View Filing Data

Dry hole, abandonment, impairment and exploration

625,564

20,931

5,482

2,720

TOTAL EXPENSES

718,939

1,291,633

565,310

Earnings before income taxes

259,660

(370,291)

136,492

Income tax provision (benefit)

88,121

(142,228)

53,968

Net earnings (loss)

$ 171,539

$ (228,063)

$ 82,524

Basic net earnings (loss) per share

$ 3.11

^[1],[2]

$ (4.21)

^[1],[2]

$ 1.54

Diluted net earnings (loss) per share

3.09

^[1],[2]

(4.21)

^[1],[2]

1.52

Dividends per share

$ 0.32

$ 0.31

$ 0.30

Electricity Generation

EXPENSES

Depreciation, depletion & amortization

$ 1,808

$ 1,963

$ 3,225

Oil and Natural Gas Properties, Buildings, and Equipment

EXPENSES

Depreciation, depletion & amortization

$ 225,892

$ 213,859

$ 179,432

[1]

(3)Due to the volatility of commodity prices, the estimated fair value of the Company's commodity derivative instruments is subject to fluctuations. As a result, the Company may recognize significant unrealized gains and losses (non-cash changes in fair value) on commodity derivative instruments from period to period.

[2]

(4)The sum of the individual quarterly net earnings (loss) per common share amounts may not agree with year-to-date net earnings (loss) 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 earnings (loss) per common share for each quarter in which the Company reported net earnings.

Statements of Comprehensive Earnings - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statements of Comprehensive Earnings [Abstract]
Net earnings (loss)	$ 171,539	$ (228,063)	$ 82,524
Amortization of accumulated other comprehensive loss related to de-designated hedges, net of income taxes	5,517	38,289	16,566
Other comprehensive earnings	5,517	38,289	16,566
Comprehensive earnings (loss)	$ 177,056	$ (189,774)	$ 99,090

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the economic entity, including both controlling (parent) and noncontrolling interests. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, including any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

Net of tax amount of the income statement impact of the reclassification adjustment of accumulated gain (loss) from derivative instruments designated and qualifying as the effective portion of cash flow hedges realized in net income. Also includes reclassification adjustments of an entity's share of an equity investee's deferred hedging gain (loss) realized in net income.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Reclassification Adjustments
-URI http://asc.fasb.org/extlink&oid=6522872

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=20435746&loc=d3e637-108580

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=20435746&loc=d3e689-108580

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624171-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 24
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 18, 19
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph c(3)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 31, 46
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Statements of Comprehensive Earnings Parentheticals - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statement of Comprehensive Earnings (Parentheticals) [Abstract]
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	$ 3,382	$ 23,467	$ 10,153

Tax effect of the income statement impact of the reclassification adjustment of accumulated gain (loss) from derivative instruments designated and qualifying as the effective portion of cash flow hedges realized in net income. Also includes reclassification adjustments of an entity's share of an equity investee's deferred hedging gain (loss) realized in net income.

Statements of Shareholders' Equity - USD ($) $ in Thousands	Total	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Common Class A Common Stock	Common Class B Common Stock
Stock Issued During Period, Value, Share-based Compensation, Net of Forfeitures	$ 4,402	$ 4,398			$ 4
Balances, beginning 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 based compensation expense	9,386	9,386
Income tax effect of stock option exercises	284	284
Dividends	(16,181)		(16,181)
Balances, end of period at Dec. 31, 2010	1,024,553	327,369	740,458	(43,806)	514	18
Increase (Decrease) in Shareholders' Equity
Net earnings (loss)	82,524		82,524
Amortization of accumulated other comprehensive loss related to de-designated hedges, net of income taxes	16,566			16,566
Stock Issued During Period, Value, Share-based Compensation, Net of Forfeitures	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)
Balances, end of period at Dec. 31, 2011	840,729	350,158	495,549	(5,517)	521	18
Increase (Decrease) in Shareholders' Equity
Net earnings (loss)	(228,063)		(228,063)
Amortization of accumulated other comprehensive loss related to de-designated hedges, net of income taxes	38,289			38,289
Stock Issued During Period, Value, Share-based Compensation, Net of Forfeitures	3,687	3,684			3
Stock based compensation expense	9,819	9,819
Income tax effect of stock option exercises	1,049	1,049
Dividends	(17,549)		(17,549)
Balances, end of period at Dec. 31, 2012	1,014,791	$ 364,710	649,539	0	$ 524	$ 18
Increase (Decrease) in Shareholders' Equity
Net earnings (loss)	171,539		$ 171,539
Amortization of accumulated other comprehensive loss related to de-designated hedges, net of income taxes	$ 5,517			$ 5,517

This element represents the amount of recognized equity-based compensation during the period, that is, the amount recognized as expense in the income statement (or as asset if compensation is capitalized). Alternate captions include the words "stock-based compensation".

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 35
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6415241&loc=d3e4534-113899

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5047-113901

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 20
-Section 55
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=6576910&loc=d3e11149-113907

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 20
-Section 55
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=6576910&loc=d3e11178-113907

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph A91
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 39
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Value of stock (or other type of equity) issued during the period as a result of any equity-based compensation plan other than an employee stock ownership plan (ESOP), net of stock value of such awards forfeited. Stock issued could result from the issuance of restricted stock, the exercise of stock options, stock issued under employee stock purchase plans, and/or other employee benefit plans.

Amount of stockholders' equity (deficit), net of receivables from officers, directors, owners, and affiliates of the entity, attributable to both the parent and noncontrolling interests. Amount excludes temporary equity. Alternate caption for the concept is permanent equity.

Summary of Significant Accounting Policies

Statements of Shareholders' Equity Parentheticals - $ / shares	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statements of Stockholder's Equity (Parentheticals) [Abstract]
Dividends per share	$ 0.32	$ 0.31	$ 0.30

Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
Statements of Cash Flows - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash flows from operating activities:
Net earnings (loss)	$ 171,539	$ (228,063)	$ 82,524
Depreciation, depletion and amortization	227,700	215,822	182,657
Gain on purchase	0	1,046	0
Extinguishment of debt	6,842	4,072	573
Amortization of debt issuance costs and net discount	7,031	8,243	8,481
Impairment of oil and natural gas properties	79	625,564	0
Dry hole and impairment	14,945	4,616	1,478
Derivatives	(36,135)	(29,094)	42,609
Stock-based compensation expense	9,819	9,636	9,386
Deferred income taxes	82,881	(149,279)	54,698
Gain on sale of assets	(1,782)	0	0
Other, net	(1,628)	1,420	(1,844)
Allowance for bad debt	414	0	0
Bad debt recovery	0	0	(38,508)
Change in book overdraft	(1,220)	(156)	528
Changes in operating assets and liabilities:
Accounts receivable	(6,740)	(23,526)	20,055
Inventories, prepaid expenses, and other current assets	(6,203)	(2,768)	(7,553)
Accounts payable and revenue and royalties payable	19,967	25,019	5,273
Accrued interest and other accrued liabilities	13,930	(4,561)	6,880
Net cash provided by operating activities	501,439	455,899	367,237
Cash flows from investing activities:
Exploration and development of oil and natural gas properties	(675,951)	(527,112)	(310,139)
Property acquisitions	(78,313)	(158,090)	(334,409)
Capitalized interest	(17,915)	(29,117)	(28,321)
Proceeds from sale of assets	17,307	0	0
Deposits on asset sales	(3,300)	3,300	0
Net cash used in investing activities	(758,172)	(711,019)	(672,869)
Cash flows from financing activities:
Proceeds from issuances on line of credit	0	406,600	316,000
Repayments of borrowings under line of credit	0	(411,900)	(310,700)
Early Repayment of Subordinated Debt	(200,000)	0	0
Early Repayment of Senior Debt	149,999	94,744	0
Proceeds from long-term borrowings under credit facility	1,467,200	719,700	363,000
Repayments of long-term borrowings under credit facility	(1,435,800)	(358,200)	(565,000)
Financing obligation	(417)	(380)	(346)
Debt issuance costs	(11,424)	(2,250)	(15,173)
Dividends paid	(17,549)	(16,846)	(16,181)
Proceeds from issuance of stock	0	0	224,313
Proceeds from stock option exercises	3,687	10,113	4,402
Excess income tax benefit	1,049	3,047	284
Net cash provided by (used in) financing activities	256,747	255,140	300,599
Net increase (decrease) in cash and cash equivalents	14	20	(5,033)
Cash and cash equivalents at beginning of year	298	278	5,311
Cash and cash equivalents at end of year	312	298	278
Supplemental disclosures of cash flow information:
Interest paid, net of capitalized interest	64,602	59,853	40,773
Income Taxes Paid	4,227	7,914	697
Noncash investing activities:
Accrued capital expenditures	98,020	61,098	51,095
Asset retirement obligations	18,248	7,448	3,721
Senior Notes 6.375% Due 2022
Cash flows from financing activities:
Net proceeds from Issuance long-term debt	600,000	0	0
Senior Notes 10.25 Percent Due 2014
Cash flows from financing activities:
Net proceeds from Issuance long-term debt	$ 0	$ 0	$ 300,000

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

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 2012 financial statement presentation. In the 2011 Balance Sheets, $4.8 million was reclassified from asset retirement obligations (ARO) to accrued liabilities in order to conform to current and non-current presentation of ARO in the 2012 Balance Sheets.

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, 2012 and 2011 was $14.9 million and $16.1 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.

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. Under this method, the fair value of property acquired and all costs associated with successful exploratory wells and all development wells are capitalized. Capitalized acquisition costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized exploratory drilling and development costs is based on the unit-of-production method using proved developed reserves. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells and oil and gas production costs.

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. 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 as long as 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 the development wells are productive or nonproductive.

Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Costs of seismic and other studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.

Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to earnings.

Unproved properties consist of costs to acquire undeveloped leases and to acquire unproved reserves. Costs related to acquiring undeveloped leases and unproved reserves are capitalized. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis.

Buildings and equipment are recorded at cost. Depreciation is calculated on a straight-line basis over estimated useful lives ranging from five to 30 years for buildings and improvements and three to ten 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 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 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. See Notes 8 and 10 to the Financial Statements.

Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. 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.

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. The Company routinely assess the realizability of its 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. The Company considers 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 the Company to establish deferred income tax asset valuation allowances in a future period. The Company is subject to taxation in many jurisdictions, and the calculation of its income tax liabilities involves dealing with uncertainties in the application of complex income tax laws and regulations in various taxing jurisdictions. The Company recognizes certain income tax positions that meet a more-likely-than not recognition threshold. If the Company ultimately determines that the payment of these liabilities will be unnecessary, the Company will reverse the liability and recognize an income tax benefit during the period in which the Company determines the liability no longer applies.

Derivative Instruments

The Company records all derivative instruments as either assets or liabilities at fair value, other than the derivative instruments that meet the normal purchases and sales exception. Cash flow is affected by derivatives to the extent that actual cash settlements under these contracts result in payments made to or received from derivative counterparties. Realized and unrealized (gain) loss on derivatives, net represents both the realized cash settlements with derivative counterparties and unrealized non-cash mark to market gains and losses.

Effective January 1, 2010, the Company elected to prospectively discontinue all hedge accounting, under which changes in derivative fair values were deferred in accumulated other comprehensive income (AOCL) rather than being recognized immediately in earnings. 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 does not enter into derivative instruments for speculative or trading purposes. See Notes 7 and 8 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. See Note 2 to the Financial Statements.

Asset Retirement Obligations

The Company's asset retirement obligations (AROs) relate to 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, the Company 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 production over the life of the oil and natural gas field.

Debt Issuance Costs

Debt issuance costs related to the Company’s senior subordinated notes are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the credit facility are amortized to interest expense on a straight-line basis over the borrowing term.

Prepaid Expenses and Other

The components of prepaid expenses and other are as follows:



	Year Ended December 31,
(in thousands)	2012		2011
Prepaid expenses	$	4,168	$	5,275
California carbon allowance inventories	545		—
Oil inventories	1,216		—
Materials inventories	12,943		11,356
Other inventory	193		170
Total prepaid expenses and other	$	19,065	$	16,801

Inventories

Inventories consist primarily of tubular goods and production materials and equipment. Inventories also include crude oil and California carbon allowance instruments. Inventories are carried at the lower of cost or market, with cost being determined on a weighted average cost basis.

Accrued Liabilities

The components of accrued liabilities are as follows:



	Year Ended December 31,
(in thousands)	2012		2011
Property taxes	$	13,496	$	10,430
Accrued interest	16,996		9,205
Accrued payroll	12,700		9,953
Asset retirement obligations (current portion)	4,430		4,763
Other accrued liabilities	3,529		5,478
Total accrued liabilities	$	51,151	$	39,829

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.

Credit Risk and Other Concentrations

The Company sells oil and natural gas to various types of customers, including pipelines, refineries and other oil and natural gas companies, and sells electricity to utility companies. Credit is extended based on an evaluation of the customer's financial condition and historical payment record. The future availability of a ready market for oil and natural gas depends on numerous factors outside the Company's control, none of which can be predicted with certainty. See Item 1A. Risk Factors—"Market conditions or operational impediments may hinder the Company's access to oil and natural gas markets or delay our production."

At December 31, 2012, the Company had commodity derivative contracts with nine counterparties, all of which were part of the Company's credit facility and all of which had investment-grade ratings from Moody’s and Standard & Poor. 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, 2012 was $23.2 million.

During 2012, 2011 and 2010, 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.

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, 2012, the Company has not incurred losses related to these investments.

Major Customers

The following table presents the percentages of the Company's total oil and natural gas and electricity sales to each significant purchaser for the years ended December 31, 2012, 2011 and 2010:



	Year Ended December 31,
	2012		2011		2010
Oil and natural gas:
ExxonMobil Oil Corporation	43	%	43	%	44	%
Shell Trading (US) Company	13	%	14	%	14	%
Enterprise Crude Oil LLC	9	%	8	%	4	%
HollyFrontier Corporation	9	%	8	%	9	%
Electricity:
Pacific Gas and Electric Company	54	%	59	%	55	%
Southern California Edison	46	%	41	%	45	%

Based on the current demand for oil and natural gas and the availability of other purchasers, the Company believes that, with the exception of its primary customer in Utah, the loss of any one of its major purchasers would not have a material adverse effect on its financial condition, results of operations and operating cash flows. See Item 1A. Risk Factors—"Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production."

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 $2.0 million, $2.3 million and $2.8 million for the years ended December 31, 2012, 2011 and 2010, 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 $28.6 million, $21.4 million and $16.2 million for 2012, 2011 and 2010, respectively. Costs for transporting natural gas used in electricity generation were $3.8 million, $5.0 million and $4.7 million for 2012, 2011 and 2010, 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

Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the requisite service period, which is generally the vesting period.

Earnings (Loss) 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 earnings (loss) per share is calculated by dividing earnings (loss) available to common shareholders by the weighted average shares-basic during each period. Diluted earnings (loss) per share is calculated by dividing earnings (loss) 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. No potential shares of common stock are included in the computation of any diluted per share amount when a net loss exists.

The following table shows the computation of basic and diluted net earnings per share for the years ended December 31, 2012, 2011 and 2010:



	Year Ended December 31,
(in thousands, except per share data)	2012		2011			2010
Net earnings (loss)	$	171,539	$	(228,063	)	$	82,524
Less: Earnings allocable to participating securities	885		—			1,199
Net earnings (loss) available for common shareholders	$	170,654	$	(228,063	)	$	81,325

Basic net earnings (loss) per share	$	3.11	$	(4.21	)	$	1.54
Diluted net earnings (loss) per share	$	3.09	$	(4.21	)	$	1.52

Basic weighted average shares outstanding	54,912		54,133			52,969
Add: Dilutive effects of stock options and RSUs	375		—			460
Diluted weighted average shares outstanding	55,287		54,133			53,429

Options of 0.6 million, 1.5 million and 0.7 million shares were not included in the weighted average shares-dilutive calculation for the years ended December 31, 2012, 2011 and 2010, 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.

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the production, development, exploitation and acquisition of oil and natural gas, and all of the Company's operations are conducted in the continental United States. The Company considers its gathering, processing and marketing functions as ancillary to its oil and natural gas producing activities.

Impact of Recently Issued Accounting Standard Updates

In December 2011, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2011-11, which requires that an entity disclose both gross and net information about instruments and transactions that are either eligible for offset in the balance sheet or subject to an agreement similar to a master netting agreement, including derivative instruments. ASU 2011-11 was issued in order to facilitate comparison between GAAP and IFRS financial statements by requiring enhanced disclosures, but does not change existing GAAP that permits balance sheet offsetting. This authoritative guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. 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.

Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2012

Business Combinations [Abstract]

Acquisitions and Divestitures

2012 Acquisitions

On September 12, 2012, the Company completed the acquisition of approximately 14,000 net acres contiguous to the Company's Brundage Canyon asset in the Uinta for an aggregate purchase price of $39.6 million, including usual and customary post-closing adjustments. Disclosures of purchase price allocation and also of pro forma revenues and net earnings for this acquisition are not material and have not been presented.

On April 13, 2012, the Company completed the acquisition of approximately 2,000 net acres and one well in the Wolfberry trend in the Permian for an aggregate purchase price of $14.9 million including usual and customary post-closing adjustments. Disclosures of purchase price allocation and also of pro forma revenues and net earnings for the acquisition are not material and have not been presented.

2012 Divestiture

On December 21, 2011, the Company entered into an agreement to sell its assets related to proved developed properties in Elko, Eureka and Nye Counties, Nevada (Nevada Assets), which closed on January 31, 2012, for total cash consideration of $15.6 million. The Company recorded a $1.6 million gain in conjunction with the sale. The gain was recorded in the December 31, 2012 Statements of Operations under the caption gain on sale of assets.

At December 31, 2011, the Nevada Assets were classified as held for sale and recorded in the balance sheets at $14.6 million. 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.

2011 Acquisition

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 acquisition was financed using the Company's credit facility. 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

2010 Acquisitions

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. The Company has not presented pro forma information for the properties acquired in the Permian Acquisition, as the impact of the acquisition was insignificant to the Company's Statements of Operations 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 acquisitions described above 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.

Debt

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Debt

Senior Secured Revolving Credit Facility

As of December 31, 2012, the Company's credit facility, which matures on May 13, 2016, had a borrowing base of $1.4 billion, subject to lender commitments. On April 13, 2012, as part of the semi-annual borrowing base redetermination process, the Company entered into a fourth amendment to its credit facility. Among other things, the fourth amendment increased the borrowing base to $1.4 billion. At December 31, 2012, lender commitments under the facility were $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.

As of December 31, 2012, outstanding borrowings under the facility were $562.9 million and $23.2 million in outstanding letters of credit, leaving $613.9 million in borrowing capacity available under the credit facility. As of December 31, 2011, there were $531.5 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 semi-annual redetermination in October 2012 did not result in any changes to the borrowing base, lender commitments, or other terms of the credit facility.

