant date fair value of the market-based portion of the performance share awards issued in 2011 and 2010, as determined by the Monte Carlo valuation model, was $1.1 million and $1.0 million, respectively, and is being recognized ratably over the respective three-year vesting period. Compensation expense for the market-based portion of the performance share awards is not reversed if vesting does not actually occur.

As of December 31, 2011, there was $1.4 million of total unrecognized compensation cost related to performance share awards granted. This cost is expected to be recognized over 2 years.

Director Fees

The Company's directors may elect to receive their annual retainer and meeting fees in the form of the Company's Common Stock issued pursuant to the Company's Non-Employee Director Deferred Stock and Compensation Plan (the Deferred Plan). The plan permits eligible directors, in recognition of their contributions to the Company, to receive compensation for service and to defer recognition of their compensation in whole or in part to a stock unit account or an interest account. When the eligible director ceases to be a director, the distribution from the stock unit account is made in shares of Common Stock. The distribution from the interest account is made in cash. Shares of Common Stock earned and deferred in accordance with the Deferred Plan as of December 31, 2011, 2010 and 2009 were 13,647, 38,462, and 124,686, respectively.

Amounts allocated to the stock unit account have the right to receive a "dividend equivalent" equal to the dividends declared and paid by the Company. The dividend equivalent is treated as reinvested in an additional number of units and credited to the director's account using an established market value. Amounts allocated to the interest account are credited with interest at an established interest rate.

Other Employee Benefits—401(k) Plan

The Company sponsors a defined contribution thrift plan under section 401(k) of the Internal Revenue Code to assist all employees in providing for retirement or other future financial needs. The Company currently matches 100% of each employee's contribution up to 8% of an employee's eligible compensation. The Company's contributions to the 401(k) Plan, net of forfeitures, for the years ended December 31, 2011, 2010 and 2009 were $1.8 million, $1.5 million and $1.4 million, respectively. Employees are eligible to participate in the 401(k) Plan on their date of hire and approximately 98% of the Company's employees participated in the 401(k) Plan in 2011.

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Fair Value Measurement

12 Months Ended

Dec. 31, 2011

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurement

The authoritative guidance for fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers include: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

A financial instrument's categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy. The fair value of all derivative instruments is estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The fair value of all derivative instruments is estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services, and the Company has made no adjustments to the obtained prices. The independent pricing services publish observable market information from multiple brokers and exchanges. All valuations were compared against counterparty valuations to verify the reasonableness of prices. The Company also considers counterparty credit risk and its own credit risk in its determination of all estimated fair values. The Company has consistently applied these valuation techniques in all periods presented and believes it has obtained the most accurate information available for the types of derivative contracts it holds. The Company recognizes transfers between levels at the end of the reporting period for which the transfer has occurred.

Liabilities Measured at Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy the Company's net derivative liabilities that were measured at fair value on a recurring basis as of December 31, 2011 and 2010:

(in millions)	Total		Level 1		Level 2		Level 3
Commodity derivatives liability, net
December 31, 2011	$	22.7	$	—	$	22.7	$	—
December 31, 2010	$	113.6	$	—	$	11.8	$	101.8

Changes in Level 3 Fair Value Measurements

The table below includes a rollforward of amounts included in the Company's Balance Sheet (including the change in fair value) for financial instruments classified by the Company within Level 3 of the fair value hierarchy. When a determination is made to classify a financial instrument within Level 3 of the fair value hierarchy, the determination is based upon the significance of the unobservable factors to the overall fair value measurement. Level 3 financial instruments typically include, in addition to the unobservable or Level 3 components, observable components (that is, components that are actively quoted and can be validated to external sources).

	Year Ended December 31,
(in millions)	2011			2010		2009
Fair value liability (asset), beginning of period	$	101.8		$	26.0	$	(172.5	)
Transfer out of Level 3(1)	(101.8		)	—		(3.4		)
Realized and unrealized (gain) loss included in earnings	—			37.4		(71.0		)
Unrealized loss included in accumulated other comprehensive loss	—			—		201.9
Settlements	—			38.4		71.0
Fair value liability, end of period	$	—		$	101.8	$	26.0
Total unrealized (gain) loss included in earnings related to financial assets and liabilities still on the Balance Sheets	$	—		$	75.8	$	(0.4	)

___________________________

(1) During the first quarter of 2011, the inputs used to value oil collars, natural gas collars and natural gas basis swaps were directly or indirectly observable, and these instruments were transferred to level 2.

The $3.4 million of transfers out of Level 3 for the year ended December 31, 2009 represent crude oil collars that were converted to crude oil swaps during the first quarter of 2009.

For further discussion related to the Company's derivatives, see Note 8 to the Financial Statements.

Fair Market Value of Financial Instruments

The Company uses various assumptions and methods in estimating the fair values of its financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of the Company's credit facility and line of credit approximated fair value because the interest rates are variable and could be at similar rates today. The fair values of the 2016 Notes, the 2014 Notes, and the 2020 Notes were estimated based on quoted market prices. The fair values of the Company's derivative instruments are discussed above.

