10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2012

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file number 001-33614

ULTRA PETROLEUM CORP.

(Exact name of registrant as specified in its charter)

Yukon Territory, Canada	N/A
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer identification number)
400 North Sam Houston Parkway E., Suite 1200, Houston, Texas	77060
(Address of principal executive offices)	(Zip code)

(281) 876-0120

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    YES  þ    NO  ¨

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

Large accelerated filer	þ	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of October 23, 2012 was 152,928,937.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
ITEM 1.	Financial Statements	3
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	26
ITEM 4.	Controls and Procedures	28
PART II — OTHER INFORMATION
ITEM 1.	Legal Proceedings	28
ITEM 1A.	Risk Factors	28
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28
ITEM 3.	Defaults upon Senior Securities	28
ITEM 4.	Mine Safety Disclosures	28
ITEM 5.	Other Information	28
ITEM 6.	Exhibits	29
	Signatures	30
	Exhibit Index	31

2

PART I – FINANCIAL INFORMATION

ITEM 1 – FINANCIAL STATEMENTS

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
	(Unaudited)
	(Amounts in thousands, except per share data)
Revenues:
Natural gas sales	$	169,594		$	262,147		$	501,470		$	743,898
Oil sales		26,781			30,994			91,319			87,101
Total operating revenues		196,375			293,141			592,789			830,999
Expenses:
Lease operating expenses		16,741			12,381			45,982			35,853
Production taxes		15,047			25,676			46,634			73,796
Gathering fees		10,274			14,445			46,591			41,363
Transportation charges		21,055			16,061			63,477			48,492
Depletion, depreciation and amortization		86,645			85,795			314,115			238,773
Ceiling test and other impairments		606,827			—			2,475,963			—
General and administrative		6,741			6,185			19,308			19,298
Total operating expenses		763,330			160,543			3,012,070			457,575
Operating (loss) income		(566,955	)		132,598			(2,419,281	)		373,424
Other income (expense), net:
Interest expense		(25,369	)		(15,902	)		(62,414	)		(46,082	)
(Loss) gain on commodity derivatives		(9,896	)		114,166			77,100			177,407
Rig cancellation fees		291			—			(9,220	)		—
Other (expense) income, net		(42	)		(3	)		(27	)		14
Total other (expense) income, net		(35,016	)		98,261			5,439			131,339
(Loss) income before income tax provision (benefit)		(601,971	)		230,859			(2,413,842	)		504,763
Income tax provision (benefit)		175			81,713			(708,977	)		183,392
Net (loss) income	$	(602,146	)	$	149,146		$	(1,704,865	)	$	321,371
Net (loss) income per common share—basic	$	(3.94	)	$	0.98		$	(11.16	)	$	2.10
Net (loss) income per common share—fully diluted	$	(3.94	)	$	0.97		$	(11.16	)	$	2.08
Weighted average common shares outstanding—basic		152,929			152,817			152,817			152,772
Weighted average common shares outstanding—fully diluted		152,929			154,280			152,817			154,418

See accompanying notes to consolidated financial statements.

3

ULTRA PETROLEUM CORP.

CONSOLIDATED BALANCE SHEETS

	September 30, 2012			December 31, 2011
	(Unaudited)
	(Amounts in thousands of U.S. dollars, except share data)
ASSETS
Current Assets:
Cash and cash equivalents	$	59,194		$	11,307
Restricted cash		121			121
Oil and gas revenue receivable		62,237			88,243
Joint interest billing and other receivables		21,816			82,370
Derivative assets		52,716			230,385
Prepaid drilling costs and other current assets		6,406			7,494
Total current assets		202,490			419,920
Oil and gas properties, net, using the full cost method of accounting:
Proven		2,095,823			3,651,622
Unproven properties not being amortized		—			537,526
Property, plant and equipment		271,284			246,586
Deferred tax assets		11,586			—
Deferred financing costs and other		12,445			14,051
Total assets	$	2,593,628		$	4,869,705
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	143,751		$	295,873
Production taxes payable		60,084			62,117
Deferred tax liabilities		11,586			73,380
Interest payable		8,495			30,306
Derivative liabilities		5,470			—
Capital cost accrual		239,671			209,303
Total current liabilities		469,057			670,979
Long-term debt		2,160,000			1,903,000
Deferred tax liabilities		—			635,009
Other long-term obligations		74,174			67,008
Commitments and contingencies
Shareholders’ equity:
Common stock - no par value; authorized - unlimited; issued and outstanding - 152,928,937 and 152,476,564 at September 30, 2012 and December 31, 2011, respectively		470,081			463,221
Treasury stock		(33	)		(14,951	)
Retained earnings		(579,651	)		1,145,439
Total shareholders’ equity		(109,603	)		1,593,709
Total liabilities and shareholders’ equity	$	2,593,628		$	4,869,705

See accompanying notes to consolidated financial statements.

4

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30,
	2012			2011
	(Unaudited)
	(Amounts in thousands of U.S. dollars)
Cash provided by (used in):
Operating activities:
Net (loss) income for the period	$	(1,704,865	)	$	321,371
Adjustments to reconcile net (loss) income to cash provided by operating activities:
Depletion, depreciation and amortization		314,115			238,773
Ceiling test and other impairments		2,475,963			—
Deferred income tax (benefit) provision		(712,363	)		176,566
Unrealized loss (gain) on commodity derivatives		183,139			(33,658	)
Reduction in (excess) tax benefits from stock based compensation		4,215			(6,441	)
Stock compensation		7,830			9,892
Other		1,663			783
Net changes in operating assets and liabilities:
Restricted cash		—			(11	)
Accounts receivable		86,560			(22,329	)
Prepaid expenses and other		1,418			(1,927	)
Other non-current assets		—			(135	)
Accounts payable and accrued liabilities		(151,016	)		1,637
Production taxes payable		(2,033	)		8,204
Interest payable		(21,811	)		8,175
Other long-term obligations		(1,747	)		14,432
Taxation payable/receivable, net		(993	)		4,460
Net cash provided by operating activities		480,075			719,792
Investing Activities:
Oil and gas property expenditures		(588,808	)		(1,081,450	)
Gathering system expenditures		(115,972	)		(35,179	)
Change in capital cost accrual		30,368			72,568
Inventory		(1,035	)		1,212
Purchase of capital assets		(4,133	)		(939	)
Net cash used in investing activities		(679,580	)		(1,043,788	)
Financing activities:
Borrowings on long-term debt		749,000			896,000
Payments on long-term debt		(492,000	)		(618,000	)
Repurchased shares/net share settlements		(6,550	)		(28,625	)
(Reduction in) excess tax benefits from stock based compensation		(4,215	)		6,441
Proceeds from exercise of options		1,157			9,655
Net cash provided by financing activities		247,392			265,471
Increase (decrease) in cash during the period		47,887			(58,525	)
Cash and cash equivalents, beginning of period		11,307			70,834
Cash and cash equivalents, end of period	$	59,194		$	12,309

See accompanying notes to consolidated financial statements.

5

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(All amounts in this Quarterly Report on Form 10-Q are expressed in thousands of U.S. dollars (except per share data) unless otherwise noted)

DESCRIPTION OF THE BUSINESS:

Ultra Petroleum Corp. (the “Company”) is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. The Company is incorporated under the laws of the Yukon Territory, Canada. The Company’s principal business activities are conducted in the Green River Basin of Southwest Wyoming and in the north-central Pennsylvania area of the Appalachian Basin.

1. SIGNIFICANT ACCOUNTING POLICIES:

The accompanying financial statements, other than the balance sheet data as of December 31, 2011, are unaudited and were prepared from the Company’s records, but do not include all disclosures required by U.S. Generally Accepted Accounting Principles (“GAAP”). Balance sheet data as of December 31, 2011 was derived from the Company’s audited financial statements. The Company’s management believes that these financial statements include all adjustments necessary for a fair presentation of the Company’s financial position and results of operations. All adjustments are of a normal and recurring nature unless specifically noted. The Company prepared these statements on a basis consistent with the Company’s annual audited statements and Regulation S-X. Regulation S-X allows the Company to omit some of the footnote and policy disclosures required by generally accepted accounting principles and normally included in annual reports on Form 10-K. You should read these interim financial statements together with the financial statements, summary of significant accounting policies and notes to the Company’s most recent annual report on Form 10-K.

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. GAAP. All inter-company transactions and balances have been eliminated upon consolidation.

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

(b) 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.

(c) Property, Plant and Equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on a seven-year useful life. Gathering system expenditures are recorded at cost and depreciated using the straight-line method based on a 30-year useful life. The gathering system assets are depreciated separately from proven oil and gas properties because they are expected to be used to transport oil and gas not currently included in the Company’s proved reserves, including production expected from probable and possible reserves, as well as from third parties.

The Company recognized impairments of $92.5 million during the nine months ended September 30, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These assets are included in Property, Plant and Equipment in the Consolidated Balance Sheets.

6

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(d) 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”). 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 Company’s proved reserves. 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. Excluded costs, if any, are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the 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 and natural gas prices may subsequently increase the ceiling.

The Company recorded a $2.4 billion non-cash write-down of the carrying value of its proved oil and natural gas properties for the nine months ended September 30, 2012 as a result of ceiling test limitations, which is reflected with 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 September 30, 2012 and June 30, 2012 of $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials.

(e) Derivative Instruments and Hedging Activities: Currently, the Company largely relies on commodity derivative contracts to manage its exposure to commodity price risk. These commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties. Additionally, and from time to time, the Company enters into physical, fixed price forward natural gas sales in order to mitigate its

7

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

commodity price exposure on a portion of its natural gas production. These fixed price forward natural gas sales are considered normal sales in the ordinary course of business and outside the scope of FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 6).

(f) 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.

(g) Earnings Per Share: Basic earnings per share is computed by dividing net earnings attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings 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.

	Three Months Ended					Nine Months Ended
	September 30, 2012			September 30, 2011		September 30, 2012			September 30, 2011
	(Share amounts in 000’s)
Net (loss) income	$	(602,146	)	$	149,146	$	(1,704,865	)	$	321,371
Weighted average common shares outstanding—basic		152,929			152,817		152,817			152,772
Effect of dilutive instruments		—			1,463		—			1,646
Weighted average common shares outstanding—fully diluted		152,929			154,280		152,817			154,418
Net (loss) income per common share—basic	$	(3.94	)	$	0.98	$	(11.16	)	$	2.10
Net (loss) income per common share—fully diluted	$	(3.94	)	$	0.97	$	(11.16	)	$	2.08
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		1,373			1,168		1,893			968

(h) 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.

8

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(i) 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.

(j) 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 7 for additional information.

(k) 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 changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations.

(l) Revenue Recognition: The Company generally sells natural gas and condensate 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. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue. Any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable.

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.

(m) Capitalized Interest: Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated as well as on work in process relating to gathering systems.

(n) Capital Cost Accrual: The Company accrues for exploration and development costs and construction of gathering systems in the period incurred, while payment may occur in a subsequent period.

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

(p) Recent Accounting Pronouncements: In May 2011, the FASB issued ASU No. 2011-04, which amends FASB ASC 820. The amended guidance clarifies many requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB’s

9

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not have a material impact on the Company’s consolidated financial statements.