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 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 credit facility. The Company is currently in compliance with all financial covenants and has 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, which has a borrowing capacity of up to $40.0 million for a maximum of 30 days, has been unavailable to the Company since the fourth quarter of 2011.

6.375% Senior Notes Due 2022

On March 9, 2012, the Company issued $600 million aggregate principal amount of its 6.375% Senior notes due 2022 (2022 Notes) for net proceeds of $589.5 million. Interest is payable in arrears semi-annually in March and September of each year. The 2022 Notes are senior unsecured obligations of the Company, which rank effectively junior in right of payment to all of the Company's existing and any future secured debt, to the extent of the value of the collateral securing that debt, equally in right of payment with the Company's 10.25% Senior notes due 2014 (2014 Notes) and 2020 Notes, and senior in right of payment to any of the Company's future subordinated debt.

On and after March 15, 2017, the Company may redeem all or, from time to time, a part of the 2022 Notes upon not less than 30 nor more than 60 days’ notice, at the following redemption prices (expressed as a percentage of principal amount of notes to be redeemed), plus accrued and unpaid interest, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the 12-month period beginning on March 15 of the years indicated below:



2017	103.188	%
2018	102.125	%
2019	101.063	%
2020 and thereafter	100.000	%

In addition, before March 15, 2015, the Company may, at its option, on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2022 Notes with the net cash proceeds of certain equity offerings and if certain conditions are met as described in the indenture governing the 2022 Notes, at a redemption price of 106.375% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. At any time prior to March 15, 2017, the Company may also redeem all or part of the 2022 Notes at a redemption price equal to 100% of the principal amount of the notes redeemed plus a “make-whole” premium described in the indenture, plus accrued and unpaid interest, if any, to the redemption date.

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. 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, with the remainder used to reduce outstanding borrowings under the credit facility. The 2020 Notes are senior unsecured obligations of the Company, which rank effectively junior in right of payment to all of the Company's existing and any future secured debt, to the extent of the value of the collateral securing that debt, equally in right of payment with the 2014 Notes, 2022 Notes and any future senior unsecured debt, and senior in right of payment to any of the Company's 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 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 $140.0 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 $6.0 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 in right of payment 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, 2022 Notes and any future senior unsecured debt, and rank senior in right of payment to any of the Company's 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.

On April 3, 2012, the Company repurchased $150.0 million aggregate principal amount of its 2014 Notes for an aggregate purchase price of $181.5 million, including accrued and unpaid interest. A related loss of $30.9 million was recorded in extinguishment of debt, consisting of $26.4 million for premiums paid over par and $4.5 million for write-offs of net discounts and debt issuance costs. The 2014 Notes were repurchased using net proceeds from the issuance of the Company's 2022 Notes. Following the consummation of the tender offer on April 3, 2012, $205.3 million aggregate principal amount of 2014 Notes was outstanding.

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

On April 9, 2012, the Company redeemed all $200 million aggregate principal amount of its 2016 Notes for an aggregate purchase price of $215.5 million, including accrued and unpaid interest. A related loss of $10.6 million was recorded in the second quarter of 2012 consisting of $8.3 million for premiums paid over par and $2.3 million for write-offs of debt issuance costs. The 2016 Notes were redeemed using net proceeds from the issuance of the Company's 2022 Notes.

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

Income Taxes

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Income Taxes

The provision (benefit) for income taxes consists of the following:



	Year Ended December 31,
(in thousands)	2012		2011			2010
Current:
Federal	$	286	$	4,115		$	363
State	4,954		2,936			1,870
	5,240		7,051			2,233
Deferred:
Federal	80,083		(125,261		)	47,709
State	2,798		(24,018		)	4,026
	82,881		(149,279		)	51,735
Total	$	88,121	$	(142,228	)	$	53,968

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



	Year Ended December 31,
(in thousands)	2012			2011
Deferred income tax assets:
Federal benefit of state income taxes	$	(239	)	$	(2,479	)
Credit carryforwards	36,028			29,186
Equity and deferred compensation	15,139			12,620
Derivatives	—			8,669
Net operating loss	412			412
Bad debt expense	163			—
Other, net	610			980
Valuation allowance	(1,201		)	(403		)
	50,912			48,985
Deferred income tax liabilities:
Depreciation and depletion	(298,659		)	(220,656		)
Derivatives	(8,477		)	—
	(307,136		)	(220,656		)

Net deferred income tax liabilities	$	(256,224	)	$	(171,671	)

At December 31, 2012, the Company's net deferred income tax assets and liabilities were recorded as a net current liability of $0.8 million and a long-term liability of $255.5 million. 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.

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



	Year Ended December 31,
	2012		2011		2010
Income tax computed at statutory federal rate	35	%	35	%	35	%
State income taxes, net of federal benefit	3		3		4
Deferred state rate impact	(1	)	—		(1	)
Research and development credits	(3	)	—		—
Net impact to uncertain income tax positions	—		1		—
Other	—		(1	)	2
Effective income tax rate	34	%	38	%	40	%

As of December 31, 2012, the Company had approximately $10.6 million of federal and $12.5 million of state (California) enhanced oil recovery (EOR) tax credit carryforwards available to reduce future income taxes. The EOR credits will begin to expire, if unused, in 2024 and 2017 for federal and California purposes, respectively. The Company has federal research and development credits of $10.4 million which will begin to expire, if unused, in 2024 and California research and development credits of $18.3 million that do not expire. The Company has federal alternative minimum income tax (AMT) credit carryforwards of $0.8 million and California AMT credits of $0.6 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 $3.0 million which will begin to expire in 2018 if not used. As of December 31, 2012 and 2011, valuation allowances of $1.2 million and $0.4 million, respectively, have been recorded against these enterprise zone credits to reduce the net deferred tax asset to an amount that is more likely than not to be recognized. As the gross amount of Colorado enterprise zone credits may be larger than the future projected Colorado income, some of the credits that are currently being carried forward may expire.

In 2012, the Company decreased the unrecognized tax benefits by $0.8 million due to the closing of certain federal and state income tax years, which resulted in a reduction of the effective income tax rate. Also in 2012, the Company increased the unrecognized tax benefits by $20.5 million for positions taken on prior returns, of portion of which increased the effective income tax rate. As of December 31, 2012, the Company had a gross liability for uncertain income tax benefits of $17.5 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, 2012 could decrease by a maximum of $6.7 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 $0.4 million and $0.8 million of interest related to its uncertain income tax positions as of December 31, 2012 and 2011, respectively. The Company recognized in earnings a benefit of $0.4 million and expenses of $0.5 million and $0.1 million related to interest on uncertain income tax positions for the years ended December 31, 2012, 2011 and 2010, respectively.

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



	Year Ended December 31,
(in millions)	2012			2011			2010
Unrecognized income tax benefits at January 1	$	2.9		$	5.2		$	6.1
Increases (decreases) for positions taken in a prior year	20.5			—			(0.8		)
Decreases for settlements with taxing authorities	—			(2.3		)	—
Decreases for lapses in the applicable statute of limitations	(0.8		)	—			(0.1		)
Unrecognized income tax benefits at December 31	$	22.6		$	2.9		$	5.2

As of December 31, 2012, 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	2009 - 2011
California	2007 - 2011
Colorado	2007 - 2011
Texas	2008 - 2011
Utah	2007 - 2011

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

Shareholder's Equity	12 Months Ended
Shareholder's Equity	Dec. 31, 2012
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 2012 was $0.32 per share. The Company's dividend is payable quarterly in March, June, September and December. Dividend payments are limited by covenants in the credit facility to the greater of $35 million or 75% of net earnings for any four quarter period. In addition, the indentures governing the Company's senior notes contain provisions potentially restricting the Company's ability to declare dividends if certain situations arise; provided that, notwithstanding such restrictions, the Company may declare dividends up to $0.36 per share annually (so long as such distributions do not exceed $20 million annually) in the event that the Company is not in default under the indentures and up to $10 million in the event that the Company is in a non-payment default under the indentures.

The entire disclosure for shareholders' equity, comprised of portions attributable to the parent entity and noncontrolling interest, if any, including other comprehensive income (as applicable). Including, but not limited to: (1) balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings; (2) accumulated balance for each classification of other comprehensive income and total amount of comprehensive income; (3) amount and nature of changes in separate accounts, including the number of shares authorized and outstanding, number of shares issued upon exercise and conversion, and for other comprehensive income, the adjustments for reclassifications to net income; (4) rights and privileges of each class of stock authorized; (5) basis of treasury stock, if other than cost, and amounts paid and accounting treatment for treasury stock purchased significantly in excess of market; (6) dividends paid or payable per share and in the aggregate for each class of stock for each period presented; (7) dividend restrictions and accumulated preferred dividends in arrears (in aggregate and per share amount); (8) retained earnings appropriations or restrictions, such as dividend restrictions; (9) impact of change in accounting principle, initial adoption of new accounting principle and correction of an error in previously issued financial statements; (10) shares held in trust for Employee Stock Ownership Plan (ESOP); (11) deferred compensation related to issuance of capital stock; (12) note received for issuance of stock; (13) unamortized discount on shares; (14) description, terms, and number of warrants or rights outstanding; (15) shares under subscription and subscription receivables, effective date of new retained earnings after quasi-reorganization and deficit eliminated by quasi-reorganization and, for a period of at least ten years after the effective date, the point in time from which the new retained dates; and (16) retroactive effective of subsequent change in capital structure.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(d),(e))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21484-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 310
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SAB TOPIC 4.E)
-URI http://asc.fasb.org/extlink&oid=6228006&loc=d3e74512-122707

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21488-112644

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.29-31)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 4
-Subparagraph (SAB TOPIC 4.C)
-URI http://asc.fasb.org/extlink&oid=6959260&loc=d3e187143-122770

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=6959260&loc=d3e187085-122770

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6405834&loc=d3e23285-112656

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Preferred Stock
-URI http://asc.fasb.org/extlink&oid=6521494

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21463-112644

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21564-112644

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 43
-Section B
-Paragraph 7, 11A
-Chapter 1
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph d
-Article 4

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 29, 30, 31
-Article 5

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section E

Reference 20: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Article 4

Reference 21: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section C

Reference 22: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 129
-Paragraph 2, 3, 4, 5, 6, 7, 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 23: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity Incentive Compensation Plans and Other Benefit Plans

12 Months Ended

Dec. 31, 2012

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 (RSUs) 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 RSUs granted to non-employee directors have historically vested immediately. Options granted under the 2010 Plan have a term of ten years. As of December 31, 2012, the Company had 426,055 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, 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 ten years. As of December 31, 2012, the Company had 173,915 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 $9.3 million, $9.0 million and $8.3 million in 2012, 2011 and 2010, respectively.

Stock Options

The following table summarizes stock option activity for the years ended December 31, 2012, 2011 and 2010:



	Number of Shares		Weighted Average Exercise Price		Aggregate Intrinsic Value (in thousands)(1)		Weighted Average Remaining Contractual Term (Years)
Outstanding at January 1, 2010	2,276,020		$	25.36
Granted	—		—
Exercised	(227,100	)	19.40		$	3,570
Canceled/expired	(31,695	)	35.51
Outstanding at December 31, 2010	2,017,225		25.87
Granted	89,865		48.50
Exercised	(579,636	)	17.47		$	17,746
Canceled/expired	(6,765	)	45.92
Outstanding at December 31, 2011	1,520,689		30.32
Granted	82,262		53.02
Exercised	(215,359	)	17.12		$	7,194
Canceled/expired	—		—
Outstanding at December 31, 2012	1,387,592		$	33.71	$	4,681	4.08
Vested and expected to vest at December 31, 2012	1,383,702		$	33.66	$	4,681	4.07
Exercisable at December 31, 2012	1,239,733		$	31.65	$	4,681	3.53

_______________________________________


(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 2012, 82,262 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:



	2012		2011
Expected volatility	50.00	%	45.00	%
Risk-free rate	0.95	%	2.54	%
Dividend yield	0.57	%	0.62	%
Expected term (in years)	5.2		6.0

The following table summarizes information about stock options at December 31, 2012:



	Stock Options Outstanding				Stock Options Exercisable
Range of Exercise Prices	Number of Options	Weighted Average Remaining Contractual Term (Years)	Weighted Average Exercise Price		Number of Options	Weighted Average Remaining Contractual Term (Years)	Weighted Average Exercise Price
$9.61-$9.97	43,850	0.93	$	9.89	43,850	0.93	$	9.89
$21.58-$21.77	253,000	1.90	21.60		253,000	1.90	21.60
$30.65-$32.57	639,500	3.51	31.70		639,500	3.51	31.70
$38.00-$53.02	451,242	6.43	45.66		303,383	5.31	43.05
	1,387,592	4.08	$	33.71	1,239,733	3.53	$	31.65

As of December 31, 2012, there was $2.5 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, 2012, 2011 and 2010:



	RSUs		Weighted Average Intrinsic Value at Grant Date		Vest Date Fair Value (in thousands)
Outstanding at January 1, 2010	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
Granted	164,112		50.60
Issued	(79,068	)	33.10		$	3,401
Canceled/expired	(18,189	)	41.50
Outstanding at December 31, 2012(1)(2)	981,877		$	26.72

__________________________________


(1)	The balance outstanding includes RSUs granted to non-employee directors that are 100% vested at the date of grant but are subject to deferral elections delaying the date on which the corresponding shares of Common Stock are issued. For the years ended December 31, 2012, 2011 and 2010, 43,554, 30,544 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, 2012, 2011 and 2010, 614,996, 483,908 and 289,335 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, 2012, there was $11.1 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, 2012, 2011 and 2010:



	Performance Share Awards		Weighted Average Grant Date Fair Value		Vest Date Fair Value (in thousands)
Outstanding on January 1, 2010	—		$	—
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
Granted	59,738		63.69
Issued	—		—		$	—
Canceled/expired	—		—
Outstanding at December 31, 2012	222,587		$	45.79

In March 2012, 59,738 RSUs that are subject to performance metrics and a three-year service condition (performance shares) were granted to executive officers and certain other officers. The vesting of the performance share awards is contingent upon satisfying certain performance criteria. No performance shares will vest unless, from January 1, 2012 to December 31, 2014, the Company maintains an interest coverage ratio of at least 2.5 to 1.0, achieves a defined total shareholder return as compared to the Company's defined peer group and achieves a defined level of compounded annual production growth as measured by average annual barrels of oil equivalent per day (excluding acquisitions and divestitures). If such thresholds are met, the number of performance shares that vest is based on the excess total shareholder return and compounded annual production growth over the thresholds.

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:



	2012		2011
Number of simulations	100,000		100,000
Expected volatility	50	%	44	%
Risk-free rate	0.42	%	1.15	%

The total grant date fair value of the market-based portion of the performance share awards issued in 2012 and 2011, as determined by the Monte Carlo valuation model, was $1.3 million and $1.1 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, 2012, there was $2.1 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, 2012, 2011 and 2010 were 12,797, 13,647 and 38,462, 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, 2012, 2011 and 2010 were $2.1 million, $1.8 million and $1.5 million, respectively. Employees are eligible to participate in the 401(k) Plan on their date of hire. Approximately 94% of the Company's employees participated in the 401(k) Plan in 2012.

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 50
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6406099&loc=d3e25284-112666

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 40
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6418621&loc=d3e17540-113929

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5070-113901

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5047-113901

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5444-113901

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 14

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 93-6
-Paragraph 53
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

12 Months Ended

Dec. 31, 2012

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 historically 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. During the second quarter of 2012, the Company began entering into derivative contracts to fix the floor and ceiling prices paid for a portion of its natural gas consumption. The Company periodically enters into interest rate derivative contracts to protect against changes in interest rates on its floating rate debt. The amount of commodity derivatives that the Company enters into depend on various factors, including its view of future crude oil and natural gas prices, the Company's future financial commitments, as well as considerations of other factors.

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

As of December 31, 2012, the Company had commodity derivatives associated with the following volumes:



	2013	2014	2015
Oil Sales (Bbl/D):	18,800	7,500	3,000
Natural Gas Purchases (MMBtu/D):	10,000	—	—

In March 2012, the Company terminated certain of its natural gas derivative instruments, which were associated with a total of 15,000 MMBtu/D for the remainder of 2012. The termination resulted in a net loss of $1.9 million, including cash settlements and non-cash fair value losses, and was recorded in the Statements of Operations under the caption realized and unrealized (gain) loss on derivatives, net.

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 net loss of $1.9 million, including cash settlements and non-cash fair value gains, and was recorded in the Statement of Operations under the caption realized and unrealized (gain) loss on derivatives, net.

Based on future strip pricing as of December 31, 2012, the Company would receive payments under existing derivative contracts of $11.8 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 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, 2012, the entire balance of AOCL had been reclassified into earnings. 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. During the years ended December 31, 2012 and December 31, 2011, $8.9 million ($5.5 million, net of income tax) and $61.8 million ($38.3 million, net of income tax), respectively, of non-cash amortization of AOCL related to discontinuing hedge accounting was reclassified from AOCL into earnings.

The following tables detail the location and the fair value amounts of derivatives recorded on the Company's Balance Sheets:



	December 31, 2012
	Derivative Assets			Derivative Liabilities
(in millions)	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Current:
Commodity	Derivative assets	$	16.4	Derivative liabilities	$	2.8
Long-term:
Commodity	Derivative assets	10.9		Derivative liabilities	1.2
Total derivatives		$	27.3		$	4.0



	December 31, 2011
	Derivative Assets			Derivative Liabilities
(in millions)	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Current:
Commodity	Derivative assets	$	23.4	Derivative liabilities	$	37.7
Long-term:
Commodity	Derivative assets	10.5		Derivative liabilities	19.0
Total derivatives		$	33.9		$	56.7

The table below summarizes 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,
Description of (Gain) Loss	Location of (Gain) Loss Recognized in Earnings	2012			2011			2010
Commodity
Loss reclassified from AOCL into earnings (amortization of frozen amounts)	Oil and natural gas sales	$	10.7		$	60.9		$	18.4
(Gain) loss recognized in earnings (cash settlements and mark-to-market movements)	Realized and unrealized (gain) loss on derivatives, net	(64.6		)	(13.9		)	23.2
Interest rate
(Gain) loss reclassified from AOCL into earnings (amortization of frozen amounts)	Interest	$	(1.8	)	$	0.8		$	8.3
Loss recognized in earnings (cash settlements and mark-to-market movements)	Realized and unrealized (gain) loss on derivatives, net	—			—			8.6

Contingent Features in Derivative Instruments

None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s derivative contracts are high credit-quality financial institutions that 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 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, 2012, the Company was in a net asset position with all of its counterparties. As of December 31, 2012, the Company's largest two counterparties accounted for 74% of the value of its total derivative positions.

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6441202&loc=d3e80720-113993

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624171-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624163-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41620-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4D
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624177-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5579240-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7668309&loc=d3e80784-113994

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41641-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5579245-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4H
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624258-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4K
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5708775-113959

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=7668309&loc=d3e80748-113994

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41635-113959

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5708773-113959

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5618551-113959

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5580258-113959

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41638-113959

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4E
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624181-113959

Reference 20: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 21: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 45
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 22: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Fair Value Measurement

12 Months Ended

Dec. 31, 2012

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 Company recognizes transfers between levels at the end of the reporting period for which the transfer has occurred.

