Ultra Petroleum 10-K24 Feb 152014 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2014	Feb. 11, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Entity Registrant Name	Ultra Petroleum Corp.
Entity Central Index Key	1022646
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$4,548,975,499
Entity Common Stock, Shares Outstanding (actual number)		152,901,361
Trading Symbol	UPL

Consolidated_Statement_of_Oper

Consolidated Statement of Operations (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Natural gas sales	$969,850	$824,266	$695,733
Oil sales	260,170	109,138	114,241
Total operating revenues	1,230,020	933,404	809,974
Expenses:
Lease operating expenses	96,496	68,106	63,823
Liquids gathering system operating lease expense	20,306	20,000	645
Production taxes	103,898	72,398	60,757
Gathering fees	59,931	52,074	59,004
Transportation charges	77,780	82,797	84,470
Depletion and depreciation	292,951	243,390	388,985
Ceiling test and other impairments	0	0	2,972,464
General and Administrative Expense	19,069	22,373	25,104
Total operating expenses	670,431	561,138	3,655,252
Operating income (loss)	559,589	372,266	-2,845,278
Other income (expense), net:
Interest expense	-126,157	-101,486	-88,180
Gain (loss) on commodity derivatives	82,402	-46,754	73,581
Deferred gain on sale of liquids gathering system	10,553	10,553	0
Contract Cancellation Fees	0	0	-15,469
Gain on sale of property	8,022	0	0
Other income (expense) net	2,618	-357	-1,765
Total other income (expense), net	-22,562	-138,044	-31,833
Income (loss) before income tax (benefit)	537,027	234,222	-2,877,111
Income tax (benefit)	-5,824	-3,616	-700,213
Net income (loss)	$542,851	$237,838	($2,176,898)
Basic Earnings (Loss) per Share:
Earnings Per Share, Basic	$3.54	$1.55	($14.24)
Fully Diluted Earnings (Loss) per Share:
Earnings Per Share, Diluted	$3.51	$1.54	($14.24)
Weighted average common shares outstanding - basic	153,136,000	152,963,000	152,845,000
Weighted average common shares outstanding - fully diluted	154,694,000	154,426,000	152,845,000

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$8,919	$10,664
Restricted cash	117	119
Oil and gas revenue receivable	111,915	84,095
Joint interest billing and other receivables	32,502	17,725
Derivative assets	104,190	1,415
Other current assets	19,495	14,613
Total current assets	277,138	128,631
Oil And Gas Properties, Net, Using Full Cost Method Of Accounting [Abstract]
Proven	3,636,643	2,008,538
Unproven properties not being amortized	242,294	413,073
Property, plant and equipment	12,186	216,909
Deferred income taxes	30,640	6
Deferred financing costs and other	26,789	18,162
Total assets	4,225,690	2,785,319
Current liabilities:
Accounts payable	77,580	54,806
AccruedLiabilitiesCurrent	89,865	79,811
Production taxes payable	55,585	40,538
Senior Notes due March 2015	100,000	0
Interest Payable Current	46,098	31,865
Current deferred tax liabilities	30,638	0
Derivative liabilities	0	27,291
Capital cost accrual	45,952	173,165
Total current liabilities	445,718	407,476
Long-term debt	3,278,000	2,470,000
Deferred income tax liability	992	0
Deferred gain on sale of liquids gathering system	136,848	147,401
Other long-term obligations	152,472	91,932
CommitmentsAndContingencies
Shareholders' equity:
Common stock - no par value; authorized - unlimited; issued and outstanding - 152,896,315 and 152,990,123, respectively	495,913	487,273
Treasury stock	-6,213	-1,961
Retained earnings	-278,040	-816,802
Total shareholders' equity (deficit)	211,660	-331,490
Total liabilities and shareholders' equity	$4,225,690	$2,785,319

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	12 Months Ended
Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Consolidated Balance Sheets [Abstract]
Common stock, no par value	$0	$0
Common stock, shares authorized	unlimited	unlimited
Common stock, shares issued	152,896,315	152,990,123
Common stock, shares outstanding	152,896,315	152,990,123

Statement_of_Shareholders_Equi

Statement of Shareholders Equity (USD $)	Total	Common Stock [Member]	Retained Earnings [Member]	Treasury Stock [Member]
In Thousands, except Share data, unless otherwise specified	Total	Common Stock [Member]	Retained Earnings [Member]	Treasury Stock [Member]
Beginning Balance at Dec. 31, 2011	$1,593,709	$463,221	$1,145,439	($14,951)
Beginning Balance, Shares at Dec. 31, 2011		152,477,000
Stock options exercised	632	632
Stock options exercised, Shares		34,000
Employee stock plan grants	613	613		0
Employee stock plan grants, Shares		708,000
Shares re-issued from treasury	0	-1,245	-14,793	16,038
Shares repurchased	-1,100			-1,100
Shares repurchased, Shares		-50,000
Net share settlements	-5,618		-5,618
Net share settlements, Shares		-239,000
Fair value of employee stock plan grants	15,222	15,222
Tax benefit of stock options exercised	-4,427	-4,427
Comprehensive earnings:
Net earnings (loss)	-2,176,898		-2,176,898
Ending Balance at Dec. 31, 2012	-577,867	474,016	-1,051,870	-13
Ending Balance, Shares at Dec. 31, 2012		152,930,000
Stock options exercised	11	11
Stock options exercised, Shares		1,000
Employee stock plan grants	700	700
Employee stock plan grants, Shares		347,000
Shares re-issued from treasury	0	-711	-652	1,363
Shares repurchased	-3,311			-3,311
Shares repurchased, Shares		-165,000
Net share settlements	-2,118		-2,118
Net share settlements, Shares		-122,000
Fair value of employee stock plan grants	13,257	13,257
Comprehensive earnings:
Net earnings (loss)	237,838		237,838
Ending Balance at Dec. 31, 2013	-331,490	487,273	-816,802	-1,961
Ending Balance, Shares at Dec. 31, 2013		152,991,000
Stock options exercised	770	770
Stock options exercised, Shares		43,000
Employee stock plan grants	700	700
Employee stock plan grants, Shares		298,000
Shares re-issued from treasury	0	-770	-1,450	2,220
Shares repurchased	-6,472			-6,472
Shares repurchased, Shares		-332,000
Net share settlements	-2,639		-2,639
Net share settlements, Shares		-104,000
Fair value of employee stock plan grants	7,940	7,940
Comprehensive earnings:
Net earnings (loss)	542,851		542,851
Ending Balance at Dec. 31, 2014	$211,660	$495,913	($278,040)	($6,213)
Ending Balance, Shares at Dec. 31, 2014		152,896,000

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
Consolidated Statements of Cash Flows (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating activities:
Net (Loss) Income Attributable to Parent	$542,851,000	$237,838,000	($2,176,898,000)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depletion and depreciation	292,951,000	243,390,000	388,985,000
Ceiling test and other impairments	0	0	2,972,464,000
Deferred and current non-cash income taxes	995,000	-6,000	-712,576,000
Unrealized loss (gain) on commodity derivatives	-130,066,000	25,876,000	230,385,000
Deferred gain on sale of liquids gathering system	-10,553,000	-10,553,000	0
(Gain) on sale of property	-8,022,000	0	0
Excess tax benefit from stock based compensation	0	0	4,427,000
Stock compensation	5,467,000	9,767,000	10,756,000
Other	4,569,000	2,252,000	3,667,000
Net changes in operating assets and liabilities:
Restricted cash	2,000	2,000	0
Accounts receivable	-43,116,000	16,565,000	62,758,000
Prepaid expenses and other	-1,920,000	1,180,000	1,740,000
Other non-current assets	284,000	277,000	284,000
Accounts payable	28,696,000	-1,400,000	-37,964,000
Accrued liabilities	-5,938,000	-32,904,000	-77,633,000
Production taxes payable	15,115,000	-7,207,000	-14,372,000
Interest payable	14,233,000	1,772,000	-213,000
Other long-term obligations	6,427,000	3,296,000	-9,031,000
Current taxes payable	609,000	-17,507,000	8,046,000
Net cash provided by operating activities	712,584,000	472,638,000	654,825,000
Investing Activities:
Acquisition costs	-891,075,000	-649,801,000	0
Oil and gas property expenditures	-599,913,000	-370,662,000	-708,017,000
Gathering system expenditures	-6,842,000	-5,510,000	-127,149,000
Proceeds from sale of property	27,944,000	0	0
Proceeds from sale of liquids gathering system	0	-129,000	203,046,000
Proceeds from sale of marketable securities	0	0	21,235,000
Change in capital cost accrual	-125,577,000	-65,975,000	38,338,000
Inventory	175,000	-627,000	-374,000
Purchase of property, plant and equipment	-5,455,000	-815,000	-4,302,000
Net cash used in investing activities	-1,600,743,000	-1,093,519,000	-577,223,000
Financing activities:
Borrowings on long-term debt	1,095,000,000	1,006,000,000	852,000,000
Payments on long-term debt	-1,037,000,000	-823,000,000	-918,000,000
Proceeds from issuance of Senior Notes	850,000,000	450,000,000	0
Deferred financing costs	-13,245,000	-8,958,000	0
Repurchased shares/net share settlements	-9,111,000	-5,429,000	-6,718,000
Excess tax benefit from stock based compensation	0	0	-4,427,000
Proceeds from exercise of options	770,000	11,000	1,157,000
Net cash provided by (used in) financing activities	886,414,000	618,624,000	-75,988,000
(Decrease)/increase in cash during the period	-1,745,000	-2,257,000	1,614,000
Cash and cash equivalents, beginning of period	10,664,000	12,921,000	11,307,000
Cash and cash equivalents, end of period	8,919,000	10,664,000	12,921,000
Cash paid for:
Interest	108,889,000	99,542,000	101,237,000
Income taxes	1,752,000	13,843,000	4,379,000
Non Cash Investing Activities Oil And Gas Properties	$20,000,000	$12,651,000	$0

Significant_Accounting_Policie

Significant Accounting Policies	12 Months Ended
Significant Accounting Policies	Dec. 31, 2014
Significant Accounting Policies Disclosures [Abstract]
SIGNIFICANT ACCOUNTING POLICIES	1. SIGNIFICANT ACCOUNTING POLICIES:

	(a) Basis of presentation and principles of consolidation: The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company presents its financial statements in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). All inter-company transactions and balances have been eliminated upon consolidation.

	(b) Cash and cash equivalents: The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

	(c) Restricted cash: Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute.

	(d) Accounts receivable: Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts. The carrying amount of the Company’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables.

	(e) Property, plant and equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life. Previously, gathering system expenditures were recorded at cost and depreciated separately from proven oil and gas properties using the straight-line method due to the expectation that they would be used to transport production from probable and possible reserves, as well as from third parties. However, subsequent to the SWEPI Transaction (See Note 13), the Company’s remaining gathering systems are expected to only be used to transport the Company’s proved volumes and as a result, $91.8 million was transferred to proven oil and gas properties at September 30, 2014.

	(f) Oil and natural gas properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Separate cost centers are maintained for each country in which the Company incurs costs. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

	The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the proved reserves as determined by independent petroleum engineers. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement obligations are included in the base costs for calculating depletion.

	Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors. The amount of any impairment is transferred to the capitalized costs being amortized. For the years ended December 31, 2014 and 2013, the Company did not determine any impairment related to unevaluated properties or major development projects excluded from capitalized costs being amortized.

	Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil, natural gas and NGL prices may subsequently increase the ceiling.

	During 2012, the Company recorded a $2.9 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations, which is reflected within ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2012, September 30, 2012 and June 30, 2012 for Henry Hub natural gas and West Texas Intermediate oil, adjusted for market differentials. The Company did not have any write-downs related to the full cost ceiling limitation in 2014 or 2013.

	(g) Inventories: At December 31, 2014 and 2013, inventory of $10.2 million and $5.2 million primarily includes the cost of pipe and production equipment that will be utilized during the 2015 drilling program and crude oil inventory. Materials and supplies inventories are carried at lower of cost or market and include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. The Company uses the weighted average method of recording its materials and supplies inventory. Crude oil inventory is valued at lower of cost or market.

	(h) Derivative instruments and hedging activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 7).

	(i) Income taxes: Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.

	The Company has recorded a valuation allowance against certain deferred tax assets of $161.5 million as of December 31, 2014. Some or all of this valuation allowance may be reversed in future periods against future income.

	(j) Earnings (loss) per share: Basic earnings (loss) per share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted income (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect.

		The following table provides a reconciliation of components of basic and diluted net income (loss) per common share:

				December 31,
				2014		2013		2012

		Net income (loss)	$	542,851	$	237,838	$	-2,176,898

		Weighted average common shares outstanding
		during the period		153,136		152,963		152,845

		Effect of dilutive instruments		1,558		1,463		-	-1

		Weighted average common shares outstanding during
		the period including the effects of dilutive instruments		154,694		154,426		152,845

		Net income (loss) per common share - basic	$	3.54	$	1.55	$	-14.24

		Net income (loss) per common share - fully diluted	$	3.51	$	1.54	$	-14.24

		Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of
		the common shares		1,377		1,406		-	-1

	(1) Due to the net loss for the year ended December 31, 2012, 1.9 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of loss per share.

	(k) Use of estimates: Preparation of consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

	(l) Accounting for share-based compensation: The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation.

	(m) Fair value accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 8 for additional information.

	(n) Asset retirement obligation: The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.

(o) Revenue recognition: The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices and under multi-year contracts that provide for a fixed price of oil and natural gas. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.” Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. Any amount received in excess of the Company’s share of the volumes is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2014 and 2013, the Company had a net natural gas imbalance liability of $3.0 million and $3.3 million, respectively.

Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances.

(p) Capitalized interest: Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated, if any, as well as on work in process relating to gathering systems that are not currently in service.

(q) Capital cost accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period.

(r) Reclassifications: Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation.

(s) Recent accounting pronouncements: In August 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU No. 2014-15”) that will require management to evaluate whether there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Management will be required to provide certain footnote disclosures if it concludes that substantial doubt exists or when its plans alleviate substantial doubt about the Company’s ability to continue as a going concern. ASU No. 2014-15 becomes effective for annual periods beginning in 2016 and for interim reporting periods starting in the first quarter of 2017. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.

In June 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which supersedes the revenue recognition requirements in FASB ASC 605, Revenue Recognition, and in most industry-specific topics. ASU No. 2014-09 provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. ASU No. 2014-09 becomes effective at the beginning of 2017. The Company is still evaluating the impact of ASU No. 2014-09 on its financial position and results of operations.

In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures. The guidance is effective for annual and interim reporting periods beginning after December 15, 2014. Adoption of this amendment will not have a material effect on our financial position or results of operations.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2014
Asset Retirement Obligations Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	2. ASSET RETIREMENT OBLIGATIONS:

	The Company is required to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The following table summarizes the activities for the Company’s asset retirement obligations for the years ended:

				December 31,
				2014		2013

		Asset retirement obligations at beginning of period	$	72,807	$	60,814
		Accretion expense		6,571		5,171
		Liabilities incurred		10,242		7,730
		Liabilities acquired(1)		53,270		-
		Liabilities divested(1)		-15,760		-
		Liabilities settled		-336		-2,334
		Revisions of estimated liabilities		446		1,426
		Asset retirement obligations at end of period		127,240		72,807
		Less: current asset retirement obligations		-417		-96
		Long-term asset retirement obligations	$	126,823	$	72,711

	(1)On September 25, 2014, a wholly owned subsidiary of Ultra Petroleum Corp. completed the acquisition of all producing and non-producing properties in the Pinedale field in Sublette County, Wyoming in exchange for certain of the Company’s producing and non-producing properties in Pennsylvania and a cash payment (See Note 13 for further details).

Oil_and_Gas_Properties

Oil and Gas Properties	12 Months Ended
Oil and Gas Properties	Dec. 31, 2014
Oil and Gas Properties And Equipment Tables [Abstract]
OIL AND GAS PROPERTIES	3. OIL AND GAS PROPERTIES:

				December 31,		December 31,
				2014		2013
		Proven Properties:
		Acquisition, equipment, exploration, drilling and environmental costs(2), (3)	$	9,731,407	$	7,817,374
		Less: Accumulated depletion, depreciation and amortization		-6,094,764		-5,808,836
				3,636,643		2,008,538
		Unproven Properties:
		Acquisition and exploration costs not being amortized (1), (2)		242,294		413,073
		Net capitalized costs - oil and gas properties	$	3,878,937	$	2,421,611

	On a unit basis, DD&A from continuing operations was $1.18, $1.05 and $1.51 per Mcfe for the years ended December 31, 2014, 2013 and 2012, respectively.