2. OIL AND GAS PROPERTIES AND EQUIPMENT:

	September 30, 2012			December 31, 2011
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$	7,106,729		$	5,974,604
Less: Accumulated depletion, depreciation and amortization(2)		(5,010,906	)		(2,322,982	)
		2,095,823			3,651,622
Unproven Properties:
Acquisition and exploration costs not being amortized(1)		—			537,526
Net capitalized costs—oil and gas properties	$	2,095,823		$	4,189,148
Property, Plant and Equipment:
Gathering Systems(1)	$	346,520		$	226,747
Less: Accumulated depreciation(3)		(104,425	)		(7,736	)
		242,095			219,011
Other Property and Equipment		14,697			11,333
Less: Accumulated depreciation		(7,851	)		(5,908	)
		6,846			5,425
Land		22,343			22,150
Net capitalized costs—property, plant and equipment	$	271,284		$	246,586

⁽¹⁾For the nine months ended September 30, 2012 and 2011, total interest on outstanding debt was $77.2 million and $69.0 million, respectively, of which, $14.8 million and $22.9 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and on work in process relating to gathering systems.

⁽²⁾The Company recorded a $2.4 billion non-cash write-down of the carrying value of its proved oil and natural gas properties for the nine months ended September 30, 2012 as a result of ceiling test limitations, which is reflected with 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 September 30, 2012 and June 30, 2012 of $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials.

⁽³⁾The Company recognized impairments of $92.5 million during the nine months ended September 30, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput

10

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These assets are included in Property, Plant and Equipment in the Consolidated Balance Sheets. (See Note 7 for additional information on fair value).

3. LONG-TERM LIABILITIES:

	September 30, 2012		December 31, 2011
Bank indebtedness	$	600,000	$	343,000
Senior Notes		1,560,000		1,560,000
Other long-term obligations		74,174		67,008
	$	2,234,174	$	1,970,008

Bank indebtedness: The Company (through its subsidiary, Ultra Resources, Inc.) is a party to a 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 lenders’ consent, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016 (which term may be extended for up to two successive one-year periods at the Borrower’s request and with the lenders’ consent). At September 30, 2012, the Company had $600.0 million in outstanding borrowings and $400.0 million of available borrowing capacity under the Credit Facility.

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 100 basis points, 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 September 30, 2012).

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 the Company’s debt rating is below investment grade, the maintenance of an annual ratio of the net present value of the Company’s oil and gas properties to total funded debt of no less than one and one half times to one. At September 30, 2012, the Company was in compliance with all of its debt covenants under the Credit Agreement.

Senior Notes: The 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 and are subject to representations, warranties, covenants and events of default customary for a senior note financing. At September 30, 2012, the Company was in compliance with all of its debt covenants under the Master Note Purchase Agreement for Senior Notes.

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

11

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

4. SHARE BASED COMPENSATION:

Valuation and Expense Information

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Total cost of share-based payment plans	$	4,497	$	5,344	$	11,513	$	15,475
Amounts capitalized in fixed assets	$	1,448	$	1,898	$	3,683	$	5,583
Amounts charged against income, before income tax benefit	$	3,049	$	3,446	$	7,830	$	9,892
Amount of related income tax benefit recognized in income before valuation allowance	$	1,265	$	1,237	$	3,249	$	3,551

Changes in Stock Options and Stock Options Outstanding

The following table summarizes the changes in stock options for the nine months ended September 30, 2012 and the year ended December 31, 2011:

	Number of Options (000’s)			Weighted Average Exercise Price (US$)
Balance, December 31, 2010		2,230		$	3.91	to	$	98.87
Forfeited		(99	)	$	51.60	to	$	75.18
Exercised		(672	)	$	3.91	to	$	33.57
Balance, December 31, 2011		1,459		$	16.97	to	$	98.87
Forfeited		(44	)	$	25.08	to	$	75.18
Exercised		(33	)	$	16.97	to	$	25.68
Balance, September 30, 2012		1,382		$	16.97	to	$	98.87

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 2010, 2011 and 2012, 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 performance period. Under each LTIP, the Committee establishes a percentage of base salary for each participant which is multiplied by the participant’s base salary and individual performance level to derive a Long Term Incentive Value as a “target” value which corresponds to the number of shares of the Company’s common stock the participant is eligible to receive 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 LTIP awards in each of 2010, 2011 and 2012, the Committee established the following performance measures: return on equity, reserve replacement ratio, and production growth.

12

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

For the nine months ended September 30, 2012, the Company recognized $5.6 million in pre-tax compensation expense related to the 2010, 2011 and 2012 LTIP awards of restricted stock units as compared to $7.5 million during the nine months ended September 30, 2011 related to the 2009, 2010 and 2011 LTIP awards of restricted stock units. The amounts recognized during the nine months ended September 30, 2012 assume that maximum performance objectives are attained under each plan. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at September 30, 2012, for each of the three year performance periods is expected to be approximately $11.5 million, $11.6 million, and $11.9 million related to the 2010, 2011 and 2012 LTIP awards of restricted stock units, respectively. The 2009 LTIP award of restricted stock units was paid in shares of the Company’s stock to employees during the first quarter of 2012 and totaled $24.1 million (409,160 net shares).

5. INCOME TAXES:

The Company’s overall effective tax rate on pre-tax (loss) income was different than the statutory rate of 35% due primarily to valuation allowances, state income taxes and other permanent differences.

As a result of the tax effect of the ceiling test and other impairments recorded during the nine months ended September 30, 2012, the Company’s previously recorded net deferred tax liability fully reversed into a net deferred tax asset. The Company has recorded a full valuation allowance against its net deferred tax asset balance of $279.2 million as of September 30, 2012. This valuation allowance may be reversed in future periods against future taxable income.

6. 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 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. The Board approved hedging greater than 50% of the Company’s forecast 2012 production.

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 balance sheet and the associated unrealized gains and losses are recorded as current income or expense 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 cash flow statement. See Note 7 for the detail of the fair value of the following derivatives.

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Commodity Derivative Contracts: At September 30, 2012, the Company had the following open commodity derivative contracts to manage price risk on a portion of its natural gas production whereby the Company receives the fixed price and pays the variable price. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties.

Type	Commodity Reference Price	Remaining Contract Period	Volume - MMBTU/Day		Average Price/MMBTU		Fair Value - September 30, 2012
							Asset
Swap	NYMEX	Oct-Dec 2012		500,000	$	4.23	$	41,720
Swap	NYMEX	Oct 2012		90,000	$	5.00	$	5,526

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 periods ended September 30, 2012 and 2011:

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
Natural Gas Commodity Derivatives:	2012			2011		2012			2011
Realized gain on commodity derivatives(1)	$	83,433		$	53,630	$	260,239		$	143,749
Unrealized (loss) gain on commodity derivatives(1)		(93,329	)		60,536		(183,139	)		33,658
Total (loss) gain on commodity derivatives	$	(9,896	)	$	114,166	$	77,100		$	177,407

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

7. FAIR VALUE MEASUREMENTS:

As required by 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 the Company has 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 utilized to measure the fair value of the Company’s 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).

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table presents for each hierarchy level the Company’s assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis, as of September 30, 2012. The Company has no derivative instruments which qualify for cash flow hedge accounting.

	Level 1		Level 2		Level 3		Total
Assets:
Current derivative asset	$	—	$	52,716	$	—	$	52,716
Liabilities:
Current derivative liability	$	—	$	5,470	$	—	$	5,470

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.

Fair Value of Long-Lived Assets

The Company recognized impairments of $92.5 million during the nine months ended September 30, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These facilities are included in Property, Plant and Equipment in the Consolidated Balance Sheets and were impaired to a fair value of $82.6 million based on the income approach, estimated using Level 3 fair value inputs.

15

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Fair Value of Financial Instruments

The estimated fair value of financial instruments is the estimated 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 Company uses available market data and valuation methodologies to estimate the fair value of its debt. The valuation assumptions utilized to measure the fair value of the Company’s debt are considered Level 2 inputs. This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact the Company’s financial position, results of operations or cash flows.

	September 30, 2012				December 31, 2011
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-Term Debt:
5.45% Notes due 2015, issued 2008	$	100,000	$	109,190	$	100,000	$	111,475
7.31% Notes due 2016, issued 2009		62,000		73,344		62,000		74,817
4.98% Notes due 2017, issued 2010		116,000		130,133		116,000		128,570
5.92% Notes due 2018, issued 2008		200,000		235,617		200,000		231,091
7.77% Notes due 2019, issued 2009		173,000		223,101		173,000		219,552
5.50% Notes due 2020, issued 2010		207,000		237,431		207,000		229,423
4.51% Notes due 2020, issued 2010		315,000		333,430		315,000		318,925
5.60% Notes due 2022, issued 2010		87,000		97,218		87,000		94,165
4.66% Notes due 2022, issued 2010		35,000		35,540		35,000		34,631
5.85% Notes due 2025, issued 2010		90,000		101,292		90,000		99,022
4.91% Notes due 2025, issued 2010		175,000		179,071		175,000		173,835
Credit Facility		600,000		600,000		343,000		343,000
	$	2,160,000	$	2,355,367	$	1,903,000	$	2,058,506

8. LEGAL PROCEEDINGS:

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, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position or results of operations.

9. SUBSEQUENT EVENTS:

The Company has evaluated the period subsequent to September 30, 2012 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.

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ITEM 2 – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of the financial condition and operating results of the Company should be read in conjunction with the Company’s consolidated financial statements and related notes. Except as otherwise indicated, all amounts are expressed in U.S. dollars.

Overview

Ultra Petroleum Corp. is an independent exploration and production company focused on developing its long-life natural gas reserves in the Green River Basin of Wyoming—the Pinedale and Jonah fields—and is in the early exploration and development stages in the Appalachian Basin of Pennsylvania. The Company operates in one industry segment, natural gas and oil exploration and development, with one geographical segment, the United States.

The Company currently conducts operations exclusively in the United States. Substantially all of its oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect only the Company’s proportionate interest in such activities. Inflation has not had a material impact on the Company’s results of operations and is not expected to in the future. The Company continues to focus on improving its drilling and production results through gaining efficiencies with the use of advanced technologies, detailed technical analysis of its properties and leveraging its experience into improved operational efficiencies.

The Company currently generates its revenue, earnings and cash flow primarily from the production and sales of natural gas and condensate from its property in southwest Wyoming with an increasing portion of the Company’s cash flow coming from gas sales from wells located in the Appalachian Basin in Pennsylvania.

Part of the Company’s business strategy includes proactive and regular review of its portfolio of investment opportunities with a focus on investments that produce positive returns. Accordingly, in response to the current low natural gas price environment, the Company has reduced capital expenditures by reducing the number of drilling rigs operating in its Wyoming fields and is encouraging the parties operating projects on its behalf in Pennsylvania to reduce their activity this year as well. Reductions in the Company’s activity are expected to result in reduced capital spending during the current year as compared to the prior year.

The price of natural gas is a critical factor to the Company’s business and the price of natural gas has declined significantly since the beginning of 2011. The Company has limited the impact of these low prices on its results by entering into swap agreements and/or fixed price forward physical delivery contracts for natural gas. During the quarter ended September 30, 2012, the average price realization for the Company’s natural gas was $4.13 per Mcf, including realized gains and losses on commodity derivatives. The Company’s average price realization for natural gas was $2.77 per Mcf, excluding the realized gains and losses on commodity derivatives. These amounts compare with $5.17 per Mcf, including realized gains and losses on commodity derivatives, and $4.29 per Mcf, excluding such realized gains during the third quarter of 2011. (See Note 6).

Critical Accounting Policies

The discussion and analysis of the Company’s financial condition and results of operations is based upon consolidated financial statements, which have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). In addition, application of GAAP requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements as well as the revenues and expenses reported during the period. Changes in these estimates related to judgments and assumptions will occur as a result of future events, and, accordingly, actual results could differ from amounts estimated. Set forth below is a discussion of the critical accounting policies used in the preparation of the Company’s financial statements which the Company believes involve the most complex or subjective decisions or assessments.