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.

Liabilities Measured at Fair Value on a Recurring Basis

The following table presents information about the Company's financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 and 2011, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values:



(in millions)	Total			Level 1		Level 2			Level 3
Commodity derivatives asset (liability), net
December 31, 2012	$	23.2		$	—	$	23.2		$	—
December 31, 2011	(22.7		)	—		(22.7		)	—

Changes in Level 3 Fair Value Measurements

The table below includes a rollforward of the Balance Sheet amounts (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, 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)	2012		2011			2010
Fair value liability, beginning of period	$	—	$	101.8		$	26.0
Transfers out of Level 3(1)	—		(101.8		)	—
Realized and unrealized loss included in earnings	—		—			37.4
Settlements	—		—			38.4
Fair value liability, end of period	$	—	$	—		$	101.8

Total unrealized loss included in earnings related to financial assets and liabilities still on the Balance Sheets	$	—	$	—		$	75.8

___________________________


(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.

For further discussion related to the Company's derivatives, see Note 7 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 following table presents fair value information about the Company's financial instruments:



December 31, 2012	Carrying Amount		Estimated Fair Value
(in millions)			Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—
Senior secured revolving credit facility(1)	563		—		563		—		563
10.25% Senior notes due 2014(2)	205		229		—		—		229
6.75% Senior notes due 2020	300		323		—		—		323
6.375% Senior notes due 2022	600		627		—		—		627
	$	1,668	$	1,179	$	563	$	—	$	1,742

________________________________

(1)

The Company's credit facility can be repaid at any time without penalty. Interest is generally fixed for 30-day increments at the prime rate or LIBOR plus a stipulated margin for the amount utilized and at a stipulated percentage as a commitment fee for the portion not utilized. The carrying amount of the credit facility approximated fair value due to the short-term maturities of the borrowings and because the borrowings bear interest at variable market rates.


(2)	Carrying amount does not include unamortized discount of $2.3 million.



	December 31, 2011
(in millions)	Carrying Amount		Estimated Fair Value
Senior secured revolving credit facility(1)	$	532	$	532
8.25% Senior subordinated notes due 2016	200		209
10.25% Senior notes due 2014(2)	355		402
6.75% Senior notes due 2020	300		302
	$	1,387	$	1,445

__________________________________

(1)


(2)	Carrying amount does not include unamortized discount of $6.6 million.

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.

The following table presents information about the Company's non-financial assets measured at fair value on a non-recurring basis as of December 31, 2011 and indicates 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

See Notes 2 and 10 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.

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7578670&loc=d3e19207-110258

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14172-108612

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 21
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13537-108611

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14064-108612

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 16
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13504-108611

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13433-108611

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15B
-Subparagraph a, b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44A, 44B
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 17-22, 27, 28
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15A
-Subparagraph a-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15C, 15D
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32, 33, 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 3, 10, 14, 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

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 that 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 four years. For the years ended December 31, 2012, 2011 and 2010, rent expense with respect to these lease commitments was $3.0 million, $2.6 million and $2.6 million, respectively. The Company currently has seven drilling rigs under contracts that require minimum payments for the full contract term or penalties upon early termination. All of these contracts expire during 2013. 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, 2012:



(in millions)	Total		2013		2014		2015		2016		2017		Thereafter
Operating leases(1)	$	18.0	$	5.1	$	5.3	$	3.6	$	2.9	$	1.1	$	—
Drilling rig commitments(2)	9.4		9.4		—		—		—		—		—
Other commitments(3)	23.5		16.2		2.9		2.3		2.1		—		—
Firm natural gas transportation contracts(4)	245.1		31.0		33.7		33.4		33.5		33.4		80.1
Total	$	296.0	$	61.7	$	41.9	$	39.3	$	38.5	$	34.5	$	80.1

___________________________________


(1)	Includes operating leases related to office facilities, vehicles, rail cars 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, California carbon allowance forward purchase contracts and equipment rentals.


(4)	The Company enters into certain firm commitments to transport natural gas production to market and to transport natural gas for use in 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.

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 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 4,420 Bbl/D in 2012.

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, 2012, 2011 and 2010 the Company incurred $3.2 million, $5.3 million and $6.7 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 $12.0 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

Department of the Interior Notice of Proposed Debarment. On June 14, 2012, the Company received a Notice of Proposed Debarment issued by the United States Department of the Interior (DOI). Pursuant to the notice, the DOI's Office of the Inspector General is proposing to debar the Company from participation in certain federal contracts and assistance activities, including oil and natural gas leases, for a period of three years. The basis for the proposed debarment relates to the Company's purported noncompliance with Bureau of Land Management (BLM) regulations relating to the operation of certain equipment, and the submission of related site facility diagrams, in its Uinta operations. In 2011, the Company entered into a settlement agreement with the BLM and paid a $2.1 million civil penalty relating to the matter. The Company intends to contest the proposed debarment and believes the matter is without merit; nevertheless, the Company is currently engaged in discussions with the DOI to resolve the matter administratively.

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, paid the $100,000 in July 2011 and paid the $73,000 to fund the public project in the third quarter of 2012, settling its obligation under the COGCC order.

Royalty Payments. Certain of the Company's royalty payment calculations are being disputed. On August 1, 2012, a federal court entered a judgment holding that the Company had inappropriately deducted certain post-wellhead deductions from royalty payments. On October 31, 2012, the Company paid the judgment to the royalty owner. The Company's share of the judgment amount was approximately $4.1 million, inclusive of statutory interest, of which approximately $1.3 million was recorded in the first quarter of 2011 under the caption operating costs—oil and natural gas production. The Company recorded an additional $2.1 million in operating costs—oil and natural gas production and $0.7 million in interest expense during the remainder of 2012 in conjunction with the verdict. As of December 31, 2012, the Company may be required to pay amounts of up to approximately $3.9 million with respect to other royalty disputes.

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.

The entire disclosure for commitments and contingencies.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 460
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6398077&loc=d3e12565-110249

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14435-108349

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.25)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 440
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6394976&loc=d3e25287-109308

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9, 10, 11, 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Oil and Gas Properties, Buildings and Equipment [Abstract]

Oil and Gas Properties, Buildings and Equipment

12 Months Ended

Dec. 31, 2012

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)	2012			2011
Oil and natural gas:
Proved properties(1)	$	4,060,106		$	3,257,321
Unproved properties(2)	236,626			228,486
	4,296,732			3,485,807
Less accumulated depreciation, depletion and amortization	(1,180,298		)	(962,154		)
	3,116,434			2,523,653
Commercial and other:
Machinery, drilling rigs and equipment	18,131			22,509
Buildings and improvements	10,110			6,894
Vehicles	9,167			7,806
	37,408			37,209
Less accumulated depreciation	(25,340		)	(29,469		)
	12,068			7,740
	$	3,128,502		$	2,531,393

________________________________________


(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, 2012, unproved properties included $25.2 million of acquisition costs for unevaluated properties. The Company assesses these properties annually and recorded impairments of $0.1 million, $0.6 million and $0.0 million for the years ended December 31, 2012, 2011 and 2010, 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 carrying values may not be recoverable. During the years ended December 31, 2012, 2011 and 2010, the Company recorded impairments of oil and natural gas properties of $0.1 million, $625.6 million and $0.0 million, respectively.

In the fourth quarter of 2011, the Company recorded a non-cash impairment of $625.0 million related to 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.

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

Dry Hole, Abandonment and Impairment

The Company recorded dry hole, abandonment and impairment charges of $19.0 million, $5.2 million and $1.5 million in 2012, 2011 and 2010, respectively. In 2012, the Company recorded dry hole expense of $11.9 million related to its four appraisal wells in Borden county, whose results were inconclusive for commercial quantities of oil, and $2.8 million related to mechanical failure on one well near Lake Canyon, which was abandoned in favor of drilling a nearby replacement well. The Company also recorded approximately $4.1 million in 2012 related to plugging and abandonment activities.

In 2011, the Company recorded an impairment of its drilling rigs of $4.3 million. In the fourth quarter of 2011, the Company decided to sell 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. All three of the Company's drilling rigs were sold in the third quarter of 2012 for $1.8 million, which, less costs to sell of $0.2 million, resulted in a gain of $0.2 million.

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

During 2012, the Company capitalized interest on its Permian asset, as development activities were ongoing. 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. 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.

Asset Retirement Obligation (ARO)

12 Months Ended

Dec. 31, 2012

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)	2012			2011
Beginning balance at January 1	$	64,019		$	53,443
Liabilities incurred	7,249			2,983
Liabilities settled	(3,325		)	(1,803		)
Liabilities assumed	2,651			119
Disposition of assets	(705		)	—
Accretion expense	5,858			4,812
Revisions in estimated cash flows	10,999			4,465
Ending balance at December 31(1)	$	86,746		$	64,019

____________________


(1)	The asset retirement obligation related to the Nevada Assets, which were held for sale as of December 31, 2011 and sold effective January 31, 2012, 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 2 to the Financial Statements.

AROs reflects 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.

Subsequent Event Subsequent Event	12 Months Ended
Subsequent Event Subsequent Event	Dec. 31, 2012
Subsequent Events [Abstract]
Subsequent Events	12. Subsequent Event On February 20, 2013, the Company, Linn Energy, LLC (Linn), LinnCo, LLC (LinnCo), Linn Acquisition Company, LLC, a direct wholly owned subsidiary of LinnCo (LinnCo Merger Sub), Bacchus HoldCo, Inc., a direct wholly owned subsidiary of the Company (HoldCo), and Bacchus Merger Sub, Inc., a direct wholly owned subsidiary of HoldCo (Bacchus Merger Sub), entered into a definitive Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which LinnCo agreed to acquire the Company in an all-stock transaction in which the Company's stockholders would receive 1.25 shares representing limited liability company interests in LinnCo (LinnCo Shares) for each share of the Company's common stock. The transaction will occur through multiple steps. First, the Company will engage in a holding company merger (the HoldCo Merger) involving HoldCo and Bacchus Merger Sub. In the HoldCo Merger, Bacchus Merger Sub will merge with and into the Company, with the Company surviving as a wholly owned subsidiary of HoldCo, and each issued and outstanding share of the Company's Class A common stock and Class B common stock will convert into the right to receive one equivalent share of Class A common stock and one equivalent share of Class B common stock, respectively, of HoldCo. Second, promptly after the HoldCo Merger, the Company will be converted into a limited liability company. Third, promptly following such conversion, HoldCo will be merged with and into LinnCo Merger Sub, with LinnCo Merger Sub surviving as the surviving company (the LinnCo Merger). In the LinnCo Merger, each share of Holdco's Class A common stock and each share of Holdco's Class B common stock will be converted into 1.25 LinnCo Shares. Finally, promptly following the LinnCo Merger, LinnCo will contribute all of the outstanding equity interests in LinnCo Merger Sub (and therefore also its indirect ownership interest in the Company) to Linn (the “Contribution”) in exchange for the issuance to LinnCo (the “Issuance”) of newly issued Linn common units. The number of Linn common units to be issued to LinnCo in the Issuance will be equal to the greater of (i) the aggregate number of LinnCo Shares issued in the LinnCo Merger and (ii) the number of Linn common units required to cause LinnCo to own no less than one-third of all of the outstanding Linn common units following the Contribution. In addition, for three years following the closing, Linn will pay to LinnCo additional cash distributions in the amount of $6 million per year. The closing of the transactions is subject to customary closing conditions, including approval of the Merger Agreement and the transactions contemplated thereby by the stockholders of the Company and the holders of the shares of LinnCo and Linn, receipt of certain opinions by the parties with respect to the tax-free nature of the transactions, and other customary conditions such as expiration of the waiting period under the Hart-Scott-Rodino Act.

Supplemental Information about Oil & Gas Producing Activities (Unaudited)

12 Months Ended

Dec. 31, 2012

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, 2012, 2011 and 2010, 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).



	2012						2011						2010
	Oil MBOE		Natural Gas MMcf		MBOE		Oil MBOE		Natural Gas MMcf		MBOE		Oil MBOE		Natural Gas MMcf		MBOE
Total proved reserves:
Beginning of year	185,880		534,279		274,926		166,181		630,192		271,213		129,940		632,178		235,303
Revision of previous estimates	12,145		(205,845	)	(22,162	)	(4,054	)	(146,349	)	(28,446	)	4,288		(46,860	)	(3,522	)
Improved recovery	—		—		—		—		—		—		1,700		—		1,700
Extensions and discoveries	8,459		100,129		25,148		19,601		65,992		30,600		12,774		43,469		20,019
Property sales	(556	)	—		(556	)	—		—		—		—		—		—
Production	(10,024	)	(19,784	)	(13,321	)	(9,041	)	(23,907	)	(13,025	)	(7,925	)	(23,989	)	(11,923	)
Purchase of reserves in place	8,304		16,740		11,094		13,193		8,351		14,584		25,404		25,394		29,636
End of year	204,208		425,519		275,129		185,880		534,279		274,926		166,181		630,192		271,213

Proved developed reserves	118,937		187,668		150,216		107,849		221,606		144,783		88,917		268,566		133,678
Proved undeveloped reserves	85,271		237,851		124,913		78,031		312,673		130,143		77,264		361,626		137,535
Total proved reserves	204,208		425,519		275,129		185,880		534,279		274,926		166,181		630,192		271,213

Notable changes in proved reserves for the years ended December 31, 2012, 2011 and 2010 included:


•	Purchase of Reserves in Place. In 2012, the Company acquired reserves of 11,094 MBOE primarily in Utah and the Permian. In 2011 and 2010, the Company acquired reserves of 14,584 MBOE and 29,636 MBOE primarily in the Wolfberry trend in the Permian. See Note 2 to the Financial Statements.

•

Extensions and Discoveries. In 2012, the Company had a total of 25,148 MBOE of extensions and discoveries, which were primarily due to successful drilling in Utah and improved performance in the Piceance. 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.

•

Revisions to Previous Estimates. In 2012, the Company had negative revisions of 22,162 MBOE, which were primarily in Piceance and E. Texas due to the SEC's five-year rule and pricing, offset by positive revisions due to development drilling in Diatomite, McKittrick, and the Permian. 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 of 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.


•	Property Sales. In 2012, the Company had total reserve sales of 556 MBOE from sale of its Nevada 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,
(in thousands)	2012			2011			2010
Future cash inflows	$	19,738,729		$	19,568,628		$	14,354,627
Future production costs	(5,884,891		)	(5,226,044		)	(4,446,183		)
Future development costs	(2,164,780		)	(1,975,429		)	(1,789,001		)
Future income tax expense	(3,344,024		)	(3,770,512		)	(2,272,184		)
Future net cash flows	8,345,034			8,596,643			5,847,259
10% annual discount for estimated timing of cash flows	(4,511,619		)	(4,561,364		)	(3,048,103		)
Standardized measure of discounted future net cash flows	$	3,833,415		$	4,035,279		$	2,799,156
Average price during the 12-month period:(1)
Oil ($/BOE)	$	90.66		$	93.72		$	69.04
Natural gas ($/Mcf)	2.88			4.02			4.57
BOE ($/BOE)	$	71.74		$	71.18		$	52.93

______________________________


(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,
(in thousands)	2012			2011			2010
Standardized measure—beginning of year	$	4,035,279		$	2,799,156		$	1,445,747
Sales of oil and natural gas produced, net of production costs	(625,707		)	(599,679		)	(406,390		)
Revisions to estimates of proved reserves:
Net changes in sales prices and production costs	(786,022		)	1,473,454			1,724,212
Revisions of previous quantity estimates	743			(281,765		)	(49,784		)
Improved recovery	—			—			24,033
Extensions and discoveries	124,466			601,313			283,011
Change in estimated future development costs	(331,498		)	(274,122		)	(152,096		)
Purchases of reserves in place	114,094			164,383			307,205
Sales of reserves in place	(15,283		)	—			—
Development costs incurred during the period	497,036			433,660			144,086
Accretion of discount	570,505			383,418			184,917
Income taxes	323,128			(634,747		)	(593,272		)
Other	(73,326		)	(29,792		)	(112,513		)
Net (decrease) increase	(201,864		)	1,236,123			1,353,409
Standardized measure—end of year	$	3,833,415		$	4,035,279		$	2,799,156

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



	Year ended December 31,
(in thousands)	2012		2011		2010
Property acquisitions
Proved properties	$	70,700	$	149,158	$	334,409
Unproved properties	10,686		6,632		—
Development	714,343		544,114		320,927
Exploration	16,405		627		2,310
Total(1)	$	812,134	$	700,531	$	657,646

__________________________________________

(1)The total above does not reflect $17.9 million, $29.1 million and $28.3 million of capitalized interest incurred in 2012, 2011 and 2010, respectively.

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data (Unaudited)



	Operating Revenues		Net Earnings (Loss)			Basic Net Earnings (Loss) Per Share(3)(4)			Diluted Net Earnings (Loss) Per Share(3)(4)
2012
First Quarter	$	241,492	$	33,898		$	0.62		$	0.61
Second Quarter	229,221		81,016			1.47			1.46
Third Quarter	244,369		18,126			0.33			0.33
Fourth Quarter(1)	259,750		38,499			0.70			0.69
	$	974,832	$	171,539		$	3.11		$	3.09
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(2)	240,600		(414,733		)	(7.62		)	(7.62		)
	$	919,558	$	(228,063	)	$	(4.21	)	$	(4.21	)

_______________________________________________________________________________


(1)	In the fourth quarter of 2012, the Company recorded a $7.2 million income tax benefit for research and development tax credits.


(2)	In the fourth quarter of 2011, the Company recorded an impairment of $625.0 million related to its E. Texas natural gas assets, largely due to the impact of lower natural gas prices.


(3)	Due to the volatility of commodity prices, the estimated fair value of the Company's commodity derivative instruments is subject to fluctuations. As a result, the Company may recognize significant unrealized gains and losses (non-cash changes in fair value) on commodity derivative instruments from period to period.

(4)

The sum of the individual quarterly net earnings (loss) per common share amounts may not agree with year-to-date net earnings (loss) 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 earnings (loss) per common share for each quarter in which the Company reported net earnings.