	December 31, 2011				December 31, 2010
(in millions)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Line of credit	$	—	$	—	$	5	$	5
Senior secured revolving credit facility	532		532		170		170
8.25% Senior subordinated notes due 2016	200		209		200		210
10.25% Senior notes due 2014, net of unamortized discount of $6,564 and $11,035, respectively	349		402		439		518
6.75% Senior notes due 2020	300		302		300		303
	$	1,381	$	1,445	$	1,114	$	1,206

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The Company applies the provisions of the fair value measurement standard to its non-recurring, non-financial measurements including business combinations, oil and natural gas property impairments and other long-lived asset impairments. These items are not measured at fair value on a recurring basis but are subject to fair value adjustments only in certain circumstances.

In 2011, the Company recognized impairment losses of $625.0 million and $4.3 million related to natural gas properties and other long-lived assets (drilling rigs), respectively. In 2009, the Company recognized an impairment loss of $4.2 million related to other long-lived assets. The following tables present information about the Company's non-financial assets measured at fair value on a non-recurring basis as of December 31, 2011 and 2009 and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values:

			Fair Value Measurements (in millions) Using
Description	Carrying Value at 12/31/2011		Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)	Losses Recognized in 2011
Natural Gas Properties	$	114.3	—	—	114.3	$	625.0
Other Long-Lived Assets	1.4		—	—	1.4	4.3
						$	629.3

			Fair Value Measurements (in millions) Using
Description	Carrying Value at 12/31/2009		Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)	Losses Recognized in 2009
Other Long-Lived Assets	$	3.3	—	—	3.3	$	4.2

See Notes 2 and 11 to the Financial Statements for additional information on the methods and assumptions used to estimate the fair values of the Company's assets measured at fair value on a nonrecurring basis.

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Fair Value Measurement (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Changes in Level 3 fair value measurements
Fair value (asset), beginning of period					$ (172.5)
Fair value liability, beginning of period	101.8		26.0
Transfers out of Level 3	(101.8)	[1]	0	[1]	(3.4)	[1]
Realized and unrealized (gain) loss included in earnings	0		37.4		(71.0)
Unrealized (gain) loss included in accumulated other comprehensive loss	0		0		201.9
Settlements	0		38.4		71.0
Fair value liability, end of period	0		101.8		26.0
Level 3
Changes in Level 3 fair value measurements
Total unrealized (gain) loss included in income related to financial assets and liabilities still on the Balance Sheets	$ 0		$ 75.8		$ (0.4)

[1] During the first quarter of 2011, the inputs used to value oil collars, natural gas collars and natural gas basis swaps were directly or indirectly observable, and these instruments were transferred to level 2.

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Commitments and Contingencies (Details) (USD $)	12 Months Ended												12 Months Ended	1 Months Ended	12 Months Ended			3 Months Ended
	Dec. 31, 2011 Rigs	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2006 Airplane	Dec. 31, 2011 Vehicles	Dec. 31, 2011 Corporate and Field Offices	Dec. 31, 2011 Drilling rig commitments		Dec. 31, 2011 Other commitments		Dec. 31, 2011 Firm natural gas transportation contracts		Dec. 31, 2011 Uinta	Jul. 31, 2009 East Texas	Dec. 31, 2011 East Texas	Dec. 31, 2010 East Texas	Dec. 31, 2009 East Texas	Dec. 31, 2011 Questar Contracts Contingent on Chipeta Plant Expansion
Operating leases
Operating lease (in years)				10 years	3 years	5 years
Rent expense related to lease commitments	$ 2,600,000	$ 2,600,000	$ 2,600,000
Number of drilling rigs committed	4
Operating Leases, Future Minimum Payments Due
Operating Leases, Future Minimum Payments Due	11,800,000
Operating Leases, Future Minimum Payments Due, Current	2,800,000
Operating Leases, Future Minimum Payments, Due in Two Years	2,800,000
Operating Leases, Future Minimum Payments, Due in Three Years	2,600,000
Operating Leases, Future Minimum Payments, Due in Four Years	2,200,000
Operating Leases, Future Minimum Payments, Due in Five Years	1,400,000
Operating Leases, Future Minimum Payments, Due after Fifth Year	0
Unrecorded Unconditional Purchase Obligation Payment Schedule
Unrecorded Unconditional Purchase Obligation							7,000,000	[1]	31,300,000		263,500,000	[2]
Unrecorded Unconditional Purchase Obligation Due within One Year							7,000,000	[1]	14,200,000	[3]	29,700,000	[2]
Unrecorded Unconditional Purchase Obligation Due in Second Year							0	[1]	11,400,000	[3]	30,200,000	[2]
Unrecorded Unconditional Purchase Obligation Due in Third Year							0	[1]	1,800,000	[3]	32,700,000	[2]
Unrecorded Unconditional Purchase Obligation Due in Fourth Year							0	[1]	1,900,000	[3]	32,600,000	[2]
Unrecorded Unconditional Purchase Obligation Due in Fifth Year							0	[1]	2,000,000	[3]	32,500,000	[2]
Unrecorded Unconditional Purchase Obligation Due after Fifth Year							0	[1]	0	[3]	105,800,000	[2]
Recorded Unconditional Purchase Obligation and Operating Leases, Future Minimum Payments Due
Unrecorded Unconditional Purchase Obligation and Operating Leases, Future Minimum Payments Due	313,600,000
Unrecorded Unconditional Purchase Obligation Due and Operating Leases, Future Minimum Payments Due, Current	53,700,000
Unrecorded Unconditional Purchase Obligation Due and Operating Leases, Future Minimum Payments Due with Second Year	44,400,000
Unrecorded Unconditional Purchase Obligation Due and Operating Leases, Future Minimum Payments Due with Third Year	37,100,000
Unrecorded Unconditional Purchase Obligation Due and Operating Leases, Future Minimum Payments Due with Fourth Year	36,700,000
Unrecorded Unconditional Purchase Obligation Due and Operating Leases, Future Minimum Payments Due within Fifth Year	35,900,000
Unrecorded Unconditional Purchase Obligation Due and Operating Leases, Future Minimum Payments Due after Fifth Year	105,800,000
Proposed transportation of gas under transportation service agreements with Questar Pipeline Company (in years)																		8 years
Volume for proposed transportation of gas under transportation service agreements with Questar Pipeline Company (in MMBtu/D)																		6,200
Uinta Crude Oil Sales Contract
Sales contract, minimum purchase of light crude oil (in Bbl/D)													5,000
Gross oil production average (in Bbl/D)													3,390
E. Texas Gathering System
Proceeds from gas gathering system, financing obligation														18,400,000
Net book value of property														16,700,000
Gas gathering system, costs incurred	$ 13,038,000	$ 19,896,000	$ 21,231,000												$ 5,300,000	$ 6,700,000	$ 2,000,000