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Derivative Instruments and Hedging Activities. Currently, the Company largely relies on derivative instruments (generally, financial swaps) to manage its exposure to commodity price risk. Additionally, and from time to time, the Company enters into fixed price forward natural gas sales in order to mitigate its commodity price exposure on a portion of its natural gas production. These fixed price forward gas sales are considered normal sales in the ordinary course of business and outside the scope of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“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.

Fair Value Measurements. The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”). Under FASB ASC 820, fair value is defined 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 measurement date and establishes a three level hierarchy for measuring fair value. The valuation assumptions utilized to measure the fair value of the Company’s 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).

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.

The fair values summarized below were determined in accordance with the requirements of FASB ASC 820 and the Company aligned the categories below with the Level 1, 2, and 3 fair value measurements as defined by FASB ASC 820. The balance of net unrealized gains and losses recognized for the Company’s energy-related derivative instruments at September 30, 2012 is summarized in the following table based on the inputs used to determine fair value:

	Level 1(a)		Level 2(b)		Level 3(c)		Total
	(Amounts in 000’s)
Assets:
Current derivative asset	$	—	$	52,716	$	—	$	52,716
Liabilities:
Current derivative liability	$	—	$	5,470	$	—	$	5,470

(a) Values represent observable unadjusted quoted prices for traded instruments in active markets.

(b) Values with inputs that are observable directly or indirectly for the instrument, but do not qualify for Level 1.

(c) Values with a significant amount of inputs that are not observable for the instrument.

Fair Value of Long-lived Assets: The Company recognized impairments of $92.5 million during the nine months ended September 30, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These facilities are included in Property, Plant and Equipment in the Consolidated Balance Sheets and were impaired to a fair value of $82.6 million based on the income approach, estimated using Level 3 fair value inputs.

Asset Retirement Obligation. The Company’s asset retirement obligations (“ARO”) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with its oil and

18

natural gas properties. FASB ASC Topic 410, Asset Retirement and Environmental Obligations (“FASB ASC 410”) requires that the discounted fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated probabilities, amounts and timing of settlements, the credit-adjusted, risk-free rate to be used, inflation rates, and future advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through depletion, depreciation and amortization (“DD&A”).

Share-Based Payment Arrangements. The Company applies FASB ASC Topic 718, Compensation—Stock Compensation (“FASB ASC 718”), which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values. Share-based compensation expense recognized for the nine months ended September 30, 2012 and 2011 was $7.8 million and $9.9 million, respectively. See Note 4 for additional information.

Write-down of oil and gas properties. The Company uses the full cost method of accounting for oil and gas 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 FASB ASC Topic 932, Extractive Activities—Oil and Gas (“FASB ASC 932”). Under the full cost method of accounting, all costs associated with the exploration for and development of oil and gas reserves are capitalized on a country-by-country basis. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells and overhead charges directly related to acquisition, exploration and development activities. Substantially all of the oil and gas activities are conducted jointly with others and, accordingly, the amounts reflect only the Company’s proportionate interest in such activities.

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 DD&A rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.

The Company recorded a $2.4 billion non-cash write-down of the carrying value of its proved oil and natural gas properties for the nine months ended September 30, 2012 as a result of ceiling test limitations, which is reflected with 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 September 30, 2012 and June 30, 2012 of $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials.

The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of

19

available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Capitalized Interest. Interest is capitalized on the cost of unevaluated gas and oil 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 (See Note 2).

Entitlements Method of Accounting for Oil and Natural Gas Sales. The Company generally sells natural gas and condensate 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. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue.

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.

Valuation of Deferred Tax Assets. The Company uses the asset and liability method of accounting for income taxes. Under this method, future income tax assets and liabilities are determined based on differences between the financial statement carrying values and their respective income tax basis (temporary differences).

To assess the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.

As a result of the tax effect of the ceiling test and other impairments recorded during the nine months ended September 30, 2012, the Company’s previously recorded net deferred tax liability fully reversed into a net deferred tax asset. The Company has recorded a full valuation allowance against its net deferred tax asset balance of $279.2 million as of September 30, 2012. This valuation allowance may be reversed in future periods against future taxable income.

Conversion of barrels of oil to Mcfe of gas. The Company converts Bbls of oil and other liquid hydrocarbons to Mcfe at a ratio of one Bbl of oil or liquids to six Mcfe. This conversion ratio, which is typically used in the oil and gas industry, represents the approximate energy equivalent of a barrel of oil or other liquids to an Mcf of natural gas. The sales price of one Bbl of oil or liquids has been much higher than the sales price of six Mcf of natural gas over the last several years, so a six to one conversion ratio does not represent the economic equivalency of six Mcf of natural gas to a Bbl of oil or other liquids.

Recent accounting pronouncements. In May 2011, the FASB issued ASU No. 2011-04, which amends FASB ASC 820. The amended guidance clarifies many requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB’s

20

intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not have a material impact on the Company’s consolidated financial statements.

RESULTS OF OPERATIONS

Quarter Ended September 30, 2012 vs. Quarter Ended September 30, 2011

During the quarter ended September 30, 2012, production remained relatively flat on a gas equivalent basis at 63.1 Bcfe compared to 63.4 Bcfe for the same quarter in 2011 as a result of decreased capital spending in response to decreased natural gas prices during the quarter. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 20% to $4.13 per Mcf in the third quarter of 2012 as compared to $5.17 per Mcf for the same quarter of 2011. During the three months ended September 30, 2012, the Company’s average price for natural gas was $2.77 per Mcf, excluding realized gains and losses on commodity derivatives as compared to $4.29 per Mcf for the same period in 2011. The decrease in average natural gas prices resulted in a 33% decrease in revenues to $196.4 million in the quarter ended September 30, 2012 as compared to $293.1 million in for the same period in 2011.

Lease operating expense (“LOE”) increased to $16.7 million during the third quarter of 2012 compared to $12.4 million during the same period in 2011 primarily due to increased well counts resulting from the Company’s drilling program. On a unit of production basis, LOE costs increased to $0.27 per Mcfe during the third quarter of 2012 compared to $0.20 per Mcfe during the same period in 2011 as a result of higher lease operating expense on non-operated wells in Pennsylvania while production remained relatively flat.

During the three months ended September 30, 2012, production taxes were $15.0 million compared to $25.7 million during the same period in 2011, or $0.24 per Mcfe compared to $0.40 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming after certain deductions and were 7.7% of revenues for the quarter ended September 30, 2012 and 8.8% of revenues for the same period in 2011. In addition, the quarter ended September 30, 2012 includes charges related to Pennsylvania impact fees totaling $1.5 million while the period ended September 30, 2011 did not include any charges related to impact fees in Pennsylvania. The decrease in per unit taxes is primarily attributable to decreased sales revenues as a result of decreased natural gas prices, excluding the effects of commodity derivatives, during the quarter ended September 30, 2012 as compared to the same period in 2011, as well as increased production in Pennsylvania in areas where the Company does not incur third party transportation charges.

Gathering fees decreased to $10.3 million for the three months ended September 30, 2012 compared to $14.4 million during the same period in 2011 largely due to the Company’s participation in the Anadarko gathering system as well as a higher percentage of production in Pennsylvania in areas where the Company does not incur third party transportation charges. On a per unit basis, gathering fees decreased to $0.16 per Mcfe for the three months ended September 30, 2012 as compared to $0.23 per Mcfe during the same period in 2011.

The Company incurred firm transportation charges totaling $21.1 million for the quarter ended September 30, 2012 as compared to $16.1 million for the same period in 2011 in association with Rockies Express Pipeline (‘REX”) transportation charges. On a per unit basis, transportation charges increased to $0.33 per Mcfe (on total company volumes) for the three months ended September 30, 2012 as compared to $0.25 per Mcfe (on total company volumes) for the same period in 2011 primarily due to demand charges associated with the additional capacity of 50 MMMBtu per day secured on the REX pipeline system beginning in January 2012.

DD&A expenses increased slightly to $86.6 million during the three months ended September 30, 2012 from $85.8 million for the same period in 2011, attributable primarily to a slightly higher depletion rate. On a unit of production basis, DD&A increased to $1.37 per Mcfe for the quarter ended September 30, 2012 from $1.35 per Mcfe for the quarter ended September 30, 2011.

21

The Company recorded a $606.8 million non-cash write-down of the carrying value of its proved oil and natural gas properties for the quarter ended September 30, 2012 as a result of ceiling test limitations, which is reflected with 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 September 30, 2012 of $2.83 per MMBtu for Henry Hub natural gas and $94.97 per barrel for West Texas Intermediate oil, adjusted for market differentials. The write-down reduced earnings in the third quarter of 2012 and will result in a lower DD&A rate in future periods. The Company did not have any write-downs related to the full cost ceiling limitation during the quarter ended September 30, 2011. See Note 1(d).

General and administrative expenses increased slightly to $6.7 million for the quarter ended September 30, 2012 compared to $6.2 million for the same period in 2011. The increase in general and administrative expenses is largely attributable to increased headcount and related compensation. On a per unit basis, general and administrative expenses were $0.11 per Mcfe for the quarter ended September 30, 2012 compared to $0.10 per Mcfe for the quarter ended September 30, 2011.

Interest expense increased to $25.4 million during the quarter ended September 30, 2012 compared to $15.9 million during the same period in 2011 as a result of increased borrowings outstanding during the period ended September 30, 2012 as well as lower amounts of capitalized interest related to unevaluated oil and gas properties that are excluded from amortization. At September 30, 2012, the Company had $2.2 billion in borrowings outstanding. In addition, the Company capitalized $0.8 million and $7.4 million in interest expense for the quarters ended September 30, 2012 and 2011, respectively, related to unevaluated oil and gas properties and on work in process relating to gathering systems (See Note 2).

During the quarter ended September 30, 2012, the Company recognized $83.4 million of realized gain on commodity derivatives as compared to $53.6 million of realized gain on commodity derivatives during the quarter ended September 30, 2011. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts.

During the quarter ended September 30, 2012, the Company recorded $93.3 million in unrealized loss on commodity derivatives as compared to $60.5 million in unrealized gain on commodity derivatives during the quarter ended September 30, 2011. The unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

The Company recognized a net loss before income taxes of $602.0 million for the quarter ended September 30, 2012 compared with income before income taxes of $230.9 million for the same period in 2011. The decrease in earnings is primarily related to the non-cash ceiling test impairments together with decreased average natural gas prices during the three months ended September 30, 2012 as compared to the same period in 2011.

As a result of the tax effect of the non-cash ceiling test and other impairments, the Company’s previously recorded net deferred tax liability fully reversed into a net deferred tax asset during the quarter ended June 30, 2012. The Company has recorded a full valuation allowance against its net deferred tax asset balance of $279.2 million as of September 30, 2012. This valuation allowance may be reversed in future periods against future taxable income. The income tax provision recognized for the quarter ended September 30, 2012 was $0.2 million, after adjustment for valuation allowance of $241.3 million, compared with an income tax provision of $81.7 million for the three months ended September 30, 2011.

For the three months ended September 30, 2012, the Company recognized a net loss of $602.1 million or ($3.94) per diluted share as compared with net income of $149.1 million or $0.97 per diluted share for the same period in 2011. The decrease is primarily related to the non-cash ceiling test impairments together with decreased average natural gas prices and the valuation allowance during the three months ended September 30, 2012 as compared to the same period in 2011.

22

Nine Months Ended September 30, 2012 vs. Nine Months Ended September 30, 2011

During the nine months ended September 30, 2012, production increased 10% on a gas equivalent basis to 196.9 Bcfe from 178.4 Bcfe for the same period in 2011. This increase in production was attributable to the Company’s successful drilling activities during 2011 and in the first nine months of 2012. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 23% to $3.99 per Mcf in the nine months ended September 30, 2012 as compared to $5.15 per Mcf for the same period in 2011. During the nine months ended September 30, 2012, the Company’s average price for natural gas was $2.63 per Mcf, excluding realized gains and losses on commodity derivatives as compared to $4.32 per Mcf for the same period in 2011. The decrease in average natural gas prices, offset in part by the increase in production, resulted in a 29% decrease in revenues to $592.8 million as compared to $831.0 million in 2011.