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

Prepaid Expenses and Other

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2012
Accounting Policies [Abstract]
Major Customers, Policy [Policy Text Block]	Major Customers The following table presents the percentages of the Company's total oil and natural gas and electricity sales to each significant purchaser for the years ended December 31, 2012, 2011 and 2010: Based on the current demand for oil and natural gas and the availability of other purchasers, the Company believes that, with the exception of its primary customer in Utah, the loss of any one of its major purchasers would not have a material adverse effect on its financial condition, results of operations and operating cash flows. See Item 1A. Risk Factors—"Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production."
Inventory, Policy [Policy Text Block]	Inventories Inventories consist primarily of tubular goods and production materials and equipment. Inventories also include crude oil and California carbon allowance instruments. Inventories are carried at the lower of cost or market, with cost being determined on a weighted average cost basis.
Basis of Presentation	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 2012 financial statement presentation. In the 2011 Balance Sheets, $4.8 million was reclassified from asset retirement obligations (ARO) to accrued liabilities in order to conform to current and non-current presentation of ARO in the 2012 Balance Sheets.
Assumptions, Judgements, and Estimates	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	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, 2012 and 2011 was $14.9 million and $16.1 million, respectively, representing outstanding checks in excess of the bank balance (book overdraft).
Accounts Receivable	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	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.
Income Taxes and Uncertain Tax Positions
Derivatives Instruments
Oil and Gas Properties, Building and Equipment	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. Under this method, the fair value of property acquired and all costs associated with successful exploratory wells and all development wells are capitalized. Capitalized acquisition costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized exploratory drilling and development costs is based on the unit-of-production method using proved developed reserves. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells and oil and gas production costs. 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. 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 as long as 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 the development wells are productive or nonproductive. Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Costs of seismic and other studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to earnings. Unproved properties consist of costs to acquire undeveloped leases and to acquire unproved reserves. Costs related to acquiring undeveloped leases and unproved reserves are capitalized. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Buildings and equipment are recorded at cost. Depreciation is calculated on a straight-line basis over estimated useful lives ranging from five to 30 years for buildings and improvements and three to ten 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 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 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. See Notes 8 and 10 to the Financial Statements. Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. 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	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 2 to the Financial Statements.
Asset Retirement Obligations	Asset Retirement Obligations
Deferred Financing Costs	Debt Issuance Costs Debt issuance costs related to the Company’s senior subordinated notes are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the credit facility are amortized to interest expense on a straight-line basis over the borrowing term.
Revenue Recognition	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.
Electricity Cost Allocation	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,
Transportation 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	Stock-Based Compensation Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the requisite service period, which is generally the vesting period.
(Loss) Earnings Per Share	Earnings (Loss) 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 earnings (loss) per share is calculated by dividing earnings (loss) available to common shareholders by the weighted average shares-basic during each period. Diluted earnings (loss) per share is calculated by dividing earnings (loss) 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. No potential shares of common stock are included in the computation of any diluted per share amount when a net loss exists.
Equity Method Investments	The Company's net investment in these entities is included under the caption other assets on its Balance Sheets.
Industy Segment and Geographic Information	Industry Segment and Geographic Information The Company operates in one industry segment, which is the production, development, exploitation and acquisition of oil and natural gas, and all of the Company's operations are conducted in the continental United States. The Company considers its gathering, processing and marketing functions as ancillary to its oil and natural gas producing activities.
Concentration Risk Disclosure [Text Block]	Credit Risk and Other Concentrations The Company sells oil and natural gas to various types of customers, including pipelines, refineries and other oil and natural gas companies, and sells electricity to utility companies. Credit is extended based on an evaluation of the customer's financial condition and historical payment record. The future availability of a ready market for oil and natural gas depends on numerous factors outside the Company's control, none of which can be predicted with certainty. See Item 1A. Risk Factors—"Market conditions or operational impediments may hinder the Company's access to oil and natural gas markets or delay our production." At December 31, 2012, the Company had commodity derivative contracts with nine counterparties, all of which were part of the Company's credit facility and all of which had investment-grade ratings from Moody’s and Standard & Poor. 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, 2012 was $23.2 million. During 2012, 2011 and 2010, 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. 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, 2012, the Company has not incurred losses related to these investments.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]



	Year Ended December 31,
(in thousands)	2012		2011
Prepaid expenses	$	4,168	$	5,275
California carbon allowance inventories	545		—
Oil inventories	1,216		—
Materials inventories	12,943		11,356
Other inventory	193		170
Total prepaid expenses and other	$	19,065	$	16,801

Schedule of Accrued Liabilities



	Year Ended December 31,
(in thousands)	2012		2011
Property taxes	$	13,496	$	10,430
Accrued interest	16,996		9,205
Accrued payroll	12,700		9,953
Asset retirement obligations (current portion)	4,430		4,763
Other accrued liabilities	3,529		5,478
Total accrued liabilities	$	51,151	$	39,829

Computation of Basic and Diluted Earnings (Loss) Per Share



	Year Ended December 31,
(in thousands, except per share data)	2012		2011			2010
Net earnings (loss)	$	171,539	$	(228,063	)	$	82,524
Less: Earnings allocable to participating securities	885		—			1,199
Net earnings (loss) available for common shareholders	$	170,654	$	(228,063	)	$	81,325

Basic net earnings (loss) per share	$	3.11	$	(4.21	)	$	1.54
Diluted net earnings (loss) per share	$	3.09	$	(4.21	)	$	1.52

Basic weighted average shares outstanding	54,912		54,133			52,969
Add: Dilutive effects of stock options and RSUs	375		—			460
Diluted weighted average shares outstanding	55,287		54,133			53,429

Revenue from External Customers by Products and Services [Table Text Block]



	Year Ended December 31,
	2012		2011		2010
Oil and natural gas:
ExxonMobil Oil Corporation	43	%	43	%	44	%
Shell Trading (US) Company	13	%	14	%	14	%
Enterprise Crude Oil LLC	9	%	8	%	4	%
HollyFrontier Corporation	9	%	8	%	9	%
Electricity:
Pacific Gas and Electric Company	54	%	59	%	55	%
Southern California Edison	46	%	41	%	45	%

Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2012

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

Tabular disclosure of a material business combination completed during the period, including background, timing, and recognized assets and liabilities. This table does not include leveraged buyouts.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=7659399&loc=d3e1486-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7659399&loc=d3e1392-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141
-Paragraph 51
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph F4
-Subparagraph e
-Appendix F

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141
-Paragraph 52
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 68
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Senior Notes 6.375% Due 2022

Debt (Tables)

12 Months Ended

Dec. 31, 2012

Debt Instrument

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



2017	103.188	%
2018	102.125	%
2019	101.063	%
2020 and thereafter	100.000	%

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	%

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)



	Year Ended December 31,
(in thousands)	2012		2011			2010
Current:
Federal	$	286	$	4,115		$	363
State	4,954		2,936			1,870
	5,240		7,051			2,233
Deferred:
Federal	80,083		(125,261		)	47,709
State	2,798		(24,018		)	4,026
	82,881		(149,279		)	51,735
Total	$	88,121	$	(142,228	)	$	53,968

Schedule of Deferred Tax Assets and Liabilities



	Year Ended December 31,
(in thousands)	2012			2011
Deferred income tax assets:
Federal benefit of state income taxes	$	(239	)	$	(2,479	)
Credit carryforwards	36,028			29,186
Equity and deferred compensation	15,139			12,620
Derivatives	—			8,669
Net operating loss	412			412
Bad debt expense	163			—
Other, net	610			980
Valuation allowance	(1,201		)	(403		)
	50,912			48,985
Deferred income tax liabilities:
Depreciation and depletion	(298,659		)	(220,656		)
Derivatives	(8,477		)	—
	(307,136		)	(220,656		)

Net deferred income tax liabilities	$	(256,224	)	$	(171,671	)

Schedule of Effective Income Tax Rate Reconciliation



	Year Ended December 31,
	2012		2011		2010
Income tax computed at statutory federal rate	35	%	35	%	35	%
State income taxes, net of federal benefit	3		3		4
Deferred state rate impact	(1	)	—		(1	)
Research and development credits	(3	)	—		—
Net impact to uncertain income tax positions	—		1		—
Other	—		(1	)	2
Effective income tax rate	34	%	38	%	40	%

Summary of Income Tax Contingencies



	Year Ended December 31,
(in millions)	2012			2011			2010
Unrecognized income tax benefits at January 1	$	2.9		$	5.2		$	6.1
Increases (decreases) for positions taken in a prior year	20.5			—			(0.8		)
Decreases for settlements with taxing authorities	—			(2.3		)	—
Decreases for lapses in the applicable statute of limitations	(0.8		)	—			(0.1		)
Unrecognized income tax benefits at December 31	$	22.6		$	2.9		$	5.2

Summary of Income Tax Examinations



Jurisdiction:	Tax Years Subject to Exam:
Federal	2009 - 2011
California	2007 - 2011
Colorado	2007 - 2011
Texas	2008 - 2011
Utah	2007 - 2011

Tabular disclosure of tax positions taken in the tax returns filed or to be filed for which it is more likely than not that the tax position will not be sustained upon examination by taxing authorities (i.e., uncertain tax positions) and other types of income tax contingencies, including: (1) the policy on classification of interest and penalties; (2) a tabular reconciliation of the total amounts of unrecognized tax benefits at the beginning and end of the period; the total amount(s) of: (3) unrecognized tax benefits that, if recognized, would affect the effective tax rate, and (4) interest and penalties recognized in each of the income statement and balance sheet; (5) for positions for which it is reasonably possible that the total amounts unrecognized will significantly change within 12 months of the reporting date the: (i) nature of the uncertainty, (ii) nature of the event that could occur that would cause the change, and (iii) an estimate of the range of the reasonably possible change or a statement that an estimate of the range cannot be made; and (6) a description of tax years that remain subject to examination by major tax jurisdictions.

Tabular disclosure of income tax examinations that an enterprise is currently subject to or that have been completed in the current period typically including a description of the examination, the jurisdiction conducting the examination, the tax year(s) under examination, the likelihood of an unfavorable settlement, the range of possible losses, the liability recorded, the increase or decrease in the liability from the prior period, and any penalties and interest that have been recorded.

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity Incentive Compensation Plans and Other Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of stock options or units activity



	Number of Shares		Weighted Average Exercise Price		Aggregate Intrinsic Value (in thousands)(1)		Weighted Average Remaining Contractual Term (Years)
Outstanding at January 1, 2010	2,276,020		$	25.36
Granted	—		—
Exercised	(227,100	)	19.40		$	3,570
Canceled/expired	(31,695	)	35.51
Outstanding at December 31, 2010	2,017,225		25.87
Granted	89,865		48.50
Exercised	(579,636	)	17.47		$	17,746
Canceled/expired	(6,765	)	45.92
Outstanding at December 31, 2011	1,520,689		30.32
Granted	82,262		53.02
Exercised	(215,359	)	17.12		$	7,194
Canceled/expired	—		—
Outstanding at December 31, 2012	1,387,592		$	33.71	$	4,681	4.08
Vested and expected to vest at December 31, 2012	1,383,702		$	33.66	$	4,681	4.07
Exercisable at December 31, 2012	1,239,733		$	31.65	$	4,681	3.53

_______________________________________


(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



	2012		2011
Expected volatility	50.00	%	45.00	%
Risk-free rate	0.95	%	2.54	%
Dividend yield	0.57	%	0.62	%
Expected term (in years)	5.2		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 Term (Years)	Weighted Average Exercise Price		Number of Options	Weighted Average Remaining Contractual Term (Years)	Weighted Average Exercise Price
$9.61-$9.97	43,850	0.93	$	9.89	43,850	0.93	$	9.89
$21.58-$21.77	253,000	1.90	21.60		253,000	1.90	21.60
$30.65-$32.57	639,500	3.51	31.70		639,500	3.51	31.70
$38.00-$53.02	451,242	6.43	45.66		303,383	5.31	43.05
	1,387,592	4.08	$	33.71	1,239,733	3.53	$	31.65

Summary of restricted stock units activity



	RSUs		Weighted Average Intrinsic Value at Grant Date		Vest Date Fair Value (in thousands)
Outstanding at January 1, 2010	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
Granted	164,112		50.60
Issued	(79,068	)	33.10		$	3,401
Canceled/expired	(18,189	)	41.50
Outstanding at December 31, 2012(1)(2)	981,877		$	26.72

__________________________________


(1)	The balance outstanding includes RSUs granted to non-employee directors that are 100% vested at the date of grant but are subject to deferral elections delaying the date on which the corresponding shares of Common Stock are issued. For the years ended December 31, 2012, 2011 and 2010, 43,554, 30,544 and 10,522 RSUs have vested, but the corresponding shares of Common Stock have not been issued.

(2)

Summary of performance share awards activity



	Performance Share Awards		Weighted Average Grant Date Fair Value		Vest Date Fair Value (in thousands)
Outstanding on January 1, 2010	—		$	—
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
Granted	59,738		63.69
Issued	—		—		$	—
Canceled/expired	—		—
Outstanding at December 31, 2012	222,587		$	45.79

Summary of assumptions used in valuing market-based restricted shares



	2012		2011
Number of simulations	100,000		100,000
Expected volatility	50	%	44	%
Risk-free rate	0.42	%	1.15	%

Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of commodity derivatives



	2013	2014	2015
Oil Sales (Bbl/D):	18,800	7,500	3,000
Natural Gas Purchases (MMBtu/D):	10,000	—	—

Schedule of derivative assets and liabilities



	December 31, 2012
	Derivative Assets			Derivative Liabilities
(in millions)	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Current:
Commodity	Derivative assets	$	16.4	Derivative liabilities	$	2.8
Long-term:
Commodity	Derivative assets	10.9		Derivative liabilities	1.2
Total derivatives		$	27.3		$	4.0



	December 31, 2011
	Derivative Assets			Derivative Liabilities
(in millions)	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Current:
Commodity	Derivative assets	$	23.4	Derivative liabilities	$	37.7
Long-term:
Commodity	Derivative assets	10.5		Derivative liabilities	19.0
Total derivatives		$	33.9		$	56.7

Summary of (gains) losses before income taxes of derivative instruments recognized in the condensed statements of income (loss)



(in millions)		Year Ended December 31,
Description of (Gain) Loss	Location of (Gain) Loss Recognized in Earnings	2012			2011			2010
Commodity
Loss reclassified from AOCL into earnings (amortization of frozen amounts)	Oil and natural gas sales	$	10.7		$	60.9		$	18.4
(Gain) loss recognized in earnings (cash settlements and mark-to-market movements)	Realized and unrealized (gain) loss on derivatives, net	(64.6		)	(13.9		)	23.2
Interest rate
(Gain) loss reclassified from AOCL into earnings (amortization of frozen amounts)	Interest	$	(1.8	)	$	0.8		$	8.3
Loss recognized in earnings (cash settlements and mark-to-market movements)	Realized and unrealized (gain) loss on derivatives, net	—			—			8.6

Tabular disclosure of the location and amount of gains and losses reported in the statement of financial performance, or when applicable, the statement of financial position. For example, (a) gains and losses recognized in the income statement on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges and (b) gains and losses initially recognized in other comprehensive income on derivative instruments designated and qualifying as cash flow hedges.

Net derivative liabilities measured at fair value on a recurring basis

Fair Value Measurement (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]



(in millions)	Total			Level 1		Level 2			Level 3
Commodity derivatives asset (liability), net
December 31, 2012	$	23.2		$	—	$	23.2		$	—
December 31, 2011	(22.7		)	—		(22.7		)	—

Changes in Level 3 fair value measurements



	Year Ended December 31,
(in millions)	2012		2011			2010
Fair value liability, beginning of period	$	—	$	101.8		$	26.0
Transfers out of Level 3(1)	—		(101.8		)	—
Realized and unrealized loss included in earnings	—		—			37.4
Settlements	—		—			38.4
Fair value liability, end of period	$	—	$	—		$	101.8

Total unrealized loss included in earnings related to financial assets and liabilities still on the Balance Sheets	$	—	$	—		$	75.8

___________________________


(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, 2012	Carrying Amount		Estimated Fair Value
(in millions)			Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—
Senior secured revolving credit facility(1)	563		—		563		—		563
10.25% Senior notes due 2014(2)	205		229		—		—		229
6.75% Senior notes due 2020	300		323		—		—		323
6.375% Senior notes due 2022	600		627		—		—		627
	$	1,668	$	1,179	$	563	$	—	$	1,742

________________________________

(1)


(2)	Carrying amount does not include unamortized discount of $2.3 million.



	December 31, 2011
(in millions)	Carrying Amount		Estimated Fair Value
Senior secured revolving credit facility(1)	$	532	$	532
8.25% Senior subordinated notes due 2016	200		209
10.25% Senior notes due 2014(2)	355		402
6.75% Senior notes due 2020	300		302
	$	1,387	$	1,445

__________________________________

(1)


(2)	Carrying amount does not include unamortized discount of $6.6 million.

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

Tabular disclosure of assets, including [financial] instruments measured at fair value that are classified in stockholders' equity, if any, by class that are measured at fair value on a recurring and/or nonrecurring basis. The disclosures contemplated herein include the fair value measurements at the reporting date by the level within the fair value hierarchy in which the fair value measurements in their entirety fall, segregating fair value measurements using quoted prices in active markets for identical assets (Level 1), significant other observable inputs (Level 2), and significant unobservable inputs (Level 3).

Tabular disclosure of the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments, assets, and liabilities. Such certain disclosures about the financial instruments, assets, and liabilities include: (1) the fair value of the required items together with their carrying amounts (as appropriate) and (2) the methodology and assumptions used in developing such estimates of fair value.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13476-108611

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 2
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=7578670&loc=d3e19207-110258

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13467-108611

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6447952&loc=d3e13220-108610

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14172-108612

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 10
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13433-108611

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 19
-Subparagraph a, b, c(1), d(1)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 14
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15
-Subparagraph b-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph c(2), d, e, f
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32
-Subparagraph a, c(1), c(2), c(3), d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Tabular disclosure of the fair value measurement of liabilities using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes attributable to the following: (1) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets), and gains or losses recognized in other comprehensive income (loss) and a description of where those gains or losses included in earnings (or changes in net assets) are reported in the statement of income (or activities); (2) purchases, sales, issues, and settlements (each type disclosed separately); and (3) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs) by class of liability.

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of future minimum rental payments for operating leases



(in millions)	Total		2013		2014		2015		2016		2017		Thereafter
Operating leases(1)	$	18.0	$	5.1	$	5.3	$	3.6	$	2.9	$	1.1	$	—
Drilling rig commitments(2)	9.4		9.4		—		—		—		—		—
Other commitments(3)	23.5		16.2		2.9		2.3		2.1		—		—
Firm natural gas transportation contracts(4)	245.1		31.0		33.7		33.4		33.5		33.4		80.1
Total	$	296.0	$	61.7	$	41.9	$	39.3	$	38.5	$	34.5	$	80.1

___________________________________


(1)	Includes operating leases related to office facilities, vehicles, rail cars 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, California carbon allowance forward purchase contracts and equipment rentals.


(4)	The Company enters into certain firm commitments to transport natural gas production to market and to transport natural gas for use in 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.