	(1) Interest is capitalized on the cost of unevaluated oil and natural gas properties that are excluded from amortization and actively being evaluated as well as on work in process relating to gathering systems that are not currently in service. For the years ended December 31, 2014 and 2013, total interest on outstanding debt was $146.6 million and $103.5 million, respectively, of which $20.4 million and $2.0 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and work in process relating to gathering systems that are not currently in service.

	(2) On December 12, 2013 the Company, through its subsidiary, UPL Three Rivers Holdings, LLC, closed on the acquisition of crude oil assets located in Three Rivers Field in Uintah County, Utah. The assets consist of producing wells, undeveloped acreage and water and gas gathering assets.

	(3) On September 25, 2014, a wholly owned subsidiary of Ultra Petroleum Corp. completed the acquisition of all producing and non-producing properties (including gathering systems) in the Pinedale field in Sublette County, Wyoming (the “SWEPI Properties”) from SWEPI, LP, an affiliate of Royal Dutch Shell, plc in exchange for certain of the Company’s producing and non-producing properties (including gathering systems) in Pennsylvania (the “Pennsylvania Properties”) and a cash payment. See Note 13.

	Unproven Properties

	The Company holds interests in domestic projects in which costs related to these interests are not being depleted pending determination of existence of estimated proved reserves. For the years ended December 31, 2014 and 2013, the Company did not determine any impairment related to unevaluated properties or major development projects excluded from capitalized costs being amortized.

				Total		2014		2013		2012		Prior
		Acquisition costs	$	228,516	$	-191,184	$	419,700	$	-481,689	$	481,689
		Exploration costs		-7,708		173		-7,881		-9,962		9,962
		Capitalized interest		21,486		20,232		1,254		-45,875		45,875
		Unproven properties	$	242,294	$	-170,779	$	413,073	$	-537,526	$	537,526

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
Property, Plant and Equipment	Dec. 31, 2014
Property Plant And Equipment Disclosure [Abstract]
PROPERTY, PLANT AND EQUIPMENT	4. PROPERTY, PLANT AND EQUIPMENT:

			December 31,
			2014						2013
			Cost		Accumulated Depreciation		Net Book Value		Net Book Value
	Gathering systems(1)(2)	$	-	$	-	$	-	$	189,110
	Computer equipment		2,967		-2,050		917		892
	Office equipment		467		-410		57		41
	Leasehold improvements		471		-360		111		136
	Land(3)		5,778		-		5,778		22,359
	Other		13,656		-8,333		5,323		4,371
	Property, plant and equipment, net	$	23,339	$	-11,153	$	12,186	$	216,909

	(1)Historically, gathering system expenditures were recorded at cost and depreciated separately from proven oil and gas properties using the straight-line method due to the expectation that they would be used to transport production from probable and possible reserves, as well as from third parties. However, subsequent to the SWEPI Transaction (See Note 13), the Company’s remaining gathering systems are expected to only be used to transport the Company’s proved volumes and as a result, $91.8 million has been transferred to proven oil and gas properties.

	(2)On September 25, 2014, a wholly owned subsidiary of Ultra Petroleum Corp. completed the acquisition of all producing and non-producing properties (including gathering systems) in the Pinedale field in Sublette County, Wyoming in exchange for certain of the Company’s producing and non-producing properties (including gathering systems) in Pennsylvania and a cash payment (See Note 13 for further details).

	(3)During November 2014, the Company sold certain real property in El Paso County, Colorado for proceeds of $27.9 million.

Long_Term_Liabilities

Long Term Liabilities	12 Months Ended
Long Term Liabilities	Dec. 31, 2014
Long Term Liabilities Tables [Abstract]
LONG-TERM LIABILITIES	5. DEBT AND OTHER LONG-TERM LIABILITIES:

				December 31,		December 31,
				2014		2013
		Short-term debt:
		Senior Notes due March 2015	$	100,000	$	-

		Long-term debt and other long-term liabilities:
		Bank indebtedness		518,000		460,000
		Senior notes		2,760,000		2,010,000
		Other long-term obligations		152,472		91,932

			$	3,530,472	$	2,561,932

		Aggregate maturities of debt at December 31, 2014:
													Beyond
			2015		2016		2017		2018		2019		5 years		Total
		$	100,000	$	580,000	$	116,000	$	650,000	$	173,000	$	1,759,000	$	3,378,000

	Ultra Resources, Inc. Bank Indebtedness –

	Bank indebtedness. The Company (through its subsidiary, Ultra Resources, Inc.) is a party to a senior revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. (the “Credit Agreement”). The Credit Agreement provides an initial loan commitment of $1.0 billion, which may be increased up to $1.25 billion at the request of the borrower and with the consent of lenders who are willing to increase their loan commitments, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016. With the majority (over 50%) lender consent, the term of the consenting lenders’ commitments may be extended for up to two successive one-year periods at the Borrower’s request. At December 31, 2014, the Company had $518.0 million in outstanding borrowings and $482.0 million of available borrowing capacity under the Credit Agreement.

	Loans under the Credit Agreement are unsecured and bear interest, at the Borrower’s option, based on (A) a rate per annum equal to the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus a margin based on a grid of Ultra Resources, Inc.’s consolidated leverage ratio (100 basis points as of December 31, 2014) or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of the Borrower’s consolidated leverage ratio (200 basis points per annum as of December 31, 2014). The Company also pays commitment fees on the unused commitment under the facility based on a grid of its consolidated leverage ratio. For the year ended December 31, 2014, the Company incurred $2.0 million in commitment fees associated with its credit facility.

	The Credit Agreement contains typical and customary representations, warranties, covenants and events of default. The Credit Agreement includes restrictive covenants requiring the Borrower to maintain a consolidated leverage ratio of no greater than three and one half times to one and, as long as Ultra Resources, Inc.’s debt rating is below investment grade, the maintenance of an annual ratio of the net present value of Ultra Resources, Inc.’s oil and gas properties to total funded debt of no less than one and one half times to one. At December 31, 2014, the Company was in compliance with all of its debt covenants under the Credit Agreement.

	Ultra Resources, Inc. Senior Notes –

	Ultra Resources also has outstanding $1.56 billion in principal amount of Senior Notes. Ultra Resources’ Senior Notes rank pari passu with the Company’s Credit Agreement. Payment of the Senior Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. The Senior Notes are pre-payable in whole or in part at any time following the payment of a make-whole premium and are subject to representations, warranties, covenants and events of default similar to those in the Credit Facility. At December 31, 2014, the Company was in compliance with all of its debt covenants under the Senior Notes.

	Ultra Petroleum Corp. Senior Notes –

	Senior Notes due 2024: On September 18, 2014, the Company issued $850.0 million of 6.125% Senior Notes due 2024 (“2024 Notes”). The 2024 Notes are general, unsecured senior obligations of the Company and mature on October 1, 2024. The 2024 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2024 Notes are not guaranteed by the Company’s subsidiaries and so are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. On and after October 1, 2019, the Company may redeem all or, from time to time, a part of the 2024 Notes at the following prices expressed as a percentage of principal amount of the 2024 Notes: (2019 – 103.063%; 2020 – 102.042%; 2021 – 101.021%; and 2022 and thereafter – 100.000%). The 2024 Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. In addition, the 2024 Notes contain events of default customary for a senior note financing. At December 31, 2014, the Company was in compliance with all of its debt covenants under the 2024 Notes.

	Senior Notes due 2018: On December 12, 2013, the Company issued $450.0 million of 5.75% Senior Notes due 2018 (“2018 Notes”). The 2018 Notes are general, unsecured senior obligations of the Company and mature on December 15, 2018. The 2018 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2018 Notes are not guaranteed by the Company’s subsidiaries and so are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. On and after December 15, 2015, the Company may redeem all or, from time to time, a part of the 2018 Notes at the following prices expressed as a percentage of principal amount of the 2018 Notes: (2015 – 102.875%; 2016 – 101.438%; and 2017 and thereafter – 100.000%). The 2018 Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. In addition, the 2018 Notes contain events of default customary for a senior note financing. At December 31, 2014, the Company was in compliance with all of its debt covenants under the 2018 Notes.

	Other long-term obligations: These costs primarily relate to the long-term portion of production taxes payable and our asset retirement obligations.

Share_Based_Compensation

Share Based Compensation	12 Months Ended
Share Based Compensation	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
SHARE BASED COMPENSATION	6. SHARE BASED COMPENSATION:

	The Company sponsors two share based compensation plans: the 2005 Stock Incentive Plan (the “2005 Plan”) and the 2015 Stock Incentive Plan (“2015 Plan”; and together with the 2005 Plan, the “Plans”). The Plans are administered by the Compensation Committee of the Board of Directors (the “Committee”). The share based compensation plan is an important component of the total compensation package offered to the Company’s key service providers, and reflects the importance that the Company places on motivating and rewarding superior results.

	The 2005 Plan was adopted by the Company’s Board of Directors on January 1, 2005 and approved by the Company’s shareholders on April 29, 2005. The 2015 Plan was adopted by the Company’s Board of Directors on March 31, 2014 and approved by our shareholders on May 20, 2014. The purpose of the Plans is to foster and promote the long-term financial success of the Company and to increase shareholder value by attracting, motivating and retaining key employees, consultants, and outside directors, and providing such participants with a program for obtaining an ownership interest in the Company that links and aligns their personal interests with those of the Company’s shareholders, and thus, enabling such participants to share in the long-term growth and success of the Company. To accomplish these goals, the Plans permit the granting of incentive stock options, non-statutory stock options, stock appreciation rights, restricted stock, and other stock-based awards, some of which may require the satisfaction of performance-based criteria in order to be payable to participants. The Committee determines the terms and conditions of the awards, including, any vesting requirements and vesting restrictions and estimates forfeitures that may occur. The Committee may grant awards under the 2005 Plan until December 31, 2014, unless terminated sooner by the Board of Directors, and under the 2015 Plan until December 31, 2024.

		Valuation and Expense Information
				Year Ended December 31,
				2014		2013		2012

		Total cost of share-based payment plans	$	8,640	$	13,957	$	15,835
		Amounts capitalized in oil and gas properties and equipment	$	3,173	$	4,190	$	5,079
		Amounts charged against income, before
		income tax benefit	$	5,467	$	9,767	$	10,756
		Amount of related income tax benefit recognized
		in income before valuation allowances	$	2,285	$	4,083	$	4,463

	Securities Authorized for Issuance Under Equity Compensation Plans

	As of December 31, 2014, the Company had the following securities issuable pursuant to outstanding award agreements or reserved for issuance under the Company’s previously approved stock incentive plans. Upon exercise, shares issued will be newly issued shares or shares issued from treasury.

							Number of Securities
							Remaining Available
			Number of				for Future Issuance
			Securities to		Weighted		Under Equity
			be Issued		Average		Compensation Plans
			Upon Exercise of		Exercise Price of		(Excluding Securities
			Outstanding		Outstanding		Reflected in the
	Plan Category		Options		Options		First Column)
	Equity compensation plans approved by		(000's)				(000's)
	security holders		690		$56.58		2,608
	Equity compensation plans not approved
	by security holders		n/a		n/a		n/a
	Total		690		$56.58		2,608

	Changes in Stock Options and Stock Options Outstanding

	The following table summarizes the changes in stock options for the three year period ended December 31, 2014:

					Weighted
					Average
			Number of		Exercise Price
			Options		(US$)
			(000's)
		Balance, December 31, 2011	1,459		$16.97	to	$98.87

		Forfeited	-68		$25.08	to	$75.18
		Exercised	-34		$16.97	to	$19.18

		Balance, December 31, 2012	1,357		$16.97	to	$98.87

		Forfeited	-110		$25.68	to	$75.18
		Exercised	-1		$16.97	to	$16.97

		Balance, December 31, 2013	1,246		$16.97	to	$98.87

		Forfeited	-513		$33.57	to	$75.18
		Exercised	-43		$16.97	to	$25.68

		Balance, December 31, 2014	690		$25.68	to	$98.87

	The following table summarizes information about the stock options outstanding and exercisable at December 31, 2014:


					Options Outstanding and Exercisable
							Weighted		Weighted
							Average		Average	Aggregate
					Number		Remaining		Exercise	Intrinsic
Range of Exercise Price					Outstanding		Contractual Life		Price	Value
					(000's)		(Years)
$	25.68	-	$	53.39	126		0.64		$44.25	$-
$	50.15	-	$	65.04	125		1.55		$57.00	$-
$	49.05	-	$	62.23	281		2.28		$53.85	$-
$	51.6	-	$	98.87	158		3.43		$70.92	$-

The aggregate intrinsic value in the preceding tables represents the total pre-tax intrinsic value, based on the Company’s closing stock price of $13.16 per share on December 31, 2014, which would have been received by the option holders had all option holders exercised their options as of that date. There were no in-the-money options exercisable as of December 31, 2014.

The following table summarizes information about the weighted-average grant-date fair value of share options:

			2014		2013		2012
	Options forfeited during the year	$	24.4	$	25.44	$	27.05

As of December 31, 2011, all options were fully vested; therefore, no options vested during the years ended December 31, 2014, 2013 or 2012. The total intrinsic value of stock options exercised during the years ended December 31, 2014, 2013 and 2012 was $0.4 million, immaterial and $0.3 million, respectively.

At December 31, 2014, there was no unrecognized compensation cost related to non-vested, employee stock options as all options fully vested as of December 31, 2011.

PERFORMANCE SHARE PLANS:

Long Term Incentive Plans. The Company offers a Long Term Incentive Plan (“LTIP”) in order to further align the interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company when specific corporate financial and operational goals are achieved. Each LTIP covers a performance period of three years. In 2012, 2013 and 2014, the Compensation Committee (the “Committee”) approved an award consisting of performance-based restricted stock units to be awarded to each participant.

For each LTIP award, the Committee establishes performance measures at the beginning of each three-year performance period. Under each LTIP, the Committee also establishes a percentage of base salary for each participant which is multiplied by the participant’s base salary at the beginning of the performance period and individual performance level to derive a Long Term Incentive Value as a “target” value. This target value corresponds to the number of shares of the Company’s common stock the participant is eligible to receive if the participant is employed by the Company through the date the award vests and if the target level for all performance measures is met. In addition, each participant is assigned threshold and maximum award levels in the event that actual performance is below or above target levels. For the LTIP awards in 2012, the Committee established the following performance measures: return on equity, reserve replacement ratio, and production growth. For the LTIP awards in 2014 and 2013, the Committee established the following performance measures: return on capital employed, debt level, reserve replacement ratio, and total shareholder return (officers only).

For the year ended December 31, 2014, the Company recognized $6.3 million in pre-tax compensation expense related to the 2012, 2013 and 2014 LTIP awards of restricted stock units. For the year ended December 31, 2013, the Company recognized $6.9 million in pre-tax compensation expense related to the 2011, 2012 and 2013 LTIP awards of restricted stock units. For the year ended December 31, 2012, the Company recognized $7.9 million in pre-tax compensation expense related to the 2010, 2011 and 2012 LTIP awards of restricted stock units. The amounts recognized during the year ended December 31, 2014 assumes that performance objectives between target and maximum are attained for the 2012 LTIP and maximum performance objectives are attained under the 2013 LTIP and 2014 LTIP plans. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at December 31, 2014, for each of the three year performance periods is expected to be approximately $10.2 million, $12.6 million, and $13.0 million related to the 2012, 2013 and 2014 LTIP awards of restricted stock units, respectively. The 2011 LTIP Common Stock Award was paid in shares of the Company’s stock to employees during the first quarter of 2014 and totaled $8.4 million (106,437 net shares).

Derivative_Financial_Instrumen

Derivative Financial Instruments	12 Months Ended
Derivative Financial Instruments	Dec. 31, 2014
Derivative Financial Instruments Disclosure [Abstract]
DERIVATIVE FINANCIAL INSTRUMENTS	7. DERIVATIVE FINANCIAL INSTRUMENTS:

	Objectives and Strategy: The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s Wyoming natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue. As a result of its hedging activities, the Company may realize prices that are less than or greater than the spot prices that it would have received otherwise.

	The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in the Company’s forward cash flows supporting the Company’s capital investment program.

	The Company’s hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production without Board approval.