LOE increased to $46.0 million during the nine months ended September 30, 2012 compared to $35.9 million during the same period in 2011 primarily due to increased well counts resulting from the Company’s drilling program. On a unit of production basis, LOE costs increased to $0.23 per Mcfe at September 30, 2012 compared to $0.20 per Mcfe at September 30, 2011 as a result of higher compression and water disposal costs for Pennsylvania wells and workover expenses in Wyoming.

During the nine months ended September 30, 2012, production taxes were $46.6 million compared to $73.8 million during the same period in 2011, or $0.24 per Mcfe compared to $0.41 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming after certain deductions and were 7.9% of revenues for the nine months ended September 30, 2012 and 8.9% of revenues for the same period in 2011. In addition, the period ended September 30, 2012 includes charges related to Pennsylvania impact fees totaling $4.1 million while the period ended September 30, 2011 did not include any charges related to impact fees in Pennsylvania. The decrease in per unit taxes is primarily attributable to decreased sales revenues as a result of decreased natural gas prices, excluding the effects of commodity derivatives, during the nine months ended September 30, 2012 as compared to the same period in 2011 as well as increased production in Pennsylvania in areas where the Company does not incur third party transportation charges.

Gathering fees increased to $46.6 million for the nine months ended September 30, 2012 compared to $41.4 million during the same period in 2011 largely due to increased production volumes. On a per unit basis, gathering fees increased to $0.24 per Mcfe for the nine months ended September 30, 2012 as compared to $0.23 per Mcfe during the same period in 2011 as a result of higher gathering fees for certain outside operated wells in Pennsylvania.

The Company incurred firm transportation charges totaling $63.5 million for the nine months ended September 30, 2012 as compared to $48.5 million for the same period in 2011 in association with REX pipeline charges. On a per unit basis, transportation charges increased to $0.32 per Mcfe (on total company volumes) for the nine months ended September 30, 2012 as compared to $0.27 per Mcfe (on total company volumes) for the same period in 2011 primarily due to demand charges associated with the additional capacity of 50 MMMBtu per day secured on the REX pipeline system beginning in January 2012.

DD&A expenses increased to $314.1 million during the nine months ended September 30, 2012 from $238.8 million for the same period in 2011, attributable primarily to increased production volumes and a higher depletion rate. On a unit of production basis, DD&A increased to $1.60 per Mcfe for the nine months ended September 30, 2012 from $1.34 per Mcfe for the nine months ended September 30, 2011 primarily as a result of increased costs in Pennsylvania.

The Company recorded a $2.4 billion non-cash write-down of the carrying value of its proved oil and natural gas properties for the nine months ended September 30, 2012 as a result of ceiling test limitations, which is reflected as 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 September 30, 2012 and June 30, 2012 of $2.83 per MMBtu and

23

$3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials. The write-down reduced earnings in the period and will result in a lower DD&A rate in future periods. The Company did not have any write-downs related to the full cost ceiling limitation during the nine months ended September 30, 2011. See Note 1(d). In addition, the Company recognized impairments of $92.5 million during the nine months ended September 30, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These assets are included in Property, Plant and Equipment in the Consolidated Balance Sheets. (See Note 7 for additional information on fair value).

General and administrative expenses remained flat at $19.3 million for the nine months ended September 30, 2012 and 2011. On a per unit basis, general and administrative expenses were $0.10 per Mcfe for the nine months ended September 30, 2012 compared to $0.11 per Mcfe for the period ended September 30, 2011.

Interest expense increased to $62.4 million during the nine months ended September 30, 2012 compared to $46.1 million during the same period in 2011 as a result of increased borrowings outstanding during the period ended September 30, 2012 along with lower amounts of capitalized interest related to unevaluated oil and gas properties that are excluded from amortization. At September 30, 2012, the Company had $2.2 billion in borrowings outstanding. In addition, the Company capitalized $14.8 million and $22.9 million in interest expense for the nine months ended September 30, 2012 and 2011, respectively, related to unevaluated oil and gas properties and on work in process relating to gathering systems (See Note 2).

During the nine months ended September 30, 2012, the Company recognized $9.2 million in rig cancellation fees. In response to low natural gas prices, the Company has reduced its drilling rig count to two operated rigs, down from six at December 31, 2011.

During the nine months ended September 30, 2012, the Company recognized $260.2 million of realized gain on commodity derivatives as compared to $143.7 million of realized gain on commodity derivatives during the nine months ended September 30, 2011. The realized gain on commodity derivatives relates to actual amounts received or paid under these derivative contracts.

During the nine months ended September 30, 2012, the Company recorded $183.1 million in unrealized loss on commodity derivatives as compared to $33.7 million in unrealized gain on commodity derivatives during the nine months ended September 30, 2011. The unrealized (loss) gain on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

The Company recognized a loss before income taxes of $2.4 billion for the nine months ended September 30, 2012 compared with income before income taxes of $504.8 million for the same period in 2011. The decrease in earnings is primarily related to the non-cash ceiling test and other impairments and decreased natural gas prices partially offset by increased production during the nine months ended September 30, 2012.

As a result of the tax effect of the non-cash ceiling test and other impairments, the Company’s previously recorded net deferred tax liability fully reversed into a net deferred tax asset during the quarter ended June 30, 2012. The Company has recorded a full valuation allowance against its net deferred tax asset balance of $279.2 million as of September 30, 2012. This valuation allowance may be reversed in future periods against future taxable income. The income tax benefit recognized for the period ended September 30, 2012 was $709.0 million, after adjustment for valuation allowance of $275.3 million, compared with an income tax provision of $183.4 million for the nine months ended September 30, 2011.

For the nine months ended September 30, 2012, the Company recognized a net loss of $1.7 billion or ($11.16) per diluted share as compared with net income of $321.4 million or $2.08 per diluted share for the same

24

period in 2011. The decrease is primarily related to the non-cash ceiling test and other impairments, valuation allowance and decreased natural gas prices partially offset by increased production during the nine months ended September 30, 2012.

LIQUIDITY AND CAPITAL RESOURCES

During the nine month period ended September 30, 2012, the Company relied on cash provided by operations along with borrowings under the Credit Agreement (defined below) to finance its capital expenditures. During this period, the Company participated in 174 gross (71.4 net) wells that were drilled to total depth and cased. For the nine month period ended September 30, 2012, total capital expenditures were $704.8 million ($588.8 million related to oil and gas exploration and development expenditures and $116.0 million related to gathering system expenditures).

At September 30, 2012, the Company reported a cash position of $59.2 million compared to $12.3 million at September 30, 2011. Working capital deficit at September 30, 2012 was $266.6 million compared to working capital deficit of $454.0 million at September 30, 2011. At September 30, 2012, the Company had $600.0 million in outstanding borrowings and $400.0 million of available borrowing capacity under the Credit Agreement (defined below). In addition, the Company had $1.56 billion outstanding under its Senior Notes (See Note 3). Other long-term obligations of $74.2 million at September 30, 2012 was comprised of items payable in more than one year, primarily related to production taxes and asset retirement obligations.

The Company’s available cash, credit facility (see Note 3) and cash generated from operations, are projected to be sufficient to meet the Company’s obligations and to fund the budgeted capital investment program for 2012, which is currently projected to be approximately $825.0 million.

Bank indebtedness: The Company (through its subsidiary, Ultra Resources, Inc.) is a party to a 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 lenders’ consent, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016 (which term may be extended for up to two successive one-year periods at the Borrower’s request and with the lenders’ consent). At September 30, 2012, the Company had $600.0 million in outstanding borrowings and $400.0 million of available borrowing capacity under the Credit Facility.

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 100 basis points, 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 September 30, 2012).

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 the Company’s debt rating is below investment grade, the maintenance of an annual ratio of the net present value of the Company’s oil and gas properties to total funded debt of no less than one and one half times to one. At September 30, 2012, the Company was in compliance with all of its debt covenants under the Credit Agreement.

Senior Notes: The 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 and are subject to representations, warranties, covenants and events of default customary for a senior note financing. At September 30, 2012, the Company was in compliance with all of its debt covenants under the Master Note Purchase Agreement for Senior Notes. (See Note 3).

25

Operating Activities. During the nine months ended September 30, 2012, net cash provided by operating activities was $480.1 million, a 33% decrease from $719.8 million for the same period in 2011. The decrease in net cash provided by operating activities is largely attributable to decreased revenues resulting from decreased realized natural gas prices during the nine months ended September 30, 2012 as compared to the same period in 2011.

Investing Activities. During the nine months ended September 30, 2012, net cash used in investing activities was $679.6 million as compared to $1.0 billion for the same period in 2011. The decrease in net cash used in investing activities is largely related to decreased capital investments associated with the Company’s drilling activities in 2012 as compared to 2011.

Financing Activities. During the nine months ended September 30, 2012, net cash provided by financing activities was $247.4 million as compared to $265.5 million for the same period in 2011. The decrease in net cash provided by financing activities is primarily due to decreased borrowings in 2012 as compared to 2011.

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of September 30, 2012.

CAUTIONARY STATEMENT PURSUANT TO SAFE HARBOR PROVISION OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report contains or incorporates by reference forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical facts included in this document, including without limitation, statements in Management’s Discussion and Analysis of Financial Condition and Results of Operations regarding the Company’s financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of the Company’s management for future operations, covenant compliance and those statements preceded by, followed by or that otherwise include the words “believe”, “expects”, “anticipates”, “intends”, “estimates”, “projects”, “target”, “goal”, “plans”, “objective”, “should”, or similar expressions or variations on such expressions are forward-looking statements. The Company can give no assurances that the assumptions upon which such forward-looking statements are based will prove to be correct nor can the Company assure adequate funding will be available to execute the Company’s planned future capital program.

Other risks and uncertainties include, but are not limited to, fluctuations in the price the Company receives for oil and gas production, reductions in the quantity of oil and gas sold due to increased industry-wide demand and/or curtailments in production from specific properties due to mechanical, marketing or other problems, operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated and increased financing costs due to a significant increase in interest rates. See the Company’s annual report on Form 10-K for the year ended December 31, 2011 for additional risks related to the Company’s business.

ITEM 3 – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 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.

26

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.

From time to time, the Company may use fixed price forward gas sales to manage its commodity price exposure. These fixed price forward gas sales are considered normal sales in the ordinary course of business and outside the scope of FASB ASC 815, Derivatives and Hedging.

The Company’s hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production without Board approval. The Board approved hedging greater than 50% of the Company’s forecast 2012 production.

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 balance sheet 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 does not impact operating cash flows on the cash flow statement. See Note 7 for the detail of the fair value of the following derivatives.

Commodity Derivative Contracts: At September 30, 2012, the Company had the following open commodity derivative contracts to manage price risk on a portion of its natural gas production whereby the Company receives the fixed price and pays the variable price. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties.