Oil and Gas Properties, Buildings and Equipment (Tables)

12 Months Ended

Dec. 31, 2012

Oil and Gas Properties, Buildings and Equipment [Abstract]

Schedule of Oil and Gas Properties, Building and Equipment Activities



	Year Ended December 31,
(in thousands)	2012			2011
Oil and natural gas:
Proved properties(1)	$	4,060,106		$	3,257,321
Unproved properties(2)	236,626			228,486
	4,296,732			3,485,807
Less accumulated depreciation, depletion and amortization	(1,180,298		)	(962,154		)
	3,116,434			2,523,653
Commercial and other:
Machinery, drilling rigs and equipment	18,131			22,509
Buildings and improvements	10,110			6,894
Vehicles	9,167			7,806
	37,408			37,209
Less accumulated depreciation	(25,340		)	(29,469		)
	12,068			7,740
	$	3,128,502		$	2,531,393

________________________________________


(1)	Includes cogeneration facilities.

(2)

Asset Retirement Obligation (ARO) (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation Disclosure [Abstract]

Summary of change in asset retirement obligation



	Year Ended December 31,
(in thousands)	2012			2011
Beginning balance at January 1	$	64,019		$	53,443
Liabilities incurred	7,249			2,983
Liabilities settled	(3,325		)	(1,803		)
Liabilities assumed	2,651			119
Disposition of assets	(705		)	—
Accretion expense	5,858			4,812
Revisions in estimated cash flows	10,999			4,465
Ending balance at December 31(1)	$	86,746		$	64,019

____________________


(1)	The asset retirement obligation related to the Nevada Assets, which were held for sale as of December 31, 2011 and sold effective January 31, 2012, 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 2 to the Financial Statements.

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

12 Months Ended

Dec. 31, 2012

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities



	2012						2011						2010
	Oil MBOE		Natural Gas MMcf		MBOE		Oil MBOE		Natural Gas MMcf		MBOE		Oil MBOE		Natural Gas MMcf		MBOE
Total proved reserves:
Beginning of year	185,880		534,279		274,926		166,181		630,192		271,213		129,940		632,178		235,303
Revision of previous estimates	12,145		(205,845	)	(22,162	)	(4,054	)	(146,349	)	(28,446	)	4,288		(46,860	)	(3,522	)
Improved recovery	—		—		—		—		—		—		1,700		—		1,700
Extensions and discoveries	8,459		100,129		25,148		19,601		65,992		30,600		12,774		43,469		20,019
Property sales	(556	)	—		(556	)	—		—		—		—		—		—
Production	(10,024	)	(19,784	)	(13,321	)	(9,041	)	(23,907	)	(13,025	)	(7,925	)	(23,989	)	(11,923	)
Purchase of reserves in place	8,304		16,740		11,094		13,193		8,351		14,584		25,404		25,394		29,636
End of year	204,208		425,519		275,129		185,880		534,279		274,926		166,181		630,192		271,213

Proved developed reserves	118,937		187,668		150,216		107,849		221,606		144,783		88,917		268,566		133,678
Proved undeveloped reserves	85,271		237,851		124,913		78,031		312,673		130,143		77,264		361,626		137,535
Total proved reserves	204,208		425,519		275,129		185,880		534,279		274,926		166,181		630,192		271,213

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



	Year Ended December 31,
(in thousands)	2012			2011			2010
Future cash inflows	$	19,738,729		$	19,568,628		$	14,354,627
Future production costs	(5,884,891		)	(5,226,044		)	(4,446,183		)
Future development costs	(2,164,780		)	(1,975,429		)	(1,789,001		)
Future income tax expense	(3,344,024		)	(3,770,512		)	(2,272,184		)
Future net cash flows	8,345,034			8,596,643			5,847,259
10% annual discount for estimated timing of cash flows	(4,511,619		)	(4,561,364		)	(3,048,103		)
Standardized measure of discounted future net cash flows	$	3,833,415		$	4,035,279		$	2,799,156
Average price during the 12-month period:(1)
Oil ($/BOE)	$	90.66		$	93.72		$	69.04
Natural gas ($/Mcf)	2.88			4.02			4.57
BOE ($/BOE)	$	71.74		$	71.18		$	52.93

______________________________


(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,
(in thousands)	2012			2011			2010
Standardized measure—beginning of year	$	4,035,279		$	2,799,156		$	1,445,747
Sales of oil and natural gas produced, net of production costs	(625,707		)	(599,679		)	(406,390		)
Revisions to estimates of proved reserves:
Net changes in sales prices and production costs	(786,022		)	1,473,454			1,724,212
Revisions of previous quantity estimates	743			(281,765		)	(49,784		)
Improved recovery	—			—			24,033
Extensions and discoveries	124,466			601,313			283,011
Change in estimated future development costs	(331,498		)	(274,122		)	(152,096		)
Purchases of reserves in place	114,094			164,383			307,205
Sales of reserves in place	(15,283		)	—			—
Development costs incurred during the period	497,036			433,660			144,086
Accretion of discount	570,505			383,418			184,917
Income taxes	323,128			(634,747		)	(593,272		)
Other	(73,326		)	(29,792		)	(112,513		)
Net (decrease) increase	(201,864		)	1,236,123			1,353,409
Standardized measure—end of year	$	3,833,415		$	4,035,279		$	2,799,156

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



	Year ended December 31,
(in thousands)	2012		2011		2010
Property acquisitions
Proved properties	$	70,700	$	149,158	$	334,409
Unproved properties	10,686		6,632		—
Development	714,343		544,114		320,927
Exploration	16,405		627		2,310
Total(1)	$	812,134	$	700,531	$	657,646

__________________________________________

(1)The total above does not reflect $17.9 million, $29.1 million and $28.3 million of capitalized interest incurred in 2012, 2011 and 2010, respectively.

Tabular disclosure of the aggregate of costs (whether the costs are capitalized or charged to expense at the time they are incurred ) incurred for the year in oil and gas property acquisition, exploration and development activities.

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Quarterly Financial Information



	Operating Revenues		Net Earnings (Loss)			Basic Net Earnings (Loss) Per Share(3)(4)			Diluted Net Earnings (Loss) Per Share(3)(4)
2012
First Quarter	$	241,492	$	33,898		$	0.62		$	0.61
Second Quarter	229,221		81,016			1.47			1.46
Third Quarter	244,369		18,126			0.33			0.33
Fourth Quarter(1)	259,750		38,499			0.70			0.69
	$	974,832	$	171,539		$	3.11		$	3.09
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(2)	240,600		(414,733		)	(7.62		)	(7.62		)
	$	919,558	$	(228,063	)	$	(4.21	)	$	(4.21	)

_______________________________________________________________________________


(1)	In the fourth quarter of 2012, the Company recorded a $7.2 million income tax benefit for research and development tax credits.


(2)	In the fourth quarter of 2011, the Company recorded an impairment of $625.0 million related to its E. Texas natural gas assets, largely due to the impact of lower natural gas prices.


(3)	Due to the volatility of commodity prices, the estimated fair value of the Company's commodity derivative instruments is subject to fluctuations. As a result, the Company may recognize significant unrealized gains and losses (non-cash changes in fair value) on commodity derivative instruments from period to period.

(4)

Summary of Significant Accounting Policies (Details) $ in Thousands			3 Months Ended	12 Months Ended
	Dec. 31, 2012 USD ($) counterparty	Jul. 23, 2010 USD ($)	Sep. 30, 2010 USD ($)	Dec. 31, 2012 USD ($) Cogeneration_facilities Industry_Segments counterparty	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2008 USD ($)
Accounting Policies
Maximum maturity for cash equivalents	3 months			3 months
Bank Overdrafts	$ 14,900			$ 14,900	$ 16,100
Collection period for trade accounts receivable, months				2 months
Asset Retirement Obligation, Current	$ 4,430			$ 4,430	4,763
Derivative Number of Counterparties to Commodity Contracts \| counterparty	9			9
Allowance for bad debt				$ 414	0	$ 0
Settlement of Flying J bankruptcy claim				0	0	21,992
Allowance for Doubtful Accounts Receivable, Recoveries				$ 0	0	38,508
Number of companies owned under equity method investments (in ones)				2
Equity method investment, ownership is less than (as a percent)				50.00%
Impairment of oil and natural gas properties				$ 79	625,564	0
Number of Cogeneration facilities (in ones) \| Cogeneration_facilities				3
Number of industry segments (in ones) \| Industry_Segments				1
Flying J
Accounting Policies
Allowance for bad debt							$ 38,500
Litigation settlement, gross		$ 60,500
Proceeds received from bankruptcy claim		$ 60,500
Settlement of Flying J bankruptcy claim			$ 22,000
Allowance for Doubtful Accounts Receivable, Recoveries			$ 38,500
Minimum \| Building and Building Improvements
Accounting Policies
Property, plant and equipment, useful lives, minimum (in years)				5 years
Minimum \| Machinery and Equipment
Accounting Policies
Property, plant and equipment, useful lives, minimum (in years)				3 years
Maximum \| Building and Building Improvements
Accounting Policies
Property, plant and equipment, useful lives, minimum (in years)				30 years
Maximum \| Machinery and Equipment
Accounting Policies
Property, plant and equipment, useful lives, minimum (in years)				10 years
Electricity Cost Allocation
Accounting Policies
Electricity Production Consumed and Included In Oil Production Costs				$ 2,000	2,300	2,800
Costs of Transporting Natural Gas
Accounting Policies
Costs of Natural Gas Transportation Used in Oil and Gas Production				28,600	21,400	16,200
Cost of Natural Gas Transportation Used in Electricity Generation				$ 3,800	$ 5,000	$ 4,700
Derivative
Accounting Policies
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$ 23,200

Summary of Significant Accounting Policies (Prepaid Expenses and Other) (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Prepaid expense
Prepaid expenses	$ 4,168	$ 5,275
California carbon allowance inventories	545	0
Oil inventories	1,216	0
Materials inventories	12,943	11,356
Other inventory	193	170
Total prepaid expenses and other	$ 19,065	$ 16,801

Summary of Significant Accounting Policies (Accrued Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Accrued interest	$ 16,996	$ 9,205
Accrued payroll	12,700	9,953
Asset Retirement Obligation, Current	4,430	4,763
Other accrued liabilities	3,529	5,478
Accrued liabilities	51,151	39,829
Property Tax
Taxes Payable, Current	$ 13,496	$ 10,430

Carrying value as of the balance sheet date of [accrued] interest payable on all forms of debt, including trade payables, that has been incurred and is unpaid. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer).

Carrying value as of the balance sheet date of obligations incurred through that date and payable arising from transactions not otherwise specified in the taxonomy. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer).

Basic (loss) earnings per share (in dollars per share)

Summary of Significant Accounting Policies Major Customers (Details) - Sales	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Oil \| ExxonMobil Oil Corporation
Revenue, Major Customer
Concentration Risk, Percentage	43.00%	43.00%	44.00%
Oil \| Shell Trading (US) Company
Revenue, Major Customer
Concentration Risk, Percentage	13.00%	14.00%	14.00%
Oil \| Enterprise Crude Oil LLC
Revenue, Major Customer
Concentration Risk, Percentage	9.00%	8.00%	4.00%
Oil \| HollyFrontier Corporation
Revenue, Major Customer
Concentration Risk, Percentage	9.00%	8.00%	9.00%
Electricity Generation \| Pacific Gas and Electric Company
Revenue, Major Customer
Concentration Risk, Percentage	54.00%	59.00%	55.00%
Electricity Generation \| Southern California Edison
Revenue, Major Customer
Concentration Risk, Percentage	46.00%	41.00%	45.00%

Summary of Significant Accounting Policies (Earnings Per Share) (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Computation of earnings per share

Net earnings (loss)

$ 38,499

$ 18,126

$ 81,016

$ 33,898

$ (414,733)

$ 134,001

$ 105,166

$ (52,497)

$ 171,539

$ (228,063)

$ 82,524

$ 0.70

^[1],[2],[3]

$ 0.33

^[2],[3]

$ 1.47

^[2],[3]

$ 0.62

^[2],[3]

$ (7.62)

^[2],[3],[4]

$ 2.45

^[2],[3]

$ 1.93

^[2],[3]

$ (0.98)

^[2],[3]

$ 3.11

^[2],[3]

$ (4.21)

^[2],[3]

$ 1.54

Dilutive (loss) earings per share (in dollars per share)

$ 0.69

^[1],[2],[3]

$ 0.33

^[2],[3]

$ 1.46

^[2],[3]

$ 0.61

^[2],[3]

$ (7.62)

^[2],[3],[4]

$ 2.42

^[2],[3]

$ 1.90

^[2],[3]

$ (0.98)

^[2],[3]

$ 3.09

^[2],[3]

$ (4.21)

^[2],[3]

$ 1.52

Basic weighted average shares (in shares)

54,912

54,133

52,969

Add: Dilutive effects of stock options (in shares)

375

460

Diluted weighted average shares (in shares)

55,287

54,133

53,429

Less: earnings allocable to participating securities

$ 885

$ 0

$ 1,199

Net earnings from available for common shareholders

$ 170,654

$ 81,325

Options not included in the diluted earnings (loss) per share calculation (in shares)

600

1,500

700

[1]	(1)In the fourth quarter of 2012, the Company recorded a $7.2 million income tax benefit for research and development tax credits
[2]	(3)Due to the volatility of commodity prices, the estimated fair value of the Company's commodity derivative instruments is subject to fluctuations. As a result, the Company may recognize significant unrealized gains and losses (non-cash changes in fair value) on commodity derivative instruments from period to period.
[3]	(4)The sum of the individual quarterly net earnings (loss) per common share amounts may not agree with year-to-date net earnings (loss) 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 earnings (loss) per common share for each quarter in which the Company reported net earnings.
[4]	(2)In the fourth quarter of 2011, the Company recorded an impairment of $625.0 million related to its E. Texas natural gas assets, largely due to the impact of lower natural gas prices.

Acquisitions and Divestitures (Details) $ in Thousands					3 Months Ended	12 Months Ended
Acquisitions and Divestitures (Details) $ in Thousands	Sep. 12, 2012 USD ($) a	Apr. 13, 2012 USD ($) a Wells	Jan. 31, 2012 USD ($)	May 25, 2011 USD ($) a	Mar. 31, 2011 USD ($)	Dec. 31, 2012 USD ($) shares	Dec. 31, 2011 USD ($) shares	Dec. 31, 2010 USD ($) property	Nov. 01, 2010 USD ($)	Jan. 31, 2010 shares
Acquisitions
Payments for (Proceeds from) Deposits on Real Estate Acquisitions						$ 3,300	$ (3,300)	$ 0
Asset retirement obligations						82,316	59,256
Purchase price paid, net of customary post-closing adjustments						78,313	158,090	334,409
Revenues generated by acquired properties						937,261	870,773	619,608
Recognized amounts of identifiable assets acquired and liabilities assumed:
Gain on purchase of oil and natural gas properties						0	1,046	0
Deferred income taxes						82,881	(149,279)	51,735
Transaction Costs on Acquisitions						0	0	2,635
Proceeds from sale of assets						17,307	0	0
Assets Held-for-sale, Current						$ 0	$ 14,622
Common Class A
Acquisitions
Common Stock, Shares, Issued \| shares						52,428,423	52,067,994			8,000,000
Wolfberry Acquisition
Acquisitions
Purchase price paid, net of customary post-closing adjustments				$ 128,398
Recognized amounts of identifiable assets acquired and liabilities assumed:
Other liabilities assumed				(180)
Total identifiable net assets				$ 128,398
Brundage Canyon Acquisition
Acquisitions
Acquisition of Oil and Gas Properties Acres Acquired \| a	14,000
Purchase price paid, net of customary post-closing adjustments	$ 39,600
Permian Basin Acquisitions
Acquisitions
Purchase price paid, net of customary post-closing adjustments								327,032
Revenues generated by acquired properties								28,700
Recognized amounts of identifiable assets acquired and liabilities assumed:
Other assets acquired								342
Deferred income tax liability								(647)
Other liabilities assumed								(333)
Total identifiable net assets								$ 328,078
Number of separate acquisitions (in properties) \| property								3
Gain on purchase of oil and natural gas properties					$ 1,000
Deferred income taxes					$ 700
Transaction Costs on Acquisitions								$ 2,600
Senior Notes 6.75 Percent Due 2020
Recognized amounts of identifiable assets acquired and liabilities assumed:
Senior Notes						$ 300,000	$ 300,000		$ 300,000
Interest rate on debt instrument (as a percent)						6.75%
Nevada Assets
Acquisitions
Asset retirement obligations							700
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proceeds from sale of assets			$ 15,600
Gain (Loss) on Sale of Oil and Gas Property			$ 1,600
2012 \| Wolfberry Acquisition
Acquisitions
Acquisition of Oil and Gas Properties Acres Acquired \| a		2,000
Number of wells acquired in acquisition \| Wells		1
Purchase price paid, net of customary post-closing adjustments		$ 14,900
2011 \| Wolfberry Acquisition
Acquisitions
Acquisition of Oil and Gas Properties Acres Acquired \| a				6,000
Purchase price paid, net of customary post-closing adjustments				$ 128,400
Revenues generated by acquired properties							$ 7,800
Oil and Gas Properties \| Wolfberry Acquisition
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed and undeveloped properties				128,697
Oil and Gas Properties \| Permian Basin Acquisitions
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed and undeveloped properties								332,214
Asset Retirement Obligation Costs \| Wolfberry Acquisition
Recognized amounts of identifiable assets acquired and liabilities assumed:
Asset retirement obligation				$ (119)
Asset Retirement Obligation Costs \| Permian Basin Acquisitions
Recognized amounts of identifiable assets acquired and liabilities assumed:
Asset retirement obligation								$ (3,498)

Debt (Details) $ in Thousands	12 Months Ended
Debt (Details) $ in Thousands	Dec. 31, 2012 USD ($) Redetermination day	Apr. 13, 2012 USD ($)	Dec. 31, 2011 USD ($)
Debt Instrument
Outstanding borrowing under credit facility	$ 562,900		$ 531,500
Line of Credit-short term
Debt Instrument
Line of credit, current borrowing capacity	$ 40,000
Line of credit, maximum number of days which borrowings may be outstanding (in days) \| day	30
Senior secured revolving credit agreement (Credit Agreement - long term)
Debt Instrument
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,400,000
Lender commitments	$ 1,200,000
Line of credit facility, borrowing base number of additional redeterminations \| Redetermination	1
Letters of credit that have been issued under the facility	$ 23,200
Remaining borrowing capacity available under the agreement	$ 613,900
Debt instrument covenant consolidated interest coverage ratio numerator (as a ratio) \| Pure	2.75
Debt instrument covenant consolidated interest coverage ratio denominator (as a ratio) \| Pure	1.0
Debt instrument covenant minimum current ratio numerator (as a ratio) \| Pure	1.0
Debt instrument covenant minimum current ratio denominator (as a ratio) \| Pure	1.0
Low End of the Range \| Senior secured revolving credit agreement (Credit Agreement - long term)
Debt Instrument
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.35%
Low End of the Range \| Senior secured revolving credit agreement (Credit Agreement - long term) \| LIBOR
Debt Instrument
Loans Payable Basis Spread On Variable Rate	1.50%
Low End of the Range \| Senior secured revolving credit agreement (Credit Agreement - long term) \| Debt Instrument Variable Rate Prime
Debt Instrument
Loans Payable Basis Spread On Variable Rate	0.50%
High End of the Range \| Senior secured revolving credit agreement (Credit Agreement - long term)
Debt Instrument
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%
High End of the Range \| Senior secured revolving credit agreement (Credit Agreement - long term) \| LIBOR
Debt Instrument
Loans Payable Basis Spread On Variable Rate	2.50%
High End of the Range \| Senior secured revolving credit agreement (Credit Agreement - long term) \| Debt Instrument Variable Rate Prime
Debt Instrument
Loans Payable Basis Spread On Variable Rate	1.50%