[1] Excludes obligations related to rigs drilling on a well-by-well basis that can be released after drilling the current well without penalty.

[2] Includes a transportation agreement with Questar Pipeline Company for an average of 6,200 MMBtu/D of firm transportation over a period of eight years, based on the expectation that the expansion of the Chipeta Processing LLC natural gas plant expansion will be completed and transportation under this contract will begin July 1, 2012.

[3] Includes primarily obligations related to natural gas purchases, cogeneration facility management services and equipment rentals.

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Fair Value Measurement (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis
Asset impairment charges related to write down of drilling rigs			$ 4,200,000
Impairment of oil and natural gas properties	625,564,000	0	1,017,000
Assets and liabilities measured on a recurring basis | Estimated Fair Value | Commodity contract
Fair Value, Assets and Liabilities Measured on Recurring Basis
Commodity derivative asset (liability), net	22,700,000	113,600,000
Assets and liabilities measured on a recurring basis | Level 1 | Commodity contract
Fair Value, Assets and Liabilities Measured on Recurring Basis
Commodity derivative asset (liability), net	0	0
Assets and liabilities measured on a recurring basis | Level 2 | Commodity contract
Fair Value, Assets and Liabilities Measured on Recurring Basis
Commodity derivative asset (liability), net	22,700,000	11,800,000
Assets and liabilities measured on a recurring basis | Level 3 | Commodity contract
Fair Value, Assets and Liabilities Measured on Recurring Basis
Commodity derivative asset (liability), net	0	101,800,000
Assets measured on nonrecurring basis
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis
Total impairment recognized	629,300,000
Oil and Gas Properties | Assets measured on nonrecurring basis | Level 1
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis
Property, Plant and Equipment, Fair Value Disclosure	0
Oil and Gas Properties | Assets measured on nonrecurring basis | Level 2
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis
Property, Plant and Equipment, Fair Value Disclosure	0
Oil and Gas Properties | Assets measured on nonrecurring basis | Level 3
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis
Property, Plant and Equipment, Fair Value Disclosure	114,300,000
Other Long-Lived Assets | Assets measured on nonrecurring basis
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis
Asset impairment charges related to write down of drilling rigs	4,300,000	0	4,200,000
Other Long-Lived Assets | Assets measured on nonrecurring basis | Level 1
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis
Property, Plant and Equipment, Fair Value Disclosure	0		0
Other Long-Lived Assets | Assets measured on nonrecurring basis | Level 2
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis
Property, Plant and Equipment, Fair Value Disclosure	0		0
Other Long-Lived Assets | Assets measured on nonrecurring basis | Level 3
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis
Property, Plant and Equipment, Fair Value Disclosure	1,400,000		3,300,000
East Texas | Oil and Gas Properties | Assets measured on nonrecurring basis
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis
Impairment of oil and natural gas properties	$ 625,000,000

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Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

	Operating Revenues		Net (Loss) Earnings			Basic Net (Loss) Earnings Per Share(1)			Diluted Net (Loss) Earnings Per  Share(1)
2011
First Quarter	$	197,486	$	(52,497	)	$	(0.98	)	$	(0.98	)
Second Quarter	242,709		105,166			1.93			1.90
Third Quarter	238,763		134,001			2.45			2.42
Fourth Quarter	240,600		(414,733		)	(7.62		)	(7.62		)
	$	919,558	$	(228,063	)	$	(4.21	)	$	(4.21	)
2010
First Quarter	$	166,012	$	17,669		$	0.34		$	0.34
Second Quarter	164,457		89,023			1.65			1.64
Third Quarter	166,040		(3,023		)	(0.06		)	(0.06		)
Fourth Quarter	180,001		(21,145		)	(0.40		)	(0.40		)
	$	676,510	$	82,524		$	1.54		$	1.52

_______________________________________________________________________________

(1) The sum of the individual quarterly net (loss) earnings per common share amounts may not agree with year-to-date net (loss) earnings per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period. Potentially dilutive securities were included in the computation of diluted net (loss) earnings per common share for each quarter in which the Company reported net