Type	Commodity Reference Price	Remaining Contract Period	Volume - MMBTU/Day	Average Price/MMBTU	Fair Value - September 30, 2012
					Asset
					(Amounts in 000’s)
Swap	NYMEX	Oct-Dec 2012	500,000	$4.23	$41,720
Swap	NYMEX	Oct 2012	90,000	$5.00	$5,526

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 periods ended September 30, 2012 and 2011:

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
Natural Gas Commodity Derivatives:	2012			2011		2012			2011
	(Amounts in 000’s)
Realized gain on commodity derivatives(1)	$	83,433		$	53,630	$	260,239		$	143,749
Unrealized (loss) gain on commodity derivatives(1)		(93,329	)		60,536		(183,139	)		33,658
Total (loss) gain on commodity derivatives	$	(9,896	)	$	114,166	$	77,100		$	177,407

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

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ITEM 4 – CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

The Company has performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”). The Company’s disclosure controls and procedures are the controls and other procedures that it has designed to ensure that it records, processes, accumulates and communicates information to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submissions within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2012. There were no changes in the Company’s internal control over financial reporting during the nine months ended September 30, 2012 that have materially affected or are reasonably likely to affect, the Company’s internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position, or results of operations.

ITEM 1A. RISK FACTORS

There have been no material changes with respect to the risk factors disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Period	Total Number of Shares Purchased (000’s)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (000’s)		Maximum Number (or Approximate Dollar Value) that may yet be Purchased Under the Plans or Programs
July 2012		—		—		—	$	385.7 million
August 2012		10	$	22.09		10	$	385.5 million
September 2012		—		—		—	$	385.5 million

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

(a) Exhibits

3.1	Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
3.2	By-Laws of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
3.3	Articles of Amendment to Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.3 of the Company’s Report on Form 10-K/A for the period ended December 31, 2005.)
4.1	Specimen Common Share Certificate — (incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Calculation Linkbase Document.
101.LAB*	XBRL Label Linkbase Document.
101.PRE*	XBRL Presentation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition.

* Filed herewith.

29

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

ULTRA PETROLEUM CORP.
By:	/s/  Michael D. Watford
	Name:	Michael D. Watford
	Title:	Chairman, President and Chief Executive Officer

Date: November 1, 2012

By:	/s/  Marshall D. Smith
	Name:	Marshall D. Smith
	Title:	Senior Vice President and Chief Financial Officer

Date: November 1, 2012

30

EXHIBIT INDEX

3.1	Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
3.2	By-Laws of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
3.3	Articles of Amendment to Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.3 of the Company’s Report on Form 10-K/A for the period ended December 31, 2005.)
4.1	Specimen Common Share Certificate — (incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Calculation Linkbase Document.
101.LAB*	XBRL Label Linkbase Document.
101.PRE*	XBRL Presentation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition.

* Filed herewith.

31

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Michael D. Watford, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Ultra Petroleum Corp.;

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

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

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

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

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

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

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

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

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

/s/    Michael D. Watford        

Michael D. Watford,

Chairman, President and Chief Executive Officer (Principal Executive Officer)

Date: November 1, 2012

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Marshall D. Smith, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Ultra Petroleum Corp.;

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

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

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

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

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

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

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

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

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

/s/    Marshall D. Smith        

Marshall D. Smith,

Senior Vice President and Chief Financial Officer (Principal Financial Officer)

Date: November 1, 2012

EX-32.1

EXHIBIT 32.1

SECTION 906 CERTIFICATION PURSUANT OF PRINCIPAL EXECUTIVE OFFICER

ULTRA PETROLEUM CORP.

In connection with the Quarterly Report of Ultra Petroleum Corp. (the “Company”) on Form 10-Q for the fiscal quarter ended September 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael D. Watford, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

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

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

/s/  Michael D. Watford       

Michael D. Watford,

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

Dated: November 1, 2012

This certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, will not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. This certification will not be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference.

EX-32.2

Exhibit 32.2

SECTION 906 CERTIFICATION PURSUANT OF PRINCIPAL FINANCIAL OFFICER

ULTRA PETROLEUM CORP.

In connection with the Quarterly Report of Ultra Petroleum Corp. (the “Company”) on Form 10-Q for the fiscal quarter ended September 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Marshall D. Smith, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

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

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

/s/  Marshall D. Smith       

Marshall D. Smith,

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

Dated: November 1, 2012

This certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, will not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. This certification will not be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference.

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Long Term Liabilities (Details) (USD $)	9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011
Long Term Obligations [Abstract]
Notes Payable to Bank	$ 600,000,000	$ 343,000,000
Other Notes Payable	1,560,000,000	1,560,000,000
Other Liabilities, Noncurrent	74,174,000	67,008,000
Total Long Term Liabilities	2,234,174,000	1,970,008,000
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 Available Credit Facility	250,000,000
Debt Instrument Interest Rate Terms Prime	1.00%
Debt Instrument Interest Rate Terms Libor	2.00%
Notes Payable to Bank	600,000,000	343,000,000
Debt Instrument, Unused Borrowing Capacity, Amount	$ 400,000,000

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Long Term Liabilities

9 Months Ended

Sep. 30, 2012

Long Term Liabilities [Abstract]

Long-term Debt [Text Block]

3. LONG-TERM LIABILITIES:
			September 30,		December 31,
			2012		2011
	Bank indebtedness	$	600,000	$	343,000
	Senior Notes		1,560,000		1,560,000
	Other long-term obligations		74,174		67,008
		$	2,234,174	$	1,970,008

Bank indebtedness:The Company (through its subsidiary, Ultra Resources, Inc.) is a party to a 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 lenders' consent, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016 (which term may be extended for up to two successive one-year periods at the Borrower's request and with the lenders' consent). At September 30, 2012, the Company had $600.0 million in outstanding borrowings and $400.0million of available borrowing capacity under the Credit Facility.

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 100 basis points, 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 September 30, 2012).

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 the Company's debt rating is below investment grade, the maintenance of an annual ratio of the net present value of the Company's oil and gas properties to total funded debt of no less than one and one half times to one. At September 30, 2012, the Company was in compliance with all of its debt covenants under the Credit Agreement.

Senior Notes:   The Senior Notes rank paripassu 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 and are subject to representations, warranties, covenants and events of default customary for a senior note financing. At September 30, 2012, the Company was in compliance with all of its debt covenants under the Master Note Purchase Agreement for Senior Notes.

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

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Derivative Financial Instruments (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Natural Gas Commodity Derivatives [Abstract]
Realized (loss) gain on commodity derivatives	$ 83,433	$ 53,630	$ 260,239	$ 143,749
Unrealized Gain (Loss) on Derivatives	(93,329)	60,536	(183,139)	33,658
Gain loss on commodity derivatives	(9,896)	114,166	77,100	177,407
Swap [Member] | Nymex Henry Hub [Member] | Calendar 2012 [Member]
Schedule Of Derivative Instruments [Line Items]
Derivative, Underlying Basis			500,000
Derivative, Swap Type, Average Fixed Price	4.23		4.23
Derivative Asset, Fair Value	41,720		41,720
Swap [Member] | Nymex Henry Hub [Member] | Summer 2012 [Member]
Schedule Of Derivative Instruments [Line Items]
Derivative, Underlying Basis			90,000
Derivative, Swap Type, Average Fixed Price	5.00		5.00
Derivative Asset, Fair Value	$ 5,526		$ 5,526

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Statement Income Taxes Details [Abstract]
Statutory tax rate	35.00%
Deferred Tax Assets, Valuation Allowance	$ 279.2

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Fair Value Measurments (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Derivative Assets [Abstract]
Derivative Assets, Current	$ 52,716	$ 230,385
Derivative Liabilities [Abstract]
Derivative Liabilities, Current	5,470	0
Fair Value, Inputs, Level 2 [Member]
Derivative Assets [Abstract]
Derivative Assets, Current	52,716
Derivative Assets, Noncurrent	0
Derivative Liabilities [Abstract]
Derivative Liabilities, Current	5,470
Derivative Liabilities, Noncurrent	$ 0

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Fair Value Measurments - Narrative (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Fair Value Measurments Details [Abstract]
Other Asset Impairment Charges	$ 92.5
Estimated Fair Value Gathering Assets	$ 82.6

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Oil and Gas Properties and Equipment

9 Months Ended

Sep. 30, 2012

Oil And Gas Properties And Equipment [Abstract]

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

2. OIL AND GAS PROPERTIES AND EQUIPMENT:
		September 30,		December 31,
		2012		2011
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$	7,106,729	$	5,974,604
Less: Accumulated depletion, depreciation and amortization(2)		(5,010,906)		(2,322,982)
		2,095,823		3,651,622
Unproven Properties:
Acquisition and exploration costs not being amortized(1)		-		537,526
Net capitalized costs - oil and gas properties	$	2,095,823	$	4,189,148
Property, Plant and Equipment:
Gathering Systems(1)	$	346,520	$	226,747
Less: Accumulated depreciation(3)		(104,425)		(7,736)
		242,095		219,011
Other Property and Equipment		14,697		11,333
Less: Accumulated depreciation		(7,851)		(5,908)
		6,846		5,425
Land		22,343		22,150
Net capitalized costs - property, plant and equipment	$	271,284	$	246,586

(1)For the nine months ended September 30, 2012 and 2011,total interest on outstanding debt was $77.2 million and $69.0 million, respectively, of which, $14.8 million and $22.9 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and on work in process relating to gathering systems.

(2)The Company recorded a $2.4billion non-cash write-down of the carrying value of its proved oil and natural gas properties for the nine months ended September 30, 2012 as a result of ceiling test limitations, which is reflected withceiling 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 periodat September 30, 2012 and June 30, 2012 of $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials.

(3)The Company recognized impairments of $92.5 million during the nine months ended September 30, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania dueto the decline in commodity prices. These assets are included in Property, Plant and Equipment in the Consolidated Balance Sheets. (See Note 7 for additional information on fair value).

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Fair Value Measurments - Debt Instruments (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Excluding Current Maturities	$ 2,160,000	$ 1,903,000
Notes Due 2015 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Excluding Current Maturities	100,000	100,000
Notes Payable, Fair Value Disclosure	109,190	111,475
Private Debt Placement Instruments Interest Rates	5.45%
Notes Due 2018 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Excluding Current Maturities	200,000	200,000
Notes Payable, Fair Value Disclosure	235,617	231,091
Private Debt Placement Instruments Interest Rates	5.92%
Notes Due 2016 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Excluding Current Maturities	62,000	62,000
Notes Payable, Fair Value Disclosure	73,344	74,817
Private Debt Placement Instruments Interest Rates	7.31%
Notes Due 2019 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Excluding Current Maturities	173,000	173,000
Notes Payable, Fair Value Disclosure	223,101	219,552
Private Debt Placement Instruments Interest Rates	7.77%
Notes Due 2017 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Excluding Current Maturities	116,000	116,000
Notes Payable, Fair Value Disclosure	130,133	128,570
Private Debt Placement Instruments Interest Rates	4.98%
Notes Due January 2020 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Excluding Current Maturities	207,000	207,000
Notes Payable, Fair Value Disclosure	237,431	229,423
Private Debt Placement Instruments Interest Rates	5.50%
Notes Due January 2022 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Excluding Current Maturities	87,000	87,000
Notes Payable, Fair Value Disclosure	97,218	94,165
Private Debt Placement Instruments Interest Rates	5.60%
Notes Due January 2025 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Excluding Current Maturities	90,000	90,000
Notes Payable, Fair Value Disclosure	101,292	99,022
Private Debt Placement Instruments Interest Rates	5.85%
Notes Due October 2020 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Excluding Current Maturities	315,000	315,000
Notes Payable, Fair Value Disclosure	333,430	318,925
Private Debt Placement Instruments Interest Rates	4.51%
Notes Due October 2022 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Excluding Current Maturities	35,000	35,000
Notes Payable, Fair Value Disclosure	35,540	34,631
Private Debt Placement Instruments Interest Rates	4.66%
Notes Due October 2025 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Excluding Current Maturities	175,000	175,000
Notes Payable, Fair Value Disclosure	179,071	173,835
Private Debt Placement Instruments Interest Rates	4.91%
Credit Facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Excluding Current Maturities	600,000	343,000
Notes Payable, Fair Value Disclosure	$ 600,000	$ 343,000