	Fair Value of Commodity Derivatives: FASB ASC 815 requires that all derivatives be recognized on the balance sheet as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments.

	Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current expense or income in the Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the Consolidated Statements of Cash Flows.

	Commodity Derivative Contracts: At December 31, 2014, the Company had the following open commodity derivative contracts to manage price risk on a portion of its production whereby the Company receives the fixed price and pays the variable price. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties.

		Natural Gas:
		Type		Commodity Reference Price		Remaining Contract Period		Volume - MMBTU/Day	Average Price/MMBTU		Fair Value - December 31, 2014
											Asset
		Swap		NYMEX-Henry Hub		Jan - Mar 2015		210,000	$4.54	$	29,201
		Swap		NYMEX-Henry Hub		Apr - Oct 2015		522,500	$3.65	$	74,989

	Subsequent to December 31, 2014 and through February 11, 2015, the Company has entered into the following open commodity derivative contracts to manage price risk on a portion of its production whereby the Company receives the fixed price and pays the variable price:

		Natural Gas:
		Type		Commodity Reference Price		Remaining Contract Period		Volume - MMBTU/Day	Average Price/MMBTU

		Swap		NYMEX-Henry Hub		Apr - Oct 2015		150,000	$2.98

	The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012:

				For the Year Ended December 31,
		Commodity Derivatives:		2014		2013		2012
		Realized (loss) gain on commodity derivatives-natural gas (1)	$	-48,170	$	-20,552	$	303,966
		Realized gain (loss) on commodity derivatives-crude oil (1)		506		-326		-
		Unrealized gain (loss) on commodity derivatives (1)		130,066		-25,876		-230,385
		Total gain (loss) on commodity derivatives	$	82,402	$	-46,754	$	73,581

		(1) Included in gain (loss) on commodity derivatives in the Consolidated Statements of Operations.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
Fair Value Measurements	Dec. 31, 2014
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	8. FAIR VALUE MEASUREMENTS:

	As required by FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), the Company defines fair value as 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 and establishes a three level hierarchy for measuring fair value. Fair value measurements are classified and disclosed in one of the following categories:

	Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

	Level 2: Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps.

	Level 3: Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

	The valuation assumptions the Company has used to measure the fair value of its commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs).

				Level 1		Level 2		Level 3		Total
		Assets:
		Current derivative asset	$	-	$	104,190	$	-	$	104,190

	In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

	Assets and Liabilities Measured on a Non-recurring Basis

	The Company uses fair value to determine the value of its asset retirement obligations (“ARO”). The inputs used to determine such fair value under the expected present value technique are primarily based upon internal estimates prepared by reservoir engineers for costs of dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and gas properties and would be classified Level 3 inputs.

	Fair Value of Financial Instruments

	The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. We use available market data and valuation methodologies to estimate the fair value of our fixed rate debt. The inputs utilized to estimate the fair value of the Company’s fixed rate debt are considered Level 2 fair value inputs. This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact our financial position, results of operations or cash flows.

				31-Dec-14				31-Dec-13
				Carrying		Estimated		Carrying		Estimated
				Amount		Fair Value		Amount		Fair Value
		5.45% Notes due March 2015, issued 2008	$	100,000	$	101,931	$	100,000	$	105,913
		7.31% Notes due March 2016, issued 2009		62,000		65,027		62,000		70,228
		4.98% Notes due January 2017, issued 2010		116,000		116,240		116,000		126,342
		5.92% Notes due March 2018, issued 2008		200,000		203,738		200,000		226,127
		5.75% Notes due December 2018, issued 2013		450,000		414,505		450,000		466,946
		7.77% Notes due March 2019, issued 2009		173,000		187,105		173,000		211,877
		5.50% Notes due January 2020, issued 2010		207,000		201,371		207,000		229,068
		4.51% Notes due October 2020, issued 2010		315,000		283,335		315,000		323,732
		5.60% Notes due January 2022, issued 2010		87,000		82,581		87,000		95,736
		4.66% Notes due October 2022, issued 2010		35,000		30,476		35,000		35,494
		6.125% Notes due October 2024, issued 2014		850,000		754,485		-		-
		5.85% Notes due January 2025, issued 2010		90,000		83,876		90,000		99,142
		4.91% Notes due October 2025, issued 2010		175,000		147,649		175,000		175,744
		Credit Facility due October 2016		518,000		518,000		460,000		460,000
			$	3,378,000	$	3,190,319	$	2,470,000	$	2,626,349

Income_Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2014
Income Taxes Disclosure [Abstract]
INCOME TAXES	9. INCOME TAXES:

	Income (loss) before income tax benefit is as follows:

			Year Ended December 31,
			2014		2013		2012
	United States	$	505,689	$	210,580	$	-2,892,207
	Foreign		31,338		23,642		15,096
	Total	$	537,027	$	234,222	$	-2,877,111


	The consolidated income tax (benefit) provision is comprised of the following:
			Year Ended December 31,
			2014		2013		2012
	Current tax:
	U.S. federal, state and local	$	-110	$	-8,491	$	9,037
	Foreign		-6,709		4,881		3,326
	(Reduction in) current tax benefit on stock based compensation:
	U.S. federal, state and local		-		-		-4,427
	Total current tax expense (benefit)		-6,819		-3,610		7,936
	Deferred tax:
	U.S. federal, state and local		-		-		-708,160
	Foreign		995		-6		11
	Total deferred tax expense (benefit)		995		-6		-708,149
	Total income tax (benefit) provision	$	-5,824	$	-3,616	$	-700,213

	The income tax provision (benefit) from continuing operations differs from the amount that would be computed by applying the U.S. federal income tax rate of 35% to pretax income as a result of the following:


			Year Ended December 31,
			2014		2013		2012
	Income tax provision (benefit) computed at the U.S. statutory rate	$	187,959	$	81,978	$	-1,006,989
	State income tax provision (benefit) net of federal benefit		8,023		1,329		-136,112
	Valuation allowance		-199,038		-81,923		446,148
	Tax effect of rate change		15,457		-2,871		1,358
	Foreign rate differential		-16,314		-3,508		-5,531
	Other, net		-1,911		1,379		913

	Total income tax (benefit) provision	$	-5,824	$	-3,616	$	-700,213


	The tax effects of temporary differences that give rise to significant components of the Company's deferred tax assets and liabilities are as follows:
					December 31,
					2014		2013
	Deferred tax assets - current:
	Derivative instruments, net			$	-	$	9,636
	Incentive compensation/other, net				6,150		7,641
					6,150		17,277
	Valuation allowance				-		-16,778
	Net deferred tax assets - current			$	6,150	$	499
	Deferred tax liabilities - current:
	Derivative instruments, net			$	36,788	$	499
	Net deferred tax liabilities - current			$	36,788	$	499
	Net deferred tax liability - current			$	30,638	$	-
	Deferred tax assets - non-current:
	Property and equipment				-		131,340
	Deferred gain				48,319		52,045
	U.S. federal tax credit carryforwards				16,144		16,254
	U.S. net operating loss carryforwards				147,336		71,843
	U.S. state net operating loss carryforwards				53,654		36,205
	Asset retirement obligations				45,039		26,876
	Incentive compensation/other, net				19,142		13,007
					329,634		347,570
	Valuation allowance				-161,480		-346,596
Net deferred tax assets - non-current			$	168,154	$	974
Deferred tax liabilities - non-current:
Property and equipment				137,514		-
Other				-		968
Net non-current tax liabilities			$	137,514	$	968
Net non-current tax asset			$	30,640	$	6
Deferred tax liabilities - non-current:
Other - non-US				992		-


In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible. Among other items, management considers the scheduled reversal of deferred tax liabilities, historical taxable income, projected future taxable income, and available tax planning strategies.

At December 31, 2014 and 2013, the Company recorded a valuation allowance against certain deferred tax assets of $161.5 million and $363.4 million, respectively. Some or all of this valuation allowance may be reversed in future periods against future income. The Company’s valuation allowance changed by $201.9 million from December 31, 2013 to December 31, 2014. Of this amount, $199.0 million reduced the Company’s current year deferred tax expense, and $2.9 million was reflected through shareholders’ equity.

As of December 31, 2014, the Company had approximately $14.1 million of U.S. federal alternative minimum tax (AMT) credits available to offset regular U.S. Federal income taxes. These AMT credits do not expire and can be carried forward indefinitely. The Company has $0.5 million of general business credits available to offset U.S. federal income taxes. These general business credits expire in 2032. In addition, the Company has $1.7 million of foreign tax credit carryforwards, none of which expire prior to 2017.

The Company generated a U.S. federal tax loss of $214.9 million and $260.1 million for the years ended December 31, 2014 and 2013, respectively. Of the 2013 loss, $54.5 million was carried back to offset taxable income generated in prior tax years. An income tax receivable of $8.0 million was recorded at December 31, 2013 and was reflected as a reduction in income tax expense in the Consolidated Statements of Operations for the year ended December 31, 2013. The remaining U.S. federal tax net operating loss of $420.9 million will be carried forward to offset taxable income generated in future years, and if unutilized, will expire in 2033 and 2034. The Company has Pennsylvania state tax net operating loss carry forwards of $798.4 million which will expire between 2031 and 2034. The Company has immaterial state tax net operating loss carry forwards in other jurisdictions, none of which expire prior to 2020.

The Company generated a Canada Federal and Provincial tax loss of $23.8 million for the year ended December 31, 2014. This loss will be carried back to offset taxable income generated in the prior three tax years. An income tax receivable of $6.2 million has been recorded at December 31, 2014 and is reflected as a reduction in 2014 income tax expense in the Consolidated Statement of Operations. As a result of this carryback, no Canada Federal and Provincial tax loss will be carried forward to offset taxable income generated in future years.

The Company did not have any unrecognized tax benefits and there was no effect on our financial condition or results of operations related to accounting for uncertain tax positions. The amount of unrecognized tax benefits did not change as of December 31, 2014.

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the Consolidated Statements of Operations. The Company has not incurred any interest or penalties associated with unrecognized tax benefits.

The Company files a consolidated federal income tax return in the United States federal jurisdiction and various combined, consolidated, unitary, and separate filings in several states, and international jurisdictions. With certain exceptions, the income tax years 2011 through 2014 remain open to examination by the major taxing jurisdictions in which the Company has business activity.

The undistributed earnings of the Company’s U.S. subsidiaries are considered to be indefinitely invested outside of Canada. Accordingly, no provision for Canadian income taxes and/or withholding taxes has been provided thereon.

Employee_Benefits

Employee Benefits	12 Months Ended
Employee Benefits	Dec. 31, 2014
Compensation And Retirement Disclosure [Abstract]
EMPLOYEE BENEFITS	10. EMPLOYEE BENEFITS:

	The Company sponsors a qualified, tax-deferred savings plan in accordance with provisions of Section 401(k) of the Internal Revenue Code for its employees. Employees may defer 100% of their compensation, subject to limitations. The Company matches all of the employee’s contribution up to 5% of compensation, as defined by the plan, along with an employer discretionary contribution of 8%. The expense associated with the Company’s contribution was $2.0 million, $1.6 million and $1.8 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2014
Commitements And Contingencies Disclosures [Abstract]
COMMITMENTS AND CONTINGENCIES	11. COMMITMENTS AND CONTINGENCIES:

	Transportation contract. The Company is an anchor shipper on REX securing pipeline infrastructure providing sufficient capacity to transport a portion of its natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for its natural gas in the future. REX begins at the Opal Processing Plant in southwest Wyoming and traverses Wyoming and several other states to an ultimate terminus in eastern Ohio. The Company’s commitment involves a capacity of 200 MMMBtu per day of natural gas through November 2019, and the Company is obligated to pay REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper.

	Subsequently, the Company entered into agreements to secure an additional capacity of 50 MMMBtu per day on the REX pipeline system, beginning in January 2012 through December 2018. This additional capacity provides the Company with the ability to move additional volumes from its producing wells in Wyoming to markets in the eastern U.S.

	The Company currently projects that demand charges related to the remaining term of the contract will total approximately $469.0 million.

	Operating lease. During December 2012, the Company sold its system of pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming and entered into a long-term, triple net lease agreement (the “Lease Agreement”) relating to the use of the LGS. The Lease Agreement provides for an initial term of 15 years and potential successive renewal terms of 5 years or 75% of the then remaining useful life of the LGS at the sole discretion of the Company. Annual rent for the initial term under the Lease Agreement is $20.0 million (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. The lease is classified as an operating lease. The Company currently projects that lease payments related to the Lease Agreement will total approximately $268.0 million.

	All of the Company’s lease obligations are related to leases that are classified as operating leases. These leases contain certain provisions that could result in accelerated lease payments. The Company has considered the effect of these provisions on minimum lease payments in its lease classification analysis and has determined that the default provisions do not impact classification of any the Company’s operating leases.

	Drilling contracts. As of December 31, 2014, the Company had committed to drilling obligations totaling $33.0 million ($31.6 million in 2015 and the remainder in 2016). The commitments expire in 2016 and were entered into to fulfill the Company’s drilling program initiatives.

	Office space lease. The Company maintains office space in Colorado, Texas, Wyoming and Pennsylvania with total remaining commitments for office leases of $8.6 million at December 31, 2014 ($1.0 million in 2015; $1.3 million in 2016; $1.3 million in 2017; $1.2 million in 2018; and $1.1 million in 2019 with the remainder due beyond five years).

	During the years ended December 31, 2014, 2013 and 2012, the Company recognized expense associated with its office leases in the amount of $1.0 million, $1.0 million, and $1.0 million, respectively.

	Delivery Commitments. With respect to the Company’s natural gas production, from time to time the Company enters into transactions to deliver specified quantities of gas to its customers. As of February 9, 2015, the Company has long-term natural gas delivery commitments of 1.2 MMMBtu in 2015, 26.2 MMMBtu in 2016, and 7.9 MMMBtu in 2017 under existing agreements. As of February 9, 2015, the Company has long-term crude oil delivery commitments of 2.4 MMBbls in 2015, 2.4 MMBbls in 2016, 1.7 MMBbls in 2017, 0.7 MMBbls in 2018 and 0.2 MMBbls in 2019 under existing agreements. None of these commitments require the Company to deliver gas or oil produced specifically from any of the Company’s properties, and all of these commitments are priced on a floating basis with reference to an index price.

	These committed volumes are below the Company’s forecasted 2015 and anticipated 2016 through 2019 production from its available reserves. In addition, none of the Company’s reserves are subject to any priorities or curtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agencies or any other factors beyond the Company’s control that may affect its ability to meet its contractual obligations other than those discussed in Item 1A. “Risk Factors”. The Company believes that its reserves are adequate to meet its commitments. If for some reason the Company’s production is not sufficient to satisfy its commitments, the Company expects to be able to purchase volumes in the market or make other arrangements to satisfy its commitments.

	Other. The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, management, after consultation with legal counsel, is of the opinion that the final resolution of all such currently pending or threatened litigation is not likely to have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company.

Credit_Risk

Credit Risk	12 Months Ended
Credit Risk	Dec. 31, 2014
Credit Risk [Abstract]
CREDIT RISK	12. CONCENTRATION OF CREDIT RISK:

	The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and commodity derivative contracts associated with the Company’s hedging program. The Company’s revenues related to natural gas and oil sales are derived principally from a diverse group of companies, including major energy companies, natural gas utilities, oil refiners, pipeline companies, local distribution companies, financial institutions and end-users in various industries.

	Concentrations of credit risk with respect to receivables is limited due to the large number of customers and their dispersion across geographic areas. Commodity-based contracts may expose the Company to the credit risk of nonperformance by the counterparty to these contracts. This credit exposure to the Company is diversified primarily among as many as ten major investment grade institutions and will only be present if the reference price of natural gas established in those contracts is less than the prevailing market price of natural gas, from time to time.

	The Company maintains credit policies intended to monitor and mitigate the risk of uncollectible accounts receivable related to the sale of natural gas, condensate as well as its commodity derivative positions. The Company performs a credit analysis of each of its customers and counterparties prior to making any sales to new customers or extending additional credit to existing customers. Based upon this credit analysis, the Company may require a standby letter of credit or a financial guarantee. The Company did not have any outstanding, uncollectible accounts for its natural gas or oil sales, nor derivative settlements at December 31, 2014.

	A significant counterparty is defined as one that individually accounts for 10% or more of the Company’s total revenues during the year. In 2014, the Company had no single customer that represented 10% or more of its total revenues.