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Income Taxes (Summary of Income Tax Contingencies) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized income tax benefits at January 1	$ 5.2	$ 6.1	$ 12.0
Decreases for positions taken in current year	0	0	(0.1)
Decreases for positions taken in a prior year	0	(0.8)	(1.3)
Decreases for settlements with taxing authorities	(2.3)	0	(3.6)
Decreases for lapses in the applicable statute of limitations	0	(0.1)	(0.9)
Unrecognized income tax benefits at December 31	$ 2.9	$ 5.2	$ 6.1

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Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2011

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data (Unaudited)

Selected Quarterly Financial Data (Unaudited)

	Operating Revenues		Net (Loss) Earnings			Basic Net (Loss) Earnings Per Share(1)			Diluted Net (Loss) Earnings Per  Share(1)
2011
First Quarter	$	197,486	$	(52,497	)	$	(0.98	)	$	(0.98	)
Second Quarter	242,709		105,166			1.93			1.90
Third Quarter	238,763		134,001			2.45			2.42
Fourth Quarter	240,600		(414,733		)	(7.62		)	(7.62		)
	$	919,558	$	(228,063	)	$	(4.21	)	$	(4.21	)
2010
First Quarter	$	166,012	$	17,669		$	0.34		$	0.34
Second Quarter	164,457		89,023			1.65			1.64
Third Quarter	166,040		(3,023		)	(0.06		)	(0.06		)
Fourth Quarter	180,001		(21,145		)	(0.40		)	(0.40		)
	$	676,510	$	82,524		$	1.54		$	1.52

_______________________________________________________________________________

(1) The sum of the individual quarterly net (loss) earnings per common share amounts may not agree with year-to-date net (loss) earnings per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period. Potentially dilutive securities were included in the computation of diluted net (loss) earnings per common share for each quarter in which the Company reported net

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Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

	Year Ended December 31,
	2011			2010		2009
Current:
Federal	$	4,115		$	363	$	3,148
State	2,936			1,870		782
	7,051			2,233		3,930
Deferred:
Federal	(125,261		)	47,709		20,885
State	(24,018		)	4,026		(4,151		)
	(149,279		)	51,735		16,734
Total	$	(142,228	)	$	53,968	$	20,664

Schedule of Deferred Tax Assets and Liabilities

(in thousands)	Year Ended December 31,
	2011			2010
Deferred income tax assets:
Federal benefit of state income taxes	$	(2,479	)	$	6,862
Credit carryforwards	28,783			28,808
Equity and deferred compensation	12,620			11,229
Derivatives	8,669			26,838
Net operating loss	412			14,545
Other, net	29			1,293
	48,034			89,575
Deferred income tax liabilities:
Depreciation and depletion	(219,705		)	(386,440		)
	(219,705		)	(386,440		)
Net deferred income tax liabilities	$	(171,671	)	$	(296,865	)

Schedule of Effective Income Tax Rate Reconciliation

	Year Ended December 31,
	2011		2010		2009
Income tax computed at statutory federal rate	35	%	35	%	35	%
State income taxes, net of federal benefit	3		4		4
Deferred state rate impact	—		(1	)	(5	)
Net impact to uncertain income tax positions	1		—		(2	)
Other	(1	)	2		(2	)
Effective income tax rate	38	%	40	%	30	%

Summary of Income Tax Contingencies

(in millions)	Year Ended December 31,
	2011			2010			2009
Unrecognized income tax benefits at January 1	$	5.2		$	6.1		$	12.0
Decreases for positions taken in current year	—			—			(0.1		)
Decreases for positions taken in a prior year	—			(0.8		)	(1.3		)
Decreases for settlements with taxing authorities	(2.3		)	—			(3.6		)
Decreases for lapses in the applicable statute of limitations	—			(0.1		)	(0.9		)
Unrecognized income tax benefits at December 31	$	2.9		$	5.2		$	6.1

Summary of Income Tax Examinations

Jurisdiction:	Tax Years Subject to Exam:
Federal	2007 - 2010
California	2007 - 2010
Colorado	2007 - 2010
Texas	2007 - 2010
Utah	2008 - 2010

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Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Deferred tax assets:
Federal benefit of state income taxes	$ (2,479)	$ 6,862
Credit carryforwards	28,783	28,808
Equity and deferred compensation	12,620	11,229
Derivatives	8,669	26,838
Net operating loss	412	14,545
Other, net	29	1,293
Deferred Tax Assets, Net	48,034	89,575
Deferred tax liabilities:
Depreciation and depletion	(219,705)	(386,440)
Deferred Tax Liabilities	(219,705)	(386,440)
Net deferred income tax liabilities	$ (171,671)	$ (296,865)

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Acquisitions and Divestitures (Earnings from Discontinued Operations) (Details) (USD $)	12 Months Ended			3 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Mar. 31, 2009 Denver Julesburg	Dec. 31, 2009 Denver Julesburg
Divestitures
Impairment of Oil and Gas Properties from discontinued operations, before tax					$ 9,600,000
Sales of oil and natural gas					11,555,000	[1]
Loss on sale of asset					(908,000)
Other revenue					623,000
Total revenues					11,270,000
Realized and unrealized (gain) on derivatives, net					(13,786,000)
Other expenses					15,799,000	[2]
Total expenses					2,013,000
Earnings from discontinued operations, before income taxes					9,257,000
Provision for income taxes					2,451,000
Earnings from discontinued operations, net of taxes	0	0	6,806,000		6,806,000
Realized gain included in Sales of oil and natural gas reclassified to discontinued operations					6,200,000
Amount of interest to discontinued operations					800,000
Reclassified gain from AOCL to the Statements of Operations					14,300,000
Unrealized net loss on hedges on Statement of Operations				$ (500,000)

[1] A $6.2 million realized gain included in sales of oil and natural gas was reclassified to discontinued operations for the year ended December 31, 2009.