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Consolidated Statement of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Revenues [Abstract]
Natural gas sales	$ 169,594	$ 262,147	$ 501,470	$ 743,898
Oil sales	26,781	30,994	91,319	87,101
Oil and Gas Revenue	196,375	293,141	592,789	830,999
Operating Expenses [Abstract]
Lease operating expenses	16,741	12,381	45,982	35,853
Production taxes	15,047	25,676	46,634	73,796
Gathering fees	10,274	14,445	46,591	41,363
Transportation charges	21,055	16,061	63,477	48,492
Depletion, depreciation and amoritzation	86,645	85,795	314,115	238,773
Ceiling test and other impairments	606,827	0	2,475,963	0
General and administrative	6,741	6,185	19,308	19,298
Costs and Expenses	763,330	160,543	3,012,070	457,575
Operating Income (Loss)	(566,955)	132,598	(2,419,281)	373,424
Other Nonoperating Income (Expense) [Abstract]
Interest Expense, Debt	(25,369)	(15,902)	(62,414)	(46,082)
Gain (loss) on commodity derivatives	(9,896)	114,166	77,100	177,407
Rig Cancellation Fees	291	0	(9,220)	0
Other income (expense) net	(42)	(3)	(27)	14
Other Nonoperating Income (Expense)	(35,016)	98,261	5,439	131,339
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Cumulative Effects of Changes in Accounting Principles, Noncontrolling Interest	(601,971)	230,859	(2,413,842)	504,763
Income Tax Expense (Benefit)	175	81,713	(708,977)	183,392
Net Income (Loss)	$ (602,146)	$ 149,146	$ (1,704,865)	$ 321,371
Earnings Per Share, Basic [Abstract]
Earnings Per Share, Basic	$ (3.94)	$ 0.98	$ (11.16)	$ 2.10
Fully Diluted Earnings per Share:
Earnings Per Share, Diluted	$ (3.94)	$ 0.97	$ (11.16)	$ 2.08
Weighted Average Number of Shares Outstanding, Basic	152,929	152,817	152,817	152,772
Weighted Average Number of Shares Outstanding, Diluted	152,929	154,280	152,817	154,418

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Description of the Business

9 Months Ended

Sep. 30, 2012

Description Of Business [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

DESCRIPTION OF THE BUSINESS:

Ultra Petroleum Corp. (the “Company”) is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. The Company is incorporated under the laws of the Yukon Territory, Canada. The Company's principal business activities are conducted in the Green River Basin of Southwest Wyoming and in the north-central Pennsylvania area of the Appalachian Basin.

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2012

Fair Value Measurements Tables [Abstract]

Fair Value By Balance Sheet Grouping [Text Block]

		Level 1		Level 2		Level 3		Total
Assets:
Current derivative asset	$	-	$	52,716	$	-	$	52,716
Liabilities:
Current derivative liability	$	-	$	5,470	$	-	$	5,470

Schedule of Fair Value of Financial Instruments

		September 30, 2012				December 31, 2011
		Carrying		Estimated		Carrying		Estimated
		Amount		Fair Value		Amount		Fair Value
Long-Term Debt:
5.45% Notes due 2015, issued 2008	$	100,000	$	109,190	$	100,000	$	111,475
7.31% Notes due 2016, issued 2009		62,000		73,344		62,000		74,817
4.98% Notes due 2017, issued 2010		116,000		130,133		116,000		128,570
5.92% Notes due 2018, issued 2008		200,000		235,617		200,000		231,091
7.77% Notes due 2019, issued 2009		173,000		223,101		173,000		219,552
5.50% Notes due 2020, issued 2010		207,000		237,431		207,000		229,423
4.51% Notes due 2020, issued 2010		315,000		333,430		315,000		318,925
5.60% Notes due 2022, issued 2010		87,000		97,218		87,000		94,165
4.66% Notes due 2022, issued 2010		35,000		35,540		35,000		34,631
5.85% Notes due 2025, issued 2010		90,000		101,292		90,000		99,022
4.91% Notes due 2025, issued 2010		175,000		179,071		175,000		173,835
Credit Facility		600,000		600,000		343,000		343,000
	$	2,160,000	$	2,355,367	$	1,903,000	$	2,058,506

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Oil and Gas Properties and Equipment (Details) (USD $)	6 Months Ended	9 Months Ended		12 Months Ended
	Jun. 30, 2012	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Proven Properties [Abstract]
Capitalized Costs, Proved Properties		$ 7,106,729,000		$ 5,974,604,000
Capitalized Costs, Accumulated Depreciation, Depletion, Amortization and Valuation Allowance for Relating to Oil and Gas Producing Activities		(5,010,906,000)		(2,322,982,000)
Proved		2,095,823,000		3,651,622,000
Capitalized Costs of Unproved Properties Excluded from Amortization [Abstract]
Oil Gas Properties Using Full Cost Method Accounting Unproved		0		537,526,000
Capitalized Costs, Oil and Gas Producing Activities, Net		2,095,823,000		4,189,148,000
Interest Expense, Borrowings		77,200,000	69,000,000
Interest Costs, Capitalized During Period		14,800,000	22,900,000
Ceiling Test Limitation Pretax Oil and Gas Properties		2,400,000,000
Natural Gas Market Price Full Cost Ceiling Test	$ 3.15	$ 2.83
Crude Oil Market Price Full Cost Ceiling Test	$ 95.67	$ 94.97
Property, Plant and Equipment [Abstract]
Gathering Systems		346,520,000		226,747,000
Accumulated Depreciation Gathering Systems		(104,425,000)		(7,736,000)
Net Gathering Systems		242,095,000		219,011,000
Other Property And Equipment		14,697,000		11,333,000
Accumulated Depreciation Other Property And Equipment		(7,851,000)		(5,908,000)
Net Other Property And Equipment		6,846,000		5,425,000
Land		22,343,000		22,150,000
Net Capitalized Costs Property Plant And Equipment		271,284,000		246,586,000
Other Asset Impairment Charges		$ 92,500,000

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Significant Accounting Policies

9 Months Ended

Sep. 30, 2012

Significant Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

1.  SIGNIFICANT ACCOUNTING POLICIES:

The accompanying financial statements, other than the balance sheet data as of December 31,2011, are unaudited and were prepared from the Company's records, but do not include all disclosures required by U.S. Generally Accepted Accounting Principles (“GAAP”). Balance sheet data as of December 31, 2011 was derived from the Company's audited financial statements. The Company's management believes that these financial statements include all adjustments necessary for a fair presentation of the Company's financial position and results of operations. All adjustments are of a normal and recurring nature unless specifically noted. The Company prepared these statements on a basis consistent with the Company's annual audited statements and Regulation S-X. Regulation S-X allows the Company to omit some of the footnote and policy disclosures required by generally accepted accounting principles and normally included in annual reports on Form 10-K. You should read these interim financial statements together with the financial statements, summary of significant accounting policies and notes to the Company's most recent annual report on Form 10-K.

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. GAAP. All inter-company transactions and balances have been eliminated upon consolidation.

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

(b) 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.

(c) Property, Plant and Equipment:  Capital assets are recorded at cost and depreciated using the declining-balance method based on a seven-year useful life. Gathering system expenditures are recorded at cost and depreciated using the straight-line method based on a 30-year useful life. The gathering system assets are depreciated separately from proven oil and gas properties because they are expected to be used to transport oil and gas not currently included in the Company's proved reserves, including production expected from probable and possible reserves, as well as from third parties.

The Company recognized impairments of $92.5 million during the nine months ended September 30, 2012related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due tothe decline in commodity prices. These assets are included in Property, Plant and Equipment in the Consolidated Balance Sheets.

(d)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”). 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 Company's proved reserves. 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. Excluded costs, if any, are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the 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 and natural gas prices may subsequently increase the ceiling.

The Company recorded a $2.4 billion non-cash write-down of the carrying value of its proved oil and natural gas properties for the nine months ended September 30, 2012 as a result of ceiling test limitations, which is reflected withceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market pricesin effect on the first day of the month for the preceding twelve month period at September 30, 2012 and June 30, 2012of $2.83 per MMBtu and $3.15 per MMBtufor Henry Hub natural gas, respectively, and $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials.

(e) Derivative Instruments and Hedging Activities:Currently, the Company largely relies on commodity derivative contracts to manage its exposure to commodity price risk. These commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties. Additionally, and from time to time, the Company enters into physical, fixed price forward natural gas sales in order to mitigate its commodity price exposure on a portion of its natural gas production. These fixed price forward natural gas sales are considered normal sales in the ordinary course of business and outside the scope of FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note6).

(f) 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.

(g) Earnings Per Share:  Basic earnings per share is computed by dividing net earnings attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings 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.

		Three Months Ended				Nine Months Ended
		September 30,		September 30,		September 30,		September 30,
		2012		2011		2012		2011
		(Share amounts in 000's)
Net (loss) income	$	(602,146)	$	149,146	$	(1,704,865)	$	321,371
Weighted average common shares outstanding - basic		152,929		152,817		152,817		152,772
Effect of dilutive instruments		-		1,463		-		1,646
Weighted average common shares outstanding - fully diluted		152,929		154,280		152,817		154,418
Net (loss) income per common share - basic	$	(3.94)	$	0.98	$	(11.16)	$	2.10
Net (loss) income per common share - fully diluted	$	(3.94)	$	0.97	$	(11.16)	$	2.08
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		1,373		1,168		1,893		968

(h) 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.

(i) 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.

(j) 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 7 for additional information.

(k) 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 changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations.

(l) Revenue Recognition:The Company generally sells natural gas and condensate 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. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue. Any amount received in excess of the Company's share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable.

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.

(m)Capitalized Interest:Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated as well as on work in process relating to gathering systems.

(n)Capital Cost Accrual:The Company accrues for exploration and development costs and construction of gathering systems in the period incurred, while payment may occur in a subsequent period.

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

(p) Recent Accounting Pronouncements: In May 2011, the FASB issued ASU No. 2011-04, which amends FASB ASC 820. The amended guidance clarifies many requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB's intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not have a material impact on the Company's consolidated financial statements.