Completion_of_Acquisition_and_

Completion of Acquisition and Disposition of Assets	12 Months Ended
Completion of Acquisition and Disposition of Assets	Dec. 31, 2014
Business Combination Description [Abstract]
COMPLETION OF ACQUISITION AND DISPOSITION OF ASSETS	13. COMPLETION OF ACQUISITION AND DISPOSITION OF ASSETS:

	On September 25, 2014, a wholly owned subsidiary of Ultra Petroleum Corp. completed the acquisition of all producing and non-producing properties (including gathering systems) in the Pinedale field in Sublette County, Wyoming (the “SWEPI Properties”) from SWEPI LP, an affiliate of Royal Dutch Shell, plc in exchange for certain of the Company’s producing and non-producing properties (including gathering systems) in Pennsylvania (the “Pennsylvania Properties”) and a cash payment of $925.0 million (the “SWEPI Transaction”) pursuant to a Purchase and Sale Agreement dated August 13, 2014 (“PSA”). In connection with the transaction, the Company settled certain liabilities with SWEPI, LP that were incurred prior to the effective date. The effective date of the transaction is April 1, 2014.

	On September 18, 2014, the Company issued $850.0 million of 6.125% Senior Notes due 2024 (“2024 Notes”) in order to finance a portion of the purchase price of the SWEPI Transaction. The remainder of the cash payment was funded through borrowings under the Company’s senior revolving credit facility. See Note 5.

	The costs related to the issuance of the 2024 Notes of $13.1 million are included with deferred financing costs and other on the Consolidated Balance Sheets and will be amortized over the term of the 2024 Notes. Additionally, the Company incurred $0.6 million of costs associated with the acquisition, which are included with general and administrative expenses in the Consolidated Statements of Operations.

	The SWEPI Properties that we acquired consist primarily of 19,600 net mineral acres in Wyoming and associated oil and gas production and wells and the Pennsylvania Properties that we sold consist primarily of 155,000 net acres in Pennsylvania and associated oil and gas production and wells. The transaction represents a strategic repositioning of the Company’s portfolio. The Company expects the acquisition will lead to improved returns, increased reserves, higher value markets in which to sell production, and increased control of capital allocation.

	The transaction was accounted for as a business combination and after customary effective-date adjustments and closing adjustments, the adjusted cash payment on the closing date of September 25, 2014 was $890.8 million and is subject to further post-closing adjustments. The adjusted cash payment was allocated to assets and liabilities based upon fair values at the closing date. There was no gain or loss recognized on the disposition of the Pennsylvania Properties since the relationship between capitalized costs and proved reserves of oil and natural gas was not significantly altered.

	The adjusted cash payment was allocated to assets and liabilities based upon fair values at the closing date as follows:

		Adjusted cash payment			$890,785

		Assets:
			Joint interest billing and other receivables - SWEPI Properties		-4,182

			Other current assets:
				Acquired condensate inventory - SWEPI Properties	819
				Acquired yard inventory - SWEPI Properties	3,515
			Subtotal - Other current assets		4,334

			Proven oil and gas properties		1,033,960

			Property, plant and equipment:
				Divested gathering system - Pennsylvania Properties	-98,580
				Acquired other fixed assets - SWEPI Properties	869
				Divested other fixed assets - Pennsylvania Properties	-50
			Subtotal - Property, plant and equipment		-97,761

		Total assets acquired, net of divested assets			$936,351

		Liabilities:
			Current liabilities:
				Current liabilities - Pennsylvania Properties	8,657
				Current liabilities - SWEPI Properties	-601
			Subtotal - Current liabilities		$8,056

			Other long-term obligations:
				Acquired asset retirement obligations - SWEPI Properties	53,270
				Divested asset retirement obligations - Pennsylvania Properties	-15,760
			Subtotal - Other long-term obligations		37,510

		Total liabilities, net			$45,566

	Contingent consideration

	In the PSA for the SWEPI Transaction, the Company agreed to attempt to extend or renew certain expiring leases in Pennsylvania at its expense. In satisfaction of this obligation, during January and February 2015 the Company made or will make a cash payment to SWEPI LP and to various landowners who agreed to extend their leases.

	Pro Forma Operating Results

	The following pro forma combined results for the years ended December 31, 2014 and 2013 reflect the consolidated results of operations of the Company as if the SWEPI Transaction and related financing had occurred on January 1, 2013. The pro forma information includes adjustments primarily for revenues and expenses from the acquired SWEPI Properties less revenues and expenses from the divested Pennsylvania Properties as well as depreciation, depletion, amortization and accretion, and interest expense associated with the financing related to the SWEPI Transaction.

	The unaudited pro forma combined financial statements give effect to the events described below:

	The acquisition and divestiture of oil and gas properties in the SWEPI Transaction completed on September 25, 2014
	Issuance of $850.0 million of 6.125% senior notes due 2024 to finance a portion of the SWEPI Transaction, and the related adjustments to interest expense
	Increase in borrowings under the Credit Agreement to finance a portion of the SWEPI Transaction, and the related adjustments to interest expense
	Includes transportation charges of $74.6 million and $113.4 million for the years ended December 31, 2014 and 2013, respectively, incurred with respect to operation of the properties acquired in the SWEPI Transaction that will not be incurred by the Company.

	The pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the SWEPI Transaction and related financing been completed as of the date set forth in the pro forma combined financial information and should not be taken as indicative of the Company’s future combined results of operations. The actual results may differ significantly from that reflected in the pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the pro forma combined financial information and actual results.

		For the year ended December 31,
		2014		2013
Revenues	$	1,421,537	$	1,160,394
Net income	$	531,188	$	164,303
Net income per common share - basic	$	3.47	$	1.07
Net income per common share - fully diluted	$	3.43	$	1.06

Post-Acquisition Operating Results

The amounts of revenues and earnings included in the Company’s Consolidated Statements of Operations for the year ended December 31, 2014 related to the SWEPI Transaction represents activity from September 25, 2014 through December 31, 2014 and includes $74.7 million in revenues and $23.5 million in earnings.

2013 Acquisition:

On December 12, 2013 the Company, through its subsidiary, UPL Three Rivers Holdings, LLC, closed on the acquisition of crude oil assets (“the Assets”) located in Three Rivers Field in Uintah County, Utah. The Assets were acquired at a contract price of $652.0 million and consist of producing wells, undeveloped acreage and water and gas gathering assets. A purchase and sale agreement was executed between the parties on October 18, 2013 with an effective date of October 1, 2013. The acquisition was financed through the issuance of $450.0 million of senior notes and the remainder under the Company’s credit facility.

Subsequent_Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2014
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	14. SUBSEQUENT EVENTS:

	The Company has evaluated the period subsequent to December 31, 2014 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading.

Summarized_Quarterly_Financial

Summarized Quarterly Financial Information	12 Months Ended
Summarized Quarterly Financial Information	Dec. 31, 2014
Summarized Quarterly Financial Information Disclosure [Abstract]
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)	15. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED):

			2014
			1st Quarter		2nd Quarter		3rd Quarter		4th Quarter		Total

	Revenues from continuing operations	$	326,299	$	296,063	$	288,608	$	319,050	$	1,230,020
	(Loss) gain on commodity derivatives		-45,273		-15,102		32,052		110,725		82,402
	Expenses from continuing operations		154,829		150,850		169,669		195,083		670,431
	Interest expense		27,068		27,294		29,599		42,196		126,157
	Gain on sale of property		-		-		-		8,022		8,022
	Other income (expense), net		2,590		2,688		2,582		5,311		13,171
	Income before income tax provision (benefit)		101,719		105,505		123,974		205,829		537,027
	Income tax provision (benefit)		4		-544		-1,383		-3,901		-5,824
	Net income	$	101,715	$	106,049	$	125,357	$	209,730	$	542,851

	Net income per common share - basic	$	0.66	$	0.69	$	0.82	$	1.37	$	3.54
	Net income per common share - fully diluted	$	0.66	$	0.68	$	0.81	$	1.36	$	3.51

			2013
			1st Quarter		2nd Quarter		3rd Quarter		4th Quarter		Total

	Revenues from continuing operations	$	225,626	$	261,376	$	221,205	$	225,197	$	933,404
	Gain (loss) on commodity derivatives		-44,715		22,091		2,074		-26,204		-46,754
	Expenses from continuing operations		139,994		143,002		136,389		141,753		561,138
	Interest expense		25,764		25,238		25,174		25,310		101,486
	Other income (expense), net		2,648		2,641		2,575		2,332		10,196
	Income before income tax provision (benefit)		17,801		117,868		64,291		34,262		234,222
	Income tax provision (benefit)		1,368		1,491		381		-6,856		-3,616
	Net income	$	16,433	$	116,377	$	63,910	$	41,118	$	237,838

	Net income per common share - basic	$	0.11	$	0.76	$	0.42	$	0.27	$	1.55
	Net income per common share - fully diluted	$	0.11	$	0.75	$	0.41	$	0.27	$	1.54

Disclosure_About_Oil_and_Gas_P

Disclosure About Oil and Gas Producing Activities	12 Months Ended
Disclosure About Oil and Gas Producing Activities	Dec. 31, 2014
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	16. DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):

	The following information about the Company’s oil and natural gas producing activities is presented in accordance with FASB ASC Topic 932, Oil and Gas Reserve Estimation and Disclosures:

	A. OIL AND GAS RESERVES:

	Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC’s regulations and GAAP. The Director – Reservoir Engineering & Development is primarily responsible for overseeing the preparation of the Company’s reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering and is a licensed Professional Engineer with over 13 years of experience. The Company’s internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation.

	The estimates of proved reserves and future net revenue as of December 31, 2014, are based upon the use of technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The reserves were estimated using deterministic methods; these estimates were prepared in accordance with generally accepted petroleum engineering and evaluation principles. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, that were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules and regulations, were also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, these estimates necessarily represent only informed professional judgment.

	The determination of oil and natural gas reserves is complex and highly interpretive. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs. From time to time, the Company may adjust the inventory and schedule of its proved undeveloped locations in response to changes in capital budget, economics, new opportunities in the portfolio or resource availability. The Company has not scheduled any proved undeveloped reserves beyond five years nor does it have any proved undeveloped locations that have been part of its inventory of proved undeveloped locations for over five years.
	The Company engaged Netherland, Sewell & Associates, Inc. (“NSAI”), a third-party, independent engineering firm, to prepare the reserve estimates for all of the Company’s assets for the year ended December 31, 2014 in this annual report. For the year ended December 31, 2013, the Company engaged NSAI to prepare the reserve estimates for all of the Company’s assets in Wyoming and Pennsylvania in this annual report. Due to the timing of the closing of the acquisition in Utah in December 2013 relative to the timing of preparing annual corporate reserves, the Company’s Reservoir Engineering Department prepared the proved reserve estimates for its Utah assets for the year ended December 31, 2013, which were prepared in accordance with the Company’s internal controls and SEC regulations and represented less than 2% of estimated proved reserves as of December 31, 2013. The Company engaged NSAI to prepare the reserve estimates for all of the Company’s assets for the year ended December 31, 2012 in this annual report.

	Our internal professional staff works closely with our independent engineers, NSAI, to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves. The report of NSAI is included as an Exhibit to this annual report.

	The reserves estimates shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Robert C. Barg and Mr. Phillip R. Hodgson. Mr. Barg, a Licensed Professional Engineer in the State of Texas (No. 71658), has been practicing consulting petroleum engineering at NSAI since 1989 and has over 6 years of prior industry experience. He graduated from Purdue University in 1983 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Hodgson, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998 and has over 14 years of prior industry experience. He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

	Since January 1, 2014, no crude oil, natural gas or NGL reserve information has been filed with, or included in any report to, any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve and other information, with the EIA.

	The following unaudited tables as of December 31, 2014, 2013, and 2012 reflect estimated quantities of proved oil and natural gas reserves for the Company and the changes in total proved reserves as of December 31, 2014, 2013 and 2012. All such reserves are located in the Green River Basin in Wyoming, the Uinta Basin in Utah and the Appalachian Basin of Pennsylvania.

	B. ANALYSES OF CHANGES IN PROVEN RESERVES:

		United States
		Oil	Natural Gas	NGLs
		(MBbls)	(MMcf)	(MBbls)
	Reserves, December 31, 2011	33,081	4,778,554	-
	Extensions, discoveries and additions	5,435	819,896	-
	Production	-1,282	-249,310	-
	Revisions	-19,097	-2,382,695	-
	Reserves, December 31, 2012	18,137	2,966,445	-
	Extensions, discoveries and additions	11,329	1,409,528	-
	Acquistions	10,114	-	-
	Production	-1,196	-224,912	-
	Revisions	-4,265	-741,319	-
	Reserves, December 31, 2013	34,119	3,409,742	-
	Extensions, discoveries and additions	34,275	866,513	210
	Sales	-	-239,290	-
	Acquistions	9,381	1,345,964	21,740
	Production	-3,409	-228,517	-
	Revisions	-6,600	-323,218	43

	Reserves, December 31, 2014	67,766	4,831,194	21,993

		United States
		Oil	Natural Gas	NGLs
		(MBbls)	(MMcf)	(MBbls)
	Proved:
	Developed	11,794	1,973,391	-
	Undeveloped	21,287	2,805,163	-
	Total Proved - 2011	33,081	4,778,554	-

	Developed	10,531	1,820,994	-
	Undeveloped	7,606	1,145,451	-
	Total Proved - 2012	18,137	2,966,445	-

	Developed	20,566	1,777,267	-
	Undeveloped	13,553	1,632,475	-
	Total Proved - 2013	34,119	3,409,742	-

	Developed	28,481	2,245,004	9,118
	Undeveloped	39,285	2,586,190	12,875
	Total Proved - 2014	67,766	4,831,194	21,993

Changes in proved developed reserves: During 2014, substantially all of our extensions and discoveries in the proved developed category were attributable to wells drilled in 2014. Proved developed reserves increased associated with reserves acquired in the SWEPI Transaction (see Note 13) and partially offset by the Pennsylvania Properties divested in the SWEPI Transaction.

Changes in proved undeveloped reserves: The changes to the Company’s proved undeveloped reserves (PUDs) during 2014 include updates to prior PUDs, the addition of new PUDs associated with current development plans, the transfer of PUDs to unproved categories due to development plan changes, and the impact of changes in economic conditions, including changes in commodity prices. The Company’s year-end development plans and associated PUDs are consistent with SEC guidelines for PUD development within five years. The Company annually reviews all PUDs to ensure an appropriate plan for development exists. Additionally, proved undeveloped reserves increased associated with reserves acquired in the SWEPI Transaction (see Note 13).

NGLs: As part of the SWEPI Transaction, the Company acquired contracts related to NGLs providing the opportunity to realize the benefit of the NGLs from the gas it produces beginning in 2017.

C. STANDARDIZED MEASURE:

The following table sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company’s proved reserves. Natural gas prices have fluctuated widely in recent years. The calculated weighted average sales prices utilized for the purposes of estimating the Company’s proved reserves and future net revenues at December 31, 2014, 2013 and 2012 was $4.32, $3.51 and $2.63 per Mcf, respectively, for natural gas, and $80.62, $84.97 and $87.85 per barrel, respectively, for oil and condensate. As part of the SWEPI Transaction, the Company acquired contracts related to NGLs providing the opportunity to realize the benefit of the NGLs from the gas it produces beginning in 2017. For 2014, the average sales price utilized for purposes of estimating the Company’s proved reserves and future net revenues associated with NGLs was $46.27 per barrel. The prices utilized in the reserve report are based upon the average of prices in effect on the first day of the month for the preceding twelve month period.

The future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties and available operating loss carryovers.

			As of December 31,
			2014		2013		2012
	Future cash inflows	$	27,331,391	$	14,861,131	$	9,380,970
	Future production costs		-8,627,657		-4,540,209		-3,217,771
	Future development costs		-3,859,385		-2,014,751		-1,661,394
	Future income taxes		-3,898,355		-1,897,340		-733,855
	Future net cash flows		10,945,994		6,408,831		3,767,950
	Discount at 10%		-5,712,511		-3,220,862		-1,873,633
	Standardized measure of discounted
	future net cash flows	$	5,233,483	$	3,187,969	$	1,894,317


The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties but without consideration of general and administrative and interest expenses.

D. SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH *FLOWS:*

			December 31,
			2014		2013		2012
	Standardized measure, beginning	$	3,187,969	$	1,894,317	$	3,796,056
	Net revisions of previous quantity estimates		-603,795		-1,089,316		-2,516,159
	Extensions, discoveries and other changes		1,787,643		2,098,644		858,951
	Sales of reserves in place		-398,506		-		-
	Acquisition of reserves		2,552,491		86,196		-
	Changes in future development costs		-1,013,652		-252,992		952,067
	Sales of oil and gas, net of production costs		-949,389		-720,826		-625,745
	Net change in prices and production costs		1,010,052		1,204,041		-2,912,698
	Development costs incurred during the
	period that reduce future development costs		342,987		171,149		316,394
	Accretion of discount		413,177		226,326		529,696
	Net changes in production rates and other		-175,419		145,289		363,788
	Net change in income taxes		-920,075		-574,859		1,131,967
	Aggregate changes		2,045,514		1,293,652		-1,901,739
	Standardized measure, ending	$	5,233,483	$	3,187,969	$	1,894,317

There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond the control of the Company. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and costs that may not prove correct over time. Predictions of future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Historically, oil and natural gas prices have fluctuated widely.

E. COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES:


			Years Ended December 31,
			2014		2013		2012
	United States

	Property Acquisitions:
	Unproved	$	26,106	$	424,540	$	47,979
	Proved		895,179		224,410		-
	Exploration*		197,664		184,007		199,569
	Development		382,984		186,755		587,618
	Total	$	1,501,933	$	1,019,712	$	835,166

	* Exploration costs (as defined in Regulation S-X) includes costs spent on development of unproved reserves in the Pinedale Field.


F. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES:

			Years Ended December 31,
			2014		2013		2012
	United States

	Oil and gas revenue	$	1,230,020	$	933,404	$	809,974
	Production expenses		-280,631		-212,578		-184,229
	Depletion and depreciation		-292,951		-243,390		-388,985
	Ceiling test and other impairments		-		-		-2,972,464
	Income tax benefit (expense)		3,736		-2,821		662,698
	Total	$	660,174	$	474,615	$	-2,073,006


G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES:

			December 31,
			2014		2013
	Proven Properties:
	Acquisition, equipment, exploration, drilling and
	environmental costs	$	9,731,407	$	7,817,374
	Less: accumulated depletion, depreciation and amortization		-6,094,764		-5,808,836
			3,636,643		2,008,538
	Unproven Properties:
	Acquisition and exploration costs not being amortized		242,294		413,073
		$	3,878,937	$	2,421,611

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	12 Months Ended
Significant Accounting Policies (Policies)	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of presentation	(a) Basis of presentation and principles of consolidation: The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company presents its financial statements in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). All inter-company transactions and balances have been eliminated upon consolidation.
Basis of presentation
Cash and cash equivalents	(b) Cash and cash equivalents: The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Cash and cash equivalents
Restricted cash	(c) Restricted cash: Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute.
Restricted cash
Accounts receivable	(d) Accounts receivable: Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts. The carrying amount of the Company’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables.
Property, plant and equipment	(e) Property, plant and equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life. Previously, gathering system expenditures were recorded at cost and depreciated separately from proven oil and gas properties using the straight-line method due to the expectation that they would be used to transport production from probable and possible reserves, as well as from third parties. However, subsequent to the SWEPI Transaction (See Note 13), the Company’s remaining gathering systems are expected to only be used to transport the Company’s proved volumes and as a result, $91.8 million was transferred to proven oil and gas properties at September 30, 2014.
Oil and natural gas properties	(f) Oil and natural gas properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Separate cost centers are maintained for each country in which the Company incurs costs. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

	The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the proved reserves as determined by independent petroleum engineers. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement obligations are included in the base costs for calculating depletion.

	Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors. The amount of any impairment is transferred to the capitalized costs being amortized. For the years ended December 31, 2014 and 2013, the Company did not determine any impairment related to unevaluated properties or major development projects excluded from capitalized costs being amortized.

	Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil, natural gas and NGL prices may subsequently increase the ceiling.

	During 2012, the Company recorded a $2.9 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations, which is reflected within ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2012, September 30, 2012 and June 30, 2012 for Henry Hub natural gas and West Texas Intermediate oil, adjusted for market differentials. The Company did not have any write-downs related to the full cost ceiling limitation in 2014 or 2013.
Inventories	(g) Inventories: At December 31, 2014 and 2013, inventory of $10.2 million and $5.2 million primarily includes the cost of pipe and production equipment that will be utilized during the 2015 drilling program and crude oil inventory. Materials and supplies inventories are carried at lower of cost or market and include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. The Company uses the weighted average method of recording its materials and supplies inventory. Crude oil inventory is valued at lower of cost or market.
Derivative Instruments and hedging activities	(h) Derivative instruments and hedging activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 7).
Derivative Instruments and hedging activities
Income Taxes Policy	(i) Income taxes: Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.

	The Company has recorded a valuation allowance against certain deferred tax assets of $161.5 million as of December 31, 2014. Some or all of this valuation allowance may be reversed in future periods against future income.

Earnings per share	(j) Earnings (loss) per share: Basic earnings (loss) per share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted income (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect

		The following table provides a reconciliation of components of basic and diluted net income (loss) per common share:

				December 31,
				2014		2013		2012

		Net income (loss)	$	542,851	$	237,838	$	-2,176,898

		Weighted average common shares outstanding
		during the period		153,136		152,963		152,845

		Effect of dilutive instruments		1,558		1,463		-	-1

		Weighted average common shares outstanding during
		the period including the effects of dilutive instruments		154,694		154,426		152,845

		Net income (loss) per common share - basic	$	3.54	$	1.55	$	-14.24

		Net income (loss) per common share - fully diluted	$	3.51	$	1.54	$	-14.24

		Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of
		the common shares		1,377		1,406		-	-1

	(1) Due to the net loss for the year ended December 31, 2012, 1.9 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of loss per share.

Use of estimates	(k) Use of estimates: Preparation of consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Accounting for share based compensation	(l) Accounting for share-based compensation: The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation.
Accounting for share based compensation
Fair value accounting	(m) Fair value accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 8 for additional information.
Fair value accounting
Asset retirement obligation	(n) Asset retirement obligation: The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.
Revenue recognition	(o) Revenue recognition: The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices and under multi-year contracts that provide for a fixed price of oil and natural gas. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.” Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. Any amount received in excess of the Company’s share of the volumes is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2014 and 2013, the Company had a net natural gas imbalance liability of $3.0 million and $3.3 million, respectively.

	Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances.

Capitalized interest	(p) Capitalized interest: Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated, if any, as well as on work in process relating to gathering systems that are not currently in service.

	(1) Interest is capitalized on the cost of unevaluated oil and natural gas properties that are excluded from amortization and actively being evaluated as well as on work in process relating to gathering systems that are not currently in service. For the years ended December 31, 2014 and 2013, total interest on outstanding debt was $146.6 million and $103.5 million, respectively, of which $20.4 million and $2.0 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and work in process relating to gathering systems that are not currently in service.
Capital Cost Accrual	(q) Capital cost accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period.
Capital Cost Accrual
Reclassifications	(r) Reclassifications: Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation.
Reclassifications
Recent accounting pronouncements	(s) Recent accounting pronouncements: In August 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU No. 2014-15”) that will require management to evaluate whether there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Management will be required to provide certain footnote disclosures if it concludes that substantial doubt exists or when its plans alleviate substantial doubt about the Company’s ability to continue as a going concern. ASU No. 2014-15 becomes effective for annual periods beginning in 2016 and for interim reporting periods starting in the first quarter of 2017. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.

	In June 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which supersedes the revenue recognition requirements in FASB ASC 605, Revenue Recognition, and in most industry-specific topics. ASU No. 2014-09 provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. ASU No. 2014-09 becomes effective at the beginning of 2017. The Company is still evaluating the impact of ASU No. 2014-09 on its financial position and results of operations.

	In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures. The guidance is effective for annual and interim reporting periods beginning after December 15, 2014. Adoption of this amendment will not have a material effect on our financial position or results of operations.
Derivatives and Hedging Activities Policies [Abstract]
Derivative Instruments and hedging activities	(h) Derivative instruments and hedging activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 7).
Derivative Instruments and hedging activities
Oil and Gas Properties Policies [Abstract]
Capitalized interest	(p) Capitalized interest: Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated, if any, as well as on work in process relating to gathering systems that are not currently in service.

	(1) Interest is capitalized on the cost of unevaluated oil and natural gas properties that are excluded from amortization and actively being evaluated as well as on work in process relating to gathering systems that are not currently in service. For the years ended December 31, 2014 and 2013, total interest on outstanding debt was $146.6 million and $103.5 million, respectively, of which $20.4 million and $2.0 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and work in process relating to gathering systems that are not currently in service.

Significant_Accounting_Policie2

Significant Accounting Policies (Tables)	12 Months Ended
Significant Accounting Policies (Tables)	Dec. 31, 2014
Significant Accounting Tables Policies [Abstract]
Schedule Of Earnings Per Share		The following table provides a reconciliation of components of basic and diluted net income (loss) per common share:

				December 31,
				2014		2013		2012

		Net income (loss)	$	542,851	$	237,838	$	-2,176,898

		Weighted average common shares outstanding
		during the period		153,136		152,963		152,845

		Effect of dilutive instruments		1,558		1,463		-	-1

		Weighted average common shares outstanding during
		the period including the effects of dilutive instruments		154,694		154,426		152,845

		Net income (loss) per common share - basic	$	3.54	$	1.55	$	-14.24

		Net income (loss) per common share - fully diluted	$	3.51	$	1.54	$	-14.24

		Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of
		the common shares		1,377		1,406		-	-1

	(1) Due to the net loss for the year ended December 31, 2012, 1.9 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of loss per share.

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Schedule Of Asset Retirement Obligations				December 31,
				2014		2013

		Asset retirement obligations at beginning of period	$	72,807	$	60,814
		Accretion expense		6,571		5,171
		Liabilities incurred		10,242		7,730
		Liabilities acquired(1)		53,270		-
		Liabilities divested(1)		-15,760		-
		Liabilities settled		-336		-2,334
		Revisions of estimated liabilities		446		1,426
		Asset retirement obligations at end of period		127,240		72,807
		Less: current asset retirement obligations		-417		-96
		Long-term asset retirement obligations	$	126,823	$	72,711

Oil_and_Gas_Properties_Tables

Oil and Gas Properties (Tables)	12 Months Ended
Oil and Gas Properties (Tables)	Dec. 31, 2014
Oil and Gas Properties And Equipment Tables [Abstract]
Capitalized Costs Relating to Oil and Gas Producing Activities				December 31,		December 31,
				2014		2013
		Proven Properties:
		Acquisition, equipment, exploration, drilling and environmental costs(2), (3)	$	9,731,407	$	7,817,374
		Less: Accumulated depletion, depreciation and amortization		-6,094,764		-5,808,836
				3,636,643		2,008,538
		Unproven Properties:
		Acquisition and exploration costs not being amortized (1), (2)		242,294		413,073
		Net capitalized costs - oil and gas properties	$	3,878,937	$	2,421,611


	G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES:

				December 31,
				2014		2013
		Proven Properties:
		Acquisition, equipment, exploration, drilling and
		environmental costs	$	9,731,407	$	7,817,374
		Less: accumulated depletion, depreciation and amortization		-6,094,764		-5,808,836
				3,636,643		2,008,538
		Unproven Properties:
		Acquisition and exploration costs not being amortized		242,294		413,073
			$	3,878,937	$	2,421,611

Schedule Of Capitalized Costs Of Unproved Properties Excluded From Amortization Text Block				Total		2014		2013		2012		Prior
		Acquisition costs	$	228,516	$	-191,184	$	419,700	$	-481,689	$	481,689
		Exploration costs		-7,708		173		-7,881		-9,962		9,962
		Capitalized interest		21,486		20,232		1,254		-45,875		45,875
		Unproven properties	$	242,294	$	-170,779	$	413,073	$	-537,526	$	537,526

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
Property, Plant and Equipment (Tables)	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment			December 31,
			2014						2013
			Cost		Accumulated Depreciation		Net Book Value		Net Book Value
	Gathering systems(1)(2)	$	-	$	-	$	-	$	189,110
	Computer equipment		2,967		-2,050		917		892
	Office equipment		467		-410		57		41
	Leasehold improvements		471		-360		111		136
	Land(3)		5,778		-		5,778		22,359
	Other		13,656		-8,333		5,323		4,371
	Property, plant and equipment, net	$	23,339	$	-11,153	$	12,186	$	216,909

Long_Term_Liabilities_Tables

Long Term Liabilities (Tables)	12 Months Ended
Long Term Liabilities (Tables)	Dec. 31, 2014
Long Term Liabilities Tables [Abstract]
Schedule of Long-term Liabilities				December 31,		December 31,
				2014		2013
		Short-term debt:
		Senior Notes due March 2015	$	100,000	$	-

		Long-term debt and other long-term liabilities:
		Bank indebtedness		518,000		460,000
		Senior notes		2,760,000		2,010,000
		Other long-term obligations		152,472		91,932

			$	3,530,472	$	2,561,932
Maturity Schedule		Aggregate maturities of debt at December 31, 2014:
													Beyond
			2015		2016		2017		2018		2019		5 years		Total
		$	100,000	$	580,000	$	116,000	$	650,000	$	173,000	$	1,759,000	$	3,378,000

Share_Based_Compensation_Table

Share Based Compensation (Tables)	12 Months Ended
Share Based Compensation (Tables)	Dec. 31, 2014
Share Based Compensation Tables [Abstract]
Valuation and Expense Information		Valuation and Expense Information
				Year Ended December 31,
				2014		2013		2012

		Total cost of share-based payment plans	$	8,640	$	13,957	$	15,835
		Amounts capitalized in oil and gas properties and equipment	$	3,173	$	4,190	$	5,079
		Amounts charged against income, before
		income tax benefit	$	5,467	$	9,767	$	10,756
		Amount of related income tax benefit recognized
		in income before valuation allowances	$	2,285	$	4,083	$	4,463
Securities Authorized for Issuance Under Equity Compensation Plans							Number of Securities
							Remaining Available
			Number of				for Future Issuance
			Securities to		Weighted		Under Equity
			be Issued		Average		Compensation Plans
			Upon Exercise of		Exercise Price of		(Excluding Securities
			Outstanding		Outstanding		Reflected in the
	Plan Category		Options		Options		First Column)
	Equity compensation plans approved by		(000's)				(000's)
	security holders		690		$56.58		2,608
	Equity compensation plans not approved
	by security holders		n/a		n/a		n/a
	Total		690		$56.58		2,608
Changes in Stock Options Outstanding					Weighted
					Average
			Number of		Exercise Price
			Options		(US$)
			(000's)
		Balance, December 31, 2011	1,459		$16.97	to	$98.87

		Forfeited	-68		$25.08	to	$75.18
		Exercised	-34		$16.97	to	$19.18

		Balance, December 31, 2012	1,357		$16.97	to	$98.87

		Forfeited	-110		$25.68	to	$75.18
		Exercised	-1		$16.97	to	$16.97

		Balance, December 31, 2013	1,246		$16.97	to	$98.87

		Forfeited	-513		$33.57	to	$75.18
		Exercised	-43		$16.97	to	$25.68

		Balance, December 31, 2014	690		$25.68	to	$98.87
Share Based Compensation by Exercise Price Table	The following table summarizes information about the stock options outstanding and exercisable at December 31, 2014:


						Options Outstanding and Exercisable
								Weighted	Weighted
								Average	Average	Aggregate
						Number		Remaining	Exercise	Intrinsic
	Range of Exercise Price					Outstanding		Contractual Life	Price	Value
						(000's)		(Years)
	$	25.68	-	$	53.39	126		0.64	$44.25	$-
	$	50.15	-	$	65.04	125		1.55	$57.00	$-
	$	49.05	-	$	62.23	281		2.28	$53.85	$-
	$	51.6	-	$	98.87	158		3.43	$70.92	$-
Weighted Average Grant Date Fair Value of Stock Options				2014		2013		2012
Weighted Average Grant Date Fair Value of Stock Options		Options forfeited during the year	$	24.4	$	25.44	$	27.05

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)	12 Months Ended
Derivative Financial Instruments (Tables)	Dec. 31, 2014
Derivative Financial Instruments Tables [Abstract]
Detail Schedule of Realized and Unrealized Gains and Losses	Commodity Derivative Contracts: At December 31, 2014, the Company had the following open commodity derivative contracts to manage price risk on a portion of its production whereby the Company receives the fixed price and pays the variable price. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties

		Natural Gas:
		Type		Commodity Reference Price		Remaining Contract Period		Volume - MMBTU/Day	Average Price/MMBTU		Fair Value - December 31, 2014
											Asset
		Swap		NYMEX-Henry Hub		Jan - Mar 2015		210,000	$4.54	$	29,201
		Swap		NYMEX-Henry Hub		Apr - Oct 2015		522,500	$3.65	$	74,989

	Subsequent to December 31, 2014 and through February 11, 2015, the Company has entered into the following open commodity derivative contracts to manage price risk on a portion of its production whereby the Company receives the fixed price and pays the variable price:

		Natural Gas:
		Type		Commodity Reference Price		Remaining Contract Period		Volume - MMBTU/Day	Average Price/MMBTU

		Swap		NYMEX-Henry Hub		Apr - Oct 2015		150,000	$2.98

	The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012:

				For the Year Ended December 31,
		Commodity Derivatives:		2014		2013		2012
		Realized (loss) gain on commodity derivatives-natural gas (1)	$	-48,170	$	-20,552	$	303,966
		Realized gain (loss) on commodity derivatives-crude oil (1)		506		-326		-
		Unrealized gain (loss) on commodity derivatives (1)		130,066		-25,876		-230,385
		Total gain (loss) on commodity derivatives	$	82,402	$	-46,754	$	73,581

		(1) Included in gain (loss) on commodity derivatives in the Consolidated Statements of Operations.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
Fair Value Measurements (Tables)	Dec. 31, 2014
Fair Value Measurements Tables [Abstract]
Fair Value of Long-Term Debt				Level 1		Level 2		Level 3		Total
		Assets:
		Current derivative asset	$	-	$	104,190	$	-	$	104,190

				31-Dec-14				31-Dec-13
				Carrying		Estimated		Carrying		Estimated
				Amount		Fair Value		Amount		Fair Value
		5.45% Notes due March 2015, issued 2008	$	100,000	$	101,931	$	100,000	$	105,913
		7.31% Notes due March 2016, issued 2009		62,000		65,027		62,000		70,228
		4.98% Notes due January 2017, issued 2010		116,000		116,240		116,000		126,342
		5.92% Notes due March 2018, issued 2008		200,000		203,738		200,000		226,127
		5.75% Notes due December 2018, issued 2013		450,000		414,505		450,000		466,946
		7.77% Notes due March 2019, issued 2009		173,000		187,105		173,000		211,877
		5.50% Notes due January 2020, issued 2010		207,000		201,371		207,000		229,068
		4.51% Notes due October 2020, issued 2010		315,000		283,335		315,000		323,732
		5.60% Notes due January 2022, issued 2010		87,000		82,581		87,000		95,736
		4.66% Notes due October 2022, issued 2010		35,000		30,476		35,000		35,494
		6.125% Notes due October 2024, issued 2014		850,000		754,485		-		-
		5.85% Notes due January 2025, issued 2010		90,000		83,876		90,000		99,142
		4.91% Notes due October 2025, issued 2010		175,000		147,649		175,000		175,744
		Credit Facility due October 2016		518,000		518,000		460,000		460,000
			$	3,378,000	$	3,190,319	$	2,470,000	$	2,626,349

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2014
Income Taxes [Abstract]
Consoldiated income tax provision table	Income (loss) before income tax benefit is as follows:

			Year Ended December 31,
			2014		2013		2012
	United States	$	505,689	$	210,580	$	-2,892,207
	Foreign		31,338		23,642		15,096
	Total	$	537,027	$	234,222	$	-2,877,111


	The consolidated income tax (benefit) provision is comprised of the following:
			Year Ended December 31,
			2014		2013		2012
	Current tax:
	U.S. federal, state and local	$	-110	$	-8,491	$	9,037
	Foreign		-6,709		4,881		3,326
	(Reduction in) current tax benefit on stock based compensation:
	U.S. federal, state and local		-		-		-4,427
	Total current tax expense (benefit)		-6,819		-3,610		7,936
	Deferred tax:
	U.S. federal, state and local		-		-		-708,160
	Foreign		995		-6		11
	Total deferred tax expense (benefit)		995		-6		-708,149
	Total income tax (benefit) provision	$	-5,824	$	-3,616	$	-700,213
Income tax expense reconciliation table	The income tax provision (benefit) from continuing operations differs from the amount that would be computed by applying the U.S. federal income tax rate of 35% to pretax income as a result of the following:


			Year Ended December 31,
			2014		2013		2012
	Income tax provision (benefit) computed at the U.S. statutory rate	$	187,959	$	81,978	$	-1,006,989
	State income tax provision (benefit) net of federal benefit		8,023		1,329		-136,112
	Valuation allowance		-199,038		-81,923		446,148
	Tax effect of rate change		15,457		-2,871		1,358
	Foreign rate differential		-16,314		-3,508		-5,531
	Other, net		-1,911		1,379		913

	Total income tax (benefit) provision	$	-5,824	$	-3,616	$	-700,213

Consoldiated deferred tax assets and liabilities
	The tax effects of temporary differences that give rise to significant components of the Company's deferred tax assets and liabilities are as follows:
					December 31,
					2014		2013
	Deferred tax assets - current:
	Derivative instruments, net			$	-	$	9,636
	Incentive compensation/other, net				6,150		7,641
					6,150		17,277
	Valuation allowance				-		-16,778
	Net deferred tax assets - current			$	6,150	$	499
	Deferred tax liabilities - current:
	Derivative instruments, net			$	36,788	$	499
	Net deferred tax liabilities - current			$	36,788	$	499
	Net deferred tax liability - current			$	30,638	$	-
	Deferred tax assets - non-current:
	Property and equipment				-		131,340
	Deferred gain				48,319		52,045
	U.S. federal tax credit carryforwards				16,144		16,254
	U.S. net operating loss carryforwards				147,336		71,843
	U.S. state net operating loss carryforwards				53,654		36,205
	Asset retirement obligations				45,039		26,876
	Incentive compensation/other, net				19,142		13,007
					329,634		347,570
	Valuation allowance				-161,480		-346,596
	Net deferred tax assets - non-current			$	168,154	$	974
	Deferred tax liabilities - non-current:
	Property and equipment				137,514		-
	Other				-		968
	Net non-current tax liabilities			$	137,514	$	968
	Net non-current tax asset			$	30,640	$	6
	Deferred tax liabilities - non-current:
	Other - non-US				992		-

Completion_of_Acquisition_and_1

Completion of Acquisition and Dispositon of Assets (Tables)	12 Months Ended
Completion of Acquisition and Dispositon of Assets (Tables)	Dec. 31, 2014
Business Combination Tables [Abstract]
Pro Forma Financial Information Table Table [Text Block]			For the year ended December 31,
			2014		2013
	Revenues	$	1,421,537	$	1,160,394
	Net income	$	531,188	$	164,303
	Net income per common share - basic	$	3.47	$	1.07
	Net income per common share - fully diluted	$	3.43	$	1.06
Adjusted Cash Payment Allocation Table Table [Text Block]		Adjusted cash payment				$890,785

		Assets:
			Joint interest billing and other receivables - SWEPI Properties			-4,182

			Other current assets:
				Acquired condensate inventory - SWEPI Properties		819
				Acquired yard inventory - SWEPI Properties		3,515
			Subtotal - Other current assets			4,334

			Proven oil and gas properties			1,033,960

			Property, plant and equipment:
				Divested gathering system - Pennsylvania Properties		-98,580
				Acquired other fixed assets - SWEPI Properties		869
				Divested other fixed assets - Pennsylvania Properties		-50
			Subtotal - Property, plant and equipment			-97,761

		Total assets acquired, net of divested assets				$936,351

		Liabilities:
			Current liabilities:
				Current liabilities - Pennsylvania Properties		8,657
				Current liabilities - SWEPI Properties		-601
			Subtotal - Current liabilities			$8,056

			Other long-term obligations:
				Acquired asset retirement obligations - SWEPI Properties		53,270
				Divested asset retirement obligations - Pennsylvania Properties		-15,760
			Subtotal - Other long-term obligations			37,510

		Total liabilities, net				$45,566

Summarized_Quarterly_Financial1

Summarized Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Summarized Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Information Table Text Block			2014
			1st Quarter		2nd Quarter		3rd Quarter		4th Quarter		Total

	Revenues from continuing operations	$	326,299	$	296,063	$	288,608	$	319,050	$	1,230,020
	(Loss) gain on commodity derivatives		-45,273		-15,102		32,052		110,725		82,402
	Expenses from continuing operations		154,829		150,850		169,669		195,083		670,431
	Interest expense		27,068		27,294		29,599		42,196		126,157
	Gain on sale of property		-		-		-		8,022		8,022
	Other income (expense), net		2,590		2,688		2,582		5,311		13,171
	Income before income tax provision (benefit)		101,719		105,505		123,974		205,829		537,027
	Income tax provision (benefit)		4		-544		-1,383		-3,901		-5,824
	Net income	$	101,715	$	106,049	$	125,357	$	209,730	$	542,851

	Net income per common share - basic	$	0.66	$	0.69	$	0.82	$	1.37	$	3.54
	Net income per common share - fully diluted	$	0.66	$	0.68	$	0.81	$	1.36	$	3.51

			2013
			1st Quarter		2nd Quarter		3rd Quarter		4th Quarter		Total

	Revenues from continuing operations	$	225,626	$	261,376	$	221,205	$	225,197	$	933,404
	Gain (loss) on commodity derivatives		-44,715		22,091		2,074		-26,204		-46,754
	Expenses from continuing operations		139,994		143,002		136,389		141,753		561,138
	Interest expense		25,764		25,238		25,174		25,310		101,486
	Other income (expense), net		2,648		2,641		2,575		2,332		10,196
	Income before income tax provision (benefit)		17,801		117,868		64,291		34,262		234,222
	Income tax provision (benefit)		1,368		1,491		381		-6,856		-3,616
	Net income	$	16,433	$	116,377	$	63,910	$	41,118	$	237,838

	Net income per common share - basic	$	0.11	$	0.76	$	0.42	$	0.27	$	1.55
	Net income per common share - fully diluted	$	0.11	$	0.75	$	0.41	$	0.27	$	1.54

Disclosures_About_Oil_and_Gas_

Disclosures About Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Analyses of changes in proven reserves		United States
		Oil	Natural Gas	NGLs
		(MBbls)	(MMcf)	(MBbls)
	Reserves, December 31, 2011	33,081	4,778,554	-
	Extensions, discoveries and additions	5,435	819,896	-
	Production	-1,282	-249,310	-
	Revisions	-19,097	-2,382,695	-
	Reserves, December 31, 2012	18,137	2,966,445	-
	Extensions, discoveries and additions	11,329	1,409,528	-
	Acquistions	10,114	-	-
	Production	-1,196	-224,912	-
	Revisions	-4,265	-741,319	-
	Reserves, December 31, 2013	34,119	3,409,742	-
	Extensions, discoveries and additions	34,275	866,513	210
	Sales	-	-239,290	-
	Acquistions	9,381	1,345,964	21,740
	Production	-3,409	-228,517	-
	Revisions	-6,600	-323,218	43

	Reserves, December 31, 2014	67,766	4,831,194	21,993

		United States
		Oil	Natural Gas	NGLs
		(MBbls)	(MMcf)	(MBbls)
	Proved:
	Developed	11,794	1,973,391	-
	Undeveloped	21,287	2,805,163	-
	Total Proved - 2011	33,081	4,778,554	-

	Developed	10,531	1,820,994	-
	Undeveloped	7,606	1,145,451	-
	Total Proved - 2012	18,137	2,966,445	-

	Developed	20,566	1,777,267	-
	Undeveloped	13,553	1,632,475	-
	Total Proved - 2013	34,119	3,409,742	-

	Developed	28,481	2,245,004	9,118
	Undeveloped	39,285	2,586,190	12,875
	Total Proved - 2014	67,766	4,831,194	21,993
Standardized measure				As of December 31,
				2014		2013		2012
		Future cash inflows	$	27,331,391	$	14,861,131	$	9,380,970
		Future production costs		-8,627,657		-4,540,209		-3,217,771
		Future development costs		-3,859,385		-2,014,751		-1,661,394
		Future income taxes		-3,898,355		-1,897,340		-733,855
		Future net cash flows		10,945,994		6,408,831		3,767,950
		Discount at 10%		-5,712,511		-3,220,862		-1,873,633
		Standardized measure of discounted
		future net cash flows	$	5,233,483	$	3,187,969	$	1,894,317

Summary of changes in the standardized measure of discounted future net cash flows				December 31,
				2014		2013		2012
		Standardized measure, beginning	$	3,187,969	$	1,894,317	$	3,796,056
		Net revisions of previous quantity estimates		-603,795		-1,089,316		-2,516,159
		Extensions, discoveries and other changes		1,787,643		2,098,644		858,951
		Sales of reserves in place		-398,506		-		-
		Acquisition of reserves		2,552,491		86,196		-
		Changes in future development costs		-1,013,652		-252,992		952,067
		Sales of oil and gas, net of production costs		-949,389		-720,826		-625,745
		Net change in prices and production costs		1,010,052		1,204,041		-2,912,698
		Development costs incurred during the
		period that reduce future development costs		342,987		171,149		316,394
		Accretion of discount		413,177		226,326		529,696
		Net changes in production rates and other		-175,419		145,289		363,788
		Net change in income taxes		-920,075		-574,859		1,131,967
		Aggregate changes		2,045,514		1,293,652		-1,901,739
		Standardized measure, ending	$	5,233,483	$	3,187,969	$	1,894,317
Costs incurred in oil and gas exploration and development activities
				Years Ended December 31,
				2014		2013		2012
		United States

		Property Acquisitions:
		Unproved	$	26,106	$	424,540	$	47,979
		Proved		895,179		224,410		-
		Exploration*		197,664		184,007		199,569
		Development		382,984		186,755		587,618
		Total	$	1,501,933	$	1,019,712	$	835,166

		* Exploration costs (as defined in Regulation S-X) includes costs spent on development of unproved reserves in the Pinedale Field.