[2] Includes $9.6 million of impairment charges related to the sale of the Company's assets in the DJ and $0.8 million of interest allocated to discontinued operations based on the ratio of net assets to the sum of total net assets

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Statements of Shareholders' Equity (USD $) In Thousands, unless otherwise specified	Total	Capital in Excess of Par Value	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Class A Common Stock	Class B Common Stock
Balances, beginning of period at Dec. 31, 2008	$ 827,544	$ 79,653	$ 633,749	$ 113,697	$ 427	$ 18
Increase (Decrease) in Shareholders' Equity
Stock options and restricted stock issued	893	890			3
Stock based compensation expense	8,623	8,623
Income tax effect of stock option exercises	(98)	(98)
Dividends	(13,664)		(13,664)
Comprehensive earnings:
Net (loss) earnings	54,030		54,030
Effect of derivative instruments, net of income taxes	(174,069)			(174,069)
Total comprehensive (loss) earnings	(120,039)
Balances, end of period at Dec. 31, 2009	703,259	89,068	674,115	(60,372)	430	18
Increase (Decrease) in Shareholders' Equity
Issuance of stock	224,313	224,233			80
Stock options and restricted stock issued	4,402	4,398			4
Stock based compensation expense	9,386	9,386
Income tax effect of stock option exercises	284	284
Dividends	(16,181)		(16,181)
Comprehensive earnings:
Net (loss) earnings	82,524		82,524
Amortization of Accumulated other comprehensive loss related to de-designated hedges, net of taxes	16,566			16,566
Total comprehensive (loss) earnings	99,090
Balances, end of period at Dec. 31, 2010	1,024,553	327,369	740,458	(43,806)	514	18
Increase (Decrease) in Shareholders' Equity
Stock options and restricted stock issued	10,113	10,106			7
Stock based compensation expense	9,636	9,636
Income tax effect of stock option exercises	3,047	3,047
Dividends	(16,846)		(16,846)
Comprehensive earnings:
Net (loss) earnings	(228,063)		(228,063)
Amortization of Accumulated other comprehensive loss related to de-designated hedges, net of taxes	38,289			38,289
Total comprehensive (loss) earnings	(189,774)
Balances, end of period at Dec. 31, 2011	$ 840,729	$ 350,158	$ 495,549	$ (5,517)	$ 521	$ 18

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Assets Held For Sale

12 Months Ended

Dec. 31, 2011

Assets Held-for-sale, Current [Abstract]

Assets Held For Sale

Assets Held For Sale

At December 31, 2011, the Company's assets held for sale had a balance of $14.6 million related to proved developed properties in Elko, Eureka, and Nye Counties, Nevada (Nevada Assets). On December 21, 2011, the Company entered into an agreement to sell its Nevada Assets to a group of private buyers for $16.5 million, subject to customary closing adjustments. The sale of the Nevada Assets was effective January 1, 2012 and closed January 31, 2012. The Company received a deposit of $3.3 million on December 22, 2011 for the sale of these assets, which is recorded under accrued liabilities on the Balance Sheets at December 31, 2011.The asset retirement obligation related to the Nevada Assets was $0.7 million at December 31, 2011 and is included in the asset retirement obligations liability on the December 31, 2011 Balance Sheets.

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Equity Incentive Compensation Plans and Other Benefit Plans (Director Fees and Other Employee Benefits-401(k) Plan) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other Employee Benefits—401(k) Plan
Company currently matches employee's contributions (as a percent)	100.00%
Contributions to 401(k) Plan, net of forfeitures	$ 1.8	$ 1.5	$ 1.4
Employees participating in 401(k) Plan (as a percent)	98.00%
Maximum
Other Employee Benefits—401(k) Plan
Company matches employee's eligible compensation (as a percent)	8.00%
Non-employee directors
Director Fees
Shares earned and deferred in accordance with the plan (in shares)	13,647	38,462	124,686

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Asset Retirement Obligation (ARO) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010
Change in the asset retirement obligation
Beginning balance	$ 53,443		$ 43,487
Liabilities incurred	2,983		3,721
Liabilities settled	(1,803)		(1,832)
Liabilities assumed	119		3,498
Accretion expense	4,812		4,569
Revisions in estimated cash flows	4,465		0
Ending balance	64,019	[1]	53,443
Nevada Assets
Change in the asset retirement obligation
Ending balance	$ 700

[1] The asset retirement obligation related to the Nevada Assets, which were held for sale as of December 31, 2011, was $0.7 million at December 31, 2011 and is included in the asset retirement obligations liability on the December 31, 2011 Balance Sheets. See Note 3 to the Financial Statements.