Debt (6.375% Senior Notes Due 2020) (Details) - USD ($) $ in Thousands			12 Months Ended
	Mar. 09, 2012	Nov. 01, 2010	Dec. 31, 2012	Dec. 31, 2011
Senior Notes 6.375% Due 2022
Debt Instrument
Interest rate on debt instrument (as a percent)			6.375%
Net proceeds from Issuance long-term debt	$ 589,500
Senior Notes	$ 600,000		$ 600,000	$ 0
Senior Notes 10.25 Percent Due 2014
Debt Instrument
Interest rate on debt instrument (as a percent)			10.25%
Senior Notes			$ 202,917	348,692
Debt Instrument redemption price percentage of principal amount plus make whole premium and accrued and unpaid interest			100.00%
Senior Notes 6.75 Percent Due 2020
Debt Instrument
Interest rate on debt instrument (as a percent)			6.75%
Net proceeds from Issuance long-term debt		$ 294,000
Senior Notes		$ 300,000	$ 300,000	$ 300,000
Debt Instrument redemption price percentage of principal amount plus make whole premium and accrued and unpaid interest			100.00%
March 9, 2012 Through March 14, 2015 \| Senior Notes 6.375% Due 2022
Debt Instrument
Debt Instrument Redemption Percentage, Maximum			35.00%
Senior notes redemption price percentage of principal			106.375%
March 15, 2017 through March 14, 2018 \| Senior Notes 6.375% Due 2022
Debt Instrument
Senior notes redemption price percentage of principal			103.188%
March 15, 2018 through March 14, 2019 \| Senior Notes 6.375% Due 2022
Debt Instrument
Senior notes redemption price percentage of principal			102.125%
March 15, 2019 through March 14, 2020 \| Senior Notes 6.375% Due 2022
Debt Instrument
Senior notes redemption price percentage of principal			101.063%
March 15, 2020 and thereafter \| Senior Notes 6.375% Due 2022
Debt Instrument
Senior notes redemption price percentage of principal			100.00%
March 9, 2012 through March 14, 2017 \| Senior Notes 6.375% Due 2022
Debt Instrument
Debt Instrument redemption price percentage of principal amount plus make whole premium and accrued and unpaid interest			100.00%
Minimum redemption notice at stipulated date and rate \| Senior Notes 6.375% Due 2022
Debt Instrument
Senior Notes Redemption Price, Notice Period Range in Days			30 days
Maximum redemption notice at stipulated date and rate \| Senior Notes 6.375% Due 2022
Debt Instrument
Senior Notes Redemption Price, Notice Period Range in Days			60 days

Debt (6.75% Senior Notes Due 2020) (Details) - 6.75% Senior notes due 2020 - USD ($) $ in Thousands		12 Months Ended
	Nov. 01, 2010	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument
Interest rate on debt instrument (as a percent)		6.75%
Senior Notes	$ 300,000	$ 300,000	$ 300,000
Net proceeds from Issuance long-term debt	$ 294,000
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 and accrued and unpaid interest		100.00%
Prior to November 1, 2013
Debt Instrument
Debt Instrument Redemption Percentage, Maximum		35.00%
Senior notes redemption price percentage of principal		106.75%
November 1, 2015 Through October 31, 2016
Debt Instrument
Senior notes redemption price percentage of principal		103.375%
November 1, 2016 through October 31, 2017
Debt Instrument
Senior notes redemption price percentage of principal		102.25%
November 1, 2017 through October 31, 2018
Debt Instrument
Senior notes redemption price percentage of principal		101.125%
November 1, 2018 and thereafter
Debt Instrument
Senior notes redemption price percentage of principal		100.00%

Debt (10.25% Senior Notes Due 2014) (Details) - USD ($)				3 Months Ended	12 Months Ended
Debt (10.25% Senior Notes Due 2014) (Details) - USD ($)	Apr. 03, 2012	Aug. 13, 2009	May 27, 2009	Oct. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Debt Instrument
Loss on repurchase of notes					$ 41,545,000	$ 15,544,000	$ 573,000
Extinguishment of debt					$ 6,842,000	4,072,000	573,000
Senior Notes 10.25 Percent Due 2014
Debt Instrument
Interest rate on debt instrument (as a percent)					10.25%
Debt Instrument, Face Amount		$ 125,000,000	$ 325,000,000
Discount on issuance (as a percent)			93.546%
Unamortized discount			$ 21,000,000		$ 2,340,000	6,564,000
Net proceeds from Issuance long-term debt		$ 129,100,000	295,100,000		$ 0	$ 0	$ 300,000,000
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 and accrued and unpaid interest					100.00%
Loss on repurchase of notes	$ 30,900,000
Aggregate principal amount under tender offer	150,000,000
Repayments of Unsecured Debt	181,500,000
Unsecured Debt	205,300,000
Repayment of Debt \| 10.25% Bond Repurchases
Debt Instrument
Aggregate purchase price for repurchase of notes				$ 108,800,000
Aggregate principal amount of notes repurchased				94,700,000
Loss on repurchase of notes				15,000,000
Extinguishment of debt				3,500,000
Lien Term Loan \| Senior Notes 10.25 Percent Due 2014
Debt Instrument
Aggregate purchase price for repurchase of notes			$ 140,000,000
Premium Paid Over Par \| Senior Notes 10.25 Percent Due 2014
Debt Instrument
Loss on repurchase of notes	26,400,000
Premium Paid Over Par \| Repayment of Debt \| 10.25% Bond Repurchases
Debt Instrument
Loss on repurchase of notes				$ 11,500,000
Write-off of Deferred Debt Issuance Cost and Net Discount \| Senior Notes 10.25 Percent Due 2014
Debt Instrument
Loss on repurchase of notes	$ 4,500,000

Debt (8.25% Senior Suborinated Notes Due 2016) (Details) - USD ($) $ in Thousands		12 Months Ended
	Apr. 09, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Senior Notes, Expressed As Percentage Of Principal Amount Redeemed, Plus Accured and Unpaid Interest
Gains (Losses) on Extinguishment of Debt		$ (41,545)	$ (15,544)	$ (573)
8.25% Senior subordinated notes due 2016
Debt Instrument
Interest rate on debt instrument (as a percent)		8.25%
Repayment of Debt \| 8.25% Senior subordinated notes due 2016
Senior Notes, Expressed As Percentage Of Principal Amount Redeemed, Plus Accured and Unpaid Interest
Aggregate principal amount of notes repurchased	$ 200,000
Repayments of Subordinated Debt	215,500
Gains (Losses) on Extinguishment of Debt	(10,600)
Write off of Deferred Debt Issuance Cost	2,300
Repayment of Debt \| Premium Paid Over Par \| 8.25% Senior subordinated notes due 2016
Senior Notes, Expressed As Percentage Of Principal Amount Redeemed, Plus Accured and Unpaid Interest
Gains (Losses) on Extinguishment of Debt	$ (8,300)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Contingency
Deferred Tax Liabilities, Net, Current	$ 1,456	$ 0
Deferred Tax Liabilities, Gross	307,136	220,656
Deferred income taxes	703	13,779
Deferred income taxes, noncurrent	255,471	185,450
Unrecognized Tax Benefits Maximum Estimated Reductions Resulting from Expiration of Applicable Statute of Limitations in Next 12 Months	6,700
Unrecognized Tax Benefits, Interest on Income Taxes Expense		500	$ 100
Unrecognized tax benefit, if recognized, would affect the effective tax rate	17,500
Accrued interest recognized due to uncertain tax positions	400	800
Unrecognized Tax Benefits, Reversal of Interest Expense	(400)
Deferred Tax Assets, Valuation Allowance	1,201	403
Unrecognized Tax Benefits, Reductions Resulting from Lapse of Applicable Statute of Limitations	800	0	100
Unrecognized Tax Benefits, Decreases Resulting from Prior Period Tax Positions			$ 800
Increases (decreases) for positions taken in a prior year	20,500	0
Federal and State
Income Tax Contingency
Deferred Tax Liabilities, Net, Current	800
Deferred income taxes		13,779
Deferred income taxes, noncurrent	255,471	185,450
California \| State
Income Tax Contingency
Deferred Tax Assets, Tax Credit Carryforwards, Research		$ 18,300
Tax credit carryforwards, alternative minimum tax	600
California \| EOR tax credit \| State
Income Tax Contingency
Tax credit carryforwards	12,500
UNITED STATES \| Federal
Income Tax Contingency
Deferred Tax Assets, Tax Credit Carryforwards, Research	10,400
Tax credit carryforwards, alternative minimum tax	800
UNITED STATES \| EOR tax credit \| Federal
Income Tax Contingency
Tax credit carryforwards	10,600
COLORADO \| Enterprise zone income tax credits \| State
Income Tax Contingency
Tax credit carryforwards	$ 3,000

Income Taxes (Schedule of Components of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current:
Federal	$ 286	$ 4,115	$ 363
State	4,954	2,936	1,870
Current Income Tax Expense (Benefit)	5,240	7,051	2,233
Deferred:
Federal	80,083	(125,261)	47,709
State	2,798	(24,018)	4,026
Deferred Income Tax Expense (Benefit)	82,881	(149,279)	51,735
Total	$ 88,121	$ (142,228)	$ 53,968

The component of income tax expense for the period representing amounts paid or payable (or refundable) as determined by applying the provisions of enacted federal tax law to the domestic taxable Income or Loss from continuing operations.

The component of income tax expense for the period representing amounts of income taxes paid or payable (or refundable) for the period for all income tax obligations as determined by applying the provisions of relevant enacted tax laws to relevant amounts of taxable Income or Loss from continuing operations.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Current Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6509736

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.7)
-URI http://asc.fasb.org/extlink&oid=6889476&loc=d3e330036-122817

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 289
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

The component of income tax expense for the period representing amounts paid or payable (or refundable) as determined by applying the provisions of enacted state and local tax law to relevant amounts of taxable Income or Loss from continuing operations.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.7)
-URI http://asc.fasb.org/extlink&oid=6889476&loc=d3e330036-122817

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Current Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6509736

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 289
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

The component of total income tax expense for the period comprised of the increase (decrease) during the period in the entity's domestic deferred tax assets and liabilities attributable to continuing operations as determined by applying the provisions of the federally enacted tax law.

The component of income tax expense for the period representing the increase (decrease) in the entity's deferred tax assets and liabilities pertaining to continuing operations.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Deferred Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6510177

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.7)
-URI http://asc.fasb.org/extlink&oid=6889476&loc=d3e330036-122817

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 289
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 28
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

The component of total income tax expense for the period comprised of the increase (decrease) in the entity's state and local deferred tax assets and liabilities attributable to continuing operations as determined by applying the provisions of the applicable enacted tax laws.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Deferred Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6510177

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.7)
-URI http://asc.fasb.org/extlink&oid=6889476&loc=d3e330036-122817

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 8, 16, 17, 289
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

The sum of the current income tax expense or benefit and the deferred income tax expense or benefit pertaining to pretax Income or Loss from continuing operations; income tax expense or benefit may include interest and penalties on tax uncertainties based on the entity's accounting policy.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (a),(b)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 45
-Paragraph 25
-URI http://asc.fasb.org/extlink&oid=21917399&loc=d3e32247-109318

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32672-109319

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45, 46
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 48
-Paragraph 15, 16, 19
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Exercise Price

Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Deferred tax assets:
Federal benefit of state income taxes	$ 239	$ 2,479
Credit carryforwards	36,028	29,186
Equity and deferred compensation	15,139	12,620
Derivatives	0	8,669
Net operating loss	412	412
Bad debt expense	163	0
Other, net	610	980
Valuation allowance	(1,201)	(403)
Deferred Tax Assets, Net	50,912	48,985
Deferred tax liabilities:
Depreciation and depletion	(298,659)	(220,656)
Derivatives	(8,477)	0
Deferred Tax Liabilities	(256,224)	(171,671)
Deferred Tax Liabilities, Gross	$ (307,136)	$ (220,656)

Income Taxes (Schedule of Effective Income Tax Rate Reconciliation) (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
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%	3.00%	4.00%
Deferred state rate impact	(1.00%)	0.00%	(1.00%)
Research and development credits	(3.00%)	(0.00%)	(0.00%)
Net impact to uncertain income tax positions	0.00%	1.00%	0.00%
Other	0.00%	(1.00%)	2.00%
Effective income tax rate	34.00%	38.00%	40.00%

Income Taxes (Summary of Income Tax Contingencies) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized income tax benefits at January 1	$ 2.9	$ 5.2	$ 6.1
Unrecognized Tax Benefits, Increases Resulting from Prior Period Tax Positions	20.5	0.0
Unrecognized Tax Benefits, Decreases Resulting from Prior Period Tax Positions			(0.8)
Decreases for settlements with taxing authorities	0.0	(2.3)	0.0
Decreases for lapses in the applicable statute of limitations	(0.8)	0.0	(0.1)
Unrecognized income tax benefits at December 31	$ 22.6	$ 2.9	$ 5.2

Shareholder's Equity (Details) - USD ($)	1 Months Ended	12 Months Ended
Shareholder's Equity (Details) - USD ($)	Jan. 31, 2010	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Shareholder's Equity
Proceeds from issuance of common stock		$ 0	$ 0	$ 224,313,000
Dividends per share		$ 0.32	$ 0.31	$ 0.30
Common Class A
Shareholder's Equity
Common Stock, voting rights (votes per share)		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	$ 224,300,000
Common Class B
Shareholder's Equity
Common Stock, voting rights (votes per share)		.95
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
Dividend payments limited by covenants in Credit Facility
Shareholder's Equity
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
Dividend payments limited by covenants in Indentures
Shareholder's Equity
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

Equity Incentive Compensation Plans and Other Benefit Plans (Equity Incentive Plans) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	May 31, 2010	May 31, 2005
Share-based Compensation Arrangement by Share-based Payment Award
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Expiration	Tenth Year
Vesting period based on plan (in years)	4 years
Total compensation cost (in dollars)	$ 9.3	$ 9.0	$ 8.3
Two Thousand Ten Equity Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award
Options granted under plan, term (in years)	10 years
Shares available to be issued in period	426,055
Two Thousand Ten Equity Incentive Plan \| Scenerio One
Share-based Compensation Arrangement by Share-based Payment Award
Vesting rate based on Plan (as a percent)	25.00%
Vesting period based on plan (in years)	4 years
Two Thousand Ten Equity Incentive Plan \| Scenerio Two
Share-based Compensation Arrangement by Share-based Payment Award
Vesting rate based on Plan (as a percent)	100.00%
Vesting period based on plan (in years)	3 years
Two Thousand Ten Equity Incentive Plan \| Common Class A
Share-based Compensation Arrangement by Share-based Payment Award
Number of Common Stock shares available for grant				1,000,000
Two Thousand Ten Equity Incentive Plan \| Common Class A \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Options may not be less than fair market value of Common Stock on the date of grant (in shares)	1
Two Thousand Five Equity Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award
Options granted under plan, term (in years)	10 years
Shares available to be issued in period	173,915
Two Thousand Five Equity Incentive Plan \| Scenerio One
Share-based Compensation Arrangement by Share-based Payment Award
Vesting rate based on Plan (as a percent)	25.00%
Vesting period based on plan (in years)	4 years
Two Thousand Five Equity Incentive Plan \| Scenerio Two
Share-based Compensation Arrangement by Share-based Payment Award
Vesting rate based on Plan (as a percent)	100.00%
Vesting period based on plan (in years)	3 years
Two Thousand Five Equity Incentive Plan \| Common Class A
Share-based Compensation Arrangement by Share-based Payment Award
Number of Common Stock shares available for grant					2,900,000
Two Thousand Five Equity Incentive Plan \| Common Class A \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Options may not be less than fair market value of Common Stock on the date of grant (in shares)	1

Equity Incentive Compensation Plans (Stock Options) (Details) - USD ($)
$ / shares in Units, $ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Equity Incentive Compensation Plans

$ 31.65

Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Outstanding Options, Weighted Average Remaining Contractual Term

4 years 29 days

Stock options activity

Outstanding at the beginning of the period (in shares)

1,520,689

2,017,225

2,276,020

Granted (in shares)

82,262

89,865

Exercised (in shares)

(215,359)

(579,636)

(227,100)

Canceled/expired

(6,765)

(31,695)

Outstanding at the end of the period (in shares)

1,387,592

1,520,689

2,017,225

Stock options, Weighted Average Exercise Price

Outstanding at the beginning of the period (in dollars per share)

$ 30.32

$ 25.87

$ 25.36

Granted (in dollars per share)

53.02

48.50

0.00

Exercised (in dollars per share)

17.12

17.47

19.40

Cancelled/expired (in dollars per share)

0.00

45.92

35.51

Outstanding at the end of the period (in dollars per share)

$ 33.71

$ 30.32

$ 25.87

Stock options, Aggregate Intrinsic Value

Exercised

$ 7,194

$ 17,746

^[1]

$ 3,570

^[1]

Outstanding at the end of the period

$ 4,681

Stock options, Number of Shares Exercisable

Options outstanding at the end of the period (in shares)

1,239,733

Vesting period (in years)

4 years

Anniversary date through which options are exercisable from grant date

Tenth Year

Fair value assumptions

Expected volatility (as a percent)

50.00%

45.00%

Risk-free interest rate (as a percent)

0.95%

2.54%

Dividend yield (as a percent)

0.57%

0.62%

Expected term (in years)

5 years 2 months

6 years

Total unrecognized compensation cost

$ 2,500

Period of recognition of unrecognized compensation cost (in years)

3 years 3 months

Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value

$ 4,681

Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term

3 years 6 months 12 days

Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number

1,383,702

Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price

$ 33.66

Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value

$ 4,681

Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Exercisable, Weighted Average Remaining Contractual Term

4 years 26 days

[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.