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Assets, Current [Abstract]
Cash and Cash Equivalents, at Carrying Value	$ 59,194	$ 11,307
Restricted cash	121	121
Oil and gas revenue receivable	62,237	88,243
Oil and Gas Joint Interest Billing Receivables, Current	21,816	82,370
Derivative Assets, Current	52,716	230,385
Deferred financing costs and other	6,406	7,494
Assets, Current	202,490	419,920
Oil And Gas Properties Net Using Full Cost Method Of Accounting [Abstract]
Proven	2,095,823	3,651,622
Unproven properties not being amortized	0	537,526
Property, Plant and Equipment, Net	271,284	246,586
Deferred Tax Assets, Net, Noncurrent	11,586	0
Other Assets, Noncurrent	12,445	14,051
Assets	2,593,628	4,869,705
Liabilities, Current [Abstract]
Accounts payable and accrued liabilities	143,751	295,873
Production taxes payable	60,084	62,117
Interest Payable	8,495	30,306
Taxes Payable, Current	11,586	73,380
Derivative Liabilities, Current	5,470	0
Capital cost accrual	239,671	209,303
Liabilities, Current	469,057	670,979
Long-term Debt, Excluding Current Maturities	2,160,000	1,903,000
Deferred tax liabilities	0	635,009
Other Liabilities, Noncurrent	74,174	67,008
Commitments and Contingencies
Stockholders' Equity Attributable to Parent [Abstract]
Common Stock, Value, Issued	470,081	463,221
Treasury Stock, Value	(33)	(14,951)
Retained Earnings (Accumulated Deficit)	(579,651)	1,145,439
Stockholders' Equity Attributable to Parent	(109,603)	1,593,709
Liabilities and Stockholders' Equity	$ 2,593,628	$ 4,869,705

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Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2012

Significant Accounting Policies Tables [Abstract]

Schedule Of Earnings Per Share

		Three Months Ended				Nine Months Ended
		September 30,		September 30,		September 30,		September 30,
		2012		2011		2012		2011
		(Share amounts in 000's)
Net (loss) income	$	(602,146)	$	149,146	$	(1,704,865)	$	321,371
Weighted average common shares outstanding - basic		152,929		152,817		152,817		152,772
Effect of dilutive instruments		-		1,463		-		1,646
Weighted average common shares outstanding - fully diluted		152,929		154,280		152,817		154,418
Net (loss) income per common share - basic	$	(3.94)	$	0.98	$	(11.16)	$	2.10
Net (loss) income per common share - fully diluted	$	(3.94)	$	0.97	$	(11.16)	$	2.08
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		1,373		1,168		1,893		968

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Document and Entity Information (USD $)	9 Months Ended
	Sep. 30, 2012	Oct. 23, 2012	Jun. 30, 2011
Document and Entity Information
Entity Registrant Name	Ultra Petroleum Corp.
Entity Central Index Key	0001022646
Document Type	10-Q
Document Period End Date	Sep. 30, 2012
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 7,003,851,599
Entity Common Stock, Shares Outstanding		152,928,937
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3

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Oil and Gas Properties and Equipment (Tables)

9 Months Ended

Sep. 30, 2012

Oil And Gas Properties And Equipment Tables [Abstract]

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Text Block]

2. OIL AND GAS PROPERTIES AND EQUIPMENT:
		September 30,		December 31,
		2012		2011
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$	7,106,729	$	5,974,604
Less: Accumulated depletion, depreciation and amortization(2)		(5,010,906)		(2,322,982)
		2,095,823		3,651,622
Unproven Properties:
Acquisition and exploration costs not being amortized(1)		-		537,526
Net capitalized costs - oil and gas properties	$	2,095,823	$	4,189,148
Property, Plant and Equipment:
Gathering Systems(1)	$	346,520	$	226,747
Less: Accumulated depreciation(3)		(104,425)		(7,736)
		242,095		219,011
Other Property and Equipment		14,697		11,333
Less: Accumulated depreciation		(7,851)		(5,908)
		6,846		5,425
Land		22,343		22,150
Net capitalized costs - property, plant and equipment	$	271,284	$	246,586

(1)For the nine months ended September 30, 2012 and 2011,total interest on outstanding debt was $77.2 million and $69.0 million, respectively, of which, $14.8 million and $22.9 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and on work in process relating to gathering systems.

(2)The Company recorded a $2.4billion non-cash write-down of the carrying value of its proved oil and natural gas properties for the nine months ended September 30, 2012 as a result of ceiling test limitations, which is reflected withceiling 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 periodat September 30, 2012 and June 30, 2012 of $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials.

(3)The Company recognized impairments of $92.5 million during the nine months ended September 30, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania dueto the decline in commodity prices. These assets are included in Property, Plant and Equipment in the Consolidated Balance Sheets. (See Note 7 for additional information on fair value).

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Consolidated Balance Sheets (Parenthetical) (USD $)	Sep. 30, 2012	Dec. 31, 2011
Statement of Financial Position [Abstract]
Common Stock, No Par Value
Common Stock, Shares, Issued	152,928,937	152,476,564
Common Stock, Shares, Outstanding	152,928,937	152,476,564

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Derivative Financial Instruments

9 Months Ended

Sep. 30, 2012

Derivative Financial Instruments [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

6.  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 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. The Board approved hedging greater than 50% of the Company's forecast 2012 production.

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 balance sheet and the associated unrealized gains and losses are recorded as current income or expense 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 cash flow statement. See Note 7 for the detail of the fair value of the following derivatives.

Commodity Derivative Contracts:At September 30, 2012, the Company had the following open commodity derivative contracts to manage price risk on a portion of its natural gas production whereby the Company receives the fixed price and pays the variable price. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties.

Type	Commodity Reference Price	Remaining Contract Period	Volume - MMBTU/Day	Average Price/MMBTU		Fair Value - September 30, 2012
						Asset
Swap	NYMEX	Oct-Dec 2012	500,000	$4.23	$	41,720
Swap	NYMEX	Oct 2012	90,000	$5.00	$	5,526

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 periodsended September 30, 2012 and 2011:

		For the Three Months				For the Nine Months
		Ended September 30,				Ended September 30,
Natural Gas Commodity Derivatives:		2012		2011		2012		2011
Realized gain on commodity derivatives (1)	$	83,433	$	53,630	$	260,239	$	143,749
Unrealized (loss) gain on commodity derivatives (1)		(93,329)		60,536		(183,139)		33,658
Total (loss) gain on commodity derivatives	$	(9,896)	$	114,166	$	77,100	$	177,407
(1) Included in (loss) gain on commodity derivatives in the Consolidated Statements of Operations.

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Income Taxes

9 Months Ended

Sep. 30, 2012

Income Taxes [Abstract]

Income Tax Disclosure [Text Block]

5. INCOME TAXES:

The Company's overall effective tax rate on pre-tax (loss) income was different than the statutory rate of 35% due primarily to valuation allowances, state income taxes and other permanent differences.

As a result of the tax effect of the ceiling test and other impairments recorded during the nine months ended September 30, 2012, the Company's previously recorded net deferred tax liability fully reversed into a net deferred tax asset. The Company has recorded a full valuation allowance against its net deferred tax asset balance of $279.2 million as of September 30, 2012. This valuation allowance may be reversed in future periods against future taxable income.

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Significant Accounting Policies (Details) (USD $) Share data in Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Jun. 30, 2012	Sep. 30, 2012	Sep. 30, 2011
Significant Accounting Policies Details [Abstract]
Discount Rate Future Net Revenues				10.00%
Earnings Per Share Reconciliation [Abstract]
Net Income (Loss)	$ (602,146,000)	$ 149,146,000		$ (1,704,865,000)	$ 321,371,000
Weighted Average Number of Shares Outstanding, Basic	152,929	152,817		152,817	152,772
Incremental Common Shares Attributable to Share-based Payment Arrangements	0	1,463		0	1,646
Weighted Average Number of Shares Outstanding, Diluted	152,929	154,280		152,817	154,418
Earnings Per Share, Basic	$ (3.94)	$ 0.98		$ (11.16)	$ 2.10
Earnings Per Share, Diluted	$ (3.94)	$ 0.97		$ (11.16)	$ 2.08
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	1,373	1,168		1,893	968
Other Asset Impairment Charges				92,500,000
Ceiling Test Limitation Pretax Oil and Gas Properties				$ 2,400,000,000
Natural Gas Market Price Full Cost Ceiling Test			$ 3.15	$ 2.83
Crude Oil Market Price Full Cost Ceiling Test			$ 95.67	$ 94.97

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Long Term Liabilities (Tables)

9 Months Ended

Sep. 30, 2012

Long Term Liabilities Tables [Abstract]

Long Term Liabilities

3. LONG-TERM LIABILITIES:
			September 30,		December 31,
			2012		2011
	Bank indebtedness	$	600,000	$	343,000
	Senior Notes		1,560,000		1,560,000
	Other long-term obligations		74,174		67,008
		$	2,234,174	$	1,970,008

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Subsequent Events

9 Months Ended

Sep. 30, 2012

Subsequent Events [Abstract]

Schedule of Subsequent Events [Text Block]

9.  SUBSEQUENT EVENTS:

The Company has evaluated the period subsequent to September 30, 2012 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent eventsarosethat should be disclosed in order to keep the financial statements from being misleading.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2012

Fair Value Measurements [Abstract]

Fair Value Disclosures [Text Block]

7.  FAIR VALUE MEASUREMENTS:

As required by 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 the Company has 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 utilized to measure the fair value of the Company's 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).

The following table presents for each hierarchy level the Company'sassets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis, as of September 30, 2012. The Company has no derivative instruments which qualify for cash flow hedge accounting.

		Level 1		Level 2		Level 3		Total
Assets:
Current derivative asset	$	-	$	52,716	$	-	$	52,716
Liabilities:
Current derivative liability	$	-	$	5,470	$	-	$	5,470

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.

Fair Value of Long-Lived Assets

The Company recognized impairments of $92.5 million during the nine months ended September 30, 2012related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These facilities are included in Property, Plant and Equipment in the Consolidated Balance Sheets and were impaired to a fair value of $82.6 million based on the income approach, estimated using Level 3 fair value inputs.

Fair Value of Financial Instruments

The estimated fair value of financial instruments is the estimated 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 Company uses available market data and valuation methodologies to estimate the fair value of its debt. The valuation assumptions utilized to measure the fair value of the Company's debt are considered Level 2 inputs. This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact the Company's financial position, results of operations or cash flows.

		September 30, 2012				December 31, 2011
		Carrying		Estimated		Carrying		Estimated
		Amount		Fair Value		Amount		Fair Value
Long-Term Debt:
5.45% Notes due 2015, issued 2008	$	100,000	$	109,190	$	100,000	$	111,475
7.31% Notes due 2016, issued 2009		62,000		73,344		62,000		74,817
4.98% Notes due 2017, issued 2010		116,000		130,133		116,000		128,570
5.92% Notes due 2018, issued 2008		200,000		235,617		200,000		231,091
7.77% Notes due 2019, issued 2009		173,000		223,101		173,000		219,552
5.50% Notes due 2020, issued 2010		207,000		237,431		207,000		229,423
4.51% Notes due 2020, issued 2010		315,000		333,430		315,000		318,925
5.60% Notes due 2022, issued 2010		87,000		97,218		87,000		94,165
4.66% Notes due 2022, issued 2010		35,000		35,540		35,000		34,631
5.85% Notes due 2025, issued 2010		90,000		101,292		90,000		99,022
4.91% Notes due 2025, issued 2010		175,000		179,071		175,000		173,835
Credit Facility		600,000		600,000		343,000		343,000
	$	2,160,000	$	2,355,367	$	1,903,000	$	2,058,506

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Legal Proceedings

9 Months Ended

Sep. 30, 2012

Disclosure Legal Proceedings [Abstract]

Legal Proceedings [Text Block]

8.  LEGAL PROCEEDINGS:

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, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company's financial position or results of operations.

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Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2012

Statement Significant Accounting Policies [Abstract]

Cash and Cash Equivalents, Policy [Text Block]

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

Restricted Cash Policy [Text Block]

(b) 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.

Property, Plant and Equipment, Policy [Text Block]

(c) Property, Plant and Equipment:  Capital assets are recorded at cost and depreciated using the declining-balance method based on a seven-year useful life. Gathering system expenditures are recorded at cost and depreciated using the straight-line method based on a 30-year useful life. The gathering system assets are depreciated separately from proven oil and gas properties because they are expected to be used to transport oil and gas not currently included in the Company's proved reserves, including production expected from probable and possible reserves, as well as from third parties.

The Company recognized impairments of $92.5 million during the nine months ended September 30, 2012related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due tothe decline in commodity prices. These assets are included in Property, Plant and Equipment in the Consolidated Balance Sheets.

Oil And Natural Gas Properties Policy [Text Block]

(d)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”). 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 Company's proved reserves. 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. Excluded costs, if any, are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the 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 and natural gas prices may subsequently increase the ceiling.

The Company recorded a $2.4 billion non-cash write-down of the carrying value of its proved oil and natural gas properties for the nine months ended September 30, 2012 as a result of ceiling test limitations, which is reflected withceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market pricesin effect on the first day of the month for the preceding twelve month period at September 30, 2012 and June 30, 2012of $2.83 per MMBtu and $3.15 per MMBtufor Henry Hub natural gas, respectively, and $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials.