Results of operations for oil and gas producing activities
	F. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES:

				Years Ended December 31,
				2014		2013		2012
		United States

		Oil and gas revenue	$	1,230,020	$	933,404	$	809,974
		Production expenses		-280,631		-212,578		-184,229
		Depletion and depreciation		-292,951		-243,390		-388,985
		Ceiling test and other impairments		-		-		-2,972,464
		Income tax benefit (expense)		3,736		-2,821		662,698
		Total	$	660,174	$	474,615	$	-2,073,006

Capitalized Costs Relating to Oil and Gas Producing Activities				December 31,		December 31,
				2014		2013
		Proven Properties:
		Acquisition, equipment, exploration, drilling and environmental costs(2), (3)	$	9,731,407	$	7,817,374
		Less: Accumulated depletion, depreciation and amortization		-6,094,764		-5,808,836
				3,636,643		2,008,538
		Unproven Properties:
		Acquisition and exploration costs not being amortized (1), (2)		242,294		413,073
		Net capitalized costs - oil and gas properties	$	3,878,937	$	2,421,611


	G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES:

				December 31,
				2014		2013
		Proven Properties:
		Acquisition, equipment, exploration, drilling and
		environmental costs	$	9,731,407	$	7,817,374
		Less: accumulated depletion, depreciation and amortization		-6,094,764		-5,808,836
				3,636,643		2,008,538
		Unproven Properties:
		Acquisition and exploration costs not being amortized		242,294		413,073
			$	3,878,937	$	2,421,611

Significant_Accounting_Policie3

Significant Accounting Policies (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share Reconciliation
Net earnings (loss)	$209,730	$125,357	$106,049	$101,715	$41,118	$63,910	$116,377	$16,433	$542,851	$237,838	($2,176,898)
Weighted average common shares outstanding - basic									153,136,000	152,963,000	152,845,000
Effect of dilutive instruments									1,558,000	1,463,000	0
Weighted average common shares outstanding - fully diluted									154,694,000	154,426,000	152,845,000
Net (income (loss) per common share - basic	$1.37	$0.82	$0.69	$0.66	$0.27	$0.42	$0.76	$0.11	$3.54	$1.55	($14.24)
Net income (loss) per common share - fully diluted	$1.36	$0.81	$0.68	$0.66	$0.27	$0.41	$0.75	$0.11	$3.51	$1.54	($14.24)
Antidilutive Securities Excluded From Computation Of Earnings Per Share Amount									1,377,000	1,406,000	1,900,000

Significant_Accounting_Policie4

Significant Accounting Policies (Details Textuals) (USD $)	12 Months Ended
Significant Accounting Policies (Details Textuals) (USD $)	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013
Significant Accounting Policies Details [Abstract]
Gathering system transferred to proven properties	$91,800,000
Discount Rate Future Net Revenues	10.00%
Ceiling test limitation		2,900,000,000
Inventory	10,200,000		5,200,000
Valuation allowance	161,500,000		363,400,000
Natural gas imbalance liability	$3,000,000		$3,300,000

Asset_Retirement_Obligation_De

Asset Retirement Obligation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation [Abstract]
Asset retirement obligations at beginning of period	$72,807	$60,814
Accretion expense	6,571	5,171
Liabilities incurred	10,242	7,730
Liabilities acquired	53,270	0
Liabilities divested	-15,760	0
Liabilities settled	-336	-2,334
Asset Retirement Obligation, Revision of Estimate	446	1,426
Asset retirement obligations at end of period	127,240	72,807
Less: current asset requirement obligations	-417	-96
Long-term asset retirement obligations	$126,823	$72,711

Oil_and_Gas_Properties_Details

Oil and Gas Properties (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Proven Properties [Abstract]
Acquisition, equipment, exploration, drilling and evnironmental costs	$9,731,407	$7,817,374
Less: Accumulated depletion, depreciation and amortization	-6,094,764	-5,808,836
Proved	3,636,643	2,008,538
Unproven Properties:
Unproven properties not being amortized	242,294	413,073
Net capitalized costs - oil and gas properties	$3,878,937	$2,421,611

Oil_and_Gas_Properties_Details1

Oil and Gas Properties (Details 1) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unproven Properties:
Net Acquisition Costs	$228,516
Interest Costs Capitalized	21,486
Exploration costs	-7,708
Total	242,294	413,073
Acquisition costs	-191,184	419,700	-481,689	481,689
Interest Costs Capitalized	20,232	1,254	-45,875	45,875
Exploration costs	173	-7,881	-9,962	9,962
Total	($170,779)	$413,073	($537,526)	$537,526

Oil_and_Gas_Properties_Details2

Oil and Gas Properties (Details Textuals) (USD $)	12 Months Ended
Oil and Gas Properties (Details Textuals) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil And Gas Property [Abstract]
DD&A per Mcfe	1.18	1.05	1.51
Ceiling test limitation			$2,900,000,000
Total interest on outstanding debt	146,600,000	103,500,000
Capitalized interest detail	$20,400,000	$2,000,000

Property_Plant_Equipment_Detai

Property, Plant & Equipment (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	$23,339
Accumulated Depreciation	-11,153
Property, plant and equipment	12,186	216,909
Gas Gathering Equipment [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	0
Accumulated Depreciation	0
Property, plant and equipment	0	189,110
Computer equipment [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	2,967
Accumulated Depreciation	-2,050
Property, plant and equipment	917	892
Office equipment [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	467
Accumulated Depreciation	-410
Property, plant and equipment	57	41
Leasehold improvements [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	471
Accumulated Depreciation	-360
Property, plant and equipment	111	136
Land [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	5,778
Accumulated Depreciation	0
Property, plant and equipment	5,778	22,359
Other [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	13,656
Accumulated Depreciation	-8,333
Property, plant and equipment	$5,323	$4,371

Property_Plant_Equipment_Detai1

Property, Plant & Equipment (Details Textuals) (USD $)	12 Months Ended
Property, Plant & Equipment (Details Textuals) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Abstract]
Proceeds from sale of oil and gas properties	$27,944,000	$0	$0
Gathering system transferred to proven properties	$91,800,000

Debt_and_Other_Long_Term_Liabi

Debt and Other Long Term Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Long Term Liabilities [Abstract]
Bank indebtedness	$518,000	$460,000
Senior notes	2,760,000	2,010,000
Other long-term obligations	152,472	91,932
Total Debt And Long Term Liabilities	3,530,472	2,561,932
Short-term Debt [Abstract]
Senior Notes due March 2015	$100,000	$0

Debt_and_Other_Long_Term_Liabi1

Debt and Other Long Term Liabilities (Details 1) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
Long Term Debt Maturities	$3,378,000
Maturities Of Long Term Debt One Year [Member]
Long Term Debt Maturities	100,000
Maturities Of Long Term Debt 2016 [Member]
Long Term Debt Maturities	580,000
Maturities Of Long Term Debt 2017 [Member]
Long Term Debt Maturities	116,000
Maturities Of Long Term Debt 2018 [Member]
Long Term Debt Maturities	650,000
Maturities of Long Term Debt 2019 [Member]
Long Term Debt Maturities	173,000
Maturities Of Long Term Debt Beyond Five Years [Member]
Long Term Debt Maturities	$1,759,000

Debt_and_Other_Long_Term_Liabi2

Debt and Other Long Term Liabilities (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Senior Credit Facility Details [Abstract]
Revolving Bank Loan Comitment Value	$1,000,000,000
Max Revolving Bank Loan Comitment Value	1,250,000,000
Letters Of Credit Availability	250,000,000
Bank indebtedness	518,000,000	460,000,000
Credit Facility Lender Consent Requirement	50.00%
Available borrowing capacity	482,000,000
Debt Instrument Interest Rate Terms Prime	100
Debt Instrument Interest Rate Terms Libor	200
Commitment fees incurred in current year	2,000,000
Ultra Resources Inc Senior Notes
Senior Notes Ultra Resources Inc	1,560,000,000
Ultra Petroleum Corp Senior Notes
Senior Notes Ultra Petroleum Corp Due 2024	850,000,000
Senior Notes Ultra Petroleum Corp Due 2024 Interest Rate	6.13%
Debt Instrument Call Feature Ultra Petroleum Corp Senior Notes Due 2024	On and after October 1, 2019, the Company may redeem all or, from time to time, a part of the 2024 Notes at the following prices expressed as a percentage of principal amount of the 2024 Notes: (2019 b 103.063%; 2020 b 102.042%; 2021 b 101.021%; and 2022 and thereafter b 100.000%).
Senior Notes Ultra Petroleum Corp Due 2018	$450,000,000
Senior Notes Ultra Petroleum Corp Due 2018 Interest Rate	5.75%
Debt Instrument Call Feature	On and after December 15, 2015, the Company may redeem all or, from time to time, a part of the 2018 Notes at the following prices expressed as a percentage of principal amount of the 2018 Notes: (2015 b 102.875%; 2016 b 101.438%; and 2017 and thereafter b 100.000%).

Share_Based_Compensation_Detai

Share Based Compensation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Valuation And Expense Information [Abstract]
Total Cost Of Share Based Payment Plans	$8,640	$13,957	$15,835
Amounts capitalized in fixed costs	3,173	4,190	5,079
Amounts charged against income, before income tax benefit	5,467	9,767	10,756
Amount of related income tax benefit recognized in income	$2,285	$4,083	$4,463

Share_Based_Compensation_Detai1

Share Based Compensation (Details 1) (USD $)	Dec. 31, 2014
Share Based Compensation Details [Abstract]
Number of Securities to be Issued Upon Exercise of Outstanding Options	690,000
Weighted Averaged Exercise Price of Outstanding Options	$56.58
Number Of Securities Remaining Available For Future Issuance Under Equity Compenstation Plans Excluding Securities Reflected In The First Column	2,608,000

Share_Based_Compensation_Detai2

Share Based Compensation (Details 2) (USD $)	12 Months Ended
Share Based Compensation (Details 2) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock Options Outstanding Summary [Line Items]
Balance,	690,000
Number Of Options [Member]
Stock Options Outstanding Summary [Line Items]
Balance,	1,246,000	1,357,000	1,459,000
Forfeited	-513,000	-110,000	-68,000
Exercised	-43,000	-1,000	-34,000
Balance,	690,000	1,246,000	1,357,000
Weighted Average Exercise Price [Member]
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit	$25.68	$16.97	$16.97	$16.97
Exercise Price, Upper Range Limit	$98.87	$98.87	$98.87	$98.87
Exercise Price, Lower Range Limit Forfeited	$33.57	$25.68	$25.08
Exercise Price, Upper Range Limit Forfeited	$75.18	$75.18	$75.18
Exercise Price, Lower Range Limit Exercised	$16.97	$16.97	$16.97
Exercise Price, Upper Range Limit Exercised	$25.68	$16.97	$19.18

Share_Based_Compensation_Detai3

Share Based Compensation (Details 3) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014
Range 4 [Member]
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit	$25.68
Exercise Price, Upper Range Limit	$53.39
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Number Outstanding	126,000
Weighted Average Remaining Contractual Life	0 years 7 months 20 days
Weighted Average Exercise Price	$44.25
Aggregate Intrinsic Value	$0
Range 5 [Member]
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit	$50.15
Exercise Price, Upper Range Limit	$65.04
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Number Outstanding	125,000
Weighted Average Remaining Contractual Life	1 year 6 months 18 days
Weighted Average Exercise Price	$57
Aggregate Intrinsic Value	0
Range 6 [Member]
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit	$49.05
Exercise Price, Upper Range Limit	$62.23
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Number Outstanding	281,000
Weighted Average Remaining Contractual Life	2 years 3 months 11 days
Weighted Average Exercise Price	$53.85
Aggregate Intrinsic Value	0
Range 7 [Member]
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit	$51.60
Exercise Price, Upper Range Limit	$98.87
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Number Outstanding	158,000
Weighted Average Remaining Contractual Life	3 years 5 months 5 days
Weighted Average Exercise Price	$70.92
Aggregate Intrinsic Value	$0

Share_Based_Compensation_Detai4

Share Based Compensation (Details 4) (USD $)	12 Months Ended
Share Based Compensation (Details 4) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Options forfeited during the year	$24.40	$25.44	$27.05

Share_Based_Compensation_Detai5

Share Based Compensation (Details Textuals) (USD $)	12 Months Ended
Share Based Compensation (Details Textuals) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Details [Abstract]
Companys Closing Stock Price Last Day Of Year	$13.16
Number Of In The Money Options Exercisable	0
Fair Value Of Options Vesting In The Period	0	0	0
Total intrinsic value of stock options excercised	400,000	0	300,000
Long Term Incentive Program Period	6,300,000	6,900,000	7,900,000
Long Term Incentive Program Total 2012 Program	10,200,000
Long Term Incentive Program Total 2013 Program	12,600,000
Long Term Incentive Program Total 2014 Program	13,000,000
Long Term Incentive Program Total 2011 Program	$8,400,000
Long Term Incentive Program Total 2011 Program Shares	106,437

Derivative_Financial_Instrumen2

Derivative Financial Instruments (Details) (Nymex Henry Hub [Member], USD $)	Feb. 24, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified	MMBTU	MMBTU
January To March 2015 [Member]
Schedule Of Derivative Instruments [Line Items]
Volume		210,000
Average Price		4.54
Fair Value		$29,201
Summer 2015 [Member]
Schedule Of Derivative Instruments [Line Items]
Volume	150,000	522,500
Average Price	2.98	3.65
Fair Value		$74,989

Derivative_Financial_Instrumen3

Derivative Financial Instruments (Details 1) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commodity Derivatives [Abstract]
Realized (loss) gain on commodity derivatives - natural gas									($48,170)	($20,552)	$303,966
Realized (loss) gain on commodity derivatives - crude oil									506	-326	0
Unrealized loss (gain) on commodity derivatives									130,066	-25,876	-230,385
Gain loss on commodity derivatives	$110,725	$32,052	($15,102)	($45,273)	($26,204)	$2,074	$22,091	($44,715)	$82,402	($46,754)	$73,581

Derivative_Financial_Instrumen4

Derivative Financial Instruments (Details Textuals)	12 Months Ended
Derivative Financial Instruments (Details Textuals)	Dec. 31, 2014
Commodity Derivatives Authorization [Abstract]
Commodity Derivatives Board Authorization	50.00%

Fair_Value_Measurments_Details

Fair Value Measurments (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative Assets Abstract
Derivative assets	$104,190	$1,415
Derivative Liabilities Abstract
Derivative liabilities	0	27,291
Fair Value Inputs Level 2 [Member]
Derivative Assets Abstract
Derivative assets	$104,190

Fair_Value_Measurments_Details1

Fair Value Measurments (Details 1) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Debt carrying value	$3,378,000	$2,470,000
Estimated Fair Value	3,190,319	2,626,349
Notes Due 2015 [Member]
Debt Instrument [Line Items]
Debt carrying value	100,000	100,000
Estimated Fair Value	101,931	105,913
Debt Instruments Interst Rates	5.45%
Notes Due 2016 [Member]
Debt Instrument [Line Items]
Debt carrying value	62,000	62,000
Estimated Fair Value	65,027	70,228
Debt Instruments Interst Rates	7.31%
Notes Due 2017 [Member]
Debt Instrument [Line Items]
Debt carrying value	116,000	116,000
Estimated Fair Value	116,240	126,342
Debt Instruments Interst Rates	4.98%
Notes Due 2018 [Member]
Debt Instrument [Line Items]
Debt carrying value	200,000	200,000
Estimated Fair Value	203,738	226,127
Debt Instruments Interst Rates	5.92%
Notes Due December 2018 [Member]
Debt Instrument [Line Items]
Debt carrying value	450,000	450,000
Estimated Fair Value	414,505	466,946
Debt Instruments Interst Rates	5.75%
Notes Due 2019 [Member]
Debt Instrument [Line Items]
Debt carrying value	173,000	173,000
Estimated Fair Value	187,105	211,877
Debt Instruments Interst Rates	7.77%
Notes Due January 2020 [Member]
Debt Instrument [Line Items]
Debt carrying value	207,000	207,000
Estimated Fair Value	201,371	229,068
Debt Instruments Interst Rates	5.50%
Notes Due October 2020 [Member]
Debt Instrument [Line Items]
Debt carrying value	315,000	315,000
Estimated Fair Value	283,335	323,732
Debt Instruments Interst Rates	4.51%
Notes Due January 2022 [Member]
Debt Instrument [Line Items]
Debt carrying value	87,000	87,000
Estimated Fair Value	82,581	95,736
Debt Instruments Interst Rates	5.60%
Notes Due October 2022 [Member]
Debt Instrument [Line Items]
Debt carrying value	35,000	35,000
Estimated Fair Value	30,476	35,494
Debt Instruments Interst Rates	4.66%
Notes Due October 2024 [Member]
Debt Instrument [Line Items]
Debt carrying value	850,000	0
Estimated Fair Value	754,485	0
Debt Instruments Interst Rates	6.13%
Notes Due January 2025 [Member]
Debt Instrument [Line Items]
Debt carrying value	90,000	90,000
Estimated Fair Value	83,876	99,142
Debt Instruments Interst Rates	5.85%
Notes Due October 2025 [Member]
Debt Instrument [Line Items]
Debt carrying value	175,000	175,000
Estimated Fair Value	147,649	175,744
Debt Instruments Interst Rates	4.91%
Credit Facility [Member]
Debt Instrument [Line Items]
Debt carrying value	518,000	460,000
Estimated Fair Value	$518,000	$460,000

Income_Taxes_Details

Income Taxes (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Loss From Continuing Operations [Abstract]
United States									$505,689	$210,580	($2,892,207)
Foreign									31,338	23,642	15,096
Income (loss) before income tax (benefit)	$205,829	$123,974	$105,505	$101,719	$34,262	$64,291	$117,868	$17,801	$537,027	$234,222	($2,877,111)

Income_Taxes_Details_1

Income Taxes (Details 1) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current:
U.S. federal, state and local - current									($110)	($8,491)	$9,037
Foreign - current									-6,709	4,881	3,326
(Reduction in) tax benefit on stock based compensation - federal, state and local									0	0	-4,427
Total current tax expense (benefit)									-6,819	-3,610	7,936
Deferred:
U.S. federal, state and local - deferred									0	0	-708,160
Foreign - deferred									995	-6	11
Total deferred tax expense (benefit)									995	-6	-708,149
Total income tax (benefit)	($3,901)	($1,383)	($544)	$4	($6,856)	$381	$1,491	$1,368	($5,824)	($3,616)	($700,213)