Equity Incentive Compensation Plans (Range of Exercise Prices) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Stock Options Outstanding, Number of Options	1,387,592
Stock Options Outstanding, Weighted Average Remaining Contractual Life (Years)	4 years 29 days
Stock Options Outstanding, Weighted Average Exercise Price (in dollars per share)	$ 33.71	$ 30.32	$ 25.87	$ 25.36
Stock Options Outstanding, Aggregate Intrinsic Value (in dollars)	$ 4,681
Stock Options Exercisable, Number of Options	1,239,733
Stock Options Exercisable, Weighted Average Remaining Contractual Life (Years)	3 years 6 months 12 days
Stock Options Exercisable, Weighted Average Exercise Price (in dollars per share)	$ 31.65
Stock Options Exercisable, Aggregate Intrinsic Value (in dollars)	$ 4,681
Exercise Prices 9.61 to 9.97
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Range of Exercise Prices, Lower Range Limit (in dollars)	$ 9.61
Range of Exercise Prices, Upper Range Limit (in dollars)	$ 9.97
Stock Options Outstanding, Number of Options	43,850
Stock Options Outstanding, Weighted Average Remaining Contractual Life (Years)	11 months 5 days
Stock Options Outstanding, Weighted Average Exercise Price (in dollars per share)	$ 9.89
Stock Options Exercisable, Number of Options	43,850
Stock Options Exercisable, Weighted Average Remaining Contractual Life (Years)	11 months 5 days
Stock Options Exercisable, Weighted Average Exercise Price (in dollars per share)	$ 9.89
Exercise Prices 21.58 to 21.77
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Range of Exercise Prices, Lower Range Limit (in dollars)	21.58
Range of Exercise Prices, Upper Range Limit (in dollars)	$ 21.77
Stock Options Outstanding, Number of Options	253,000
Stock Options Outstanding, Weighted Average Remaining Contractual Life (Years)	1 year 10 months 25 days
Stock Options Outstanding, Weighted Average Exercise Price (in dollars per share)	$ 21.60
Stock Options Exercisable, Number of Options	253,000
Stock Options Exercisable, Weighted Average Remaining Contractual Life (Years)	1 year 10 months 25 days
Stock Options Exercisable, Weighted Average Exercise Price (in dollars per share)	$ 21.60
Exercise Prices 30.65 to 32.57
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Range of Exercise Prices, Lower Range Limit (in dollars)	30.65
Range of Exercise Prices, Upper Range Limit (in dollars)	$ 32.57
Stock Options Outstanding, Number of Options	639,500
Stock Options Outstanding, Weighted Average Remaining Contractual Life (Years)	3 years 6 months 5 days
Stock Options Outstanding, Weighted Average Exercise Price (in dollars per share)	$ 31.70
Stock Options Exercisable, Number of Options	639,500
Stock Options Exercisable, Weighted Average Remaining Contractual Life (Years)	3 years 6 months 5 days
Stock Options Exercisable, Weighted Average Exercise Price (in dollars per share)	$ 31.70
Exercise Prices 38.00 to 53.02
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Range of Exercise Prices, Lower Range Limit (in dollars)	38.00
Range of Exercise Prices, Upper Range Limit (in dollars)	$ 53.02
Stock Options Outstanding, Number of Options	451,242
Stock Options Outstanding, Weighted Average Remaining Contractual Life (Years)	6 years 5 months 6 days
Stock Options Outstanding, Weighted Average Exercise Price (in dollars per share)	$ 45.66
Stock Options Exercisable, Number of Options	303,383
Stock Options Exercisable, Weighted Average Remaining Contractual Life (Years)	5 years 3 months 23 days
Stock Options Exercisable, Weighted Average Exercise Price (in dollars per share)	$ 43.05

Equity Incentive Compensation Plans (Restricted Stock Units and Performance Share Program) (Details) - USD ($)
$ / shares in Units, $ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Restricted Stock Units

Other than stock options activity

Outstanding at the beginning of the period (in shares)

915,022

^[1],[2]

857,360

^[1],[2]

1,107,293

Granted (in shares)

164,112

159,333

34,529

Issued (in shares)

(79,068)

(62,127)

(246,633)

Canceled/expired (in shares)

(18,189)

(39,544)

(37,829)

Outstanding at the end of the period (in shares)

^[1],[2]

981,877

915,022

857,360

Weighted-average intrinsic value at grant-date

Outstanding at the beginning of the period (in dollars per share)

$ 23.88

^[1],[2]

$ 19.67

^[1],[2]

$ 22.14

Granted (in dollars per share)

50.60

47.98

30.94

Issued (in dollars per share)

33.10

26.18

28.98

Canceled/expired (in dollars per share)

41.50

25.12

22.20

Outstanding at the end of the period (in dollars per share)

$ 26.72

$ 23.88

^[1],[2]

$ 19.67

^[1],[2]

Vest Date Fair Value - Issued (in dollars)

$ 3,401

$ 2,588

$ 7,813

Performance Based Restricted Stock Units

Other than stock options activity

Outstanding at the beginning of the period (in shares)

162,849

103,794

Granted (in shares)

59,738

65,620

103,794

Issued (in shares)

Canceled/expired (in shares)

(6,565)

Outstanding at the end of the period (in shares)

222,587

162,849

103,794

Weighted-average intrinsic value at grant-date

Outstanding at the beginning of the period (in dollars per share)

$ 39.00

$ 31.20

$ 0.00

Granted (in dollars per share)

63.69

51.86

31.20

Issued (in dollars per share)

0.00

Canceled/expired (in dollars per share)

0.00

44.20

0.00

Outstanding at the end of the period (in dollars per share)

$ 45.79

$ 39.00

$ 31.20

Vest Date Fair Value - Issued (in dollars)

$ 0

[1]

[2]

The balance outstanding includes RSUs granted to non-employee directors that are 100% vested at the date of grant but are subject to deferral elections delaying the date on which the corresponding shares of Common Stock are issued. For the years ended December 31, 2012, 2011 and 2010, 43,554, 30,544 and 10,522 RSUs have vested, but the corresponding shares of Common Stock have not been issued.

Equity Incentive Compensation Plans (Restricted Stock Units and Performance Share Program Parenthetical) (Details) $ in Millions		1 Months Ended		12 Months Ended
	Dec. 31, 2012 USD ($) shares	Mar. 31, 2012 USD ($) simulation	Mar. 31, 2011 USD ($) simulation	Dec. 31, 2012 USD ($) shares	Dec. 31, 2011 shares	Dec. 31, 2010 shares
Equity Incentive Compensation Plans
Total unrecognized compensation cost \| $	$ 2.5			$ 2.5
Period of recognition of unrecognized compensation cost (in years)	3 years 3 months
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)				50.00%	45.00%
Risk-free interest rate (as a percent)				0.95%	2.54%
Performance Based Restricted Stock Units
Equity Incentive Compensation Plans
Total unrecognized compensation cost \| $	$ 2.1			$ 2.1
Period of recognition of unrecognized compensation cost (in years)	2 years
Granted (in shares) \| shares				59,738	65,620	103,794
Number of years of service to be completed to participate in the program (in years)				3 years
Minimum interest coverage ratio, numerator \| Pure				2.5
Minimum interest coverage ratio, denominator \| Pure				1
Vesting period (in years)				3 years
Grant date fair value determined by Monte Carlo valuation model \| $		$ 1.3	$ 1.1
Fair value assumptions used in market-based portion of performance shares valuation model (Monte Carlo model)
Number of simulations \| simulation		100,000	100,000
Expected volatility (as a percent)		50.00%	44.00%
Risk-free interest rate (as a percent)		0.42%	1.15%
Restricted Stock Units
Equity Incentive Compensation Plans
Total unrecognized compensation cost \| $	$ 11.1			$ 11.1
Period of recognition of unrecognized compensation cost (in years)	3 years 3 months
Granted (in shares) \| shares				164,112	159,333	34,529
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) \| shares	614,996			614,996	483,908	289,335
Restricted Stock Units \| Non-employee directors
Equity Incentive Compensation Plans
Percentage of stock units vested at date of grant (as a percent)	100.00%			100.00%
Fully Vested Shares Outstanding Subject to Non-Employee Director Deferral Election (in shares) \| shares	43,554			43,554	30,544	10,522

Equity Incentive Compensation Plans and Other Benefit Plans (Director Fees and Other Employee Benefits-401(k) Plan) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
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	$ 2.1	$ 1.8	$ 1.5
Employees participating in 401(k) Plan (as a percent)	94.00%
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)	12,797	13,647	38,462

Derivative Instruments (Details) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
Derivative Instruments (Details) $ in Thousands	Mar. 31, 2012 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2012 USD ($) MMBtu / day OilBblD	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Mar. 31, 2011 MMBtu / day
Accumulated Other Comprehensive Loss
Expected derivative payments during next twelve months			$ 11,800
Unrealized losses, before tax, on contracts previously designated as cash flow hedges				$ (8,900)
Unrealized losses, net of tax, on contracts previously designated as cash flow hedges			0	(5,517)
Reclassified unrealized losses, before tax from AOCL into earnings			8,900	61,800
Reclassified unrealized losses, after tax from AOCL into earnings			$ 5,517	$ 38,289	$ 16,566
Interest rate contract \| Termination of Derivatives
Notional amount of derivative instruments
Gain (Loss) on Contract Termination		$ (1,900)
Natural Gas \| 2013 \| Natural Gas
Notional amount of derivative instruments
Notional amount of derivatives (Bbl/MMBtu) \| MMBtu / day			10,000
Natural Gas \| 2014 \| Natural Gas
Notional amount of derivative instruments
Notional amount of derivatives (Bbl/MMBtu) \| MMBtu / day			0
Natural Gas \| Full 2015 Term \| Natural Gas
Notional amount of derivative instruments
Notional amount of derivatives (Bbl/MMBtu) \| MMBtu / day			0
Natural Gas \| Termination of Derivatives
Notional amount of derivative instruments
Notional amount of derivatives (Bbl/MMBtu) \| MMBtu / day						15,000
Gain (Loss) on Contract Termination	$ (1,900)
Crude Oil \| 2013 \| Crude Oil
Notional amount of derivative instruments
Notional amount of derivatives (Bbl/MMBtu) \| OilBblD			18,800
Crude Oil \| 2014 \| Crude Oil
Notional amount of derivative instruments
Notional amount of derivatives (Bbl/MMBtu) \| OilBblD			7,500
Crude Oil \| Full 2015 Term \| Crude Oil
Notional amount of derivative instruments
Notional amount of derivatives (Bbl/MMBtu) \| OilBblD			3,000

Derivative Instruments (Details 2) - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
Fair value derivative assets and liabilities classified in condensed balance sheets
Derivative Assets	$ 27.3	$ 33.9
Derivative Liabilities	4.0	56.7
Current
Fair value derivative assets and liabilities classified in condensed balance sheets
Derivative Assets	16.4	23.4
Derivative Liabilities	2.8	37.7
Long-term
Fair value derivative assets and liabilities classified in condensed balance sheets
Derivative Assets	10.9	10.5
Derivative Liabilities	$ 1.2	$ 19.0

Derivative Instruments (Details 3) $ in Thousands	12 Months Ended
Derivative Instruments (Details 3) $ in Thousands	Dec. 31, 2012 USD ($) counterparty	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)
Location and amount of derivative instrument (gains) losses before income taxes recognized in the condensed statements of income
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, before Tax	$ 8,900	$ 61,800
Realized and unrealized (gain) loss on derivatives, net	$ (64,620)	(13,908)	$ 31,847
Credit risk
Percentage of Derivative Value Held by Major Counterparties	74.00%
Derivative instruments, number of largest counterparties (in counterparties) \| counterparty	2
Sales Of Oil And Gas \| Commodity Contract
Location and amount of derivative instrument (gains) losses before income taxes recognized in the condensed statements of income
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, before Tax	$ 10,700	60,900	18,400
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
Realized and unrealized (gain) loss on derivatives, net	(64,600)	(13,900)	23,200
Realized And Unrealized Gain Loss On Derivatives Net \| Interest rate contract
Location and amount of derivative instrument (gains) losses before income taxes recognized in the condensed statements of income
Realized and unrealized (gain) loss on derivatives, net	0	0	8,600
Interest Expense \| Interest rate contract
Location and amount of derivative instrument (gains) losses before income taxes recognized in the condensed statements of income
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, before Tax	$ (1,800)	$ 800	$ 8,300

Fair Value Measurement (Details) - Assets and liabilities measured on a recurring basis - Commodity Contract - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
Estimated Fair Value
Fair Value, Assets and Liabilities Measured on Recurring Basis
Commodity derivatives asset (liability), net		$ (22.7)
Commodity derivatives asset (liability), net	$ 23.2
Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring Basis
Commodity derivatives asset (liability), net		0.0
Commodity derivatives asset (liability), net	0.0
Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring Basis
Commodity derivatives asset (liability), net		(22.7)
Commodity derivatives asset (liability), net	23.2
Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring Basis
Commodity derivatives asset (liability), net		$ 0.0
Commodity derivatives asset (liability), net	$ 0.0

Fair Value Measurement (Details 2) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Changes in Level 3 fair value measurements

Fair value liability, beginning of period

$ 0.0

$ 101.8

$ 26.0

Transfers out of Level 3

^[1]

0.0

(101.8)

0.0

Realized and unrealized (gain) loss included in earnings

0.0

37.4

Settlements

0.0

38.4

Fair value liability, end of period

0.0

101.8

Fair Value, Inputs, 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

$ 0.0

$ 75.8

[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.

Fair Value Measurement (Details 3) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

May 27, 2009

Fair value and carrying value of debt instruments

Senior secured revolving credit facility

$ 562,900

$ 531,500

Senior secured revolving credit facility

Fair value and carrying value of debt instruments

Interest Rate Generally Fixed, Number of Days

30 days

8.25% Senior subordinated notes due 2016

Fair value and carrying value of debt instruments

10.25% Senior notes due 2014

8.25%

Fair value and carrying value of debt instruments

6.75% Senior notes due 2020

10.25%

Unamortized discount

$ 2,340

$ 6,564

$ 21,000

Fair value and carrying value of debt instruments

Senior Notes 6.375% Due 2022

6.75%

Fair value and carrying value of debt instruments

Fair value and carrying value of debt instruments

6.375%

Carrying Amount

Carrying Amount | Senior secured revolving credit facility

$ 1,668,000

1,387,000

Fair value and carrying value of debt instruments

Carrying Amount | 8.25% Senior subordinated notes due 2016

563,000

532,000

^[1]

Fair value and carrying value of debt instruments

Carrying Amount | 10.25% Senior notes due 2014

200,000

Fair value and carrying value of debt instruments

Carrying Amount | 6.75% Senior notes due 2020

205,000

^[2]

355,000

^[3]

Fair value and carrying value of debt instruments

Carrying Amount | Senior Notes 6.375% Due 2022

300,000

Fair value and carrying value of debt instruments

Fair value and carrying value of debt instruments

600,000

Estimated Fair Value

Estimated Fair Value | Senior secured revolving credit facility

1,742,000

1,445,000

Fair value and carrying value of debt instruments

Estimated Fair Value | 8.25% Senior subordinated notes due 2016

563,000

^[4]

532,000

^[1]

Fair value and carrying value of debt instruments

Estimated Fair Value | 10.25% Senior notes due 2014

209,000

Fair value and carrying value of debt instruments

Estimated Fair Value | 6.75% Senior notes due 2020

229,000

402,000

Fair value and carrying value of debt instruments

Estimated Fair Value | Senior Notes 6.375% Due 2022

323,000

$ 302,000

Fair value and carrying value of debt instruments

Cash and Cash Equivalents | Carrying Amount

627,000

Fair value and carrying value of debt instruments

Cash and Cash Equivalents, Fair Value Disclosure

Cash and Cash Equivalents | Estimated Fair Value

Fair value and carrying value of debt instruments

Cash and Cash Equivalents, Fair Value Disclosure

Fair Value, Inputs, Level 2

Fair value and carrying value of debt instruments

Fair Value, Inputs, Level 2 | Estimated Fair Value | Senior secured revolving credit facility

563,000

Fair value and carrying value of debt instruments

Fair Value, Inputs, Level 1

^[4]

563,000

Fair value and carrying value of debt instruments

Fair Value, Inputs, Level 1 | Estimated Fair Value | 10.25% Senior notes due 2014

1,179,000

Fair value and carrying value of debt instruments

Fair Value, Inputs, Level 1 | Estimated Fair Value | 6.75% Senior notes due 2020

^[3]

229,000

Fair value and carrying value of debt instruments

Fair Value, Inputs, Level 1 | Estimated Fair Value | Senior Notes 6.375% Due 2022

323,000

Fair value and carrying value of debt instruments

Fair Value, Inputs, Level 1 | Cash and Cash Equivalents | Estimated Fair Value

627,000

Fair value and carrying value of debt instruments

Cash and Cash Equivalents, Fair Value Disclosure

$ 0

[1]	(1)The Company's credit facility can be repaid at any time without penalty. Interest is generally fixed for 30-day increments at the prime rate or LIBOR plus a stipulated margin for the amount utilized and at a stipulated percentage as a commitment fee for the portion not utilized. The carrying amount of the credit facility approximated fair value due to the short-term maturities of the borrowings and because the borrowings bear interest at variable market rates.
[2]	(2)Carrying amount does not include unamortized discount of $2.3 million.
[3]	(2)Carrying amount does not include unamortized discount of $6.6 million.
[4]	(1)The Company's credit facility can be repaid at any time without penalty. Interest is generally fixed for 30-day increments at the prime rate or LIBOR plus a stipulated margin for the amount utilized and at a stipulated percentage as a commitment fee for the portion not utilized. The carrying amount of the credit facility approximated fair value due to the short-term maturities of the borrowings and because the borrowings bear interest at variable market rates.