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Equity Incentive Compensation Plans and Other Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2011

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of stock options or units activity

	Number of Shares		Weighted Average Exercise Price		Aggregate Intrinsic Value (in thousands)(1)		Number of Shares Exercisable
Outstanding at January 1, 2009	2,421,650		$	25.16	$	—	1,842,532
Granted	—		—
Exercised	(62,050	)	13.52		560
Cancelled/expired	(83,580	)	28.48
Outstanding as of December 31, 2009	2,276,020		25.36		15,296		2,008,325
Granted	—		—
Exercised	(227,100	)	19.40		3,570
Cancelled/expired	(31,695	)	35.51
Outstanding at December 31, 2010	2,017,225		25.87		35,974		1,884,937
Granted	89,865		48.50
Exercised	(579,635	)	17.47		17,746
Cancelled/expired	(6,765	)	45.92
Outstanding at December 31, 2011	1,520,690		$	30.32	$	17,798	1,434,020

_________________________________________

(1) The intrinsic value of a stock option is the amount by which the market value of the underlying stock at the end of the related period exceeds the exercise price of the option.

Summary of assumptions to estimate fair value of stock options

	2011
Expected volatility	45.00	%
Risk-free rate	2.54	%
Dividend yield	0.62	%
Expected term (in years)	6.0

Schedule of Range of Exercise Prices

	Stock Options Outstanding					Stock Options Exercisable
Range of Exercise Prices	Number of Options	Weighted Average Remaining Contractual Life (Years)	Weighed Average Exercise Price		Aggregate Intrinsic Value (in thousands)	Number of Options	Weighted Average Remaining Contractual Life (Years)	Weighed Average Exercise Price		Aggregate Intrinsic Value (in thousands)
$7.00-$15.00	199,000	2.13	$	12.36	5,902	199,000	2.13	$	12.36	$	5,902
$15.01-$25.00	287,000	2.90	21.60		5,861	287,000	2.90	21.60		5,861
$25.01-$35.00	655,001	4.51	31.65		6,792	655,001	4.51	31.65		6,792
$35.01-$48.50	379,689	6.79	44.01		—	293,019	6.09	42.68		—
	1,520,690	4.47	$	30.32	17,798	1,434,020	4.18	$	29.22	$	18,360

Summary of restricted stock units activity

	RSUs		Weighted Average Intrinsic Value at Grant Date		Vest Date Fair Value (in thousands)
Outstanding at January 1, 2009	966,198		$	20.83
Granted	294,504		26.72
Issued	(107,375	)	28.98		$	2,574
Canceled/expired	(46,034	)	25.08
Outstanding at December 31, 2009(1)(2)	1,107,293		$	22.14
Granted	34,529		30.94
Issued	(246,633	)	28.98		$	7,813
Canceled/expired	(37,829	)	22.20
Outstanding at December 31, 2010(1)(2)	857,360		$	19.67
Granted	159,333		47.98
Issued	(62,127	)	26.18		$	2,588
Canceled/expired	(39,544	)	25.12
Outstanding at December 31, 2011(1)(2)	915,022		$	23.88

__________________________________

(1) The balance outstanding includes RSUs granted to the non-employee directors that 100% vested at date of grant but are subject to a deferral election before the corresponding shares of Common Stock are issued. For the years ended December 31, 2011, 2010 and 2009, 30,544, 10,522 and 10,522 RSUs have vested, but the corresponding shares of Common Stock have not been issued.

(2) The balance outstanding includes RSUs granted to executive officers and other officers that have vested in accordance with the RSU agreement, but are subject to a deferral election before the corresponding shares of Common Stock are issued. For the years ended December 31, 2011, 2010 and 2009, 483,908, 289,335, and 124,799 RSUs have vested, but the corresponding shares of Common Stock have not been issued.

Summary of performance share awards activity

	Performance Share Awards		Weighted Average Grant Date Fair Value		Vest Date Fair Value (in thousands)
Outstanding at January 1, 2009	—		$	—
Granted	—		—
Issued	—		—		$	—
Canceled/expired	—		—
Outstanding at December 31, 2009	—		$	—
Granted	103,794		31.20
Issued	—		—		$	—
Canceled/expired	—		—
Outstanding at December 31, 2010	103,794		$	31.20
Granted	65,620		51.86
Issued	—		—		$	—
Canceled/expired	(6,565	)	44.20
Outstanding at December 31, 2011	162,849		$	39.00

Summary of assumptions used in valuing market-based restricted shares

	2011		2010
Number of simulations	100,000		100,000
Expected volatility	44	%	79	%
Risk-free rate	1.15	%	1.36	%