Income_Taxes_Details_2

Income Taxes (Details 2) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation Abstract
Income tax provision (benefit) computed at the U.S. statutory rate									$187,959	$81,978	($1,006,989)
State income tax provision net of federal benefit									8,023	1,329	-136,112
Valuation allowance									-199,038	-81,923	446,148
Tax Effect Of Rate Change									15,457	-2,871	1,358
Foreign tax rate differential									-16,314	-3,508	-5,531
Other, net									-1,911	1,379	913
Total income tax (benefit)	($3,901)	($1,383)	($544)	$4	($6,856)	$381	$1,491	$1,368	($5,824)	($3,616)	($700,213)

Income_Taxes_Details_3

Income Taxes (Details 3) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred tax assets - current:
Derivative instruments current, net	$0	$9,636
Incentive compensation-other, net	6,150	7,641
Deferred Tax Assets Valuation Allowance Net Current	0	-16,778
Net deferred tax assets - current	6,150	499
Deferred Tax Liabilities Current [Abstract]
Derivative instruments, net	36,788	499
Deferred Tax Assets Liabilities Net Current	30,638	0
Deferred tax assets - non - current [Abstract]
Property and equipment	0	131,340
Deferred gain on sale	48,319	52,045
U.S. federal tax credit carryforwards	16,144	16,254
Net operating loss carryforwards	147,336	71,843
US state net operating loss carryforward	53,654	36,205
Asset retirement obligations	45,039	26,876
Incentive compensation/other, net	19,142	13,007
Deferred tax assets noncurrent before valuation allowances	329,634	347,570
Valuation allowance	-161,480	-346,596
Net deferred tax assets - non-current	168,154	974
Deferred Tax Liabilities - non current [Abstract]
Property and equipment	137,514	0
Other	0	968
Net non-current tax liabilities	137,514	968
Net non-current tax asset	30,640	6
Non-US Deferred tax liabilities - non-current
Other - Non US	$992	$0

Income_Taxes_Details_Textuals

Income Taxes (Details Textuals) (USD $)	12 Months Ended
Income Taxes (Details Textuals) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement Income Taxes Details [Abstract]
Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate	35.00%
Deferred Tax Assets, Valuation Allowance	$161,500,000	$363,400,000
Total change in valuation allowance	201,900,000
Change in valuation allowance - earnings	199,038,000	81,923,000	-446,148,000
Change in valuation allowance - equity	2,900,000
U.S. federal alternative minimum tax credits	14,100,000
Deferred Tax Assets Tax Credit Carryforwards General Business	500,000
Foreign tax credit carryforward	1,700,000
Deferred Tax Assets Operating Loss Carryforwards Domestic Total	214,900,000	260,100,000
Deferred Tax Assets Operating Loss Carryback Domestic		54,500,000
Income Tax Receivable		8,000,000
Deferred Tax Assets Operating Loss Carryforwards Domestic	420,900,000
State tax net operating loss carryforwards	798,400,000
Canadian Operating Loss	23,800,000
Income taxes receivable - Canada	$6,200,000

Employee_Benefits_Details

Employee Benefits (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Tax Deferred Savings Plan [Abstract]
Employee Deferral Percent for 401(k)	100.00%
Company Matching Percent for 401(k)	5.00%
Company Discretionary Contribution for 401(k)	8.00%
Pension and Other Postretirement Benefit Contributions [Abstract]
Other Postretirement Benefits Payments	$2	$1.60	$1.80

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MMBTU	Dec. 31, 2013	Dec. 31, 2012
Commitements And Contingencies Disclosure [Abstract]
Commitment capacity per day of natural gas	200
Increased commitment capacity per day of natural gas	50
Demand charges related to remaining contract	$469
Initial Term Liquids Gathering System Lease	15
Renewal Term Liquids Gathering System Lease	5
Renewal Term Liquids Gathering System Lease Useful Life	75.00%
Liquids Gathering System Operating Lease Rental Expense	20
Lease And Rental Expense Total	268
Committed drilling obligations with rig contractors, total	33
Committed drilling obligations with rig contractors, due in one year	31.6
Office Space Operating Lease Total Future Minimum Payments	8.6
Commitment to office leases, current	1
Commitment to office leases, due in two years	1.3
Commitment to office leases, due in three years	1.3
Commitment to office leases, due in four years	1.2
Commitment to office leases, due in five years	1.1
Office leases expense	$1	$1	$1
Oil and gas delivery commitments details	Delivery Commitments. With respect to the Companybs natural gas production, from time to time the Company enters into transactions to deliver specified quantities of gas to its customers. As of February 9, 2015, the Company has long-term natural gas delivery commitments of 1.2 MMMBtu in 2015, 26.2 MMMBtu in 2016, and 7.9 MMMBtu in 2017 under existing agreements. As of February 9, 2015, the Company has long-term crude oil delivery commitments of 2.4 MMBbls in 2015, 2.4 MMBbls in 2016, 1.7 MMBbls in 2017, 0.7 MMBbls in 2018 and 0.2 MMBbls in 2019 under existing agreements. None of these commitments require the Company to deliver gas or oil produced specifically from any of the Companybs properties, and all of these commitments are priced on a floating basis with reference to an index price. These committed volumes are below the Companybs forecasted 2015 and anticipated 2016 through 2019 production from its available reserves. In addition, none of the Companybs reserves are subject to any priorities or curtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agencies or any other factors beyond the Companybs control that may affect its ability to meet its contractual obligations other than those discussed in Item 1A. bRisk Factorsb. The Company believes that its reserves are adequate to meet its commitments. If for some reason the Companybs production is not sufficient to satisfy its commitments, the Company expects to be able to purchase volumes in the market or make other arrangements to satisfy its commitments.

Credit_Risk_Details

Credit Risk (Details)	12 Months Ended
Credit Risk (Details)	Dec. 31, 2014
Schedule Of Significant Customers [Line Items]
Percentage of revenue	10.00%

Completion_of_Acquisition_and_2

Completion of Acquisition and Disposition of Assets (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition Pro Forma Information [Abstract]
Revenues	$1,421,537	$1,160,394
Net income	$531,188	$164,303
Net income per common share - basic	$3.47	$1.07
Net income per common share - fully diluted	$3.43	$1.06

Completion_of_Acquisition_and_3

Completion of Acquisition and Disposition of Assets (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2014
Business Combination Consideration Transferred [Abstract]
Adjusted Cash Payment	$890,800,000
Assets [Abstract]
Joint Interest Billing and Other Receivables SWEPI Properties	-4,182,000
Other Current Assets [Abstract]
Acquired Condensate Inventory	819,000
Acquired Yard Inventory	3,515,000
Subtotal Other current assets	4,334,000
Proven oil and gas properties	1,033,960,000
Property Plant And Equipment [Abstract]
Divested Gathering Systems Pennsylvania Properties	-98,580,000
Acquired Other Fixed Assets SWEPI Properties	869,000
Divested Other Fixed Assets Pennsylvania Properties	-50,000
Subtotal Property Plant And Equipment	-97,761,000
Total assets acquired, net of divest assets	936,351,000
Current Liabilities [Abstract]
Current Liabilities Pennsylvania Properties	8,657,000
Current Liabilities SWEPI Properties	-601,000
Subtotal Current liabilities	8,056,000
Other long term obligations [Abstract]
Acquired Asset Retirement Obligation SWEPI Properties	53,270,000
Divested Asset Retirement Obligation Pennsylvania Properties	-15,760,000
Subtotal Other Long Term Obligations	37,510,000
Total Liabilities Net	$45,566,000

Completion_of_Acquisition_and_4

Completion of Acquisition and Disposition of Assets (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	acre	Dec. 31, 2013
Business Combination Details [Abstract]
Business Combination Gross Purchase Price	$925,000,000
Senior Notes Ultra Petroleum Corp Due 2024	850,000,000
Senior Notes Ultra Petroleum Corp Due 2024 Interest Rate	6.13%
Senior Notes Ultra Petroleum Corp Due 2024 Deferred Financing Costs	13,100,000
Business Combination Integration Related Costs	600,000
Gas And Oil Developed Acreage Acquired Net	19,600
Gas And Oil Developed And Undeveloped Acreage Divested Net	155,000
Adjusted Cash Payment	890,800,000
Business Combination Non Recurring Transportation Charges	74,600,000	113,400,000
Post-Acquisiton Operating Results Revenues	74,691,000
Post-Acquisition Operating Results Earnings	23,515,000
Uinta Gross Acquisition Cost	652,000,000
Senior Notes Ultra Petroleum Corp Due 2018	$450,000,000

Summarized_Quarterly_Financial2

Summarized Quarterly Financial Information (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Selected Quarterly Financial Information [Abstract]
Revenues from continuing operations	$319,050	$288,608	$296,063	$326,299	$225,197	$221,205	$261,376	$225,626	$1,230,020	$933,404	$809,974
Gain (loss) on commodity derivatives	110,725	32,052	-15,102	-45,273	-26,204	2,074	22,091	-44,715	82,402	-46,754	73,581
Expenses from continuing operations	195,083	169,669	150,850	154,829	141,753	136,389	143,002	139,994	670,431	561,138
Ceiling test and other impairments					0	0	0	0	0	0	2,972,464
Interest expense	42,196	29,599	27,294	27,068	25,310	25,174	25,238	25,764	126,157	101,486	88,180
Gain on sale of property	8,022	0	0	0					8,022	0	0
Contract Cancellation Fees					0	0	0	0	0	0	15,469
Other (expense) income, net	5,311	2,582	2,688	2,590	2,332	2,575	2,641	2,648	13,171	10,196
Income (loss) from continuing operations	205,829	123,974	105,505	101,719	34,262	64,291	117,868	17,801	537,027	234,222	-2,877,111
Income tax (benefit)	-3,901	-1,383	-544	4	-6,856	381	1,491	1,368	-5,824	-3,616	-700,213
Net income (loss)	$209,730	$125,357	$106,049	$101,715	$41,118	$63,910	$116,377	$16,433	$542,851	$237,838	($2,176,898)
Net (income (loss) per common share - basic	$1.37	$0.82	$0.69	$0.66	$0.27	$0.42	$0.76	$0.11	$3.54	$1.55	($14.24)
Net income (loss) per common share - fully diluted	$1.36	$0.81	$0.68	$0.66	$0.27	$0.41	$0.75	$0.11	$3.51	$1.54	($14.24)

Disclosure_About_Oil_and_Gas_P1

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	bbl	bbl	bbl
Oil Reserves [Member]
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance	34,119,000	18,137,000	33,081,000
Extensions, discoveries and additions	34,275,000	11,329,000	5,435,000
Sales	0	0	0
Acquisitions	9,381,000	10,114,000	0
Production	-3,409,000	-1,196,000	-1,282,000
Revisions	-6,600,000	-4,265,000	-19,097,000
Reserves, Ending Balance	67,766,000	34,119,000	18,137,000
Natural Gas Reserves [Member]
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance	3,409,742,000	2,966,445,000	4,778,554,000
Extensions, discoveries and additions	866,513,000	1,409,528,000	819,896,000
Sales	-239,290,000	0	0
Acquisitions	1,345,964,000	0	0
Production	-228,517,000	-224,912,000	-249,310,000
Revisions	-323,218,000	-741,319,000	-2,382,695,000
Reserves, Ending Balance	4,831,194,000	3,409,742,000	2,966,445,000
Natural Gas Liquids Reserves [Member]
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance	0	0	0
Extensions, discoveries and additions	210,000	0	0
Sales	0	0	0
Acquisitions	21,740,000	0	0
Production	0	0	0
Revisions	43,000	0	0
Reserves, Ending Balance	21,993,000	0	0

Disclosure_About_Oil_and_Gas_P2

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 1)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	bbl	bbl	bbl	bbl
Oil Reserves [Member]
Reserve Quantities [Line Items]
Developed	28,481,000	20,566,000	10,531,000	11,794,000
Undeveloped	39,285,000	13,553,000	7,606,000	21,287,000
Total Proved	67,766,000	34,119,000	18,137,000	33,081,000
Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Developed	2,245,004,000	1,777,267,000	1,820,994,000	1,973,391,000
Undeveloped	2,586,190,000	1,632,475,000	1,145,451,000	2,805,163,000
Total Proved	4,831,194,000	3,409,742,000	2,966,445,000	4,778,554,000
Natural Gas Liquids Reserves [Member]
Reserve Quantities [Line Items]
Developed	9,118,000	0	0	0
Undeveloped	12,875,000	0	0	0
Total Proved	21,993,000	0	0	0

Disclosure_About_Oil_and_Gas_P3

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves Future Net Cash Flows Abstract
Future Cash Inflows	$27,331,391	$14,861,131	$9,380,970
Future Production Costs	-8,627,657	-4,540,209	-3,217,771
Future Development Costs	-3,859,385	-2,014,751	-1,661,394
Future Income Taxes	-3,898,355	-1,897,340	-733,855
Future Net Cash Flows	10,945,994	6,408,831	3,767,950
Discount at 10%	-5,712,511	-3,220,862	-1,873,633
Standardized measure of discounted future net cash flows	$5,233,483	$3,187,969	$1,894,317

Disclosure_About_Oil_and_Gas_P4

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized Measure, beginning	$3,187,969,000	$1,894,317,000	$3,796,056,000
Net revisions of previous quantity estimates	-603,795,000	-1,089,316,000	-2,516,159,000
Extensions, discoveries and other changes	1,787,643,000	2,098,644,000	858,951,000
Sales of reserves in place	-398,506,000	0	0
Acquistion of reserves	2,552,491,000	86,196,000	0
Changes in future development costs	-1,013,652,000	-252,992,000	952,067,000
Sales of oil and gas, net of production costs	-949,389,000	-720,826,000	-625,745,000
Net change in prices and production costs	1,010,052,000	1,204,041,000	-2,912,698,000
Development costs incurred during the period that reduce future development costs	342,987,000	171,149,000	316,394,000
Accretion of discount	413,177,000	226,326,000	529,696,000
Net changes in production rates and other	-175,419,000	145,289,000	363,788,000
Net change in income taxes	-920,075,000	-574,859,000	1,131,967,000
Aggregrate changes	2,045,514,000	1,293,652,000	-1,901,739,000
Standardized Measure, ending	$5,233,483,000	$3,187,969,000	$1,894,317,000

Disclosure_About_Oil_and_Gas_P5

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 4) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Acquisition costs - unproved properties	$26,106	$424,540	$47,979
Acquisition costs - proved properties	895,179	224,410	0
Exploration	197,664	184,007	199,569
Development	382,984	186,755	587,618
Total	$1,501,933	$1,019,712	$835,166

Disclosure_About_Oil_and_Gas_P6

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 5) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Results of Operations, Oil and Gas Producing Activities Net Income (Excluding Corporate Overhead and Interest Costs) [Abstract]
Oil and gas revenue	$1,230,020	$933,404	$809,974
Production expenses	-280,631	-212,578	-184,229
Depletion and depreciation expense	-292,951	-243,390	-388,985
Write-downs of proved oil and gas properties	0	0	-2,972,464
Income taxes	3,736	-2,821	662,698
Total	$660,174	$474,615	($2,073,006)

Disclosure_About_Oil_and_Gas_P7

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 6) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Proven Properties [Abstract]
Acquisition, equipment, exploration, drilling and evnironmental costs	$9,731,407	$7,817,374
Less: Accumulated depletion, depreciation and amortization	-6,094,764	-5,808,836
Proved	3,636,643	2,008,538
Unproven Properties:
Oil Gas Properties Using Full Cost Method Accounting Unproved	242,294	413,073
Net capitalized costs - oil and gas properties	$3,878,937	$2,421,611

Disclosure_About_Oil_and_Gas_P8

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Internal Engineer Experience	13
Expert Qualfications	The reserves estimates shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. B NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. B Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Robert C. Barg and Mr. Phillip R. Hodgson. B Mr. Barg, a Licensed Professional Engineer in the State of Texas (No. 71658), has been practicing consulting petroleum engineering at NSAI since 1989B and has over 6 years of prior industry experience. B He graduated from Purdue University in 1983 with a Bachelor of Science Degree in Mechanical Engineering. B Mr. Hodgson, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998B and has over 14 years of prior industry experience. B He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. B Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
Reserves Prepared Internally		2.00%
Weighted Average Sales Price For Proved Reserves Textuals [Abstract]
Weighted Average Sales Price For Proved Reserves Natural Gas	$4.32	$3.51	$2.63
Weighted Average Sales Price For Proved Reserves Condensate	80.62	84.97	87.85
Weighted Average Sales Price For Proved Reserves Natural Gas Liquids	$46.27	$0	$0