Derivatives, Policy [Text Block]

(e) Derivative Instruments and Hedging Activities:Currently, the Company largely relies on commodity derivative contracts to manage its exposure to commodity price risk. These commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties. Additionally, and from time to time, the Company enters into physical, fixed price forward natural gas sales in order to mitigate its commodity price exposure on a portion of its natural gas production. These fixed price forward natural gas sales are considered normal sales in the ordinary course of business and outside the scope of FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note6).

Income Tax, Policy [Text Block]

(f) 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.

Earnings Per Share, Policy [Text Block]

(g) Earnings Per Share:  Basic earnings per share is computed by dividing net earnings attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings 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.

		Three Months Ended				Nine Months Ended
		September 30,		September 30,		September 30,		September 30,
		2012		2011		2012		2011
		(Share amounts in 000's)
Net (loss) income	$	(602,146)	$	149,146	$	(1,704,865)	$	321,371
Weighted average common shares outstanding - basic		152,929		152,817		152,817		152,772
Effect of dilutive instruments		-		1,463		-		1,646
Weighted average common shares outstanding - fully diluted		152,929		154,280		152,817		154,418
Net (loss) income per common share - basic	$	(3.94)	$	0.98	$	(11.16)	$	2.10
Net (loss) income per common share - fully diluted	$	(3.94)	$	0.97	$	(11.16)	$	2.08
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		1,373		1,168		1,893		968

Use Of Estimates [Text Block]

(h) 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.

Compensation Related Costs, Policy [Text Block]

(i) 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.

Fair Value Policy [Text Block]

(j) 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 7 for additional information.

Asset Retirement Obligations and Environmental Cost, Policy [Text Block]

(k) 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 changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations.

Revenue Recognition, Policy [Text Block]

(l) Revenue Recognition:The Company generally sells natural gas and condensate 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. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue. Any amount received in excess of the Company's share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable.

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.

Interest Expense, Policy [Text Block]

(m)Capitalized Interest:Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated as well as on work in process relating to gathering systems.

Reclassifications Policy [Text Block]

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

Capital Cost Accrual Policy [Text Block]

(n)Capital Cost Accrual:The Company accrues for exploration and development costs and construction of gathering systems in the period incurred, while payment may occur in a subsequent period.

Recent Accounting Pronouncements [Policy Text Block]

(p) Recent Accounting Pronouncements: In May 2011, the FASB issued ASU No. 2011-04, which amends FASB ASC 820. The amended guidance clarifies many requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB's intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not have a material impact on the Company's consolidated financial statements.

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Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2012

Derivative Financial Instruments Tables [Abstract]

Schedule of Derivative Instruments [Text Block]

Type	Commodity Reference Price	Remaining Contract Period	Volume - MMBTU/Day	Average Price/MMBTU		Fair Value - September 30, 2012
						Asset
Swap	NYMEX	Oct-Dec 2012	500,000	$4.23	$	41,720
Swap	NYMEX	Oct 2012	90,000	$5.00	$	5,526

Gain or loss on derivative instruments

		For the Three Months				For the Nine Months
		Ended September 30,				Ended September 30,
Natural Gas Commodity Derivatives:		2012		2011		2012		2011
Realized gain on commodity derivatives (1)	$	83,433	$	53,630	$	260,239	$	143,749
Unrealized (loss) gain on commodity derivatives (1)		(93,329)		60,536		(183,139)		33,658
Total (loss) gain on commodity derivatives	$	(9,896)	$	114,166	$	77,100	$	177,407
(1) Included in (loss) gain on commodity derivatives in the Consolidated Statements of Operations.

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Share Based Compensation (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended			12 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012 Number Of Options [Member]	Dec. 31, 2011 Number Of Options [Member]	Sep. 30, 2012 Weighted Average Exercise Price [Member]	Dec. 31, 2011 Weighted Average Exercise Price [Member]	Dec. 31, 2010 Weighted Average Exercise Price [Member]
Valuation And Expense Information [Abstract]
Total cost of share based payment plans	$ 4,497	$ 5,344	$ 11,513	$ 15,475
Amounts capitalized in fixed costs	1,448	1,898	3,683	5,583
Share-based Compensation	3,049	3,446	7,830	9,892
Amount of related income tax benefit recognized in income before valuation allowance	$ 1,265	$ 1,237	$ 3,249	$ 3,551
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Outstanding Options					1,459	2,230
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Lower Range Limit							$ 16.97	$ 16.97	$ 3.91
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Upper Range Limit							$ 98.87	$ 98.87	$ 98.87
Forfeited					(44)	(99)
Exercise Price, Lower Range Limit Forfeited							$ 25.08	$ 51.60
Exercise Price, Upper Range Limit Forfeited							$ 75.18	$ 75.18
Exercised					(33)	(672)
Exercise Price, Lower Range Limit Exercised							$ 16.97	$ 3.91
Exercise Price, Upper Range Limit Exercised							$ 25.68	$ 33.57
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Outstanding Options					1,382	1,459

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Income (Loss)	$ (1,704,865)	$ 321,371
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depletion, depreciation and amoritzation	314,115	238,773
Ceiling test and other impairments	2,475,963	0
Deferred Income Tax Provision (Benefit)	(712,363)	176,566
Unrealized Gain (Loss) on Derivatives	183,139	(33,658)
Excess Tax Benefit from Share-based Compensation, Operating Activities	4,215	(6,441)
Share-based Compensation	7,830	9,892
Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities, Other	1,663	783
Increase (Decrease) in Operating Capital [Abstract]
Increase (Decrease) in Restricted Cash for Operating Activities	0	(11)
Increase (Decrease) in Accounts Receivable	86,560	(22,329)
Increase (Decrease) in Prepaid, Deferred Expense and Other Assets	1,418	(1,927)
Increase (Decrease) in Other Operating Assets	0	(135)
Increase (Decrease) in Accounts Payable and Accrued Liabilities	(151,016)	1,637
Other long-term obligations	(1,747)	14,432
Increase (Decrease) in Accrued Income Taxes Payable	(993)	4,460
Increase (Decrease in Production Taxes Payable	(2,033)	8,204
Increase (Decrease in Interest Payable	(21,811)	8,175
Net Cash Provided by (Used in) Operating Activities	480,075	719,792
Net Cash Provided by (Used in) Investing Activities [Abstract]
Oil and gas property expenditures	(588,808)	(1,081,450)
Gathering system expenditures	(115,972)	(35,179)
Change in capital cost accrual	30,368	72,568
Inventory	(1,035)	1,212
Purchase of Capital Assets	(4,133)	(939)
Net Cash Provided by (Used in) Investing Activities	(679,580)	(1,043,788)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from Issuance of Long-term Debt	749,000	896,000
Repayments of Long-term Debt	(492,000)	(618,000)
Payments for Repurchase of Equity	(6,550)	(28,625)
Excess Tax Benefit from Share-based Compensation, Financing Activities	(4,215)	6,441
Proceeds from Stock Options Exercised	1,157	9,655
Net Cash Provided by (Used in) Financing Activities	247,392	265,471
Cash and Cash Equivalents, Period Increase (Decrease)	47,887	(58,525)
Cash and Cash Equivalents, at Carrying Value	11,307	70,834
Cash and Cash Equivalents, at Carrying Value	$ 59,194	$ 12,309

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Share Based Compensation

9 Months Ended

Sep. 30, 2012

Stock Based Compensation [Abstract]

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

4. SHARE BASED COMPENSATION:
Valuation and Expense Information
			Three Months				Nine Months
			Ended September 30,				Ended September 30,
			2012		2011		2012		2011
	Total cost of share-based payment plans	$	4,497	$	5,344	$	11,513	$	15,475
	Amounts capitalized in fixed assets	$	1,448	$	1,898	$	3,683	$	5,583
	Amounts charged against income, before
	income tax benefit	$	3,049	$	3,446	$	7,830	$	9,892
	Amount of related income tax benefit recognized
	in income before valuation allowance	$	1,265	$	1,237	$	3,249	$	3,551

Changes in Stock Options and Stock Options Outstanding

The following table summarizes the changes in stock options for the nine months ended September 30, 2012 and the year ended December 31, 2011:

		Weighted
	Number of	Average
	Options	Exercise Price
	(000's)	(US$)
Balance, December 31, 2010	2,230	$	3.91	to	$	98.87
Forfeited	(99)	$	51.60	to	$	75.18
Exercised	(672)	$	3.91	to	$	33.57
Balance, December 31, 2011	1,459	$	16.97	to	$	98.87
Forfeited	(44)	$	25.08	to	$	75.18
Exercised	(33)	$	16.97	to	$	25.68
Balance, September 30, 2012	1,382	$	16.97	to	$	98.87

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 2010, 2011 and 2012, 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 performance period. Under each LTIP, the Committee establishes a percentage of base salary for each participant which is multiplied by the participant's base salary and individual performance level to derive a Long Term Incentive Value as a “target” value which corresponds to the number of shares of the Company's common stock the participant is eligible to receive 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 LTIP awards in each of 2010, 2011 and 2012, the Committee established the following performance measures: return on equity, reserve replacement ratio, and production growth.

For the nine months ended September 30,2012, the Company recognized $5.6 million in pre-tax compensation expense related to the 2010, 2011and 2012LTIP awards of restricted stock units as compared to $7.5million during the nine months ended September 30, 2011 related to the 2009, 2010 and 2011 LTIP awards of restricted stock units. The amounts recognized during the nine months ended September 30, 2012 assume that maximum performance objectives are attained under each plan. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at September 30, 2012, for each of the three year performance periods is expected to be approximately $11.5 million, $11.6 million, and $11.9million related to the 2010, 2011 and 2012 LTIP awards of restricted stock units, respectively. The 2009 LTIP award of restricted stock units was paid in shares of the Company's stock to employees during the first quarter of 2012 and totaled $24.1 million ( 409,160net shares).

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Share Based Compensation - Textuals (Details) (USD $) In Millions, except Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Share Based Compensation Details [Abstract]
Long Term Incentive Program Period	$ 5.6	$ 7.5
Long Term Incentive Program Total 2010 Program	11.5
Long Term Incentive Program Total 2011 Program	11.6
Long Term Incentive Program Total 2012 Program	11.9
Long Term Incentive Program Total 2009 Program	$ 24.1
Long Term Incentive Program Total 2009 Program Shares	409,160

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Share Based Compensation (Tables)

9 Months Ended

Sep. 30, 2012

Share Based Compensation Tables [Abstract]

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Text Block]

4. SHARE BASED COMPENSATION:
Valuation and Expense Information
			Three Months				Nine Months
			Ended September 30,				Ended September 30,
			2012		2011		2012		2011
	Total cost of share-based payment plans	$	4,497	$	5,344	$	11,513	$	15,475
	Amounts capitalized in fixed assets	$	1,448	$	1,898	$	3,683	$	5,583
	Amounts charged against income, before
	income tax benefit	$	3,049	$	3,446	$	7,830	$	9,892
	Amount of related income tax benefit recognized
	in income before valuation allowance	$	1,265	$	1,237	$	3,249	$	3,551

Stock Option Activity TextBlock

		Weighted
	Number of	Average
	Options	Exercise Price
	(000's)	(US$)
Balance, December 31, 2010	2,230	$	3.91	to	$	98.87
Forfeited	(99)	$	51.60	to	$	75.18
Exercised	(672)	$	3.91	to	$	33.57
Balance, December 31, 2011	1,459	$	16.97	to	$	98.87
Forfeited	(44)	$	25.08	to	$	75.18
Exercised	(33)	$	16.97	to	$	25.68
Balance, September 30, 2012	1,382	$	16.97	to	$	98.87