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Summary of Significant Accounting Policies (Earnings Per Share) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2011		Sep. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Dec. 31, 2010		Sep. 30, 2010		Jun. 30, 2010		Mar. 31, 2010		Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Computation of earnings per share
Net (loss) earnings from continuing operations																	$ (228,063)		$ 82,524		$ 47,224
Net earnings from discontinued operations																	0		0		6,806
Basic (loss) earnings per share from continuing operations (in dollars per share)																	$ (4.21)		$ 1.54		$ 1.03
Basic earnings per share from discontinued operations (in dollars per share)																	$ 0.00		$ 0.00		$ 0.15
Basic (loss) earnings per share (in dollars per share)	$ (7.62)	[1]	$ 2.45	[1]	$ 1.93	[1]	$ (0.98)	[1]	$ (0.40)	[1]	$ (0.06)	[1]	$ 1.65	[1]	$ 0.34	[1]	$ (4.21)	[1]	$ 1.54	[1]	$ 1.18
Dilutive (loss) earnings per share from continuing operations (in dollars per share)																	$ (4.21)		$ 1.52		$ 1.02
Dilutive earnings per share from discontinued operations (in dollars per share)																	$ 0.00		$ 0.00		$ 0.15
Dilutive (loss) earings per share (in dollars per share)	$ (7.62)	[1]	$ 2.42	[1]	$ 1.90	[1]	$ (0.98)	[1]	$ (0.40)	[1]	$ (0.06)	[1]	$ 1.64	[1]	$ 0.34	[1]	$ (4.21)	[1]	$ 1.52	[1]	$ 1.17
Basic weighted average shares (in shares)																	54,133,000		52,969,000		44,625,000
Add: Dilutive effects of stock options (in shares)																	0		460,000		221,000
Diluted weighted average shares (in shares)																	54,133,000		53,429,000		44,846,000
Options not included in the diluted earnings (loss) per share calculation (in shares)																	1,500,000		700,000		1,600,000
Continuing Operations
Computation of earnings per share
Less: earnings allocable to participating securities																	0		1,199		1,134
Net earnings from available for common shareholders																	(228,063)		81,325		46,090
Discontinued Operations
Computation of earnings per share
Less: earnings allocable to participating securities																	0		0		174
Net earnings from available for common shareholders																	$ 0		$ 0		$ 6,632

[1] The sum of the individual quarterly net (loss) earnings per common share amounts may not agree with year-to-date net (loss) earnings per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period. Potentially dilutive securities were included in the computation of diluted net (loss) earnings per common share for each quarter in which the Company reported net

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Supplemental Information about Oil & Gas Producing Activities (Unaudited)

12 Months Ended

Dec. 31, 2011

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Information about Oil & Gas Producing Activities (Unaudited)

Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited)

The reserve estimates were made in accordance with oil and natural gas reserve estimation and disclosure authoritative accounting guidance issued by the Financial Accounting Standards Board effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and natural gas reserve estimation and disclosure requirements with the requirements in the SEC's "Modernization of Oil and Gas Reporting" rule, which was also effective for annual reports for fiscal years ending on or after December 31, 2009.

The above-mentioned rules include updated definitions of proved oil and natural gas reserves, proved undeveloped oil and natural gas reserves, oil and natural gas producing activities, and other terms used in estimating proved oil and natural gas reserves. Proved oil and natural gas reserves were calculated based on the prices for oil and natural gas during the twelve month period before the reporting date, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. In addition, the SEC generally requires that reserves classified as proved undeveloped be capable of conversion into proved developed within five years of classification unless specific circumstances justify a longer time.

Changes in Estimated Reserve Quantities

The following table sets forth the Company's estimates of its net proved, net proved developed, and net proved undeveloped oil and natural gas reserves as of December 31, 2011, 2010 and 2009, and changes in its net proved oil and natural gas reserves for the years then ended. For the years presented, the estimates of proved reserves and related valuations were based 100% on reports prepared by the Company's independent petroleum engineers, DeGolyer and MacNaughton (D&M).

	2011						2010						2009
	Oil MBOE		Natural Gas MMcf		MBOE		Oil MBOE		Natural Gas MMcf		MBOE		Oil MBOE		Natural Gas MMcf		MBOE
Proved developed  and undeveloped reserves:
Beginning of year	166,181		630,192		271,213		129,940		632,178		235,303		125,251		724,135		245,940
Revision of previous estimates	(4,054	)	(146,349	)	(28,446	)	4,288		(46,860	)	(3,522	)	2,786		(34,564	)	(2,975	)
Improved recovery	—		—		—		1,700		—		1,700		—		—		—
Extensions and  discoveries	19,601		65,992		30,600		12,774		43,469		20,019		8,989		54,664		18,100
Property sales	—		—		—		—		—		—		—		(126,600	)	(21,100	)
Production	(9,041	)	(23,907	)	(13,025	)	(7,925	)	(23,989	)	(11,923	)	(7,186	)	(22,657	)	(10,962	)
Purchase of reserves in place	13,193		8,351		14,584		25,404		25,394		29,636		100		37,200		6,300
End of year	185,880		534,279		274,926		166,181		630,192		271,213		129,940		632,178		235,303
Proved developed  reserves:
Beginning of year	88,917		268,566		133,678		82,870		255,520		125,456		74,616		361,575		134,879
End of year	107,849		221,606		144,783		88,917		268,566		133,678		82,870		255,520		125,456

Notable changes in proved reserves for the years ended December 31, 2011, 2010, 2009 included:

• Purchase of Reserves in Place. In 2011 and 2010 the Company acquired reserves of 14,584 MBOE, 29,636 MBOE and primarily in the Wolfberry trend in the Permian. See Note 2 to the Financial Statements. In 2009, the Company acquired reserves of 6,300 MBOE primarily in the Piceance.

• Extensions and Discoveries. In 2011, the Company had a total of 30,600 MBOE of extensions and discoveries, which were primarily due to successful drilling and completion activities in the Diatomite, McKittrick, Utah, Piceance and Permian assets. In 2010, the Company had a total of 20,019 MBOE of extensions and discoveries, which were primarily due to the successful drilling and completion activities in the Diatomite, Permian, Utah and E. Texas assets. In 2009, the Company had a total of 18,100 MBOE of extensions and discoveries, which were primarily due to the successful drilling and completion activities in the Diatomite and Piceance assets.