Fair Value Measurement (Details 4) - USD ($) $ in Thousands	12 Months Ended
Fair Value Measurement (Details 4) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$ 79	$ 625,564	$ 0
Fair Value, Measurements, Nonrecurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset Impairment Charges		629,300
Carrying Amount \| Oil and Gas Properties \| Fair Value, Measurements, Nonrecurring \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, plant, and equipment, fair value disclosure		114,300
Carrying Amount \| Other Long-Lived Assets \| Fair Value, Measurements, Nonrecurring \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, plant, and equipment, fair value disclosure		1,400
Estimated Fair Value \| Oil and Gas Properties \| Fair Value, Measurements, Nonrecurring \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, plant, and equipment, fair value disclosure		0
Estimated Fair Value \| Oil and Gas Properties \| Fair Value, Measurements, Nonrecurring \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, plant, and equipment, fair value disclosure		0
Estimated Fair Value \| Other Long-Lived Assets \| Fair Value, Measurements, Nonrecurring \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, plant, and equipment, fair value disclosure		0
Estimated Fair Value \| Other Long-Lived Assets \| Fair Value, Measurements, Nonrecurring \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, plant, and equipment, fair value disclosure		$ 0

Commitments and Contingencies (Details)
$ in Thousands

1 Months Ended

12 Months Ended

Jul. 31, 2009

USD ($)

Dec. 31, 2012

USD ($)

bbl / day

Rigs

Dec. 31, 2011

USD ($)

Dec. 31, 2010

USD ($)

Operating leases

$ 3,000

$ 2,600

Number of drilling rigs committed | Rigs

Operating Leases, Future Minimum Payments Due

Operating Leases, Future Minimum Payments Due

^[1]

$ 18,000

Operating Leases, Future Minimum Payments Due, Current

5,100

Operating Leases, Future Minimum Payments, Due in Two Years

5,300

Operating Leases, Future Minimum Payments, Due in Three Years

3,600

Operating Leases, Future Minimum Payments, Due in Four Years

2,900

Operating Leases, Future Minimum Payments, Due in Five Years

1,100

Operating Leases, Future Minimum Payments, Due after Fifth Year

Recorded Unconditional Purchase Obligation and Operating Leases, Future Minimum Payments Due

Unrecorded Unconditional Purchase Obligation and Operating Leases, Future Minimum Payments Due

296,000

Unrecorded Unconditional Purchase Obligation Due and Operating Leases, Future Minimum Payments Due, Current

61,700

Unrecorded Unconditional Purchase Obligation Due and Operating Leases, Future Minimum Payments Due with Second Year

41,900

Unrecorded Unconditional Purchase Obligation Due and Operating Leases, Future Minimum Payments Due with Third Year

39,300

Unrecorded Unconditional Purchase Obligation Due and Operating Leases, Future Minimum Payments Due with Fourth Year

38,500

Unrecorded Unconditional Purchase Obligation Due and Operating Leases, Future Minimum Payments Due within Fifth Year

34,500

Unrecorded Unconditional Purchase Obligation Due and Operating Leases, Future Minimum Payments Due after Fifth Year

80,100

E. Texas Gathering System

Gas gathering system, costs incurred

$ 6,873

13,038

19,896

Corporate and Field Offices

Commitments and Contingencies

Operating Lease, in Years

5 years

Vehicles

Commitments and Contingencies

Operating Lease, in Years

4 years

Airplane

Commitments and Contingencies

Operating Lease, in Years

10 years

Drilling rig commitments

Unrecorded Unconditional Purchase Obligation Payment Schedule

Unrecorded Unconditional Purchase Obligation

^[2]

$ 9,400

Unrecorded Unconditional Purchase Obligation Due, Current

^[2]

9,400

Unrecorded Unconditional Purchase Obligation Due in Second Year

^[2]

Unrecorded Unconditional Purchase Obligation Due in Third Year

^[2]

Unrecorded Unconditional Purchase Obligation Due in Fourth Year

^[2]

Unrecorded Unconditional Purchase Obligation Due in Fifth Year

^[2]

Unrecorded Unconditional Purchase Obligation Due after Fifth Year

^[2]

Other commitments

Unrecorded Unconditional Purchase Obligation Payment Schedule

Unrecorded Unconditional Purchase Obligation

23,500

Unrecorded Unconditional Purchase Obligation Due, Current

^[3]

16,200

Unrecorded Unconditional Purchase Obligation Due in Second Year

^[3]

2,900

Unrecorded Unconditional Purchase Obligation Due in Third Year

^[3]

2,300

Unrecorded Unconditional Purchase Obligation Due in Fourth Year

^[3]

2,100

Unrecorded Unconditional Purchase Obligation Due in Fifth Year

^[3]

Unrecorded Unconditional Purchase Obligation Due after Fifth Year

^[3]

Firm natural gas transportation contracts

Unrecorded Unconditional Purchase Obligation Payment Schedule

Unrecorded Unconditional Purchase Obligation

^[4]

245,100

Unrecorded Unconditional Purchase Obligation Due, Current

31,000

Unrecorded Unconditional Purchase Obligation Due in Second Year

33,700

Unrecorded Unconditional Purchase Obligation Due in Third Year

33,400

Unrecorded Unconditional Purchase Obligation Due in Fourth Year

33,500

Unrecorded Unconditional Purchase Obligation Due in Fifth Year

33,400

Unrecorded Unconditional Purchase Obligation Due after Fifth Year

80,100

East Texas

E. Texas Gathering System

Proceeds from gas gathering system, financing obligation

$ 18,400

Net book value of property

$ 16,700

Gathering Agreements, Total Cost Incurred

$ 3,200

$ 5,300

$ 6,700

Gross | Uinta

Recorded Unconditional Purchase Obligation and Operating Leases, Future Minimum Payments Due

Minimum Contractual Daily Crude Oil Sales | bbl / day

5,000

Uinta Crude Oil Sales Contract

Gross oil production average (in Bbl/D) | bbl / day

4,420

[1]	Includes operating leases related to office facilities, vehicles, rail cars 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, California carbon allowance forward purchase contracts and equipment rentals.
[4]	The Company enters into certain firm commitments to transport natural gas production to market and to transport natural gas for use in 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.

Commitments and Contingencies (Details 2)	1 Months Ended	3 Months Ended	12 Months Ended
Commitments and Contingencies (Details 2)	Jul. 31, 2011 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Jan. 14, 2011 USD ($) a
Commitments
Period of potential debarment			3 years
Carry and Earning Agreement
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 \| a					160
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
Contractual Obligation, Contingent Construction Expense per January 2011 Amendment					$ 9,000,000
Third Party Share of Construction Costs, Percentage					50.00%
Bureau of Land Management
Commitments
Litigation settlement expense				$ 2,100,000
Royalty payment disputes
Commitments
Payments for Legal Settlements				4,100,000
Other Royalty Disputes
Commitments
Loss Contingency, Range of Possible Loss, Maximum		$ 3,900,000	$ 3,900,000
Cash Settlement \| Order of Violation from Colorado Oil and Gas Conservative Commission
Commitments
Litigation settlement expense				100,000
Payments for Legal Settlements	$ 100,000
Mutually Acceptable Project \| Order of Violation from Colorado Oil and Gas Conservative Commission
Commitments
Litigation settlement expense				73,000
Payments for Legal Settlements		73,000
Recorded in Interest Expense in 2012 \| Royalty payment disputes
Commitments
Estimated Litigation Liability		700,000	700,000
Recorded in Operating Expense in 2011 \| Royalty payment disputes
Commitments
Estimated Litigation Liability				$ 1,300,000
Recorded in Operating Expense in 2012 \| Royalty payment disputes
Commitments
Estimated Litigation Liability		$ 2,100,000	$ 2,100,000

Oil and Gas Properties, Buildings and Equipment (Details)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2011

USD ($)

Dec. 31, 2012

USD ($)

Drilling_rigs

Wells

Dec. 31, 2011

USD ($)

Dec. 31, 2010

USD ($)

Wells

Oct. 02, 2011

USD ($)

Oil and natural gas: Proved properties and Unproved properties, gross

Proved properties

^[1]

$ 3,257,321

$ 4,060,106

$ 3,257,321

Unproved properties

^[2]

228,486

236,626

228,486

3,485,807

4,296,732

3,485,807

Less accumulated depreciation, depletion and amortization

(962,154)

(1,180,298)

(962,154)

Oil and natural gas: Proved and Unproved properties, Net

2,523,653

3,116,434

2,523,653

Oil and natural gas properties (successful efforts basis), buildings and equipment, net

2,531,393

$ 3,128,502

2,531,393

Capitalized interest costs as component of property costs for development projects (in months)

Gain on sale of assets

$ 1,782

$ 0

Dry Hole Abandonment and Impairment

19,000

5,200

1,500

Plugging and Abandonment Expense

4,100

625,564

$ 0

Less accumulated depreciation

37,209

37,408

37,209

(29,469)

(25,340)

(29,469)

Commercial and other, net

7,740

12,068

7,740

Machinery, drilling rigs, and equipment

Building and improvements

22,509

18,131

22,509

6,894

10,110

6,894

Vehicles

East Texas | Oil and Gas Properties

7,806

9,167

7,806

E. Texas Carrying Amount Prior to Impairment

739,300

East Texas | Fair Value, Measurements, Nonrecurring | Oil and Gas Properties

625,000

Texas

Results of Operations, Dry Hole Costs

$ 11,900

Exploratory Wells Drilled, Net Nonproductive | Wells

Utah

Results of Operations, Dry Hole Costs

$ 2,800

Exploratory Wells Drilled, Net Nonproductive | Wells

COLORADO

Number of wells encountering mechanical failure | Wells

3 Drilling Rigs

Impairment charge related to the write-down of a rig to its fair market value

4,300

Drilling rigs | Drilling_rigs

Proceeds from Sale of Oil and Gas Property and Equipment

$ 1,800

200

Gain on sale of assets

200

$ 1,400

1,400

$ 5,700

Unevaluated properties

Unproved properties

25,200

$ 100

$ 600

$ 0

NYMEX HH

Future strip, average of the daily settlement prices of futures contracts, percentage decrease

15.00%

[1]

Includes cogeneration facilities.

[2]

Asset Retirement Obligation (ARO) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Asset Retirement Obligation [Line Items]

Asset retirement obligations

$ 82,316

$ 59,256

Revisions in estimated cash flows

Beginning balance

64,019

53,443

Accretion expense

5,858

4,812

10,999

4,465

Ending balance

86,746

^[1]

64,019

Nevada Assets

Asset Retirement Obligation [Line Items]

Asset retirement obligations

700

Developmental Activities

Liabilities incurred

7,249

2,983

Liabilities Settled

Liabilities settled

(3,325)

(1,803)

Acquisition Activities

Liabilities incurred

2,651

119

Divestiture Activities

Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

Liabilities settled

$ (705)

$ 0

[1]

The asset retirement obligation related to the Nevada Assets, which were held for sale as of December 31, 2011 and sold effective January 31, 2012, 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 2 to the Financial Statements.

Subsequent Event (Details) $ in Millions	Feb. 20, 2013 USD ($) shares
LinnCo, LLC \| Common Class A
Subsequent Event
Number of Shares Issued Upon Merger	1.25
Subsequent Event \| LinnCo, LLC
Subsequent Event
Minimum Shares, Percent	33.33333%
Cash Distributions, Years	3 years
Other Ownership Interests, Cumulative Cash Distributions \| $	$ 6
Subsequent Event \| LinnCo, LLC \| Common Class B
Subsequent Event
Number of Shares Issued Upon Merger	1.25
Subsequent Event \| HoldCo \| Common Class A
Subsequent Event
Number of Shares Issued Upon Merger	1
Subsequent Event \| HoldCo \| Common Class B
Subsequent Event
Number of Shares Issued Upon Merger	1

Supplemental Information about Oil & Gas Producing Activities (Unaudited) (Reserve Quantities) (Details)	12 Months Ended
	Dec. 31, 2012 MBoe MMcf	Dec. 31, 2011 MBoe MMcf	Dec. 31, 2010 MBoe MMcf	Dec. 31, 2012 MBoe MMcf	Dec. 31, 2011 MBoe MMcf	Dec. 31, 2010 MBoe MMcf	Dec. 31, 2009 MBoe MMcf
Reserve Quantities [Line Items]
Estimates of proved reserves and related valuations based on independent petroleum engineers	100.00%
Proved Developed Reserves (BOE)				150,216	144,783	133,678
Proved Undeveloped Reserve (BOE)				124,913	130,143	137,535
Proved Developed and Undeveloped Reserves, Net BOE				275,129	274,926	271,213	235,303
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates BOE	(22,162)	(28,446)	(3,522)
Proved Developed and Undeveloped Reserves, Improved Recovery BOE	0	0	1,700
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions BOE	25,148	30,600	20,019
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place BOE	(556)	0	0
Proved Developed and Undeveloped Reserves, Production BOE	(13,321)	(13,025)	(11,923)
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place BOE	11,094	14,584	29,636
East Texas
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates BOE		(19,632)	(3,666)
Piceance
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates BOE		(5,779)	(3,890)
Uinta
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates BOE			(840)
Permian
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates BOE			971
California
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates BOE			3,903
Utah
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates BOE		(2,576)
Oil
Reserve Quantities [Line Items]
Proved Developed Reserves (BOE)				118,937	107,849	88,917
Proved Undeveloped Reserve (BOE)				85,271	78,031	77,264
Proved Developed and Undeveloped Reserves, Net BOE				204,208	185,880	166,181	129,940
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates BOE	12,145	(4,054)	4,288
Proved Developed and Undeveloped Reserves, Improved Recovery BOE	0	0	1,700
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions BOE	8,459	19,601	12,774
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place BOE	(556)	0	0
Proved Developed and Undeveloped Reserves, Production BOE	(10,024)	(9,041)	(7,925)
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place BOE	8,304	13,193	25,404
Natural Gas
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume) \| MMcf				187,668	221,606	268,566
Proved Undeveloped Reserve (Volume) \| MMcf				237,851	312,673	361,626
Proved Developed and Undeveloped Reserves, Net \| MMcf	534,279	630,192	630,192	425,519	534,279	630,192	632,178
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved developed and undeveloped reserves, Beginning of year \| MMcf	534,279	630,192	632,178
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates \| MMcf	(205,845)	(146,349)	(46,860)
Improved recovery \| MMcf	0	0	0
Extensions and discoveries \| MMcf	100,129	65,992	43,469
Property sales \| MMcf	0	0	0
Production \| MMcf	(19,784)	(23,907)	(23,989)
Purchase of reserves in place \| MMcf	16,740	8,351	25,394
Proved developed and undeveloped reserves, End of year \| MMcf	425,519	534,279	630,192

Supplemental Information about Oil & Gas Producing Activities (Unaudited) (Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2012

USD ($)

$ / boe

$ / Mcf

Dec. 31, 2011

USD ($)

$ / boe

$ / Mcf

Dec. 31, 2010

USD ($)

$ / boe

$ / Mcf

Discount Rate Used in Standardized Measure of Discounted Future Net Cash Flow of Proved Oil and Gas Reserves

10.00%

Future cash inflows

$ 19,738,729

$ 19,568,628

$ 14,354,627

Future production costs

(5,884,891)

(5,226,044)

(4,446,183)

Future development costs

(2,164,780)

(1,975,429)

(1,789,001)

Future income tax expense

(3,344,024)

(3,770,512)

(2,272,184)

Future net cash flows

8,345,034

8,596,643

5,847,259

10% annual discount for estimated timing of cash flows

(4,511,619)

(4,561,364)

(3,048,103)

Standardized measure of discounted future net cash flows

$ 3,833,415

$ 4,035,279

$ 2,799,156

BOE (average sales price in dollars) | $ / boe

^[1]

71.74

71.18

52.93

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

$ 4,035,279

$ 2,799,156

$ 1,445,747

Sales of oil and natural gas produced, net of production costs

(625,707)

(599,679)

(406,390)

Net changes in sales prices and production costs

(786,022)

1,473,454

1,724,212

Revisions of previous quantity estimates

743

(281,765)

(49,784)

Change in estimated future development costs

(331,498)

(274,122)

(152,096)

Purchases of reserves in place

114,094

164,383

307,205

Sales of reserves in place

(15,283)

Development costs incurred during the period

497,036

433,660

144,086

Accretion of discount

570,505

383,418

184,917

Income taxes

323,128

(634,747)

(593,272)

Other

(73,326)

(29,792)

(112,513)

Net increase (decrease)

(201,864)

1,236,123

1,353,409

Standardized measure—end of year

$ 3,833,415

$ 4,035,279

$ 2,799,156

Oil ($/Bbl)

Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

Average sales prices (in dollars per production type) | $ / boe

^[1]

90.66

93.72

69.04

Natural Gas ($/Mcf)

Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

Average sales prices (in dollars per production type) | $ / Mcf

^[1]

2.88

4.02

4.57

Improved Recovery

Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]

Extensions, Discoveries, Additions and Improved Recovery, Less Related Costs

$ 0

$ 24,033

Extensions and Discoveries

Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]

Extensions, Discoveries, Additions and Improved Recovery, Less Related Costs

$ 124,466

$ 601,313

$ 283,011

[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.

Supplemental Information about Oil & Gas Producing Activities (Unaudited) (Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Costs Incurred, Acquisition of Oil and Natural Gas Properties

Proved properties

$ 70,700

$ 149,158

$ 334,409

Unproved properties

10,686

6,632

Interest Paid, Capitalized

17,915

29,117

28,321

Development

714,343

544,114

320,927

Exploration

16,405

627

2,310

Total

^[1]

$ 812,134

$ 700,531

$ 657,646

[1]	The total above does not reflect $17.9 million, $29.1 million and $28.3 million of capitalized interest incurred in 2012, 2011 and 2010, respectively.

Costs incurred, including capitalized costs and costs charged to expense, associated with the acquisition of oil and gas properties that have proved reserves.

Costs incurred, including capitalized costs and costs charged to expense, associated with the acquisition of oil and gas properties that have unproved reserves.

Income Tax Reconciliation, Tax Credits, Research

Selected Quarterly Financial Data (Unaudited) (Details) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

$ 7,200

Basic net earnings (loss) per share

$ 79

$ 625,564

$ 0

Operating Revenues

259,750

$ 244,369

$ 229,221

$ 241,492

$ 240,600

$ 238,763

$ 242,709

$ 197,486

974,832

919,558

Net (Loss) Earnings

$ 38,499

$ 18,126

$ 81,016

$ 33,898

$ (414,733)

$ 134,001

$ 105,166

$ (52,497)

$ 171,539

$ (228,063)

$ 82,524

$ 0.70

^[1],[2],[3]

$ 0.33

^[2],[3]

$ 1.47

^[2],[3]

$ 0.62

^[2],[3]

$ (7.62)

^[2],[3],[4]

$ 2.45

^[2],[3]

$ 1.93

^[2],[3]

$ (0.98)

^[2],[3]

$ 3.11

^[2],[3]

$ (4.21)

^[2],[3]

$ 1.54

Diluted net earnings (loss) per share

$ 0.69

^[1],[2],[3]

$ 0.33

^[2],[3]

$ 1.46

^[2],[3]

$ 0.61

^[2],[3]

$ (7.62)

^[2],[3],[4]

$ 2.42

^[2],[3]

$ 1.90

^[2],[3]

$ (0.98)

^[2],[3]

$ 3.09

^[2],[3]

$ (4.21)

^[2],[3]

$ 1.52

Oil and Gas Properties | Fair Value, Measurements, Nonrecurring | East Texas

$ 625,000

[1]	(1)In the fourth quarter of 2012, the Company recorded a $7.2 million income tax benefit for research and development tax credits
[2]	(3)Due to the volatility of commodity prices, the estimated fair value of the Company's commodity derivative instruments is subject to fluctuations. As a result, the Company may recognize significant unrealized gains and losses (non-cash changes in fair value) on commodity derivative instruments from period to period.
[3]	(4)The sum of the individual quarterly net earnings (loss) per common share amounts may not agree with year-to-date net earnings (loss) 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 earnings (loss) per common share for each quarter in which the Company reported net earnings.
[4]	(2)In the fourth quarter of 2011, the Company recorded an impairment of $625.0 million related to its E. Texas natural gas assets, largely due to the impact of lower natural gas prices.

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 225
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03.21)
-URI http://asc.fasb.org/extlink&oid=6880815&loc=d3e20235-122688

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 55
-Paragraph 52
-URI http://asc.fasb.org/extlink&oid=16381557&loc=d3e4984-109258

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7655603&loc=d3e1252-109256

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04.19)
-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-04.23)
-URI http://asc.fasb.org/extlink&oid=6879574&loc=d3e536633-122882

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 18
-Article 7

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 36, 37, 38
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 07-4
-Paragraph 4
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 03
-Paragraph 20
-Article 5

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 21
-Article 9

The amount of net income (loss) for the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period.