• Revisions to Previous Estimates. In 2011, the Company had negative revisions of 28,446 MBOE, which were primarily due to removing proved undeveloped reserves related to assets that reached aging limitations, as mandated by the SEC and negative performance revisions. Specifically, the decrease is due to a 19,632 MBOE decrease in E. Texas, a 5,779 MBOE decrease in Piceance and a 2,576 MBOE decrease in Utah. In 2010, the Company had negative revisions 3,522 MBOE, which were primarily due to negative performance revisions and the Company's future development plans. Specifically, the decrease is due to a 3,666 MBOE decrease in E. Texas, a 3,890 MBOE decrease in the Piceance, and a 840 MBOE decrease in Uinta, offset by a 971 MBOE increase in the Permian and a 3,903 MBOE increase in California. In 2009, the Company had negative revisions of 2,975 MBOE, which were primarily due to negative performance revisions. Specifically, the decrease is due to a 9,108 MBOE decrease in E. Texas, offset by a 398 MBOE increase in California and 5,735 MBOE increase in Utah and Piceance.

• Property Sales. In 2009, the Company had total reserve sales of 21,100 MBOE from sale of its DJ assets. See Note 2 to the Financial Statements.

Standardized Measure of Discounted Future Net Cash Flows

Future oil and natural gas sales are calculated applying the prices used in estimating the Company's proved oil and natural gas reserves to the year-end quantities of those reserves. Future production and development costs, which include costs related to plugging of wells, removal of facilities and equipment, and site restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved oil and natural gas reserves at the end of each year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory income tax rates to the estimated future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax bases of the properties involved. The future income tax expenses give effect to income tax deductions, credits, and allowances relating to the proved oil and natural gas reserves. All cash flow amounts, including income taxes, are discounted at 10%.

The following table presents the standardized measure of discounted future net cash flows related to proved oil and natural gas reserves:

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Future cash inflows	$	19,568,628		$	14,354,627		$	9,028,991
Future production costs	(5,226,044		)	(4,446,183		)	(3,826,832		)
Future development costs	(1,975,429		)	(1,789,001		)	(1,159,465		)
Future income tax expense	(3,770,512		)	(2,272,184		)	(969,771		)
Future net cash flows	8,596,643			5,847,259			3,072,923
10% annual discount for estimated timing of cash flows	(4,561,364		)	(3,048,103		)	(1,627,176		)
Standardized measure of discounted future net cash flows	$	4,035,279		$	2,799,156		$	1,445,747
Average price during the 12-month period: (1)
Oil ($/BOE)	$	93.72		$	69.04		$	52.06
Natural gas ($/Mcf)	4.02			4.57			3.58
BOE ($/BOE)	$	71.18		$	52.93		$	38.37

______________________________     

(1) Differences between the average benchmark prices and the average prices used in the calculation of the standardized measure are attributable to adjustments made for transportation, quality and basis differentials.

The present value (at a 10% annual discount) of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of its estimated oil and natural gas reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on prices and costs in effect on the day of estimate in accordance with the applicable accounting guidance. However, actual future net cash flows from its oil and natural gas properties will also be affected by factors such as actual prices the Company receives for oil and natural gas, the amount and timing of actual production, supply of and demand for oil and natural gas and changes in governmental regulations or taxation.

The timing of both the Company’s production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor the Company uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general.

A summary of changes in the standardized measure of discounted future net cash flows is as follows:

	Year ended December 31,
	2011			2010			2009
	(in thousands)
Standardized measure—beginning of year	$	2,799,156		$	1,445,747		$	1,135,581
Sales of oil and natural gas produced, net of production costs	(599,679		)	(406,390		)	(353,052		)
Revisions to estimates of proved reserves:
Net changes in sales prices and production costs	1,473,454			1,724,212			637,882
Revisions of previous quantity estimates	(281,765		)	(49,784		)	(33,943		)
Improved recovery	—			24,033			—
Extensions and discoveries	601,313			283,011			206,542
Change in estimated future development costs	(274,122		)	(152,096		)	(52,824		)
Purchases of reserves in place	164,383			307,205			29,348
Sales of reserves in place	—			—			(138,265		)
Development costs incurred during the period	433,660			144,086			110,200
Accretion of discount	383,418			184,917			131,745
Income taxes	(634,747		)	(593,272		)	(190,727		)
Other	(29,792		)	(112,513		)	(36,740		)
Net increase	1,236,123			1,353,409			310,166
Standardized measure—end of year	$	4,035,279		$	2,799,156		$	1,445,747

The following table presents costs incurred in oil and natural gas property acquisition, exploration, and development activities:

	Year ended December 31,
	2011		2010		2009
	(in thousands)
Property acquisitions
Proved properties	$	149,158	$	334,409	$	13,497
Unproved properties	6,632		—		—
Development	544,114		320,927		138,168
Exploration	627		2,310		209
Total(1)	$	700,531	$	657,646	$	151,874

__________________________________________

(1)The total above does not reflect $29.1 million, $28.3 million, and $30.1 million of capitalized interest incurred in 2011, 2010, and 2009, respectively.